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How Massachusett’s Alternative Energy Credit Prices Will Impact Heat Pump and Biomass Operating Costs

aecprices

We passed the Massachusetts “Clean Heat Bill” in July 2014. The final bill number is S. 2214. 

The bill created a production-based incentive, similar to solar PV renewable energy credits (SRECs), for renewable thermal technologies including solar thermal, air source heat pumps, ground source heat pumps, solid biomass, and biogas.

In this article, I’ll explain how Alternative Energy Credit (AEC) prices will impact the cost to deliver heat from biomass and air source and ground source heat pumps. An AEC works the same as a REC, but the “A” stands for “Alternative” rather than “Renewable.” While the bill applies to more technologies than heat pumps and biomass, I’ll focus on technologies that can be used as primary heating sources for Massachusetts properties to provide some perspective for the building and HVAC industries.

I’ll discuss the impact of a $20/MWth payment on the generating cost for air source heat pumps, ground source heat pumps, and advanced biomass boilers. The current market price for APS AECs is trading around $29/MWth, close to the ACP payment, so $20/MWth is a conservative market price for these AECs.

The article will explain that potential AEC prices will reduce ASHP operating costs by 13%, will reduce GSHP operating costs by 33%, and will reduce biomass operating costs by 30%.

For this article, I’m only going to focus on the impact of operating costs for these technologies. I won’t focus on how these operating costs savings will impact the returns of specific projects. The reason for this is that it would require too much research and I’d have to control for to many “what if” scenarios. In order to address returns on a project, I would need to include installation costs and then compare these installed and operating costs to a competing technology to determine how it would impact returns and savings.

My assumption is that by providing specific operating cost information you can then apply these to your project-specific installed costs.

If you need some technical background information on how air source heat pumps, ground source heat pumps, solar thermal or biomass work, sign up for our in-depth free course on the subject: High Performance Building and HVAC 101

Background on the Bill

S.2214 created a production-based incentive for “useful thermal energy” that provides heating and cooling in situations where fossil fuels would have otherwise been the source of energy.

Here is how the bill defines useful thermal energy:

“Useful thermal energy”, energy in the form of direct heat, steam, hot water or other thermal form that is used in production and beneficial measures for heating, cooling, humidity control, process use or other valid thermal end use energy requirements and for which fuel or electricity would otherwise be consumed.”

One of the most impressive aspects of the bill is that it had broad support from many parties including private industry, environmental groups, renewable energy groups, electric utilities, and the Patrick administration.

What made the bill work well is that the existing Alternative Portfolio Standard (APS) market was under-supplied. The existing APS was created in 2008 as part of the Green Communities Act. However, the applicable technologies in the APS have never fully developed. The result of the APS under-supply is that the utility load serving entities were paying alternative compliance payments (ACP) because the AECs didn’t exist. The total ACP payments totaled around $12MM per year.

Assumptions for the Cost to Deliver 1 MMBtu For Each Energy Source

To discuss this, we first need to make a number of assumptions about each technology source.

Air Source Heat Pumps Operating Costs

  • Electricity Cost – $0.15/kWh
  • Operating COP – 2. Many will say that this is low. However, for my analysis, I’m assuming that air source heat pumps are the primary and only heating system for the entire load. This makes the analysis easier on my end, but would mean a lower COP over a long period of time over a large data set of systems. If you have any specific data to the contrary, please put it in the comments.

Ground Source Heat Pumps Operating Costs

  • Electricity Cost. $0.15/kWh
  • Operating COP – 3.5. With this, many in the ground source industry will say that this is too low and that they see COPs in the 4s and 5s. My response to this is that I’ve never seen any real time data over a large number of years, with a large sample size, that can support this claim. Read more about real time geothermal monitoring data. An operating COP of 3.5 is much more conservative.

Biomass Boilers

  • Cost per ton delivered: $225. This is based on conversations I’ve had with a few suppliers.
  • BTUs per ton. We will assume that each ton of pellets can produce 16 million BTUs.
  • Operating efficiency of boiler and distribution system is 80%.

Based on these assumptions, here’s the cost to deliver 1 MMBtu for these systems.

costperMMBTU

Here are the specific numbers:

  • ASHP – $21. 98
  • GSHP – $12.56
  • Biomass – $17.57

In case you’re curious, here’s the calculation:

cost

For each MMBtu, what percentage came from a renewable source?

  • In the case of air source heat pumps, how much heat was extracted from the air?
  • For ground source heat pumps, how much heat was extracted from the ground?
  • For biomass, how much of the heat delivered came from biomass?

Based on our assumptions of operating efficiency for each technology, here are the answers:

  • ASHP – 500,000 BTUs of 1 MMBtu will come from the air
  • GSHP – 714, 285 BTUs of 1 MMBtu delivered will be extracted from the ground.
  • Biomass – 900,000 of 1 MMBtu will come from biomass.

How many MWth were produced from a renewable source?

AECs are minted on a per MWth basis. Thus, we need to convert MMBtu to MWth.

The conversion to go from MMBtu to MWth is multiplying MMBTU by 0.293. In case you’re curious, the conversion factor to go the other way, from MWth to MMBtu, is multiplying MWth by 3.412.

Here’s how much each type of technology, given our assumptions, will harvest from a renewable resource per 1 MMBtu delivered to a conditioned space.

  • ASHP – 0.146 MWth
  • GSHP – 0.20 MWth
  • Biomass -  0.26 MWth

If we assume that the AEC prices are $20 per MWth, here’s the value of that production per MMBtu delivered.

  • ASHP: $2.93
  • GSHP: $4.19
  • Biomass: $5.27

MMBtu Cost vs. AEC Value vs. New MMBtu Cost

To make this interesting, let’s compare the existing MMBtu delivery cost, the value of AECs per MMBtu with the new law, and the new cost to deliver MMBtu after considering the AEC prices.

aecprices

 Here is the information on this graph with specific numbers:

graphmmbtu

What this graph shows is that, given our assumptions about operating efficiency are correct, the AEC prices will reduce ASHP operating costs by 13%, it will reduce GSHP operating costs by 33% and it will reduce biomass operating costs by 30%.

How would this impact normal home economics? Let’s assume we have a house with a 100 MMBtu load. 

See the graph for what the numbers what would look for a 100 MMBtu load.

100mmbtu

You’ll notice that the AEC prices, while they do decrease the per MMBtu cost by between 13% and 30% is substantial, they don’t add up to a large amount in cash.

Here is what the AEC payments would be for each system if the system delivered 100 MBtu in a heating season, given all our assumptions about AEC price, operating efficiency of equipment, and how much it ran.

  • ASHP – $293
  • GSHP – $418
  • Biomass – $527

You’ll notice that these payments are not huge. Given that “revenue grade metering” does not come standard on any of this equipment, this could be an issue for smaller systems.

Heat Metering

The legislation clearly states the metering requirements. You can see the language from the bill at the top of the below slide.

doer

Systems using biomass boilers or ground source heat pumps can be metered effectively. ASTM is currently working on a heat metering standard that should be completed by 2015. However, there are no known methods for providing utility-grade metering for biomass furnaces or air source heat pumps. It’s extremely difficult to measure heat transfer through air.

This is further compounded by the amounts of money that are being considered. For small residential systems, the cost of metering systems, even if a standard exists, would likely outweigh the increased revenue of those systems.

The DOER is currently in the process of creating regulations and a key aspect that they are considering is metering guidelines and how to distinguish between small and large systems.

Upfront Minting – Getting XX years of AEC Payments in Year 1

During our renewable thermal stakeholder metering, one of the things that the DOER expressed interest in is “upfront minting,” which would mean that a property owner would get the credit for many years of AEC payments upfront. The amount of payments would be based on software projections. If the systems had metering and underperformed, there would be some sort of under-performance penalty in future years. There are many “what if” scenarios for upfront minting that the DOER is still trying to figure out.

Upfront minting would have the benefit of decreasing installed costs in year one, something that property owners are extremely sensitive to. Here’s how much 5 and 10 years of AECs could be worth in our simplified example.

5 Years of AECs

  • ASHP – $1,465
  • GSHP – $2,090
  • Biomass – $2,635

10 Years of AECs

  • ASHP – $2,930
  • GSHP – $4,180
  • Biomass – $5,270

Another issue raised by upfront AECs is who will cover the spread. If a biomass system is getting paid for 10 years of AECs before those AECs have actually been created, where is the money coming from?

An answer doesn’t exist for this question yet, but it will be important to consider.

Heat Pumps as “Producing” Energy

One of the key aspects of the law that always brings up an interesting conversion is this line of thinking: “Heat pumps don’t produce energy; they’re energy efficiency. They just move energy.”

My response to that is twofold.

First, solar PV does not produce energy; it just moves it. However, we consider solar PV to be a production resource. It moves energy from sunlight into something that we can use in the form of AC electricity. Also, solar PV isn’t very efficient at all. It only converts about 15% of 20% of the sun’s energy into useful energy. You could argue heat pumps do the same thing, they move energy from a non-useful to a useful form. However, heat pumps are actually much more efficient than solar PV.

Second, if I had a air source heat pump that delivered 10 MMBtu to a conditioned space with an average annual COP of 2, it means 5 MMBtu came from the outside air. Aren’t the BTUs in that air renewable? Obviously they are.

Applications in the Market

Another question to think about as the regulations for this law are created and go into effect is how and where the new law will impact the existing heating market. There are two places to look at: the residential HVAC retrofit market and low energy use building market.

Residential HVAC Retrofits

Massachusetts is a retrofit market. This means that the large benefit of these incentives will be to spur investment in these technologies for existing homes. However, metering on a residential project, assuming AECs cannot be minted upfront or a simpler method can’t be created, could be cost-prohibitive.

If the DOER can figure out how to minimize metering costs and pay for AECs upfront on smaller projects, the residential market will benefit enormously.

For the commercial and industrial markets, project costs relative to metering costs will be so large that metering won’t be an issue. Also, the AEC value for larger projects will be much more substantial.

Low Energy Use Buildings

While low energy use buildings are a growing trend, they’re not a large enough segment to actually impact the market. However, within these buildings, air source heat pumps tend to be the main source of heat pump simply because the space heating loads are so low. In these instances, almost by definition, they wouldn’t create many AECs simply because they don’t need much heat.

Further Learning

Here are a few resources if you’d like to learn more about the basics of these technologies, the new Massachusetts renewable thermal law, or existing renewable thermal incentives in Massachusetts.

  1. Free Course: High Performance Building and HVAC 101. This is an in-depth free course on high performance building, air source and ground source heat pumps, and biomass HVAC systems
  2. Massachusetts Clean Heat Bill
  3. Existing Massachusetts Renewable Heating and Cooling Incentives

 

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Community Solar 101

There’s been a lot of buzz about community solar lately. While the amount of investment in community solar projects is a fraction of the investment of the entire solar industry, there are a few leaders who recognize the incredible potential of community solar.

Over the next few months, we’ll be publishing a series about community solar. This is the first article in that series. If you’d like to learn more about the subject, sign up for our free Commercial Solar PPA 101 course.

In this article, I’ll address the following questions.

1. What is community solar?

2. Why is community solar important for the solar industry?

3. What are the regulations that make community solar possible?

4. Who are the key parties involved?

5. Are the different structures that can be used to develop community solar projects?

Background – Why are we writing this article?

To give you a sense for how small community solar is at the moment, SEIA reports that there “at least” 52 “shared renewables energy projects” in the US. While it’s likely the amount is higher, even if it’s 10 times more, that’s only 520 projects.

We decided to create this article series simply because of the volume of questions we’ve been receiving about this topic in three places.

  1. A section in our commercial solar PPA 101 free course dedicated to community solar has been getting a lot of questions.
  2. Professionals continue to join our LinkedIn group “Best Practices for Financing Mid-Marketing Solar Projects” and ask for help on community solar topics.
  3. Lastly, in our Solar Executive MBA, where students are focused on learning how to develop and finance commercial solar projects from start to finish, we’re getting more and more questions about community solar.

This article will outline some of the basic key points around community solar. The goal with this first article is to go much deeper than most of the trade press can go and provide practical advice on the subject. While some of the content will be original, a lot of what I’ll focus on will be curation and organization of the existing material on the Internet that will make it easier for you to do research on your own time.

We’ll start with the basics and get more and more detailed.

There are so many questions to be answered that it’s difficult to determine where to start, so I asked our “Best Practices for Financing Commercial Solar Projects” Linkedin group, focused on financing mid-market solar projects any questions about community solar, to tell me what they wanted to learn. Here’s what they asked:

  1. How much should a developer expect to pay to lease the land/rooftop space for the array?
  2. Are lease payments based on $ per acre (sq. ft.)? or $ per MW? or $ per MWh?
  3. Are there typical escalators? 1% a year?
  4. Who takes responsibility for paying the taxes? Landowner? Developer?
  5. Are typical lease terms 20 or 25 years? Do they typically have options for renewal?
  6. What sort of developer fee is reasonable given the significant additional overhead associated with managing a community array?
  7. Do the community solar customers really own a piece of the system? Or do they only own the rights to the energy and environmental attributes of the production from their piece of the system?
  8. Is the community solar LLC able to depreciate the value of the solar array?
  9. Who gets the federal tax credit? The community solar owners on a pro-rata basis? or the community solar LLC?
  10. What are the advantages / disadvantages of having a large anchor tenant / off-taker?
  11. Are there any rules of thumb on the cost of sales? How much should a developer budget in cost per watt for sales/marketing/admininstration/legal expenses to close a customer?
  12. Do you have any legal agreement templates to review for several agreements needed between the various parties?

These are all excellent questions. They’re just hard to answer without a significant amount of work. Also, given that such a small number of installations have been completed, it’s not clear that there are concrete answers for any of these questions.

By the way, if you’d like to connect with other professionals working on financing community solar projects, please join our Linkedin group on best practices for financing community solar projects.

For this article, I’m going to assume that most solar professionals have heard of community solar and know that it’s something about having one large array that credits a larger number of residential customers but have not done much more reading than that. If you have a much deeper understanding of community solar than this, this article will be dull to you. If this is exactly what your understanding is, it should be a better fit.

What is community solar?

In the most basic form, community solar means that there is a single solar asset that is producing power. The power that is produced can be owned or purchased by multiple parties that are not sited at the exact location of the array.

In many ways, community solar is similar to community wind, although community wind has been far more successful. The wind industry, unlike the solar industry, first developed as a utility-scale energy provider and has slowly been working towards smaller and smaller projects. Two of the largest community wind developers, National Wind and OwnEnergy, have developed a combined capacity of 5,000 MW.

How does community solar work?

  1. There is a single large solar array that is installed.
  2. Similar to financing any commercial solar project, it can be structured as a power purchase agreement, where the homeowner is simply purchasing a specific amount of power, or an ownership model, where the members technically own a certain number of modules of the array and receive the production of those modules.

Why is community solar important for the solar industry?

Community solar is important for a number of reasons.

  1. Increase the addressable market size by 2X to 3X overnight.
  2. Instantly lower the customer acquisition costs for a residential solar installer that is already generating and selling roof mounted solar projects.
  3. Lower investor risk, in theory.

Let’s dig deeper into each of those.

First, community solar drastically increases the number of people that can buy solar. Increasing the number of potential customers means that the solar industry simply has more room to grow, more equipment can be installed, more people employed.

Faze1 screened all of the 1.2 million single family homes in Massachusetts and found that only 26% of them have suitable roofs for solar. It is true that some of them could install a small ground mounted system in their yard. However, it’s reasonable to assume that this would be a small percentage. Community solar provides solar access to the rest of the homeowners who don’t have proper roofs.

It also provides solar access to renters who cannot buy solar because they don’t own their home. In the existing solar model, solar makes the most sense when you own the building where the solar is being installed. Because community solar can change ownership quickly, renters will have access to solar.

The benefit of having more potential solar customers is clear. By increasing the potential market size of solar, it allows there to be a larger target market, more customers, more companies, more solar workers, and more cash flowing.

Second, community solar instantly lowers the customer acquisition costs for a residential solar contractor that is already selling roof mounted solar projects.

Reducing soft costs, and specifically customer acquisition costs, has been a focus of the solar industry for the past 18 to 24 months. Allowing community solar development would solve this problem. In fact, a recent solar bill in Massachusetts would have eliminated community solar potential because it removed virtual net metering. 

I’d argue that the most important reason for more community solar development is the ability to decrease customer acquisition costs for existing roof-mounted solar providers by at least 50% to 70% overnight. Let me explain why.

Let’s look at the sales funnel of a typical solar customer. This data was provided by Faze1. They have done extensive research on optimizing solar marketing profitability using better consumer data.

Let’s assume this is what a typical sales funnel looks like. Yes, these are averages and over-simplified, but they will illustrate my point. You could simply plug in your business’s number to get a better idea.

  • Marketing spend: $10,000
  • Leads Generated: 300
  • 30 – Qualified lead. Those that are willing and able to go solar.
  • 120 – Willing and not able lead. Willing means that they are interested in solar, have good credit, etc. They could purchase cash, use a solar loan, or buy cash. Not able means that the existing site is not suitable for solar.

This is anecdotal evidence from most of the contractors I’ve spoken with. But it’s clear that in order to find customers who can go solar and have acceptable roof space requires attracting and talking with 3 to 5 times more potential customers who want solar but don’t have the roof space. By being able to sell that customer a 20-year PPA for their home’s power or a 5kW share of a 1MW community solar facility, you can generate more revenue for the same marketing spend and number of salespeople.

If selling a community solar share was possible alongside roof-mounted solar, then the same $10,000 investment in marketing would yield 150 qualified leads instead of just 30.

Here are the numbers from my simple example.

  • Cost per qualified lead without community solar; $333 ($10,000 divided by 30)
  • Cost per qualified lead with community solar: $66 ($10,000 divided by 150)

Third, community solar has lower investor risk, in theory.

With community solar, the risk of default is lower than a PPA with a traditional roof mounted system. The reason for this is simple: In the case of non-payment, the community solar provider can instantly find another customer and change who is being credited for the power. In the case of non-payment for a roof-mounted project, power can be shut off from the solar provider, but there is no easy way to recoup the value of the solar array.

However, I’d suggest that, while this theoretical reduction in risk is true in the long term, community solar is perhaps a little more risky in the short term from an investor’s perspective simply because it is new. Potential risk will be affected by regulations, policy, and execution.

Key Parties

Here are the key parties in a community solar project.

  • Community Solar Service Provider. The community solar provider is responsible for setting up the SPE, gathering members, changing members, and handling billing.
  • Special Purpose Entity (SPE). The SPE is the specific legal framework that is set up to finance the project. It’s typically a LLC and it’s set up to own and operate the project.
  • Subscribers or Members. The subscribers or members are the “off-takers” for the project. They are buying the power. If they are “members” and invest in the project, they contribute their own money to buy a part of the project.
  • Host. The host is simply the location where the physical array exists.
  • Utility. The utility is responsible for distributing the power and billing credit. In the case of a utility-sponsored model, they are also buying the power and then distributing it to their members.
  • Developer. The developer does the engineering, procurement, and construction work and sets up the PPA.
  • Installer. The installer is responsible for building the project.
  • Investor. The investor is the individual or entity that is financing the project and monetizing the tax credits if the community solar project is financed with a PPA.

Regulations

There are three types of regulations that allow for community solar development:

  1. Group Billing Standards. Group bill is often compared with how master metering arrangements can be set up in real estate transactions. A landlord receives a single bill for the entire building. The landlord then determines how to split that bill up between all of the tenants. Using group bill in the content of solar works the exact same way, except all of the “tenants” don’t need to live in the same building. What happens is that the utility creates a group of members who want to be billed together. The utility produces a bill that describes all of the members’ electric usage and charges. Second, the output from the solar array is netted against the group bill. In this way, a number of residential homes can receive credit from a single facility. In this structure, there must be a single utility representative that deals with disputes and billing. This is the structure most commonly used in Vermont. Read about community solar lessons learned in Vermont.
  2. Virtual Net Metering. Virtual net metering allows net metering credits generated by a facility to offset loads at multiple retail electric accounts within a utility’s service territory. Under virtual net metering, credits appear on a customer’s bill as they would under a traditional net metered project.
  3. Joint Ownership. Laws and regulations that allow joint ownership allow many individuals to invest and own a certain percentage of a larger solar array. They are then are entitled to the power produced by that array.

Available States

Technically, there is some form of virtual net metering in 11 states according to DSIRE:

virtual-net-metering-policies-feb-2014.001

However, only 4 states have effective policies that are actually spurring investment. Those are Massachusetts, Vermont, Colorado, and Minnesota.

This is a development map from Clean Energy Collective. You can see they only develop community solar projects in 4 states.

Screen shot 2014-10-09 at 8.54.07 AM

Why is there a difference between laws on the books and development?

Laws on the books and effective regulations are separate animals. I ran into this when trying to help a friend develop a small community solar facility in Maine, a state that does allow joint ownership and virtual net metering, technically. What I ended up having to do is work through a loophole to make the project the work. However, this loophole is only something that’s possible with close friends or family situations and made it obvious why community solar on a commercial basis in Maine is impossible. Read more about a step-by-step guide to a 14.25kW community solar project in Maine. 

 Ways to Structure Community Solar Programs

In my research, I have found that there are three main ways to structure a community solar facility. All of these images are courtesy of a NREL report on community solar. 

1. Utility-sponsored model

Under the utility-sponsored model the utility itself owns or operates the solar array. Ratepayers of this utility are then allowed to voluntarily chose to receive power produced by solar.

Here is how flows of capital work in the utility-sponsored model.

Screen shot 2014-10-09 at 8.44.56 AM

2. SPE. In special purpose entity formation, a group individual investors join a business enterprise to develop a community solar array.

Here is how this model is structured.

Screen shot 2014-10-09 at 8.45.05 AM

3. Non Project Buyback structure. Through a non-profit entity, donors contribute to purchase a community installation that is eventually owned by a charitable organization.

Screen shot 2014-10-09 at 8.45.16 AM

This is the first article in a series of articles and interviews that we’ll do on community solar. If you have a question about any of the content, please leave it in the comment section.

Additional Recommended Reading

If you’d like to learn more about the topics in this article, I highly recommend these resources.

 

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Air Barriers vs. Vapor Retarders vs. Drainage Planes: Learn Essential Building Science Specifics in 60-Minutes

Building science is complex. It takes time and experience to understand and integrate physics, chemistry, climatology, and ecology into building enclosures. Understanding the complex interplay of heat, air, and moisture flows within and across building enclosures— while paying attention to the conditions that occupants impose on the indoor environment—is integral to building success.

In this 60-minute video lesson, you will learn 3 essential building science specifics:

1) How to distinguish between air barriers, vapor retarders, and drainage planes

2) How to explain the role of vapor permeance in labels such as vapor barrier and vapor retarders

3) Several different materials that can be used as drainage planes

Enroll in our free Residential Building Science 101 course to learn more. Designed for residential architects, builders, trade contractors, and energy raters who want to learn the fundamentals of building science, including how to:

  • Calculate the necessary amount of ventilation air
  • Explain the pros and cons of balanced, exhaust-only, and supply ventilation
  • Describe various types of ventilation equipment

Looking to dive deeper into building science? Join Allison Bailes, one of the leading voices in the industry, in a 7-week online learning opportunity. Building on the BPI and HERS trainings, Mastering Building Science is a rigorous, highly-interactive GreenBuildingAdvisor.com course designed for professionals with a good handle on the fundamentals of building science. It provides an in-depth focus on the analysis and control of physical phenomena affecting buildings, incorporating building materials and building envelope systems. Review the full course outline here. The course is capped at 50 with 30 discounted seats. 

About Allison Bailes:
Allison A. Bailes III, PhD, is founder and owner of Energy Vanguard in Decatur, Georgia. Like many in the field of building science and green building, he is multi-faceted: His academic credentials in physics (BS, MS, MST, and PhD all in that field) give him a solid foundation in the science that underlies buildings. Having taught physics at the high school and college levels, he’s adept at explaining technical concepts in a way that people new to green building can understand. In addition, he has practical, hands-on experience. He built a high-performance home out of structural insulated panels, doing much of the work himself, and ran a home performance contracting business. You can read more about his work on his EnergyVanguard.com blog

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Understand the Key Grounding and Bonding Standards for Commercial Solar PV Projects in Less Than 30 Minutes

What are the differences between grounding and bonding in solar design? What are the most recent codes? Where are the codes headed? What are some of the changes that have happened? What does it mean for you and your installations?

In this free 20-minute video lesson, Ryan Mayfield identifies the key 2014 NEC code sections for PV system grounding and bonding and outlines general requirements of Article 250 – beginning part of code for Grounding and Bonding (and what he considers one of the most difficult and fun discussions). He also begins outlining Article 690 Part V: Grounding and Bonding Requirements.

Watch the full video below to learn more. If you have any questions about the content, please leave it in the comment section. If you’d like to connect with other professionals focused on designing, commissioning, managing, and installing large commercial solar projects, join our Megawatt Design Linkedin group.

The video covers the following:

  1. Key NEC standards for grounding and bonding
  2. Overview of Article 250 as it relates to solar PV
  3. Article 690 – Part V on grounding and bonding requirements
  4. How grounding and bonding changes will impact system design and installation

Watch the Lesson Here

Spend ten weeks learning from Ryan Mayfield, the Solar PV Technical Editor at SolarPro Magazine. Ryan, along with help from other industry leaders, has developed Megawatt Design, an online course to help experienced solar professionals get their projects permitted and installed faster and cheaper. This course goes beyond traditional solar training: it is technical, rigorous, and for experienced professionals only. We cover all types of large solar PV systems, with a heavy emphasis on commercial rooftop systems. Test-Drive Megawatt Design to access more free videos. The course is capped at 50 students with 30 discounted seats.

—-

Ryan Mayfield has been working in the renewable energy field since 1999 and is the President of Renewable Energy Associates, a consulting firm providing design, support and educational services for electrical contractors, architectural and engineering firms, manufacturers and government agencies. Ryan serves as Photovoltaic Systems Technical Editor for SolarPro Magazine, regularly writing feature articles in SolarPro and Home Power magazines, and wrote PV Design and Installation for Dummies. Ryan was also a contributor and video team member for Mike Holt’s Understanding the NEC Requirements for Solar Photovoltaic Systems. Ryan teaches various PV courses across the nation for electricians, existing solar professionals, code officials, inspectors and individuals looking to join the solar industry. Class topics include National Electrical Code and PV systems, residential and commercial PV systems.

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

Learn in 60 Minutes: Conventional vs. Passive Floor Planning

If you don’t floor plan properly, you will fail.

During this free 60-minute lecture, Mike Duclos, Principal and Founder of DEAP Energy Group and expert instructor at HeatSpring, describes how Passive House floor planning differs from conventional floor planning. Mike provides a background on the Passive House movement, presents examples of Passive House designs and floor plans, and explains why floor planning is critical for energy efficiency, cutting costs, and meeting the rigorous (and non-negotiable) Passive House Space Heating and Primary Energy requirements.

Access the full lecture and archived discussion board here

Thoughtful floor plan design can make the experience of living in the home much more enjoyable, reduce construction costs, and be a substantial asset in ‘making the numbers.’

plan

During this free 60-minute lecture, Mike will teach you:

  • Why orienting the long axis of the home to face South will save you money
  • Why plumbing layout impacts DHW quality of service, Primary Energy use, recovery, and the challenges to optimization and implementation
  • Some not-so-obvious reasons for orienting rooms with respect to the sun
  • Alternatives to the suggestions in the floor plan to adapt the implementation of the ‘physics’ to the aesthetics and desires of your clients
  • How to think ‘outside of the box’ with respect to floor planning

Access the Free Lecture and Archived Discussion Board Today! 

Mike Duclos is a principal and founder of The DEAP Energy Group, LLC, a consultancy providing a wide variety of Deep Energy Retrofit, Zero Net Energy and Passive House related consulting services. Mike was an energy consultant on the Transformations, Inc. Zero Energy Challenge entry, and has worked on a variety of Zero Net Energy, DER and Passive House projects, including two National Grid DER projects which qualified for the ACI Thousand Homes Challenge, Option B, the first National Grid DER to achieve Net Zero Energy operation, and the first EnerPHit certified home in the USA. Mike is a HERS Rater with Mass. New Construction program specializing in Tier III design and certification, a Building Science Certified Infrared Thermographer, a Certified Passive House Consultant responsible for the design and certification of the second Passive House in Massachusetts, holds a BS in Electrical Engineering from UMass Lowell, and has two patents.

Looking to gain solid knowledge and skills for Passive House construction or consulting work? Mike teaches “Passive House Design,” a six-week advanced online course that teaches students how to meet the rigorous (and non-negotiable) Passive House design criteria and make Passive House happen in the real world. Take a free test-drive of the course today. (There course is capped at 50 with 30 discounted seats.)

 

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Calculate Heat Loss to the Ground with Marc Rosenbaum

Marc Rosenbaum, Director of Engineering, South Mountain Company and one of HeatSpring’s expert instructors, taught a free live lecture to more than 200 architects and builders last week. His focus: demonstrate how buildings interact thermally with the ground and teach people how to calculate heat loss to the ground.

Access Full Lecture and Additional Resources Here

During the live lecture, Marc started with a 2D THERM model of a basement, reviewed the U factor that THERM calculates for the foundation assembly, and used that to calculate the design heat loss of the basement. He showed the attendees how to estimate the annual heat loss as well.

heatloss

He then presented the simplified Los Alamos algorithms for calculating heat loss from basements and slab-on-grade foundations and used those to analyze the model and compare the result with the THERM calculation.

losalamos

At the conclusion of the lecture, Marc discussed how to apply the algorithms to a walk-out basement condition and how to estimate design heat loss in the case where the insulation is in the frame floor over a basement.

Learning Takeaways

  • Learn about relative conductivity and heat capacity of soils vs. air
  • Learn about variations in soil temperature with time and depth
  • See the results of a 2D THERM model of a basement, including the temperature distribution, direction of heat flow, and heat loss rates
  • Learn about using the U factor calculated by THERM to estimate foundation heat loss
  • Learn how to do simplified heat loss calculations for basements, slab-on-grade, and walkout basement foundations
  • Learn how to estimate design heat loss through an insulated floor to a basement below

Marc Rosenbaum is the Director of Engineering, South Mountain Company. He uses an integrated systems design approach to help people create buildings and communities which connect us to the natural world, and support both personal and planetary health. He brings this vision, experience and commitment to a collaborative design process, with the goal of profoundly understanding the interconnections between people, place, and systems that generate the best solution for each unique project. Marc teaches a 10-week course,Zero Net Energy Homes, where students walk away with a comprehensive understanding of all of the key components of a zero net energy home, do a full design of a Zero Net Energy Home, and earn NESEA’s ‘Zero Net Energy Homes Professional Certificate.’ The next course starts on September 15th.

Read the full course outline of Zero Net Energy Homes and learn more here.
The course is capped at 50 students with 30 discounts.

 

 

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How to Handle Unknown Risk to Increase Solar Project Success

Known Knowns PNGImage: Universe of Issues, Risks, and Challenges

This is a guest article from Chris Lord, Managing Director at CapIron, Inc. He’s a former lawyer with extensive banking experience who now consults with solar developers and investors. I’ve never met anyone else who can, seemingly, answer any financial or legal questions about financing commercial solar projects.

In the article, Chris shares some of his experiences about how to understand and mitigate the risks that you don’t know exist in commercial solar development. Unknown unknown risks are extremely important to understand because they can have large negative impacts on profits and relationships with investors and clients. These risks are especially important for firms that are experienced in solar but new to financing larger commercial solar projects.

I found this article extremely interesting and if your work revolves around selling or financing commercial solar projects, I’m sure you’ll love it. If you have questions about the article, please leave a comment. If you’d like to connect with other professionals focusing on best practices for financing commercial solar projects, join our LinkedIn group on Best Practices for Financing Mid-Market Solar Projects.

Chris Lord also teaches our 6-week Solar Executive MBA that starts on Monday, September 15th. In the course, you’ll work a commercial solar deal from start to finish with expert guidance. The course includes financial models, legal contracts, and development tools that are indispensable.

Enter Chris Lord

Not long ago, I spoke with an experienced developer who told me about a small utility-scale project undertaken by a team within his company. Although experienced with distributed generation projects, the team and its leader had never developed a third party financed, utility-scale project. They knew that they had to learn more about the technical and procedural requirements for interconnection with the local utility and delivery of the solar power to the grid. Over the course of development, the project hit many roadblocks and challenges before finally arriving successfully at COD. Throughout the process, the team modeled the project early and often, generally showing a tight but acceptable profit margin for the project. At COD, the company collected its profit and moved on. Less than a year later, the third party investor in the project made a call on the developer’s tax indemnity required as part of the close. It turned out – to the utter surprise of the project manager and his team – that they had incorrectly assumed the federal ITC would apply the interconnection costs paid to the local utility for equipment on the utility’s side of the transformer. The error – when finally caught – cost the company more than its small profit margin on the project and constrained the company’s cash flow.

This articles focuses on the most dangerous and difficult threat to successful project development: the risks, issues, and challenges that you don’t know that you don’t know. These “unknown unknowns” are not the items that you know you don’t know. When you know you don’t know enough about a risk, issue, or challenge, you can remedy that ignorance by focusing on the problem and calling on experts – colleagues, advisors, consultants or lawyers – to help you learn what you must learn to overcome, hedge, or eliminate it. In the example above, the team knew it had to learn more about the technical and procedural requirements for interconnection with the local utility, and they did so successfully. What the team did not know was that it did not know enough about the ITC’s definition of “eligible equipment” and its application to their project.

Understanding the Challenge of Unknown Unknowns

Developers by nature have to be optimistic and confident souls, if they are to make their way through the minefield of project development. Without that optimism and confidence, a developer would never get started on the daunting task of taking a green field site from start to finish. In fact, the persistence that everyone tends to think of as the critical ingredient in developer success is actually just a manifestation of optimism and confidence.

Known Knowns (PNG)

But as life shows us, our greatest strengths are also our greatest weaknesses. That very same optimism and confidence necessary for successful project development often blinds a developer to the biggest risks of all. These are the risks – that through optimism, confidence, and ignorance – are simply not on the developer’s radar screen. These are not the known or expected risks. A successful developer manages a known risk by minimizing and staging investments of time and money until more about the risk is known or its threat neutralized. There are a lot of surprises in the life of a development project, and, because developers are an optimistic lot, it is rare that these surprises add to a project’s upside. More often than not, these “upside” events were already incorporated into project economics as “good to average assumptions.”

So what really can kill projects are the unknowns and the unexpecteds. We will just call them the “unknown unknowns.” These items consist of issues, events, or results that a developer does not even know that he does not know. And while a wealth of experience and education can reduce the potential unknown unknowns, they are always there. Nassim Nicholas Taleb (author of The Black Swan and several other books on risk) and many other investors specialize in investment strategies designed to capitalize on unexpected and dramatic events, such as the mortgage meltdown crisis of 2008. These strategies involve multiple small bets on a wide variety of extreme outcomes. But a project developer is betting on not having unknown unknowns occur, and that is a lot harder to do.

Tackling the Problem of Unknown Unknowns

The image above illustrates the problem. If we begin with the blue box, then that is the complete universe of all issues, risks or challenges. At the very center of the box is the yellow circle that illustrates what we know (sometimes called the “known knowns”). These are the items that, through education and experience, we know how to handle and are comfortable wrestling with them. The orange cloud surrounding the yellow circle represents the items that we know we don’t know. Within this nebulous cloud are the issues, risks, and challenges that we know just enough about to know we must anticipate and manage them, but we don’t know enough to define them and consider the solutions, hedges, or alternatives. In other words, we know that we can expect the item to arise, and that to manage that item we must either educate ourselves, find an expert to manage it for us, or some combination of the two. For example, most developers know that they must consider whether a project will be subject to property tax over the course of its existence. Property taxes are a set of arcane rules that vary not just from state to state but also from county to county. Moreover, solar PV projects may be characterized and taxed as real property in some jurisdictions, but they may also be taxed as personal property in jurisdictions that make the distinction. In this case, when a developer begins a new project in a new state or county, he or she knows to consult local counsel early – before even meeting with local taxing authorities to discuss abatements or PILOT agreements.

Known Knowns PNG

Image: Universe of Issues, Risks, and Challenges

Specific Actions to Address Unknown Unknowns

So, turning back to our unknown unknowns, how does a developer guard against something that by its very nature is unknown and unexpected? Not easily, of course. But a couple of options come to mind. The key to all of these options is to work on expanding the known knowns and the unknown knowns. If you look at the illustration above, we are talking about expanding our knowledge and leveraging the experience of others to make the yellow circle as large as possible and grow the orange cloud outwards as well. In effect, we want to shrink the blue portion of the box – the unknown unkowns – by expanding the circle and cloud. Of course, we can never eliminate the blue, and should not imagine that is where our efforts should focus, but the faster we can grow the yellow circle and orange cloud, the better hedged against the unknown unknowns we will be.

Continue reading

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Free 65 Minute Lecture on Biomass Thermal Storage + Free Invitation to Maine Alternative Energy Expo 2014

Interphase Energy, a Maine-based leader in supplying central pellet heating equipment throughout North America, is hosting Alternative Energy Expo 2014 at their Portland, Maine facility this Friday, September 12th, 2014 from 2:00 – 8:00 p.m. EDT. Free to the public, the expo will showcase a variety of alternative energy organizations providing information and demonstrations as well as speakers, workshops, panels, food trucks and more.

We wanted to join the expo remotely, so we’re sharing a free lecture about alternative energy that we hosted in August with John Siegenthaler, one of our expert instructors with over 32 years of experience in designing modern hydronic heating systems.

FREE LECTURE: TEMPERATURE STACKING IN THERMAL STORAGE FOR BIOMASS HEATING SYSTEMS

This free lecture describes a unique method of managing the operation of biomass-fueled as well as auxiliary boilers for optimum system performance. Beginning with an explanation of why thermal storage is critically important in many systems using biomass boilers, Siegenthaler goes on to describe how temperature stacking is accomplished using multiple temperature sensors mounted in different vertical locations within a thermal storage tank and off-the-shelf controllers. He then explains how to use the temperature stacking technique in systems using multiple biomass boilers as well as systems that combine a biomass boiler with an auxiliary boiler.

The lecture covers:

  • The need for proper thermal storage in systems using wood-fired heat sources
  • The rationale of temperature stacking within thermal storage tanks
  • How to configure standard controls to manage temperature stacking
  • How temperature stacking differs when an auxiliary boiler is used

Check out the full free lecture and access the archived discussion board! 

John Siegenthaler, P.E., is a mechanical engineer and graduate of Rensselaer Polytechnic Institute, a licensed professional engineer, and Professor Emeritus of Engineering Technology at Mohawk Valley Community College. “Siggy” has over 32 years of experience in designing modern hydronic heating systems. He’s teaching two courses about biomass with us this fall: Mastering Hydronic System Design and Hydronic-Based Biomass Heating Systems. Both courses are capped at 50 students with 30 discounted seats.

Did you like that free lecture? Check out another free lecture taught by John: Low Temperature Heat Emitter Options in Hydronic Systems  

Interact with other professionals in the biomass industry in our LinkedIn Group: Hydronic-Based Biomass Heating Professionals

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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 HealthyHeating.com. 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.

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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