Sunday, August 6, 2017

Solar Power in New Hampshire – Part 2

Today we see solar power and especially photovoltaic (PV) technology everywhere: it is powering homes and businesses, roadside warning signs, large community applications, and even larger grid-scale operations. PVs generate electricity directly from sunlight using semiconductor technology that is built into the PV panels. The ever-increasing scope of PV applications ranges from small devices that generate tiny amounts of electricity used to power calculators (outputs in the milliwatt (mW) range), to one- or two-panel systems generating 100 to 300 watts (W) to charge cell phones and provide light (often installed in developing countries), to 2 to 50 kilowatt (kW) systems that power homes and businesses, all the way to grid-scale solar farms with ratings as high as 1000 megawatts (MW). Below are photographs of some solar installations that I have recently observed.


There are two kinds of PV systems: grid-connected and off-grid systems. In grid-connected systems, the excess AC (alternating current) output of a solar operation is fed into the electrical grid to supplement the power produced by other power plants. These operations usually do not include any storage so they can only generate and supply power to the grid during daylight hours. The supply from these operations is therefore highly variable: low in the mornings and afternoons, high at midday, and cloud cover significantly reduces their output. The electrical grid needs to be managed to adjust to this variable output. Most smaller residential solar systems in the US are grid-connected, and range from large utility-scale systems to smaller home-based units in which electricity produced during the day in excess of that used by the homeowner is fed back into the grid. These systems are often bidirectional: during the day, electricity is supplied to the grid; during the night, when no solar electricity is produced, power is drawn from the main electrical grid.

The other type of solar system is not connected to the main electrical grid. These are known as off-grid systems and are typically found in off-grid homes or in remote areas far away from the grid in developing countries. These usually incorporate batteries so that any excess energy can be stored for use during evening hours. During the day, the sun generates electricity that is used to power the site, while excess electricity is stored in batteries to provide power for the evenings. Off-grid systems are sometimes combined with other means of electricity generation, such as diesel generators, that can provide backup power during cloudy conditions or when the batteries are depleted. These are referred to as hybrid systems.

Some solar systems combine grid-connected and off-grid approaches. These have battery storage, but are also connected to the grid. Such operations generate some or all of the electricity needed by the homeowner or business during the day and any excess is stored in the batteries (as opposed to sending it out to the grid); however, the grid connection is there to provide any shortfalls in power production from the solar panels or when the batteries are depleted. These systems offer the best of both worlds—they produce and use renewable energy so their electricity purchases from the grid are reduced, but the grid is there as a standby to cover any shortfalls. Solar systems utilizing the much-touted Tesla Powerwall battery systems are of this type and I anticipate that we will see many more of these systems in the future.

In the energy field, one needs to be sure to understand what is meant by the rating of a power plant, whether it be a small residential solar system or a nuclear power plant. For most power plants, say the 1244 MW Seabrook nuclear power plant in NH, the power rating refers to the output of AC electricity. In this case, it is easy to calculate how much electricity a power plant would generate over a certain time period. For example, if the Seabrook plant was running at its rated output, uninterrupted for 24 hours, the yield of electricity would be:

1244 MW x 24 hours = 29,856 MWh.

Solar system ratings are different. The PV modules produce direct current (DC) electricity and the rating of solar PV operations is given as the combined DC output capacity of the panels under the standard irradiation condition of 1000 W/m2 at 25oC – conditions known as one peak sun (see an earlier post for an explanation of irradiation and the peak sun hour concept). As I showed in my previous post, the irradiation levels are only close to one peak sun at around noontime. A solar panel will therefore only produce its rated output of DC electricity for a short period around midday; at other times, the irradiation is lower and the output is commensurately lower. But DC electricity is not particularly useful for powering our existing homes and businesses: we have to convert that DC current to AC to operate our appliances, lights, and devices. During this conversion, there are losses through the electrical system and wiring. These losses are typically of the order of 5 to 10%. There are also performance losses due dust on panels, degradation of the panels over time, and  elevated temperatures.

Intuitively, one would expect hot sunny days to be ideal for solar power generation, but an aspect of PV technology not often appreciated is that the electricity output of PV panels actually decreases as the temperature increases—by approximately 0.5%/oC. When temperatures are high, panels operating in the New England area can often reach surface temperatures of 140oF (60oC), which can cause a 10 to 12% decrease in performance. This problem is even more extreme in the sunny environments of Nevada and Arizona, where the choice of solar power may seem obvious. Furthermore, when clouds roll over the skies during the day, we can also expect a big decrease in electricity production.

Between the conversion, dust, degradation, and temperature losses, clouds, and the limited number of peak sun hours during the day, the AC output of a solar installation is, in fact, a small fraction of its DC rating. For example, the PV calculator from NREL shows that a DC-rated 1 MW solar plant in NH will produce, on average, 3.6 MWh of AC electricity per day. A 1 MW AC-rated fossil-fuel plant operating for 1 day would produce 24 MWh—almost seven times more electricity, This is an important distinction that is often forgotten. Size is important in energy production, but it is important to understand what the rated size means.

Speaking of size, the largest solar plant in NH is presently the 942 kW operation that is powering the wastewater treatment plant and other municipal buildings in Peterborough. Here are some interesting specifics about this plant:
  • It cost $ 2.4 million. Half of the funds came from the Renewable Energy Fund administered by the NH Public Utilities Commission; the remainder was funded by the developer and builder of the solar array, Borrego Solar.
  • The array is built on land previously covered by a holding pond at the wastewater treatment pond.
  • The plant consists of 3088 Canadian Solar modules, each with a rating of 305 W.
  • The project went online in November 2015.
  • The benefit to Peterborough is that there was no upfront capital investment and, per the power purchase agreement, the town buys all the electricity produced by the solar array at a cost of 8c/kWh (with a 1%/year increase for next 20 years). Previously, the cost for electricity from the utility was 14c/kWh. It has been estimated that this solar installation will produce savings of $ 250,000 to $ 500,000 over the 20-year term of the agreement.
  • Borrego Solar gets to sell the associated renewable energy credits and benefits from the 30% federal tax credit.
  • Based on the NREL PVWatts calculator, the annual output for the Peterborough system should be 1165 MWh; however, as noted above, the output will vary from year to year depending on the irradiation conditions, temperatures, and amount of cloud cover. In 2016, the annual electricity production was 1280 MWh, which was a little better than calculated.
  • The performance of the plant can be monitored online through a useful solar dashboard link.
Aerial View of Peterborough Solar Plant. Source: Peterborough

The chart below shows the panel temperatures and solar radiance levels for one recent day, 7/20/17, at the Peterborough solar plant. Even though the ambient temperature only reached 90oF, the panel temperatures rose to as high as 140oF. The periodic dips in the solar power and irradiance levels are due to passing clouds.


In my next post on solar power in NH, I will look at how the state is doing with respect to solar installations. I will also highlight some recent changes that NH homeowners who are considering solar should take into account.

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

Mike Mooiman
Franklin Pierce University
mooimanm@franklinpierce.edu

Monday, June 19, 2017

Solar Power in New Hampshire - Part 1

In states such as Massachusetts, New Jersey, and California, there is a remarkable roll-out of solar energy generation operations underway, both large- and small-scale, driven by generous solar power incentives as well as improvements in technology and the falling prices of solar panels. In some respect, NH is arriving late to the game, but, as I will highlight in future posts, there are positive steps being taken. In my next series of posts, I discuss various aspects of solar energy, how NH is benefiting from its 2500 hours/year of sunshine, and how the state could further tap into this solar energy potential. 
There are several ways to harness the energy of the sun:
  • Solar thermal uses the heat of the sun to warm up water so that it can be used for showers and other hot-water applications like washing.
  • Concentrating solar power concentrates the energy of sunlight by mirrors onto a focal point. The focused sunlight heats a fluid, which is used to generate steam, which then turns a turbine to generate electricity.
  • Photovoltaic generation of electricity through the use of solar panels is the most widely used and most promising approach to tap into the sun’s energy. Its application is growing exponentially in many countries and it represents one of the most significant resources of renewable energy.
Each of these applications requires sunny days and the direct radiation of the sun, so let’s start with some simple measures of solar radiation. The state of New Hampshire has ~2500 hours of sunshine and 90 clear days per year. In comparison, Nevada has about 160 clear days annually and about 3600 hours of sunshine. For a more exact determination of the power available from the sun, we use the concept of irradiance, which is a measure of sunlight intensity on one square meter of horizontal surface at a point in time. This, of course, changes during the day: it is low in the early morning; at a maximum at noon when the sun is directly overhead; and then tapers off towards evening. It also changes depending on the location, time of year, and amount of cloud cover. The typical average peak irradiance at noontime is 1000 watts per square meter (W/m2) for the planet. This value is referred to as the peak sun value. Measurements of irradiance averaged over 30 years for two days in June appear in the figure below. The yellow June 8th data show an essentially cloudless day, whereas the grey June 18th data show a day with a considerable amount of cloud cover. The drop-off in irradiance levels with cloud cover is significant.
 Source: PVWatts
Irradiance is a measure of the intensity or power of sunlight at a point in time, but what we are really interested in is the energy that we can harvest over a period of timeIn an earlier post, I explained the difference between power and energy. Energy is the amount of power expended over a period of time (an hour or a day). The mathematical relationship between Energy and Power is given by the simple formula:
Energy = Power x Time.
In the solar field, we determine the energy that can be potentially harvested over a day by calculating the area under the irradiance curve, such as the yellow area in the figure above. This measure of energy over a day is termed insolation; it is measured in kilowatt hours per square meter (kWh/m2). Another measure of insolation is to calculate how many hours of peak sun (with a fixed irradiance of 1000 W/m2) will deliver the same energy as the sum of the varying (irradiation x time) values over the day. The hours of peak sun per day is a particularly useful measure and is extensively used in the solar energy field to determine the daily output of electricity from solar panels. Insolation data are often available in tables of peak sun hours for different times of the year and different locations around the world. For example, the figure below shows peak sun hours for Concord, NH, at different times of the year. On average, the annual peak sun value for Concord is 3.9 hours.
Source:NREL
These insolation measures are for a panel lying flat on the ground, but that is not the normal orientation for most solar projects. In the northern hemisphere, solar panels are angled towards the south, so as to capture as much sunlight as possible as the sun rises and sets in the southern skies. Typically, the mounting angle of the panels is equivalent to the latitude of the location: panels in Concord, NH are ideally oriented at an angle of 43o from the horizontal. With the correct mounting angle, the average annual insolation value increases from 3.9 to 4.6 peak sun hours, an 18% improvement over a horizontally mounted panel. This is the average improvement for a fixed-angle array, but further improvements can be achieved by adjusting the orientation of the panels during the year. In winter, panels should have a higher mounting angle to capture the sunlight from the sun sitting lower in the southern skies and, in summertime, the panels should lie flatter to catch the rays of the sun when it sits high in the sky during the day.
Some solar arrays are very sophisticated, with intricate motor drives and control systems that can follow the sun from east to west during the day and also make small daily adjustments in the tilt angle to follow the sun’s seasonal orientation. Dual-axis systems, such as these, can boost the insolation by about 28% or more over a fixed-angle array; however, these systems are expensive and maintenance issues with the drives and controllers often occur. Solar panels are pretty cheap these days, so a 28% gain in efficiency can rather be captured by simply adding more panels and avoiding the maintenance headaches. For this reason, most solar systems are simple fixed-angle systems.
Let’s return for a moment to measures of solar insolation. We have been using units of peak hours, which are particularly useful when calculating the energy that a photovoltaic (PV) panel will generate. Another useful unit is the direct measure of energy per square meter, i.e., kilowatt hours per square meter, kWh/m2. We determined above that the average for a Concord, NH, array mounted at 43o was 4.6 peak sun hours. So, at a peak sun value of 1000 W/ m2, we can calculate the average annual insolation value as:
4.6 hours/day x 1 kW/m2 x 365 day/year = 1679 kWh/year.
Of course, higher irradiation values created by improved mounting angles lead to higher annual insolation values. To gauge the amount of solar energy that can be harvested, maps of annual solar insolation have been prepared for the entire planet. The map below shows the average annual insolation, in kWh/m2, for the USA.



It is clear that New Hampshire is not subjected to large amounts of high-intensity solar irradiation. The choice areas lie in the Southwest, but there is still sufficient solar radiation here in the Northeast to make it worthwhile harvesting.
In an earlier post, I noted that annual electricity consumption for New Hampshire was ~11 million megawatt hours/year (MWh/y). Using the average insolation value of 1680 kW/m2 as determined above, we can roughly calculate how much land area would be needed to generate New Hampshire’s annual electricity demand using the following assumptions:
PV panel efficiency: 15% (a typical value for modern panels)
Electrical and storage system losses: 50%
Panel coverage of land area: 50%
Based on these assumptions, we can determine that an area of approximately 67 square miles would be needed to generate sufficient energy to meet New Hampshire’s annual electricity needs—an area approximately 8 miles by 8 miles. This hardly seems much in state with a land area of 9350 sq. miles. The thought that it would only require ~0.7% of NH’s land area to generate all of the state’s electricity needs is an intriguing one; however, it is important to put this fun-to-do order-of-magnitude calculation into perspective and consider the technical and economic feasibility of this idea.
Let’s start with the size of the plant. Very large solar plants are being built today. There are several in the 500 MW range in the US and some larger ones in India and China. As of the date of this post, the largest solar power plant in the US is the BHE Renewables Solar Star operation in Antelope Valley, California. This is a 579 MW AC output plant, capable of generating ~1, 800,000 MWh of electricity per year or about 16% of NH’s needs. It uses 1.7 million solar panels and is located on 5 sq. miles of land. Technically, large-scale solar plants are feasible, but the costs are high. The cost for a 550 MW plant in California was reported to be $ 2.4 billion. The largest solar farm in the world is presently the Kurnool Ultra Mega Solar Park in Andra Pradesh, India. This monster has over 4 million panels, a nameplate capacity of 1000 MW, a cost about $1.1 billion, and covers a land area of 9.3 sq. miles. It is reported to produce 2.6 billion kWh of electricity annually, which is 24% of NH annual needs.
Cost is an issue, but the bigger problem associated with solar power is that it is an intermittent and variable resource. Unlike a traditional nuclear, fossil fuel, or hydroelectric power plant that can vary its output day or night (within a certain range), a solar resource can only produce energy during the daylight hours and is subject to the whims of cloud cover and passing storms – during which output can drop considerably. To fully utilize solar energy, we need electricity storage in batteries to provide power for the nighttime and when it is cloudy. Unlike grid-scale electricity generation from large PV plants, grid-scale battery storage is still in its infancy. It is complicated and very expensive. To date, the largest grid-scale battery-based storage operation is near San Diego in California – a 30 MW unit with storage of 120 MWh. To store just one day’s worth of electricity for NH would require some 30,000 MWh of storage. This is 250 times the capacity of the largest existing storage plant and is simply not technically and economically feasible at this time. In many respects, generation of electricity from sunlight these days is fairly straightforward; the storage aspect is the bigger challenge that we face this century.

My back-of-the-envelope cost estimates yield a $10 billion price tag for a solar and storage operation to supply all of NH's electricity needs and one full day of storage. This is certainly cheaper than building a nuclear power station and I am confident that with the falling cost of storage and solar panels, we will, within the next decade, be building solar and storage plants of this size. Perhaps one of these will be in NH.
This is the first in a series of posts about solar power and its application in NH. I trust that I have given you a sense of the resource available and the scale that is needed to harness it, but also a sense of the technical challenges, complexities, and costs involved in developing this resource.
Until next time, remember to turn off the lights when you leave the room. 
Mike Mooiman
Franklin Pierce University
mooimanm@franklinpierce.edu

Sunday, June 11, 2017

New Hampshire's Renewable Portfolio Standard – Part 4

My last three posts have looked into various aspects of NH’s Renewable Portfolio Standard (RPS). I presented the basic workings of the program,  discussed renewable energy credits (RECs) and REC prices and, most recently, looked at money flow and costs of the RPS program.  The program originally included a steady increase in the renewable energy (RE) requirement year on year; however, to reduce costs to electricity customers, some big adjustment in the requirements have been made over time to accommodate changing market conditions and the non-availability of RECs in specific classes. This post discusses the implications of some of those changes as NH gets back on track to meet its 2025 RPS goals. 

As noted previously, there are four classes of renewable energy in the NH RPS. Class I is for newer RE technologies, such as wind or ocean energy, and RE operations that have been commissioned since 2006. Class II is a special carve out for solar power. Classes III is for the older biomass operations, which include electricity generated from burning landfill methane or wood, and Class IV is for smaller hydro operations that were established prior to the end of 2005.

NH has an important forestry industry and eight wood-burning plants that generate electricity. Right from the start of the RPS program, a large Class III requirement  was put in place to support these wood-burning plants; however, from 2012 to 2016, the amount of RE from Class III was significantly curtailed to cope with the shortage of Class III RECs and to mitigate the cost of the shortage for ratepayers. The reason for the shortage was that the Connecticut (CT) REC market had high prices and had sucked in RECs from all over New England, including NH Class III RECs that qualified as CT Class I RECs. With limited NH Class III available, electricity suppliers would have been compelled to pay the Alternative Compliance Payment (ACP) instead, increasing costs to ratepayers.

In 2016 the NH Public Utilities Commission (PUC) held hearings on the topic and  were informed  that the REC market had changed, that CT REC prices had decreased, and there was testimony from the biomass coalition that sufficient Class III RECs would be generated and be available for purchase. Electricity suppliers weren’t convinced and, after deliberation, the PUC commissioners ruled to return the Class III requirement from 0.5 to 8% to put NH back on track to meet its RE ramp-up to meet the 2025 obligation, as shown in the chart below.


For 2017, the specific RE class requirements and associated ACPs are presently as follows:


Given this big ramp from 0.5% to 8%, I though it worth taking a closer look at the Class III REC market and the availability of biomass RECs to meet this requirement.

Let’s start with some basic calculations. Approximately 11,000,000 MWh of electricity are supplied annually to ratepayers and customers in NH. It follows that an 8% Class III requirement therefore needs to provide 880,000 MWh of electricity from pre-2006 biomass operations. The REC requirement is therefore also 880,000 MWh. That is a boatload of RECs – and the question is: Can that many RECs be generated from this source?

I then found the list of registered Class III providers at the NH PUC, which is provided below.


Closer examination of this list brings to light the following:

  • There are 20 registered Class III operations, providing a total generating capacity of 137 MW. Most of the operations (13 of 20) are from out of state.
  • Only three of NH’s eight wood-burning plants (highlighted in green) are registered as Class III producers: the rest, such as the large Berlin biomass operation, appear to be registered as Class I producers.
  • Of the 137 MW of Class III capacity available, the NH wood-burning plants only provide 56 MW, or 41% of the total capacity: the rest comes from in-state and out-of-state landfill methane operations.
  • If we include the NH landfill methane operations (highlighted in grey) with the NH-based wood plants, only 68 MW, or 49% of the total capacity, is provided by NH-based plants: the rest is from out-of-state landfill gas operations in RI, NY, and VT.
I found all of this surprising because my understanding is that the original intent of including the Class III category in the NH RPS was to support NH biomass operations.  Instead, in its present form, it seems to be doing a lot to support out-of-state landfill operations.

Let’s return briefly to some calculations. If we take that 137 MW of Class III generating capacity and assume that the generating plants are operational for 90% of the time (see my I’ve Got the Power post for a discussion of capacity factor and the difference between generation capacity and energy), we can determine how much electricity should be generated over one year: 137 MW x 0.9 x 365 days x 24 hours/day. This calculation gives 1,080,108 MWh or RECs. This is a useful result because it suggests that there could be production of sufficient RECs to cover the 880,000 that we need. In fact, the calculation suggests that we might potentially have an excess of Class III RECs, which hopefully will drive their prices down and save money for NH ratepayers.

REC producers in New England are required to register and file their REC production data with the New England Power Pool Information System (NEEPOL GIS). Some of the data is available to the public. I noted that in 2015 and 2016, 1,005,258 and 924,716 NH Class III eligible RECs were produced, respectively. This is right in line with my calculation of 1,080,108 RECs. Historically, there seem to be sufficient Class III RECs to meet NH’s needs.

However, availability does not obligate producers to sell into the NH REC market. They could, especially if prices are high, elect to sell, as in previous years, into other markets, such as the CT Class I market. If insufficient Class III RECs are available, prices will quickly rise close to the Class III ACP cap of $ 45. As a biomass RE generator, that is what I would want and I might choose to direct some of my RECs to a different market to support higher NH Class III REC prices. This is a direct consequence of our inconsistent and changing REC market in New England. It provides opportunities for good traders to play off the differences between markets—and it makes perfect business sense to do so.  

However— and this is a big HOWEVER— the calculation of a surplus assumes that all operations run 90% of the time, that there are no major shut downs at any of the larger facilities, and that biomass REC producers don’t elect to sell Class III in other eligible markets. Another complicating factor is that there is legislation, known as SB129 presently making its way through the NH General Court that makes important modifications to the RPS program, especially in the Class III category. Just last week, the NH House approved a change in the RPS law that promotes NH biomass in two ways:

  • It would put a 10 MW limit on the size of landfill methane operations that qualify for Class III RECs. This change appears to be directed at eliminating some of the large out-of-state landfill operations from RI and NY that have been participating in the NH Class III market.
  • The ACP for Class III RECs would be increased to $ 55, which should increase the REC prices in the case of a Class III REC shortfall.
If we go back to the list of Class III operations above, I have highlighted two potential operations that may not qualify for the production of Class III RECs under the new 10 MW limit: the first is the large Johnston landfill in RI, highlighted in orange, and the second, highlighted in blue, is the Seneca landfill in NY (if its combined output is considered).  If both of these landfills are excluded, this would lead to a 36.3 MW reduction in Class III REC generation capacity, which represents an overall decrease of 26%. This would result the production of only 794,000 RECs, which is short of the 880,000 that NH needs in Class III. What are the consequences of this shortfall?  This means that the prices for Class III will climb to close to the value of the price cap (the ACP) and the shortfall will be made up by utilities having to pay the ACP. 

The next question is: What are the implications of these changes to NH ratepayers? Let’s turn again to some calculations and assume that those 794,000 RECs sell for 90% of the $ 55 ACP, or $ 50, and that the shortfall of 86,000 is paid in as the $ 55 ACP. In this case, we can calculate that the Class III requirement of 8% and the higher ACP could cost NH electricity customers some $ 44 million annually. If we apply this amount over the 11 billion kWh of electricity sold annually in NH, the rates can be expected to increase by 0.4 cents/kWh. For a NH residential customer using 600 kWh per month, this could result in an annual electricity cost increase of about $ 30. 

I did extend this calculation to determine a total cost for the RPS program for 2017 based on lower Class I REC prices and some significant assumptions on REC availability and prices in the other classes. My calculations led to an RPS cost of approximately $77 million which is 4.7% of the $1.7 billion I’m assuming will be paid for electricity by NH ratepayers in 2017 (based on $150/MWh ($0.15/kWh) retail rate and 11 million MWh of electricity). This is a significant increase over the 2.6% value I calculated for the 2015 RPS program in my previous post.

Now, bear in mind that these are rough back-of-the-envelope calculations; they do, however, give a sense of the potential implications for NH ratepayers of the Class III ramp up to 8% combined with the proposed RPS SB129 legislation. Perhaps I am dead wrong in my assumptions. Maybe the Class III generators will produce RECs beyond their rated capacity, perhaps not all of those highlighted out-of-state landfills will be excluded from the Class III list, and perhaps the Class III generators will choose not to sell any of their RECs into the CT Class I market. In this case, a surplus of Class III RECs will be produced, prices will be much lower, and the costs to NH ratepayer will be reduced. There is even the possibility that the PUC could jump in again to ratchet down that Class III requirement, as they have in previous years. Regardless, this is certainly food for thought as the SB129 legislation makes its way through the lawmaking machine and onto the Governor’s desk.

This is a complicated matter and it presents a huge dilemma for legislators, regulators, and the wood-burning plants in NH. On one hand, as pointed out in my post, Between a Rock and Hard Place, the NH wood-burning plants absolutely need the REC revenue and higher REC prices to survive. In fact, one such plant, the Indeck Energy plant in Alexandra, recently closed down  due to low wholesale electricity and REC prices. Alternative forms of electricity generation are also very important and wood-burning capacity helps to reduce our dependence on natural gas-fired generation. But, on the other hand, legislators and the PUC commissioners need to weigh the cost of the REC-based subsidies of the biomass industry against costs to ratepayers. There are no easy answers and these are difficult decisions to make.

Feel free to weigh in on this issue because it is a surprisingly important one. In the meantime, do your part to reduce our need for electricity from any generation source by remembering to turn off the lights when you leave the room.

Mike Mooiman
Franklin Pierce University
mooimanm@franklinpierce.edu


Monday, May 29, 2017

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

Tuesday, May 16, 2017

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