With the implementation of AB32, many solar advocates are hoping that the California TREC program will boost solar development the way SREC markets have in the country’s fastest growing solar markets on the East Coast. After much delay, the TREC, or tradable REC or unbundled REC program, finally launched on December 10th, allowing utilities to procure Renewable Energy Certificates from renewable projects not connected to their service territory in order to meet the RPS. Unfortunately, the legislation and subsequent rules have inadvertently stacked the odds against the distributed solar industry and here is why:

One key issue that has been resolved is whether or not the California Public Utilities Commission (CPUC) will allow distributed generation (DG) projects to be eligible for the state Renewable Portfolio Standard (RPS). Fortunately, recent CPUC revisions (pdf) include DG for RPS eligibility. For the sake of clarification, in California, the technical definition for DG extends to all projects that are considered onsite generation, meaning the electricity produced by the system is used locally, rather than transmitted through the broader electricity grid (think residential, small commercial and community solar projects).

That said, there are three categories used for RPS compliance. These tiers are intended to give preference to in-state renewables over out-of-state projects, with least preference to T-REC transactions. Unfortunately, DG projects, by definition, use their energy on-site and therefore, the only way to count California-sited distributed projects is through the purchase of TRECs. This means that local, distributed renewable California electricity is an after thought in meeting the California RPS.

Here are the three tiers for the California RPS: 

  1. In-State: At least 50 percent of the renewable energy must be sited in California.
  2. Out-of-state: Up to 50 percent of the renewable energy can come from projects outside California that supply electricity to the California grid.
  3. TRECs: Up to 25 percent of the RPS can be met through the purchase of Tradable Renewable Energy Certificates, a cap that will be reduced to 10 percent by 2020.

Many advocates disagree with this classification for in-state distributed projects. Proponents for DG have argued that TRECs from in-state distributed projects should be included in the in-state tier. A few reasons supporting this position include the added benefits from reduced transmission costs inherent in DG projects and the fact that the state should favor supporting distributed renewable energy projects sited in California over utility-scale projects outside of California.

In a rare occurrence, advocates for the solar industry and the major utilities in California share this opinion. The only opponents we can think of are regulators and lawyers with a strict interpretation of the legislative mandate. It is likely that the legislature envisioned tradable RECs as those coming from systems sited outside of regional territories and/or outside the state of California, without proper consideration for the fact that local distributed renewable projects would also suffer from being in Tier 3.

This decision is even more important because of the way the state has chosen to achieve the RPS goals. Instead of having annual compliance requirements, the CPUC has set up multi-year compliance periods (see sample schedule in table below). As we have written previously, the fact that buyers don't actually need SRECs until the very end of the year creates uneven demand, resulting in volatile prices and long periods of illiquidity. This problem would be even worse under the California program.

Given these conditions, TRECs are unlikely to factor into the economics of projects. Since the RPS rules are set up to favor Tier 1 and Tier 2, buyers will probably wait until the end of their compliance periods to fill the final 25 percent or 10 percent of their requirements with TRECs (if necessary). Therefore, the trading of TRECs will be highly speculative in interim years leading up to the end of the compliance periods. Some might argue that TRECs will be cheaper, so buyers would be incentivized to enter into these contracts, but the point here is that the price of a contract that qualifies as "cheaper" won't have much impact on the economics of the project, nor the decision to build that distributed project.

CA AB32 Implementation

This places an even greater level of importance on the current push to qualify California-sited DG projects under Tier 1. The impact of the current decision will effectively curtail the ability for distributed solar projects in particular to count towards the RPS. The RPS incentive scheme will first favor utility-scale hydro, wind and solar from within the state borders, followed by counterparts outside California and then, TRECs produced by renewable facilities anywhere in the Western U.S. and a portion of Canada (WREGIS). This means TREC prices will be next to nothing and the market will be dominated by regional utility-scale hydro and wind projects able to produce at a much larger scale than local DG solar.

To put that into perspective, the fastest growing solar markets in the U.S. today (SREC states driven by RPS laws such as New Jersey, Pennsylvania and Massachusetts) are made up primarily of DG solar projects! As a result, California will need to find ways outside the RPS to encourage the growth of a blossoming distributed solar energy. This most likely means a continuation of short-term, taxpayer funded, grant/rebate based programs like the California Solar Initiative (CSI).

Compared to other states, California is backward in its approach to DG projects. Here we have an industry fighting to be on a level playing field with utility-scale renewables, where other states (16 at the most recent count) have DG or solar set-asides that recognize the value of distributed generation and favor it in their RPS incentive structure over utility-scale renewables. We have often written about the need for a solar carve-out specifically because of different cost structures and the need to support solar separately.

The reality is that wind and other distributed renewables have traditionally been more cost-effective, and therefore more competitive within DG carveouts. In addition, the small-scale inherent with solar relative to wind or hydro add transaction costs that also favor the larger producers. Even in an ideal world, where California distributed solar is in Tier 1, the fear is that it will be crowded out by large scale producers with cheaper alternatives to solar and lower transaction costs. The hope has always been that the RPS and the TREC program could be a stepping stone towards a solar-only SREC program in California with long-term, sustainable growth targets similar to those seen on the East Coast.