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Phoenix, AZ, United States

Arizona Public Service Company is the largest electric utility, and the highest tax payer in Arizona, USA, and the principal subsidiary of publicly traded S&P 500 member Pinnacle West Capital Corporation , which in turn had been formerly named AZP Group, when Arizona Public Service reorganized as that holding company in 1985.With 4,000 MW of generating capacity, APS serves more than one million customers in 11 counties throughout most of the state, but mainly concentrated in northern and central Arizona. APS is one of the two suppliers of electricity to the Phoenix metropolitan area .APS is regulated by the Arizona Corporation Commission , the state agency that, by mandate of Article 15, Section 2 of the state's constitution, regulates energy utilities in Arizona, with the notable exception of SRP and the rural electrical districts.The holding company, Pinnacle West Capital, through its APS utility sells wholesale and retail power to the wider western United States and also provides energy-related services. Through another major subsidiary, Pinnacle West also developed and manages real estate in Arizona. Pinnacle West left the real estate business in 2010.The utility company also operates three nuclear reactors. Its Palo Verde Nuclear Generating Station in Arizona, the largest nuclear plant in the U.S., came under scrutiny by the Nuclear Regulatory Commission in 2005 when operational problems began to cause prolonged outages. Wikipedia.

Virtually all utility executives believe the industry's century-old business model is changing and that utilities need to adapt. Where there’s less consensus is around how. Only 3 percent of utility executives said they believe their company's business model does not need to change, according to a recent survey conducted by Utility Dive. The results stem from an online poll of 515 U.S. electric utility executives conducted at the end of 2015 and the beginning of 2016. So there’s a near consensus on the need to evolve, which goes for all utility types -- investor-owned utilities, municipal utilities, public power agencies and electric co-operatives. But respondents see several hurdles in the way. The report notes that the 21st century has seen the emergence of the smart grid, renewable portfolio standards, federal carbon regulations and new disruptive market players, among other factors. And yet, while new challenges have emerged, the survey found that legacy issues continue to dominate, with utility executives citing an aging workforce, outdated regulatory models and aging infrastructure as the most pressing challenges facing their company. These issues have long plagued utilities, but they’re arguably exacerbated by changes in the energy system. The falling cost of renewables and increased availability of distributed energy resources (DERs), like rooftop solar and energy storage, are driving concerns around load reduction and cost recuperation. Investor-owned utilities are particularly concerned that their regulatory models will not serve them well in this changing environment. Next to legacy issues, renewable energy integration and stagnating load growth were cited as some of utility executives' top concerns. For many utilities, DERs present a particular set of opportunities and challenges. Choosing from among a suite of advanced clean energy technologies, 66 percent of utility executives said they are currently most invested in utility-scale solar and wind, 64 percent said demand-side management and 50 percent said distributed generation. Out of the technologies they felt they should invest in more, energy storage rose to the top, with 65 percent of utility executives reporting this as a priority. Distributed generation was second at 52 percent and utility-scale solar came in third at 47 percent. These responses track last year’s Utility Dive survey, in which 56 percent of respondents said that DERs presented an opportunity, but at that time, executives were unsure how to build a business model around them. This year, utility respondents clearly favored two approaches: partnering with third parties to deploy DERs and installing DERs by rate-basing investments through the regulated utility. When respondents were offered five DER business models and asked to select all that apply, the results show 60 percent of utility executives believe they should partner with third parties and 59 percent believe they should rate-base their investments. Some utility respondents (39 percent) were open to procuring or aggregating power from DERs owned by third-party providers, and others (29 percent) were open to owning and operating DERs through an unregulated subsidiary. Very few (5 percent) said they do not believe their utility should have a business model around DERs. Because the choices aren’t mutually exclusive, responses show that utilities are considering and possibly pursuing multiple DER business models, which is likely a reflection of regulatory uncertainty. In the same vein, a recent Greentech Media survey found that a majority of respondents, including utility personnel, policymakers and industry leaders, wanted regulators to issue rulings that would help determine the value of DERs. One respondent said regulators should "implement policies that allow incumbents to effectively and fairly compete with un- or less- regulated competitors.” In the Utility Dive survey, when asked specifically if regulated utilities should be allowed to own and rate-base DERs, a strong majority of respondents -- 65 percent -- said that they should. Another 17 percent said utilities should be able to rate-base DER investments, but only when the competitive market fails to deploy DERs that would benefit the grid, which is the model put forward by regulators in New York. Only 12 percent of respondents said they should offer DERs through an unregulated subsidiary, and just 6 percent said utilities shouldn’t offer DERs at all. The notion of utilities owning and recuperating costs for DERs is the subject of heavy debate. National solar companies view allowing monopoly utilities with a pre-existing customer base to participate in the DER market as anti-competitive. There’s also no precedent, as to date, very few regulated utilities have sought to deploy DERs. However, Arizona Public Service and Tucson Electric Power were recently given regulatory approval to launch residential solar pilot projects, and other utilities, such as Georgia Power, have begun offering rooftop solar through their unregulated utilities. How these and other utility-owned DER programs evolve is likely to remain a hot-button issue in the industry. For utilities, the rapid growth of third-party-owned DERs creates a necessity to reform rate structures to compensate for lost revenues. “While the sheer volume of electricity sales lost to DERs in most regions of the nation is still small, stagnant or declining load growth can make even small increases in DER penetration significant for utility earnings,” the report notes. Few utilities see lowering net metering credits for DERs as the sole solution. To solve the issue of decreasing revenue, most utility executives (38 percent) believe they need to adjust rates through fixed charge increases, demand charges and time-of-use rates. If not through rates, many utility executives (27 percent) believe they should offer their own renewable energy options, such as green pricing or community solar programs. Among the possible rate-change options, a majority of respondents (55 percent) favored instituting time-of-use rates to charge more at peak times. The second and third most popular options were to increase fixed charges (29 percent) and increase demand charges (28 percent), respectively. The answers surrounding rate reforms were not mutually exclusive, which indicates that utilities are pursuing multiple approaches. “If there’s one overarching takeaway from Utility Dive’s third annual State of the Electric Utility industry survey, it’s that the transformation has arrived -- but a standardized approach on how to adapt to it has not,” the report states. Utilities see clean energy and grid-edge technologies changing the way they operate, and they increasingly want to get in on the game, although it's not clear what their role will be. There's no doubt that non-utility players will have input on how that process unfolds. But, ultimately, the decision rests with regulators and policymakers -- as the recent Nevada solar controversy has shown. Interestingly, despite often-stated concerns over the potential for DERs to erode utility revenues by reducing load, the notion that customers will generate and store enough of their own power to abandon the grid -- a trigger of the so-called utility death spiral -- appears to be a relatively small concern in the grand scheme of things. Just 16 percent of utility executives see load defection as one of the top challenges facing their industry.

The 20-year struggle to create a cohesive Western power grid has entered a new phase, with a strong push by the California Independent System Operator (CAISO) to expand membership to other utilities in the West. CAISO brought together over 800 stakeholders from across the region in Sacramento last week to talk about regionalization. While speakers agreed that the engineering rationale and cost benefits are clear, the political process creates a formidable obstacle to achieving the dream. “The topography of the western grid follows the power flows, but the politics follows all kinds of weird things,” lamented Michael Picker, chair of the California Public Utilities Commission. Advocates of grid expansion are inspired by the success of the energy imbalance market (EIM), which has saved $88 million since it began in 2014. The EIM allows member utilities -- currently the three California IOUs plus Pacificorp and NV Energy -- to share resources to balance the grid. More utilities are scheduled to join over coming years, including Idaho Power and Arizona Public Service. But spurred by legislation (SB350), CAISO is pushing for a more comprehensive regional partnership, extending the market to cover day-ahead bids. This regional system operator (RSO) would facilitate wholesale competition across the region, similar to regional markets in the East. A big driver for the RSO is the growth of wind and solar across the region. Wind and solar made up 14.2 percent percent of California’s supply last year, and are among the least costly sources of new generation. All states except Wyoming and Idaho have renewable energy goals, with both California and Oregon expanding their own targets to 50 percent. A bigger grid would be a low cost way to integrate renewables, by spreading out the variability and tapping the best resources, as well as a way to capture operating efficiencies in general. But the technical benefits of a regional grid will have to overcome the political barriers Governor Jerry Brown was a surprise guest at the symposium, telling the crowd that California is committed to climate action, but acknowledging the difficulties of regional action. “We will continue innovating in this state,” he told the crowd. “We think we’ll get to 50 percent renewables sooner than 2030. To make it work we need a grid that is highly sophisticated.” “It’s true that different states have different needs and perspectives, but the efficiency of a wider grid is unmistakable,” he said. “I hope you can work all that out." The issue is that the CAISO board is appointed by Governor Brown with the advice and consent of the state senate. An expanded regional system operator would include utilities from across the region, and their state regulators will expect to have a say in management The idea reveals the anxieties of stakeholders both in California and in other states. Mark Schiavoni, with Arizona Public Service, pointed to the lingering effects of the 2000-2001 power crisis. “Regulators and politicians fear that California will control my state, and we won’t allow that to happen,” he said. “There are a lot of people with long memories.” Other market models also inspire trepidation. PJM officials have been making presentations in the region to educate people about the market -- to mixed reactions, apparently. “In my neck of the woods PJM is the antichrist,” said Doug Hunter with Utah Associated Municipal Power Systems. This prompted another panelist to ask “if PJM is the antichrist, what is California?” Hunter replied, “It’s potentially the good witch of the West.” A fear from Californians is that an RSO would provide new markets for existing coal plants, undermining California’s climate goals. Travis Ritchie of the Sierra Club said a regional market will make lowest cost the dominant goal, rather than carbon reductions. “I don’t think that’s what California wants,” he said. “I don’t think California will be comfortable putting at risk all the things we’ve done. We’ve done policies that have taken a lot of money and sweat and tears to get right.” But Carl Zichella of NRDC disagreed. “These markets really put the squeeze on legacy plants,” he argued. “The only thing keeping these coal plants alive is a bilateral contract.” Being exposed to competition from lower cost wind and solar would hasten their demise, said Zichella. Steven Greenlee, a spokesman for CAISO, pointed out two additional issues that have to be addressed. First, how will new RSO members pay for the grid? Transmission access charges are paid by generators to use the grid and pay off past investments. Hunter from Utah confirmed this concern. “Our biggest concern is paying for overheads and costs,” he told the audience. “It could quadruple the transmission access charge in Utah.” Resource adequacy is a second concern. California doesn’t have a capacity market to guide future year investments, like PJM and New England have. Instead, it requires regulated utilities to procure 100 percent of load, plus a 15 percent reserve margin. There is no mechanism in CAISO for acquiring future capacity, and therefore no mechanism for the RSO. CAISO has open dockets now on both these issues. The governance issue raised enough concern in the legislature that Gov. Brown announced in August he would go slower, with a possible vote in January. The regional grid concept is hardly new. It began with INDEGO -- the independent grid operator -- that was discussed by 21 Western entities over 20 years ago. “Implementation problems and tariff design disputes led to the official demise of the plan,” according to a 1998 study. Next came RTO West in the late 1990s, just in time for the great Western power crisis in 2000. As prices exploded due to market manipulation by Enron and others, anything related to California and competition became toxic. The idea was revived in 2003 as Grid West, in response to a strong push from FERC for standard market design, championed by then-chair Pat Wood. But the scars from the crisis were too fresh, and a push from the feds was seen as a top-down power grab, and fared poorly in the independent West. There are some major differences this time, according to Doug Larsen, former executive director of the Western Interstate Energy Board. Previous attempts started from scratch, and would have cost hundreds of millions of dollars for software and systems. “This time the CAISO has already developed everything,” said Larsen. “That’s why the EIM was successful -- it was plug and play for new participants.” A second major difference is the maturity of wind and solar power. “They have changed the realities, and more is coming,” he said. “There are real operational reasons to join now, not just a theoretical benefit.” The RSO is not the only option on the table. Seven utilities -- including Xcel, Western Area Power Administration and Basin Electric -- are discussing terms for a Mountain West Transmission Group, a regional entity that would create uniform transmission tariffs in Colorado, Wyoming, and neighboring states. And parties in the Pacific Northwest have been talking about a pooled operation since 2012, through the Northwest Power Pool’s Market Assessment and Coordination Committee. Their footprint includes 14 of the 38 balancing authorities in the Western Interconnect.

Kim J.J.,Sejong University | Foley E.M.,Arizona Public Service | Reda Taha M.M.,University of New Mexico
Cement and Concrete Composites | Year: 2013

Synthetic calcium silicate hydrate (C-S-H) made with calcium to silicate (C/S) mixture ratios of 0.9, 1.2 and 1.5 respectively is characterized. C-S-H was produced by extracting calcium oxide (CaO) from calcium carbonate (CaCO 3) and then mixing it with micro-silica (SiO2) and deionized water to make slurry. The slurry was continuously mixed for 7 days, then the excess water was removed and thermo gravimetric analysis (TGA) was conducted. The drying method was equilibrated to 11% relative humidity (RH). The stoichiometric formula of the synthetic C-S-H were approximated as C 0.7SH0.6, C1.0SH0.8 and C 1.2SH2.4 for C/S mixture ratios of 0.9, 1.2 and 1.5 respectively. The dried powders were characterized using X-ray diffraction analysis (XRDA), and 29Si magic angle spinning (MAS) nuclear magnetic resonance (NMR) spectroscopy. The powders were also compacted with 95 MPa pressure and nanoindentation of the compacted specimens were then undergone to mechanically characterize the synthetic C-S-H. The experiments provide insight on the nanoscale mechanical characteristics of C-S-H. © 2012 Elsevier Ltd. All rights reserved.

Foley E.M.,Arizona Public Service | Kim J.J.,Sejong University | Reda Taha M.M.,University of New Mexico
Cement and Concrete Research | Year: 2012

In this study, calcium silicate hydrate (C-S-H) is synthesized and characterized. C-S-H slurry was made with calcium oxide (CaO) to micro-silica (SiO 2) mixture ratio of 1.5 and enough deionized water. The slurry was continuously mixed for 7 days, then the excess water was removed. Two methods of drying were implemented: one method used the standard d-dry technique and the other was equilibrated to 11% relative humidity (RH). The dried powders were characterized using thermo gravimetric analysis (TGA), X-ray diffraction analysis (XRDA), and 29Si magic angle spinning (MAS) nuclear magnetic resonance (NMR) spectroscopy. The stoichiometric formulas of synthetic C-S-H powders dried to d-dry and 11% RH in this study were approximated as C 1.2SH 0.7 and C 1.2SH 2.4 respectively. The powders were then compacted to create specimens with porosities similar to C-S-H in hydrated cement. The specimens underwent nanoindentation to mechanically characterize C-S-H. The experiments provide insight on the nanoscale mechanical characteristics of C-S-H. © 2012 Elsevier Ltd. All rights reserved.

Arizona Public Service | Date: 2011-07-19

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