California Self-Generation Incentive Program Expanded

by David Niebauer

A recent decision by the California Public Utilities Commission (“CPUC”) has reinvigorated and expanded the Self-Generation Incentive Program (“SGIP”) by greatly expanding the technologies that are eligible for the program and creating up-front rebates plus performance-based incentives for developers and manufacturers working to install these technologies.

The impetus for the new expanded program was legislative action taken in October 2009 in Senate Bill 412.  That bill authorized the CPUC, in consultation with the California Air Resources Board, to expand eligible technologies based on greenhouse gas (“GHG”) emissions, and extended the expiration of the program to January 1, 2016.  In addition, on September 10, 2011, Assembly Bill 1150 allowed SGIP money to be raised by the state’s electric utilities for an additional three years through 2014. The program collects $83 million annually from ratepayers through their electricity bills.

The SGIP was established in 2001 as a peak-load reduction program seeking to encourage the development and commercialization of new distributed generation (DG) – generation installed on the customer’s side of the utility meter.  In 2007, the solar portion of the SGIP was replaced with the California Solar Initiative, a much larger program that has met with considerable success.  Originally funded with $2.167 billion to cover a 10-year period, the program is nearly out of cash, but has been instrumental in California leading the country in solar installations. A recent report by the Solar Electric Power Association (SEPA) shows all three of California’s investor owned utilities (IOUs) in the top ten utility solar rankings for 2010 – much of it DG.

From 2007 – 2010, the SGIP was only available for small wind turbines, fuel cells and advanced energy storage.  The expanded program now includes wind turbines, fuel cells, organic rankin cycle/waste heat capture, pressure reduction turbines, advanced energy storage, and combined heat and power gas turbines, micro-turbines, and internal combustion engines – provided they achieve reductions in GHG emissions.

The following chart shows each eligible technology with the incentive in dollars per watt:

Technology Type Incentive ($/W)

Renewable and Waste Heat Capture

Wind Turbine                                                                                                  $1.25                                               Waste Heat to Power                                                                                     $1.25                                            Pressure Reduction Turbine                                                                        $1.25

Conventional Fuel-Based CHP

Internal Combustion Engine – CHP                                                           $0.50                                   Microturbine – CHP                                                                                       $0.50                                                 Gas Turbine – CHP                                                                                         $0.50

Emerging Technologies

Advanced Energy Storage                                                                              $2.00                                            Biogas                                                                                                                 $2.00                                               Fuel Cell – CHP or Electric Only                                                                  $2.25

For projects under 30kW, the entire incentive will be paid up front.  For larger projects, the incentive will be paid 50% up front and the remainder over a five year period, based on capacity factors.

Size does matter, and the incentive will be tiered as follows:

0-1 MW = 100 %                                                                                                                                                            1-2 MW = 50 %                                                                                                                                                             2-3 MW = 25 %

Pointing to the CSI as its model, the CPUC has adopted a declining incentive structure to “gradually reduce the market’s reliance on a subsidy”.  The decline will apply a 10% annual reduction for emerging technologies and 5% annual reduction for all other technologies, with the first reduction starting on January 1, 2013.

The decision puts a 40% “concentration limit” on manufacturers (i.e., no one manufacturer can claim more than 40% of the incentive slated for any given year).  This concentration limit will not apply to project developers, however.

The funds collected each year will be allocated with 75% dedicated to the renewable and emerging technology bucket and 25% dedicated to the non-renewable bucket.

The new program will require a service warranty in addition to a parts warranty.  The CPUC has requested stakeholder input on the length of the warranty for the “reasonable expected useful life of a project”.

SB 412 also directed the CPUC to provide “an additional incentive of 20 percent from existing program funds for the installation of eligible distributed generation resources from a California supplier.” This additional incentive can be found in Section 3.5 of the 2009 SGIP Handbook.

At least one California manufacturer of natural gas fired microtrubines is touting the new CPUC decision as a boon to DG installations and energy efficiency.  Developers who deploy waste heat recovery systems should also be pleased by the decision.  More efficient use of on-site energy generation and storage will not only reduce GHG emissions, but also ease transmission and distribution infrastructure bottlenecks.

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

14 Ways that Solar Power Costs will Decrease Sharply

Solar power continues to grow by over 30 percent annually. Solar panels cost 100 times less than in the 1970s. Solar is clean, often generated at or near where electricity is needed, and not at the mercy of fluctuating coal or uranium prices.

The timing for solar energy growth is excellent. Voters have lost their appetite for spending billions to try to make coal clean while carrying the burdens of health damage. Similarly, most voters do not want to pour billions into loan guarantees for expensive nuclear power in the wake of the disaster in Japan.

In this decade, installed solar will drop to half its current cost. Such cost reductions will take more than lower costs of silicon panels and thin-film. Process and policy are now key areas for cost reduction. I recently attended the 3rd Annual Solar Leadership Summit hosted by SolarTech. With progress in these areas, solar costs will drop in half:

  1. Manufacturing scale
  2. Efficiency
  3. Balance of System
  4. Installation
  5. Right Size
  6. Right Place
  7. Improve Interconnect
  8. Markets not Monopolies
  9. Policy
  10. Process
  11. Financing
  12. Concentrate
  13. Hybrid Systems
  14. Storage

Manufacturing scale

Ten solar manufacturers in China produce over one gigawatt of solar panels. High manufacturing volumes, lower labor costs, and favorable government policy have helped lower costs. Morningstar estimates that China has a 20 to 30 percent manufacturing cost advantage and that Trina is producing crystalline silicon cells for 78 cents per watt.


China may be winning the c-Si cost battle, but First Solar uses thin-film innovation to lower cost. First Solar is increasing manufacturing capacity from 1.5 to 2.3GW per year, including manufacturing in low cost countries such as Vietnam. Last year it improved its CdTe module efficiency from 11.1 to 11.6 percent to deliver 75 cents per watt cost. GE announced 12.8 percent efficiency with its CdTe panels. In 2013 it will have a new 400 MW plant online. Honda is betting on CIGS thin film. Venture capitalists are betting on exciting emerging companies as the efficiency and cost battle intensifies.

Balance of System

Dr. Alex Levran, President of the RE Division of Power-One, asked the industry to measure system efficiency in harvesting energy, rather than just evaluate inverters efficiency with specific solar modules. He identified areas for cost savings including eliminating the grounding of inverters. This is not done in Europe and it lowers inverter efficiency. Europe uses 1,500-volt systems. In the U.S., 600 volts is common. Modular inverters are need for quick repair. He feels that a 10-cent/watt goal is feasible in 2 to 3 years with the right component costs.


Experienced conference participants agreed that a major variability in annual electricity generated from a solar project is how well it is installed. Square feet can be used optimally or poorly. The slope of panels needs to be ideal. The quality of wire and installation affect longevity and output. SolarTech is working with industry groups and community colleges to insure a growing pool of skilled labor.

Right Size

The highest U.S. growth will be in the middle market of 100 kW to 20 MW at locations near load centers. Urban commercial roofs, industrial yards, and parking structures are good examples. The price per watt benefits from economy of scale, flabor costs, shared balance of system. Installed solar is cheaper by the megawatt than kilowatt. These segments appeal to electric utilities that face RPS requirements in 30 states. Commercial distributed solar is often well matched with the location of electricity demand, minimizing transmission and distribution investment. For example, transit operators including LA Metro, New Jersey Transit, and MARTA are among the dozens of agencies heavily investing in solar in the 100kW to MW category. Public Transportation Renewable Energy Report

Right Place

My wife and I recently rode our bicycles to a 5 MW solar installation in the middle of San Francisco. The panels are mounted at ground level on the cement cover of a local water reservoir. Labor and construction costs are lower on the ground than on old roofs that may need to be upgraded to support the weight and maintenance of solar. Near ground, such as erecting steel grids to cover parking structures, can also be more cost effective than roof-mounted systems.

Improve Interconnect

A public utility can make it easy, difficult, or impossible to connect to their system. Follow the money. Some solar makes them money; some costs them. Some projects provide RPS credit; some do not.

Markets not Monopolies

I once shared lunch with a public transit manager who wanted to cover a transit line with megawatts of solar power and a water wholesaler who wanted to buy the power. It was a win-win and the numbers worked, except that they were legally required to put the local public utility in the middle. The utility wanted to build a new natural gas power plant. Somehow, the solar numbers no longer worked. Laws need to be changed, so that micro grids and markets can work without utility monopoly power.


Installation of solar power is complicated by having 21,500 local codes to deal with beyond the National Electric Code. Permitting can take weeks. Inspection outcomes and reworks are variable costs due to lack of one national code. Promising is DOE’s Solar America Board of Codes and Standards (Solar ABCs).


“The solar industry is at a critical turning point, where the technology is here, yet the overhead process costs keep prices high and force customers to navigate through a complicated process,” said Doug Payne, executive director of SolarTech.  “There is no reason that it should take three months for a customer to adopt solar, when it takes half that time to remodel your kitchen and only a few days to get a new water heater.  The Solar Challenge aims to make solar adoption easier and faster for customers, while simultaneously creating the local jobs and economic growth that follow. “


Solar financing needs to be as easy as getting a mortgage loan. Instead, many solar projects fail to get financed. Lenders need more certainty in the annual output expected from projects for 20 years. Standard spreadsheets and models would help. More certainty about government policy or an established carbon market would greatly help. Major players that could aggregate many projects would add diversity, certainty and simplify rating and securitizing large portfolios. In Europe, feed-in tarrifs have greatly simplified financing.


Concentrated photovoltaics, in the lab, have demonstrated 41 percent efficiency; roughly double the c-Si being installed. Now what is needed is low cost manufacturing of CPV, 20-plus year reliability, and effectiveness over a range of light-source angles. Also, in the pipeline are gigawatts of concentrating solar-thermal utility scale plants. The big challenge for these plants is years of site approval and high-voltage lines to load centers.

Hybrid Systems

Mark Platshon, Vantage Point Venture Partners is optimistic that installed solar will reach $2 per watt. The magic dollar per watt would require PV to be reduced to 30 cents per watt. Hybrid systems could lower the total cost taking advantage of common infrastructure and interconnect with hybrid systems such as solar and natural gas, roof PV and BIPV, and solar on existing light and power poles. Victor Abate, GE’s VP of Renewable Energy Business, stated the GE has sold 60 megawatts of its thin-film solar to NextEra, an existing GE wind customer. Abate said, “We are an energy company and expect to supply full solutions.” He suggested that if ten percent of GE’s wind farms added hybrid solar, the new 400MW GE factory would be sold out for six years.


Solar power often delivers when electricity is most needed, such as hot summer days when air conditioning is blasting. Storage of off-peak solar for peak use would add to solar energy’s value. One approach is concentrating solar thermal with molten salt storage. For PV, utilities are piloting a variety of promising grid storage, some as large as 150MW using compressed air, advanced batteries, and even flywheels. In the next decade, major storage could come from electric vehicle to grid.

Cleantech Meets Heavy Steel

I had a fascinating presentation today from John Robertson, managing director of BiFab, one of the first movers in offshore wind platform fabrications.  They just rolled off doing a 31 unit, 14 month project for Vattenfall’s 150 MW Ormonde project (which still counts as large in the offshore wind business), and built the original Beatrice prototype jackets.  They also sold 15% of the company to offshore wind developer SSE, essentially a vertical integration highlighting just how fragile the supply chain actually is.

There are three types of offshore mounting systems for wind 1) monopile (think big cylinder), 2) jacket, or 3) floating (of which the only prototyped system, though not yet at full scale,  is a spar (floating upright hollow cylinder).  Essentially those are in order of depth capability, with the 50-200 foot range the province of jackets, shallower water for monopiles, and at the 150 foot+ range a floating system is needed.

And right now we’re in the offshore wind’s infancy, still building one-offs.  At scale, this has to change. The wind turbine industry is already able to product final turbine assemblies within days to weeks. The rest of the supply chain for offshore is going to have to match that if the industry is to deliver the scale in the pipeline.

BiFab for example, builds jacket type mounting systems (basically four legged lattice tower) in Scotland for the offshore wind market in the North Sea.  Which sounds like a totally boring exercise.  Until you realize the following facts:

  • The offshore wind development pipeline in the UK is measured in multi-gigawatts, equaling 1,000+ plus platforms over the next 10 years.  Forget transmission constraints.  Just getting that much steel in the water fast enough at a low enough cost is an almost ungodly constraint.
  • The platforms are smaller, lighter, and have to cost much, much less, and be installed in a fraction of the time that the oil & gas industry has traditionally done.
  • Basically the fabrication shop has to learn to cookie cutter a product, not fabricate a series of one-off. Think order of magnitude three per week from a facility.  Nobody in the marine industry has done that since the Liberty Ships in World War II.  Nobody.  This is closer to manufacturing transformers or aircraft than it is shipbuilding or offshore construction except the end result has to in 50-150 feet of salt water.

I mean, when was the last time you heard a fabricator talking about manufacturing process technology, scale up and licensing designs.  They assemble steel.  Yet in offshore wind, that isn’t going to work.  Heavy steel has to meet cleantech for heavy steel to find new markets, and cleantech to reach scale.  It will be an interesting experience.