Solar Financing – Part 3: Third Party Ownership

In the distributed generation world, TPF is a financing structure that provides a workaround to the limits placed on tax equity funding by a developer’s tax appetite. It allows the solar/storage developer to reap the benefits of the tax equity provided by the incentives described in Part 2 (or other related incentives) by going through a third party financier. When the financier is used for this purpose specifically they are called a tax equity financier. This is accomplished essentially by the developer trading ownership with the financier (who has a much larger tax appetite). The topic of this post will be the three primary routes by which TPF is accomplished: sale-leasebacks, partnership flips, and inverted leases (summarized form Woodlawn Associates).

First, there are three primary players and a few key terms to be defined:


  1. Developer: The solar or storage developer in charge of identifying and executing the project.
  2. Tax Equity: This is the financial party to which the project ownership is transferred in order to take full advantage of the tax credits.
  3. Customer: The beneficiary/ host of the project who will be receiving the energy or value of the energy, likely through a lease or PPA.

Key Terms

  1. Fair Market Value (FMV): This is generally defined as the price at which an asset would change hands between a willing buyer and a willing seller given both have reasonable knowledge of all the relevant facts. There are three commonly accepted ways to determine this value: (1) income – the income that will be generated by the asset; (2) market – the cost of similar assets on the market; (3) cost – the cost to develop or replace the asset.
  2. Special-Purpose Entity (SPE): A legal entity created to carry out only a specific set of tasks. By limiting the SPE’s operations, they can isolate financial risk from their parent company, and therefore are often used for complex financing situations.


The sale-leaseback is the simplest of the three financing structures where the Developer contracts with a Customer before handing it off to the Tax Equity firm, who acts as the middleman. Steps 2 & 3 relate to the financing transaction, while 1 & 4 are standard to any developer-customer transaction.

Figure 1: Sale-Leaseback Diagram
TPF_sale-leaseback diagram.PNG


  1. Developer identifies Customer, signs the contract (lease or PPA), provides/ contracts engineering, procurement, and construction (EPC) for the system.
  2. Developer sells the system and the contract to Tax Equity. Tax Equity is now the owner and can take full advantage of the relevant tax incentives (ITC & depreciation).
  3. Developer leases the system back from Tax Equity at agreed upon rate.
  4. Developer charges Customer monthly fees (higher than the lease cost from [3]).


  • This is the simplest option.
  • Allows full transfer of tax benefits to Tax Equity (because the purchase price associated with the tax benefits is now based off of the Developer-Tax Equity transaction, which often includes a marked up development cost, the benefits will be correspondingly larger).
  • Minimal financing required from Developer.
  • Buffer time between system completion and financing structure (90 days).


  • Most of the capital comes from Tax Equity. Because the cost of capital from Tax Equity is usually high compared to other forms of financing, this can lead to an inefficient financing structure.
  • Depending on the structure of the Developer-Tax Equity and Developer-Customer contracts, the developer can be exposed to significant performance risk.
  • Developer loses ownership. If they want to reclaim ownership at the end of the lease, they will have to pay FMV (contract must be structured such that FMV is 20% at the end of the lease).

Partnership Flip

Under this financing structure, the Developer (sometimes called “Sponsor” in this scenario) and Tax Equity partner to form the Project Company, a joint venture SPE made specifically to own the development and allow transfer (“flips”) of distribution of profits, cash, and benefits back and forth between the parties. The Project Company is organized as an LLC so that income taxes are paid on the entities individual corporations as opposed to the Project Company.

The “flips” provide the means for the general functions of a Sale-Leaseback, without a complete transfer of ownership. A common partnership is split into two phases. (1) The vast majority of tax benefits, profits, and losses are allocated to Tax Equity (the distributions of profit and tax benefits do not have to match). Over this period there are usually losses, which reduces Tax Equity’s corporate tax payments. (2) After a minimum of 5 years, the allocations “flip” such that Developer receives the majority of the attributes. If the flip is executed before year 5, a portion of the tax benefits will be recaptured by the government. After the flip, Developer often has the option to buy out Project Company.

There are two primary categories of these flips: (1) Yield-based flips are subject to the performance of the assets; the flip does not occur until Tax Equity meets its predetermined return – these are the most common; (2) Fixed flips are not conditional on a specific return being met, rather they flip at a predetermined date regardless of performance – these are less common and make most sense when tax rates are very stable.

Figure 2: Partnership Flip DiagramTPF_partnership flip diagram.PNG


  1. Developer (Sponsor) and Tax Equity provide capital (majority usually provided by Developer) to Project Company.
  2. Project Company provides/ contracts EPC of system.
  3. Customer enters lease or PPA and makes associated payments.
  4. Project company distributes the tax benefits (usually ~99%) and enough cash to meet the target IRR to Tax Equity (cash is not synonymous with profit). The remaining tax benefits and cash is distributed to Developer.
  5. Assets and attribute “flip” to a new distribution after tax benefits have been used/ Developer buys out Project company.


  • The structure is well established and is widely used in renewables.
  • Reasonable buyout price for the developer after the flip.
  • There are rarely fixed payments meaning that under will not have direct monetary costs but rather will cause a delayed flip.


  • Requires a much larger capital investment from Developer than a Sale-Leaseback.
  • Maintains a slight risk to the tax appetite of Developer.
  • Developer must enter the partnership prior to the assets being installed.
  • High overhead, especially in legal and accounting.

Inverted Leases

There are two types of inverted leases which are structured differently so they will be broken down separately. These inverted leases are basically inverted forms of the two structures we already discussed which keep ownership in the hands of Developer. The first is a Simple or Clean inverted lease and the second is a Partnership inverted lease.

Figure 3: Inverted Lease (Simple) DiagramTPF_inverted lease-clean diagram.PNG

Steps (Simple/Clean):

  1. Tax Equity leases the system from Developer, allowing the Tax Equity to receive 100% of the incentive.
  2. Tax Equity makes lease payments to Developer.
  3. Customer makes scheduled payments to Tax Equity.
  4. After the lease term ends, Customer pays Developer directly.

Steps (Partnership): The primary role here is to allow Developer to keep nearly half the tax benefits. For this reason it is not as favorable to Tax Equity financiers. Two new SPE’s are created in this TPF agreement, the Master Tenant and the Owner/Lessor.

  1. Developer and Tax Equity fund a new entity called the Master Tenant (similar to the Project Company). Tax Equity funds the vast majority (~99%) of Master Tenant.
  2. Developer and Tax Equity fund another new entity called the Owner/Lessor which takes ownership of the solar system. Structured such that Developer is the majority owner (~51%).
  3. Owner/Lessor provides capital to Developer.
  4. Owner/Lessor leases system to Master Tenant, passing the ITC benefits over as well.
  5. Master Tenant subleases to Customer in exchange for scheduled payments. Master Tenant passes some of this payment to Owner/Lessor.
  6. After lease term ends, Customer pays Owner/Lessor directly.
  7. Developer and Tax Equity take ITC benefits proportional to their ownership of Master Tenant (~1:99 respectively).
  8. Developer and Tax Equity take depreciation benefits proportional to their ownership of Owner/Lessor (~51:49 respectively).


  • Developer keeps some of the depreciation benefits (not always a pro).
  • Because the recipient of the ITC is a lessee and therefore has no insight into the actual cost of the project, ITC amount is based off of the FMV according to the appraised value of the transaction.


  • The lowest portion of tax benefits go to Tax Equity in this structure.
  • Highest tax structuring risk.
  • This is not a common structure and is usually unfavorable to Tax Equity.

These posts show the wide spectrum of difficulty that can be involved in getting solar financed and installed. I haven’t included all the considerations, yet it is clear a standard homeowner looking to put some panels on their roof already has some tough decisions. Further, the complexity of the decision tree for a developer of large commercial or industrial projects grows exponentially. What is the limit to cost of installation, O&M, and other overhead to meet my desired rate of return? How much funding will be required and where will it come from? Who is going to take the tax benefits? Which tax benefits even make sense given their limitations? The ramifications of these complex considerations are what determine the financeability of a project. They may not be a necessity for everyone in renewables to understand, but a grasp of the fundamentals can prove to be very useful.

Solar Financing – Part 2: Programs and Incentives

This second post in our series on financing renewable projects will build on Post 1 to provide an introduction to the available programs and incentives that make solar & storage investments particularly attractive. Government programs and incentives have historically fostered technological innovation by increasing it’s financial viability [ brief | dive ]. While there is undeniable value in the services provided by distributed generation, like peak shaving, demand management, and demand response, the market has not yet quantified the value in potential revenue streams.  Therefore, what often makes a project viable are the available government programs and incentives. Unfortunately, the interrelations between the numerous federal and state incentives are difficult to navigate. On top of that, they can vary greatly from state to state, making it hard to determine what path is best for a project. To simplify things, in this post we will review only four of the largest and most widely used renewable programs and incentives: Net Energy Metering, Feed In Tariffs, Investment Tax Credits, and Bonus Depreciation & MACRS.


The following programs are meant to encourage faster adoption of renewable energy resources but are not necessarily meant to be scaled in the long run. Thus in general, these incentives will ramp down over time to prevent overburdening of the grid and oversaturation of the market.

Net Energy Metering (NEM): NEM is a program that allows on-site generated energy to offset the site’s energy consumption. However, unlike a standard non-export, behind the meter generating facility (GF), under NEM, all excess on-site generation can be exported to the grid in exchange for credit equal to the cost of purchasing that same energy. Unused credit at the end of a monthly billing cycle is carried over to the next billing cycle instead of being lost. There is also an option to participate in Net Surplus Compensation (NSC), a program that allows net GF’s (GF’s that produce more energy than they use) to be compensated for their overproduction on a yearly cycle at wholesale prices. Under NEM the grid basically becomes a battery of unlimited capacity, minus the ability to conduct demand management and other cost saving functions which would require control. This is incredibly valuable for desired generators as the risk of overproduction is greatly reduced. NEM programs often have a system size cap (usually as a capacity or % of load), which creates a threshold to how many credits could be generated, but it is much more appealing than the alternative of losing any excess generation.

NEM in CA: California has been a pioneer of the NEM program and the clear leader in installed NEM capacity (over 2 GW installed to date). In July 2017 CA shifted from NEM-1.0 to NEM-2.0 (which will last until 2019). This marks the first stage of its transition from the original program and adds a few important updates: (1) All customers installing a solar system will be automatically switched to Time-of-Use (TOU) rates. This means that the value of the exported excess energy depends on the time during which it was exported (i.e. energy exported during an on-peak period will be worth more than energy exported during an off-peak period), making the option of choosing when to export energy through a combination of solar + storage even more appealing; (2) there is an additional interconnection fee required depending on your utility; (3) NEM facilities are no longer fully exempt from Non-Bypassable Charges (NBCs) (under NEM-2.0, all energy delivered by the grid will be subject to NBCs of ~0.02 – 0.03 $/W).

Feed-in Tariff (FiT): A FiT is similar to NEM in that it allows export to the grid. However, unlike NEM, exported energy is sold to the grid at a predetermined price, not stored as credit. This means there is no limit to how much energy one could export to the grid. Since rapid and large increases in exported energy can cause serious strain on the grid, many utilities have built in disincentives: (1) The base price is usually lower than the purchasing price of energy; (2) most states have either a project cap or program cap to limit the gross generation operating under the FiT program; (3) some include a “tariff degression” – a tiered decrease in selling prices based on how much or how long energy has been sold in the program.


Similar to the programs above, these incentives are to create action NOW. Therefore they are limited in time and often contain degressive tiers.

Investment Tax Credit (ITC): The federal ITC permits purchasers of specific items (solar systems and battery systems are among those included) to take a tax credit equal to 30% of the investment. This is tiered down over time to 26% (2020); 22% (2021); 10% (2022+). Because solar developments can be fairly expensive, these 30% tax credits often correspond to large amounts of money in credits. Therefore, to take full advantage of the ITC, the developer must either have a large enough tax appetite (which is uncommon), or they must enter a third party financing agreement with a tax equity.

Bonus Depreciation & MACRS: Bonus Depreciation and MACRS (Modified Accelerated Cost Recovery System) are federal incentives designed to encourage and accelerate investment in private development. Each incentive reduces the timeline of depreciating an asset, reducing tax liability and increasing rate of return on an investment. Note: Projects utilizing the Federal ITC must reduce the depreciable value by half of the ITC credit (if 30% ITC is claimed, a 15% reduction or 85% total depreciable value).

Bonus Depreciation: As a response to the 2008 recession, Congress passed an Act allowing companies to depreciate a larger portion of their investment in its first year. It started as 100% bonus depreciation for capital investments put in place by December 31, 2011, but has since been extended multiple times to its most recent iteration – a tiered degression. The tiers are as follows: 50% bonus (2015-2017); 40% (2018); 30% (2019); 0% (2020+).

MACRS: Similar to Bonus Depreciation, MACRS are a method to accelerate the depreciation process. However, instead of a single year increase, MACRS allow an investment to be depreciated over a set shortened timeline. For solar, this is a 5 year recovery period, but the timeline varies depending on the technology being depreciated. The exact yearly depreciation varies (usually weighted more heavily towards the early years), but a 5 year recovery period averages to 20% a year.

These particular incentives are not mutually exclusive; a single project could use any number of the above incentives in parallel. To see how they affect each other, here is an example case:

Ex Program Incentive Table v4.PNG

Ex table legend v4.PNG

In total, the first year tax deductions are equal to $454,700 ($300,000 from ITC and $154,700 from depreciations). This equates to a ~45% savings on your investment within the first tax year!

As you can see, these incentives lead to massive savings, showing why they can be so influential in encouraging investment. While the total amount of savings is the same regardless of the depreciation route you take, the depreciation incentives above provide the cash in hand at a much earlier date (full depreciation in ~5 years rather than ~35 years). Earlier return means quicker access to capital and in turn a quicker return on  investment. Combining the decreased cost of investment with the program benefits makes distributed generation a more valuable asset and a very attractive investment.

Solar Financing – Part 1: Fundamentals

Solar photovoltaic installations are historically pricey investments, but over the past few years there have been significant cost reductions that make them competitive with other renewable, nuclear, and even fossil fuel generators. A common metric to measure the competitiveness of renewables is the levelized cost of energy (LCOE). If the LCOE is equal to or less than the cost to purchase the same amount of energy from the local grid, then it is said that the renewable resource has grid parity in that region. This is an important concept as it is a strong indicator of whether a renewable development will be viable or not. In 2016, Greentech Media (GTM) reported that residential solar has reached grid parity in 20 states of the US, and predicts that 42 states could reach grid parity by 2020 under business-as-usual conditions. The recent tariffs [ brief | dive ] will alter this trajectory of course, but most analysts consider this as a temporary setback, not an industry killer. The point is that the base cost of solar is becoming less and less expensive, allowing it to compete with other forms of energy – add on federal and state incentives and you have a very attractive investment. This series of posts will aim to clarify the many terms and types of agreements / relationships used in the financials of solar (and other renewable energy) developments.

PART 1 – Fundamentals: basic consumer-developer relationships

First, there are three fundamental structures for which the end userdeveloper transactions: Cash Purchase, Power Purchase Agreement, and Lease. The following evaluates each method from the perspective of the end user:

  1. Cash Purchase: This is just as it sounds – a complete upfront purchase of the system.

Pros: By taking full ownership of the solar system, the end user receives all of the generation, full access to whatever incentives apply, and a faster project timeline as there is no need for a third party credit evaluation.

Cons: A cash purchase is inherently the highest risk option for the end user. Full ownership of the potential gain also means full ownership of the potential risk. Without an external party managing the system, the end user will have to contract with another firm to operate and maintain (O&M) the system, or perform that work themselves. Lastly, the purchaser may not have a large enough tax appetite (ability to use the available tax credit) to take full advantage of the available incentives. In addition to these risks, because of the size of the capital investment, cash purchases usually are of residential or commercial projects.

  1. Power Purchase Agreement (PPA): A financing agreement which allows the end user to purchase solar electricity at a fixed price (lower than local electricity prices) in exchange for hosting the project. The solar system is installed on the host site, but the host does not own the system.

Pros: Because this is merely an exchange of goods and services (host site for lower cost of electricity), there is no capital investment needed, usually providing immediate net positive returns. The fixed price also protects against rising utility prices. Unlike a cash purchase, the third party accepts the performance risk as well as O&M responsibility. The third party usually has a larger tax appetite, making it more likely for the incentives to be received in full. These savings can then be passed down to the end user in the form of cheaper electricity prices.

Cons: It can be a very complicated and long contracting process, a credit review is required, and the project timeline will be longer than a cash purchase (by a month or so depending on the complexity of the legal agreements).  Additionally, most models assume aggressive changes to utility pricing which may result in less savings over the course of the project lifetime.

  1. Lease: Again, this is just as it sounds – the end user will receive access to a solar system in exchange for monthly lease payments. This is similar to a PPA, but instead the lessee receives direct access to the generated energy instead of a reduced $/kW price. Often, there will be an option to buy out the system towards the end of the lease.

Pros: This requires little to no capital investment upfront, making solar accessible to a wider range of economic backgrounds. This also protects against rising utility prices and usually provides an immediate net positive return. Depending on the terms of the lease, the user may assume no O&M responsibility.

Cons: This is generally the least favorable option of the three. On top of its inherent faults, their contracts are usually the most aggressive and malicious – commonly written with hidden charges, unspecified payment increases, and other unfavorable terms. This isn’t to say that a lease is never a viable option, but that the terms and conditions should be evaluated closely. A lease requires the strictest credit requirements and the most complex legal terms, therefore they will usually have the longest project timeline. The investment is also the least efficient of the three options: unless a buyout is enacted, the investment disappears at the end of the lease; the total lease payment is likely more costly than the total payment by any of the other financing means. Finally, because the lessor receives a fixed monthly payment regardless of the energy produced, the lessor assumes very little performance risk and therefore lacks the incentive provided by a PPA.

Check out Part 2!

We’ve been Fluxin’ for 2 years!

Flux has been in business for two years!   I am so proud of Flux’s accomplishments, yet I am humbled by our customers and mentors who are changing the world.  It has been inspiring to work with

Scrappy startups launching convention-defying technology,

Brave entrepreneurs exploring new markets around the world,

Principled policy experts attacking century-old regulations, and

Developers seeking environmental equity for all communities.

I am especially grateful to my team.  Your hard work and good-humor make even the most stressful days enjoyable, and your dedication to our clients is what makes us successful.

Check out some photos of the past two years.

Part 3: EV Charging Stations – Utilities

In our last two blog posts (Part 1; Part 2), we have reviewed the different types of charging station hardware, and service providers.  The third critical player in charging station development is the electric utility.  Some utilities are advocating for EVs since they see the possibility of stealing market share from gasoline and diesel suppliers and want to be proactive in defining the grid-interface.  On top of that, EVs are a great way for utilities to green their image, since EVs frequently appeal to a similar segment of customers who otherwise may defect from the grid.  

Los Angeles has two primary electric utilities: Southern California Edison (SCE) an investor-owned utility and Los Angeles Department of Water and Power (LADWP) our municipal utility.  The former has a relatively forward thinking “Transportation Electrification” program, while the latter provides a simple rebate as part of their Charge Up LA! program.

SCE offers a number of different programs to their business and residential customers encouraging the installation of EV charging.  For anyone interested in EVs, the SCE website is a great reference with summaries of rebates, installation FAQs, and even sample workplace surveys to help business owners assess the value of installing EV chargers.  Ultimately, they control the EV charging through their time-of-use (TOU) rates.  This means that the cost of energy varies throughout the day and encourages off-peak EV charging.  TOU rates are frequently looked upon as the first, critical step to monetizing grid services.  Creating a market for grid services such as demand response, voltage regulation, and peak shaving, allows for innovative business models that make EVs and other technologies valuable.

LADWP’s program is far simpler and less comprehensive than SCE’s.  It offers a rebate (~$4000/charger) for residential and commercial charger installation.  The rebate application requires technical documentation that emphasizes product selection and quality of installation.   While this helps consumers make the jump to EVs, the structure of the program does little to enhance integration of the vehicles to the grid.

While LADWP and SCE’s programs are fairly different, there is one thing in common – the application process is tedious, requires professional support and understanding of a lot of fine print.  This provides great opportunities for businesses like us, but makes it frustrating for consumers.  

As more vehicles connect to the electric grid, forward-thinking electric utilities will see their potential value.  Among many other grid services, electric vehicles could minimize the impact of renewable intermittency, improve grid resiliency and provide demand response services, but this will only happen at scale if there is monetary value associated with each service.  SCE is conducting a number of pilot programs to evaluate different models for “Transportation Electrification.”  There are also many startups clamoring with new technologies to ease the problem. We look forward to seeing how new hardware, innovative software and forward thinking utilities integrate EVs into our electric grids!  



EV Chargers:

Everything else SCE:

Part 2: EV Charging Stations – Software

As we covered in last week’s blog post,  more drivers are purchasing Electric Vehicles (EVs) over conventional gasoline and diesel powered cars.   Accordingly, a market has developed around the supply and installation of the charging station hardware.   With only 300,000 EV’s on the road, the market is still small, but it is rapidly growing.  There has been a 3000% rise in EVs since 2011! [Elkind, Ethan, 2017] To further increase their sales, some automakers are now partnering with charging service companies to provide a comprehensive service offering to their customers.

As charging station hardware has developed, so too have the business models for public charging stations.   Public EV charging stations fall into three primary categories: (1) non-network, pay as you go, (2) networked, subscription based, and (3) free [Berman, Brad, 2014]. Companies who provide networked charging stations advertise the following benefits:

  1. If a driver is part of a network he/she will have a membership which dictates the price of charging.  This can benefit drivers with discounted rates compared to out-of-network drivers.
  2. Network stations are easy to find.  The network providers maintain databases and maps of the stations which allows the EV driver to find the closest available station instead of driving around to find an open charging station. A non-networked charger is not part of any connected map; it is a stand alone piece of equipment and cannot transmit or receive information.
  3. Network stations have remote support for EV drivers. Support agents can remotely unlock a charging station and also monitor and maintain the stations. This cannot be done for non-networked charging stations where a technician has to troubleshoot problems in-person
  4. When a driver is part of a network of chargers, they are able to join a waitlist when there is a demand for charging. The charger hosts track the use of individual chargers and prevent drivers from monopolizing chargers.  Non-networked chargers do not have similar systems in place, so, except by increasing the hourly rates to charge, they are limited in their ability to control wait times.

The amount of time required for full charge is a critical feature for an EV owner in their selection of charging infrastructure.  This rate is determined by the electric vehicle and the charging station technology.   Charging stations fall into three categories:

  1. Level 1 is the standard wall outlet. It is the slowest charge level requiring 8-15 hours to fully charge a vehicle.  Due to the slow rate of charge, these are rarely installed in public.
  2. Level 2 is the typical EV plug that homeowners frequently install in their garage. Many public charging stations are Level 2 chargers. 3-8 hours are required to fully charge a vehicle.
  3. Level 3 (DC fast charge) – These charging stations are the quickest means to recharge a vehicle. It takes typically 20 mins to 1 hour to fully charge a vehicle. An example for this would be the Tesla supercharger.

ChargePoint and EVgo are two of the larger EV Charging Station Networks.  Both are comprised of Level 2 and Level 3 chargers. [Berman, Brad, 2014]  ChargePoint owns chargers at both residential and commercial properties.   Their network includes a proprietary energy management software, a mobile app, full installation services and ongoing maintenance.  They have partnered with companies throughout the supply chain including hardware manufacturers such as Eaton and Schneider, automakers such as BMW and Nissan, resellers, local installation and maintenance partners.   

EVgo is another “full service” company. They too design, manufacture and support the technology for their charging stations, but they primarily deploy Level 3 chargers for businesses.  This has made them have the largest network of public Level 3 chargers in the nation [Ayre, James, 2017]. EVgo has also become competitive by offering BMW and Nissan EV drivers charging incentives for being a part of the EVgo charging network.

Currently, “full service” companies are dominating the market, but the electric vehicle industry is still in its infancy. As the demand for EVs continues to grow, and EV’s become mainstream, there will be new technical, financial and policy-based innovations that will shape the market.   


Elkind, Ethan. “California Needs More Electric Vehicle Charging Stations to Keep Pace with Demand.” The Berkeley Blog, 25 Sept. 2017,

Ayre, James. EVgo Opens Its 1,000th DC Fast-Charging Station In US. 6 Dec. 2017,

Berman, Brad. “The Ultimate Guide to Electric Car Charging Networks.”, 8 Jan. 2014,

Part 1: EV Charging Stations – Hardware

Many people don’t realize that the the first small scale electric cars were made all the way back in 1830! However, by the mid 1930’s they were abandoned for the most part. Now, almost 100 years later, new players like Tesla have rejuvenated the EV market. Picking up off the hybrid trend popularized by the Prius, a period of high gas prices, and a growing awareness of the environment, EVs have disrupted the car manufacturing market, forcing the public to accept an alternative to the gas standard. The ultimate goal of EV’s is to create a cleaner, more sustainable transport infrastructure, but to have a significant impact, scale is key.

Roughly 20% of all US emissions come from personal vehicles[1]. With EV’s representing only 0.22% [ChargePoint 2016 report] of the personal vehicle fleet in the US, there is clear room for improvement. However, for EV’s to hold a significant portion of the market, three things must be true and stay true. EV’s must: (1) have public appeal, (2) be cost competitive, and (3) have the infrastructure to accommodate the charging of large fleets in reasonable time periods. (1) & (2) have seen substantial progress over the last few years, but (3), charging infrastructure, is just beginning to ramp up on a large scale.

Before we dive in, some fundamentals in EV charging are necessary. EV’s are currently charged through either an AC charger or a DC charger. Car batteries run on DC, so AC chargers commonly utilize an inverter internal to the EV, while DC chargers will have a separate inverter specific to the charger to convert the electricity from the grid. For this reason, AC chargers are much more limited in their ability to charge at higher speeds. There are multiple levels (speeds) and standards (connection hardware) associated with these. The levels may vary by location. See Table 1 for a summary of the charger levels and standards.

Standards are important because chargers will only work if the charging standard of the charger matches the charging standard of the car. Generally, car manufacturers have chosen their charging standard according to the region. You cannot charge across different standards – it would be like trying to plug an American plug into a European outlet. Charging levels matter because they dictate the rate of charge. So when charging manufacturers look to develop a charger, they have to decide which standard(s) and which level(s) make the most sense for them to produce.

Charging Levels (power output) Typical Charge Time Charging Standard
Level 1 (Standard Plug) 8-15 hrs J1772
Level 2 (Menekkes) 3-8 hrs J1772, Tesla
Level 3 (DC Fast) ~1 hr CCS, CHAdeMO, GB/T, Tesla Supercharger
Level 3 (DC Ultra-Fast) <30 min CCS

Table 1: Charging levels and standards.

As seen in Table 1, there are currently 3 major standards in the DC fast charging market apart from Tesla, each associated with a region: CCS (North America and Europe), CHAdeMO (Japan), and GB/T (China). In late 2016, automaker powerhouses, BMW, Daimler, Ford, and the Volkswagen Group with Audi and Porsche, declared a joint venture to deploy 400 ultra-fast (350kW) CCS charging stations in Europe. While Europe joining America’s standard would seem to imply that CCS has won the battle for the fast charging standard of choice, China has the largest and fastest growing EV fleet in the world, so GB/T cannot be ruled out just yet.

Most charging manufacturers exist as more than just charging manufacturers. The spectrum ranges from large electrical companies like ABB who have a branch producing chargers, to specialized vertically integrated EV charging companies like ChargePoint, who handles everything from manufacturing to charging services and more. In general, however, charging manufacturers will offer a range of products to support the needs of various types of customers. Residential options include level 1 and level 2 chargers, while public charging stations require faster charge times and thus a level 3 charger. Manufacturers will also usually offer different variations of chargers to support different options for charging standards. Only ABB offers multiple standards and levels in a single charger.

Global EV Outlook 2017 reports that despite massive public charge station growth in 2016, there are only 212,000 public slow charger outlets and 110,000 public fast charger outlets for the 2 million EV’s in the world. That is a ratio of more than 6:1 EV to public outlets, implying that most EV owners are using private chargers. Inevitably, a successful solution will have a combination of residential, private/business, and public charger options, but I believe the most important component for large scale public adoption is a significant ultrafast charging infrastructure (>200kW). These could become synonymous with our current gas stations and relieve users (or autonomous cars) of the stress associated with long charge times and unavailability of charge stations. A future of large scale public charge stations means that a universal standard, agreed upon across car manufacturers and charger manufacturers, would be the most efficient path forward. However, a universal solution is likely years down the line, and in the meantime, the battle for charging standard will persist.

We must also consider the fact that to accommodate such a charging infrastructure, a corresponding electrical infrastructure upgrade will be required. Many charger manufacturers and software providers have created a workaround to inadequate infrastructure through demand management, basically allowing manual or automated setting of charge rates. By allowing a lower charge rate, property owners can increase the maximum number of operating chargers. However, this means that any time the number of people charging crosses a certain threshold, the chargers will not be acting at their nameplate capacity. Ideally, infrastructure would be upgraded to allow for charging of large fleets at full capacity, recognizing the full potential of EV’s.

On a forward looking note, it can be fun and useful to envision the future technologies of charging infrastructure. Some things we have started to see or can hope to see are induction chargers and portable chargers. Induction chargers aren’t a serious competitor at the moment, but ABB recently introduced a fast charging induction charger for public transportation that would be installed at select bus stops to quickly replenish the bus along its route. Portable chargers are another solution to the same problem. Instead of creating new lots for the charging of large EV’s, people are envisioning new ways to bring the charging to the vehicle. An exciting version of this would be drone delivered charging, where the vehicles would never even have to stop their route! Amazon has already been granted a patent for a roving drone that would charge personal EV’s as you drive. Of course for all of this to matter, EV’s still need to beat out hydrogen cars for the title of the preferred alternative to gas vehicles.