Hawaiian Electric Industries Inc.. is the largest supplier of electricity in the state of Hawaii, supplying power to 95% of Hawaii's population through its electric utilities: Hawaiian Electric Company, Inc., Hawaii Electric Light Company, Inc. and Maui Electric Company, Limited. In addition, HEI owns a financial institution serving Hawaii, American Savings Bank. HECO, HELCO, and MECO employ more than 2,000 people. Approximately 20,000 Hawaii residents are shareholders of HECO’s parent company, Hawaiian Electric Industries . The company is headquartered in Honolulu. The net income of the company reached 164 million dollars by the end of 2012 with a yearly revenue of 3.4 billion dollars. Wikipedia.
Hu Y.,University of Hawaii at Manoa |
Kuh A.,University of Hawaii at Manoa |
Kavcic A.,University of Hawaii at Manoa |
Nakafuji D.,Hawaiian Electric Company
Proceedings of the International Joint Conference on Neural Networks
This paper presents a new probabilistic approach of the real-time state estimation on the micro-grid. The grid is modeled as a factor graph which can characterize the linear correlations among the state variables. The factor functions are defined for both the circuit elements and the renewable energy generation. With the stochastic model, the linear state estimator conducts the Belief Propagation algorithm on the factor graph utilizing real-time measurements from the smart metering devices. The result of the statistical inference presents the optimal estimates of the system state. The new algorithm can work with sparse measurements by delivering the optimal statistical estimates rather than the solutions. In addition, the proposed graphical model can integrate new models for solar/wind correlation that will help with the integration study of renewable energy. Our state-of-art approach provides a robust foundation for the smart grid design and renewable integration applications. © 2011 IEEE. Source
News Article | April 7, 2016
Hawaiian Electric Company and Santa Clara-based Varentec, Inc. have announced a strategic partnership to ensure grid reliability and efficiency while allowing more private rooftop solar systems to be added to island grids.
They appear periodically, but predictably -- media reports on state-level debates over net metering that reduce the story to a struggle of irreconcilable and unevenly matched forces. It’s the powerful corporate utilities seeking to block consumer access to rooftop solar and maintain control of the grid, versus the plucky, disruptive solar companies, fighting to bring clean, free power -- and energy independence -- to the masses. Such oversimplification is as misleading as it is counterproductive. Net energy metering -- or NEM, the compensation solar owners receive for the excess power they feed back into the grid -- is part of a much larger transformation now underway in our energy system. The issue is also more complex and multifaceted than most people appreciate. California is a case in point. Under a 2013 law, the California Public Utilities Commission (CPUC) must come up with a plan for net-metering reform by the end of this year. The proceedings on this effort -- including more than 320 documents, all publicly available on the CPUC website -- go back to July 2014, which is just one measure of how complicated the whole process has been. The CPUC’s call for proposals for an NEM “successor” rate plan went out in June of this year, and in response, on Aug. 3, 16 different proposals were posted on the commission’s website. Media reports, however, have focused almost exclusively on the three from California’s investor-owned utilities -- Pacific Gas & Electric, San Diego Gas & Electric and Southern California Edison. Of the remaining 13 proposals, several deal primarily with how net metering or its successor can be used to expand access to solar energy for low-income communities, while others target specific customer classes. The California Farm Bureau Federation asks that, whatever net-metering reform is adopted, it continue to include aggregation -- that is, allowing generation from one solar installation on a farm to be credited to more than one meter. The Federal Executive Agencies, a Department of Defense office that maintains military bases in California, wants streamlined interconnection policies and net metering for solar projects of more than 1 megawatt. Across the board, filings from solar-industry trade groups and advocates argue that to maintain solar market growth and jobs, net metering should be continued pretty much as is -- with a few minor modifications. Arguably, however, the more interesting and thoughtful proposals come from environmental and consumer groups, including the Sierra Club, the Natural Resources Defense Council (NRDC), the CPUC’s Office of Ratepayer Advocates (ORA) and The Utility Reform Network (TURN), a San Francisco-based nonprofit. While all take somewhat different approaches, these proposals tackle the key flashpoints in the debate. They either acknowledge some shifting of grid upkeep costs from solar to non-solar customers or find, somewhat counterintuitively, that rate designs that cut savings for solar customers might not stop market growth. The ORA proposal is the most direct on the cost-shifting issue, which it sees in terms of the evolving economics of solar -- specifically that solar prices are continuing to fall while utility rates are on the rise. The price decreases in the residential solar market are not being passed on to all customers in the form of lower net metering costs, ORA argues in its proposal. FIGURE 1: A Perverse Incentive? Solar Costs vs. NEM Compensation Solar costs fall (top), while retail rates, and NEM compensation, continue to rise (bottom) Source: Lawrence Berkeley National Laboratory, DOE SunShot Initiative “Currently, as retail rates increase, NEM compensation increases, which is a perverse incentive for a declining cost resource,” the ORA proposal says. “The existing NEM tariff is a mechanism that doesn’t account for the explosive growth of solar, the declining costs of solar, the rising California retail rates, and the need for solar customers to share in the costs of the distribution system.” ORA's proposed solution is to continue retail-rate net metering, with an added “installed capacity fee” based on the size of individual installations. The fee would be introduced on a gradually increasing “glide path” linked to total net-metered solar megawatts on the grid. Existing solar customers would be grandfathered in at retail rates, but beginning in 2017, new solar customers would pay a monthly fee of $2 per kilowatt; that is, a customer with a 5-kilowatt system would pay an extra $10 per month. The fee would rise to $5 per kilowatt between 2020-2025, and then to $10 between 2022-2027, depending on when the market reaches certain benchmark levels of net-metered solar. FIGURE 2: The ORA Plan -- A "Glide Path" for Solar Fee Increases Source: Calif. Office of Ratepayer Advocates Customers in each tier would lock in the fee they pay for 10 years, based on whatever the rate is at the time their solar is installed. At the end of that time, they would pay whatever the current rate is. The Sierra Club also proposes that net metering at retail rates continue, but based on time-of-use (TOU) rates that would vary electricity prices -- and hence credits to solar customers -- depending on the time of day they feed their excess power onto the grid. For example, excess solar generated at midday, when demand is low, would be credited at a lower rate than solar fed back to the grid during a late afternoon or early evening peak. Using market simulation models revised from the standards developed by the CPUC, the Sierra Club was surprised to find that neither TOU rates nor the likely expiration of the 30 percent federal Income Tax Credit (ITC) at the end of 2016 affected potential increases in residential solar installations. Still, the club’s proposal discounts these projections and instead echoes a proposal from the NRDC that no changes be made to net metering until 2019 to give the residential market time to absorb the loss of the ITC. California law calls for the new rates to go into effect in July 2017, and with the law’s year-end deadline for a final ruling looming, the question now is how or whether the CPUC will be able to synthesize the varying proposals into a single workable compromise. The Hawaii PUC offered another approach in its Oct. 12 ruling establishing a menu of NEM reform options based on the specifics of the state’s high-penetration solar market, high electric rates and likely adoption of energy storage and other advanced technologies going forward. Solar customers will be able to choose a net-metering option that pays them about 50 percent of Hawaii’s high retail rates for power they feed back into the grid. Option 2 is self-consumption -- that is, pairing solar, storage and other energy management technology so customers can use all the power they generate to cut their bills, without feeding any back into the grid. A third possibility will be a time-of-use rate, to be developed by the Hawaiian Electric Company, the state’s main investor-owned utility. Certain to be closely watched, the Hawaiian model underlines the fluid situation that regulators, utilities, solar companies and consumers now face on net metering and a range of associated issues. Any solution or suite of solutions adopted today will evolve along with ongoing changes in technology, utility business models and customer demand. The transitions ahead will, by their very nature, create uncertainty for utilities and solar companies, both of which have large financial interests and thousands of jobs at stake. But achieving our common goal -- clean, reliable and affordable power for all -- will depend on a collaborative, rather than divisive, approach to the issues, recognizing their complexity and ensuring that all stakeholders are well informed and all voices are heard. This piece was originally published at SEPA's utility solar blog and was reprinted with permission. K Kaufmann is communications manager for the Solar Electric Power Association. She previously covered renewable energy projects and policy in California for The Desert Sun in Palm Springs. She can be reached at firstname.lastname@example.org.
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 | September 7, 2016
Many know that rooftop PV penetration in Hawaii far surpasses almost anywhere else in the world. Given the state’s 100% renewables mandate by 2045, the pace to explore and quickly implement renewable energy in Hawaii has exposed many challenges and has forced them to the “bleeding edge” of the newest technologies. This forced progress now includes accelerated installation of various forms of energy storage, particularly at the grid-edge. This situation underscores the growing importance of cost-effective and scalable energy storage and its synergy to greater solar generation. Importantly, a draft NARUC Distributive Energy Resources Compensation Manual says: “Energy storage can be used as a resource to add stability, control, and reliability to the electric grid. Historically, storage technologies have not been widely used because it has not been cost competitive with cheaper sources of power, such as fossil fuels. However, given the recent decline in cost as well as improved storage technologies, storage has become an option that is able to compete.” Our answer is focus your study on Hawaii, because of all the locations across the planet, Hawaii is transitioning faster than anywhere else from a huge and risky over dependency on imported fossil fuels, particularly for electricity generation. That was the strategy that our company committed to (PDF) just 4 years ago, and it paid off as Hawaiian Electric began deploying our smart water heater solution about a year ago as its very first residential behind-the-meter real-time energy storage. For perspective, Hawaii is heavily dependent upon oil and gas for its electricity. In past years, total oil imports cost the average person in Hawaii as much as $3000/person/year, but as crude prices dropped by more than half, the money bleeding out of the islands also receded. Hawaiian Electric’s regulatory filings show that its price for low sulfur fuel oil prices dropped from $135.10/bbl in August 2014 to the current $58.44/bbl. For residential customers on Oahu, that collapse in oil prices took their $0.367/kWh electricity rate in August 2 years ago to $0.267 today. In other words, the drop in price of imported oil converted to a drop of $50/month in the monthly electricity bill for an average customer using 500 kWh/month. Not so coincidentally, the incredible rise in oil prices that peaked in 2008, and again in August 2 years ago, spurred a torrent of legislative and regulatory activity in Hawaii. For instance, in 2007, Hawaii became the second state in the nation to set a binding cap on greenhouse gas (GHG) emissions through Act 234, a policy to reduce GHG emissions statewide to 1990 levels by the year 2020. Hawaii’s Renewable Portfolio Standard (RPS) that was established in 2001 was amended during the 2006 legislative session to require that 20% of electricity sales be produced from renewable resources by 2020. In June 2015, Governor Ige signed a bill strengthening Hawaii’s commitment to clean energy by directing the state’s utilities to generate 100% of their electricity sales from renewable energy resources by 2045. As further background, the Hawaiian Islands have 6 electrical grids, and none are connected to any other island. Hawaiian Electric Company (HECO) and its subsidiaries, Maui Electric (MECO) and Hawaii Electric Light Company (HELCO), serve about 93% of the state’s electric utility customers. The island of Kauai is served by Kauai Island Utility Cooperative (KIUC). Under Hawaii’s Renewable Portfolio Standard (RPS), each electric utility company must meet the following percentages of “renewable electrical energy” sales: The PUC stated earlier this year that RPS compliance stood at 23%. KIUC has already spent a total of $350 million to get where it is right now, and plans to get to 60% renewable energy by 2020 and 70% by 2030. Hawaiian Electric plans to get to 46% renewable energy by 2020 and 67% by 2030. It also was recently reported that it will cost $8 billion in infrastructure upgrades alone on Oahu. As mentioned, in the spring and up until September 2014, oil was continuing to push residential electricity bills to highly unsustainable levels. Hawaiian Electric (just like most utilities) periodically updates its Integrated Resource Planning (IRP). Yet in April 28, 2014, in an unprecedented action, the Public Utility Commission (PUC) rejected HECO Companies’ IRP Report and associated Action Plans and issued 4 new orders, including within Order 32052 Appendix A “Inclinations on the Future of Hawaii’s Electric Utilities” which was both guidance and a roadmap to move Hawaii to a grid of the future. The PUC also set a late summer deadline for the HECO Companies to file several new and very exhaustive reports. Among those reports that HECO was required to file: During the 2 years that followed, over a dozen associated PUC Dockets added thousands of pages of studies and documents to support the PUC’s “Inclination” guidelines and goals, yet the key report was always the PSIP. That initial August 26, 2014 PSIP filing (at 1600 pages) was informally rejected by the Commission. Later, after a careful review, the Commission issued Order No. 33320 on November 4, 2015, where it stated that it found several shortcomings in the PSIPs that need to be addressed. The Commission ordered the Hawaiian Electric Companies to file a Revision Plan that month and ordered HECO to file updated PSIPs by April 1, 2016 — which it did. In a June 20, 2016 submittal, HECO told the PUC that it incurred, but never sought recovery for, approximately $5 million in outside consultant costs for development of the PSIPs submitted into August 2014, and approximately $700,000 was incurred in beginning the planning and update work required in late 2015. The outside consultants began their work on the interim and updated PSIPs in late 2015. So, through May 2016, the companies incurred approximately $3,578,632 in PSIP consultant outside services costs and estimated they will incur an additional $2,188,893 from June 2016 through year end. This is a gold mine waiting to be prospected by utilities, because if HECO is correct, the research contained in the Docket has nearly $10 million in consulting evaluations and reports from companies like Energy and Environmental Economics (E3), Boston Consulting Group (BCG) and others contained within the 11,000 pages PSIP Docket alone. In addition, further critical information will be added after the 2 Technical Conferences scheduled by the PUC before the final HECO PSIP is submitted at year end. This is the motherlode, but there are at least another dozen other supporting Dockets that contain thousands of other pages of analysis and rich veins of lessons learned. Part of the reason that those sources are so valuable is the little-known fact that Hawaii was first or among the first to investigate and institute programs, and certainly the first to face some of the expected and unexpected consequences. For instance, Feed-in-tariffs (FIT) as a renewable energy procurement mechanism were initiated in September 2009 and ended in December 2015. However, future revisions or modifications could be addressed either in Docket No. 2014-0192 (DER policies) or in Docket No. 2014-0183 (the HECO Companies’ PSIPs). Hawaiian Electric was also the first to: Hawaiian Electric also proposed a Time-of-Use to the PUC, and a recent working paper by University of Hawaii Economic Research Organization (UHERO) modeled it into 3 different scenarios and said: To maximize the success and benefits of implementing a TOU program, our study underscores two critical considerations. The first is the importance of enabling technologies providing for greater potential load shifting, both in regards to information and automation, and the second is the importance of customer participation in achieving efficiency goals in electricity generation. UHERO’s model results point to the importance of appliances in a residential household’s decision to shift load. The difference in percentage change during TOU periods between the Appliance and Literature Scenarios suggest that although a certain amount of appliance load is potentially switchable, residents are unlikely to switch that amount of their appliance load, especially without enabling technologies. The UHERO paper also included some graphs which we see as pointing to the value of smart water heaters — substantial load with significant usage during the critical late afternoon ramp. This entire first ever deployment – anywhere – of Grid Integrated Water Heaters (GIWH) technology would not have happened without Olin Lagon and his company Shifted Energy. Olin is a software architect with a string of patents who has a long history of social responsibility. Born and raised in Hawaii’s public housing this founder and former director of non-profit Kanu Hawaii is putting his love of technology directly to work. Olin formed Shifted Energy and joined the Energy Excelerator specifically to help leverage GIWH. He is convinced that GIWH is the single most cost-effective and scalable renewable technology that will directly benefit all stakeholders. Working directly with Hawaiian Electric, Olin and the Energy Excelerator helped fund this first deployment in western Oahu and Olin took personal responsibility (“kuleana” in Hawaii) working hands-on over the past year with plumbers and electricians during installation and start up. In July, Olin was honored to participate in Microsoft’s World Partner Conference in Toronto (if interested, see the portion in this clip from 1:20 – 1:54). Our final suggestions to utilities anticipating adding renewables to their power generation mix: Mining these data results in high quality learning outcomes and solid “next steps,” all stemming from the real life challenges, experiences, and solutions ongoing in Hawaii. About the author: Kelly Murphy, Business Development Specialist for Steffes, is responsible for the “go to market” and sales strategies for a patented and cost-effective electric energy storage system known as GETS. HECO selected the GETS System for their very 1st behind-the-meter (non-battery) residential energy storage deployment which began about a year ago. Kelly’s background includes co-founding a venture capital funded energy startup company as well as being a peer reviewer for a landmark DOE study that concluded that renewable generation when combined with flexible systems is capable of supplying 80% of our total electricity energy needs in the US by 2050. Drive an electric car? 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