Solar Power in NH – Part 5 - Financing a Residential Solar System in New Hampshire

In this post, I take a closer look at funding a residential solar photovoltaic system in New Hampshire. Solar power has received a lot of coverage recently because the State rebates for new solar systems have been halted due to a lack of money in the Renewable Energy Fund that is set aside for this purpose and there have also been changes in the net metering regulations. The key point I want to make in this post is that there are still a lot of good reasons to install solar in NH - the net metering changes and the lack of a state rebate should not deter you.

Among the many good reasons to install solar on your home in NH are the following:

• Electricity prices in NH are high and the production of your own solar power will provide you with some protection from further increases;
• There is a generous federal investment tax credit on the installed cost of your solar system;
• You have the ability to earn money through the sale of renewable energy credits (RECS);
• Net metering of electricity in NH means that you get credit for the excess solar generated electricity that you feed into the grid during the daylight hours and you only pay for the net amount of electricity that you draw from the grid;
• NH state rebates on the costs of installed solar might become available again in the near future.

In this post, I look at a typical system and figure out how these incentives come into play so that your solar system will eventually pay for itself over time. For my calculations and the rest of this discussion, I have assumed that a homeowner installs a 5 kW solar system (about 17 panels) at an installed cost of $15,000, which would produce 6500 kWh per year, and that the homeowner uses about 600 kWh/month (7200 kWh/year) of electricity at a rate of $0.16/kWh. I have also assumed that the homeowner lives in an area where there is a property tax exemption for installed solar. (See the NH Office of Energy and Planning website for a list of NH towns with property tax exemptions for solar installations.)

One of the most important incentives for residential solar systems is the federal investment solar tax credit. This program provides you with a tax credit of 30% of the installed cost of your solar system. This program is in effect until 2019, but the tax credit begins to decrease in 2020 and, beyond 2021, the program has not been renewed and it is possible that it will no longer be available in the future.

Another good incentive is the rebate provided by the NH Public Utility Commission (PUC). Until recently, a homeowner could receive up to $2500 from the Renewable Energy Fund administered by the PUC.. However, this program is presently on hold as has been reported in the press. The program has been a popular one and, owing to the flood of applications, the PUC has had to cease approving projects and awarding rebates until they know how much money they have to work with. The funds for this program come from Alternative Compliance Payments paid by the utilities. As noted in a previous post, these vary from year to year and the funding available from this source is unpredictable. I expect that the PUC will go back to funding projects, but not all installations will be able to get rebates and I expect the rebate amounts to be smaller. For the purposes of my analysis in this post, I have assumed that the rebate is not available. If you are fortunate enough to be awarded a state rebate in the future, this will just improve the cash flow and payback on your solar investment.

Another incentive is the sale of RECs, which I discussed in a previous post. Solar has a special carve-out class – Class II – in the NH Renewable Portfolio Standard: for every 1 MWh (1000 kWh) of electricity you produce from your solar system, you can sell the equivalent REC. Class II solar RECs are presently selling for between $15 and $20, so, if your 5 kW solar system produces 6500 kWh/year, you could sell your six RECs for  $15 each to earn an additional $90. However, it is important to keep in mind that, as a small producer of RECs, the administrative and commission costs involved in tracking, verifying and selling those RECs could be of the order of $50, eating up a good amount of  your REC income. To benefit to a greater degree from REC sales,  homeowners would need higher RECs prices or should install a larger solar system to produce more RECs to defray the administration costs.

Net metering is an important incentive but as of June 2017, new regulations were issued by the NH PUC, which reduced some of the monetary benefits of net metering. With the new regulations, homeowners, whose exports of power exceed their consumption, will receive a reduced rate for their monthly net exports. I discussed this in detail in my last post and determined the rate reduction would be of the order of 20%. Homeowners with monthly net imports will continue to pay the retail rates for their net imports but the non-bypassable charges are treated separately. These charges, which include the system benefits charge, stranded cost recovery charge, and the state electricity consumption tax, are of the order of 0.5 cent/kWh and will be billed for every imported kWh no matter how much electricity is exported. The homeowner will not receive any credit for these charges for their exported kWhs.

To get a better appreciation of net metering at work, consider the following chart which shows the projected usage and solar generation for that typical NH home with a 5 kW solar system. The chart was prepared using generation data from the PVWatt calculator and residential load profiles for a NH residence from the Department of Energy. The graph shows monthly usage and generation and is different from my graph in my previous post which charted hourly data. The monthly view is important one as net metering is presently carried out on a monthly basis. The data shows that in the winter months, October to March, electricity demand is greater than solar power generation so there will be a net import of electricity into the home in those months. Homeowners would pay retail prices for those net monthly electricity imports. For the summer months, April through September, the amount of solar generation is greater than usage so there will be a net export of electricity and the homeowner would earn the lower export rates for their net exports during those months. My calculations indicate that, for the NH home we are considering in this post, a 5 kW solar system would save a homeowner $990 in electricity charges over the year. This is about $57 or 5% lower than the savings that would have been expected from net metering before the recent set of changes to the net metering regulations.

With these incentives in mind, let’s look at funding a solar system. There are three basic ways that homeowners can finance their solar systems:

• The first, and very popular with frugal northern New England Yankee types, is simply to buy the system outright using savings. The system then pays for itself through electricity savings, the federal solar tax credit, REC sales, and, if available, the NH rebate.
• The second is taking out a loan from a bank to fund the solar system and paying it back over a number of years. For the purposes of my calculations, I have assumed a $15,000 home equity line of credit (HELOC) with an interest rate of 6%, no down payment, payable over 15 years, and that the interest payments on the loan are tax deductible.
• The third approach is having a solar company pay to install the panels on your roof and you sign an agreement, known as a power purchase agreement (PPA), to purchase electricity at a reduced rate for an agreed number of years (typically 15). In a variant of this approach, known as a solar lease, you can end up owning the system after a number of years. The advantage of this approach is that there are no upfront costs, no bank loan, and you benefit during the period of the agreement from reduced electricity rates. However, in this approach, the solar company makes the investment and benefits from the incentives.

Each of these approaches have their respective pros and cons and will work for you in different ways – what is right for you depends on your savings and financial situation and how long you plan to be in your home. I took a look at each option and calculated the annual cash flows  over 15 and 20 years to compare how much money each of these options would put into your pocket. My key assumptions are that the electricity price is currently 16 cents/kWh and will increase by 2%/year, that RECs are $15 each and prices will decrease by 5%/year and that the administrative costs involved in selling RECs are $50/year. The results for all three financing options are plotted below.

The outright purchase option is plotted in blue. The initial outlay of $15,000 for the system is offset in the first year by the federal solar tax credit, the electricity savings of $990/year and REC sales of $90 (offset by the associated administrative costs and commissions). Every year thereafter, the initial capital outlay is offset by the annual electricity savings and REC sales. Early in the ninth year, the cumulative cash flows go from negative to positive. This is the payback point, so the payback period would be just over 9 years. After this, the investment is cash flow-positive and, by Year 15, the cumulative cash flow from the project is almost $7000. By Year 20, it will have risen to almost $14,000. Another way to view this financing option is that it is equivalent to making a $15,000 investment and earning a 8.7% return over 20 years, a return which, for most of us, is very hard to find these days. (Should the NH rebate become available, the project cash flows would be larger, the payback period would improve to 7 years, and the 20-year investment return would increase to 11.7%.)

Should you not have $15,000 available for a solar investment, you could consider taking out a loan for the solar system. There are a number of solar-system-specific deals available from NH lenders but, for this post, I have assumed a simple 6% home equity loan paid back over 15 years with tax-deductible interest. The cash flows are shown in orange in the chart above. The attraction of this option is that there is no initial cash outlay on your part and you benefit right away in the first year from that $4500 federal tax credit, which immediately puts that nice stack of money in your pocket. Going forward, you then have annual benefits of electricity savings and REC sales, but you also have loan payments of approximately $1520 per year. In this scenario, your annual loan payments are higher than your annual savings and that, over time, eats into that Year 1 tax benefit. By Year 15 your loan has been paid off and, from that point on, you benefit fully from your electricity savings and REC sales. By Year 20, the cumulative cash flow from the project will have risen to ~$8100.

The third option, popular with many homeowners in other states, is to have a solar company install a system on your home and then sign an agreement with them to purchase the produced solar power at a rate lower than the prevailing utility rate. For this case, I have simply assumed no outlay on the part of the homeowner and they get to purchase solar generated electricity for 13 cents/kWh, instead of 16 cents/kWh, giving an annual saving of ~$200. The cash flows for this option are shown in green - the cumulative cash flow from the solar project by Year 15 is approximately $3400; by Year 20, it will have risen to $4700.

Should you have different numbers and want to consider different system sizes, interest rates, or loan periods, feel free to use the Excel-based calculator that I have posted on this site and see what works for you. Please use the calculator as a guide only. Collect as much information as you can from other sources, get multiple quotes for your solar system and quiz each solar company on their payback calculations. Ultimately the more informed you are, the better your decision is likely to be. If you have questions or comments about the calculator, please reach out to me via email.

I have summarized the 15- and 20-year cash flow information for the three options in the table below. If we look at the cash flows for the project, it is clear that the best option, assuming that a homeowner has the funds, is the outright purchase of the system. The loan option, especially after 20 years when the loan has paid off, starts looking good as well. The least favorable option, over the 20-year view, is the PPA; however, if you don’t have the funds, and don’t want to take out a loan, it might be an interesting possibility.

Many of us don’t like home-investment projects with long payback periods or lengthy loans unless we are committed to staying in our homes for an extended amount of time. A report from the Lawrence Berkeley National Laboratory indicated that solar panels do increase the value of your home, but this only applied to homes with an owned solar system and not to homes where a solar company owned the system. So, if you pay to install a solar system and sell it before reaping all the long-term energy savings, you should gain from a higher sale price.

Take a look at the solar calculator I have developed and, if you have not done so already, seriously consider installing a solar system on your home. It will put money in your pocket over the long term, it will partially shield you from future electricity rate increases, and, most importantly, you will be helping to reduce greenhouse gas emissions from the burning of fossil fuels. In the meantime, while you are contemplating installing a solar system, remember to turn off the lights when you leave the room. 

Mike Mooiman

Franklin Pierce University

mooimanm@franklinpierce.edu

Click on this link to receive email notifications for Energy in New Hampshire updates

New Hampshire's Renewable Portfolio Standard – Part 3

In previous posts, I provided some introductory information about the Renewable Portfolio Standard (RPS) in NH, as well as specific information about Renewable Energy Credit (REC) trading and pricing. In this post, I take a closer look at the money flows in the RPS program and what it costs NH ratepayers.

                    

But first a quick review. Electricity providers in NH are required to source a certain percentage of their electricity from renewable energy (RE) sources by purchasing RECs generated by RE operations. There are different classes of RE and obligations for each class. RECs are a tradable commodity: their prices depend on supply and demand, which are driven by the various RPS requirements in each state. There is a upper limit on REC prices: as noted in my previous post, the Alternative Compliance Payment (ACP) sets a price cap on what the utilities are required to pay for each REC. If prices of RECs are above the ACP, the utilities are obligated to pay the ACP instead. When there is a shortage of REC in a specific class, their prices quickly rise to the ACP value set for that class; when a surplus occurs, REC prices can drop way below the ACP.

The flows of money (black) and RECs (green) within the RPS program are shown in the figure below. NH electricity suppliers, which include the four electrical utilities (Eversource (PSNH), Liberty, Unitil, and the New Hampshire Electric Cooperative) as well as the competitive electricity suppliers (for example, Constellation and TransCanada Power, among many others), can purchase RECs from NH RE plants or from RE generators in other states, as long as the generators meet the NH class requirements and are registered with the NH Public Utilities Commission (PUC) for that class. Some utilities have entered long-term contracts with RE generators  to buy electricity and the associated RECs directly. An example is the power purchase agreement between Eversource/PSNH and the Berlin Biomass facility that was put into place in 2011. These power purchase agreements have to be approved by the PUC.

When there are insufficient RECs available to meet the various class requirements or if REC prices are higher than the NH ACP, electricity suppliers are obligated to pay the ACP to the PUC. These payments go into the Renewable Energy Fund, which is used to support RE projects in NH. These projects, in turn, generate more NH-based RECs, which can then be purchased by electricity suppliers in NH.

Ultimately, the RPS program is paid for by ratepayers or customers of the various electricity suppliers because all monies paid out by electricity suppliers, either to buy RECs or in ACP payments, are bundled into their overall costs, which then find their way into the rates that the supplier charges its customers or ratepayers.

The money for the RECs is paid directly to the RE generators and is a valuable source of revenue for them. The wholesale price for electricity in NE is typically about $30/MWh, so the additional revenue from RECs, which can range from $10 to $55/MWh, is a very important part of their income. In fact, most RE projects could not survive without the REC income and, for many, it comprises the larger part of their income.

These RECs are, in effect, subsidies for RE generation. It is these subsidies that cause opponents of the RPS a great deal of angst: they view these subsidies as picking winners and losers in the energy market – the winners are subsidized RE generators over fossil-fuel based losers. However, another way to view these subsidies is to consider that they provide stimulus for innovation. We all live our very modern and connected lives due to innovation that has been driven by public policy. Just think of improvements such as microprocessors, vaccines, and the internet, all of which had their origins in government-funded research that was paid by our tax dollars. The RPS is similar: it is a public policy that provides subsidies that allow innovation in the energy field to take place; once technological advancement has proceeded to a certain point, the new technologies can stand on their own merits and compete head-to-head with non-renewable technologies.

One hitch with RECs being a revenue source is that it complicates the wholesale markets for electricity. Revenue from RECs is often much greater than that from the sale of electricity: RE generators want to sell power, regardless of how low electricity rates drop, so that they can generate the associated RECs and earn that income. There are times when RE operations, especially the larger wind operations in New England, will bid into the electricity market at zero or even negative prices, just to earn the REC-based revenue. This can cause market distortions and complicate the economics for non-RE plants, such as nuclear, that are not similarly subsidized.

Let’s turn our attention to those ACP payments. As noted previously, when there are insufficient RECs available to meet the various class requirements or if prices are higher than the ACP, the utilities are obligated to pay the ACP. That money goes into the Renewable Energy Fund, which is used to supplement funding for RE generation by state and local governments, commercial and industrial enterprises, and smaller residential-based projects.

The Sustainable Energy Division of the PUC administers the Renewable Energy Fund and runs two types of programs: a rebate program and a grant program. The rebate program provides direct financial support for commercial, industrial, and residential projects involving the installation of solar photovoltaics (PV), solar hot water, and wood-pellet furnaces. The grant program is a competitive scheme for the installation of RE projects at commercial and industrial operations. There is a rigorous selection process to determine which projects receive funding. The focus of the grant programs changes depending on the particular RE needs. At the moment, the preference is for thermal and small hydropower projects because there are REC shortfalls in these classes and attention is required to get additional facilities up and running to generate more RECs. Funding and disbursement of funds through the rebate and grant programs are reported annually by the PUC. This makes for informative reading if you are interested in these matters.

As can be seen in the figure below, ACP payments fluctuate significantly from year to year depending on a host of issues, including the NH RE requirement (which can ramp up annually), REC prices in other states, eligibility of NH RECs in other states, the number of RE facilities coming online and adding their RECs to market, and operational issues, such as shutdowns at larger RE plants. The ACP payments are typically of the order of $1 to $4 million, but, in some years when there was a shortage of Class 1 RECs, they were very high: in 2013, the total ACPs were $17.5 million; in 2011, they exceeded $19 million. Over the past few years, those very high ACPs have abated as the shortage of Class I RECs has subsided.

I took a look at the most recent report of ACP payments and used the data, plus some calculations, to generate the table below. Based on 2015 retail sales of electricity and the prevailing ACP rates at that time, I calculated that if no RECs were available in any of the classes, the total ACP payable would have been ~$47 million. However, the actual ACP amount paid was only $4.2 million—9% of the maximum payable— which indicates that the electricity suppliers were able to source the difference (91% of their REC needs) from RE generators.

The data also show that, for Class I Thermal and Class IV, more than half of the RE obligation was met by paying the ACP. For the other classes, most RE obligations were met by purchasing RECs, indicating their ready availability, for the most part, in these classes. It is this shortage of Class I Thermal and Class IV RECs that has shifted the focus of the NH PUC Renewable Energy Fund to promoting and supporting thermal and small hydropower projects.

Information on the ACPs is readily available, but, interestingly, that for RECs and what the electricity suppliers pay for them is not. This information is considered confidential and only manifests in the rates that the suppliers charge. For a data geek like me, this is a little disappointing, as I think more transparency would be useful here: we could learn about the origins of the RECs being purchased and see how much is used to support in-state and out-of-state projects. This information would also allow us to determine exactly how much the RPS program costs NH ratepayers. As I noted previously, the extra money paid for RE in the form of RECs or ACPs is funded by rate payers via local electricity rates, but this begs the question: How much does the RPS plan cost NH rate payers? A key piece of information—the costs of the purchased RECs in the different classes—is missing.  

Although this information is not directly available, I made some assumptions, using  historical REC prices, and calculated that, in 2015, the costs of the ACP payments and REC were of the order of $40 million. This is 2.2% of the $1.8 billion that was paid for electricity by NH ratepayers (based on $160/MWh ($0.16/kWh) retail rate and 11 million MWh of electricity). This is in line with data calculated by the Berkeley Lab, which determined that RPS costs for NH were 2.7% in 2012 and rose to 3.2% in 2014.

My calculations were, however, carried out using the 2015 RE requirement of 8.9%.  As we climb up to the 2025 level of 24.8% RE, we can anticipate that costs will increase. Based on moderate electricity use and rate increases, I have calculated that, in 2025, the costs of RPS compliance will be a maximum of 8% of electricity rates, assuming only ACP payments, but are more likely to range from 3% to 5%, depending on the availability and pricing of RECs over the next eight years. 

This post has taken a look at money flows in the RPS program and seen how ratepayers ultimately subsidize RE projects through their electricity suppliers purchasing RECs and paying the ACPs. The program presently adds about 3% to NH electricity rates, but it can be viewed as an important stimulus for innovation of RE sources as we, over time, deplete our resources of fossil fuels.

In the meantime, do your bit to reduce our needs for both renewable and fossil fuel-generated electricity by remembering to turn off the lights when you leave the room.

Mike Mooiman

Franklin Pierce University

mooimanm@franklinpierce.edu

Click on this link to receive email notifications for Energy in New Hampshire updates

New Hampshire's Renewable Portfolio Standard – Part 2

In my introductory post on the Renewable Portfolio Standard (RPS) in NH, I provided some basic information on RPS programs, how they work, and what renewable energy credits (RECs) are. In this post, I take a deeper look into the buying and selling of RECs and their pricing.

In Part 1, I noted that there were four classes of RECs in NH (see the figure below). Classes I and II are for the newer RE technologies and those operations that have come on-line since 2006. Class II is dedicated to solar power alone. Classes III and IV are for older biomass and smaller hydro operations that were established before the end of 2005. NH is unique in that it is the first state to have developed a sub-class and specifications for thermal RECs. These RECs are distinctive because they don’t involve the generation of electricity, but instead involve electricity savings via renewable energy sources such as the installation of a solar hot water heater, geothermal system or a wood fired boiler.

Carve outs such as those for solar and thermal are useful as they create specific requirements for a particular type of renewable energy and prevents a flood of RECs from another source, such as a large wind or biomass project or even out of state generation, from driving down REC prices in these special classes

In 2017, the total NH requirement for renewable energy is 17.60% of total electricity generation. The amount for each class, along with their Alternative Compliance Payment (ACP), is shown in the table below. As I noted in my previous post, the ACP sets an upper limit – a price cap – on what the utilities are required to pay for each REC. If prices of RECs are above the ACP, the utilities are obligated to pay the ACP instead. When there is a shortage of REC in a specific class, their prices quickly rise up to the ACP value set for that class; when a surplus occurs, REC prices can drop way below the ACP.

The allocation between the different classes is interesting. The NH program, similar to those in many other states, has a heavy weighting to newer renewable energy generation operations in Class I, but there is also (naturally, for a tree-covered state) a hefty weighing to Class III to support and subsidize the pre-2016 biomass electric generators in NH. The support for solar via Class II, is, compared to some other states, like Massachusetts, minimal.

When the RPS plan was first implemented in 2008, a steady ramp-up in the amount of renewable energy was anticipated, from 4% in 2008 to 24.8% in 2025. Instead, there have been some important modifications to the requirements of the various classes. From 2012 to 2016, the amount of renewable energy from Class III was significantly curtailed to cope with the shortage of Class III RECs. The reasoning was that a shortage of available Class III RECs would drive the utilities to pay the ACP instead and, with the large requirement for Class III and the high ACP payments, the costs to ratepayers would be too high.

The figure below shows how the amounts for the different classes have changed over time. Generally, the heavy weightings of Class I and Class III are clear and the big dip created by the reduction in the Class III obligation from 2012 to 2016 is obvious. In 2017, the Class III requirement zooms up from 0.5 to 8% again and the total renewable energy obligations are back on track to meet the 2025 goal.

Different states have different RPS goals, classes, and requirements for different types of renewable energy. For example, Maine promotes biomass and has a high biomass requirement and Vermont includes large-scale hydro. Each state has different ACP caps for their different classes. Complications arise as RECs generated in one state can qualify to meet another state’s REC requirements. Moreover, RECs qualifying in one state for a specific class can qualify as another class in another state.   This creates a New England market for RECs but also a complicated mess due to the inconsistency in intra-state, inter-class transactions that can occur.  According to ISO-NE the “regional REC market is not a true regional market due to the lack of uniformity and consistent price caps”.

The result is that high ACPs, and thus high REC prices, in one state can draw in RECs from a neighboring state, thereby raising prices in the REC export state. For example, RECs from the older NH biomass operations, i.e., NH Class III, qualify as Class I in Connecticut (CT), so if REC prices in CT are high, NH Class III generators will sell their REC into the CT market instead of NH. For a number of years, CT had an enormous Class I REC requirement, which drove regional REC prices high – close to $55 (the CT ACP level). As a result, CT became a REC black hole, sucking in RECs from other New England states, including NH Class III generated RECs. This drove up regional Class I REC prices, as well as those for the NH Class III RECs. This situation created the shortage of NH Class III RECs referred to earlier and prompted the NH Public Utilities Commission to change the Class III requirements over the 2012–2016 period. 

As shown in the chart below, Class I REC prices were, for a number of years, right around $55, which is the CT and NH ACP value. Massachusetts and Rhode Island prices were higher for a while, reflecting their higher ACPs. Biomass from Maine did not qualify in other states and the large volume of available biomass kept Maine Class I prices low. This chart only shows information until the end of 2015.

Source: Berkeley Lab

In the last year, we have seen big changes in REC market pricing. The CT REC market has recently moderated, due to changes in CT Class I specifications as well as a lot of renewable energy supply coming online. As a result, CT has received a flood of Class I RECs, and NE Class I prices have dropped to about $16, as can be seen in the chart below.

Source: Karbone

It should be noted that REC banking is permitted, which allows electricity suppliers to take advantage of low prices to purchase RECs for use in subsequent years. REC banking rules differ from state to state: for NH, 70% of RECs used to meet a specific RE obligation must be from current year of production, but unused RECs can be used for a further two years.

This post has provided some information about the changing REC obligations in New Hampshire especially those in Class III, and current REC pricing. This will provide a good starting point for future posts, in which I will be taking a closer look at money flows in the RPS program, as well as the implications associated with that big ramp up in Class III requirements that NH is facing in 2017. 

Until my next post, do your bit to reduce our needs for electricity and RECs by remembering to turn off the lights when you leave the room. 

Mike Mooiman

Franklin Pierce University

mooimanm@franklinpierce.edu

Click on this link to receive email notifications for Energy in New Hampshire updates

New Hampshire’s Renewable Portfolio Standard – Part 1

Just like the regular attempts to repeal New Hampshire’s participation in the Regional Greenhouse Gas Initiative, there are perennial attacks on the NH Renewable Portfolio Standard. It is important to know about these programs so that the associated debates can be fact-based. In my next couple of posts, I have assembled information on the Renewable Portfolio Standard and how it impacts NH. This post presents some general information; in follow up posts, I will dig into the details, money flows, and costs of these programs.

A Renewable Portfolio Standard (RPS) is a mandate by a government, local or state, that requires electrical utilities to source a certain amount of their electricity supply from renewable energy sources. The intent of an RPS is to promote and subsidize the use of renewable energy sources such as those produced by natural processes such as solar, wind, hydro, ocean, biomass, or geothermal sources. The use of renewable energy decreases the burning of fossil fuels, which, in turn, reduces emissions of greenhouse gases and other associated pollutants. In the process, it improves public health, uses local natural resources, and creates local business opportunities and jobs.

Most states already have an RPS in place: by April 2017, 29 states had a mandated RPS program, eight had renewable energy goals, and only 13 did not have any renewable energy requirements. The map below shows the RPS status across the US. The site from which I copied this information, the National Conference of State Legislatures, has a very useful interactive map that provides specific information for each state. Each state has different regulations and requirements for their RPS programs. The most ambitious is Hawaii, which mandates that 100% of their energy needs will be generated by renewable sources by 2045.

 Source:NCSL

New Hampshire’s RPS was implemented in 2007. Its main components are as follows:

• By 2025, 24.8% of electricity sold in NH must come from renewable energy sources;
• Four classes of renewable energy sources are considered;
• Sourcing of renewable energy by electricity suppliers is demonstrated by the purchase of Renewable Energy Credits (RECs) in each of the classes;
• An alternative compliance payment has been established for each class to provide a cost cap on  REC prices;
• The total amount of renewable energy increases each year: from 4% in 2008 to 24.8% in 2025 (although adjustments in the total amount and amounts in each class can be —and have been— made to accommodate market conditions).

The four NH classes of renewable energy are shown in the figure below. Classes I and II refer to newer renewable energy technologies and operations that have been commissioned since 2006. Class II is a special carve out for solar power. Classes III and IV are for the older biomass and smaller hydro operations that were established before the end of 2005.

The implementation of an RPS occurs through the generation, sale, and purchase of renewable energy credits, RECs.  A REC is a digital certification that the particular generator has produced 1 megawatt hour (MWh) of electricity from a renewable energy source, such as those listed above. Each megawatt of renewable electricity gets assigned a unique certificate number and a date of production and it then becomes a tradable instrument - a REC that can be bought and sold like a stock or bond. They give renewable generators two products to sell: the actual electricity that they produce and the RECs. The RECs therefore provide an extra revenue stream – in effect, a subsidy – for renewable energy generation.

RECs are issued and tracked by the New England Power Pool Generation Information System (NEPOOL GIS) and there is a regional market for these certificates. The sellers are generators of renewable energy and the buyers are usually electricity suppliers, like Eversource, that are looking to comply with the RPS program. Like any other market, there are supply and demand aspects and, should there be a shortage due to insufficient renewable generation, REC prices go up, signaling to the market that more RE sources are required. It is important to note that the price of RECs has little correlation with the price of electricity: REC prices are set by supply and demand in the markets where they are traded. The supply is set by the amount of renewable energy that is generated and the demand by the amount of renewable energy the utilities are required to source, which, in turn, is dictated by different RPS regulations in each state.

To comply with the RPS, the NH electricity suppliers, utilities (such as Eversource), and competitive suppliers (such as Constellation) are required to purchase a sufficient number of RECs to match their renewable energy obligations in each class for any particular year. This demonstrates that the required portion of their supplied electricity is generated by renewable energy sources. NH is a deregulated state, so utilities are not allowed to own power plants, even renewable ones: they must therefore meet their renewable energy requirement by purchasing RECs that are generated by non-affiliated renewable energy generators.

REC prices can fluctuate with changing demand and supply; in the case of short supply and/or high demand, prices can escalate so a price-cap mechanism has been built into the program. This is known as the Alternative Compliance Payment (ACP). It sets an upper limit on what the utilities are required to pay for each REC. If prices of RECs are above the ACP, the utilities are obligated to pay the ACP instead. A table of recent ACP prices published by the NH Public Utilities Commission is provided below, showing a separate ACP for each class of renewable energy. Adjustments in the ACP are made from year to year, depending on the rate of inflation and legislative modifications to the RPS program.

Before wrapping up this introductory post, I thought it would be useful to get a sense of what is involved in producing 1 MWh of electricity from a renewable energy source, which is the requirement to produce a single REC. One megawatt hour (MWh) is equivalent to 1000 kilowatt hours (kWh), which represents approximately six weeks of electricity use in an average NH home (assuming a monthly use of 600 kWh). This is also the approximate amount of electricity that a three-panel solar array, rated at 0.75 kW, would produce in one year. Most residential solar systems are larger, ranging from 2 to 5 kW, and produce ~2 to 7 MWh/year, or 2 to 7 RECs per year. At the other end of the scale, the Lempster wind operation,  which has 24 wind turbines each rated at 2 MW, would generate ~105,000 RECs per year (assuming a 25% capacity factor).

Having covered some introductory information about the RPS program, such as the different classes, RECs, and the ACP, I will turn my attention in my next posts to the renewable energy quotas for each class, REC pricing, and the money flow in the RPS program. Until then, reduce your need for both fossil and renewable energy by turning off the lights when you leave the room.

Mike Mooiman

Franklin Pierce University

mooimanm@franklinpierce.edu

Click on this link to receive email notifications for Energy in New Hampshire updates

Between a Rock and a Hard Place* – Wood-Fired Electricity in New Hampshire – Part 3

In my post, It Don't Come Easy, we took a look at the revenue side of the wood-fired electricity business in New Hampshire and we determined that later this year the biomass plants could be earning about $100/MWh for the electricity they produce. Half of this amount will come from selling electricity into the wholesale markets in New England and the other half will come from the sale of renewable energy credits, RECs. Their revenue stream is very much dependent on the high prices which presently exist in the REC market, but I expressed some concerns that the flood of RECs coming from the Berlin plant could have a downward impact on REC pricing. As a reader of this blog, Bob Baker, pointed out to me just this past week, there is another dark cloud looming on the horizon. Within New England, the REC market is an interstate one, and in Connecticut the local utilities purchase a lot of out-of-state RECs in order to meet their renewable energy quotas and avoid the fines levied through the alternative compliance payments. It has been reported that in 2010 that 76% (!) of the Class 1 series of Connecticut RECs have come from wood-fired plants in New Hampshire and Maine. 
 

One of the fundamental principles of economics is that of unintended consequences. This economic principle states that the actions of individuals, organizations and governments often have unintended and unexpected consequences. The REC program in Connecticut is a very good example of the unintended consequences of a well-meant program to support renewable energy in Connecticut that has ended up providing support for older, out-of-state renewable energy operations. Utility regulators in Connecticut are naturally grumpy that they are not helping newer Connecticut renewable energy companies, the price of renewable electricity is high (due to high REC prices) and they are supporting wood-fired plants in New Hampshire and Maine that were already in place before the establishment of the REC program. As a result, they are now looking to modify their renewable energy incentive programs in ways that would, in essence, exclude the older out-of-state wood plants. This would leave the NH wood-fired power plants looking at substantially smaller and less attractive markets for their RECs and as a result REC prices could plummet. 

 

We have spent quite a bit of time looking at the revenue side of the wood-fired electricity business and it is time we got down to looking at the cost side. An enterprise in the commodity business is termed a price taking business. Price takers, selling an undifferentiated product, such as electricity, accept the prevailing price the market offers. They are not a company like Apple which sells a unique product and who can, for the most part, set the price for that product. Price taking businesses can be very successful, but they require a laser-like focus on costs and, in the case of wood-fired power plants, the costs for producing electricity are considerable. Let's take a closer look. 

 

Woodchips are presently selling for about $30/ton and, based on Energy Information Agency (EIA) data for biomass plants in NH, it appears to take about 1.7 tons of woodchips to generate one megawatt hour of electricity. This is a lot of wood and is a result of the low energy content of green woodchips, which contain as much as 50% moisture, as well as the low conversion efficiencies of these operations, which I noted in a previous post was only about 23%. 

Using 1.7 tons of woodchips at $30/ton, means that the fuel cost alone is $51 per megawatt hour of produced electricity. The other costs these plants face include labor, operating and maintenance costs other than fuel, depreciation and financing costs. My very rough estimate of their cost structure per MWh of produced electricity is shown in the table below.

 

I might be high on the depreciation and finance costs but my estimate is that their costs are of the order of $80 to $90 per MWh. If they are earning $100/MWh from a combination of electricity and REC sales, this means that these operations are earning a profit of $10 to $20/MWh at this time. It is important to note that my estimates are based on my research, engineering judgment and business experience and are, at best, rough approximations. The actual financial information for these wood-fired operations is confidential and correctly so. However, if better information is publically available I would be interested in learning about it.

 

This cost structure does indicate that these plants are not viable based on just selling electricity at $50/MWh. They unquestionably need the RECs to remain in business, and moreover, they need attractive REC pricing. Anything below $30 to $40/MWh for REC pricing could lead to unprofitability and could be hugely damaging.

 

However, the high dependence of their costs on woodchips is cause for concern. Even a relatively limited increase of $6/ton in woodchip prices at 1.7 tons/MWh leads to a cost increase of $10/MWh which gets close to putting these plants underwater, profit-wise. Therefore, wood plant operators worry a lot about woodchip prices and their escalation. Here they have two major concerns. The first is that woodchip prices are highly dependent on diesel fuel costs. As noted in Songs from the Wood, wood harvesting, chipping and transportation involves a lot of high powered machinery and is therefore fossil-fuel intensive and woodchip prices, in large part, reflect prevailing diesel fuel prices. This is demonstrated in the chart below which shows there is a strong long-term correlation between diesel costs and woodchip prices. As the diesel price, plotted in blue, increases, the woodchip price, plotted in red, follows and rises accordingly. In the long term diesel prices are bound to increase and so we can expect to see woodchip prices increase as well.

 

The other woodchip price concern the existing wood-fired plants face is the startup of the large Berlin biomass plant later this year. As noted in Knock on Wood, this plant is a behemoth and it will increase woodchip consumption in the State by almost 50%. This increase in demand is bound to put upward pressure on woodchip prices. The price increase will be somewhat moderated by trucking in woodchips from out-of-state sources but I suspect that the pending Berlin plant start-up is cause for concern at the smaller wood-fired operations. The wood-fired power plants are faced with a challenging future and they are likely to find themselves squeezed between falling revenues and rising fuel costs.

So what could they do? Here are some options for consideration:

1. Lobby aggressively for the expansion of renewable energy programs that favor wood-fired energy and that would support high REC prices or even seek some other form of outright subsidy. Without significant subsidies, through RECs or other means, wood-fired power plants are likely to reach the point of unprofitability.
2. Figure out a way to use that 67% of waste heat and consider the implementation of district heating programs in the vicinities of the plants. The challenge is that these plants are in rural communities and getting the waste heat to local communities in the form of hot water will require long and very expensive pipe runs. Perhaps projects like low income housing, trailer parks, nursing homes, industrial parks, or heat intensive industries could be considered for development nearby these power plants so that the waste heat could be harvested and used.
3. Consider the investment in new technology to improve conversion efficiencies but it must be understood that these investments would be in the tens to hundreds of millions of dollars with long, long payback periods. These investments could include installation of unit operations to pre-dry woodchips using the waste heat or even entirely new technologies that involve the gasification of wood to produce a combustible gas that could then be fired in combined cycle gas turbine units. However, according to the EIA, these newer wood-fired technologies would cost of the order of 4 to 8 times that of an equivalent natural gas-fired electricity operation. Energy companies would be hard pressed to make this investment in renewable energy unless they were assured of a higher price for electricity through a favorable power purchase agreement or subsidy.  

Many of these ideas are a stretch but, in the meantime, I am sure legislative developments in Connecticut as well as the low costs of electricity, created by low natural gas prices, are keeping the owners and managers of these wood-fired power plants awake at night. Perhaps expanding renewable energy subsidies to support home grown and produced NH energy is not necessarily a bad idea, however, we do need to think through the unintended consequences of these subsidies beforehand, rather than after the fact like the folks in Connecticut. I am concerned that without substantial subsidies, through RECs or other means, our smaller wood-fired power plants will find themselves being squeezed between lower revenues and higher costs – the proverbial rock and hard place* with nowhere to turn.

Many folks believe that subsidies are the wrong way to go and that renewable energy plants need to compete in an open competitive energy market alongside fossil fuel operations. I do not agree with that approach and I believe we need to support renewable energy through subsidies even if it means paying more for the fossil fuel based energy we presently use. There are even some that say renewable energy subsidies are OK but that wood-fired electricity should not be subsidized because it is a "dirty" form of renewable energy owing to the fossil fuel used in harvesting, transporting and chipping the wood. Again, I don't agree because the reality is that every type of renewable energy is "dirty" in one form or another. When it comes to energy, there is no free lunch. There is an environmental and social impact associated with every form of energy utilization, renewable or not. What we need to do as a society is decide which of those impacts we are willing to live with and to make decisions about subsidies that will provide good options for future generations instead of leaving them with depleted oil wells, piles of poorly stored nuclear waste and exhausted coal mines. We need to think long term and not just about our children. We need to think about our children's great grandchildren. Making good decisions today that will give future generations viable energy options is an enormous responsibility and not one we can push off anymore.

 

Until next week, remember to turn off the lights when you leave the room.

 

Mike Mooiman
Franklin Pierce University
mooimanm@franklinpierce.edu
4/29/13

  

(*Rock and a Hard Place is a great rock and roll tune by the Rolling Stones from their Steel Wheels album which came out in 1989 after the rift between Mick Jagger and Keith Richards was repaired. To my mind this was the last decent album the Stones put out, but it pales in comparison to Sticky Fingers, my personal favorite. However debating the best Stones album would be worthy of a blog by itself.)

 

Click on this link to receive email notifications for Energy in New Hampshire updates