Tag Archives: community solar gardens

Microgrids could cost 10% of undergrounding PG&E’s wires

One proposed solution to reducing wildfire risk is for PG&E to put its grid underground. There are a number of problems with undergrounding including increased maintenance costs, seismic and flooding risks, and problems with excessive heat (including exploding underground vaults). But ignoring those issues, the costs could be exorbitant-greater than anyone has really considered. An alternative is shifting rural service to microgrids. A high-level estimate shows that using microgrids instead could cost less than 10% of undergrounding the lines in regions at risk. The CPUC is considering a policy shift to promote this type of solution and has new rulemaking on promoting microgrids.

We can put this in context by estimating costs from PG&E’s data provided in its 2020 General Rate Case, and comparing that to its total revenue requirements. That will give us an estimate of the rate increase needed to fund this effort.

PG&E has about 107,000 miles of distribution voltage wires and 18,500 in transmission lines. PG&E listed 25,000 miles of distribution lines being in wildfire risk zones. The the risk is proportionate for transmission this is another 4,300 miles. PG&E has estimated that it would cost $3 million per mile to underground (and ignoring the higher maintenance and replacement costs). And undergrounding transmission can cost as much as $80 million per mile. Using estimates provided to the CAISO and picking the midpoint cost adder of four to ten times for undergrounding, we can estimate $25 million per mile for transmission is reasonable. Based on these estimates it would cost $75 billion to underground distribution and $108 billion for transmission, for a total cost of $183 billion. Using PG&E’s current cost of capital, that translates into annual revenue requirement of $9.1 billion.

PG&E’s overall annual revenue requirement are currently about $14 billion and PG&E has asked for increases that could add another $3 billion. Adding $9.1 billion would add two-thirds (~67%) to PG&E’s overall rates that include both distribution and generation. It would double distribution rates.

This begs two questions:

  1. Is this worth doing to protect properties in the affected urban-wildlands interface (UWI)?
  2. Is there a less expensive option that can achieve the same objective?

On the first question, if we look the assessed property value in the 15 counties most likely to be at risk (which includes substantial amounts of land outside the UWI), the total assessed value is $462 billion. In other words, we would be spending 16% of the value of the property being protected. The annual revenue required would increase property taxed by over 250%, going from 0.77% to 2.0%.

Which turns us to the second question. If we assume that the load share is proportionate to the share of lines at risk, PG&E serves about 18,500 GWh in those areas. The equivalent cost per unit for undergrounding would be $480 per MWh.

The average cost for a microgrid in California based on a 2018 CEC study is $3.5 million per megawatt. That translates to $60 per MWh for a typical load factor. In other words a microgrid could cost one-eighth of undergrounding. The total equivalent cost compared to the undergrounding scenario would be $13 billion. This translates to an 8% increase in PG&E rates.

To what extent should we pursue undergrounding lines versus shifting to microgrid alternatives in the WUI areas? Should we encourage energy independence for these customers if they are on microgrids? How should we share these costs–should locals pay or should they be spread over the entire customer base? Who should own these microgrids: PG&E or CCAs or a local government?

 

 

 

 

Problems with “Residential storage can undercut benefits of rooftop solar, says new study” | (A response to a Utility Dive article)

A new study in Nature Energy finds storing rooftop solar can increase emissions and energy consumption.

My thoughts: Here’s the key statement for the finding in this report: “based on today’s Texas grid mix, which is primarily made up of fossil fuels.” If the either the marginal generation on the grid is low or no GHG (e.g., renewables overgeneration which is an increasing problem in California) or the connection to the grid is cut or restricted (e.g., in a microgrid), then this premise doesn’t hold.

This study relies on fossil fueled generation being the marginal energy source. It also focuses solely on operational changes with existing resources. The appropriate frame is looking at the change in generation investment with and without storage, so for example more renewables become cost effective with storage so the overall generation mix changes.

The second problem is that most of the production cost models are yet incapable of capturing reduction in flexible capacity use. That’s why the California Energy Commission has had DNV and LBNL working on modeling those resources. So the emission savings are underestimated.

The third problem is that savings in residual unit commitment (RUC) is underestimated in the models. These are gas units running on standby with no-load, to be available the next day for ramping, load following or reliability. Storage reduces the need for these resources as well. NREL recently released a study on the value of storage that captures this benefit.

If these findings are valid, then the existing Helms pumped storage plant is also increasing GHG emissions. One could go so far as to say that the value of pondage hydropower storage may be so diminished that relicensing conditions that require run of river operations may have little effect on costs and GHG emissions.

Source: Residential storage can undercut benefits of rooftop solar, says new study | Utility Dive

Community choice spreading across California

Yolo County and the City of Davis became the latest community to approve a CCE (for community choice energy, an alternative moniker to the legalistic community choice aggregation). I sat on the advisory committee assessing options and the business case is strong for the viability of this option. This is the leading edge of a wave of CCEs across California. The combination of market conditions, falling renewable power costs, recognition of changes in the electricity market, and dissatisfaction with the incumbent utilities is pushing broad community coalitions to take the leap.

ca-cca-map-solo-10-10-16-e1476219431587To date three communities have operating CCE’s, with MCE starting first in 2010. MCE is made up of not only Marin County, but also Napa County, and the City of Richmond and Benecia. It also is considering adding new members. It currently has 17 voting communities. Sonoma Clean Power followed in 2014, and is considering adding Lake and Mendocino counties.  The City of Lancaster started in late 2015 in SCE’s service territory. Peninsula Clean Energy, composed of San Mateo County and its cities, kicked off service in 2016.  In addition, San Francisco has approved a CCE but has had various political barriers to getting off the ground.

Here’s a couple websites that show maps and lists of what counties and cities are pursuing CCAs (the lists are slightly different).

 

Other communities in the midst of either approving or implementing new CCEs include:

Alameda County

Contra Costa County – considering joining Alameda or MCE, or going it alone

Humboldt County as Redwood Coast Energy Authority – considering joining SCP or going alone

South Bay Cities of Los Angeles County as South Bay Clean Power

Los Angeles County

Monterey, Santa Cruz and San Benito Counties and their cities as Monterey Bay Community Power

Riverside and San Bernardino Counties – issued RFP for joint study

San Diego County

City of San Diego – issued RFP for a study

City of Solana Beach

Santa Clara County and 11 cities as Silicon Valley CCE Partners – starting late 2016

City of San Jose – exploring joining SVCCEP or going alone

Santa Barbara CountySan Luis Obispo County and Ventura County – released study on feasibility and options

City of Walnut Creek – considering joining with Contra Costa or going alone

 

All of this activity has serious implications for IOU purchasing and contract management going forward, CPUC regulation and overall procurement transparency. The IOUs and CPUC have operated in black box to date claiming that confidentiality is necessary to prevent market manipulation. Yet with all of these CCEs likely operating as open books, everyone will have the market information that the IOUs claim is so vital to protect. This is likely to open up IOU PPAs to greater scrutinty–attention that neither the IOUs or the CPUC probably want.

Reaction to Is “Community Choice” Electric Supply a Solution or a Problem?

Severin Borenstein at the Energy Institute @ Haas wrote a good summary of the issues around community choice aggregation.

Source: Is “Community Choice” Electric Supply a Solution or a Problem?

I am on the City of Davis’ Community Choice Energy Advisory Committee and have been looking at these issues closely for a year. I had my own reactions to this post:

First, in California the existing and proposed CCEs (there are probably a dozen in process at the moment to add to the 3 existing ones) universally offer a higher “green” % product than the incumbent IOU, most often a 50% RPS product. And although MCE and SCP started out relying on RECs of various types to start out, they all are phasing out most of those by 2017. I think most will offer a 100% product as well.

The reason that these CCE’s are able to offer lower rates than the IOUs at a lower RPS is that the IOUs prematurely contracted long for renewables in anticipation of the 2020 goal. In fact, the penalty for failing to meet the RPS in any given year is so low, that the prudent strategy by an IOU would have been to risk being short in each year and contract for the year ahead instead of locking in too many 20+ year PPAs. At least one reason why this happened is that the IOUs require confidentiality by any reviewers and no connections to any competing procurement decisions. As a result the outside reviewers couldn’t be up to speed on the rapidly falling PPA prices. The CPUC has made a huge mistake on this point (and the CEC has rightfully harassed the CPUC over this policy.)

CCE’s also offer the ability to craft a broader range of rate offerings to customers–even flat 20 year rates that can compete with solar roofs on the main issue that customers really care about: price guarantees. In addition, CCE’s are more likely to be to nimbly adjust a rapidly changing utility landscape. CCE’s are much less likely to care about falling loads because their earnings aren’t dependent on continued service.

It’s also to recognize the difference between local government general services (e.g., safety and public protection, social services, regulation, etc.) and enterprise services (e.g., utilities of all sorts). In general, the latter are as efficient as IOUs (except LADWP which illustrates the INefficiency created by overlarge organizations). So one can’t make a broad generalization about local government problems and how they might apply in this situation. The fact is that almost all of the existing and new CCEs are or will be JPAs, which are often even leaner. (Lancaster is the exception.)

Finally, Severin made this statement:

“Whatever regulatory mandates, managerial mistakes, or incompetence occurred in the past, customers switching to a CCA should not be allowed to shift their share of costs from past decisions onto other ratepayers.”

I have to disagree to a certain exent with this statement. Am I forced to pay for the past incompetencies of GM or GE or any other corporation? Yes, utilities have a higher assurance of return on their investments, but no where is it written that it is “ironclad.” Those utilities had an assurance first as the sole legal provider and then as the provider of last resort, but that’s eroding. In California, the CTC was a political deal to get the IOUs out of the way. The fact is in California that the CPUC abrogated its responsibility to oversee these decisions on behalf of ratepayers with the encouragement of the IOUs. If the IOUs want to retain their customers, then they should be forced to compete with the CCEs (and DA LSEs.) It’s time to reopen this matter.

And to add a bit more:

The logic of this statement is that ANY customer who leaves the system, including moving to another area, state or nation, should have to continue to pay these stranded costs. Why should we draw the line arbitrarily at whether they happen to still get distribution services even though the generation services have been completely severed? Particularly if someone moves from say, San Francisco to Palo Alto, that customer still relies on PG&E’s transmission system and its hydro system for ancillary services. Why not charge that Palo Alto customer a non-by-passable charge? And why shouldn’t it be reciprocal? Relying on “political practicality” is not an answer. Either ALL customers are tethered forever, or no customers are required to meet this obligation.

 

Is the Future of Electricity Generation Really Distributed?

Severin Borenstein at UC Energy Institute blogs about the push for distributed solar, perhaps at the expense of other cost-effective renewables development. My somewhat contrary comment on that is here: https://energyathaas.wordpress.com/2015/05/04/is-the-future-of-electricity-generation-really-distributed/#comment-8092

Davis to look at Community Choice Energy

After calling a halt to the deeper exploration of an electric publicly-owned utility, the city has turned to an easier mountain to climb in community choice energy aggregation (now remonikered to CCE). The original POU study briefly looked at the CCE option and moved past (and in my opinion used too generic of an approach to assess the POU path with some incorrect assumptions and didn’t consider the rapidly changing electricity market). Several direct access providers have approached the city and interested parties about helping implement a CCE. The citizen’s committee will look at whether a CCE opens up new value for the city and its citizens, and whether to go it alone or to join another CCE. Marin Clear Energy and Sonoma Clean Power both have participation rates over 90%. I will be sitting on that committee as an appointee via the Coalition for Local Power. (I also sit on the Utilities Rates Advisory Committee which has an appointee.)

Perhaps one of the most attractive features is that Davis can gain control of the energy efficiency funds available from the public good charge by preparing a plan specific to the city. Fortunately, the framework for that plan is already underway with a prompt from the Georgetown University Energy Prize.