The Brattle Group provides consulting services and expert testimony in economics, finance, and regulation to corporations, law firms, and public agencies. It hires internationally recognized experts, and has had strong partnerships with leading academics and highly credentialed industry specialists around the world.The Brattle Group has offices in Cambridge, Massachusetts, San Francisco, Washington, DC, New York, NY, Rome, Madrid and London. Wikipedia.
News Article | November 28, 2016
CHICAGO, Nov. 28, 2016 /PRNewswire/ -- Without the Quad Cities and Clinton nuclear plants in Illinois, consumers would pay $364 million more annually and over $3.1 billion more over the next ten years (on a present value basis) in electricity costs. Annually, this equates to $115 million...
News Article | March 4, 2016
New research suggests that in the future, one of the most lowly, boring, and ubiquitous of home appliances — the electric water heater — could come to perform a surprising array of new functions that help out the power grid, and potentially even save money on home electricity bills to boot. The idea is that these water heaters in the future will increasingly become “grid interactive,” communicating with local utilities or other coordinating entities, and thereby providing services to the larger grid by modulating their energy use, or heating water at different times of the day. And these services may be valuable enough that their owners could even be compensated for them by their utility companies or other third-party entities. “Electric water heaters are essentially pre-installed thermal batteries that are sitting idle in more than 50 million homes across the U.S.,” says a new report on the subject by the electricity consulting firm the Brattle Group, which was composed for the National Rural Electric Cooperative Association, the Natural Resources Defense Council, and the Peak Load Management Alliance. The report finds that net savings to the electricity system as a whole could be $ 200 per year per heater – some of which may be passed on to its owner – from enabling these tanks to interact with the grid and engage in a number of unusual but hardly unprecedented feats. One example would be “thermal storage,” which involves heating water at night when electricity costs less, and thus decreasing demand on the grid during peak hours of the day. Of course, precisely what a water heater can do in interaction with the grid depends on factors like its size or water capacity, the state or electricity market you live in, the technologies with which the heater is equipped, and much more. “Customers that have electric water heaters, those existing water heaters that are already installed can be used to supply this service,” says the Brattle Group’s Ryan Hledik, the report’s lead author. “You would need some additional technology to connect it to grid, but you wouldn’t need to install a new water heater.” Granted, Hledik says that in most cases, people probably won’t be adding technology to existing heaters, but rather swapping in so-called “grid enabled” or “smart” water heaters when they replace their old ones. In the future, their power companies might encourage or even help them to do so. Typically, a standard electric water heater — set to, say, 120 degrees — will heat water willy-nilly throughout the day, depending on when it is being used. When some water is used (say, for a shower), it comes out of the tank and more cold water flows in, which is then heated and maintained at the desired temperature. In contrast, timing the heating of the water — by, say, doing all of the heating at night — could involve either having a larger tank to make sure that the hot water doesn’t run out, or heating water to considerably higher temperatures and then mixing it with cooler water when it comes out to modulate that extra heat. Through such changes, water heaters will be able to act like a “battery” in the sense that they will be storing thermal energy for longer periods of time. It isn’t possible to then send that energy back to the grid as electrical energy, or to use it to power other household devices — so the battery analogy has to be acknowledged as a limited one (though the Brattle report, entitled “The Hidden Battery,” heavily emphasizes it). But the potentially large time-lag between the use of electricity to warm the water and use of the water itself nonetheless creates key battery-like opportunities, especially for the grid (where utility companies are very interested right now in adding more energy storage capacity). It means, for instance, a cost saving if water is warmed late at night, when electricity tends to be the cheapest. It also means that the precise amount of electricity that the water heater draws to do its work at a given time can fluctuate, even as the heater will still get its job done. These services are valuable, especially if many water heaters can be aggregated together to perform them. That’s because the larger electricity grid sees huge demands swings based on the time of day, along with smaller, constant fluctuations. So if heaters are using the majority of their electricity at night when most of us are asleep, or if they’re aiding in grid “frequency regulation” through instantaneous fluctuations in electricity use that help the overall grid keep supply and demand in balance, then they are playing a role that can merit compensation. “If the program is well-designed, meaning in particular, you have a well-designed algorithm for controlling the water heater in response to these signals from the grid, then what’s really attractive about a water heating program is that you can run these programs in a way that customers will not notice any difference in their service,” says Hledik. In fact, using electric water heaters to provide some of these services has long been happening in the world of rural electric cooperatives — member-owned utilities that in many cases control the operation of members’ individual water heaters, heating water at night and then using the dollar savings to lower all members’ electricity bills. Take, as an example, Great River Energy, a Minnesota umbrella cooperative serving some 1.7 million people through 28 smaller cooperatives. The cooperative has been using water heaters as, in effect, batteries for years, says Gary Connett, its director of demand-side management and member services. “The way we operate these large volume water heaters, we have 70,000 of them that only charge in the nighttime hours, they are 85 to 120 gallon water heaters, they come on at 11 at night, and they are allowed to charge til 7 the next morning,” Connett explains. “And the rest of the day, the next 16 hours, they don’t come on.” Thus, the electricity used to power the heaters is cheaper than it would be if they were charging during the day, and everybody saves money as a result, Connett says. But that’s just the first step. Right now, Great River Energy is piloting a program in which water heaters charging at night also help provide grid frequency regulation services by slightly altering how much electricity they use. As the grid adds more and more variable resources like wind power, Connett says, using water heaters to provide a “ballast” against that variability becomes more and more useful. “These water heaters, I joke about, they’re the battery in the basement,” says Connett. “They’re kind of an unsung hero, but we’ve studied smart appliances, and I have to say, maybe the smartest appliance is this water heater.” Of course, those of us living in cities aren’t part of rural electric cooperatives. We generally buy our electricity from a utility company. But utilities also appear to be getting interested in these sorts of possibilities. The Brattle Group report notes ongoing pilot projects in the area with both the Hawaiian Electric Company and the Sacramento Municipal Utility District. Thus, in the future, it may be that our power companies try to sign us up for programs that would turn our water heaters into grid resources (and compensate us in some way for that, maybe through a rebate for buying a grid-interactive heater, or maybe by lowering our bills). Or, alternatively, in the future some people may be able to sign up with so-called demand response “aggregators” that pool together many residential customers and their devices to provide services to the grid. And as if that’s not enough, the Brattle Group report also finds that, since water heating is such a big consumer of electricity overall — 9 percent of all household use — these strategies could someday lessen overall greenhouse gas emissions. That would be especially the case if the heaters are being used to warm water during specific hours of the day when a given grid is more reliant on renewables or natural gas, rather than coal. Controlling when heaters are used could have this potential benefit, too. Granted, these are still pretty new ideas and the Brattle Group report says they need to be studied more extensively. But as Hledik adds, “I haven’t really come across anyone yet who thinks this is a bad idea.”
News Article | March 17, 2016
Earlier this month, I attended the 2016 Electric Reliability Council of Texas (ERCOT) Market Summit. The summit brought together thought leaders and stakeholders to discuss the future of Texas’ electric grid. Many of the discussions at the conference centered around the expected boom in new solar and wind energy capacity in Texas, and how ERCOT is planning to cope with the evolution of its electric grid and market as more and more renewable energy is added. While Texas will add a lot of new wind and solar capacity over the coming years, the grid operator is more than prepared to manage the reliability of the electric grid into the future. Even More Wind Energy on the Horizon Since the early 2000s, Texas has emerged as the national leader in wind energy. Last year, Texas sourced 11.7 percent of its electric energy from wind, with wind eclipsing nuclear energy, which provided 11.3 percent, for the first time ever. On an instantaneous basis, wind energy has provided about 45 percent of electric power on more than one occasion. On December 20 of last year, wind peaked at 44.7 percent of total power generation and provided about 40 percent of instantaneous generation for 17 straight hours. And on February 18 of this year, wind peaked at 45.1 percent of total generation and provided roughly 40 percent of instantaneous power generation for the entire day. Texas isn’t done adding wind energy yet. Over the next two years, Texas is expected to add more wind energy than ever before thanks in part to the declining cost of wind turbines and the extension of the federal wind energy production tax credit, which gives wind energy an extra 2.3 cents for every kilowatt-hour of energy produced. With all of the new anticipated wind energy capacity, expect Texas to continue breaking wind energy integration records for the foreseeable future. For the first time, wind energy isn’t the only form of renewable energy expected to see significant growth in Texas over the coming years. Thanks to steadily decreasing costs for utility-scale solar plants and the extension of the federal investment tax credit, which covers 30 percent of upfront investment costs, Texas is expected to add 1,725 megawatts of new utility-scale solar capacity between now and 2017 — increasing the total amount of solar capacity installed more than six-fold. All of the anticipated solar installations in Texas are solar farms that use photovoltaic panels to convert sunlight directly into electricity. ERCOT doesn’t track the amount of solar capacity installed in the form of rooftop photovoltaic panels, so there might be even more solar energy installed than meets the eye. A New Market Design for the Future Texas benefits from a large fleet of flexible natural gas generation that has the capability to balance the output from wind and solar energy with the rest of the electric grid with relative ease. However, as the amount of wind and solar capacity increases, there will be less and less flexible generation available on a real-time basis to compensate for the additional intermittency introduced by wind and solar energy. Fortunately, ERCOT is already in the midst of a major electricity market redesign to ensure electric reliability even as wind and solar make up a larger and larger share of total electricity generation. To operate the grid reliability, it is important to perfectly balance electricity supply with demand in real time. Today, this balance is maintained by flexible generators that provide “ancillary services,” which refers to a collection of services procured by the grid operator to maintain electric reliability no matter what. ERCOT ancillary services consist of “regulation” (generators that adjust their output to maintain the second-to-second balance between supply and demand), “responsive reserve” (generators that are spinning and ready to supply power in case of a contingency), and “non-spinning reserve” (generators that are offline but ready to turn on in a pinch if needed). All of these services are procured in the market and are part of the total cost we pay for electricity. Beginning with a concept paper released in 2013, ERCOT proposed a newly designed ancillary services market better able to cope with rising solar and wind energy intermittency as conventional generation makes up a smaller share of overall generation. The new design proposes unbundling balancing services traditionally provided by fossil generators into separate services that more adequately address the needs of a heavy-renewable grid and are compatible with new grid-balancing technologies like energy storage. The newly designed ancillary services market doesn’t just help integrate wind and solar energy, it also makes the electricity market more economically efficient overall by breaking up conventional ancillary services into their component parts. An independent analysis from the Brattle Group, widely considered a thought leader in electricity markets, found that ERCOT’s proposed future ancillary services market would provide $137 million in cost savings over the next ten years, or ten times the anticipated implementation cost of $12 to $15 million. Texas Set to Lead the Way With lots of solar and wind energy on the horizon, and a new electricity market design in the works, Texas is set to continue its role as a leader in the integration of renewable energy with the grid. This might come as a surprise considering the state’s frequent legal battles with the federal government over environmental regulations. It just goes to show how the technology-agnostic nature of competitive markets can lead to renewable energy growth even where local government is against carbon dioxide regulations of any kind.
News Article | October 4, 2016
Wind power is an success story, both in Texas and throughout the U.S. Recent commentary in the MIT Technology Review shares several captivating stories about the ways wind power benefits communities across Texas. Wind supports well-paying jobs and stable income for farmers and ranchers, provides a drought-proof cash crop they can rely on when the rains don’t fall or the fields don’t produce. However, Martin’s final written product also gets some things wrong about wind power’s technology. This fact check clears up those misunderstandings. The strongest electricity system is one that uses a diversity of generating sources. That way, if one source fails another one remains online to help pick up the slack. That keeps both the lights on for consumers and protects their wallets against price spikes from declines in energy supply. That’s exactly what happened during 2014’s Polar Vortex weather event, when the extreme cold knocked several conventional plants offline. Because wind energy kept reliably generating electricity during the frigid cold spell, it helped save consumers across the Great Lakes and Mid-Atlantic regions over $1 billion in just two days. Likewise, this Bloomberg article reports when New York’s Indian Point nuclear plant suddenly went offline this past December, “Wind turbines in the state came to the rescue, running close to capacity and compensating for the loss of the reactor.” We’ve also seen the benefits of a diversified electricity mix in Texas. ERCOT (grid operator for most of the state) data show the cost of wind’s variability is lower, in both total and dollar/megawatt hour (MWh) terms, than the cost of accommodating conventional power plant failures. That’s because wind plant output changes gradually and predictably, so the changes can often be accommodated using inexpensive offline power plants (non-spinning reserves) that can start up over 10-30 minutes. In contrast, conventional power plants fail abruptly, requiring the use of expensive, fast-acting reserves. Nor is there a difference in the quality of the electricity wind farms produce; wind plants exceed the ability of conventional power plants to regulate voltage and frequency. ERCOT regularly uses wind plants’ fast and accurate frequency response control as the primary tool for keeping system frequency stable as electricity demand and supply fluctuate. Wind plants meet far more stringent standards for riding through voltage and frequency disturbances, standards that cannot be met by conventional power plants. Using their sophisticated power electronics, wind plants quickly and accurately regulate voltage, in many cases even when the turbines are not producing power. Wind power is one of the biggest, fastest, cheapest ways to cut carbon pollution As the nation’s largest energy user, it shouldn’t come as a surprise that Texas would have high carbon dioxide (CO2) emissions. And that’s been exactly the case. By a large margin, Texas’s carbon emissions have been the country’s highest for decades. The more relevant factor is that those emissions are trending downward, as the state moves to wind generation and other low-carbon forms of energy. This downward trend has continued despite a large increase in overall electricity consumption in Texas (driven by population growth, increased electricity demand for oil and gas production, etc). The emissions intensity (CO2/megawatt hour (MWh)) of Texas electricity has been declining even more dramatically, as shown by this data from the Energy Information Administration. Because wind is one of the biggest, fastest, cheapest ways to cut carbon pollution, it makes sense that Texas’s carbon emission intensity would decrease as more wind power comes online in the state. Indeed, wind energy in the Lone Star State cuts nearly 5.5 million cars’ worth of CO2 pollution every year. Updating transmission pays for itself and saves consumers money Modernizing America’s electricity grid to meet 21st century needs benefits all sources of electricity generation, and doing so often creates significant consumer savings. For example, Americans could save up to $47 billion on the electricity bills every year from better transmission planning, according to analysis from the Brattle Group. Likewise, the Southwest Power Pool, a grid manager in 14 states, reports that transmission upgrades would save $800 for each of its customers over the next four decades. Similarly, the Midcontinent Independent Systems Operator, which manages the grid in another 15 states, found improvements could save each person it serves $1,000 in the coming years. That’s why other parts of the country are following Texas’s lead, including much of the Midwest, from Oklahoma west to Colorado and Wyoming, north to the Dakotas, and east to Illinois and Indiana, all areas all with very good wind resources. Texas has recognized that transmission pays for itself, and has always spread the cost of transmission for all energy sources across all users of the power system. A strong transmission system is essential for a free electricity market, as a congested power system hinders competition. The reality is all U.S. energy sources receive government incentives, and wind has received a small portion of the overall amount. Since 1950, wind has accounted for less than 3 percent of all federal dollars spent on energy incentives, while fossil fuels and nuclear have led the way at 65 percent and 21 percent, respectively. The reality is the more wind power has grown, the more Americans like it. Today, wind energy is widely deployed in 40 states, and places like Iowa, Kansas and South Dakota use wind to generate at least 20 percent of their electricity. Overall, a dozen states use to wind to generate at least 10 percent. Voters in these states realize wind brings economic development, well-paying jobs and new revenue streams to their communities. That’s why a recent poll found 91 percent of likely voters favor expanding wind power. While some may persist in spreading outdated or misleading information, the truth is wind a clean, reliable affordable solution for millions of American families and businesses.
News Article | December 16, 2016
LITTLE ROCK, AR--(Marketwired - December 16, 2016) - On Dec. 7, America commemorated the 75th anniversary of the bombing of Pearl Harbor. Nine days later, an organization in Little Rock, Ark., will likewise celebrate 75 years of existence. On Dec. 16, 1941, in support of the American war effort, 11 electric utilities agreed to pool their resources to keep power flowing to Jones Mill -- an aluminum production facility outside Malvern, Ark. President Franklin Roosevelt's wartime goal to produce 50,000 airplanes per year had created the need for huge quantities of aluminum, and Jones Mill's operation would require 120 megawatts of power -- exceeding its home state's installed capacity of 100 MW at the time. From the utilities' partnership, Southwest Power Pool (SPP) was formed, and the new organization was successful in pooling power to support the plant. After the war, SPP continued as a leader providing safe, reliable power to U.S. homes. SPP today is a regional transmission organization (RTO): a not-for-profit, federally regulated service organization that ensures the reliable operation of a portion of the nation's power grid on behalf of its member companies, with more than 50,000 MW in capacity. SPP describes itself as the air-traffic controller of the power grid. Air-traffic controllers do not own the airports in which they operate or the planes they direct but are responsible for ensuring air travelers depart, fly and land safely. Similarly, SPP does not own the power stations it directs or the transmission lines across which electricity flows in its footprint, but it partners with generators, transmission owners, municipalities, power marketers, state and federal agencies, electric cooperatives and others to ensure the cost-effective and reliable delivery of power across a 14-state region. Though SPP works at the wholesale level and thus doesn't directly serve end users and ratepayers, it does benefit them. A recent study conducted by SPP and validated by the Brattle Group showed transmission investments in the SPP region had, on average, a benefit-to-cost ratio of 3.5-to-1. That means every dollar spent to build or upgrade transmission lines throughout SPP's region will ultimately produce $3.50 in electricity production cost savings and other benefits. In addition to planning transmission infrastructure, SPP facilitates the sale and purchase of electricity through its Integrated Marketplace, a wholesale electric market. SPP's marketplace launched in 2014 and has since reduced the cost of electricity in the organization's region by more than $1 billion. These and other services provide net benefits to SPP's members in excess of $1.4 billion annually at an overall benefit-to-cost ratio of more than 10-to-1. For the typical end-use customer using 1,000 kWh per month that means $68 of benefits a year at the cost of just 62 cents monthly. Or, put another way, without the services SPP provides its members, a ratepayer's $100 electric bill would be $105.65. Throughout its 75 years, SPP has evolved and grown from an affiliation of 11 companies with a common goal in 1941 to an organization employing about 600 professionals in support of nearly 100 member companies across a region spanning from the Canadian border in the north to Louisiana in the south and from southeastern Missouri to northwestern Montana. SPP attributes its legacy of success to the strength of its stakeholder relationships. In the foreword to a book published this year chronicling SPP's history, its President and CEO Nick Brown said, "Reliability is job one for SPP. We exist to help our members keep the lights on, today and in the future. We do so not through hard work, innovation or efficiency, though each is a necessary component of our success. For SPP, reliability is accomplished through strong, healthy relationships with those we serve." Because of the strength of those relationships, its legacy of success and deliberate focus on continuous improvement and building consensus among its members, SPP has every reason to think its future is just as bright as its history. Southwest Power Pool, Inc. manages the electric grid and wholesale energy market for the central United States. As a regional transmission organization, the nonprofit corporation is mandated by the Federal Energy Regulatory Commission to ensure reliable supplies of power, adequate transmission infrastructure and competitive wholesale electricity prices. Southwest Power Pool and its diverse group of member companies coordinate the flow of electricity across 60,000 miles of high-voltage transmission lines spanning 14 states. The company is headquartered in Little Rock, Ark. Learn more at www.spp.org. Acciona Wind Energy USA, LLC; American Electric Power (AEP Oklahoma Transmission Company, Inc.; AEP Southwestern Transmission Company, Inc.; Public Service Company of Oklahoma, Southwestern Electric Power Company); Arkansas Electric Cooperative Corporation; Basin Electric Power Cooperative; Board of Public Utilities of Kansas City, Kansas; Boston Energy Trading and Marketing, LLC; Calpine Energy Services, L.P.; Cargill Power Markets LLC; Central Power Electric Cooperative, Inc.; Cielo Wind Services, Inc.; City of Coffeyville; City of Independence, Missouri; City Utilities of Springfield; Clarksdale Public Utilities Commission; Cleco Power, LLC; Corn Belt Power Cooperative; CPV Renewable Energy Company, LLC; Dogwood Energy, LLC; DTE Energy Trading, Inc.; Duke Energy Transmission Holding Company, LLC; Duke-American Transmission Company, LLC; Dynegy Power Marketing, Inc.; East River Electric Power Cooperative, Inc.; East Texas Electric Cooperative, Inc.; EDP Renewables North America LLC; El Paso Marketing Company, LLC; Enel Green Power North America, Inc.; Entergy Asset Management; Entergy Services, Inc.; Exelon Generation Company, LLC; Flat Ridge 2 Wind Energy, LLC; Golden Spread Electric Cooperative, Inc.; Grain Belt Express Clean Line LLC; Grand River Dam Authority; Harlan Municipal Utilities; Heartland Consumers Power District; Hunt Transmission Services, LLC; ITC Great Plains, LLC; Kansas City Power & Light Company (KCP&L Greater Missouri Operations Company); Kansas Electric Power Cooperative, Inc.; Kansas Municipal Energy Agency; Kansas Power Pool (KPP); Lafayette Utilities System; Lea County Electric Cooperative, Inc.; Lincoln Electric System; Louisiana Energy and Power Authority; Luminant Energy Company, LLC; Mid-Kansas Electric Company, LLC; Midwest Energy, Inc.; Midwest Gen, LLC; Missouri Joint Municipal EUC; Missouri River Energy Services; Mountrail-Williams Electric Cooperative; Municipal Energy Agency of Nebraska; Nebraska Public Power District, NextEra Energy Resources, LLC; NextEra Energy Transmission, LLC; Noble Americas Gas & Power Corp; Northeast Nebraska Public Power District; Northeast Texas Electric Cooperative, Inc.; Northwest Iowa Power Cooperative; NorthWestern Energy; NRG Power Marketing, LLC; OGE Transmission, LLC; Oklahoma Gas and Electric Company; Oklahoma Municipal Power Authority; Omaha Public Power District, Plains and Eastern Clean Line LLC; Prairie Wind Transmission, LLC; Public Service Commission of Yazoo City; Public Service Company of Oklahoma; Rayburn Country Electric Cooperative; Shell Energy North America (US), L.P.; South Central MCN, LLC; Southwestern Electric Power Company; Southwestern Power Administration; Sunflower Electric Power Corporation; Tenaska Power Services Co.; Tex-La Electric Cooperative of Texas, Inc.; The Central Nebraska Public Power & Irrigation District; The Empire District Electric Company; Transource Energy, LLC; Transource Missouri, LLC; Tri-County Electric Cooperative, Inc.; Tri-State Generation and Transmission Association, Inc.; Westar Energy, Inc. (Kansas Gas and Electric Company); Western Area Power Administration - Upper Great Plains Region; Western Farmers Electric Cooperative; Williams Power Company, Inc.; Xcel Energy (Southwestern Public Service Company, Xcel Energy Southwest Transmission Company, LLC); XO Energy SW, LP.
News Article | December 16, 2016
The new projects will carry clean, low-cost energy to millions of Americans. After eight years of review from federal agencies, the Bureau of Land Management (BLM) has approved routes for two new transmission projects which will carry renewable energy across the mountain west, desert southwest and California. U.S. Secretary of the Interior Sally Jewell also inked a formal agreement with California Gov. Jerry Brown to bolster wind, solar and geothermal projects after the presidential transition next month. The TransWest Express, first outlined in 2007, stretches 730-miles from the proposed Chokecherry and Sierra Madre wind farm in Wyoming through Utah and Colorado, reaching the extensive energy appetite of Las Vegas. Adding 3,000 megawatts (MW) of transmission capacity, the three-year construction project is predicted to create 1,500 jobs each year, according to BLM. More than half of the lines will cross BLM-managed land. The second transmission project approved by BLM, Energy Gateway South, will be developed by PacifiCorp and boasts an estimated 1,500 MW capacity. Beginning in Southeast Wyoming, the transmission lines will connect to Mona, Utah. Together, the two projects could support more than 26,000 construction and operations job, according to BLM. “These efforts strengthen our commitment to work with state and local communities to unlock the West’s abundant renewable energy resources, create jobs and support development that makes sense for both the economy and the environment,” Secretary Jewell said. The new transmission lines will offer an abundance of clean energy to Western consumers, and it may help some states, including Utah, Colorado, Nevada, Arizona and California, reach their Renewable Portfolio Standards. Studies show that transmission projects like these more than pay for themselves. Similar upgrades in the Southwest Power Pool and Midcontinent Independent Systems Operator saved customers between $800 and $1,000 each, while the Brattle Group found consumers could save up to $47 billion every year from improved transmission planning. Since 2009, BLM has approved 11 new wind energy projects. BLM also plans to develop a wind resource mapping tool to streamline the process of identifying sites with the highest wind energy potential and lowest environmental risk. Combined with the new transmission routes, these wind energy projects and tools may help the nation reach 20 percent electricity from wind by 2030. That will create more jobs and bring more low-cost energy to millions of Americans, and expanded transmission will play a key role in making it happen.
News Article | November 5, 2016
For the last ten years, more and more people have been buying solar panels and installing them on their roofs. Companies like Elon Musk's SolarCity have flooded the market with cheap home solar deals, relying heavily on federal and state subsidies and creative loan agreements to keep prices low. In fact, just last week Mr. Musk revealed home solar panels that look like designer Italian shingles. Over the years, these rooftop solar systems have been great buys, at least from an economic standpoint, for a lot of homeowners. But what many of these solar customers don't realize is this: their rooftop solar purchases have likely been slowing, not increasing, the overall rate of solar penetration in this country, while also causing numerous cross-subsidies and distortions in power markets. Fortunately, there is a new, more efficient (and more equitable) form of residential solar power hitting the market in many cities across the country. And it doesn't require you to install solar panels on your roof. It's called shared (or community) solar. And in the right form, it's likely to spread like wildfire. In fact, just last month, I signed my home up for my local utility's shared solar program. Here's how it works. Instead of installing a small solar system on your roof, you sign a contract to pay for a portion of a large, utility-scale solar installation that the utility builds and operates for you somewhere else (in my case, on top of a big commercial building just outside of my hometown of Madison, Wisconsin). The utility still gets to earn a rate of return on the solar plant (as it would with any plant it owns and operates). So the utility is happy. I get greener, more efficient utility-scale solar power without having to put anything on my roof. So I'm happy. The exact details on the customer's end differ depending on your utility. But in my shared solar contract, I paid for 10% of my portion of the solar plant's capital costs up front. I also locked in—for the next 25 years—an electric rate for the solar power (12 cents per kWh) that is only about a penny higher on a per kWh basis than my current residential electric rate. And there is a pretty good chance that this locked-in solar rate will be substantially lower than what my utility charges over the next twenty-five years. Shared solar systems offer many advantages over home rooftop solar systems. Rooftop solar is much less efficient; generally speaking, if you take a rooftop solar panel and put it into a utility-scale, shared solar system, it will produce more power. This is primarily due to siting considerations—people don’t build their homes so that their roofs are optimally positioned (i.e., south- or west-facing) to capture solar energy, whereas utilities can site solar farms in a manner that maximizes the amount of energy they produce. Utilities also do a better job of cleaning and maintaining the systems to optimize performance. In fact, according to a recent Brattle Group study, rooftop solar is about twice as expensive on a per kWh basis as utility-scale solar, mainly due to these inefficiencies and economies of scale. Putting solar panels on your house also causes all kinds of distortions in power markets. Because virtually all states have a policy called net metering, a homeowner that installs solar panels on his or her roof gets to directly offset the power generated with the power their home consumes. This might sound reasonable, but it's not.
News Article | August 11, 2016
Studies show transmission pays for itself and then some. Studies show that expanding America’s electricity grid to meet 21st century needs more than pays for itself, and can even result in significant consumer savings. Improved transmission planning could save American families and businesses up to $47 billion every year, according to a recent white paper from the Brattle Group. However, some groups remain unaware of these findings, wringing hands and missing the forest for the trees by focusing on upfront costs and ignoring long-term benefits. The latest attacks focus on the Competitive Renewable Energy Zones, or CREZ lines. Built to relieve congestion on the Texas grid, the CREZ lines have been a major success. They allowed Texas to more than double the amount of wind energy it can transmit from the low-population northern and western parts of the state to large cities like Dallas, Austin, San Antonio and Houston. As a result, Texas now has more wind capacity under construction than any other state, providing a nearly $10 billion investment in the state’s economy. These transmission lines, and all others planned in the state, passed rigorous cost-benefit tests showing they will pay for themselves in a matter of years by providing consumers with access to lower-cost energy. Recent analysis showed that continued growth of wind power can save Texans $15 billion on their electric bills through 2050. Texas has always correctly recognized that a strong transmission system is essential for the state’s free market for electricity, as a congested grid allows monopoly pricing and other uncompetitive outcomes. Transmission benefits all users of the power system by providing greater access to low-cost energy and improving electric reliability, so Texas has always broadly allocated the cost of that transmission. Through the CREZ line process, Texas wisely pioneered the policy of pro-actively planning transmission to access high-quality renewable resources, as the timing mismatch between the long time to build transmission and the short time to build wind projects had prevented either from moving forward. It should also be clarified that the transmission lines currently being developed in the Texas Panhandle were part of the initial CREZ proposal. Moreover, other lines being built in the Rio Grande Valley of southern Texas are being constructed to reliably meet the electricity growth in the region, with an added benefit that new wind capacity will be able to use those lines. Some have raised concerns that additional transmission will be needed going forward, based on the speed at which the existing CREZ lines have been successfully fully subscribed. As the state examines the best way to cost-effectively diversify its energy mix and reduce carbon emissions, the success of CREZ offers a compelling option for the path forward. As we have explained in the past, new transmission more than pays for itself by improving electric reliability and reducing consumers’ electricity costs. Upgrades to America’s obsolete and congested transmission grid are needed anyway, and the benefits from bringing new clean energy sources online are just another reason to expand the grid. Transmission accounts for around 10 percent of a typical electric bill. However, the costs of building new transmission are more than offset by reduced energy costs (which account for the majority of the typical electric bill) by providing access to cheaper sources of energy. The Southwest Power Pool (SPP), a grid operator for Kansas, Oklahoma, Nebraska and nearby states recently conducted a study to quantify the consumer and reliability benefits that resulted from transmission upgrades it performed between 2012 and 2014. Among SPP’s findings were: The Midcontinent Independent System Operator (MISO), a grid operator for all or parts of 13 states throughout the Midwest, also conducted analysis whose findings mirrored SPP’s. MISO found transmission upgrades currently underway will result in: Building transmission to move wind-generated electricity from the best resource sites to the towns and cities where energy demand is highest is not a new concept. In the past, we built railroads to transport coal and pipelines to move natural gas, and in many cases we built transmission to deliver low-cost fossil, hydropower, and nuclear electricity. Now it’s time for the next chapter in our country’s energy story, and new transmission is necessary if we want to realize America’s full energy potential. Focusing only on the up-front cost of transmission, without looking at ongoing benefits that quickly repay initial investments, presents a misleading picture of transmission assets’ value, which will provide benefits for generations to come.
News Article | February 15, 2017
Since mid-2016, the challenges facing the nation’s nuclear fleet have only grown more pressing. Natural gas prices, despite recent volatility, remain very low, keeping nuclear revenues in competitive electricity markets low. Nuclear plants continue to announce retirement decisions, with the 2.2 MW 2-unit Indian Point retirement by mid-2021 being especially notable considering its current profitability. More than 10% of the U.S.’s 2010 nuclear fleet is now retired or scheduled to retire within the next 8 years. Faced with the loss of the largest zero carbon electricity source in the country, states are taking the lead in maintaining struggling nuclear facilities. Since New York finalized its ZEC program, Illinois has provided similar targeted nuclear support as part of broader energy legislation. Other states are considering following suit. While state action may be the most likely policy solution for struggling nuclear units, regional or federal policy solutions offer different and more comprehensive changes. Increasingly, regulatory power over utility-scale electricity generation has shifted from the states to FERC. The evolving regulatory roles of state commissions, ISOs, and FERC constrain and inform any major policy efforts to address the challenges facing the nation’s nuclear fleet. As we discussed in Part 2, this shifting regulatory landscape limits how state legislatures and PUCs address nuclear retirements in individual states. At the same time, the new regulatory landscape provides the opportunity for policy solutions at the regional and federal level. The U.S. Congress, ISOs, regional programs, and FERC together can all play unique roles in limiting retirements of existing nuclear facilities. In key ways, regional and federal solutions are qualitatively different from the state solutions analyzed in part 2: Critically, the ‘higher’ the regulatory avenue used, the more nuclear facilities and general power plants that are effected. Most states only have a handful of nuclear reactors, making it possible to micro-target struggling nuclear reactors even if it brings charges of favoritism. Comparably, regional and federal regulatory authorities have many nuclear reactors under their oversight. Due to political and regulatory constraints, any actions these regulators take may have to benefit all nuclear units, potentially increasing retirement prevention costs. The effects of any policy will be different for deregulated and rate-regulated nuclear units. Parts 1 and 2 highlighted the key differences between these two types of reactor compensation. A quick recap: Of the two, deregulated reactors face the most pressing retirement risks. Nevertheless, many rate-regulated reactors face major retirement risks in 5-15 years without policy action. In this article, we review four potential energy policies that operate primarily on the regional or federal level that could stem the tide of nuclear retirements: This is the third article in a three-part series on existing nuclear electricity generation in the United States. Part 1 discusses major economic and policy challenges. Part 2 examines several specific actions states can take to prevent nuclear retirements. This article (Part 3) examines potential regional and federal policy solutions. Of the seven competitive wholesale electricity markets (ISOs) in the United States, four have some type of capacity market construct: PJM, ISO-NE, NYISO, and MISO. These markets only emerged relatively recently and are still being actively designed. Although the rules behind each capacity market are complex, the concept is simple: While energy only markets compensate generators for energy provided to the grid, capacity markets compensate generators for promising to provide capacity when dispatched by the ISO. Effectively, capacity markets substitute for the traditional role of state regulators in long term system planning. Capacity markets work to maintain long term grid reliability and adequate resource supply. Energy-only markets maximize for short term operation and, due to price volatility and market cycles, will often not provide sufficient revenue to keep power plants open in the short term even if they are economic in the mid or long term. By providing revenues up to three years in the future, existing capacity markets provide some long-term certainty for market revenues (the extent is debated). In the markets where they exist, prevailing capacity prices can thus shape overall market outcomes. Indeed, they already have. Around half of retired or retiring nuclear reactors are in the three ISOs with the most developed capacity markets: PJM, NYISO, and ISO-NE. Most states in these three ISOs are deregulated. These nuclear units almost exclusively receive revenue from energy and capacity markets. Capacity markets are still being developed, are somewhat controversial, and have notable limitations.They are not markets as most people think of them; rather, they are administrative auctions. Based on ISO-developed and FERC-approved rules, grid operators run their own capacity auction processes. They determine the amount of capacity needed in the target year, receive bids for supplying that capacity, and determine the ultimate capacity clearing price. Typically, if a generator clears the auction, they are required to generate electricity when called upon by the grid operator. They receive capacity revenues in a $/MW-time period format. The rules governing capacity auctions often play as much role in setting prices as competitive bids do. The ISOs determine what level of capacity needs to be procured, generator eligibility, under what conditions suppliers can provide the capacity, how the auction price is determined, and more. In most capacity auctions, most plants plan on continuing to operate no matter what. They are price takers, meaning that there are only a handful of plants bidding competitively into the auctions. Hence the rules of the auction effectively determine the revenues the generators receive. ISO-NE provides a stark example: in the first seven capacity auctions in ISO-NE, ISO-wide capacity prices cleared at the administrative floor. Two of the retired or retiring nuclear units in the country are in ISO-NE, making low capacity revenues a key factor in those specific retirements. New England’s remaining plants face some of the highest retirement risks in the country. There are several ways that capacity markets could be reformed to help address existing nuclear retirements: Any changes that occur in capacity markets need to recognize the rapidly changing technologies in electricity. Existing capacity markets are still young and developing, focused on economic efficiency, and were (effectively) limited to only thermal units. New and emerging energy technologies, particularly renewable energy and energy storage, will challenge overall market design and capacity markets specifically. Due to their major economic ramifications for generator revenues and customer costs, the policy process to drive changes in capacity markets is complex and contentious. The economic challenges facing some nuclear reactors in the short term and most reactors in the long-term boil down to one problem: insufficient cost competitiveness with non-nuclear plants due to both ‘true’ competition and market design. In deregulated markets, lower electricity prices greatly reduce revenues for existing nuclear plants; in rate-regulated markets, low natural gas and renewable prices can offer lower cost (and potentially lower risk) alternatives. Government subsidies for nuclear plants could address nuclear plants’ lack of cost competitiveness in both types of electricity markets. In energy world, the term “subsidies” is often used widely with many definitions depending on the context. For purposes of this article, we refer to subsidies in a narrow sense: a subsidy is a direct government transfer from taxpayers used to meet some specific public policy objective. This definition includes direct grants or tax credits but would not include something indirect or intangible, like the debated Price Anderson ‘subsidy’. In both deregulated and rate-regulated markets, subsidies increase plant revenues. In deregulated markets, subsidies directly increase a plant’s competitiveness in the market; at current market prices and nuclear costs, the most vulnerable nuclear plants would be profitable at a moderate subsidy. In rate-regulated markets, subsidies increase the relative cost competitiveness of existing nuclear reactors during commission and utility decision-making. A nuclear subsidy can be implemented at either the state or federal level. Either the relevant state legislature or Congress would need to pass legislation. Administratively, subsidies are relatively straightforward with limited technical complications. The government decides on what basis to provide money: the plant’s capacity, its generation, or some financial metric like investment or operating costs. Most likely, any nuclear subsidy would probably be in $/MWh, like existing production tax credits. Perhaps more than any other potential nuclear solution, subsidies for existing nuclear generation are likely to face significant political opposition. There are several major considerations that likely make subsidies infeasible: Of these five, the last is a major limitation. A general principle of US energy regulation (derived from the broader economy) is that consumers should be responsible for all costs associated with their service. Reality is far from this ideal. Nevertheless, this principle underlies the rate-shifting concerns of the net metering debates as well as environmental regulations that internalize external costs. Unlike every other solution presented in this series (excepting perhaps nationalization), subsidies would violate this principle by shifting the cost burden to taxpayers. Subsidies are often more visible and transparent than regulatory actions as they come directly from the legislature, as opposed to PUCs or the ISOs. The prospect of taxpayers subsidizing ratepayers is likely to engender significant political opposition to any existing nuclear subsidy. From a legal standpoint, additional obstacles come into focus; planners must be careful in crafting government-sponsored subsidies. Where subsidies are found to be discriminatory, they are potentially illegal, and so basic risk management could require that subsidy programs be applied to every nuclear plant in a jurisdiction. For states, this might mean a nuclear plant or two would receive unnecessary subsidies to keep other plants online. A national nuclear subsidy would similarly provide revenues to the whole nuclear fleet, even though only nuclear units in restructured markets are most at risk. As existing nuclear plant’s current challenges are largely economic, increasing energy prices indirectly via imposing a carbon tax on fossil generation could be ideal: Carbon pricing can be implemented at almost any level of energy policymaking: state, regional, and federal. There are two major carbon pricing schemes in the US today: California’s cap and trade system and the Northeast’s Regional Greenhouse Gas Initiative. Unlike subsidies, the financial effects of carbon pricing can depend on a nuclear plant’s regulated environment. In all deregulated wholesale markets, carbon prices increase fossil prices which are on the margin, increasing energy prices and driving higher revenues for nuclear facilities. Meanwhile, in rate-regulated markets, carbon prices make fossil generation less attractive compared to existing nuclear units but do not directly affect plant revenues. Whereas subsidies in a rate-regulated market lead to more revenue for nuclear units, a carbon price would not. Over the short to mid-term, a moderate carbon price would likely be sufficient to keep all but the most uneconomic reactors online. Brattle Group recently estimated a $12-20/ton CO2 tax would be sufficient to prevent most additional retirements. Over time, the carbon price would likely need to rise: While carbon pricing is promising, it has so far proven ineffectual at prevent nuclear retirements. More than half of retired or retiring nuclear reactors are already located in areas subject to cap-and-trade (RGGI and California C+T). With natural gas (not coal) dominating the margin in these markets, carbon prices in both of these trading schemes have been too low to sufficiently increase power prices to benefit struggling nuclear facilities. The low carbon prices in RGGI and California arise from differing circumstances. In RGGI, policymakers have consistently set the cap too high, making CO2 permits especially cheap. In California, complementary policies reduce carbon reductions required from the cap and trade scheme, also reducing CO2 permit prices. Politically, carbon pricing may be the most promising regional or federal solution presented in this article. Unlike other policies, it offers a strong opportunity for nuclear owners to coalition build with non-nuclear interests. It is favored by regulators, industry, and many politicians. It will not happen nationwide in the current administration, but regional efforts may continue and a national carbon price may be inevitable. While carbon pricing may be a more politically acceptable solution, it still faces political opposition that make it unlikely in the short term. Tightening RGGI or California’s carbon cap could help nukes in those specific markets but may be politically unviable; excess existing permits may keep prices depressed regardless. Perhaps the most radical policy proposal to keep the U.S.’s nuclear fleet online calls for government ownership and management of the U.S. nuclear fleet. In short, this option involves nationalization of private nuclear facilities in varying degrees. Although this idea generated considerable interest, there has been limited discussion as to what it would look like in practice. Nationalization occurs when a national government takes control of an existing private entity. In modern times, the US has practiced both temporary nationalization (AIG and General Motors) and permanent nationalization (Amtrak and TSA). To use nationalization as a policy solution for struggling nuclear units, the federal government would purchase or take ownership of one or more existing nuclear units. Critically, nationalization does not mean the government is forcing a mandatory purchase of a nuclear facility. The federal government (via an appropriate agency) could negotiate with a nuclear plant owner on a fair price to purchase the plant voluntarily. If such negotiations proved unsuccessful, the federal government could seize ownership of one or more existing nuclear reactors using its power of eminent domain. In such a case, the government would need to compensate the owner of the nuclear reactor at a market rate. Either a voluntary or mandatory nationalization program almost certainly require an act of Congress to grant authority and supply any necessary funding. To a certain degree, nationalizing the nuclear fleet is not as radical as it might first sound. The federal government has significant technical, operational, and even institutional expertise in nuclear power: One of these units, Watts Bar 2, was the first new nuclear unit to come online in two decades in the US last year. Beyond nuclear power, the federal government already owns and operates much of the nation’s hydropower. Four Federal Power Marketing Administrations marketed 42% of the nation’s existing hydropower in 2012. Once the government owns some (or all) existing nuclear facilities, the key question is how markets compensate these plants for their generation. The economic challenges facing nuclear do not just disappear if the plants are owned by the federal government. Reduced profit incentives (and reduced borrowing costs) only somewhat reduce required market revenues. Most likely, nationalized nuclear plants would need to be compensated through some sort of cost of service regulation (without a need for a rate of return). If the plants just received market revenues, they would lose money, which would ultimately come from the federal taxpayer. As noted above, regulatory principles generally call for ratepayers to be responsible for compensating electricity costs, not taxpayers. Since Congressional legislation is required for nationalization, Congress could well mandate in that same legislation that nationalized nuclear facilities receive cost of service compensation from wholesale power markets (i.e. ISOs/RTOs). As with other potential solutions, timing is a critical factor. Mandatory nationalization is a longer term option for the nuclear fleet but highly unlikely to occur in either the short or the mid-term (energy and cultural norms would have to change before policy). However, it is possible that a voluntary nationalization program could occur relatively quickly at a targeted scale. Under such a voluntary program, federal power agencies could purchase and then operate select nuclear power plants that would otherwise retire. If structured well, such legislation could minimize direct costs to the taxpayer while also ensuring that nuclear facilities are fully valued for the public goods they provide. The post Addressing the Plight of Existing Nuclear Retirements, Part 3 appeared first on SparkLibrary.
News Article | December 4, 2016
Last Thursday, December 1st, the Illinois State Legislature passed a measure that will allow continued operation of two of the state’s six nuclear power plants. In a nail-biter more reminiscent of overtime at the Super Bowl, the Illinois State Legislature passed The Future Energy Jobs Bill (SB 2814) with less than an hour remaining in the legislative session. The bi-partisan bill allows Exelon’s Clinton and Quad Cities nuclear power plants to remain open, saving 4,200 jobs and over 22 billion kWhs of carbon-free power each year, more than all of the state’s renewables combined. These two plants were in jeopardy of closing because even at a low cost of five cents or so per kWh, they were losing a combined $100 million per year because they could not compete with cheap natural gas and wind energy that is subsidized at 2.3¢/kWh. Illinois taxpayers subsidize solar energy at 21¢/kWh. This bill provides these nuclear plants with just 1¢/kWh, and only until market conditions change. Exelon had drafted a press release announcing the closure of the two plants that was to be issued last night if the bill failed. Instead, these plants will be operating for at least another 10 years, producing over 200 billion kWhs of carbon-free energy. In addition to preserving nuclear energy as a way to support cleaner air, the measure also expands the state’s energy efficiency programs and makes changes to the state’s renewable portfolio standard sought by renewable advocates. The latest version of the bill removed incentives for southern Illinois coal-fired power plants that had been added to draw more support for the legislation. Also cut from the measure was a contentious billing system that based power bills on average peak use instead of overall use. Nuclear power produces over half of Illinois’ electricity, all with no carbon or other polluting emissions. The enormous negative impact of shutting down nuclear plants because of an artificial market finally got through to the Legislature, since the generating capacity of these nuclear plants would have to be replaced by natural gas or coal, doubling the State’s total carbon emissions and ensuring that the state would not meet its emissions goals anytime soon. This is just what happened in New England after the unnecessary closing of the Vermont Yankee Nuclear Power Plant in 2014. Their clean nuclear energy was replaced entirely by natural gas and out-of-state purchases, the local community was devastated economically, and electricity prices have increased. The rise in conventional air pollutants by moving from nuclear to coal or natural gas in Illinois would also have increased premature deaths. A recent study found that the use of nuclear energy worldwide has prevented about 1.8 million premature deaths from fossil fuel pollution, and could prevent up to several million additional ones in the near-future. It’s why China is planning 400 new nuclear power plants by 2040 – they lead the world in coal deaths and really bad air quality since their surge in coal began in 1992. The fate of these Illinois nuclear plants had drawn the attention of the entire country, including the leading climate scientists, since Illinois generates more zero-emissions electricity than any other state, 90% of which comes from nuclear power, and climate scientists are in favor of nuclear power. Earlier this year, a coalition of scientists and conservationists, including famed climate scientist James Hansen, anti-nuclear activist turned nuclear proponent Michael Shellenberger, and Whole Earth catalogue founder Stewart Brand, sent an open letter to Illinois legislators asking them to “do everything in your power to keep all of Illinois’s nuclear power plants running for their full lifetimes.” Even the Sierra Club reluctantly supported this bill. Nuclear plants across the country are at risk of being closed prematurely mainly because they are excluded from federal and state clean energy policies. First, the federal production tax credit subsidy for wind is not available to nuclear energy. This credit sometimes turns wholesale electricity prices negative by encouraging wind farms to overproduce during periods of low demand when no one wants their electricity and it threatens to overload the grid. Nuclear plants must pay to supply the grid during temporary wind surges, while wind farms continue earning money from the tax credit. It appears that individual states are beginning to see the advantages of keeping nuclear power viable. Recently, the New York Public Service Commission adopted a Clean Energy Standard that recognizes the economic and environmental benefits of commercial nuclear energy in that state, allowing two nuclear plants to remain open that were in the same precarious situation as the Clinton and Quad Cities plants. Connecticut faces a similar challenge. “The Future Energy Jobs Bill, now headed to the governor’s desk, preserves more than $1.2 billion in annual economic activity across Illinois, including 4,200 direct jobs at Clinton and Quad Cities and thousands more jobs that the plants support,” said Maria Korsnick, Nuclear Energy Institute’s chief operating officer. “The bill levels the playing field for nuclear energy with other carbon-free energy sources. Between them, the Clinton and Quad Cities facilities prevent the emission of more than 20 million metric tons of carbon dioxide a year.” This is more than twice the emissions of all the cars in Chicago and surrounding suburbs. The long-term savings from not having to replace the electricity supply that Clinton and Quad Cities reliably generate is substantial. A Brattle Group study found that keeping the Quad Cities and Clinton nuclear generating stations would save residential and business consumers $300 million in electricity costs every year they continue running. Illinois Governor Rauner is expected to sign the bill into law quickly. Dr. James Conca is a geochemist, an energy expert, an authority on dirty bombs, a planetary geologist and professional speaker. Follow him on Twitter @jimconca and see his book at Amazon.com