Net Energy Metering, Zero Net Energy and The Distributed Energy Resource Future: Adapting For The 21st Century

NET ENERGY METERING, ZERO NET ENERGY AND
THE DISTRIBUTED ENERGY RESOURCE FUTURE
aDaPtiNG ElEctric utility BuSiNESS moDElS For tHE 21St cENtury

contEntS
ExEcutivE Summary 1
ProjEct ovErviEw 6
DrivErS oF cHaNGE 10
PotENtial cHallENGES 26
aPProacH to SolutioNS 35

2Executive Summary
Executive
Summary
California’s electricity system stands at the forefront of changes that are transforming the
electricity industry globally. These changes include integration of increasing amounts of
renewable electricity supplies, creation and execution of programs to improve customers’
energy efficiency, and implementation of new smart grid technologies for better coordination,
control, and communication in managing the electricity grid. Today, however, an even more
fundamental shift is taking place. New technologies and service offerings are emerging to
grant customers unprecedented options in managing their energy consumption, generating
electricity onsite, charging electric vehicles, and a host of other activities.
The increasing scope and power of customer decisions bring a new dimension to the electric
utility business environment. Whereas utilities have traditionally exercised a high degree of
control over investment decisions and operational management for most electricity system
assets, utilities’ future role could increasingly entail coordinating a vast array of supply- and
demand-side resources owned and operated by tens of thousands—potentially millions—
of independent actors. Based on publically announced power purchase agreement (PPA)
contracts, the California Solar Initiative goals, and Gov. Brown’s targets for distributed
renewables, one-fourth of the total new investments in generating capacity in PG&E’s service
territory between 2012 and 2020 could come on the customer’s side of the meter, largely in
the form of rooftop solar PV systems. In parallel with these trends, growing numbers of
buildings, campuses, and communities that meet California’s Zero Net Energy policy goals
will be exporting and importing electricity to and from the grid, bringing fundamental
changes to the relationship between these customers and the utility. In short, the electricity
system of the future is likely to encompass an increasingly diverse and interconnected set
of actors, with widely varying assets, behaviors, and motivations.
If this emerging system is to sustainably achieve societal goals for the electricity system—
providing reliable and resilient energy services at reasonable cost while meeting standards
for fairness and environmental stewardship—then the decisions and behaviors of utilities
and their customers must be harmonized to an unprecedented degree. The behaviors of many
actors must be aligned to match fluctuations of supply and demand in real time. Investments
in distributed resources must be made with a view to the temporal and geographic variations
in the value and cost of electricity supply. Overall, the effectiveness of a utility’s role in
conducting the orchestra of distributed energy resources that interact with its system will
be a critical factor in achieving favorable outcomes for all stakeholders. And the long-term
health and stability of the electricity grid will be essential to making such a system work.

3Executive Summary
Existing utility rate structures and business models, which have evolved over time to meet
a complex set of policy and economic goals, are poorly adapted to this new environment.
Already, there are signs of growing tensions and conflicts among stakeholders in the electricity
system as distributed resources are more widely deployed. Rate structures and incentives
designed to stimulate the early adoption and scale-up of rooftop solar systems, electric
vehicles, and other new technologies and design approaches will need to be modified
over time, as adoption rates increase. New technologies and design practices call for new
approaches to managing utility operations and pricing electricity services to accurately reflect
benefits and costs of distributed resources and provide a sustainable path for the increased
deployment of these resources.
To explore these issues, Rocky Mountain Institute and PG&E convened a roundtable
composed of leading policy experts and industry and customer representatives. The work
of the roundtable was to build a shared understanding of the problems and challenges facing
stakeholders in the electric system and to identify the essential characteristics of workable
long-term solutions.
While the roundtable’s participants represented a diverse set of perspectives on the issues, the
participants agreed that three key building blocks will be essential in developing solutions
to the challenges discussed:
1. Identify and Measure Impacts, Costs and Values of Distributed
energy resources
Building a shared understanding among stakeholders in the electricity industry of
the full range of costs and benefits of distributed resources is an essential first step
toward devising the business strategies, rates, and incentives that will create the
greatest benefit for all. Select utilities, national labs, and other research organizations
are starting to identify and analyze these costs and benefits, such as the capital and
operating expenses incurred or avoided as a result of distributed generation installation.
However, experience with high penetration of distributed generation, especially solar
PV, is limited, and many questions remain about (a) the types of costs and benefits that
may be incurred, (b) the magnitude of these costs and benefits, and (c) the degree to
which these costs and benefits may be influenced by utility rates and other incentives.
In California, studies using differing methods and assumptions have reached varying
conclusions about the degree to which net metering results in a “cost shift” from
customers adopting solar PV to other customers.1,2,3
Based on these competing studies,
there are diverse opinions and projections about the rate impacts of increased solar
penetration in the future. For example, PGE projects that the adoption of large
amounts of solar photovoltaics (PV) on customer sites would increase the utility’s
top-tier residential rates significantly4
, leading to higher adoption of distributed solar

4Executive Summary
by customers in these rate classes. However, there remains a lack of consensus about
analysis methods and data.
More rigorous analysis is needed to fully assess the costs and benefits of distributed
resources for California’s electric utilities and the potential for change in these costs and
benefits in the future as penetration rates increase and new technologies are integrated
on both the customer and grid side of the meter. Such analysis will require evaluation
of impacts of distribution system capital and operating costs, equipment lifetimes,
balancing costs, generation capacity costs, fuel price risks, implications for the reliability
and resilience of the electricity grid, and a wide range of other considerations. New
data collection and analysis methods will be necessary to develop estimates of these
costs and benefits while ensuring accountability, transparency, and verifiability of cost
and benefit estimates that will provide the foundation for policymaking.
2. Remedy misalignments between economic incentives to customers
and the cost and value to the system provided by distributed
resources
Existing rates and incentives fail to provide accurate economic signals to align
distributed generation investment with system costs and benefits over the long term.
Retail net energy metering, combined with tiered volumetric rates does not provide a
sustainable long-term business model for electric utilities, nor does it provide accurate
price signals for customers. As more investment is made outside of the utility’s control,
new rate structures, price signals and incentives will be critical for directing that
investment for greatest system benefit. For example, these signals might provide
incentives for the customer to reduce demand on the system during peak periods, or
to provide voltage support or other ancillary services that reduce overall system costs.
These solutions could require fundamental changes in existing non-time differentiated
tiered rate structures, which allow little flexibility to accurately reflect costs of serving
customers with distributed generation capabilities. Given the right price signals,
distributed generators can adapt over the long term to provide new sources of value
to the utility system. This change, however, would require a significant restructuring
of existing rates, creating greater complexity in customers’ bills.
3. Adapt Utility Business Models to create and sustain value
in a future characterized by higher levels of efficiency and
increased deployment of distributed resources
Utilities have important and valuable roles as enablers and integrators in the deployment
and operation of distributed resources. However, proliferation of distributed energy
resources pose challenges to existing utility business models, whose basic tenets were
designed under a production and delivery model dominated by centralized generation
and one-way distribution. Further, electric utility business models exist within the

5Executive Summary
context of regulatory structures that shape the roles of key actors, influence how
markets evolve and, ultimately, control the gateway to the available technical solutions.
Roundtable participants agreed that, to fully adapt to this role, utilities must develop
new ways of pricing the “network services” they provide and of promoting value
creation through distributed resource development. However, they expressed differing
views about how California’s regulated utilities might best adapt to a future with
increasing shares of distributed generation resources. Two approaches were discussed:
Incentive regulation approach
An “incentive regulation” approach that would allow the utility a more
expansive role in managing and, potentially, investing in distributed resources
as a tool for reducing costs.
Network utility approach
A “network utility” approach under which the utility would provide highly
differentiated price signals to incent customers to provide the highest value
energy supply, load management, or ancillary services to the utility system.
Overall, significant changes will be needed to adapt utility’s electricity rate structures and
business model to meet the needs of the future. Shared understanding among industry
stakeholders about system costs and benefits in relation to distributed resources is a critical
first step toward finding appropriate solutions.
Significant changes will be
needed to adapt electricity
utility business models, and
pricing structures to meet
future needs.
About This Report
The potential proliferation of advanced technologies,
combined with rapid improvements in the cost competitiveness
of current energy efficiency technologies and distributed
resources, especially solar photovoltaics (PV), present
unique challenges and opportunities to the traditional utility
infrastructure. This can be especially true where distributed
generation is concentrated, as in the case of a ZNE community.
This report represents a first step to explore the implications
for customers, utilities and other providers in this future.
This report identifies and articulates key issues that emerged
from analysis completed by RMI and PGE, together with
insights and recommendations that emerged from the
roundtable discussion, and defines an “options space” for
future analysis. The report and analysis primarily focus on
the distributed solar market, which is growing at a strong rate
and is nearing penetration levels that will cause noticeable
impacts to grid operations and utility business models.
However, within the 2020 time horizon described in this
report, other distributed resources such as electric vehicles
or energy storage could also achieve similar cost declines and
increased adoption, resulting in similar needs for reassessing
the basic infrastructure, pricing models and business models
of the current electricity system.

7Project overview
Project
Overview
On behalf of PGE, Rocky Mountain Institute (RMI) organized and facilitated a roundtable
of experts to evaluate the potential implications for the utility and its customers of a future
business environment characterized by high levels of customer energy efficiency, growing
numbers of Zero Net Energy (ZNE) buildings, and increased adoption of distributed generation
(largely solar PV) by utility customers. The political and policy environment surrounding
distributed resources is highly charged, with strongly held beliefs and assumptions about
distributed generation benefits and impediments to customer adoption. At the same time, there
are myriad complexities in analyzing the costs and benefits to the utility system of installing
these technologies. Costs and benefits will shift over time as markets evolve, penetration
rates increase, and new technologies are deployed.
Establishing a common framework for understanding the implications for the utility system of
distributed generation (DG), measuring impacts, and aligning rates and policies is a daunting
but unavoidable task. The key questions to be addressed include:
How will increased penetration of distributed resources and ZNE buildings
affect cost and value for the utility and its customers?
How could rate structures be modified to enable sustainable, fair, and
efficient development of these resources?
How might utility business models change?
What innovative energy services could be provided by the utility in
conjunction with distributed resources and ZNE customers? What is the
value of these services to all customers?
This report identifies and articulates key issues that emerged from analysis completed by RMI
and PGE in support of the expert roundtable, together with insights and recommendations
that emerged from the roundtable discussion. This work defines an “options space” for
future analysis.

8Project overview
External participants
Ron Binz, former Colorado Public Utilities Commission
Chairman
Ralph Cavanagh, Co-Director, Natural Resources Defense
Council (NRDC) Energy Program
John Dilliott, Energy and Utilities Manager, University of
California, San Diego (UCSD)
Stephen Frantz, Sacramento Municipal Utility District
(SMUD), Program Planner
Sue Kateley, Senior Consultant, California State Assembly
Laura Manz, Senior Vice President, Western Region, Viridity
Energy
Janine Migden-Ostrander, Principal, The Regulatory
Assistance Project (RAP)
Peter-Fox Penner, Principal and Chairman, The Brattle
Group
Nancy Ryan, Assistant Executive Director for Policy, California
Public Utilities Commission
Lisa Wood, Executive Director, Institute for Electric Efficiency,
The Edison Foundation
Rocky Mountain Institute
participants
James Newcomb, Program Director
Virginia Lacy, Senior Consultant and Project Manager
Ned Harvey, Chief Operating Officer and Vice President
of Finance
Lena Hansen, Principal
Ryan Matley, Consultant
PGE participants
Jan Berman, Senior Director, Integrated Demand Side
Management Policy
Steve Kline, Vice President, Corporate Environmental
and Federal Affairs and Chief Sustainability Officer
Steve Malnight, Vice President, Customer Energy
Solutions
David Rubin, Director, Service Analysis
Susan Buller, Principal Strategic Analyst
Peter Turnbull, Principal Program Manager, Zero Net
Energy
Roundtable Participants

9Project overview
Scope Definitions
An industry standard definition does not presently exist for many of the terms or concepts
in this report. For the sake of clarity, we define the terms used in this report as follows:
DER
Distributed Energy Resources
Distributed energy resources are
“demand- and supply-side resources
that can be deployed throughout an
electric distribution system to meet
the energy and reliability needs
of the customers served by that
system. Distributed resources can
be installed on either the customer
side or the utility side of the meter.”5
This includes generation, managed
loads (including electric vehicle
charging), energy storage, and other
technologies that can provide energy,
load management, and ancillary
services, such as reserves, voltage
control, and reactive power, and
black start capabilities.
DG
Distributed Generation
Any electricity generation device
connected at the distribution level
installed on the customer’s side of
the meter that is interconnected with
the grid, such as distributed solar PV,
wind or combined heat and power
(internal combustion engines, fuel
cells, microturbines, gas turbines).6
ZNE
Zero Net Energy
Though California has established
goals for achieving Zero Net
Energy for all new buildings
by 2020 (residential) and 2030
(commercial), the definition of ZNE
is still unsettled, especially as it
pertains to the parameters for site
and energy source. For the purposes
of this report, a Zero Net Energy
customer is defined as one whose
annual electricity consumption and
generation net to zero or less. The
customer could use any combination
of renewable generation, energy
efficiency measures, and distributed
resources to achieve net zero status.

11DRIVERS OF CHANGE
Drivers
of Change
Transformative market forces are poised to fundamentally change California’s electricity
system. While these trends are partly attributable to California energy policies, they are also
shaped by changes in technology and economics at the national and global level. For example,
across the U.S., supportive policies, combined with rapid technology cost declines and
business model innovations (including third-party financing and other financial innovations),
have spurred distributed generation, particularly solar photovoltaics (PV), to grow rapidly
in recent years. In California, these drivers have resulted in over 1 GW of installed solar PV
capacity, representing 48% of the total U.S. solar capacity. Key policy and market drivers are
detailed in this section.
Policy drivers
Legislative and regulatory action to support renewable energy
and efficiency is driving a significant shift in the demand for
electricityandthegenerationmixtomeetit.Majorpolicydrivers
include:
Targets and Mandates Policy-directed targets and
mandates include efficiency goals that will reduce
load growth, renewable portfolio standards (RPS) that
mandate the adoption of clean energy technologies, and
environmental regulations that limit the viability of heavily
polluting power plants.
Financial Incentives Policymakers have also crafted a suite
of financial mechanisms, such as tax incentives that are
designed to encourage the continued growth of distributed
and renewable generation technologies.
ƒƒ Federal and state tax incentives and rebates
ƒƒ Net energy metering policies
ƒƒ Feed-in tariffs
ƒƒ Electricity prices and rate structures
Technology MARKET TRENDS
Technological innovation, lead by both global and local markets,
enormously expands the range of offerings from traditional and
new service providers.
Technology Cost Reductions The costs of renewable and
distributed generation technologies have dropped dramatically
in the past decade, and are poised for continued reductions.
Cost competitiveness significantly accelerates adoption while
opening the potential market to even more customers.
Enabling Technologies The market is poised to see further
changes with the introduction of smart-grid technologies,
electric vehicles, energy storage, and home energy management
systems. The deployment and integration of these technologies
can provide customers greater control in their interactions
with the utility grid, and help utilities manage increasing
penetrations of variable renewables and distributed generation.
Service Innovation Innovative distributed generation business
models are lowering barriers to adoption and providing new
and existing providers with the opportunity to offer new types
of integrated energy services in parallel with the regulated
utility.

12DRIVERS OF CHANGE
Figure 1
Targets and mandates affecting california’s electricity sector (2010–2030)
Current policies and mandates will reshape California’s electricity system.
Policy Drivers
California has been a global leader in energy policy since the early 1970s. With the Warren-
Alquist Act of 1973, the legislature created the California Energy Commission and established
the state’s energy policy cornerstone to pursue, “all practicable and cost-effective conservation
and improvements in the efficiency of energy use and distribution that offer equivalent
or better system reliability.” The state’s success in aligning profit incentives for utilities to
implement and support energy efficiency has helped keep per-capita electricity use flat for the
last 30 years and made California the largest energy efficiency market in the country. Today,
the combined impact of the energy efficiency, distributed generation, large-scale renewable
energy, and environmental regulations affecting thermal power plants is reshaping California’s
the electricity system (Figure 1).
ARB GHG Market
AB 32 becomes enforceable in 2012, Cap-and-Trade program emissions
obligations begin in 2013
California Solar Initiative
2,550 MW of solar capacity by 2017, 1,940 MW from IOUs
EPA Regulations
US EPA’s Clean Air Transport, Mercury and Air Toxic Standards, Coal
Combustion Residuals, and New Source Performance Standards rules
take effect between 2014 and 2020
Once Through Cooling Rules
Will affect 20.4 GW of generation, roughly 35% of CA’s fleet. Compliance
dates range from 2015-2020
CPUC Energy Efficiency Goal
20% reduction in the business-as-usual forecast for residential electricity
consumption by 2015, and 40% by 2020
Zero Net Energy Goals
All new residential construction will be net zero by 2020
Renewable Portfolio Standard
33% by 2020
ARB CHP Goal
Additional 4,000 MW of CHP by 2020
AB 32
CO2
emissions reduced to 1990 levels by 2020
Governor Brown’s Clean Energy Jobs Plan
20,000 MW of renewable energy capacity by 2020 (35,000 MW above
existing mandates)
Zero Net Energy Goals
All new commercial construction will be net zero by 2030.
2010
2015
2020
2025
2030
Existing Generation
Renewable Generation
Environment
Efficiency

13DRIVERS OF CHANGE
TARGETS AND MANDATES AFFECTING CALIFORNIA’S ELECTRICITY SECTOR
California’s targets and mandates affect both the demand and supply of electricity. On the
demand side, California has set some of the most ambitious energy efficiency goals in the
nation. By 2020 California is projected to lower annual load growth from ~2% to 1% through
customer-funded efficiency programs. Beyond 2020, as part of the CPUC’s Big Bold Energy
Efficiency Strategies, all residential new construction should be Zero Net Energy (ZNE) by
2020 and all new commercial construction will be ZNE by 2030. These requirements should
slow load growth dramatically in these sectors as residents and businesses migrate to new,
energy efficient buildings. Together, California’s energy efficiency strategies are expected
to result in a 9% reduction in electricity demand from the projected “business-as-usual”
demand in 2020 (Figure 2).
Figure 2
Projected Demand for Electricity in California
Demand for electricity in California is expected to grow by only 1% annually due to efficiency investments.
Sources and Notes:
California Energy Commission, Preliminary California Energy Demand Forecast 2012-22. August 2011.
Kavalec, Chris, Tom Gorin, Mark Ciminelli, Nicholas Fugate, Asish Gautam, and Glen Sharp. 2011. Preliminary California Energy Demand Forecast 2012-2022. CEC-200-
2011-011-SD.
Scenario Descriptions: p. 28
Self Generation Stats: p. 34
Assumptions: “Low Demand” scenario, included uncommitted savings, assumed sector totals did not include demand met by DG. BAU: Assumed no EE savings, no EV
growth, and no addt’l self generation, (modeled BAU by backsolving, given EE as a % of consumption)

14DRIVERS OF CHANGE
Renewable Portfolio Standard
(RPS)
California’s RPS, enacted in 2002 and
subsequently updated, is the single greatest
driver of the changing resource mix in the state.
It sets forth a strict timeline, mandating that 33%
of utilities’ annual electric sales be procured from
renewable resources by 2020.
Technology-Specific Goals
The Go Solar California campaign aims to install
3 GW of solar energy systems by 2017 through
the California Solar Initiative (CSI), the New Solar
Homes Partnership, and various POU programs.
Additionally, to meet AB 32, CARB set the
ambitious goal of adding 4,000 MW of new CHP
capacity by 2020 — nearly a 50% increase.
Governor Brown’s Clean Energy
Jobs Plan In 2010
Governor Brown called for 20 GW of new
renewable energy capacity by 2020, including
12 GW of DG and 8 GW of utility-scale capacity.
This goal is a 3.5 GW increase over existing
mandates and would more than triple the non-
hydro renewable capacity on the system. The
plan also expands CARB’s CHP goal, calling for
6.5 GW of new cogeneration capacity by 2030.
Once Through Cooling (OTC)
Policy
To protect the state’s marine environments,
in 2010 the California State Water Resources
Control Board (SWRCB) established regulations
restricting the use of coastal and estuarine water
for power plant cooling, affecting 20.4 GW of
generation capacity (30% of CA’s fleet). From
2015 to 2020, 12 GW of natural-gas-fired power
plants are expected to retire,rather than retrofit
to comply with the new rules.
Global Warming Solutions Act
(AB 32)
California’s legislature signed AB 32 in 2006,
establishing goals to reduce CO2
emissions to
1990 levels by 2020 and to 20% of 1990 levels
by 2050. To enforce this law the California Air
Resources Board (CARB) plans to institute a
Cap-and-Trade Program, which will limit GHG
emissions and create a market for tradable
allowances. Emissions obligations for electric
utilities begin in 2013.
Environmental Protection Agency
(EPA) Regulations
The North American Electric Reliability
Corporation anticipates that the EPA’s
enforcement of Clean Air Act regulations
will significantly accelerate the retirement of
generation capacity as they take effect between
2014 and 2020.
FossilfueledorThermalGeneration
Renewables,DistributedGeneration
On the supply side, a range of policies encouraging large-scale renewables and distributed
generation coupled with new restrictions on thermal power plants (Table 1) will reshape the
electric supply mix. Between 2010 and 2020, these policies will at minimum require a 250%
increase in installed non-hydro renewable capacity, and the retirement of 25% of existing
natural gas-fired generation capacity (Figure 3).
Table 1
Policies Affecting Electricity Supply Mix in California

15DRIVERS OF CHANGE
Figure 3
Projected Generating Capacity for California (2010–2020)
The supply mix will include significant contributions from renewables at the
expense of thermal generation.
70
80
60
50
40
30
20
10
0
Generating Capacity
(GW)
2010 2020
Once-Through-Cooling
Retirements
CA Solar Initiative
New Solar Homes
Program
Air Resources Board
CHP Goal
Additional Necessary
to Meet 33% RPS
Natural Gas
Nuclear
Hydro
Other Fossil
Solar
Wind
Other Renewables
2010 Generator Capacity California Energy Commission. Database of California Power Plants. http://energyalmanac.ca.gov/powerplants/POWER_PLANTS.XLS. 2011.
2010 Behind-the-Meter Capacity 2011. Staff Draft Report on Renewable Power in California: Status and Issues. California Energy Commission, August 2011, Publication No. CEC 150 2011 002.
Expected OTC Retirements Vidaver, David, Mike Ringer, Michael Nyberg, Darryl Metz, Connie Leni. 2009. The Role of Aging and Once-Through-Cooled Power Plants in California An Update.
California Energy Commission. CEC-200-2009-018.
CARB CHP Goals Darrow, Ken, Bruce Hedman, Anne Hampson. 2009. Combined Heat and Power Market Assessment. California Energy Commission, PIER Program. CEC 500 2009 094 D.
CSI/NSHP Additions California Public Utilities Commission. About the California Solar Initiative. http://www.cpuc.ca.gov/puc/energy/solar/aboutsolar.htm. 2009.
2020 Renewables Capacity California Independent Systems Operator. 2011 Annual State of the Grid. 2011.
FINANCIAL INCENTIVES
In addition to technology or efficiency targets, which are often used to “push” markets, financial
incentives, such as tax incentives and rebates, create market “pull” for the growth of renewable
and efficiency resources by reducing the costs to potential buyers. By substantially reducing
the cost to install these systems, these subsidies have resulted in more attractive investment
opportunities and significantly greater demand. Beyond ensuring that the development of
distributed generation is economically viable for the adopter at the point of initial capital
investment, additional policies and regulations within the electricity sector—such as net-
metering policies, feed-in tariffs, and the relative cost of electricity itself—significantly affect
the viability of distributed and/or renewable investments.

16DRIVERS OF CHANGE
Table 2
Selected Rebates and Tax Incentives Affecting California’s Supply Mix
Rebates
California Solar
Initiative (CSI)
The California Solar Initiative (CSI) provides electric customer-
funded cash rebates to PV owners. Rebates decline as installed
capacity increases until a self-sustaining solar market is created.
Thus far, $1.1 billion has been provided for over 600 MW of PV. Early
program rebates of $2.50/W dropped system prices 25% and jump-
started the market. At present, CSI rebates have dropped to as low
as $0.35-$0.20/W, and are no longer the primary determinant in
whether a system is economic.
California Self
Generation
Incentive Program
(SGIP)
The California Self Generation Incentive Program (SGIP) provides
rebates to distributed wind, CHP, fuel cell, and advanced storage
technology system owners. The SGIP program focuses on high-cost,
recently commercialized technologies, has a $75 million annual
budget, and provides $1.50-4.50/W incentives. 350 MW have been
installed under this program since 2000. Recent policy changes will
reduce incentives beginning in 2011, and shift to a mix of up-front
and performance-based incentives to reward performance, not just
installation. The CHP rebates are based in part on efficiency.
Tax
Incentives
Federal Tax Credits
Provides a personal investment tax credit of 30% of installed system
capital cost and a corporate investment tax credit equal to either
10% or 30% of system cost depending on the technology.
CA AB 1451
Allows for the property tax exemption of 100% of the increase in
property value resulting from the installation of a PV system.
TAX INCENTIVES AND REBATES
Funding comes primarily from the federal, state or local governments, and utilities.
The availability of incentives differs based on technology, system size, and type of
owner. Benefits may be tied to system capacity ($/kW), system production ($/kWh),
or investment cost, and are typically distributed as either tax benefits or rebates.
To illustrate the effect of these incentives on the economics of a renewable energy
investment, Figure 4 illustrates the annual and cumulative savings that result from the
installation of a residential 4 kW PV system or a commercial 500 kW biogas internal
combustion engine CHP system. The California Solar Initiative (CSI) rebate and federal
residential investment tax credit (ITC) combine to reduce the capital cost of the PV system
by 35%, while the Self Generation Incentive Program (SGIP) rebate and federal business
ITC cut the cost to install the CHP system in half.

17DRIVERS OF CHANGE
Figure 4
Impact of current incentives
Current incentives reduce the upfront cost of a residential solar PV system
by 35% and the upfront cost of a commercial CHP system by 50%.
Source: CHP system is a 500 kW biogas-fueled ICE, cost data from ITRON report for CPUC:http://www.cpuc.ca.gov/NR/rdonlyres/2EB97E1C-348C-4CC4-A3A5-D417B4DDD58F/0/SGIP_CE_Report_Fi-
nal.pdf | SGIP data from PGE: http://www.pge.com/mybusiness/energysavingsrebates/selfgenerationincentive/equipmenteligibility.shtml | ITC data from DSIRE
CHP
Unsubsidized
Installed Cost
PV
Unsubsidized
Installed Cost
NET ENERGY METERING
To encourage the installation of distributed generation, net energy metering (NEM)
programs credit customers for the electricity they export, typically at retail rates.7
By “netting” the customer’s bill, full retail NEM provides the customer the retail
value for electricity exported to the grid, which can significantly increase the value
of self-generation to the customer (Figure 5). The simplicity of full retail NEM, or
“running the meter backward,” has led to the adoption of NEM in 43 states and
the District of Columbia.
Recent legislation expanded retail net metering in California to all renewables up to
1 MW that are sized to a customer’s annual load. California regulators have capped
the total generation capacity participating in NEM programs at 5% of peak load.
If installed PV capacity in California continues on its current growth trajectory (a
46% per year average over the last two years) capacity will approach the NEM cap
in approximately 2014 (Figure 6). In addition, they have recently begun to extend
NEM eligibility beyond single contiguous properties by allowing virtual net energy
metering (VNEM), which in some instances enables customers to participate in
off-site and/or group-owned projects. California has carefully restricted VNEM
to multi-tenant and multi-meter properties with a single point of interconnection
with the distribution system.

18DRIVERS OF CHANGE
Figure 5
Illustrative Example of Retail Net Energy Metering for Residential Customer with Solar PV
Under retail NEM, a solar customer receives full retail credit for excess generation exported to the grid.
2.5
2
1.5
1
0.5
0
-0.5
-1
-1.5
-2.0
-2.5
0:00 12:00 0:00
Net load
Solar Generation
Demand
kW
Reimbursed at
retail rates
FEED-IN TARIFFS AND RENEWABLE AUCTIONS
While NEM programs incent distributed generation on the customer side of the meter,
alternative mechanisms, such as feed-in-tariffs (FITs) and auctions, allow utilities to
procure power from distributed renewable generation. These mechanisms, intended
to bridge the gap between incentives for DG on the customer side of the meter and
utility-scale projects, will help to meet California’s RPS, while also creating additional
market growth in the state. FITs allow regulators to encourage small-scale renewable
development using predefined PPA terms with differentiated rates, meaning FIT rates
may vary depending on technology, siting, or other attributes.8
California recently
extended FIT eligibility to renewable generators up to 3 MW capacity, with a cap of
750 MW.9

19DrivErS oF cHaNGE
figurE 6
iNStallED DG caPacity iN caliForNia
installed DG capacity in california has grown exponentially, approaching the program cap of 5% peak load.
if installed Pv capacity in california continues on its current growth trajectory (38% per year average over
the last two years) capacity will approach the NEm cap in approximately 2014.
To complement the state’s FIT offering, the CPUC created the Renewable Auction
Mechanism (RAM), an innovative program that allows IOUs in the state to use auctions
to procure contracts with larger renewable projects (≤ 20 MW). The RAM establishes
regulatory certainty for developers and utilities, and also protects electricity customers
by ensuring that utilities secure the lowest-cost projects available through competitive
bidding — it will result in the addition of approximately 1 GW of contracted renewable
generation capacity to California’s grid by 2013.
california ElEctricity ratES
California has a tiered rate structure for residential customers with the primary goal of
encouraging energy efficiency. That is, the price for electricity (cost per kWh) increases
as the amount of electricity a customer uses increases over a billing period (Figure 6).
Thus, reductions in electricity consumption will be valued at the marginal tiered rate, and
higher electricity consumers will have a larger efficiency incentive. Since the reduction
of utility-generated electricity via distributed generation looks economically equivalent
to an efficiency investment, California’s tiered rate structure also serves to encourage
distributed energy resources.
Source: California Solar Initiative Data, accessed Feb 28th, 2011

20DRIVERS OF CHANGE
In response to the 2000-01 energy crisis, the California Legislature froze lower-tier rates
(Tiers 1 and 2) as a means to protect some customers from the impact of crises-related
cost increases. Therefore, all rate increases over the past decade have fallen to the top
tiers: 3, 4 and 5. In 2010, legislators voted to allow the lower tiers to increase by 3-5%
annually; however, this will relieve only some of the pressure on the upper tiers.
The restrictions on increasing lower-tier rates have resulted in a significant disparity
among rate tiers, in which upper tier rates are three to four times as high as lower tier
rates. For example, the average upper-tier rate is currently $0.33 per kWh—and was
recently as high as $0.49 per kWh, compared to the average lower-tier rate of $0.12 per
kWh. Comparing these rates to the current levelized cost of solar PV for a residential
customer, which is estimated to be $0.25 to $0.29 per kWh, it is apparent that customers
whose usage reaches the upper tiers have a strong incentive to install solar PV.
Figure 7
PGE’s current residential tiered rate structure (January 2012)
Residential customers, whose cumulative monthly usage rises above 150% of their baseline value (as
defined for each climate zone), see their marginal electricity rate more than double.
Source: PGE E-1 Tariff, effective Jan 25, 2012

21DRIVERS OF CHANGE
technology market Trends
Technology cost reductions
Experience, scale, and technological innovation continue to drive down the cost of emerging
and rapidly maturing power generation technologies across global markets. The costs of
renewable and distributed technologies have dropped dramatically in the past decade and
are poised for continued reductions. For example, since the 1970s, the cost of solar module
production has declined by 50% for every tenfold increase in production. Recently, the cost
reduction trend has accelerated as global module prices fell by more than half from 2008 to
2011.10
Cost competitiveness significantly accelerates adoption while opening the potential market to
more customers—without additional incentives. The industry has support in its cost cutting
efforts: U.S. Department of Energy’s SunShot Initiative, which sets the goal of making solar
energy systems cost competitive with wholesale power by 2020 (Figure 8).
HISTORICAL DATA: BARBOSE G, WISER R, DARGHOUTH N. 2011. TRACKING THE SUN IV. LBNL. | COST PROJECTIONS: RMI 2010. ACHIEVING LOW-COST SOLAR PV; EIA 2009. DECEMBER SOLAR
PHOTOVOLTAIC CELL/MODULE MANUFACTURING ACTIVITIES 2008.| WASHINGTON, D.C.; EERE 2010. MAY 28 SOLAR VISION STUDY - DRAFT; TRACKING THE SUN IV.
Figure 8
Historical and projected Solar PV costs
Solar costs have declined rapidly and many forecasts expect
that decline will continue.
2010
$/W
$10
$12
$8
$4
$6
$2
$0
2000 2005 2010 2015 2020 2025 2030
Cumulative National Installed Capacity at 2010 $/W
HISTORICAL–2010 PROJECTED FUTURE
Historical
Sunshot Target
EIA (2010)
RMI (2011)
McKinsey-EERE (2009)
GERMANY
17,320MW
Germany
Japan
United States

22DRIVERS OF CHANGE
Meanwhile, a recent surge of interest and investment has led to optimism that new forms of
energy storage will provide increasingly competitive options for managing electricity supply
within the next decade (Figure 9). Projected growth in electric vehicle (EV) adoption will
add a fleet of regularly connected distributed batteries to the grid. In the future, utilities and
grid operators may be able to take advantage of these storage devices to provide the added
flexibility for the electricity grid. (Figure 10).
Enabling Technologies
Information technology is driving remarkable innovations in how electricity can be monitored,
controlled, and delivered throughout the grid. Advanced grid infrastructure, including smart
grid technologies, could further open the market for distributed energy resources by enhancing
distribution network operations and management, potentially mitigating some of today’s
technological barriers to higher penetrations of distributed generation and storage assets.
Grid modernization is already underway. Seventy-four percent of California IOU customers
currently have advanced metering infrastructure (AMI) installed. In four years this technology
will be installed in over 50% of U.S. households.11
Supervisory control and data acquisition
(SCADA) systems and AMI can provide high-resolution network data to system operators,
which can enable dynamic pricing and demand response, thereby providing greater demand
flexibility and creating opportunities for customers to contribute to system balancing.
Meanwhile, new energy management systems for homes and businesses can provide
consumers with better tools and fewer hassles to manage their electric loads and minimize
their bills.
Figure 10
Projected Electric Vehicles in PGE’s Territory
Electric vehicles in PGE’s service territory could number more
than half a million by 2020.
Figure 9
Projected Lithium Battery Costs (2010–2020)
Costs of lithium-ion batteries are projected to decline
significantly by 2020.
$1,200
$900
$600
$300
$0
2010 2012 2014 2016 2018 2020
Li-ion Battery Pack
Cost ($/kWh)
Deloitte (2010)
USABC Goal (2007)
Year
GM (2010)
Nissan (2010)
Argonne (2009)
EIA High
EIA Low
A123 (2010)
Sandia (2008)
EIA Med
1,000
750
500
250
00
2010 2012 2014 2016 2018 2020
TIAX LLC “LOW” (2009)
PGE (2011)
TIAX LLC “Achievable” (2009)
CEC (2009)
CA Air Resources Board
Thousand
Vehicles

23DRIVERS OF CHANGE
service and business model innovation
Innovative ownership and financing arrangements are lowering the barrier to entry for hosts
in the development of renewable distributed generation projects. Leveraging government
tax incentives, many third party entities have proven particularly creative as they shift away
from the customer-ownership model by building systems supported by customer lease or
power purchase agreements (PPAs). Like a mortgage, lease agreements and PPAs allow
system costs to be repaid by users over time, and require little or no money down. Customers
can be cash-flow positive immediately, dramatically reducing the investment hurdle to go
solar. Third-party-owned projects now account for 57% of the market in California (Figure
11). Similarly, in Colorado, the market share of residential customers leasing systems has
grown to 57% in the 18 months since the state authorized leasing structures.
Installed Capacity
(MWdc)
Years
80
60
40
20
0
2009 2010 2011
Owned Residential Owned Non-Residential
Lease Residential Lease Lease Non-Residential
Figure 11
California PV installation (2009–2011)
Third-party owned projects now account for 57% of the California PV market and growing.

24DRIVERS OF CHANGE
The availability of zero- or low-money down leases has had a dramatic impact, increasing the
pace of solar adoption in existing customer segments and opening up markets not available
to system ownership. An NREL study of Los Angeles-area solar project data found that
leased systems increased customer demand for residential PV systems by up to 28% from
2007 to 2011 in Los Angeles and Orange counties. The success has attracted capital: The pool
of financing available to fund leases has grown from $105 M in 2008 to over $1.8 B in 2010.
Additionally, developers with little tax liability have used sale-leasebacks and partnership
flips to enable the development of projects that would otherwise have been uneconomic.
These ownership arrangements involve structuring transactions where investors with greater
tax appetite assume ownership of a system, maximizing the value of available government
incentives.
Cumulative impact: Forecasted Growth
The net impact of technological innovation, cost reductions, and an encouraging policy
environment is rapidly expanding the range of options for onsite generation and management
of electricity. Conservative forecasts by the California Energy Commission of statewide solar
Figure 12
Range of Projected Residential And Commercial PV Adoption Estimates in California (2011–2022)
Solar PV adoption over the next decade is projected to increase from less than 1,000 MW to between 2,900 and 6,500 MW by
2022. Solar PV adoption over the next decade could increase significantly in PGE’s territory.
Source: California Energy Commission, Preliminary California Energy Demand Forecast 2012-22. August 2011.

25DRIVERS OF CHANGE
Figure 13
Gross and Net Residential Solar PV Installed Cost in California (1998–2010)
Solar cost declines should offset the future impact of the sunsetting of state and federal subsidies.
adoption project rooftop PV supplying 5% of total energy needs in 2022—assuming that all
solar adoption would be behind or attached to the customer’s meter. Assuming no adaptive
response in rate policy by regulators, upper-tier residential rates in 2017 could continue to
climb, providing an additional incentive for solar adoption (Figure 12). To the extent that
California enables virtual net energy metering where the solar system can be located at a
significant distance from the customer’s load, the penetration would be expected to be much
higher.
Several interrelated factors will likely sustain growth in the distributed solar PV market even
after current subsidies sunset in 2017. First, the CSI program was designed with subsidies
that step down as the market expands past discrete installed capacity benchmarks. As the
market grows and solar installed costs drop, the state pays a smaller share of the cost of
new installations. The state CSI incentives now have a minimal impact on system costs. The
current CSI level for residential systems in PGE’s territory is $.25 per watt, which results in
a 3%12
cost reduction on the current average system. Second, conservatively projected solar
cost reductions over the next six years will make up for the expiration of the 30% Federal
ITC so that the net levelized cost of energy (LCOE13
to the customer remains the same in
2017 as it is today (Figure 13). Third, today’s solar LCOE, which is estimated to be $0.25 to
$0.29 per kWh,14
is competitive with Tier 3 and 4 rates, supporting the strong growth the
solar market has experienced.
Source: LBNL, Tracking the Sun IV. September 2011

26PotENtial cHallENGESPotENtial cHallENGES 26PotENtial cHallENGES
potEntial
challEngES

27POTential CHALLENGES
Potential
Challenges
Projected growth in the distributed solar market will provide more choices to customers
that are more competitive and environmentally benign while at the same time raising new
operational and cost recovery challenges for the regulated electric utility. The following
section describes these potential challenges in detail.
unpacking the challenge
DG or ZNE customers rely on the grid to meet their needs for power at various times, as
well as to export power when DG output exceeds onsite use. Grid power could either be
used to provide supplemental power or backup for outages (scheduled or unscheduled)
affecting distributed generation. The timing and magnitude of these customers’ needs for
grid service will differ depending upon the sizing and characteristics of the customer’s on-
site technologies and demand and load profile.
Daily Load
Proﬁle
Energy (kWH)
Weekly Load
Proﬁle
Net Load (kWh)
Traditional Full Service Customer DG Customer Zero Net Energy Customer
Traditional Full Service Customer DG Customer Zero Net Energy Customer
2.5
2
1.5
1
0.5
0
-1
-1.5
-0.5
12:00 0:000:00
2.5
2
1.5
1
0.5
0
-1
-1.5
-0.5
2.5
2
1.5
1
0.5
0
-1
-1.5
-0.5
0
20
30
40
-10
10
M T W R F SS
0
20
30
40
-10
10
M T W R F SS M T W R F SS
0
20
30
40
-10
10
Original Demand
Demand After Efficiency
Net Load
Generation
12:00 0:000:00 12:00 0:000:00
Figure 14
A DG customer receives less energy from the utility but
still relies on the grid for power supply and network
services to export power to the grid

In this illustrative example (Figure 14), a traditional full service customer has a typical daily
residential afternoon peak and a relatively consistent weekly demand for grid power. A DG
customer with the same demand for power over the course of the day has her power met
by onsite PV power. During the day, when she isn’t home and solar output is at its greatest,
she exports the power to the grid for her utility to reimburse her at retail rates. Although
the total amount of energy demanded from the grid is smaller than the demand of the
traditional customer, the DG customer’s demand profile has changed substantially. There
are steeper peaks and valleys that the grid will have to meet, especially if many of the DG
customer’s neighbors also decide to install solar PV on their roofs. The ZNE customer, who
wanted to produce as much renewable power onsite as he consumes from the grid, pursued
energy efficiency before adding a large PV array to his roof. The PV power completely
offsets his energy use annually. Therefore, on smaller timescales, such as hours, day and
weeks, the amount that he is importing or exporting vastly fluctuates. In fact, the ZNE
customer’s peak demand on the grid could be when he is exporting power. These phenomena
represent a fundamental shift in the formerly one-way power system from both a technical
and institutional perspective.
Under existing rate structures, typical residential customers are charged a bundled volumetric
rate. These bundled rates are designed to reflect estimated total costs incurred by the utility
to serve customers, including the variable and fixed costs required to generate and deliver
electricity. These rate structures have the virtue of simplicity, and they provide strong
incentives for energy efficiency, but they do not allocate fixed and variable costs to separate
charges (see Traditional Electricity Rates text box). Therefore, under the volumetric rate
structure, energy generated on the customer side of the meter displaces grid power at the
full retail rate. Further, under retail net metering, customer generation exported to the grid
is also credited at full retail rates. DG customers on volumetric rates who export as much
or more generation as they consume from the grid can reduce their bill to zero through
the power exported to the grid. Further, many customers on time-of-use (TOU) rates can
actually zero out their bills—excluding minimum charges—while remaining net consumers
of electricity from the grid.

Traditional Electricity Rates
The traditional costs of service are fixed and variable. Variable costs change as a function of volume. For example, the
variable cost of generating electricity includes the change in costs associated with the production of an incremental
kilowatt-hour—primarily fuel and variable generator operations and maintenance costs. Fixed costs include all capital
investments in capacity, including generation, transmission and distribution, billing systems, and customer service
call centers required to supply electricity and service each account. Fixed costs are a function of not only the highest
level of electricity demanded by customers, but also the magnitude and timing of that demand. If the customer’s
electricity demand adds to the amount of generation, transmission, and distribution capacity the utility must build
and maintain, then this adds to what are generally considered to be the utility’s fixed costs.
Traditionally, utilities have used “bundled” rates for estimating charges for smaller customers, while using more
complex pricing structures for larger customers. For example, residential and small business customers are typically
charged a single volumetric rate ($/kWh) and possibly a customer charge, while larger commercial and industrial
customers may see two or three charges, such a volumetric energy charge combined with a demand and/or
customer charge. The distinctions in rate structures among customer classes are driven by the historical premise
that smaller customers with smaller bills have less motivation, necessary sophistication or the needed tools to
respond to complex price signals.
Figure 15
Conventionally, utilities have bundled service costs, which are re-allocated by rate design
Costs of Service
Revenue Requirements
Cost Allocation
Rate Design
CUSTOMER SERVICE
DISTRIBUTION CAPACITY
TRANSMISSION CAPACITY
GENERATION CAPACITY
ENERGY
OPERATIONS
FIXED COSTS
TRANSMISSION DELIVERY
DISTRIBUTION DELIVERY
RATE OF RETURN
GRID STABILITY
(Ancillary Services)
SUPPORT
(Billing, Metering, etc)
INDUSTRIAL
COMMERCIAL
RESIDENTIAL
$/yr
DEMAND CHARGE
Costs of the generation,
transmission and distribu-
tion capacity to serve peak
demand
ENERGY CHARGE
kWh-based generation costs
(e.g., fuel, wholesale
electricity)
CUSTOMER CHARGE
Flat monthly charge
covering ﬁxed costs of
servicing customer
regardless of use (e.g.,
billing, customer service)

Traditional, Full Service Customer
This customer, whose load proﬁle is
average for the type of residential
customer likely to install DG under NEM,
pays for her electricity on PGE's E-1S
schedule. On average, the utility fully
recovers its costs.
Distributed Generation Customer
The customer installs a PV system that
meets part of her annual energy use.
Under current rates, the utility is likely to
under-recover its costs to serve such a
customer, but the results depend on
usage, load shapes, and other factors.
Zero Net Energy Customer
The customer installs a PV system that
meets ALL of her annual energy use. The
utility receives no revenue even though the
customer still uses to the utility's network as
a battery.
Distributed Generation
Cost Savings?
Figure 16
Residential Net Energy Metering Under Tiered, Volumetric Rates
Under existing rate structures, the cost of providing service to DG or ZNE customers may not be
recovered, or the value created by DG not recognized.
Figure 16 shows a traditional full service utility customer without a DG system and pays the
utility $2,445 a year. Her payment covers the fixed and variable costs to provide generation,
transmission, distribution and other services, such as billing and energy efficiency. If that
customer were to generate 50% of annual energy needs from a rooftop PV system, she could
reduce her annual bill to $757 (since they offset higher tier usage first). If she generated 100%
of her annual electricity needs from a PV system, becoming a zero net energy customer, then
she could reduce her average utility bill to effectively $0. However, the utility still incurs
costs to serve a zero net energy customer who is exporting and importing power via the
distribution system. If these costs are not outweighed by the benefits associated with the
DG, such as the value of displaced energy or avoided distributed system costs, the under-
collection of the cost to serve DG customers will result in a cost shift to other customers on
the grid in the form of higher rates.

31PotENtial cHallENGES
imPlicatioNS
Adisconnect between service and value flows creates multiple misalignments along economic,
social and technical dimensions that may result in higher system costs and unrealized benefits.
These misalignments can occur across several dimensions:
cost allocation The cost or value of the energy, capacity, delivery, and grid support
services that sustain the electricity system are not being appropriately priced or allocated,
distorting the value of customer-side energy and infrastructure.
Equity Amisallocation of who is paying and who is benefiting creates significant equity
issues between NEM customers and non-NEM customers.
operations At the distribution level, the grid’s operational needs are not valued, such
as the importance of reliability, safety, flexibility, predictability, where and when service
is needed or the cost of energy at the distribution feeder level.
figurE 17
miSaliGNmENtS aloNG multiPlE DimENSioNS
multiple misalignments along economic, social and technical dimensions that
may result in higher system costs and unrealized benefits.
A DISCONNECT BETWEEN
SERVICE AND VALUE FLOWS
CREATES MISALIGNED INCENTIVES:
What are the misalignments and where are they occurring?
Social Equity
Costs not paid for by DG customers
are borne by all customers.
DG and DSM
service providers
DG Customers
Non DG Customers
Utility/Grid
service$$
DG DSMDG DSM
Cost Allocation
To the utility, revenue from DG
customers may not match the cost
to serve those customers. Further
the cost of integration—balancing
supply and demand—is not
transparent.
Social Priorities
Society values the environmental are
allocated to non-DG customers benefits
that distributed renewables provide, but
utility has little incentive to encourage it
due to rate impacts.
Flexibility and Predicability
Providing reliable power
requires grid flexibility and
predictability. Power from
distributed renewables fluctuate
with the weather, adding
variability, and require smart
integration to best shape their
output to the grid.
Location and Time
Limited feedback loop to
customers that the costs of
service and value of DG, DR and
EE vary by location and time.
Value Recognition
Mechanisms are not in place
to recognize or reward service
that is being provided by actor
(utility or customer).

Cost allocation
As customer-generators offset their energy use, they are reimbursed at their retail volumetric
rate, which includes the fixed costs that the utility incurs on their behalf. If these costs are
not outweighed or offset by the benefits from the customer generator, the result is revenue
from these customers that declines to a greater degree than the cost to serve them; essentially,
current volumetric rates do not appropriately charge these customers for the service that
they receive from the utility, and may not appropriately credit them for the services that
they provide to the utility. A further misalignment is created between the large number of
customers paying volumetric rates and the fixed-cost nature of the utility’s cost of service.
The utility must spread costs over a reduced number of kilowatt-hours, which results in
higher rates, resulting in inequity among customers.
Although energy efficiency creates some similar cost shifts, there are several distinguishing
characteristics between energy efficiency and DG: 1) The number of customers that invest in
and accrue benefits from energy efficiency investments are greater and more widespread than
customers currently investing in DG; 2) At current costs, energy efficiency investments result
in lower costs from a total resource perspective, whereas DG still requires some subsidization;
3) Energy efficiency has smaller operational and planning impacts on the grid, such as the
need for providing instantaneous power when a distributed generator fails.
Equity
Where DG customers do not cover costs incurred for their grid service, these costs will be
borne by other customers, resulting in inequity between NEM and non-NEM customers.
Such rate increases, which are could be largely borne by upper-tier customers under existing
rate structures, could lead to even higher rates of adoption, creating an unsustainable cycle.
MAXIMIZING VALUE BY ALIGNING WITH SYSTEM NEEDS
The degree of impact and value of DG and ZNE technologies to the grid depend on the
correlation of their timing and magnitude to the needs of the system. However, currently DG
or ZNE customers receive no signal to help shape their interactions with the grid to minimize
costs or maximize value. For example, without a price signal to customers that indicates the
value of energy throughout the day, net-metered solar customers’ natural incentive would be
to maximize the annual electricity output of their PV system. Thus, they would position their
PV systems to maximize total energy output through a southern orientation. However, in a
utility system that sees its peak loads in the midafternoon, as most do, a western-orientation
solar system would provide power at the time in which energy is most valuable—at or

figurE 18
tHE oriENtatioN oF Solar Pv imPactS itS caPacity aND ENErGy valuE to tHE GriD
At present, solar owners
have incentive to
maximize energy
production (kWh) with
orienting their solar
panels to the south.
Orienting panels to the
Southwest or West
could produce less
kWh, but that energy
production would be
more aligned with the
utility peak, when the
cost to produce power
is at its highest.
near the system peak (Figure 18). A time-differentiated price signal, such as time-of-use
(TOU) pricing, could better match system needs by providing the incentive to increase peak
contribution through customer solar production.
Further, from a planning perspective, the rise in DG popularity means an increasing flow
of investment in generation capacity will occur outside of the control of the utility, either
through capacity investments made on the demand side of the meter by customers or third
parties on behalf of customers. Based on publically available renewable and thermal power
plant power purchase agreement (PPA) contracts, the California Solar Initiative goals and
Gov. Brown’s targets for distributed renewables, one quarter of the cumulative investment
in capacity out to 2020 could be made by the customer.16
This could make system planning
more challenging for the utility. Virtual power plants composed of distributed assets could
begin to provide a significant contribution to the balancing needs.

achiEving zEro-nEt EnErgy: talE of two buildingS
a university campus that wishes to be “net zero” can accomplish this goal in a number of different ways—each
with different value or impacts to the grid. one method would be to add as many solar panels as required to
generate as much electricity as the campus consumes in a year. another method could be to install a cHP system
with thermal storage and microgrid controls to shift loads in response to price signals. Each of these methods
would result in a net zero campus, but the solar solution would require the utility to provide more generation and
tD capacity as well as incur higher integration costs compared to the cHP/storage/microgrid solution (Figure
19). with volumetric prices, there is no incentive for the customer to adopt the solution that minimizes impacts
on the electricity system and thereby minimizes the impact on utility rates for all customers.
figurE 19
accomPliSHiNG “NEt ZEro ENErGy” caN HavE vEry DiFFErENt GriD imPlicatioNS
5
0
10
15
20
25
30
1 12 24
Demand(MW)
Hour of the Day
Load
Solar PV
-20
-15
-10
-5
0
5
10
15
24121
Demand(MW)
Solar PV
Daily 30 MW grid usage
0
5
10
15
20
25
30
1 12 24
Demand(MW)
Hour of the Day
Original Load
Load w/ EE
Load w/ EE
DR
-20
-15
-10
-5
0
5
10
15
1 12 24
Demand(MW)
Hour of the Day
Hour of the Day
Energy Efﬁciency, Demand Response, then Solar PV
Grid usage cut to 10 MW

35aPProacH to SolutioNSaPProacH to SolutioNS 35aPProacH to SolutioNS
approach
to SolutionS

36APPROACH TO SOLUTIONS
Approach
to solutions
Tensions among different stakeholder views about the future implications of increased
adoption of distributed solar in California are already beginning to play out in regulatory
and political proceedings. There is a growing possibility that these differences in perspectives
could result in prolonged and increasingly polarized conflict over policies, including utility
rate design and net energy metering. Ultimately, however, it is important to find common
ground among these different views in order to devise a sustainable electricity system that
includes higher penetrations of distributed and renewable supplies while maintaining a
healthy and reliable grid.
To move toward this goal, three basic issues must be addressed:
Identify, Measure And Communicate Impacts, Costs and Values
Remedy Misalignments Through Innovative Pricing Models
Adapt Utility Business Models To Create and Sustain Value
Identify, measure and communicate impacts,
costs and values
Building a shared understanding among stakeholders and regulators in the electricity sector
about the full range of costs and benefits of distributed energy resources and the implications
of net energy metering is an essential first step toward devising rates and incentives that
will create the greatest benefit for all. With limited experience of the integration of high
penetrations of distributed energy resources, many questions remain to be answered about
the net impacts. In addition, changes in technology, including new inverters and storage
technologies, could have significant implications for costs and benefits in the future.
At present, although the lack of tools and analysis to fully address these questions remains a
stumbling block, a growing number of studies are beginning to fill this void. Recently, four
utilities have published analyses on the impacts of high penetrations of distributed PV systems
within their service territories. The studies range in scope from impacts on the distribution
system to regional balancing operations. The range of results is indicative of the case-specific

nature of determining the impacts of distributed energy resources on utility operations and
planning (Figure 20). Several ongoing utility studies of the impact of high penetrations of
distributed energy resources on their networks will add to the existing body of knowledge
over the next several years (Figure 21).
Utility
(Year Completed)
Sacramento Municipal
Utilities District (2009)
Arizona Public service Southern California
edison (2011)
Nevada Energy (2011)
Measured distribution impact from
238 kWac PV on 115-unit ZNE sub-
division with eventual buildout of
1.2 MWac. The model will inform
the acceptable level of penetration.
Evaluating the potential value of
distributed solar resources to APS
generation and TD systems
based on three penetration
scenarios of PV adoption to 2025
Identifying PV system models
and distribution system
analysis tools to integrate high-
penetration PV levels. Reviewing
advanced inverter functionality.
Variable PV generation impact
on system operations, balancing
reserve requirements, and the
ability of the existing generation
fleet to accommodate increasing
amounts of large-scale PV and
DG in South NV.
While it is possible to see the effects
of PV on the voltage at homes and
distribution transformers, PVs
have not adversely affected voltage
regulation and provide a large
potential for peak demand savings.
APS’ required upgrades and
growth prevent any system
deferrals until 2025. Upgraded
transmission lines are inherently
“lumpy” capacity additions. PV
only obviates the need when
it is widely adopted. High
penetrations shift the peak later
in the day.
Current distribution system
modeling tools do not
adequately model solar PV
systems. New capabilities are
needed. Advanced inverter
functionality can clearly facilitate
high penetration PV.
Spatial diversity mitigates some
of PV’s intermittency. For all
penetrations of DG or PV of up
to 15% of NCP load, additional
balancing reserves are needed for
regulation and load following.
These costly operations run
CCNG/CT less efficiently, require
more unit starts, and ramp them
faster.
Costs or Benefits
Generation
Capacity
PV operation at 40 to 58% (S and
W orientation, respectively) of
rated output available during peak
periods on SMUD’s system
0–1.8 ¢/kWh for central gen
deferrals
Unquantified 0–0.5 ¢/kWh (2011) for fast
ramping, OM.
Energy
7–8.2 ¢/kWh for fuel power,
losses
Unquantified 0.3– 0.8 ¢/kWh (2011) for
additional regulation units.
Transmission
Distribution
Capacity
PV Penetration (at light loading of
4% of transformer, 13% of feeder)
created no excessive service or
substation voltage from reverse
power flow. 40% penetration TX
had 0.16% V rise.
0–0.8 ¢/kWh for TD deferrals Unquantified Unquantified
Energy
0.8–3 ¢/kWh for mainly Tran
OM savings
Unquantified Unquantified
GridSupport
Not adversely affected voltage
regulation. address peak demand.
Dependable PV capacity
diminishes with Increased
penetration as a result of pushing
peak demand later.
Lower TD loss and switching
operations with advanced
inverters. Ramping, frequency
regulation, power balancing.
Large scale PV does not violate
steady state voltage, transient
voltage stability, or thermal
loadings.
Figure 20
Recently Published Studies on Distributed Generation Impacts

Hawaiian Electric Company (Heco)
APEC workshop on renewable energy grid integration systems (2009)
Arizona Public Service (AzPs)
Distributed Renewable Energy Operating Impacts and Valuation Study (2009)
University of California San diego
Modeling tools (2010-12)
Clean Power REsearch
Advanced modeling (2010-12)
Sacremento Municipal Utility District (SMUD)
Anatolia (2010-2012)
Nevada Energy
Large Scale PV Integration Study (2011)
Arizona Public Service (AzPs)
Flagstaff (2009–2013)
SunPower
Resource forecasting (2010–2012)
National Renewable Energy Lab (NREL)/
Southern California Edison (SCE)
California (2010–2014)
PGE/university of california Irvine
Integration limits (2011–2013)
Colorado Governor’s Energy Office
Solar PV and small hydro valuation
Virginia Polytechnic Institute State University
Power conditioners (2010–2014)
San Diego Gas Electric / (SDGE)
california independent system operator / (CAISO)
University of California San diego (UCSD)
System forecasting (2011–2013)
Florida
Resource variability (2010–2015)
Utility Pilots
Demonstration Projects
2010
2013
2015
Figure 21
Ongoing Studies on the Impacts of DG
Several utility projects and collaborative
demonstration projects will add to the existing
body of knowledge.
The challenge is that the degree of impact and value of distributed resources to the grid
depend on the relationship among timing, magnitude, and location of distributed supplies
and to the needs of the electricity system. Put another way, DG that is at the “right place at
the right time” will create the greatest value. Additionally, the value of distributed resources
is affected not only by timing and location, but also by the flexibility, predictability, and
controllability of the resource.
For example, the capacity value of distributed energy resources, especially DG, is highly
geographically specific and varies by distribution feeder, transmission line configuration,
and composition of the generation fleet. Further, capacity investments, such as transmission
upgrades or centralized generation plants, are “lumpy” in nature; therefore, it is necessary
to determine the sufficient capacity demand reduction to avoid or defer transmission system
investment. Thus, the capacity costs and benefits are highly variable and non-linear in
nature, with the greatest value accruing in places of high system congestion and at times
of peak demand.

FIGURE 22
High Penetration of DG could have positive or negative impacts across the electricity value chain
At the system level, large scale adoption of DG results in impacts that
could translate into new costs or new sources of value and for different actors.
PLANNINGOPERATIONS
GENERATION TRANSMISSION DISTRIBUTION
Reduced Capacity
for Thermal
Generators
Increased Cycling
of Thermal Units
Physical Flexibility on
Grid of Increased
Value Increasing
Complexity For
Balancing
Requests for
Interconnection
on Distribution Network
Days
Increased Ramping
and Ramp Rates
Avoided Fuel
and OM Costs
Avoided
Line Losses
Need for
Bi-drectional
Power Flows
Increased Demand
Vulnerability and
Uncertainty
Hours
Reduced System
Inertia
Peak Power Resources
Include Demand Response,
Displacing High Marginal
Cost Productions
Need For Protection
Coordination
Need for
Voltage Control
Unintentional
IslandingMinutes
Seconds
Avoided/Deferred
Generation
Capacity
Avoided/Deferred
Transmission
Investment
Distribution Circuit
Redesign
or Upgrades
Increased
Generation
on Distribution
System
Increased Demand
Variability and
Uncertainty
Years
Avoided/Deferred
Distribution Investments
Distributed Generation: Potential Sources of Value
Depending upon the type and amount of DG at individual nodes on the distribution system, strategic deployment
could result in net benefits across the electricity value chain, including generation, transmission, and distribution,
as well as across varying time scales, from real-time operations to long-term planning (Figure 22). The potential
benefits of DG result from the installations’ inherent characteristics: they are smaller in unit size, can be constructed
in shorter lead times, and can be installed closer to demand. From an operational perspective, the potential
value to the utility network from DG depends on attributes including variability, predictability, and contribution
to peak supply.
Displacing Conventional Generation By displacing the
need to produce energy from conventional sources, DG
could decrease fuel and purchased power requirements.
Additionally, onsite thermal generators like mini-CHP plants
or fuel cells can also often reuse waste heat nearby, displacing
fuel and equipment.
Reducing Line Losses Line losses average between 6-7%
but can double when demand is high and lines are strained.
Generation produced at or close to demand can obviate these
losses.
Reducing Transmission Investment By pinpointing
congested, high-cost areas, DG could be deployed reduce
the use of strained transmission or distribution capacity,
thereby reducing or deferring the need for additional capacity
investments.
Reducing Financial Risk Associated With Larger Scale
Investments Distributed resources’ combination of short
lead time and small unit size lets utilities reduce financial
risk by building capacity in increments more closely matched
to changing customer demand.
Deferring or Reducing Grid Investment By pinpointing
congested, high-cost areas, DG could be deployed to reduce
the use of constrained transmission or distribution capacity,
thereby reducing or deferring the need for additional capacity
investments.

40aPProacH to SolutioNS
More research is needed to quantify these impacts in order to create pricing or incentive
structures that properly account for the costs or benefits of these resources. Such analysis will
require evaluation of impacts of distribution system capital and operating costs, balancing
costs, fuel use and a wide range of other considerations. New data collection and analysis
methods will be necessary to develop estimates of these costs and benefits while ensuring
accountability, transparency, and verifiability of cost and benefit estimates that will provide
the foundation for policymaking.
rEmEdy miSalignmEntS through SuStainablE pricing modElS
Electricity rate structures that bundle the utility’s many disparate costs into a single volumetric
rate provide customers with simple electricity bills together with strong incentives for
energy efficiency and distributed generation. With significant penetration of customer-level
generation and net metering, however, this pricing model begins to break down. Under
current volumetric rate structures, net metering does not accurately recover the costs of a
customer’s use of the grid network and, simultaneously, it may not be compensating the
customer for the value of the power they are providing.
pErSpEctivES
can rooftop Solar pv gEnEratE Significant coSt SavingS in thE
ElEctric utility diStribution SyStEm?
yES. adding solar generation capacity can reduce distribution systems costs
in a variety of ways. increased distributed supply can prolong lifetimes of
transformers and other equipment on the utility system by regularly reducing
loads during peak periods. where solar Pv supply is reliably correlated
with peak demand, distributed supply may allow utilities to avoid or defer
capacity expansion in parts of the distribution system. the experience
of regional transmission organizations (rtos) such as Pjm indicates
that distributed resources have provided a large share of the resources
procured through capacity auctions. in the long run, if there are appropriate
incentives, distributed solar, coupled with electricity storage and necessary
communications and control equipment, may be able to provide increased
capacity value to the electricity grid. Eventually, with advanced inverters,
solar systems may even help to provide voltage regulation and reactive
power on distribution system feeders.
no. all the assets on the distribution system
are needed to serve energy deliveries and
energy exports for electricity customers.
utility rooftop Pv provides little or no offset
to the amount of distribution capacity that
the utility must provide, since the utility must
stand ready to provide electricity supply to
customers when solar power is not available.
Solar power supplies may not correlate well
with system peak electricity demand, so
capacity requirements on the utility system
may not be reduced even under the best
of circumstances. in some cases, high
penetrations of distributed solar power may
necessitate making additional investments in
the distribution system to handle the power
exported by solar systems at periods of peak
supply.

aPProacH to SolutioNS
yES. the lack of cost recovery from fixed charges in residential rates, for example,
customer charges or demand charges, has caused the upper tier rates to be
higher than they otherwise might be. industrial customers, for example, pay
demand charges. the current exemption for solar customers from standby
charges and generation-related stranded costs has hampered the ability of
utilities to recover the appropriate level of costs when customers choose to
install solar systems. as a result, customers with solar Pv are being subsidized
by other customers who pay higher rates to cover the costs of service to these
customers. in the long run, this could result in a vicious cycle of rate increases
on upper tier customers leading to further solar Pv adoption—a “death spiral”
scenario for the electric utility.
no. rate designs with minimal
fixed charges create the strongest
incentives for energy efficiency
and solar investments, and are
therefore aligned with social and
policy objectives. increased fixed
charges would reduce incentives
for efficiency and solar and
reduce incentives for utilities to
aggressively manage costs.
The generation of onsite power is not in itself flawed; rather, the problem is rooted in the
underlying rate structure. Moreover, the combination of traditional rates and net energy
metering incentives do not provide price signals that incent the customer to provide the
greatest possible value to the electricity system. As a result, investment in new DG capacity
may be made without regard to how the timing and location of those resources will influence
power system operation. Existing rates and policies obscure the costs and benefits of distributed
resources to the grid, limit the ability to add smarter integration technologies, which could
add value, and restrict signals to the customer that would enable them to make mutually
beneficial decisions. These misalignments may be negligible at low penetrations of DG, but
as the share of distributed generation increases they become significant.
Legislative and ratemaking changes may be necessary to create a sustainable long-term path
for distributed resource development. Utilities and their regulators are considering new
and modified rate structures that provide the price signals necessary to promote and realize
the full value of not only DG, but also EVs and the Smart Grid. Rate design should ensure
two things: that utilities receive adequate compensation to cover their prudent costs, and
that those costs are distributed among customers equitably, so a customer’s electricity bill is
representative of the value of the services provided to, and by, that customer.
In developing new rate structures, utilities will be forced to reexamine the fundamental
elements of the “cost to serve”—capacity related fixed costs, non-capacity-related fixed costs
and variable costs17
—and the allocation of these costs as they pertain to customer-generators.
For example, distributed generators produce power that directly displaces generation from
pErSpEctivES
Should california’S utility ratES Shift toward grEatEr fixEd chargES?

centralized power plants. One issue is the true value of this power—and, therefore, the rate
at which it should be credited—since generation costs are only a portion of the full cost of
electricity service and vary. In addition, a straightforward assessment of the value of power
from DG is complicated by the temporal and locational variability in the costs and benefits
of individual systems. Distribution feeders with large amounts of DG capacity downstream
may require upgrades to maintain power quality, or, conversely, if implemented carefully
and thoughtfully, may alleviate congestion and potentially defer the need for upgrades.
To equitably distribute costs, a utility cannot simply levy energy, demand, and customer
charges equally across all customers. This would require individual customers to be charged
for the cost to provide them with service, and also compensated for any value that they
create. In reality, however, cost causation principles are not the only factor that utilities must
take into account during the ratemaking process. Technological constraints limit the level
of specificity that rates may have and determine the degree to which time and location may
be valued, while the potential consequences in terms of load shifting and load growth (or
reduction) must also be considered. At the same time, for any rate structure to gain PUC
approval it must strike a balance between the interests of traditional customers and customer-
generators, while remaining simple enough to be understood by customers. The utility must
ask: can the pricing model pay for operational services, properly capture and promote value
yES. revising net metering rules and utility rates will reduce the conflicts
created by the cross-subsidy implicit in the current rate system which requires
that customers without solar systems pay part of the cost of utility services to
those customers with solar. revised net metering rules could level the playing
field to reduce or eliminate these cross-subsidies and provide a stable revenue
model for the utility for the future in the event of high levels of solar adoption.
Net metering 2.0 might unbundle charges so that the utilities could recover
revenues for customers’ use of the distribution system wires to export power to
the grid and provide more refined incentives for customers to install systems and
manage their energy use to create the greatest benefit for the electricity system.
No. revising net metering rules
today would slow the adoption of
rooftop solar Pv, resulting in the
loss of jobs in the solar industry.
Net metering socializes the costs
and benefits of distributed solar,
which is reasonable in view of the
societal benefits of distributed
solar power.
pErSpEctivES
Should california implEmEnt a rEviSEd approach to nEt mEtEring,
ESSEntially “nEt mEtEring 2.0?”

to the system, and be implemented effectively with the flexibility to accommodate a changing
system? On their own, many pricing models pay for different services or capture sources
of system value, but few meet all of these criteria. However, smart combinations or hybrids
of pricing models may ultimately create a nimble system that pays for required services,
maximizes value, and allows for effective implementation.
San Diego Gas and Electric Company (SDGE) provides an example of a utility attempting
to modify its rates as it prepares for higher penetrations of DG. As part of its General Rate
Case in October 2011, SDGE proposed modifying its residential electric rates to include a
“Network Use Charge,” which would bill customers for the costs associated with network
use.18
Figure 23 shows the portion of the costs to serve a residential customer encompassed
by the Network Use Charge. Currently, customers utilizing NEM avoid paying for these fixed
Figure 23
Cost Allocation For Residential Customers
SDGE’s Network Use Charge addresses the demand-related fixed
costs that are currently contained within standard volumetric rates.
Distribution Demand*
Distribution Customer*
14%
12%
26%
39%
4%
5%
Transmission
Public Purpose Programs
Other
Electric Commodity
The Network Use Charge
addresses this portion of
residential costs.
* SDGE cost studies identify two cost components to the distribution system for providing
service to customers: customer costs and distribution demand-related costs.

costs. SDGE proposed to measure a customer’s absolute demand as a basis for the charge,
which would account for the fact that when a customer-generator has negative demand—
therefore exporting power—the customer is still in fact using the utility’s network (NEM vs.
NUC). Proponents of the Network Use Charge note that it would allow SDGE to ensure that
NEM customers pay for their fair share of distribution system costs when exporting power,
while reducing the inequitable cost shifts that result from retail NEM. However, the measure
met with fierce opposition from the solar industry, consumer advocates, environmentalists,
and NEM customers. These groups argue that the Network Use Charge does not account
for the benefits that DG systems provide to the network, that it runs contrary to California’s
renewable energy goals by discouraging solar, and that it does not send price signals that
encourage reduction in coincident peak demand—rather, it pushes PV owners to shift their
demand to times when their system is producing, i.e. midday.
SDGE’s Network Use Charge illustrates the difficulty of the challenge, and of how sensitive
the many stakeholders are to the implications of any proposed change to existing rates. An
acceptable solution will be needed to balance the needs of the network with the concerns
of its stakeholders, which will likely require compromise from both sides. This process will
ultimately create new profit opportunities that, given the right price signals, will allow
distributed generators to adapt and provide new sources of value to the utility system.
Figure 24
SDGE’s Proposed Network Use Charge
The Network Use Charge would measure the absolute value of a customer’s demand,
accounting for network use by NEM customers when exporting power.
TODAY
Residential Net Metered Solar Customer
PROPOSAL
Residential Network Use Charge Solar Customer
Demarnd
(kW)
3
2.5
2
1.5
1.0
0.5
0.0
-0.5
-1.0
-1.5
0:00 12:00 0:00 0:00 12:00 0:00
IMPORTS
FROM GRID
EXPORTS
TO GRID
1.2 kW avg. for
Network Use
Charge

Adapt utility business models to create and sustain value
While the steps described in previous sections of this report are necessary to address
misalignments in existing institutional and pricing structures, they are not sufficient to
provide a long-term, sustainable foundation for the electricity system. The key drivers that
are transforming the electricity industry—slow or declining demand, increased variable
renewable generation, increased customer generation and energy management, and
environmental priorities—will continue to alter revenue streams, sources of value, and
operational requirements for electric utilities. This, in turn, will necessitate further evolution
and adaptation of utility business models.
Important steps have already been taken in California to shift the utility business models
toward new approaches that align utilities’ profit motives with social priorities and emerging
market realities. For example, revenue decoupling breaks the link between electricity sales and
utility profits. However, basic elements of the utility business model still must be addressed.
The key question, as framed by roundtable participants, is: What are the functions that
utilities will perform in the future and how should we create mechanisms to appropriately
compensate utility companies for performing those functions?
Utility business models are largely shaped, but not completely determined, by the regulatory
policies. With the rapid growth of distributed resources that provide increasing alternatives
for customers, new questions are emerging about the role of the utility and other actors.
Should the utility be allowed to own and operate distributed resources on its customer’s
premises? What incentives should the utility have to ensure that distributed resources are
fully deployed to minimize costs for the system as a whole? If the utility is allowed a more
expansive role in owning and/or managing distributed energy assets, will this unfairly
crowd out other competitors?
Roundtable participants discussed the relative merits of two approaches to regulating electric
utilities’ roles and activities in these areas:
New forms of incentive regulation to support a more expansive role for utilities in
managing distributed resources
A more limited network utility model that relies on highly differentiated price signals
to direct investments in distributed resources by customers or other intermediaries
for greatest system benefit.
While these approaches suggest different emphasis in how to overcome the limitations
inherent in existing policies are not mutually exclusive, so solutions could be constructed
with elements from each.

New approaches to incentive regulation could provide utilities with stronger motivation
to direct and manage investments in distributed energy resources. Performance incentives
include performance based earnings, shared savings, and incentive rates-of-return. These
mechanisms could be used to reward utilities for performance in achieving distributed
resource deployment targets, and in doing so in a way that minimizes costs for the system
as a whole. In the same way that revenue decoupling and shared savings policies together can
provide strong incentives for utilities to invest in energy efficiency, a similar approach could
strengthen incentives for utilities to invest in distributed generation, storage, microgrids, smart
electric vehicle charging, smart inverters, or other distributed technologies to reduce operating
costs and/or defer or avoid the need for investments to expand capacity of distribution
feeders or invest in other electricity supply, transmission, or distribution assets. Under some
scenarios, the utility might be allowed to invest in and earn a return on assets on the customer
side of the meter that offer the least-cost means of delivering service.
Proponents of this approach argue that utilities are in the best position to understand how
and where to deploy distributed resources for greatest system benefits and should be allowed
greater freedom to direct these investments to the areas on their system where they provide
the greatest value. Moreover, performance incentives should ensure that utilities earn more
by finding the least-cost ways to address system needs. If it costs less to deploy distributed
resources in a targeted fashion than it would to make rate-based investments to reinforce
or upgrade the grid, then utilities should be made better off by implementing the solutions
that costs customers the least.
The portfolio of distributed resources available to the utility might include a wide range
of assets and technologies, from distributed generation and storage to microgrids that
enable control and dispatch of local resources in response to price signals from the grid.
Under this model, the utility would fill the role of both network orchestrator and service
provider. The utility would continue to perform many of the key functions of a historically
vertically integrated utility, such as ensuring reliable power delivery, as well as owning
and operating some generation resources. It could offer a variety of emerging new services
that are enabled with the technological advances in distributed generation, grid intelligence
and communications. The utility would have incentives to deploy distributed resources
wherever doing so could reduce the cost of providing electricity services. This approach
would require significant changes in the current regulatory paradigm to ensure a level playing
field for service providers, including energy service companies and other onsite generation
providers. A key challenge is that alternatives to the conventional return-on-rate base, such
as performance-based regulation, have proven complex and difficult to execute.
Incentive regulation can take relatively simple forms. For example, legislation introduced in
the U.S. Senate by Senators Amy Klobuchar (D-MN) and Tim Johnson (D-SD) in the summer
of 2011 proposed a “Renewable Integration” tax credit to offset the costs of integrating wind

APPROACH TO SOLUTIONS
and solar resources to the grid. The tax credit would provide an incentive for utilities to adopt
more renewable power by offering a tax credit of up to 0.6 cents per kWh for power supplied
from variable renewable sources such as wind and solar. If utilities can integrate supplies
from these sources at costs less than the level of the tax credit, they can profit accordingly.
Under a network utility approach, the utility would provide highly differentiated price
signals to direct investments by other service providers. In this case, the utility’s role would
increasingly be focused on maintaining and operating the grid and on creating markets,
managing transactions, replacing aging distribution equipment, and/or making smart grid
investments and interconnecting buyers and sellers with the network. This network utility
would shepherd and coordinate the network of increasingly complex transactions among
growing number of actors. The utility in this scenario would evolve toward a role more like
that of grid owner/operators at the wholesale level, enabling markets for energy, capacity,
reserves, and ancillary services that differentiate value for these services according to time
and location.
New product revenue streams to achieve profitability would include investments that improve
network operations and facilitate market. Key challenges in this paradigm are determining
how a network utility should be compensated as the enabler of the network and in setting
benchmarks for performance.

nEw formS of incEntivE rEgulation could allow the utility to innovate and meet customer’s changing needs
while expanding its range of offerings to ensure the vitality of a functioning electricity system. under this approach,
the utility would have incentives to invest in owning and operating distributed resources on customers’ premises, or
to contract for other entities to do so, where such investments could reduce the overall costs of providing electricity
services. the costs and benefits of distributed resource development would be fully socialized, and the utility would
have strong incentives to achieve all available cost savings from distributed resource deployment. the utility might
be required to outsource distributed resource deployment to other companies, but would ultimately manage where
and how such resources would be deployed. the utility has the responsibility for maintaining reliability and serving all
electricity customers fairly. under an incentive regulation approach to distributed resource development, customers
that cannot invest in distributed resources or take advantage of solar lease offers would not be disadvantaged.
these customers might, for example, participate in utility programs that oversee the installation of solar panels at
optimal places within the utility system on behalf of such customers, providing benefits similar to those available
from rooftop systems.
thE nEtwork utility modEl is the right approach because it allows the competitive
markets to direct the provision of innovative technologies and services to customers, while
providing incentives that reflect the costs and benefits to the grid from distributed resources.
the utility isn’t the most efficient or cost effective provider to install distributed resources on
the customer’s side of the meter, or even to manage such investments through contracting
to third parties in today’s rapidly changing environment. the utility of the future will look
increasingly like today’s independent system operators: providing time-varying price signals
via the grid that encourage other companies to make customer-level investments to create
value by providing energy supply, managing load shapes, or providing ancillary services to
help manage the grid.
pErSpEctivES
what iS thE bESt approach for adapting utilitiES to 21St cEntury
ElEctricity innovation?

Looking Ahead:
Future Challenges and Opportunities
The rapid growth of solar PV adoption by electricity customers in California foreshadows
far-reaching changes in the state’s electricity system in the decades ahead. As costs of solar PV
systems continue to fall, it is clear that this technology can play a significant role in helping
to build a bridge to a low-carbon energy future. At the same time, important questions are
arising about how best to design electricity rates and policies to ensure that solar power
and other distributed resources are developed in a way that provides greatest benefits to
electricity customers and to society as a whole. Policies created to stimulate the growth of
the solar industry in its early stages will need to be modified as the industry matures, new
technologies emerge, and impacts on the utility system increase. Ideally, these policies will
provide incentives for deployment of solar power in ways that create the greatest value for
the system as a whole, while simultaneously benefitting the customers that adopt solar.
Beginning the conversation about changing existing incentives for solar power has risks.
The escalation of rhetoric expressing opposing views can lead to polarization and impasse.
Uncertainty about changes in policies can deter customers from making decisions to adopt
solar, with damaging consequences for the solar industry. On the other hand, new policies
must be developed that provide a sustainable long-term foundation for solar development
and a sustainable foundation for a healthy electricity grid. While participants in the RMI-
PGE roundtable did not reach consensus about specific policy measures or utility business
model innovations, they did agree about the need for change and the initial critical steps,
that could lay the foundation for sustainable long-term solutions:
1. Identify and Measure Impacts, Costs and Values of Distributed
energy resources
2. Remedy misalignments between economic incentives to customers
and the cost and value to the system provided by distributed
resources
3. Adapt Utility Business Models to create and sustain value
in a future characterized by higher levels of efficiency and
increased deployment of distributed resources

1 E3’s study estimated that, for customers who installed systems in
2008, the levelized cost shifted to other customers as a result of the
California Solar Initiative was $0.26/kWh generated based on the
Ratepayer Impact Measure (RIM) test. The study estimated that
this cost shift declined to $0.21/kWh generated in 2009 and would
decline further to $0.10/kWh generated by 2017. (“California Solar
Initiative Cost-Effectiveness Evaluation”, Energy and Environ-
mental Economics, April 2011, Table 52, Table 56, and Table 60 p.
A-26-A-30.) The extent to which CSI and Net Energy Metering
(NEM) policies impose costs on non-NEM customers is controver-
sial, and E3’s conclusions about NEM have been disputed by other
analysts. While analysts disagree about the level of “cost shift” that
results from CSI and NEM policies based on differences in analysis
approaches and assumptions, there is broad agreement that the
results are heavily influenced by rate design. As rates structures
change, so will the cost-effectiveness of CSI and NEM. With respect
to NEM, E3 concluded that, under 2008 rates, the average net cost
of NEM to non-participants for generation installed through the
end of 2008 was $0.12/kWh exported. (“Net Energy Metering Cost-
Effectiveness Evaluation”, Energy and Environmental Economics,
January 2010, Table 3, p.7.) A subsequent study by Lawrence Berke-
ley National Laboratory estimated that the net cost of residential
NEM was $0.02-0.05/kWh exported. (Dargouth, N., Barbose, G.,
and Wiser, R., The Impact of Rate Design and Net Energy Metering
on the Bill Savings from Distributed PV for Residential Customers
in California, April 2010, LBNL-3276e.) Finally, a study published
by Crossborder Energy in January 2012 estimated that the net
cost of NEM was $0.02/kWh exported. (Beach, R., McGuire, P.,
“Re-evaluating the Cost-Effectiveness of Net Energy Metering in
California, Crossborder Energy, January 17, 2012.)
2 “California Solar Initiative Cost-Effectiveness Evaluation”,
Energy+Environmental Economics, April 2011
3 California IOUs cost recovery is separate from rates, with an an-
nual adjustment to account for differences between forecasted sales
and actual sales. This means utilities will recover authorized fixed
costs without over- or under-recovery as a result of fluctuations in
weather or customer energy efficiency.
4 PGE residential rates currently have four tiers with prices that
increase as usage increases.
5 D.Moskovitz, Profits and Progress Through Distributed Resources,
published by the Regulatory Assistance Project (www.rapmaine.
org), Maine, USA, February 2000
6 Again, many stakeholders consider distributed generation to be
any generation connected at the distribution level, whether serv-
ing customer load, or merchant generation.
7 While net energy metering has been commonly implemented
across the U.S. to value exported power from customers at full
retail rates, the concept of net energy metering does not equate to
compensation at retail rates.
8 As with similar policies, FITs will not necessarily result in benefi-
cial siting of DG unless location and other attributes are taken into
account in the tariff design.
9 FERC recently updated the rules governing FITs, which will likely
stimulate additional use of FITs in the U.S
10 Lawrence Berkeley National Lab, Tracking the Sun IV
11 CA IOUs have deployed 8.8 M of 11.95 M electric SmartMeters,
while nationally 65 million SmartMeters will be deployed by 2015.
12 At the outset of the CSI program in 2007, the initial $2.50 per watt
Endnotes

incentive offset 25% of the system cost.
13 Levelized cost of energy (LCOE) is defined as the total cost of
building and operating a generating plant over its life.
14 LCOEs calculated from http://www.pvcostconvergence.org/
calculator.aspx, assuming a 4kW residential system in the year
2012 located in San Jose, with Federal ITC and CSI incentives,
aggressive PV cost declines, and a financing structure of either 0%
down 4% interest or 30% down 6% interest.
16 “Utility” investment is considered to be any generation built
or directly contracted for (through a PPA) by the utility while
“customer” refers to any generation investment on the customer
side of the meter, whether owned by the customer or a third
party. This forecast is based on publically available supply plans
for thermal generation and large scale renewables to meet the
33% RPS for the utility, and distributed generation policy goals
for the customer. The value of investment is based on forecasts of
technology costs from the EIA and national labs.
17 As detailed on p. 42, a utility’s cost to serve are broken into three
main categories: non-capacity-related fixed costs are overhead
expenditures incurred as a direct result of a customer’s existence,
capacity-related fixed costs stem from the TD and generator
capacity required to serve the customer, and variable costs cover-
ing the fuel, operations, and maintenance costs associated with
generating power.
18 On January 18, 2012 CPUC found that this proposal was out of
scope for the instant proceeding.

52
Drivers Section
Barbose G., N. Dargouth, R. Wiser. 2011. Tracking the Sun IV: An
Historical Summary of the Installed Cost of Photovoltaics in the
United States from 1998 to 2010. Lawrence Berkeley National
Laboratory, September. eetd.lbl.gov/ea/ems/reports/lbnl-5047e.pdf
Wesoff, Eric. 2011. “Third-Party-Owned Solar Dominates the
California Market.” Greentech Media, September 30. http://
www.greentechmedia.com/articles/read/Third-Party-Owned-
Solar-Drives-California-Market/
Keesee, Mike. 2010. “Impact of Distributed Solar on SMUD’s
Peak Load and Local Distribution System.” Presentation to
4th
International Conference on Integration of Renewable
and Distributed Energy Resources, Dec 6. http://
www.4thintegrationconference.com/downloads/Session%20
3-6_Keesee-New.pdf
Mather, Barry and Benjamin Kropowski. 2011. Southern California
Edison High-Penetration Photovoltaic Project – Year 1. National
Renewable Energy Laboratory, June. www.nrel.gov/docs/
fy11osti/50875.pdf
R.W. Beck. 2009. Distributed Renewable Energy Operating Impacts and
Valuation Study. Arizona Public Service, January. www.aps.
com/_files/solarRenewable/DistRenEnOpImpactsStudy.pdf
Navigant Consulting, Inc. 2011. Large Scale PV Integration Study. NV
Energy, June. http://www.navigant.com/insights/library/
energy/large-scale_pv_integration_study/
San Diego Gas and Electric. 2011. SDGE’s GRC Phase II Application.
California Public Utilities Commission, October. http://
regarchive.sdge.com/regulatory/A11-10-002.shtml
Fox-Penner, Peter. 2010. Smart Power: Climate Change, the Smart Grid,
and the Future of Electric Utilities. Washington DC: Island Press.
Public Utilities Commission of the State of California, Decision
Adopting the Renewable Auction Mechanism, Decision 10-12-048
(Sacramento, CA, 2010).
North American Electric Reliability Corporation, 2010 Special
Reliability Scenario Assessment: Resource Adequacy Impacts of Potential
U.S. Environmental Regulations, October 2010.
Anon. Ocean Standards - CWA §316(b) Regulation. California State
Water Resources Control Board. http://www.swrcb.ca.gov/water_
issues/programs/ocean/cwa316/.
Bachrach, Devra, Matt Ardema, and Alex Leupp. 2003. Energy
Efficiency Leadership in California. National Resources Defense
Council, April.
Bell, Mathias, Brendan O’Donnell, Ryan Matley, and Noel
Crisostomo. 2011. Turbocharging Efficiency Programs. October.
Brown For Governor Campaign. 2010. Brown Announces Clean
Energy Jobs Plan. June 15. http://www.jerrybrown.org/Clean_
Energy.
California Air Resources Board. 2011. Overview of ARB Emissions
Trading Program. October 20. http://www.arb.ca.gov/
newsrel/2011/cap_trade_overview.pdf.
———. Cap-and-Trade Program. http://www.arb.ca.gov/cc/
capandtrade/capandtrade.htm.
———. Climate Change Programs. http://www.arb.ca.gov/cc/
cc.htm.
California Division of Ratepayer Advocates. 2007. Electric Rate
Design. http://www.dra.ca.gov/DRA/energy/Customer+Rates/
Rate+Design/.
California Energy Commission. 2005. Implementing California’s
Loading Order for Electricity Resources. July.
———. 2011a. About the Appliance Efficiency Database. http://
www.appliances.energy.ca.gov/About.aspx.
———. 2011b. Staff Draft Report on Renewable Power in California:
Status and Issues. August.
California Public Utilities Commission. 2011a. Summary of Feed-In
Tariffs. July 1. http://www.cpuc.ca.gov/PUC/energy/Renewables/
feedintariffssum.htm.
———. 2011b. California Energy Efficiency Strategic Plan: Strategic Plan
Progress Report. October.
———. 2011c. Renewable Auction Mechanism. October 17.
http://www.cpuc.ca.gov/PUC/energy/Renewables/hot/
Renewable+Auction+Mechanism.htm.
———. RPS Program Overview. http://www.cpuc.ca.gov/PUC/
energy/Renewables/overview.
Casey, Keith. 2011. Briefing on Renewable Integration. California
ISO, August 18.
Como, Joseph P. 2011. RE: SB 142 (Rubio) Oppose. March 29. http://
www.dra.ca.gov/NR/rdonlyres/194AD00E-041C-4331-892F-
64BDC0E0E09C/0/SB142RubioOppose.pdf.
Go Solar California. 2011. About Go Solar California. http://www.
gosolarcalifornia.org/about/index.php.
Kavalec, Chris, Tom Gorin, Mark Ciminelli, Nicholas Fugate, Asish
Gautam, and Glen Sharp. 2011. Preliminary California Energy Demand
Forecast 2012-2022. August.
Bibliography
REFERENCES

53REFERENCES
North American Electric Reliability Corporation. 2010. 2010 Special
Reliability Scenario Assessment: Resource Adequacy Impacts of Potential
U.S. Environmental Regulations. October.
Padilla, Alex. 2011. SB 142 Senate Bill—Bill Analysis. May 3. http://
www.leginfo.ca.gov/pub/11-12/bill/sen/sb_0101-0150/sb_142_
cfa_20110502_120000_sen_comm.html.
PGE Currents. 2011. PGE Supports Bill to Reform California
Electric Rate Structure for Residential Customers. April 7. http://
www.pgecurrents.com/2011/04/07/pge-supports-bill-to-reform-
california-electric-rate-structure-for-residential-customers/.
Prusnek, Brian C. 2005. Promoting Energy Efficiency in California
presented at the State EE/RE Technical Forum, May 18. http://www.
epa.gov/statelocalclimate/documents/pdf/PrusnekPresentation.
pdf.
U.S. EPA. 2009a. New Source Performance Standards and State
Improvement Plans. June 16. http://www.epa.gov/compliance/
monitoring/programs/caa/newsource.html.
———. 2009b. CHP Support at the State Level. July.
———. 2011a. Selected New Source Performance Standards. October
4. http://www.epa.gov/ttn/atw/nsps/nspstbl.html.
———. 2011b. Cross-State Air Pollution Rule. November 16. http://
www.epa.gov/crossstaterule/.
Photo Credits
Cover, p6: iStockphoto.com: Elenathewise
p. 1: iStockphoto.com: dja65
p. 10: iStockphoto.com: LydiaGoolia
p. 26: iStockphoto.com: LPETTET
p. 35: iStockphoto.com: jokerproproduction
p. 40, 41, 42, 48: BrettCharlton

rmi.org | 2317 Snowmass creek road | Snowmass, co 81654
p: 970.927.3851 f: 970.927.3420
about rocky mountain institute
rocky mountain institute (rmi) is an independent,
entrepreneurial, nonprofit think-and-do tank. rmi emphasizes
integrative design, advanced technologies, and mindful
markets in fulfilling its mission to drive the efficient and
restorative use of resources. rmi’s strategic focus is to map
and drive the u.S. transition from fossil fuels to efficiency and
renewables by 2050.
if you are interested in contacting the authors, or engaging
with rocky mountain institute, communications can
be sent to vlacy@rmi.org.
the program supporting this report is funded by california
utility customers and administered by PGE under the
auspices of the cPuc.
rocky mountain institute © march 2012
rmi.org
2317 Snowmass creek road | Snowmass, co 81654
p: 970.927.3851 f: 970.927.3420
Design and layout: michelle F Fox

Net Energy Metering, Zero Net Energy and The Distributed Energy Resource Future: Adapting For The 21st Century

More Related Content

What's hot (20)

Similar to Net Energy Metering, Zero Net Energy and The Distributed Energy Resource Future: Adapting For The 21st Century (20)

More from Private Consultants (20)

Recently uploaded (20)

Net Energy Metering, Zero Net Energy and The Distributed Energy Resource Future: Adapting For The 21st Century