Phoenix, AZ, United States
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.


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News Article | February 15, 2017
Site: www.greentechmedia.com

Pulling a cohesive narrative out of the DistribuTech conference’s thousands of participants and menagerie of electrical doohickeys is like synopsizing James Joyce’s Ulysses. Amid the cacophony, however, a few trends emerged. The sophistication of software used to manage an increasingly decentralized grid continues to grow, as Jeff St. John observed. Meanwhile, utility representatives expressed caution about the dislocations stemming from that decentralization. "Our main charge is to make sure our customers have reliable power," said James Boston, manager of market intelligence at San Antonio utility CPS Energy, which recently deployed a demonstration microgrid. "Utilities are generally cautious to make sure these things are tested, are proven, before we put customers’ reliability in any type of jeopardy." A spot of optimism from both utilities and grid edge enthusiasts appeared in the form of microgrids. In the last few years, the drop in prices for solar photovoltaics and energy storage, the arrival of advanced grid-forming inverters, and the impacts of solar penetration on the flow of electrons through the grid have made microgrids more cost-effective and attractive. “Ten years ago, resiliency was the only reason you would buy a microgrid, because the energy would cost too much to create -- it would never be cheaper than a grid,” said Mark Feasel, vice president of smart grid at Schneider Electric. “Now with PV and CHP with natural gas, in many states you can generate energy cheaper than you can buy it.” Cheap technology, though, is not sufficient to usher in the age of the microgrid. “The challenge is on the commercial side,” said Ken Horne, director for smart grid at Navigant, on a panel at DistribuTech. “Not all value streams from these investments are readily monetizable.” Now, more than ever before, utilities and other energy companies are experimenting with those business models. Many models are emerging, but three distinct concepts stood out at the conference: microgrids to defer transmission and distribution costs, microgrids as a service to a customer, and microgrids developed for both customer and grid-wide benefit. Not surprisingly, utilities tend to like microgrids when they can own them, control them and recover their costs through the rate base. If the commercial microgrid-as-service model takes off, though, it could usher in a broad deployment of this technology without asking ratepayers to put their money on the line. San Diego Gas & Electric delivers power to the town of Borrego Springs via a single radial transmission line running through the desert. Lightning strikes and desert flash floods threaten that line, resulting in historically poor reliability, Chief Engineer Thomas Bialek explained at the DistribuTech panel. The utility needed to maintain or improve reliability for the nearly 2,800 Borrego Springs customers, but the traditional fix -- building out a parallel transmission line -- was pricey. A microgrid would be three or four times cheaper, Bialek said. So that’s what they did. The system, paid for by SDG&E, the Department of Energy and other partners, combines diesel generators, large and small batteries, and rooftop solar PV. SDG&E's microgrid kept the desert town of Borrego Springs powered during a flash flood-induced outage (Source: SDG&E) The microgrid has already proven itself in the face of adversity. When a flash flood in September 2013 downed transmission poles and lines leading to the town, the microgrid fired up and restored power to 1,056 customers while the grid repairs unfolded. That covered the core city center, so that those residents who didn't have power yet could move to central facilities for shelter from the heat. In this use case, the microgrid doesn’t challenge or complicate the utility’s role -- it helps achieve the core mission of reliability for all customers, however remote. “If they were redoing from scratch all the rural electric cooperatives, I doubt they would build all those miles and miles of lines,” Bialek said. Up in metropolitan Toronto, distribution utility PowerStream faced a similar conundrum. It powers a remote town called Penetanguishene well north of Toronto, fed by very long transmission lines under constant threat from storms and snow. “When we tried to improve reliability in this town where reliability was historically poor, we thought, ‘We could put out more conventional assets to solve the problem or we could do something more innovative,’” said Shuvo Chowdhury, smart grid project lead at the utility. They decided to test whether a microgrid really could defer a traditional grid investment. The installation took a year from detailed design to deployment and commissioning, and includes a 500-kilowatt-hour lithium-ion battery from Samsung SDI with an advanced microgrid controller and 750 kilovolt-ampere inverter. The microgrid can island and run the town for 42 minutes, considerably longer than the usual outage of 10 minutes. When an outage is not expected, the battery can earn some revenue by arbitraging from cheap to expensive generation. “The major play is for resiliency, but most of the time, you don’t use it for that,” Chowdhury said. “We’ve had a very mild winter, so we haven’t had as many outages. Not that I’m asking for some.” There is still work to be done, then, to optimize the design of such a system for return on investment. It’s one thing to prove a microgrid is cheaper than wires upgrades, and it’s another to design and operate it in a way that pays for itself as quickly as possible. A different model is emerging to give customers access to microgrid services while shielding them from risk. This approach adopts the power-purchase agreement model from the solar industry to sell microgrids as a service. Schneider Electric will be supplying one of these microgrids at the public safety headquarters and correctional facility in Montgomery County, Maryland, the company announced Wednesday. Under this structure, Duke Energy’s renewables arm will own and operate the microgrid. Montgomery County will pay a 25-year PPA for the energy created onsite as well as the secure power for the critical facilities in the event of an outage. Schneider connected the customer with the investor and supplies about half of the equipment that Duke will purchase to construct the setup. Duke has plenty of experience developing renewable energy and maintaining electrical infrastructure, and a big enough balance sheet to absorb a large upfront investment. “For the past 10 years, Duke Energy Renewables has been successful selling wind and solar power through power-purchase agreements, so we extended that model to the Montgomery County microgrid project, meeting the customer’s need for reliability, security and affordability,” said spokesperson Tammie McGee. Montgomery County has a triple-A credit rating, but limited expertise in the construction of microgrids, not to mention a limited budget for capital investment and maintenance. Thus, Duke can trust the county to pay incrementally over the next 25 years for resilience, energy cost stability and expanded renewables. The structure avoids the risk of using taxpayer dollars to buy the emerging technology itself. “Not only are we preparing for outages, but these facilities are in a better condition for day-to-day operations,” said Eric Coffman, Montgomery County chief of energy and sustainability, tuning in virtually to a launch event at the conference. In this case, the local government is the customer, but ratepayers themselves don’t bear the cost or risk of the installation. Duke owns the assets as a private investor; the county pays for service. It’s easy to see how this model would work for commercial and industrial applications. It also carries implications for the equitable improvement of the grid. “If this works out in some commercial arrangement, why should we put that in the rate base and hope the business model works?” said Feasel, Schneider’s smart grid leader. “Because eventually, if it doesn't work, poor Grandma [living] in public housing is going to pay more, and that's not fair.” In the pay-for-service model, he continued, the customer pays the agreed-upon amount, the developer makes sure everything works, and if something breaks, the suppliers have to replace it. Ratepayers are not on the hook for any of that. Elsewhere, though, utilities are exploring ways to build out microgrids with partial ratepayer support. The general model derives from the dual nature of most microgrids as both a local, independent service and a grid-tied resource. In the partially rate-based model, the utility builds a customer-sited microgrid in a place where resilience is in high demand, but uses some of the assets for broader grid services when the customer doesn’t need backup. The customer pays for its expected use of the facility, and the utility asks its public utilities commission for permission to recover costs from the grid-serving portion of the project. Arizona Public Service has undertaken two such projects, using diesel generators rather than solar and storage. One is at Marine Corps Air Station Yuma, the other is at Aligned Data Center, going up in Phoenix. Data centers place a premium on uninterrupted power, so APS used the microgrid as a way to attract the center to its territory. The host customers contribute based on their expected usage of the facility, said Scott Bordenkircher, APS director of transmission and distribution technology innovation and integration. When those facilities don't need backup power, though, the microgrids can serve the broader grid with peaking energy, frequency response, voltage regulation and spinning reserve. The utility is asking for cost recovery based on the stacked values the microgrids provide for ratepayers at large. "I've got to do these certain things anyway, now I can do them with this. What does that look like from a cost-comparison standpoint?" Bordenkircher said of the decision-making process. "In fact, it's far cheaper using the microgrid generation than it is through other means." This is one of those calculations that makes sense in principle but could get tricky when it comes to divvying up the costs in real-world situations. The microgrids are up and running, but APS is still waiting to hear back from regulators on the rate case that would reimburse the grid side of the projects. A rendering depicts the futuristic aerotropolis development Peña Station Next, where Panasonic's new office will host a microgrid (City and County of Denver). Over in Colorado, utility Xcel Energy has partnered with the city of Denver and Panasonic to create a $10.3 million microgrid in Peña Station Next, a “smart city” development under construction near the airport. Panasonic is anchoring the new development with an office to house the operations center for its nationwide network of utility-scale solar installations. Such a facility needs to run at all times. Meanwhile, Xcel was looking to improve grid reliability in the area and brace for a feeder heading toward 30 percent solar penetration. The company had received permission from the state public utility commission to recover costs for testing energy storage on the grid, making the deal even more attractive. Peter Bronski with Panasonic's marketing and content strategy team described the project as “a microgrid with fuzzy boundaries,” because the components don’t all live within the fence in the way one might expect. The microgrid includes 1.6 megawatts of solar owned and operated by Xcel but installed on a carport at Denver International Airport. Panasonic is footing the bill for 259 kilowatts of solar PV on its own roof and will host the 1-megawatt, 2-megawatt-hour lithium-ion battery from Younicos. That battery is located in front of the meter, but on Panasonic's side of the islanding switch. The partnership, then, leverages private land and funding to deploy equipment with the potential to help the broader grid. Panasonic will enjoy an estimated 4 hours of backup for its critical facilities. The utility gets solar integration, grid peak demand reduction, energy price arbitrage and frequency regulation. The partners will watch and learn how the batteries work for two years, testing the ability of the battery to stack different jobs in real life. After that study period, Xcel and Panasonic will finalize a more formal agreement for use and payment for the rest of the battery’s life. It's also possible to do this sort of project without a rate case. CPS used company funds to construct a demonstration microgrid at Fort Sam Houston in Joint Base San Antonio, to operate with analytics funded by a National Renewable Energy Laboratory grant. The company chose a library as the project site, to gain experience with real usage patterns without putting any critical operations on the line just yet. That approach doesn't constitute a business model per se, but it's a way to develop early microgrids and figure out sustainable business models down the road. Several microgrids have arrived, then, but microgrids as a class are still in a state of arriving. This category of project has entered the grid and started carrying real loads, but the examples discussed here still serve an exploratory purpose, gathering data for a better understanding of how they can work in the future. Given the diversity of markets and customers, it's reasonable to expect that no one model will win out. The sources interviewed for this story agreed that the microgrid market is still in its infancy, and a thriving market for this asset won't arrive for perhaps five or 10 years. In some cases, regulatory policies will impose constraints, particularly where utilities are barred from owning distribution and generation, and where storage is classified as the latter. The precedent set by the Arizona Corporation Commission in the APS rate case will also be a sign of the viability of the hybrid model for leveraging private and public capital. It is noteworthy that utilities are not shying away from this type of grid experiment. Utility representatives repeatedly dismissed the idea that a proliferation of microgrids could catalyze a death spiral like the one once expected from distributed solar generation. They're not worried about grid defection from customers who can run their own miniature grids. Part of that is logistical. For secure, nonstop power, localized generators would run into air permit issues, and solar-plus-storage still requires a big upfront expenditure, said APS' Bordenkircher. "I don't see [a microgrid] as becoming my 24/7 power source of choice," he said. "It's going to provide a secondary service that I need, not a primary service." It's cost-effective to run a microgrid on grid power most of the time, and island it in an emergency; to achieve full independence drives the costs up fast. Additionally, microgrids offer utilities a new source of revenue, which is especially welcome as traditional utility business models face changes in the years ahead. The skills required to design and operate a microgrid -- electrical engineering, grid balancing and the like -- are already areas where utilities specialize, noted David Chiesa, who watches over S&C Electric Company's microgrid market segment as senior director of business development. Meanwhile, distributed solar and energy storage are spreading on their own steam and complicating the business of grid operation, as seen on the feeder where Xcel is building the microgrid. Microgrids offer a way to compartmentalize these distributed resources and mitigate their effects on the grid at large, before things get out of hand. "Why do you think they’re experimenting with it now?" Chiesa said. To really enable a utility-driven microgrid market to flourish, microgrid design will need to become more standardized, he added. "If you look at microgrids today, they're all perfect little snowflakes," Chiesa said. "That's anathema to fleetwide management. [...] Utilities are going to want their microgrids to look more like a fleet." Several pathways forward have become clear. Microgrid developers need to log more hours of run time and shave the costs of designing and building. But they've got an essential crowd-pleaser on their hands: a product that combines the safety and reliability of traditional grid architecture with the control and flexibility of distributed energy. Make sure to attend Greentech Media’s Grid Edge World Forum 2017, our premier conference and exhibition focused exclusively on tomorrow’s distributed energy system. Join us to discuss and debate the latest issues impacting tomorrow’s distributed energy system, and examine the trends and innovation happening at the grid edge. Learn more here.


News Article | March 1, 2017
Site: www.businesswire.com

PHOENIX--(BUSINESS WIRE)--Arizona Public Service and a broad, diverse group of stakeholders reached agreement today on a far-reaching resolution of the company’s first rate review in five years. The agreement must now go before the Arizona Corporation Commission for review, a public hearing and a vote by Commissioners later this summer. If approved, the agreement will pave the way for: “This agreement demonstrates what can be accomplished when people come together with a willingness to compromise and resolve complex policy issues. Consumer advocates, environmental advocates, business customers, solar industry representatives and more have agreed on a path for Arizona’s energy future. The winners are Arizona electricity customers,” said Don Brandt, APS Chairman, President and CEO. “What we have is a blueprint that will bring about more solar, a smarter energy infrastructure, a cleaner energy mix and more options for customers.” APS would be allowed an overall revenue increase of 3.3 percent. The typical monthly bill for residential customers, pending approval from the ACC, would increase 4.5 percent, or about $6 per month. APS originally had requested a revenue increase of 5.74 percent, which would have raised the typical monthly bill for residential customers by 7.96 percent, or about $11 per month. The agreement includes optional demand rates that will provide more ways for customers to save money. In addition, under the agreement APS would refund to customers $15 million of surplus energy efficiency program funds over the first year that new rates are in effect. Limited-income customers would benefit from increased program funding from the current $35 million to $48 million, a simplified monthly bill discount and a $1.25 million annual emergency bill assistance fund. Under the agreement, APS would not begin another request for a comprehensive review of its rates before June 1, 2019, meaning three years between rate reviews. If approved, the agreement would enable APS to: Continuing Arizona’s Solar Leadership the Right Way APS agreed to invest $10 million to $15 million per year in an AZ Sun rooftop program in which customers would receive a monthly credit to allow the company to install rooftop solar systems on their homes. This innovative program would expand access to solar for limited- and moderate-income customers throughout the APS service area. The agreement builds on the ACC’s decision in December to ensure private rooftop solar customers are fairly compensated when they produce excess electricity, while reducing the generous subsidies previously paid for by customers without rooftop solar. If approved, the settlement would: “This agreement continues Arizona’s solar leadership with smart policies that enable the continued growth of solar and other new consumer technologies while protecting non-solar customers,” said Brandt. Through a separate agreement, APS, industry representatives and solar advocates commit to stand by the settlement agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC. New Rate Options for All Customers If approved, the agreement includes changes in the rate options APS offers its customers, including incentives for more efficient use of energy and additional opportunities to save money. Among the choices: The agreement preserves the company’s proposal to offer four new “off-peak” holidays, increasing the total number to 10. For business customers, the agreement would: “This agreement allows us to continue investing in Arizona’s future. Our work on advanced technology and grid innovations over the coming years will create jobs and opportunities for suppliers and others,” said Brandt. Thirty of 40 stakeholders in the rate review process support the agreement, including ACC Staff, the Residential Utility Consumer Office, merchant generators, unions, seniors, business customers, industry groups, environmental groups, limited-income advocates, rural municipalities, schools, federal agencies and several private rooftop solar organizations (Arizona Solar Deployment Alliance, Arizona Solar Energy Industries Association, Solar Energy Industries Association, Vote Solar and Energy Freedom Coalition of America). APS serves about 2.7 million people in 11 of Arizona’s 15 counties, and is the Southwest’s foremost producer of clean safe and reliable electricity. Using a balanced energy mix that is nearly 50 percent carbon-free, APS has one of the country’s most substantial renewable energy portfolios, and owns and operates the Palo Verde Nuclear Generating Station, the country’s top power producer and largest producer of carbon-free energy. The company is also a proven leader in introducing technology and services that offer customers choice and control over their energy consumption. With headquarters in Phoenix, APS is the principal subsidiary of Pinnacle West Capital Corp. (NYSE: PNW).


News Article | February 23, 2017
Site: www.businesswire.com

"We have made significant investments to meet growth in our region and to replace aging infrastructure, some of which is almost 60 years old. This modern infrastructure will benefit our customers well into the future," said Mary Kipp, Chief Executive Officer. "We are pleased that we have started to recover and earn a return on some of those investments. Our improved overall financial results are largely due to the rate relief we received in 2016, which helped to partially mitigate regulatory lag. Including Montana Power Station Units 3 and 4 and other plant additions, we have now completed $444 million of capital projects since the end of the test year in our 2015 rate cases. As a result, we filed a new rate case in Texas on February 13, 2017 to allow us to begin to recover and earn a return on these most recent investments." The table and explanations below present the major factors affecting 2016 net income relative to 2015 net income (in thousands except per share data): Financial Effect of the Public Utility Commission of Texas ("PUCT") Final Order On August 25, 2016, the PUCT issued its final order in the Company's rate case in Docket No. 44941 (the "PUCT Final Order"). The PUCT Final Order had a significant effect on the Company's 2016 financial results, the impacts of which are reflected in the table above. See "Rate Cases- 2015 Texas Retail Rate Case Filing" for a discussion of the PUCT Final Order. Income for the quarter ended December 31, 2016, when compared to the quarter ended December 31, 2015, was positively affected by (presented on a pre-tax basis): Income for the quarter ended December 31, 2016, when compared to the quarter ended December 31, 2015, was negatively affected by (presented on a pre-tax basis): Income for the twelve months ended December 31, 2016, when compared to the twelve months ended December 31, 2015, was positively affected by (presented on a pre-tax basis): Income for the twelve months ended December 31, 2016, when compared to the twelve months ended December 31, 2015, was negatively affected by (presented on a pre-tax basis): Excluding the $7.2 million PUCT Final Order impact, for the fourth quarter of 2016, retail non-fuel base revenues increased $0.6 million, pre-tax or 0.5% compared to the fourth quarter of 2015. This increase was primarily due to increased revenues from small commercial and industrial customers of $0.7 million due to a 1.0% increase in kWh sales which were driven by a 2.9% increase in the average number of customers. This increase was partially offset by a decrease of $0.1 million in revenues from residential customers due to a 0.2% decrease in kWh sales. While the Company experienced a 1.4% increase in the average number of residential customers served, milder weather particularly in the second half of the 2016 fourth quarter resulted in lower kWh sales compared to the 2015 fourth quarter. Non-fuel base revenues and kWh sales for the fourth quarter of 2016 and 2015 are provided by customer class on page 12 of this news release. Excluding the $40.9 million PUCT Final Order impact, for the twelve months ended December 31, 2016, retail non-fuel base revenues increased $3.4 million, pre-tax or 0.6% compared to the twelve months ended December 31, 2015. This increase was primarily due to increased revenues from residential customers of $3.5 million due to a 1.3% increase in kWh sales and increased revenues from small commercial and industrial customers of $2.5 million due to a 0.8% increase in kWh sales. Increased kWh sales from residential customers and small commercial and industrial customers were driven by a 1.4% and 1.9% increase in the average number of customers, respectively, offset in part by milder weather during the twelve months ended December 31, 2016 compared to the twelve months ended December 31, 2015. Revenues decreased $2.4 million from large commercial and industrial customers during the twelve months ended December 31, 2016 compared to the twelve months ended December 31, 2015 due to a 3.0% decrease in kWh sales, due primarily to reduced demand by the steel manufacturing industry, and a decrease in surcharges billed to a large customer in 2016 compared to 2015. Non-fuel base revenues and kWh sales for the twelve months ended December 31, 2016 and 2015 are provided by customer class on page 14 of this news release. On August 10, 2015, the Company filed with the City of El Paso, other municipalities incorporated in its Texas service territory and the PUCT in Docket No. 44941, a request for an annual increase in non-fuel base revenues. On August 25, 2016, the PUCT issued the PUCT Final Order, which provided for: (i) an annual non-fuel rate increase, lower annual depreciation expense, a revised return on equity for AFUDC purposes, and the inclusion of substantially all new plant in service in rate base, all as specified in the uncontested Stipulation and Agreement filed with the PUCT; (ii) an additional annual non-fuel base rate increase of $3.7 million related to Four Corners Generating Station costs, which will be collected through a surcharge terminating on July 12, 2017; (iii) removing the separate treatment for residential customers with solar systems; (iv) allowing the Company to recover $3.1 million in rate case expenses through a separate surcharge; and (v) allowing the Company to recover revenues associated with the relate back of rates to consumption on and after January 12, 2016 through March 31, 2016 through a separate surcharge. Interim rates, associated with the annual non-fuel rate increase, became effective on April 1, 2016. The additional surcharges associated with the incremental Four Corners Generating Station costs, rate case expenses and the relate back of rates to consumption on and after January 12, 2016 through March 31, 2016 were implemented on October 1, 2016. For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail Rate Case until it received the PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the cumulative effect of the PUCT Final Order which related back to January 12, 2016. Details of the impacts of the PUCT Final Order are provided on page 17 of this news release. On May 11, 2015, the Company filed with the NMPRC in Case No. 15-00127-UT, for an annual increase in non-fuel base rates. On June 8, 2016, the NMPRC issued the NMPRC Final Order which provided for an annual increase in non-fuel base rates of approximately $0.6 million, an increase of approximately $0.5 million in other service fees, and a decrease in the Company's allowed return on equity to 9.48%. The NMPRC Final Order concluded that all of the Company's new plant in service was reasonable and necessary and therefore would be recoverable in rate base. The Company's rates were approved by the NMPRC effective July 1, 2016 and implemented at such time. On February 13, 2017, the Company filed with the City of El Paso, other municipalities incorporated in the Company's Texas service territory and the PUCT in Docket No. 46831, a request for an increase in non-fuel base revenues of approximately $42.5 million. The Company invoked its statutory right to have its new rates relate back for consumption on and after July 18, 2017, which is the 155th day after the filing. The difference in rates that would have been billed will be surcharged or refunded to customers after the PUCT's final order in Docket No. 46831. The PUCT has the authority to require the Company to surcharge or refund such difference over a period not to exceed 18 months. The Company cannot predict the outcome or the timing of the rate case at this time. The Company has completed construction of the MPS placing into service Units 3 and 4 on May 3, 2016 and September 15, 2016, respectively, and the related common facilities and transmission systems at a cost of approximately $160.5 million, including AFUDC, for the two units. Each unit is an 89-MW simple cycle aero-derivative combustion turbine, is powered by natural gas and has quick start capabilities which allows the unit to go from off-line to full output in less than 10 minutes, thus increasing overall power grid stability. Each of the four MPS units will work in concert with the Company's renewable energy sources and will generate enough energy to power more than 40,000 homes in the Company's growing service territory. Completion of the Sale of Four Corners On February 17, 2015, the Company and Arizona Public Service Company ("APS") entered into an asset purchase agreement, providing for the purchase by APS of the Company's interests in Units 4 and 5 of the Four Corners Power Plant. On July 6, 2016, the closing of the transaction occurred, after which the Company no longer owns any coal-fired generation. No significant gain or loss was recorded upon the closing of the sale. In March 2016, we issued $150 million in aggregate principal amount of 5.00% Senior Notes due December 1, 2044 to repay outstanding short-term borrowings on our Revolving Credit Facility ("RCF") used for working capital and general corporate purposes, which may include funding capital expenditures. We continue to maintain a strong capital structure in which common stock equity represented 44.1% of our capitalization (common stock equity, long-term debt, current maturities of long-term debt and short-term borrowings under the RCF) as of December 31, 2016. At December 31, 2016, we had a balance of $8.4 million in cash and cash equivalents. Based on current projections, we believe that we will have adequate liquidity through our current cash balances, cash from operations and available borrowings under our RCF to meet all of our anticipated cash requirements for the next twelve months including the maturity of $50.0 million aggregate principal amount of our Series B 4.47% Senior Notes (due August 2017) and $33.3 million aggregate principal amount of 2012 Series A 1.875% Pollution Control Bonds which are subject to mandatory tender for purchase in September 2017. Cash flows from operations for the twelve months ended December 31, 2016 were $231.2 million, compared to $246.7 million for the twelve months ended December 31, 2015. The primary factors contributing to the reduction in cash flows from operation were increases in net under-collection of fuel revenues and accounts receivable. Offsetting the decreases in cash flows were increased revenues due to the PUCT Final Order and the NMPRC Final Order and increases in deferred income taxes. A component of cash flows from operations is the change in net over-collection and under-collection of fuel revenues. The difference between fuel revenues collected and fuel expense incurred is deferred to be either refunded (over-recoveries) or surcharged (under-recoveries) to customers in the future. During the twelve months ended December 31, 2016, we had fuel under-recoveries of $14.9 million compared to over-recoveries of fuel costs of $13.3 million during the twelve months ended December 31, 2015. At December 31, 2016, we had a net fuel under-recovery balance of $10.9 million, including an under-recovery of $11.1 million in Texas offset by an over-recovery of $0.2 million in New Mexico. On November 30, 2016, we filed a request to increase our Texas fixed fuel factor by approximately 28.8% to reflect increasing natural gas costs. This requested increase was approved by the PUCT and was effective with our January 2017 billings. During the twelve months ended December 31, 2016, our primary capital requirements were for the construction and purchase of electric utility plant, payment of common stock dividends, and purchases of nuclear fuel. Capital requirements for new electric utility plant were $225.4 million for the twelve months ended December 31, 2016 and $281.5 million for the twelve months ended December 31, 2015. Capital expenditures for 2017 are expected to be approximately $215 million. Capital requirements for purchases of nuclear fuel were $42.4 million for the twelve months ended December 31, 2016, and $42.0 million for the twelve months ended December 31, 2015. On January 26, 2017, the Board of Directors declared a quarterly dividend of $0.31 per share payable on March 31, 2017 to shareholders of record as of the close of business on March 17, 2017. On December 30, 2016, we paid a quarterly cash dividend of $0.31 per share, or $12.6 million, to shareholders of record as of the close of business on December 14, 2016. We paid a total of $49.6 million in cash dividends during the twelve months ended December 31, 2016. We expect to continue paying quarterly cash dividends in 2017. No shares of common stock were repurchased during the twelve months ended December 31, 2016. As of December 31, 2016, a total of 393,816 shares remain available for repurchase under our currently authorized stock repurchase program. We may in the future make purchases of its common stock in open market transactions at prevailing prices and may engage in private transactions where appropriate. We maintain the RCF for working capital and general corporate purposes and financing of nuclear fuel through the Rio Grande Resources Trust (the "RGRT"). The RGRT, the trust through which we finance our portion of nuclear fuel for Palo Verde, is consolidated in our financial statements. On January 9, 2017, we exercised the option to extend the maturity of the RCF by one year to January 14, 2020 and to increase the size of the facility by $50 million to $350 million. We still have the option to extend the facility by one additional year to January 2021 and to increase the RCF by up to $50 million (up to a total of $400 million) upon the satisfaction of certain conditions, more fully set forth in the agreement, including obtaining commitments from lenders or third party financial institutions. The total amount borrowed for nuclear fuel by the RGRT, excluding debt issuance costs, was $132.6 million at December 31, 2016, of which $37.6 million had been borrowed under the RCF, and $95.0 million was borrowed through the issuance of senior notes. Borrowings by the RGRT for nuclear fuel, excluding debt issuance costs, were $128.7 million as of December 31, 2015, of which $33.7 million had been borrowed under the RCF and $95.0 million was borrowed through the issuance of senior notes. Interest costs on borrowings to finance nuclear fuel are accumulated by the RGRT and charged to us as fuel is consumed and recovered through fuel recovery charges. At December 31, 2016, $44.0 million was outstanding under the RCF for working capital and general corporate purposes, which may include funding capital expenditures. At December 31, 2015, $108.0 million was outstanding under the RCF for working capital and general corporate purposes. Total aggregate borrowings under the RCF at December 31, 2016 were $81.6 million with an additional $267.9 million available to borrow, after giving consideration to the $50 million increase on January 9, 2017. We received approval from the NMPRC on October 7, 2015, and from the FERC on October 19, 2015, to issue up to $310 million in new long-term debt and to guarantee the issuance of up to $65 million of new debt by the RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. We also requested approval from the FERC to continue to utilize our existing RCF without change from the FERC’s previously approved authorization. The FERC authorization is effective from November 15, 2015 through November 15, 2017. The approvals granted in these cases supersede prior approvals. Under this authorization, on March 24, 2016, we issued $150 million in aggregate principal amount of 5.00% Senior Notes due December 1, 2044. The proceeds from the issuance of these senior notes, after deducting the underwriters' commission, were $158.1 million. These proceeds included accrued interest of $2.4 million and a $7.1 million premium before expenses. The effective interest rate for these senior notes is approximately 4.77%. The net proceeds from the sale of these senior notes were used to repay outstanding short-term borrowings under the RCF. These senior notes constitute an additional issuance of our 5.00% Senior Notes due 2044, of which $150 million was previously issued on December 1, 2014, for a total principal amount outstanding of $300 million. On February 13, 2017, the Company filed a rate case in Texas as discussed above. The outcome of this case could have a significant impact on the Company's results of operations in 2017. Since we cannot predict the outcome of this rate case, the Company has decided not to provide earnings guidance at this time. However, we will provide management's outlook on key drivers on the Company's February 23, 2017 conference call. A conference call to discuss 2016 financial results is scheduled for 10:30 A.M. Eastern Time, on February 23, 2017. The dial-in number is 888-503-8163 with a conference ID number of 1144948. The international dial-in number is 719-325-2405. The conference leader will be Lisa Budtke, Director Treasury Services and Investor Relations. A replay will run through March 9, 2017 with a dial-in number of 888-203-1112 and a conference ID number of 1144948. The replay international dial-in number is 719-457-0820. The conference call and presentation slides will be webcast live on the Company's website found at http://www.epelectric.com. A replay of the webcast will be available shortly after the call. This news release includes statements that are forward-looking statements made pursuant to the safe harbor provisions of the Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. This information may involve risks and uncertainties that could cause actual results to differ materially from such forward-looking statements. Additional information concerning factors that could cause actual results to differ materially from those expressed in forward-looking statements is contained in EE's most recently filed periodic reports and in other filings made by EE with the U.S. Securities and Exchange Commission (the "SEC"), and include, but is not limited to: (i) increased prices for fuel and purchased power and the possibility that regulators may not permit EE to pass through all such increased costs to customers or to recover previously incurred fuel costs in rates; (ii) full and timely recovery of capital investments and operating costs through rates in Texas and New Mexico; (iii) uncertainties and instability in the general economy and the resulting impact on EE's sales and profitability; (iv) changes in customers' demand for electricity as a result of energy efficiency initiatives and emerging competing services and technologies, including distributed generation; (v) unanticipated increased costs associated with scheduled and unscheduled outages of generating plant; (vi) unanticipated maintenance, repair, or replacement costs for generation, transmission, or distribution facilities and the recovery of proceeds from insurance policies providing coverage for such costs; (vii) the size of our construction program and our ability to complete construction on budget and on time; (viii) potential delays in our construction schedule due to legal challenges or other reasons; (ix) costs at Palo Verde; (x) deregulation and competition in the electric utility industry; (xi) possible increased costs of compliance with environmental or other laws, regulations and policies; (xii) possible income tax and interest payments as a result of audit adjustments proposed by the IRS or state taxing authorities; (xiii) uncertainties and instability in the financial markets and the resulting impact on EE's ability to access the capital and credit markets; (xiv) possible physical or cyber attacks, intrusions or other catastrophic events; and (xv) other factors of which we are currently unaware or deem immaterial. EE's filings are available from the SEC or may be obtained through EE's website, http://www.epelectric.com. Any such forward-looking statement is qualified by reference to these risks and factors. EE cautions that these risks and factors are not exclusive. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements or present or prior earnings levels. Forward-looking statements speak only as of the date of this news release, and EE does not undertake to update any forward-looking statement contained herein.


News Article | March 1, 2017
Site: www.greentechmedia.com

Arizona Public Service, electric industry representatives and solar advocates have reached a rate design settlement that could help bring an end to years of fierce policy debates in Arizona. "This settlement was a compromise with a lot of different parties involved and a lot of different interests recognized," Stefanie Layton, director of revenue requirements at APS, told GTM. "And it’s an agreement that’s a win for customers." "The term sheet provides an opportunity for continued investment in smarter and cleaner energy infrastructure," she added. "It gives our customers more choices and control through new rate options and allows for continued solar leadership in Arizona.” In a key development, the settlement plan dismisses APS' original request to implement mandatory demand rates for all residential and small commercial customers. Instead, it gives all new distributed solar customers the option to take a demand-based rate or a time-of-use (TOU) rate. It also allows non-solar customers to adopt a demand or TOU rate, but does not require that they select an alternative. However, after May 1, 2018, all new APS customers will move to a time-varying rate by default. If the settlement is approved by the Arizona Corporation Commission (ACC), new solar customers would also see a change in their self-consumption and grid export rates. The settlement would set the self-consumption offset rate around 12 cents per kilowatt-hour, which includes a grid access fee that APS solar customers must pay. The new export rate, based on the ACC's newly adopted resource proxy model, would be 12.9 cents per kilowatt-hour. Arizona solar customers are currently compensated for their excess solar generation at rates between 13 and 14 cents per kilowatt-hour. The "Resource Comparison Proxy" (RCP) methodology referred to in the settlement was approved in December as part of a yearlong value-of-solar proceeding (E-00000J-14-0023). Going forward, solar export rates will either be determined by the RCP, or by an avoided-cost methodology that uses five-year forecasting to evaluate the costs and values of energy, capacity and other services delivered to the grid from distributed generation. Export rates are to be reevaluated on an annual basis. While the export rate is subject to change, the proposed settlement released today keeps compensation distributed solar customers roughly on par for the near term. And while new rooftop solar customers are required to adopt one of four new TOU or demand-based rate options, solar stakeholders indicated that these options are workable. Significantly, the agreement also guarantees that existing rooftop solar customers will have 20 years of full retail-rate net metering on their current utility rate plan. According to the Arizona Solar Energy Industries Association (AriSEIA), the settlement, if adopted, would shrink Arizona's solar industry, but allow the market to remain intact. "The future of Arizona's solar industry was very much on the line in this case, and while this settlement doesn't help Arizona solar grow, it allows solar to remain a viable option for some Arizonans," said Brandon Chesshire of Sun Harvest Solar, board president of AriSEIA, in a statement. Anne Hoskins, chief policy officer at Sunrun, praised the collaborative nature of the agreement and underscored Sunrun's commitment to serving the Arizona market. But she also stated that the settlement "does not fully recognize the multitude of benefits that rooftop solar brings to all Arizonans." “As recent research confirms, rooftop solar power can deliver benefits above the retail rate of electricity and provides opportunities to all customers through grid modernization, local jobs, and affordable clean energy choices," Hoskins said. Sunrun and other solar stakeholders will continue to make their case that Arizona regulators should account for the full spectrum of benefits distributed solar provides during the annual export rate review process. Alex McDonough, Sunrun's new vice president of policy, added that his company does not view the Arizona outcome as a precedent for how the industry should value solar, "but we do support having collaborative discussion about how to make policies workable for solar and provide customers choice." The decision to forge a settlement agreement is widely viewed as the preferable alternative to months of legal debates over APS' proposed rate plan. Thirty of the 40 parties involved in the case signed on to the agreement, including ACC staff and the Residential Utility Consumer Office. Signatories to the settlement agreed to refrain from undermining it through ballot initiatives, legislation or advocacy at the ACC. Overall, the settlement proposal will increase the average residential electricity customer's monthly bill by $6, but that's down from the $11 increase APS initially requested. The deal also includes other customer benefits, including a $15 million refund in unspent cash earmarked for efficiency projects, an additional $13 million to assist low-income customers, and a rate-hike freeze until June 1, 2019. APS will also be permitted to spend $10 million to $15 million per year to install solar for low-income customers and at multi-family units. The utility also agreed to place a moratorium on new self-build generation prior to January 1, 2022, excluding distributed energy projects, renewable energy generation, microgrids and upgrades to existing infrastructure. The settlement is still subject to debate and a vote by Arizona's five elected utility commissioners.


News Article | February 15, 2017
Site: www.greentechmedia.com

The Arizona Corporation Commission (ACC) approved Tucson Electric Power’s proposed rate plan on Wednesday, which includes several new pricing options and monthly fees for rooftop solar customers. This is the first utility rate case to advance since regulators voted to eliminate retail-rate net metering in December -- following a three-year value-of-solar proceeding. The new Tucson Electric Power (TEP) plan requires residential and small commercial customers to pay a monthly fee to cover the costs of a second electric meter used to measure solar output, according to a company statement. Residential customers are required to pay $2.05 per month, while commercial customers are required to pay an additional 35 cents. Existing solar customers are exempt from the fees. The new charges will make distributed solar only moderately less attractive, but they could soon be coupled with more significant changes. The ACC’s December decision replaced the retail-rate credit solar customers receive for excess power they produce, with two new valuation methodologies based on the lower wholesale rates utilities pay for solar from large-scale power plants. Regulators determined that both methods would be established in utility rate cases and updated on an annual basis. Arizona regulators did not address the solar export rate in TEP’s case, however. The utility noted that additional changes for solar customers, including revised compensation rates, are expected later this year. Commissioner Bob Stump, whose term ended in December, said the new valuation methods will ensure “all ratepayers will be treated fairly and that technological innovation will continue to thrive.” Commissioner Bob Burns offered a dissenting opinion, noting that a broader range of distributed solar benefits should have been taken into account. Rooftop solar customers aren’t the only ones who will see revised rates this year. The average residential TEP customer will see their monthly bill increase by about $8.50 compared to rates paid in November 2015, when TEP first submitted its rate request. “The increase covers the cost of new energy resources, upgraded distribution networks and other necessary upgrades to secure and expand TEP’s energy grid,” according to a press release. In addition, when the rate changes take effect on or before March 1, residential and small commercial customers will have the option to choose from new Time-of-Use (TOU), Peak Demand and Demand TOU plans as alternatives to their existing rate. The new plans will reduce the basic service charge from $13 to $10, and enable customers to reduce their bills by limiting their electric use during peak periods. “Our new rates include a new suite of pricing plan options for customers that offer new savings opportunities and contribute to the long-term sustainability of our local energy grid,” said TEP President and CEO David Hutchens, in a statement. “These new rates also support our ongoing investments in cost-effective energy resources that help us provide safe, reliable service.” Last year, Arizona regulators rejected a proposal from TEP’s sister utility, UniSource Energy Services, to impose mandatory demand charges for residential customers. The utility’s lack of experience implementing demand rates was cited as one of the top stakeholder concerns. TEP’s new voluntary rates may offer a response to that critique, and could pave the way for a broader rollout of demand-based rates in TEP territory in the future. Arizona’s largest utility, Arizona Public Service (APS), already offers a voluntary demand rate, with roughly 120,000 customers currently subscribed. Last summer, APS submitted a request to implement mandatory demand rates for residential customers, as well as reduce compensation for rooftop solar customers. The ACC is also expected to rule on the APS case this year.


News Article | February 28, 2017
Site: www.marketwired.com

NEWTON, MA--(Marketwired - Feb 28, 2017) -  BRIDGE Energy Group, the leading consulting and systems integration company focused on improving utility operational performance, announced today that Hugo van Nispen has been appointed Chief Executive Officer. Mr. van Nispen has more than 25 successful years of utility and energy industry experience, most recently as President and CEO of KEMA, Inc., which he grew to be a recognized leader in energy consulting, testing and sustainability, and which has now merged with DNV GL, a global leader in risk management services. His background includes extensive work in grid modernization, systems implementation, strategy formulation and business process optimization. "I am looking forward to leading BRIDGE at a time when the utility industry is undergoing such transformational change meeting increasingly challenging customer, regulatory and shareholder expectations," said Mr. van Nispen. "The work the BRIDGE team does enabling clients to rapidly realize breakthrough results through grid modernization, operational effectiveness, cyber-security, and analytics, aligns perfectly with the critical solutions that utilities need to navigate through the business, technical and regulatory challenges of today and tomorrow." The electric grid operations and business model are in a state of significant transition. As a result, utility organizations are faced with increasing pressure from changing social, business and technological dynamics. In addition, tightening security, analytical measurement and increasing operational efficiencies require utilities to integrate agile consulting resources that are familiar with core systems and advanced technologies as well as the operational impacts to the business processes associated with their deployment. Hugo van Nispen is well versed in these new disciplines and poised to take BRIDGE to the next level. "Hugo's name is well known in the utility industry as a dynamic leader who has built successful businesses," said Colum Lundt, BRIDGE co-founder and Board member. "This industry is experiencing tremendous change, and it's the right time to bring in a leader with Hugo's track record to build upon the team's successes and take the company to the next level." BRIDGE has experienced tremendous growth over the past few years, having been named to Inc. 5000s Fastest Growing Companies 6 of the past 7 years while expanding its client base to nearly half of all the large North American utilities including industry leaders such as National Grid, Pacific Gas & Electric, Arizona Public Service, Exelon, and others. "Hugo will build on the strong foundation put in place by Dave Olsson and the senior team at BRIDGE," said Barry Goldsmith, Board member and General Partner at Updata Partners. "We wish Dave much success in his future endeavors and appreciate his enormous contributions to the Company." To enable breakthrough operational performance improvement at your energy enterprise, contact BRIDGE at 1.888.351.8999 or via www.bridgeenergygroup.com/contact-us/ BRIDGE Energy Group is the leading consulting and systems integration company focused on improving utility operational performance. BRIDGE combines business, OT and IT domain expertise to deliver and optimize innovative grid operations solutions. BRIDGE's capabilities and expert services enable engagement at any stage in the lifecycle, from strategy & regulatory to implementation & optimization. Founded in 2004, BRIDGE is headquartered in Newton, MA. For more information on BRIDGE, please contact 888-351-8999 or visit www.BridgeEnergyGroup.com.


PHOENIX, March 01, 2017 (GLOBE NEWSWIRE) -- Today, solar industry representatives, Arizona Public Service Electric Company (APS), and other stakeholders filed a rate design settlement with the Arizona Corporation Commission (ACC). In response, Anne Hoskins, Chief Policy Officer at Sunrun, issued the following statement: “The joint agreement between the solar industry, APS, and other stakeholders is more proof that rooftop solar is inevitable. Sunrun will stand by the terms of the settlement agreement and plans to provide Arizonans with access to rooftop solar, even though the settlement does not fully recognize the multitude of benefits that rooftop solar brings to all Arizonans. “As recent research confirms, rooftop solar power can deliver benefits above the retail rate of electricity and provides opportunities to all customers through grid modernization, local jobs, and affordable clean energy choices. "While Arizona does not serve as a model to encourage innovation in distributed energy, we are pleased that, together, we have ended years of debate on the future of rooftop solar policy in Arizona.”


PHOENIX, March 01, 2017 (GLOBE NEWSWIRE) -- Today, solar industry representatives, Arizona Public Service Electric Company (APS), and other stakeholders filed a rate design settlement with the Arizona Corporation Commission (ACC). In response, Anne Hoskins, Chief Policy Officer at Sunrun, issued the following statement: “The joint agreement between the solar industry, APS, and other stakeholders is more proof that rooftop solar is inevitable. Sunrun will stand by the terms of the settlement agreement and plans to provide Arizonans with access to rooftop solar, even though the settlement does not fully recognize the multitude of benefits that rooftop solar brings to all Arizonans. “As recent research confirms, rooftop solar power can deliver benefits above the retail rate of electricity and provides opportunities to all customers through grid modernization, local jobs, and affordable clean energy choices. "While Arizona does not serve as a model to encourage innovation in distributed energy, we are pleased that, together, we have ended years of debate on the future of rooftop solar policy in Arizona.”


News Article | February 22, 2017
Site: www.greentechmedia.com

What follows is a tale of two Dukes, one power plant and a bunch of hot air. As in steam. Steam produced by a combined heat and power plant that would burn natural gas on the campus of Duke University, but be owned and operated by Duke Energy. Duke the utility proposed the project for Duke the university (they share a common ancestor) in May as a way to install local generation while helping the host institution heat its classrooms, labs and hospital facilities. If the plant is approved, it could cut the university’s carbon emissions by reducing the need to burn natural gas in its campus steam plants. Clean energy advocates on campus and in the region had other ideas. They questioned the accounting Duke used to assess the benefits of the project, and warned that the project would create a long-term addition of fossil fuel infrastructure on a campus committed to carbon neutrality by 2024. Duke Energy, meanwhile, is hoping to gain experience in the up-and-coming CHP technology for development elsewhere in its territory. CHP works particularly well for college campuses, which have the electrical load and heating needs to justify such projects. Many of those campuses also hold strong public commitments to climate-change mitigation. "We definitely see this as a growing business within Duke Energy," Duke Energy spokesperson Randy Wheeless said of CHP. "There’s nothing like going to one that's already in existence and operating, and we hope the Duke University one will be that one for us. [...] We want to make sure this one goes correctly." This proposed 21-megawatt turbine, quite small by power plant standards, has shown the challenges of winning over public support for a new energy asset that's cleaner than traditional gas generation, but not absolutely clean. The proposal developed by the university administration and Duke Energy promises several big benefits. The gas plant will capture waste heat from electricity generation and pump it onto campus, making it a more efficient use of gas than traditional generators. That incidental heat source would allow the university to pull back on the natural gas it currently burns in two campus steam plants. A presentation on the topic says getting steam from the CHP project will cut campus natural-gas consumption by a whopping 50 percent, and reduce emissions counted under the Climate Action Plan by 18 percent. This tackles a major source of greenhouse gas emissions on campus, as well as avoiding $2.5 million in investments that would otherwise be needed for hot water infrastructure. The university expects a two- to three-year payback. Additionally, having an on-campus power generator serves the resilience of the university’s labs and hospital in the face of grid interruptions like hurricanes or thunderstorms. Diesel backup generators currently serve that role, but gas turbines are generally more reliable machines. Duke Energy would need to perform "minor relaying additions and programming" to enable this microgrid application, said Michael Schoenfeld, vice president for public affairs and government relations. A clean alternative like a solar array cannot guarantee backup at night, and pairing energy storage with solar would cost a lot more for this service than the gas turbine will at this time. The administration views resiliency improvement as the top priority in the project, Schoenfeld noted, followed by emissions reductions and cost savings. These benefits come at the expense of a new facility built to burn natural gas, and that on its face conflicts with the institutional drive toward a smaller carbon footprint. After the administration announced the plan in May, campus activism forced a pause for additional review. Duke Energy asked the North Carolina Utilities Commission to postpone a hearing on the project from Jan. 24 until May, campus newspaper The Chronicle reported. Some of the concerns centered on the internal processes that led to the proposal, and whether or not the campus sustainability bodies were adequately included. The local response also posed a deeper energy question: Should an institution committed to reducing its climate impact embrace a fossil fuel technology, even a relatively clean one? In this case, Duke aims to host a gas plant on campus and claim the carbon reductions it allows versus existing campus emissions. Since the new plant's emissions come from Duke Energy's business in generating electricity for the grid, the university would count them as part of the emissions factor for purchased electricity, not as emissions originating from campus. A pair of professors from Duke’s Nicholas School of the Environment argued in The Chronicle that the university should account for the plant’s carbon emissions when assessing the benefits of the proposal. “Under this alternative assumption, the net greenhouse gas emission benefits to Duke University are dramatically reduced, since the carbon intensity of electricity produced at the new CHP plant is considerably higher than the carbon intensity of the current Duke Energy electricity generation fleet,” they wrote in a letter to The Chronicle. When factoring in those emissions, plus transmission losses and upstream leakages associated with the additional gas consumption, the professors calculated a net Climate Action Plan emissions reduction of less than 4 percent. This debate comes down to a matter of where to draw the boundaries of responsibility. If Duke Energy built the plant nearby on land it acquired, and the university bought the steam and burned less fuel, there would be a stronger case for the 18 percent emissions reduction. But that’s not the case here. “This plant would not be built without Duke University support," said sophomore Claire Wang, who runs the Duke Climate Coalition. “We tout ourselves as a climate leader, and part of that is being responsible for the emissions that we cause.” The administration has asked the Campus Sustainability Committee to evaluate this and other questions about the proposal, and to make a recommendation about how to proceed. They are open to a change in the carbon accounting, Schoenfeld said. The hope is to get an answer by May, which would guide the administration's approach to a board of trustees meeting that month. If all goes well for the plan, the utility could then move ahead at the PUC. The questions facing utility regulators touch on a different set of concerns, specifically the equity of who pays for what. As Duke Energy's first CHP project in the state, this would set a broader precedent that the regulated utility can leverage ratepayer funds for a grid-serving generator that also delivers a specific, localized benefit to a particular customer. Ratepayers will get a deal from the Duke project that's as cost-competitive as more conventional, large-scale gas plants, Wheeless said. The utility would save on cost thanks to "a very attractive lease price" for the campus land, and the university's steam payments will go back to ratepayers. Ratepayers, though, would have to pay $55 million for the ability to create that steam in the first place. The ratepayer dollars going to create a resource for a particular host customer is what sets this apart from typical plant construction. There are some similar cases in the world of microgrids, with an important distinction in payment structure. Arizona Public Service is building two microgrids, one at a military base and one at a new data center. The host customer contributes for the resilience benefits in the event of an outage. The microgrids will provide grid power and other services most of the time, so APS asked regulators for permission to rate-base the costs for those services. A microgrid collaboration in Denver between utility Xcel Energy and Panasonic includes solar panels and a big battery on the latter's new facility there. Panasonic contributes some of the assets and gets backup power for its operations center; Xcel gets to rate-base its expenses for the assets that will improve grid reliability the rest of the time. Duke, on the other hand, has been piloting a “utility-controlled, single-customer microgrid” model, and has been able to enter costs into the rate base when the microgrid serves the distribution grid, rather than splitting costs with a host client. Now, this Duke project is not a microgrid, yet. That means the only benefit the school gets that the grid doesn't is the heat, which the school will pay for. Critics could still charge that if the utility wants to spend time on projects with a more localized benefit, it should extract more in return for the ratepayers at large. A plant that only served one customer wouldn't be a good candidate for the rate base, Wheeless said, but this is different. "In this case, it's connected to a substation that serves that customer but also serves other people in the community too," he said. Down the road, if the Dukes pursue the microgrid expansion, they could work out an appropriate cost-sharing agreement on that service. The way the NC Utilities Commission rules on CHP cost sharing will shape the utility's options in paying for projects like this, which will affect its willingness to pursue them. One lesson from this experience is already clear: Rolling out new CHP infrastructure isn't a technical challenge so much as a social one.


Patent
Arizona Public Service | Date: 2011-07-19

A transformer (26) is monitored by a dissolved gas monitoring device (28). A method (36) in the form of executable code instructs a processor (34) to estimate a remaining life (124) of the transformer. The method includes receiving (126), from the monitoring device (28) data elements (60) representing a current value (134) of dissolved gases (72) in the transformer (26) that correlate with degradation of insulating material in the transformer. Adjustment values (142, 144) are determined for the gases (72) in response to isolated events (160, 162) occurring at the transformer. The current value (134) and the adjustment values (142, 144) are combined to obtain a total value (114), and a degree of polymerization value (116) is estimated using the total value (114). The value (116) is converted into a measure of remaining life (124) of the transformer, and the measure of remaining life (124) is presented to a user (58).

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