Tag Archives: Distributed Energy Resources

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 Chief Utility Regulator: The Future Grid Is All About ‘Distributed Decision-Making’

By Jeff St. John, Greentech Media

Michael Picker has spent part of his 11 months as president of the California Public Utilities Commission managing the aftermath of the alleged misdeeds of his predecessor. But as he oversees some of the biggest changes to California energy policy in over a decade, he’s also spent a good deal of time explaining his vision for greening the state with distributed energy, along with the distributed decision-making to make it work for the grid.

Since he was appointed in December, Picker has been stressing certain key policy philosophies for how the CPUC can help the state reach its carbon reduction and green energy goals. These include a preference for market-based solutions over technology mandates, a heavy emphasis on electric vehicles as part of the mix, and an enthusiasm for technologies that can manage lots and lots of distributed energy resources (DERs) in concert with the grid as a whole.

In a series of talks this month, Picker declined to discuss details of big proceedings under review, such as the CPUC’s net-metering reform, which has pitted the solar industry against the state’s big three investor-owned utilities. But he did sketch out a plan for managing the inevitable growth of intermittent renewable energy, whether from millions of rooftops or ever-cheaper utility-scale solar and wind projects.

Read full article from Greentech Media

From theory to practice: The challenges in moving to ‘Utility 2.0’

By Herman K. Trabish, Utility Dive

For all the theorizing about what the utility of the future will look like, real world examples of how to adapt current power sector business models to the new world of renewables and distributed resources can seem few and far between.

While utilities often trumpet their new smart grid technologies, microgrid projects and storage pilots, actually working out how to make those solutions scalable and profitable can be a lot harder than it looks from the outside.

But utilities across the nation can learn from each other’s experiences, with the aim that the questionable technologies of the day can become the ubiquitous tools of tomorrow.

That was the goal of the emerging technologies panel at the recently-concluded Energy Storage North America 2015 conference in San Diego. There, representatives from four major utilities—PG&E, the Sacramento Municipal Utility District (SMUD), Southern California Edison, and Consolidated Edison—highlighted the challenges and successes of a diverse set of DER pilots, hoping their struggles could translate into easier adoption of distributed resources and demand side resources at other companies…

Read full article from Utility Dive

Inside California’s energy politics, the FERC Order 745 case, and the coming storage cost shift

By Gavin Bade, Utility Dive

[Editor’s Note: The following is part of Utility Dive’s coverage of the 2015 Energy Storage North America conference.]

For many power sector observers, California utilities are the ideal partners for forward-thinking regulators looking to adapt the utility business model to the 21st century. California’s investor-owned utilities proclaim their commitment to clean energy technologies demonstrating how they’ve surpassed mandates, accepted more rooftop solar, or integrated large amounts of storage.

Utility executives from San Diego Gas & Electric (SDG&E), Southern California Edison (SCE), and Pacific Gas & Electric (PG&E), provided apt examples in their keynotes at the Energy Storage North America conference. All these announcements could logically lead observers to conclude that California utilities have been proactive partners in helping set California’s ambitious clean energy goals. Not exactly, two veteran state legislators told Utility Dive at the conference.

Politics of renewable energy policy:

State Sen. Ben Hueso, chair of the Senate energy and utilities committee, ushered SB 350, the bill that set the state’s 50% RPS, through committee earlier this year. He said that the utilities have always fought hard against any mandates behind closed doors, whether it was SB 350 or earlier efforts. Former Assemblymember Nancy Skinner, echoed Hueso’s observations, but said that the power industry doesn’t behave much differently than others in this respect. “No industry likes mandates,” she said, noting that it took three legislative sessions to usher through the state’s previous 33% RPS, which was met with utility pressure behind closed doors.

California’s new RPS, by contrast, was authored and passed in one legislative session, a feat that Skinner said cannot be overstated. Not only does the bill increase the renewables portfolio standard to 50% by 2030, it also specifically calls on utilities to deploy energy storage and combines the renewables goal with an aggressive efficiency standard. So what changed to get such an aggressive bill passed so quickly?

…Clifford Rechtschaffen, a senior advisor to Brown, said the most important thing was that, in the end, “all of the utilities with the tiny exception of some northern California power agencies that had some qualms, they all supported SB 350.” Rechtschaffen said that while the utilities may have shown some resistance as the bill was working its way through the legislature, most of their concerns were operational in nature. “They weren’t quarreling with the notion that we needed to get to 50%,” he said. “They had concerns about how best to do it — some of which we agree with and others which we aren’t completely in line with, but we’re working on those. Storage is a big part of the solution.”

The role of storage in California’s renewable energy economy:

In a keynote panel discussion the California policymakers highlighted energy storage as the technology that can make 50% renewables and beyond possible for California. Once you get to that level of renewables, Rechtschaffen said, “storage is absolutely critical for grid integration. There’s no arguing about that.”

But the situation for storage, especially in the eyes of utilities, wasn’t always so rosy, Rechtschaffen said. Back in 2014, the state’s IOUs were resistant to the PUC’s mandate to deploy over 1,300 MW of storage on the grid by 2020, worried that the technology wasn’t ready and that it would “put storage in a bad light.”

In reality, the opposite happened, and SCE started off the storage procurements by buying 264 MW, when it was only compelled to purchase 50 MW at the time. For the California policymakers, it was a validation of the power of mandates to drive innovation in the power sector.

Read full article from Utility Dive

Related article: Why energy storage is key to a future with ‘no more gas turbines’ (Utility Dive) – Oct. 15, 2015

Building the 21st Century Power System

By Ted Craver (Chairman, President & CEO of Edison International), EnergyBiz Magazine – Fall 2015

Imagine for a moment that you are a homeowner or a small-business owner and you just shelled out $25,000 or more for a shiny new rooftop solar generator. Then imagine your electric utility told you that you could not hook it up to the grid right away, not until your neighborhood circuit was upgraded. And even then, it said you could only turn it on during certain hours. I am guessing you would not be a happy customer.

As CEO of one of the nation’s largest electric power companies, I do not want to be in the business of telling our customers what they can install on their own properties and how they can use it. As utilities, we don’t control what customers put behind the meter. We don’t tell them what TVs and appliances they can buy. The same should apply to PV solar panels, home batteries and electric cars.

Our job as utilities is to provide the power network that enables customers to choose which energy technologies they want to use. At Edison International and Southern California Edison, we like to call it a “plug-and-play” network, meaning that customers should be able to plug in any device and have it work seamlessly with our power system. Building that network to provide customer choice broadly across our system requires us to modernize the power grid so it can accommodate these new technologies… That is why we are building a more flexible, resilient and low-carbon electricity distribution grid for the 21st century and beyond. Modernizing the grid will not only preserve reliability in the face of increasingly complex distributed energy resources, it will also allow us to utilize these resources to provide grid services.

Read full article from EnergyBiz

Inside Southern California Edison’s energy storage strategy

By Gavin Bade, Utility Dive

Last winter, Southern California Edison (SCE) sent the U.S. energy storage sector into a frenzy with a single announcement: It would purchase over 250 MW of energy storage in one fell swoop — more than five times the amount California regulators required it to do at the time, and easily the biggest single storage procurement to date.

That purchase was brought on by a landmark mandate from the California Public Utilities Commission (CPUC). Passed in 2013, the order requires the state’s three big investor-owned utilities (IOUs) to put 1.3 GW of storage on the grid by the end of the decade.

As a first step in that process, the regulators stipulated that the IOUs had to contract for 50 MW of storage by the end of 2014. But as a part of a larger request for proposals, SCE elected to contract for 264 MW of diverse energy storage technologies, including utility-scale batteries, behind-the-meter resources, and non-battery storage alternatives. That giant storage procurement puts the company in uncharted territory for an American utility, forcing it to grapple with valuation and operational issues involving storage that other power companies have only imagined.

Nearly one year on from that historic proposal, what has SCE learned about storage—and what is its outlook for the future? Utility Dive spoke with SCE President Pedro Pizarro to find out…

Read full article from Utility Dive

A Revolutionary Roadmap for California’s Distributed Energy Future

By Jeff St. John, Greentech Media

California is already changing its utility and energy regulations to incorporate rooftop solar, behind-the-meter energy storage, plug-in electric vehicles and other grid-edge resources, arguably faster than any other state. But a group of utilities and energy industry members have ideas for even more radical transformations ahead.

On Tuesday, the Advanced Energy Economy Institute released a report that calls for California regulators to consider entirely new ways for its major utilities to invest in and operate a distributed energy resource-rich grid, and how to get paid for it. The report, Toward a 21st Century Electricity System in California, lays out a laundry list of concepts that could help utilities shed their institutional need for investing in traditional generation and grid infrastructure, and encourage them to embrace customer-owned and third-party-controlled distributed energy resources (DERs) as an alternative.

The ideas aren’t that novel in and of themselves. What’s more noteworthy is the list of participants in the working group that created the document. That list includes California utilities Pacific Gas & Electric and Southern California Edison, as well as DER providers like SolarCity, Stem, SunPower, Enphase, EnerNOC, ChargePoint and SunEdison, which have at times sparred with the state’s utilities over how to balance utility and third-party interests when it comes to distributed energy.

Read full article from Greentech Media

Related article: Report—Incentives hold back clean energy (The San Diego Union Tribune)

California’s Distributed Energy Grid Plans: The Next Steps

By Jeff St. John, Greentech Media

Last week, after a year of behind-the-scenes work and much public debate, California’s big three investor-owned utilities turned in their long-awaited distribution resource plans (DRPs). These DRPs are essentially blueprints for how Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric are going to merge rooftop solar, behind-the-meter energy storage, plug-in electric vehicles and other distributed energy resources (DERs) into their day-to-day grid operations and long-range distribution grid planning and investment regimes.

Each California utility has created mapping tools that show how much capacity is available on each distribution circuit for new DER interconnection, for instance — something that could be very useful for distributed energy developers. All three utilities have also agreed on a common set of measures for how DERs could help shore up grid capacity, increase reliability, serve system-wide needs, and otherwise stand in for costly utility upgrades. And each has laid out how it plans to fold these DRP methodologies into their general rate cases (GRCs), the once-every-three-years process that determines how much each can charge its customers for its capital and operating costs for the coming years.

Many questions remain about how to determine which combination of DERs will meet the least-cost models that utilities use to rank their distribution grid upgrades, and what kinds of new capabilities grid-supporting DERs will need to have to serve as replacements for utility investments. There’s also much uncertainty about how DERs serving as stand-ins for grid infrastructure should be paid for, and how their costs and benefits should be shared. These issues are of major interest for solar-storage combinations from SolarCity and Tesla, SunEdison and Green Charge Networks, Sungevity and Sonnenbatterie, and SunPower and partners Stem and Sunverge, which see an opportunity for earning grid services revenues as stand-ins for distribution grid investments. They’re also important for the commercial building and residential energy management platform providers looking for ways to tap California’s emerging opportunities for distributed demand response.

These costs and values wouldn’t just flow from utilities and their customers to DER providers—each utility’s DRP asks the California Public Utilities Commission (CPUC) for permission to spend lots of money on beefing up their own systems to enable their visions. Southern California Edison alone is estimating its DRP-related capital expenditures could add up to $347 million to $560 million over the next three years, for example, and PG&E and SDG&E will also be seeking new funding, though they haven’t yet specified how much.

All three DRPs add up to nearly 1,000 pages, which makes it hard to summarize all the next steps they contain, but here are a few highlights of the challenges to come.

Read full article from Greentech Media

Related articles: How California’s biggest utilities plan to integrate distributed resources (Utility Dive)

Inside SoCal Edison’s Plan to Open Its Grid to Distributed Energy

By Jeff St. John, Greentech Media

Two years ago, California told its three big investor-owned utilities to do something they’ve never done before — make distributed energy resources (DERs for short) a fundamental part of their billion-dollar distribution grid investment plans.

Under state law AB 327, Southern California Edison, Pacific Gas & Electric and San Diego Gas & Electric were tasked with finding a way to integrate solar PV, behind-the-meter batteries, electric vehicle chargers, building energy management systems, and other distributed energy resources into a new set of distribution resource plans (DRPs). The DRP planning process has been the subject of much debate and scrutiny over the past year, because they have profound implications for how rooftop PV installers, energy storage developers, demand response providers and other third-party DER companies will do business in the state.

Now, with Wednesday’s deadline for utilities to file their plans with the CPUC, the wait is over — and we’ve got details on how one utility is putting its grid-edge plan together. This week, Southern California Edison shared some fundamental features of its DRP, including some new software tools and methodologies to assess distribution grid capacity, the way it plans to assess the costs and benefits of DERs for its upcoming rate case, and new pilot projects to test these propositions in the real world.

Read full article from Greentech Media