by Allen Best Lowering electricity bills in Colorado: Study makes the case to Colorado legislators and others about the benefits to consumers of advanced energy markets https://www.vibrantcleanenergy.com/wp-content/uploads/2020/10/CO-EIM-Options-Report.pdf
by Allen Best
A new study commissioned by two electrical cooperatives in Colorado makes the case again for developed markets and coordinated transmission of electricity both through energy imbalance markets and, more robustly, thorough a regional transmission organization.
The news is less in the study results than the motivation of two cooperatives, Glenwood Springs-based Holy Cross Energy and Sedalia-based Intermountain Rural Electric Association. Why did they pay for this study?
What benefits do they see for their customers in Vail, Basalt and Parachute, in the case of Holy Cross, or Castle Rock, Conifer and Bennett, in the case of Intermountain? We’ll get to that.
First, the results by Vibrant Clean Energy, a company based in Boulder, that is said to have the capabilities to analyze benefits of the evolution in electrical generation and deliver better than any other company.
Integrating Colorado into a regional energy market could save the average residential electricity customer $255 per year by 2040 as compared with today, according to the study posted last week. The annual savings across Colorado would be $1.76 billion.
See the full report here. And the PowerPoint here.
The first baby step is creation of energy imbalance markets, which Colorado’s utilities have set out to do. An energy imbalance market is described as a low-risk, low-reward step that helps match supplies and demands across multiple utilities. Colorado will have two within a couple years.
Tri-State Generation and Transmission made the first move last September, announcing that it and the Western Area Power Authority were joining an energy imbalance market being created by the Arkansas-based Southwest Power Pool.
Duane Highley, chief executive of Tri-State, has said repeatedly that the costs of creating the market can be recouped within three years from the benefits it will deliver.
Then, in December, Xcel Energy and three other utilities along the Front Range of Colorado announced they would join an energy imbalance market being created by CAISO, or the California Independent System Operator.
The real prize will be creation of a regional transmission organization, or RTO, which requires more investment—and delivers far greater benefits.
Greater benefits to the west
The Vibrant study says utilities will benefit from going either eastward, into the Southwest Power Pool, or westward, toward an alignment with CAISO.
Even greater benefits would accrue from an alignment with other utilities in Western states. This arrangement would allow Colorado to better develop its wind and solar resources for export to other Western states, according to the study. It also facilitates an easier transition to meet Colorado’s targeted greenhouse gas emissions. It would produce a 1,000-megawatt increase in wind and solar in Colorado along with 70,000 new jobs by 2040 in the electricity sector.
The general gist of this is not new, but this study offers a greater level of detail and authority than was previously available.
A press release from Vibrant offered statements from the chief executives of the two electrical cooperatives who funded the study. They indicated hope that thestudy triggers more rapid movement toward creation of an RTO or its sibling, an ISO (independent system operator).
“Using this study as a guide, Colorado can improve transmission access and tariffs within its borders before all electricity companies join the same Energy Imbalance Market,” said Bryan Hannegan, CEO of Holy Cross Energy.
“The key is to have fixed or zonal transmission tariffs across Colorado with all entities having equal access to a system developed through coordinated regional or statewide planning,” said Patrick Mooney, chief executive of Intermountain.
Both electrical cooperatives have relationships with Xcel Energy but are weaning themselves. They both depend, in part, upon Xcel for supply of electricity. Both depend upon Xcel for transmission. And both are part-owners with Xcel of Comanche 3, the coal-unit completed in 2010 at Pueblo. Intermountain owns 25% of the coal-burning unit and Holy Cross 8%. Holy Cross, however, has assigned its output to Guzman Energy, a wholesale provider.
And both electrical cooperatives have set out to shift their generation sources. That necessarily brings in questions of transmission and associated costs. Transmission lines are not like interstate highways, where you just get on and drive. They’re more like toll roads. Getting electrical generation from the giant wind farms of eastern Colorado to consumers on the Western Slope can involve three or more tolls. The electrical co-ops believe there’s a better way.
Holy Cross has set out to decarbonize its electricity through a program called Seventy70Thirty, which aims for 70% renewable energy by 2030. This would align roughly with Xcel’s current plans. But Holy Cross has begun developing its own energy resources, including a wind farm along Interstate 70 east of Denver that will, when completed in the next year or two, put it substantially close to achieving that goal.
Intermountain looks for options
Intermountain has already asked for proposals to supply its power once its current power-purchase agreement with Xcel Energy’s subsidiary, Public Service Co. of Colorado, ends in late 2025.
With that in mind, said Mooney, his cooperative wants to advance an RTO. “We see (it) as important to the integration of renewable energy and necessary to maximize efficient use of generation and transmission resources. Several of the large players, Xcel included, are in no hurry to see an RTO in the region, public statements to the contrary notwithstanding,” he wrote in an e-mail response to questions.
In a follow-up email, Mooney elaborated: “My view is that Xcel and Tri-State are really only giving lip service to an RTO at this point; neither wants to create an environment in which currently captive load for their generation may be able to go to a market. They also like to control their respective transmission systems, and Xcel’s plan is to grow by expanding its transmission and generation rate base, a plan that could be threatened by an RTO,” he wrote.
“Xcel, Platte River Power Authority and Colorado Springs Utilities like the EIM (energy imbalance market) arrangement, as all profit from it, but it doesn’t have the benefits we would see from an RTO. None of those parties has been willing to lift a finger legislatively to support an RTO. Indeed, all have opposed efforts to bring players to the table through legislation.”
Intermountain, he said, proposed legislation in 2019 and again this year and has been working with several legislators. “Of course, there are real limits to what the state can do, and it’s not even clear what direction (east or west) would be best in the long run,” he wrote in an e-mail in response to questions.
The Vibrant study was commissioned by Holy Cross, he explained, “and we agreed to participate expecting some work product to educate people about the subject.”
State Sen. Chris Hansen, a legislator heavily involved in energy legislation and an ardent supporter of organization of an RTO, suggested in a recent video-conference meeting he might be interested in sponsoring legislation to give utilities encouragement to engage in energy markets. See: Why Colorado needs an RTO
Good data for regulators, legislators
At Holy Cross, Steve Beuning, vice president, power supply and programs, said there are no specific plans to seek a legislative prod to creation of an RTO. But neither is the study purely academic.
“If we are going to inform regulators and legislators about the benefits of a regional development, we need a model that has a clear view of the entire landscape and not just the interests of an individual utility,” he said in an interview.
Vibrant, he said, has modeling for the entire North American grid, including the wind and solar capacities down to a resolution of three kilometers. “I am not aware of any utility in the United States that has that level of modeling detail,” he said. Most model only for their own service territories.
Beuning explained that electrical transmission of wind or any other electric resource can pass across lines of three or even five different operators. An RTO dismantles those barriers. Think of it being something like an Epic or Ikon ski pass, good at many ski areas.
Another comparison is to roads. You don’t have to pay tolls three or four times as you cross Colorado. And in the United States, you can travel anywhere with one state’s license plates.
The following is a contributed article by Colorado State Senator Chris Hansen, D, and Doug Howe, director at the Western Grid Group and a former commissioner with the New Mexico Public Regulation Commission.
Since the inception of the Federal Power Commission — the predecessor to FERC — there has been an important and valuable “struggle” between regulators and the regulated. In the early to mid-1900s it was about conflicts over hydroelectric power siting and regulation of interstate natural gas sales. Today, it is about how to balance the transition of the electricity grid from fossil fuels to renewables with grid resiliency while protecting ratepayers. To do so, regulators and developers must also navigate a patchwork of state regulations, emissions reduction goals, and localized utility territories.
Utilities logically want what’s best for their bottom line, environmental advocates want zero-carbon energy, and ratepayers want low electricity bills and customer choice. While many might consider these goals incompatible, there is a path forward that achieves a desirable outcome for all parties: regionally coordinated transmission organizations.
Progress toward an RTO, or an incremental step in that direction, such as an energy imbalance market, should not be conflated with electricity sector deregulation, as a recent Utility Dive opinion piece has done. Reforming wholesale markets through RTOs and reforming the retail part of the electric system are two very different issues, with two very different goals.
Regionally coordinated, competitive wholesale power markets are inherently efficient, create savings for consumers and create opportunities for low-cost, low-carbon, reliable power to meet consumer needs. On the other hand, the goal of retail deregulation is consumer choice, which might or might not result in lower prices or cleaner electricity portfolios than could occur in the regulated utility context (though it has generally resulted in better consumer satisfaction according to reports by J.D. Power).
In an RTO, bidding processes determine which power plants are the most cost-effective and get to dispatch their power. Contrast that idea to what we currently have, where utility monopolies dominate states in the West and Southeast and there are no market forces to dictate which power plants are the least-cost power providers. Additionally, RTOs should not be confused with exertion of more government control — in fact, RTOs are open free markets that manage the costs for the consumer. It is not surprising that utilities in non-RTO regions that have high cost power plants (e.g., coal) want to avoid the cost-discipline inherent in RTOs.
The competitive nature of a regionally coordinated market drives down both utility and consumer costs. The western energy imbalance market has exceeded $1 billion in gross benefits to customers since its launch in 2014. Experts estimate that a southeastern regional transmission organization could save $348 billion by 2040. Even FERC’s own estimates show that RTOs will save hundreds of billions of dollars.
Everything Old is New Again, the previous Utility Dive opinion piece, implies that state leaders lose control of their state energy policies in an RTO. This is not true and has never been true of an RTO, and the West is perhaps the best example of states collaborating in a wholesale market while pursuing very diverse state-led energy policies.
Whether you agree with their energy policy or not, California certainly stands as the prime example of a state with strong, state-led energy policies and a well-functioning RTO. Other western states, with state energy policies as diverse as Wyoming and Washington, successfully participate with California in the Western Energy Imbalance Market with significant savings to consumers in every state in which it operates.
RTOs do not solve all problems that the regulators and the regulated will face in the transition to a carbon-free grid, and they should not be sold as such. What they will do is produce real savings for consumers by instituting market discipline, and eliminate unnecessary cost burdens created through transmission tariff pancaking that restricts the flow of lower cost renewable energy across regions.
To say that reliability, affordability and innovative grid investments are best supported through traditional regulatory structures misunderstands both the problem and the solution. A coordinated grid and regional power markets are inevitable not only because of the many benefits, but because it will help resolve many of the rifts between regulators and the regulated.
John Adams famously said, “try and fail, but don’t fail to try.” Clearly, the traditional energy regulatory structures are an outdated solution to a modern problem. We have an opportunity to take lessons learned from existing regional markets and create structures that will benefit consumers and utilities. It will be those that try that will shape the solution, while those that fail to try will have to find a way to fit in, at a potentially great cost.
Electric Cars Could Save California’s Power Grid
December 7th, 2020 by Nexus Media
California is doubling down on electric vehicles (EVs). Critics say more plug-in cars will strain the power grid. Here’s why they’re wrong.
Originally published on Nexus Media News.
Climate change ramped up its attacks on California this year, serving up massive wildfires and blistering heat waves, which led to widespread power outages. To fight back, Governor Gavin Newsom took aim at heat-trapping carbon pollution from cars. In September, he signed an order to phase out the sale of new gas-powered cars in California by 2035.
The move earned praise from green groups, but critics say that millions of new electric vehicles will further strain California’s power grid, which is already buckling under the stress of worsening heat waves. In a letter to Governor Newsom, outgoing EPA Chief Andrew Wheeler asked how California can expect to service a massive fleet of EVs when it “can’t even keep the lights on today.”
In their response to Wheeler, California environmental officials said that electric cars “support a more reliable, resilient, and affordable grid. Indeed, electric transportation and increasingly cleaner electricity go hand-in-hand.”
On this point, experts agree. They say that EVs can charge up when demand is low, making use of surplus wind or solar power that might otherwise go unused, and they can unplug when demand peaks. In the future, EVs could even sell electricity back to the grid when needed, helping to prevent blackouts when the grid is overwhelming, such as during a heat wave.
“There’s ample supply in California to charge lots of electric vehicles,” said Camron Gorguinpour, director of mobility solutions at ENGIE Impact, a clean-energy consulting firm. The challenge, he said, is making sure EVs charge at the right time.
Today’s more sophisticated EV chargers can fuel cars when power is most abundant and prices are lowest. Drivers can set their cars to juice up overnight — for instance, after most people have gone to bed and the grid is flush with cheap power. This helps make sure that EVs don’t overload the grid when demand surges, usually in the late afternoon or early evening. Some chargers allow drivers to fuel up only when power falls below a specified price.
“You would want to plan to have your electric vehicles charging overnight or in the early hours of the morning when air conditioning isn’t peaking on the system,” said Samantha Houston, a vehicles analyst at the Union of Concerned Scientists.
In the future, EVs will have a two-way relationship with the grid. Some EVs are already able to discharge electricity. In Japan, the Nissan LEAF can supply backup electricity in an emergency—enough to power a home for two to four days. Someday, EVs will be able to sell electricity to the grid.
“This isn’t a magic technology that doesn’t exist,” Gorguinpour said. “Virtually every automaker is doing something on what we call ‘offboardable power.’”
Federal regulators recently cleared the way for drivers to sell power to the electric grid, though hurdles remain. EV manufacturers will need to update vehicle warranties to allow for this use, Houston said. Tesla’s warranty currently doesn’t cover damage from “using the vehicle as a stationary power source.” Grid operators will also need to install safety controls to prevent EVs from overloading the grid, Gorguinpour said.
Conceivably, EVs could help supply needed power during heat waves, Houston said. EVs could also come to the rescue during wildfire season, when grid operators shut off electricity in wooded areas to prevent power lines from sparking fires. Homeowners could use their EVs as a backup power source.
California Independent System Operator CEO Steve Berberich told reporters that in order to prevent blackouts during future heat waves, the state needs to build out more clean power and batteries. The California Energy Commission is now updating its Vehicle-Grid Integration Roadmap with that in mind.
The International Renewable Energy Agency projects there will be 160 million EVs on roads around the world by 2030. Those EVs can work with renewables, charging up on surplus solar power during the day and surplus wind power at night. By buying electricity that would otherwise go unused, EVs will make wind and solar plants more valuable, Gorguinpour said.
The Parker Project, an EV pilot program in Denmark, is exploring how plug-in cars can support renewables. As part of its work, it’s developing a certificate that automakers can apply to cars that cooperate with the power grid, an important step in shifting to clean energy. Grid-smart EVs have the potential to make our power supply cleaner, more reliable and more resilient.
“We just need all vehicles doing something,” Houston said. “They don’t have to do it all the time, but we need every vehicle doing something beneficial.”
Jeremy Deaton writes for Nexus Media, a nonprofit climate change news service. You can follow him @deaton_jeremy.
The roadmap to the lowest cost grid is paved with distributed solar and storage
We wanted to know what the grid would look like, and cost, if we stopped ignoring the benefits of DERs and optimized the integration of these resources through a better modeling process. We found that when you use better planning models and scale both local solar and storage, as well as utility-scale solar and wind, you maximize cost savings and unlock the path to the lowest cost grid.DECEMBER 3, 2020 JEFF CRAMER
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For months now we have heard President-elect Joe Biden tout the job and economic growth that would come from transitioning to a clean electric grid. We’ve also heard from critics who say the new clean electric grid he is proposing will cost upwards of $2 trillion.
These assumptions about costs are misguided, as are other widely-held assumptions about a clean electric grid. Transitioning to a clean electric grid could actually cost less money and save us billions of dollars, create jobs, and result in a cleaner, more reliable grid across the United States.
We found that when you use better planning models and scale both local solar and storage, as well as utility-scale solar and wind, you maximize cost savings and unlock the path to the lowest cost grid. In fact, it could generate nearly half a trillion dollars in savings to ratepayers over the next 30 years.
In recent years, myriad studies conducted in more than twenty states have tried to evaluate the net value of distributed energy resources (DERs) like local solar and storage. While these studies have been used to influence the implementation of tariffs for DERs on a limited scale, none have been able to project those costs and benefits at scale into total system planning processes — in the all-important capacity expansion and production cost modeling that underpins utility system resource planning. In fact, most grid and system planning processes aren’t equipped to consider resources based on their total costs and benefits to the entire system. That’s because they analyze the grid in a piece-meal fashion in distribution, transmission, and generation modules, lack exhaustive data inputs, and can’t fairly consider smaller resources like DERs.
We wanted to know what the grid would look like, and cost, if we stopped ignoring the benefits of DERs and optimized the integration of these resources through a better modeling process aimed at a true least-cost development plan for the entire grid. So we engaged Dr. Christopher Clack of Vibrant Clean Energy to apply his advanced and big-data friendly WIS:dom(R) model to the task. What we found surprised even us.
What did we do?
We had the model compare multiple scenarios: 1.) a “dumbed down” scenario that mimics traditional models by only considering and weighing cost impacts from a central transmission-level grid perspective; 2.) a scenario that integrated and optimized for distributed solar and storage assets located closer to the customers; and 3.) a scenario that sets a clean electricity target of 95% reduction in carbon emissions in each state by 2050 from 1990.
The model spent days crunching data, analyzing over 1.5 trillion data points across every county in the continental U.S., down to a resolution of a single kilowatt, three square kilometers, and intervals of just five minutes—the fine resolution necessary to reveal distributed resource benefits. The model’s ability to work at this detailed scale solved for the complex resource choices that system planners face in the real world, reconciling costs and options across technologies, sizes, and locations.
What did we find?
Not surprisingly, the model built a lot of solar, wind, and storage—over 1,000 GW (a terawatt) of solar and over 800 GW of wind by 2050. What surprised us was how and where it built these resources and why that accounted for hundreds of billions of dollars in potential savings.
The model found that by scaling local solar and storage at the distribution level and closer to customer load, we don’t have to over-rely on the most expensive parts of the transmission system and under-utilize the distribution system as many traditional planners assume. The daily peaks that the system must ramp up and down to serve can be permanently and more cost-effectively managed by local solar assets, storage injections, and off-peak charging. These DERs cost-effectively reshape the load as seen by the large-scale grid, reducing bulk power system costs and smoothing volatility and variation in load across the system. This allows for a more efficient overall allocation of investments, and a more flexible and local electricity system through the addition of 247 GW of distributed solar and 160 GW of distributed storage by 2050.
(Average summer month utility-scale generation and distribution demand in business as usual vs. DER integration and optimization)
And how much does it cost?
Just by integrating and optimizing distributed solar and storage, we found potential for over $300 billion in grid savings. When we asked the model to also meet a 2050 clean electricity target, we found $473 billion in grid savings versus a clean electricity grid that doesn’t scale distributed solar and storage. And finally, and most notably considering current discussions around President-elect Biden’s clean electricity plans, the model found that a clean electricity grid that scales local solar and storage is $88 billion less expensive than maintaining the status quo. These savings are driven by reduced grid costs alone and do not include the massive societal benefits that also come with more local solar and storage.
On top of saving the grid lots of money, deploying more community and rooftop solar and storage will result in massive economic benefits, including jobs, and additional social and environmental indirect benefits. While this analysis didn’t account for these indirect benefits in resource selection, the model did calculate that a clean electricity grid that scales local solar and storage would result in over 2 million jobs by 2050.
But you may ask: if we’re seeing per unit costs for utility-scale solar and wind at less than five cents per kilowatt-hour, why not just build more of that and avoid the higher per-unit costs of local solar and storage? Embedded within the results of this analysis, we found that the lowest cost bulk renewables are optimized when local solar and storage are optimized as well. Analyzing resources on their per unit cost alone is misguided and misleading, and when you run a better analysis that chooses resources based on their net cost to the entire system, you achieve the lowest cost system with a portfolio of resources with varying per unit costs. The sub five cent wind alone still requires the ramping of gas combustion turbines and additional transmission, and the local solar alone still requires capacity support from the bulk power system. But together, they can deploy the maximum efficient amount of bulk power and local power to deliver the lowest cost system for all.
So how can we realize these savings?
As an analogy, while navigating with paper maps is of course still possible, we know there are better, more efficient maps that use modern technology and more and better data to get us where we need to go. If we want to build the lowest cost electric grid that serves the needs of all customers in ways that can adapt to the challenges of a new era, we must evolve the tools we are using in the electricity sector as well.
For too long we’ve used outdated tools, methodologies, and thinking, with too few actors in mind to inform our thinking about how we build a better electricity system. Using new tools that take advantage of technology and big data, we find that a local, clean electric grid isn’t as expensive as we thought—and far more local, too. It turns out we can build a clean grid that empowers consumers and strengthens communities with distributed solar and storage. We can build a grid that leverages private investment while also reducing overall costs on all customers. We can build a grid that increases resilience. And we can build a grid that improves the equity of our electricity system.
So what do we need to do to bring these benefits to life?
Policymakers should apply the outputs of this advanced modeling to all energy policy decisions today. They should demand better planning and analysis that focuses on the most tangible solutions right away, and let the data-driven results guide their decision making on everything from planning, to RPSs, to interconnection, equity, and local solar programs like community solar. They should also establish clear and consistent policies and programs that scale local solar and storage right now, because if we continue on our current trajectory of distributed solar and storage deployments, we will not be able to achieve the maximum cost savings uncovered by our analysis.
We have a data-driven roadmap to the lowest cost grid of the future. Now is the time we must start building and let the benefits start accruing. Because if we’re not saving ratepayers money, then we’re costing them money. We simply cannot afford to wait.
Jeff Cramer is the executive director of Coalition for Community Solar Access, a coalition of businesses and non-profits advocating for expanding access to solar energy through community solar.
The views and opinions expressed in this article are the author’s own, and do not necessarily reflect those held by pv magazine.
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