“Harmonizing” California’s TRECs with AB 32 Cap-and-Trade

by David Niebauer

Now that the California Public Utilities Commission (CPUC) has lifted its moratorium on the use of renewable energy credits (RECs or TRECs) by investor owned electric utilities (IOUs) for compliance with the State’s renewable portfolio standard (RPS), observers may ask themselves this logical question:  what is the future of RECs under Assembly Bill 32?

Assembly Bill 32, the California Global Warming Solutions Act, authorizes the California Air Resources Board (CARB) to establish a cap-and-trade mechanism designed to reduce the State’s greenhouse gas (GHG) emissions.  How will RECs and GHG allowances and offsets relate to one another?  Will one mechanism obviate the other or is there a place for both in the State’s overarching environmental initiative?

To answer these questions, we need to review some history and understand the roles of the various State agencies that are tasked with implementing the sometimes-conflicting legislative and executive mandates.

California’s Renewables Portfolio Standard (RPS) was established by the State legislature in 2002.  After various amendments, the law resulted in a requirement for the State’s IOUs to increase their sales of eligible renewable-energy resources so that 20% of their retail sales are derived from such resources by December 31, 2010.  According to the CPUC website, 2009 renewable energy procurement for the three IOUs in the state were as follows:  PG&E – 14.4%; So Cal Ed – 17.4%; SDG&E – 10.5%.

On September 15, 2009, Governor Schwarzenegger signed Executive Order S-21-09, which directed an increased renewable energy standard (RES) to 33% by 2020, made the requirement apply to all electric utilities (not just the three IOUs) and shifted the responsibility for implementing and overseeing the RES to the CARB.

However, the 33% standard was mandated by executive order, not by the legislature, which failed to pass a 33% RPS bill at the end of 2010.  Influential voices within the legislature opposed the expansion of the RES and have argued that CARB lacks the authority to proceed with RES adoption.  A 33% RPS bill is still pending in the legislature (SB 23)  which, if adopted, could pre-empt and/or modify the current CARB regulatory framework.

CARB is required by the legislature under AB 32 to regulate sources of greenhouse gasses to meet the State’s goal of reducing emissions to 1990 levels by 2020, and an 80% reduction of 1990 levels by 2050.

Renewable Energy Credits

The use of renewable energy credits to track RPS requirements has significant momentum.  The Western Renewable Energy Generation Information System (WREGIS) began operation in June 2007.  It is designed to track renewable energy generation in 14 western states and two Canadian provinces.  It is a system for authenticating WREGIS certificates for each REC, which are used to demonstrate compliance with RPS goals. One REC represents one megawatt-hour (MWh) of electricity generated from a renewable resource.

On January 13, 2011, the CPUC published its final rules on the use of TRECs, lifting a moratorium on its earlier decision.  In the final ruling, the State’s IOUs can procure TRECs to satisfy up to 25% percent of their RPS, with a $50/REC price cap. Both of these provisions expire at the end of 2013, when the CPUC “will consider modifying or removing those limitations all together.”

AB 32 to trump TRECs?

CARB’s resolution adopting the RES regulations directed the agency’s Executive Officer to monitor the ongoing CPUC proceeding on TRECs and to institute a rulemaking no later than 30 days after the CPUC issues a decision on the use of TRECs “to ensure the continued harmonization of the [RPS and RES] programs, specifically incorporating provisions related to [TRECs] for all regulated parties under the RES regulation.”

But what would this “harmonization” look like?  To answer this question we must look at the current framework of the State’s cap-and-trade mechanism.

Cap-and-Trade on the Way

On December 16, 2010, CARB adopted Resolution 10-42, approving the California cap-and-trade program.  The program takes effect January 1, 2012.  In the first phase, covered entities will include electricity generation, large industrial facilities that emit 25,000 metric tons or more carbon dioxide equivalent (MTCO2e) of greenhouse gases (GHG) per year, such as petroleum refineries, cement production facilities and food processing plants.  Phase two will begin in 2015 and will expand to cover all commercial, residential and small sources.

CARB will begin the program by issuing allowances sufficient to meet the capped amount.  Allowances will be reduced during the course of the program with the goal of eventually auctioning 100% of the allowance.

A facility can meet up to 8 percent of its annual GHG compliance obligation through offsets. An offset is a reduction or removal of GHG emissions by an activity (or facility) not covered by the Cap and Trade Program that can be measured, quantified, verified and approved by CARB.

CARB has set a minimum reserve price of $10/MTCO2e for auctioned allowances, but ultimately expects market prices for allowances to increase to $15-$30 by 2020.

What Might “Harmonization” Look Like?

First, it is important to understand the differences between a REC and a GHG allowance or offset.  RECs are designed specifically to encourage an increase in the use of renewable energy by electric utilities.  As noted above, one REC represents one megawatt-hour (MWh) of electricity generated from a renewable resource.  A GHG allowance or offset represents one MTCO2e.  Generating electricity from burning fossil fuels emits CO2e.  When coal is burnt, approximately one MTCO2e is produced for every MWh of electricity produced.  A combined cycle natural gas power plant will generate less than one-half the amount of MTCO2e for every MWh of electricity produced.

“Harmonization” will likely be governed by “ratepayer pain”.  Assuming that the State’s IOUs hit the 20% renewables mark established under the RPS, Executive Order S-21-09 will likely provide the framework to move to 33% by 2020.  RECs will be valuable in assisting energy generators to hit this mark.

When the GHG caps for the electricity generation sector are put into place, they will most likely take into account the “early adopter” status of the State’s IOUs.  In this way, we should avoid ratepayers from bearing an undue share of the burden of the environmental initiatives.  RECs will be used to satisfy the utilities’ new RES requirements while GHG allowances and offsets will be used to meet the emissions cap for the industry.  After 2020, when we have achieved our renewable energy goals, new goals can be implemented – whether they relate to renewable energy generation, GHG emissions or another achievable sustainability goal.

David Niebauer is a corporate and transaction attorney, located in San Francisco, whose practice is focused on financing transactions, M&A and cleantech.

California TREC Decision Side-steps Energy Infrastructure of the Future

By David Niebauer

Most of the discussions of tradable renewable energy credits (TRECs) in California revolve around the extent to which the State’s large utilities can use TRECs for compliance with the California renewables portfolio standard (RPS) program.  The utilities would like a free hand to use as many RECs as possible, derived from sources both in-State and out-of-State – presumably RECs will be easier and cheaper to acquire than new renewable generating facilities are to build.  The interests of the utilities are balanced by those of rate-payers as well as policy initiatives, such as AB 32.  These interests move sometimes in opposite directions, one toward less expensive retail energy and one toward more environmentally sustainable energy generation.

As the revised decision on TRECs winds its slow and tortuous way through the California Public Utilities Commission (CPUC), it is becoming clear that there will be a price cap ($50) and there will be a limit on use (30% likely) and that the cap and limit will expire at the end of 2013 “to give Energy Division sufficient time to develop [an] evaluative framework” to make sure the system works without snafu.  See procedural trail to CPUC Proceeding R06-02-012.

Lost in the shuffle, however, is what many believe will be the energy infrastructure of the future – distributed generation (DG).  The California Energy Commission (CEC) defines DG in the California Distributed Energy Resource Guide as “small-scale power generation technologies (typically in the range of 3 to 10,000 kW) located close to where electricity is used (e.g., a home or business) to provide an alternative to or an enhancement of the traditional electric power system.” The term “distributed” is borrowed from the computer industry where it has long been recognized that widely disbursed or “distributed” computing is more economic, more efficient and more secure than centralized systems.

In energy generation, “distributed” means fewer centralized generation facilities and little or no transmission.  Utilities don’t like it, naturally, because a fully implemented distributed generation infrastructure would obviate the need for a publicly subsidized electric utility monopoly – the institution feels justifiably threatened.  Whether DG will ever supply all of our energy needs is a question for the future.  In the meantime, policy makers should guard against steering the market away from its proper implementation.

Because there are a number of technologies and a variety of ways to implement DG, the California Public Utilities Commission (CPUC) and the CEC have defined DG as those technologies and implementations that generate electricity on the “customer side of the meter”.   See the CEC’s Renewables Portfolio Standard Eligibility Guidebook (3d ed., December 2007), at 17-19. These would include home installations of solar photovoltaics (PV) and would also include commercial PV such as rooftop and ground-based solar being implemented by large energy users (food processing, cold storage, manufacturing, etc.) and others.  For this purpose, DG does not include solar rooftop programs being sponsored by the large utilities that utilize commercial rooftop space in order to generate energy that is then sold into the grid.  It is energy used on-site that does not require a central transmission and distribution system.

To some extent, DG has been an afterthought in the TREC considerations and decisions.  This is because the market is currently quite small compared with utility-scale projects.  However, it seems likely that DG is the next frontier in renewable energy generation.  As PV continues to drop in price, and new technologies are developed, more and more commercial enterprises will come to realize that generating their own energy from the sun (or from fuel cells or other new technologies) is simple, safe, and less expensive than being beholden to large utility monopolies.
The CEC is concerned that TRECs for DG would provide an excessive subsidy in light of current programs in place for such projects.  The CEC’s current position is as follows:

“Facilities that receive funding under the Energy Commission’s New Solar Homes Partnership program, Emerging Renewables Program, or Pilot Performance‐Based Incentive Program, under the CPUC‐approved Self Generation Incentive Program or California Solar Initiative, or any similar ratepayer‐funded program, and facilities that benefit from net metering programs or tariffs approved by the CPUC or any POU, are considered distributed generation and may not be certified as RPS‐eligible at this time.”  RPS Eligibility Guidebook p. 25.

However, as argued persuasively by the Solar Alliance in its comments on the revised RPS Eligibility Guidebook:  “given the reality that, as the incentives under the California Solar Initiative [and other programs] decline, the sale of TRECs is likely to become a critical means for financing distributed solar generation.” To meet the state’s aggressive RPS goals, it only makes sense to allow TRECs for DG.  The CPUC anticipates this eventuality as it takes great pains in the revised proposed decision of Commissioner Peevey to “clarify the relationship of [the CPUC’s] discussion of TRECs from DG sources to the CEC’s authority…to determine what resources are RPS eligible.”

The CEC has also stated “[t]he Energy Commission will not certify distributed generation [DG] facilities as RPS-eligible unless the CPUC authorizes tradable RECs to be applied toward the RPS.”  This pronouncement, combined with the revised proposed decision on TRECs, which will permit tradable RECs to be applied toward the RPS, will presumably make customer-side DG eligible for the sale and trading of TRECs, notwithstanding the CEC’s concern over excessive rate-payer subsidies.

The numbers for DG are small at present.  As pointed out by the CPUC, the California Solar Initiative (CSI) will have provided incentives for approximately 1,100 GWh by 2011.  At $50 per TREC, this would amount to only about $50 million State-wide in additional financing for solar DG projects (1 TREC = 1,000 kW hrs of renewable generation).  However these numbers are anticipated to grow significantly.

It’s useful to look at TRECs for DG from a commercial application perspective.  A 250 kW solar PV system can be expected to generate at least 300,000 kWh per year in a relatively high solar radiation area, such as the LA basin.  Even at the $50 per TREC cap set by the CPUC, this is still $15,000 per year in new financing for a commercial system.  At $200 per TREC, it amounts to $40,000 per year.  Assuming the facility owner could forward-sell these TRECs, even discounted to present value, this is a significant amount of money that could be used to finance installation and maintenance of the system over its useful life – especially in the face of declining or vanishing solar incentives.

We agree with the Solar Alliance and others who urge the PUC and the CEC to coordinate their agency actions so as to accommodate TRECs for DG and to do it soon.  Other states are way ahead of California in allowing RECs to stimulate the renewable energy markets.  For example, New Jersey, which has a specific solar set-aside, has allowed RECs for RPS compliance for a number of years.  Solar RECs sold at auction in New Jersey were recently trading for as much as $600 per REC (see  California cannot afford to continue to ignore the energy infrastructure of the future.

David Niebauer is a corporate and transaction attorney, located in San Francisco, whose practice is focused on clean energy and environmental technologies.