Tag Archives: Distributed Energy

California’s Distributed Energy Future

GTM Research has established itself as the premier source of information on solar industry trends and developments in the United States. It’s instructive that from that perspective, they chose to organize a conference focusing on a single state, California.

We who participate in the solar industry here have recognized the state as a leader, but the less patronizing among us also recognize that the magnitude of this lead is only temporary. If solar is to realize its potential as one means of reducing environmental damage while reducing future customer utility costs, then other parts of the United States need to catch up (and as GTM’s latest data for 2015 shows, they are).

Nonetheless, as GTM Research Senior Vice President Shayle Kann observed in his opening keynote at GTM’s California Distributed Energy Future conference in San Francisco, California remains the epicenter of next generation distributed energy (DE) regulation and is at the forefront of the shift toward distributed energy in the U.S. And (I would add) what happens in California doesn’t always stay in California. Hence the conference to examine California’s transition to a distributed energy future and consider what’s working and what isn’t.

The discussions at the conference covered a variety of issues confronting the state. Here is an overview of the key themes coming out of the discussions, and the insights shared by the different speakers:

The strongest and most frequently recurring theme was that of the interaction of Distributed Energy Resources (DERs, essentially distributed solar PV) and the electrical grid. This issue has numerous dimensions, and subsequent “fireside chats” helped highlight some of these.

Appropriately the first discussion was with a Senior Vice President from Pacific Gas & Electric (PG&E), California’s largest investor-owned utility (IOU) and the utility with more connected PV capacity than any other in the United States. Issues were fairly raised: e.g., how should rates be structured to fairly compensate the value of Grid access received by the customer, how does PG&E envision an environment of growing Community Choice Aggregation (CCA) systems and how is the Grid managed for reliability. Unfortunately, the moderator for this session let the PG&E representative off with the stock, PR answers: “we have to make changes in our rate structures”, “they can work, note how long Marin (Clean Energy, 2010) and Sonoma (Clean Power, 2014) have been in service”, and “we need to build in robustness.”

Ah well, at least subsequent chats returned to DER issues in more depth. DERs can lower costs for Grid operators / managers; experiments were cited by both Southern California Edison (SCE) and San Diego Gas & Electric (SDG&E) involving combinations of storage and DERs. Time of Use (TOU) pricing is coming, and 150 studies worldwide on this issue indicate that customers like this. But there is just too little experience with California’s residential customers while the customers themselves have too little information on which to make decisions as to costs versus savings.

Questions were also raised about Grid planning, to which respondents appeared to agree that too much is moving to identify a “right” strategy, especially as there isn’t even agreement on how to weigh technical issues such as reliability against other social goals we “should” be pursuing. The underlying complexity raised by these superficially straightforward questions was well-highlighted.

Michael Picker, President of the California Public Utility Commission (CPUC) noted that despite all the issues the CPUC addresses, DE issues are of significant importance. CPUC needs to consider even the framework for its decision making processes going forward. A system designed to regulate railroads in the 1890’s may not provide the responsiveness and flexibility for regulating changes to utilities in a rapidly evolving technological, economic and social environment. The “adversarial” approach used in CPUC proceedings may not be the best approach—why is the current process more dependent on legal skills than on engineering skills? The desire is to move forward not too fast, not too slow in opening the market to competition while allowing utilities to remain viable business entities. These are issues that could keep one up at night.

Michael Picker (CPUC, left) and Shayle Kann (GTM, right) during their “Fireside Chat”

GTM California's Distributed Energy Future Conference

The second, albeit lesser, recurring theme I heard at the conference was that of CCA developments. Until this year, there have been only three of these organized in California: Marin (with subsequent geographic extensions) and Sonoma were cited above, and Lancaster Choice Energy was launched in 2015. San Francisco’s Clean Power SF, Silicon Valley Clean Energy and Peninsula Clean Energy (San Mateo County) are in the process of launching this year.

As Mark Ferron, CAISO Board of Governors, cited, in 5 years 60% of the state’s eligible population could potentially be served by CCA’s if all programs now in discussion came to completion in that time. He provided a link in later discussion which I repeat here for those who want to follow up on the tally he reported: climateprotection.tumblr.com/tagged/Community-Choice

CCA’s make solar available to those in multi-family dwellings or who own a home not situated with a solar-favorable orientation or location. Expansion of solar power to these customers is required if solar-based power is to expand. Yet as Michael Picker observed, CCA “forced collectivization is a coup against the traditional utility model, challenging utilities and eroding the role of the PUC.” We don’t know yet where this takes existing suppliers and industry participants.

The challenges of the new, evolving energy infrastructure are actively being addressed by the states of California and New York. Conferences such as this provide an excellent opportunity to reflect on the issues and the difficulty this transition poses for firms competing in the market, regulators and the state legislatures who will eventually need to rewrite the rules for structuring state energy markets.

The Perils of Wholesale Distributed Generation: Can California Live Up to Its Promise?

By Tam Hunt (Community Renewable Solutions LLC), Greentech Media

There has been a lot of excitement about the promise of wholesale distributed generation in California in recent years. But the state still hasn’t lived up to its promise.

Wholesale distributed generation (DG) refers to front-of-meter systems (typically sized between 1 megawatt and 20 megawatts) that sell power directly to the utility or a third-party offtaker. This is an important market niche that remains underdeveloped. But there are some reasons to be optimistic about the future of wholesale DG in California — if some key policy changes can be made.

I’ve written various columns over the years for GTM highlighting the opportunities, innovations and issues facing distributed generation. Last year, I wrote a very optimistic piece that reflected my excitement over the California Public Utilities Commission’s push for more DG. In particular, I highlighted the new Distribution Resource Plan proceeding and the new interconnection maps that utilities were required to produce as part of their DRPs.

GTM’s Stephen Lacey recently wrote a piece kicking off a series of articles on the utility of the future. In it, he said: “Today, experts across the energy industry are predicting a…shift toward a decentralized, digital and dynamic grid system.” I agree with his appraisal of this trend. But California — long considered the leader on these issues — has yet to address a number of hurdles that stand in the way of realizing that future. In fact, the obstacles now facing solar DG in PG&E’s territory threaten to kill this niche entirely…

Read full op-ed from Greentech Media

 

California’s Solar Industry Fights Back on Net Metering 2.0

By Jeff St. John, Greentech Media

California’s biggest utilities want future net-metered rooftop solar systems to earn less for the energy they feed to the grid and solar customers to pay extra charges to cover the costs of serving them grid power.  California’s solar industry has a different idea: keep things the way they are — and don’t believe utilities when they say they and their non-solar customers can’t afford it.

In filings this week, key solar groups The Alliance for Solar Choice (TASC), the Solar Energy Industries Association (SEIA) and Vote Solar have asked the California Public Utilities Commission to retain key features of the state’s net metering regime, including full retail payments for the power that rooftop solar systems feed back to the grid. That’s in stark contrast to proposals from the state’s three large investor-owned utilities, which ask the CPUC to lower payments, impose new charges, and make other changes that would reduce the economic payback of future net-metered solar systems. Utilities say that today’s net-metering regime unfairly slants compensation toward rooftop solar and will impose billions of dollars of cost shifts to non-solar customers if not changed.

Read full article from Greentech Media

How California plans to integrate distributed resources into its ISO market

By Herman K. Trabish, Utility Dive

A new era of grid operations is about to begin in California.

The state’s grid operator is preparing to offer aggregators of distributed energy resources (DERs) the opportunity to sell into its marketplace, the first in the nation to do so. DERs are the resources on the customer side or the distribution grid side of the electric system, such as rooftop solar, energy storage, plug-in electric vehicles, and demand response, and are typically below the 500 kW minimum size required to sell into the ISO system.

CAISO’s Final Plan

The “straw proposal,” an early draft of the ISO’s DERP initiative, was published last November to give stakeholders an opportunity to comment.  The final draft of the ISO’s plan answers many of the stakeholder concerns, with a focus on details of expanded metering and telemetry, the communications and counting methods, and the technologies the grid operator will need.

DER Aggregation

The ISO’s proposal provides a framework for the aggregation of DER to meet the ISO’s 0.5 MW minimum participation requirement and participate in ISO wholesale markets as an aggregated resource. The ISO proposes to classify a distributed energy resource provider or “DERP” as the owner/operator of one or more aggregations of individual distributed energy resources2 (DER) that participate in the ISO market as an aggregate resource rather than as individual resources.

Metering

In today’s California market, all of CAISO’s centralized generators have a resource identity (resource ID) and are required to have “revenue quality metering.” That can be via a direct interaction between the ISO and the resource ID, or it can be through a scheduling coordinator that mediates between the ISO and the resource ID. But for distributed resources, assigning a resource ID to each one is not feasible.

The proposal allows a scheduling coordinator to take administrative control of aggregated distributed energy accounts and meter them with any technology, including any online technology, that suits their purposes. The aggregator can be its own scheduling coordinator or can hire a third-party. A directly connected interface between the ISO and the aggregator is no longer required.

Locational dispersion and capacity of DERP aggregations

There are some 4,900 market pricing nodes (PNodes) on the ISO system. The system is also divided into load aggregation points (LAPs) that follow the territories of the state’s three investor-owned utilities. They are subdivided into sub-LAPs. With the issue of counting the DERPs clarified, the proposal takes up the question of how the ISO can keep track of the multiple sources and types and locations of DERs with which it will have to deal.

Under the new proposal, DERP aggregations may consist of one or more sub-resources at single or multiple locations. There can be multiple small resources across multiple PNodes, but they must be within one sub-LAP.  There is no minimum size limitation on the individual sub-resources in a DERP aggregation. This means that individual sub-resources may exceed the ISO’s minimum participation requirement of 0.5 MW. DERP aggregations across multiple PNodes may not exceed 20 MW, but for DERP aggregations limited to a single PNode, there is no MW size limitation.

Mixing DERs

For DERP aggregations limited to a single PNode, the sub-resources may be heterogeneous – that is, a mixture of sub-resource types is permitted, and there is no MW size limitation. It is not required that all of the sub-resources move in the same direction, only that the net movement of the aggregate of the sub-resources equate to the ISO dispatch instruction.

DERP aggregations across multiple PNodes may not exceed 20 MW. For DERP aggregations across multiple PNodes, all sub-resources within that sub-LAP must be homogenous and must move in the same direction as the ISO dispatch instruction. Homogenous aggregations are those in which all sub-resources are generation, energy storage acting together in charge or discharge only, or are load. For aggregations of energy storage, all sub-resources must be operating in the same mode (i.e., charging or discharging, but not a mix of the two) in response to an ISO dispatch.

The ISO performs network analyses to make certain the system is receiving what the market is selling into it. Sub-resources in an aggregation across multiple PNodes can cause distribution variability. But the PNode distribution variability must be minimized or “the congestion impacts estimated in the network analysis will be off.”  Until the ISO has enough operational experience to know whether the distribution variability would be a problem, it wants to limit DER aggregations “to those that move in the same direction as the ISO dispatch instruction.”

This is especially relevant to aggregated solar-plus-storage technologies that might be producing both load and generation, the final draft acknowledges. “The ISO recognizes that there is great interest in aggregating mixtures of rooftop solar, energy storage, plug-in electric vehicles, and demand response across multiple PNodes, without all the limitations required in this proposal. The ISO plans to examine such options in subsequent initiatives.”

Wait ‘Til Next Year

Several stakeholders suggested provisions be made for demand response (DR) in aggregations of distributed resources, but the ISO chose to limit its role, and does not include demand response participating as Proxy Demand Resource (PDR) or Reliability Demand Response Resource (RDRR) in the DERP proposal. In the proposal, the ISO clarifies that demand response participating as PDR or RDRR would continue to participate under its existing demand response framework and not under the DERP framework. The ISO says the existing PDR and RDRR framework already provides for market participation of aggregated demand response. This existing framework is designed to accommodate load reducing resources whose performance is assessed under a baseline methodology.

Stakeholders also suggested including in the DERP final proposal both the alternative baselines for PDR, and the alignment between distribution level interconnection and the ISO New Resource Implementation process. They are part of a separate energy storage initiative. These suggestions were declined. To facilitate bringing aggregated DERs into its marketplace, the ISO wants to include initially only those that can be directly metered under the specified terms.

The ISO will take formal comments on the final draft through June 24th. If approved by the Board in mid-July, the ISO will probably file by early autumn with the Federal Energy Regulatory Commission. That approval will require at least 60 days.

Read full article in Utility Dive