I made ten predictions in January 2014 about Smart Grid and Smart City trends and changes that will occur between 2014 and 2020. Here is an update on the final five predictions. The first five were reviewed last week. You can review the full predictions here and here, and judge for yourself the quality of my crystal ball.
6. Debates about the future of the social compact for electricity services and the socialization of electricity costs continue. The Reforming Energy Vision initiative includes the objective to “enable and facilitate” new business models for utilities, customers, and energy service companies. This is just the first state activity that will generate significant discussion about how to equitably balance distribution grid investments that accommodate and integrate more distributed energy resources (DER). Since it will take time to implement and then measure results from new business models, this debate is sure to continue for the next decade.
7. EVs advance to 10% of the US car market. The current electric vehicle (EV) penetration in 2013 was just a bit over .5%. The falling costs of gasoline are putting additional pressure on EV manufacturers to reduce prices of zero emission vehicles to increase consumer adoption. However, utilities are now taking a more active role, as Edison Electric Institute members will start investing up to $50 million annually in EV service trucks and charging stations for consumers. The Department of Defense (DoD) is conducting pilots for vehicle to grid or V2G applications. Their first smart charging demonstration are exploring V2G performance, and they will also examine re-purposing used EV batteries for fixed energy storage.
8. Resiliency measures also become part of the definition of a smart building. There are a number of federal, state, and non-governmental initiatives that address resiliency, and some critical infrastructure definitions include selected buildings. The National Institute of Standards and Technology (NIST) is developing standards guidance for community disaster resilience, but this is focused on building materials and codes. Microgrids, DER and Zero Net energy codes and technologies can bridge the gap in existing resiliency initiatives for buildings. Microgrids are already in production as resources to maintain power to critical infrastructure during emergencies – one of the goals of the Borrego Springs microgrid.
9. Nanotechnologies help propel solar harvesting efficiencies past the 50% mark, and by 2020 research scientists are aiming for 75% harvest efficiencies. The number of patents filed for innovations in nanotechnology using graphene have tripled in the past 10 years. The research pipeline contains single molecule thick sheets of graphene and molybdenum that can potentially provide 1000 times more power per weight unit of material than current commercially available solar cells. The fabrication of flexible solar panels is on the horizon, which can be wrapped around curved or uneven surfaces or reduced in scale, expand the possibilities for where solar can be deployed.
10. There’s sufficient electricity production from renewable energy sources that we no longer talk about “renewables.” American grid-connected wind turbines have a combined capacity of 60,000 MW, projected to double by 2020. Solar is enjoying explosive growth. Energy storage solutions will “firm up” the intermittency of wind and solar and thus eliminate the last objections to reliance on renewables. It will just be a cheap and clean source of electricity without the price volatility of fossil fuels.
These final five predictions are well on their way to realization too, although the prediction about nanotechnology advances is admittedly a stretch goal. You’ll note that energy storage has a significant influence on the advancement of some of these predictions. We’ll keep tracking these predictions and bring you periodic updates.
This week, the Smart Grid Library features a guest writer, Chris Kotting, a colleague with SGL Partners, the consulting group of the Smart Grid Library.
I just took a look, and I haven’t blogged since the first week of this year. Egad! That was one short-lived New Year’s resolution! Now, here I am writing a blog entry, and it won’t even see the light of day on my blog. I’m “guest-blogging” while my buddy Christine goes gallivanting around Europe.
To borrow a line from Warren Zevon “Poor, poor, pitiful me...” (Yes, I know that Linda Ronstadt made the song famous, but Warren wrote it for pity’s sake, so let’s give credit where credit is due.)
Anyway, while I’m feeling sorry for myself (in the future tense, since I’m writing this while Christine is still in the States) I see that the Solar industry is facing some nasty integration issues, some of which relate to Net Metering.
Now I’ve talked about Net Metering before, and I’m not a big fan of it. It is intended to be a simple way of paying residential customers for their solar (or sometimes other) generation, while at the same time providing an incentive for that generation. It creates too good an incentive, in my opinion.
To recap my issues with Net Metering:
- Net metering pays a retail customer the same amount for each kWh that they sell back into the grid (from their rooftop solar unit, for example) that the customer pays per kWh for power that they take from the grid. It seems simple and equitable, until you look into the details.
- The market value of the power that the customer produces may be wildly different from the market value of the power they take, and of course neither relates to the cost of producing that power.
- That difference between the value of “sold” kWh and “bought” kWh is going to generally be pretty consistent, since when a PV unit makes power, and when a residential customer takes power (a) don’t tend to be the same time, and (b) tend to be pretty consistent day-to-day.
- Therefore, on energy, the customer either wildly overpays, or wildly underpays.
- In addition, that kWh rate includes load-balancing, frequency regulation, and a host of other ancillary services that a “prosumer” is still using, even as a producer of power, but they aren’t paying for. In fact, they are getting paid for it. (This is more of an issue where the price for power doesn’t disaggregate Transmission and Distribution services. However, even in states where the services are disaggregated, the use of the net metering model assumes that consumer generation somehow offsets the cost of ancillary services.)
That’s just a capsule summary, and it misses a lot of the details, but you get the idea. To my mind, the worst thing about this scenario is that it leads to customer-owned rooftop solar being installed where it isn’t really economic because the inherent subsidies mask the real economic costs. It may even lead to situations where solar is not being installed where it genuinely makes economic sense, because the inherent subsidies also mask the real economic benefits.
Similarly, it leads to customer-owned solar being operated inefficiently, at least as far as the efficiency of the grid is concerned, because solar generation under a net metering model is a “non-dispatchable” supplier. Whether the grid needs the power at that time or not, it has to take it and find a use for it.
But what does this have to do with the problem of grid integration of large quantities of renewables? This paragraph from the article points out the connection:
“The largest integration challenge that emerges,” E3 found, “is overgeneration.” That is when must-run generation (non-dispatchable renewables, combined-heat-and-power, nuclear generation, run-of-river hydro and thermal generation needed for grid stability) is greater than energy demand.”
Anyone familiar with renewable energy, particularly solar, is familiar with the “duck chart” which shows the need for generation to dispatch differently to accommodate solar energy. The biggest challenge is at the “neck” of the “duck” when a significant amount of generation has to come online in a short period of time to meet the demand that is placed on the grid when solar resources drop their output. (Utility folks refer to this as “ramp rate”, how fast generation has to “ramp up” to meet the load placed on it.) The lower the “back” of the duck, the more of a problem bringing enough generation online in time becomes (the higher the “ramp rate”.)
As I just mentioned, net metering generation is non-dispatchable. The more non-dispatchable generation you have to deal with, the steeper the neck becomes. One diagram shown in the executive summary of the report shows that at a 40% renewables level, power taken under net metering is more than half of the overgeneration problem. Under those conditions, the “duck diagram” gets positively swaybacked so that, in the study, the ramp rate in one scenario approaches twice what happens currently.
So, what can be done about it? Is there no way to solve the integration problem? Of course there are ways to resolve it, but that discussion will get picked up next week, back over on my blog.
After all, they say that the best way to make a resolution stick is to make it public.
The news for solar energy in the USA is optimistic, based on recent reports from Navigant Research and statistics compiled by the SEIA and Greentech Media. The first firm indicates that the market for distributed energy resources, of which solar, mostly in PV forms, is anticipated to reach $625 billion USD in cumulative spending in residential generation and storage between 2014 and 2023. The second report projects that PV installations will reach 6.6 GW in 2014, almost doubling in size since 2012.
There are several reasons for these healthy growth projections. First, there are more affinity marketing promotions in your mail and email these days, in which environmental organizations such as the Sierra Club team with solar vendors and combine purchase discounts with donations to environmental or social justice causes. Second, there are more financing options as crowd-sourcing, PACE, third-party ownership via power purchase agreements* (PPAs), and Green Bank and Green Bond options make capital more affordable and available for residential, commercial, and municipal projects.
Third, the federal government has a number of initiatives designed to reduce the investment costs in solar and increase the effective energy harvestability of solar technologies. Of the fourteen programs the White House described in its Energy 2030 announcement to double energy productivity this past week, 10 cover renewable energy. Some are already in existence, like the SunShot program to improve technologies and ongoing reporting of solar technology trends and deployments. New activities include industry roundtable discussions intended to improve capital flows and risk assessments for solar projects.
These are all positive incentives that encourage residential, municipal, commercial and industrial building owners and farmers to invest in solar energy to reduce their reliance on local utilities and/or improve their self-sufficiency in light of grid disruptions. And states like California, Massachusetts, and Arizona have been setting the pace for solar deployments. However, a series of events in Northern California, territory for Pacific Gas & Electric (PG&E), could culminate in an unintended perverse incentive that encourages its customer base to embrace solar and other DER assets.
A catastrophic natural gas pipeline explosion occurred on September 9, 2010 in a San Bruno, CA neighborhood. The resulting inferno killed 8 people, injured 66, and destroyed 38 homes. PG&E owned the pipeline, and was ultimately fined $1.4 billion USD, based in part on its failures to maintain pipeline safety and keep accurate records. As a side note, had this pipeline been upgraded with Smart Grid technologies that deliver remote sensing and controls, much of the damage might have been minimized. Instead, a dumb gas grid required manual intervention to shutoff gas, an action delayed for well over an hour as a maintenance truck traversed half of the Bay Area during the afternoon rush hour and first responders battled fires fueled by gas.
The story doesn’t end with the fine. Since then, a number of emails between the utility and the California Public Utilities Commission (CPUC) highlighted a very cozy relationship between the monopoly and the regulatory agency. All these recent revelations have earned the attention of the governing representatives of PG&E customers at the local, state, and federal levels, as well as the customers themselves. A few heads have rolled, but we haven’t seen the last act in this story.
But there’s more. PG&E is also the utility that suffered the still-unsolved April 2013 physical attack to its Metcalfe transmission substation in Silicon Valley. Someone with a high-powered rifle destroyed valuable assets that maintain grid reliability. That event stirred much needed, industry-wide discussion and subsequent actions to upgrade physical security perimeters for critical infrastructure. Yet even after PG&E installed new fence monitoring equipment at the Metcalfe site, on August 27 of this year burglars cut their way into the perimeter and stole construction equipment on site to repair the damages incurred in the previous attack. The fence monitoring alarms worked, but they weren’t addressed, and the fault has been attributed to human error.
PG&E customers are weighing four years of news about this utility’s failures in maintaining the social compact of safe, reliable, and cost-effective electricity and gas distribution. It could add up to become a perverse incentive that motivates people to adopt more solar to generate at least some of the energy they need as confidence in the utility drops. These failures won’t be solved with investments in advertising campaigns about pipeline safety or lobbying the regulatory agency. Focus on running the business on the principles of the social compact.
Most Smart Grid discussions about human impacts address the demographic trends in utility workforces or the influences that Smart Grid technologies and applications have on people in residential and commercial settings. While both are very worthy topics, the subject of job creation doesn’t get the same attention. And that’s a puzzle, given today’s economy. The Smart Grid’s technology, policy, and financial disruptors have happy consequences for the labor market through increased and sustainable local employment opportunities.
Jobs can be defined as direct, indirect, and induced. Direct jobs are the positions created to perform a specific function. Indirect jobs are created in supply chains and the businesses that support those direct jobs. Induced jobs are created based on the savings generated from the results of the direct and indirect jobs.
For instance, one of the most important Smart Grid trends is the growth of distributed energy resources (DER). One important DER asset class is renewable energy such as found in solar generation solutions. The state of California has more than 47,000 people working in this sector – about one third of the nation’s total solar employment. Many of these jobs are focused on installation and maintenance of solar systems – “boots on the ground” or direct jobs that every region of the USA should encourage.
What led to solar generating energy and jobs? It’s not just the natural climate of abundant sunshine in the state. The state renewable portfolio standard of 33% that Governor Jerry Brown stated was a “floor, not a ceiling requirement”; the million solar roofs program, and other regulatory and legislative actions created the business climate, which enabled companies to put certainty to former risks, and led to the establishment or growth of scores of businesses and new direct, indirect, and induced jobs.
Other DER asset classes include energy storage, energy efficiency retrofits, and demand response programs. The California Public Utilities Commission (CPUC) mandated in 2013 that its regulated utilities must incorporate 1.325 GW of energy storage into their grids by 2020, the largest amount of storage in the world today. Energy storage and renewable generation assets go together like peanut butter and jelly – good on their own, but even better together. Like recent solar cost trends, upfront energy storage costs are expected to decrease as deployments increase and benefit from economies of scale. New market entrants with innovations in technologies, processes, and services will bend the cost curves downwards even more. These trends mean more direct jobs for skilled technicians and a labor force that remains in place to respond to maintenance and upgrade requests. Greentech Media estimates that the energy storage market will quadruple every four years, and one of the reasons is California policy, which essentially made a market for energy storage solutions at the transmission, distribution, and behind the meter (consumer and prosumer) points.
Energy efficiency is another promising homegrown employment area. Spurred by the oil embargo and economic shocks of the early 1970s, California has gradually introduced energy efficiency (EE) standards for white goods like refrigerators, electronics like TVs, and commercial and residential buildings themselves. The building standards are updated every three years. Similar policies have been adopted worldwide since then. The latest round of EE building standards will create locally-situated jobs as building owners retrofit structures or deploy the appropriate energy efficiency measures in their new construction. This American Council for an Energy-Efficiency Economy (ACEEE) paper outlines the economic impacts of EE projects in both employment and cost savings. The cost savings benefits of energy efficiency measures are sometimes overlooked too. As less money is needed to pay for energy expenditures, more capital is available to invest in business growth.
There are two centers in California designed to support job training on EE technologies and services. The newest center is a collaboration between the International Brotherhood of Electrical Workers (IBEW) and the National Electrical Contractors Association (NECA). These organizations understand the connection between smart energy policies and sustainable employment. California has often led the way in smart energy policy, although the aftermath of Superstorm Sandy has prompted some eastern states to promulgate innovative energy policies that build and enhance grid and community resiliency. Where these pioneers lead – will other states follow? They would be wise to enact similar energy policies to benefit their regional economies through job creation and reductions in energy costs for citizens and businesses.
The Interstate Renewable Energy Council (IREC) just released a white paper that should be read by every utility regulator and state legislator interested in encouraging renewable generation sources into the grid. The Integrated Distribution Planning Concept Paper offers practical suggestions that help accelerate the transformation to a Smart Grid. It also helps build the foundation for the transactive energy business model.
IREC focuses on regulatory policy innovations to enable deployment of clean energy like solar, particularly at the distribution grid level. Although this is called a concept paper, it has a realistic focus on interconnection practices and encourages a nation-wide approach to accommodate more renewables. Interconnection from the distribution grid perspective refers to the utility processes that ensure that connection of distributed energy resources (DER) like solar occur in a timely manner with safe, reliable, and high quality electricity flow.
The paper focuses on solar interconnections into the grid, but there’s no reason why these same practices and policies shouldn’t be adopted for other distributed energy resources (DER) like small turbine wind and all forms of energy storage that can interconnect to the distribution grid. The researchers reviewed interconnection processes in California, Hawaii, Massachusetts, and PEPCO, a utility with a footprint in New Jersey, Delaware, and Maryland. These entities have demonstrated leadership in policies to address the explosive growth of DER interconnection requests.
Grid-connected solar photo voltaic capacity jumped 4000% from 2005 to 2012, according to IREC solar research. Imagine how the work volume in utilities’ planning departments has similarly increased, and as the numbers of applications have grown, so have the waiting times. That’s a problem for DER owners who want to enjoy the benefits of a solar investment as soon as possible. However, the utilities have to make sure that anything that interconnects to the grid doesn’t blow it up.
Interconnection requests might require significant upgrades of grid equipment to ensure that the electricity delivered is safe, reliable and has good power quality (meaning no voltage sags or surges). Utility planners have to consider the local circuit design and the type, size and location of the DER asset on that circuit, and depending on the answer, it could make a project’s ROI move back a few years. Since distribution grids were designed for a one-way power flow from generators to consumers, not localized generation to supplement/substitute/sell, as envisioned in transactive energy models, there’s a good chance that some grid investment is required.
Some of the creative policies identified in the paper include creating new utility plans that incorporate DER – at least generation assets – into future grid modernization initiatives. California’s policy requires utilities to consider how generation assets in the distribution grid can “defer transformer and transmission line upgrades, extend equipment maintenance intervals, reduce electrical line, losses, and improve distribution system reliability, all with cost savings to utilities.” That’s hugely influential thought leadership because it considers that assets that are not owned by a utility can have a quantifiable value to the utility, and therefore create the foundation for a transactive energy market.
The paper’s approach, called Integrated Distribution Planning (IDP) determines the status (particularly capacity) of the existing distribution equipment and identifies potential upgrades that may be needed to accommodate anticipated DG growth in a five step process. Most importantly, this information should be readily available to anyone interested in developing a renewable project, so realistic assumptions can be made about any grid upgrade costs and timelines.
Perhaps some day utilities will identify distribution grid points where independently-owned DER assets are welcomed to inject resiliency into the local grid or help avoid an expensive upgrade. Potential DER asset owners – commercial and residential – could be financially incented to take on projects with reduced risks because utilities could think about these assets in newly useful ways. The DER assets under consideration here could include energy storage, not just generation. That’s a significant step in the right direction to build an electricity value chain based on transactive energy concepts.