The energy sector is undergoing a dramatic change – one that promises to transform it for generations to come. Energy generation and management, customer expectations, technical innovations, and financing approaches are all changing at a rapid pace, but within a sector that was structured and organized in the 1930s.
In the US, energy policy is largely formed at the state level. State legislatures set priorities and objectives while also establishing the mechanisms for achieving those objectives. Energy offices implement programs that promote new energy technologies, and environmental offices enforce regulations to protect land, air, and water. State utility regulators evaluate the trillions of dollars utilities invest on behalf of their rate-payers. The policies enacted by legislatures and regulators impact the more than 3,500 utilities serving customers large and small throughout the country.
In the 2013-2017 state legislative sessions, over 16,000 energy-related bills were introduced around the country. Of these, over 2,800 have been enacted. The impact of this legislation is not only significant at the state or national level, but on a global scale. If you were to take the combined population of states that have enacted a renewable portfolio standard - a requirement that a percentage of their electrical power come from renewable resources (see Section 4.6: Renewable Portfolio Standards) - it would be the world’s 5th most populous country (see Figure i).
This e-book does not cover all potential energy-related policies, but rather focuses on those policies that have successfully moved states toward a modern, clean, and cost effective energy system. In our “New Policy Frontiers” sections, we discuss some of the emerging issues and policies that are developing in this changing energy landscape.
The Center for the New Energy Economy will continue to update this e-book as new policies are developed and as technologies change.
This e-book is one tool provided by the Center for the New Energy Economy. We offer a variety of other tools that can be used in concert with this e-book.
CENTER FOR THE NEW ENERGY ECONOMY STATE LEGISLATIVE TOOLS:
The Center for the New Energy Economy at Colorado State University has developed a series of tools to help state legislators, administrators, regulators, non-governmental organizations (NGOs), and others interested in developing policies to facilitate the transition to an efficient, affordable, and clean energy system. In addition to this legislative e-book, the Center maintains multiple tools to promote best practices in energy policy, track state energy legislation, evaluate legislative trends, and identify policy opportunities in each state.
State Policy Opportunity Tracker for Clean Energy
The State Policy Opportunity Tracker for Clean Energy (SPOT for Clean Energy) is a gap analysis that breaks 37 different state policies into their key components and looks state by state at what each state has and what they are missing. The website contains briefs on each policy as well as links to supporting resources.
Advanced Energy Legislation Tracker
The Advanced Energy Legislation Tracker (AEL Tracker) documents energy-related legislation introduced throughout the country and tracks the legislation as it moves through the legislative process. The database is searchable by year, state, category, and keywords. Our extensive archive of legislation demonstrates that there are many good policy ideas that are not enacted, but the work put into developing them can be valuable for other legislators around the country.
Energy Policy Podcast
The Energy Policy Podcast is a podcast developed by the Center for the New Energy Economy to discuss policy issues and events impacting state energy policy. Interested listeners can subscribe to the podcast here.
HOW TO USE THIS E-BOOK
This e-book is another tool to assist those working on legislation to help make their states leaders in the New Energy Economy. Each chapter addresses a specific policy area and contains a description of policies that have effectively moved states forward in each area.
Some chapters also include a “New Policy Frontiers” section to present some of the emerging issues and ideas being discussed around the country that may not yet be implemented. These sections are included to help policymakers consider a wide variety of policy options.
All policy discussions include links to reports, resources, and embedded videos and graphics to help readers gain a greater understanding of the issues underlying each policy, and the objectives and challenges the policy is designed to address.
While one can certainly read through the book from start to finish, the book is designed to be used as a tool that will assist the reader in honing both their understanding of specific issues as well as finding policy solutions to specific challenges. In this way, the e-book may be seen as a resource to be used in addition to the tools above. For example, one may see a series of bills introduced on a topic in AELTracker and will go to the specific section to learn more about the issue. Or, one may see policy gaps identified for their state in SPOT for Clean Energy and want to investigate ways in which they may be able to address those gaps. Finally, a legislator may be hearing a bill in committee and want to quickly get background information on the issue. This e-book should be seen as a resource to be used in all of these ways.
If you are unable to watch the video below, click here.
This book would not have been possible without the work and collaboration of many.
This e-book was created by staff at the Center for the New Energy Economy: Senior Policy Advisors Tom Plant and Jeff Lyng, Research Manager Katherine Heriot Hoffer, and Research Associates Chris Edmonds, Jane Culkin, and Alison Anson under the direction of former Colorado Governor and the Center for the New Energy Economy’s Director, Bill Ritter.
This project would not have been possible without the assistance of student interns from Colorado State University, the University of Notre Dame, and the University of Colorado at Boulder. They included Alison Smith, Katie Jordan, Rick Zieser, Jessica Hertzog, Bridgit Kodenkandath, and Marina Witt.
Thanks also to the team of internal and external policy experts who reviewed and vetted these policy briefs. They included Sarah Booth, Booth Clean Energy; Matthew Brown, Harcourt Brown & Carey; Jeffrey J. Cook, CNEE and NREL; Liz Doris, NREL; Angie Fyfe, ICLEI; Annie Gilleo, ACEEE; Jenny Heeter, NREL; and Will Toor, SWEEP.
Chapter 1.1: Energy Efficiency - Introduction
The cleanest and most cost effective energy is the energy you don’t use. Technology is constantly improving to allow us to use energy more efficiently while powering our daily lives. This chapter looks at policies to advance energy efficiency.
When some of us think of energy efficiency, we think of sacrifices like putting on a sweater and turning down the thermostat. However, that’s not what energy efficiency is about at all. Instead, energy efficiency is about using energy in the most cost effective and efficient manner while delivering the same – or improved – energy services.
When you turn on an incandescent light bulb it offers useful light, but also a great deal of heat. This heat represents the inefficiency of the light bulb. In comparison, an LED bulb offers light without heat. Because of this, the LED bulb uses less energy. This illustrates how we can use energy more efficiently and cost effectively without sacrificing the benefits of technology.
In a report from the American Council for An Energy-Efficient Economy (ACEEE), ”The Greatest Energy Story You Haven’t Heard,” the authors estimate that “from 1980 to 2014, our GDP increased by 149% while energy use in the United States increased by just 26%, from 78 quads (or a quadrillion Btus) to 98 quads.” That is energy efficiency at work.
Improving energy efficiency doesn’t just represent an advantage to the individual user or homeowner. As the population grows, energy efficiency must improve or we will need to pay for additional, costly generation. Because the cost of this additional generation is shared by all citizens, the advantages of a more energy efficient system accrue to society as a whole.
For example, building codes are generally set by the government. If there aren’t minimum efficiency requirements, houses could be built with very little insulation and windows that don’t seal the building. These houses might be cheaper to build, and probably cheaper to buy. However, the financial burden will fall to the occupant of the building as they pay for the higher energy costs of the building every month. The general population at large will also see increased costs as the inefficient buildings drive more demand for energy and new generation is required to serve the increased load.
Estimates of the inefficiency of our systems are as high as 86%, meaning that as much as 86% of our energy potential is lost in the process of producing goods and services. The laws of thermodynamics won’t allow us to get to 100%, but we can do much better than 14%.
Energy supply and demand is a closed loop. If you use less energy, you don’t need as much supply. If you use more energy, you need more supply. Energy efficiency is much less expensive than building new energy generation. For this reason, energy efficiency is often referred to as the “first fuel”.
Another dynamic to the supply and demand equation is the time at which the demand is occurring. We don’t use energy equally during the day or during the year, but we need to have resources available to meet peak energy demand times. For example, in the heat of summer, as the population turns on their air conditioners, the system requires a great deal more electricity than during the evening in the spring. These peaking units only operate in the hours when we don’t have the generation capacity available to meet our peak energy needs. Yet, the capital costs of these units are still incurred by utility customers even when they’re not running. This is why peaking units are some of the most expensive generation resources we can buy. Technology can help us manage demand more effectively and shift peak loads to times when there are more resources available. This type of “demand response” is another form of energy efficiency that can lead to enormous reductions in costs for the system.
Reliability is the most important focus of a utility. Traditionally, utilities ensure grid reliability by building sufficient generation to meet demand. Focusing on generation (or the “supply side”) has led to overbuilding capacity to avoid the possibility of black- or brown-outs. New technologies allow us to adopt an approach to energy planning that looks at both demand and supply.
Increasing demand response measures, and increasing the efficiency of energy generation, transmission, and consumption allows us to use our generation assets more cost effectively and leads to a much more stable and economical system.
The least expensive and cleanest way to provide services is with a highly efficient system. To ensure the development of this system, public policy is essential. This chapter looks at some supportive policy approaches.
Chapter 1.2: Energy Efficiency - Building Energy Codes
The Department of Energy (DOE) projects that, over time, improvements in building codes can have the greatest single impact in energy efficiency within the built environment. Because buildings will be around for generations, energy efficiency within the built environment is a matter of statewide and long-term importance. Some states have statewide building codes; others defer to local governments. In either case, legislation can set a baseline efficiency standard. Preferably the legislation also provides for regular review and update, for instance, by a code panel that has rule making authority.
Building codes not only improve the performance of buildings for generations to come, but they also compliment the impacts of other clean energy policies. For example, furnace efficiency standards will have a much greater impact on energy use within an energy efficient home than within a less efficient home.
Building energy code legislation typically establishes a baseline International Energy Conservation Code (IECC) standard to be incorporated into state and local building code requirements. The International Code Council (ICC) updates the IECC every three years. IECC standards include the 2009, 2012, 2015, and 2018 standards. The ICC also works with the American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE) to recommend standards for the commercial environment.
DOE’s Building Energy Codes Program (BECP) supports energy efficiency through multiple program areas, including the development of model energy codes and standards. In order to support the adoption and implementation of, as well as compliance with, building codes and standards, the program provides technical assistance to states, local governments, and building owners.
Combined Heat and Power (CHP) allows large industrial users with on-site electricity generation to leverage the generator’s heat by-product for beneficial uses in production and building heating requirements. Excess steam in the summertime can also be used for absorption chilling for cooling loads.
Sometimes referred to as cogeneration, the primary benefit of CHP is very high system efficiency. While separate electric and heating systems may have 40-50% efficiency, CHP systems have system efficiencies in the 70-80%+ range. Often, the fuel for CHP systems is natural gas, which may yield a climate benefit over grid power, especially considering the enhanced thermal efficiency. The extent of the climate impact is dependent upon the prevailing generation resource being used.
A key consideration in CHP deployment is identifying the right application – a constant electric and heating / cooling load. Breweries, universities, and hospital complexes are all suitable applications.
CHP tends to suffer from the lack of a clear home in state policy, defined in some states as efficiency and in others as clean energy or renewable energy. Some states include CHP explicitly in their Energy Efficiency Resource Standard (EERS), others in their Renewable Portfolio Standard (RPS), while others lack a clear statutory definition of CHP.
From a public policy perspective, a key consideration to deployment is having a clear utility tariff for customers who opt to add CHP. More specifically, utilities design ‘stand-by’ charges into their rates for customers that have on-site generation but who may need backup power from time to time when their on-site generation is offline. Clear and consistent tariff design is the lynchpin for CHP deployment. Legislation directing a public utilities commission (or their equivalent) to design and approve a clear stand-by charge for CHP is often going to be the best place to focus in this policy area. The Department of Energy (DOE) and Environmental Protection Agency (EPA) also have a partnership on CHP deployment, which stems from President Obama’s Executive Order setting a goal of 40 gigawatts (GW) of CHP by 2020 (a 50% increase from present trends). Technical assistance is available from DOE to help states and industrial customers deploy CHP through the CHP TAP Program, and EPA maintains a database of CHP incentives.
Decoupling of utility revenue from sales removes a disincentive for utilities to invest in energy efficiency. Broadly defined, decoupling refers to a process by which a utilities commission grants a utility a level of return on equity that is not dependent on the volume of their sales.
So, while utilities will typically rely on a certain volume of sales to earn revenue at a set rate, decoupling changes that dynamic - removing the disincentive for achieving system efficiencies that would lead to a reduction in the volume of electricity or gas sold to each customer.
Many view decoupling as the foundational policy for removing the disincentive for utilities to invest in energy efficiency. By separating utility revenues from kilowatt hour (kWh) sales, the process of decoupling sets the Rate of Return (RoR) for the utility and adjusts the kWh rate for the customer to ensure the recovery of that return. This rate adjustment mechanism can be moved up or down to achieve the approved utility RoR.
Some states attempt to achieve a result similar to decoupling by using a Lost Revenue Adjustment Mechanism (LRAM). With an LRAM, utility regulators determine the volume of declining sales attributable to energy efficiency programs and calculate the marginal revenues lost to the utility due to those measures. The utility is then able to collect the lost revenue through an LRAM “rider” on utility bills.
Decoupling is one part of a multi-pronged policy approach for motivating utilities to invest in energy efficiency (See Figure 1.10). Another key piece is the timely and full recovery of the costs of Demand Side Management (DSM) program administration and customer incentives.
It is important to note that Decoupling, LRAMs, and program cost recovery simply get utilities to a point of indifference; they do not create an incentive for utility investment in energy efficiency. The final, and perhaps the most important aspect, is some form of incentive for the utilities to invest in energy efficiency, or a performance incentive. This performance incentive can take the form of a net economic benefit adder or a percentage bump in a regulated RoR.
Multiple aspects of this policy suite should be in place to maximize the success of DSM program implementation.
Demand for utility service follows peaks and valleys both diurnally and seasonally. In the middle of the night demand is relatively low, and as people wake up, demand increases. During the day, residential demand might go down while industrial and commercial demand goes up, but in the evening that trend reverses. Seasonally, a utility might see large spikes in demand on hot days when air conditioning loads overwhelm the system.
Peak energy demand drives some of our most expensive generation and leads to high costs for consumers. A Demand Response Standard works similarly to a generation standard like a Renewable Portfolio Standard (RPS) or an Energy Efficiency Resource Standard (EERS) by requiring that a certain percentage of demand be met through technology that allows a utility to manage demand loads on the customer side of the meter. Rather than requiring expensive generation to meet peaks, this can bring demand peaks down.
A demand response standard is designed to promote programs and technologies that will manage peak demand to reduce peaks by a specific percentage. Similar to an EERS, a demand response standard targets not just the overall energy sales for a reduction, but specifically a percentage reduction in peak demand.
Peak power generation drives up rates for customers because it is used so infrequently. For example, if a utility achieves peak demand a total of 30 hours per year, a “peaking unit”, or generation facility that is used to deliver power during these times, will only earn money 30 hours per year. This makes the utility investment in a peaking generation unit very expensive to the system and, in a competitive merchant utility system, makes the costs per kWh of market peaking power very expensive to the customer.
Because peak power comes at the greatest cost to the consumer, a demand response standard may lead to the greatest consumer savings (although not necessarily the greatest reductions in emissions or overall generation requirements).
If the goal of demand response is to address transmission congestion and difficulty in delivering peak energy requirements through the existing infrastructure, a demand response standard may also be combined with the establishment of a capacity market. In this approach, demand response is not only offsetting the potential capital investment in peak generation, but also the costs of increasing the capacity of transmission infrastructure.
In January 2016, the Supreme Court upheld the Federal Energy Regulatory Commission’s jurisdiction to set wholesale rates for demand response. This ruling may have a significant impact in the expansion of demand response as a resource to meet peak energy needs.
Energy efficiency measures undertaken by a utility are frequently seen as an additional program, rather than the purchase of an actual energy resource, and therefore one that has additional costs to the utility.
States can avoid this dynamic by making energy efficiency a resource that utilities must buy when it is cost effective as compared to other resources. But, without this kind of approach, a budget is required to finance investments in energy efficiency. The good news is, these investments reap substantial savings in generation-related costs.
To ensure a program’s success, utilities (or the entity managing energy efficiency programs) need an established budget. Budget expenses are not only for incentives for energy efficiency, but also for marketing and outreach. Energy efficiency program budgets are created through the establishment of a fund to finance various incentives offered to energy consumers. These funds may be managed by the utility itself or a third-party designated responsible for achieving efficiency savings.
Often times, the source of money is through a rider on the customer’s bill - relative to their volume of energy use. This is often referred to as a system benefits charge or public benefits fund. Funds might also be created through some other designated source of stable revenue.
In assessing a fee to fund energy efficiency programs, legislation may also identify a third-party administrator as well as a reporting requirement to the state or the regulatory commission to identify both megawatt hours (MWh) and megawatts of demand (MW) saved as well as the overall costs of programs (rendering a cost/MWh or cost per/MW avoided – for comparison to other generation technologies).
Establishment of a designated budget is critical to ensuring investment by the utility (or designated third-party) in advancement of energy efficiency measures. This is because energy efficiency is often located on the demand side and is not treated as a true energy resource in the same way supply side resources are funded. And, because utilities don’t traditionally earn a return for shareholders on demand side resources, but rather supply side resources, they have a lower priority.
As an alternative to establishing an energy efficiency budget, state legislatures could simply incorporate energy efficiency as a resource and instruct utilities commissions to pursue all cost-effective energy efficiency, require that alternatives to generation are evaluated prior to approval to build new generation, or include a budget for energy efficiency (perhaps including an energy efficiency resource standard or target of savings from efficiency) in the utility’s resource planning process.
Energy efficiency is often considered an objective of our public utilities, yet, there may not be a real incentive to the utility to make their consumers more productive or efficient users of energy because that means lower sales and reduced revenues.
If legislatures want to ensure a more productive and efficient system that takes advantage of the latest technological innovations, they may want to require that a utility demonstrate a percent reduction in demand through efficiency programs or “demand side” programs. This is considered an Energy Efficiency Resource Standard (EERS) – for example: a regulated utility will achieve a 10% reduction in projected demand over the next 10 years.
While our economy is getting more energy efficient as technology improves, a recent study by the American Council for An Energy-Efficient Economy (ACEEE) shows that states with an EERS achieved 1.2% electric savings per year while states without an EERS averaged just .3%. This translates not only to reduced pollution, but reduced costs for the consumer as well. Furthermore, ACEEE’s Big Savers report shows that, in terms of efficiency, all of the highest performing utilities are in a jurisdiction with an EERS.
An EERS establishes a percentage of energy demand reduction by a specific date or on an annual basis that a utility will achieve through demand reduction programs. The achievement of these targets is usually mandated and enforced through the utilities commission.
Currently, there are 26 states with an EERS for electric utilities; 15 states also had standards for gas utilities. In 7 states, the standards included a requirement that the utility achieve all cost effective energy efficiency.
Most states have found that anywhere from 1%-3% per year is available in energy efficiency savings. Other states simply set a percentage by a specific date (e.g.: 10% by 2020) and allow the utilities commission to establish a schedule to meet those established savings. Many states will conduct a “Market Potential Study” to determine the level of efficiency that is economically achievable each year prior to setting their targets.
In a recent evaluation of compliance strategies for the Environmental Protection Agency’s (EPA) Clean Power Plan in Western states, those plans that incorporated energy efficiency were shown to save consumers money - with the most significant impact occurring when states achieved a 2% annual savings target (See Figure 1.15, scenario EE2).
In a few states, energy efficiency savings are allowed to be counted toward a portion of the Renewable Portfolio Standard. However, this approach reduces market certainty for both energy efficiency and renewable energy.
Energy is a significant portion of the average low-income household’s annual budget. In fact, a recent study shows that low-income households spend, on average, more than twice the percentage of their income on energy costs as median-income households. Still, many low-income residents live in homes with substandard insulation and inefficient appliances, windows, and lighting. Because of these inefficiencies, low-income households are spending more than they need to on energy, taking away from other household needs.
The low-income community is an attractive target for government sponsored weatherization programs because these residents are often participating in other assistance programs. By increasing home efficiency, expenses associated with energy use are decreased, which can potentially reduce reliance on public assistance and increase spending in other sectors of the economy.
While low-income families are excellent candidates for cost effective upgrades, there are sometimes structural issues that need to be addressed that can impact the overall costs of the program. For this reason, many states will waive or modify existing cost effectiveness requirements for low-income program improvements. Low-income populations have been a difficult group to reach because they may lack liquid capital, generally have lower than average credit scores, and have lower participation rates in activities that are the focus of standard avenues of marketing.
The federal government runs the Weatherization Assistance Program (WAP) out of the Department of Energy. There is also a Low-Income Heating and Energy Assistance Program (LIHEAP) out of the Department of Health and Human Services which provides cash assistance to those low-income families that need assistance in meeting energy costs. Over $6 billion per year is spent on cash assistance. The weatherization program is seen not only as a way to reduce the energy bills of a low-income family, but also as a way to reduce the costs to the federal government of cash assistance programs (or to allow the existing funding to assist more families). Bill assistance helps people pay their bills in the short-term, but weatherization programs lower energy costs for the long-term.
The federal WAP program comes with some limitations on deployment. For example, states may not contract with for-profit entities. There are also limitations on the types of investments a state may make. Furthermore, the contractors for low-income services are only allowed to provide weatherization services to homes that apply and qualify for assistance. This may reduce opportunities for economies of scale, and decreased costs for everyone, when many people in a neighborhood could receive efficiency upgrades at the same time. As a result, the program can be inefficient in maximizing the deployment of energy efficiency across low-income households, particularly when trying to address challenges specific to a region or community.
With the addition of dedicated state funds, the state can leverage the resources of the federal program while expanding offerings.
The state might run a “neighborhood sweep” program in the neighborhood of a qualified WAP recipient. This type of program can leverage the infrastructure of delivering weatherization services to a neighborhood by signing up more homes than the weatherization program has targeted. Much of the cost of delivering services in a weatherization program is simply getting the crew to the house. A neighborhood sweep program can achieve economies of scale and drive down the cost per house by expanding the pool of residents receiving efficiency upgrades in a neighborhood. Non-federal funds may be used for outreach and for deploying services to homes in the neighborhood that do not qualify for federal assistance.
The state could also use a low-income fund to provide additional measures, those that are outside of the WAP allowable expenditures, to existing WAP recipients. Such measures could include renewable energy installation or ownership in a shared renewable facility that would further reduce the occupant’s energy burden.
If there is a waiting list under the federal WAP program, state funds could be used to target specific weatherization services to reduce the wait time. This may be done in conjunction with the streamlining policy described below. Such funds could be established through policy either as a utility ratepayer-funded program or through dedicated state revenues.
States may establish policies to streamline or facilitate enrollment in the low-income weatherization program. Historically, the WAP program only serves those who expressly fill out an application and request weatherization services. However, states use similar qualification criteria for more widespread programs such as food stamps. A state policy to streamline enrollment would automatically enroll any enrollee in other low-income assistance programs into the WAP program - or at a minimum, sign them up for an energy audit that could then be used to enroll them into the program if it were deemed appropriate. A more scaled back version of this program would focus automatic WAP enrollment on those who receive cash assistance through LIHEAP. By signing people up for weatherization, the state can not only decrease utility bills for the low-income customer but also free up LIHEAP funds to serve more people. A range of policies have been pursued to address these barriers toward expanding access to energy efficiency and renewable energy for the low income population.
Most states include some kind of “cost effectiveness” criteria for investment in energy efficiency. This is to ensure that any investments utilities make in efficiency measures are less expensive than the costs of generation and infrastructure they are reducing. The majority of the states that have these tests have adopted the 2001 California Standard Practice Manual: Economic Analysis of Demand-Side Programs and Projects’ “Total Resource Cost Test” (TRC). Stated simply, the TRC test is a measure of the total program benefits divided by the total program costs, but importantly, while the TRC looks at the benefits to the utility, it counts both rate payer-funded incentives and individual customer costs as the “total cost” in determining cost effectiveness. In effect, a utility is evaluating “total” (participant and utility) cost as a measure against utility benefits to determine whether an efficiency investment is cost effective. This disassociation within the cost-benefit equation eliminates many investments the utility could make through programs that would lead to cost effective savings, but are excluded because they don’t pass the TRC test.
As a result, many states are re-evaluating their energy efficiency cost tests used to make a determination of cost effectiveness.
“Cost Effectiveness” is a worthy goal of any program, but a key consideration for states is the way in which cost effectiveness is calculated.
Most states use the TRC, which includes the cost not only to the utility in offering the program, but the total amount of money the individual spends on the entire measure for their home - they then compare those total costs to the energy savings received by the utility.
A recent analysis by The Cadmus group suggests that applying the TRC exclusively may not fully reflect the benefits to the utility and customer. The Cadmus group proposes testing demand-side management (DSM) programs with the TRC when compared to supply side resources, and testing programs with the Utility Cost Test (UCT) to determine approval for cost recovery. In this way, only the costs to ratepayers would be considered in determining the application of ratepayer funds, not the cost to participating customers, allowing for small ratepayer-funded incentives to stimulate investments by program participants. Cadmus further argues that participation rates by customers are a better metric of whether, from the customer’s perspective, the benefits outweigh the costs to participate in a given program.
The goal is to make a cost effectiveness screening as balanced as possible so all programs and technologies that can provide a benefit to the utility customers are considered and not rejected because of a lopsided testing regime.
States throughout the country are recognizing that investments in energy and water efficient buildings, operations, and fleets save the state money over the long-term while providing myriad environmental benefits. As a large energy user, the state can also help to attract industry and investment while reducing long-term risk and costs by setting strong goals for increasing the use of energy efficiency, renewable energy, and alternative fueled vehicle technologies in state operations.
These “Lead by Example” programs are typically set out in legislation or by an executive order that directs units of government to meet certain targets related to energy and/or water consumption in conjunction with directives that state owned buildings will achieve a certain Leadership in Energy and Environmental Design (LEED) score or some other performance benchmark. These directives may instruct agencies to work with Energy Service Companies on upgrades to existing buildings (see Section 5.3 for more information on Energy Savings Performance Contracting). In the case of renewable energy, state agencies might be directed to install certain technologies on state-owned buildings or to source a certain amount of their average energy use from renewable resources.
Energy and water efficiency programs typically set procurement requirements for efficient appliances and set minimum building standards for new or remodeled state buildings. They may also set a target of a percentage reduction in consumption by a specific date without specifying the mechanism for achieving those reductions. Typically, this type of approach will be combined with the establishment of an interagency committee that will oversee the development of approaches to achieve reductions, issue status reports, and evaluate mechanisms to standardize measurement practices.
In the transportation sector, policy should require that state fleets meet certain minimum requirements related to fuel efficiency or use alternative fuels. Agencies may also be required to submit plans for meeting state goals, provide progress reports on attaining targets, or both. States should be careful when it comes to flex-fuel vehicles, and provide for tracking when the flex-fuel vehicle is actually fueled with an alternative fuel.
Because most states already employ procurement personnel, implementation of a lead by example program is not likely to require hiring additional state employees. Rather, most programs will require a change to procurement decision-making procedures by altering the cost-benefit calculations used in the purchasing process. An agency responsible for overseeing the program should be identified.
Our nation’s transmission infrastructure is considered to be one of America’s great engineering accomplishments. But, while all other industries have transformed in the information age, our utility infrastructure has remained much as Edison imagined it over 100 years ago.
Not only does our physical grid need modernization, we also need to incorporate the digital revolution into the services available both to the utility and its customers. The “internet of things” is a term used to describe the growing interconnectedness of the items we use in our daily lives. While the products marketed directly toward consumers are utilizing the internet of things, utilities are falling behind. For example, we are now able to control our thermostat using our phone, but most of us can’t check our current energy usage or how much our electricity bill is at any given time during the month. We can’t choose options for resources or be alerted if we are approaching our “energy budget.” We can’t use the data generated by our energy use to manage our usage more effectively - or even participate in a dynamic energy marketplace for utility services as energy users and generators.
The smart home is technologically available, but our regulatory environment lags far behind our technical capability. These aren’t difficult concepts to grasp in the 21st century, but policies are necessary to establish the ground rules for a new energy paradigm. This chapter looks at the following questions regarding the role of technology, and the issues legislatures and utilities commissions should consider as they imagine a new age of innovation and services within the utility sector:
- If customers have multiple options to manage their energy usage, what is the emerging role of the utility?
- How does a centralized suite of services for a large electric service territory, overseen by a three or five member utilities commission, intersect with the public’s growing expectation of individualized choices and the entrepreneurial aspirations of service companies designing technology solutions in a fast paced environment?
- How do companies market products and solutions to customers when the utility acts as a gatekeeper for commerce?
- How do we use the lessons of the information age to imagine a new way of driving innovation in the utility sector?
If AT&T or Verizon were responsible for providing all the services in a smart phone, as approved by a utilities commission, would we have the range of individualized applications partnering with the innovative expansion of smart phone capabilities to solve the challenges of daily life? Or would we just have a phone?
Many states and utilities are investigating the smart grid as a mechanism for improving utility performance. However, much of the realization of the potential for improving service to customers relies on an active private sector developing applications targeted at increasing consumer value. If the market is to effectively find a willing buyer for its services, they must have access to that customer, and be able to enter into a direct agreement with the consumer. This is where the question of customer data access becomes a relevant issue.
Access to consumer usage data is key to spurring this third-party marketplace. Providing for third-party access to timely and detailed customer data is a low- to no-cost method for expanding the energy efficiency marketplace.
Green Button Connect is one application that enables developers to access consumer energy data in a secure and streamlined manner. As an added advantage, the application allows instantaneous access and does not require that the customer approve every energy data transfer. Green Button Connect improves the ability of energy service providers to retrieve and analyze energy data which assists consumers in becoming more energy efficient.
Green Button Download allows a customer to download their data for either their own use or to transfer to a third-party. The transfer is not automated and requires a repeated authorization of transfer from the customer, so much of the benefit of automated program offerings and timely transfer of data is lost in the process.
Policies for allowing third-party access to consumer data may either take the form of ownership or permission. In the former, legislation would establish that all information related to consumer energy use or signals provided by the utility are the property of the customer. By doing this, the customer is the sole owner, and thus, the controlling entity of this data. This doesn’t mean that the utility would lose access to the customers’ data. For example, legislation could include a provision saying that an agreement with a utility to provide service to the customer releases access to all data owned by the customer to the utility.
A second approach would be to specifically state that the customer has sole authorizing authority to release data to a third-party through a standard agreement. This would not get into the “data ownership” question, but would instead enable the customer to give permission to a third-party to access any relevant data. If the customer is given authorizing authority, it is important that the utility is not placed in a position of approving either data transfers or service providers. The objective of this policy is to open the marketplace between service providers and customers.
Once authorization is granted (either through ownership or permission), the third-party should have direct access to the highest possible resolution interval data available - for example, 15 minute or 5 minute periods. This allows the marketplace to directly innovate automated products in support of a variety of customer services. Any data access policy should include clear privacy provisions that are based on the existing Fair Information Practice Principles:
- Notice / Awareness;
- Choice / Consent;
- Access / Participation;
- Integrity / Security; and
- Enforcement / Redress.
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Energy storage offers a unique opportunity to dynamically manage supply and demand to maximize the value of grid resources. By deploying storage in strategic locations, utilities can more effectively manage their energy portfolios.
First, storage can dispatch power in such a way that better integrates intermittent resources like renewable energy. Second, it provides management of intermittent demand – helping to flatten peak demand requirements for the utility. Third, the quick response of energy storage can allow the utility to implement voltage regulation and other ancillary services, useful for improving system efficiency.
Finally, energy storage can help the commercial sector avoid costly “demand charges” sometimes implemented by utilities. Demand charges establish an incremental cost above energy usage based on the highest period (highest 15 minutes, for example) of demand during the month. Eliminating spikes in demand with storage can reduce these costly charges for businesses. This is becoming an even more important issue as utilities around the country are considering extending demand charges to the residential sector.
Storage provides multiple benefits to both the customer and the utility. State regulatory policies can help maximize these benefits through a combination of 1) establishing a framework for easy integration of energy storage into the grid and 2) establishing a marketplace that monetizes the benefits of energy storage for cost-effective investment.
Deregulated markets may have an additional challenge if storage is defined as “generation” because “wires-only” utilities may be prohibited from making investments in generation. In some cases, utilities may be permitted to own the assets, but only use them for specific purposes. This limits their cost-effectiveness because services with value that can be provided by energy storage are not permitted services from the utility. In these instances, a state might consider a “sharing” arrangement between the utility – which can derive direct distribution benefits of energy storage – and a third party that can monetize other services within the market for ancillary services, demand response, or energy dispatch.
Energy storage can be described in two ways: power capacity and duration. Power capacity is expressed in kilowatts (kW) or megawatts (MW) and duration is expressed in hours. As shown in Figure 2.6, above, different energy storage technologies, because they vary in terms of capacity and duration, provide different benefits and services to the system. This is important when looking at potential applications of energy storage technologies. Storage has distinct roles when providing services on the utility’s side of the meter or on the customer side (behind the meter).
Integrated Resource Plans (IRPs) have historically evaluated larger transmission and grid investments in infrastructure and generation. In general, utility commissioners have not exercised a great deal of oversight of the distribution system. However, as we increase the intelligence of our grid, enable distributed generation and storage systems, and facilitate two-way communication in the distribution system, distribution planning is becoming more critical to long-term utility planning. Commissions can instruct utilities to submit distribution reports in conjunction with their IRPs to demonstrate how they will integrate distributed energy resources (DERs) onto their distribution system – including an evaluation of how an increasing level of DERs may help to defer or avoid traditional investments.
IRP or DER planning requirements could be structured in a manner that requires or encourages utilities to consider the following recommendations for addressing the “Duck Curve” from Jim Lazar’s (of the Regulatory Assistance Project) “Teaching the ‘Duck’ to Fly”. First, utilities should address how they will acquire energy efficiency and demand response measures that will provide savings during peak demand. Second, and in a similar vein, utilities should evaluate the acquisition of renewable resources that can be dispatched and controlled to meet peak demand. This would include solar thermal and storage hydro facilities. Third, utilities should re-evaluate rate structures to encourage water pumping (for example for irrigation) during periods of low load or high solar output. Fourth, in a similar manner, utilities should explore time-of-use rates and other rate designs that employ price signals to shift load. Fifth, utilities could explore incentives to expand storage opportunities in space and water heating and cooling (see below). Sixth, utilities could explore the use of inter-regional power exchanges that would allow them to take advantage of a more diverse set of loads and resources. Seventh, utility plans should identify and outline proposals for retiring generating plants with “high off-peak, must-run requirements.” Lastly, as this section focuses on, utility plans should investigate optimal locations for the placement of energy storage resources.
Distribution planning should also include evaluation of electric vehicles and thermal storage. Initially, there was a great deal of discussion around V2G or “Vehicle to Grid” services – where a utility would be able to pull power from an electric vehicle as it sat at a charging station overnight or during the day while the owner was at work. However, vehicle manufacturers do not like to maintain battery warrantees in those conditions. The V2G market has largely moved to the smart charging market - one that gives utilities more control over the charging units attached to the vehicle (see more about electric vehicle policy options in Sections 3.1 - 3.3). Thermal storage can be advanced through smart space or water heaters (for heating) or chilled water storage (for air conditioning). These applications allow utilities to intelligently push power to these units at times when they need to shed load in exchange for pulling back power at times when they have peak load.
Energy storage technologies offer multiple benefits and services – but only if those services can be monetized in the marketplace. Rate structures are one primary way to provide a transparent monetization of the ability for a customer or a utility to manage load through energy storage. This includes time of use rates that are dynamic based on market rates driven by demand, or peak/off-peak rates that reward customers for shifting their demand to times of off-peak with lower rates. Demand Response programs also provide a mechanism for the monetization of the benefits of energy storage (see more about demand response in Section 1.5). Utilities commissions can include a quantification of the value of energy storage from the perspective of avoiding building of excess generation for peak load, spinning reserves, or frequency regulation.
Policymakers should first focus on the foundational policies that allow storage to be integrated into the energy system. The recommendations below draw heavily from an excellent 2017 report by the Interstate Renewable Energy Council (IREC ) called “Charging Ahead – An Energy Storage Guide for Policymakers.”
The electric grid is a complex system of generation, transmission, distribution, and demand. Not only is this infrastructure aging, but recent advances in technology also mean that the electric industry is undergoing a major shift in the manner in which electricity is produced, delivered, and used. High quality and reliable electricity is required to support the transition to a digital economy. Emerging physical and cyber security threats, along with increased demand for faster outage response times, require, at minimum, real-time incident response capabilities. Enabling the integration of energy efficient and clean energy technologies like distributed generation, utility scale renewable resources, and electric vehicles, will create resilient and clean electricity. Increased grid penetration of renewable energy coupled with the adoption of advanced metering, energy storage, microgrid, and other technologies to modernize our electric system, will provide economic benefits, increased security, and more reliable, resilient, and clean electricity. However, this next level of innovation requires a large investment in improving grid technology.
The electric utility grid is one of the last components of our society without robust digital data capabilities.
In the last two decades, digital technologies have been developed that enable utilities to better manage the grid and also provide opportunities for consumers to customize their energy services to fit their priorities. These technologies allow a two-way flow of information between both the electric grid and grid operators, as well as between utilities and their customers.
Emerging technologies improve system reliability and resiliency by enabling better tracking and management of resources. These technologies allow grid operators to incorporate central and distributed energy resources, energy storage technologies, electric vehicles, and assist in addressing the challenges associated with planning, congestion, asset utilization, and energy and system efficiency. This can make the operational side of the utility more efficient.
On the customer’s side of the meter, advanced metering infrastructure, dynamic pricing, and other emerging technologies allow an exchange of information and electricity between a consumer and their electric provider. Grid modernization is associated with greater consumer choice, allowing customers to meet their energy priorities by producing their own energy or selecting to receive innovative energy efficiency or other clean energy services from different providers.
Dynamic metering ability allows the utility (and the commission) to consider strategies like real time pricing. The ability to price power on a real time basis can avoid cross-subsidization issues that are inherent with flat pricing schemes and also enable customers to take greater control of their energy usage in a way that will benefit the entire system. It also provides utilities and regulators with more tools for tracking energy trends and considering a wide variety of options to meet utility system challenges.
Grid Modernization efforts compliment other policies such as those addressing demand response, customer data management, smart metering infrastructure, electric vehicles, and other technologies. Policy approaches for grid modernization should be seen as a platform that support and tie together these other policy initiatives.
Advanced metering technologies or “smart meters” are meters, or a system of meters, that transmit energy usage information from residential or commercial customers. The data transmits in various time increments, from minutes (high resolution) to hours or days (low resolution). The higher the resolution of the data, the more valuable the information is to the customer or the utility.
High resolution data from advanced metering infrastructure (AMI) enables utilities and third-party providers to gather energy usage trends, identify outages, and implement and track energy efficiency practices, all without having to physically go to a site to read a meter - increasing efficiency while decreasing cost. The dynamic nature of the data allows for rate structures that send pricing signals to customers to promote particular energy practices that are desirable to the utility or the public. It also allows third-parties to market energy information and management services to customers - if policies are in place to support such a market.
Over the last decade, smart metering technologies have proliferated across the country as more and more utilities have begun viewing smart metering as a way to increase efficiency and decrease costs, both for their customers and themselves. Smart metering has been used to facilitate demand response programs, to evaluate, measure, and verify energy efficiency project performance, and to develop and analyze energy trends within a specific region or sector. Smart meters can enable a customer to see real time energy consumption and cost in a way that engages them directly with their energy use, can help them identify sources of high energy use, and lead to greater efficiency. On the utility side, technology to manage resources (including central, distributed, and demand-based) can make the operational side of the utility more efficient. The capability to price power on a real-time basis can avoid cross-subsidization issues that are inherent with flat pricing schemes. It also provides regulators with more opportunities for tracking energy trends and evaluating a wide variety of options to meet utility system challenges.
In order to fully capitalize on the cost savings of AMI technology, customer data should be presented to the customer in a clear and concise manner so that it is easy for them to understand their energy consumption and compare it to those around them. Third-party organizations can facilitate this understanding, but must be authorized to access customer data. It is important that states adopt policies that clarify the process and authorization for access to this data as well as ownership of the data. States and utilities should work to ensure that private customer information, such as billing information, is stripped from the energy usage data when it is shared with a third-party. Policymakers should ensure customers are able to authorize access to the data without approval or authorization from the utility.
While many customers see the benefit of using a smart meter system, there is a small cohort of consumers who prefer analog metering. There are many states that allow these customers to opt-out of smart meter programs; but in order to make up for the costs associated with utilizing an analog meter, customers are required to pay a fee. This is not a recommended approach because individuals may choose to opt-out for many reasons, including those beyond their control.
Time varying rates, or tariffs, provide transparency to utility customers on the differential between wholesale energy costs and retail costs at a given time of day. In general, the wholesale price of electricity is higher during times of high demand (often late afternoon/early evening) and lower during times of less demand (late evening and early morning hours) – following traditional market forces. Historically, the regulatory regime has shielded the utility customer from these market fluctuations, with energy users at low cost times of the day subsidizing energy users at the high cost times.
In addition to the daily fluctuations in demand, there are seasonal fluctuations (for example, high air conditioning demand causes a seasonal spike in demand). Utilities have traditionally had to build to these “worst case scenarios” - a supply side response to potential demand spikes.
Traditional, flat rates do not provide any direct signal or transparency to customers on when electricity is in high demand and therefore expensive for the utility to generate. Voluntary time varying rates are a critical piece to utilizing the energy market to engage customers with their energy use and recover costs for expensive peak generation.
Time varying rates generally rely on market forces to influence customer behavior and create the opportunity for arbitrage on the part of the customer or a system aggregator to fully capture the value of efficiency or distributed resources.
All electricity doesn’t cost the same, and price tends to follow basic economic principles of supply and demand. When demand is highest, the cost of the supply is also high. Reflecting these market forces within rate design can facilitate cost reduction across the rate base by minimizing demand at times when the cost is the highest.
As the Edison Electric Institute points out in their paper, “Future of Retail Rate Design”: ”To promote efficiency, regulation favors rates that convey ‘proper price signals;’ that is, prices which accurately reflect the costs incurred to serve customers”.
In their report on rate design, the Regulatory Assistance Project (RAP) has summarized the following options for varying rates:
Time-of-Use (TOU) Rates employ Off-Peak and On-Peak (and sometimes Mid-Peak) pricing. This is the simplest form of time varying rate.
Critical Peak Price (CPP) Rates are more pronounced than TOU rates in that they enable the utility to establish a certain number of “event” or “control” days (10 days per year from 2-8pm, for example) during which demand is expected to be very high. These event days tend to be declared by the utility 24 hours in advance. Because the cost of electricity during event days is considerably higher, CPP can be much more effective than TOU at reducing peak demand. However, the risk of customer bill shock is also greater.
Peak-Time Rebates (PTR) are similar in design to CPP, though instead of a higher rate, customers are given rebates for saving during those times. Some have referred to PTR as “training wheels” for CPP. Since there is no rate impact for inaction on an event day, the consequences are lower. Customer behavior change on PTR tends to be less than CPP, though the barrier to entry is lower.
Real Time Pricing (RTP) is the most sophisticated of the four rate types in that it requires real time pricing and usage data on an interval (15 minute) basis. Since the data requirements and customer engagement are high with RTP, this rate is typically only offered for large commercial and industrial customers. However, when combined with grid modernization elements and advanced metering infrastructure, this type of sophisticated system not only best reflects the dynamics of the energy market, but also facilitates advanced information technologies to manage the energy uses of the customer and opens a new commercial marketplace for energy services, especially in the largely untapped residential market.
It is important to note that not all time-varying rates are created equal in the level of policy effort to create them, the level of required customer engagement to make them work and, perhaps most importantly, their potential to reduce energy consumption, particularly at peak generation times. Figure 2.12 illustrates this continuum.
The Regulatory Assistance Project seeks to weigh the concerns on both sides of the regulatory divide that have emerged between utilities and the distributed generation industry. In their paper, “Smart Rate Design for a Smart Future”, they outline some of these principles.
A comparison of some of the Solar Energy Industries Association (SEIA) and Utility areas of disagreement and agreement are discussed in the above figure, as well as RAP’s proposed approaches to address the areas of disagreement and programmatic recommendations.
The information revolution that has transformed virtually every industry in the world is just beginning to touch the energy world - and when it is fully implemented, the potential impacts are substantial. The policies in this section discuss policy opportunities to set the stage for this transformation. For example, as the consumer is empowered to make energy decisions, generate electricity, dynamically manage load, and perhaps arbitrage energy for compensation from the utility, how does the traditional utility business model change? We have explored de-regulation of the generation side of the utility model, but what about the consumer side? As more services are developed for the consumer, opening this market to the private sector may offer opportunities for economic development as well as new avenues for energy conservation and distributed generation. The traditional utility rate structure is not very market friendly, contains multiple cross-subsidization issues, and doesn’t reflect the actual cost of resources, or appropriately value the relative benefits. Using new technology, there are now options for better reflecting these market forces.
NEW UTILITY BUSINESS MODELS
Utility regulation varies, to some extent, by state utilities commission. Most Commissioners and commission staff, however, still adhere to the now nearly sixty year old regulatory principles outlined by James Bonbright in his seminal text, Principles in Public Utility Rates (1961). At the writing of Bonbright’s text, most utility companies were vertically integrated, were experiencing increases in load, and had the ability to capitalize on economies of scale for new generation. These “natural monopolies” warranted a state regulatory body that could balance the tradeoff between efficiency (in the form of least cost production) and equity (consumer protection).
Historic electric and gas utility regulation could be characterized as somewhat simplistic in its backward accounting, heavily grounded in principles developed in the era of load growth and large central generation – a time before Energy Efficiency Resource Standards (EERS) or Renewable Portfolio Standards (RPS). Many have argued recently that the regulated utility industry needs a new set of principles that are far more sophisticated, more forward planning, and more incentive based.
In a conversation about the role of state policy in 21st century utility regulation, it is helpful to define the boundaries. Energy “policy” and “regulation” often tend to focus on the investor-owned utilities (IOUs), which supply the majority of the market with energy. Most public power entities (municipals, cooperatives, and subdivisions) are typically exempt from commission jurisdiction, yet these utilities are heavily influenced by the market structures established for the regulated utilities and many legislative policies are equally applicable to all utilities regardless of their governing body.
State efforts to reform the current regulatory construct have taken many forms, the most high profile of which are underway in Hawaii, New York, and Massachusetts. A concise summary of 2014 state utility business model initiatives was compiled by Advanced Energy Economy and can be found here.
In terms of the actual policy changes being proposed, some of the concepts that have emerged are focused on regulating and rewarding utilities based on their performance against certain metrics, rather than the traditional rate of return based on spending. Performance Based Regulation (PBR) was developed by the utility regulator in the UK – the Office of Gas and Electricity Markets (Ofgem). Ofgem has implemented the RIIO Model (Revenue = Incentives + Innovation + Outputs) for the regulated utilities in the UK. Many states are looking at how to adapt this model for the US.
Because utilities commissions generally fulfill state statutory directives, legislatures may want to use policy to direct the commission to open an investigatory docket with the purpose of examining potential new utility business models. The legislation should identify the public objectives that would be incentivized through a new business model for utilities and direct the commission to identify ways in which to align the utility’s financial incentives with public policy objectives.
OPENING COMPETITION FOR CUSTOMER ENGAGEMENT
While a number of states have opened the generation side of the utility structure to competition (retail choice states), this proposal considers opening the customer side of the utility system to market competition - including customer engagement, billing, and service.
The business model utilities commonly operate under is one that is heavily focused on investment in generation resources. Utilities have historically been guaranteed a customer base in exchange for operating under a regulated regime that offers them an established rate of return on investments, collected through customer rates.
Some states have “de-regulated”, or opened to retail competition, the provision of utility generation services - allowing customers to contract directly with energy providers that offer them the best rates and resource mix.
While this has driven competition on the generation side of the energy system, the customer side has remained within the domain of the utility service provider.
When viewed through a regulatory lens, customer services such as financing, smart metering, and efficient appliance solutions, and energy data management require a lengthy regulatory approval process, consistency of offerings across the state and, if they are to be embraced by the utility, need to meet the utility’s objectives (including a return to their shareholders). This represents, to a great extent, what the utility and regulators believe the customer wants. This is the opposite of the emerging paradigm in other sectors of individualized customer driven marketing and product deployment.
As our electric system moves into the information age with data capture through advanced metering infrastructure (AMI) and smart appliances, a market is opening up for energy management through data analytics. Terra-watt hours worth of demand management is available for a competitive market if the regulatory conditions are supportive of such a market.
Establishing this market requires existing advanced metering infrastructure (AMI) that is capable of freeing the customer to pursue advanced service offerings using energy data. This policy would allow third-parties to contract directly with customers to provide services that utilize energy-use data to maximize customer energy efficiency, manage demand-side resources, and meet consumer needs. The third-party would be authorized to serve as an intermediary between utility billing and the consumer – allowing the utility to continue to earn their established rate on the power they sell to the customer.
By serving as an intermediary between the utility and the customer, the third-party would be able to both reduce the customer’s bill with demand side resources and reduce the power purchased from the utility - the delta between the two can be used to finance the purchase of installed equipment while earning a profit. The more innovative and effective the resources they provide, the greater the earning potential.
However, there are infrastructure components that need to be in place for such a paradigm shift to occur. We discuss a number of these factors in Section 2.4 on grid modernization, but in a nutshell: AMI to communicate the data, and rules that empower customers to authorize third-parties to access their energy data at a high resolution (explained in Section 2.2 on Customer Data Access).
REGULATORY-FUTURE TEST YEAR
Regulated investor-owned utilities typically operate under a regulatory compact: In exchange for investing in generation, transmission, and distribution infrastructure, and for managing the grid to ensure reliability of service, they receive an established rate of return on their investments combined with a monopoly on the customer base. The rate of return on equity is recovered from customers through their rates.
Investment and return decisions are traditionally based on taking a representative sample of 12 months in the utility’s history - a “Historic Test Year” - to anticipate energy demand and utility performance. Any future investments in technology or programs that are a diversion from the historic test year suffer from a regulatory lag in recovery – that is, the utility makes the expenditure, then, in the next rate case, looks backward for rate compensation. This legislation would shift from a historic test year to a future test year.
Utilities see two major advantages in this type of change: First, a reduction in regulatory lag in recovery for future investments that have little corollary in the past; and, second, increased opportunity to earn the authorized rate of return. Critics of a Future Test Year argue that it is difficult to make a “just and reasonable” determination on an investment that has no historic analogue.
Policy change may occur through legislative authorization to the public utilities commission (PUC), or its equivalent, to examine the implementation of a future test year.
Alternatively, PUCs can be directed by the legislature to implement a future test year in order to stimulate specific policy objectives. For example: Build out advanced metering infrastructure, expand customer-sited renewable thermal technologies, or expand energy efficiency programs.
The objective of such a change is to provide utilities with the opportunity to reduce regulatory lag in making investments that will modernize infrastructure, improve system performance, and expand customer services.
The last Environmental Protection Agency’s (EPA) emissions report lists the transportation sector as the second greatest source of greenhouse gas emissions in the US, accounting for 27% of all US emissions (see Figure 3.1). However, with declining emissions from the electric sector, indications are that in 2016, the transportation sector passed the electric sector as the greatest source of greenhouse gas emissions (see Figure 3.2). Policies to reduce these emissions are a critical component in any energy strategy that seeks to reduce harmful pollution.
Much of the country’s achievements in reducing emissions from the transportation sector have been through efficiency improvements for vehicles.
National Corporate Average Fuel Economy Standards or “CAFE” Standards were set in the mid-1970s and remained largely unchanged until the Energy Independence and Security Act of 2007. The Act raised CAFE Standards to achieve a 40% improvement by 2020. The legislation was passed with broad Congressional support and signed by President George W. Bush. A negotiated agreement between the Obama Administration and the large automakers in 2011 resulted in another increase to the standards. These new standards should lead to a doubling of fuel efficiency (54.5 MPG for passenger cars) by 2025 (see Figure 3.3). However, in March 2017, President Donald Trump announced that he was ordering the EPA to review these standards. At the time of this writing, however, no further action had been taken.
While these changes are happening at the Federal level, states are also empowered to reduce emissions in the transportation sector, and do so by providing incentives and infrastructure related to advanced vehicle technologies. Electric vehicles (EVs) enjoy strong Federal tax incentive support, and 35 states also provide tax credits that drive growth in the EV sector.
A statewide charging plan would assist any state in driving EV adoption. Such a plan would be beneficial to prepare the state for investment in charging infrastructure. Development of this infrastructure would address a key barrier to EV adoption: consumer range anxiety. Put simply, consumers want to be sure their car will get them where they need to go. Technological innovation is dramatically increasing the range capabilities of electric vehicles: the most recent GM Bolt has an estimated range of 240 miles - twice that of the Nissan Leaf.
While gas vehicles fuel up when they are going somewhere, electric vehicles fuel up when they are stopping somewhere. Most EV charging is done in one of three places: Home, Work, or “Public Hot Spots”. Government policies are generally focused on these areas.
Workplace charging can promote the use of EVs to cut down on the emissions associated with commuting. Tax credits for home charging units also incentivize EV owners to install or upgrade charging infrastructure and, in a modernized grid environment, can be used to schedule charging at times when it is most beneficial to the electric grid.
There have been great advances in ethanol (E85) fueling infrastructure through a federal program run by the Department of Agriculture to expand E85 fueling infrastructure. The state of Texas has established an Alternative Fueling Corridor to build out natural gas fueling infrastructure. Other states have focused on fleets and large industrial vehicles, particularly those in the Natural Gas extraction industry.
A provision in the Clean Air Act allows states to adopt one of two standards - the federal emissions standards or the Zero-Emissions Vehicle (ZEV) standards adopted by California. As of 2016, there were 9 states that had adopted these ZEV standards. More discussion on how states can adopt ZEV standards is found in the Emissions Chapter (Section 6.6).
There is a great deal of debate regarding the impact of alternative-fueled vehicles (AFVs) on greenhouse gas (GHG) emissions, and in many cases it depends on the state. For example, EVs move the emissions profile from mobile source (each individual vehicle) to the stationary source emissions of the power plants providing the electricity. As these emissions get cleaner, the associated emissions of the vehicle will also get cleaner. In a state with very low GHG emissions associated with their electric sector, these GHG savings will be significant; in other places, the savings will not be as great.
With natural gas-fueled vehicles, the savings may be more elusive. As with traditionally-fueled vehicles, natural gas vehicles are mobile sources of emissions. They generally will emit lower levels of carbon dioxide and criteria pollutants than a traditional vehicle. However, when run through the GREET model from the Argonne National Laboratory, which looks at the lifetime emissions associated with natural gas, upstream methane emissions limit the GHG benefits as methane is a much more potent GHG than carbon dioxide. Some studies show a net savings and others show no savings depending on the levels of methane emissions assumed in the life cycle. A result of a comprehensive study of vehicles, which was supported by Oakridge National Laboratory in 2014 is shown in Figure 3.5.
There are wide ranging results in studies of the level of methane emissions associated with natural gas production, so the assumptions used in any model of the emissions associated with natural gas-fueled vehicles may vary. A slightly higher assumption of fugitive methane emissions eliminates the climate benefit, while a slightly lower estimate will show a clear benefit. It should be noted that newer diesel engines are operating at much higher efficiency and may prove a better climate solution than a conversion to natural gas.
Increasingly, states are adopting stricter production regulations to limit methane emissions, so these associated emissions should decrease over time. However, it is difficult to determine the GHG benefits provided by a natural gas-fueled vehicle over a traditionally-fueled vehicle.
One of the most important barriers to increased adoption of alternative-fueled vehicles (AFVs) is their sometimes higher upfront cost as compared to a similar traditionally-fueled vehicle. Also, because they are new and operate differently from conventional vehicles, many consumers are hesitant to spend the substantial upfront money required to purchase an AFV when they can stay with something they know and are used to. Consumer anxiety about these costs can be ameliorated through a range of state policies that provide financial incentives for the purchase of AFVs. Incentives can also be employed to support the conversion of existing vehicles to alternative fuels.
Tax Credits - Sales and income tax credits are one of the simplest methods for addressing higher upfront costs. While sales tax credits are typically applied at the time of purchase, income tax credits may do less to address the upfront cost barrier as receipt of the credit is typically removed in time from the purchase. This can be addressed by making the tax credit “transferable”, allowing the vehicle buyer to transfer the tax credit to the dealer in order to decrease the upfront cost.
A study by the Congressional Budget Office suggests that tax credits are important tools for ensuring increased adoption of AFVs. States may also choose to reduce licensing or registration taxes or fees for AFVs.
The Federal Government also provides a tax credit for AFVs. For electric vehicles, this is $7,500 (depending on battery size). Because the credit is transferable, dealers will often monetize this tax credit in the form of a reduced purchase or lease price for the consumer – immediately reducing the customer’s upfront cost.
Grants, Rebates, and Vouchers – Grants, rebates, and vouchers are the most direct method for addressing the upfront cost barrier. While grants and vouchers are typically provided for local government fleets, rebates are typically targeted to all consumers. In evaluating whether to use rebates or tax credits, policymakers can weigh the various advantages and disadvantages of each.
With rebates, customers don’t have to wait to receive the incentive, and rebates are available to entities and individuals with little to no tax burden. However, offering rebates or grants has a much higher cost of administration, requires an established budget, and is usually limited by available funds. Finally, funding received through grants may be taxable to the recipient, offsetting the full benefit of the funds.
When using tax credits, the process can be built into the tax code, making administration easier, but more work may need to be done at the front end to ensure the tax credit is easily understood, can be transferred to dealerships, and is structured in a way that benefits the entire tax base.
Loans – Low-interest loans for the purchase of AFVs or conversion to alternative fuels are typically aimed at local governments and school districts. In some states, loans are available to support private fleets. Dealerships usually offer low-interest financing for individuals.
Weight Limit Exemptions – Because they are equipped with natural gas tanks, natural gas-fueled heavy-duty vehicles carry additional weight. Weight limits on intrastate roads may reduce the amount of freight these vehicles can carry as compared to traditionally-fueled vehicles. One method to avoid this disincentive and level the playing field for natural gas is to allow natural gas-fueled vehicles to exceed weight limits.
HOV, HOT, and Parking Incentives – Post-purchase benefits can be attractive to expand AFV ownership. Allowing AFVs to use high-occupancy vehicle (HOV) or high-occupancy toll (HOT) lanes regardless of number of passengers and without paying the toll may make AFV ownership more attractive. Most states require that AFVs using these lanes display a decal or particular license plate; others limit eligibility to certain types of vehicles or to a certain number of vehicles. States can also implement programs to provide parking incentives for owners of AFVs. Typically, these programs provide access to carpool parking, preferential spaces, reduced fees, and/or access to charging or fueling stations.
The relationship between increased adoption of electric vehicles (EVs) and the availability of EV charging stations has been described as a “chicken or the egg” problem. On one hand, consumer range anxiety creates an important barrier to increased adoption of EVs. On the other hand, while greater availability of charging stations would ease this anxiety, the relatively low numbers of vehicles on the road provides little incentive to install and make these stations available to the public. Recent developments, including the development of longer range vehicles and more extensive charging infrastructure (see Figures 3.9 and 3.10) may lead to the reduction of consumer range anxiety.
There are a number of programs that states can adopt to support charging stations.
Development of State Charging Infrastructure Plan – Locating charging infrastructure is different than locating conventional fueling stations. For the most part, EVs are used for commuting and local trips (although this may change with expanded infrastructure and range). Furthermore, while one fuels a traditionally-fueled vehicle when they are going somewhere, pausing at a gas station for the specific purpose of filling up, a driver of an EV is generally looking to refuel when they are stopping somewhere: when going shopping, going into a restaurant, or going to work. Charging infrastructure plans should target these types of locations and attempt to pair the appropriate level of charging infrastructure with a reasonable amount of time a person may be stopped at that location.
Financing and Financial Incentives – The provision of financial incentives and innovative financing options can increase installations of charging stations. States have adopted a number of financial incentives including income and property tax credits, sales tax credits, low-interest loans, grants, and rebates. A handful of states qualify EV charging stations under their property assessed clean energy (PACE) programs.
Building Standards and Codes – Many states and local governments are updating building standards and codes to provide guidance and standards for the installation of charging equipment. Building codes might also be updated to require either higher voltage pre-wiring or the installation of charging infrastructure.
Parking Infrastructure Requirements and Restrictions – Some states have adopted permitting standards for parking lots, requiring, for instance, that for every 100 parking spaces, one EV charging spot must be provided. States have also passed Anti-ICEing Legislation. “ICEing” occurs when a car with an internal combustion engine (ICE) is parked in an EV-only parking space. Some states have passed laws establishing penalties for non-EVs parking in EV-only parking spots.
Rental Properties and Homeowners Associations – Legislation can also make it easier for lessees, renters, and members of a homeowners association (HOA) to install charging equipment. Typically, lessors are directed to allow lessees, at their own cost, to install charging systems. In some cases, lessees are required to maintain additional insurance for the system. Legislation related to HOAs typically directs associations to avoid restrictions that would inhibit the installation of charging equipment.
Utility-Run Programs – Charging rate incentives and time of use rates can reduce the cost of electricity used for charging. Eligibility for a charging rate incentive may be limited to users with a separate meter or with advanced metering systems. Some utilities also offer financial incentives for the purchase of an EV charging system. In some states, enabling legislation may be required to direct or authorize a public utilities commission to allow regulated utilities to offer and recover costs for these incentives.
The Volkswagen (VW) Settlement - In October 2016, the VW settlement for violating vehicle emissions rules was finalized. In addition to the $10B in direct customer rebates, $2.7B was allocated to states to reduce emissions. Of these funds 15% may be earmarked for electric vehicle infrastructure investments (the rest are targeted at NOx reductions in the medium- and large-duty vehicle fleet markets).
Another $2B will be distributed nationally by VW with $800M going directly to California and $1.2B approved by the EPA and delivered nationally. The first investment category includes the planning, installation, operation, and maintenance of the following types of zero-emissions vehicle (ZEV) infrastructure, which must be available to all vehicles, utilizing non-proprietary connectors:
- Level 2 charging at multi-unit dwellings, workplaces, and public sites;
- DC fast charging facilities;
- Later generations of charging infrastructure; and
- Hydrogen fueling stations.
New heavy-duty ZEV fueling infrastructure is also considered an eligible investment in California. Initial plans must be submitted by February 17, 2017.
Federal Congestion Mitigation and Air Quality (CMAQ) Funds - CMAQ funds are available to states and may be targeted toward the development of electric vehicle charging infrastructure. There may be a unique opportunity to pair a request for CMAQ funds with the VW Settlement money and a commitment from utilities to invest in charging infrastructure as a public/private partnership that would leverage the federal investment.
Alternative Fuel Corridors - In 2016, the US Department of Transportation established the Alternative Fuel Corridors network. The program is intended to:
- Provide the initial opportunity for a formal corridor designation now and in the future on a rolling basis, without a cap on the number of corridors;
- Ensure that corridor designations are selected based on criteria that promote the “build out” of a national network;
- Develop national signage and branding to help catalyze applicant and public interest;
- Encourage multi-state and regional cooperation and collaboration; and
- Bring together a consortium of stakeholders including state agencies, utilities, alternative fuel providers, and car manufacturers to promote and advance alternative fuel corridor designations in conjunction with the Department of Energy.
As with electric vehicles (EVs), increased installation of natural gas (NG) fueling infrastructure suffers the “chicken or the egg” problem: while consumer anxiety about the availability of fueling stations creates barriers to vehicle acquisition, the relatively low number of natural gas-fueled vehicles (NGVs) in operation creates uncertainties about return on investment for potential owners of fueling stations. Due to higher fueling equipment costs and fewer original equipment manufacturers, the problem is more severe for NGVs than for EVs. Still, there are a number of programs that states can adopt to support NG fueling infrastructure.
Financing and Financial Incentives – The provision of financial incentives and innovative financing options can increase installations of fueling stations and equipment. States have adopted a number of financial incentives including income and property tax credits, natural gas sales tax credits, loans, grants, and rebates.
Energy Savings Performance Contracting – An emerging method for financing NGV fleets and fueling infrastructure, this model provides opportunities for overcoming the barriers associated with greater use of natural gas as a vehicle fuel. For further discussion, see the Energy Savings Performance Contracting policy overview in Section 5.3.
Utility-Run Programs – Provided by natural gas utilities, refueling rate incentives can reduce refueling costs. Some utilities also offer financing options and financial incentives for the purchase of refueling equipment. A handful of states also allow utilities to provide rate-based fueling stations. Depending on the existing authority of the utilities commission, some states may require enabling legislation to direct or authorize the commission to allow regulated utilities to offer and recover costs for these programs.
State Codes and Requirements – In order to regulate the installation of vehicle refueling equipment, state building codes and contractor certification requirements may need to be updated.
Renewable Energy refers to a naturally reoccurring energy source that can be used to replace or augment traditional energy resources like coal or natural gas. This could be in the form of solar thermal heating, solar photovoltaic electricity generation, geothermal heating, mechanical generation from wind power, or a variety of other resources.
In the US, the most effective policy tool for expanding renewable generation has been the Renewable Portfolio Standard (RPS) - a requirement that over time, a utility will provide a specific percentage of electricity from renewable resources.
However, even this relatively straightforward policy has a number of nuances. How do we define renewable energy? Does the policy only apply to large (utility) scale power? Does it apply to all utilities or only those regulated by the public utilities commission? What are the time frames for compliance? What happens if the utility doesn’t comply?
While RPSs address the large scale implementation of renewable energy, what if someone wants to put solar power on their home or business? How do they connect to the grid? What mechanisms are in place to support investment by private third-parties? How do state objectives align with federal incentives and how do states take advantage of the incentives available to save ratepayers money?
Historically, the public has viewed renewable energy as a more expensive “boutique” form of energy. But as the industry has matured, technology has improved, and global production of generating equipment has increased, renewable energy is increasingly seen as the least cost and lowest risk form of energy (excluding energy efficiency).
With increased deployment, utilities are learning more about how to integrate renewables effectively, investors are becoming more comfortable with the technologies, and building code officials are recognizing common standards and best practices.
Renewables in the US are at a point of transition. In the first quarter of 2016, solar energy made up 64% of new electricity generation. In 2015, 41% of all new generation was from wind. Yet, while this transition is manageable, it requires a different kind of thinking in the regulatory arena. This new approach will require thinking that values the contributions of distributed resources and plans for a future utility design that can accommodate large quantities of intermittent resources.
Within this context, greenhouse gas emissions are now recognized as pollutants by the Supreme Court. As a result, those resources that provide electricity while producing less pollution are going to be an integral part of any future energy portfolio that is attempting to limit pollution and regulatory risk for consumers.
For these reasons, it is in the interests of policymakers to ensure their states are well positioned to benefit from the transition to clean and sustainable energy resources.
Most renewable energy policies center on requirements or incentives or both. Many lay the foundation for renewable energy providers to begin to compete in the monopoly framework of the energy industry. We discuss those policies here.
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Renewable Portfolio Standards (RPSs) require a specific percentage of utility sales or a specific megawatt hour (MWh) capacity to be provided by renewable resources by a specific date. Because RPSs have traditionally favored large-scale renewables, many states have implemented legislation to carve-out a percentage of their RPS requirements to support distributed generation (DG). DG carve-outs have been used as a component of RPSs to advance DG with or without specifying a technology (like solar, for example).
DG can play a unique role in an electric system, reducing line losses because it is closer to the load, providing for ancillary services such as volt/VAR regulation, and enhancing micro-grid capability, resiliency, and reliability.
DG carve-outs often target solar. Though we tend to think of DG as being customer-sited generation, many states have instead identified a megawatt (MW) limitation that is targeted toward sub-station capacity. For example, Colorado shifted their solar carve-out to a DG carve-out in 2010 and identified DG as renewable generation facilities producing up to 30 MW.
If states choose to do this, they should be aware of the impact on the overall carve-out. In Colorado’s case, when they shifted from a solar carve-out to a DG carve-out in 2010, they increased the overall capacity of the carve-out (because they broadened the pool), so the shift was still seen as an increase for solar while broadening the distributed resources that could qualify.
Similarly, expanding the definition of qualifying resources under a distributed generation standard may require a differentiation of targets for specific technologies or size categories of systems.
For example, large systems will generally be able to be developed at a lower cost than smaller rooftop systems. This lower cost means savings for the energy consumer - but there may be additional customer and system benefits with a diversity of system sizes. As shown in Figure 4.3, polls have demonstrated overwhelming public support for rooftop solar energy. Addressing this public desire for rooftop solar may be a focus of distributed generation policies. In addition, locating generation closer to demand increases the efficiency of energy delivery and may address capacity challenges within the transmission system. As a result, geographic prioritization, or increased incentives based on geographic location and maximizing value to the grid may be a focus of legislation.
Finally, workforce development and job creation may be a focus for legislators. Rooftop systems offer opportunities for job creation that are greater and more geographically diverse than do large ground mounted systems.
As a result, legislators may want to establish requirements for systems below 10kW - addressing the residential market, below 50kW - addressing small commercial systems, below 500kW - targeting the large commercial sector, and above 500kW for larger “utility scale” systems.
Distributed generation investment overall may be a good mechanism for stabilizing costs and reducing risk in the utility portfolio of resources. In their 2017 study, Lawrence Berkeley Lab attempted to quantify the impact of distributed generation investment within the context of other investments and showed a favorable cost comparison.
Twenty-five years ago, only a few utilities offered customers the opportunity to voluntarily purchase “green power” from renewable energy sources such as wind and solar. Today, this is a much more common offering, though the way the offer is structured may take a variety of forms, providing differing degrees of flexibility.
The most common approach is allowing customers to purchase blocks of renewable power at some premium - this is offered in 47 states in one form or another. However, with declining costs of renewables - often times at rates below the wholesale rate of electricity - the idea of a premium cost for these resources may be passé.
Green power pricing programs may take a number of forms, but they share a common thread: offering customers an opportunity to invest in a specific type of technology separate from the usual portfolio offered to the rest of the rate base.
This section looks at options for states to consider when offering utility customers an option to direct their rate paying dollars toward a specific technology or project.
Utility Green Pricing Programs: Utility renewable energy opt-in programs allow customers to choose competitively procured renewable energy supplied through their utility. Traditionally, these programs are offered in relation to a specific technology, such as wind power, and are offered in blocks of purchased capacity. A Renewable Energy Credit (REC) based program simply adds a premium to the customer’s rate for the purchase of RECs that are then invested in a project that is not necessarily connected to the utility’s system. Other renewable energy tariffs are priced according to the price of the renewable energy procured by the utility from a specific project. In this way, participating customers could realize the financial benefits of their renewable purchase when the rate is lower than the typical portfolio rate.
Utility-Enabled Back-to-Back Power Purchase Agreements (PPAs) or Green Tariffs: Sometimes grouped together with utility renewable energy tariffs, back-to-back (or “sleeved”) PPAs allow large energy users - typically a corporation or a community using community choice aggregation - in traditionally regulated markets to contract for renewable energy, with the utility agreeing to act as an intermediary between a customer and a specific renewable energy project.
Direct Access Tariffs: Direct access tariffs allow certain customers in traditionally regulated states, most frequently large energy users, to choose to purchase power from an energy supplier rather than the local distribution utility. Direct access tariffs do not necessarily have a renewable energy requirement, but this pathway does create the opportunity for renewable energy purchases.
Corporate procurement objectives (See Section 4.10), as well as community priorities to reduce emissions or purchase a certain percentage of their power from renewable sources, are leading policymakers to provide greater avenues for these groups to procure renewable energy. Still, utilities and utilities commissions are responsible for managing the load and determining what level of generation is required to meet the demands of the system.
The objective of a green pricing program is to balance these demands while continuing to offer customers options.
Twelve states require utilities to offer some mechanism for their customers to purchase renewable power above the resources already procured by the utility in their resource mix. Typically, utilities offer these options not because they are mandated to, but because they see value in providing a renewable option to their customers.
Community Choice Aggregation (CCA) is a policy that specifically allows statutory cities to aggregate their loads and negotiate the source of their electricity supply- for example, a wind farm - production which may allow the community to achieve cost savings over prevailing utility rates. Unlike green pricing programs, individual customers typically must opt-out of CCA programs, rather than opting in. Those communities that employ CCA are not required to purchase renewable power, but many of them do. In fact, some procure up to 100% of their electricity from renewable sources at a cost savings over that of utility rates.
As with corporate purchasing, these types of large-scale investments in renewable resources should be managed within the portfolio of the utility in conjunction with an integrated resource plan. To avoid overbuilding generation resources, states might consider, as with the corporate procurement of renewables, establishing a process for commissions to integrate both community choice aggregation and corporate renewable procurement commitments into a utility’s integrated resource plan.
Historically, green power pricing programs have been voluntary, where customers have to opt-in to a utility, electric service provider, or unbundled renewable energy certificate provider program to purchase green power.
More recently, the development of shared renewable programs offers an additional pathway for customers to purchase green power. For additional discussion, see the Shared Renewables section (Section 4.7).
Interconnection is the process of “plugging renewable energy systems into” the grid. Interconnection standards apply to both customer-sited and utility-scale systems; however, the focus of most interconnection standards are customer-sited systems in conjunction with net metering policies.
Generally, customers want a clear, streamlined, affordable, and predictable system for getting connected to the grid. Without clear interconnection standards, the process customers must follow can be burdensome and expensive.
Interconnection standards must address both technical and procedural requirements. Most of the technical concerns associated with interconnection have been resolved through the development of national standards like the Institute of Electrical and Electronics Engineers (IEEE) 1547 Standard for Interconnecting Distributed Resources with Electric Power Systems and the Underwriters Laboratories (UL) Standard 1741.
Both state and federal policy governs interconnection. With oversight of wholesale electric sales, the Federal Energy Regulatory Commission (FERC) may have jurisdiction in some cases. Through Order 2006, issued in 2005, FERC adopted interconnection standards for generators up to 20 megawatts.
At the state level, a directive to establish interconnection standards that comport with certain guidelines (for example, those from the Interstate Renewable Energy Council (IREC)), may be established in state statute to cover all utilities, even those not regulated by the state’s utilities commission. For regulated utilities, utilities commissions may establish and enforce interconnection standards.
A variety of fairly technical guidelines are included in the establishment of interconnection standards, but state legislatures can instruct their commissions to implement standards that adhere to Freeing the Grid’s best practices (listed under Key Policy Components).
Legislatures may also want to establish certain time frames and capability of online application processes to ensure safety, certainty, speed, and ease in installation. For more information, see Streamlined & Standardized Permitting for Renewable DG (Section 4.9).
A significant challenge for the development of customer-sited distributed generation is the variation among state interconnection standards and procedures. A positive trend is states are increasingly relying on model standards created by the Interstate Renewable Energy Council (IREC), the Mid-Atlantic Distributed Resources Initiative (MADRI), the Federal Energy Regulatory Commission (FERC), or by individual states like California. Legislatures can instruct their commissions to adopt one of these existing standards rather than developing another version.
Prior to net energy metering (NEM), people who installed a solar or other renewable generation system had two options for dealing with the energy they weren’t using at the time of production. First, they could certify as a qualifying facility under the Public Utility Regulatory Act (PURPA) and sell that energy at the utility’s avoided-cost rate (a wholesale rate, far below retail). Because owners were buying power from the utility at retail and selling it at wholesale, this extended the payback period and reduced the incentive for investing in these systems. Alternatively, consumers could install batteries to store the energy produced by their systems and deliver the power to their home when they needed it. But this added significant cost and put the investment out of reach for most people.
With the advent of NEM policies, the economics of installing distributed energy systems improved dramatically. With net metering, a customer usually gets full retail credit for the power they put on the grid from their renewable system - then they use that credit when they take power off the system. Because they are credited for the kilowatt hours (kWh) of production, they don’t get taxed on revenue (as would happen if they were “selling” the power to the utility) and, because they get the full value of the power they put on the grid, they don’t get penalized financially for their investment. As a result, NEM has become one of the most important policy tools for supporting distributed generation.
NEM simply refers to a way of accounting for distributed generation that is produced on the consumer side of the utility meter (a rooftop for example), but not consumed directly by the consumer/producer at the time of production. The power goes instead onto the electricity grid to be purchased by someone else on the system. When the power is delivered to the grid, the meter moves backwards, crediting the customer for each kWh of production. When the consumer/producer needs power, the meter then moves forward again. The consumer/producer is then charged only for the “Net” amount of energy they use. Thus the name, “Net Energy Metering”.
NEM allows the grid to operate like a battery for the customer, but also contributes clean generation to the energy mix. This policy saves customers money and helps drive growth in the renewable energy industry by expanding the customer base and simplifying the process.
Recently, utilities have begun to push back against NEM because it reduces revenue. Utilities argue that other customers need to pay more for grid infrastructure because net metered customers are not paying the portion of the rate that goes toward infrastructure repayment and these investments are unfairly driving up rates for non-participants. However, a 2017 study by Lawrence Berkeley Labs, “Putting the Potential Rate Impacts of Distributed Solar into Context,” brings these assertions into question.
As demonstrated in the study noted above, utilities would need to reach substantial levels of photovoltaic (PV) solar penetration before there would be a significant impact on grid costs - and even then, less of an impact than other resource investments. One must also consider that while the utility is crediting the customer for the power put onto the grid, they are also selling that same power to other customers when it comes back off the grid. In addition, especially in the summer months, solar generation often coincides with peak demand, offsetting the most expensive generation, which provides benefits for utilities and ratepayers.
This points to a much larger and systemic challenge - utilities are not making money from the sale of solar that is purchased and fed onto the grid by the solar owner. This issue is a function of the revenue model under which utilities have traditionally operated - regulated utilities spend money on generation and collect their return through rates. Some states are now starting to address this dynamic and develop new approaches - see New Utility Business Models (Section 2.7).
While most states already have NEM policies, utilities are seeking to change these policies through a variety of means including assessing a fixed or per kilowatt (kW) monthly fee on solar owners to make up for infrastructure costs or shifting from “net metering” which is a kWh for kWh credit to “net billing” which pays solar customers a different rate for the power they put on the grid than the customer pays for power they take off the grid. Many utilities have suggested this rate should be tied to “avoided cost” - or their wholesale cost of other resources they purchase. This clearly puts small solar installations at a financial disadvantage because the wholesale cost of small distributed generation is generally higher than the per kWh cost of a large central station power plant.
States can determine the best approach based on their policy goals. If a state wants to increase economic activity in the solar sector, expand customer options for financing solar installations, and increase renewable distributed power on the grid, they should have a strong NEM policy combined with advanced rate design, grid modernization (Section 2.4), and an investigation into new utility business models (Section 2.7).
If, instead, a state wants to focus on the utility costs of the portions of the grid infrastructure an owner/generator is using that are not collected through rates assessed throughout the system, they could identify a per kWh fee for power that is delivered to the grid – this is the power that is using the grid and not paying for the rate portion that goes to grid infrastructure. This is different than the power generated by the distributed system, as some of that power is going directly to meet the demand at the location and never makes it to the grid.
The second approach only looks at one side of the cost-benefit equation: The cost of the infrastructure, and not the benefit of the generation. Many states have studied the benefits of certain distributed generation technologies (primarily solar) and found that the benefits far outweigh the costs. See Standard Offer Contracts (Section 4.8).
Recently, states have begun implementing “virtual net metering” through shared renewable systems (Section 4.7). This approach allows for multiple people to invest in a generation facility that is not located at their home, and get credit for that shared system on their bill.
Aggregated Net Metering
Net metering policies apply to generation that is produced on the customer side of the meter; however, for customers like agricultural facilities, there may be multiple meters serving multiple loads and systems generating electricity at multiple sites. For these customers, policies allowing for aggregated net metering allows NEM to be applied using the aggregated generation and demand rather than simply on one meter.
Agricultural operations are important targets of aggregated net metering policies. And though some policies may specifically limit its application to agricultural facilities, other great applications for aggregated net metering include commercial properties and public entities like state and local governments, universities, and schools.
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Since the late 1990s, Renewable Portfolio Standards (RPSs) have been one of the most important policy tools for supporting the renewable energy market. RPSs typically specify that utilities in a state supply a minimum percentage of their retail electric load with renewable resources by a certain date along with incremental targets to meet that goal.
In regulated states, the utility then incorporates these targets into their resource plan. Standards place the contracting of renewable power into the portfolio of the utility, meaning the utility needs to plan for incorporation of renewable energy, issue requests for proposals (RFPs) for specific sizes of projects, and contract for purchase of that power.
RPSs that don’t include carve-out provisions tend to favor large-scale renewables, generally wind resources, though solar capacity is growing significantly (a recent study from Lawrence Berkeley National Labs found that while 64% of all RPS capacity was in wind generation, 69% of all RPS construction in 2015 was in solar).
For this reason, different portfolio standards may have specific carve-outs for different technologies and/or for smaller scale projects. See Distributed Generation/Solar Carve-Out (Section 4.2).
Some states will also differentiate the types of renewable energy that qualify under the standard into separate classes with a cap for each class. For example, in the Northeast, there was concern that low-cost Canadian hydropower would consume a significant portion of an RPS, negatively impacting the in-state economic development potential of the RPS. As a result, some states limit the percentage of the standard that can be met by hydropower.
RPS policies may also want to promote solar technology. However, in most states, wind will most likely be less expensive on a per MW basis, though solar is becoming more cost competitive. Similarly, large scale solar will probably be less expensive than distributed solar (The National Renewable Energy Laboratory (NREL) provides cost estimates here). But each of these market segments have their own advantages that policy can be crafted to promote. Also, price per kWh is not always the only, or best, way to determine value. There are myriad other factors to consider including coincidence with demand, complimentary production with other resources on the grid, and the characteristics of the market the power is feeding into.
There may also be benefits regarding the reliability of a system that has multiple distributed sites. And, there may be an interest in reducing grid congestion by increasing the number of distributed systems that are closer to the load.
There are other considerations outside of pure energy value that a legislator may want to take into account. For example, there are more jobs associated with distributed solar systems than with a large scale centralized system.
Because of these different, in some cases complimentary benefits, some states have established policies to ensure that a diverse set of renewable technologies are used to meet RPS targets. These policies recognize the different benefits to the system that may not be entirely captured under a simple calculation of electricity delivery and price/kWh as a form of qualifying for the RPS.
Increasingly, states are also allowing renewable thermal technologies like solar thermal to count toward compliance with their RPS (generally through a British thermal unit (Btu) to kWh conversion rate - see New Hampshire’s Thermal Carve-Out).
Compliance with RPSs is almost always documented through “Renewable Energy Credits” or RECs. A REC represents the environmental attributes associated with the generation of one MWh of energy - and operates both as a measurement of compliance and as a commodity for a marketplace. In most states, once a REC is used for compliance with the standard, it is “retired” - and cannot be traded or used in any other capacity. There are a number of organizations which operate REC tracking systems and the inclusion of a REC tracking mechanism should be included in any RPS legislation. Policies must also provide the “vintage,” or the number of years a REC can be actively used, as a qualifying mechanism. While some RPSs allow the purchase of RECs for compliance, states may want to limit the extent to which this is allowed.
In the early development of RPSs, policymakers frequently included either “multipliers” to incentivize production of renewables in a specific state or set requirements that all renewables complying with the standard be developed within the state. Because these provisions may be subject to challenge under the US Constitution’s Commerce Clause, states should avoid these types of geographical restrictions based on state lines.
Boston College Environmental Affairs Law Review has an excellent summary of the Commerce Clause issue and mechanisms for states to ensure compliance with the Commerce Clause through their RPS design.
Some states have successfully used multipliers (one REC counts as 1.2 RECs toward compliance, for example) to develop renewables earlier, or in certain locations. It should be noted, however, that renewables developed with multipliers of this type will reduce the overall amount of renewables required to comply with the standard.
A final consideration is timing. The Consolidated Appropriations Act of 2016 phases out both the production tax credit (PTC) - primarily used for wind projects - and the investment tax credit (ITC) - primarily used for solar - by 2020 and 2022 respectively. The PTC is reduced by 20% per year until phase out in 2020. This means that wind can be developed at a lower cost for those states that choose to develop the resources faster. Similarly, solar that is developed prior to 2022 will have a significant (30%) cost reduction relative to resources developed after that date. As a result, states may want to accelerate compliance in order to maximize the financial benefit to their rate-payers. For more information, see Accelerating Renewable Standards to Maximize the Benefit of Tax Credits (Section 4.10).
This policy allows for shared, or community, solar systems that have multiple owners or subscribers who pay for a portion of the generation provided by the system. This type of arrangement has numerous advantages over traditional solar installations:
- Many residents – some estimates are up to 70% - don’t have access to traditional solar generation because of shading issues, orientation of roofline, or building ownership issues.
- Shared solar can allow renters to own solar and if they move, take that solar ownership with them.
- Large-scale systems can be oriented for maximum productivity, and economies of scale allow systems to be developed at a lower cost than individual rooftop systems.
- Marketing of virtual ownership decreases the “soft costs” associated with typical customer-sited systems including site assessments, permitting, and administrative expenses.
- Because most power purchase agreements made with the solar developer include payment for infrastructure, virtually net metered systems avoid some of the lost revenue issues utilities identify as a problem with traditional net metered systems. For a discussion of this, please see the ‘Net Metering’ policy overview (Section 4.5)
As discussed previously (Section 4.5), shared renewables use “net metering,” but with an important distinction: shared systems are off-site from the customer. As a result, this type of net metering is referred to as “virtual net metering.”
Virtual net metering allows power generation from a shared system to be credited to the customer as if the generation were on site. This ties in with shared solar policies, which allow for multiple subscribers to a large solar system to receive credit for a specific amount of generation purchased from the plant.
Virtual net metering is an important distinction from a “power purchase agreement” (PPA), which pays the customer for the proportion of power they produce. Because it is treated as a “credit” on the customer’s bill, the customer can avoid the tax implications of a PPA payment - which can adversely impact the economics of the system (and may come as a surprise to the participant).
Shared renewable policies can instruct the regulatory commission to include a minimum capacity of shared renewables to be contracted by the utility on an annual basis, providing a competitive environment and a measure of market certainty. This is particularly important in vertically oriented regulated markets.
The policy may also be designed to drive low-income participation, as credit ratings often exclude participation in solar markets for low-income populations. Ensuring participation by low- and moderate-income households has several benefits, including increased adoption of renewable technologies and reduced energy costs. Low-income participation can be increased either through a percentage mandate for the overall annual contracted capacity, or by offering a higher rate of payment for the portion of shared solar capacity attributed to low-income customers. States that have a shared renewable program may want to coordinate this program with implementation of the federal Weatherization Assistance Program (see Section 1.8) to provide recipients of assistance with participation in a shared renewable system.
Shared solar systems offer multiple benefits over traditional distributed systems, particularly as measured by cost, portability, and ease of participation. While they shouldn’t be seen as completely replacing systems located at a home or business, they are an excellent complimentary offering.
Standard Offer Contracts (SOCs), including feed-in tariffs (FITs), refer to a policy of offering a certain value - either through credit or payment - for the generation and delivery of renewable energy to the grid.
SOCs may take a number of forms, but will generally be distinguished between wholesale energy providers (usually on the utility side of the meter) or customer generators (on the customer side of the meter). While net metering provides a credit for a kWh regardless of the price of that power, a standard offer is a policy that provides a financial credit/kWh. In an effort to stimulate investment by the private sector, SOCs may be designed to provide a basis for an investment that is predictable and financeable over a period of time. This policy may also be an attempt at quantifying the value of the power being generated and delivered to the grid which acknowledges that, due to a variety of factors, all kWhs do not have the same value.
On the wholesale side, SOCs may be structured as a certain payment or “Tariff” that is paid to those who can deliver power to the grid based on the characteristics of that power. This is generally a better approach for systems that are not directly tied to load. Vermont has had a great deal of success with their standard offer. In 2013, they shifted the program from a rate setting standard offer to one based on an RFP system. However, they kept the standard offer structure for their “dairy air” program which seeks to advance farm methane projects. These projects receive 20 year contracts at 14.5¢/kWh for projects over 150MW and 19.9¢/kWh for projects under 150MW. This provides farmers a guaranteed revenue stream they can literally “take to the bank.”
SOCs are attractive for offering predictable, stable, long-term revenue streams capable of drawing private investment and commercial lending to the renewable energy market. Detractors claim that the costs of long-term commitments to provide FITs are too high and do not reflect changing market conditions. Understandably, policies should include a mechanism allowing the rate to be adjusted to reflect market conditions, but part of the attraction of SOC policies is that they stabilize the guaranteed payment across an established period of time reducing finance rates for private sector investors.
Setting of the price of the SOC may take a number of forms, from a “reverse auction” where bids are taken for generation and the lowest price is used to set the tariff price, to a more traditional return on investment-driven approach where the offer price is set at a level designed to repay the typical investment at a set earnings on equity level over a set period of time.
Value of Solar Tariffs (VOSTs) provide another form of standard offer. And while our examples come from VOST, states could expand this concept to include other energy resources. In this approach, a value is determined by the characteristics of energy provided to the grid, rather than from a specific technology.
In the debate over net metering (see Section 4.5), utilities have claimed that net metering amounts to a subsidy to solar owners from non-solar owners because the kilowatt hour (kWh) credited through a net metering policy credits not only the generation, but also the portion of the rate that is used to pay for transmission and distribution infrastructure. Solar advocates have countered that the value of the power delivered from a solar system is much higher than the credit a solar generator receives - utilities often argue the value is lower. Value of Solar Tariffs seek to quantify that value and compensate the solar owner accordingly.
VOST is a policy that establishes a tariff to be paid to a solar generator for the determined value that solar delivers to a utility system. Critical to the quantification of a value for energy that is fed into the grid is an acknowledgement that, depending on the form and character of energy, there are various benefits and costs that should be included in a comprehensive cost-benefit analysis. For example, in the development of the VOST proposal in Minnesota, the state established the following components to be included in the value calculation (see figure 4.17 or this detailed study for more information):
- Avoided Fuel Cost
- Avoided Plant O&M Cost
- Avoided Generation Capacity Cost
- Avoided Reserve Capacity Cost
- Avoided Transmission Capacity Cost
- Avoided Distribution Capacity Cost
- Avoided Environmental Cost
- Voltage Control Value
- Integration Costs (not a value, but a cost - reducing VOST price)
States may want to consider a variety of other issues associated with technologies that provide different benefits to the utility system. For example, the interconnection of storage systems may offer emergency dispatchable energy value beyond those characteristics identified here.
We recommend that legislators not try and identify these values themselves, but rather instruct their utilities commission (or in the case of Minnesota, their commerce department) to undertake a study to determine these values.
Because of the tax implications of an individual receiving a payment for the power they deliver, when looking at customer-sited systems, the legislation should establish a credit as a primary component of the VOST - with a true-up payment to the customer for the full value on an annual basis. In this way, the customer is only paying taxes on the revenue they receive above the value of the credit.
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For renewable distributed generation (DG), “Soft Costs,” including permitting and interconnection expenses for installers, can drive up costs for consumers and for interconnecting renewable energy projects to the grid. Streamlining this process can save costs and reduce time for both installers and consumers.
This policy establishes either statewide standards for local governments to establish streamlined permitting processes, or resources for local governments to voluntarily implement a streamlined standards program. State incentives, such as tax credits, financial incentives, or loans may be tied to systems that are established within a designated streamlined permitting jurisdiction.
Installation of renewable energy systems requires interconnection to the grid and engineering and installation of electrical components. As a result, there are important permitting steps that need to be followed to ensure health and safety. As the industry has matured, some standard systems have become established. These enable a streamlined permitting process and cost savings to participants.
For solar energy, solarcommunities.org highlights twelve steps (Figure 4.18) that local governments can take to streamline the solar permitting process. A state may require these steps, or establish a program to assist local governments in putting these steps in place.
Furthermore, recognizing that the soft costs associated with an inefficient permitting system can drive unnecessary costs to the consumer, a state that has established an incentive system for renewable energy projects might restrict incentives to jurisdictions that have put these streamlined steps in place. In this way, the state is providing incentives only for systems with reduced administrative costs, which avoids subsidizing an administratively inefficient system.
The state may want to establish a mechanism for rewarding local governments that have achieved the objectives of the streamlining and include a regular periodic renewal of that recognition - For example, a “Solar Friendly Community” designation.
NREL has published a “Solar Ready Buildings Planning Guide” which includes a checklist of components for solar ready buildings and guidelines for developing a solar ready building code.
Just as renewable energy technologies have been improving over time, mechanisms for deploying renewables have expanded. With that shift, policy approaches for expanding access to renewable energy continue to be developed. We discuss some of those ideas in this section.
AGGREGATED ROOFTOP SOLAR
Shared solar systems (Section 4.7) allow for a developer to find numerous subscribers / owners. These subscribers purchase a percent of the development on a kilowatt (kW) basis and then are credited for each kilowatt hour (kWh) produced in relationship to the capacity purchased through a “virtual net metering” arrangement. While these shared systems are usually developed in large ground mounted arrays, this policy considers a potential addition to the standard structure of shared renewable systems to include rooftop aggregation forming large virtual systems that can have the same subscription model as large ground mounted systems.
This policy builds upon the established shared solar or community garden legislation. It is an advanced application of the policy that eliminates any caps on shared solar systems, and allows for customers to over-build their solar system and participate in a virtual shared solar concept.
Something similar to this idea is being proposed by the California Independent System Operator (CAISO) to address the size limitations of systems feeding into the CAISO wholesale market (Similar ideas are also being discussed in Texas and New York). The approach refers to these systems as DERPs or Distributed Energy Resource Providers. Recognizing that rooftop systems are small individually, but there is a great deal of capacity potential in aggregate, CAISO is proposing rules to allow for the aggregation of these rooftop systems that would be compensated with an ISO tariff through a Participating Generator Agreement.
While the policy explicitly allows utilities to enter into this shared solar market, there should also be conditions that remove a utility’s inherent advantage in a competitive marketplace when serving as both buyer and seller. This could be accomplished, for example, by way of a third-party evaluator to regulate any marketing or bidding advantage the monopoly utility may have over private companies.
The policy also creates a system of distributed shared ownership by allowing developers to over-build an individual system on a customer’s rooftop and place the excess generation into a pool of shared resources for sale. This not only allows additional profit opportunities for those leasing their rooftops for this purpose, but also achieves the expanded build-out of renewable resources without requiring additional land and transmission to be developed - as occurs with most ground mounted systems.
ACCELERATING RENEWABLE PORTFOLIO STANDARDS
One of the oldest and most successful advanced energy policy tools, renewable portfolio standards (RPSs), usually set a target for a specific percentage of renewable electric generation to be achieved by a specific date. For further discussion, see Renewable Portfolio Standards (Section 4.6).
While these policies have various target dates and percentages (i.e.: 25% by 2025 or 30% by 2030), recent changes in federal tax incentives mean that states have significant incentive to accelerate the development of renewable resources to save ratepayers money.
The federal tax incentives available for wind and solar have been critical to maintaining low costs during the dramatic expansion of renewable energy in the US For wind, the production tax credit (PTC) has been the primary incentive - offering about 2.2¢/kWh credit on all wind generation over ten years. For solar, it has been the investment tax credit (ITC) which offers a credit of 30% of the investment value.
After years of stop and start in the PTC and ITC, Congress negotiated a phase out of these two incentives, and enacted this in the Consolidated Appropriations Act of 2016. The phase out occurs through 2020 for the PTC and 2022 for the ITC.
Under the new law, the PTC will apply to projects that commence construction in 2016 with a reduction in the value of the credit by 20% in 2017, 40% in 2018, 60% in 2019 – and expire completely by 2020. Similarly, the ITC, primarily used for solar projects, has been extended to 2022 with a slower ramp down of the value.
As a result of these declining incentives over time, there is a strong financial argument to accelerate the build out of the renewable resources required by an RPS prior to these time-frames. In 2016, Xcel Energy in Colorado proposed to the PUC to own and develop 600MW of wind for the Colorado market - not to comply with the state’s 30% RPS, but because favorable federal tax policy will result in savings for their customers.
As shown in the graph above, most RPSs will have reached their target dates well before 2030. For standards expiring after 2020, there is a financial incentive to accelerate compliance to 2020 and 2022 in order to maximize the value of the production tax credit and the investment tax credit, respectively. This can also have a significant financial benefit for the ratepayer.
EXPANDING RENEWABLE PROCUREMENT OPTIONS
In vertically integrated monopoly states (states that do not have a deregulated utility market), renewable energy contracts are driven by utility commitments to purchase renewable energy, usually as required through an RPS. One of the challenges of this type of monopsonistic (one buyer) arrangement is that once a request for proposals (RFP) period for generation has been completed, the market for large renewable developments dries up, and along with it, competition to develop renewable generation.
The following proposals fit into the larger category of expanding renewable procurement options - essentially allowing large energy users, or aggregated smaller energy users, to contract for development of utility-scale resources (for example, a large solar development, or a wind farm). To ensure utility resource planning includes these substantial commitments to renewable resource procurement, the processes outlined in each of these policy proposals should be integrated into the utility resource planning process. We look at two primary avenues for these types of renewable procurement: 1) Corporate Procurement and 2) Community Choice Aggregation.
This policy proposal would allow individual companies to execute power purchase agreements (PPAs) for renewable energy directly with developers and be credited for the generation placed onto the grid through the procurement.
Many fortune 500 companies have now established either climate goals or commitments to purchase renewable energy. In just the last four years, 6 gigawatts (GW) of renewable contracts have been announced by corporate entities. In many cases, these companies are accomplishing this through the purchase of Renewable Energy Credits (RECs) which go toward the development of renewable projects in other states.
By allowing corporate PPAs, those companies with large loads and a commitment to purchasing renewable energy can negotiate contracts directly with renewable developers. This not only develops increased renewable capacity in a state without impacting the broader rate base, but also opens the market for renewables beyond the established monopsony.
For More Information: See the Center for the New Energy Economy’s Paper “Private Procurement, Public Benefit: Integrating Corporate Renewable Energy Purchases with Utility Resource Planning.”
COMMUNITY CHOICE AGGREGATION
Community Choice Aggregation policies empower local communities (e.g. towns, cities, counties) to harness the collective buying power of the community (i.e. all the electricity used by all the residents as well as local government and schools) to support the development of renewable energy sources. By deciding – as a community – to purchase significant amounts of renewable energy, the community becomes a credit-worthy buyer of renewable energy.
Legislation to authorize a local government to aggregate their population to enter into a PPA for renewable energy resources may take a couple of forms - either through required participation by all in the community or through opt-in aggregation.
With the required participation approach, the financing of the project would be absorbed by the community and funded through a community-wide assessment. Generation from the renewable project would be credited to the community and managed by the utility.
The required participation approach would typically be authorized through a vote to assess a community wide fee over a period of time that would be dedicated toward the purchase of the renewable resource. This approach lowers risk (due to the certainty of the revenue), which can lower the overall cost to the community while also including all energy users. The collective buying power of an entire community allows for a competitive bidding process that can attract low cost resources.
A slightly different approach - as California provided for in CA AB 117 in 2002 - allows individual members of a community to “opt-in” to an aggregated community purchase of renewable resources.
The Department of Energy has outlined community choice aggregation programs across the country.
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INTEGRATING AGGREGATED PROCUREMENT INTO UTILITY PLANNING
Utilities and regulators want to avoid the overbuilding of generation resources on a system. As a result, it is prudent in areas without a broad energy imbalance market to incorporate corporate renewable purchase commitments and community choice aggregation programs into the regular Integrated Resource Plans (IRPs) that utilities submit to regulators to plan for resource needs over multiple decades. By integrating these renewable purchase commitments into the IRP process, regulators can avoid over-building resources, avoid stranding generation assets, and can receive important commitments from the procuring party to purchase a specific quantity of renewable assets directly.
While financing programs alone cannot drive markets, they are absolutely critical for opening access to the market for energy technologies.
For example, the best financing program in the world is not going to drive demand for energy efficiency or renewable energy without a suite of other policies that create the foundation for that market. But when individuals decide to participate in the market, the ability for them to easily and affordably finance the purchase of a product or service is absolutely essential to widespread adoption.
The nature of energy related purchases - such as insulation, renewable generation equipment, or energy management technology - are fundamentally an initial capital investment followed by monthly savings on a utility bill. As a result, any financing option that allows a customer to move the initial capital investment to a monthly payment aligns the costs with the benefits - making the entire investment more affordable for the customer.
A perfect example is a question often posed to solar power owners: “How long does it take for the system to pay off?” The premise being that the cost of a system - say, $10,000 - applies to the first kilowatt hour (kWh) of production and then the benefits accrue at 10¢/kWh increments. But take this example and apply financing. If a 4kW system costs the customer $10,000 and they finance the system over 20 years at an interest rate of 5%, the system will cost them $66/month. If the 4kW system is able to produce an average of 110 hours per month of full 4kW production, the cost of that power would be 15¢/kWh. When compared to the cost of power in this example of 10¢/kWh it is more expensive, but the costs are flat over 20 years. If you add in an electricity cost escalator of 5%/year, the solar system would be producing cheaper power in 10 years - every year after would deliver savings to the customer.
Policymakers can look at this dynamic and identify a number of financial variables that can improve conditions for the customer. First of all, is 20 years the right term of financing? If the system is warrantied for 25 years, perhaps that’s a better term. Changing the term to 25 years would bring the cost/kWh to 9.7¢/kWh, making the system immediately cost effective. Or perhaps the term stays at 20 years but, with a credit enhancement mechanism from the state, the financial markets are able to support a 3% interest rate rather than 5%. That brings the cost to 10¢/kWh - making the investment immediately cost effective. Certainly, direct incentives that drive down the cost of the system provide another way to achieve cost effectiveness. If the state offers a tax credit for 15% of the cost of the system, the consumer would be paying 9.3¢/kWh, also making the investment immediately cost effective.
This example from a solar system could be applied to energy efficiency investments or energy management systems. The objective is to help make the movement to greater energy efficiency or cleaner energy generation both more cost effective and easier for the customer.
This chapter highlights a few of the financing approaches that have been successful around the country.
Distributed generation (DG) provides localized generation that serves a specific part of the grid. It may include generation serving a specific residence or business, a neighborhood, or a region served by a substation. DG has the benefit of reducing stress on large transmission infrastructure by providing distribution level power (as opposed to central generation).
Because small-scale renewable energy systems require large upfront investments, many states provide financing and financial incentives to spur adoption of these technologies.
DG systems are typically generation systems that are located on the customer side of the utility meter. But a state may choose to include larger systems in the definition of distributed generation. For example, Colorado defined DG systems as those below 30MW. This allows the DG systems to connect directly to an existing substation without requiring infrastructure upgrades.
This type of incentive pairs particularly well with financing structures that spread the costs out over time.
Initially, solar DG incentives were based on an upfront $/Watt rebate. Today, more states are moving to incentives that are associated with production - providing ongoing revenue over time.
There are many approaches to how a state might incentivize these systems, but one critical component is that the incentive is predictable and reliable. In the event that there may be a change in the value of the incentive, a state should base that change on a specific capacity reached and then have a schedule for stepping down the incentive. This is known as a declining incentive structure.
Some mechanisms for providing incentives include:
- Performance-Based Incentives – A performance based incentive may take the form of a power purchase agreement, a standard offer payment, or a bill credit providing a certain dollar amount per kilowatt hour (kWh) of power generated. An example is Rhode Island’s Renewable Energy Growth Program.
- Loans – By providing low-interest financing to an individual utility customer, the state can shift the upfront payment for generation to one that reflects typical utility costs – a monthly payment over time. An example is Connecticut’s Low Interest Loan Program.
- Bonds – Through the 2009 American Recovery and Reinvestment Act, states were provided additional access to low interest financing for renewable energy and energy efficiency projects through Qualified Energy Conservation Bonds (QECBs) which work similarly to Build America Bonds.
- On-bill Financing – If utilities are willing to finance renewable energy investments directly for consumers, legislatures may authorize utilities to lend money and recover their regulated rate of return on the investment from customers through On-bill Financing of the loan. Similar to on-bill programs through utilities, private financing may be available. States can facilitate this by enabling On-bill Repayment of a renewable energy loan. This gives consumers a convenient way to incorporate their energy investments into their utility bill. For additional information, see On-bill Financing / On-bill Repayment (Section 5.5).
- Third-Party Financing – Third-party ownership attempts to address affordability by allowing a system to be purchased by a third-party with the generation sold over time to the customer. By doing this, the third-party can monetize tax credits, capitalize on commercial benefits like depreciation, and take advantage of large-scale financing at low interest rates. The total cost is significantly reduced, and the third-party passes the savings on to the customer. For more information, see Third-Party Financing (Section 5.8).
Energy Savings Performance Contracting (ESPC), sometimes also referred to as Utility Energy Service Contracting (UESC) or simply Performance Contracting, is primarily a financing mechanism for retrofitting commercial buildings in the Municipal, University, State, and Hospital (MUSH) sector with more efficient technologies (HVAC, lighting, building controls, etc) and, more recently, distributed renewable technologies (solar, ground source heat pumps, etc). The new equipment is paid for over time through the utility bill savings of the measures themselves. “Performance Contract” means that the savings from the performance of the energy investment is committed to repayment of the loan. While this method of financing could be applied in any application, the target market for investors is generally large institutions where risk is low and the investment timeframe is generally longer than in the private sector.
The diagram in Figure 5.2 depicts a commercial customer’s utility bill over time as a result of an ESPC. In this example, the grey box represents the savings that are used to finance the upgrades. The blue box displays the “extra” savings to the customer (often a buffer against the performance guarantee) over the useful life of the project, which is typically long after the performance guarantee has expired. A key component of an ESPC or a UESC is the guarantee: The Energy Service Company (ESCO) guarantees a certain, negotiated level of savings (grey box).
ESPCs and UESCs are typically best implemented in the MUSH market and by Federal Government users. Building owners in these sectors tend to be willing to install measures with longer payback periods and, therefore, the projects tend to generate deeper retrofit savings. ESPC programs are often managed by state energy offices for in-state MUSH markets. UESC programs are offered by utilities (often regulated utilities).
Availability of private sector funding for ESPCs and UESCs is not generally a barrier – there is sufficient capital waiting to lend to quality projects. Perhaps the biggest barrier, at least for new programs to launch, is statutory and executive clarity that state agencies can retain the savings generated from a project without being allocated a lower utility bill budget in later years. For some states, the ambiguity surrounding this issue has caused them to struggle with launching a program. For example, in 2009 in Arkansas, Governor Beebe issued Executive Order 09-07 to promote energy conservation by state agencies. The order allowed the use of ESPCs. In 2013, he signed legislation clarifying that state agencies may retain the savings from an ESPC. Another real challenge is that many projects are too small (under $1,000,000) to find a willing lender, especially given the longer payback periods for these projects. Financing may be required by the state to sufficiently staff a robust program.
While the staffing needs are not expansive, the commitment of personnel to assist in the implementation of a good ESPC program is essential. Contracts can be very technical and usually beyond the scope of facilities managers. States may want to hire engineering consultants to assist facilities managers and represent the state’s interests. While some of these costs can be rolled into a contract, the administrative burden and upfront costs are generally covered by the state. Furthermore, states should see a good ESPC program as a public resource – not limited simply to state-owned facilities, but also a tool for local governments, school districts, and universities. This requires staffing, management, and marketing resources that a state program may provide.
A performance contract starts first with an investment grade audit. The investment grade audit will identify a range of investments and their payback from energy savings. There is sometimes a tendency to want to cherry pick the highest payback items and do just those. A performance contract should really consider the investment as a whole – some retrofits will subsidize others to create a product package that will pay for itself in savings. In this way, the facility can avoid expensive future replacements of energy equipment and finance the new equipment within the performance contract.
These audits can be very expensive. The costs of the audits can be incorporated into an ESPC, but the upfront costs may need to be provided by the state (some ESCOs may provide the audit free of charge in certain circumstances). States may want to consider creating funds to pay for investment grade audits that could ultimately be repaid through ESPC projects.
A state may want to set a goal, for example, reducing energy usage in state buildings by 20% by a certain date, and specify that the goal is tied to performance contract audits for all state buildings. Or, a state may want to specify that all school districts need to complete performance contract audits on all of their school buildings – and tie that directive to the state’s performance contracting program.
Innovative Financing Programs is an umbrella policy category that covers any mechanism to reduce the upfront cost of clean energy technologies for customers. Though personal, corporate, sales, and property tax credits are a common form of state incentives, CNEE does not consider them to be true financing unless a third-party entity is able to monetize them and, in doing so, reduce upfront costs. We only include policies that reduce the upfront cost barrier in this description.
Historic approaches to achieve clean energy objectives have focused on simple incentives - payments from the state or utility to entice a customer to choose a particular product or technology. However, as the market has matured and led to a greater understanding of clean energy technologies by lending institutions and financial markets, there has been a move away from focusing on up-front incentives and toward looking for mechanisms to facilitate long-term financing.
As Richard Kauffman, “Energy Czar” for the state of New York, has observed about shifting from a subsidy rich policy to a financing policy, “We have to ask: Is there a better way than being in the resource acquisition business? We’re restructuring programs at NYSERDA [New York State Energy Research and Development Authority] and at the utilities to do things so they are enablers of markets, rather than becoming the market.”
A few innovative approaches include:
- State Green Bank – At its essence, a green bank blends public and private capital to fund the upfront cost of clean energy improvements. The intent is to reduce the risk for the investor and to scale the market for projects. Sometimes these banks will attempt to address a limitation in the private lending sector – for example, while most bank commercial loans are 5-10 years, the NY Green Bank extends these terms for 20 years and assumes the risk of the investment on the back end. In this way, the public bank is partnering with private lending institutions to address barriers for businesses. Green banks also provide education, assistance with loan securitization, and sometimes, direct lending. These entities can be housed within an existing state agency with administrative, rule-making, and underwriting authority. Examples include the New York Green Bank and the Connecticut Green Bank.
- Revolving Loan Funds – The distinguishing characteristic of these public funds is that they are evergreen in the sense that the repaid principal and interest from loans made are re-issued to other loan recipients. In this way, the program funding “revolves” over time. An example is Texas' LoanSTAR Revolving Loan Program.
- Loan Loss Reserve - These funds are a credit enhancement or credit wrap in which a percentage of a program or project (for example, 10% of loan recipients or 10% of the principal) is held in reserve and only drawn in the event of a default. These programs are used to leverage or reduce risk of private capital investment in clean energy projects. An example is Michigan Saves.
- Aggregate programs - These programs bundle un-securitized loans offered by private sector lenders, coupled with an interest rate buy down from a public funding source (for example, the American Recovery and Reinvestment Act of 2009). The loans are then bundled and sold to the secondary bond market.
- Securitization – In this context, securitization is borrowing against future ratepayer contributions into a public benefits fund. Perhaps the best example of a state securitization program is the Hawaii Green Energy Market Securitization (GEMS) program which makes low cost capital available to a broad range of participants including renters and lower credit score borrowers.
Overcoming the upfront cost barrier is arguably the biggest challenge to clean energy deployment at the customer level. Financing is key to addressing this barrier. On-bill Repayment (OBR) and On-bill Financing (OBF) are mechanisms to finance residential and small commercial clean energy technologies in buildings. Capital can come from the utility (OBF), or through a private entity to be repaid through the utility bill (OBR). In either case, the customer’s costs of retrofits or equipment are amortized and combined with savings from the measures on the utility bill.
Having the financing on the customer’s bill allows the project to be directly associated with the savings benefit. If the investment is saving money, or is cost neutral, this means the improvement can be made with no out of pocket cost to the consumer.
The source of financing is the main design component separating OBR from OBF. Because a regulated utility’s cost of capital is in the 7-8% range, utility financing is typically not as economically competitive as Third-Party Financing. When utilities do offer financing, they often use ratepayer Demand Side Management or energy efficiency funds that are arguably 0% interest capital. However, utilities often see customer financing as outside of their area of expertise and prefer that financing be done through an authorized financial institution.
In this case, a private lending (or a state lending) institution is identified to provide the upfront capital with the utility acting as a conduit for collection of the repayment. Outside capital could also be provided through a state fund.
Programs vary from state to state by source of funding, marketing, target markets, qualifying terms, and policy origination (legislative or utility proposal to a public utilities commission).
To reduce repayment risk for the lender, some programs allow for a ‘disconnect of utility service’ in the event of default, which has raised consumer protection concerns in some states. Some financial institutions will allow a history of utility bill payments to qualify customers with lower credit scores, but most institutions will not.
This is where a state program can work in concert with the OBR/OBF offering. A credit enhancement fund (such as a loan loss reserve) could be established specifically for those higher risk customers to maintain the reduced interest rates.
Commercial Property Assessed Clean Energy (C-PACE) is a financing mechanism used by local governments that allows commercial, industrial, and multi-family property owners to repay the cost of energy efficiency and renewable energy improvements through their property tax payment. The repayment of qualified energy improvements is done via a voluntary property tax assessment allowing local governments to repay, via property tax revenues and other funds, third-party lenders who finance the up-front costs of the improvements. Repayment responsibility transfers to the next owner if the property is sold.
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Because commercial loans are not backed by Fannie Mae and Freddie Mac, the Federal Housing Finance Agency (FHFA) guidance issued in 2010 does not impact C-PACE, which has allowed it to flourish while Residential PACE has stalled (outside of California).
Though many states have passed C-PACE enabling legislation, there has been a real lack of model legislation, which has led to states setting their own loan terms, qualifying retrofits, and target markets. For a detailed analysis, download PACENation’s comparative chart of C-PACE legislation.
This lack of standardization has prevented C-PACE market growth from scaling to its potential within the private lending community. States continue to modify their existing C-PACE statutes. For example, in the 2014 state legislative session alone, C-PACE statutory changes were made in Maryland (HB 202), New Hampshire (HB 532), and Oregon (HB 4041) – all of which had pre-existing C-PACE legislation that needed to be modified. Therefore, CNEE recommends a full evaluation of existing C-PACE policies to determine if any statutory changes would enable programs to reach greater scale.
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Residential Property Assessed Clean Energy (R-PACE) is a financing mechanism facilitated by local governments allowing residential property owners to easily finance energy efficiency and renewable energy improvements.
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The repayment of qualified energy improvements with R-PACE is done via a voluntary property tax assessment, allowing homeowners to repay the loan through a line item on their property tax bill. Local governments can then issue bonds on the property tax revenue stream to finance the capital investment. The voluntary tax assessments authorized with PACE are used to repay the bonds overtime.
R-PACE legislation authorizes the creation of a voluntary taxing district that participants opt-in to. The participant agrees to an assessment on their home, which is then financed through some type of warehouse facility from the PACE lender. At scale, many home assessments can then be bundled and securitized.
States may need to pass authorizing legislation for local governments to create “taxing districts” for the issuance of the bonds. Similarly, states may pass legislation allowing for multiple districts issuing bonds to combine their participating tax base into one super-district to drive down the costs of bond issuance and increase access to secondary bond markets.
Usually, the repayment responsibility transfers to the next owner if the home is sold. However, some states have included provisions that the entire balance must be paid off in the case of a transfer of ownership.
From 2008-2010, thirty-five states passed legislation authorizing R-PACE financing. In 2009, the White House issued principles for model R-PACE programs. But, R-PACE hit a major roadblock in 2010 when the Federal Housing Finance Agency (FHFA), which oversees the activities of the nation’s two largest mortgage underwriters, Fannie Mae and Freddie Mac, directed them not to underwrite PACE mortgages primarily because the improvement loan would take seniority over a mortgage held by a lien holder. Following the issuance of the letter, nearly every program in the country ceased to operate.
In 2012, FHFA opened a rule-making on the issue, but withdrew the proposed rule a year later. In December of 2014, the Agency issued a statement reiterating its position and “[making] clear to homeowners, lenders, other financial institutions, state officials, and the public that Fannie Mae and Freddie Mac’s policies prohibit the purchase of a mortgage where the property has a first lien PACE loan attached to it.”
In August 2015, however, Ed Golding, the new head of Federal Housing Administration (FHA), a separate entity that provides mortgage insurance for FHA approved lenders, announced that, under forthcoming guidance, properties with subordinated PACE loans could be purchased and refinanced with FHA insured mortgages.
The Department of Housing and Urban Development (HUD) subsequently issued the following guidance for determining eligibility for FHA insured mortgage financing:
- Collection: The PACE obligation is collected and secured by the creditor in the same manner as a special assessment against the property;
- Enforcement: The property may only become subject to an enforceable claim (i.e., a lien) that is superior to the mortgage for delinquent regularly scheduled PACE payments. The property shall not be subject to an enforceable claim superior to the mortgage for the full outstanding PACE obligation at any time;
- Property Transfer: There are no terms or conditions that limit the transfer of the property to a new homeowner. Provisions to require the consent of a third-party prior to conveyance are prohibited, unless these provisions can be terminated at the option of, and with no cost to, the homeowner;
- Disclosure: The existence of a PACE obligation on a property is readily apparent to all parties to an FHA-insured mortgage transaction in the public records and must show the obligation amount, the expiration date and cause of the expiration of the assessment, and in no case can default accelerate the expiration date; and,
- Attachment to Property: In the event of a sale, including a foreclosure sale, the PACE obligation will continue with the property.
One solution for states and cities that have been able to work through the guidance from FHA lies in the creation of a fund to address possible default risk to the mortgage holder. Two programs that have been particularly successful in this regard are California First and the Ygrene Works’ Clean Energy Green Corridor in Miami.
The California Treasurer’s Office set aside a $10M loan loss reserve fund intended to repay mortgage lenders in the event of default. The California Alternative Energy and Advanced Transportation Financing Authority (CAEATFA) administers this fund. FHFA responded that this was insufficient to address their first lien concerns with PACE loans and that they would still not support the purchase or refinance of mortgages with PACE loans in the first lien position. The City of Miami passed a $230M bond in September, 2013 which is intended to address the PACE senior lien concerns. Ygrene Works also continues to expand its PACE assistance to more and more residents in Miami. Other Florida cities are also able to participate in PACE Financing through The Florida PACE Funding Agency.
The FHFA and FHA are in ongoing discussions to address concerns about the priority status of PACE assessments. And, while FHFA’s main concern with R-PACE is the seniority status of the lien, a growing body of evidence suggests that energy efficiency leads to lower mortgage default rates. Research published by the University of North Carolina Center for Community Capital found in a study of 71,000 homes that owners of ENERGY STAR rated homes were 32% less likely to default on their mortgage than owners of built to code homes.
Finally, the Department of Energy has issued guidelines for Residential PACE financing programs to address programmatic structure. Further resources on PACE development are available from DOE here.
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Traditional purchases of solar systems require large up-front expenditures. Any incentives for such purchases are frequently tax credits, an incentive that is not captured until taxes are submitted – and then only if the customer has sufficient tax liability. Third-party ownership attempts to address affordability by allowing a system to be owned by a third-party with the generation sold over time to the customer – offsetting the power purchased from a utility. By doing this, the third-party can monetize the tax credits, capitalize on commercial benefits like depreciation, and take advantage of large-scale financing at low rates to procure systems at a very low cost – passing the savings on to the consumer in the form of low price per kilowatt hour (kWh) rates that are comparable, and often lower, than established utility rates.
Third-Party Financing policies allow for third-party ownership of a generation system, usually located on the customer side of the meter, enabling a lease purchase agreement or the selling of power to the customer from the generating unit without the third-party company being regulated as a utility.
Legislation is often required to allow this because utilities are typically granted monopoly status and are the only entity legally authorized to sell electricity to customers in their territory. Legislation provides an exception to this monopoly authority for systems located on the customer side of the meter to allow third-party owners of the systems to sell the power generated from the system to the customer.
Third-Party Financing has proven very popular with customers in the states that have implemented these policies. In states like Arizona, Colorado, and California, where third-party solar policies have been in place for years, up to 80% of residential systems are procured using this method.
In some states, open retail markets allow for third-party power purchase agreements (PPAs), but may need some modification to allow for these kinds of customer-sited systems. As of 2016, nine states disallow or otherwise restrict third-party PPAs.
As financing institutions become more familiar with renewable energy and energy efficiency, new opportunities are opening up to expand financing options and drive innovation within the sector.
PROPERTY TRANSFER ENERGY UPDATES
While most states have adopted energy efficiency requirements within their building codes (see Section 1.2), this only impacts new buildings. Property transfer legislation would require that prior to the transfer of a property, the property must achieve some standard of energy efficiency - either a HERS rating or some other measure of energy efficiency - to increase the efficiency of the building stock.
ENERGY DISCLOSURE IN PROPERTY SALES
When an individual purchases a home or other property, there are multiple required disclosures. However, unless expressly authorized, the buyer can’t usually find out the energy costs associated with the property. Having this information could help the buyer determine what their out of pocket costs will be each month - thereby increasing the value of an energy efficient home. Such information may also allow the buyer a negotiating pathway. Because of higher energy costs, they may want to finance a lower amount so their out of pocket expenses are not increased above their budgeted level. Legislation could be passed that would require such energy disclosure prior to the sale of a property.
ENERGY INNOVATION PATHWAY
Utilities are often lagging in innovation, particularly compared to the private sector. This is largely because the utility regulatory model doesn’t provide an incentive for innovation or risk with the possibility of higher rates of return. Furthermore, there is a substantial downside to risk taken by utilities for the public, regulatory bodies, and, potentially, Wall Street investors. Yet, to achieve public objectives of a cleaner and more efficient energy mix as well as state objectives for economic development and job creation, innovation is critical. And to drive innovation from the private sector, there needs to be the opportunity to ultimately supply a market with a product that achieves stated objectives.
Energy Innovation Pathway legislation would seek to advance innovative technologies within the utility sector and create markets for deployment of successfully demonstrated technologies.
Utilities in vertically oriented regulatory markets usually submit Integrated Resource Plans (IRPs), or their equivalent, to their regulatory commissions that chart large-scale investments in transmission, generation, and (sometimes) demand side management over an investment-planning horizon. The guiding principles of these IRPs are generally low cost and high reliability. As a result, IRPs tend to consist of traditional, proven technologies with a long history of performance.
Although there are thousands of different technologies that are beyond the lab and are capable of addressing various aspects of the energy sector, there have not been any good policy avenues for innovative technologies. If a utility wants to test a new technology, they can propose a pilot. But usually there is neither a pathway, nor a utility incentive, for successful pilots to translate into full deployment through the IRP process. All this reduces the marketplace for innovative technologies and increases uncertainty within the market for development of new technologies.
The proposed legislation would provide a pathway for innovative technologies within the energy sector by establishing a potential market for successful projects thereby reducing investor and ratepayer risk.
A fund is used as a credit enhancement and risk mitigation tool for technologies that are proposed to address specific public policy objectives (as defined by the legislature or the commission). While the proposed technologies will have projected performance criteria, the risk mitigation fund will protect ratepayers and utility investors in the event that those performance projections are not achieved. This could also be accomplished by establishing a certain percentage of ratepayer funds targeted toward selected D&D projects.
Since innovative technologies do not have a long history of demonstrated costs and savings, there is no basis upon which to establish “cost effectiveness” within the state’s cost effectiveness criteria (usually used as a way of developing a demand-side management (DSM) portfolio- see Section 1.9). As a result, projects included in pilots and passing the performance criteria would be allowed to waive cost effectiveness requirement for a specified period of time to allow for scaling of the market to drive down costs for each measure.
Establish a Budget for Design and Demonstration (D&D) Projects: Require the utility to spend no less than a certain percentage of DSM and distributed generation or renewable energy portfolios on D&D projects.
Performance Evaluation: Establish performance evaluation criteria to determine the success of pilot D&D projects and their inclusion as an approved resource in the IRP.
Critical to the innovation pathway is a mechanism for evaluating the performance of technologies included in the demonstration process. This evaluation should measure the costs and demonstrated performance of the technology, as well as the level to which the technology was able to achieve identified policy objectives.
The utilities commission should identify performance metrics for each D&D project that will determine whether the project will be more broadly deployed.
Market Pathway: Establish inclusion in the utility IRP process for pilot projects that achieve the approved level of performance in the D&D phase.
Innovative technologies often rely upon investor funds that need to see a predictable pathway to market penetration. Yet, market penetration relies upon not just technology performance, but also inclusion by the utility in their proposed resource plan. For this reason, there should be an inclusion of all technologies that meet established performance criteria through the innovation pathway into consideration of broader deployment throughout the utility service territory. This depends somewhat on the specific technology being included, for example: DSM and DG Technologies, once proven, would be included as eligible for incentive programs. Similarly, utility technologies (Demand Response, Smart Grid, Generation, Storage, etc.), once proven, would be approved for inclusion in the utility IRP. Finally, a utility incentive would allow utilities to recover an enhanced rate of return for technology that is successfully deployed in the market.
Pathway for Reducing Investor and Ratepayer Risk: The success of an innovation pathway relies upon a mechanism for financing innovative technologies that doesn’t risk utility ratepayer and investor credit and can be accessed through the established resource planning process. The financing pathway should be predictable and established so technological solutions can be proposed from interveners throughout the stakeholder spectrum and not solely through the utility’s proposed plan. It is recommended that a portion of ratepayer funds are carved out to finance this fund and that the legislature authorize the leverage for such a fund as a loss reserve or subordinated debt up to a specified percentage of utility investment. Alternatively, this fund could be used to directly finance D&D project deployment.
While energy policy often focuses on the inputs to a generation system (renewable portfolio standards, for example), emissions-based policies focus instead on the outputs of that generation.
Increasingly, there is concern about long-term impacts of various pollutants on air and water quality, human health, and global phenomena like climate change.
Emissions-based policies look at these outputs both from a regulatory standpoint as well as from a market perspective. While there are many emissions-related policies that fall under one of the other chapters in this book, this chapter deals with policies that operate across sectors and are less easily categorized.
Broadly speaking, emissions from the electricity sector have been declining in recent years - so much so that electricity sector emissions have fallen below transportation sector emissions for the first time since the late 1970s.
The decline in emissions is related to a wide range of factors: increasing efficiency of buildings and appliances, a de-carbonizing electric generation fleet, declining costs of both natural gas and renewable resources, and an aging out of some of our most highly polluting electricity resources. Combine these trends with policies such as renewable portfolio standards (Section 4.6), energy efficiency resource standards (Section 1.7), and building codes (Section 1.2), and the result is a cleaner, lower polluting grid.
Viewing emissions policies as outcome-based approaches also references policies like new utility business models (Section 2.4). In this chapter, we will take a more focused look at policies that are truly aimed at reducing emissions from the power sector and the transportation sector.
Perhaps it all starts with establishing an energy or climate plan - the nature of emissions objectives are inherently long term, both in implementation and in impact. International mechanisms like the Compact of States and Regions (Section 6.3) help states to measure and track progress toward emissions objectives. Aging Infrastructure Replacement (AIR) legislation assists states in planning a transition for aging generation infrastructure (Section 6.2). Emissions standards (Section 6.4) may mark a shift from technology specific standards, such as renewable portfolio standards, toward an outcome-based standard that recognizes the complexity of planning for an emissions objective across a portfolio of resources. Finally, adopting ZEV standards for vehicles (Section 6.6) offers states an opportunity to shift the curve of emissions from the transportation sector (other transportation specific policies such as Advanced Vehicle Incentives and Electric Vehicle Charging Infrastructure are discussed in the Transportation chapter).
The Aging Infrastructure Replacement (AIR) proposal lays out a process for states to replace aging coal-fired power plants with newer, more cost-effective, and cleaner resources.
Regional Haze standards, pending EPA greenhouse gas regulations, and the Mercury and Air Toxics Standards have all contributed to the market conditions that are leading many lending institutions to view highly polluting resources as risky investments. A combination of competition, economics, and aging infrastructure have compelled states and utilities to consider policy solutions for the shift from coal to cleaner energy sources, such as natural gas combined cycle (NGCC) and renewable energy generation. As the so called “first fuel,” energy efficiency can be added to the list of pollution-free energy resources.
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Two dynamics are undeniable in the US: 1) our coal generation infrastructure is aging and is in need of either replacement or a massive investment in upgrades; and 2) the country’s energy mix is rapidly de-carbonizing. This policy would establish a structure for replacing aging infrastructure with cleaner burning, and increasingly less expensive resources such as natural gas, renewables, energy efficiency, and nuclear energy.
Enabling legislation and regulatory policies that direct utilities to transition very old coal generating units to low-cost and low-carbon generation options may be key to compliance with existing and future federal regulations. This approach can maintain utility revenue requirements, provides regulatory certainty, and reduces ratepayer risk.
Legislation to accomplish this would instruct the Public Utilities Commission (PUC) to evaluate proposals to eliminate the highest polluting and oldest resources and replace them over a period of time with cleaner energy resources. Legislation may go as far as to identify certain plants or an overall MW reduction and specify emissions requirements or percentages of specific replacement resources (e.g.: Natural gas, 30%; renewables, 50%; and energy efficiency 20%).
As an example, The Colorado “Clean Air Clean Jobs Act” HB 1365 (2010) directed the PUC to accelerate the retirement of 900 megawatts (MW) of coal-fired generation already within 5 years of retirement and to replace or convert that capacity with other sources including natural gas, renewable energy, and end use energy efficiency. Subsequently, the PUC approved plans from Xcel Energy and Black Hills Energy that will reduce GHG emissions 28% by 2020.
This policy is a noteworthy case study of collaboration between a state air agency (the Colorado Air Quality Control Commission), the state legislature, and the PUC in both policy formation and implementation. Proposed resource plans were required to meet the designated pollution standards and be verified by the state’s pollution control agency (the Colorado Department of Public Health and Environment).
The Nevada “NVision” SB 123 (2013) directed NV Energy to submit a comprehensive emissions reduction plan to the Public Utilities Commission of Nevada (PUCN). In outlining the requirements of such a plan, the legislation directed the utility to retire at least 800 MW of coal-fired capacity, and acquire at least 350 MW of renewable capacity and 550 MW of capacity from other electric generating plants.
Targeting aging plants allows policies to minimize “stranded” utility coal assets – or those plants that will be closed ahead of their scheduled retirement dates. However, this objective should be viewed within the additional context of reduced risk, reduced cost to consumers, and the benefits of long-term investments in clean energy resources.
The Compact of States and Regions was created at the UN Summit on Climate in 2014 with a recognition that the actions on the part of sub-national governments (provinces, states, cities, etc.) were having a substantive and significant impact on climate when considered in aggregate, yet there was no way to track these actions and quantify their impact. The compact is managed and operated jointly by the Climate Group and CDP.
In the US, the combined population of states with a renewable portfolio standard is over 200 million people, yet when US action is evaluated internationally, the lack of a federal RPS makes it appear that the US is doing very little from a policy standpoint.
US energy policy is primarily established and implemented at the state level. The many policies outlined in this book are evidence of the robust state of energy policy activity in the US. States that join the Compact of States and Regions help to reflect the impacts of these actions on the international stage while also raising the profile of their leadership on energy to attract investment and economic development from the clean energy sector. This is an approach that both California and New York have pursued to great effect.
How do states join the Compact of States and Regions?
Joining the compact is easily done and tracking software is provided free of charge by the CDP.
However, states should identify the most appropriate agency and department for administration of the state’s membership. Membership requires a state to adopt a climate objective (reduction of greenhouse gas emissions over a period of time) and then track the progress toward meeting that objective. Taking part in the Compact gives states a verifiable system of measuring progress toward their goal. This helps to identify policies that work or do not work and locate the areas where the state needs to focus their efforts. This is not only an extremely valuable tool for the individual state, but the state also becomes a part of a larger network of sub-national governments across the globe.
States may wish to demonstrate their participation in the Compact of States and Regions by joining the “Under2” Coalition. One component of the Under2 MOU states, “participants will work toward consistent monitoring, reporting, and verification across jurisdictions, and will work through mechanisms such as the Compact of States and Regions and the Compact of Mayors to that end.”
The Under2 MOU was spearheaded by California and the German state of Baden Württemberg. The MOU has now been signed or endorsed by 46 jurisdictions representing 19 countries and five continents, collectively representing 497 million people and more than $14.6 trillion in GDP. If the signatories represented a single country, it would be the world’s second largest economy behind only the United States.
Each December, The Compact of States and Regions releases a disclosure report showing the contribution of sub-national governments toward meeting international climate objectives.
For more information on the Compact of States and Regions, contact The Climate Group.
Some states have created programs that drive greenhouse gas emission reductions either in certain sectors of the energy industry, such as electricity generation, or economy-wide, through the application of cap-and-trade programs.
Other states may see an emissions standard as the next step in a progression from successful renewable portfolio standards (RPS). The RPS greatly expanded the market for renewable energy which has led to lower costs and a mature renewable industry in the US. With the expiration of RPS target dates, states may want to switch to a technology neutral approach that looks at the total emissions of the utility portfolio - driving those emissions down with a combination of renewables, traditional fuels, efficiency, and technological advances. For more information on RPSs, see Chapter 4: Renewable Energy. Emission standards are designed to drive emission reductions either through carbon portfolio standards or by joining a market that spurs emission reductions through interstate trading markets.
One of the advantages of a market-based program is that it does not mandate carbon reductions from specific facilities, but rather is designed to reduce emissions in the most economically efficient manner possible. Such a standard may also address other concerns such as environmental justice or water reduction.
Emissions standards can take a variety of forms including a multi-state trading regime (such as the Western Climate Initiative or the Regional Greenhouse Gas Initiative) or a state- or utility-based approach that targets a specific utility’s resource investments over time and steers those investments toward lower polluting resources.
Under the market-based structure, a state or a group of states might require a certain percentage reduction in carbon emissions, for example, from 1990 levels by 2050. This reduction will be achieved by the distribution of annual emission allowances that decrease to the point when the standard is met in 2050. Other states may establish a portfolio emissions standard that reduces over time and implement it through an Integrated Resource Plan (IRP) with the utilities commission or establish a maximum allowable rate of emissions per unit for commission approval.
A multi-state market-based program establishes an agreed upon reduction in emissions across a broad region and then allows affected entities to buy and sell allowances. In this program, firms that can more efficiently reduce their emissions will choose to do so and then they can sell their allowances to other firms that cannot easily reduce emissions.
By monetizing the reductions at these facilities, utilities can reduce the facility costs usually borne by their customers and avoid stranded assets in operating facilities that may not meet the emissions standard, while also saving their customers money. These programs may also spur technological changes, as carbon performance standards have done, but they do not inherently require them.
There are currently two active markets in the US trading emissions: the Regional Greenhouse Gas Initiative (RGGI) in the North East, and the Western Climate Initiative (WCI), currently operating in California (with participating Canadian Provinces). Both of these trading regimes may be interested in additional partner states - greatly reducing the cost and time of developing a parallel trading regime from scratch.
A state-based emissions performance standard would limit the emissions from a portfolio of utility resources. This could be implemented through the public utilities commission and/or the Integrated Resource Planning (IRP) process, where a utility would propose a mix of generation investments that would be required to meet a declining rate of emissions over time. Approval of a resource plan would be contingent on demonstrating that the portfolio of resources would meet emissions standards. Such a demonstration could be conducted or verified by the state’s air regulatory agency.
While the EPA’s Clean Power Plan’s future is uncertain, an emissions standard could be structured in such a way that it would meet the requirements of the regulation - either through the IRP approach or the market-based approach.
State energy plans (SEPs) are developed in order to provide guidance for meeting current and future energy needs sustainably, reliably, and cost-effectively. While the motivations for developing a SEP are likely to vary across states, most state plans address emerging environmental and energy security concerns. These two sources of motivations are most obvious in the use of Climate Action Plans (CAPs), which take the place of SEPs in some states.
Climate Action Plans generally include a target date and a set emissions reduction objective, while identifying the sectors covered by the plan - for example, whether the plan is intended for the electricity sector or is an economy-wide plan (including transportation, space heating, industry, and the electric sector). A CAP may also direct the energy office to develop an SEP that would comport with the emissions objectives of the Climate Action Plan.
Plan development and planning procedures are typically mandated by either legislative or executive action, and administered by State Energy Offices (SEOs) and/or Public Utilities Commissions (PUCs). These authorities typically provide a public comment period to gather input from multiple public and private stakeholders.
Ideally, SEPs are comprehensive documents that set clear goals, action items for meeting those goals, and metrics for evaluating success. In practice, existing plans vary from state to state. Differences exist in the sectors covered, the specific targets, and the new policies and programs proposed to achieve the plan’s objectives. Finally, plans vary in the extent of administration committed to evaluating outcomes. While some set clear, measurable goals, outline specific timelines, and provide metrics and processes for evaluating success, others provide more general goals and action items. However, there may be an emerging trend towards increasing comprehensiveness and attention to program measurement and evaluation.
Because the effects of climate change are now observable and many states are already experiencing the impact of climate change, climate plans may also include an adaptation component. Adaptation plans will generally be predicated on a scientific evaluation of potential impacts to the state in the foreseeable future and propose adaptation strategies to mitigate those impacts. Such a study may be performed or contracted by the relevant state agency such as the environmental regulatory agency or similar department within the state’s administrative structure.
To ensure automakers research, develop, and market electric vehicles, the Zero Emission Vehicle (ZEV) program in California requires automakers to sell an increasing percentage of electric cars within the state. Managed by California Air Resources Board (CARB), the program aims for 1.5 million ZEV sales in the state by 2025, as outlined in this Action Plan.
The state of California has the unique ability under Section 209 of the Clean Air Act (CAA) to adopt a vehicle emissions standard stricter than that set by the federal government. Other states can’t create their own standard as California can, but, under Section 177 of the CAA, they do have the option of adopting California’s standard as an alternative to the federal standard.
California’s ZEV Standard requires vehicle manufacturers to sell a certain number of ZEV qualified vehicles within the state as a percentage of their overall fleet of vehicle sales. Automakers are assigned a baseline number of credits depending on the percentage of an automaker’s conventional gasoline and diesel light-duty vehicle (LDV) sales, averaged over the previous three model years. Over time, the total percentage of credits increases from 4.5% in 2018 to 22% in 2025 (See Figure 6.5).
Because ZEVs vary in range and in emissions (for Transitional Zero Emission Vehicles (TZEVs) or Partial Zero Emission Vehicles), compliance credits vary from model to model. For example, the all-electric Nissan Leaf counts as 1.8 ZEV vehicles while the Tesla model S counts for 3.3 vehicles based on its range. To further incentivize the sale of battery electric and fuel cell vehicles, only a certain percentage of ZEV credits may originate from hybrids and other TZEVs. As Figure 6.5 shows, the minimum share of credits for battery and fuel cell vehicles increases over time. ZEV Credits may be traded regionally among manufacturers, as discussed below.
Ten States have exercised Section 177 of the CAA and adopted California’s ZEV standard. By adopting the standard, vehicle manufacturers are required to sell a certain number of ZEV vehicles in the state. However, the standard makes it easier for manufacturers by allowing tradeable credits among regional markets (western and eastern) and a variety of classifications of vehicles that count toward the standard in varying degrees. The Multi-State ZEV Task Force, which is comprised of eight of the 10 states that have adopted California’s standard (Maine and New Jersey are not members), provides a network of multi-state initiatives and best practices, along with a multi-state Action Plan. Together, the member states have set a goal to reach 3.3 million ZEVs on the road by 2025.
Because the standard will change in 2018 and runs through the next seven years to 2025, states considering joining the ZEV market should make the legislation effective beginning in 2018.