The Salt River Project is the umbrella name for two separate entities: the Salt River Project Agricultural Improvement and Power District, an agency of the state of Arizona that serves as an electrical utility for the Phoenix metropolitan area, and the Salt River Valley Water Users' Association, a utility cooperative that serves as the primary water provider for much of central Arizona. It is one of the primary public utility companies in Arizona.The name, Rio Salado Project, is used to refer to the improvement projects along the Salt River through the Phoenix Metropolitan Area, is not related to SRP. Wikipedia.
News Article | January 7, 2016
Originally published on RMI Outlet. By Titiaan Palazzi and Sam Ramirez We are accustomed to buying our electricity from utilities: they provide us with power; we pay for it. To reduce our utility bill, we can reduce our electricity demand with efficiency (these negawatts have considerable value), or install distributed generation such as rooftop solar PV panels to make our own electricity. Alternatively, we can switch to a retail energy provider that offers better pricing, if we live in deregulated electricity markets like Texas that allow us to do so. And now, due in part to the rise of distributed energy resources, there is a new way to lower our electric bills: demand flexibility. Demand flexibility offers tremendous value to those who live in markets with compatible rate structures, such as where utilities charge less when market demand is lower. As we show in our report The Economics of Demand Flexibility, it is now possible to shift your electricity use to times of day when the same watt comes at a cheaper price. We call this resource “flexiwatts”—power consumption that is moved to times when power costs less, without sacrificing on the end-use service the electricity is meant to provide. Flexiwatts are the new kid in town. They save you money in simple ways that are often invisible to the end user and without compromising on quality, choice, or value. Companies like Nest, Whirlpool, and ChargePoint can inexpensively and unobtrusively shift when your air conditioner turns on, your water is heated, or your electric vehicle is charged. How do these companies extract value from controlling the timing of electricity demand? They rely on emerging rate structures from utilities around the country. Shifting your electricity use makes economic sense only if electricity costs are not equal at all times (or for all sources, such as grid-supplied electricity, behind-the-meter solar PV compensated for grid export, and self-consumed solar PV). Today, according to U.S. EIA data, 65 million U.S. customers are served by utilities that offer time-varying rates such as time-of-use (TOU) rates (where the utility provides a discounted rate outside of peak times), real-time pricing rates (where rates vary as often as hourly based on wholesale prices), or peak pricing rates (where electricity is more expensive during critical peak times). In many utility territories, this requires you to actively opt-in. Traditionally, electricity rates did not vary over time and many people to whom time-varying rates are available don’t know of their existence, or value. Just a few electricity-using devices determine the majority of your electricity bill, and there are big savings opportunities if you can take advantage of the flexibility of these devices’ energy use schedules. Fortunately, many new businesses provide products and services to make it easy for you to take advantage of this flexibility. The biggest electricity use in U.S. homes is heating, ventilation, and air conditioning (HVAC). On a hot summer afternoon in Texas, AC units send electricity demand jumping up, causing wholesale electricity prices to jump up to 300 times their typical value. But you don’t need to suffer this price spike: by running your AC unit an hour or two before prices start to skyrocket, you can pre-cool your house, so that it’s at the right temperature when you come home. This allows you to switch your AC off during peak-price hours. Nest offers this service to their users through , but only engages it in a handful of cases per year. Domestic hot water follows HVAC as the second-largest residential electricity use and, more importantly, can have a huge power draw. Around two-fifths of all water heaters in the U.S. are electric. A typical, 55-gallon water heater costs about $500, has a 4.5-kW heating element, and can store around 8 kWh of hot water. In comparison, a $3,000 Tesla Powerwall with a 7-kWh daily cycle and a 3.3-kW peak charge can cause a demand fluctuation of 6.6 kW by switching from charging at full power to discharging at full power. The humble water heater thus has about the same energy storage capacity as a Powerwall, but at one-sixth the cost. Adding inexpensive smart controls gives you a high-performance storage asset at a fantastic price. In fact, making electric water heaters controllable is such a good deal for both the customer and the overloaded grid that some utilities are now offering new water heaters for free, provided the utility can control when the heating element switches on, and all with no impact on your ability to take a hot shower. A third opportunity to save money by shifting electricity use is by keeping your clothes dryer from switching on during periods of peak electricity prices. You can do this either by buying a “smart dryer” that costs $500 more than a regular dryer, or simply by starting your dryer when time-of-use electricity prices are low. The marginal cost of making a dryer smart is likely only a few dollars for a wireless control module and a microchip, so this extravagant price for smart clothes dryers will likely come down over time. A fourth opportunity for electricity bill reduction through flexiwatts lies in electric vehicles (EVs). A typical level-2 charger has a maximum power draw of 6.6 kW—twice the average power demand of a U.S. household. Sometimes, your EV needs to be charged as quickly as possible. Often, though, electric cars are parked at the office for the full day, or at home during the evening. When this happens, controlling charging to achieve minimum electricity costs is ideal. eMotorWerks offers a free electric-vehicle charger to California residents (otherwise you’ll pay $500–$1,000), providing they can control the charging of the vehicle. In our report The Economics of Demand Flexibility, we calculate how much electricity bills can go down by using flexiwatts in four different U.S. states. Our findings are impressive: in utility Salt River Project’s service area in Arizona, for example, flexiwatts can reduce peak demand by 48 percent, and save customers with solar photovoltaics (PV) 41 percent of their electric bill. In Hawaii, customers with solar PV can save 33 percent of their electric bill by controlling their AC, EV charger, water heater, and clothes dryer. What can you do to seize these cost savings? You don’t need to become an energy trader, and you have many more options than utility-sponsored efficiency programs. First, research the different electricity rates your utility offers you. Second, if you consider buying a new air conditioner, clothes dryer, or pool pump, look into products that can be controlled through Wi-Fi, so that you can unlock the value of the flexiwatt. Image courtesy of Shutterstock. Get CleanTechnica’s 1st (completely free) electric car report → “Electric Cars: What Early Adopters & First Followers Want.” Come attend CleanTechnica’s 1st “Cleantech Revolution Tour” event → in Berlin, Germany, April 9–10. 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 | February 14, 2017
This story was originally published by High Country News and is reproduced here as part of the Climate Desk collaboration. The smokestacks of the Navajo Generating Station rise 775 feet from the sere landscape of the Navajo Nation in northern Arizona, just three miles away from the serpentine, stagnant blue wound in sandstone known as Lake Powell. Red rock cliffs and the dark and heavy hump of Navajo Mountain loom in the background. Since construction began in 1969, the coal plant and its associated mine on Black Mesa have provided millions of dollars to the Navajo and Hopi tribes and hundreds of jobs to local communities, as well as electricity to keep the lights on and air conditioners humming in the metastasizing cities of Phoenix, Tucson, Las Vegas, and Los Angeles. Yet, they’ve also stood as symbols of the exploitation of Native Americans, of the destruction of the land, and of the sullying of the air, all to provide cheap power to the Southwest. But coal power is no longer the best energy bargain. And on Monday, the plant’s four private utility owners, led by the Salt River Project, voted to shut down the plant at the end of 2019, some 25 years ahead of schedule. When the giant turbines come to a halt and the towers topple in the coming years, the plant will become a new symbol, this one of a transforming energy economy and an evolving electrical grid that is slowly rendering these soot-stained, mechanical megaliths obsolete. Here’s what you need to know about the plant, the mine, and the coming closure: In addition to these jobs, both mine and plant have contractors for various purposes and each of the power plant’s three units requires a major overhaul every three years, which temporarily employs an additional 400 or more people. These are highly coveted jobs on the Navajo Nation, which deals with high unemployment and chronic poverty. Both the Hopi and Navajo tribes got the short end of the stick — a royalty rate of just 3.3 percent — when Peabody Coal first got the leases to mine Black Mesa in the 1960s. The attorney representing the Hopi tribe, John Boyden, was actually on Peabody’s payroll at the time, and managed to get a sham tribal government to sign over mining rights against the objections of traditional Hopis, as chronicled by writer and law professor Charles Wilkinson. The mines — Black Mesa and Kayenta — forced families to relocate, destroyed grazing land, dried up springs, and wrecked ancestral Hopi shrines and other sites. The tribes fought back and eventually negotiated better terms. Both tribes now rely heavily on royalty and lease payments from the mine and the power plant, even as tribal members fight against the polluting and water-gulping ways of plant and mine. Prior to Monday’s announcement, the plant’s owners and the Navajo Nation were refashioning the lease, which runs out in 2019, to make it more favorable for the tribe. Peabody also hoped to expand the mine. Both the Kayenta Mine and the Navajo Generating Station use large amounts of water. The Bureau of Reclamation owns a large share of the plant, and uses most of its electricity to run the pumps for the Central Arizona Project, which delivers Colorado River water to Arizona cities. Salt River Project officials have been very clear on this point. They note that it’s now cheaper for them to buy power for their 1 million customers from other sources than it is to generate power at Navajo, thanks mostly to low natural gas prices. A November 2016 study by the National Renewable Energy Laboratory found that the Central Arizona Project pays about 15 percent more for electricity from the power plant — of which it is part owner — than it would if it bought power wholesale from the Mead trading hub located near Las Vegas. None of this will change even if President Donald Trump rolls back the Clean Power Plan or other regulations put in place by the Obama administration. In fact, if a drill-heavy energy policy is put into place, it will increase natural gas supplies, thus increasing the spread between natural gas and coal. Having said that, California’s move away from coal power lowers the value of the plant’s power, and the requirement that the plant install nitrous oxide-reducing equipment increases costs — so environmental protections do play a role, albeit a smaller one than economics. Although it’s happening slowly, the electrical landscape is evolving. The days of vertically integrated utilities that own huge, centralized power stations and their own balkanized grids are giving way to a new era in which utilities purchase power generated by smaller plants that are connected to larger, regional grids. California’s independent grid operator has already joined up with NV Energy, PacifiCorp, and other Western utilities to form an energy imbalance market, which allows the utilities to share generators — be they wind, solar, natural gas, or coal — to “balance” their grids in real time, rather than having to rely only on their own generators. These utilities are hoping to expand this market and then take it to the next level of a regional, integrated grid in coming years. The closure of Navajo Generating Station adds new urgency to this effort. The decision to close the plant came as a surprise. Until several weeks ago, the plant’s owners were negotiating a new lease with the Navajo Nation and considering shutting one of three units and replacing it with other energy sources. Meanwhile, the mine was looking to expand. Outright closure this soon was not on anyone’s radar, so there is no firm transition plan in place. The Bureau of Reclamation and Peabody are looking for ways to keep the plant running beyond 2019, but they’d have to do it without the other owners and against economic headwinds. When the Mohave Generating Station and the Black Mesa Mine closed in 2005, environmentalists and tribes pushed the California Public Utilities Commission to create a revolving “just transition” fund with money earned from the sale of sulfur dioxide credits from the shuttered plant. The fund, the value of which dwindled as sulfur credit prices fell, is supposed to help develop renewable energy on the reservations. There are little or no such credits available for Navajo Generating Station, however, so that approach won’t work here. The owners of the plant could work with the tribes to replace some of the lost electricity generation by building new solar, wind, or other plants on the reservations, where there is ample potential for renewable energy development. Two major transmission systems are associated with the plant, and could be taken over by the tribes to move solar or wind power to the south and west. The water rights could be turned over to the tribes, for use in agriculture or other purposes.
News Article | November 15, 2016
As one of the sunniest states in the US, Arizona has enjoyed early and great success as a leader in solar energy production. With 2,453 megawatts (MW) of solar installed, the US Solar Energy Industries Association (SEIA) ranks Arizona as #2 for total installed solar capacity. Expanding 4% over 2014, in 2015, 258 MW of solar capacity was installed, ranking Arizona 5th in the nation for 2015 installed capacity. Over $582 million was invested last year in Arizona’s solar installations. Currently, the total amount of solar power capacity installed in Arizona is enough to power 348,000 homes, but over the next 5 years, SEIA expects that number to more than double. With over 375 solar companies serving the value chain in Arizona, there are more than 6,900 people employed in the state’s solar market. With all this tremendous growth in Arizona’s solar industry over the past 4 years, it is sad to see the current negative effects of solar policy manipulation and politics at play in Arizona’s energy arena. Changes in net metering incentives, the imposition of new rate plans, proposed demand rates and grid-use charges, and on top of all of this, politically nuanced media representation have given rise to huge instability in the state’s solar market. Engaging with local stakeholders and policy makers, SEIA states that it is working to promote “stability and transparency into policies so that the market can recover from this market disturbance and continue to grow.” A huge back-and-forth exchange between solar proponents and state utilities has developed into a full-blown battle over the value of rooftop solar in Arizona. At the root of the tumult is the view of Arizona Public Service Electric Company (APS) and state regulators that grid-connected solar customers must pay their “fair share” for grid services in the form of an additional fee tacked on to their utility bill. Solar proponents respond that grid-connected solar energy supplies a bonus to the grid that other customers don’t offer, so paying an additional charge is an unfair penalty. Especially in the face of lowered net metering rates for excess solar energy entering the grid, proposing an additional charge for grid-connected solar customers has really slapped rooftop solar customers in the face and heated up the public debate. The volley reached the level of drafting competing solar ballot initiatives to amend the state’s constitution, until solar advocates and state lawmakers entered mediation, brokered a compromise, and dropped the ballot initiatives. The ceasefire, brokered between SolarCity (representing “Yes on AZ Solar,” a political action committee funded by SolarCity) and Arizona Public Service Company finally occurred when the two sides agreed to mediate over how solar customers will be compensated for their excess electricity. The ceasefire was brokered less than 1 hour after the Arizona State Senate initiated steps to send the electorate measures mandating separate rates for rooftop solar customers, and for regulating solar leasing companies as utilities. Head utility regulator, Arizona Corporation Commission (ACC) Chairman Doug Little, expressed relief at the ceasefire negotiation. He said, “It would have been a pretty ugly dispute between the ballot measures over the summer.” In August, after 2 full days of testimony before the commission, the ACC rejected requests to add fees for solar customers and to end net metering. Earthjustice attorney Michael Hiatt reported, “This decision is great news for Arizona families and small businesses that plan on going solar, and for everyone who breathes cleaner air as a result.” He added, “The decision sends a powerful message to Arizona utilities that the Commission will not simply rubberstamp their anti-solar agenda.” However, the squabbles over Arizona’s solar energy future are not over yet. A year-long Value of Solar Docket was opened at this same time last year, hoping to resolve the rancorous debate over solar customer compensation once and for all. The VOS docket could conclude within the next month and promises to offer another round of spectacular fireworks, rhetoric, and politically nuanced media representation. Stay Tuned! The following is an (untumultuous) in-depth exploration of the state of solar energy in Arizona. Please feel free to offer further contributions in the comments, below. Because everyone’s situation is unique, there’s really no substitute to simply getting a solar quote. However, research and data are always being updated and the SEIA reports that installed solar PV system prices in the US have dropped by 12% from last year and 66% from 2010. The latest data indicates that in 2016 the average installed cost of solar in the US is just below $3.50/watt for residential and $2.00/watt for commercial installations. This means that today it will cost about $17,500 to buy an average-size (5 kW) system at roughly $3.50/watt. In Arizona, 6 kW systems are fairly common, so this price works out to about $21,000. Even using 2011’s data for monthly savings, at $137 saved per month for Arizona over the course of 20 years, this works out to be $32,880, netting a gain of (at least) $11,880 on a 6 kW system installed in 2016. What if you don’t stay in your home for the full 20 years? In Arizona, property taxes don’t increase with the addition of a rooftop solar installation, but your home’s sales value increases an average of $5,911 per kilowatt of solar installed, according to a 2013 Lawrence Berkeley National Laboratory (LBNL) study. So, even if you sell your home in the year following your 6 kW solar rooftop installation, it is reasonable to expect a sales price increase of something like $35,466. This leaves you with a net gain of about $14,466 on your ($21,000) solar rooftop, assuming you sell your house at the asking price. Sell or stay, either way, rooftop solar is a win-win scenario! The federal solar investment tax credit (ITC) is available in all states of the US. Up to 30% of a solar installation’s costs can be credited via the ITC. However, you can only take advantage of the credit once, and only if you have that much tax liability in that tax year. Currently, the 30% ITC extends through 2019 but is scheduled to be phased out after that. Businesses may also qualify for incentives, including the Renewable Energy Production Tax Credit (PTC), the Business Energy Investment Tax Credit (ITC-1603), and a corporate depreciation incentive, as well. The following are a few of Arizona’s state solar energy incentives listed on the DSIRE Incentives Database. Operated by the N.C. Clean Energy Technology Center at N.C. State University, the Database of State Incentives for Renewables & Efficiency (DSIRE) offers an up-to-date and comprehensive website for solar energy incentives across the US, including federal and state incentives, programs, and policies. • Start Date: 05/23/2009 • Eligible Renewable/Other Technologies: Geothermal Electric, Solar Thermal Electric, Solar Photovoltaics, Wind (All), Biomass, Hydroelectric, Hydrogen, Municipal Solid Waste, Combined Heat & Power, Landfill Gas, Wind (Small), Hydroelectric (Small), Anaerobic Digestion, Fuel Cells using Renewable Fuels • Applicable Sectors: Commercial, Industrial, Local Government, Nonprofit, Residential, Schools, State Government, Federal Government, Agricultural, Institutional, Senior citizens • Applicable Utilities: Investor-owned utilities, electric cooperatives • System Capacity Limit: No capacity limit specified, but system must be sized to meet part or all of customer’s electric load and may not exceed 125% of customer’s total connected load • Aggregate Capacity Limit: No limit specified • Net Excess Generation: Credited to customer’s next bill at retail rate; excess reconciled annually at avoided-cost rate • Ownership of Renewable Energy Credits: Not addressed in net metering rules; customer owns RECs unless participating in a utility incentive • Meter Aggregation: Not addressed Net Excess Generation: Accomplished using a single bi-directional meter, customer net excess generation (NEG) “is carried over to the customer’s next bill at the utility’s retail rate, as a kilowatt-hour (kWh) credit. Any NEG remaining at the customer’s last monthly bill in the annual true-up period will be paid to the customer, via check or billing credit, at the utility’s avoided cost payment.” The NEG rule continues, “For customers taking service under a time-of-use rate, off-peak generation will be credited against off-peak consumption, and on-peak generation will be credited against on-peak consumption. The customer’s monthly bill is based on the net on-peak kWh and net off-peak kWh amounts. Any monthly customer NEG will be carried over to the customer’s next bill as an off-peak or on-peak kWh credit.” Additional Charges: The ACC requires net metering charges be assessed non-discriminatorily. Any new or additional charges increasing eligible customer-generator’s costs beyond that of other customers in the rate class that the eligible customer-generator would be otherwise assigned to must first be proposed to the ACC for consideration and approval. The ACC also notes that the utility has the burden of proof in any such cost increase proposal. In December 2013, responding to an application from APS addressing cost shifting, the ACC ordered a $0.70 per kW charge (a $3.50 monthly charge for a 5 kW system) for all residential distributed generation systems installed on or after January 1, 2014.** However, this charge doesn’t apply to customers with systems installed on or before December 31, 2013. The ACC also requires APS to file quarterly reports about the number of new distributed generation installations per month, the kW size of those installations, and to report the amount of revenue collected from customers through the lost fixed cost recovery charge. Other utilities have also proposed additional charges for customer-generators. *Salt River Project (SRP) and municipal utilities do not fall under the jurisdiction of the Arizona Corporation Commission, and are therefore not subject to the state net metering rules–see SRP Net Metering Program Overview, below. **The charge applies specifically to “distributed generation” systems, not “net-metered systems.” However, as net metering only applies to systems located on the customer’s premises, this charge will affect net metering customers. The charge only applies to APS customers. • Website: http://www.srpnet.com/environment/earthwise/solar/solarelectric.aspx • Utilities: Salt River Project • Eligible Renewable/Other Technologies: Geothermal Electric, Solar Photovoltaics, Wind (All), Wind (Small) • Applicable Sectors: Commercial, Residential, Low-Income Residential • Applicable Utilities: SRP • System Capacity Limit: Existing Self-Generation Customers: 300 kW • New Self-Generation Customers: Not specified • Aggregate Capacity Limit: No limit specified • Net Excess Generation: Credited to customer’s next bill at retail rate; held for same time of use period. • For existing DG customers: excess reconciled annually in April at average annual market price minus price adjustment of 0.00017/kWh • Ownership of Renewable Energy Credits: Not addressed • Meter Aggregation: Not allowed Note: Salt River Project (SRP) requires an interconnection agreement. SRP changed its existing net metering program for residential customers in February 2015. These changes went into effect with the April 2015 billing cycle. However, customers who purchased their distributed energy system or signed a lease agreement before December 8, 2014, are allowed to keep their original net metering rate plan for 20 years. Net Excess Generation: According to the SRP NEG rules, “The kWh delivered to SRP are subtracted from the kWh delivered from SRP for each billing cycle. If the kWh calculation is net positive for the billing cycle, SRP will bill the net kWh to the customer under the applicable price plan. If the kWh calculation is net negative for the billing cycle, SRP will carry forward and credit the kWh against customer kWh usage on the next monthly bill. However, if the kWh is net negative at the end of the April billing cycle, SRP will credit the net kWh from the customer at an average annual market price. No credits will be carried forward to the May billing cycle.” Additional Charges: Under SRP’s self-generation plan, customers must pay a fixed monthly service fee based on the size of their electricity service. They also must pay a grid, or demand, charge based on the customer’s maximum energy usage during peak electricity times. According to SRP, the energy charges per kilowatt-hour (kWh) are lower with the customer generation plan than with the standard residential rate plans. Aimed at reducing Arizona’s staggering peak load, a $4 million residential storage program was mandated in July 2016 by the Arizona Corporation Commission (ACC). Arizona Public Service (APS) received a 120-day deadline to firm up the specifics and get approval from the ACC, making this the first time a state besides California has mandated investment in home energy storage. Totally amazingly, the ACC has initiated this hallmark policy at no additional cost to ratepayers by tapping into an existing fund for energy-efficiency projects. Commissioner Andy Tobin proposed the idea last June. Refined with the help of Commissioner Bob Stump, the proposal passed at ACC’s July meeting. Commissioner Tobin said, “My view is, why should we be waiting around when we can help stimulate the storage market with surplus funds that are already there, that are supposed to be used for these energy efficiencies?” He added, “We’re missing the boat across the country, quite frankly, in pushing for storage the way we pushed for solar 10 years ago.” The ACC has mandated that energy storage should help residents lower demand during peak system load times. The proposal states, “Distributed generation technology may require sending more complex price signals not otherwise appropriate for traditional customers,” explaining that the utility “may need to offer participating customers advanced, time-differentiated rate plans.” “Arizona’s only energy problem in the short [term] and now,” said Tobin, “is peak demand four hours a day, five days a week for three months.” He explained, “When you’re talking 110, 115 degrees on a hot day and you’ve got kids in the house or seniors at home, it’s not like you have a lot of options.” The ACC’s proposed residential energy storage program offers a new option. Incentivizing residents to use stored energy at peak load times may be the best solution for Arizona. The pilot plan may even lead to a robust market for energy storage in the state, as well as offering significant savings for residential ratepayers. Commissioner Tobin is optimistic about the future of energy storage for Arizona. “If you can take two hours in storage out of a four-hour peak in an Arizona summer,” he said, “that’s huge.” The Solar Energy Industry Association (SEIA) lists the following solar installations as especially noteworthy in Arizona: • Agua Caliente in Yuma County was completed in 2013 by developer First Solar. This photovoltaic project has the capacity to generate 290 MW of electricity– enough to power over 41,200 Arizona homes. • At 125 MW, Arlington Valley Solar Project II is among the largest solar installations in Arizona. Completed in 2015 by LS Power, this photovoltaic project has enough electric capacity to power more than 17,700 homes. • Several large retailers in Arizona have gone solar, including Wal-Mart, REI, Intel, and IKEA. Macy’s has installed one of the largest corporate photovoltaic systems in the state with 3,456 kW of solar capacity at their location in Goodyear. According to SEIA, there are currently over 375 solar companies employed throughout the value chain in Arizona, ranging from solar system installers to manufacturers. The following is not a complete listing of all solar installers in Arizona, but were chosen and listed based on high customer recommendations and reviews: It is worse than ironic that Arizona should be debating the value of rooftop solar energy generation. The Arizona Public Service (APS) has around $2 billion invested in solar energy capacity, with a portfolio divided between 551 MW of rooftop solar installations and 499 MW of utility-scale solar plants. This past summer, amidst all the tumult and rancor over rooftop solar customer compensation, APS became the first utility outside of California to surpass 1 GW of solar energy capacity. Reaching this milestone hasn’t exactly promoted solar benevolence among APS, however. As noted in the introduction, APS has rather promoted battle between itself and Arizona’s solar advocates, narrowly avoiding a ballot initiative to amend the state constitution in favor of rooftop solar customers. A rate increase proposal before the Arizona Corporation Commission (ACC) is currently under review, pushing for a mandatory demand charge that would increase residential customers’ bills by an average of 7.96%. “In its upcoming rate case,” states Solar Strong America Chairman Kris Mayes, “APS suggests ratepayers shoulder an additional $3.6 billion in new costs. That’s real money out of household budgets, and if the ACC can help mitigate those costs by encouraging more rooftop solar energy, then the benefits of rooftop solar must be fully acknowledged.” Mayes, a former ACC Commissioner, adds dryly, “Arizona ratepayers could have cost savings falling from the sky, if our regulators see the light.” In November, the ACC is expected to vote on a methodology for quantifying the benefits of rooftop solar for utility ratepayers. The “Value of Solar” docket, as the ACC vote is referred to, is a critical pivot point upon which Arizona’s rooftop solar industry is poised, breathless but hopeful for its future. Retired Congressman Barry Goldwater Jr. and Retired Mohave County Sheriff Tom Sheahan are encouraging all solar advocates to weigh in on the value that rooftop solar and energy choice has in Arizona. In their recent opinion piece, published in the AZ Capitol Times, Goldwater and Sheahan note: “The Arizona Corporation Commission is holding a proceeding to determine the value of rooftop solar, the value that utilities should pay customers who deliver electricity back to the grid. It is clear that rooftop solar benefits all Arizonans. It drives down costs for utilities by lessening the need to build new generating stations and transmission lines, for starters – costs that are passed onto us. “Solar gives Arizonans options to generate their own electricity and lower their bills. It reduces pollution. Solar saves water. Solar creates jobs and provides almost 9,000 Arizona families with incomes higher than the national average according to the Solar Foundation. The benefits of our sunshine and rooftop solar are numerous. “Rooftop solar encourages free market competition. That’s why Arizona monopoly utilities have been trying to undermine rooftop solar. They don’t want you to supply any of your own energy. “The outcome of the ACC Value of Solar docket will impact all Arizonans. Recent independent studies conducted in other states show rooftop solar provides a long-term benefit to all, whether you have solar on your roof or not. “If our Arizona Commissioners conclude that solar is not a net positive for everyone, utilities across our state will use this as an excuse to strengthen their monopolies. This will hurt Arizona energy choice and send jobs and business running from the state. All benefits need to be thoroughly considered in the Commission’s deliberations. “Currently six utilities regulated by the ACC have filed proposals that threaten to eliminate thousands of solar jobs and the growing solar industry. Now, they are hoping that the value of solar proceeding will give them an excuse to do so. “A fair methodology for assessing all the benefits of rooftop solar would do the opposite and stop the utility assault on rooftop solar in its tracks. “That’s why it’s important for Arizonans to weigh in. Let regulators know the value that rooftop solar and energy choice has for Arizona. Let regulators know that our values lie in individual choice and freedom, homegrown jobs, innovation and competition.” Goldwater and Sheahan urge interested people to call the Arizona Corporation Commission and reference the Value of Solar Docket. ACC Phoenix Office: (602) 542-4251 or 1-(800) 222-7000 (Toll Free In-State Only). ACC Tucson Office: (520) 628-6550 or 1-(800) 535-0148 (Toll Free In-State Only). In addition, you can email Arizona’s Commissioners and offer your thoughts on the value of rooftop solar at the following addresses: Arizona Corporation Commission – Learn about the governing body that regulates the electricity rates and services of Arizona public utilities Arizona State Legislature – Track pending legislation affecting solar energy, locate and contact individual legislators, and stay up to date on current legislative issues in Arizona Arizona Governor’s Office of Energy Policy – Find a wide variety of information on state government energy programs, policy, projects, energy-saving strategies and energy-related statistics Arizona State University – Solar Power Lab – Read about the innovative solar technology research taking place at Arizona State University Arizona Goes Solar – Learn about residential and commercial solar energy options and related regulations through a collaborative effort led by the Arizona Corporation Commission and implemented by the regulated electric utilities in Arizona DSIRE Incentives Database — Arizona – Search a public clearinghouse for specific solar energy incentives in Arizona and across the United States U.S. Energy Information Administration – Arizona State Profile – Explore official energy statistics, including data on electricity supply and demand, from the U.S. government BBB Accredited Business Directory — Solar Energy System Design & Installation – Better Business Bureau’s comprehensive directory of Arizona’s solar energy contractors, dealers, suppliers, manufacturers, and distributors Check out this Youtube clip on Arizona’s Solar Story: Buy a cool T-shirt or mug in the CleanTechnica store! 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News Article | March 1, 2017
The largest coal-fired power plant in the Western U.S. will shut down 25 years earlier than expected. Environmentalists are celebrating, but hundreds of Navajo workers there are devastated.(Image credit: Amber Brown/Courtesy of Salt River Project )
News Article | December 6, 2016
NEW YORK--(BUSINESS WIRE)--Knoa Software, a leading provider of user experience management (UEM) software, today announced that Arizona power and water utility Salt River Project (SRP) is utilizing the SAP® User Experience Management (SAP UEM) application by Knoa to improve employee experience and drive adoption for its SAP applications. Through its extensive user analytics, SAP UEM provides full visibility into user behavior and the effectiveness of employee engagement with enterprise applications. SAP UEM enabled SRP to identify application challenges and inefficiencies, identify screens that would benefit from proofs of concept for the SAP Fiori® user experience and SAPUI5, and eliminate the need for employees to remember process steps in order to recreate system issues. “Until now, our system-support users had no easy way of knowing exactly how employees interact with SAP, nor a way to successfully retrace the actions that led to an error and creation of a defect ticket,” said Gibbons Saint Paul, SAP functional solution architect for Salt River Project. “With the insights provided by SAP UEM, we are now able to resolve each usability issue in the most appropriate ways – through increased training, business process modification, development of an SAP Fiori mobile application, or whatever else makes sense for that use case.” Knoa is an SAP partner whose UEM solution is resold by SAP as an SAP Solution Extension, providing in-depth visibility into SAP user behavior. SAP UEM sheds light on every aspect of application usage and user workflows, helping to protect and maximize investments in SAP applications and upgrades. The unique insights it provides make it a powerful tool for SAP S/4HANA® migration projects, SAP Fiori or SAPUI5 development projects, or SAP cloud implementations (such as SAP SuccessFactors® or SAP Hybris® Cloud for Customer solutions). SRP began using SAP UEM in May 2016, as part of a project to improve user experience across the organization. SAP UEM analyzes all user activities across all business transactions, and provides insight into which transactions are seeing the most user activity, highest error rates and longest response times. SRP is now in the process of designing new application screens based on this analysis. When the new user interfaces are implemented, SAP UEM will help to confirm that employees are adopting and using them correctly. “It’s gratifying to know that Salt River Project has joined the long list of customers that are using our solution to flag and resolve user behavior issues while increasing productivity,” said Brian Berns, CEO of Knoa Software. “We are pleased that they are deriving value from our UEM solution to not only guide training, but also as essential insight for the design of new screens in SAP Fiori as part of their SAP S/4HANA migration.” SRP is a community-based, not-for-profit public power utility and the largest provider of electricity in the greater Phoenix metropolitan area, serving more than 1 million customers. SRP also is the metropolitan area’s largest supplier of water, delivering about 800,000 acre-feet annually to municipal, urban and agricultural water users. Knoa Software delivers on-premise and cloud solutions that generate unique insights for the optimization of the end-user experience for solutions from vendors including SAP, Oracle and others. Knoa's patented software provides CIOs and business executives the actionable metrics needed to help ensure organizations and end-users realize the full value of their enterprise application investment. Headquartered overlooking Union Square in New York City, Knoa provides solutions that help hundreds of global corporations and government organizations make impactful, real-time, fact-based decisions that enrich and maximize the experience for over a million end users. For further information, visit www.knoa.com or follow us at @knoasoftware on Twitter. SAP, SAP Fiori, SAP S/4HANA, SuccessFactors, Hybris and other SAP products and services mentioned herein as well as their respective logos are trademarks or registered trademarks of SAP SE (or an SAP affiliate company) in Germany and other countries. See http://www.sap.com/corporate-en/legal/copyright/index.epx for additional trademark information and notices. All other product and service names mentioned are the trademarks of their respective companies.
News Article | March 4, 2016
Net metering and interconnection are rights afforded distributed generation (DG) residential and commercial solar system owners through the U.S. Energy Policy Act of 2005. The act required publically owned utilities to offer net metering and left the various policies up to the states to enact. In 2004, before that energy policy was enacted, 39 states had net metering and interconnection standards and policies. At the beginning of 2016, 43 U.S. states and three territories had net metering policies, and four states had policies similar to net metering that the Database of State Incentives for Renewables & Efficiency refers to as “statewide distributed generation compensation rules other than net metering.” In the U.S., the availability of net metering was a key driver in the adoption of residential and small commercial solar. Net metering allows DG system owners (or lessees) to receive a credit for the electricity their solar systems generate. In the early days of net metering the electricity generated by the owner’s solar system was purchased monthly by the utility with, typically, the excess credited and rolled over to the following period or granted to the utility at the end of the year. Utilities paid for the net excess or credited the electricity generated by net metered solar systems at avoided cost, a market average or in some cases, at the retail rate. The concept of avoided cost is essentially a comparison point used by utilities (in this context) to arrive at reference price point for buying electricity from another source. The Public Utility Regulatory Policies Act of 1978, affectionately known as PURPA, defined avoided cost in general as the cost of generating power from another source. In 2005, the Energy Policy Act amended PURPA and, as previously noted, obligated publically owned utilities to offer net metering. In terms of DG residential and commercial solar, avoided cost comes into play in terms of how utilities pay for a system’s net excess electricity. Not only is there no standard for the state-by-state definition of avoided cost in the context of net metering, there is no standard as to how net excess electricity will be compensated. Some states use a definition of avoided cost based on short run marginal cost — diminishing marginal returns — and some states use a definition based on long run marginal cost — returns to scale. Basically, avoided cost is a reference point derived by some means to set a price for power. In the case of DG residential and commercial solar the method by which avoided cost is calculated is very important — it is also important in setting power purchace agreement rates. In the early days of net metering, it was not typical for customers to be paid for the net excess generated by their solar systems at retail rates or favorable market rates. In many cases, utilities owned the net excess electricity generated by net metered systems while the owners of these systems had no right to the excess electricity. In the early days of net metering customers were solely looking to save money — the potential of making money at the DG system level is fairly recent. From 2005 through 2015, the residential application in the U.S. grew at a compound annual rate of 53 percent. Though net metering is only one driver of this growth, it certainly makes the economic case for the homeowners, particularly when net excess electricity is credited at retail rates. Figure 1 offers residential solar growth in the U.S. from 2005 through 2015. Utilities did not expect solar industry growth to accelerate so significantly, and there is no doubt that they see this growth in terms of revenue decay. Currently, and it must be stressed that there is no clear trend in terms of outcomes, the following changes to net metering are being sought on a case by case basis: The utility argument for altering how net excess is compensated and for adding additional fees is economic. Utilities argue that ratepayers with solar systems (leased or owned) are renting less electricity from the utility and thus not paying their fair share for overall maintenance. The argument continues that the costs are unfairly shifted to ratepayers without solar systems on their roofs. Establishing a fair fee for solar customers over and above the base fee all ratepayers pay is not simple. The addition of fees for solar customers should not be overly punitive or appear as a referendum against DG solar. After all, ratepayers without solar systems benefit from the clean energy generated by ratepayers with solar systems. Also, the electricity future likely includes more self-consumption and more microgrids as well as a new operating and revenue model for utilities. Fighting this change is futile. The argument over who owns the net excess electricity generated by a DG solar system is simple. The electricity is fed into a common grid, all electricity customers use it and the generator of the electricity owns the net excess and deserves to be paid a market rate for it. At the core of the utility’s argument, and often unmentioned, is a reduction in its revenues. Four states have been front-and-center currently in the net metering landscape: Arizona, California, Hawaii and Nevada. These states offer examples of the way things could play out as the net metering argument spreads from state to state. Reference years provided as examples are 2006, 2009, 2013 and 2016. In 2006, Salt River Project (SRP) purchased net excess at an average monthly market price minus a price adjustment, while Arizona Public Service (APS) and Tucson Electric Power (TEP) credited net excess at retail rate and granted the electricity to the utility at the end of the calendar year. There were no specific fees for solar system owners/lessees. In 2016 things are very different; the state net metering policy credits net excess at retail rate with net excess paid at avoided cost. APS ratepayers, whether they leased or bought their systems, pay a $0.70/kWp monthly charge. For many, the changes in net excess compensation along with the additional fees for ratepayers in APS territory could swing the economic argument away from leasing or owning a solar system. California’s solar system owners came through a recent high profile fight over net metering relatively unscathed, though the result is not perfect. The net metering landscape has changed from no fees to a one-time interconnection fee and non-by-passable monthly charges for all electricity consumed from the grid. Though the charges are relatively modest, system owners beware; charges always go up and almost never go away. Ratepayers with solar systems will also be forced into time-of-use billing and will be credited or paid for net excess at the rate equal to the 12-month spot market price. To this last, spot market prices are not always favorable and in an oversupply situation can be downright penurious. Hawaii: Not an Island Paradise for Solar In October 2015, for all those applying for interconnection/net metering after Oct. 12, 2015, the Hawaii Public Utilities Commission voted to end net metering, offing instead three options: grid-supply, self-supply and time-of-use tariff. This decision effectively put the brakes on Hawaii’s strong market for DG residential and small commercial solar. Nevada’s recent net metering decision slammed the door shut on the state’s DG solar installation industry, outraged current solar customers and set a precedent that — if not overturned by legislation or lawsuit — will be considered in states across the country. Specifically, by making the new rules essentially retroactive the decision of Nevada’s Public Utilities Commission (PUC) could cause potential DG solar system owners/lessees to think once, twice and maybe delay adoption. Nevada’s PUC increased the monthly fee paid by net metered solar customers from $12.75 to $17.90 and will credit net excess at avoided cost. Existing solar customers will be phased into the new rates in three years for the monthly fees and over 12 years for the lower net excess rates. The Trend is That the Fight is On — As Usual Net metering serves the market function of setting a price for kWhs of electricity. A DG solar system (homeowner or small business) generates electricity and the owner/lessee of the system sells the electricity that it does not need (the net excess) to the utility. The electricity that is generated is used by all ratepayers. The value proposition is clear. Reasonably the sellers want to profit from the electricity they sell or at least receive a credit on their electricity bill that fairly values their net excess generation. Unreasonably, utilities would prefer not to pay a fair market price for the net excess. Changes to net metering programs are being considered all across the U.S., and there will be wins, losses and new fees. Trends to be very concerned about include the switch back to crediting net excess at avoided cost instead of at retail rates and to higher fees for net metered solar customers. The most disastrous potential trend is to make changes to net metering retroactive thus encouraging potential customers to reconsider. This last trend must be fought vigorously. The U.S. solar industry is up to the fight.
News Article | February 15, 2017
As a presidential candidate, Donald Trump promised to help revive the struggling coal industry. It’s looking like a tough promise to keep. In the past three weeks, owners of two of the nation’s biggest coal-fired power plants have announced plans to shut them down, potentially idling hundreds of workers. One plant in Arizona is the largest coal-fired facility in the western United States. “[We’re] bringing back jobs, big league,” President Trump said Tuesday after signing legislation that would scrap requirements for natural resources companies to disclose payments to foreign governments. “We’re bringing them back at the plant level. We’re bringing them back at the mine level. The energy jobs are coming back.” Yet even with his efforts to roll back Obama-era energy regulations, a lot of coal jobs won’t ever return, mainly because of harsh economic realities. Case in point: The decision this week by the utilities that own the Navajo Generating Station outside Page, Ariz., to decommission the plant at the end of 2019, decades earlier than expected. [Trump’s energy plan doesn’t mention solar, an industry that just added 51,000 jobs] The 2,250-megawatt plant has faced increasing financial pressure in the face of record-low natural gas prices, which have made it more expensive to produce electricity at the facility than to purchase it from cheaper sources. “The utility owners do not make this decision lightly,” said Mike Hummel, deputy general manager of Salt River Project, which operates the plant and owns it along with several utility companies and the U.S. Bureau of Reclamation. “NGS and its employees are one reason why this region, the state of Arizona and the Phoenix metropolitan area have been able to grow and thrive,” he added in a statement. “However, [its owners have] an obligation to provide low-cost service to our more than 1 million customers, and the higher cost of operating NGS would be borne by our customers.” Environmental activists welcomed the prospect of closing the plant, one of the biggest polluters in the country. The Navajo Generating Station was third on a 2014 Environmental Protection Agency list of major carbon-emitting facilities. But its closure would deal its community a significant economic blow. Between the plant itself and the Kayenta Mine — located roughly 80 miles away, it provides all the coal for the generating station — nearly 800 workers could find themselves out of work. Many are members of the Navajo and Hopi tribes, which also receive royalties from the plant. In their announcement, the plant’s owners said the tribes or others could still step in to operate the facility beyond 2019. [In West Virginia coal country, voters are ‘thrilled’ about Donald Trump] Less than three weeks ago, Dayton Power and Light reached an agreement with the Sierra Club to close its Killen and Stuart coal-fired power plants in Ohio due to economic reasons. The plants would close in June 2018, the company and nonprofit said. The Stuart plant, built in the early 1970s, has a capacity of 2,440 megawatts. The Killen plant, built in 1982, has a capacity of 666 megawatts. Dayton Power and Light submitted a closure plan for approval by the Public Utilities Commission of Ohio. The utility said it would develop solar and wind projects generating at least 300 megawatts of power no later than 2022. It also proposed a variety of energy-efficiency steps and grid improvements. The Sierra Club applauded the moves, which it said would save $37 million a year in health-care costs by avoiding more than 1,200 asthma attacks, 100 heart attacks and nearly 100 deaths linked to the two plants’ emissions. Both facilities are among the largest sources of pollution in the United States, affecting residents as far away as the Atlantic coast. “The economics of coal are increasingly bad,” said Bruce Nilles, a Sierra Club lawyer. State governments and utilities commissions “will do a lot to prop up” ailing plants, he said, but “it gets increasingly expensive.” Dayton Power and Light is a subsidiary of Virginia-based AES Corp. Trump’s ability to save the Navajo plant and others like it is limited, despite his rhetoric. Even if his administration follows through on its promises to relax regulations on the coal industry, those changes aren’t likely to change coal’s fading market. And if the owners of coal-fired plants lose money when they operate their facilities, keeping them running makes little economic sense.
News Article | October 27, 2016
FRANKLIN, Mass. & PHOENIX--(BUSINESS WIRE)--Salt River Project Enhances Customer Service with Interactions Intelligent Virtual Assistant Solutions
News Article | February 20, 2017
The Navajo Generating Station located near Page, Arizona, is the largest coal-fired electric generation facility west of the Mississippi. With an output of 2,250 megawatts, it has been supplying electricity to Arizona, California, and Nevada residents since 1976. “NGS and its employees are one reason why this region, the state of Arizona and the Phoenix metropolitan area have been able to grow and thrive,” says Mike Hummel, deputy general manager of the Salt River Project which operates the plant. That’s the good news. The bad news is that in a 2014 survey, NGS was listed as the 3rd largest emitter of carbon dioxide in the United States by the EPA. The story of the Navajo Generating Station brings together several disparate threads. The plant is owned by a consortium of utility companies, including the Salt River Project, and the US Bureau of Land Reclamation. The coal it burns comes from the Keyenta Mine located 80 miles away. The generating plant and the mine employ about 800 people, the majority of them members of the Navajo and Hopi Native American tribes. Both tribes collect royalties from the operation of the generating plant and the mine. Last week, the utilities that own the NGS made a decision to close it down at the end of 2019, about a decade earlier than planned. The cost of electricity from burning natural gas has plummeted, making it unprofitable to keep operating NGS. “The utility owners do not make this decision lightly,” Hummel told the Washington Post. “However, [its owners have] an obligation to provide low cost service to our more than 1 million customers, and the higher cost of operating NGS would be borne by our customers.” The closing of the Navajo Generating Station gives the lie to Donald Trump’s campaign bluster about bringing back jobs for coal miners and relaxing environmental restrictions on coal fired plants. Facilities such as NGS were the target of President Obama’s Clean Power Plan. Trump has promised to eviscerate that plan and has installed just the right head of the EPA to make that happen, but in the end it won’t make any difference. Simple economics are dictating the end of the coal era in a way that regulations could not. Coal is also taking a drubbing in Ohio, one of the states that went heavily in favor of Trump, swayed by his promise of more jobs for coal miners. Things aren’t working out that way though. Last week, Dayton Power and Light reached an agreement with the Sierra Club to close its Killen and Stuart coal fired power plants in Ohio by June of this year. The Stuart plant, built in the early 70s, has a capacity of 2,440 megawatts. The Killen plant, built in 1982, has a capacity of 666 megawatts. Combined, the two coal plants are some of the largest polluters in the country, with their emissions affecting millions of people as far away as the Mid-Atlantic region. The plant closures raise two important considerations. What should be done to help the workers who will lose their jobs find other employment, and who should pay for it? At the national policy level, it is good news that three large carbon polluters are being taken off line. At the local level, it is unfair to simply throw people out of work without planning for how to keep the closures from having devastating financial consequences on the workers. A national carbon tax would provide a pool of money to help retrain workers but, given current policies, those workers will receive only whatever unemployment benefits their states and the Congress provide them and nothing more. In fact, if Republicans have their way, the workers will suffer the indignity of being drug tested before they can qualify for any benefits at all. Some people think members of Congress should be drug tested instead. There is also a fine irony here for the Native people who will be affected by the NGS closure. The tribes will lose money once the royalties stop and hundreds of their members will become unemployed. The tribes could elect to continue operating the plant themselves but digging coal and burning it is at odds with the Native American ethos of being good stewards of the earth — the motivation behind the resistance to the Dakota Access pipeline project in North Dakota. The closing of three old coal plants is cause for celebration, but America must develop a comprehensive plan to replace the electrical power lost with electricity from renewable sources. It’s wonderful that natural gas is cheaper than coal and has lower emissions when burned, but it still comes largely from fracking, a process that is as destructive to the land as coal mining. It also is associated with massive releases of methane into the atmosphere, a gas that is far more dangerous to the environment than carbon dioxide. Unless America transitions to renewable energy, closing coal plants and replacing them with natural gas plants is at best a mixed blessing. As the cost of grid scale solar energy continues to fall, the day is getting closer when simple economics will put an end to natural gas generating plants just as natural gas has put and end to coal fired plants. For the health of all Americans, that day cannot come soon enough. 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 | February 15, 2017
TUCSON, Ariz.--(BUSINESS WIRE)--Tucson Electric Power (TEP) joined other owners of the Navajo Generating Station today in voting to continue operations at the plant through December 2019 if a lease extension agreement can be reached with the Navajo Nation. The three-unit, 2,250-megawatt (MW) facility is located in Northern Arizona near Page on land leased from the Navajo Nation. Phoenix-based Salt River Project operates the plant and owns 43 percent of its output. Other owners include the U.S. Bureau of Reclamation, Arizona Public Service and NV Energy. TEP is the plant’s smallest stakeholder with ownership of 7.5 percent, or 168 MW. Without the lease extension, owners would be forced to shut down the coal-fired plant later this year to allow enough time for decommissioning work to be completed before the current lease expires. A lease extension would continue power production, maintain plant employment and preserve revenues for the Navajo Nation and Hopi Tribe, providing continued support for the area economy. “We recognize the Navajo Generating Station’s value and support a lease extension that would allow operations to continue through 2019 as we continue to explore options for the plant’s future,” said David G. Hutchens, TEP’s President and CEO. “We look forward to working toward a long-term solution for NGS that balances the needs of the plant’s many stakeholders and serves the best interests of our customers and the community we serve.” TEP provides safe, reliable electric service to approximately 417,000 customers in Southern Arizona. For more information, visit tep.com. TEP and its parent company, UNS Energy, are subsidiaries of Fortis Inc., which owns utilities that serve more than 3 million customers across Canada and in the United States and the Caribbean. To learn more, visit fortisinc.com.