If you want to buy a house or a car, few of us have the savings to pay cash for it. What do we do instead? We seek out a private financier who will put up the money to purchase the item as long as we commit to make a series of payments over a term on which the lender and we can agree. We identify that the home or vehicle will add value to our lives, and before lending the money, the lender agrees that we have the ability to afford that value.
Now, what if, instead of considering a house or a car, you wanted to buy energy for your life from a renewable source that had not yet been tapped. Just like a house or a car, you would first need to find the source and means of obtaining it, then you would need to find a way to pay for the resource. We have grown so accustomed to buying conventional sources of energy that have fully mature and developed markets, that we have become insulated from the financing piece. In a mature market, the company that sells you your monthly energy supply uses a portion of your monthly payment to obtain the new resources, and on we go. How do we make this transaction happen with new sources of energy? What tools act like the regular payments from the home/car analogy to help energy purchasing look more like loan financing?
One solution to this problem comes in the form of governmental renewable portfolio standards (RPS). In its simplest form, an RPS establishes a statutory requirement for the minimum balance of total electricity energy purchases (we will get to the "who?" of the purchase in a second) that must come from a renewable source. Although many have advocated for a federal renewable portfolio standard (see here), currently it is the states that have set RPS throughout the country. Illinois is one of the twenty-nine states and DC to have a renewable portfolio standard, while seven others have less stringent goals for renewable energy. Among these, California has the most ambitious standard requiring that 25% of electricity purchases in the year 2016 come from renewable sources and 33% by 2020.
The Illinois RPS first came into law in 2007 as part of the Illinois Power Agency Act. (For a full description of the regulatory environment surrounding the creation of the IPA and electricity procurement in Illinois, see the Illinois State University [ISU] Center for Renewable Energy page.) In creating the Act, the state legislature set two pieces in motion: 1. it established an entity to facilitate contracts between the state utilities (ComEd and Ameren) and the generators to provide more cost effective service, and 2. it required the IPA to, when facilitating those contracts, require renewable sources of generation. The initial requirement included 2.0% of all electricity in 2008, sliding up to 10.0% in 2015, and then increasing by 1.5% every year after until reaching 25% in 2025. Within the Act, the legislators also required that 75% of each years purchase come from wind.
On the surface, the reason for the RPS came from wanting to provide "environmentally sustainable electric service at the lowest possible rate over time" to the people of Illinois. The reason for the wind requirement belied one of the real goals of the law: development of a wind power industry in Illinois. Back to our house/car example, if a company looking to develop a wind farm needs money to get the farm built, a financing entity will need something against which to loan the money. The Act allowed the IPA to enter into long-term contracts with suppliers in order to provide this collateral for the loan. In general, an RPS should be neutral to source - allowing the most cost effective sources to rise to the top of the market, however the secondary goal of market development for wind meant that for 75% of each year's requirement, the most cost effective source of wind rose to the top, while the remaining 25% could come from other sources. In general, those other sources included more wind and methane gas from landfills. Also, at the time of the Act's adoption, it covered only purchases through the IPA, and not through alternative retail energy suppliers (ARES). Utility purchases constituted the largest percentage of residential and small business methods to market (large retail customers had already left the utilities years early in favor of ARES) meaning the Act covered most of the state's smaller electricity customers.
Because of the movement toward ARES in the small customer retail market, and the slant toward wind energy purchases, the legislature made two changes to the act in 2008 and 2009 respectively. First, they added the applicability of the RPS to ARES, then added a 6% requirement for solar electricity starting in 2015. It remains to be seen whether the added solar requirement will lead to more solar in the state, or just to more purchases by the IPA and ARES for out-of-state solar. The Act provides a guide to purchasing first in-state electricity generation, then adjacent states, then - only if the requirement cannot be met with these - out-of-state generation. Because the IPA and ARES also have the requirement to procure the most cost effective electricity that meets the requirement, the out-of-state market (through renewable energy certificates [REC}) has provided the most cost effective solution. REC come from the environmental aspects of existing generation, and those aspects get priced on an open marketplace like any other commodity. This means that the REC can be less than the incremental price to actually generate the electricity (1). This may not hinder the generator, as their business model may not require the REC, and they merely use it to increase revenue. It has a huge effect on the ability for RPS to achieve new development...especially within the state.
The state legislature inadvertently exacerbated this issue in 2010 by amending the Illinois Power Agency Act to allow counties and municipalities to aggregate. The IPAA required the IPA to put together procurement plans for utilities to buy electricity. Previously, the utilities had entered into contracts that bound them to purchases for some of their load through 2013. IPA met the remainder, lowering prices, but could not renegotiate the remainder. This left a window of opportunity for ARES to get into the market, but the cost of going door-to-door would be cost-ineffective. The legislature, by allowing municipalities to aggregate their customers, created a path for ARES to grab thousands of customers at a time through a single procurement at the municipal level. Some of these communities desired more than the RPS level of renewable electricity, driving up the demand for renewable energy beyond what the state could supply, and furthering the purchase of electricity through out of state REC. The price currently being paid for these REC falls below the threshold for new resource development. With no change, the market will have to wait for the REC price to increase. It will be interesting to see if municipalities - that are largely entering into short-term contracts, and with politicians who look to the short term over the long term - drive the REC market enough to spur the development of more state resources, or if they bail when REC prices get too high.
There is no question that the RPS in Illinois must now adapt to the new market for retail electricity. More customers are moving to aggregated ARES contracts (Chicago, the largest municipality has a referendum on the November ballot), meaning the IPA has a smaller pool of customers for which they can enter into long-term contracts. ARES meet their requirements with short-term REC deals, meaning fewer financing agreements can take hold. This is not to say that RPS is the only or best way to help finance new renewable energy, but thus far it is the way Illinois has chosen. The legislature will have to, again, modify the Act to make RPS not just a feel-good source of increasing renewable energy, but one that makes Illinois more resilient and a greater center for technology development in the renewable energy field.
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