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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.

One of the major economic and reliability challenges facing utilities today is managing direct buried primary cable that is nearing the end of its useful life. Because many utilities are faced with cable replacement programs that will require 10, 20, 30, or more years to complete, today-s budgetary decisions can have a major effect on underground system reliability well into the future. To address aging direct buried primary cable management, Salt River Project (SRP) has focused its efforts in three main areas: 1. Establishing an accurate fault and cable length database for each underground primary cable type in the SRP system based on year of installation, 2. Establishing an accurate fault forecast methodology and model based on cable length, and 3. Developing a computer simulation of the underground cable replacement process that forecasts faults and reliability over a 30-year period. All three of these areas are interwoven; the fault and cable length data are used to obtain the fault forecast model parameters, and these parameters and the model itself are used in the cable replacement simulation along with the cable length data. Thus SRP views establishing accurate cable data as being of primary importance and the cornerstone of this effort. This paper, however, will focus only on the model and methodology used to forecast cable faults and the process and reasoning behind the 30-year underground cable replacement simulation. © 2011 IEEE.

Two years ago, energy investment veteran Peter Kind wrote a report for the Edison Electric Institute, suggesting that utilities need to be freed to develop alternative business models to deal with the threat of third-party distributed energy. Among the new revenue streams, tariff structures and cost-sharing mechanisms the report put on the table, there were some ideas that have drawn fire from the solar industry, such as reducing compensation for net-metered solar customers. But none has proven as unpopular as fixed charges for solar-equipped or net-metered customers. That’s why Kind’s latest report, Pathway to a 21st Century Electric Utility Model, released Monday on behalf of sustainable investment nonprofit Ceres, takes it off the table. That’s not to say that the pressure to find utility alternatives has eased, Kind said in a recent interview. In fact, with the Clean Power Plan, utilities face an entirely new set of uncertainties, as well as opportunities, in their clean energy futures, he said. But fixed-charge proposals rolled out by vanguard utilities in the past two years have faced widespread opposition from solar advocates and the general public, as well as skepticism from regulators, he said. “Two years later, I’m thinking, 'Well, that’s pissing off a lot of people,'” he said. What’s more, fixed charges are “not sending the right price signal,” he said, because they’re a cost that customers can’t reduce, no matter how efficiently they manage their electricity. And where fixed charges have gone through, such as at Arizona utility Salt River Project, they’ve crimped the growth of solar significantly. That’s antithetical to the broader imperative to encourage clean energy, the report notes. These are some of the reasons why utility Arizona Public Service has dialed back its original solar fixed-charge proposal. Instead, it’s asking state regulators to take up the issue of how to share costs across solar and non-solar customers in a future proceeding, meant to determine the true cost of serving the distribution grid. That’s the kind of work that could inform new ways to compensate net-metered solar customers, based on the value of the solar they generate. One idea is to stop paying net-metered customers the retail rate for the solar power they produce, and switch them to a rate set by competitive wholesale rates, or the “levelized cost of the lowest incremental cost to deploy efficient renewables” -- in other words, some kind of value-of-solar tariff. This is similar to what Hawaii has done with net metering, and what California utilities are proposing in the state’s net metering 2.0 proceeding. These aren’t popular ideas with rooftop solar companies, however, because they will reduce revenues significantly -- in Hawaii and California, the utility proposals would pay roughly half the retail rates, on average. Even so, “We can’t afford to buy the least efficient renewables,” Kind argued. “We need to find out what the most efficient renewables are, and the owner of those most efficient renewables should receive either the wholesale price for energy, or if it’s higher, the most efficient cost of renewables adjusted for getting it to your house.” Community solar, which allows individuals to “own” a portion of a larger-scale solar system, can provide a more capital-efficient entry for homeowners and small businesses, he said. It could help expand the market to the roughly four-fifths of the population that lacks a proper roof for solar PV. Tariff structures such as time-of-use rates could help encourage planning and investment in solar that more closely matches grid needs, as well as drive behavior change -- “If you’re going to use energy at the most expensive time of the day, you should pay for it,” he said. Bidirectional metering capabilities could allow compensation schemes that separate consumption and generation, he added. Kind, the executive director of Energy Infrastructure Advocates and a former long-time energy and utilities investment director, also laid out some high-level ideas for loosening the linkage between utility capital investments and guaranteed rates of return. The report suggests the U.K.’s Totex (total expenditures) model, which includes incentives to consider operating investments that replace or defer capital investment, as one option. Regulators should also decouple utility revenues from energy sales, as states like California have done, to take away a direct disincentive for utilities to invest in energy efficiency. Cost-of-service regulatory frameworks should be replaced with systems that allow utilities to earn incentives for exceeding expectations, along with penalties for not meeting them, he added. This is rare today, although states like Oklahoma and Ohio have made them part of specific utility smart-grid deployments, and Illinois lawmakers have ordered Commonwealth Edison to hit certain performance metrics for its 2.2-million-unit smart meter deployment. As for new revenue streams, utilities could use their connections with customers, such as call centers and web portals, to open “app stores,” he said -- clearinghouses of utility and third-party energy services, that could earn revenues on a “per-click” basis. “Today, you can go to utility websites and learn about products, but you can’t click through, because there’s no incentive there,” he said. In terms of how different states are realizing this vision, Kind said that New York’s Reforming the Energy Vision initiative seems to be relegating utilities to a role as a platform provider for third-party energy services companies, rather than as a participant. California’s wide-ranging reforms are “all interesting,” he said, though “I wish they’d come up with a comprehensive plan, rather than a bunch of mandates.” Minnesota’s e21 Initiative is also an interesting initiative, although it’s so far led by non-utility players, he said. It's in everyone's interest to ensure that utilities remain financially healthy, given that they’re still going to be the provider of energy to the vast majority of people for decades to come -- claims of “grid defection” not withstanding, he said. Along with the net-metering challenges in solar-rich states like Hawaii, California and Arizona, utilities everywhere still face flat or declining energy demand, hundreds of billions of dollars in future infrastructure costs, and the mandate to fairly share costs across all customers. “I think we’re going to need plenty of solar,” he said. “If the Clean Power Plan is implemented as proposed, we need all of it. The question is, at what price? Solar is a good proposition for many customers, no matter what the [net metering] rate might be. This doesn’t suggest the demise of rooftop. But if we’re using customers’ money, let’s spend it on the most efficient product available.”

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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 | September 24, 2008
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Congratulations Mr.Chaudhary, your story is very inspirational

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In the final hours of the legislative session, California lawmakers passed a landmark climate bill that will promote greater deployment of clean energy technologies over the next 15 years, but which some supporters say still fell short of expectations. SB 350 will increase building energy efficiency in the state by 50 percent by 2030. It will also boost the amount of renewable energy utilities need to buy to 50 percent by 2030. California's three investor-owned utilities are already well on their way to meeting the state's 33 percent renewable energy goal by 2020, according to the California Public Utilities Commission's fourth-quarter 2014 RPS report. The third major component of the bill -- a target to reduce oil use in cars and trucks by 50 percent over the next 15 years -- was struck down earlier in the week. The measure was strongly opposed by oil industry groups, including the Western States Petroleum Association, which insisted that the target would cripple California’s economy and even lead to bans on SUVs. "We are disappointed that the legislature was unable to take action this session setting specific transportation goals for 2030, which would have sent a clear market signal for continued growth of electric vehicles and alternative fuels over the next decade," said Graham Richard, the CEO of Advanced Energy Economy. Senate leader and bill author Kevin de León harshly criticized the oil industry’s scare tactics earlier this week. “Big Oil might be on the right side of their shareholder reports, but we’re on the right side of history,” he said. SB 350 embodies the environmental goals Governor Jerry Brown laid out in his inaugural address earlier this year. Brown praised the passage of the bill on Friday, but insisted the battle to reduce oil use is far from over. In addition, to the dismay of both solar companies and utilities, SB 350 does not specify that distributed solar arrays count toward the mandatory component of the renewable energy target. SB 350 is one of 12 climate bills that have been working their way through the California state legislature. A separate bill (SB 32) that would have required California to reduce emissions 80 percent below 1990 levels by 2050 failed to pass in the Assembly, despite strong support from the governor, as well as from U.S. Senators Barbara Boxer and Dianne Feinstein. However, lawmakers did pass legislation (SB 185) mandating that the state's two largest pension funds divest from coal companies. With the state's legislative session now over, clean energy advocates are focusing their attention on the California Public Utilities Commission. California’s three investor-owed utilities have filed proposals to reduce compensation for net-metered solar customers, and add monthly charges for the electricity these customers consume. While the changes are expected to raise solar customers’ electricity bills (from an average of $65 per month to $135 per month in Southern California Edison territory), utilities claim solar customers will continue to see savings, especially as solar costs decrease. In a recent blog post, Caroline Choi, SCE’s vice president for energy and environmental policy, wrote that solar customers can still expect to pay off their system in seven years under the utility's proposal. Under a 2013 law (AB 327), the CPUC has until the end of the year to . Solar advocates, including the state’s leading cleantech investors, are pushing for regulators to keep solar incentives the same through 2020. “If California intends to maintain its role as leader in renewable energy, it will have to reject these proposals,” said Bryan Miller, vice president of policy at Sunrun. “Net energy metering exists in 44 states; South Carolina recently became the 44th. If California wants to be more regressive than South Carolina on renewable energy policies, it would accept these utilities’ proposals. But I don’t think that’s where California’s values are.” Miller pointed to Arizona, where Salt River Project recently approved solar demand charges, and consequently solar installations fell by 95 percent. “There is a dead body in Arizona, and utilities in California really like that result, and want to do the same thing,” said Miller. This debate comes after the CPUC passed reforms to residential electricity rates in July, including a requirement for utilities to create time-of-use plans, a move to a two-tiered rate structure, and the rejection of fixed monthly charges in favor of a minimum bill approach.

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