Great River Energy is an electric transmission and generation cooperative in the U.S. state of Minnesota; it is the state's second largest electric utility, based on generating capacity, and the fifth largest generation and transmission cooperative in the U.S. in terms of assets. Great River Energy was formed in 1999 when Cooperative Power Association and United Power Association merged.Great River Energy owns or co-owns more than 100 energy transmission substations in the region. The company's system also includes more than 500 distribution substations. Great River Energy is a not-for-profit cooperative that provides wholesale electricity to more than 1.7 million people through 28 member distribution cooperatives in Minnesota, covering roughly 60 percent of the state. The company also owns transmission lines in North Dakota and Wisconsin. Wikipedia.
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 | April 18, 2016
This article originally posted at ilsr.org. For timely updates, follow John Farrell on Twitter or get the Democratic Energy weekly update. This is part two of a two-part series from our recently released report, Re-Member-ing the Electric Cooperative by myself, Matt Grimley, and Nick Stumo-Langer. Cooperatives across the nation are showing how to rely on each other and their members to create community-centric institutions that can overcome long-term reliance on dirty power sources and member disengagement. With a recent ruling, the Federal Energy Regulatory Commission may have recently crashed one of the biggest gates to the cooperative clean energy party.19 For years, cooperatives have been hitched to wagon of large, coal-fired power generation through all-requirements contracts. A few, like Delta-Montrose Electric Cooperative and other cooperatives went looking for local energy options. Unable to get resolution in direct negotiation, Delta-Montrose took Tri-State to the Federal Energy Regulatory Commission. The request was relatively simple: tell Tri State that it’s required to allow Delta Montrose to buy power from a proposed local hydroelectric power plant, even if it takes a bite out of their contract with Tri-State. Although FERC didn’t accept Delta-Montrose’s rationale, they did accept their conclusion. In requiring electric utilities to purchase renewable power from “qualifying facilities,” FERC said that the 1978 federal PURPA law supersedes the cooperative’s contract.20,21 Delta Montrose must purchase power from small renewable energy facilities in their service territory, and pay at least their own “avoided cost” of energy, e.g. the cost of the energy purchases avoided by the purchase from the qualified PURPA facility. This is a contested issue, with many utilities asserting that this is simply their wholesale cost to purchase a marginal kilowatt-hour of power. On the other hand, a FERC ruling in 2010 allowed that states could set avoided cost rates by technology, on the basis of the differing values of the renewable resources.22 FERC allowed that Delta Montrose could negotiate a power purchase rate. The FERC ruling doesn’t allow Delta Montrose to develop more of its own clean energy resources outside its contractual limits, nor does it change where they get the balance of their energy supply: from Tri-State. FERC noted two potential exceptions to the ruling that did not apply to this particular case. Some distribution cooperatives have transferred their PURPA purchase obligation to their wholesale supplier. In that case the power generator would have to sell to the wholesale supplier (e.g. Tri-State). Some utilities have received a waiver from their purchase obligation under PURPA, but only if there’s a competitive marketplace available for the generator to sell into other than the utility, an unlikely scenario for most cooperatives.23 Tri-State is now requesting FERC that it be allowed to levy a fee on Delta-Montrose for any lost revenues from the cooperative purchasing outside its contract. If they succeed, it will undermine the economics of buying local power for Delta-Montrose.24 However, FERC has opened the door for distribution cooperatives to purchase local power outside their contractual obligations, providing a novel level of flexibility. Several cooperatives are adapting to the new era by bringing energy efficiency and renewable energy closer to home with the help of a federal program, and even a few cooperative ventures of their own. The USDA’s Rural Utility Service’s Energy Efficiency & Conservation Loan Program allows rural utilities to borrow money at low rates – over 30 years at 3.3% – for energy efficiency and renewable energy improvements at their facilities or properties owned by customer-members it serves. The obligation to pay can be tied to the meter, allowing the energy savings and the financial obligation to pass from owner to owner of the property. The bill-based financing can be particularly powerful at reaching disproportionately low-income cooperative members because the financing can be secured by the projected energy savings rather than a member asset (such as their home). It can also be provided without credit scoring that typically eliminates most low-income households from participation. In 2014, the Rural Utility Service authorized as much as $6 billion in loans in 2015. What could $6 billion buy?25 But it’s not just for energy efficiency. What if $6 billion was invested in renewable energy like solar power? The cooperatives can also make money offering this program. The USDA allows utilities to re-loan the money to individuals at up to 1.5% interest above their own borrowing rate of 3.3%. On loans of $6 billion, rural electric utilities would have a margin of $59 million per year re-loaning the money to their members. Roanoke Electric Cooperative has already proven that on-bill financing works well for its membership. Using $6 million in financing from the U.S. Department of Agriculture, Roanoke Electric Cooperative’s Upgrade to $ave program enables members to benefit from debt-free, on-bill financing for home energy upgrades.27 The program will assist 1,000 members-owners over five years, generating savings for all participants and saving the cooperative more than $2 million through reduced energy demand. Households participating in Kentucky’s How$martKY program have lowered their annual energy use by average of 5,500 kWh, a savings of 30%, or $624 a year.28 Other cooperatives with on-bill financing programs report similar savings. Electric cooperatives are also experimenting with community solar projects.29 The total is small — just 92 megawatts (MW), equivalent to only 0.18% of their overall power generation — but cooperatively-owned utilities are much more likely to experiment with collectively-owned generation than their municipal and for-profit peers. Below is a map identifying the 78 community solar projects throughout the country separated by ownership structure. The lion’s share is owned by electric cooperatives. Some cooperatives have also added local renewable generation through their wholesale cooperative generation and transmission provider.30 Great River Energy in Minnesota added a 5 percent self-supply allowance to their members’ all-requirements contracts, anticipating the addition of resources such as community solar gardens. Great River then provided its members with solar, by building and financing up to twenty 20-kilowatt solar arrays in its members’ area. The projects are funded through a lease with CoBank. Each co-op is obligated to pay the G&T for the lease costs and for a buyout at the end of 10 years. For many cooperatives, the ability to add community solar will be the first generation resource that qualifies under the 5 percent option. G&Ts in Wisconsin, Florida, and Michigan have tried other G&T-financed models for local solar development. Other electric cooperatives utilize creative ownership structures to work around contract obligations, such as three cooperatives in Minnesota that actually sell solar energy back to their G&T.31 The cooperative leaders in renewable energy development often work without all-requirements contracts, relying on a mixture of partial-requirement contracts, wholesale market purchases, and energy project ownership instead. Farmer’s Electric Cooperative, which purchases half of its energy from the wholesale market, uses a homegrown feed-in tariff, community solar, and a green power purchasing program that have encouraged one-fifth of its membership to participate in renewable energy projects.32 The Kauai Island Utility Cooperative in Hawai’i now receives close to 40 percent of its energy from utility-owned and member-owned renewable resources while stabilizing sky-high electric rates.33 The Southern Maryland Electric Cooperative has built 5.5 megawatts of solar, and is proceeding on another 10 megawatt project, to go along with close to 1,000 of its members either owning or waiting to install some form of distributed generation. The New Hampshire Electric Cooperative, hitting their net metering cap that would limit rooftop solar, determined it was in their members’ best interest to permanently lift the cap. They lowered the compensation rate by 25 percent for residential customers (although they increased it for commercial customers) and will allow more rooftop solar development.34 At Jackson Energy Cooperative, Randy Wilson’s landslide loss wasn’t for naught. Proxy votes were outlawed shortly after the election in 2009.35 On-bill financing was instituted at the cooperative in 2010 as part of a pilot program with the Mountain Association for Community Economic Development. In 2013, an incumbent board member was defeated by a newcomer. Other cooperatives have also reformed their ways through member-focused efforts. The Pedernales Electric Cooperative survived a scandal, and emerged with reform candidates on its board of directors. A member bill of rights was passed, opening up the elections, nominations, and giving members full access to records and meetings for the first time. The new board members formalized goals for 30 percent renewable energy in power capacity by 2020 and new energy efficiency savings.36 In 2010, community advocates of the Beartooth Electric Cooperative in Montana proposed bylaw revisions after bad management decisions over the coal-fired Highwood Generation Station were exposed.37 As the Highwood deal failed, Beartooth’s G&T cooperative went bankrupt. Beartooth successfully exited the G&T as a result of the settlement, and just last year saw their first rate decrease in a decade. According to the Northern Plains Resource Council, Beartooth is now one of the most transparent and member-responsive cooperatives in the state. Cooperative members across the nation are demanding change and organizing. Groups such as Kentuckians for the Commonwealth have suggested a cooperative members’ bill of rights.38 Georgia Watch, a consumer protection advocacy group, even made a helpful study and checklist to determine if an electric cooperative is truly democratic.39 The Northern Plains Resource Council has made a chart for member-owners to easily see how their electric cooperative is performing (below). The heavy reliance on outsourcing their local authority has resulted in economic strains, tension between the local and generation and transmission cooperatives, and member disillusionment. At its worst, it has placed cooperatives in a nearly untenable net of long-term obligations for dirty and increasingly expensive power or in a scandal of abused member trust. Fortunately, the solution lies in the best of the cooperative movement. Delta-Montrose and other distribution cooperatives are re-taking some of their local authority to emphasize clean and affordable local power generation. Roanoke and other cooperatives are providing low-cost financing to help members reduce energy costs and make the grid more efficient. Beartooth is modeling transparency and member engagement toward more effective stewardship of cooperative resources. Cooperatives may face their greatest challenge since the inception of rural electrification in the 1930s, but with their members, they have the power to overcome. Drive an electric car? Complete one of our short surveys for our next electric car report. Keep up to date with all the hottest cleantech news by subscribing to our (free) cleantech newsletter, or keep an eye on sector-specific news by getting our (also free) solar energy newsletter, electric vehicle newsletter, or wind energy newsletter.
News Article | December 16, 2016
This post made possible by the tireless efforts of ILSR intern Abbigail Feola. She dug up the data, identified the story worth sharing, and wrote the following piece below. Historically, the purpose of both municipal and cooperative utility agencies has been to bring energy services to communities that for-profit corporations thought unprofitable to serve. This philosophy of self-reliance shifted the focus from profit margins towards social goods, and persists today. Municipal utilities are owned by and located in the cities they serve; their primary interest is not the welfare of their investors, but of their city or town. Likewise, cooperatives are owned and run by their members, people with strong social, environmental, financial, and cultural stakes in the activities of the cooperative. But the ways in which municipal and cooperative utilities procure power undermine this ethic of community service and self-reliance. Most municipal utilities have long-term contracts to purchase power from joint action agencies, and cooperative utilities from generation and transmission cooperatives. Utilities pursue these long-term contracts to obtain favorable interest rates and credit ratings from the finance industry. Even the National Rural Electric Cooperative Association states, “Since the wholesale power contract serves as the basic foundation for G&T [generation and transmission cooperative] financing, and since a multiplicity of stakeholders (such as lenders, regulators, or trustees, for example) have approval rights on any modifications to the contracts, it is nearly impossible to side-step the provisions of all-requirements wholesale power contracts in accessing and using power from sources other than the G&T.” In other words, financiers give better deals for financing big, new power plants when the local utilities are legally obligated to buy the power on a very long-term contract. Click here to see an example of one of the long-term contracts The more restrictive and longer the term, the less costly it will be to fund energy infrastructure. But the result of this system is a major restriction of utilities’ abilities to operate flexibly and independently. In many cases, small, local utilities are tied into contracts for increasingly-expensive fossil-fuel power for decades, even when they may have options to procure local, renewable electricity at low cost, or with additional local economic benefits. The loss of local authority, flexibility, and freedom can be solved in whole or part by shifting decision-making authority back to the local level, including expanding options for self-supply. To understand the current state of the industry and how it could be changed, ILSR contacted various cooperative and municipal utilities, the latter under the Data Practices Act, to collect information on their contract lengths and the costs of electricity paid by utilities. The findings show that decades-long contracts and past and current heavy investments in dirty energy are dramatically limiting utilities’ use of cost-efficient and environment-friendly power sources. The electric industry has always made enormous investments, in the billions of dollars, to generate and transmit electricity. Rising investments in transmission and distribution technology, among other factors, have contributed to rising electricity costs. Prior to the last 10 years, rising energy demand allowed utilities to spread these costs over greater sales. But in the past decade, costs have risen while general demand for electricity (measured in kilowatt-hours, or kWh) has been either unchanging or declining. The result is higher costs for consumers. For example, Great River Energy, one of Minnesota’s largest generation and transmission cooperatives, made massive investments in coal plants over the past decade, resulting in rising electric costs. (x)These include nearly 500 million dollars spent constructing the Spiritwood coal-fired plant, which was shut down due to lack of demand. The Southern Minnesota Municipal Power Agency has a similar cost problem. Due to the low costs of wind and natural gas power and the inflexible operating system of its coal plant Sherco 3, according to its 2015 annual report, it is having difficulty recovering the costs of operating the coal plant. Costs are also rising to comply with environmental regulations, rules that utilities have known about for decades. U.S. environmental policy has steadily been progressing towards stricter air quality control since the 1963 Clean Air Act. This trend continues today, as represented by the impending Clean Power Plan (CPP), a shift towards renewable and carbon-free energy sources which Minnesota has already begun putting into action. Because of their past heavy investments in coal (in some cases mandated by the federal government) and current investments in natural gas, municipal and cooperative utilities are at a disadvantage. For example, 78% of the Southern Minnesota Municipal Power Agency’s (SMMPA’s) power is from the coal-fired plant Sherco Unit 3, which was built in 1987. Already, utilities have submitted plans to close Sherco units 1 and 2 in 2023 and 2026, respectively. Unit 3 may not be far behind. These stricter governmental regulations mirror shifting consumer preferences and changing economics. Clean energy technologies (such as wind and solar) are currently outpacing coal in economic efficiency, and are projected to continue to do so, as the price of coal continues to rise. For the North Dakota and Minnesota generation and transmission company Minnkota, rising coal prices were responsible for ten million dollars (or 11% of the total cost increases) of the company’s rising operating costs in just one fiscal year. Such cost increases caused electric prices to rise by 60%. Such rising costs are symptomatic of the continuing conflict between large power providers (with huge sunk costs into aging and costly power plants) and the autonomy and flexibility of local utilities. Increases in demand for renewable and distributed generation, accompanied by unpredictably rising costs of coal and other fossil fuels, make long-term contracts that support centralized generation increasingly burdensome. These lengthy and demanding power purchase contracts are increasingly a millstone around the necks of utilities in the sea of rising costs and dropping sales. Power agencies or generation and transmission cooperatives require decades-long contracts to ensure that they recover their costs for building massive new power plants. These restrict utilities’ choices in power supplies for the duration of the contract; a very, very long duration. The Northern Municipal Power Agency, for instance, has contracts with its members extending as far as 2055, including with the cities of Chaska, Anoka, and Moorhead. The Minnesota Municipal Power Agency, Western Area Power Administration, and the Southern Minnesota Municipal Power Agency all also have contracts extending through 2050. The majority of Great River Energy’s contracts end in 2045 (source: conversation with utility representatives). Not only are such contracts unreasonably lengthy, but generation companies can and often make attempts to stretch them out even further than was originally agreed. For instance, the Florida Municipal Power Association (FMPA) auto-renews its 30-year contracts with its members each year. Many of these contracts are “all-requirements,” mandating that utilities buy the entirety of their power supply from the power agency or generation and transmission cooperative (or the maximum amount that the company can supply). These contracts keep local utilities tied to large investments in dirty power sources, and prevent them from increasing the role of locally-owned and/or locally-procured power generation. Of the twenty-eight cooperative utilities contracted with Great River Energy, twenty were all-requirements, with a five percent allowance for locally owned energy. Other utilities featured smaller allowances or none at all, as was the case with all the Minnesota municipal utilities whose data was available. Although most local municipal and cooperative utilities are tied into long-term contracts, a few had the foresight to avoid being tied down. The Southern Maryland Electric Cooperative (SMECO), which has no contracts with a generation and transmission cooperative, has installed or is in the process of installing a total of 15.5 MW of solar. In 2002, the Kauai Island Utility Cooperative (KIUC) purchased the utility from for-profit Connecticut-based Citizens Communications. Due to the import costs of coal, gas, and other resources on the island, Kauai has faced unique pressures in finding alternative sources of energy. KIUC has set a goal of 50% renewable energy by 2023, and in 2016 reached the mark of 38% renewable energy. The municipal utility in Denton, TX, reached 40% renewable energy supply in 2015. And after the expiration of its contract in 2012, the town of Georgetown, TX, signed contracts for 100% wind and solar electricity to start in 2017. Other municipal utilities are taking similar, self-initiated steps towards renewable generation. The town of Minster in Ohio has utilized its partial-requirements contract to build a solar/storage system consisting of a 3 MW array and a 7 MW battery, which is owned by Half Moon Ventures. Rochester Public Utilities (RPU), the largest municipal utility in Minnesota (footnote 1), has opted not to renew its 1978 contract with the Southern Minnesota Municipal Power Agency (SMMPA) when it expires in 2030. Concordantly, Rochester has set a goal of 100% renewable energy by 2031. Encouraging member leadership and participation in renewable generation is a major part of RPU’s plan: the proclamation states that “[a]t the heart of a successful 100% renewables strategy, it is fundamental to allow open participation in the development and financing of energy infrastructure….” Rochester’s new arrangement interweaves its freedom to choose with renewable energy accessibility, with each motivating the other. Farmers Electric Cooperative is an Iowa cooperative utility that generates 1,500 Watts of renewable power per customer, more than any other utility and more than double the next utility’s solar capacity per customer. Customers with their own solar arrays receive between 12.5 cents (the retail price) and 20 cents per kWh produced, depending on the amount produced and how it compares to their own consumption. The cooperative has also constructed a 750 kW solar array; only 20% of their power comes from coal. This success has been possible because only 30% of FEC’s power is sourced with long-term contracts; the rest is purchased from local generation sources on the spot market. Since few cooperative or municipal utilities can exit their long-term contracts easily, flexibility in the short term may require cooperation with their generation and transmission cooperative or power agency. Such cooperation can allow utilities to reap the benefits of economies of scale and coordinated action without sacrificing the needs and desires of their members and communities. For example, generation and transmission cooperative Great River Energy recently helped twenty of its member cooperatives construct small solar arrays in their communities. On the other hand, GRE constructs and owns these arrays and may be able to use that ownership in future contract extension negotiations. In another case, three local Minnesota utilities — the Freeborn-Mower Electric Co-operative, People’s Cooperative Services, and Tri-County Electric Cooperative — jointly built a solar array that sells power to Dairyland, their generation and transmission cooperative. As economies of scale are usually optimized around the 500 kW to 1 megawatt for solar arrays, planning around designing solar to connect to the distribution network can save wholesale power utilities and their members time and money. Cooperation between local utilities can also achieve cost savings. The Michigan Energy Optimization Collaborative was created by eight cooperatives and four municipal utilities in response to a 2008 law mandating an annual 1% reduction in electricity usage. The Collaborative has streamlined and lowered the cost of compliance through rebates for energy efficient appliances, energy audits, and agricultural programs. With more local negotiating power behind negotiations with power providers, cooperatives are more able to increase renewable energy and efficient usage — or, as in the case of the town of Niles, to break out of a contract early. Niles, a town of 7,000 people located in Indiana, estimates that it has been spending 20-30% above the market cost of power in its current contract. This spurred Niles to partner with ten other utilities to end their contracts with Indiana Michigan Power six years early — in 2020, instead of 2026. By joining forces, these utilities are managing to renegotiate their contract with a large power agency that may have run roughshod over a single utility’s attempt to renegotiate. The International Co-operative Alliance (ICA), an organization founded in 1895 which works to unite cooperatives worldwide, lists autonomy and independence as key principles through which cooperatives can fulfill their commitments to their members. It does so with good reason. The achievements of utilities such as Rochester Public Utilities and the smaller Farmers Electric Cooperative show the abilities of local utilities to act in financially and environmentally wise manners when freed from lengthy, restrictive contracts. The cases of I&M-contracted utilities joining forces to leave their contracts early, as well as three Minnesota utilities’ joint project to sell renewable power back to their power provider, show the successes and potentials of cooperation between local utilities to take on widespread problems. Local utilities, including their members, must continue to work against financial and legal entrapment by power agencies and generation and transmission cooperatives. Despite these mentioned successes, there remains much work to be done for the majority of local utilities, still chained to contracts with steadily increasing costs and few means to mitigate them. For timely updates, follow John Farrell on Twitter or get the Energy Democracy weekly update. Under the Minnesota Statutes Chapter 13, the Data Practices Act, members of the public have rights to access public data free of charge (in certain forms) and in a timely and accessible manner. These rights include the right to have public data explained and presented in an accessible form; to see and have copies of summary data; and many others, including the most basic and essential right to view public data unless there is a law classifying that data as protected, trade secret, or otherwise non-public. While cooperatives are not subject to the Data Practices Act, municipal utilities, as government organizations, are. Unfortunately, we found that there was little to no compliance with this act among municipal utilities. Despite Data Practices Act requests sent to multiple positions (including city clerks, general utility contact addresses, utilities staff members, city council members) associated with more than twenty-five municipal utilities in Minnesota, we received only six responses. The Data Practices Act was explicitly cited in the majority of these communications, and the reasons for rejection included not knowing the inquirer’s political beliefs. We regret this inaccessibility and hope that compliance with the Data Practices Act in the future would allow more thorough research on the energy industries in Minnesota. Here is a link to download the municipal utility contracts that we obtained. It’s worth noting that the barriers we faced may not be unique to Minnesota. Nebraska public utilities are claiming such information is a “trade secret.” Buy a cool T-shirt or mug in the CleanTechnica store! Keep up to date with all the hottest cleantech news by subscribing to our (free) cleantech daily newsletter or weekly newsletter, or keep an eye on sector-specific news by getting our (also free) solar energy newsletter, electric vehicle newsletter, or wind energy newsletter.
News Article | November 3, 2016
Electric vehicle use in the state of Minnesota reduces greenhouse gas emissions (well-to-wheel carbon intensity) by at least 61%, according to a new analysis from the Great Plains Institute. The 61% figure quoted above is with reference to Xcel Energy’s electric mix (in 2015). If the electric vehicle (EV) owner uses 100% renewable energy to recharge their vehicle (through Xcel’s Windsource program, a similar program, or their own PV power system), then this figure can be raised to 95% most of the time. The findings are the result of the Great Plains Institute (GPI) using Argonne National Laboratory’s GREET Lifecycle Model to determine well-to-wheels carbon intensity in Minnesota under a number of different vehicle driving scenarios. The GREET model collects and organizes the results of peer-reviewed science on GHG emissions and is considered to be one of the top “authorities on the measurement of GHGs.” As indicated by the “lifecycle” term, the GREET model “includes exhaustive data on every aspect of energy production and use.” This includes data on fuel extraction, refinement, battery and vehicle manufacturing, fuel shipment and distribution, and automotive engine combustion. Data on the specific energy situation in Minnesota was used by GPI as inputs to better determine the local picture for greenhouse gas intensity of internal combustion engine (ICE) and electric vehicle use in the state. Here are some of the main findings: “Gasoline vehicles in Minnesota emit an average of 465 grams of GHGs per mile (g/mile) when accounting for the full fuel lifecycle, which includes energy used for fuel extraction and refining. In comparison, full lifecycle accounting of an electric vehicle (EV) in Minnesota results in only 183 g/mile of GHGs on Xcel Energy’s 2015 fuel mix. It is interesting to note that because EVs have no tailpipe emissions, all emissions take place upstream, aka at the power plant and during vehicle manufacturing. And although it currently takes more energy to manufacture an electric vehicle and its battery than to build a gasoline automobile, as you can see in the above graph, the emissions from combusting gasoline vastly outweigh those from vehicle manufacturing. “To calculate emissions outside of Xcel’s service territory, GPI used an average snapshot of electricity production on the Midcontinent Independent System Operator (MISO) system, which manages electric distribution across most of the Midwest. Because MISO includes many states that use a higher portion of fossil fuels than Minnesota, an EV that charges on the MISO grid would result in 268 g/mile GHGs, which still marks a 42% improvement over gasoline.” A high percentage of EV owners utilize renewable energy programs offered by their utility — Xcel Energy’s Windsource and Great River Energy’s Wellspring being examples of such programs. A recent survey performed by GPI found that ~56% of regional EV owners take part in these sorts of renewable energy subscription programs. When doing so, EVs create an average of only 21 g/mile of greenhouse gas emissions — all of which relate to battery and vehicle manufacturing. Going by the analysis findings, over an assumed vehicle lifespan of 160,000 miles, the average gas-powered vehicle would be responsible for around 76 tons of greenhouse gas emissions, the average EV would be responsible for somewhere around 29 tons of greenhouse gas emissions, and EV owners who recharge with 100% renewables would be responsible for only around 3.4 tons of greenhouse gas emissions. An interesting but periphery finding of the analysis was that gasoline refined in Minnesota had an average carbon intensity around 10% higher than the US average, owing to the high proportion of product from the Alberta oil sands and the North Dakota shale oil fields. Buy a cool T-shirt or mug in the CleanTechnica store! Keep up to date with all the hottest cleantech news by subscribing to our (free) cleantech daily newsletter or weekly newsletter, or keep an eye on sector-specific news by getting our (also free) solar energy newsletter, electric vehicle newsletter, or wind energy newsletter.
News Article | October 28, 2016
MAPLE GROVE, Minn.--(BUSINESS WIRE)--Dakota Electric Association, along with its power supplier Great River Energy, is pleased to announce a joint solar project that will provide dedicated solar power directly to Dakota Electric’s membership. The 1-megawatt (MW) solar array will be built along Highway 61 in Marshan Township by SoCore, a leader in solar energy development and construction. “We are pleased to announce this significant project,” said Greg Miller, president and CEO of Dakota Electr
Li Y.,Great River Energy
Applied Optics | Year: 2011
Nonparaxial ray tracing is performed to investigate the field scanned out by a single beam through two rotatable thick prisms with different parameters, and a general solution is obtained and then expanded into a power series to establish the third-order theory for Risley prisms that paves the way to investigate topics of interest such as optical distortions in the scan pattern and an analytical solution of the inverse problem of a Risley-prism-based laser beam steering system; i.e., the problem is concerned with how to direct a laser beam to any specified direction within the angular range of the system. © 2011 Optical Society of America.
Li Y.,Great River Energy
Applied Optics | Year: 2011
Nonparaxial ray tracing through Risley prisms of four different configurations is performed to give the exact solution of the inverse problem arisen from applications of Risley prisms to free space communications. Predictions of the exact solution and the third-order theory [Appl. Opt. 50, 679 (2011)] are compared and results are shown by curves for systems using prisms of different materials. The exact solution for the problem of precision pointing is generalized to investigate the synthesis of the scan pattern, i.e., to create a desirable scan pattern on some plane perpendicular to the optical axis of the system by controlling the circular motion of the two prisms. © 2011 Optical Society of America.
Great River Energy | Date: 2015-12-16
Flue gas is a by-product of many energy and industrial plants and is typically emitted through a chimney stack. If the flue gas temperature in the chimney stack drops below the flue gas dew point, condensation of water vapor and acid gases ensues. These gases are very corrosive for chimney stacks designed to operate in a dry condition. The Flue Gas Reheat System of the present invention continuously and proactively manages flue gas chimney stack temperatures above the dew point in order to optimize emission control and effectuate energy efficiency improvements in industrial plants. Waste heat is harvested from the exterior surfaces of existing steam and pollution control equipment through conduction, convection and radiation. This heat is transferred to a working fluid. The working fluid is then directly mixed with the flue gas prior to the flue gas entering the chimney stack to raise the temperature of (or re-heat) the flue gas above its dew point to maintain a dry chimney stack condition. The use of residual or waste heat from throughout the plant and the minimal equipment required to harvest the waste heat reduces the operating cost and improves the overall reliability of the system. This method is useful in many industries, including electric power generation plants and other energy intensive process industries that seek emission control and various boiler and fuel energy efficiency improvements, many of which improvements result in a reduction in normal chimney stack temperature.
Great River Energy | Date: 2011-10-10
The present invention harvests and utilizes fluidized bed drying technology and waste heat streams augmented by other available heat sources to dry feedstock or fuel. This method is useful in many industries, including coal-fired power plants. Coal is dried using the present invention before it goes to coal pulverizers and on to the furnace/boiler arrangement to improve boiler efficiency and reduce emissions. This is all completed in a low-temperature, open-air system. Also included is an apparatus for segregating particulate by density and/or size including a fluidizing bed having a particulate receiving inlet for receiving particulate to be fluidized. This is useful for segregating contaminants like sulfur and mercury from the product stream.
Great River Energy | Date: 2013-10-21
The present invention harvests and utilizes fluidized bed drying technology and waste heat streams augmented by other available heat sources to dry feedstock or fuel. This method is useful in many industries, including coal-fired power plants. Coal is dried using the present invention before it goes to coal pulverizers and on to the furnace/boiler arrangement. Coal can be intercepted on current coal feed systems ahead of the pulverizers. Drying fuel, such as coal, is done to improve boiler efficiency and reduce emissions. A two-stage bed utilized in the process first pre-dries and separates the feed stream into desirable and undesirable feedstock. Then, it incrementally dries and segregates fluidizable and non-fluidizable material from the product stream. This is all completed in a low-temperature, open-air system. Elevation of fan room air temperature is also accomplished using waste heat, thereby making available to the plant system higher temperature media to enhance the feedstock drying process.