State of the US Solar Industry: SPI 2015 Wrap Up

There is a lot going on in the solar industry right now. Here is just a taste of some of the hot topics we heard about at the Solar Power International (SPI) held in Anaheim, California last week.

Just about everyone was talking about the pending expiration of the federal investment tax credit (ITC) at the end of 2016. If it is allowed to expire, it will reduce the existing tax credit incentives for commercial solar projects from 30% down to 10%, and the residential tax incentive will be completely eliminated. There is concern that this will have significant impact on the solar industry, leading to reduced momentum in project development and job losses.  Based on previous experience from the wind industry I think we can expect some slowdown in projects, although existing renewable energy mandates from state and federal mandates will help keep things moving on larger-scale projects at least.  However, there could definitely be a pretty big reduction in residential PV projects until the market adjusts.

On the plus side, the federal Clean Power Plan, which set standards for carbon dioxide emissions reductions from power plants, is expected to have a positive impact on renewable project development, especially solar and wind. This will firm up some of the existing markets and open up new markets for implementation. One speaker stated that the CPP is expected to drive an incremental increase of 20 GW of utility scale solar, not to mention impacts in community solar projects and distributed generation resources.  While this will clearly help push solar project development, many states may not have a significant ramp up of activity until the 2019 time frame.

Here in California, SB 350 was just passed on September 11, which increases the state RPS from the current target of 33% electric generation from renewables by 2020, to 50% by 2030.  There is also a requirement for a 50% increase in energy efficiency for existing buildings.  According to a utility representative, about 20% of the current California electric supply comes from renewable energy, and the state is on track to meet the 2020 goal.  California also has a Grid Energy Storage Mandate (CPUC Energy Storage Decision D.13-10-040), which requires 1,325 MW in operation by 2024.

Grid integration will continue to be an important consideration with an increased penetration of intermittent renewables and distributed generation resources. One way the solar industry is dealing with this is though smart inverters, which can have advanced functions such as Volt/VAR control, voltage and frequency ride-through, and reactive power control. Such functions can be helpful to improve grid stability, and can allow increased capacity on feeder lines to support distributed generation resources. In order to take advantage of these benefits, utilities need to have control and communication capabilities, which is a work in progress.

Energy storage is another way to support grid flexibility, as it can be used as a generation source as well as a load.  As stated by SEPA: “photovoltaic electricity storage technologies can be deployed in two ways—1) directly with a specific solar installation to manage its particular output or maximize benefits, or 2) within the distribution or transmission vicinity of one or more solar installations to manage the localized or system level impacts.” When grid-connected, energy storage technologies can provide ancillary services for utilities such as frequency regulation, spinning reserves, Volt/VAR support, voltage regulation, as well as cost benefits to consumers through arbitrage, peak shifting, and demand reduction. Energy storage systems can also be used for backup power or to support off-grid projects.  It is important to note that energy storage technology selection will ultimately depend on the project goals; there is no one size fits all, and no single project can provide all these different types of services effectively.

Overall, the solar power industry faces the challenges of maintaining its momentum in the light of potentially significant policy shifts, while continuing to develop new pathways for converting an intermittent, small-scale energy generation technology into large-scale dispatchable power. The past decade has been an exciting time for renewable energy, but perhaps the next decade will truly define how the US will deal with bulk power delivery for the next 100 years.

SRECs: What are they and what value do they have?

Intro to RECs and SRECs

As a quick primer, REC stands for Renewable Energy Credit (or Renewable Energy Certificate).  A REC is a commodity, which is used to track the “green” attributes from 1 MWh of renewable energy generation. An SREC is a REC generated from a solar project.

RECs (of any type) can be decoupled from the actual electricity generated by a renewable energy project, and sold separately.  However, it is critical to understand that ownership of the REC is essential to making claims about renewable energy.  So, for example, if Entity A purchases electricity generated by a wind project, but the RECs are sold to another Entity A, then Entity A cannot claim to be using green energy.  However, since Entity B purchased the RECs, they can claim to be using renewable energy, even if the actual electrons they use were generated from a coal plant. It may sounds confusing, but it’s really just an accounting method to ensure that the green attributes are not counted twice.

Beyond tracking green energy production, SRECs are also a commodity which provide monetary value to a project. The actual value depends on the market conditions, and can vary tremendously over time and from one market to the next. Recent figures indicate SREC prices ranging from $25/MWh to more than $400/MWh in different areas. The SREC market and associated value is impacted by the aggressiveness of the goals and the market supply, which is in turn affected by policy requirements project eligibility (location, size limitations, install date, etc.).  The penalty costs for not meeting set-aside obligations also impacts SREC values.

At these prices, SRECS can represent a significant contribution to annual project revenue.  On the high end, SRECs can be worth two or three (or more) times more the value of the electricity generated by a project, at least during the initial period when high SREC prices apply. (The value for SRECs typically reduce over time, whereas electricity prices typically increase. Furthermore, SRECs may only apply for a portion of 20 year project life.)

The Massachusetts SREC Program

With that general background, it’s worth delving into a concrete example of why SRECs matter.

Massachusetts (historically not viewed as a prime solar resource state) has had an SREC market since the Solar Carve-Out Program for the state RPS was initiated in January 2010.  The original program targeted development of 400 MW of solar PV across the Commonwealth, and was so successful that a total of 654.4 MW of capacity from nearly 12,000 projects has been qualified, and the program stopped accepting applications in 2014.

The second phase of the Massachusetts Department of Energy Resources (DOER) Solar Renewable Energy Credit program (SREC-II) was initiated on April 25, 2014.  This program is used to meet the RPS Solar Carve-Out II, with a goal of 1,600 MW of solar PV projects by 2020 (including the solar project capacity already covered under the SREC-I program).

Solar PV Generation Units must meet the following requirements to participate in the MA RPS Solar Carve‐Out II:

  • Capacity of 6 MW DC or less per parcel of land
  • Interconnected to the electric grid in the Commonwealth of Massachusetts
  • Use some generation on‐ site (includes any new or existing load, including parasitic loads from operating the unit itself)
  • Commercial Operation Date of January 1, 2013 or later

Unlike the SREC-I program, the SREC-II Program assigns an “SREC Factor” to each project based on market sectors.  The SREC Factor is used to determine the total qualifying amount of SREC IIs generated by a project, since SREC-IIs are calculated by multiplying the SREC factor times the number of MWh generated.  A list of the market sectors, project requirements, and applicable SREC factor is shown in the table below.

SREC-II Market Sector Categories

SREC-II Market Sector Categories

The Massachusetts SREC-II Program is set up to provide a higher level of support for development of smaller projects and systems that generate power for on-site use, or are built on land with limited other development opportunity such as landfills and brownfields.  This is apparent in part from how the SREC factors are set up. In addition, the DOER is also limiting the amount of projects that will be approved in the Managed Growth category by setting an annual cap in total capacity.  None of the other market sectors have a cap.

There is a Solar Credit Clearinghouse Auction to provide price support for the MA SREC programs. The fixed auction price for SREC-IIs varies from $285 in 2015 to $180 in 2024.  Actual prices for SREC-II’s may be even higher than this, although there are no guarantees.

At these prices, the SREC program can be a huge factor in project revenues. As an example, the graph below shows potential annual revenue / value associated with a hypothetical 500 kWDC ground mount array in MA, categorized in Market Sector B.  The system is assumed to generate 625 MWh per year to offset on-site electricity consumption, as well as 563 SREC-IIs based on the SREC Factor of 0.9.  Massachusetts has a pretty high electric costs—using the average retail rate over the last year, which was about $160/MWh, the project would save nearly $100,000 in the first year from electric costs.  However, even with these high rates and the decreasing value of SRECs over time, SRECs could provide more than half of the project’s value in the first 10 years.

example project revenue for the first 10 years

Example Project Revenue for the First 10 Years

As noted, the MA SREC program has been successful in spurring meaningful growth of the Solar PV market in the state, despite its relatively modest solar resource. It wasn’t so long ago that if you weren’t planning to build your PV project in the Southwest, you might as well forget about it. Now, programs like the MA RPS and associated SRECs have totally changed the math. As with many projects, “follow the money” is always good advice. For solar projects (at least in the northeast) that usually means – follow the SRECs.

President Obama Sets New Federal Government Sustainability Goals to Reduce GHG Emissions

On March 19th, President Obama signed a new Executive Order that increases Federal requirements for reducing Greenhouse Gas Emissions (GHG) and increasing renewable energy usage.  As stated in the Order:

Through a combination of more efficient Federal operations […] we have the opportunity to reduce agency direct greenhouse gas emissions by at least 40 percent over the next decade while at the same time fostering innovation, reducing spending, and strengthening the communities in which our Federal facilities operate.

Since the Federal government is the single largest consumer of energy in the Nation, actions like this can have a significant impact on the country’s GHG emissions profile.

carbonchart_1200x600

Image from Energy.Gov

Specifically, the Executive Order sets the following key targets for Federal agencies (where life-cycle cost effective).  They extend and expand upon previous Federal government sustainability goals:

  • Ensure that at least 25% of total building energy (electric and thermal) is clean energy by 2025 (interim targets start at 10% by 2016). Clean energy includes renewable energy technologies as well as combined heat and power, fuel cell energy systems, new small modular nuclear reactors, projects with active carbon capture and storage, and other alternative energy approaches.
  • Ensure that 30% of building electric energy is renewable by 2025 (interim targets start at 10% in 2016).
  • Reduce energy intensity in Federal buildings by 2.5% per year from 2015 through 2025.
  • Reduce water usage by 2% per year through 2025 (potable water and water for industrial, landscaping, and agricultural uses).
  • Reduce per-mile GHG emissions for agency fleets by 30 percent by the end of 2025 (relative to 2014 levels), and increase the percentage of zero emission vehicles or plug-in hybrid vehicles.

In related news, the IEA recently announced that global carbon emissions were flat in 2014, following four decades of steady rises. At the same time, the global economy grew by 3 percent. This is just one more indication that economic growth and use of lower carbon energy sources can be compatible goals.

The VA Continues to Pursue Renewable Energy Projects

The US Department of Veterans Affairs (VA) continues to support solar project development at their facilities, as shown by 2.1 MW PV array on top of a landfill at the Salem VA Medical Center in Virginia, scheduled to be completed by mid-November.

[Read more…]

The First U.S. Solar Plant with Energy Storage Begins Operations

Abengoa’s Solana large scale solar CSP (concentrating solar power) plant just began commercial operations.

Read the article on SiliconBeat

Have a look at this aerial shot of it.

Abengoa Solana solar plant

Abengoa’s 280MW Solana plant in Arizona

This facility, located south of Phoenix, AZ, is the first large scale solar plant with thermal energy storage in the U.S. The Solana plant has a 280 MW gross capacity, and can provide up to 6 hours of electricity from the storage system. [Read more…]

Corporate Greenhouse Gas (GHG) Inventory

Every year we at ANTARES calculate our corporate greenhouse gas (GHG) emissions inventory, which shows the emissions associated with our business activities. In this post I’ll describe our experiences, including what type of data we use, how we track it, and how this data is in turn used to estimate our GHG emissions. But first, I’ll start by talking a bit about what a GHG inventory is and why it’s useful.

What is a GHG Inventory?

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Co-Digestion: A Good Option for Dairy Anaerobic Digesters?

As Clair discussed in a previous post, anaerobic digesters can make a lot of sense for a dairy farm, as they can be used to treat a large and smelly source of waste (manure) while providing a combination of useful products including fuel (biogas), energy (heat and/or electricity), fertilizer (liquid effluent), and fibers for animal bedding. At the same time, they can help to control odors on the farm, and the process of digestion helps to neutralize pathogens and kill weed-seeds found in the raw manure. In addition, since anaerobic digesters capture the methane (a potent greenhouse gas) that would naturally be emitted during decomposition of the manure, they help to reduce a farm’s carbon footprint. Even greater environmental benefits can be attributed to a project that uses the biogas to generate energy that offsets fossil fuel consumption.

With all these reasons that make dairy digesters appealing, one may find it strange that there aren’t actually that many installed in the U.S. (EPA listed only 157 farm-based digesters in 2010.) Some of the main challenges of implementing anaerobic digesters at dairy farms are high upfront costs, relatively long payback periods, and regulatory and permitting requirements that can be confusing, expensive and time-consuming to comply with. These are generally the same types of hurdles that many renewable energy technologies face. For farmers with a herd of cows to milk two or three times a day (even on Christmas!) who are already experiencing challenging economics and limited profit margins, the time and upfront expense are especially crucial.

ANTARES is currently looking at the potential for co-digestion projects at dairy farms in New York as part of an effort to develop a business plan for anaerobic digestion projects in the state. Co-digestion of dairy manure involves adding non-manure organic feedstocks to a dairy manure digester. A wide variety of other feedstocks can be digested, including food wastes (from municipal sources or industrial processing), some types of biomass crops or agricultural residues, fats, oils, and greases (collectively known as FOG), and other waste materials. Co-digestion is pursued by dairy operators primarily to increase the economic return of dairy-manure digestion. Cost benefits occur from increased biogas yields (associated with digesting materials with higher methane production potential) and, in some cases, collecting tipping fees for disposing of the waste materials. In addition, if a significant steady stream of other feedstock sources is available, a larger digester may be installed, which can provide economies-of-scale advantages in terms of lower per-unit installation costs.

There are a number of types of anaerobic digesters that can be used to digest dairy manure and generate biogas. While co-digestion could potentially be implemented in most types of digesters, some digesters are more accommodating to a range of feedstocks than others. In particular, complete mix digesters (also called complete stirred tank reactors) are especially appealing for co-digestion as they are can accommodate a wide range of materials and utilize regular mixing to maintain a consistent feedstock slurry. They are commercially available and have relatively moderate retention times. Although they are more expensive than the passive covered lagoon digesters, they are more flexible and have higher biogas yields, and can be installed even in cold climates.

Synergy Biogas, LLC Co-digester at Synergy Dairy in Wyoming County, New York, which was commissioned in December 2011. The digester uses dairy manure and food-grade organic waste feedstocks, and produces electricity from biogas with a 1.4 MW engine-generator. (Photo Credit: CH4 Biogas)

One of the drawbacks for co-digestion is that pre-processing of the feedstocks may be required, including material particle size reduction (for the non-manure substrates) and pre-mixing prior to digestion. Perhaps a more significant challenge is changes these feedstocks may introduce to the volume and composition of effluents and the associated regulatory hurdles. For example, certain feedstocks such as food processing waste, which is known to significantly increase biogas yield, also contain unwanted constituents such as salt or excess nutrients such as nitrogen. Depending on local regulations and the existing nutrient management plan, this can make it more difficult to dispose of the effluent in a cost-effective manner. Some incentives or net metering laws may also require a certain portion of the digester influent to come from manure. For example, New York requires a net-metered anaerobic digester to utilize at least 50% manure (among other requirements).

Despite these concerns, the array of potential benefits for anaerobic digesters makes the technology worth investigating. There are some excellent sources out there for additional information on dairy digesters and co-digestion, including EPA AgSTAR and the Cornell Dairy Environmental Systems Program. You can also contact us here at ANTARES if you have any questions or need help evaluating a system for your site.