Power to the People: The Future of Electric Utilities and the Rise of Distributed Energy

Power to the People:
The Future of Electric Utilities and Distributed
Energy Resources in the 21st
Century
By Jeremy Conway
Reviewed by Chris Gadomski

1
Copyright © 2016 by Jeremy Conway
All rights reserved. No part of this publication may be reproduced,
distributed or transmitted without the express consent of the author.

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Acknowledgements
First and foremost, I would like to express my gratitude to the professors who have
kindled my interests in energy, finance, economics and environmental policy. In
particular, I would like to thank Carolyn Kissane for providing one of the most
engaging and enjoyable classroom experiences in my academic career and for taking
such an interest in nurturing future energy leaders. I would like to especially thank
Chris Gadomski for arousing my curiosity in the economics and finance of energy and
Jay Taparia for urging me to take on this challenging topic. I am indebted to all of my
professors, friends and family who have encouraged me along the way.
I dedicate this work to my grandparents who have always believed in me. Without
their kindness and generosity, this thesis never would have seen the light of day.

3
Recommended Research Sources
America’s Power Plan. http://americaspowerplan.com
Center on Global Energy Policy. http://energypolicy.columbia.edu/
Cost of Renewable Energy Spreadsheet Tool.
https://financere.nrel.gov/finance/content/crest-cost-energy-models
Database of State Incentives for Renewables & Efficiency. http://www.dsireusa.org/
Edison Electric Institute. http://www.eei.org/
Energy Information Administration. http://www.eia.gov/
Federal Energy Regulatory Commission. http://www.ferc.gov/
Freeing the Energy Grid. http://freeingthegrid.org/
Institute for Local Self-Reliance. https://ilsr.org/
International Energy Agency. http://www.iea.org/
Interstate Renewable Energy Council. http://www.irecusa.org/
Lawrence Berkeley National Laboratory. http://www.lbl.gov
MIT Energy Initiative. http://mitei.mit.edu/
National Renewable Energy Laboratory. http://www.nrel.gov/
NC Clean Energy Technology Center. https://nccleantech.ncsu.edu/
PV Watts Calculator. http://pvwatts.nrel.gov/
Rocky Mountain Institute. http://www.rmi.org/
Shared Renewables HQ. http://sharedrenewables.org/
Solar Energy Industries Association. http://www.seia.org/
SEIA Major Solar Projects List. http://www.seia.org/map/majorprojectsmap.php
Smart Electric Power Association. http://www.solarelectricpower.org/
The Open PV Project. https://openpv.nrel.gov/rankings

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List of Acronyms
IOU – Investor Owned Utility
EE—Energy Efficiency
EEI – Edison Electric Institute
EIA – Energy Information Administration
DER – Distributed Energy Resource
DG – Distributed Generation
DR – Demand Response
DOE – Department of Energy
DSIRE – Database of State Incentives for Renewables & Efficiency
DSP – Distribution Service Platform
FERC – Federal Energy Regulatory Commission
IPP – Independent Power Producer
IREC – Interstate Renewable Energy Council
ISO – Independent System Operator
ITC – Investment Tax Credit
LCOE – Levelized Cost of Electricity
NCCETC – NC Clean Energy Technology Center
NEG – Net Excess Generation
NEM – Net Energy Metering
NREL – National Renewable Energy Laboratory
PUC – Public Utility Commission
PURPA – Public Utility Regulatory Policies Act (1978)
PV – Photovoltaic
QF – Qualifying Facility
REV – New York State’s Reforming the Energy Vision
RTO – Regional Transmission Organization
SEIA – Solar Energy Industries Association
SEPA – Smart Electric Power Alliance
T&D – Transmission & Distribution
TPO – Third Party Ownership

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Table of Contents Page
1 Executive Summary---------------------------------------------------------------------------7
2 An Overview of Investor Owned Utilities------------------------------------------------------9
3 Current Industry Structure and Competitive Forces-----------------------------------------25
4 IOUs Current Strategic Reactions (Case Studies)--------------------------------------------56
5 Policy Recommendations for Power Industry Stakeholders---------------------------------70
6 Conclusions----------------------------------------------------------------------------------75
List of Figures
Figure 2.1: Growing Economies of Scale Reduces a Company’s Average Total Costs-------------10
Figure 2.2: Declining Economies of Scale for IOU Industry --------------------------------------- 15
Figure 2.3: Regional Transmission Organizations in the U.S.-------------------------------------- 16
Figure 2.4: Declining Electricity Use Now a Long Term Trend------------------------------------- 17
Figure 2.5: Evolving Energy Efficiency Standards--------------------------------------------------19
Figure 2.6: IOU’s Historical Credit Ratings--------------------------------------------------------- 20
Figure 2.7: The So Called Utility Death Spiral------------------------------------------------------ 21
Figure 2.8: IOU Industry Capital Spending & Retail Rates------------------------------------------23
Figure 3.1: Solar Prices & Installation Rates-------------------------------------------------------27
Figure 3.2: Nationwide Electricity Rates by County------------------------------------------------30
Figure 3.3: Soft Costs for a Typical Solar Installation----------------------------------------------31
Figure 3.4: Residential PV System Costs Reaching Grid Parity------------------------------------ 32
Figure 3.5: Financial Performance of Pure Play Residential Solar Companies-------------------- 35
Figure 3.6: Financial Performance of IOUs--------------------------------------------------------- 36
Figure 3.7: EBITDA Comparison of Solar Providers & IOUs-----------------------------------------37
Figure 3.8: PV Solar Insolation Across the US------------------------------------------------------39
Figure 3.9: Solar Insolation & Retail Rates Shape the Economics of Solar Systems-------------- 40
Figure 3.10: State Changes to NEM Policies------------------------------------------------------- 47
Figure 3.11: Interconnection Standards by State-------------------------------------------------- 48
Figure 3.12: ITC Stimulates Annual Solar Installations-------------------------------------------- 50
Figure 3.13: Map of Third Party Ownership (TPO) Regulations------------------------------------ 52
Figure 3.14: Community Solar Policies & Programs----------------------------------------------- 54
Figure 3.15: Residential Solar Market Potential by State------------------------------------------ 55
Figure 4.1: Top 10 Utility Solar Installations, 2015-------------------------------------------------58
Figure 4.2: Utility Scale Solar in South Atlantic Region Dominated by North Carolina, Georgia---59
Figure 4.3: APS Solar Innovation Study------------------------------------------------------------ 62
Figure 4.4: Integration of Customer, DER Service Providers and the Utility through the DSP----- 65
Figure 5.1: Performance-based Ratemaking------------------------------------------------------ 71
Figure 5.2: Generic Smart Utility Business Models------------------------------------------------ 72
Figure 5.3: The Power Industry’s “Inseparable Triad---------------------------------------------- 73

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List of Tables
Table 3.1: Ranking of States with Third Party Solar Operators by Retail Rate---------------------29
Table 3.2: Average Capacity Factors for Generation Technologies-------------------------------- 38
Table 3.3: Southern Nevada Net Metering Rate Change Forecast--------------------------------- 43
Table 3.4: NEM Rates in Top 10 DG Markets by Per Capita Installations, 2016--------------------45
Table 3.5: Solar Investment Tax Credit Time Horizon----------------------------------------------49
Table 3.6: Renewable Portfolio Standards Policies------------------------------------------------ 51
Table 5.1: Business Model Elements---------------------------------------------------------------72

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Chapter 1
Executive Summary
During the 20th
century, the US power industry and its regulatory overseers sought to
make electricity reliable, cheap and accessible to all of the nation’s citizens. The
regulatory compact formulated by these stakeholders succeeded in accomplishing
these goals by promoting the development of vast electrical transmission and
distribution networks interconnected to large central power stations. However, in the
21st
century, this regulatory structure is now being challenged. While policymakers
seek to maintain the goals of sustaining affordable and reliable electricity as a public
good, public policy also seeks to preserve a modern power grid that mitigates the
negative “public health and environmental costs” caused by carbon emissions.1
Moreover, now that economies of scale peaked in the 1970s, infrastructure spending
leads to rate increases—meaning that the investor owned utilities’ financial incentive
encouraging infrastructure spending (an incentive embedded in the regulated
ratemaking framework) no longer provides cost reducing benefits to consumers.
Since 2008, the growth of residential solar energy markets has created interest in
developing distributed energy resource (DER) markets that help consumers reduce
their power consumption and lower their electricity bills while providing potential
benefits to the whole grid through deferred investments and aggregation of demand
side resources (i.e. demand side management and load shifting) to optimize the grid’s
operation. As a whole, investor owned utilities (IOUs) dislike DERs because the rise of
these resources exacerbate the declining consumption of centralized power. This
secular trend completely undermines the traditional financial motive of utilities:
namely, to promote consumer demand for utility delivered kilowatt hours as a means
to boost revenue and justify future investments in grid infrastructure.
So far, the rise of DERs is most pronounced in regions that complement non-policy
supporting factors (i.e. higher than average retail prices and/or high solar capacity
factors) with a strong collection of market enabling policies such as the availability of
net metering and investment tax credits. However, while the rise of DERs is most
pronounced in the following regions (the Mid-Atlantic, Northeast, Southwest and
California), even IOUs operating in markets with low DER deployment levels have
taken strategic precautions to confront the disruptive threat.
Financial incentives of IOUs create conflict with policymakers that aim to facilitate
DER growth and integrate the DER market into the power sector’s value chain. The
growth of DERs hurt IOUs because they render future infrastructure spending
unnecessary and cause some customers to reduce their consumption. Under the
1
Harvey, Hal and Sonia Aggarwal. “Rethinking Policy to Deliver a Clean Energy Future,” Energy Innovation
Policy & Technology LLC. September 2013. http://energyinnovation.org/wp-content/uploads/2014/06/APP-
OVERVIEW-PAPER.pdf

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IOUs traditional business model and ratemaking framework, the growth of DERs
poses a threat to their business strategy and financial well-being through the ongoing
loss of revenue and loss of potential investment opportunities with a regulated rate of
return.
In general, vertically integrated IOUs have wielded defensive strategies aimed at
hindering DER growth. Others have instituted offensive strategies seeking to enter and
potentially control the DER market. Meanwhile IOUs operating in progressive DER
markets like California have made unprecedented progress in stimulating DER market
growth, but much of this has occurred under a compliance mindset. It has not
principally been driven by natural business initiatives. Consequently, even IOUs in
California rely more on regulatory mandates rather than financial drivers to integrate
DERs into their business operations.
In order to overcome this conflict between the goals of policymakers and regulators
on the one hand and the goals of IOU shareholders on the other, the major
stakeholders involved in the power industry’s future must cooperate to realign IOUs’
financial incentives to see DER growth as an opportunity rather than an existential
threat. Working in tandem to create new business models supported by performance
based regulation, policymakers, IOUs and other major energy stakeholders can
potentially create a regulatory compact for the future—a regulatory compact that
provides new valuable energy services for consumers while unleashing new revenue
generating opportunities for utilities. Transforming the regulatory compact and utility
business model of the 20th
century without creating unintended consequences will be
a challenging feat. Therefore, regulators and utilities will need to work in concert to
develop a cogent transition plan.

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Chapter 2
An Overview of Investor Owned Utilities
I. A Brief History of Investor Owned Utilities
A. The Power Industry: Origins
The origins of the electric utility industry emerged as a result of two key inventions by
Thomas Edison: the introduction of the incandescent light bulb in 1879 and the
emergence of the “world’s first central generating power station in New York City’s
financial district” in 1882.2
Shortly after the arrival of centralized power, Thomas
Edison and other innovative entrepreneurs took advantage of this new power source
and created a variety of new electrical machines for commercial, industrial and
residential applications. Within a few years, electricity now began to power
manufacturing processes, public transportation, heating, etc. In short order, Edison’s
innovations created the initial push toward electrification. But it would take another
innovator to shape the “economic, structural and regulatory framework“ that would
give rise to the modern vertically integrated electric utility companies that came to
dominate the 20th
century and still play an essential role in today’s electric power
industry.3
His name was Samuel Insull.
B. Industry Growth Through Economies of Scale
Samuel Insull, formerly Thomas Edison’s principal assistant in charge of Edison’s
finances and business strategy, understood that growth in the power industry
necessitated massive investment in new generation technology and infrastructure,
mass consumption and industry consolidation. In other words, he realized that
industry growth required his business to attain cost leadership position vis-à-vis his
competitors through economies of scales. Economies of scale refer to the overall
cost benefits a business attains from increasing the scale of its operations.4
As a
business increases its economies of scales, it will reduce the cost of each unit
produced as the total volume of output rises.5
Figure 2.1 below demonstrates how
increased output reduces the average total cost for the industry. Growing asset heavy
industries can significantly reduce these fixed costs by spreading them out over a
larger quantity of output. During the early to mid 20th
century, the power industry lived
through a “decreasing cost era” that hinged on increasing economies of scale, and as
2
“Emergence of Electrical Utilities in America,” The National Museum of American History.
http://americanhistory.si.edu/powering/past/h1main.htm
3
Lambert, Jeremiah D. The Power Brokers: The Struggle to Shape and Control the Electric Power Industry.
MIT Press, 2015, 1.
4
Porter, Michael E. Competitive strategy: Techniques for analyzing industries and competitors. Simon and
Schuster, 1980, 7.
5
Ibid.

10
utilities reduced the average total cost of its business operations, they were able to
pass these savings on to their consumers.6
Figure 2.1: Growing Economies of Scale Reduces a Company’s Average Total Costs
Source: Investopedia
C. Transmission and Distribution Network Creates Mass Market Potential
A low cost business strategy through economies of scale also “requires a relatively
high market share.”7
Insull’s creation of a vast unprecedented alternating current (AC)
transmission system permitted generated electricity to reach ever greater distances
and therefore immensely expanded the range of his company’s captive market. Before
Insull, a central station’s generated electricity delivery radius exceeded no further than
one-mile from the generation source.8
Even with additional steam turbine generators
creating electricity more efficiently, electric power flowing over distribution lines would
degrade quickly under Edison’s direct current system. With the introduction of AC
technology, power stations could now break through this barrier and electricity could
travel great distances “without experiencing much degradation.”9
This new
transmission and distribution (T&D) system allowed utilities to reach every end user in
its service area. By allowing power companies to reach every single end user in its
extended service area, the T&D system may have been the most important element in
permitting the scaling up of production. Consequently, the creation of this system
greatly increased Insull’s marketing and distribution advantages relative to his
6
Olson, Wayne. The A to Z of Public Utility Regulation. Public Utilities Reports, Inc, 2015, 182.
7
Porter, Competitive Strategy, 36.
8
Lambert, The Power Brokers, 6.
9
Emergence of Electrical Utilities.

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competitors and was one of the factors that led to Commonwealth Edison obtaining a
virtual monopoly in the greater Chicago area.
D. A Capital Intensive Industry Requiring High Market Share and Large Revenue
There is, however, a significant challenge in building and maintaining a large T&D
network: its cost. While Insull’s scalable steam turbines and T&D system allowed his
company to scale up power production and reach an ever larger audience compared
to his competitors, it required enormous capital investments. As Michael Porter notes
in his seminal work Competitive Strategy, a low cost position through economies of
scale “requires heavy upfront capital investment, aggressive pricing and startup
losses to build market share.”10
Insull employed all of these tactics, but the large
capital investments required to secure economies of scale are still a key trait of the
industry even to this day.
In order to reduce overall costs and pass on price savings to the customer,
Commonwealth Edison had to attract large amounts of capital to acquire the
enormous cost reducing assets. To accomplish that, the company needed a large,
steady revenue stream and profit margin to cover these investment expenses. Insull
constantly found ways to increase his revenue intake through an aggressive customer
acquisition strategy, and, as we’ll see later, through political regulation.
Although Insull had the capacity to produce power in bulk and the potential to reach a
large market, he needed to attract more customers to his company. Insull understood
that his generation capacity needed to be large enough to provide peak demand,
which tends to occur in the early evening.11
While obtaining enough power to provide
peak power is necessary to meet the needs of a service area’s energy demand, it also
means that the most expensive portion of a utility company’s generating assets—
those providing peak power—will remain inactive and unproductive for much of the
day. To compensate for this dilemma, Insull sought to maximize the load factor of all
of his power plants i.e. the average time each plant generated electricity. The power
plants’ assets—the turbines, pipes, wires, and boilers—still need to be paid off even
when the plant is sitting idle.12
Insull astutely understood that profit margins hinged
upon increasing each power plant’s average time of use—i.e. the load factor.
According to Insull, “the nearer you can bring your average to the maximum load, the
closer you approximate the most economical condition of production, and the lower
you can afford to sell your current.”13
In general, this required diversifying his customer
base in order to include a variety of consumers based on time of use and volatility of
use. To raise the load factor, Insull needed more customers during off peak hours,
10
Porter, Competitive Strategy, 36.
11
12
Ibid.
13
Lambert, The Power Brokers,12.

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less customers with volatile usage patterns and a more diverse group of customers
whose time of use varied.14
Insull also made use of a new innovative demand meter created by Arthur Wright that
allowed him to determine the actual use and the degree to which each consumer
utilized his installed capacity. In other words, each consumer’s monthly bill revealed
his disaggregated portion of the fixed costs of the utility company that arose from the
generating capacity the utility provided to meet peak load.15
In measuring the quantity
of electricity each user consumed, it also reflected each user’s contribution toward a
central plant’s operating costs. In short, with the arrival of the Wright meter, monthly
charges suddenly seemed more transparent, fair and reasonable.
Additionally, Wright’s demand meter revealed that two customers with the same
installed capacity (let’s say, 15 lamps as example) could have vastly different cost
profiles.16
As an example, customer A only uses her electricity three times a year,
while customer B uses her electricity every single day.17
Since the company must
“invest so heavily in equipment” to provide peak load capacity for each customer, it
actually costs more to serve the customer who uses her lamps only three times a year
than the customer who leaves her lamp running each and every evening.18
Hence, the
Wright meter concretely validated Insull’s growth paradigm: as customers increased
their consumption, costs declined.
Thus, the Wright meter reinforced Insull’s general growth strategy: to attract more end
users and increase revenue through mass consumption.19
Ultimately, the Wright meter
further encouraged Insull to capture a larger audience, abandon unprofitable power
plants and confirmed a monopolistic system as the best path to push down both
company expenses and service pricing.20
E. Natural Monopoly Leads to Regulatory Compact
Despite Insull’s success vis-à-vis his competitors, remaining competition still
undermined industry growth and subverted the benefits of economies of scale.
Intense rivalry split market share, meaning that no single company could produce
sufficient revenue to justify investment in larger turbines and an expanding T&D
system.21
In order to overcome this limitation, Insull began to buyout competitors and
consolidate the electricity market. This allowed him to absorb more customers and
escalate his company’s load factor—that is, to increase the average use of his plants
14
Hughes, Thomas Parke. Networks of power: electrification in Western society, 1880-1930. JHU Press,
1993., 220
15
Ibid.
16
McDonald, Forrest. Insull: the rise and fall of a billionaire utility tycoon. Beard Books, 2004, 67.
17
Ibid.
18
Ibid.
19
20
21

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through customer acquisition.22
Despite Insull’s initial successes through free market
competition, the destabilizing threat of competition persisted.
Through parallel experiences in the railroad industry, some economists, politicians and
industry insiders understood that certain asset heavy industries “exhibiting economies
of scales” represented what some would deem as “natural monopolies.”23,24
While
most consumers and politicians abhorred the potential for market abuse inherent in a
monopolistic system, the exorbitant investment requirement in building a large T&D
network tied to enormous turbine generators meant that “duplication” would be
wasteful, raise both business costs and consumer prices and create an unstable
bankrupt conducive business climate.25
At the same time, while some of the most powerful political, consumer and financial
stakeholders accepted the electric utility industry as a natural monopoly, both
investors and Progressive era politicians agreed upon the need to create a robust
regulatory framework for the industry. The guiding principles that underpinned this
regulation came to be known as the regulatory compact.
Under the auspices of the regulatory compact, utility companies and consumers
reached a bargain with state political committees providing regulatory oversight over
utility companies. To this day, the basic features of the regulatory compact remains
intact. The terms are as follows: each utility company in a given service area is
“granted a monopoly,” and it is permitted to price its electricity at an approved rate
that provides a fair return on its investments.26
In return for this favorable arrangement,
the company must provide “low-cost, reliable” electricity to all of the consumers
residing in its service area as a public good.27
In order to hold the utility accountable to
this arrangement, a state appointed public utility commission (PUC) possesses
ultimate authority over approving the utilities’ annual investment decisions and
consumer pricing.28
For investors, regulation provided enormous financial benefits. In many markets, fierce
competition pushed electricity prices under marginal costs—driving many power
companies into insolvency.29
Protection from competition assured a steady and
22
23
24
Roberts, David. “Utilities for dummies: How they work and why that needs to change,” Grist. 21 May 2013.
25
26
Ibid.
27
Ibid.
28
A monopoly may have a perverse incentive to abuse its market power in a way that serves its own profit
maximizing agenda in lieu of maximizing consumer utility. A monopoly seeking to increase profits can merely
raise its price or reduce its output. Regulators can ensure that utility monopolies keep price and quantity in
line with the lowest point of the firm’s average total cost curve in order to maximize public benefits to
consumers and society at large. See Olson, Wayne. The A to Z of Public Utility Regulation, 31-34.
29
Brooks, Cameron. "The Periodic Table of the Electric Utility Landscape: A Series of Visual Tools for
Enhanced Policy Analysis." The Electricity Journal 28.6 (2015): 82-95, 84

14
dependable revenue stream which guaranteed return on investment. As a result,
capital costs declined and credit quality soared allowing cheaper financing, which was
critical for such a “capital intensive and highly leveraged industry.”30,31
F. The Hope Case Creates Modern Ratemaking Paradigm
Then, in 1944, the Supreme Court passed a ruling that left a momentous legacy on the
utility industry’s ratemaking patterns. The ruling in the Federal Power Commission v.
Hope Natural Gas Co. case proffered even greater financial protection to IOUs’
investment decisions by approving a new ratemaking standard that bundled utility
capital expenditures along with a guaranteed rate of return into the customers’ rates.32
This ratemaking system allowed utilities to minimize risks to shareholders, and, hence,
more effectively attract capital. However, as will be explained later, this ratemaking
system embedded an incentive structure within the business model that favors the
deployment of expensive capital projects (i.e. grid infrastructure) as a means to boost
profit margins. While favorable to shareholders’ interests and the societal need for
cheap, reliable and ubiquitous electrification in the 20th
century, this incentive structure
may not always adequately serve the interests of a society demanding a nimbler, more
efficient and cleaner grid.
G. The Mid 20th
Century: The Industry’s Boom Phase
As utility CEOs like Insull relinquished regulatory authority to state commissions,
conditions for industry growth boomed. Under this new system of regulatory
protection, the industry quickly consolidated into vertically integrated monopolies all
over the country, and throughout the 20th
century, most of the country’s generation
capacity and T&D system arose under this arrangement. The industry realized greater
economies of scale, reduced costs in conjunction with rising demand while curtailing
undesirable factors—like competing infrastructure—averse to industry growth.33
In
sum, regulation accelerated the industry’s growth rate during the middle of the 20th
century.
H. The Late 20th
Century: Industry Maturation, Oil Shocks, and PURPA
During the 1970s, the industry began to undergo some economic changes. Firstly, as
the industry entered the 1970s, the industry no longer achieved the same cost
reducing benefits from boosting economies of scale. Figure 2.2 demonstrates how
the electric industry’s increasing output beyond 20 billion kWh provided no further
cost reductions for the industry at large; the cost curve remained completely flat
beyond 20 billion kWh of generated power. Secondly, the two major oil shocks of the
1970s motivated utilities to lobby for the inclusion of fuel costs into customers’
electricity rates in order to attain greater financial security from volatile fuel
30
Brooks, The Periodic Table of the Electric Utility Landscape, 85.
31
32
Brooks, The Periodic Table of the Electric Utility Landscape, 87.
33
Ibid.

15
expenses.34
Within two decades, fuel costs were included into most utility customers’
rate cases.35
Moreover, during the 1970s, a greater focus on environmentalism and energy security
in public policy began to place higher priority in clean and efficient energy
generation.36
Then, with the passage of the Public Utility Regulatory Policies Act of
1978 (PURPA), the federal government pushed to end the total monopolization of the
power generation part of the electric industry. It sought to promote the development
of a “non-utility power sector” comprised of independent power producers competing
side by side with utilities.37
PURPA encouraged energy efficiency through the growth
of cogeneration facilities as well as other alternative energy sources such as solar
power production. Over the past forty years, PURPA has played an essential role in
promoting the deployment of small renewable energy production facilities under 80
MW.38
Figure 2.2: Declining Economies of Scale for IOU Industry39
Source: Christensen, L.R. Green.
34
Brooks, "The Periodic Table of the Electric Utility Landscape,” 87.
35
Ibid.
36
Ibid.
37
Campbell, Richard J. “Customer Choice and the Power Industry of the Future” Congressional Research
Service. September 2014, 1.
38
“What is a Qualifying Facility?” Federal Energy Regulatory Commission. 30 June 2016.
39
Christensen, L.R. Green, W.R., 1976. Economies of Scale in US Electric Power Generation. J. Polit Econ
74 (4), 671.

16
I. The 90s: An Era of Industry Restructuring
With the introduction of the Energy Policy Act of 1992 and the creation of the Federal
Energy Regulatory Commission (FERC) in 1996, the federal government urged states
to promote open wholesale market access between states and overall greater levels
of competition in the energy utility sector. Throughout the 1990s, 16 states voluntarily
embraced this shift toward restructuring and as of 2011, non-utility power producers
generated as much as 40% of the electricity consumed in the United States.40
In order to manage and ensure more competition in electricity generation,
participating states developed Regional Transmission Organizations (RTOs). RTOs
seek to create transparent, non-discriminating and open wholesale electricity markets
within its regional interstate service territory. In general, the RTOs have created a
system that allows non-utility generators to compete more fairly with IOU owned
generation facilities.
Figure 2.3: Regional Transmission Organizations in the U.S.
Source: FERC
As a result of these changes, the traditional vertically integrated IOU industry
fragmented into two more distinct entities in these 16 states: restructured utilities (an
assortment of distribution companies) and retail utilities (which function as
40
Campbell, “Customer Choice and the Power Industry of the Future,” 2.

17
“commodity energy brokers”).41
With the exceptions of California and Texas, the
regions most devoted to restructuring have been the Midwest, Mid-Atlantic and New
England states. The rest of the country’s IOUs operating in the Southern or Western
United States continue to adhere to the age old vertically integrated model pioneered
by Insull.
J. Present Challenges for IOUs and with Current Utility Business & Regulatory Model
a. Declining Electricity Use
Throughout the 20th
century, economic growth heavily relied on substantial amounts
of electricity. However, over time, GDP growth has come to be less reliant on
electricity use. Between 1975 and 1995, as electricity use declined, the two variables
moved in synchrony. Since the beginning of the 1990s, GDP growth steadily
surpassed electricity use, which now appears to be flattening to about a 0.9% growth
rate. The EIA projects that this will continue to be a long run trend. While this
slowdown is partially a result of macroeconomic factors—such as a slowing
population growth and outsourcing of heavy industry—it is also a result of
improvements in energy efficiency.42
If this trend moves forward in line with the EIA’s
estimates, there will likely be less overall demand for electricity in the coming future.
This outcome could challenge the IOUs’ current investment and profit making
strategies, which heavily rely on state regulators to sign off on the need for such
capital spending.
Figure 2.4: Declining Electricity Use Now a Long Term Trend
Source: Energy Information Administration
41
Brooks, "The Periodic Table of the Electric Utility Landscape,” 87-88.
42
“U.S. Economy and Electricity Demand Growth Are Linked but Relationship Is Changing,” U.S. Energy
Information Administration. 22 March 2013.

18
b. Societal and Consumer Aims for Energy in 21st
Century
Over the past forty years, consumer attitudes and public policy have demonstrated
greater concern for environmental issues, especially concerning energy production.
Changing environmental attitudes continue to create stricter legal and regulatory
standards from state and federal governments. Meanwhile, innovative companies are
seeking to capitalize from stricter clean energy requirements and growing consumer
demand for clean energy.
An ongoing survey conducted between 2002 and 2010 by the Natural Marketing
Institute’s (NMI) Lifestyles of Health and Sustainability (LOHAS) Consumer Trends
Database®, demonstrates that 80% to 90% of consumers contacted in the survey
“care about renewable energy.”43
The survey reveals that about 80% of consumers
increasingly care about using renewable energy in order to protect the environment.
With that said, if given the choice for renewable sources of electricity at a higher price,
many consumers in the survey demonstrate a degree of price sensitivity. In 2010, 69%
of consumers stated that they “cared about the environment,” but that purchasing
decisions were ultimately based on price.44
Twenty-six percent of the consumers said
they would willingly pay “$5-$20 extra each month to have some of their power”
derived from renewable sources.45
Finally, only 16% of consumers in the survey
demonstrated a willingness to “pay more than 20% for products that are produced
sustainably or in an environmentally friendly” manner.46
According to these trends, IOUs and state regulators will increasingly face more
pressures from consumers and legal standards to simultaneously maintain affordable
electricity, while also offering more environmentally friendly forms of electricity.
Unfortunately, the IOUs’ outdated business model and regulatory framework may limit
its potential to effectively innovate and meet the growing demand of its consumer
base. As a result, in localities where utilities and lawmakers fail to cater to this
demand, third party companies will attempt—where possible—to meet this demand.
In the future, distributed energy resources, when priced appropriately, may play a
significant role in the household of consumers. If that is the case, it could pose a
significant threat to IOUs’ business model.
43
Bird, Lori and Jenny Sumner. “Consumer Attitudes About Renewable Energy: Trends and Regional
Differences,” National Renewable Energy Laboratory, 6.
44
Bird and Sumner. “Consumer Attitudes About Renewable Energy,” 12.
45
Ibid.
46
Ibid.

19
c. Growing Threats: Demand Side Management and Distributed Energy
Resources
At the same time the growth of electricity use has leveled out at less than one percent
per annum, utility customers have demonstrated greater interest in demand side
management through the adoption of energy efficiency appliances, demand response
programs and the use of distributed energy resources—such as residential solar
panels. Figure 2.5 shows how government standards have forced appliance
manufacturers to improve their energy efficiency by more than two-thirds in the past
forty years. All of these distributed energy resources and energy efficiency initiatives
represent a threat to utilities by reducing its revenue stream.
Figure 2.5: Evolving Energy Efficiency Standards
Source: Energy Information Administration
On a societal and consumer basis, many argue that distributed energy resources and
demand reduction initiatives—such as energy efficiency improvements, demand side
management, distributed rooftop solar systems and residential energy storage
systems—have an important role to play in mitigating climate change, reducing
pollution and offering cost savings to certain consumers. Many public policies,
incentives, subsidies and utility commissions have forced utilities to adopt these
measures—even though they run counter to the principle that undergirds their
traditional cost of service business model: mass consumption.
The industry’s current trend—slowing growth and a declining revenues—serves as a
signal that IOUs are facing a growing competitive threat. Some analysts even believe
that these distributed energy resources may pose an existential threat to the IOU
industry.47
In fact, if we look at the historical credit rating trends of the utility industry
47
Kind, Peter. “Disruptive Challenges: Financial Implications and Strategic Responses to a Changing Retail
Electric Business,” Edison Electric Institute, 2013, 11-12.

20
listed in figure 2.6, it becomes apparent that a combination of economic trends,
business model and regulatory changes and increased competition over the past few
decades have had a depressing impact on the industry’s credit ratings. The arrival of
additional competitive forces could further pull down the industry’s credit ratings,
raise the cost of capital and reduce “credit availability and investor receptivity to the
sector.”48
Since the electric utility industry is such a highly leveraged industry, poor
investment grades from ratings agencies could significantly “reduce the industry’s
access to low cost capital” that it has relied upon historically to make needed
improvements to the grid.49
It could also serve, according to some analysts, as a
foreboding signal for worse things to come.
Figure 2.6: IOU’s Historical Credit Ratings
Source: EEI, Standard & Poor’s, Macquarie Capital
In fact, according to a report commissioned by the Edison Electric Institute (EEI)—the
IOU industry’s leading think tank and lobby group—the continued growth of
distributed energy resources could eventually undermine the strategic and financial
viability of the utility business model.50
Under this potential scenario, revenues and
profits would decline and credit quality would plummet leading to a higher cost of
capital. Higher capital costs would require IOUs to raise retail rates. As more
customers reduce their usage or defect from the grid, the utility would have less
48
Kind, “Disruptive Challenges,”, 9-10.
49
Kind, “Disruptive Challenges,” 9.
50
Ibid.

21
customers to cover the costs of its fixed investments. It would have to raise rates to
cover these fixed costs and the remaining customers would be required to shoulder a
greater burden of the utilities’ investments. Many of these remaining customers would
likely react to these growing rate hikes by retrofitting their homes and adopting solar
panels as a cost competitive alternative. Some have referred to this phenomenon as
the utility industry’s potential “death spiral.”51
Figure 2.7: The So Called Utility Death Spiral
Source: EEI
The figure above represents a worst case scenario. While the aforementioned
disruption may not unfold with such severity, the IOU industry cannot ignore the threat
posed by these competitive forces. To overcome this dilemma, many analysts believe
the IOU industry will eventually need to adapt their business models. New business
models could permit IOUs to take advantage of new opportunities and to capture new
markets and revenue streams that could be a source of profit rather than a disruptive
threat. Specifically, some argue that IOUs should compete or offer services that work
in line with trends occurring along the consumer side of the distribution meter to
prevent such an outcome. This approach would require managers, shareholders and
regulators to develop new business models and regulatory frameworks to operate
beyond its duty as a commodity provider of centralized power. It would also require
the creation of new profit making incentives and scenarios for utilities to enter into the
distributed energy market.
51
Kind, “Disruptive challenges,” 11-12.

22
d. Investor Owned Utilities’ Financial Incentives
i. Profit Maximization through Capital Spending and Asset Growth
Ever since the famous Hope Case ruling “invested capital” became the main criterion
encouraging IOUs’ investment habits.52
Indeed, utility executives and shareholders
have a vested interested to boost capital expenditures as a means to enhance profits
since all of these fixed costs are automatically included into the rate base. Here is the
ratemaking formula that most utilities still use today:
• 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 = 𝐴𝑠𝑠𝑒𝑡𝑠 rate base 𝑥 𝑅𝑎𝑡𝑒 𝑜𝑓 𝑅𝑒𝑡𝑢𝑟𝑛 + 𝑂𝑝𝑒𝑟𝑎𝑡𝑖𝑛𝑔 𝐸𝑥𝑝𝑒𝑛𝑠𝑒
• 𝐶𝑢𝑠𝑡𝑜𝑚𝑒𝑟 𝑅𝑎𝑡𝑒𝑠 = 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 + 𝐹𝑢𝑒𝑙 𝐶𝑜𝑠𝑡𝑠53
As you can see, the utilities projected customer rates not only include all of its costs—
fixed, operational and variable costs—but also include a predetermined rate of return
attached to its capital investments. Because utilities’ capital spending offer a
compounded growth in relation to its rate of return, these companies have a perverse
incentive to spend on expensive supply side “generation and transmission” projects in
lieu of “demand reduction, consumer side initiatives” and other such alternative
demand side solutions.54
On the contrary, as our historical overview demonstrates,
utilities prefer to invest in projects that boost economies of scale and mass
consumption. Between 2003 and 2014, utilities’ capital spending more than doubled
and residential rates surged by 40% (see figure 2.8). This is problematic—and some
would argue a wasteful allocation of resources—since the benefits associated with
increasing economies of scale already reached its limits in the 1970s.
While a focus on increasing scale may have been ideal in the early to mid 20th
century,
this growth strategy is no longer as effective nor ideal in an era that places greater
priority on social, environmental and consumer value added factors. In contrast to
more competitive sectors, the electric industry’s static business model offers no
intrinsic incentive for efficiency or for innovative practices that could produce large
benefits to society at large. As will be argued later, the adoption of more distributed
energy resources may prevent the need to invest as heavily in such expensive
centralized generation facilities and T&D expansion projects.
52
53
54
Brooks, "The Periodic Table of the Electric Utility Landscape,” 89-90.

23
Figure 2.8: IOU Industry Capital Spending & Retail Rates
Source: EEI (spending), Department of Energy (prices), The Wall Street Journal
ii. Profit Maximization Through Sales and Revenue Growth
Like all businesses, IOUs have an intrinsic incentive to boost its sales. After all, extra
sales boost revenue and more revenue—once expenses are deducted—will create a
heftier bottom line. However, in the case of utilities, regulators set the rates to meet
the utility’s revenue requirement. For instance, using the regulatory principles of a cost
of service rate of return, the PUC will attempt to set rates so that gross revenues
“equal prudently incurred actual costs for the service proved plus a fair return on
invested capital.”55
In setting the rate, regulators typically “work backward”—that is,
they start with the “required revenue” amount they seek to achieve and then divide it
by the projected quantity of power sales they predict in their forecasts.56
For example,
if required revenue is $200 and estimated sales are 1,000 kWh, regulators will set the
average rate at 20 cents/kWh.57
After regulators establish the average rate, it tends to stay in place for about “two to
five years” before regulators will repeat the procedure.58
However, creating a static
regulated rate that endures unchanged for long periods of time “encourages larger
sales by utilities and discourages their energy efficiency efforts.”59
Because rates are
55
Fox-Penner, Peter. Smart power: Climate change, the Smart Grid and the Future of Electric Utilities.
Washington (2010), 181.
56
Ibid.
57
Ibid.
58
Ibid.
59
Ibid.

24
set in kilowatts per hour, the more kilowatt hours a utility sells will equate to larger
revenues for the company. Therefore, utilities will often attempt to sell beyond the
projected quantity estimated by the regulator. After all, more sales will eventually
translate into larger profits. Moreover, larger sales, which signals business growth, will
also please a company’s investors and shareholders—especially since such growth
justifies the need to construct more infrastructure to meet rising demand.60
As a result of this sales incentive, many IOUs tend to dislike distributed energy
resources, energy efficiency and other demand reducing entities or initiatives.
Consequently, until a utility’s regulation, business model and financial incentives are
adapted, utility shareholders and board members may continue to view demand side
management, energy efficiency and distributed energy resources as source of
competition rather than a business opportunity.
60
Fox-Penner, Peter. Smart power, 183.

25
Chapter 3
Current Industry Structure & Competitive Forces
A. Definition of Investor Owned Utility Electric Industry Today
To this day, many IOUs still operate in all segments of the electricity value chain—
from generation, transmission, distribution to retail. From the perspective of our
analysis, I will refer to this entire value chain—in aggregate or in its separate
components—as centralized power.
Regardless of the market they operate in, the IOUs—integrated or restructured—in
some way shape or form, generate, procure and distribute centralized power to a
variety of industrial, commercial and residential end users.
The structural analysis of the industry that follows will investigate and highlight the
competitive forces emerging outside of the traditional segments of this value chain. It
will especially demonstrate how distributed energy resources—represented by
photovoltaic solar panels in this analysis—will be playing a significant disruptive role in
the IOUs’ market power, industry structure and traditional business model.
B. Structural Analysis of the Investor Owned Utilities
In this current section, I will highlight the competitive forces and disruptive threats
emerging against IOUs.
Since the 1970s, IOUs faced competition from IPPs seeking to provide non-regulated
power mostly to industrial and commercial end users. Now a new wave of competition
has emerged in the form of distributed roof top solar companies. Unlike the earlier
wave of competition, which focused more widely on industrial and commercial users
exploiting cogeneration technology, providers of distributed roof top solar systems
include residential end users as one of their primary markets.
In the following section, we will look at how distributed solar providers represent
competitive entrants into the electricity market by circumventing the utilities
relationship with consumers and providing distributed power directly to end users.
To analyze this market trend, I will utilize Michael Porter’s paradigm for structural
analysis of industries. This analysis will particularly focus on the economic and
regulatory factors that raise and lower barriers of entry into state electric markets.

26
i. Threat of Entry into IOUs’ Market
According to Porter, the threat of entry in any given industry hinges upon the barriers
of entry in place, as well as the organized response from incumbent competitors an
entrant may face upon entering into the industry.61
In the analysis that follows, I have
added additional variables unique to the electric utility industry to create a more
detailed framework specific to the industry under consideration. The main barriers to
entry include the following:
a. Economies of Scale
As stated earlier in the chapter, IOUs centralized production of power utilizes
economies of scale to reduce its average total costs of generating and distributing
electricity. However, in general, economies of scale may create both barriers and
opportunities for third party solar entrants facing off against incumbent IOUs.
Since IOUs operate with scale efficiencies in the production of electricity, the
distributed roof top solar industry will face cost challenges against the incumbent
IOUs in certain markets across the United States where power prices remain lower
than average (see table 3.1). And, generally speaking, the industry will need to incur
heavy capital spending requirements to attain the cost benefits of scale.
Many vertically integrated IOUs operating in traditionally regulated markets may have
retained more cost benefits from scale vis-à-vis restructured IOUs that were forced to
divest their generation assets. In general, markets with vertically integrated utilities
offer lower rates than utilities operating in competitive markets.62
Therefore, markets
with vertically integrated IOUs—whether through price competition or regulatory
impediments—will likely retain stronger barriers to entry. These cost barriers will
generally be stronger in most—though not all—states in the south, northwest, lower
plains and upper plains.
While residentially scaled solar does not experience scale efficiencies in the
production of electrons, the PV panels used in such markets incur the benefits of
scale economies during its manufacturing phase. As the prices of PV modules have
declined from increased economies of scales, so too have PV sales and the level of
PV installations (see figure 3.1). As solar PV prices continue to decline from
technological improvements and scalability, third party solar operators should attract
more clients and further build its customer base. This will create competitive
pressures in certain markets where consumers have greater financial incentives to
61
Porter, Michael E. Competitive strategy: Techniques for analyzing industries and competitors. Simon and
Schuster, 1980, p. 7.
62
Johnston, David Cay. “Competitively Priced Electricity Cost More, Studies Show,” The New York Times. 06
November 2007.

27
switch over to a more cost competitive source of electricity—especially in regions that
charge end users higher retail rates.
Figure 3.1: Solar Prices & Installation Rates
Source: GTM Research, SEIA
Moreover, economies of scale no longer produces cost reduction benefits for IOUs.
Since the end of the IOUs “decreasing cost era” by the 1970s, the industry entered
into an increasing cost era. Now when a utility builds a new power plant or expands its
distribution network, the utility must raise its rates to cover these investments. These
rate increases (see figure 2.4 in the previous chapter) may impel some customers to
view a distributed solar system as a more cost competitive source of electricity—
especially in regions that charge end users higher retail rates.
b. Electricity Retail Rates
Regional electricity retail rates may create significant entry barriers—or
opportunities—for third party solar operators seeking to establish beach heads or
increase market share in certain markets. Retail rates for electricity vary significantly in
the United States. Where utility retail rates are lower than average, solar companies
may be much more reliant on government polices to create the financial incentives for
residential users to adopt solar panels.
Meanwhile, high retail rates create an enormous incentive for third party solar
companies to enter into a state’s market. As Christensen Associates highlights, “the
ten jurisdictions that offer the highest rate of return when tax incentives are removed

28
are present in states with retail rates that are 42% higher than those of the next ten
states.”63
Table 3.1 lists a selected sample of US states ordered by retail price.
In a number of states, electricity rates (measured in cents per kilowatt hour) have
climbed high enough that adopting solar for residential use has reached a point of
grid parity, i.e. the point in which the levelized cost of electricity (LCOE) for
distributed solar is less than or equal to the price of centralized grid power. According
to a report by Greentech Media, as of 2016, retail pricing in 20 states allow many
rooftop PV users to attain grid parity.64
Where local utility rates exceed 15 cents per
kilowatt hour, residential solar often becomes price competitive with grid power—
granting certain customers the opportunity to save money by producing their own
electricity.65
Moreover, if we assume that higher retail rates are correlated with higher
wholesale costs, then states with higher retail rates could be appealing for those
seeking higher net metering rates—even if the net metering credit offered in some
states is pushed below the retail rate. 66
This means that utility companies will most
likely face greater competitive threats in these jurisdictions where fundamental pricing
trends will impel residential users—even before artificial subsidies are accounted for—
to adopt solar panels as a means to save money on their monthly utility bills.
63
Olson, Wayne. “Customer Choice, Solar 3rd-Party Operators, Utility Ratemaking, and the Future of the
Electric Distribution Business,” Seeking Alpha. 29 February 2016.
64
However, most of these grid parity figures depend on government tax benefits and subsidies (such as net
metering). Munsell, Mike. “GTM Research: 20 States at Grid Parity for Residential Solar,” Greentech Media.
10 February 2016.
65
Biello, David. "Solar Wars." Scientific American 311.5 (2014): 66-71.
66
Olson, Wayne. “Customer Choice.”

29
Table 3.1: Ranking of States with Third Party Solar Operators by Retail Rate67
State 2015
Residential
Rate
(Cents/kWh)*
DG
Solar
Capacity
(Watts)
per
capita
(2016)
RTO Retail
Competition
SolarCity SunRun Vivint
Solar
Hawaii 29.61* 237.54 No No Yes Yes Yes
Connecticut 20.91* 46.51 ISO-NE Yes Yes Yes Yes
New York 18.57* 24.13 NYISO Yes Yes Yes Yes
New Hampshire 18.52* 19.77 ISO-NE Yes Yes Yes Yes
Massachusetts 19.81* 84.88 ISO-NE Yes Yes Yes Yes
Vermont 17.07* 88.01 ISO-NE No Yes No No
California 17.02* 93.47 CAISO No Yes Yes Yes
Rhode Island 19.29* 10.51 ISO-NE Yes Yes No No
New Jersey 15.97*
98.63 PJM Yes Yes Yes Yes
Delaware 13.46 57.40 PJM Yes Yes Yes No
Nevada 12.77 53.10 No No No No No
Maryland 13.91 54.59 PJM Yes Yes Yes Yes
Pennsylvania 13.84 12.4 PJM Yes Yes Yes Yes
South Carolina 12.42 1.88 No No No Yes Yes
Texas 11.64 5.42 ERCOT Yes Yes No No
Colorado 11.98 48.38 No No Yes Yes No
New Mexico 12.55 37.94 No No Yes No Yes
Arizona 12.18 98.11 No No Yes Yes Yes
Utah 10.98 20.33 No No No No Yes
Oregon 10.66 18.62 No No Yes Yes No
Washington 9.00 8.14 No No Yes No No
Source: Wayne Olson, EIA, US Census
As figure 3.2 below demonstrates, states in the Northeast, Southwest and California
have electricity rates that significantly exceed this price threshold. Thus far, service
areas that have surpassed this electricity rate threshold and/or offer strong solar
radiation have seen the largest adoption of solar panels.
67
Olson, Wayne. “Customer Choice”.
* These jurisdictions have retail rates at or above 15 cents/kWh, a price point that raises consumers’
incentive to use solar energy instead of utility power.

30
Figure 3.2: Nationwide Electricity Rates by County
Source: US News, Joshua Rhodes, University of Texas at Austin
c. Soft Costs
Perhaps one of the biggest cost hurdles third party solar companies must overcome
are soft costs. Soft costs are all of the non-hardware costs involved in the
development of a solar project. These include financing costs, installation labor,
permitting, inspection and interconnection fees, and customer acquisition costs. While
China’s massive output of PV panels have significantly pushed down hardware costs,
soft costs—accounting for as much as 64% of the total system costs—are now seen
as the biggest hurdle in solar deployment.68
68
Office of Energy Efficiency & Renewable Energy. “Soft Costs,” http://energy.gov/eere/sunshot/soft-costs

31
Although the
U.S.
Department of
Energy Sunshot
Initiative’s soft
cost program
seeks to lower
these costs
through data
analysis,
training
programs,
business
innovation and
networking and
technical
assistance to
state and local
lawmakers, this
will be a difficult
challenge
because of the United States’ “fragmented energy marketplace.”69
In the U.S. “there
are over 18,000 jurisdictions and 3,000 utilities” that impose unique “rules and
regulations” for solar projects.70
However, greater market growth, competition and
more streamlined and standardized rulemaking and regulation could significantly
lower these costs. For instance, in 2013, German solar soft costs were $0.33 per watt;
at the same time, they were $1.22 per watt in the U.S.—about 3.7 times higher.71
As of the fourth quarter of 2015, total system costs for residential solar systems fell to
$3.50 per watt—though soft costs actually rose by 7 percent due to customer
acquisition costs.72
Therefore, soft costs are stymying efforts to reduce residential
solar system costs and LCOE.73
The DOE’s Sunshot Initiative aims to reduce
69
US Department of Energy. “Soft Costs Fact Sheet,” May 2016.
http://energy.gov/sites/prod/files/2016/05/f32/SC%20Fact%20Sheet-508.pdf
70
US Department of Energy. “Soft Costs Fact Sheet,” May 2016.
71
Calhoun, Koben and Jesse Morris. “Can the Cost of Solar in the US Compete with Germany?” Rocky
Mountain Institute. 05 December 2013.
http://blog.rmi.org/blog_2013_12_05_can_usa_solar_cost_compete_with_germany
72
Gallagher, Ben. “Pricing for Solar Systems in the U.S. Dropped 17% in 2015,” Greentech Media. 15 March
2016. http://www.greentechmedia.com/articles/read/Pricing-For-Solar-Systems-in-the-US-Dropped-17-in-
2015
73
The DOE defines the LCOE as “the ratio of an electricity-generation system’s costs to the electricity
generated by the system over its operational lifetime, given units of cents/kilowatt-hour (kWh).” A system’s
LCOE is “sensitive to installed costs, O&M costs, local solar resource and climate, PV panel orientation,
financing terms, system lifetime, taxation and policy.” For more information, see Sunshot Vision Study, 76:
http://energy.gov/sites/prod/files/2014/01/f7/47927_chapter4.pdf.
Figure 3.3: Soft Costs for A Typical Solar Installation
Source: Department of Energy

32
residential solar system costs to $1.50 per watt by 2020—mainly by reducing soft
costs. If the DOE is successful in this endeavor, the LCOE of solar PV systems in
certain jurisdictions could become less than or equal to the LCOE of utility retail rates.
This would mean solar systems in such localities would attain grid parity—that is, the
cost of generating residential solar would be equal to or cheaper than consuming
electricity from the grid.
Greater collaboration and cooperation between the private and public sector and
federal and local governments could reduce these costs. If so, as system costs
decline, more jurisdictions may attain grid parity and residential solar development will
accelerate even further. To see how this may play out, figure 3.4 shows how reducing
residential system costs from $3.50 per watt to $1.50 per watt could enable
jurisdictions in almost all of the lower 48 US states to attain grid parity.74
Therefore, if
residential solar soft costs continue to decline, IOUs’ protective barriers may erode at
an even faster rate.
Figure 3.4: Residential PV System Costs Reaching Grid Parity
Source: US News, Joshua Rhodes, University of Texas at Austin
d. Product Differentiation
Companies attain product differentiation when they possess “brand identification and
customer loyalties” from “advertising, customer service, product differences or simply
being the first in the industry.”75
Most IOUs—at least at the distribution level—possess
a captive market due to their monopolized status. As a result, these distribution utility
companies have not had much incentive to offer differentiated energy products or
services. Rather, they have merely sold their product to consumers as a commodity.
Hence, brand identification stems mostly from its market power and monopoly status,
not due to the nature of the product or service rendered.
74
Grid parity estimates often rely on assumptions such as net metering compensation at retail rates and
other market enabling incentives like state and federal tax credits.
75
Porter, 9.

33
By contrast, solar companies have a wide range of means to differentiate their
product from the commoditized electricity sold by utility companies. Firstly, solar
energy produces its electricity from a renewable resource: the sun. The product’s
“green” credentials have already won over many environmentalists seeking to
consume cleaner forms of energy. Other conservative or libertarian minded
consumers celebrate how the product would promote more energy independence and
boost self-reliance.76
The introduction of affordable rooftop solar panels, therefore,
would please a large group of consumers.
While energy storage technologies needed to go “off-grid” are still fairly expensive,
there are still consumers seeking to develop micro-grids and community solar projects
as a means to limit full reliance upon centralized power.
Increasingly, some third party non-utility companies are offering “value added
services” to further differentiate their company offerings from incumbent utilities. In
the future, we may see both distributed rooftop solar companies and utilities including
more “value added” services into their business models as competition along the
distribution edge of the grid becomes more intense.
However, at the moment, lack of product differentiation is a highlighted weakness of
the IOUs that lowers the barriers of entry into the power industry. Third party
companies will likely exploit product differentiation in order to attract a customer base
seeking clean energy and greater energy independence.
e. Capital Requirements
Capital requirements to enter in the power industry have always been high, creating a
significant barrier to entry. Utility companies often allocate billions of dollars annually
toward capital expenditures, though, as previously mentioned, these costs are
recovered when regulators set the electricity rates in each service area. By contrast,
non-regulated electricity companies face greater challenges in meeting capital
requirements, raising capital and recovering the costs of these investments.
As a basis of comparison, SolarCity, a vertically integrated roof top solar company,
spent $1.8 billion in capex in 2015.77
Since its IPO in 2011, SolarCity reported growing
negative free cash flows. By contrast, in 2015, Con Edison spent $3.2 billion and
Southern Co allocated $7.4 billion in capex. In the past five years, Con Edison
sustained positive cash flows; Southern Co reported negative free cash flows in the
past two years, but, with such large operating cash flows and regulatory protection,
the company can afford to take on moderate losses. The graphs below demonstrate
how high capital requirements can challenge an industry entrant’s financial health.
76
Biello, 70
77
Financial data in this section obtained from Morningstar.com.

34
Mature companies operating in a stable industry environment, on the other hand, can
more predictably and easily translate these capital expenditures into a healthy return
on investment.
This large capital requirement could give some utility companies a distinct advantage
in entering the distributed solar rooftop space. An entrant like SolarCity or SunRun, by
contrast, must be willing and able to accept large—and potentially unrecoverable—
start-up losses to enter into a new market and compete with an established industry.
New entrants assuming loads of debt, reporting negative cash outflows and
attempting to take on stable cash flow positive industries like the IOUs would likely
require ongoing access to capital markets and favorable government subsidies to stay
afloat.
These high capital costs combined with fierce competition in the PV solar sector could
put additional pressure on margins leading to bankruptcies, mergers and acquisitions
and/or greater vertical integration.78,79
As an example, in 2011, Total SA, one of
Europe’s largest oil companies, bought a 60% stake of Sunpower Inc.80
As part of the
deal, Total offered Sunpower a $1 billion line of credit and with cheaper borrowing
costs, it may be able to help Sunpower procure cheaper capital as needed.81
While
these capital costs for solar companies seem like an insurmountable burden in the
short run, if the residential PV industry potentially consolidates in such a way, the
economics of residential solar continues to improve and residential solar assumes
larger market share in the generation mix of a utility’s service territory, cash flows and
margins could surge into healthier levels. Should this happen, capital outlays could
one day become much more manageable for the residential solar industry.
78
Ali-Oettinger, Shamsiah. “More mergers and acquisitions to come,” PV Magazine. 22 July 2015.
http://www.pv-magazine.com/news/details/beitrag/more-mergers-and-acquisitions-to-come_100020302/
79
Groom, Nichola. “Solar company Sungevity to go public in reverse merger,” Reuters. 29 June 2016.
http://www.reuters.com/article/us-sungevity-easterlyacquisition-idUSKCN0ZF1HS
80
Herndon Andrew, et al. “Total to Buy 60% of SunPower for $1.38 Billion in Solar Bet,” Bloomberg. 29 April
2011. http://www.bloomberg.com/news/articles/2011-04-28/total-to-begin-friendly-tender-for-up-to-60-of-
sunpower-shares
81
Herndon Andrew, et al. “Total to Buy 60% of SunPower for $1.38 Billion in Solar Bet,” Bloomberg. 29 April
2011.

35
Figure 3.5: Capital Expenditures & Financial Performance of Pure Play Residential Solar
Companies, USD in Thousands82
82
The emerging rooftop solar industry requires immense capital spending to fuel its growth. However, SolarCity
and SunRun have reported negative free cash flows and negative profit margins since their respective IPOs.
These companies will continue to rely on further injections of debt and/or equity from capital markets as well as
government subsidies while they attempt to expand their market share vis-à-vis utility companies and develop
positive cash flows. (Financial data from Morningstar).

36
Figure 3.6: Capital Expenditures & Financial Performance of IOUs,
USD in Thousands83
83
These graphs demonstrate how the IOU industry also utilizes heavy capital spending to boost profits. Although
utilities worry how widespread distributed solar adoption could undermine the industry’s profitability in the long
run, so far their cash flows and margins remain at healthy levels. This financial strength gives IOUs a competitive
advantage over its solar competitors. (Financial data from Morningstar).

37
Figure 3.7: EBITDA Comparison of Solar Providers & IOUs, USD in Thousands84
84
Rooftop solar companies’ growing negative EBITDA demonstrates that it suffers problems producing both
profit and cash flow. As more customers adopt solar panels, these companies may be able to overcome these
financial difficulties. In the meantime, this metric is a further demonstration of the solar industry’s over reliance on
capital markets to stay afloat. (Financial Data from Morningstar).

38
f. Switching Costs
Switching costs are defined as one-time costs consumers endure when switching
from one product to another. For some, this could include the cost of learning how to
use the new system. Since most distributed solar users remain connected to the grid
and use centralized power as a secondary source of power, switching costs should be
scant. For customers seeking to go off the grid completely—which would require
some sort of storage device synced to the solar panels—switching costs would likely
be more significant for customers unwilling to deal with this cost. Switching costs
could create a barrier in customer acquisition.
g. Solar Insolation and Capacity Factors
Solar electricity produced by a photovoltaic system is an intermittent source of
energy—that is, it only generates electricity while the sun shines. Moreover, as a result
of geographic sunlight variations, PV systems produce different quantities of
electricity in different regions. A map from NREL (figure 3.8) shows the PV solar
radiation differentiation in the United States—and even variation between regions
within each state. This variation in annual solar irradiance—or solar insolation—can
significantly alter how much electricity a solar panel generates over the course of its
productive lifespan. Since many PV owners receive financial compensation for the
electricity they generate, this variation in solar irradiance can alter the financial
performance of a PV system. Using a financial model, analysts can estimate the cash
flows a PV system will produce over the course of its economic lifespan. One of the
project performance assumptions an analyst can manipulate in the model is the
system’s capacity factor. The capacity factor is a ratio that measures the amount of
electricity a plant produces divided by the total amount of electricity it could have
produced if it were hypothetically running 100% of the time over the course of a year.
Basically, generating technologies with higher capacity factors have the capacity to
generate more electricity during the course of a year.
• 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 𝐹𝑎𝑐𝑡𝑜𝑟 =
DEFGHI JKL MNOPGEQP MQN RQHN
JKL MQN RQHN HF NHFQP OGFMGF × TUVW LOGNX MQN RQHN
Table 3.2: Average Capacity Factors for Generation Technologies85
Plant Type Capacity Factor (%)
Dispatchable Technologies
Combined Cycle Gas Turbine 87
Advanced Nuclear 90
Geothermal 91
Non Dispatchable Technologies
Wind 42
Solar PV 26
Source: EIA
85
Table 3.2 shows that solar PVs have a lower capacity factor in relation to other generation technologies.
However, a solar panel that can store its surplus energy for later use would have a higher capacity factor. If
manufacturers can reduce the cost of batteries, the economics of solar would become even more attractive.

39
Due to geographic considerations, seasonal variability, system design and
deployment decisions (which include PV panel efficiency levels, level of shading, array
tilt and optional sun tracking technologies) solar PV capacity factors will vary.
However, generally speaking, sunnier regions that offer PV owners higher capacity
factors will allow users to generate more electricity than in shadier or sun deprived
regions that would lower a system’s capacity factor. In less sunny regions, a system
may not produce sufficient cash flows to justify the purchase of the PV system—
though there are other important variables that would often need to be accounted for
to reach such a conclusion.,86
Figure 3.8: PV Solar Insolation Across the US
Source: NREL
In reality, the capacity factor is only one input impacting potential cash flows. Another
important variable, as we have already noted, is the retail rate. The map below (figure
3.9) shows how both retail rates and solar strength are separate inputs that—
together—can alter the economic outcome of a solar project. As the map highlights,
86
Project developers can use proprietary financial models or publicly available ones such as NREL’s Cost of
Renewable Energy Spreadsheet Tool (CREST) or System Advisor Model (SAM) to see how capacity factors and
other economic assumptions impact the overall financial viability of installing a PV system. See (NREL. “CREST
Cost of Energy Models,” https://financere.nrel.gov/finance/content/CREST-model) and (NREL. “System Advisor
Model,” https://sam.nrel.gov/) for more information.

40
California and Hawaii have both high retail rates and high solar insolation. Many areas
in the southwest have lower retail rates. However, this is offset by the region’s strong
annual solar irradiance and higher capacity factors. The northeast region is reversed;
the retail rates are high and insolation levels are low. In these jurisdictions, PV systems
can often produce sufficient cash flows in spite of the lower capacity factors. Finally,
while Alaska has expensive retail rates, the state’s extremely low solar insolation levels
pushes down the capacity factor for PV system. This would likely reduce the
economic viability of solar in Alaska and help explain why Alaska has virtually no
installed distributed solar capacity in the state. Hence, jurisdictions with extremely low
solar irradiance can be a potential barrier for solar development.
Figure 3.9: Solar Insolation & Retail Rates Shape the Economics and Finance of Solar Systems
h. Key Government Policy Drivers Stimulating Residential Solar PV Markets
Government policies have the power to reinforce or reduce barriers to entry to any
given industry—especially highly regulated industries such as the electricity sector.
For most of the 20th
century, government regulation has greatly benefited the IOU
industry. However, in the past 30 years, federal and state governments have designed
standards and encouraged the development of renewable electricity. Some of these
regulatory changes have also forced the utilities to slightly modify their business
practices and have opened up the electricity sector to greater levels of competition.

41
In the following sections, I will enumerate and explain the most important government
policies that have encouraged the development of the distributed PV solar market.
h.1 Net Metering & Interconnection Standards
Another potential market barrier to entry for any business is the need to access
distribution channels to deliver its product.87
As it turns out, residential solar markets
depend on access to a utility’s distribution network because most homeowners with
solar panels can receive compensation for their surplus electricity through an
arrangement made with their local utility companies.
Through a policy known as net energy metering (NEM), owners of rooftop solar
panels who receive authorization from their utility can connect their solar panels to the
utility’s local distribution system. Through the NEM arrangement, a bidirectional meter
is installed at the end user’s residence that measures both the inflows of grid power
and outflows of surplus solar electricity sent back to the grid. During the course of
each billing period, customers only pay for the net amount of electricity consumed at
that time. For customers that produce ample solar power, this means they can, at
times, “zero-out their utility bill.”88
During especially productive billing periods, they
can even produce surplus power, which can then be credited toward future billing
periods.89
While owners of rooftop solar panels—so long as they have ample storage
capabilities—could in theory produce their own electricity off the grid all of the time—
most potential consumers would need access to the grid and NEM in order to even
make the investment a viable option.90
For this reason, quick and affordable interconnection to the grid—without debilitating
red tape—and the capacity to sell net excess generation (NEG) through NEM to local
distribution utilities is arguably the key market-enabling policy driver for residential
solar markets.91,92
While 41 states offer NEM, the terms, limits and stability of NEM
policy vary in each state and these variations impact the effectiveness of the NEM
program as an market enabling tool. Interconnection best practices and standards
also vary significantly. Historically, states that have had fewer NEM restrictions and
laxer interconnection standards have developed more robust residential solar
markets.
87
Porter, 10.
88
California Energy Commission & CPUC. “Net Energy Metering in California,”
http://www.gosolarcalifornia.ca.gov/solar_basics/net_metering.php
89
Biello, 68
90
Due to high costs, battery storage technologies are too expensive for most residential solar users.
91
Interconnection is defined as the “technical rules and procedures allowing customers to plug into the
grid.” Some states and municipalities have more onerous procedures to connect to the grid. These
interconnection delays significantly raise the solar system’s soft costs. See www.freeingthegrid.org for more
details.
92
Steward, D and E. Doris. “The Effect of State Policy Suites on the Development of Solar Markets,”
National Renewable Energy Laboratory. November 2014.

42
h.2 Economics of Net Energy Metering
Many customers, attracted by the prospect of lower monthly utility bills via net
metering, have signed solar leases or loans with companies such as SolarCity or
Vivint. Either way, NEM plays a crucial role in the economics of solar leases and loans.
Without the financial benefit provided by NEM, many consumers would be unwilling or
unable to adopt rooftop solar panels. In fact, 99% of the 1,957 MW of installed
residential PV systems in the U.S. during 2015 were net metered, which seems to
indicate the importance of the policy in enabling consumers to afford the investment.93
Alternatives to net metering—such as utility-owned residential programs and solar
tariffs—represented less than 1% and almost 1% of installations, respectively.94
Until
these emerging alternatives or other experimental policies, incentives or programs
come to fruition, NEM will continue to be the most pertinent market enabling tool—
especially when working in tandem with other policies and incentives.
The Interstate Renewable Energy Council (IREC), one of the contributors at
freeingthegrid.org, defines NEM as the “billing arrangement by which customers
realize savings from their systems where 1kWh generated by the customer has the
exact same value as 1kWh consumed by the customer.”95
In practice, compensation
rates vary. According to the Database of State Incentives for Renewables & Efficiency
(DSIRE), only 11 states firmly compensate net excess generation (NEG), at the retail
rate.96
However, in total, about 32 states compensate net excess generation at or near
the retail rate. Another 21 states initially remunerate NEG at the retail rate, however,
NEG credits rolled over for the following months eventually expire or are reduced to
the utility’s avoided cost.97
Currently, nine states compensate below the retail rate—
though with the utility industry’s antipathy toward NEM policies, this number may
grow.
Until recently, the current top ten states ranked by installed residential solar capacity
all had stable NEM policies with NEG compensated at retail rates. In the past year,
Hawaii and Nevada—ranked number 1 and number 9 in installed watts per capita of
distributed generated solar energy respectively—both drastically changed their NEM
policies. Hawaii cancelled its NEM program. Although Hawaii is projected to install
105 MW of residential solar in 2016—a 57% increase from the previous year—many of
these projects are merely delayed interconnections in the pipeline from the previous
93
“2015 Solar Market Snapshot,” Smart Electric Power Alliance. Accessed 1 July 2016.
https://www.solarelectricpower.org/discover-resources/solar-tools/2015-solar-power-rankings.aspx
94
“2015 Solar Market Snapshot,” Smart Electric Power Alliance. Accessed 1 July 2016.
95
Freeing the Grid. Accessed 31 June 2016. http://freeingthegrid.org/
96
DSIRE. “Customer Credits for Monthly NEG Under Net Metering,” Accessed 1 July 2016.
http://ncsolarcen-prod.s3.amazonaws.com/wp-content/uploads/2016/01/NEG-1.2016.pdf
97
DSIRE. “Customer Credits for Monthly NEG Under Net Metering.”

43
year still qualifying for the NEM.98
Since the state dismantled its NEM program, solar
companies have shed 39% of its workforce.99
The number of permits issued in the
state in June 2016 fell by 42% compared to the previous year.100
In fact, the Hawaii
Solar Energy Association (HSEA) claims that “unless the Hawaii PUC approves a
motion filed by the HSEA to increase the cap on a new program that replaced net
metering,” the state’s solar industry will likely continue to deteriorate.101
Meanwhile, Nevada’s PUC will incrementally triple net metered users’ monthly grid
access fee and will gradually reduce NEG compensation to the state’s wholesale
rate—approximately 2 cents per kilowatt hour—over the next twelve years.102
For
means of comparison, Nevada’s average retail rate in 2015 was around $0.12 cents
per kilowatt hour. Table 3.3 shows Nevada’s net energy metering rate change
forecast.
Table 3.3: Southern Nevada Net Metering Rate Change Forecast
Date Grid Access Fee Retail Rate Excess Energy Credit
Prior rate $12.75 $0.11 $0.11
Jan 1 2016 $17.90 $0.11 $0.09
Jan 1 2019 $23.05 $0.10 $0.07
Jan 1 2022 $28.21 $0.10 $0.05
Jan 1 2025 $33.36 $0.10 $0.04
Jan 1 2028 $38.51 $0.10 $0.02
Source: NV Energy
In general, before accounting for incentives, the cost of a residential solar PV system
ranges between $0.25 to $0.30 cents per kilowatt hour.103
Federal and state tax
incentives and subsidies tend to push the system cost down to around $0.15 cents
per kilowatt hour.104
Without the cash flow benefits of retail rated net metering, solar
98
Walton, Robert. “Hawaii Solar Sector Braces for Job Losses after Net Metering Decision,” Utility Dive. 29
March 2016. http://www.utilitydive.com/news/hawaii-solar-sector-braces-for-job-losses-after-net-metering-
decision/416417/
99
Shimogawa, Duane. “Large majority of Hawaii solar companies reporting job losses,” Pacific Business
News. 06 July 2016. http://www.bizjournals.com/pacific/news/2016/07/06/large-majority-of-hawaii-solar-
companies-reporting.html
100
Shimogawa, Duane. “Oahu solar energy industry continues to cool down,” Pacific Business News. 05
July 2016. http://www.bizjournals.com/pacific/news/2016/07/05/oahu-solar-energy-industry-continues-to-
cool-down.html
101
Shimogawa, Duane. “Large majority of Hawaii solar companies reporting job losses.”
102
“Southern Nevada 12-Year Net-Metering Rate Change Forecast” NVEnergy. Accessed 05 July 2016.
https://www.nvenergy.com/renewablesenvironment/renewablegenerations/NetMetering.cfm?utm_source=nv
e_frontpage&utm_medium=banner&utm_content=net-meter-rates&utm_campaign=net-meter-ratesFP
103
Martin, Richard. “Battles Over Net Metering Cloud the Future of Rooftop Solar,” MIT Technology Review.
05 January 2016. https://www.technologyreview.com/s/545146/battles-over-net-metering-cloud-the-future-
of-rooftop-solar/
104
Martin, Richard. “Battles Over Net Metering.”

44
systems in regions with retail rates lower than $0.15 cents per kilowatt hour will
generally offer a poor return on investment.105
With net metering compensated at retail rates, Nevada’s residential solar installations
grew by 600% in 2014 and 2015. Since the PUC’s policy change, installation rates are
projected to shrink by 73%.106
According to Bloomberg, Nevada’s new regulations
“not only make it more expensive to go solar, but also make it uneconomical for those
who have already signed up.”107
Put simply, for most residential rate payers in Nevada,
the cost of solar panels is now no longer financially viable. This explains why all the
major rooftop solar companies immediately abandoned Nevada’s market after the
PUC ruling.108
Under the right set of circumstances, NEM can allow owners of solar energy systems
to recoup the cost of their investments. However, the lifetime revenue potential and
speed of cost recovery for the system heavily depends on two variables: how much
electricity is produced and how much the customer is paid for the excess
generation.109
I already discussed the first variable (the capacity factor) in the previous
section. The second variable (the credited NEM rate) depends on the retail rate of the
state and on the compensation rate awarded for the NEG. Both of these factors vary
by state and can have an enormous impact on the lifetime revenue potential, internal
rate of return and net present value of a residential solar PV investment. As you can
see in table 3.4, historically the states with the most installed solar capacity mostly
had stable NEM programs credited at the retail rate for many years.
While other supportive policy factors and non-policy factors (such as the capacity
factor) also play a significant role in enabling solar markets generally and in increasing
the lifetime revenue potential from net metering more specifically, for over several
years the top ten states ranked by installed residential solar capacity all had stable
NEM policies with NEG compensated at retail rates. As we have seen in the case of
Nevada, these NEM credits play a crucial role in making solar an attractive investment
in states that have lower retail rates. Although reducing the compensation rate would
raise barriers to entry for solar companies in all of the states with retail rated NEM,
lower compensation would have a much more pronounced effect in states with lower
retail rates.
105
Ibid.
106
Bromley, Hugh et al. “2016 US PV Market Outlook,” 06 June 2016. Bloomberg New Energy Finance.
107
Buyahar, Noah. “Who Owns the Sun?” Bloomberg Businessweek. 28 January 2016.
108
Buyahar, Noah. “Who Owns the Sun?”
109
To analyze all of the variables and financial assumptions involved in the lifetime revenue potential
calculation from net metering, see Steward D and E. Doris, “The Effects of State Policy Suites on the
Development of Solar Markets,” NREL, 2012, 21-25.

45
Table 3.4: NEM Rates in Top 10 DG Markets by Per Capita Installations, 2016
Rank State
Net Metering Rate
2016
Average Retail
Price (Cents per
Kilowatt Hour)
2015
Total Distributed Solar
PV Installed (Watts) Per
Capita 2016
1
Hawaii
Suspended* 29.61 273.54
2
New Jersey
Retail Rate 15.97 98.63
3
Arizona
Retail Rate† 12.18 98.11
4
California
5
Vermont
6
Massachusetts
Less than retail rate** 19.81 84.88
7
Delaware
Retail rate† 13.46 57.40
8
Maryland
9
Nevada
Less than retail rate*† 12.77 53.10
10
Colorado
Source: (DSIRE, EIA, U.S. Census) * Previously compensated at retail rate. ** Varies by customer class
h.3 Will Clashes Over Net Metering Undermine the Future of Residential Solar?
Recently, many IOUs have been concerned that the rapid rise of net energy metered
solar customers will undermine their efforts to recover costs for their companies’ fixed
investments. These IOUs claim that net metered customers utilize the distribution
network without adequately paying for these fixed costs as estimated by their cost of
service ratemaking models. In response to these concerns, over the past year about
half of the US state PUCs—at the behest of IOUs—ordered studies in order to
consider changing their states’ existing NEM policies.110
The list of possible changes111
presently under consideration include:
o The implementation of monthly grid access fees. Monthly grid access
fees could permit utilities to hedge against revenue losses caused by
their rooftop solar customer’s load defection and to cover the fixed costs
of its distribution network. However, large monthly fees, could undercut
the economic viability of solar adoption.
† States with retail rates below 15 cents per kilowatt-hours tend to be more reliant on retail rated NEM to
bolster their solar markets.
110
Meyers, Glenn. “Changing Net Metering Policies Being Studied In Over Half of US States,” Clean
Technica. 16 November 2015. http://cleantechnica.com/2015/11/16/changing-net-metering-policies-studied-
half-us-states/
111
Mints, Paula. “Notes from the Solar Underground: The US Utility War against Net Metering,” Renewable
Energy World. 23 February 2016. http://www.renewableenergyworld.com/articles/2016/02/notes-from-the-
solar-underground-the-us-utility-war-against-net-metering.html

46
o Reducing the remuneration rate for net excess generation to the utility’s
avoided cost (i.e. wholesale rate). Until an alternative compensation
scheme for net excess generation is considered, slashing the
compensation rates from retail rates to wholesale rates will hamper the
growth of many residential solar markets.
o The adoption of demand charges or time of use rates. Lower
compensation for off peak rates and higher prices during peak hours
could undermine the economic benefits to net metered solar
customers.112
o Ending net metering programs or upholding service territory’s net
metering cap.113
As states approach the stated net metering caps in their
service territories, utilities may press regulators to uphold the cap rather
than raise it. Other states that experience rapid growth may pause or
cancel their net metering program in order to maintain “grid stability.”114
This could impede further residential solar market growth by eroding the
arrangement that made such investments financially viable in the first
place.
112
Mints, Paula. “Notes from the Solar Underground.”
113
For recent figures on net metering caps by state, see Barnes, Justin and Rusty Haynes, “The Great
Guessing Game: How Much Net Metering Capacity is Left?,” EQ Research. September 2015. http://eq-
research.com/blog/the-great-guessing-game/
114
Smith, Rebecca and Lynn Cook. “Hawaii Wrestles with Vagaries of Solar Power,” The Wall Street Journal.
28 June 2015. http://www.wsj.com/articles/hawaii-wrestles-with-vagaries-of-solar-power-1435532277

47
Some states with high residential
solar penetration have already
started to implement some or a
combination of these policies
ostensibly to recoup revenue
losses from load defection. In
2015, twenty seven states in all
contemplated potential changes
to net metering compensation
arrangements.115
Meanwhile,
“sixty-one utilities in 30 states
proposed monthly fixed charge
increases and twenty-one utilities
in 13 states propose new or
increased existing charges
specific to rooftop solar
customers.”116
Overall, for both the distributed
solar industry and the IOU
industry, changes—or the lack
thereof—in net metering represent
a risk to their businesses—though
especially for rooftop solar
companies dependent on third
party leasing and loan schemes.
Until another alternative mechanism with widespread appeal can replace the market
enabling function of NEM, government regulation over net metering policies will
continue to be a contentious issue between IOUs and solar advocates. PUCs—or in
some cases state legislatures—regularly have the power to alter net metering quotas
and compensation levels. The decisions made by policymakers or regulatory bodies of
each state could raise or lower barriers to entry by voting against or in favor of net
metering.
h.4 Interconnection Standards
In accordance with guidelines set by state PUCs, distribution utilities need to analyze
and provide an approval to new renewable electricity generators that enter into their
service territory. IOUs decide which generators may or may not connect to their
distribution network and what conditions they must meet to achieve interconnection.
These procedures can create substantial barriers to entry for those seeking to install
115
Trabish, Herman K. “5 maps that show where the action is on solar policy,” Utility Dive. 22 March 2016.
http://www.utilitydive.com/news/5-maps-that-show-where-the-action-is-on-solar-policy/415938/
116
Trabish, Herman K. “5 maps that show where the action is on solar policy.”
Figure 3.10: State Changes to NEM Polices
Source: Wall Street Journal, GTM Research, SEIA

48
distributed energy systems. In cases where interconnection regulations “are unclear,
or where redundant or unnecessary tests or steps are piled on the existing national
standards, the results can be costly.”117
As a result of these varying standards, where
some utilities take as little as one week to connect a solar system to their grid, others
take well over two and a half months.118
Where such conditions exist, soft costs will be
higher and serve as a stronger barrier to entry for residential solar systems.119,120
Figure 3.11: Interconnection Standards by State
Source: Center for Biological Diversity, IREC, DSIRE, Freeingthegrid.org
h.5 Federal Tax Credit
The solar investment tax credit (ITC) is one of the main federal policy instruments
currently stimulating solar development in the United States. The Energy Policy Act of
2005 instituted a 30 percent ITC for commercial and residential solar projects ordered
between January 1st
2006 and December 31st
2007. In 2008, Congress extended the
ITC for an additional 8 years as part of an agreement reached in the Emergency
Economic Stabilization Act. Most recently, in December 2015, Congress further
extended the ITC to December 31st
2022. Under the auspices of the Consolidated
117
See http://freeingthegrid.org/#education-center/interconnection/
118
Bogage, Jacob. “Study: Pepco is the country’s worst utility at connecting solar power,” The Washington
Post. 21 July 2015. https://www.washingtonpost.com/news/energy-environment/wp/2015/07/21/study-
pepco-is-the-countrys-worst-utility-at-connecting-solar-power/
119
For a detailed national comparison of interconnections standards by state, visit http://freeingthegrid.org.
120
Marcacci, Silvio. “Solar Interconnection Delays Cost Americans Millions—Here’s How We Solve Them,”
Clean Technica. 12 August 2015. http://cleantechnica.com/2015/08/12/solar-interconnection-delays-cost-
america-millions-heres-solve/

49
Appropriations Act, the 30% credit will slowly wind down incrementally starting in
2020 to 26% until settling to 10% in 2022. After 2022, the rate will linger at 10% for
commercial projects—though the tax credit will no longer apply to residential
installations. Assuming there are no more future extensions, the tax credit phase out
will proceed as follows:
Table 3.5: Solar Investment Tax Credit Time Horizon121
Year 2016 - 2019 12/31/20 12/31/21 12/31/22 Future
Years*
Solar ITC
Rate
30% 26% 22% 10% 10%
Source: Department of Energy *ITC only available for commercial projects after 2022.
For the residential solar market, these tax credits are awarded to homeowners who
purchase the solar panels. For those who sign solar lease agreements with third party
providers like SolarCity, “banks like Goldman Sachs Group Inc and J.P. Morgan
Chase & Co.” receive the tax credits because they are the institutions who finance
those installations.122
In either case, whether they are the homeowners or financial
institutions, the equity holders assume the most risk in undertaking any investment.
The ITC and other tax incentives—such as accelerated depreciation—allow equity
investors to more quickly recover the cost of their investment, increase cash flows and
increase the investments’ rate of return. Since equity investors assume the most risk
in any project, tax incentives can offer attractive rewards that encourage these
investors to assume more risk.
The graph below (figure 3.12) shows how solar installations dramatically expanded by
“a compound rate of 76 percent” since 2006.123
For over 10 years, the ITC has been
one of the main engines stimulating the boom in solar investments. According to
Christensen Associates Energy Consulting, the ITC “accounts for 40% to 50% of solar
developers net profits on residential installations.”124
Consequently, it will continue to
be a pivotal policy driver boosting rooftop solar installations going into the next
decade. The policy’s long extensions and gradual rate declines will provide ongoing
stability and predictability for investors and the market as a whole.
121
Department of Energy. “Business Energy Investment Tax Credit,” Accessed 05 July 2016.
http://energy.gov/savings/business-energy-investment-tax-credit-itc
122
Sweet, Cassandra. “Wind, Solar Companies Get Boost From Tax-Credit Extension,” The Wall Street
Journal. 16 December 2015.
123
Martin, Richard. “Tax Credit Extension Gives Solar Industry New Boom,” MIT Technology Review. 28
December 2015. https://www.technologyreview.com/s/544981/tax-credit-extension-gives-solar-industry-a-
new-boom/
124
Morey, Mathew, et al. “Retail Choice in Electricity: “What Have We Learned in 20 Years?,” Christensen
Associates Energy Consulting. 11 February 2016., p. 9.

50
Figure 3.12: ITC Stimulates Annual Solar Installations
Source: SEIA
h.6 Renewable Portfolio Standards & Solar Carve Outs
Across the United States, renewable portfolio standards (RPS) have played a
substantial role in meeting renewable energy development goals. These state-wide
directives force utilities to include a certain percentage or level of renewable power
into their generation and/or distribution portfolio. While RPSs have helped stimulate
solar development throughout the US, RPS requirements vary within each state. In all,
29 states have firmly committed to binding RPS standards; eight others have
established non-binding renewable energy goals. Of the 29 states in the former
category, 21 states included explicit solar or distributed generation (DG) carve-outs
within their RPS requirements to nurture solar and/or DG markets in these states.
Certain states with solar carve outs have even developed tradable Solar Renewable
Energy Credit (SREC) markets where utilities can meet their RPS requirements by
purchasing the energy produced from non-utility owned solar generators.125
States
with more demanding RPS requirements can create more robust market opportunities
for residential solar developers. Table 3.6 enumerates all of the RPS requirements for
each state.
125
Edge, Ryan and Erika H. Myers. “Solar Fundamentals Volume 2: Markets,” SEPA. 2015.
https://www.solarelectricpower.org/media/395320/Solar-Fundamentals-Vol-2.pdf

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