Utilities and regulators evaluate grid modernization initiatives using economic paradigms. They determine if investments at the grid edge are cost effective relative to investments made in traditional generation, transmission and distribution assets. The Intergovernmental Panel on Climate Change (IPCC) recently published a special report titled ‘Global Warming of 1.5°C’, with an accompanying Summary for Policymakers. The Summary stated that if global warming continues at its current rate, we will likely reach a 1.5°C increase in global mean surface temperature (GMST) compared to pre-industrial levels between the years 2030 and 2052. The Report and Summary provided a comparison of outcomes we can expect if GMST increases to 1.5°C versus 2.0°C. It also presented solutions to support limiting global warming to the smaller value.
Peak demand is the highest rate of electricity use. Fortunately, it only occurs a few times a year – usually on the hottest days of the year or on the very coldest days of the year, depending on your geography. Our power systems are prepared for these peaks (otherwise we risk potential blackouts), but as urban populations increase, and we add more variable renewable energy resources to our grid, we see more need to accommodate increases in peak demand. Traditionally, utilities would forecast demand in their service territories and resort to upgrading or building new peaking power plants to supply the anticipated increase in electricity demand. This solution tends to be land-intensive and has resulted in significant increases in greenhouse gas emissions.
At this year’s GridFWD conference delegates met for the first time in beautiful Vancouver, British Columbia, home of our Canadian headquarters. Enbala was present in full force, as a sponsor, panelist and moderator. The well-attended event covered a range of pertinent and enlightening topics including grid modernization and decarbonization.
One such discussion, moderated by Graham Horn, Enbala’s VP, Business Development, focused on the path from DER grid presence to VPP flexibility. Graham was joined by Jeremy Twitchell, Energy Research Analyst with Pacific Northwest National Labs (PNNL), J.P. Batmale, Division Administrator at the Oregon PUC, and Smriti Mishra, Strategic Partnership Manager with National Grid.
Leading up to a September 17 webinar with Alectra, Navigant and Enbala, Navigant's Peter Asmus provides insights on some of the topics to be covered in the webinar.
Alectra, the second largest municipal utility in North America, was the first utility to develop a microgrid offering for its customers. It developed a small, commercial-scale microgrid and then a utility-scale microgrid, the latter at its own headquarters at Cityview in Vaughan, Ontario. This utility-scale microgrid integrates a variety of distributed energy resources (DERs) while also featuring the ability to island, if necessary, to maintain reliability at a site that includes Alectra’s center of operations.
This utility-scale microgrid was focused on the internal optimization of these assets to create a reliable optimization network. As Alectra looks out into the future, however, it realizes that it had to build the business case to provincial regulators about why ratepayer investments in control of BTM assets provided value to all distribution network ecosystem stakeholders, including those with DERs and those without.
Guest blogger Peter Asmus of Navigant Research posts this week about virtual power plants, distributed energy resources management systems, microgrids — and the way in which Alectra is bringing them all together to meet its customers energy needs and its own grid reliability requirements.
Electricity is a multidimensional product that requires constant fine-tuning. Otherwise, the lights go out, resulting in substantial lost economic activity. The challenge of accomplishing this task has become increasingly difficult as the fleet of distributed energy resources (DERs) begins to take over electricity resource pools. Beginning in 2018, annual centralized power resources began to give way to distributed generation and a more diverse DER mix. I noted last year that this transition was likely.
The world is changing. This isn’t news, of course. In fact, it’s rather old news – the world has changed. And the composition of the power grid has changed along with it. More roofs have solar panels. More garages house electric vehicles. The devices consumers plug into outlets have radically different load profiles than the devices of previous generations. Today there is an increased prevalence of wind farms, smart inverters, batteries and many other distributed energy resources (DERs) at the grid edge.
All these DERs offer tremendous potential through control and optimization. But while this capability presents copious opportunities, it also creates a few headaches, particularly for grid operators, often miles away (literally and figuratively) from where the DERs are located.
Yet DERs are becoming so entrenched in the daily operations of the grid that it’s tempting to ponder just where their limitations lay. With advancements in technology and business models, many innovators are looking to increase value from DERs, which leads to the latest question surrounding the capabilities of these assets: Can DERs play in utility and wholesale markets?
For more than 100 years utilities have supplied electrical power to customers and have done so with good reliability. The principle is simple. Loads may do as they wish. They may be random or intermittent and generally are not individually monitored by the utility. Generation, on the other hand, MUST be both dispatchable and monitorable, and electric system operators must be able to manage the real and reactive power from a generator.
Historically, utilities have become very adept at managing generation capacity to maintain a continuous balance between supply and demand. But today, the world is faced with a need to reduce or even eliminate carbon emissions, which complicates the supply-demand balance. Most electricity in the US, for example, is generated by burning fossil fuel. This needs to change, along with change to the electricity supply system and the direct customer use of fossil fuel. We are looking to remove the steady performers, and to replace them with supplies that are intermittent and perhaps random, all the time maintaining a balance between supply and demand.
I take the bus to work. On any given weekday, you can find me waiting on the side of a road while vehicles of all shapes and sizes whiz by, leaving behind a trail of noise and exhaust. It would be all well and good if this was just another weekday annoyance that could be easily shrugged off, like a fresh pile of snow blocking the sidewalk or a texter blissfully skipping the line at a busy coffee shop. But that’s not the case. Vehicle exhaust is a known pollutant that significantly affects human health and the environment. Regulators put limits on emissions – but these generally focus on new car sales, and then they can still be tampered with. So as a commuter waiting at the side of a busy road, I don’t feel too reassured. But, when I see that clean technology goals for electric vehicles are on track, hear announcements from companies like Tesla, Thor and Volvo electrifying trucking fleets, and read about commitments by governments to support these efforts, I do feel hopeful.
The California Duck Curve reveals a potential costly issue for utilities and their customers. The annual peak load appears to be continuing to grow -- because it occurs after dark when there is no solar power being generated -- yet energy sales may be declining with the growth of distributed solar generation during the day. This results in the need to continue to expand the grid, but without the sales revenue to support the added capital expense, presenting a Catch-22 that utilities are struggling to overcome.
For more than 100 years utilities have supplied electrical power to their customers and have achieved this with good reliability. The principle is simple. Loads may do as they wish, but generation — the supply — MUST be both dispatchable and monitorable. An operator must be able to start or stop a generator or to change capacity at the touch of a button to maintain a continuous balance between supply and demand. On the other hand, the loads that use the electric power can be intermittent, unmonitored and subject to starting and stopping at what the system operator would see as near random times.
Suddenly, the world is faced with a need to reduce or even eliminate emissions.