# Solar Photovoltaics

Solar Photovoltaic systems use solar energy to create electricity. In 2010, the solar PV industry was the fastest growing industry in the US, with a growth rate is 69%.

Read the Guide to Financing Commercial Solar Projects
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Click here if you want to see 60 minutes of videos answering 8 questions about best practices for financing commercial solar power purchase agreements.

If you’re brand new click here to learn what is NABCEP and wether or not you should need to get the certification. If you’re serious about the solar industry and you want to get the NABCEP Certification, but you need to understand how exactly to apply, you can read more about getting the NABCEP Certification here.

If you need to get in depth training on how to market, sell, design or installation solar PV project. Look at our solar trainings.

## Free 25-Question Practice Test for the Upcoming NABCEP Installer Exam

For the next month, we’re offering a free 25-question practice test for the upcoming NABCEP PV Installation Professional certification exam. All of the questions are here. For hints, answers, explanations, and a free lesson on battery systems, follow this link to the “Test Drive”:

1. Fill in the blank: NEC section ________ shows the requirements for working spaces around live electrical equipment.
2. What is the maximum latitude at which the sun can achieve a 90º altitude angle?
3. If the open circuit voltage of a polycrystalline silicon PV module is 37.0V, the module Vmp is 29.9V, the inverter max voltage is 600VDC and its MPPT voltage range is 300 to 480VDC, and the minimum temperature is -24°C. What is the maximum number of modules per source circuit according to the NEC? List the NEC section where the answer is found.
4. A PV array of Suniva 300 Watt modules consists of 3 rows and 10 columns of racked modules mounted in landscape and facing south at latitude 30°. The modules are tilted at 20⁰. The mounting posts are installed 3 ft. deep. How long must the posts be? Module dimensions are 77.6” x 38.7”.
5. At 43⁰ North latitude on the winter solstice, the solar altitude angle at noon is____.
6. An array is comprised of 22 modules. Each module is 64.5” x 38.7” and weighs 44.1 lbs. The site will experience 50 psf. of uplift force. What is the approximate total uplift on the array?
7. What is the temperature correction factor if the module correction factor is -0.335 %/⁰C and the cell temperature is 54⁰C?
8. A module has dimensions of 64.5” x 38.7” and is in a landscape orientation on a flat roof. The position of the sun at 9am on Dec 21 is 11° elevation and 130° azimuth. What is the maximum tilt angle the modules can have so that there is no inter-row shading? (A 2 foot walkway is required between adjacent rows)
9. Where no overcurrent protection is provided for the PV dc circuit, an assumed overcurrent device rated at the PV circuit Isc is used to size the equipment grounding conductor in accordance with NEC ____.
10. There are to be two critical loads on a PV system. Your analysis shows that one uses 1900 Wh/day and operates for 6 hrs. per day and the other uses 1200 Wh/day and operates for 3.5 hrs. What is the weighted average operating time?
11. What is the combined effect in wattage of the 2 loads in the previous question?
12. The critical design month is the worst case scenario where the load and the _____________ are used to design the PV system.
13. Active means of charge control is required by the NEC unless the maximum array charge current for 1 hour is less than ____ % of the rated battery capacity measured in amp/hours.
14. When battery temperature is high, temperature compensation ________ the VR set point to minimize the excessive over charging and reduce electrolyte losses.
15. A 48 volt battery bank is used to provide power for critical loads requiring 7458 Wh/day. Three days of autonomy are required. What is the required capacity of the battery bank?
16. Critical loads operate for 12 hours. Three days of autonomy are required and the preferred depth of discharge of 50%. What is the average discharge rate?
17. A battery bank of 500 Ah is required. The depth of discharge is 50%, the minimum operating temperature is -10ºC and the average discharge rate is C/128. According to the manufacturer’s specs. this yields a temperature and discharge rate derating factor of approximately 73%. What is the required battery bank capacity?
18. A battery bank must supply 1200 Ah and will operate at 48V. The battery selected is an 800 Ah battery. How many 6V batteries will be required in this battery bank?
19. A PV system needs to supply 5834 Wh per day. The daily average insolation is 4.8 peak sun hours. The battery system charging efficiency is 0.9. The nominal voltage is 48V. What is the required array current not including any additional deration factors?
20. You are an installer called to move a residential two-axis tracker system from Yuma, AZ to Duluth, MN. Before reinstalling the system what should you check?
21. For a PV array to directly face the sun at 11 AM solar time on June 21st at 30⁰N latitude, at what tilt and azimuth angles should the modules be mounted? Use the sun-path chart provided.
22. The purpose of a linear current booster is to:
23. Where the removal of the utility-interactive inverter or other equipment disconnects the bonding connection between the grounding electrode conductor and the photovoltaic source and/or the photovoltaic output circuit grounded conductor, a____ shall be installed to maintain the system grounding while the inverter or other equipment is removed.
24. In addition to NEC Article 690. where else in the NEC are over-current devices are addressed?
25. An array located at 30⁰N latitude consists of two rows racked facing south. Both rows are on a level surface and the height from the ground to the highest point on the module is 39.7”. Calculate the minimum distance in feet needed between rows so the modules will not be shaded at 9AM on December 21. Use the sun chart provided.

Click here to take this free NABCEP practice test. You’ll receive a full score report, including correct answers. You can take it as many times as you like. It’s being offered as part of a “Free Test Drive” of our NABCEP Solar PV Installer Exam Prep course that runs through September up until the next exam on October 4th. The course is a structured study group, and it’s led by ISPQ Certified Master Trainer Ken Thames. It includes over 20 hours of video lectures by Ken as well as 50 additional practice questions.

## Why Performance and Not Price Is the Most Important Factor In Finding an Investor or Buyer for Your Solar Projects

Question or comments? If you’re a solar developer or investor and have a story to share that relates to this article or a question about the content, please leave it in the comment section below the article.

This is a guest article by Chris Lord of CapIron Inc. Chris also teaches our Solar Executive MBA. The next Solar Executive MBA session starts on September 15th. In the course, students will work a commercial solar project from start to finish with expert guidance from Chris along the way. The class is capped so to provide maximum student attention, but there are a limited number of discounted seats. You can get your \$500 discounted seat here.

In the Solar Executive MBA, one of the most common topics students have questions about is about identifying, screening, and closing investors or buyers of their solar projects.

Most commonly, students focus exclusively on getting investors who pay the highest price per watt for their projects. In the article on the three keys to defining bankability, we discussed why this is not the best strategy. The investor actually wants the best returns on a project. The best returns means the project is economically strong and reliable.

From the developers’ perspective, there is risk in selecting the right investor. This article will address why it’s critical to address the competence of investors and how developers can screen investors to find the best ones.

Enter Chris Lord from CapIron, Inc

In today’s highly competitive solar PV market, project developers looking for an investor or purchaser for their projects tend to focus almost exclusively on finding those with the lowest project return requirement or willing to pay the highest price for a project.

But is this the best measure to use when locking in your solar project upside?

This article examines the importance of purchaser performance in selecting a project purchaser and outlines ways to collect data that will enable you to assess purchaser performance.

Here is an example of how a developer lost a lot of value in a very short time by ignoring the importance of performance or execution risk when selecting a purchaser for his solar PV projects.

The developer had a mid-sized distributed generation project for sale, largely shovel-ready. The developer asked outside consultants to conduct an auction process among a select group of purchasers. With the bids in, the results were arranged in a matrix to show dollar price against execution risk.

In the matrix, shown below, execution risk was estimated based on a variety of due diligence and market intelligence assessments. The highest execution risk was assigned a ten, and the lowest execution risk assigned a one.

One of the parties added late in the process by the developer offered the highest price at \$3.18 a kW, almost \$0.35 a kW higher than the average of the other six bidders, and \$0.26 a kW higher than the next highest bidder. Based on market experience, the consultants interpreted that as a strong sign that rumors of financial distress at the high bidder were true. The prospective high bidder was desperately trying to bolster a weak pipeline in order to attract a badly-needed infusion of capital.

The consultants recommended a bidder offering a price of \$2.85 a kW bolstered by the lowest likely execution risk. Focused solely on price, the developer ignored the recommendation and proceeded with the highest bidder.

After thirty days of intense negotiation on an LOI, and days before execution of the LOI, the purchaser’s parent filed for bankruptcy and the purchaser followed suit. Worse yet, when the developer turned back to the other bidders in an effort to salvage value, he found that they knew of his predicament and were inflexible on terms and soft on their original price bids. Ultimately, the developer settled for \$2.82 a kW, but this did not account for the lost legal fees and time spent negotiating a deal that never closed.

1.    Pricing vs. Performance

a.     Why the focus on Pricing?

It is not surprising that project developers zero in on price when selecting a project purchaser. Particularly for small and mid-size developers, finding every possible dollar on the sale price is critical to covering the economic uncertainties inherent in a project’s development and construction phases and generating enough capital to fund continued growth.

The overriding problem facing developers is that there is a complete and natural disconnect between project costs (development and construction) on one side, and the valuation that an investor or purchaser might place on the project.

In the real world, purchasers look solely to the net cash and tax benefits that a project is expected to generate over the 15 to 25 years of its life. By discounting those net cash and tax benefits back to the present using their target return, a purchaser arrives at a price that he or she is willing to pay today for the project and related benefits.

For the capital costs of developing a project, the investor or purchaser is completely indifferent. If a developer spent more than the purchase price, then the developer will lose money. Any amount over the developer’s costs is how the developer generates a return on the development capital invested in the project.  Either way, it has no impact on the value of a project to investors or purchasers.

This sounds simple enough but, given that most developers must find an investor or project purchaser before construction begins, and – worse yet – the actual costs of development and construction may not be known at this point, developers naturally steer to the highest price offered by a purchaser because there appears to be no downside. A higher price gives the sense of security – more margin to cover development and construction unknowns – and, should costs come in at or below projections, more profit to fund future growth.

b.    What’s the downside?

By focusing solely or primarily on price, developers overlook other critical factors including investor or purchaser performance that can dramatically and sometimes adversely impact price. Sometimes this risk is characterized as “execution” risk. Whatever we call it, we are talking about the likelihood and cost of actually closing the specific, targeted transaction with a particular investor or purchaser on terms and conditions (including price) reasonably close to those the parties originally expected when they executed an LOI or otherwise first “shook hands” on the deal.

Performance is important because the ability of an investor or purchaser to follow through and close a transaction in a timely and cost-effective manner can have a bigger impact on a developer’s realized value than the promise of an incrementally higher purchase price from an investor or purchaser who fails to close.

In any financing, there is always a risk that a closing fails. There are at least three main classes of these types of risk: market risk, developer risk, and investor risk.

Market Risk

Market risk is the risk that arises from adverse changes in general market conditions. An example of a market failure, well known to most veterans of solar development, occurred in 2008 with Lehman’s collapse that fall and the onset of the Great Recession. Most project purchasers suddenly lost their tax appetite. Almost all major banks took economic hits to income that saddled them with substantial losses, wiping out the very profits that they were counting on to create their tax appetite. As a consequence, there was very little tax appetite among investors nationwide for the balance of 2008 and much of the first half of 2009. Even when investors did return to the market, tax-drive transaction volume in 2008 was substantially below pre-Lehman projections. In fact, Congress created the Treasury’s Cash Grant program in lieu of the ITC precisely to address that issue.

## AC Coupling – How to Cost Effectively Add Battery Back-up to Existing Grid-Tied Solar PV systems

This is a guest article by Chris LaForge.

Chris is teaching an in-depth 6-week technical training on designing battery based solar PV systems that starts in September. You can read the full description and get a limited-time discount here. If you need to learn how to design, quote, and commission a battery based solar PV array, this is the best course for you.

In the past three years, three trends have converged to create higher demand for battery-based solar arrays: battery prices are declining, the penetration of grid-tied systems is exploding, and homeowners are becoming more interested in backup power.

Retrofitting existing solar PV arrays to include batteries is becoming an opportunity for added revenue for contractors.

Enter Chris LaForge –

AC Coupling

Since the advent of high-voltage battery free (HVBF or grid-direct) solar electric systems, some clients have been frustrated by not being able to use their systems during power outages. The re-work necessary to move to a grid-intertied system with battery back up is costly (GTBB or DC coupled system), inefficient, and, in some cases, unworkable.

Ac coupling can be used in both utility-intertied systems and in off-grid applications. This article will discuss the utility-intertied aspects of AC coupling.

With the advent of AC coupling as a means to introduce battery back-up to an existing HVBF system, an efficient and more workable solution has come to the fore.

AC-coupled systems use the HVBF system while adding a battery-based inverter that works in tandem with the HVBF inverter. It maintains the efficient operation of the PV system while the utility is available and then allows for its operation during power outages by having the GTBB inverter disconnect from the grid, power the back-up load panel and use the power from the HVBF system to power the critical loads in the back-up load panel. It also provides power to the GTBB inverter to charge its battery bank.  If this sounds a bit complicated, well, it is.

Courtesy of Schneider Electric

AC coupling provides the following advantages over traditional DC-coupled GTBB system designs:

• Retrofit-able with existing HVBF systems (within manufacturer requirements and limitations)
• Allows for employing the efficiencies of HVBF equipment while achieving back-up power for utility outages
• Can reduce the number of components used in DC coupling
• Can reduce losses do to low-voltage aspects of DC-coupled systems
• Can provide for more flexible and efficient wiring configurations
• For designs requiring long distances between the renewable energy resources and the balance of system components

As with any innovation, AC coupling has some notable challenges, especially when the design utilizes multiple manufacturers.

For several years, system integrators have completed AC-coupled designs using one manufacturer’s equipment or by using multiple brands of inverters.

SMA pioneered the AC coupled concept with its “Sunny Island” Inverter. Initially built to provide for the creation of microgrids on islands and other non-utility environments. The design lends itself to grid-intertied AC-coupled systems as well.

As shown in the diagram below, SMA’s design allows for multiple HVBF inverter outputs to be combined with the Sunny Island inverter to connect to the utility and have battery back-up.

Courtesy of SMA America

SMA’s design provides for an elegant method of regulating the battery state of charge as long as all the inverters can be networked with cat-5 cable. In this design the HVBF inverters can have their outputs incrementally reduced as the battery reaches a full state of charge. If the distance between the HVBF components and the Sunny Island is too great to network with cat-5 cable, the Sunny Island controls the output by knocking out the output of the HVBF inverters with a shift in the frequency of the inverter’s AC waveform.  The HVBF inverter senses an out-of-spec frequency and disconnects until the frequency is back in spec for five minutes.

This frequency shift method of regulating battery state of charge is often used when different manufacturers’ inverters are used to create the AC-coupled design. This has several drawbacks that we will discuss.

Several other battery-based inverter manufacturers have developed designs for using their inverters with other HVBF inverters to create AC-coupled designs. These include OutBack Power, Magnum Energy, and Schneider Electric. Both SMA and Schneider provide for single manufacturer AC-coupled systems because they manufacture both HVBF inverters and GTBB inverters. This presents the basic advantage of having one manufacturer provide and support the entire AC-coupled design.

OutBack Power and Magnum Energy manufacture only battery-based inverters and therefore require the mixing of manufacturers in AC coupling in order to bring in HVBF inverters.

Both companies provide design information and support for AC-coupled designs.

Schneider’s regulation

With Schneider Electric’s AC coupling, the battery is regulated by the frequency shift method. Schneider itself recognizes the drawback of this method in its AC-Coupling Application Note (see appendix): “Unlike its normal three-stage behavior when charging from utility grid, the Context XW does not tightly regulate charging in a three-stage process when power is back fed through AC inverter output connection to the battery. In this mode charging is a single-stage process, and the absorption charge and float stage are not supported. Charging is terminated when the battery voltage reaches the bulk voltage settings, which prevents overcharging of the batteries. Repeated charging of lead acid batteries in this way is not ideal and could shorten their useful lifetime.”

This can be improved by employing a diversion load controller added to the design.  The diversion load controller will limit the battery voltage by “dumping” excess power into a DC load during times of excess generation for the PV system. While this re-introduces the 3-stage charge regulation into the design it negates some of the benefit of AC coupling because it re-introduces the cost of a charge controller and adds the cost of the DC diversion load(s).

Magnum’s regulation

Magnum Energy also provides for frequency shift method battery regulation but in their White Paper titled “Using Magnum Energy’s Inverters In AC Coupling Applications” (see appendix) they indicate that frequency shift regulation should only be used as a back up to the employment of a diversion load controller. They are developing an innovative addition to their product line the ACLD-40, which will provide for diversion control using AC loads. One aspect of using diversion load controllers is that DC loads are often difficult to find and expensive. Magnum intends the ACLD-40 to be a solution to this issue by allowing the use of more common AC loads for diversion controlling such as AC water heaters or air heaters. This product is under beta testing at this time and is due for release in late 2014.

OutBack’s regulation

OutBack Power’s design provides for frequency shift method battery regulation. The disadvantages to this method can again be overcome by the introduction of a diversion load controller and this comes with the same issues as with the other manufacturers.   OutBack Power’s AC coupling white paper discusses both on and off grid applications for AC coupling (see appendix).

Disadvantages to AC coupling:

• Frequency shift methods of regulating the battery state of charge are coarse and may create significant power loss if there is a miss-match of equipment leading to nuisance tripping of the HVBF inverter
• Battery optimization may not be possible without re-introducing a charge controller as a diversion load controller
• Complexity in systems mixing manufacturers can create systems that are difficult to operate
• Care must be take not to void warrantees by using equipment that is not designed for this application

Conclusion

In many ways, AC coupling is a good tool for working with both the difficulties of retrofitting battery storage in existing HVBF systems and systems with long distances between resources and loads. As with any innovation in this field, be sure to get the right design and make sure that the application does not void product warrantees.

## Three Keys to Developing Bankable Solar Projects – Lessons from Developing 150 MW+ of Solar Projects

Thanks to Chris Lord and Keith Cronin for providing all of the insights in this article. Chris and Keith teach our Solar Executive MBA course (the next session starts on September 15th). Together, they have advised investors, owners, and other developers on more than 150 MW worth of distributed generation solar projects. While there is no standard for defining bankable projects, I trust their on-the-ground experience to provide these insights.

Introduction – Why is Bankability Important?

The majority of large-scale US solar projects are done through power purchase agreements. The key to power purchase agreements is having investors who buy into these projects. As SREC prices and policy continue to fluctuate while project IRRs and installed costs continue to drop, project investors are most interested in investing in bankable projects that have good returns and minimal risk.

One of the most common question we get in our Solar Executive MBA course is, “How can I build a bankable project?”

In other words, “How do I structure a project so it’s very easy for an investor to want to invest in or purchase the project?” For commercial solar, the answer is of course “it depends” because there are so many moving variables that go into projects and everything is negotiable.

In this article, we’ll define and go into three keys to developing bankable projects. Then we’ll go into what developers need to keep in mind to stop wasting time on chasing bad projects.

This article will be useful to a professional who needs to get good at or keep up to date with best practices for financing mid-market solar projects. The goal is to go deeper than most articles on the Internet, but it will be impossible to provide the deep dive necessary to make you an expert. If you have any questions about the content, please leave them in the comment section of the article.

If you’d like to get more resources on the subject, here they are. We will reference all of these articles in the article, but I wanted to provide a simple list for ease of use.

Article Outline and Learning Objectives

The article will be split into four major sections. After reading this article, you should understand the most important factors that go into developing a bankable solar project. The goal is that you’ll become familiar with these variables and will be able to start screening your existing projects to find the bankable ones and will also be better at screening new potential customers.

Defining Bankability

Technically speaking, bankable projects mean investment-grade projects. These are the projects that are the economically strongest and most reliable (i.e. low-risk) projects. These projects are able to win the most conservative and lowest-cost capital.

Economically strong is defined as a project that uses reasonable or conservative assumptions and documented facts to create a healthy economic cash and tax flow that comfortably hits or exceeds the investors’ target IRR.

Economically reliable is based in part on the strength of the developer/construction entities and also on the confidence of any state subsidy. But is also heavily based on the quality of the design and construction of the project. Investors want to know that the project was built to a rigorous standard so its economic performance may be reliably predicted to actually generate the forecast numbers in the pro forma over a twenty or twenty five year term. That is a long time by anyone’s standards. Imagine if a project were a car. In twenty years, do you expect to be driving the same car you are driving today? Probably not. A high-quality project is not a project built to meet minimum performance standards at the lowest possible cost.

• Economic performance is most commonly addressed by establishing production guarantees. Oftentimes, investors will negotiate for the developer or EPC to guarantee a certain level of project, this is especially true if the equipment is being finance under a PPA and not a lease.
•  The other item that impacts economic performance in modeling is the use of P50 vs P90 production levels. Investors will typically want to use P90 production numbers because they are the most conservative. Read more about production modeling 101 here.

First Key to Bankability  Understand How Investors Evaluate Projects

Solely on a 20-year discounted cash and tax basis.

Investors value a project based solely on the cash and tax benefits that will flow from the project. Similar to how you might value an annuity, they are paying good cash for the right to receive the cash and tax benefits from a project. Project the annual benefits over a twenty or twenty five-year term, and discount each year’s value back to the present using your target return rate.

This valuation method creates a problem for developers.

1. Developers’ first instinct is to cut construction costs to the bone. Why not? After all, the difference between the development/construction cost and the sale price to the investor is all margin for the developer.
2.  Projects are also judged on their quality – performance and reliability. In fact, successful developers have learned to fight the instinct to indiscriminately attack costs and to focus instead on managing costs intelligently with an eye to longer-term value.
3. The key learning here is that it’s not the project with the lowest installed costs that wins, it’s the projects with the highest returns. This takes into consideration installed costs, the amount of power that an array will provide, and the confidence that the installed costs and power production will be very close to what’s expected.

A Second Key to Bankability – Have a Strong Economic Model

It’s key for commercial solar projects to have a comprehensive economic model. You need to know what kind of return you are really offering your investors before you show them the project.

It’s okay to start with a simple model for initial project screening and early development, but the sooner you move to a comprehensive and robust model the sooner you know where your project’s strengths and weaknesses are so you can then develop the project accordingly.

It is extremely important to use reasonable assumptions on all variables of the project economics. This includes: installed costs, PPA price, sales tax, property tax, interconnection costs and timelines, and SREC prices.

It’s important to lock in the “knowns” or “facts” of a project. This means variables that are documented and that you are close to 100% certain of their value. Be clear about which variables in the project are known and unknown.

Comprehensive and accurate documentation of variables is essential. The fastest way to lose the trust of an investor is not properly performing your due diligence by gathering information on all the necessary variables or not accounting for them correctly. For example, interconnection costs and real estate are not eligible for ITC and MACRS depreciation. Did you remember to exclude them? Not properly discounting the ITC is the single most common modeling mistake, even in large projects.

A Third Key to Bankability – Weighing Capital Costs Against Operating Expenses to Maximize Project Returns

This links directly to having a proper economic model. In your model, you need to know and understand what saving \$1 on the operating side means relative to \$1 on the capital side. The impact is different and depends on the facts.

• For example, on a 5 MW (AC) project on the East Coast, cutting the construction cost by \$.10 a watt (or \$500,000) raises the project IRR by approximately 0.4%.
• On the same project, cutting \$6,500 of annual expenses by finding a lower-cost property raises the IRR by almost the same amount. The greater impact comes from the recurring impact of the lease rate reduction. In other words, the \$6,500 is realized every year over the term, not just the first year.
• Effective and valuable cost-cutting involves weighing capital cost reductions against operating expenses – and this is where good development and good design can help.
• Energy efficiency in buildings offers a very easy way to see this trade-off. Imagine a developer looking to build a commercial office space. The developer might consider a highly-insulated and energy-efficient window solution but reject it because the cost is “too high.” Instead the developer goes with a very cheap but not very efficient window solution. After the building is completed, the operating cost of the building with lower efficiency windows is higher because of the additional energy required to warm and cool the interior space. Had the building owner gone the other way, the capital cost would have been higher, but the operating cost would have been lower. The trade-off is never an easy one to make, but in the building example, if the tenant is not the developer/owner, then the trade-off involves shifting costs from capital (owner/developer) to the tenant (who pays the energy bill).
• A solar project requires the same trade-offs on the design, choice of materials, and construction. And, as we saw in connection with knowing your model, the impact of changes can vary considerably depending on whether you are cutting capital costs or cutting operating costs. In both cases, you need to know how the IRR is impacted and whether cutting the capital cost makes for a lower life cycle cost.

The Developer’s Perspective

After Chris Lord provided this advice on the modeling and legal aspects of developing solar projects, I asked Keith Cronin a simple question, “This advice seems so clear, why are developers not following it? What are they chasing around bad projects? What advice do you have for them?”

Here’s an excerpt from his response:

Developers around the globe all want to seize opportunities in the solar industry, as they see gold in their eyes. This has been happening for almost a decade now in various iterations. Small and large developers are always looking at incentives, pulling out their spreadsheets, and eagerly looking to secure properties to park these opportunities on them.

What developers often overlook is the identification of a good versus a bad opportunity. As Chris Lord points out, determining bankability is essential. Discovering that a project can’t be financed is a large source of disappointment for developers after they’ve invested hours of time chasing deals.

This stems from a host of variants, but these are the most likely primary offenders:

1. Developer runs into unforeseen conditions at a project’s location and the additional costs make the investment economically unattractive.
2. Cost for construction and interconnection delays decreases project returns. Projects in the Hawaii market that have been involved in the FIT program have experienced 18-plus month delays from a host of parties involved in a project. For example, if you look at a 500kW AC PV system producing \$23,000 per month in revenue, how many developers can afford to lose \$400,000 during that time period, and how many investors have that level of patience? If you look at Chris’s example with capital expenditure versus operational expenditure and how this impacts project returns, any hiccups with construction delays can substantially decrease project returns.
3. Uncertainty around interconnection makes some projects impossible. If programs become oversubscribed and circuits on the grid become saturated, how do you explain to investors that you will not only see additional cost overruns, but the likelihood of waiting until the infrastructure can be modernized to impact the project timeline?

As Chris Lord points out, the cost of a project, versus the recurring costs for land, insurance, taxes, leases etc., should be carefully scrutinized. As developers, we all want to build a project for less than what we planned for. What is the best strategy for the short term and long term?

1. It is advisable not to cut corners on solar equipment because arrays have a useful life of 20 to 30 years. Make the long-term investment and build that into your budget. Be prepared to tell the investment community “why” your costs are higher and they are usually thankful for the insight and your long-term thinking.
2. What is your O&M strategy? These numbers fluctuate radically. It can be anywhere from \$10 per kW to \$25 per kW per year on larger scale projects. The bigger question is what is included in this service that will be provided and what isn’t? Remember, the PV system’s output will not go up over time and only go down with degradation, so plan for the impacts of time on a system and understand how your investors are looking for less lumpy returns and more stable forecasts.
3. Bundling other complementary services offers a unique angle on getting your project to the finish line. With the cheap cost of capital, investors are looking for low-risk returns, and adding in energy efficiency will stabilize returns for the investment community. Access to this money today is easy to find. In places with high-energy costs, it makes the amalgamated deal more attractive and often can give a developer the margin they were originally looking for at the onset.

Project risks often burden developers in the early stages of a project’s introduction and inception. Engineering, permitting, site control, and negotiations with landowners all consume a lot of in-house resources. Getting better at selecting projects that have a higher probability of being developed requires experience and knowing the market you’re entering. Finding local partners that can help you traverse the nuances of the market is essential in maintaining your expectations as well as the expectations of the investment community.

Conclusion

This article outlined the knowledge you need to develop and screen existing and new bankable solar projects. You now know what you need to keep in mind to stop wasting time on chasing bad projects.

The most important factors that go into developing a bankable solar project:

• Understanding how investors evaluate projects (solely on a 20-year discounted cash and tax basis)
• Strong economic modeling
• Weighing capital costs against operating expenses to maximize project returns

If you have additional knowledge to share, please leave it in the comment section below.

If you’d like to get more resources on the subject, please review the following resources (they were also included in the article). Please leave comments in the comment section below if you have questions or additional knowledge to add!

## Modeling Solar Production Risk 101 – An Introduction to P50 and P90 Production Levels

Source: http://www.slideshare.net/davidfparker/estimating-uncertainty

This article is part of a series of interviews, tutorials, and definitions around commercial solar financing that is leading up to the start of our next Solar MBA that starts on Monday September 15th. In the Solar MBA students will complete financial modeling for a commercial solar project from start to finish with expert guidance. The class is limited to 50 students, but there are 30 discounted seats.

Financing a large commercial solar project is about understanding, controlling, reducing, and communicating risk and uncertainty.

Because solar has a variable energy source, the amount of power that an array will produce, and thus the value of that power, is highly variable and needs to be understood to finance a project. As projects get larger, more due diligence is required to understand and evaluate the potential solar production of an array.

Solar production estimates are based on a number of factors. Some factors can be controlled and modeled with a high degree of certainty and others are closer to guesses about the future. Because these are guesses, we need to state a confidence level for each guess.

The confidence level of the amount of energy a solar array will produce is measured in P50 and P90 production levels.

This article will be useful to any solar installer who sees commercial solar projects, and specifically the financing of those projects, as critical to the success of their business. For larger projects, PVWatts won’t cut it. You’ll need to understand the amount of potential revenue a solar array can generate, and your confidence in its ability to generate that revenue,  in order to get investors to buy into the project.

1. The general types of production risk and why there is such a huge focus on solar radiation levels.
2. The definition of P50 and P90, how it’s graphed, and the impact of weather variability.
3. The potential impact of revenue expectations.
4. What is critical to understand about P50 and P90.

Let’s dive in.

1. Types of Risk

There are many ways to describe the risks associated with a solar array. In general, you could put them into two buckets: “construction risk” and “operating risk.”

From an investor’s perspective, construction risk is any source of risk that happens before COD, when the system is not operating. This can include site risk, site control, interconnection risk, EPC and construction risk, and more. An entire article could be written on those topics. For the most part, construction risks are about understanding and controlling the cost and time required to build the array. There are some obvious factors during the engineering and installation of the array that can have large impacts on the potential production of the array.

Operating risks are the risks associated with running the facility and generating revenue from the production of energy. These can still include some site and equipment failure or warranty risks, but, assuming those are controlled for, the major risk after a solar array has been constructed is how much power it will produce.

AWS Truepower published a report about reducing uncertainly in solar energy estimates in which they rank ordered the factors that have the largest potential impact on solar production estimates. That graph is below.

As you can see, “solar resource uncertainty” is the single largest item that can impact total solar power production based on their analysis.

David Park from IEEE published a similar analysis. He rank ordered the impact solar radiation, climate, module model, inverter model, aging, and system derate can have on expected array production versus estimated production and found that solar radiation, climate, and radiation and module model explained the largest amount of production variability.

The value of energy produced by a solar array is a function of two items: how much energy is produced and the value of that energy. The value of that energy can be based on a number of factors: the kWh rate it’s offsetting, any net-metering laws that are in place, the negotiated PPA rate, potentially demand charge reductions, any production-based incentives, and more.

Given that we cannot predict with 100% certainty the amount of solar radiation that will hit an array over any given period of time, to understand and communicate the potential solar resource we use P50 and P90 production levels of an array.

While these production estimates rely to some degree on system design and siting, the main variable is weather.

2. The definition of P50 and P90 and how they are graphed

In P50 and P90, the P stands for probability.

P50 means there is a 50% chance in any given year that production will be at least a specific amount. If an array has a P50 production level of 500 kWh, it means that on any given year there is a 50% chance that production will be AT LEAST 500 kWh.

P90 production means that there is a 90% chance that in any given year production will be at least the specific amount. This means that there is only a 10% chance that production will be lower then the stated amount. If any array has a P90 production level of 400 kWh per year, it means that on any given year year there is a 90% chance that production will be AT LEAST 400 kWh.

Here’s a graph of P50 and P90 production estimates from David Park’s report.

For any statistics geeks who are reading this, it will look very familiar. What he’s doing is graphing the variability of the mean in a confidence interval, in this case one standard deviation is 12.5%. P50 is the mean and P90 is a little less than two standard deviations (remember that two standard deviations is 95%) from the mean.

3. Weather Data Variability and the Relationship Between P50 and P90

Because the variability of solar production, and thus the difference between P50 and P90, is largely based on the variability of weather, extensive weather analysis must be performed to calculate these values.

The above graph comes from the report by David Parker and illustrates how weather recordings over a specific period are used to determine the variability of irradiation for a specific location.

What this means for solar production is that areas that have less sporadic weather changes have closer P50 and P90 values. Statistics geeks, lower variability means a lower standard deviation across the distribution of solar irradiation values.

If you look at the two graphs below, the top graph is an illustration of an array that has highly variable weather characteristics while the bottom graph displays an array with more stable and predictable weather.

4. Potential Impact of P50 and P90 Production Estimates on Revenue Potential

The difference between P50 and P90 production levels in areas with moderately variable weather can have large impacts on the assumed production for an array.

If we want to use the example from our first graph:

P50 production was: 32,413 kWh

P90 production was: 27,228 kWh

That’s a difference of 5,185 kWh. P90 production estimates are 15.9% lower than P50 values. 15.9% is a lot!

Assume the value of a kWh is \$.15 per kWh

P50 production is expected to be: \$4,861

P90 production is expected to be: \$4,084

If we assume that each kWh is worth exactly the same amount, this means that the value of the power produced would be expected to be 15.9% lower if P90 was used compared with P50. However, we can be much more confident that every year we’ll hit the P90 production levels. This is why investors signed into a PPA tend to favor P90 production levels if they are being paid with power production.

5. What’s critical to understand about P50 and P90?

• P50 and P90 production levels are hard to determine with software models.
• For larger projects, an engineering firm will work to perform this analysis.
• P90 is more conservative, so investors will focus on this amount. P50 is less conservative, so developers tend to focus on this.
• The greater the variability of weather in a specific area, the greater the variability between P50 and P90 because solar radiation levels explain the majority of the variability in production.
• Investors will be most concerned with production levels in legal structures where their returns are based on the production of the system. In lease structures, the investors will be less concerned with production because the payments are hell or high water payments.

6. Further Reading on Production and Risk Modeling

Posted in Solar Photovoltaics | 1 Comment

## New Massachusetts Solar Bill H.4185 Would Destroy Community Solar Potential In the Commonwealth

This is a guest post from Sam Rust from SRECTrade about new solar legislation in Massachusetts.

(Editor Note: A note about the importance of community solar for lowering customer acquisition costs, something EVERYONE in the solar industry cares about. Everyone is talking about lowering customer acquisitions costs and soft costs and community solar has the potential to instantly drop acquisition costs by 50% to 80% for solar companies offering roof mounted and community solar projects. Why? It’s simple math. If you had 100 solar leads, a good conversion rate of leads to customers would be 10%. This equals 10 customers. Here’s the thing, in order to find 10 customers that WANT to invest in solar and HAVE a good roof, you must bump into 3 to 4 people that WANT solar but DON’T HAVE the roof space. If those 3 to 4 people could become community solar customers, then the conversion rate of those 100 leads would become 30% to 40% instead of 10%. This would then drop the acquisition costs because you’re getting more customers with the same marketing spend. Food for thought.)

Enter Sam Rust.

In 2013 Massachusetts was ranked 4th, behind California, Arizona, and New Jersey for most solar installed. Despite this success, legislation, officially known as H.4185 (An act relative to net metering), is pending at the Massachusetts State House that could drastically change the direction of the Massachusetts solar industry. Touted in the media as successful compromise between regulated utilities and the solar industry, H.4185 might be more of a step back, than a step forward. The bill could pass in both the Massachusetts House and Senate before the end of the legislative session on July 31st, despite the opposition of many solar owners, installers, and representatives of the community solar movement.

Here’s a short explanation of how we got here and what H.4185 is.

Currently there are limits on how much Massachusetts solar capacity can qualify for net metering in each utility territory. These limits, which only apply to larger solar facilities, are nearly maxed out for each utility and prevent the Commonwealth from meeting Governor Deval Patrick’s 1,600 MW by 2020 solar goal.  H.4185 would remove the net metering limits and put in statute Governor Patrick’s 1,600 MW target in exchange for a radical adjustment in the structure of Massachusetts solar policy of which the primary adjustments are:

• The removal of annual capacity restrictions on large “solar farm” projects
• The creation of yet-to-be defined minimum electric bills for all ratepayers
• The reduction of the virtual net metering rate from compensation at the retail rate to the wholesale rate of electricity
• A limit on the size of behind-the-meter projects to 100% of the on-site load
• A transition away from the successful market-based SREC program to an unknown program managed by the Department of Public Utilities
• Transfer of all of the “environmental” attributes of solar arrays to the utilities

In translation, H.4185, a bill that is ostensibly about net metering would remove or weaken most of the policies that have made the Massachusetts solar industry so successful. It is a bill that exchanges a set of known, highly successful policies, for a new set of untested policies.  The bill has not yet passed and many stakeholders are calling amendment language that would remove most of the major policy language in exchange for an incremental increase in the net metering caps and a formal commission to be convened next year to review the more contentious aspects of the legislation. This more cautious approach would stabilize an already jittery Massachusetts solar industry and ensure that all stakeholders are at the table the next time net metering limits need to be addressed.

How this could negatively impact solar installers.

1. Anybody working to do community solar will be negatively impacted because the VNM credit is being reduced
2. H.4185 removes the protections in place under the SREC-II program for incentivizing distributed/ rooftop/ carports/ general behind-the-meter projects
3. The declining block incentive program will be set at the DPU, rather than at the DOER. This means that installers will need to lawyer up and deal with the regulated utility lawyers in order to argue for favorable incentive targets. Solar in Massachusetts goes from a decentralized system, where everyone and anyone can participate in the rule making process to a system where the big player have the negotiating advantage
4. The utilities receive all of the attributes of the solar, including the RECs and will be able to lead the discussion on monitoring and other equipment requirements. This reduces the possibility for innovation in the solar space regarding capacity markets, battery storage, voltage regulation etc
5. The minimum bill imposition will hurt anyone with a low electric bill, which means smaller projects will be most affected by the minimum bill
6. Anybody doing business in Muni territory is left out. Currently the SREC program covers Munis
7. Above all else this just adds more complication to the system. We just spent a year implementing SREC-II and now we have to work on implementing another program for which installers will need to fight to be part of the process for negotiating the declining block targets and minimum bill. This just adds more uncertainty, which is bad when you are trying to mature an industry.

WANT TO HELP? Contact Sam

First. Here is Sam’s email address: contact@competitivesolar.org

Send him an email and he’ll figure out how you can help.

Massachusetts voters are encouraged to research this bill further and to contact their state legislators. Here is a link to a site that makes legislators searchable by zip code.

For more information please read this well written opinion piece in Commonwealth magazine and visit the Facebook page for the Massachusetts Stakeholders for Competitive Solar or www.competitivesolar.org.

## Free Solar Design Tool: String Sizing Tool For Commercial Solar Projects That Works with All Inverters

One of the most important aspects of designing a solar array is sizing module strings to operate within the parameters of the selected inverter. This is especially true for commercial and megawatt solar projects. To help in this process, we’re providing a free solar design tool to our readers.

Ryan Mayfield and Renewable Energy Associates has developed a free solar design tool to help in that process. Most inverter manufacturers offer some type of sizing tool, whether it’s simple or advanced, it’s usually limited to selecting only their products. The REA System Sizing Tool lets you select from a wide variety of products and manufacturer’s. Ryan is teaching a 10-week advanced solar design class with SolarPro called Megawatt Design.

You can click here to down the string sizing tool.

Key Features of the Solar String Sizing Tool

A quick note. The tool now requires you to turn on macros. For those concerned about security we can not guarantee that the tool will work well, accurately or at all without macros enabled.

• Thousands of modules.
• Hundreds of inverters.
• Add your own module or inverter.
• World Wide ASHRAE locations. 5,000+
• Create your own custom sites.
• Dual MPPT’s configuration possible.
• Voltage drop calculator.
• Performance calculator.
• Quick Printing features.

Screen Shots of the Solar Design Tool

Inserting Array Characteristics

Inserting Weather Conditions

Logging Other Project Specific Activities

You can click here to down the string sizing tool.

## How to Identify and Eliminate the 7 Forms of Waste in Residential Solar Installations

This is a guest post by Pam Cargill. Pam is an expert at optimizing residential solar operations. She’s helped scale operations both at Alteris Renewables (now RGS Energy) and Sungevity. She knows all the secrets of the larger installers and is now running her consulting practice, Chaolysti, to spread what she’s learned.

Here are a few ways you can learn more from Pam.

Enter Pam Cargill.

Soft costs. While analysts have been long on talk analyzing what they are and how they are impacting the industry, they have been short on solutions. Why? Because residential solar is, by nature of its need to interface with a varied landscape of regulatory and policy issues, a complex business. It is equal parts finance, construction, and high-tech. Since there is no common formula to apply to reduce soft costs nor a single soft cost category that installers should universally tackle first, installers should use a more individualized approach to evaluating their project delivery process to find out which areas would be most impactful to improve first.

This post, geared for owners and/or operations managers of residential solar installation companies, will teach you about the 7 Forms of Waste, a powerful categorization methodology you can apply in your operations to begin to learn where time, energy, and money is misspent, a leading causes of customer dissatisfaction. In residential solar, maximizing customer satisfaction is crucial because the leading source of low-cost leads is from the referrals of currently installed customers according to solar analyst Nicole Litvak, author of GTM Research’s U.S. Residential Solar PV Customer Acquisition: Strategies, Costs and Vendors.

# What is the 7 Forms of Waste?

The 7 Forms of Waste is a framework used in proven cost reduction methodologies from the Toyota Production System (TPS), now commonly referred to as “Lean Production” or simply Lean. Using this framework, you can begin to reframe your operations in the language of what your customer considers valuable. By classifying all process activities into these two categories of “value added” and “non value-added” activities, you can begin to take action improving valuable parts and removing or reducing non value-added waste.

# Who is the Customer?

In order to begin categorizing waste activities, employees must identify and understand their internal customers and the final customer. These relationships are key to meeting customer expectations. For example, design staff drafting plan sets must meet the needs of the AHJ, Utility, installers, and the final customer. Without seeing the AHJ, Utility, and installers as customers of their product, the designer could overlook important safety or design requirements in order to meet a customer-specified design constraint, which could cause rework and delays if in conflict with AHJ or Utility requirements or real-world installation practices. When each employee frames the recipient of their work as a customer, they are more likely to see how their activities could be value-added or non-value added. When framed in this way, management can also work more intelligently together to streamline handoffs and minimize or remove re-work related to misalignment of goals.

# What Defines “Non Value-Added?”

A value-added process is an activity that a customer is willing to pay for that contributes to the end product they expect. Non value-added processes, on the other hand, fall into two categories – business requirements and pure waste. Business requirements comprise the overhead of the company: your fleet of vehicles, HR activities, compliance-related activities (especially if you deal with finance or credit). Examples of pure waste are excessive coordination meetings, generating reports that are not read or acted upon, multiple layers of approval, and any kind of rework. The 7 Forms of Waste are comprised by these two-types of non value-added activities.

# 7 Forms of Waste and Common Residential Solar Examples

Now that you understand how to identify your internal and external customers and know how to identify value-added and non value-added activities, let’s look at the 7 Forms of Waste: What they are, what they mean, and an example of each one so you can learn how to see them in your own company.

## Transport

The unnecessary motion or movement of materials or information, including work-in-process, from one operation to another. This adds time to the process during which no one adds value.

Example: Ordering from a vendor that cannot drop ship directly to the customer site or to your warehouse, hence product must move through several channels, adding time and potential for loss or damage in the process which could further delay the project.

## Inventory

This refers to inventory that is not directly required to fulfill current Customer orders. Inventory includes raw materials, work-in-process and finished goods. Inventory all requires additional handling and space. Inventory is often closely associated with Waiting and Over-Production.

Example: Ordering more rails, mid-clamps, and wire than is necessary for the amount of projects currently in progress and run rate of equipment. This thinking compounds and causes company capital to become tied up unavailable for other uses and causes warehousing space to become crowded which can lead to demand to expand.

## Motion

Built-in extra steps taken by employees to accommodate inefficient process, rework, reprocessing, overproduction or excess inventory.

Example: Developing and automating queues for plan set rework instead of reducing or eliminating the need for rework.

## Waiting

This refers to downstream inactivity that occurs because previous activities are not delivered on time. Idle downstream resources are then often used in activities that either don’t add value or result in overproduction.

Example: Installers cannot perform installations because plan sets are not completed fast enough to pull permits and schedule jobs. These installers are then sent out on site evaluations or given warehouse “housekeeping” tasks.

## Over-Production

Overproduction occurs when an operation continues after it should have stopped.

Example: Plan set is “overproduced” — it includes additional sheets, viewports, and data points above and beyond what the AHJ or Utility needs to approve the permit or installer needs to build the project.

## Over-Processing

This occurs any time employees put more work on a project than required to satisfy the customer. This also includes using components that are more precise, higher quality, or expensive than absolutely required.

Example: A designer spends extra time on a project researching and specifying a non-standard piece of equipment deemed necessary due to site conditions that the customer did not pay extra money for.

## Defects

This refers to products or services not conforming to the company’s internal specification or expectation of internal or that of the final Customer thus leading to Customer dissatisfaction.

Example: AHJ redlines and rejects a plan set because design did not follow a local municipal code unknown to or forgotten by the designer. The designer cannot work on a new plans and must now research the issue and schedule rework of old plan set.

Now that you understand how to see the 7 Forms of Waste, you can begin to categorize activities. In our next post, we will build on this understanding to cover the next step in process improvement: mapping your process using the Critical Path Method.

Pamela Cargill is Principal and Founder of Chaolysti, a strategic consulting firm that helps residential solar installers operate more efficiently through direct relationships and program development with solar services providers. Follow her on twitter: @chaolyst

## The Most Common Solar PPA Modeling Mistake, The Fix, and a Free Tool

This article will address the most common error that developers and EPCs make when modeling commercial solar PPAs. The video below will discuss the problem, the solution, and provide a free tool you can download so you can work through the answer yourself.

This article is part of a series common topics and questions that professionals have about financing commercial solar projects. Past topics include how to price the risk of cash equity vs tax equity in a partnership flip and how to calculate the buyout process of a PPA.

This lessons will be on the most common modeling mistakes that Chris Lord see’s developers make. Chris Lord runs a consulting practice called CapIron and is a co-teacher of the Solar Executive MBA that teaches students how to finance commercial solar projects from start to finish with expert guide. You can get a \$500 off the Solar MBA here.

The modeling problem has to do with properly discounting the tax benefits of a project. The result of that problem is two-fold. First, it’s an obvious beginners mistakes. If you want to look like a professional, you need to make sure that you’re not doing this. Second, if you do it improperly, it inflates project returns, which can hurt you when the investor does their due diligence.

Note: If you want to see what Chris is doing, click on the FULL SCREEN button on the bottom right of the video. You can also download the tool Chris is using by entering your email at the bottom of the article.

We all know the importance of understanding and modeling the economics of a solar project, but what is the most common and easily corrected modeling mistake you see Developers make?

Failing to properly discount the federal tax benefits in a transaction, particularly the ITC. Most show the ITC as a direct and immediate reduction of the Capital Cost of a Project. In effect, developer is asking the tax investor to buy the tax credit by paying \$1 for every \$1 dollar of tax credit. Developers want to pay a discount. Sometimes the discount is expressed as a price per dollar, but the best way to account for the cost is show the purchase price paid in year zero and the ITC recovered in year 1. This ensures that the ITC will be discounted at least one year by the Investor’s discount rate.

How would you handle depreciation?

Answer: You take the available depreciation for each year – let’s say that is the excess depreciation beyond what is needed to shelter the project’s current income – calculate the value of that depreciation as the amount of tax savings that such excess depreciation will generate. For example, if you had in year 2 \$110 of depreciation and \$10 of project income, you would have \$100 of excess depreciation. For an investor with enough other qualifying income to use that \$100 of excess depreciation, the value is equal to the applicable tax rate times \$100. At a 35% federal tax rate, that would mean \$35 of value in year 2. Discount that back to year 0 to determine today’s value of that \$100 of excess depreciation in year 2.

Enter your email to download the model to help your calculate the value of the ITC and MACRS on commercial solar projects.
• This is where email where the model will be sent.

## Interview with Cory Honeyman, GTM Research Solar Analyst, on Emerging Trends in Residential and Commercial Solar

In this interview, GTM Research Solar Analyst Cory Honeyman provides some background on the U.S. Solar Market Insight Report and discusses trends in residential and commercial solar, including hard costs, important skills for salespeople, state incentives, common misconceptions, and financing. (The interview has been lightly edited for length and clarity.)

Tom McCormack (TM): Can you give some background on the U.S. Solar Market Insight Report?

Cory Honeyman (CH): The U.S. Solar Market Insight Report is a publication that we release with the Solar Energies Industry Association (SEIA) on a quarterly basis. The key takeaways from the report are a combination of understand installations across each state and market segment, our outlook on future installations, our forecast, by state and market segment on future installations through 2017. Within that, we break apart and identify the leading states and provide qualitative background on the key drivers and challenges to growth that are fueling or hampering installations across the top 10, and some of the newer state markets that are just beginning to hit the national radar. We also cover installation pricing trends, manufacturing and component pricing trends, and, finally, a breakdown of both PV and concentrating solar trends.

TM: What is the methodology for the report?

CH: The quantitative data comes from an extensive data collection effort that I take the lead on. We reach out to 60-80 sources, including utilities, incentive program administrators, and government program administrators, who provide figures on new installation capacity across the major market segments. One key element that sets this report apart from other reports that are tracking growth in the solar industry is the fact that I think we have the most robust coverage of actual utility interconnection data. We also conduct an extensive array of channel checks where we have discussions with people across the downstream value chain for solar about the major drivers of growth in the states where we’re seeing upticks in a given quarter.

TM: What is driving the increase in residential installations?

CH: Customer acceptance and the interest in going solar in the major state markets, especially in California, is increasing every year. When you see three of your neighbors go solar, it inevitably makes you want to go solar, too. Outside of the increased social acceptance, the economics for installing solar on the residential side have become increasingly attractive. The cost to install has gone down, but it’s also been driven by the introduction of a lot more innovative and attractive third-party financing options that have really scaled up growth. The entrance of companies like SolarCity that can enable homeowners to avoid a lot of the upfront costs of installing solar is driving a lot of the growth in the established state markets. We see, on the residential side, in most major markets, that third-party ownership accounts for two thirds to 85 percent of the market each quarter.

TM: What is making solar cheaper?

CH: On the upstream side, we’re seeing declining prices across both components and polysilicon. Combined with that is the fact that we’ve seen increased electricity retail rates for customers. Those two things together increase the value proposition for customers to go solar. Also, in many of the established state markets installers have fine-tuned their internal operational efficiencies, cutting down on a lot of soft costs and have also even focused on customer acquisition.

TM: Do the current solar trends suggest any new careers or skills that will be more in demand in the coming years?

CH: Our partner SEIA recently released a report on the number of jobs that have been created within the solar industry, and that goes into the types of jobs the industry attracts and how that has evolved over time. As we’ve seen really impressive and continued growth across the entire market, obviously that requires a ramp-up in sales capacities. So, if you go on LinkedIn and type in “solar,” all of the leading companies have positions open for outside and inside sales consultants, and I think that is an area where there will be constant demand. Although it’s becoming increasingly heterogeneous, the U.S. market is still concentrated in the hands of a few state markets. However, the dynamics within those states is changing, so I think there’s a need for more and more roles that involve a strong understanding of where the market is heading both geographically as well as in terms of financing trends and other major trends that can lead to increased acquisition of customers.

TM: What types of skills would make a prospective solar employee marketable today?

CH: It’s a different conversation depending on whether you’re pitching to a residential or a commercial customer. The requirements for commercial are more technical and focused on the financial returns whereas with residential, you really just need to shore up what your elevator pitch is when you’re reaching out to potential customers. Regardless of what the customer acquisition strategies are for a given company, if you’re in a sales position, a lot of that is going to be external-facing and either on the phone or face-to-face work. So, it’s important to understand financing options and be able to explain the key metrics that homeowners care about. So, what is the payback period? Or, what is the discount I can expect based on what I am currently paying for my electricity bill?

TM: What do you consider to be an overlooked or not-well-understood element of the current solar market?

CH: I think one of the prevailing notions about installing solar is that you need to have incentives to make it work, and I think we expect any project to take advantage of the federal-level incentives, which means the federal investment tax credit along with another incentive or accelerated depreciation. That will continue to be the primary driver of growth for the next couple of years. When a lot of people think about the economics of solar working out, it has to go hand-in-hand with the availability of really strong state incentive programs. That does fuel a lot of growth across many smaller and middle-tier state markets. But we’re really beginning to see a number of the leading states, that account for 80 percent of the market begin to shift away from needing any state incentives to make projects work. Last quarter was a hallmark moment for California, where over half of all the residential installations that came online actually came online without any state incentives. The trend is getting closer to this notion of retail rate parity, where a project can work with only the federal-level incentives. The misconception that you need incentives to make projects work is an important one because if you’re interested in making sales pitches and becoming an attractive candidate for jobs, being able to talk confidently about where the industry is heading and how it’s becoming increasingly independent of these state-level incentives is important.

TM: What are the main drivers of solar growth? Is it the political landscape of the state, the incentives in the state, or simply the availability of solar based on state geography?

CH: I think they all work together and are weighted differently depending on the state. The underlying market fundamentals that need to be there are: “What are the current retail electricity rates in a particular state?” and “What are the solar resources for that state?” When you have those two questions factored in, the role of incentives plays an important role, but when you think about the roles governments and utilities play in helping to promote solar growth, I think it really varies. From an outsider’s perspective, it’s probably surprising to hear that, in a number of states where you wouldn’t expect to see meaningful investment in solar, it’s actually taking place. Yes, California has and will continue to be the #1 state market for solar, but recently, for example, within the utility-scale market segment, North Carolina is the #2 state right now. Also, even farther south, Georgia, and specifically the utility Georgia Power, has made significant efforts an investment to begin ramping up solar development within its territory.

TM: Can you explain why that’s surprising? Is it because we’d expect redder states to be more reluctant to embrace the technology, or is it a different reason?

CG: I don’t think it’s surprising. The value of going solar is not driven solely by altruism and doing right. That’s an important piece to the puzzle, but the economics are structured in a way that, both for utilities and end users, there are strong cases to be made for integrating solar into the mix. So in Georgia, Colorado, and even Minnesota, the value of adding solar not for compliance reasons, but, for example, as a hedge against natural gas prices inevitably rising again. For customers in states where the incentive landscape isn’t as strong, and as project economics become increasingly attractive, the value of avoiding energy costs altogether is something that I don’t think people always factor in to the evaluation of what role solar can actually play across the U.S.

TM: What are the factors that impact how a utility company participates in the market? You mentioned that it’s a hedge against the price of other energy sources.

CH: That’s a second-order driver at this point. The #1 factor has been that states have set renewable portfolio standards (RPS), and a lot of those have solar carve-outs where the utilities are required to procure a certain amount of solar to meet annual compliance obligations. Those pieces of legislation have launched a number of procurement programs and incentive programs across all market segments. There are a number of states where those RPS are set. The most recent one was established in Minnesota.

TM: So, if there’s new legislation in a state, that’s going to be a major driver, forcing the utilities to get on board whether they like the idea or not?

CH: The prospects for new RPS legislation are going to be few and far between. There are a few states where we’ve seen an extension or revision of these standards, but a lot of the standards have been set over the past few years, going back as early as the mid-2000s, so that legislation is not something that will create new demand. It will just sustain demand that’s been set into place over the past several years.

TM: What types of new commercial projects are we seeing on the horizon?

CH: On the commercial side, the market saw a downturn in 2013 and kind of flat-lined. I think the market has shifted toward smaller-scale commercial systems, sub 100 kilowatt. In the past, especially in New Jersey, which was, for a while, the leading driver of growth in the commercial market, you saw a ton of 5 to 10 megawatt, ground-mount systems that were driving a lot of growth there. And, that market fall apart for a bit because its primary driver is SRECs, and the demand for SRECs dropped once there was too much investment in that market. Looking forward, I don’t think you’re going to necessarily see a shift in the types of projects; it’s more about the way in which that market can become reinvigorated. A lot of it has to do with mirroring what has happen recently on the residential side: figuring out ways to unlock capital to start developing projects again. On the residential side, we’ve seen really innovative platforms for linking investors with developers and linking third-party ownership agreements with customers. Coming up with innovative online platforms to facilitate and then unlock investment for commercial customers is a really important strategy that’s been employed on the residential side. Revising the financing structures that are currently in place in commercial markets is a really important trend to keep in mind. But there’s isn’t one specific type of project we can expect to see. It really depends on the state market. In Massachusetts, which is well on its way to being the #2 commercial market, looking at 2014, that market still sees a number of 1 to 5 megawatt, ground-mount systems. So, it depends on which state you’re in, what incentives are in place, and what those incentives are targeting.

TM: If there was something I needed to learn or familiarize myself with, when you’re talking about the more innovative financing for commercial solar, is that just a matter of getting comfortable with the all the different options that are out there, or creatively bringing investors to the table, or exploring new crowdsourcing options? What would I want to key in on to be on the cutting edge of that change as it happens?

CH: That’s one of the million-dollar questions for 2014 with commercial solar. There are a few companies that are beginning to introduce innovative financing structures. There was an announcement from Wiser Capital that they’re introducing a platform for scaling up commercial solar. Topics you’d really want to understand are how a power purchase agreement (PPA) is structured and expected returns and requirements from different types of nonresidential customers. “Commercial” is often used interchangeably with “nonresidential,” but a lot of the developers who are developing commercial projects are also developing projects for municipal, government, and non-profit entities, too. So, it’s important to recognize that the types of financing available for school projects, for example, are different than what you can secure for a commercial customer. And, I think there are trade-offs and benefits to both types of projects, but really understanding what types of debt instruments you can take advantage of with school and government projects, it’s perhaps a little more niche, but some of those opportunities are really important to leverage. Good case studies to reference are a number of school projects that have been developed in California and Arizona where they have PPA documents available to the public that you can review.

We plan to do an interview like this one each quarter to stay on top of quickly-evolving trends in the solar industry. What topics would you like to see covered?

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