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Slouching toward a microgrid tariff in California

image credit: Clean Coalition

What will it take to fulfill SB 1339’s promise of commercializing microgrids across the state?

California has always been a clean energy leader. The state should be continuing this venerable tradition with its microgrid legislation, SB 1339, which has the commendable goal of facilitating the commercialization of microgrids in California.

Given the urgent need for energy resilience in California’s new normal of increasingly severe wildfire seasons and continuing planned utility outages, the California Public Utilities Commission (CPUC) proceeding tasked with implementing SB 1339 should be paving the way for microgrid proliferation in the state. Renewables-driven Community Microgrids, in particular, bring our communities an unparalleled trifecta of economic, environmental, and resilience benefits. With lowered air quality from ever-longer wildfire seasons coupled with economic woes related to the pandemic, all of these benefits are crucial for California.

Since 2019, the Clean Coalition, a California nonprofit, has been active in the SB 1339 proceeding, arguing in our filings for these elements and more:

  • Creating standard tariffs for microgrids in California that:
    • Provide value streams for the secondary markets that microgrids can participate in and the ancillary services microgrids provide when not in island mode. Alternatively, all the value streams can be aggregated into a single straightforward Dispatchable Energy Capacity Services (DECS) contract with a load-serving entity (LSE).
    • Cover both behind-the-meter (BTM) and front-of-meter (FOM) solar+storage microgrids.
  • Adopting a market-responsive Feed-In Tariff (FIT), like the one the Clean Coalition designed for the City of San Diego, to facilitate the procurement of renewable resources for microgrids, with a Dispatchability Adder to incentivize energy storage.
  • Streamlining interconnection for microgrids.

Thus far, though, SB 1339 has not lived up to its promise due to the conservative approach being taken by the CPUC.

Little progress so far

Track 1 of the three tracks in the proceeding focused on the urgent short-term need for California’s investor-owned utilities (IOUs) to develop microgrids before the start of the 2020 wildfire season.

By the time an early, and already severe, wildfire season hit the state in August 2020, little progress had been made; Pacific Gas & Electric (PG&E) contracted for 350 megawatts (MW) of diesel generation in resilience zones, while the other two major California utilities, San Diego Gas & Electric (SDG&E) and Southern California Edison (SCE), claimed to already have microgrid projects in the works. Interestingly, SCE cited the Montecito Community Microgrid Initiative (MCMI) in its service territory as evidence of progress, despite the utility’s lack of cooperation on this initiative; the MCMI is being led by the Clean Coalition in collaboration with numerous Montecito critical community facilities and other key stakeholders.

In the end, Track 1 resulted in a compromise: The CPUC ruled that any diesel generator solutions must be temporary and are to be replaced by adequate renewables-driven solutions in 2021. More recently, lack of progress at the CPUC seemed to indicate that even this plan may be derailed.

Track 2, currently in progress, provides an opportunity for the microgrid proceeding to get into the serious nuts and bolts of implementing SB 1339, focusing on medium-term solutions including developing rates and tariffs. However, the CPUC has continued its conservative approach in this track.

The July 2020 Staff Proposal for Track 2 (see p. 14 of the PDF), while it made some important progress, fell short of facilitating microgrid commercialization. The proposal focused on BTM microgrids and failed to clearly define a FOM Community Microgrid — which multiple parties to the proceeding agree is a microgrid that consists of multiple end-use customers and energy resources at multiple points of interconnection to the utility distribution system, and that uses existing utility distribution feeders when operating in island mode.

The proposal’s primary focus on exemptions for departing load and other charges, as well as on BTM microgrids at critical facilities owned by municipal corporations, is extremely limiting. And while the proposal defines a tariff for specific microgrids when used for emergency backup power, it omits a more general tariff. (See more in this filing and this filing from the Clean Coalition.)

In addition to the Track 2 proposal, the CPUC staff released a Concept Paper (p. 59 of the PDF) that delves into many of the details omitted in the proposal and even cites the Clean Coalition’s VOR123 methodology (p. 94 of the PDF). However, the Concept Paper is intended only for staff use in preparation for Track 3, and comments on it will not be part of the Track 2 proceeding record.

Why we need a microgrid tariff

Why is a general tariff so important for microgrid proliferation?

Microgrids are made up of multiple technologies, may have complex ownership structures, and come with various costs that may be borne by different parties. Standardized tariffs that can be applied to any microgrid project could account for all of these complexities.

In addition, microgrids provide numerous benefits that need to be part of microgrid valuation — including the most obvious one: resilience. But resilience accounts only for a microgrid’s value during grid outages. Microgrids can also provide numerous benefits during normal (blue-sky) operations, such as grid services like demand-side management, voltage support, and deferral of grid infrastructure upgrades.

Microgrid tariffs are crucial to compensate microgrids for use during blue-sky operations, access to wholesale and secondary markets, and options for sharing electricity with other parties. The lack of such tariffs makes it difficult to commercialize microgrids.

A case in point is the Clean Coalition’s Valencia Gardens Energy Storage (VGES) Project, a partnership with PG&E and the California Energy Commission (CEC). Designed to enhance the solar hosting capacity of the existing feeder by at least 25% — allowing far more solar to be sited on that feeder — this project will add FOM energy storage to a low-income and senior housing facility in San Francisco’s Mission District that already has 580 kilowatts (kW) of FOM solar.

The following diagram shows the existing solar and planned energy storage, as well as the project’s potential for a future Community Microgrid. Because the project includes FOM solar and energy storage, creating a Community Microgrid would require simply installing a grid isolation switch, as indicated by the red box in the diagram — providing the hundreds of low- income and senior residents at the Valencia Gardens Apartments with significant resilience.

Potential long-term VGES resilience design

 

However, the value proposition of this system is not just resilience — as important as that is — but also the ability to participate in wholesale energy markets and provide ancillary services. The problem, however, is that the value streams are complex, fragmented, and generally too expensive to access. VGES provides just one example of the need for microgrid tariffs that compensates for resilience without limiting microgrid functionality to resilience.

A microgrid tariff model: The Redwood Coast Airport Microgrid

Creating microgrid tariffs is not simple, but it’s being tackled already for the Redwood Coast Airport Microgrid (RCAM) in Humboldt County, an innovative partnership between the local community choice aggregator (CCA), Redwood Coast Energy Authority (RCEA); the Schatz Energy Research Center at Humboldt State University; and PG&E.

A complex project involving multiple facilities, a CCA, and PG&E customers, RCAM will be the first FOM, multi-customer microgrid in Northern California and is staging to be a leading Community Microgrid showcase anywhere. (For more, see this webinar the Clean Coalition hosted on the RCAM project.)

The project will feature a 2.2 MW solar array and a 2.2 MW/8.8 megawatt-hour (MWh) battery storage system. In blue-sky operation, the microgrid will be used to participate in the California Independent System Operator (CAISO) wholesale market. During grid outages, RCAM will go into island mode with RCEA in control of what is normally PG&E’s distribution feeder segment.

To enable this arrangement, the project team is developing agreements, processes, procedures, and protocols that outline roles and responsibilities and address the need to share costs and benefits. The Clean Coalition and other parties are advocating that lessons learned through this process be used as a model for a Community Microgrid tariff in the CPUC microgrids proceeding.

Five key questions

What goes into creating a microgrid tariff? A good guide can be found in five key questions that must be answered to provision resilience for microgrids, in particular for Community Microgrids:

  1. What distribution automation solutions are required to achieve the needed Community Microgrid functionality during grid outages? These may include line-segment sectionalizing equipment and Monitoring, Communications, and Control (MC2) solutions. Proposal 5 of the Track 2 Staff Proposal calls for the IOUs to test other low-cost reliable methods of electrical isolation, including using smart meters and reconfiguring current electrical equipment.
  2. What costs are associated with the distribution automation solutions? Upfront capital expenditures (capex) and ongoing operating costs (opex) need to be evaluated; for Community Microgrids, this includes the cost of distribution grid upgrades.
  3. Who owns the Community Microgrid and/or its key components? A major inhibitor for Community Microgrids remains the over-the-fence rule (PUC §218), which makes the most likely iteration of a Community Microgrid one in which the IOU owns the electrical infrastructure and operates the microgrid. Changing this would unlock the true potential of Community Microgrids like the Montecito Community Microgrid Initiative (MCMI). As demonstrated in the block diagram below, the three initial sites for the MCMI are all located on the same feeder segment, making them perfect for a Community Microgrid made up of FOM solar+storage microgrids. But the over-the-fence rule limits the sites to using BTM microgrids for resilience at each separate site.
  4. Who operates the Community Microgrid during grid outages? In most cases, this will be the utility. However, the microgrids proceeding has been inadequate when it comes to accounting for or defining Community Microgrids, so this question has not been clearly answered. Using the RCAM project as a model could help provide clarity on this question.
  5. How does the utility recover its costs? A Community Microgrid brings ratebase opportunities for providing resilience to critical community facilities and fee opportunities when the resilience is delivered to specific customers only. These fees could be as simple as an adder for resilience. The Clean Coalition and other parties are recommending that microgrids be exempt from fees if they provide community-wide benefits like resilience. The IOUs, however, have claimed that because there is no value of resilience, this exemption could be considered cost-shifting. That’s the same tired cost-shifting argument that’s been used for years in attempts to do away with net energy metering (NEM), which has been shown to benefit all utility customers. Moreover, the Clean Coalition has shown that resilience does provide a quantifiable value; therefore, that value should be accounted for.

What comes next?

As Track 2 of the microgrid proceeding continues, the Clean Coalition and other parties are advocating that the CPUC develop an initial microgrid tariff by the end of 2020 and a multi-customer microgrid tariff in the first half of 2021. It is unclear whether the CPUC will make this a priority.

Track 3 will focus on finding long-term solutions and finalizing the requirements of SB 1339 — something that was originally scheduled to be done by the end of 2020. A permanent working group will be created to focus on microgrids, with an emphasis on ensuring that microgrids provide resilience, as well as on streamlining interconnection for microgrids.

These are laudable goals, but to achieve them the CPUC must adopt a more forward-looking approach than it has to date. The Clean Coalition will continue working hard in this proceeding to ensure that California has a path to commercialize — and thus proliferate — all types of microgrids.

Rosana Francescato's picture

Thank Rosana for the Post!

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Discussions

Matt Chester's picture
Matt Chester on Sep 18, 2020 11:34 am GMT

Rosana-- are these type of microgrid tariffs you're pursuing a first of their kind, or are their roadmaps set out by any other regions/markets/countries that have made progress on such solutions already? 

Rosana Francescato's picture
Rosana Francescato on Sep 18, 2020 6:09 pm GMT

I'm not aware of others but will ask my policy colleague. Generally, this is pretty cutting-edge stuff.

Daniel Duggan's picture
Daniel Duggan on Sep 18, 2020 3:43 pm GMT

I feel compelled to challange this concept.  The microgrids described in the article are grid connected.  When the true fixed cost a grid connection (which in a renewables rich grid can easily exceed 80% of an annual electricity bill) is added to the real cost of electricity supplied by the microgrid, the end customers may have some of the most expensive electricity in the USA.  Examples of microgrids cited by the California Energy Commission in support of SB 1339 included 26 case studies of microgrids that rely on subsidies for less than 50 percent of project costs, the remainder required even higher subsidy.  As microgrid proposers are obviously not selling the concept based on more expensive electricity, the business case of these microgrids must contain very substantial direct and indirect subsidies to be carried by utility connected consumers and/or the tax payer.  Expensive electricity microgrids for the few are what we had before today’s lower cost, egalitarian and equitable state-wide grid power supplying the vast majority of consumers.  What have I missed, what is the logic driving a return to microgrids?

Rosana Francescato's picture
Rosana Francescato on Sep 18, 2020 6:14 pm GMT

Many early microgrids have relied on subsidies and grants. That's starting to change as costs come down and learnings are applied from early adopters.

An example: The Clean Coalition is currently working with the Santa Barbara Unified School District (SBUSD) on a huge project to install solar at many of their sites and solar+storage microgids at six sites. This is being done with a power purchase agreement (PPA) that will cost the school district nothing; they'll start saving money on Day 1, and savings will increase as utility costs go up because the PPAs are set at a fixed price for 25 years. In addition, the schools will get resilience benefits, which the Clean Coalition has determined are normally worth a 25% adder (see https://pv-magazine-usa.com/2020/09/02/think-we-cant-place-a-value-on-resilience-think-again/), for free.

More info on the SBUSD project here:

https://clean-coalition.org/community-microgrids/goleta-load-pocket/santa-barbara-unified-school-district/

Microgrids at schools and other critical community facilities provide numerous benefits to their host communities, as well as to the facilities themselves.

We still need a microgrid tariff to account for all the values provided by microgrids.

Daniel Duggan's picture
Daniel Duggan on Sep 22, 2020 8:52 am GMT

Looked at the above links where I found microgrid promoters seeking subsidies from taxpayers and below cost back-up support from grids.  Want your own microgrid?  Then go for it, cut the umbilical cords to the gas and power utility and do your own thing, but don’t ask me to subsidise you, I already subsidise the renewable energy portion of my own utility supplies.  The deal proposed by microgrid promoters is asymmetric and negative for utility customers and taxpayers as the beneficial grid services mentioned are provided at lower cost in a large grid than through a microgrid, while microgrids assumes a 100% back-up will be provided at below cost by a utility.  There will be some exceptions to this generalisation, these cases are often at industrial locations where heat can be generated by burning a waste product to produce process steam and generate electricity.  A sugar mill where cane residue is burned is a good example, another is a lumber mill which produces all required heat and power from waste wood.  In both examples an energy dense fuel is available on site, and at very low cost.  A microgrid relying on wind/solar/diesel back-up does not have this significant cost advantage and with the exception of very remote low-energy consumption locations which are expensive to connect to a grid, is not cost-competitive with utility power and gas.  Another consideration is the large-scale lowest cost CO2 reduction possible in grids is generally not achievable in small-scale local projects.  If it were, large-scale RE projects would not be developed.  As for net energy metering, that is acceptable provided the utility pays the independent microgrid only the true value to the utility of the kWh provided, and when the sun is shining brightly on a breezy day, just the time a microgrid might have a surplus, that may be a negative value!

Jim Allen's picture
Jim Allen on Sep 29, 2020 11:51 am GMT

in the UK the subsidies associated with all form of renewables for large and small scale microgrids ended in 2015. There hasn't been a replacement for these or for the more recent new additions of storage, hydrogen, electrification of heat, etc.. the markets for microgrid and decentralisation of power supply and distribution is incentivised through different market measures for system balancing at a national and local level. This approach has had the effect of driving down technology costs and innovations to achieve new projects which are subsidy free but attract a revenue stack of market measures and incentives. It has to be said that these subsidy free projects require scale to enable them to successfully participate in the markets mechanisms available to them. Therefore, community scale and other microgrids are yet to develop a viable technology mix that is both interoperable and financial viable, to successfully provide a subsidy free solution. I agree with Daniel Duggan that the grid connection costs are more often than not, prohibative and as stand alone systems, they do not have the cost advantage to those at industrial scale who can offset against other energy by-products. This being said, we need to continue to push the envelope on decentralised energy solutions and systems and Rosana is certainly doing this. The ability to automate the control of renewable generation, main power supply, storage and making these interoperable with the local grid will in turn attract new market incentives in real time prosumer flexibility for enabling local system balancing and for helping to defer or remove altogether the need for investment in network upgrades is the market proposition for microgrids. In these scenarios, the physical costs of providing a grid connection are removed and additionally, there is an argument that distribution use of system costs should be reduced to reflect the balance between supply and demand both sides of the meter.  

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