Historic Review,

Comparative Analysis and

Future Recommendations For

Distributed Renewable Energy

Management Strategies

John-Peter Dolphin

Candidate, Harvard University Masters in Sustainability and

Environmental Management

Spring 2015

i

Abstract

Swanson’s Law has held true and the price of photovoltaic solar panels has dropped

precipitously. In fact, the technology has now reached a tipping point where installing rooftop

solar is within the reach of middle class Americans. The U.S. solar industry already employs

more individuals than the coal and natural gas industries combined, and the number of rooftop

installations in the US is expected to grow more than 600% over the next five years.

The rise of solar will catalyze a stark transition in the electric utility industry on par with

the switch from direct to alternating current. In mass, solar, and other distributed generating

systems, can cause considerable damage to existing electrical infrastructure, which is designed to

facilitate the historic centralized generation service model. In addition to this new bi-directional

flow of energy, distributed solar is extremely variable, with changes in on-site usage as well as

local weather conditions significantly affecting generation. As such and based on the accuracy of

current weather prediction algorithms, distributed generation systems are difficult to incorporate

into demand forecasts. In addition to infrastructure damage and over generation, solar is also

causing a cost shift to non-solar customers. Similar to deregulation and decoupling, this solar

cost shift will significantly impact the financial integrity of the electric utility industry.

This research paper reviews how three geographies, California, Hawaii and Germany, are

handling the growth of distributed solar. Infrastructure integrity as well as government policies

and financial incentives are reviewed. Load profile curves for each jurisdiction are compared,

with utility responses evaluated. Eight key recommendations are made, applicable to not only the

geographies reviewed, but also to any grid operator facing increasing distributed solar

penetration rates.

ii

Acknowledgements

My pursuit of a graduate degree, never mind the successful completion of this research paper,

would not be possible without the love and support of my wife, Rachel Silverman Dolphin. In

good times, and bad, she has been on my side, all while exceling in her own graduate work. I

also have to thank my parents and in-laws for their unbridled emotional and mental support.

Professor George Buckley and Teaching Assistant Sarah Driscoll provided the entire Spring

2015 Capstone cohort with an excellent framework for success and enough positive feedback to

fill the Giant Ocean Tank of the New England Aquarium.

Thank you to all of the professors and administrators, past and present, who helped shape the

Sustainability and Environmental Management program into the cornucopia of opportunity and

new beginnings that it is today.

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Table of Contents

Abstract ............................................................................................................................................ i

Acknowledgements ......................................................................................................................... ii

List of Figures ................................................................................................................................ iii

List of Tables ................................................................................................................................. iv

Definition of Terms......................................................................................................................... v

Introduction ..................................................................................................................................... 1

Note on Prior Knowledge Requirements .................................................................................... 2

Background ..................................................................................................................................... 2

The Industrial Revolution Sparks Demand for Electricity ......................................................... 3

The Battle of the Currents ........................................................................................................... 5

Centralized Power with Monopoly Service Territories .............................................................. 7

RTOs and OPEC ......................................................................................................................... 9

Deregulation, Enron, and Decoupling ...................................................................................... 14

Critical Mass and Impacting the Electricity Grid ..................................................................... 21

Methodology ................................................................................................................................. 27

Cases ............................................................................................................................................. 28

California .................................................................................................................................. 29

Hawaii ....................................................................................................................................... 36

Germany .................................................................................................................................... 40

Discussion & Recommendations .................................................................................................. 48

Discussion ................................................................................................................................. 49

Strengths and Weaknesses of the German Electricity Industry ............................................. 50

Energy Storage ...................................................................................................................... 53

A Threatened Business Model ............................................................................................... 57

Forecasting............................................................................................................................. 58

Recommendations ..................................................................................................................... 60

Conclusion ............................................................................................................................. 66

References ..................................................................................................................................... 68

iv

List of Figures

Figure 1 – Competition Abounds In The Early DC Market . ......................................................... 4

Figure 2 – Simplified Diagram Of Electricity Flow, From Generation To Use ............................. 8

Figure 3 – The Ratio Between Elrctricity Demand And Generation Capacity ............................. 12

Figure 4 – Historic Price Of Electricity ........................................................................................ 13

Figure 5 – Wholesale Price Of Electricity In California During Deregulation ............................ 19

Figure 6 – Installed Solar Cost per Watt ...................................................................................... 23

Figure 7 – Levelized Cost of Energy, variety of generating sources ........................................... 25

Figure 8 – Recent and Expect Residential Solar Growth ............................................................ 26

Figure 9 – Organization of NERC Interconnections.................................................................... 30

Figure 10 – California Genration Mix .......................................................................................... 31

Figure 11 – CSI Installed Capacity ............................................................................................... 32

Figure 12 – California's Duck Curve (Cal ISO 2013). ................................................................. 34

Figure 13 – Hawaii Genration Mix ............................................................................................... 37

Figure 14 – Hawaii's Nessie Curve ............................................................................................... 38

Figure 15 – Growth of Renewables in Germany .......................................................................... 42

Figure 16 – Solar Irradiation Rates, United States v. Germany .................................................... 43

Figure 17 – Germany's Extended Nessie Curve ........................................................................... 44

Figure 18 – Map of US Renewable Portfolio Standards............................................................... 51

Figure 19 – Worldwide Energy Storage Installtions .................................................................... 54

Figure 20 – Solar Cost Shift Positive Feedback Loop .................................................................. 58

Figure 21 – R&D by Investor Owned Utilities ............................................................................. 61

Figure 22 – Rooftop Solar Cost Comparision US v. Germany .................................................... 62

List of Tables

Table 1 – Basic Case Study Jurisdiction Comparables ................................................................ 28

v

Definition of Terms

Alternating Current (AC) – An electrical current that oscillates directions with a defined

frequency. The dominant form of electricity used for transmitting electrical energy over large

distances.

Balancing authority – The organization responsible for predicting electricity demand and

insuring generation capacity availability. Generally either the local utility, ISO or RTO.

Base load – Electricity demand or load that rarely if ever subsides; for example, transportation

and water infrastructure demands. Because of its constant nature, specific generating facilities,

also called base load power plants, are designed to serve this load. Base load power plants, such

as nuclear power plants, are incapable of quickly varying generation rates.

Demand response – A method of matching electricity supply with grid demand by having high

use customers strategically reduce demand, rather than by increasing electricity generation.

Direct Current (DC) – An electrical current that flows in a single direction. Used primarily by

in home appliances and machinery, requiring a transformer when using electricity from the grid.

Distributed Generation (DG) – Electricity generation that occurs within the distribution grid.

Although on-site generators at hospitals or industrial facilities technically qualify, the use of DG

typically refers to small scale renewable installations, especially rooftop solar.

Distribution grid – Low voltage electrical infrastructure used to safely distribute electricity

from substations through neighborhoods and to the final point of use.

Eastern Interconnection – The connection of electrical networks that stretches from the eastern

seaboard, north into Canada and as far west as the Rocky Mountains.

Electricity grid – Also known simply as “the grid,” the combination of distribution and

transmission networks that relay electricity between generation and points of use.

European Energy Exchange (EEX) – A wholesale electricity market that connects generating

plants throughout the European Union, providing reliability and connecting demand with the

most efficient source of generation.

Frequency – The rate of oscillation of alternating current, typically 60 hertz in the United States.

Changes to this rate can cause super positioning as well as constructive and destructive

interference, all of which can have devastating effects to electrical equipment.

Grid operator – Umbrella term which refers to the local utility, ISO or RTO in charge of

activities including demand forecasting, generation scheduling, and infrastructure maintenance.

May or may not also be the jurisdiction’s balancing authority.

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Independent System Operator (ISO) – A third party organization typically established by a

state government to oversee the jurisdiction’s wholesale electricity market. An ISO typically

owns no infrastructure and its revenue is separated from the amount of electricity sold.

Peak load – The highest electricity demand of either a day, season or year. Peak load often

coincides with extreme weather events. Specific power plants, known as peaker plants, typically

serve this load and are normally designed with minimal lead time requirements and increased

ramping flexibility. Peaker plants are generally not as economically efficient to operate and often

have some of the highest emission rates.

Point of use – Overarching term meant to signal the location of energy consumption by any

customer class including homes, businesses and industrial locations.

Ramp rate – How quickly a power plant can change its generation. Because of their very nature,

the incorporation of variable energy sources, such as solar and wind, can require ramping by

other generating facilities in order to meet consistent demand requirements.

Regional Transmission Organization (RTO) – Typically a self-organized group of

neighboring utilities who interconnect electricity networks in order to continue to meet customer

needs during times of increased demand or maintenance.

Photovoltaics solar (PV solar) – A type of solar panel, typically made of silicon, that generates

electricity through the transfer of electrons between metalloids, rather than through the use of

thermal energy.

Smart meter – Onsite equipment that measures electricity consumption at intervals as short as

every minute and relays such information to the grid’s operator via a wireless radio network.

Substation – A critical piece of the electricity grid that steps down high voltage electricity from

the transmission grid to voltages usable on the distribution grid.

Transmission grid – Network of high tension, high voltage electrical wires that transmits

electricity from large centralized power plants to substations, typically using AC.

Variable energy source - Electricity generating systems that depend on natural conditions,

rather than fuel, for power. As such, their generation varies when weather conditions change.

Watt (W) – Standard unit of measure for electricity. 1,000 watts is abbreviated as kW, a MW is

1 million watts and a GW is 1 billion watts. A single CFL lightbulb uses about 12 watts in an

hour or 12Wh, and the average U.S. home uses about 900 kWh of electricity per month. The

average centralized power plant has a generation capacity of between 1 – 1.5 MWhs.

Western Interconnection – The connection of electrical networks that stretches from Baja,

Mexico to British Columbia, Canada and east to the Rocky Mountains.

1

Introduction

Electricity serves as a critical cornerstone of modern life, used in everything from the

cultivation and curation of our food, extending education beyond the confines of the classroom,

improving land, air and sea transportation as well as, supporting emergency services including

police and fire. Electricity is so integrated into our modern lives that society sometimes takes it

for granted, forgetting the impact centralized power plants can have on communities and the

environment.

Increased awareness regarding these impacts, combined with technological

advancements, and associated cost reductions, have led to distributed renewable energy

technologies, especially rooftop photovoltaic (PV) solar, becoming increasingly popular.

However, the modern electricity grid and nearly everything associated with it, including utility

business models and regulatory language, were not designed for the bi-directional flow of

electricity from these new distributed generating assets. Faced with a new market landscape, but

few new tools, many utilities choose to essentially ignore output from small scale installations,

which they believe to be negligible (St. John, 2013).

While this output was negligible 15 years ago, distributed PV solar installation costs have

continued to plummet, and consequently installed generating capacity has continued to grow

(QER, 2015). California alone now exceeds 2 GWs of installed PV capacity, or approximately

7% of peak demand. (Cal ISO, 2013b; CPUC, 2015). Although no longer cost prohibitive, legacy

infrastructure systems, outdated regulations and threatened business models have suppressed the

continued growth of distributed renewable energy systems. Furthermore, failures in forecasting

technology prevent electric utilities from accurately incorporating distributed renewable energy

2

into generation plans. Because of this, utilities over-generate, essentially negating any positive

environmental or health benefits created by the distributed energy (MIT, 2011).

This report will assess the impacts that distributed generation (DG) has had on the

German electricity market, where nearly 70% of peak demand is met by solar power (Wirth,

2015). Based on third party and governmental reviews of this jurisdiction, the policies,

technologies and equipment used to successfully manage this level of distributed solar PV

penetration will be accessed against the infrastructure and regulatory environments of California

and Hawaii. These two locations are currently the largest markets for distributed PV solar in the

United States by capacity and penetration rate, respectively.

Note on Prior Knowledge Requirements

A technical understanding of electrical power systems and electricity generation, i.e.

voltage, frequency, reactive power, etc., are not required to understand the recommendations

made by this research paper. However, if a reader would like to learn more about these

fundamental topics, The Future of the Electric Grid provides an accessible, yet thorough,

overview of the topic (MIT, 2011). A historical account of the growth and transformation of the

electricity industry does, however, provide an important backdrop to the legacy systems,

operating standards and regulations of today. As such, the Background section of this report

includes a chronological overview of the foundation, growth, regulation and evolution of the

electricity industry.

Background

The saying “Thomas Edison would recognize today’s electricity grid” is widely used to

highlight the slow moving nature of the electricity industry (LaMonica, 2014). For several

reasons, including utility companies’ service territory monopolies which eliminate competition

3

and therefore innovation, the sentiment of the saying is true; the use of Edison, however, is

anachronistic. The electricity industry in general, and especially the electricity grid, has evolved

significantly since the early twentieth century. To begin, Edison’s direct current technology lost

to Nikola Tesla’s alternating current (EIA, 2000). Alternating current allows for centralized

power plants, leading to the radial array electricity grid of today (MIT, 2011). Rising costs, along

with increasing environmental awareness, have however led to a return to on-site direct current

generation, this time in the form of rooftop solar PV arrays (DOE, 2015). The penetration rate of

solar PV systems is now reaching a critical mass and beginning to negatively impact

infrastructure and reduce system wide efficiencies (MIT, 2011). This historical perspective is

critical to understanding why the modern electrical grid is designed and operated in the way it is

today.

The Industrial Revolution Sparks Demand for Electricity

While electricity as we know it has been experimented with since the mid-1700s, it was

not until the invention of the reciprocating steam engine during the Industrial Revolution that

electricity’s potential was realized (NAE, 2015). In addition to enabling railroad transportation,

the steam engine revolutionized manufacturing and allowed factories, previously dependent on

water wheels for mechanical power, to be located more strategically. These first closed circuit

systems were initially limited to facilities that could afford on-site generators, which required

significant fuel and labor. Electricity generation continued in this on-site manner until the first

commercial power plant, the Edison Electric Light Station, was built in 1882 (NAE, 2015). The

attraction of electric lights in storefront windows helped to expose the marvel of electricity to the

masses, and combined with safety campaigns lambasting the use of open flames, these and other

efforts led to increased demand for electricity in residential applications (ibid). This increased

4

demand led to an explosion of electricity and lighting companies. By 1907 there were forty-five

electricity companies operating in Chicago, with similar numbers in other major cities (Crews,

1998). An open market meant that while one resident received power from Company A, their

neighbor on the left might receive service from Company B, and their neighbor on the right from

Company C. Soon overhead electric lines crisscrossed even small cities, see Figure 1.

Although revolutionary, electricity service from the power company was both unreliable

and expensive. As a result many manufacturing facilities maintained their own on-site generation

capabilities, and those that didn’t often used batteries (EIA, 2000). Although they had minimal

capacity when compared to today’s devices, these batteries aimed to provide the same service

that modern day data centers and manufacturing centers require: a bridge power supply that helps

Figure 1 – Pratt, Kansas 1911. With no defined service territories and minimal regulations,

providing electricity to businesses and residents was a wide open market, even in small

town America (Cassingham, 2011).

5

overcome interruptions and protects equipment from drastic changes in frequency (EIA, 2000;

Schröder, 2012). So how did the decentralized, minimally regulated, unreliable, open market of

Edison’s time evolve into the electricity industry of today?

The Battle of the Currents

While Edison may have been instrumental in creating demand for electricity through

advancements to the incandescent lightbulb, creating a matching supply of electricity was not a

problem the world renowned inventor could effectively overcome. Hindsight and modern

electrical engineering principles demonstrate that there were two main reasons why Edison’s

direct current (DC) electricity grid failed: voltage drop and economies of scale.

Aluminum, steel and copper are the standard materials used in electrical wiring (MIT,

2001). Each material has a different conductivity, which can be simplified as the friction endured

by electricity as it travels along the length of a material (MIT, 2001). This “friction” decreases

electricity’s voltage, or the total available power. The further that electricity travels along a wire,

the more resistance is endured and increasing amounts of voltage is lost (MIT, 2011). This

voltage drop required early DC power plants to be located within approximately 1 mile of the

electrical load, otherwise the amount of resistance endured would create too much of a voltage

drop to service customer load (NAE, 2015).

This required DC generating plants, as well as the associated infrastructure to be

replicated several times throughout a city. Furthermore, electrical use cases that required more

powerful electricity than the standard 12V lightbulb necessitated DC power plants to have a

completely separate generator and distribution system (NAE, 2015). Comparatively high voltage

alternating current endures less resistance over the same electrical wire, allowing it to be sent

great distances with minimal voltage losses (MIT, 2001). This high voltage AC is then stepped

6

down through a transformer to a voltage that is useful for the customer (MIT, 2001). This step

down process allows for large centralized plants, which benefit from economies of scale, to be

built in strategic locations some distance away from the end user. High voltage alternating

current can also be stepped down to different levels. This allows one generating facility to

provide power to both manufacturing and residential applications through the same distribution

grid.

Because of these benefits, AC was chosen to power the World’s Fair in Chicago and

shortly thereafter the Niagara Falls hydro-electric plant also chose to employ AC (EIA, 2000).

Edison, who had invested significantly in direct current, did not readily admit defeat; driven by

pride and the desire for profit, Edison conducted a media blitz which lambasted AC as dangerous

and orchestrated, among other things, the invention of the electric chair, which was built to use

alternating current (EIA, 2000). Economic realities of centralized power production overpowered

Edison’s efforts and AC became the standard in the US and around the world.

Over the course of just 50 years the proximity relationship between man and power, both

mechanical and electrical, came full circle. Pre-Industrial Revolution manufacturing centers were

located along rivers, in order to take advantage of the natural power of flowing water. Thanks to

the steam engine, DC electricity could be generated locally or onsite and factories were moved to

cities, which were more strategic locations given the proximity to labor and transportation

networks. Centralized AC power plants then moved electricity generation out of the city center

and back to the water, which is used to help cool the plants’ generators (Botkin & Keller, 2010).

As previously mentioned, this research paper will discuss how rooftop solar is now bringing

customer-located DC power generation back.

7

Centralized Power with Monopoly Service Territories

Economies of scale played a critical role in the War of the Currents and again in the

creation of utility service territories as they are known today. As shown in Figure 1, the urban

electricity market was flooded with competition in the late nineteenth and early twentieth

century. Direct current required generation to occur within just a few miles of consumption, and

as a result an entire electric company’s operations were often within the purview of a municipal

government. However, the Great Depression brought a steep decline in demand for electricity.

Many electric utilities declared bankruptcy, selling off both their customer bases and the metal in

their overhead power lines, in order to help pay off debts (EIA, 2000). As a result, the utilities

that survived often had operations that extended beyond municipal and sometimes state

boundaries, undermining the authority and bearing of local regulations. With local laws no

longer enough to control these large utilities, and a great sense of distrust in unregulated

industries due to the stock market crash, The Public Utilities Holding Company Act of 1935

granted the Securities and Exchange Commission regulatory authority over utilities (MIT, 2011).

As part of this regulation and despite the aversion to large corporations, it was widely

recognized that a geographically based natural monopoly was a more efficient use of

infrastructure. It was at this time that both natural gas pipeline companies and electric utilities

were granted exclusive service territories and exceptions from the Sherman Antitrust Act (MIT,

2011). As part of the negotiations leading up to this legislation, utility representatives agreed to

not resist or impede the efforts of the Bureau of Reclamations, the Tennessee Valley Authority

(TVA) and the Rural Electrification Administration (REA) (EIA, 2000). These government

agencies created large generation sites, including the Hoover, Cooley and Bonneville dams,

providing low cost electricity to rural and Western markets. Utility representatives, whose

8

businesses served mainly large East Coast municipalities, bartered away what they saw as

perpetually small, rural markets.

Government and commercial systems alike, utilized large centralized AC power plants.

These plants were both more efficient, i.e. more affordable for the consumer, and more reliable

than previous DC plants, eliminating the need for manufacturing facilities to continue to own and

operate onsite generating facilities or battery storage devices. Figure 2 provides a basic overview

of the infrastructure involved in transmitting high voltage AC power from a centralized plant to

end users. Moving from left to right, a centralized power plant generates high voltage AC

electricity, which in turn is sent over transmission lines. Because of this potentially dangerous

voltage level, transmission lines have clearly defined easements and are strung above the tree

line. Community lines are the prototypical electricity lines one might see on a residential street

and are often also referred to as distribution or overhead lines. Before electricity can be sent

along local community lines, a decrease in voltage must be made. This decrease is completed at a

local sub-station; substations can reduce the electric flow from upwards of 65kV all the way

down to the standard 120V utilized by modern day home appliances (EIA, 2000).

Figure 2 – Simplified diagram of electricity flow, from generation to use

9

Community lines can be arranged in either radial, grid or hybrid arrays. Radial arrays

reach outward like the branches of a tree. With only one connection to a central source of

electricity, outer service areas are vulnerable to an interruption in operation closer to the center;

true radial arrays are rare due to their vulnerability (EIA, 2000). Grid arrays traverse a given area

in a checkerboard type pattern; such systems minimize the number of customers impacted by any

one incident through extreme redundancy with a multitude of alternative routes available if any

interruption occurs (ibid). Hybrid arrays combine the two in what can be most accurately

described as a spider web type fashion. Hybrid arrays allow for an effective level of redundancy

without requiring extensive amounts of infrastructure (ibid). The presence of one array type or

another depends significantly on the geographic conditions and history of development.

RTOs and OPEC

Between the Great Depression and the end of the twentieth century, technological

advancements continued to improve the efficiency of centralized plants. However, this 70 year

period brought with it significant changes in how utilities operated and the demands of the

customers they served.

During World War II and for approximately the ten years after, electricity demand was

dominated by factories and manufacturing facilities. Demand was predictable and consistent, and

the limited number of large customers allowed for utilities to have direct relationships with their

most important clients. It was at this time that demand response relationships first developed;

scheduled maintenance, extreme weather or unexpected grid demands would occasionally

exceed a local utility’s generation capacity. Rather than force a brownout, or worse, rolling

blackouts on all customers, strapped local utilities would request that industrial facilities reduce

10

production or cut a shift short. In exchange, utilities offered these industrial customers reduced

rates, and lauded them for putting the needs of the community above their own.

While these mutually beneficial relationships between industrial customers and utilities

continue to this day, there were and will continue to be times when industrial users of electricity

prefer not to reduce demand. For example, ahead of an impending quarterly manufacturing

quota, or in the middle of a sensitive production run. While formal demand response contracts

exist today, locking industrial users into specific curtailments, historically such contracts were

not common-place and in many instances plant managers chose not to reduce electricity use

when requested (EIA, 2000). The combination of increased grid demand due to suburbanization

and increasingly stalwart industrial customers put local electric utilities in a difficult position.

Should the local utility build a power plant that would only be utilized to meet peak demand for a

few hours every year? Even if the answer is yes, constructing a power plant is a multi-year

process, what was a utility to do in the interim? In order to most efficiently meet peak demand

requirements, many local utilities began to connect their electrical grid with that of a neighboring

utility. “Because different utilities often had standardized on different transmission voltages,

mergers and interconnections between adjacent utilities often required—and often still require—

transformers to link lines with different voltages. These transformers produce losses” (MIT,

2011, p. 238). Despite these losses, the marginal cost of these connections is generally lower

than building a rarely used “peaker plant,” and consequently these types of connections between

otherwise vertically integrated utilities with service territory monopolies began to arise with

increased frequency during the 1950s. This happened to such an extent that by 1962, nearly the

entire Eastern Seaboard of the United States was connected.

11

Interconnection brought reliability, but it also brought the potential for domino effect

destruction. This was the case in 1965 when a transmission line’s safety relay was tripped and set

in motion a cascade of overwhelmed electricity grids. In addition to affecting power availability

in Ontario, which was the site of the original infrastructure failure, the resulting blackout covered

the vast majority of New York (including Manhattan), New Jersey, Connecticut, Rhode Island,

Vermont, New Hampshire and Maine; all in all, 30 million people were without power (NBC,

1965).

In response to the blackout, and with the hopes of preempting increased regulation, the

electric utility industry formed the North American Electric Reliability Council (NERC). The

council created voluntary operating standards and worked communally to address reliability and

capacity issues. Side Note: Following a similar overloading event in 2003, affecting 55 million

people across 9 states and provinces, the Federal Energy Regulatory Commission (FERC)

directed that all NERC standards, previously voluntary, were mandatory (MIT, 2011). Because

all systems are not the same, NERC moved to establish Regional Transmission Organizations

(RTOs). Where interconnected utilities previously primarily relied on one another during times

of excess demand, RTOs coordinate generation capacity, maintenance, and related issues on a

daily basis.

While RTOs helped to improve resiliency, they did little to reduce the cost of generation.

Incremental technological advancements were made during the time period, but they could not

compete with the rising costs of fuel leading up to and following the OPEC Oil Embargo. While

many associate the OPEC Embargo with gasoline rationing during the winter of 1973, the utility

industry was hit just as hard and perhaps for a longer period of time. In 1973, 30% of the total

energy (BTUs) consumed in the US was attributable to gasoline, almost entirely by the

12

transportation industry; however, 47% of total energy consumption was from oil and similarly

was almost entirely attributable to electricity generation (EIA, 1979). Limited domestic supplies,

either pumped dry or abandoned due to the previously cheap availability of Middle Eastern oil,

escalated the problem.

In addition to scarcity inflated fuel costs, utilities also faced a continually increasing

demand for electricity, as outlined by Figure 3.

. Compounding double digit increases in demand were experienced each year between

1950 and 1973 (EIA, 2015b). In the three years leading up to the Oil Embargo, electricity

demand increased by 30%, 49% and 46%, respectively (EIA, 2015b). Faced with rising demand

Figure 3 –The ratio between supply and demand has stayed very stable over the last 65 years, save for

three influential events (Derived from EIA, 2015b).

13

and limited supply from both domestic and foreign sources, electricity prices began to increase.

As shown in Figure 4 in the years following the OPEC Oil Embargo of 1973, electricity prices

rose by as much as 35% (MIT, 2011, p. 237). In order to help reign in rising costs, as well as

diversify the electricity industry in hopes of protecting it from future international market

manipulations, Congress passed a series of pieces of legislation beginning with the Public

Utilities Regulatory Policies Act (PURPA) (EIA, 2000). PURPA aimed to add market

coordinated cost minimizing functions to a regulated monopoly space and did so by requiring

local utilities to buy power from non-utility power generators at “avoided costs,” effectively

creating the wholesale market for electricity (MIT, 2011, p. 238). This required the creation of a

third party purchasing authority, a role filled by Independent System Operators (ISOs). Whereas

RTOs are self-organized industry association aimed at insuring adequate supply during periods

of maintenance and high demand, ISOs are independent third party organizations that operate

Figure 4 – During the time of Edison, electricity cost as much as $5 per kWh (MIT, 2011, p.

235). The transition to centralized plants and alternating current significantly reduced costs,

and following the recovery from the Great Depression electricity prices have dropped

significantly (MIT, 2011, p. 237).

14

above the utilities with the goal of insuring generation efficiency. While ISOs play an important

role in forecasting system wide demand as well as scheduling and dispatching generation assets,

they do not own any power plants or transmission infrastructure, nor do they operate at the

distribution level of the electricity grid. This lack of ownership helps to insure efficient operation

and shortly after initial implementation the PURPA created ISO structure was deemed a success.

The combination of behind the scenes competition with a consumer facing monopoly was lauded

“as the benchmark for market design – the textbook ideal that should be the target for policy

makers” (MIT, 2011, p. 239). Following its successful implementation in the United States

historic revision to electricity markets were made all across the globe, most notably in Chile and

the United Kingdom (ibid).

Deregulation, Enron, and Decoupling

As previously mentioned the original intent behind PURPA was to create wholesale

electricity markets. The underlying ideology behind the legislative change was that opening up

the utility markets to competition would help to drive down the price of electricity (Weare,

2003). This was certainly the thought process in California, where electricity rates were “on

average 50 percent higher than the rest of the U.S.” (PBS, 2001). Deregulation was a step beyond

the creation of ISOs; in theory a free market would aggressively identify waste without the need

for an overseeing body. Each jurisdiction implemented deregulation in its own manner; for

example, Pennsylvania created a wholesale market, but does not allow independent energy

traders, who did not directly own generating assets, to participate (MIT, 2001). Because of the

number of companies and individuals affected, the size of the financial ramifications, and the

impact on international policy, California’s deregulation process will be the focus of this section.

15

Determining the underlying cause of the California Energy Crisis is beyond the scope of

this research paper. This paper will, however, outline several of the coinciding factors that

affected and allowed for manipulation of the California electricity market. These factors become

increasingly important as distributed energy generation capacities continue their penetration

beyond first adopters and further into the general population.

With an ISO already in place, and electricity prices still unreasonably higher than the rest

of the country, California was one of the first states to pursue almost complete deregulation

(Weare, 2003). This “almost” is an important caveat as traditional utilities were not allowed to

change rates charged to residential customers, despite the fact that the utility would be facing

variable costs depending on market pricing, fuel costs, etc. A wholesale market requires

suppliers other than the pre-existing vertically integrated utilities. Because it takes several years

to build a power plant, the first step in deregulation in California was the forced sale of 40% of

California investor owner utilities’ (IOUs) generation capacity (Weare, 2003) . Under Assembly

Bill (AB) 1890 power plants were sold at auction, with minimal requirements relating to industry

knowledge or ability to effectively operate the generating facility (ibid). Several out of state

investment companies purchased power plants (ibid). One issue that would add another layer to

the Energy Crisis is that many of these purchasing companies owned and operated assets outside

of the state. Similar to the transition from municipal to state utilities, these new companies no

longer came under the exclusive jurisdiction of prior regulators, in this case the California

Public Utilities Commission as all previous state utilities had, instead they fell under the

jurisdiction of the Federal Energy Regulatory Commission (Weare, 2003). Another subtle, but

important, variable that contributed to the energy crisis was reduced new generating capacity

construction. As previously outlined by Figure 3, electricity generating capacity traditionally

16

tracked growth in electricity demand. While the OPEC crisis reduced the ratio of demand to

supply, uncertainty regarding deregulations during the 1990s reversed this trend as many utilities

were wary to invest in a large power plant that they could be forced to sell, at a potential loss,

before recovering their investment (Weare, 2003).

One of the key components of California's AB 1890 that differed from other deregulation

schemes was that it forbade utilities from signing extended power purchase agreements and

instead forced utilities to make all purchases in the day ahead and spot market (Weare, 2003). By

emphasizing these short term markets, the CPUC shifted power producers’ focus from continued

long term operation to short term profit maximization. Seeking this short term profit

maximization, independent power producer (IPP) began to manipulate the wholesale market in

May of 2000. One way this was achieved was through unscheduled maintenance (Weare, 2013).

After accepting bids from the day ahead market, power producers who owned multiple

generating facilities would inform the Cal ISO that one of their facilities required unscheduled

maintenance (ibid). Unscheduled maintenance carried no penalty and would flood the spot

market, which was intended to only cover slight variations in demand from Cal ISO’s forecasts,

with immediate demand requirements (ibid). These last minute requests artificially inflated the

wholesale price of electricity leading to higher revenues for power producers.

Another market manipulation method used by independent power producers was over

scheduled transmission lines (Weare, 2003). With the state's electricity transmission

infrastructure built by previously vertically integrated monopolies, there was very little need for

interconnection. In fact, there was only one transmission line that connected the northern and

southern halves of the state, named Path 15. Recognizing this vulnerability, power producers

would intentionally bid on generation requirements on the other side of the interconnection. A

17

coordinated bidding process eventually led to the maximum capacity passing through the

transmission line; this allowed IPPs to tack on “congestion charges” on top of their day ahead

bid. This eliminated the availability of generating capacity from the other side of Path 15 to serve

spot market needs. As a result, the spot market was separated into two separate markets, allowing

independent power producers located on either side of Path 15 to charge even higher prices, and

leaving traditional utilities with no recourse (ibid).

AB 1890 included a tariff on electricity produced outside of California (Weare, 2003). In

theory, this allowed in-state power producers to charge comparatively lower prices, making their

electricity more attractive, with the intended purpose of encouraging in-state operation and job

creation (ibid). However, IPPs participated in electricity laundering schemes that would obscure

the original source of the electricity generated (ibid). Their goal was to make it seem that

electricity was actually coming from out of state, increasing the sales price. A simplified

explanation of the convoluted accounting schemes used does not do justice to the lengths IPPs

went to in order to scheme the wholesale market (Weare, 2003). In short, IPPs purchased,

bundled, resold, split, rebundled and then resold generation quotas dozens of times (ibid).

California’s deregulation process did not require separation between upstream and

downstream non-utility actors (Weare, 2003). As such, divisions of the same company were

allowed to purchase generation rights from one another, as discussed previously in regards to

energy laundering. Several IPPs also owned and operated natural gas supply pipelines and

extended this corporate nepotism to the purchase of natural gas (ibid). These companies,

including Enron, manipulated the underlying cost of natural gas in order to affect the price of

electricity, costs that were recuperated when they were eventually passed onto the local utility.

18

In order to drive prices even higher, independent power producers on several occasions

chose not to completely match all demand purchase requests. Because electricity cannot be

efficiently stored, these gaps between supply and demand would lead to brown and black outs

(Weare, 2003). Utilities, who were legally obligated to serve customers in their service territory,

would then be forced to bid even higher in the whole sale markets, in hopes of attracting

generation capacity that previously had not participated (ibid).

Market manipulation is not completely to blame, as the newly created regulatory

structure exaggerated suppliers’ power and left electricity purchasers with imperfect competition

and no reasonable alternatives. Rises in wholesale market prices, outlined in Figure 5, could not

be passed along to consumers, who were protected by a rate freeze (Weare, 2003). With no

consumer price signal attached to the peaks in the wholesale market, demand for electricity

increased as individuals and companies moved to incorporate computers and other electronics

into the daily operation of homes and businesses. During the ten years between 1990 and 2000,

electricity demand in the state increased on average approximately 1.5% annually (ibid, p. 16).

But this average rate was heavily influence by 4% annual increases in demand between 1998 and

2000, which was coincidently the time period of California’s deregulation. It was during this

same time period that supply was at its lowest (ibid, p. 16). California historically imported 20%

of its electricity from neighboring states, but droughts in the Pacific Northwest limited the

amount of hydroelectricity available to meet California’s increased demand (ibid). Demand also

increased by 6.2% in Nevada and 3.7% in Arizona, leading to limited export availability (ibid, p.

16).

As a result of these and other market variables, the price of electricity on the wholesale

market was 2,000% higher during the winter of 2000 than it had been just a year prior, see Figure

19

5 (Weare, 2003 p. 1). Unable to pass along these increased costs, state utilities lost millions of

dollars. The electricity crisis was at its worse during 2001 when over the course of nine days

there were “a total of 42 hours of outages,” (Weare, 2003, p. 3). The US urban area average is no

more than 5 minutes over the course of an entire year (MIT, 2011, p. 9).

With its income limited and facing unprecedented increases in costs, Pacific Gas &

Electric (PG&E), California’s largest utility, borrowed $13 billion dollars in order to bridge the

gap between rising costs and limited income. With no end to the underlying issues in sight and

the company’s lowest credit rating in history, barring it from borrowing any further at reasonable

rates, PG&E declared bankruptcy (ibid). California’s other large IOUs were also forced to

borrow significantly in order to meet their obligations. A conservative estimate of the financial

Figure 5 - The wholesale price of electricity in California during the period of deregulation. As can be

clearly seen the mere initiation of deregulation in 1998 did not immediately lead to the rise of electricity

prices, in fact prices initially dipped. It was however the confluence of several factors that played a role

the rising price of electricity (Weare, 2003, p. 1).

20

impact of The California Energy Crisis is $40 billion or 3.5% of California’s annual GDP (id, p.

3). In comparison, the most temporally recent crisis, the nationwide Savings and Loan Crisis,

was approximately $100 billion, but only 0.05% of the country’s GDP (ibid, p. 4).

The California state government was forced to intervene and using its emergency powers

shutdown the wholesale electricity market. Criminal charges were filed against IPPs who

colluded to affect wholesale prices, including Enron and its CEO Kenneth Lay. The international

popularity of PURPA legislation came to a screeching halt; no new ISOs have been formed since

the 2001 Energy Crisis (MIT 2011, p. 240). That being said previously established alternative

forms of deregulation including in Texas and New York have been successful in decreasing costs

and providing consumers with increased provider options.

California’s electricity industry required significant reforms, one of which was

decoupling. Decoupling separates a utility’s revenues from the amount of electricity the utility

sells. Instead revenues are based on a percentage of the monetary value of assets under

management. This calculation includes the value of power plants, transmission lines, and the

distribution grid. Electricity usage is estimated and this forecast is used to determine electricity

rates, which in aggregate meet state set revenue levels. Decoupling eliminates the juxtaposition

of promoting customer energy efficiency with utility revenues. In fact, customer energy

efficiency, along with corporate operational efficiency and demand side management can lead to

increased profits as they reduce costs, while leaving revenues unaffected. Decoupling actually

presents electric utilities with a rare opportunity: even when other parts of the economy are doing

poorly, the utility is essentially guaranteed revenues.

Similarly distributed renewables do not affect decoupled utilities’ profits as they simply

reduce demand, just like customer energy efficiency. Decreased demand, whether through

21

efficiency or renewable energy generation, does however effect electricity rate calculations. In

order to recoup the same amount of revenue from a smaller amount of demand, usage rates must

be raised. This phenomenon is known as a “cost shift;” similar to the unintended impacts of

deregulation, cost shifting could potentially impact the utility industry’s financial integrity and is

reviewed in more detail during the California and Discussion sections.

Critical Mass and Impacting the Electricity Grid

Before the California Energy Crisis, the PURPA ISO model was replicated in

Switzerland, where for the first time the right to produce electricity by “non-utility” actors was

extended beyond involvement in wholesale markets and all the way downstream to the consumer

(Perlin, 2013). Just like in the United States, electricity prices in Switzerland rose following the

OPEC Oil Embargo (Perlin, 2013). It was at this time that research into renewable energy

systems, which required no fuel, began to increase (ibid). Markus Real of Zurich was an early

adopter of rooftop PV solar and felt that it was an underappreciated technology, which not only

had the potential to protect consumers from future oil embargos, but also to reduce pollution

(ibid). Mr. Real believed so adamantly in the potential of the technology that in 1987 he started

Project Megawatt (Perlin, 2013). Intended as a social movement more than anything, Project

Megawatt aimed to install 333, three kW solar PV systems on rooftops throughout the capital

city (Perlin, 2013). The combined capacity of all 333 systems was one MW, hence the name. The

core idea of price protection and environmental stewardship resonated with the people of Zurich

and Project Megawatt was able to quickly enroll more than enough homeowners. However, once

the rooftop PV systems were installed, participating homeowners were disappointed with paying

the retail rate for electricity from their local utility, but only being paid an “avoided costs” rate,

which was 600% lower, for the electricity that their rooftop panels generated (ibid). As these

22

early adopters were individuals of influence, they were able to convince the local utility council

that electricity generated on their roofs was just as valuable as the electricity generated by the

utility’s large centralized plant (ibid). Side Note: One key factor in this political success was the

incorporation of local business leaders into Project Megawatt, including the owner of

Switzerland’s largest glass fabrication company, which made glass covers for solar panels. As a

result “net metering” was born, and Project Megawatt’s impact extended well beyond the 333

homes in Zurich, with net metering legislation significantly improving the return on investment

of distributed renewable systems and became the legislative standard in regions with some of the

highest rates of renewable energy generation, including Japan, Germany and California (ibid).

While net metering revolutionized the potential revenue stream for distributed

renewables, the core technology was still relatively expensive at approximately $10.00 per watt

in 1987 (BNEF, 2015a). For reference the un-weighted average residential price of electricity in

the United States in 2014 was $0.115 per kWh (EIA, 2015b). However, similar to Moore's Law

regarding the exponential increase in semiconductor computing power, Swanson's Law exists in

regards to the exponential decrease in the per watt cost of PV solar. Historical pricing metrics

outline the validity of this hypothesis, as seen in Figure 6. The per watt cost of utility scale solar

installations is now so low that it has reached "grid parity" in some markets. Grid parity

compares the per watt marginal costs of building a new generating source, such as a traditional

centralized coal, natural gas or nuclear power plant (EIA, 2000). In order to better account for

required operating expenses over the life of a plant, and not just installation costs, a different

metric has been developed: the Levelized Cost of Energy (LCOE). In addition to the cost of fuel,

which renewables do not entail, LCOE takes into account operating labor, maintenance and the

23

Figure 6 - Historic data visualization of the per watt cost of installing PV solar. Year after year the

price has dropped precipitously, as predicted by Swanson's Law (BNEF, 2015a).

24

expected useful life of the power plant (EIA, 2000). LCOE has its own faults, as it does not take

into account associated transmission infrastructure costs or end of life recycling and remediation

costs. There are several other metrics, including lifetime system costs, which attempt to consider

either a more holistic approach or a different perspective. While solar may be dependent on feed-

in tariffs or subsidies in order to reach grid parity, or a comparable LCOE, many argue that these

financial appropriations help to take into account externalities not currently considered by the

market (MIT, 2011; QER, 2015; Weare, 2003). Examples of externalities include the human

health and environmental impacts of smokestack exhaust, the greenhouse gas effect of power

plant emissions, and the historic non-monetary subsidies received by the oil and gas industries.

The National Renewable Energy Laboratory tracks LCOE in an open database, called the

Transparent Cost Database, and has developed an interactive tool which allows users to

compare LCOE as well as capital costs, operating costs and capacity factors across generation

technologies. A screen shot of the Transparent Cost Database’s LCOE visualization can be seen

in Figure 7.

No matter the metric, the cost of installing, operating and supporting renewables has

dropped precipitously over the last 30 years; furthermore, these reductions are expected to

continue for renewables whereas traditional generating sources have already matured as

technologies. Economic models suggest that the cost of distributed solar has likely approached a

tipping point where in it is now affordable for the general public (BNEF, 2015b). The United

States’ residential solar market has grown by 50% or more for each of the past three years (EIA,

2015b). This rate is expected to continue, with forecasts of 630% market growth over the next 5

years, see Figure 8 (EIA, 2015b). Another way this groeth can be explained is that in 2016 solar

systems will be installed at a rate of one per minute (BNEF, 2015b).

1977: $76.67 per watt

2014: $0.70 per watt

25

Fig

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26

This exponential growth rate has transformed what was once a small group of early

adopters into a substantial assembly of distributed power generators. As such the scale of these

systems’ impacts on the electricity grid has also significantly increased. Much of the electrical

infrastructure was built during the post-World War II construction boom, and designed to

accommodate the centralized flow of electricity from power plant to end user (DOE, 2015). The

bi-directional flow of electricity, caused when distributed energy systems create more electricity

than is used on site, is a new phenomenon and not something legacy systems were built to

handle. The impacts of bi-directional flow include overheated transformers, voltage spikes and

frequency interruptions, just to name a few, and can cause significant equipment damage. As a

result utilities are reassessing the resilience of their infrastructure and moving to bring

2012

2013

2014

Figure 8 - A to scale

representation of the near

term historic and five year

expected increase in the

number of residential solar

systems in the United

States (Derived from EIA,

2015b).

2019 - 3.2 million homes

27

transparency to these unintended, nevertheless significant, infrastructure costs. Distributed solar

does however offer benefits to the electricity grid as well. If strategically located the combination

of distributed systems, batteries and/or demand response can eliminate the need for expensive

transmission infrastructure upgrades (MIT, 2011). Furthermore solar systems generation

overlaps with a significant portion of peak demand and can reduce associated GHG emissions

and air pollution (QER, 2015).

Methodology

This research paper takes a case study approach to assessing how governments and

private utilities have promoted and are incorporating distributed photovoltaic solar into the

electricity grid. Utility structures, renewable penetration rates and infrastructure resiliency are

reviewed for California, Hawaii and Germany. The cases under consideration each bring a

unique perspective, as distributed solar generation is in a different stage of deployment in each

jurisdiction, and are further differentiated as the regulatory atmosphere in each circumstance is

unique. This research paper relies entirely on publically available information; in addition to

aiming to understand the problems faced by utilities, this research attempts to discover strategies,

based on historic successes and failures, that will aid in the continued integration of distributed

renewables into the electricity grid. As the installation costs of renewables continues to drop and

demand for greenhouse gas and pollution free electricity continues to rise, utilities will be faced

with critical decisions regarding how to minimize costs while fully utilizing a growing asset

class.

28

Cases

This research paper reviews three electricity markets: California, Hawaii and Germany.

Although more in depth details will be given in each section, Table 1provides an overview of the

each geography.

California Hawaii Germany

Population Served 38.8 million1 1.42 million

1 80.62 Million

2

Service Territory 163,696 mi2 1

4,028 mi2 1

137,903 mi2 2

Total Generation 296,628 Gwh3 9639 Gwh

4 614,000 Gwh

5

from Renewables 18.77%3 13.7%

4 26.2%

5

from Solar 1.8%3 <3%

4 5.7%

5

from Distributed Solar <1%3 <2%

4 4.5%

5

Peak demand met by Solar 7%6 80%

7 69.5%

5

Price* $0.1747/kWh8 $0.3334/ kWh

8 $0.31428/kWh

5

* Residential rate; assumes €1=$1.08

1: (USCB, 2014). 2: (World Bank, 2015). 3: (DBEDT, 2013). 4: (CEC, 2014). 5: (Wirth,

2015). 6: (CPUC, 2015). 7: (Paulos, 2014). 8: (EIA, 2015b).

California Overview:

California’s state government has set clear mandates regarding distributed energy

resource integration, yet utilities have little control over their own energy generation portfolio, as

they have been forced to cede this authority to the Cal ISO (Weare, 2003). California has the

largest installed solar capacity, distributed or otherwise, in the nation (CPUC, 2015). As a result,

grid operators are beginning to encounter a bi-model demand curve (PG&E, 2014). Often called

the Duck curve, the associated bi-directional flow of electricity can negatively impact

infrastructure (Cal ISO, 2013).

Hawaii Overview:

Spurred by the highest electricity rates in the United States, one in nine Hawaiian utility

customers have rooftop solar installed (HECO, 2013; Wesoff, 2014). Faced with dwindling

Table 1 – Basic electrical industry information comparison for each case study jurisdiction

29

profits and strained infrastructure, the local electric company is no longer approving solar

interconnection requests in some areas (St. John, 2014a). This high level of solar penetration

forms a “Nessie Curve,” which has a steep increase in electricity demand following sunset,

similar to the steep slope of the Loch Ness Monster’s neck. Such a quick ramp up in demand is

not only expensive to service, but is also nearly unfeasible with the current infrastructure. (St.

John, 2014b). The utility and the state’s Public Utilities Commission are at odds, with the PUC

calling the Hawaiian Electric Company’s (HECO’s) renewable integration plans “fundamentally

flawed” and a “failure” (HPUC, 2014, p. 28).

Germany Overview:

As the result of the country’s unique feed-in tariffs, Germany exceeds both California in

total installed solar capacity and Hawaii in penetration rate. German utilities have dealt with the

Duck and Nessie curves by focusing on local infrastructure and shifting from a centralized power

production model to a distributed system where the utility acts as an enabler of customer owned

generating assets. Following Fukushima, Germany expedited the decommissioning of a majority

of its nuclear power plants GFNA, 2015. These shutdowns have added flexibility to the

electricity grid and allowed it to actually increase electricity exports to neighboring countries,

while still being able to supply power during a solar eclipse.

California

The California Independent System Operator (Cal ISO or CAISO) is one of the largest

third party grid management organizations in the world and is considered a thought leader in the

space (Weare, 2003). Cal ISO incorporates over 80% of the state of California and works closely

with the state’s utilities, especially the three largest: Pacific Gas & Electric (PG&E), Southern

California Edison (SCE), and San Diego Gas & Electric (SDG&E), all of which are investor

30

owned utilities (IOUs) (Cal ISO, 2015d). Cal ISO forecasts the state’s electricity demand and

then manages the competitive wholesale electricity market in order to properly match this

demand, while insuring transmission lines and other high level infrastructure are not

overburdened (Cal ISO, 2015a). As a result of unique state legislation, utility and Cal ISO

revenues are “decoupled” from both demand forecasts and the amount of electricity generated.

Approximately a quarter of the electricity used in the state is imported from power plants

outside of, but connected to, the Cal ISO grid as part of the Western Interconnection (Cal ISO,

2015a). The Western Interconnection helps to provide Cal ISO and all connected electricity grid

Figure 9 – The electricity grids of the United States and Canada are linked and

subsequently split into three different interconnections governed by eight different regional

councils (NERC, 2013).

31

operators with reliability and the opportunity to service electricity demand outside of their

service territory. The Western Interconnect stretches eastward into parts of Texas, as far south as

Baja, Mexico, and north to encompass the Canadian provinces of British Columbia and Alberta,

see Figure 9 (Cal ISO, 2015b).

Over 1,400 generation facilities, located throughout the Western Interconnection and

owned by more than 100 companies, participate in Cal ISO’s wholesale electricity markets,

which include day ahead, hour ahead and on-demand auctions (Cal ISO, 2015a; Cal ISO, 2015c;

Cal ISO, 2015e). It is Cal ISO’s responsibility to manage these markets while adhering to the

confines of the Renewable Portfolio Standard (RPS) set by the CPUC. The Cal ISO failed to

meet the RPS legislation requirement for 2010, which required that 20% of electricity generated

during that year come from renewable resources (CEC, 2014). The next goal, established by

Senate Bill X1-2, is for 33% of electricity to be renewable in 2020 (CEC, 2014). California’s

Figure 10 - In 2013 California consumed 199,783 GWhs of electricity. The fuel source ratios outline a

clear commitment to low greenhouse gas emission sources (CEC, 2014).

32

electricity generation portfolio is outlined in Figure 10.

In order to meet these renewable energy generation goals California has instituted several

programs, including financial incentives. The Go Solar Campaign is the umbrella name for state

programs designed to incentivize customer owned solar; the largest such program is the

California Solar Initiative (CSI) which has a budget allocation of $2.167 billion over 10 years

(CPUC 2014a). The CSI program, as outlined by Figure 11, contains a stepwise functionality

designed to incentivize a growing capacity of solar given the same amount of funding each year.

Financial payments are made to solar system owners based on monitored system generation

(CPUC 2014a). The incentive, which is a consistent per kWh rate, continues for 20 years.

Incentive rates decrease with each year for new participants (ibid). To date, the CSI program has

Figure 11 – Customer sited solar capacity installed in CA’s IOU territories through the CSI

program, 1993-2013 (CPUC, 2014b).

33

led to the installation of over 2,100 MW of solar capacity at more than 227,000 customer sites

(CPUC, 2014b, p. 8). Other incentive programs include the New Solar Homes Partnership,

designed to benefit low income families, the Emerging Renewables Program, and the Self

Generation Incentive Program (CPUC, 2014a).

The combination of these incentive programs with the continually declining price of solar

has led to California having the largest installed solar capacity in the United States. Other states

look to California with hopes of understanding what their state’s electricity grid may look like in

the future. One unanticipated impact is the solar “cost shift;” in short, solar panels reduce the

overall amount of electricity which utilities can spread their decoupled revenues over. As a

result, the per kWh retail price of electricity rises (E3, 2013). Additionally, because the type of

individuals that install solar panels a) are likely high users of electricity, who pay higher rates

under California’s tiered rate structure; b) own a home on which they can install solar; and c) can

afford the upfront payment solar panels historically required, this “cost shift” has been compared

to a regressive tax (Johnson, 2011). Politicians and disgruntled citizens have condensed the

situation into the middle class, paying for the rich to install solar panels (Johnson, 2011).

Although the rhetoric may be terse, the sentiment is actually not too much of an exaggeration

and might even under sell the scale of the problem. According to a report commissioned by the

CPUC, the current cost shift is approximately 1% of all utility revenues, or $359 million, and

with increased solar installation rates expected over the next several years, the cost shift in 2020

is expected to impact 3.2% of all utility revenues, or $1 billion (E3, 2013).

In addition to this social angst the cost shift is causing, solar is having a significant

impact on how Cal ISO manages electricity production. Electricity demand over the course of

the day typically resembles a sine wave with a peak between 4-6PM and a similar magnitude and

34

length valley around 3AM. Depending on the latitude, solar panels generate their maximum

amount of electricity in the late afternoon. As outlined in Figure 12, production from customer

owned solar panels has flattened demand and led to a steep peak approaching sunset. Ramp rates

required to match this decrease in solar generation is not only expensive, but is also hard on

power plant machinery and can have higher associated emissions than simply producing peak

electricity through the entire day (QER, 2015).

Not only is the distributed solar caused Duck curve more difficult to supply electricity

generation for, but it is also more difficult to predict. As discussed in more detail in the

Forecasting subsection, accurately predicting generation from distributed energy systems is

Figure 12 – The changing shape of the electricity demand curve. 2012’s two peaks, which coincide with

before and after work activities at home, earned it the Camel curve nickname. In keeping with animal

nicknames the deep valley (belly), steep ramp (neck) and sudden decline (head) caused by mid-day

generation of electricity from demand side solar, earned the 2020 curve the Duck Curve (Cal ISO 2013).

35

difficult. One of these reasons is that most DG systems are installed “behind the meter,” meaning

grid operators only have insight into the net demand, and not the independent variables of solar

generation and on-site demand (Letendre, 2014, p. v). The ramp rate of solar panels, which can

quickly change the amount of electricity generated due to a passing cloud, adds another layer to

forecasting algorithms. When combined with weather forecasts that are both temporally

inaccurate, and do not have enough locational granularity, the task is almost impossible (ibid).

For these reasons Cal ISO does not currently include DG systems in demand forecasts, although

the organization is working on a pilot algorithm to predict generation; there are no plans to

incorporate the results of this algorithm into demand forecasts (ibid).

One of the final unique characteristics of the California electricity industry to be

discussed as a part of this research paper is the ability of local governments to create public

power agencies (CMUA, 2003). As previously discussed, decoupling bases local utilities’

revenues on assets under management. Via public power agencies, local governments are able to

purchase the electrical infrastructure within their jurisdiction, despite IOUs regulatory protected

service territory monopolies (Eskenazi, 2014). Therefore, the creation of new public power

agencies threatens to decrease future revenues for the state’s IOUs. This purchasing authority

extends beyond standard city governments and includes almost any formal body regardless of its

involvement or expertise in energy generation such as school boards, water districts, and public

transit authorities (Eskenazi, 2014). Based on growing consumer demand for renewable energy,

an increasing number of applications have been submitted to create new public power agencies

(Eskenazi, 2014). While the scale of public power authorities is currently minimal, they could

radically shift the utility landscape and require an increased role from the Cal ISO to maintain

infrastructure and insure reliability (ibid).

36

Hawaii

Where California leads in total installed capacity, Hawaii leads in distributed renewable

penetration: one in nine customers has rooftop solar installed (Wesoff, 2014). Growth in

distributed solar has been fueled by electricity rates at 34 cents per kilowatt hour, which is more

than three times higher than the national average (HECO, 2013). Like many things in the

Hawaiian Islands, much of the cost associated with power production is a result of supply chain

costs, mainly, transporting fuel to the remote islands. As outlined in Figure 13, petroleum

accounts for the overwhelming majority of electricity generated by the HECO, the state’s

electricity conglomerate (IER, n.d.).

Unfortunately, energy generation from petroleum causes significant pollution, including

greenhouse gas emissions. This combination of the high expense and environmental impacts has

made Hawaii a popular market for alternative energy generation systems. Biomass and waste-to-

energy systems experienced early adoption, as legislatures recognized that using part of the

state’s limited space for landfills was a losing proposition. Offshore wind has also seen success,

as the prevailing winds that made Hawaii an important trade waystation continue today. The

distributed energy generation source that has been most popular, however, is solar. Rooftop solar

systems are financially accessible and aesthetically minimalist. In addition, the state has

significantly subsidized the installation of solar panels through its feed-in tariff program.

Hawaii’s feed-in tariff structure is both technology and size dependent, but in almost

every category has some of the highest tariffs in the world (HECO, 2014b). Residential sized PV

systems qualify for $0.274 per kWh, in addition to Hawaii’s personal tax credit (PTC) of 35% of

system costs and the federal government’s 30% PTC (HECO, 2014b; Farrell, 2010). Combined,

this creates a 24% return on investment, leading to installations paying themselves off in just

37

over four years, with over 20 years of guaranteed performance remaining (Meehan, 2013). In

comparison, the average annual return on investment of the S&P 500 over the last 50 years has

been 9% (ibid). In addition to these attractive financial incentives for solar, Hawaii is one of just

a few states to cap greenhouse gas emissions (DBEDT, 2013). Associated incentive programs

have been responsible for making utility scale renewable energy systems, including offshore

wind, profitable. Together the state’s feed-in tariff and GHG emission cap have led the state to

already exceed its RPS goal of 15% by the end of 2015 (IER, n.d.).

On the other side of these benefits have come some negative impacts. Similar to

California, solar homeowners in Hawaii have created a cost shift, in this case $50 million worth

(PBS, 2015). Additionally, because of the geographic proximity of early DG adopters, customer

level bi-directional flow now extends beyond neighborhood transformers and all the way up to

Figure 13 – In 2013 Hawaii generated 9639 MW of electricity, distributed accordingly (IER, n.d., p. 74).

38

the substation (St. John, 2014b). In fact, the impact of solar DG in Hawaii is far greater than

anything the Cal ISO has ever predicted for itself, as the Hawaiian grid reaches system-wide

demands “underwater”, or below zero, during peak solar generation, see Figure 14. In order to

highlight the dangerous nature of this negative demand, Hawaii’s demand curve has earned the

name “Nessie” curve (Paulos, 2014). The isolated nature of the Hawaiian grid means there is no

place for this electricity to go; in fact, in Kauai there are considerations for the utility to pay

customers to use electricity during the mid-day over generation period, for example to charge

electric cars (Paulos, 2014). The isolation also means that when quick or unexpected

interruptions in solar generation occur there is no RTO, ISO or interconnect to supply generation

capacity. Instead, energy storage has taken off on the chain of islands. Such a system prevented a

Figure 14 – Load profile curve for one of the Hawaiian Islands. The features of California’s Duck curve are

accentuated, with solar generation actually exceeding even base load demand (HECO, 2014a).

39

significant blackout in Kauai when an oil-fired generator tripped offline due to a DG solar

caused frequency interruption (Paulos, 2014).

Insight into when this type of event might happen in the future is complicated by two

factors. The first is a lack of accurate and granular solar generation data. Similar to California,

most Hawaiian DG systems are installed behind the meter, and as a result the local utility can

only access net generation information. However, where the case is worse in Hawaii than it is in

California is the lack of “smart meters” (DBEDT, 2013). In Hawaii, on-site electricity meters are

checked by hand once a month, while in California smart meters register electricity flow every

15 minutes and relay this information via a radio network to the utility. Smart meters provide

temporally relevant data with minimal operating costs. Without smart meters HECO is forced to

depend on transformer level data, which may cover several square miles of service territory,

making determining the location or cause of an interruption notoriously difficult. The second

difficulty in predicting DG production is a result of the microclimates of the leeward and

windward sides of the islands. Climates can be significantly different within just a few miles of

one another. Quick moving Pacific Ocean storms can arrive, interrupt solar generation and then

dissipate, all within the ramp period of an oil fired power plant (HECO, 2014; MIT, 2011). Note:

Similarly, these storms can increase generation from wind farms, and because of the difficulty to

predict these events, HECO prefers to curtail generation from wind farms, rather than adjust the

output of inflexible base load plants. For example, during the month of February 2013, 40% of

wind generation in Maui was curtailed (NREL, 2014b). Independent models suggest that

curtailment rates of 2-4% are achievable with minimum modifications (ibid).

These complications have delayed HECO’s ability to further integrate increased

renewable energy onto the grid, distributed or otherwise. It is estimated that HECO would need

40

to make $38 billion in capital investments in order to safely reach existing 2050 RPS goals

(Shimogawa, 2015). The utility understandably is hesitant to make such large investments and

has submitted several requests for revisions to the state’s RPS goals and the Public Utility

Commission’s (PUC’s) implementation procedures. The PUC, aggravated by years of delays,

intentional disregard of its instructions, and inaction by the utility, called HECO’s renewable

integration plans “fundamentally flawed” and a “failure” (HPUC, 2014, p. 28). Florida Power

and Light is awaiting federal regulatory approval for a purchase of HECO. Hawaiian citizens and

the state’s PUC hope this change in ownership will mark a change in commitment to renewables,

especially distributed systems (PBS, 2015).

Germany

Sparked by social concerns regarding pollution and climate change in the mid 1980s,

Germany has since become one of the leading governemental advocates for energy efficiency

and renewable energy (Wirth, 2015). The first piece of national legislation focused on energy

generation was the Stromeinspeisegesetz, or “Electricity Feed-In Act,” of 1991; with it, Germany

began to financially incentivize the democratization of electricity production through guaranteed

prices for electricity generated from distributed renewable energy systems (Wirth, 2015). The

Erneuerbare-Energien-Gesetz (EEG) or “German Renewable Energy Act” of 2000 refined the

earlier legislation, leading to increased renewable energy installations. The three main tenets of

the EEG are:

1) Guaranteed purchasing

Previous legislation allowed for private utilities to prefer centralized and conventional

generation facilities when scheduling eletricity generation merit order; as a result, generation

from distributed renewable systems was rarely utilized (GNFNA, 2015). The EEG mandates that

41

electricity grid operators incorporate distributed renewable systems before conventional sources

(GNFNA, 2015). These systems, because of their lack of externalities, are then paid an above

market rate for the electricity generated, this rate is called a feed-in tariff (ibid).

2) Revenue neutrality

The EEG feed-in tariff does not cost the German government anything. Instead, the

German people have accepted paying higher electricity rates to fund these renewable energy

installations (GNFNA, 2015). While the German citizenry pays approximately $0.14 extra per

kWh in order to fund the program, German industrial and manufacturing facilities are exempt

from electricity price increases associated with feed-in tariffs (NREL, 2014a). Because of this

guaranteed subsidy, the electriricty price that feed-in tariff renewables require to operate

profitiablly is extremelly low. This in turn drives prices on the wholesale elctricity market down.

In fact, retail electricity prices have dropped for four years straight (Morison & Mengewein,

2014).

3) Declining subsidies over time

Renewable energy installations are guaranteed a technology specific feed-in tariff rate for

20 years (GFNA, 2015). However, the initial tariff amount decreases each month at a

predetermined rate; this digression is desgined to promote increasingly efficient systems over

time (ibid). While future rates and time tables have been adjusted several times since the initial

passage of the EEG in 2000, historical rates have been left intact (ibid). This is not the case in

Spain, which has a similar feed-in tariff system, where the government has retroactively changed

tariff prices, obviously negatively impacting project economics (NREL, 2014a).

As a result of the EEG, significant increases in renewable enegry installations have

occurred. In 2000, all renewables (onshore and offshore wind, biomass, photovoltaics and

42

hydropower) accounted for approximatelly 6.5% of Germany electricity consumption (Wirth,

2015). Although sources vary regarding the exact amount, all statistics outline a clear trend: solar

now accounts for between 5.7 – 6.9% of total electricity generation, which is essentially the

entire renewable market share of the 14 years prior (wirth, 2015). A typical 2014 generation

profile for Gernmany can be seen in Figure 15 shows the growth in each renewable sector over

the past 10 years. EEG feed-in tariffs are a significant financial incentive. When they are

combined with decreasing installation costs, 13% compounded annually since 2006, it is easy to

understand the exponential growth in German solar insallations (NREL, 2014).

This growth has not been achieved through large scale utility systems, but through much

smaller systems installed on rooftops across the country. In fact, there are 1.5 million distributed

renewable energy generating "power plants" in Germany, with more being added every month.

Figure 15 – 10 years of growth in the German renewable energy sector. While a portion of this

this can be attributed to utility scale wind projects, the largest increase comes from distributed

solar (Wirth, 2015, p. 5)

43

Germay has also streamlined the application and permitting process. Installing a rooftop solar

panel system costs more than twice as much in the United States than it does in Germany

(Woody, 2012).

All of this investment and dependence on solar has occurred despite the fact that

Germany has comparatively poor solar resources. As outlined in Figure 16, the amount of annual

solar radiation that lands on Germany, with its generally cloudy weather, is akin to the amount of

sunshine that lands on Alaska, which partailly falls within the Artic Cirlce. Despite this,

Germany creates 6.5 times the solar energy of the entire United States (Sahan, 2013b).

Only 20% to 30% of the energy generated by rooftop arrays in Germany is “self

Figure 16 – Solar irradiation rates for the United States compared to Germany. Note not only

the relative size of each country, but also the wealth of solar irradiation in even the wet Pacific

Northwest as compared to Germany (Shahan, 2013a).

44

consumption” or used on-site to fill household demand (Stetz et al, p. 51). This means that 70 –

80% of the elctricity generated by rooftop solar panels is sent up the distribution grid. To

decrease the amount of electricity sent back to the grid, an incentive program for residential scale

battery storage system was initiated in May of 2013. This program includes a €600 per kW

subsidy, in addition to a low interest rate loan to cover the remaining system cost (Stetz et al, p.

51). Residents are prohibitied, however, from exporting more than 60% of their PV system’s

capacity (ibid). In the last two years the program has funded the installation of more than 15,000

combination PV and battery systems. The energy not absorbed by these in home energy storage

systems flows to the distirbution grid, and in 2009 Germany began to experience substation level

reverse load flows (Stetz et al, 2015). As outlined by Figure 17, these negative loads grew until

Figure 17 – Similar to Hawaii’s Nessie Curve, solar generation in Germany first began to exceed

demand in 2009. The scale of reverse flows now exceeds the scale of peak demand (Shahan, 2013).

45

2011, when the amount of eletricity exported from the substation matched the peak amount used

by the station during the winter. Note that Germany’s system is a full four years ahead of the

Hawaiian Nessie Curve, and at rates that the Hawaiians have yet to experience. Since 2011,

summer exports have only continued to grow in relation to peak load demands, which are now

50% of peak exports. Given that the elctricity grid is desgined for a downflow of electricity from

centralized power plants to end users, a substation level back flow has significant infrastucture

impacts. German utilities were forced to make infrastructure upgrades and chose to pursue $35

million worth of “classic grid reinforcements,” such as the installation of additional transformers

and builing of new substations (GTAI, 2015).

Even with these infrastructure investments, the German grid is subject to a 1,000 MW

swing in solar production over the course of just 15 minutes (Stetz et al., 2015, p. 58). The

negative ramifications of these swings in production can be magnified when poor forecasting

tools are utilized. The scale of current forecasting error is exemplified by an example from April

of 2013 (Stetz et al., 2015, p. 58). A day ahead forecast estimated that 20 GW of distributed

electricity would feed into the German electricity grid (ibid). This exceeded expected demand

and required German utilities to find electricity buyers on the European Energy Exchange

(EEX). Actual distributed production for the day in question only reached 11.2 GW, which

represents more than a 45% over estimation (ibid). Grid reliability required German utilities to

find 8,800 MW of reserve power. This amount exhausted all power reserves of the four German

utiltiies and the support of neighboring countries was required in order to balance the electricity

grid (ibid). This example is an extreme outlier regarding the accuracy of current forecasting

methodolodies; the root mean squared error of forecast compared to production is between 5 and

46

7% (Stetz et al., 2015, p. 58). Even these single digit inaccuracies can result in significant

pressure on on-demand elctricity requirements (ibid).

This accuracy was at no time more important than during the recent near total solar

eclipse. The eclipse, which lasted for two and a half hours, caused solar generation in Germany

to go from 21.7 GW to 6.2 GW, a more than 70% drop in production (Wesoff, 2015). Not only

was there expansive decline in production, but also it happened more than 2.7 times faster than

would normally occur during sunset, which means that following the eclipse, producition from

PV solar rebounded excessively faster than is the norm as well (Wesoff, 2015). Germany’s grid

operators responded with a combination of strategies to match the generation and ramp rate

needs. These included increasing hydroelectric storage in anticipation of the event, employing

demand response in order to cut demand by more than 5%, and ramping up natural gas peaker

plants earlier in the day than traditionally would be required (ibid). Europe as a whole was able

to counteract the impact of the eclipse by importing electricity into areas impacted by the eclipse.

In addition to connecting to the EEX, in order to effectively match DG variability and

forecast error, Germany has made significant investments in the flexibility of its generation

profile. Modifications to baseload nuclear and coal power plants have allowed for increased

flexibility and ramp rate. This has allowed the baeload facilities to act in conjunction with peaker

plants (GTAI, 2015). Despite these investments, electricity outages do occur. Even though these

fluctations generally only last a few seconds, they can have significant impacts on sensitve

electrical machinery. In order to counteract this impact, manufacturing facilities, which account

for a significant percentage of Germany’s economy, are investing in onsite power production and

protection equipment (Schröder, 2012). Depending on the timing of an interruption and the

sensitivity of the process, damages can range “between €10,000 and hundreds of thousands of

47

euros” (ibid). If it is deemed that an interruption could have been prevented, the utility is only

responsible for €5,000 worth of losses (ibid). As a result of the increased frequency of

interruptions and the gap between potential damages and utility liability, sales of emergency

power technologies have grown by 10% each of the last three years (Schröder, 2012). Some

facilities are actually moving beyond surge protectors and batteries and are instead using the

electricity grid as a back up to on-site power generation, which is powered by natural gas fuel

cells (Bloom Energy, 2013).

With this in mind, Germany’s largest power producer, RWE, has shifted from a

generation based business model to one of a service provider, positioning the company as a

“project enabler, operator and systems integrator” based on the company’s internal expertise

with the country’s energy infrastructure and markets (Beckman, 2013). RWE is aiming to reduce

risk by facilitating, rather than leading, investments now funded by third parties (ibid). RWE

aims to shed operations with long payback periods and significant maintenance costs, such as

nuclear and coal power plants, while holding onto assets it believes will be critical to the

successful transition towards a green energy future, including transmission and distribution

infrastructure (ibid).

One piece of infrastructure RWE believes will be critical to the German electricity grid in

the future is the Stromautobahn or “Energy Highway,” a transmission line which will connect

the wind rich North Sea coasts with the demand of the Southern cities; the Stromautobahn is

expected to cost $1 trillion (Karnitschnig, 2014). This expense is larger than it otherwise would

have been, as Germany has been accused of putting the cart before the horse by engaging in the,

siting, construction and operation of wind farms before determining how the associated

electricity would be transmitted (Karnitschnig, 2014). As outlined by Günther Oettinger, Energy

48

Commissioner of the European Union, this has forced the hand of German utilities, leading to

increased cost and limited transmission route flexibility (Karnitschnig, 2014).

Discussion & Recommendations

Regardless of the jurisdiction in question, the entire electrical industry suffers from a lack

of standard metrics and performance evaluation methodologies. This in turn limits comparable

statistics and analysis of system performance and industry changes over time. This deficit has

been noted in prior industry reports, but its importance merits repeating, as overcoming it is

critical to the success of centralized policy and focused reforms (MIT, 2011; DOE, 2015). This

difference in metrics spawns from the same cause that makes RTO interconnections difficult:

service territory monopolies that did not require corporate communication between utilities. But

as the industry moves towards a more integrated grid, it is not just the infrastructure that needs to

be harmonized, but also the data centers and corporate reports. With utilities and grid

interconnections spreading across state and province boundaries, it is the role of national

agencies and international industry associations to set and enforce standards. Common financial

measures should at a minimum consider operating costs, as the leveled cost of energy metric

does, if not also account for externalities including human and environmental health effects.

Until such standards are developed, future analysis of the electric industry will be limited from

reaching its full potential.

Another limiting factor is the timing of this paper in relation to two other in-depth reports

by the US federal government in relation to the current state of the country’s electrical

infrastructure. The Quadrennial Energy Review (QER) was published within the same month as

this research paper and findings from the 350 page document could only minimally be

incorporated (DOE, 2015). The breadth of the report outlines the expansive nature of the

49

problems at hand and the impact climate change will have on the nation; the QER Task Force,

which helped compile the document, includes representatives from over 20 different federal

departments including Defense, Interior, Agriculture, State, Energy and Army Corps of

Engineers (DOE, 2015). The second report, the Eastern Renewable Generation Integration Study

(ERGIS) is a computer based model of the Eastern Interconnect including infrastructure

mapping, interlinked capacity limits and a simulated wholesale market (NREL, 2015). This

model allows for the impact of a variety of renewable integration scenarios to be assessed,

including both utility and distribution scale systems (ibid). ERGIS will help to identify weak

links in the Eastern Interconnect and aid in the prevention of cascading system failures

previously described and experienced in 1965 and 2003 (ibid). A request to review a preliminary

version of the report was made, but denied; the final report, dataset and model should be

published within the next three months. Future research on the subject of distributed energy

management strategies should incorporate findings from both of these sources.

Discussion

As was previously outlined by Figure 6, the price of solar panels has a downward cost

trend over time. When this trend is combined with the increased number of states that are

requiring the installation of renewables, see Figure 18, it can almost be guaranteed that

distributed energy penetration rates will increase in the United States. However, as outlined by

both the German and Hawaiian cases, if regulations are not properly worded or allow utilities

discretion, these entrenched interests will resist, at least initially, the expansion of renewables in

their service territories (HPUC, 2014; GNFNA, 2015). These utilities’ concerns are not

misplaced, as renewables do significantly impact the complexity of operating an already intricate

system as well as have the potential to cause harm to distribution level infrastructure (MIT,

50

2011). In order to minimize the infrastructure damage caused by integrating renewables at

critical mass, it is important that a strategic and coordinated approach is taken.

As outlined in Figure 18, even the U.S. states with the highest renewable integration

goals, in terms of capacity and percentage, pale in comparison to the amount of solar already

installed in Germany. It is because Germany has already overcome the challenges that California

and Hawaii are currently facing that this research paper aims to understand the governmental

policies and corporate strategies that have allowed for the incorporation of significant distributed

renewables, with minimal impact on grid integrity and reliability.

Strengths and Weaknesses of the German Electricity Industry

The German electrical system is not without its faults. For example outage rates in the

U.S. are about 30 seconds annually in urban areas, while the comparable German rate is 45

seconds (Nicola & Landberg, 2015; MIT, 2011, p. 9). Although a holistically minimal

difference, this 50% increase in total outage length can have a significant effect on computer

driven systems (Schröder, 2012). In order to combat these effects, owners of such systems are

forced to spend thousands of dollars on surge protection and emergency power supplies (ibid). In

fact, some of the most sensitive operations, such as data centers, are initiating a movement back

to employing onsite power generation and have gone so far as to flip the script and are relying on

the grid as a back-up power source. (Bloom Energy, 2013). Furthermore, several key factors

separate and differentiate the three geographies, making an exact mimicking of the German

electrical system both unwarranted and improbable. Although clear upon examination, it should

be explicitly noted that the California and German electricity grids are part of the larger Western

Interconnect and European Network of Transmission System Operators for Electricity,

respectively. As such, these locations are provided with additional flexibility regarding

electricitygeneration and the effect of weather, as well as better access to emergency generation

51

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52

support. Conversely, the Hawaiian electricity grids are a series of semi-independent island

networks which serve a population orders of magnitude smaller. Hawaii’s 14 power plants have

a firm capacity of just over 2,000 MWs (NREL, 2013). California, through the Cal ISO, is

comprised of 760 central generation facilities with a capacity of 60,000 MW (Cal ISO 2013a).

Despite the fact that Germany has a smaller land mass than California, Germany’s two-state

history and district utility focus have resulted in the country having over 5,200 power plants over

10MWs in size, with combined capacity of 70,769 MWs (GTAI, 2015). Despite their differences

grid operators from each jurisdiction can learn a significant amount from one another.

In all three geographies distributed generation has reached grid parity (Meehan, 2013;

Wirth, 2015). As such, it is not deployment costs that further limit the incorporation of additional

renewables, but the flexibility of system operators to handle these variable, yet semi-predictable

generation sources. Centralized generating plants, especially nuclear and lignite coal base load

facilities, cannot effectively reduce generation. As a result power systems with more flexibility,

such as windmills, are curtailed when peak solar generation, which cannot be curtailed, occurs

(MIT, 2011). Such instances have happened in all three jurisdictions under consideration,

including 1,200 MW of renewable curtailment by Cal ISO (Howarth & Monsen, 2014). Pitting

renewable energy generating systems against one another, rather than applying the focus on

outdated and non-displaceable base load generation facilities, outlines a clear status quo basis.

Base load facilities were designed with the centralized grid in mind, which is a paradigm, for

better or worse, which no longer applies. Without these non-displaceable sources of base load

generation, it is estimated that the Cal ISO could increase renewable penetration by as much as

18.6% without enduring additional curtailment requirements (Taneja, Smith, Culler &

Rosenberg, 2013).

53

Germany has excelled at integrating renewables into its generation mix, both distributed

and centralized, and although Germany is lauded for the growth of its solar market, the country

has been technology agnostic when it comes to emission standards and subsidies. Similarly, the

EPA’s new Clean Power Plan is technology agnostic, allowing state governments to determine

how they will meet federal goals, whether it be through efficiency, solar wind, tidal, clean coal,

natural gas, etc. (QER, 2015). Where there is still room to grow in the United States compared to

Germany is investments in both distribution and transmission infrastructure. In Germany’s

“Energy Highway,” the transmission line will cross municipal and province boundaries in order

to support North Sea wind farms. The United States’ transmission network is in dismal shape and

the lack of connection between the Wind Belt and the West Coast or the Eastern Seaboard and

Mid Atlantic population centers has already made developing projects in those areas

economically unfeasible (QER, 2015).

While investment in infrastructure may separate the three jurisdictions, investments in

workforce training for “green collar” jobs does not. Germany’s investment in its energy

infrastructure helped to carry it through the Financial Crisis and Great Recession (Wirth, 2015).

In the U.S., the solar industry employs more individuals than the coal and natural gas industries

combined (Sustainable Business, 2014). The current count of 173,000 solar jobs is likely to

continue to rise as the number of rooftop systems increases (ibid). In Hawaii, the number of jobs

in the solar industry exceeds the number of jobs in agriculture and is second only to the tourism

industry (Shimogawa, 2015).

Energy Storage

Energy storage represents an alternative to retrofitting base load power plants, as it

provides both a flexible form of generation and a depository for otherwise curtailed production.

Although often lumped together, energy storage is actually comprised of a myriad of distinct

54

technologies including gravitational, thermal, chemical, and combination approaches. Depending

on the technology, energy storage can serve a variety of important roles including load leveling,

frequency control, contingency reserves, and infrastructure upgrade replacement (NREL, 2010).

As shown in Figure 19, the vast majority of currently installed energy storage capacity is in the

form of pumped hydro.

Pumped hydro energy storage is very similar to hydroelectric energy generation,

popularized by the Hoover and Three Gorges Dams. Where these dams allow water to continue

down river once it flows over gravitationally fed turbines, pumped storage moves water between

two reservoirs with differing elevations. Water from the higher embankment flows downhill and

over a turbine when energy is needed, and when there is excess energy, water from the lower

reservoir is pumped to the higher basin to develop capacity for future energy needs (EPRI,

2010). Because there are no thermal or change of state losses, pumped hydro storage is only

Figure 19- Worldwide installed electricity storage capacity by technology (EPRI, 2010).

55

limited by the efficiency of the turbine, losses due to evaporation, and the elevation difference

between upper and lower reservoirs, allowing it to reach recovery rates as high as 80% (EPRI,

2010). However, because of the geographic constraints, few additional locations for pumped

energy storage exist (EPRI, 2010). Furthermore, flooding otherwise healthy ecosystems in the

name of energy storage is becoming increasingly unpopular. As such, alternatives to pumped

hydro are needed. Lead-acid batteries are one of the oldest and most mature battery types,

reaching 85% efficiency (EPRI, 2010). Lead-acid batteries are used in a slew of industrial and

household applications, most popularly in vehicles. However, lead-acid batteries corrode over

time and lose efficiency when deeply drained, making them unsuitable for use by utilities (ibid).

Consequently, researchers and private companies are pursuing an alternative battery technology.

Lithium-ion batteries are popular in consumer electronic because of their energy density;

however, the availability of rare earth metals like lithium makes large scale lithium-ion energy

storage systems prohibitively expensive.

Compressed air energy storage (CAES) may have the most potential. Although the

underlying technology was first developed during the Industrial Revolution, compressed air was

not used for utility scale energy storage until a 642 MWh facility was built in Germany in 1978

(DOE, 2014). The still operational facility utilizes natural subterranean geological formations to

store compressed air (DOE, 2014). The facility exemplifies all of the benefits of CAES: it is

extremely reliable, has minimal operating costs, and has essentially no ramp up or cool down

requirements (ESA, 2014). Just as with pumped hydro storage, however, the size and location of

CAES facilities has been limited by the existence of adequate natural geographic locations.

Several attempts were made to build compression tanks large enough to serve utility scale

demand; however, the size of the equipment required was cost prohibitive (ESA, 2014). Modular

56

compression tanks arranged in series were also attempted, but commercially unattractive (ESA,

2014). These attempts have been limited by the intense heat generated during compression, a

result of the Ideal Gas Law, PV = nRT; where P stands for the gas’ pressure, V represents the

volume of the compression chamber, n the mass of the gas, R the ideal gas constant, and T the

gasses’ temperature.

Recent technological advancements, however, allow for a work around to the variables of

the Ideal Gas Law, specifically the high temperatures created during compression (LightSail

Energy, 2014a). When an ambient temperature liquid is aerosolized in the chamber of a CAES

system during compression, the liquid absorbs the change in temperature. Once settled, this

liquid, and the associated thermal properties, can be removed from the chamber. The process can

then be repeated, allowing for high pressures to be reached without the previously associated

high temperatures (LightSail Energy, 2014). Where previous CAES systems reached

approximately 40% efficiency and were geographically and capacity limited, this new ambient

temperature design is achieving energy recovery rate upwards of 70% (ESA, 2014; LightSail

Energy, 2014).

Finding an economically viable form of energy storage has become increasingly

important as California’s Duck Curve is five years ahead of schedule (Blunden, 2015). This

unexpected advancement becomes progressively overbearing as the Cal ISO and CPUC both

based their energy storage pilots and funding for similar programs on the model’s timeline

(Blunden, 2015). Based on the accelerated nature of the Duck curve, investments in energy

storage, including increased government research and a streamlined energy storage

interconnection application process, should also be accelerated.

57

A Threatened Business Model

While deregulation and decoupling significantly impacted the electrical industry in short

order, distributed renewables can slowly erode away a utility’s customer base and establish a

positive feedback loop that escalates bottom line impacts over time. As previously discussed, in

jurisdictions that allow net metering, solar creates a cost shift from customers with solar panels

to those without. While this cost shift is currently minimal, an informed and active consumer

base, triggered by increased costs and a lower cost alternative, will create a downward cycle, as

outlined by Figure 20. In fact, Figure 20 comes straight from a publication by the Edison Electric

Institute (EEI), one of the oldest and most well regarded electricity industry organizations in the

U.S. EEI believes that distributed renewables represent a threat on the same scale as cell phones,

which bankrupted the telecommunications industry, or the digital camera, which all but

artistically replaced the use of film for photography (EEI, 2013). EEI is not alone in its

sentiment, financial services firm Barron’s downgraded corporate bonds for the entire electric

utility sector, citing competition from solar (Anerio, 2014). Although it is unlikely, at least in the

near term, that all utility customers will install on-site solar panels, the EEI suggests that in order

for utilities to survive they must disrupt the positive feedback loop’s cycle by shifting to a

service based model (EEI, 2013). Similar shifts include Kodak’s use of the disposable camera

and IBM’s movement towards consulting services.

As previously discussed, utilities in Germany have already began to adopt changes in

their business models. In addition to changes in the type and location of generation systems,

utilities should consider changes to how and where people use energy. Easy access to electricity

has become increasingly important as use of smart phones and electric cars escalates. Depending

on penetration rates, electric vehicles (EVs) could drastically change the shape of the demand

curve. If properly incentivized, EV owners could help to reduce if not eliminate DG mid-day

58

backflow (QER, 2015). Until recently, California utilities were not allowed to own EV charging

infrastructures (Trabish, 2015). Following a regulatory change, PG&E is proposing building

25,000 EV charging stations throughout its service territory (Trabish, 2015). EVs represent a

completely new class of customer, as the demand from charging a single EV is akin to that of 10

homes (ibid). Yet this load is mobile and can connect without warning to almost any part of the

grid. Do EVs represent another blow to utilities or the potential to avoid the cost shift positive

feedback cycle?

Forecasting

Astronomers were able to predict the occurance of the eclipse with significant foresight

and satelittle technology allowed for the path of lunar shadow to be plotted as it moved across

the Earth (Letendre, 2014). This same foresight accuracy and locational granularity does not

exist with regards to the weather. Weather patterns, including cloud location, translucence,

Figure 20 – A positive feedback loop of rising costs and fewer customers. Triggering the solar

cost shift threatens the financial integrity of the electricity utility industry (EEI, 2013).

59

speed, and direction, are influenced by conduction, convection, humidity and a slew of other

global forces, and are difficult to predict with significant accuracy. It is therefore equally difficult

for grid operators to predict with accuracy the amount of electricity that will be produced by

renewable systems. A miscalulation in the timing of a storm front, or the speed at which it will

pass through an area, significantly affects generation needs. Solar panels can vary their output by

as much as 90% over the course of just a few seconds (MIT, 2011, p. 55). Current hourly

forecasts provided by NOAA are both not accurate enough, nor at a time scale that is informative

(Letendre, 2014). Although private weather forecasting services do exist, they too could benefit

from increased accuracy, with a 16% mean absolute error for hour ahead forecasts (Letendre,

2014). On top of the need for this temporal accuracy, grid operators also need location

granularity. Centralized electricity systems are only moderately affected by the location of

demand; the narrowest location of consequence is the substation level, which has a bi-model

distribution of urban versus rural in regards to a service area size with a mean of 50 square miles

(QER, 2015). Because weather can vary significantly within just one square mile, sub-station

level weather predictions are not granular enough to provide insight into distributed generation

(Letendre, 2014). Pilot programs that combine numerical weather predictions with spacial cloud

imagery offer the potential for increased accuracy and granularity, but still require significant

development (Letendre, 2014).

Because of the extreme volatility and lack of accurate information regarding expected

generation, utility companies cannot rely on production from distributed renewables to service

grid demand. As a result, distributed energy generation is only marginally included in demand

forecasts (MIT, 2011). Rough calculations of the cost of this over production in California are

conservatively $296 Million annually and will continue to grow (EIA, 2014). This is on top of

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the estimated 590,000 metric tons of carbon dioxide and other greenhouse gas emissions caused

by over production (EIA, 2014).

Recommendations

Among the following recommendations are those that can be implemented in the short

term, medium term and long term. Despite its delayed impact, the potential of this first

recommendation is so great that it should be pursued immediately. As highlighted by Figure 21,

investments in research and development in electrical infrastructure by investor owned utilities

(IOUs) have degraded. R&D budgets in the mid-2000s were half of what they had been just ten

years prior and the most recently available data represents that less than 1% of the industries’

revenues are spent on R&D (MIT, 2011, p. 11). While the bottom line impacts of these cuts in

R&D are enjoyed by short term decision makers, they negatively impact the industries’ potential,

and the success of future leaders to handle market shifts, such as the increased penetration of

distributed renewable energy. Both fortunately and unfortunately, a small portion of these R&D

investment gaps have been filled by research teams at the National Renewable Energy

Laboratory (NREL) and Lawrence Livermore National Labs (LLNL). However, the scale, focus

and risk profile of national laboratories is much different than that of private industry. As such,

these labs have not had the same impact as if private research efforts had been continued. It is

essential that the NREL and LLNL be allowed to continue their work, immune from fear of

budget cuts or experiments being interrupted by government shutdowns. These organizations

offer a critical independent voice and have outlined the technical and economic potential of

renewable resources, including power system models which allow utilities to test and visualize

the infrastructure impacts of projects before requests for procurement are even finalized (NREL,

2014a). Furthermore, utilities should reassess the financial perspectives that value the short term

61

benefits of budget cuts, when compared against the long term shareholder value created by past

developments projects. Furthermore, the foregone advantages of potential developments should

be calculated before any future cuts in R&D budgets are considered.

The need for leadership from governments and utilities continues and should include

streamlining the distribution grid interconnection application process. As outlined by Figure 22

the cost required to purchase, install and interconnect a residential rooftop solar system in the

United States is more than twice what it costs in Germany. Although a small difference in the

price of the physical panels exists, much of the cost variance is attributable to permitting, taxes

and company overhead (Woody, 2012). In fact, these “soft costs” account for over half of the

price of installing such a system in the U.S. (Woody, 2012). Temporal requirements mirror the

ratio of excessive financial burdens placed on U.S. potential residenital solar homeowners via

paperwork and applications required by local, county, utility and state oversight boards (ibid). In

Figure 21 – Research and Development investments by Investor Owned Utilities. Over ten years

R&D budgets were cut by over 50% (MIT, 2011, p. 11).

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Germany, just one form, which fits on one piece of paper front and back is required; in

comparison, depending on the jurisdiction in the United States, more than 50 separate documents

must be completed and approved before interconnection approval is granted (Woody, 2012).

Nevermind the waste of paper or frustration completing so many forms causes, this red tape

levies significant opporutnity costs on potential solar homeowners. Where Germany has

streamlined the process, Hawaii has brought it to a halt by placing holds on all solar

interconnections (DBEDT, 2013). Although the Hawaiian electricity grid faces unique

limitations because of its isolated nature, barring additional interconnections is a short term

Figure 22 – Cost breakdown of installing residential rooftop systems in Germany compared to the

United States. “Soft costs” represent over 80% of the difference (Woody, 2012)

63

solution for a long term problem that requires investments in the distribution grid, discussed in

more detail below.

Further investment is required as society adapts legacy infrastructure, originally designed

to service centralized power distribution, to a bi-directional paradigm. The California Energy

Crisis outlined the need for redundant transmission lines in order to protect against market

manipulation or a less nefarious, but equally impactful, event. The Western Area Power

Administration (WAPA) commissioned an upgrade to Path 15, the congested transmission line

that served as a bottle neck during the energy crisis (WAPA, 2004). While resilience is

important, investments in infrastructure are often dismissed for more popular projects. Although

the corporate recovery from the Great Recession may be complete, Main Street’s recovery is

snarled by both un- and under- employment. With this in mind, few government programs can

offer better returns than investments in the country’s electrical networks. For every dollar spent,

as much as six dollars are returned in the form of increased efficiency and reliability, in addition

to the creation of 47,000 skilled jobs since 2012. (Silverstein, 2015). Even when projects have

enough local political capital, “fragmented and overlapping jurisdictions threaten to impede

development of the grid of the future” (DOE, 2015, p.3-22). It is for this reason that federal

guidance is required, especailly if new transmission lines are to cross state and province

boundaries.

While the transmission grid requires new paths and increased redundancy, the distributed

grid has been, and will continue to be, the segment of the electricity grid most impacted by the

co-location of generation with customer demand. As previously discussed, Germany has also

made significant investments in its distribution grids, and luckily for grid operators in Hawaii,

California, and the rest of the globe, the vast majority of these infrastructure upgrades, completed

64

in 2009, used mature and ubiquitous technologies (Wirth, 2015). Technologies that were not yet

commercially viable or cost competiivtive in 2009, but are today, such as local reactive power

provisions and tap changing transformers, could potentially result in a 50% cost savings when

compared to classical grid reinforcement techniques (Stetz et al., 2015, p. 55). Rather than

delaying distribution system upgrades until they are required, as is already the case in Hawaii,

grid operators should use a mix of mature and experimental technologies, testing and publically

reporting on the benefits and problems of each.

These investments should be paired with increased scrutiny regarding distributed

generating system interconnections. PV solar technology, although still developing, is mature

enough to no longer require universal and unfettered access to the electrical grid. Just like horse

drawn carriages, bicycles and mopeds are not allowed on highways, standards should be

developed in order to protect the electron highway, the elctricity grid (PBS, 2015). Such

interconnections can and do cause significant harm and reliability issues, including the potential

for a frequency shift to trip sensitive solar inverters and cause a snowball effect, disconnecting

massive amounts of renewable generation from the grid (MIT, 2011). Such an event would

require significant ramping of generation without warning and would likely lead to brown, if not

black, outs.

It is clear that neither the utilities nor the solar industry are independent enough of their

own bottom lines to create such standards. Instead, an independent body, likely compiled of

representatives from both industries as well as government regulators and advisors, should

conduct studies and pilots in order to determine actual impacts and only then establish a standard

for where, how, what type, and in what quantities distirbuted renewable systems can be

interconnected.

65

In addition to standards and independent arbiters, the electricity grid also needs increased

flexibility, specifically ramp-up and ramp-down speed and capacity capable of matching

predictable changes in renewable output. As has been previously discussed, legacy centralized

plants were designed for steady, continual output. While Germany’s base load capacity still

includes some nuclear facilities, these power plants have undergone upgrades allowing for

stepwise changes in generation, rather than all or nothing operation (GFNA, 2015). This

flexibility allowed the German electrical grid to successfully meet demand during a near total

solar eclipse (Wesoff, 2015).

While pumped hydro also played a critical role in the German electricity grid’s clean

encounter with the solar eclipse, there is little additional capacity available (Wesoff, 2015; ESA,

2013). In order to handle such an event in the future, when increased penetration of solar is

likely, utilities will need to make significant investments in energy storage. Compressed air

energy storage may have the most unmet potential, but rare earth metal batteries may offer

higher energy densities and round trip recovery efficiency. Similar to feed in tariffs, energy

storage research and investments should be technology agnostic, helping to reduce the potential

for inappropriate industry influence on regulators. Another key component of surviving the solar

eclipse was accurate forecasting regarding the path, intensity and duration of the event. Similar

forecasting accuracy is needed for every day weather events. Forecasts that accuratly represent

an actionable time frame, i.e. 15 minutes which would match the wholesale spot market time

frame, would help to increase the inclusion of DG into demand profiles and reduce over

generation and curtailment.

The next two recommendations strike at the core of the traditional electric utility model.

These recommendations’ institutionalization will be required due to the increasing threat of the

66

solar cost shift and resulting positive feedback cycle, both previously discussed. The first action

is a change in business model from a consumption based service territory company to an open

and enabling service provider. Again, U.S.-based utilities can look to Germany to determine the

potential pitfalls and successes of such a system. Acting as an enabler of renewables, even in the

short term, may help to dissuade the cry for Public Power Agencies in California and improve

relationships with regulators in Hawaii. In decoupled markets, like California, solar still

represents a cost shift for customers, but does not threaten the utility’s revenues. It is in these

areas that utilities should pursue rate reform to more accurately reflect the cost associated with

the bi-directional flow of electricity. This includes the separation of transmission and distribution

infrastructure use from generation charges, and the inclusion of demand or time of use charges

that highlight the temporal value of electricity. While this may complicate consumers’ bills, it

provides transparency into the complexity of operating a 24/7/365 system to cynical regulators,

wary investors and uninformed consumers. Alternatively, or perhaps as an intermediate step,

utilities can begin to collect fixed charges. This is already the case for customers of the leading

utility in Arizona, APS, where residential solar customers are now charged a $5 “grid access fee”

(Pyper, 2015). The resulting $60 annual expenditure seems to have little, if any, impact on the

decision by homeowners to install solar panels. Installations are actually up 10% since initiating

the charge and interconnection applications have doubled compared to the same period just a

year prior (Pyper, 2015).

Conclusion

With the price of solar and other distributed renewable energy generation technologies

continuing to fall, on-site consumer generation is forecasted to increase significantly. Electricity

grid operators in California and Hawaii have already been exposed to the initial impacts of solar

penetrations; government bodies and utilities across the country, and in fact the world, look to

67

these jurisdictions for guidance. Fortunately, the experiences of German utilities have provided

clear examples of how to handle significantly high levels of solar penetration using existing

technology, all while maintaining profitability and resiliency. In order to achieve this same

success, utilities and government regulators should begin to transition the electricity grid into a

bi-directional network by implementing the following changes:

1) Institutionalize operational and metric standards across the industry

2) Streamline interconnection costs and paperwork, while creating interconnection standards

3) Invest in transmission and distribution infrastructure, increasing resilience

4) Increase generation capacity flexibility through legacy base load power plant upgrades

5) Make technology agnostic investments in the energy storage industry

6) Improve distributed generation forecasting accuracy and granularity

7) Shift to an open and enabling service based business model

8) Modernize rate structures to reflect infrastructure costs and the temporal value of electricity

The need for reliable electricity and the momentum of distributed energy need not be

diametrically opposed forces. By making smart investments in infrastructure and improving the

accuracy and use of analytics, grid operators can transition towards a generation profile with

minimum greenhouse gas emissions and pollution. There were those that thought electricity

would never catch on due to the amount of effort required to traverse the nation with miles and

miles of expensive metal wires, yet look where we are today. Is the challenge of renewable

energy greater than the challenge of starting from nothing? With technology and knowledge

already in hand, societal will is all that is needed now.

68

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