Today at High Performance Building Magazine

Two Free Tools: ASHRAE Standards 55 and 62.2 Calculators

Registered engineering technologist and expert HeatSpring instructor Robert Bean has developed two calculators to help designers meet ASHRAE Standards 55 and 62.2: “Thermal Environmental Conditions for Human Occupancy” and “Ventilation and Acceptable Indoor Air Quality in Low-Rise Residential Buildings.”

Considered one of the leaders and most knowledgeable professionals in his field, Robert’s research and teaching enables designers to determine how indoor environmental quality affects human comfort, productivity, and health.

Free Download: ASHRAE Standard 55 Calculator

Free Download: ASHRAE Standard 62.2 Calculator

For a full description of the free downloadable tools, please see below. 

Free Tool: ASHRAE Standard 55 Calculator
This free tools allows designers to calculate the inside surface temperature for the purpose of determining the mean radiant temperature in calculating the operative temperature as per ASHRAE Standard 55 – Thermal Environmental Conditions for Human Occupancy.

ashrae 55.5

Download this calculator for free today!

Free Tool: ASHRAE Standard 62.2 Calculator 
This free tool allows designers to select floor area and modify number of bedrooms, duct size and duct length, and quantity of duct fittings for the purposes of calculating CFM, duct velocity, and friction. It works for both the 2011 and 2013 versions of ASHRAE 62.2 – Ventilation and Acceptable Indoor Air Quality in Low-Rise Residential Buildings. Output includes differential comparison in CFM, friction loss, and duct size as a result of CFM change from the 2011 to the 2013 version.

ashrae 62.2

Download this calculator for free today! 

Robert Bean, R.E.T., P.L.(Eng.) is a registered engineering technologist in building construction and a professional licensee in mechanical engineering. He is president of Indoor Climate Consulting Inc. and director of He is a volunteer instructor for the ASHRAE Learning Institute and serves ASHRAE TC’s 6.1, 6.5, 7.4 and SSPC 55 Thermal Environmental Conditions for Human Occupancy; and is a special expert on IAPMO’s new Uniform Solar Energy and Hydronics Code committee. He has developed and teaches numerous courses related to the business and engineering of indoor climates and radiant based HVAC systems. He will be teaching an online, advanced 10-week course, Integrated HVAC Engineering, this fall. The course is capped at 50 students with 30 discount seats. Read the full course outline here.

ASHRAE, the American Society of Heating, Refrigerating and Air-Conditioning Engineers, is a global society focused on building systems, energy efficiency, indoor air quality, refrigeration and sustainability within the industry. Through their research, standards writing, publishing and continuing education, ASHRAE helps shape today’s built environment.

Posted in Building Efficiency, elearning | Leave a comment

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

HeatSpring NABCEP Prep Test DriveFor 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.

Posted in Solar Photovoltaics | Tagged , , | Leave a comment

Master the Outdoor Reset Curve in 60 Minutes

Plumbing and hydronics expert, Dave Yates has mastered the outdoor reset curve: boosting the value of his work, maximizing fuel savings, and increasing the comfort of his clients’ home. He wants you to master it, too.

In this 60-minute free lecture, Dave uncovers everything you need to know to master the outdoor reset curve. He explains how to set up a reset curve, tailor it for any application, and present it to your customers in a way that will separate you from your competition.

You will learn:

  • How to integrate the outdoor reset curve into retrofit systems
  • Why an accurate heat loss calculation is the rock-solid foundation
  • Why measuring existing radiation reveals the ECV (Energy Conservation Value) potential
  • Why low-temperature systems have higher ECV
  • How to put it all together for peak performance, ECV, and ROI

Watch the free lecture here and enroll in the HeatSpring event Free Lecture: Mastering the Reset Curve to access all of the materials, including downloadable presentation slides, and the event discussion board. 

About Dave Yates: In February of 2014, Contractor Magazine named Dave  one of the most influential people in plumbing and hydronics by Contractor Magazine. Born and raised in York, Pa., Dave began his career in the PHVAC trades in 1972. After serving his apprenticeship and working up to Master Plumber status, Dave struck out on his own in 1979. In 1985, Dave returned to the company where he had served his apprentice years and purchased F.W. Behler, Inc., a third-generation PHVAC firm that is celebrating 114 years of service in 2014. Dave’s company has won numerous awards for its work and Dave was the first recipient of the international Carlson-Holohan Industry Award of Excellence. Dave Yates is an expert instructor at HeatSpring and will be teaching an advanced, 6-week online course Fundamentals of Radiant Design for the third time starting September 8th. The course is capped at 50 students with 30 discounts. Read the full course outline here.

Posted in Building Efficiency | Leave a comment

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.

Continue reading

Posted in Featured Designs, Products, and Suppliers, Solar Photovoltaics | Tagged , , | 2 Comments

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


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.





Posted in Geothermal and Solar Design and Installation Tips, Solar Photovoltaics | Tagged , , , , , | Leave a comment

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.

More Reading

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.


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.

Learn More

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!

Posted in Solar Photovoltaics | Tagged , , , , | 1 Comment

Solar Technology Tour: Differentiating Solar Heating Technologies Across North America

Take a solar heating technology tour of several different solar installations across North America and become better acquainted with solar technologies used in residential and commercial heating applications across the continent in this 40-minute free video lesson.

Your tour guide? Vaughan Woodruff, owner of Insource Renewables, a solar consulting firm in Pittsfield, Maine and one of our expert instructors. 

By the end of the free video lesson, you will be able to:

  • Describe the visual appearance of specific solar technologies
  • Differentiate between solar technologies
  • Identify specific applications for solar heating technologies
  • Discuss climate considerations for solar heating systems


You can access the free video lesson by test-driving Vaughan’s upcoming course, Solar Approaches to Radiant Heating.

Interested in learning more about Vaughan’s upcoming course? Check out the full course outline! 

Posted in elearning | Tagged , | Leave a comment

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



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.

In this article we will explain:

  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.
  5. Further reading.

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.

Screen shot 2014-08-06 at 9.39.08 AM


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

Troubleshooting Condensing Boilers in Hydronic Systems – What is the System Doing?

This a guest post from Roy Collver. Roy is a condensing boiler expert. Here’s what John Siegenthaler, author of “Modern Hydronic Heating,” says about Roy’s work: “When I have a detailed question about the inner operation of a modulating / condensing boiler, Roy Collver is the first person I contact. The investment in Roy’s HeatSpring course is a fraction of the cost of a single mod/con boiler, but it will teach you concepts, procedures, and details that will return that investment many times over.”

Learn from Roy

  • Free. Roy is teaching a two-part free course on how to sell mod-con boilers. The second live lecture is happening on Wednesday, July 30th. Sign up for the free mod-con course here.
  • Paid: Roy Collver teaches an advanced 5-week course on mastering condensing boiler design in hydronic systems with the folks at HeatSpring. If you need to increase your skills and confidence around selling, quoting, designing, setting up controls, or troubleshooting condensing boilers in new construction or retrofit applications, this course is for you. Each session is capped at 50 students, but there are 30 discounted seats. Get your discount and sign up for Condensing Boilers in Hydronic Systems.

Enter Roy…

Understanding the Simple Basics

Cold weather is never too far away in most parts of North America. Be ready when it hits, and review the basics of hydronic system operation so you can quickly locate the problems that always come up. When you approach an operational hydronic system it will exhibit one of the following six states. Quickly understanding what you are dealing with will greatly reduce head-scratching time and point you in the right direction. Standing slack-jawed in front of a boiler with no clear path to determining what is wrong is very uncomfortable and a waste of time. Confidence is a key factor in successful troubleshooting, and to be able to indicate to a customer what the BASIC problem is right away buys you time to be able to work the problem, find out the SPECIFIC cause, and fix it. Using this guide as a quick reference should help speed the troubleshooting process along.

Hydronic systems are all about Delta T (the difference in temperature between the heating fluid, the system components and the surrounding air and objects). Heat always travels to cold, and if heat is not added to the heat transfer fluid (usually water), the fluid and all of the components in the system will eventually cool down to the temperature of the surroundings.



The boiler is on and the hot combustion gases create a large Delta T between the combustion chamber and the water in the surrounding heat exchanger. Because heat travels to cold, the water heats up. The circulation pump moves the hot water through the distribution piping to the terminal units. The terminal units heat up and a Delta T develops between the hot terminal units and the colder air. The air will get warmer at the expense of the water, which cools slightly. The cooler water circulates back through the system back to the boiler where it is heated up again. If the heat going into the boiler is more than the system can use, the water will continue to get hotter until the boiler cycles off on its operating control. The temperature difference between the water leaving the boiler and the water returning to the boiler will be “normal” for the system (usually 15°F to 40°F depending on the load and system design).

noflowThe boiler is on, adding heat to the water, but for some reason the hot water is not circulating through the distribution piping to the terminal units. The terminal units will cool down to the temperature of their surroundings and a “no heat” condition will result. The water in the boiler will continue to get hotter until the boiler cycles off on its operating control or internal high limit control. The supply and return piping near the boiler will be close to the same temperature.



The boiler is on, adding heat to the water, but the hot water is not circulating fast enough through the system. The first terminal unit may become warm, but because the water is moving so slowly, all of the usable heat is transferred out of it before it gets very far. The last terminal units do not become warm enough to heat the space and a “not enough heat” condition will result. The water in the boiler will continue to get hotter until the boiler cycles off on its operating control or internal high limit control. There will be a large Delta T between the water leaving the boiler and the water returning to the boiler. (The supply will be a bit hotter than normal, but the return will be much colder than normal.)


Continue reading

Posted in Building Efficiency | Tagged , , , , | Leave a comment

5 Ways the Biomass Heating Industry is Laying the Foundation for Explosive Growth

At HeatSpring, we connect and build communities of learners and experts. Sharing knowledge is our passion. We collaborate with people in technical, complex industries to develop awareness, inspire creative ingenuity, and push boundaries. Most recently, we’ve focused on the biomass energy heating industry.

To get a pulse for what’s happening in the industry, we connected with six awesome individuals who are working on increasing the adoption of biomass heating systems:

The vibrancy of and momentum happening in the biomass heating industry prompted the creation of the Hydronic-Based Biomass Heating Professionals LinkedIn group. The group is a space to provide biomass heating professionals an opportunity to connect, collaborate, and share their own knowledge. Check it out to add to this conversation.

5 Ways the Biomass Heating Industry is Laying the Foundation for Explosive Growth:


Dr. Harry “Dutch” Dresser, Managing Director of Maine Energy Systems, is a pioneer in the biomass energy industry. He formed Maine Energy Systems with his partners, Les Otten and William Strauss, to improve energy production and usage in Maine by offering a complete wood pellet fired central home heating system and guaranteed fuel delivery, as well as comprehensive annual maintenance. When asked to share industry barriers to growth, he shared that just as the introduction of any technology takes time, so too will boiler technology for homeowners, insurance companies, and policymakers. Maine Energy Systems’ website focuses heavily on education for that very purpose. Spending a few minutes on their website, homeowners begin to learn how to differentiate between different boilers, that pellet stoves differ from boiler systems in every regard, and how to calculate the cost savings of shifting from oil to biomass.


Maura Adams, Program Director of Northern Forest Center, Alice Brumbach, Executive Administrator of the NY Biomass Energy Alliance , and Gabrielle Stebbins, Executive Director of Renewable Energy Vermont know this best. They work on initiatives to raise awareness about the benefits of alternative energy consumption spanning New York, Maine, Vermont, and New Hampshire. Adams’ team leads the Model Neighborhood Project, a program that incentivizes the installation of high-efficiency, automated wood pellet boilers to increase familiarity with these systems, demonstrates their value and viability, and develops service and pellet delivery infrastructure. In June 2014, the Center launched their most recent Model Neighborhood Project in nine Northeast Kingdom towns in Vermont. Brumbach and the NY Biomass Energy Alliance, a coalition of individuals, businesses, and organizations working together to enhance support, understanding, and use of sustainably-produced farm and forest biomass as a source of renewable energy, co-hosts the Northeast Biomass Heating Expo. The Expo is the biggest in the region. Brumbach recently completed a two-year project: The Local Impact of Woody Biomass Energy Projects: Quick Assessment Tool for Planners and Community Leaders, a first of its kind Excel-based tool, to help people calculate the impact of a shift from oil to biomass on harvesting, air quality, and highway traffic, as well as potential benefits such as local economic activities, tax revenues, and employment. Stebbins and the Renewable Energy Vermont team are focused on bringing together the multiple stakeholders in the renewable energy industry – from land owners to loggers to system designers, installers and maintenance operators — to identify market barriers, reduce soft costs and increase the expansion of modern wood heating throughout Vermont. On October 16 & 17, they will host Renewable Energy 2014 (RE 2014), Vermont’s annual convention bringing together key players in the clean energy sector. This year’s conference will highlight current energy challenges, Vermont’s leadership role in the energy industry, and the steps needed to implement an integrated energy infrastructure. What else is happening in Vermont? Currently, more than 30% of Vermont’s K-8 public school students attend schools heated by wood and over the next year, the Vermont Clean Energy Development Fund is expecting to disperse a few million dollars into incentives for modern wood heating for public schools and residences.  Simultaneously, Vermont just received a grant from the US Forest Service to develop the industry through a State Wood Energy Team.


The adage of life also applies to biomass heating systems. John Siegenthaler shared that when it comes to boiler installation, the biomass industry must focus on complete systems supplied by biomass heat sources. He stressed the importance of using modern hydronics technology and specific control techniques that allow the operating characteristics of a boiler to match the load profile of a building. Amanda Byrd, Program Coordinator at the Alaska Center for Energy and Power (ACEP), recently flew John to Fairbanks for a two-day workshop dedicated to teaching more than 50 designers, utility managers, and engineers best practices for system design. ACEP, based at the University of Alaska, is dedicated to applied energy research and testing focused on lowering the cost of energy throughout Alaska and developing economic opportunities for residents and Alaskan industries. The ACEP and the Alaska Energy Authority are hosting their 9th annual Alaska Rural Energy Conference on September 23rd, 2014 to offer more than 500 research professionals, engineers, installers, and policymakers new energy technologies and technical sessions.


It’s obvious that Dresser and his team don’t do anything half-heartedly. From all-you-can-eat lobster festivals educating consumers about the specifics of biomass energy heating to installation training requirements and truck redesigns for optimal pellet delivery to comprehensive maintenance reviews, Maine Energy Systems upholds what Dresser says is important for the biomass energy movement to grow. Positive user experience and properly-installed boiler systems are key to advance the market. Companies and individuals who compromise the continuum of quality (like installing the wrong equipment together) pollute the marketplace.


The biomass energy industry is an economic closed loop. Supply and demand are directly related to resources. Some barriers the industry faces include High upfront costs of equipment and confusion about fuel costs. Joe Seymour, Executive Director of the Biomass Thermal Energy Council (BTEC), shared the initial high costs of converting to modern wood heating equipment can scare away home and business owners. However, biomass fuels have historically been much cheaper and less subject to wild price swings compared to oil and propane, meaning consumers can often pay for their systems through cost savings alone with a few years. Credits and grants for biomass heating systems are available to defray costs, too. People interested in incentives for renewable energy can learn more from DSIRE, the most comprehensive source of information on incentives and policies that support renewables and energy efficiency in the United States. Through its Model Neighborhood Project, the Northern Forest Center offers financial incentives for residential and non-residential installations in specific towns in Maine and Vermont. For a more specific take on incentives, BTEC will hold a webinar about thermal grants, rebates, and credits.

Joining The Community

What do you know that others should know? Share your knowledge in the Hydronic-Based Biomass Heating Professionals LinkedIn group and contribute to the Live Lecture: Temperature Stacking in Thermal Storage for Biomass Heating Systems discussion board.

Investing in Biomass Training

This fall, in collaboration with BTEC, HeatSpring is offering a course to teach engineers and contractors how to design hydronic-based biomass heating systems. John Siegenthaler, our expert instructor, will teach advanced control techniques for system design and more.

John will also host an August 7th live lecture that will cover a very specific control technique that is ideally suited to systems using pellet-fueled or wood chip-fueled boilers and is open to the public at no cost.

Posted in Biomass Heating | Leave a comment