Responsible Policies for Renewable Energy Development...which allow customers to supply their household electricity (usually through rooftop solar) and sell excess generation back

Responsible Policies for Renewable Energy DevelopmentUpdated 12.2018

Prepared by

Public Sector ConsultantsLansing, Michiganwww.publicsectorconsultants.com

Prepared for

Michigan Energy FirstOkemos, Michigan

PUBLICSECTORCONSULTANTS.COM Responsible Policies for Renewable Energy Development 3

TABLE OF CONTENTSEXECUTIVE SUMMARY ...................................................................................................................................4HISTORY OF RENEWABLE ENERGY.................................................................................................................7TRANSFORMATIONAL TRENDS IN THE ELECTRIC POWER SECTOR..............................................................11

AGING GENERATION INFRASTRUCTURE ....................................................................................................................11

FLAT DEMAND FOR ENERGY ........................................................................................................................................13

CHANGING GENERATION ECONOMICS .....................................................................................................................14

Limitations of LCOE Metric ........................................................................................................................................... 16

Trends in New Generating Capacity ............................................................................................................................. 19

ADVANCING ENERGY STORAGE TECHNOLOGY ........................................................................................................21

REINVESTMENT IN THE ELECTRIC GRID ....................................................................................................................23

RENEWABLE ENERGY POLICIES ..................................................................................................................24

TAX CREDITS, DIRECT SUPPORT, AND INVESTMENT SUBSIDIES ............................................................................24

History of Federal Funding for Renewable Energy ....................................................................................................... 24

RENEWABLE PORTFOLIO STANDARDS .......................................................................................................................26

History of RPSs ............................................................................................................................................................. 27

CUSTOMER-OWNED DISTRIBUTED GENERATION .....................................................................................................28

History of Net Metering ................................................................................................................................................ 28

Evolution of Net Metering Policies ................................................................................................................................ 29

PUBLIC UTILITY REGULATORY POLICIES ACT ............................................................................................................33

History of PURPA .......................................................................................................................................................... 33

Evolution of PURPA ...................................................................................................................................................... 36

IMPLICATIONS FOR PUBLIC POLICY .............................................................................................................39

SUCCESS OF THE RENEWABLE ENERGY PORTFOLIO STANDARD .........................................................................39

THE RIGHT ROLE FOR PURPA .....................................................................................................................................40

ACCOMODATING CUSTOMER-OWNED DISTRIBUTED GENERATION .......................................................................41

Need for New Rate Designs ......................................................................................................................................... 42

Environmental Benefits ................................................................................................................................................. 42

Equity ............................................................................................................................................................................ 42

Comprehensive Planning ............................................................................................................................................. 43

REFERENCES ................................................................................................................................................46

EXECUTIVE SUMMARYThe electric power industry is in a period of disruption and transformation—driven largely by aging generation and grid infrastructure; declining costs for new generation resources; advances in technology, especially renewable energy and battery storage; and changing customer demands. Together, these factors have the potential to irrevocably change the electric power system, and because of this, today’s energy providers are in a position to fundamentally remake the nation’s electric system into a smarter, cleaner, more advanced grid.

In the last decade alone, the installed costs for new solar and wind have fallen dramatically—by 81 and 58 percent, respectively. In addition to this economic incentive, renewable energy offers a number of other benefits. Renewables hedge against variable fuel supply costs, enjoy strong customer support, and boast environmental benefits, such as reduced water use, lower air pollution, and fewer greenhouse gas emissions. Together, these factors have helped new renewable energy developments grow substantially. For example, in 2017, solar energy projects represented 30 percent of all new generating capacity brought online, second only to natural gas. And since 2010, wind and solar combined have added more than 120 gigawatts (GW) of new generating capacity.

Buoyed by lower prices and other favorable trends, this growth in renewable energy generation is also the result of various federal and state policies that have supported the industry over the years. In particular, four policies have primarily been used to encourage renewable energy development—federal funding, renewable portfolio standards (RPSs), net metering, and the Public Utility Regulatory Policies Act (PURPA):

• Much of the early research, development, and testing for renewable energy was supported by the federal government in the form of tax credits, investment subsidies, and other direct aid. These investments helped technologies mature to the point where they can, in many cases, compete with more conventional generating resources like nuclear and fossil fuels.

• State RPSs establish a required minimum level of renewable energy. More than half of states now have an RPS, and since 2000, these policies have accounted for roughly half of all new renewable energy expansion in the country.

• More recently, renewable energy growth has been driven by states’ adoption of net metering polices, which allow customers to supply their household electricity (usually through rooftop solar) and sell excess generation back to their energy provider at the retail rate. Net metering has fostered a growing market for renewable energy and has been responsible for nearly 20 GW of newly installed customer-owned distributed generation throughout the nation.

• PURPA has also played a role in increasing renewable energy development. Although it is not explicitly a renewable energy policy, PURPA has been responsible for 13 percent of renewable energy capacity created within the last decade.


The convergence of favorable economics for renewable energy and other trends in the electric power sector have highlighted the need to reexamine these policies that have, to date, promoted the development of renewable energy. While the changes underway undoubtedly offer benefits for consumers, policymakers, regulators, and energy systems planners, there is also risk. Future planning must carefully balance these changes with Michigan’s core principles for its electric grid—affordability, reliability, adaptability, and environmental protection.

These principles were central to the formation of Michigan’s newest energy policy—Public Acts 341 and 342 of 2016. After nearly four years of stakeholder workgroups, protracted legislative debate, and a final middle-of-the-night compromise, this legislation was supported by a bipartisan group of lawmakers and passed by wide margins.

Central to this new energy law was the establishment of the state’s first integrated resource planning (IRP) process. The IRP process creates a holistic planning construct that requires utilities to evaluate all resource options in a contested case proceeding. This allows various parties, including state regulators, to review plans and ensure that companies will provide energy to customers in the most valuable and cost-effective manner.

For the IRP process to successfully help Michigan achieve its broader energy goals, we must realign the current patchwork of renewable energy policies, mandates, and subsidies. The current system has done the opposite of integrating Michigan’s energy planning decisions; it has created a system that forces utility planners to make decisions piecemeal, without long-term planning or consideration for where investment is most needed. PURPA, RPS, and customer-owned distributed generation are and will continue to be a part of Michigan’s energy landscape, but allowing these policies to each independently drive Michigan’s renewable energy future leaves the state unable to design its energy system in a way that best suits Michigan residents and businesses.

If the state does not take a holistic view of how renewable energy policy is established and implemented, then customers could miss out on the full potential offered by renewable energy technologies, and the state will be set back in attaining a more sustainable, advanced energy grid. However, if Michigan can embrace the potential of renewable energy through policies like the IRP process, we have a greater opportunity to create an energy future that serves customers reliably and affordably, adapts to the latest technology, and protects our environment for generations to come.


“The renewable energy industry is in the midst of an historic

growth period. Advances in technology are driving prices down

and enabling new ways to incorporate renewables into the

electric grid.”


HISTORY OF RENEWABLE ENERGYIt is easy to forget that renewable energy is the oldest form of energy harnessed by civilization, and, for most of human history, was the only source available. Eventually, technological discoveries led to the wide use of fossil fuels to meet our energy needs. Now, just as technological advances moved away from renewable energy during the early 20th century, new innovations are reintroducing it into the mainstream (Sorenson 1991).

Renewable energy generation has been around since the earliest days of the electric power industry. The same year that Thomas Edison opened the nation’s first commercial power plant in 1882, the first commercial hydroelectric power plant began operation in Wisconsin (Schmalensee 2009). Hydroelectric power became a major source of electricity during the first half of the 20th century, as the federal government was investing heavily in new dams and hydroelectric facilities. By the 1940s, hydroelectric power comprised 40 percent the nation’s electric generation, according to the U.S. Department of Energy, or DOE (DOE n.d.). Hydroelectric power’s share of the nation’s generating output has declined steadily since the 1950s, as demand for electricity grew and power providers built new fossil fuel and nuclear generation to meet growing demand, shown in Exhibit 1.

For most of the 20th century, hydroelectric power was essentially the only commercially viable renewable energy technology.1 Through 1989, other nonhydroelectric renewable energy technologies, such as biomass, geothermal, wind, and solar, made up less than 1 percent of the U.S.’s electricity production combined, as shown in Exhibit 2.

Interest in developing other renewable energy technologies began in earnest during the 1970s, brought on by global oil prices and availability shocks, culminating in the 1973 oil embargo. In response to the energy security risk exposed by the oil crisis, policymakers began considering options to diversify the U.S.’s fuel mix.

President Nixon called for the creation of a cabinet-level agency to oversee national energy policy issues, including energy security and independence. In 1974, the Energy Research and Development Administration (ERDA) was created and, in 1975, released the first national energy plan, calling for a transition from oil and gas to new fuel sources.2 The plan outlined five objectives for diversifying the nation’s energy system, which included recommendations to promote the expansion of coal and nuclear power production and advance electricity generated by solar power, such as solar heating and cooling, as well as geothermal power. The ERDA was instrumental in promoting research into new energy sources, energy conservation, and commercialization of renewable energy technologies. It led to the founding of the Solar Energy Research Institute and advanced studies of geothermal technology, wind energy, and other technologies (Buck 1982).

1 Electricity production from biomass (e.g., wood and wood waste products) is another source of renewable energy that has been used since the early days of the electric power industry; however, it has historically accounted for less than 1 percent of all generation.

2 ERDA was the predecessor to the U.S. Department of Energy, which was established in 1977.

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

mill

ion

kwhs

Total Generation Hydroelectric Wood Waste Geothermal Solar Wind Fossil fuels Nuclear

EXHIBIT 1. Percentage of Electricity Generation from All Sources, 1949–2017

Source: U.S. EIA April 26, 2018a.

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63 65 67 69

mill

ion

kwhs

Hydroelectric Wind Wood Waste Geothermal Solar Percent of Renewables from Hydro

EXHIBIT 2. Renewable Energy Generation, 1949–2017


8

The upheaval over energy supplies during the 1970s also led to what was ostensibly the first federal energy policy that promoted renewable energy. Responding to the desire to diversify the electric sector, Congress enacted PURPA in 1978, creating a market for independent power production by requiring energy companies to purchase power from qualifying facilities. (More detail on PURPA is provided in Section III.)

Another factor that promoted renewable energy development during the 1970s was the push for environmental protection. During this time, three of the nation’s most sweeping environmental laws were passed, including the National Environmental Policy Act, the Clean Water Act, and the Clean Air Act. While it would be several years before these policies were used to advance renewable energy in the electric power sector, at the time, they represented a growing shift in America’s consciousness to promote environmental protection.

The success of new policy initiatives during the 1970s and 1980s is evidenced by the increase in new, nonhydroelectric renewable energy projects built in subsequent years. As shown in Exhibit 3 below, a limited amount of new nonhydroelectric renewable energy capacity was brought online during the 1970s, but development took off in subsequent decades. Energy providers added 3.7 GW of new capacity during the 1980s. Development slowed during the 1990s; however, with the onset of new policies promoting renewable energy at the start of the 21st century, the sector grew again. Of all new renewable energy capacity additions, 82 percent have been from wind energy projects, as shown in Exhibit 3.

The trend for renewable energy in Michigan has been similar to what has played out on the national level. Historically, hydroelectric power was the primary renewable energy resource in the state—only in the last two decades have wind and solar begun to play a more sizeable role in the state’s resource mix. (See Exhibit 4.)

10

EXHIBIT 3. U.S. Nonhydroelectric Renewable Energy Capacity Additions, Summer Capacity (Megawatts)

Year Geothermal Solar Wind WoodNonhydroelectric Renewables

1970–1979 349 0 17 174 540

1980–1989 1,255 268 544 1,636 3,702

1990–1999 273 88 1,088 897 2,346

2000–2009 361 242 32,389 287 33,278

2010–2018 841 21,726 97,799 1,325 121,691

Total 3,079 22,324 131,837 4,319 161,557

Total Percentage 2% 14% 82% 3%

Source: U.S. EIA March 23, 2018.

0

500

1000

1500

2000

2500

3000

3500

4000

Pre–1900 1900–1919 1920–1939 1940–1959 1950–1969 1970–1979 1980–1989 1990–1999 2000–2009 2010–2018

Net

Sum

mer

Cap

acity

(M

Ws)

Year

HydroelectricHydroelectric pumped storageWind

Wind - offshoreGeothermalBatteries

Municipal solid wasteWoodSolar thermal with energy storage

SolarSolar thermalOther

EXHIBIT 4. Renewable Energy Capacity by Operating Decade, Michigan



TRANSFORMATIONAL TRENDS IN THE ELECTRIC POWER SECTORThe energy sector is at an inflection point. New technologies are playing a role in changing customer preferences and behaviors, and energy companies are facing a seismic shift in the way they operate as older technologies become obsolete and new ones have the potential to fundamentally reform the way companies plan for and build infrastructure. In this paper, five transformational trends are identified that are setting the stage for the electric power sector’s evolution: aging generation infrastructure, a flat demand for energy, changing generation economics, advancing energy storage technology, and reinvestment in the electric grid.

AGING GENERATION INFRASTRUCTURE

The average power plant in the U.S. is more than 30 years old and in Michigan the average power plant is even older, having been in operation for over 44 years, as shown in Exhibit 5 (U.S. EIA June 2018). Due in large part to their age, many of these plants are coming to the end of their useful lives.

Nationwide, between 2010 and 2016, 97 GW of electric generating capacity were retired. The majority of these retirements were coal-fired power plants that had reached the end of their useful lives or faced high environmental compliance costs to continue operating. These plants had been in operation, on average, for 50–60 years. Despite the number of retirements already made, based on the average age of the nation’s power plants, they are likely just the beginning of many retirements soon to occur (Mills, Wiser, and Seel 2017).

Through the 1960s and 1970s, the electric industry showed a strong preference for large coal and nuclear power plants with long lifespans (in some cases, 60 years or more). However, preferences changed during the 1990s and 2000s. As technology and markets evolved, the industry began building somewhat smaller natural gas plants with projected 30-year lifespans. By some analysts’ measures, these factors are creating a looming retirement cliff in 2030 that will require new capacity construction and, potentially, significant new spending from energy companies—in excess of five times their historic average capital expenditures—to address construction costs (Rode, Fischbeck, and Páez 2017).

Beyond the age of plants currently in operation, there are several other factors driving dramatic change in plant retirement and thus the composition of the nation’s electric supplies. These factors include:

• Declining wholesale power prices driven by reductions in natural gas prices

• Low growth in electric demand

• High reserve margins in many regions of the country

• Newer plants that offer better efficiency, improved flexibility, and lower operating costs and emissions

• Rising costs for existing plants driven by increasing maintenance costs or environmental controls (Mills, Wiser, and Seel 2017)

12

EXHIBIT 5. Average Age of Power Plants in Operation

Note: NG—Natural Gas, MSW—Municipal Solid Waste

Source: U.S. EIA June 2018.

Hyd

roel

ectr

ic

Coa

l

Hyd

ro P

umpe

d S

tora

ge

Land

fill G

as

MS

W

NG

Com

bine

d C

ycle

NG

Com

bust

ion

Turb

ine

NG

Inte

rnal

Com

bust

ion

Eng

ine

NG

Ste

am T

urbi

ne

Nuc

lear

Ons

hore

Win

d

Pet

role

um C

oke

Pet

role

um L

iqui

ds

Sol

ar

Woo

d/W

ood

Was

te B

iom

ass

Ave

rage

Michigan 75 49 45 17 30 22 26 36 45 40 6 40 43 2 33 44

U.S. Average 65 44 43 12 30 19 23 27 51 37 9 33 31 4 36 31

EXHIBIT 6. Percentage Change in U.S. Annual Electric Generation, 1949–2017


-10%

-5%

0%

5%

10%

15%

20%

1949

1951

1953

1955

1957

1959

1961

1963

1965

1967

1969

1971

1973

1975

1977

1979

1981

1983

1985

1987

1989

1991

1993

1995

1997

1999

2001

2003

2005

2007

2009

2011

2013

2015

2017

Percent change Linear (Percent change)

FLAT DEMAND FOR ENERGY

Throughout the 20th century, demand for electricity grew consistently. Despite this growth, the rate of increase began to slow during the latter half of the century to 9 percent per year in the 1950s; an average of 6 percent in the 1960s and 1970s; 2–3 percent in the 1980s and 1990s; and, finally, by the year 2000, less than 1 percent growth annually. Since 2000, the average growth rate has, essentially, been flat. These changes in demand are displayed below in Exhibit 6.

The trend for electricity demand in Michigan over recent years has been in line with the national trend. During the 1990s, electricity consumption grew 2.6 percent per year. From 2000 to 2010, the state’s year-over-year growth in electricity consumption was actually negative, averaging -0.5 percent. This decline was largely driven by a sharp drop in industrial electricity consumption in 2002 and 2009. The state’s overall electricity

consumption fell by 7.2 percent from 2008 to 2009 in response to the Great Recession.1 Since 2010, demand has been essentially flat, averaging 0.1 percent growth in the last eight years, but despite this returned growth, the state’s annual electric consumption is still below prerecession levels (U.S. EIA November 6, 2017).

Other than a lack of demand, a variety of factors have contributed to declining electric load growth in the U.S., the most influential of which have been greater investment in energy-efficiency measures, changing weather patterns, and slowed gross domestic product growth (Nadel and Young 2014).

Current projections from the U.S. Energy Information Administration (U.S. EIA) show that recent trends are expected to continue. In its Annual Energy Outlook 2018 report, the U.S. EIA

1 The Great Recession officially lasted from December 2007 to June 2009 and was the longest period of economic downturn since the Great Depression (Isidore 2010).


predicts that demand for electricity will continue to grow at less than 1 percent per year through 2050 despite expectations for continued economic growth. This small growth in electricity demand is the result of improved technology efficiency, which effectively erodes any new growth in demand as technology can now do more with less.

Though experts expect stagnant electricity demand, there is still an expected need for new generation resources in the coming years due to “retirements of older, less-efficient fossil fuel units, the near-term availability of renewable energy tax credits, and the continued decline in the capital cost of renewables, especially solar photovoltaic” (U.S. EIA February 6, 2018).

CHANGING GENERATION ECONOMICS

Another major trend leading to transformation in the energy industry is changing economics for renewable generation sources. Historically, electric generation has come from four primary sources: hydroelectric, coal, nuclear, and petroleum products like oil and natural gas. It was not until the 1970s that other forms were considered, and, even then, their application was limited to predominately small, site-specific installations. Only in the last two decades have resources like renewable energy increasingly gained shares of new generation. This is due to substantial price drops resulting from technological innovations, improved manufacturing, and policy support. The two renewable energy technologies gaining the largest share of new generation in the U.S. have been wind and solar, largely because they have the most favorable economics out of current technologies, as indicated by recent price trends.

One way to compare different generating technologies is to use levelized cost of energy (LCOE) studies. LCOE is a convenient measurement of the economic characteristics

of different generation technologies because it presents the average cost in terms of the full life-cycle per megawatt hour (MWh), which includes construction, operations, and financing expenses.

In 2017, the weighted average LCOE for utility-scale solar was 73 percent less than 2010 prices. This was mainly due to an 81 percent decline in the cost of solar modules as the technology has advanced (IRENA 2018). Wind energy has undergone similar advances during the same period. Improved turbine technologies, coupled with taller towers and longer blades, have increased capacity factors for new wind installations from 27 to 30 percent. Costs for new wind turbines have also declined: the total installed cost for new wind generation was up to 58 percent lower than just a decade ago (IRENA 2018).

Improvements in the economics of other renewable energy sources, such as hydroelectricity, biomass, and geothermal, have been more limited in recent years. In many cases, these resources are already able to compete with conventional resources, but they require specific sets of conditions and readied access to resources for construction, making them less desirable, especially as costs for wind and solar have declined.

The latest national LCOE estimates show that many renewable energy technologies, including wind and solar, are becoming cost competitive with conventional resources, such as natural gas combined-cycle power plants. In some cases where investment or production tax credits are available, renewables exhibit lower LCOE than conventional technologies. A summary of the unsubsidized, levelized costs for new generation is shown in Exhibit 7 (Lazard 2017).

15

EXHIBIT 7. Unsubsidized National Levelized Cost of Electricity for New Generation Resources

Note: C—Commercial, I—Industrial, PV—Photovoltaic

Source: Lazard 2018.

Leve

lized

Cos

t ($/

MW

h)

Midpoint Operating Cost for Fully Depreciated Plant


While LCOE is useful for comparing different generating sources based on price, relying solely on LCOE to draw conclusions could result in incomplete or misleading findings (Wiser et al. 2017). Consideration must be given to the right mix of resources based on their dispatchability and capacity they provide, among other factors.

Dispatchable and Nondispatchable Resources

There are several key differences between generating sources that must be accounted for when deciding which resources to invest in. The primary difference between conventional, baseload generating resources, such as coal, nuclear, or natural gas facilities, is that they are dispatchable, meaning they can respond to changes in energy demand by reducing or increasing their production as soon as necessary.2 Renewable energy technologies, such as wind and solar are nondispatchable, meaning they cannot increase or decrease production enough to respond to shifting demand because they depend on the variability of wind speeds or sunlight. It is possible, to some extent, to reduce output from nondispatchable resources, but increasing output when demanded is limited to the extent to which wind and solar radiance are occurring.

Beyond whether a resource is dispatchable or not, all generating resources have advantages and limitations. While certain baseload generation may have higher capacity ratings, it may not respond quickly to sudden changes in demand. On the other hand, many renewable energy resources have variable output respective to their power

2 Not all conventional dispatchable resources have the same characteristics. Technologies have different ramp rates that indicate the rate at which they can increase or decrease output. The ramping characteristics of power plants also have different economic implications. For example, nuclear power plants take much longer to ramp up and down than other conventional resources; as such, nuclear power plants provide baseload power as they run continually. Other fossil fuel-fired generators have greater ability to ramp up quickly in response to changing energy demands.

source, time of day, and season. Solar output in a state like Michigan varies from season to season as the number of sunlight hours change, peaking during summer months when demand for energy is highest. While solar energy peaks during summer months, wind energy production is at its peak during the winter, when wind speeds are highest, which does not align with summer peak load (U.S. EIA February 2015).

Capacity Factor

The ratio of a resource’s variable output and its maximum capable output is commonly expressed as a resource’s capacity factor, which is articulated as a percentage of the maximum generating capability. This factor can be influenced by the variability of the resource’s fuel source, as is the case with many renewable energy technologies, and by the economics of a given generator, such as fuel costs, age of a resource, location, and local energy demand. Historically, nuclear power plants have high capacity factors because they have relatively low fuel costs. However, other generating resources are designed to only operate for short periods when demand peaks—they can respond quickly, but may have an added caveat of higher variable costs. Capacity factors for utility-scale generating resources are shown in Exhibit 8.

Capacity factors will also vary by the location of the resource. For example, areas of the country with a strong wind energy resource will have wind energy developments with higher capacity factors than areas where the resource is not as favorable. The average output from Michigan’s wind facilities in 2016 was 33 percent of the maximum capable

17

EXHIBIT 8. Utility-scale Capacity Factor, Nationwide

Source: National Renewable Energy Laboratory n.d.b.

Cap

acity

Fac

tor

Technology (number of values)

Win

d, O

nsho

re (3

5)

Win

d, O

ffsho

re (2

4)

Sol

ar, P

hoto

volta

ic (5

3)

Con

cent

ratin

gS

olar

Pow

er (3

7)

Geo

ther

mal

,H

ydro

ther

mal

(24)

Blin

d G

eoth

erm

alS

yste

m (2

)

Enh

ance

d G

eoth

erm

alS

yste

m (E

GS

) (12

)

Sm

all H

ydro

pow

er (4

)

Hyd

ropo

wer

(11)

Oce

an (3

)

Bio

pow

er (5

3)

Dis

tribu

ted

Gen

erat

ion

(13)

Fuel

Cel

l (7)

Nat

ural

Gas

Com

bine

d C

ycle

(20)

Nat

ural

Gas

Com

bust

ion

Turb

ine

(17)

Coa

l, P

ulve

rized

Coa

l,S

crub

bed

(5)

Coa

l, P

ulve

rized

Coa

l,U

nscr

ubbe

d (0

)

Coa

l, In

tegr

ated

Gas

ifica

tion

Com

bine

d C

ycle

(5)

Nuc

lear

(6)

100%

80%

60%

40%

20%

0%

DOE Program Estimate NREL ATB(Annual Technology Baseline)

Other Estimate(insufficient data to show box and whisker)

“Only in the last two decades have resources like renewable

energy increasingly gained shares of new generation. This is

due to substantial price drops resulting from technological

innovations, improved manufacturing, and policy support.”


output.3 The capacity factor nationwide was 34.5 percent. Capacity factors for solar resources exhibit similar locational variations to wind resources. The average capacity factor for solar nationally in 2016 was 25.1 percent; however, the actual capacity factor of Michigan’s utility-scale solar facilities was only 13.3 percent (U.S. EIA May 24, 2018).4

In addition to variances in capacity factors, resource types also vary in the capacity credit they receive when planning for reliability. The Midcontinent Independent System Operator, the regional body that governs electric power supplies for most of Michigan and all or parts of 14 other states across the Midwest, sets reliability rules to ensure that load-serving entities have sufficient resources to meet anticipated peak demand plus an appropriate reserve margin. These rules determine the capacity credit granted for each type of resource. Nonintermittent, often baseload, resources are credited based on average historic performance over all hours in a calendar year while intermittent resources (such as wind and solar) are credited based on historic performance over specific peak summer hours. The capacity credit applied to intermittent resources is referred to as the effective load carrying capability (ELCC), which is an estimate of how much wind and solar output that resources can be expected to produce.

3 Michigan’s average wind capacity was calculated using EIA Form 923 and Form 860 data for the 21 utility-scale wind facilities in operation for all of 2016. These facilities include Bay Windpower I, Big Turtle Wind Farm LLC, Harvest, Stoney Corners Wind Farm, Michigan Wind 1, Echo Wind Park, Gratiot Wind Park, Lake Winds Energy Park, Gratiot County Wind LLC, Heritage Garden Wind Farm LLC, Beebe 1B Wind Farm, Tuscola Bay Wind Farm, Tuscola Wind II LLC, Cross Winds Energy Park, Brookfield Renewable, Minden Wind Park, Harvest II Wind Farm, Pheasant Run Wind LLC, McKinley Wind Park, Sigel Wind Park, and Michigan Wind 2.

4 Michigan’s average solar capacity was calculated using EIA Form 923 and Form 860 data for the three utility-scale solar facilities in operation for all of 2016—Ford World Headquarters, Domino’s Farms Solar, and Greenwood Solar Farm.

Wind resources from the Dakotas and Minnesota have the highest ELCCs of 18.3 percent, while ELCCs across Indiana are only at 7.4 percent. Michigan’s Lower Peninsula has an expected capacity credit of 11.2 percent (MISO December 2017). Actual output from Michigan’s wind resources tends to be higher than the capacity credit these facilities are given.

Trends in New Generating Capacity

Downward price trends for wind and solar have spurred new investment across the globe and in the U.S. The U.S. added 10.6 GW of new solar generation in 2017, representing 30 percent of all capacity additions in 2017, trailing only natural gas (Wood Mackenzie n.d.). Wind continues to be a major source of new generation in the U.S., adding seven GW of new wind capacity in 2017, taking the nation’s total installed capacity to just under 90 GW (AWEA n.d.). Exhibit 9 shows the cumulative utility-scale capacity additions for solar, wind, geothermal, and woody biomass since 1980.5

Industry experts anticipate that renewable energy deployment will continue as long as resources offer competitive economics, help companies hedge against variable fuel supply costs, maintain strong customer support, and provide environmental benefits, including reduced water use, local air pollution, and greenhouse gas emissions (Stark et al. 2015). Wind and solar are expected to remain leaders in renewable energy deployment, according to U.S. EIA projections, representing 64 percent of all new electric generation added through 2050. Utility-scale wind capacity is expected to add 20 GW from 2020 to 2050. During the same period, the U.S. EIA projects utility-scale solar capacity will increase by 127 GW. Storage capacity is also expected to grow in order to respond to the increase in variable resources

5 Electric power plants with nameplate capacity of one megawatt or greater.

20

EXHIBIT 9. Nonhydroelectric Renewable Energy Capacity by Operating Year, Pre-1980–2016


0

20,000

40,000

60,000

80,000

100,000

120,000

MW

s

Wind Solar Geothermal Municipal solid waste Wood


from nondispatchable renewable sources. As technology becomes cost effective, utility-scale storage will grow by 34 GW (U.S. EIA February 6, 2018).

ADVANCING ENERGY STORAGE TECHNOLOGY

The ability to store energy has long been a limiting factor in the electric power industry. As such, electricity production and consumption must be kept in balance at all times. Engineers have developed several ways to effectively store electricity, such as hydroelectric pumped storage, where water is pumped uphill, stored in a reservoir, and then subsequently released downhill through a turbine to generate electricity when needed. The U.S. has nearly 23 GW of hydroelectric pumped storage capacity. The earliest pumped storage facility still in operation came online during the 1920s (U.S. EIA June 2018). While it is a well-developed technology, other forms of storage have only been brought online in recent years.

The other types of energy storage deployed at utility scale in the U.S. are compressed air, flywheels, and battery storage. Compressed air energy storage systems operate by pumping air into storage tanks or underground geologic formations when electricity is plentiful; the air is stored under high pressure until generation is needed and then released to drive a turbine generator. Flywheels have the same essential function as a traditional battery, except that they store kinetic energy mechanically instead of through chemical reactions. To charge the flywheel, energy is used to wind up a rotor that stores energy, which is released when needed. Flywheels have the lowest installed capacity of utility-scale storage technologies (U.S. EIA May 25, 2017).

The storage technology anticipated to provide the greatest transformative opportunity for the electric power sector is battery storage. Battery storage can provide a variety of benefits to the grid and to customers, including:

• Balancing supply and demand through frequency regulation and voltage control

• Shifting peak consumption by charging during times of low demand and discharging during high consumption periods

• Storing excess generation from renewable energy to reduce the need to curtail production or mitigate overproduction during periods of low demand

• Alleviating the need for large infrastructure investments, such as upgraded substations or distribution capacity

• Providing backup power to customers during outages

• Enabling customers to reduce demand charges by supplying a portion of their energy needs (U.S. EIA January 2018)

Battery storage has historically been cost prohibitive for utility-scale installations. With the general advancement of technology, costs have started declining in recent years, and starting in 2003, prices reached a point where energy providers in the U.S. began investing in utility-scale battery storage projects. Since then, energy companies have added nearly 700 megawatts (MW) of battery storage capacity to the electric grid, with over 70 percent of this capacity coming online from 2015 to 2018 (U.S. EIA January 8, 2018).

These investments have been spurred by price trends similar to those witnessed with renewable energy capacity. New advances in battery storage technology are driving costs down. The price per kilowatt hour (kWh) of battery storage was more than $1,000 per kWh before 2010, but in just the


last seven years, prices have dropped 77 percent to around $230 per kWh. Analysts predict that battery storage costs will continue to decline in coming years, promoting greater deployment (Frankel and Wagner 2017).

Despite favorable price trends over recent years, there are still economic and technical characteristics of battery energy storage systems that limit system application at the utility scale. One of those limitations is the length of time energy can be stored. The suitable storage duration for different battery technologies varies by the technology type. The second factor that must be considered when evaluating battery energy storage is how long the technology can provide energy output on a single charge. As with storage duration, the amount of time a battery can produce energy varies by technology, but, to date, most commercial battery energy storage applications can provide energy output at their power rating for up to ten hours on a single charge

(Luo et al. 2015). Another challenge facing grid-scale storage is how long batteries will last without significant efficiency loss, as batteries degrade with each charging cycle. While some emerging battery storage technologies show potential for longer life and degradation can be managed by the way a battery is used, current technologies have a useful life of approximately ten years (Luo et al. 2015).

Until some of these limitations are overcome, large-scale battery storage applications will be limited in both their installed capacity and the functions they provide to the grid. New investments in battery storage technology, in places like California and Australia, are on the leading edge of this technology, but to date, large-scale adoption has been highly site specific as high costs restrain battery use to areas that present unique challenges to which batteries are well suited e.g, frequency regulation and renewables integration. In the Annual Energy Outlook 2018, the U.S. EIA projects utility-scale battery storage


will grow to 34 GWs by 2050; however, the storage industry seeks to outpace these projections and has the goal of adding 35 GWs of new battery storage by as early as 2025 (U.S. EIA February 6, 2018; Silverstein 2018).

REINVESTMENT IN THE ELECTRIC GRID

The changes occurring in the electric power sector have not been limited to generation. Investment in the transmission and distribution side of energy companies’ systems has risen over the past two decades as energy companies enter a period of reinvestment and system modernization. Historical spending on the transmission and distribution system peaked between the 1960s and 1980s, when energy companies were adding new generation to accommodate increasing demand and expanding their systems to serve growing communities (U.S. EIA October 24, 2014).

A number of factors is driving reinvestment in the distribution system—among them is the fact that much of the existing utility infrastructure was deployed during the 20th century and is now reaching the end of its expected life. However, it is more than just the age of these assets driving accelerated replacement. The infrastructure deployed in the 20th century is not equipped to handle the demands of a 21st century electric grid, illustrated by energy company investment in smart grid technologies, such as advanced metering infrastructure, which allows more granular energy-use data, time-based pricing, and enhanced user experience opportunities (U.S. EIA October 2014). Energy companies expect to continue investing in their distribution systems over the coming years to integrate new technology, accommodate more distributed generation resources, and increase reliability of their systems.

Similar trends are occurring with investment

in transmission infrastructure. In 2016, energy companies spent more than $35 billion on the transmission system alone to make necessary system upgrades and replacements, integrate new renewable energy, and integrate system hardening and resiliency (U.S. EIA February 2018). A survey of investor-owned electric energy companies suggests that the rate of investment will continue to be high over the coming years, with $91 billion expected to be spent on transmission construction between 2017 and 2020 (EEI 2016).

Even with the recent rise of investment in the transmission and distribution systems, current estimates indicate that a full upgrade of the nation’s transmission and distribution system could require $2.3 trillion in new investment (Rhodes 2017).


RENEWABLE ENERGY POLICIES While the trends discussed in the previous section have done a great deal to spur investment in renewable energy, the primary driver of market development for renewable energy in the U.S. has been state and federal policy. Dating back to the 1970s, U.S. energy policy has promoted renewable energy as a way to diversify the nation’s electricity supply and, in recent years, to promote environmental benefits.

Renewable energy policies have come in many different forms. This section provides an overview of key policies used to promote renewable energy, with specific attention paid to how these policies have been implemented in Michigan, including:

• Tax credits, direct support, and investment subsidies

• Renewable energy portfolio standards

• Net energy metering

• PURPA

TAX CREDITS, DIRECT SUPPORT, AND INVESTMENT SUBSIDIES

Throughout the years, policymakers have sought to achieve different energy goals through federal funding for energy resources. Early federal support was targeted at national security and energy independence through support for domestic energy resources (i.e., the oil and gas industry). Later, policy goals shifted to diversifying the country’s energy system and responding to environmental concerns by supporting conservation and renewable energy (Sherlock May 2011). Support has taken different forms over time but has broadly fallen into the following four categories: federal tax expenditures through tax credits, direct expenditures paid to producers and consumers, research and development funding, and loan guarantees (U.S. EIA April 26, 2018b).

History of Federal Funding for Renewable Energy

Prior to 1978, federal government spending that supported energy technologies focused predominately on nuclear and fossil fuels—with nearly $63 billion spent on research and development between fiscal years 1948 and 1978. During that time frame, less than $1 billion was spent on renewable energy research. Spurred by the energy crisis of the 1970s, the federal government and the newly established DOE made new investments in renewable energy technologies, like solar, wind, biomass, and geothermal, totaling in $14.2 billion in research and development from 1978 to 2005 (Clark 2018).

Like the experience during the 1970s, rising oil prices during the 2000s led to renewed efforts by the federal government to promote energy independence through domestic energy production, alternative fuels, conservation, and renewable energy technologies. The Energy Policy Act of 2005 greatly expanded federal tax subsidies for renewable resources. Federal support for renewable energy, energy efficiency, and clean fuels was later expanded through stimulus programs—the Emergency Economic Stabilization Act of 2008 and The American Recovery and Reinvestment Act (ARRA) of 2009—in response to the nation’s economic recession (Sherlock May 2011).

25

EXHIBIT 10. Electric Renewable Energy-related Subsidies and Support by Type (Millions of 2016 Dollars)

EXHIBIT 11. Business Energy Investment Tax Credit Phase-out Timeline

Source: U.S. EIA April 26, 2018b.

Source: NC Clean Energy March 1, 2018.

Technology 2016 2017 2018 2019 2020 2021 2022 Future Years

PV, Solar Water Heating, Solar Space Heating/Cooling, Solar Process Heat

30% 30% 30% 30% 26% 22% 10% 10%

Hybrid Solar Lighting, Fuel Cells, Small Wind

30% 30% 30% 30% 26% 22% 22% N/A

Geothermal Heat Pumps, Microturbines, Combined Heat and Power Systems

10% 10% 10% 10% 10% 10% N/A N/A

Geothermal Electric

10% 10% 10% 10% 10% 10% 10% 10%

Large Wind 30% 24% 18% 12% N/A N/A N/A N/A

Federal support for energy resources overall has declined since fiscal year 2010, as temporary ARRA-authorized measures have expired. From fiscal year 2013 to fiscal year 2016, federal energy subsidies for renewable electric energy declined by more than 70 percent, dropping from $13.3 billion to just $3.8 billion. While total spending declined, the share of federal funding for renewable energy accounted for 45 percent of all federal energy subsidies in fiscal year 2016 (U.S. EIA April 26, 2018b). A breakdown of federal subsidies for electric renewable energy is available in Exhibit 10.

Support for most forms of renewable energy development through federal tax expenditures will continue through 2022. In 2015, Congress extended the Business Energy Investment Tax Credit (ITC) to support the development of renewable energy, and amendments added in 2018 expanded the list of technologies eligible for this support. The current iteration of the ITC will decrease until 2022 and phase out all together for certain technologies in that year, see Exhibit 11.

While there is evidence to show that federal support for renewable energy has led to greater deployment of renewable energy technologies, these policies are not the only driver responsible for this increase. Other drivers include fluctuating natural gas prices, declining cost of renewable energy equipment, and other renewable energy policies mostly at the state and local level (Mai February 2016).

RENEWABLE PORTFOLIO STANDARDS

RPSs have been the preferred tool for policymakers to promote deployment of renewables and address environmental externalities from energy production such as air emissions production and their associated environmental and societal costs. These standards were intended to address cost barriers and market failures that limited deployment of renewable energy generation. The policies were not meant to


provide the ongoing solution for renewable energy development, instead they were meant to spur technological investment by creating a market for products, despite initial cost barriers. The absence of comprehensive federal energy policy that supports renewable energy development has transferred responsibility to states to drive renewable energy production and local economic development (Rabe 2007).

History of RPSs

Iowa established the first state RPS in 1983. From 1983 to 2003, 12 more states enacted their own and by 2017, 29 states and the District of Columbia had an RPS in place. While individual designs varied from state to state, all policies shared the same essential feature—an established minimum level of generation or capacity that electric providers must get from renewable sources by a target date. States’ targets range from the relatively conservative, like the state of Washington’s 15 percent by 2020, Pennsylvania’s 8.5 percent by 2020, and Wisconsin’s 10 percent by 2015, to aggressive, like California’s 50 percent by 2030, Minnesota’s 26.5 percent by 2025, or Maine’s 40 percent by 2017. Through 2017, 29 states and Washington, D.C. have enacted an RPS (Barbose 2017).

States’ experiences with RPSs have largely been successful in advancing the deployment of renewable energy resources. Approximately half have already met their RPS requirements, and more than half of those with an RPS have moved to expand their initial targets in recent years. From 2000 to 2016, the electric power sector added 120 GW of renewable capacity, with more than half driven, at least in part, by the need to meet RPS requirements. As technologies have matured and costs have come down in recent years, more and more renewable energy capacity is being added outside of RPS requirements. However, there is still a significant amount of new capacity that will

need to be built to meet upcoming compliance timelines. Projections estimate that, by 2030, states will have to add 55 GW of total new capacity nationwide to meet RPS requirements (Barbose 2017).

RPSs in Michigan

Michigan introduced its first RPS in 2008 with Public Act 295 of 2008 (PA 295). This standard required the state’s electric providers to get 10 percent of their electricity from renewable sources by 2015. Electric providers exceeded the state’s RPS target, generating renewable energy credits equal to 10.8 percent of Michigan’s electric load (MPSC February 15, 2018). The success of Michigan’s RPS led policymakers to increase the goal when they enacted new energy policies in 2016. Public Act 342 of 2016 (PA 342) established the new 15 percent RPS by 2021. The legislation also included interim targets of 12.5 percent in both 2019 and 2020. Michigan’s RPS supports the legislation’s broader objective of ensuring not less than 35 percent of the state’s electric needs are met through a combination of energy waste reduction and renewable energy by 2025 (MCL December 2016).

Michigan’s RPS has resulted in significant development of new renewable energy resources. Through 2016, Michigan added 1,670 MW of new renewable energy capacity in response to the RPS. The average price for this new capacity was $72.60 per MWh, which is lower than original estimates and 45 percent less than the guidepost cost of generation used by the MPSC to determine cost effectiveness. The most recent contracts for wind energy approved under PA 295 have come in much lower than original contracts. They range from $45–$69 per MWh. Meanwhile, the levelized cost of the latest 48 MW solar array approved by the MPSC came in at $113.52 MWh. Though nearly twice the price of current wind projects, this solar project is still less than the MPSC benchmark for comparison (MPSC February 15, 2018).


CUSTOMER-OWNED DISTRIBUTED GENERATION

Net energy metering—more commonly referred to as net metering—policies were created to enable customers to install and own distributed electric generation (in particular, rooftop solar) that supplies their onsite energy needs and to govern the flow of energy between a customer and energy company by establishing a compensation mechanism for customers’ electricity production. Under the net metering policy framework, energy companies are required to purchase the excess energy from customers owning distributed generation, who then receive credits to offset the cost of the energy they consume. While net metering policies vary from state to state, allowing for different technologies, system sizes, and compensation mechanisms, in general they were designed to promote customer-owned distributed generation as an alternative to the energy provided through the bulk power grid.

History of Net Metering

The aim of net metering policies—to allow customers to generate the electricity they need and sell only excess power back to the utility—is reflected in the fact that distributed generation systems are generally designed to match customers’ household energy consumption. When a customer consumes more than the output of their system, however, the grid supplies them with power. Any excess energy put out onto the grid is a result of the inability of customers’ self-generation to consistently match their consumption needs throughout the day. While these system inefficiencies can be better managed through technology such as battery storage, most customers depend on the grid to take excess generation when their system produces more than they can consume and to supply generation when they consume more than they produce.

Net metering policies were established to address the fundamental issue that the actual electricity generated by a customer-owned system rarely matches customer energy demand and the inevitability that they will have to rely on the electric grid. There are elements of household energy consumption that require support from the energy grid even if a household is producing its own energy. For example, when a refrigerator or air conditioning unit cycles on, there is an instantaneous burst of energy demand—called inrush current—that is required to support the momentary spike in demand and not diminish power quality to the rest of the system (Basso 2009).

When net metering programs were first introduced, the available technology was limited to analog meters designed to measure one-way flow of electricity and record consumption. While these meters were intended to only measure energy consumption, they were also capable of measuring electricity that flowed in the opposite direction—from the customer to the grid—essentially erasing prior consumption. This reality formed the fundamental structure for net metering. Customers pay for the electricity they consume at the same rate as any other customer and receive credit for the energy they produced at that rate because it effectively reduced their monthly consumption by rewinding the meter.

The inability of traditional analog meters to differentiate and separately track production and consumption left little choice for policymakers and regulators for how to govern customer-owned generation and led to the earliest versions of net metering policies. Minnesota became the first state to establish a net metering policy in 1983. Other early adopters during the 1980s included Idaho, Arizona, and Massachusetts (Wan 1996). Net metering was codified into federal law by the Energy Policy Act of 2005, which required all energy companies to offer net metering to


customers upon request, which had the effect of catalyzing state adoption of net metering programs. Currently, there are net metering policies of some form in 42 states; Washington, D.C.; and several American territories (NC Clean Energy n.d.).

Net Metering in Michigan

Michigan established its statewide net metering program in 2008 with the passage of PA 295, and the program was officially implemented by state regulators the following year (MPSC May 2009). The state created two different types of net metering programs: true net metering, for customers generating 20 kilowatts (kW) or less, and modified net metering, for customers generating 20–150kW. True net metering refers to when customers’ consumption and production are valued at the full retail rate, meaning that if a customer generates more power than they consume during a given month, then they would be credited for their net production at the standard retail rate. Customers enrolled in modified net metering pay the full retail rate for electricity they purchase from their energy company, but only receive credit equal to the generation portion of the retail rate or the wholesale rate for energy they supply back to the grid. Participation in energy companies’ net metering programs was capped at 1 percent of their in-state peak load from the previous year (MCL October 2008).

Through 2016, there were 2,582 customers participating in Michigan’s net metering program, representing a total capacity of 21,888 kW. While the program grew more than 28 percent from 2015 to 2016, the total capacity of net metering

installations is only 0.024 percent of Michigan’s total retail electricity market (MPSC December 2017).1

Evolution of Net Metering Policies

Net metering policies were designed to encourage the growth of customer-owned distributed generation, by providing attractive compensation to customers for their participation, and, on the whole, the policies have proven successful. Through 2017, energy companies reported 16 GW of solar capacity enrolled in net metering programs, representing 96 percent of all net metering capacity (U.S. EIA April 27, 2018).2 While net metering programs have been successful in promoting growth in customer-owned distributed renewable generation, the expansion of these programs has raised concerns regarding how the policy compensates customers and the potential unintended consequences for energy providers, the electric grid, and other customers.

As explained above, customers’ onsite generation does not always meet their energy demands, making them reliant on the grid (e.g., during times of day when the sun is not shining). Advances in battery technology offer the potential to mitigate this reliance, but, to date, installations of distributed generation systems, paired with battery storage, have been limited, though advances in battery storage will likely drive greater deployment. Because customers depend on the grid throughout the day to provide energy when their system does not meet their needs or to take the excess power they produce, there are costs associated with their use of the grid even when their solar installation is producing power.

1 As of 2016, only one utility, the Upper Peninsula Power Company, had reached the cap for enrollment in their net metering program (MPSC December 2017).

2 The U.S. EIA’s data related to net metering is not fully reported by all monthly respondents and are incomplete for some states.

“While net metering programs have been successful in promoting growth in customer-owned distributed renewable generation, the expansion of these programs has raised concerns regarding how the policy compensates customers and the potential unintended consequences for energy providers, the electric grid, and other customers.”


Traditionally, energy companies have recovered the majority of their costs through a single volumetric charge or rate based on the amount of electricity a customer consumes. These rates include the energy company’s bundled costs to serve customers, such as generation, transmission, and distribution services. By compensating net metering customers for the power produced using the retail rate, customers can potentially erase most monthly charges by producing more energy than they consume in a given month. This essentially allows customers to avoid paying their full share of the cost and transfers the cost to other customers.3

Recognizing that traditional net metering policies have resulted in cost shifting to other customers has prompted many states to update their policies. Policy activity related to customer-owned distributed generation has risen sharply in recent years—up 17 percent in 2017 compared to 2016 and 30 percent from 2015 (Trabish February 2018). There were nearly 250 actions taken on net metering policies in 45 states and in Washington, D.C. during 2017. Of these actions, 84 dealt with fixed charges for residential customers and minimum bill increases, 66 changed compensation structures for distributed generation, and 30 addressed community solar policies. To date, the most common reform approach taken by states has been to adopt net billing policies, which differ from net metering by crediting the energy exported to the grid at a rate other than retail. These rates have taken a variety of forms, including using an energy company’s avoided cost rate or other value-based

3 There is ongoing debate about whether net metering customers are subsidized by the rest of the electric system or if they provide net benefits to the system. The Michigan Public Service Commission has established that true net metering rates, set at the retail level, result in net metering customers avoiding paying their fair share of the grid costs. More discussion related to subsidies is available in Section IV.

credits (Proudlove et al. 2018).4

Net Metering Across the Country

During 2017, the majority of states undertook policy changes for distributed generation and/or renewable energy, and the actions taken varied widely from state to state. States pursued three primary policy options to update their net metering tariffs: upholding traditional net metering; instituting a net billing program; and using the buy-all, sell-all approach. The examples in the following section were selected to highlight states that recently made changes to their distributed generation policies and the variety of approaches available to implementing net metering successor tariffs.

Nevada

Nevada was one of the states with the most publicized net metering debates in the country over the past couple of years. Like many other state utility commissions, Nevada’s Public Utilities Commission chose to adopt a net billing approach where customers receive credit for excess generation at the wholesale rate (Shallenberger December 2015). After outcry from the solar industry and public backlash, the state assembly passed Assembly Bill 405 to restore net metering and establish new program rates. Under the revised rules, customers with rooftop solar receive 95 percent of the retail rate for their energy output. That credit declines as more solar is brought online, with a 75 percent floor of the retail rate (Walton June 2017).

4 Avoided costs means the incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from a qualifying facility, a utility would generate itself or purchase from another source (Code of Federal Regulations §292.101(6)).


North Carolina

North Carolina enacted sweeping energy policy changes in 2017. House Bill 589, signed into law in July 2017, made modifications to the state’s net metering program as well as PURPA, community solar programs, and solar leasing options. The new law requires energy companies in the state to investigate the costs and benefits provided by customer-owned distributed generation to ensure customers are paying their full, fixed cost of service and may include fixed monthly energy and demand charges. The state’s current net metering policies stay in effect until new rates can be established in response to the state’s findings on the costs and benefits (Shallenberger July 2017).

New York

Following a prolonged stakeholder engagement process, the New York Public Service Commission introduced the state’s new compensation policy as a successor to net metering. The new value of distributed energy resources (VDER) tariffs will be different for each energy company and be rolled out in two phases. The goal of the VDER tariff is to more accurately reflect the locational, environmental, and temporal values of distributed generation projects. The first phase will define the new compensation structure or value stack. The state’s current net metering policy will remain in place through 2020 as VDER tariffs are developed (NC Clean Energy April 2017).

Minnesota

The shift to net billing for distributed generation has generally resulted in lower compensation rates for consumers, but there have been examples of states adopting new definitions for the value generation from distributed solar that are higher than rates under net metering. In 2014, Minnesota became the first state to adopt a value of solar (VOS) approach to compensating customers with

solar generation. Like net billing arrangements, Minnesota’s VOS tariff was designed as a successor to net metering, but unlike net metering, the VOS tariff explicitly values attributes of solar energy systems by accounting for the following nine components: avoided fuel cost, avoided plant operating and maintenance costs, avoided generation capacity costs, avoided reserve capacity costs, avoided transmission capacity costs, avoided distribution capacity costs, avoided environmental costs, voltage control, and integration cost (Minnesota Department of Commerce April 2014). Minnesota regulators determined that the value of solar generation was $0.135 per kWh. This is higher than the state’s retail electricity rate of $0.131 per kWh (Revesz and Unel 2017).

Maine

Maine is the only other state to have undertaken a VOS study, and, like in Minnesota, the study suggested that solar distributed generation is more valuable than the current retail rate (Trabish March 2015). Instead of implementing the state’s VOS study, like Minnesota, Maine adopted a much different approach to replace their net metering policy. In March 2017, the state’s public utilities commission instituted a buy-all, sell-all framework for distributed generation. Unlike net metering or net billing where customers can sell their excess generation back to the grid, this framework requires customers to purchase all of their electricity from the grid, even when their onsite generation is producing electricity, and sell all their production to the grid at a set rate. Customers receive a credit for all their production against their energy bill (NC Clean Energy May 30, 2017a).

Arizona

In 2016, the Arizona Corporation Commission moved away from the state’s net metering to a net billing policy. The net billing policy still enables


customers to consume energy produced onsite, but sets the compensation rate for energy exported to the grid at energy companies’ avoided cost (NC Clean Energy May 30, 2017b).

Changes to Net Metering in Michigan

Michigan overhauled its energy policies in 2016 with the passage of Public Acts 341 and 342. Among a host of other changes, this legislation directed the MPSC to undertake a study to develop a successor program to net metering that reflects “equitable cost of service for energy company revenue requirements for customers who participate in a net metering program” (MCL December 2016). At the direction of the commission, MPSC staff engaged stakeholders to participate in the development of a new distributed generation tariff and review cost-of-service considerations.

Citing “a critical deficiency of [net metering] that distribution system infrastructure and maintenance costs are inappropriately shifted to non-[distributed generation] customers,” MPSC staff recommended that the state move to a net billing arrangement for distributed generation, referred to as an inflow/outflow billing mechanism (MPSC February 21, 2018). Essentially, the recommended approach separates the energy a customer consumes from the grid and the energy they produce, assigning each a different price. This “creates a more complete picture of a customer’s energy usage and excess generation and is better equipped to reflect distributed generation customers’ cost of service” (MPSC April 18, 2018).

The MPSC determined that not only will the recommended inflow/outflow model provide transparent price signals and better reflect customers’ cost of service, but also new solar projects will continue to have favorable economics under this compensation structure. Additionally, this model will be flexible to incorporate future

rate designs and new technologies, such as battery storage (MPSC February 21, 2018).

The MPSC adopted a tariff based on staff’s recommended inflow/outflow model and directed energy companies to include the tariff in rate cases filed after June 1, 2018.5 The actual distributed generation tariff and compensation rates will be determined on a company-by-company basis. The state’s current net metering program will remain in place until new distribution generation compensation mechanisms are established.

PUBLIC UTILITY REGULATORY POLICIES ACT

In the earliest days of the electric power system, energy companies owned and operated the entire electric system from generation and transmission to distribution. These firms were able to restrict who could access the grid and what resources were built because they controlled the entirety of the system. The system operated this way for most of the 20th century—until PURPA. PURPA wrested vertically integrated energy companies’ ability to control the electric grid by promoting independent power producers and nonutility generators, initiating a trend toward greater federal influence and increased competition in the electric grid that is still evolving to this day.

History of PURPA

PURPA was one of several federal statutes enacted in response to the energy crisis of the early 1970s. Its fundamental purpose was to promote energy conservation and efficiency while fostering greater use of domestic and renewable energy resources. To accomplish this, PURPA established a new class of generating facilities called qualifying facilities

5 Energy companies can include other distributed generation tariffs in their rate cases as well.

“This current era is characterized by relative energy abundance,

rather than scarcity and crisis, and the U.S. is far less dependent

on foreign energy sources and oil-fired generation, one of the

original drivers of PURPA.”


(QFs), which fell into one of two categories: (1) small, independent power production facilities (80 MW or less) using hydro, wind, solar, biomass, waste, or geothermal and (2) cogeneration facilities that produce electricity and useful steam heat.

PURPA also mandated energy companies to purchase the power from these QFs at their avoided cost. The purpose of using avoided cost was to ensure that customers will not have to pay more than they otherwise would. Another element of PURPA, aimed at helping smaller providers, was the requirement for standard offer contracts. The law required these contracts for all providers, up to 100 kW, as an effort to help smaller providers who might not have the capacity to negotiate contracts with energy companies to gain QF status. State regulators can allow the use of standard offer contracts for facilities larger than 100 kW; however, facilities that do not meet provisions for standard offer contracts must negotiate directly with the energy company.

Although a federal law, PURPA was, and continues to be, implemented at the state level, with state utility regulators making key decisions, such as establishing the avoided cost, addressing interconnection issues, establishing contract terms and length, as well as making other critical decisions that impact the viability of PURPA projects.

PURPA in Michigan

PURPA’s history in Michigan began on March 17, 1981, when the MPSC initiated proceedings to begin implementation. The first PURPA QFs began operating in the early 1980s, with most coming online shortly thereafter and through the 1990s. Michigan now has 90 QFs, with a majority of these being a variety of small renewable energy projects, such as hydro, landfill gas, biomass, and municipal waste-to-energy (MPSC April 20, 2018).

Michigan’s PURPA QFs also include the Midland Cogeneration Venture (MCV), a natural gas-fired power plant completed in 1990 through the conversion of the abandoned Midland nuclear energy project, the construction of which was halted in the early 1980s. This facility qualifies as a PURPA QF by virtue of the fact that it is a cogeneration project, producing electricity and steam.

The contracts to purchase the power generated by these 90 projects are divided among four Michigan energy companies: Consumers Energy (with 61 projects of varying types); DTE Energy (24 projects of varying types); Indiana Michigan Power (four hydro projects); and the Upper Michigan Energy Resources Corporation (one biomass project, with wood being the principal fuel). Together, these 90 projects provide a total of 2,467 MW of capacity with the MCV contributing 1,400 MW.

Despite PURPA QFs making up 7.7 percent of Michigan’s overall generating capacity, PURPA contracts contribute relatively little of the renewable energy generated in Michigan. Less than half of the PURPA projects in Michigan are from renewable energy sources and energy companies can only count a portion of these PURPA contracts toward their annual renewable energy goals (MPSC April 20, 2018).6 Renewable energy in Michigan is now responsible for about 10 percent of the electricity generated in the state, and this capacity has been built over the past several years, largely as a result of the state’s RPS as well as improving technology and declining costs for renewable energy (MPSC April 20, 2018).

6 Energy companies with PURPA contracts in place prior to the establishment of Michigan’s RPS in 2008 were granted four out of every five renewable energy credits from facilities through the life of their contract. Renewable energy credit ownership for any new PURPA contracts is specified in a company’s contract with a QF.


Evolution of PURPA

A relatively obscure law for many years, PURPA is receiving renewed attention and generating debate at both the state and federal levels. One of the biggest changes to PURPA came at the federal level with the modification of the mandatory power purchase obligation—commonly referred to as the “PURPA put”—included in the Energy Policy Act of 2005. The change was based on the recognition that, due to the creation of independent transmission operators and competitive markets for energy capacity, independent power producers can access the bulk power grid without needing to contract with an electric energy company. The Federal Energy Regulatory Commission (FERC)—the entity with authority over PURPA—later found that all seven of the nation’s independent system operators met these conditions. The change only applied to QFs larger than 20 MW (FERC October 2006).

Recent trends have made utilities more reluctant to commit to new, long-term PURPA contracts, since energy prices are falling, particularly for renewables, and the market is generally more dynamic than when these contracts were initially established. In addition, there is a new push from renewable energy companies that are attempting to use PURPA as a way to develop new projects in a number of states around the country, including Michigan. Such proposed projects are causing controversy, however, regarding the ability of these projects to live up to the intent of key PURPA provisions and if the projects can provide the necessary capacity.

PURPA in Other States

In response to growing concern about how PURPA fits in with today’s energy markets and state policy goals, state regulators have begun reviewing how PURPA is implemented. Major topics of debate have been setting avoided cost rates, terms for

standard offer contracts, and issues related to capacity. To date, activity has been limited to a handful of states, but their actions inform a general trend toward ensuring that PURPA is balanced with other state policy objectives.

North Carolina

Over the past decade, North Carolina experienced rapid growth of renewable energy projects as a result of PURPA. In just five years, from 2012 to 2017, the state added over 2,000 MW of new renewable energy, mostly solar, with an additional 7,000 MW proposed (NUCC 2017). The growth in solar power was due to its improving economics, state and federal tax credits, and favorable standard offer contracts for solar energy systems set by state regulators.

The rapid growth in solar contracts prompted North Carolina to review its PURPA policies over concerns that the proliferation of solar capacity due to PURPA was imposing higher costs on customers and adversely impacting the electric system overall (Fionn 2016). According to Duke Energy, the 621 PURPA projects added between 2010 and 2015 were responsible for over $1 billion in additional costs for North Carolina customers (Bowman 2016).

In 2017, the state adopted sweeping energy policy changes that revised the standard offer contracts available to PURPA providers. The changes included reducing the size of contracts eligible for standard offer contracts from five MW to one MW, shortening the contract length to ten years, and requiring utilities to make capacity payments if their integrated resource plan identified a need for new capacity (Maloney February 2018). Solar advocates decried the change as hitting the brakes on the industry’s development in North Carolina, but the state’s utilities have cited that, because of the incurred additional costs for customers associated with solar PURPA contracts, the


changes are necessary (NUCC October 2017).

Montana

In 2017, Montana regulators moved to limit contract terms for PURPA facilities from 25 to five years and adjusted the avoided cost rate, which reduced compensation by up to 40 percent. This followed a ruling by FERC, regarding the Montana Public Service Commission’s suspension of payments to solar facilities under PURPA, which violated the law, forcing regulators to reevaluate implementation of PURPA (Maloney October 2017).

Idaho

Regulators in Idaho trimmed the length of PURPA contracts from 20 years to two years after determining that PURPA contracts led to higher prices for customers. In their order, the Idaho Public Utilities Commission (IPUC) noted they made changes “to maintain a more accurate reflection of the actual costs avoided by the energy company over the long term” (IPUC 2015). The commission specifically noted that the state’s largest utilities projected sufficient capacity into the future and that additional capacity from QFs would extend capacity surpluses by more than ten years.

This decision to reduce contract lengths to two years was not made to disadvantage potential QFs but instead the IPUC determined that matching the length of PURPA contracts to the state’s integrated resource planning cycle offers a more accurate accounting for avoided costs, reduces price risks, and increases certainty in forecasting (IPUC 2015.).

Oregon

A similar approach to what was adopted in Idaho was proposed by utilities in Oregon, who petitioned the Oregon Public Utility Commission

(OPUC) to reduce standard contract terms to two years and project size to 100 kW. Unlike in Idaho, OPUC upheld more favorable standard contract terms for PURPA facilities, requiring utilities to offer standard contracts with fixed prices for the first 15 years and then to offer market prices for the last five years. The commission also reduced the size for eligible solar projects from ten MW to three MW, stopping short of utilities’ requested caps (OPUC 2016). This decision was applauded by solar industry advocates (Shallenberger March 2016). Similar actions to revise PURPA in a way favorable to renewable energy development has also taken place in Utah (Shallenberger January 2016).

National Push to Update PURPA

The debate surrounding PURPA is occurring in a dramatically different context than that of 1978 when it was first enacted. This current era is characterized by relative energy abundance, rather than scarcity and crisis, and the U.S. is far less dependent on foreign energy sources and oil-fired generation, one of the original drivers of PURPA. Another change since 1978 is that much of the U.S. now has a mature independent power production sector and competitive markets for energy and capacity. Improvements in technology have lowered the cost of installing wind and solar energy, and the number of renewables in the country is only expected to grow as states pursue renewable energy and environmental goals. We also live in an era of energy efficiency where energy use is flat or declining, despite economic growth.

The change in energy markets and controversy over how some are attempting to use PURPA to bring large-scale solar projects online has invited the introduction of House Resolution 4476 (HR 4476) in the U.S. Congress—the PURPA Modernization Act of 2017—by Michigan congressman Tim Walberg. The changes to


PURPA contained in HR 4476 have been generally supported by those who believe that current PURPA prices and contract lengths have been overly generous but opposed by interests who want to bring utility-scale solar projects online and others who would benefit from those projects (Brooks 2018). FERC has also recently undertaken review of PURPA to investigate potential abuses with how the law is being implemented (Bade 2018).

Changes to PURPA in Michigan

To date, major changes to PURPA have not been made, so the MPSC is faced with implementing PURPA in its current form. Many of Michigan’s existing PURPA contracts are now expiring, which creates the opportunity to establish updated avoided cost rates and make other modifications to contract terms and lengths. In fact, Michigan’s new energy law—PA 341 of 2016—included the

requirement that the MPSC conduct a proceeding at least every five years to ensure that procedures and rate schedules, including avoided cost rates, are just and reasonable based on PURPA statute as well as FERC regulations and orders. The MPSC must, therefore, address the difficult issues of scale, capacity need, contract duration, price, and whether to treat long-standing PURPA projects differently than new ones.

The MPSC’s efforts to update the state’s implementation of PURPA are already underway. The MPSC initiated separate documents for the each of the state’s rate-regulated electric utilities. Only two utilities have completed the process of updating their avoided cost provisions. Both Alpena Power Company and Upper Peninsula Power Company reached settlement agreements, which were approved by the MPSC (MPSC 2018).


IMPLICATIONS FOR PUBLIC POLICYThe convergence of favorable economics for renewable energy technology and other trends in the electric power sector have highlighted the need to reexamine policies and programs that have—to date—been the primary factor in promoting renewable energy. If Michigan simply retains old policies, customers will miss out on the full potential offered by renewable energy technologies and set the state back in achieving a more sustainable, advanced energy grid.

This section summarizes the implications of Michigan’s current renewable energy policies and potential policy solutions for ensuring the state achieves its goals of a reliable electric system by ensuring all customers have the energy they need, maintaining affordable cost-of-service principles and ensuring prudent investment, accommodating emerging technologies and opportunities to engage consumers, and protecting the environment through the replacement of older coal-fired power plants with cleaner technologies.

SUCCESS OF THE RENEWABLE ENERGY PORTFOLIO STANDARD

The progress made on renewable energy deployment in Michigan over the past decades has been largely in response to federal support for renewable energy through tax credits; state requirements of the RPS; declining costs driven by improving technology; and, more recently, greater procurement commitments from major corporations. PURPA and customer-owned distributed generation have played a limited role in promoting the growth of renewable energy in terms of Michigan’s installed renewable energy capacity.

Michigan achieved its goal of getting 10 percent of its electricity from renewable sources while holding costs in check for consumers and protecting reliability. The MPSC’s annual report on the implementation of the state’s RPS demonstrates that utilities met the state’s renewable energy goal and that costs for renewable energy have declined steadily since the inception of the state’s RPS. And, except for a small fraction of projects, new renewable energy has been less expensive than the benchmark plant used for comparison.

While Michigan chose to expand its RPS with the passage of PAs 341 and 342 in 2016, its largest utilities have already demonstrated that the policy is not the only factor pushing them to invest in new renewables. In response to efforts to raise the state’s RPS, Consumers Energy and DTE Energy—collectively responsible for 90 percent of the state’s electric customers—announced their commitment to generating or acquiring 25 percent of their energy from renewable sources by 2030 (Oosting 2018). The commitment comes from the recognition that Michigan can have all of the above energy strategies and that affordability and reliability do not have to take a backseat to environmental protection.

Given the announced progress of renewable energy in Michigan, there is no reason to reevaluate Michigan’s current RPS statute, but this success raises questions about whether the state should pursue subsequent RPSs. Another central provision of Michigan’s new energy policy was the requirement that utilities undergo integrated resource planning processes, where stakeholders can debate the merits of various technologies and other assumptions with state regulators’ input. Renewable energy’s ability

to compete with conventional technologies from an economic perspective suggests that the appropriate place to evaluate how much and when the state adds new renewable energy capacity is during a comprehensive planning process. This will ensure that the future of renewable energy development will be based on achieving all of the state’s energy policy goals.

THE RIGHT ROLE FOR PURPA

PURPA’s original purpose was to encourage energy security and offer a diverse energy supply through the advancement of renewable energy, energy efficiency, and independent power production. However, PURPA has not yet been responsible for the large growth in the deployment of renewables. Its definition of energy efficiency, focused on cogeneration, is outdated, and independent power production is alive and well autonomous of PURPA. This does not, however, mean that these are the wrong goals. It simply demonstrates that

dramatic changes have occurred since PURPA’s enactment 40 years ago, and it may not be the most effective tool to achieve current objectives.

This raises the question of whether PURPA has a place in the energy sector of the 21st century. A liberalized power sector, driven by federal policies for more than 20 years, has increased access to the electric grid for independent producers and led to the development of energy and capacity markets.1 The renewable energy industry is thriving, as is the domestic natural gas industry, which not only helps insulate the U.S. from global supply shocks, but has also greatly increased the diversity of the electric power sector. These realities beg the question of what is left to accomplish of PURPA’s original intent and if the policy is still necessary in the modern electric power system.

1 For certain states that are still traditionally regulated, not a part of an independent system operator or regional transmission operator, and are lacking competitive energy markets, independent power providers would have limited ability to access the grid without PURPA.


In recent years, PURPA has begun to take on a new role, serving as the regulatory tool of choice for renewable energy developers nationwide. Declining module costs and the extension of tax credits for solar energy, combined with favorable standard contract terms, have led to a boom in solar development through PURPA. This expansion has taken many states by surprise, and utilities that are not in the position of needing new capacity have been forced to take on new contracts for as long as 20 years.

The potential that the MPSC will adopt new, more favorable standard offer contract terms for solar in Michigan has raised concern over whether PURPA is in step with the state’s broader energy policy goals. While the goal of diversifying Michigan’s fuel supply and the principle that projects would only be able to charge the utilities’ avoided cost rate may seem like good reasons to promote PURPA projects, making decisions about the state’s resource mix, apart from the newly established integrated resource planning process, runs counter to the goal of planning investment in a way that minimizes cost and negative impacts for consumers. PURPA’s objectives may not directly contradict those that Michigan is trying to achieve, but PURPA’s structure is not complementary to Michigan’s energy policy, putting the state at risk of bearing long-term, unvetted costs. Ultimately, it is customers who will bear any cost increases due to PURPA, and it is the responsibility of state regulators and policymakers to ensure PURPA serves a purpose in the 21st century while also allowing states to achieve their own unique policy goals.

ACCOMODATING CUSTOMER-OWNED DISTRIBUTED GENERATION

Michigan already has a fundamental framework for making policy decisions based on promoting reliability, affordability, adaptability, and

environmental protection (MAE 2017). These principles were central to crafting Michigan’s new energy policy and should remain a focus in determining the right path for distributed generation policy in Michigan. Beyond these broad objectives, there are a few key principles, specific to customer-owned distributed generation, that are essential for designing an equitable policy: providing fair compensation for the value these customers supply to the grid, ensuring customers’ ability to choose to self-supply, and requiring that customers pay for their share of fixed infrastructure investment in the grid. It is possible to balance these principles at the same time, but it requires taking stock of the full benefits and drawbacks of distributed resources.

The debate over the future of net metering is playing out across the country as state policymakers and regulators determine how to design compensation for customer-owned distributed generation in an equitable way. The stakeholder process and subsequent discussion of the MPSC’s April 18, 2018, order regarding the state’s new distributed generation tariff, have exposed a deep divide among Michigan stakeholders about the future direction of distributed generation programs. Comments from energy company participants suggest that the state could have gone further in addressing subsidies for distributed generation customers. Others, including solar industry advocates, have decried the commission’s order as not appropriately valuing the contributions of distributed generation, like mitigating transmission line losses, offsetting costly peak generation, and considering environmental benefits. Already, legislators in Michigan’s House of Representatives have moved to scrap the new distributed energy program in favor of going back to net metering (Samilton 2018).


Need for New Rate Designs

The debate over net metering centers on the disagreement over whether net metering customers receive a subsidy or whether they provide net benefits to the grid. Despite ongoing debate, the emerging national trend is to move away from true net metering programs in favor of net billing with new, more accurate rates. Underpinning state efforts to reform net metering policies has been a consistent effort to study and quantify the costs and benefits of customer-owned distributed generation to design a compensation mechanism that appropriately compensates customers (Proudlove et al. 2018).

Decisions from state regulators are reflective of the reality that net metering is a tool that has outlived its original purpose. Net metering was borne out of a time with limited options for regulators due to technological limitations. Today’s advanced metering infrastructure has expanded regulators’ ability to develop rate structures that accurately reflect the actual time of use and production. While net metering may have been the easy or only way to enable customer-owned distributed generation in years past, maintaining this structure may overlook better options for appropriately valuing these resources and getting price signals right for both customers and utilities.

While the state has taken the step to move away from the net metering compensation structure for customer-owned generation, MPSC staff has suggested that using utilities’ avoided cost set through PURPA proceedings could be a suitable way to value the energy that distributed generation pushes back to the grid. This approach, despite capitalizing on cost determination already underway, would conflict with the approach explicitly outlined in Michigan’s new energy policy (PA 342 Section 177(4)).

Environmental Benefits

Net metering supporters often point to a diverse set of benefits provided by distributed energy systems to back up their claim that there is no subsidy for net metering customers. One of these benefits is that distributed generation, particularly solar, provides societal benefits through emissions reduction of local air pollutants and greenhouse gases. While there is an established history of allowing energy companies to recover costs due to required environmental compliance regulations, there is no such authority to compensate distributed generation for its environmental performance characteristics in Michigan. Both Maine and Minnesota’s VOSs include avoided emissions as a value of distributed solar generation, but that is because they have explicit statutory requirements to include them. It is in the purview of policymakers and regulators to redesign energy company compensation structures and/or explore new options for regulation, but with an absence of specific legislative authority to place a value on societal benefits, such as emissions reductions, the MPSC cannot consider these benefits in the development of a distributed generation tariff. Additionally, it would fundamentally undermine Michigan statute to allow distributed energy to count noneconomic values, such as reduced emissions, while not allowing other renewable developments to claim the same benefits. If Michigan decides that reducing emissions is a goal, it should do so by evaluating all policy options to determine the most economically efficient approach, using this goal to support additional payments for distributed generation.

Equity

While there is truth to the argument that the cost of customer-owned distributed generation is not born by other customers in that an individual customer takes on the investment,


not the energy company, this argument does not consider that there are system costs associated with net metering customers receiving the retail rate for their energy production. These currently unaccounted for system costs end up being borne by all customers to maintain and modernize our state’s electric system. Further, by promoting net metering policies, stakeholders may not see that the ability to invest in distributed generation is only available to a select group of customers who have the motivation and the resources. The risk associated with continued promotion of net metering is that Michigan will have a disparate system—between those who have access to distributed generation and those who do not. For those who lack access, they will be left to maintain a system abandoned by those of the highest means.

The challenge of creating inequity in the system is not entirely overcome by shared solar projects where multiple subscribers can purchase shares of an installation and have the output credited against their monthly energy consumption. While there has been growing interest in these types of programs because they expand access to solar to more customers, if the compensation structure is not properly designed, these facilities present many of the same risks of traditional net metering systems, like allowing a subset of customers to avoid costs associated with their access to the grid and shifting costs to other consumers.

If the state wants to promote clean and affordable energy for all customers, it must recognize that utility-scale generation can be provided at a much lower levelized cost than residential, commercial, and even industrial solar energy projects. The state should also consider that utility-scale projects do not have the same effect of shifting costs to customers who cannot afford to invest in their own distributed generation (Brown and Bunyan 2014).

Comprehensive Planning

If deployed in the right places, distributed generation can have real economic benefits. Theoretically, it could help defer investment in new generation sources or defer additional investment in transmission and distribution. Deployed strategically, distributed resources can enhance the resilience of the electric grid, especially when paired with battery storage, microgrids, and/or smart inverters. When distributed technology, like solar, is incorporated into energy company planning processes, it can yield benefits in the range of $0.01 to $0.02 per kWh (Bird et al. 2013). To fully realize these benefits, Michigan must strategically deploy new generation and other technologies, which will only occur if resources can be sited through robust systems planning.

The current deployment of distributed generation is almost entirely driven by individual customer desire. And while customers should have the option to self-generate, this gradual deployment approach makes the touted benefits of distributed generation harder to quantify and limits any benefits that could be accrued through the deployment of resources. Instead, customer-owned distributed generation creates additional variables that utilities must consider as they manage the rest of their system without regard to whether installation of customer-owned generations is appropriately placed to yield systemwide benefits.

Advocates who focus on net metering, to the exclusion of other policy options, run the risk of overlooking other lower-cost pathways to the same outcomes. Therefore, it is important to look at the big picture and carefully plan for how to reach Michigan’s goals. If the desire is greater distributed resources, then there are ways to ensure that these resources are being sited where they will actually defer energy company


investment; if the goal is more renewable energy, then there are other lower-cost options to be pursued.

Utilities are now investing in renewables because of the changing economics of renewables and customer expectations. In many cases, these changes are happening regardless of government mandates, policies, and subsidies, which raises the question of how or if government should play a role in supporting renewable energy, given the changing dynamics outlined in this paper. Instead of advancing renewable energy policies that apply various supports for different technologies and resources, policymakers should be looking for more holistic, inclusive ways to ensure that renewable energy and the greening of the electric power sector are undertaken in a way that ensures optimal reliability, affordability, and fairness for all users of the system.

The one key theme emphasized throughout this white paper is the importance of comprehensive

planning in designing the right system and the right resource mix. Michigan has never truly had an integrated approach to developing its electric power sector, and, because of that, has relied on a fragmented mix of subsidies, mandates, and laissez-faire strategies. However, Michigan’s adoption of the integrated resource plan as part of PA 341 in 2016 provides an opportunity to finally put all of the state’s goals into perspective and define a comprehensive approach to achieve them. The integrated resource planning process will help inform decision makers of the implications of their choices and better prepare them to make judgments in a dramatically changing environment. The process does not resolve issues related to distributed generation, PURPA, or government mandates to everyone’s satisfaction, but, at minimum, will contextualize decisions on these issues and allow decision makers to weigh the economics with other goals to make the right choice for all Michigan customers.

“Michigan’s adoption of the integrated resource plan as part

of PA 341 in 2016 provides an opportunity to finally put all of

the state’s goals into perspective and define a comprehensive

approach to achieve them”


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———. May 30, 2017a. “Distributed Generation Buy-All, Sell-All Program: Program Overview.” Database of State Incentives for Renewables and Efficiency (DSIRE). Accessed May 8, 2018. http://programs.dsireusa.org/system/program/detail/280

———. May 30, 2017b. “Net Billing: Program Overview.” Database of State Incentives for Renewables and Efficiency (DSIRE). Accessed May 8, 2018. http://programs.dsireusa.org/system/program/detail/3093

———. March 1, 2018. “Business Energy Investment Tax Credit (ITC): Program Overview.” Database of State Incentives for Renewables and Efficiency (DSIRE). Accessed June 15, 2018. http://programs.dsireusa.org/system/program/detail/658

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Revesz, Richard L. and Burcin Unel. January 2017. “Managing the Future of the Electricity Grid: Distributed Generation and Net Metering.” The Harvard Environmental Law Review 41: 41–108. Accessed April 15, 2018. http://policyintegrity.org/files/publications/Managing_the_Future_of_the_Electricity_Grid.pdf

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Rode, David C., Paul S. Fischbeck, and Antonio R. Páez. July 2017. “The Retirement Cliff: Power Plant Lives and Their Policy Implications.” Energy Policy 106: 222–232. Accessed May 7, 2018. https://www.sciencedirect.com/science/article/pii/S0301421517302136


Samilton, Tracy. April 30, 2018. “Bill Would Restore Net Metering for Solar Roof Customers.” Michigan Radio. Accessed May 4, 2018. http://michiganradio.org/post/bills-would-restore-net-metering-solar-roof-customers

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Shallenberger, Krysti. December 22, 2015. “Nevada Regulators Approve New Net Metering Policy, Creating Separate Rate Class for Solar Users.” Utility Dive. Accessed April 20, 2018. https://www.utilitydive.com/news/nevada-regulators-approve-new-net-metering-policy-creating-separate-rate-c/411284/

———. January 8, 2016. “Utah Regulators Slim Down PURPA Contracts to 15 Years.” Utility Dive. Accessed May 20, 2018. https://www.utilitydive.com/news/utah-regulators-slim-down-purpa-contracts-to-15-years/411790/

———. March 31, 2016. “Oregon PUC Rejects PacificCorp Bid to Trim PURPA Contracts.” Utility Dive. Accessed May 20, 2018. https://www.utilitydive.com/news/oregon-puc-rejects-pacificorp-bid-to-trim-purpa-contracts/416627/

———. July 27, 2017. “North Carolina Governor Signs Solar Bill, Targets Wind Moratorium with Executive Order.” Utility Dive. Accessed April 20, 2018. https://www.utilitydive.com/news/north-carolina-governor-signs-solar-bill-targets-wind-moratorium-with-exec/448091/

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Trabish, Herman K. March 19, 2015. “Is Solar Worth $0.33 per kWh? Inside Maine’s Valuation Debate.” Utility Dive. Accessed May 6, 2018. https://www.utilitydive.com/news/is-solar-worth-033-per-kwh-inside-maines-valuation-debate/376364/


———. February 1, 2018. “In 2017, Solar Policy Debates Took the Industry’s Future to Higher Ground.” Utility Dive. Accessed May 6, 2018. https://www.utilitydive.com/news/in-2017-solar-policy-debates-took-the-industrys-future-to-higher-ground/515716/

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———. February 25, 2015. “Wind Generation Seasonal Patterns Vary across the United States.” Today in Energy. Accessed April 19, 2018. https://www.eia.gov/todayinenergy/detail.php?id=20112

———. May 25, 2017. “Energy Storage and Renewables Beyond Wind, Hydro, Solar Make Up 4% of U.S. Power Capacity.” Today in Energy. Accessed April 19, 2018. https://www.eia.gov/todayinenergy/detail.php?id=31372

———. November 6, 2017. Sales to Ultimate Customer (Megawatt Hours) by Sector, by State, by Provider 1990–2016. Accessed June 15, 2018. https://www.eia.gov/electricity/data/state/sales_annual.xlsx

———. January 8, 2018. “Batteries Perform Many Different Functions on the Power Grid.” Today in Energy. Accessed May 7, 2018. https://www.eia.gov/todayinenergy/detail.php?id=34432

———. February 6, 2018. Annual Energy Outlook 2018. Accessed April 20, 2018. https://www.eia.gov/outlooks/aeo/pdf/AEO2018.pdf

———. February 9, 2018. “Utilities Continue to Increase Spending on Transmission Infrastructure.” Today in Energy. Accessed May 15, 2018. https://www.eia.gov/todayinenergy/detail.php?id=34892

———. February 25, 2018. “Wind Generation Seasonal Patterns Vary Across the United States.” Today in Energy. Accessed May 17, 2018. https://www.eia.gov/todayinenergy/detail.php?id=20112

———. March 2018. Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2018. Accessed April 25, 2018. https://www.eia.gov/outlooks/aeo/pdf/electricity_generation.pdf

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———. April 2018. Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2016. Accessed May 8, 2018. https://www.eia.gov/analysis/requests/subsidy/pdf/subsidy.pdf

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———. April 26, 2018a. Table 7.2A Electricity Net Generation: Total (All Sectors). Accessed May 8, 2018. https://www.eia.gov/totalenergy/data/monthly/pdf/sec7_5.pdf

———. April 26, 2018b. “Renewable Energy Subsidies Have Declined as Tax Credits, Other Policies Diminish.” Today in Energy. Accessed May 2, 2018. https://www.eia.gov/todayinenergy/detail.php?id=35952

———. April 27, 2018. “Form EIA-861M (Formerly EIA-826) Detailed Data: Net Metering 2017.” Electricity. Accessed May 7, 2018. https://www.eia.gov/electricity/data/eia861m/#netmeter

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———. June 16, 2017. “Nevada Governor Signs Net Metering Bill.” Utility Dive. Accessed April 20, 2018. https://www.utilitydive.com/news/nevada-governor-signs-net-metering-bill/445177/

———. September 19, 2017. “New York Regulators Unveil New DER Compensation Implementation Plan.” Utility Dive. Accessed April 20, 2018. https://www.utilitydive.com/news/new-york-regulators-unveil-new-der-compensation-implementation-plan/505217/

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Responsible Policies for Renewable Energy Development...which allow customers to supply their household electricity (usually through rooftop solar) and sell excess generation back