GE Digital Energy field tests mobile damage app

By Karen Haywood Queen/Published Sept. 08, 2015/Smart Grid Today

EXCLUSIVE INTERVIEW

Makes predictions based on partial outage data

Helps manage, maximize benefit from foreign crews

GE Digital Energy’s new mobile damage-assessment app could shave one to two days from a two-week, major storm-related outage – saving utilities millions of dollars, John Chisum, utility product line leader for GE Digital Energy, told us recently in an exclusive interview.

The app was released in February, according to the GE website, and this interview was our first inquiry into what it offers utilities that use it.

“Using this application, a utility can start inspecting things in the field a day earlier after a major storm or other event than they could using traditional logistic systems,” Chisum said. “Putting people in the field a day earlier can cut days off recovery time and save multi-millions of dollars.”

For a major hurricane, a full restore might take 14 days without using the app, he added. “If we can restore them in 12 days, we can save the utility millions in revenue stream and the cost of foreign crews.”

“Workers can be out in the field as soon as it is safe,” Chisum said. “This could be within hours of the storm passing, based on safety conditions. A utility could have repair crews staged in a safe location with the app downloaded so as soon as conditions are safe, they could be sent into the field immediately,” he added.

This app offers a simple user interface, a GPS feature and works on any popular mobile device – not just those owned by the utility, Chisum said. During major storm recoveries, mutual-assistance crew members from other utilities can download the app onto their own devices, he added.

As crews check for damage and enter new information, the GPS can identify their location.

Although the app will work with legacy meters, smart meters enhance the performance of the app by offering more real-time data, thus restoring power faster, Chisum said.

The cost to the utility is expected to cost about $1 million for a utility with a million smart meters, Chisum said, though the firm believes he savings from a single major outage could offset the investment. The firm considered a shared-risk model of pricing, where the utility would pay based on how much money the app saved after a storm.

“If you were able to pull one to three days off that event, what would that be worth to you?” he said. “They might save tens of millions of dollars.

“That risk-sharing model could be much more profitable to GE,” but utilities might not have been happy with the bill, Brian Friehauf, GE Digital Energy asset management product line leader, told us. “That’s the tricky part. That’s why we went with a more traditional pricing model.”

Two utilities are field-testing the app to let GE further refine it, Friehauf said. Five utilities expressed interest, but the technology firm limited the rollout and the two do not want to be named at this stage, he added.

GE expects to offer the app more widely by the end of this year, he added.

Many utilities still use manual, paper-based processes, requiring data-entry at the home office to evaluate damage after an outage, Chisum noted.

“Probably 75% of utilities are still gathering data manually to some extent, even if they have a mobile solution for their own staff, because they don’t have devices to give to outside contractors,” he added. “If you’re doing it on paper in the field, a lot of the information has to be re-entered in the office.

“Anybody coming into the area to assist can use the device they brought with them,” he added.

With other apps, when the mutual-assistance people show up, the utility need needs to give them a laptop and credentials and teach them how to use the app. That this is not always a smooth process as some foreign crews are resistant to using another utility’s system.

GE has an older mobile app but use of it has been limited to a utility’s own employees, Friehauf said.

“Crews could download information onto their specific devices, but we couldn’t leverage the devices to mutual-assistance crews.

“It was a tool useful to utilities but it stayed within the utility’s boundaries. This [new app] allows us to perform a much better damage triage assessment.”

Damage prediction included

Information available on that older app is more limited, Friehauf said.

“If you’re doing damage assessment on a company’s existing mobile solution, the information doesn’t come back in a form that lets a utility say, ‘Based on the data we have, there are 50,000 poles we need to replace,'” because older systems typically do not have the ability to predict totals based on a partial collection of data.

Smart meters can help give utilities a more detailed damage assessment, and as a utility installs more smart meters, the overall system will become more adept at providing data, Friehauf said.

During an outage, utilities get good information already from smart meters but it is incomplete, Chisum noted.

Acting on AMI info

“If I have a great smart metering infrastructure out there, I would get the signaling or lack of signaling to know who is out of power. That helps with the outage-restoration process, but there are still some details missing for restoration of the network.

“The automated system can tell me that everyone on the street is out of power, but it can’t tell me about the infrastructure requirements. It can’t tell me if five or three poles are down.”

In an initial damage assessment with the new app, a storm team can walk 10% of the affected area and the app will let them accurately predict total damage, Chisum said. The utility can then order the right number of foreign crews and provide statements to the media about how long it will take to restore power, he added.

It is still the case that “in some cases, mutual-assistance crews are brought in and the utility doesn’t know yet where to put them to work,” he said, “or first responders show up and may not have all the skills and materials to make the repairs.”

Possible scenarios include a bridge needed for access being so small only one type of truck can cross it. “Very often, a large bucket truck that can’t cross that bridge will get sent and then another truck has to be sent. With the app, they will have this information.”

Efficiency for minor outages

Utilities can benefit from using the app in a minor outage not related to a storm, Chisum said. It helps them determine the experience a crew would need to correct it and, again, lets the main office know of any size restrictions on access roads and bridges.

One of the utilities field testing the app had calm-weather days in mind when requesting the app, he added. The utility wanted its workers to get accustomed to using it before a big emergency, he added.

Most of the requested refinements from the early adopters were minor, such as changes to the graphics interface and better usability, Chisum said. The app works now on mobile devices using Apple and Windows operating systems, he added, and Friehauf said that by fall, an Android version will be added.

Other officials can help

A utility could provide the app to police and firefighters to let them share information with the utility, Chisum said. If such government employees saw a utility pole down or other issue, they could let the utility know via the app.

Such information sharing would be one-way only, he added, noting the police and firefighters would not have access to the big-picture data.

 

Silver Spring transfers grid expertise to cities

By Karen Haywood Queen

Published Oct. 5, 2015/Smart Grid Today

EXCLUSIVE INTERVIEW Many start with smart streetlights, build onto network

With two-way communication, cost savings and improved reliability, smart LED street lighting systems are helping create smart cities – using technology similar to what is being used to build the smart grid, Sean Tippett, director of smart cities at Silver Spring Networks, told us last week in an exclusive interview.

Since it came on the scene in 2002, Redwood City, Calif-based Silver Spring became a leader in critical infrastructure networking – starting with utilities, he said. Silver Spring helped Pacific Gas & Electric (PG&E) network 5 million devices over 70,000 square miles, he added.

“We’ve spent a lot of time working with our utility customers, helping them securely network their assets. “In doing so, we’ve provided a large amount of value in grid reliability, improved service, better information for customers and better information for utilities,” Tippett said. “We’re starting to see a new customer set emerge over the past couple of years that can benefit from the same technology: cities.”

QUOTABLE: There are a lot of similarities between smart grid and smart city. Both have the need for secure, scalable, multi-application networks. For utilities, critical infrastructure means their smart metering or other smart equipment on the electric distribution grid. For cities, critical infrastructure means their street lighting systems, intelligent traffic systems, smart water networks, smart parking, weather and air quality sensors, EV chargers and more. – Sean Tippett, director of smart cities at Silver Spring Networks, in an exclusive interview

“The common thread is, we network large-scale outdoor devices. We’re able to take all the things we’ve learned from employing smart grid with our utility customers and port them over to cities,” he added.

For cities, streetlights are the first step in becoming smarter, Tippett said. There’s a strong business case for making the move: Over the past two or three years, LEDs have become longer lasting, more energy efficient and less expensive, he noted. “It’s the merging of two technologies,” Tippett said. “LED technology has really started to come down in price. We’re also seeing the full maturation of this utility-scale networking technology for cities.”

LEDs alone yield significant savings, but smart networking yields even more savings, he added. A city switching from legacy high-pressure sodium lights to LED and controls can get its investment back in six to eight years, depending on its costs, a Silver Spring case study found.

Adding two-way communication/networking helps cities save even more because they get to know immediately when a light is out or shining during the day – and so they can avoid sending out patrols to look for malfunctioning lights or waiting for citizens to report problems. Networked LED lights can eliminate up to 90% of truck rolls and cut repair and maintenance costs through more accurate crew dispatching, the case study found.

As Silver Spring began to work with cities, especially small ones such as Fitchburg and Randolph in Massachusetts, it realized some cities looking for a smart city network were not looking to expand their IT departments to support the new technology, Tippett said.

“Utilities typically have robust IT departments, used to owning their equipment and hosting it in their data center. “With some cities, you can see that they don’t have the ability, budget or the desire to build out IT to support the network. That understanding drove us to offer networking as a service,” with all the in-field networking infrastructure and back-office data services to support streetlight networks and other networked applications, he added. A city has only to manage the application by logging in with secure credentials to a mapped system to see if there are any malfunctioning lights.

Florida Power & Light (FPL) is working with Silver Spring on “the largest networked street lights project in the world – more than 500,000 lights,” FPL CEO Eric Silagy said today in prepared remarks. “Establishing a smart street light network will continue the advancement of our smart grid and deliver benefits to our customers, including more reliable and efficient service.”

Silver Spring quoted Silagy as it told the press about an upgrade to its street light and smart city control and management platform, now called “Streetlight Vision 6.” The software has over 100 new features, the firm said, adding that over 500 cities use Silver Spring’s street light-control software.

In addition to the towns in Massachusetts, Silver Spring is working with Bristol, England; Chicago; Copenhagen; Glasgow, and Paris on their smart cities programs, Tippett told us last week.

Streetlights earn savings

The benefits of networked streetlights extend beyond troubleshooting repairs, according to the case study to which Tippett pointed us. Cities with networked streetlights can easily dim the lights and alter the timing to save money. At a smart cities conference in Washington, DC, last month, Tippett discussed case studies from Bristol, Chicago, Copenhagen, Miami and Paris.

After networked streetlights, cities can add more applications such as networked, intelligent traffic systems and environmental sensors to measure CO2 and noise, he said at the event. Copenhagen was one of the first cities to adopt smart street light technology and added more applications over the years, Tippett said.

“They’ve been very proactive about trying to gather all the stakeholders and try to find different ways they could use the system,” he told us.

Boost safety for cyclists

In Copenhagen, where 40% of all trips taken are by bicycle, traffic sensors can work with networked lighting so streetlights brighten when a bike approaches an intersection, Tippett said.

“The bicyclist is able to transition through the intersection in a much safer manner than before.” “That’s especially important in Copenhagen, where bike traffic is expected to grow to 60% of all trips in four years,” he added.

Implementing smart city communication infrastructure may seem daunting, but city leaders who are considering it “can establish a multi-application smart city network through a lighting system. You can do it within budget and you can do it with your existing IT department. Any city can be a smart city,” Tippett assured.

Changing regulatory model could offer big benefits

By Karen Haywood Queen

Published Sept. 17, 2015/Smart Grid Today

EXCLUSIVE Revamping the current US utility regulatory model to create a network of distribution system operators (DSOs) to control the grid would open the market for solar PV, energy storage, energy efficiency programs, EVs and DR, Michael Rutkowski, managing director within Navigant’s energy practice in the firm’s Chicago office, told us recently in an exclusive interview.

“Having the grid be essentially ‘plug and play’ for all these types of distributed energy resources would enable consumers to also be ‘prosumers’ – producers of energy,” he said. “Such a system would provide equal access to the grid, essentially serving as a gatekeeper to allow those new types of services to become more available. It would offer flexibility and more choices for consumers,” Rutkowski said.

But such a change also would pose challenges for pricing, cost recovery and reliability, he added. He emphasized that both he and his consulting firm remain neutral on the issue and weigh the pros and cons on a case-by-case basis since individual utilities could try to make the case for a DSO within their own service territories.

Former FERC chairman Jon Wellinghoff, who now represents clients in a number of emerging energy fields for Stoel Rives law firm including distributed solar PV, proposed such a model, we reported in March (SGT, March-7). Wellinghoff outlined a system on the retail side where state-regulated distribution utilities would continue to own the distribution grid but would transfer operations to independent DSOs akin to the ISO/RTOs on the transmission side.

If these DSOs wanted to be involved in another energy business, they could create a separate division, Rutkowski said. Consumers could choose among different billing and pricing structures and could better control their energy costs. Discussion of such a change is in the early stages, he added, but “there has definitely been a lot of discussion and debate on the topic.”

As pricing and financing costs for solar and other distributed energy drop and prices for energy in some regions rise, more scenarios are arising where such models might make sense, Rutkowski said. “The cost trajectories of a number of these distributed energy technologies are getting to the point that within a number of years, they’re projected to be at grid parity, at which point the economic conditions would exist for customers to capture savings over their current service,” he said.

Since energy prices vary widely from state to state, some areas will have more financial incentives to make changes. For example, residential power is 30¢/KWH in Hawaii compared with 9¢/KWH in Louisiana and Washington, according to July statistics from the US Energy Information Administration. “It’s a region-by-region story in terms of making it work,” Rutkowski said. “States with relatively high retail rates such as Hawaii and California (17¢/KWH) are at or near the tipping point where new technology produces savings for customers,” he said.

“On the other hand, in some regions we already have very low cost energy being delivered to consumers. For example, Idaho has very low electric rates (10¢/KWH for residential customers), and it could take a while before the business case can be made that DER (distributed energy resources) will provide net cost savings to consumers. But there are other benefits to distributed resources such as reliability of supply at home that some consumers might be willing to pay for.”

Proper design of the pricing structure will be important in any regulatory model, he added. “The one thing you hear about the most as it deals with net energy metering for solar PV is, ‘How do we ensure that the costs of the distributed grid are being fairly and appropriately attributed to the customers that incur those costs?’ ” Rutkowski said. “The tensions lie in the possibility that one customer class could be subsidizing another customer class. If those pricing structures are not designed appropriately, ironically, low-income customers could be subsidizing higher income consumers. “It gets very complex. That’s where the devil’s in the details – in the rate design.”

Under the current market design, this issue already came up in Australia, Hawaii, Nevada (SGT, Aug-3) and elsewhere as utilities and PUCs worked on how to fairly price the energy PV customers sell back to the grid (SGT, March-6). System reliability is another concern under a DSO model, he added. “If the market transition isn’t set up right, there could be a risk where electric grid reliability is hurt. “If the utility is in a position where it is not recovering its costs, then it may not be able to make investments to maintain reliability and maintain the system. Without that backbone of reliability, you could have longer and more frequent outages.”

Grid security is another issue that should be considered and included in any plan to set up DSOs, Rutkowski said. With more participants in the market, there is more risk for security incidents, he added.

Another question for consideration is whether utilities themselves could serve as those DSOs or whether the DSOs should be independent. On the pro-utility side, “some utilities would say, ‘We know our distribution grid and we’re in the best position to manage it. We know where investments are needed and where and how third parties can access it.’ “In performing that service [as a DSO], utilities should be able to recover costs,” Rutkowski said. But if utilities served as the DSO, the independence between owning and operating the grid would be lost, he added.

“It has to be a well-planned and well-orchestrated transition. Utilities need to be integrally involved in the process.”

Wellinghoff Urges Creation of Distribution ISOs

Published March 17, 2015 in Smart Grid Today. By Karen Haywood Queen
IOUs would own grid, maintain it but not run it

EXCLUSIVE INTERVIEW

In retail markets, grid ownership and operation should be separated to allow competitive energy sales, Jon Wellinghoff, former chairman of FERC, told us recently in an exclusive interview. “Retail energy sales are a competitive product and as a competitive product, should be provided by multiple entities,” he added.

In the current model in most states, there is no incentive for utilities to encourage DG and DR because successful deployment may cut the need to boost the utility’s asset base, Wellinghoff, who stepped down as FERC chairman in 2013, said. He argued for unbundling utility services and increasing competition while at FERC.

Such a separation between operation and ownership of the power transmission system already works well in the power wholesale markets at ISO/RTOs, he added, noting competition has lowered prices.

QUOTABLE: Most of the RTOs are doing a very good job of creating robust markets at the wholesale level and incorporating as many products as possible – both supply and demand-side products. In those markets, you create systems that improve efficiency and provide benefits to individual entities that are providing products to the market and providing benefits to all members of the market. The result is, overall prices go down. – Jon Wellinghoff, former FERC chairman, in an exclusive interview

He imagines a system on the retail side where state-regulated distribution utilities would continue to own the distribution grid but would transfer operations to independent distribution-system operators akin to the ISO/RTOs on the transmission side. If these distribution system owners wanted to be involved in another energy business, they could create a separate division, Wellinghoff said.

“The only monopoly service would be the owner and maintainer of the distribution system,” he added. “The Duke Energies and other owners of the distribution system would be like the transmission owners on the bulk grid. They would own the assets, maintain the assets and earn a regulated cost-of-service return on those assets.”

The resulting independent distribution operators would operate a market platform for the sale of energy and other energy service products to retail end users, Wellinghoff said. Competitive firms would facilitate and aggregate these energy services, including DR and energy efficiency.

Such a separation could yield results in the utility sector similar to what happened when the Bell system was broken up in 1984, we noted and Wellinghoff agreed.

QUOTABLE: To the extent that consumers will have new and additional sources for the generation of energy through solar PV and other local generation opportunities, as well as storage opportunities, [the utility sector] will start to look like this diverse world we now have in the communications sector. – Wellinghoff

Seventeen states and the District of Columbia currently have retail energy choice, but none yet provides an ideal array of distinct options, he added.

In an ideal competitive retail market, consumers might choose among different billing and pricing structures with and without demand or time-of-use pricing, from their retail provider, Wellinghoff said. Such pricing would provide customers incentives to cut energy use during peak times.

In turn, that would lessen the need to build peak generation plants and reverse the trend of higher peak-to-average demand ratios, he added.

“We really need a market-based system that provides consumers with multiple market choices that allow them to control their energy costs overall. We would have more opportunities for that if we had a retail choice structure.

“I would advocate for allowing retail third-party providers to provide services for consumers because it is competitive.”

To create such a system, nothing would have to change at the federal level but the states would have to change how their PUCs oversee the distribution utilities, Wellinghoff said. States already looking at such a change include California, Hawaii, Minnesota and New York, he added.

There has been much discussion surrounding the fairness of net energy metering (NEM) policies for rooftop solar, we reported this month (SGT, March-6) but a market-based, retail energy pricing system would transcend that discussion, Wellinghoff noted.

“Efficiency is a better word than fairness,” he said. “Any pricing system that does not provide for a market-based system that looks at costs and benefits that are being provided by consumers participating in these systems is not efficient. You improve efficiency and everybody wins.”

Wellinghoff stepped down as FERC chairman in 2013 and joined the law firm Stoel Rives based in Portland, Ore. The firm listed San Francisco and Washington, DC, as the offices he works in.

Since leaving FERC, he has written frequently about NEM and fixed charges. Wellinghoff represents clients in an array of emerging energy technology fields including energy storage, DR, data analytics, distributed solar PV, advanced transmission control technology and waste heat recovery systems, the Stoel Rives website said.

BOTTOM LINE: We included the topic tag “transactive energy” on this story because we think the idea of distribution ISOs is a good match to the idea of a future in which computers buy and sell electrons from a variety of systems and devices based on finding the lowest cost, creating market efficiencies and price signals throughout the energy internet of things. That is one way of describing the transactive energy future we would love to see evolve from some of the old models used now. Taking the ISO/RTO concept and using it on the distribution side begs one to imagine transactive energy systems having access to those market efficiencies. That seems like a very smart grid, maybe Smart Grid 3.0.

The Fix: Critical Insights on US Grid Cybersecurity

Published as a series January through May 2015 and then as a special report for sale by Smart Grid Today.

By Karen Haywood Queen

Security risks, including and maybe especially cybersecurity vulnerabilities, abound inside utilities in the US. Digital SCADA systems are thought to be air-gapped but are not. Internet service provider systems used for SCADA systems are thought to be private but are not. Utility staff members have been wrongly presuming using a SCADA protocol across the internet was obscure enough to avoid hacking.

And risks are posed by software bugs, SCADA-system programming errors, substation maintenance mishaps, payment kiosks in shopping malls, utility employees checking email and surfing the internet at work and online systems that let consumers track energy use and savings.

The vulnerabilities expose the nation to risks that might not be obvious. Experts we interviewed noted that countries like Iran and North Korea can cause damage to critical infrastructures – and a hostile country could first cripple the US power grid and then launch nuclear weapons.

All kinds of malicious cyber-attacks on the grid are growing, including attacks that exploit what the industry calls “zero-day” vulnerabilities – ones without a patch or fix. At the same time, increased smart grid automation and internet connectivity create vulnerabilities linked to mistakes, negligence, misguided intentions and other mundane actions.

Renewables are also a major cybersecurity vulnerability for utilities and their smart grid tech providers.There is a bit of hope for those concerned about cybersecurity – but in the form of tough love, we were told.

Many utilities in the last 18 months have moved to insure themselves against problems caused by cyber attacks, but one out of 10 initially are turned down because their systems are not sufficiently protected, an expert told us.

In this 41-page report, (which I wrote) you will get critical insight on the state of US grid cybersecurity from the experts listed below, plus a list of 14 actions that utilities and other stakeholders should take now to minimize risk.

14-point Action Plan Recommended by Top Cybersecurity Experts in Smart Grid Today’s “The 2015 Fix”

No single fix will eliminate cybersecurity vulnerabilities in the grid, cybersecurity experts told us. No single set of stakeholders can solve the problem, and all the parties involved can take steps to lessen the risk. Those parties include utilities, insurance firms, IT and security experts, RTOs, control system experts, control system vendors, proponents of renewables and federal regulators. This report offers a 14-point action plan that cybersecurity experts believe will yield big results.

A peek at the action plan for 2015:

  1. Consider one-way OT (operational technology) connectivity to the outside world;
  2. Take an active, preventive approach to security and reliability;
  3. Set rules for access, and
  4. Inventory devices and software

(Please note: this piece is copyrighted by the owner of Smart Grid Today and is posted here only for purposes of showing what I can do. It is not intended for distribution beyond this site. To purchase a copy, please contact Smart Grid Today).

 

Smart Grid Enigma SGT_The2015Fix_Final

Australia Suffers Net Metering, PV Challenges

By Karen Haywood Queen Smart Grid Today January 12, 2015

EXCLUSIVE INTERVIEWS

Energy pricing creates ‘death spiral’ as AC grows

The energy pricing structure in Australia is creating a world of energy “haves” and “have-nots” where homes with large air conditioning systems and/or solar panels are subsidized by those with neither, leaders of two industry groups told us recently.

“Many higher income families are putting more than their fair share of pressure on the grid by using large AC systems and creating extreme peaks,” Mark Paterson told us. He is grids and renewable energy integration leader at CSIRO’s (Australia’s National Science Agency) Energy Flagship.

“Meantime, many of these people also have installed a lot more PVs. So their electricity bills have been significantly reduced as they sell power back to the utilities. The rates do not actually reflect a home’s peak demand impact on the grid.”

GROWING PAINS
3rd in a series on the challenges of renewables

Both tariff reform and, in time, something like the transactive energy approach under development in the US (SGT,2013-Nov-7) and the Netherlands (SGT, Dec-18) are needed to resolve this issue, the pair said.

For customers with large air conditioners, the cost of their network service exceeds what they pay by AU$683/year (US$585/year), Energy Networks Assn (ENA) CEO John Bradley told us. His organization represents Australia’s gas and power distribution firms.

For solar customers, the reduction in network charges exceeds the reduction in network costs by AU$29-117/year (US$24-95/year) depending on which direction the panels face, Bradley said, citing a report ENA published last month on a national approach to power network tariff reform.

Paterson was in the US last month to speak at the GridWise Architecture Council conference on transactive energy in Portland, Ore, and he called the growing problem “a social justice issue” in his country where, according to Oxfam, the richest 1% own the same amount of wealth as the bottom 60%.

In the last 15 years, Australia experienced a sharp rise in residential AC adoption. In 1999, about 35% of homes in the country had AC, according to figures ENA released in April. By 2010, that doubled to 70%.

When many residential customers install AC, this can drive the need for expanded distribution grid capacity that is under-used for most of the year, Paterson said. This drives up rates for all customers, he added.

About AU$11 billion (US$9 billion) in peak generating and other infrastructure has been built to meet this peak demand for AC and is used only 1% of the time – the equivalent of only four or five days a year. Meeting this demand at peak times costs AU$2,500/appliance (US$2,000/appliance), the ENA estimated.

“It’s a major factor in over 50% of every electric bill,” Paterson said. Network charges range from 25-58% of the bill, ENA said.

Paying for this infrastructure has sent power bills soaring – 8-20%/year – and created what Paterson called “a death spiral” as more PVs are added in response to higher power bills. Consumers now pay over AU33¢/KWH (US27¢/KWH), he added.

“There’s a lot of bill shock every year,” Patterson said. The Energy Users Assn of Australia in 2012 said energy prices in Australia were among the highest in the world. Those rising energy prices – combined with high buyback rates of over AU40¢/KWH (US33¢/KWH) for early adopters of PV-generated power – spurred fast growth in PV installation for those who could, Paterson said.

As all those AC units came online, peak demand grew dramatically, creating a low network capacity use – the ratio between peak demand and average demand. From 2001 to 2012, peak demand grew 20-37%, twice the rate of average energy demand during the same period, ENA said. In newer subdivisions, average energy use is just 21% of peak demand.

Meanwhile, solar panels in that time grew to over 1.3 million for about 9 million homes from almost none in 2007, according to 2014 figures from ENA and the Australian Institute of Family Studies. That growth was compared with 500,000 panels in the US for 120 million homes.

Initial Australian government incentives offering payments of over AU40¢/KWH (US33¢/KWH) for PV generation – an amount higher than customers were billed for energy use – helped drive that PV growth, Paterson said.

Participation in the PV programs typically exceeded what the original policymakers may have anticipated. In some states, that became a runaway train. Not everyone could catch the train,” he added.

“There are a lot of families living in apartments where it’s not simple or perhaps even possible to take advantage of PVs,” Paterson said. “Meantime, if you happen to be able to install solar, you can either be paying nothing for your electricity bill or you may actually be paid.

Wrong pricing hurts

QUOTABLE: This is increasingly presenting a social inequity challenge. Australian households with large AC and PVs are placing an inordinate burden on that common shared infrastructure that they’re not paying for due to Australia’s volumetric rate structures. This is understandable, however, because our rates do not signal how customer choices impact the grid or the community as a whole. – Mark Paterson, grids and renewable energy integration leader at CSIRO’s (Australia’s National Science Agency) Energy Flagship

For example, a typical PV customer in New South Wales provides a benefit to the grid of about AU$10/month (US$8/month) but receives benefits estimated at AU$69/month ($56/month), Bradley said.

Those payment rates for new PV connections are much lower now, around AU8¢/KWH (US7¢/KWH) in most states, Paterson said, but solar customers who installed solar early on have been grandfathered in under old rates until they expire as late as 2028 in some states, according to ENA.

HECO Faces Big Challenges After Solar PV Explosion

By Karen Haywood Queen

Published January 27, 2015 Smart Grid Today 

Solar business slows dramatically behind inspection queue

With 12% of customers using PV, new rules were needed

EXCLUSIVE INTERVIEW

As Hawaii’s electric utilities address reliability issues stemming from an explosion in home PV systems, there are solar-integration lessons to be learned for grids in the rest of the US, EPRI senior project engineer Ben York told us recently. He spoke to us from Honolulu where he is involved in research on PVs and other renewables.

QUOTABLE: The biggest takeaway is, we’re starting to see the need for standards and equipment that goes beyond what we’ve traditionally thought about for PV generation. Hawaii is very dynamic and rapidly changing in this particular field. – EPRI senior project engineer Ben York

Hawaii had 850 home solar systems connected to the grid in 2008, Darren Pai, a spokesperson for Hawaiian Electric Co (HECO), told us recently. By the end of last year the number had surged to 51,000, he added.

That’s 12% or about one in eight of HECO’s 450,000 customers – far more than any other utility in the nation, Pai said. Compare that with an average of one system per-240 homes on the mainland, York said.

GROWING PAINS: Part 7 in a series on the challenges of renewables

“It’s been an incredibly rapid pace,” Pai said.

The huge growth in PV generation, with power flowing back onto the grid and potential fluctuations when clouds block the sun, can strain a system designed for a one-way, constant flow from the point of generation to the end-use customer, York noted. The danger is that power flow will veer from required parameters for voltage, posing risks to utility infrastructure, customer equipment and utility employees working in the field, he added.

“Now you have power generators, ‘prosumers,’ on a system that’s designed to be one-way,” York told us last week. “That changes how the system works. If you get a lot of generation concentrated in one area, it’s so far from how the system is designed, it may pose a reliability problem.”

HECO was not prepared for the explosive home-solar growth, leaders of Hawaii’s solar firms told us.

“This whole solar PV thing started to blow up in 2008,” Gary Ralston, founder of Hawaii Island Solar – on the island of Oahu – and a board member of the Hawaii Solar Energy Assn (HSEA), told us this month. “By 2011, it was just going gangbusters.

QUOTABLE: I don’t think Hawaiian Electric had any idea that all these people would be buying PV systems. So they, I’m sure, were caught by surprise. They had to put some kind of brakes on it before things got out of hand. – Gary Ralston, founder of Hawaii Island Solar and a board member of the Hawaii Solar Energy Assn

HECO in September 2013 began enforcing a provision in its PUC-approved tariff requiring that customers seeking to install solar systems on circuits with high amounts of solar follow a technical interconnection review process, Pai said. That process was meant to ensure new solar systems would not impact safety and reliability for those customers and their neighbors, he added.

QUOTABLE: Collectively, thousands of PV systems installed on our island grids can impact the overall system reliability. On Oahu, for example, PV systems cumulatively exceed 280 MWs, exceeding the size of the largest central station generator on the island. Especially on small, stand-alone island grids like ours with high concentrations of PV, voltage spikes can damage utility equipment, damage customers’ appliances or even cause outages. – Darren Pai, a spokesperson for Hawaiian Electric

Solar firms were not prepared for the change that effectively brought new solar installations to a halt in September 2013 in areas that already had a lot of home PV. “They had said for a while that change was going to come but they didn’t say when or what,” Christian Adams, president and partner at Bonterra Solar in Honolulu and VP of HSEA, told us recently.

When the utility sent a letter stating the new rules, “it was a shock to the whole industry.”

The slowdown that followed left about 2,500 solar customers waiting for months for the go-ahead to connect rooftop PV to the grid. Some of those customers had already purchased a PV system.

HECO completed a series of the interconnection studies, Pai said. Most of those pending customers should be hooked up by April with another 200 connected by the end of 2015, he said.

Solar firms, meanwhile, took it on the chin.

Hawaiian Island Solar went from 20-25 salespeople and the same number of service technicians to four in sales and five service techs, Ralston told us.

QUOTABLE: A lot of us had to lay off a lot of people. We still have a stack of people that were sold PV system that are waiting. Some of these people have waited so long that they have changed their minds or something might have happened in their family – somebody lost their job or got divorced – so not all of those jobs will be going through. It’s been pretty devastating. – Ralston

Hawaiian Island Solar was not hit as hard as others because the firm is diversified – offering hot water systems, split PV-assisted AC that is not connected to the grid and solar PV pumps not connected to the grid. That gear does not need utility approval, Ralston said.

Bonterra’s 2014 business was down 50% compared with 2012, Adams told us.

Renegade systems seen

Some customers connected their home solar without permits. Late last year, HECO began notifying what it called “prematurely connected customers” – those who connected without a permit – to deactivate their PV systems while the utility reviewed their application, Pai said.

“To ensure safe, reliable service for all customers and protect our crews working in the field, it’s important that we know where and how many PV systems are interconnected to neighborhood circuits,” he added.

While the robust feeder lines near substations can more easily handle PV generation, smaller feeder lines serving more remote customers may not be strong enough for demands placed on them, York said.

The required upgrades so feeders can handle the demand vary from circuit to circuit, Pai said. If the upgrade has system-wide benefits, the cost may be passed on to all customers, he added.

Customers contribute

In other cases, under a regulatory “cost causation” principle, customers are responsible for upgrades that specifically benefit them, he added.

Typical equipment needed for the upgrade includes upgraded service transformers, grounding transformers, load tap changer controllers at substations and power lines, Pai said.

HECO recently approved about 1,000 applications for customers who agreed to share in the cost of upgrading certain control systems in neighborhood substations, he said, noting that the cost was less than $100/customer in most cases. For these customers, HECO upgraded load tap changer controllers that help regulate the flow of power the utility’s substations.

More PV on the way

HECO has continued to approve PV interconnections each month, Pai said, noting about 11,000 applications were approved last year.

Once the issue is resolved, HECO expects faster growth. The firm has submitted plans to its PUC committing to increase renewable energy to at least 65% of all generation by 2030 – far above the current clean-energy mandate of 40%, Pai said. That includes tripling distributed, largely rooftop solar, he added.

With those plans in mind, HECO is conducting additional studies to determine whether other safety or reliability issues will arise as the utility pushes to even higher levels of PV on circuits, Pai said. “We really believe there is an opportunity to use more technology to improve the integration of not just PV but all renewable resources,” he added.

More standards needed?

In the future, more standards and equipment may be needed. New standards could cover interconnection and equipment such as IEEE 1547 for connecting DR, and interconnection rules that are maintained by individual states or utilities, York said. Additional equipment might include smart inverters and other smart grid communications technologies, he added.

BEAMA calls UK AMI plan ‘big mountain to climb’

Delayed deadlines were prudent, consumer benefits clear

Published Dec. 10, 2014 Smart Grid Today By Karen Haywood Queen

Although the UK’s £11 billion (US$17 billion) smart meter rollout will start six to eight months later than originally planned, most of the country’s 53 million smart meters still should be installed by the end of 2020, British Electrotechnical & Allied Manufacturers Assn (BEAMA) CEO Howard Porter told us last week. BEAMA represents 350 firms that make grid technology, he added, including many UK firms plus a who’s who of global smart grid gear brands, according to the group’s website.

The AMI deployment is “a big mountain to climb,” said Porter, who was similarly optimistic when he spoke recently at the Smart Grid World Summit in London. “But we’re still on track by the end of 2020 to have the vast majority done. The level of cooperation among the different stakeholders is unprecedented,” he added.

The UK is working to cut GHG emissions 20% by 2020 from 1990 levels as part of the Climate Change Act of 2008. The UK AMI rollout differs from other deployments by calling for every home in the nation to have a smart meter and a consumer interface with an in-home display (IHD) of energy use, Porter said.

“The UK rollout is the most complex, arguably, in the world,” he added as he walked along the Thames near his London office. “The fact that we have a fully deregulated market with at least 20 different retailers makes it complex.”

Critics have questioned whether the rollout can be completed on schedule and have raised concerns about costs.

About 900,000 smart meters are currently in use in the UK, according to the Data Communications Co (DCC), and the current timetable calls for installation to begin, under DCC oversight, a year from now. DCC will provide the AMI infrastructure needed for smart meters to run consistently for all consumers, regardless of their energy supplier, Porter explained.

The recently proposed start of service could be April 2016, DCC said in a report it publicized last month. Now, the firm wants feedback on whether a July 2016 or October 2016 start is more appropriate.

The later go-live would allow more time for testing and would “reduce the impact of unplanned operational issues on consumer experience and cost.” The change would add up to £90 million (US$140 million) in added costs, the DCC report said.

The timetable slipped partly because a communications system, called the Great Britain Companion Specification (GBCS), that defines the messaging between the meters and DCC needs more work and testing than originally envisioned, DCC reported. Design, build and pre-integration testing will likely take until Aug 31 instead of the original plan of April 10, it added.

The organization is proposing to extend the next phase – system testing – by at least two months.

Delaying progress now to solve problems is better than pushing ahead, said Porter, who spoke recently in the House of Lords and to Parliamentary committees on the meter rollout. The three main political parties continue to be forceful in support of the rollout, he added.

“I … agree with the government, that it’s good that these systems are vetted now to make sure the systems are working as opposed to rushing ahead and finding out in the first year that things are not working – then having a longer delay to get on track,” Porter said.

Cost concerns are understandable, he added. “A number of other IT projects in the UK have gone up in price considerably,” and so it is appropriate that people are watching to make sure added costs do not grow to a level that puts too much pressure on consumers.

Critics have said the estimated £215/home (US$337/home) cost for smart metering equipment is too high. Most of the UK’s 27 million homes have two meters, one for gas and one for power.

But the government has precluded energy suppliers from charging up front for the meters. “It would be madness,” Porter said, for energy retailers to charge consumers up front. “I imagine they will amortize it over the lifetime of the meters, over a 10-year basis.”

Some retailers may even absorb up to half of the meters’ cost, he said.

Benefits of smart grid

Critics have put consumer savings from AMI at 2%/year. Porter cited an independent research study by VaasaETT this year that found an average savings in power use of 9%/year over three years.

That study qualitatively reviewed findings of six British and European consumption feedback studies with over 28,000 participants, and research from an another six British studies.

Extrapolating from the data, the UK average residential customer with both gas and power using an in-home display (IHD) would save £111/year (US$174/year), BEAMA told the press this year.

With smart meters and the IHDs showing energy use, consumers will get more accurate bills and have the chance to monitor and cut energy use, Porter noted.

QUOTABLE: You’re getting better service. You have the ability to control your energy and save energy by managing your energy better. You will be able to save considerably more, radically larger savings, than the amortized annual cost of the smart meter. – British Electrotechnical & Allied Manufacturers Assn CEO Howard Porter in an interview last week

Full deployment of smart meters also will allow more consumers to switch to paying in advance for energy use, Porter said, noting 3 million customers use pre-pay today. In the future, there will be “smart ways of paying” including via mobile phones, Porter said.

Use of IHDs challenged

Some stakeholders criticized the planned IHDs, saying that by the time the rollout is complete, most consumers will be able to get the energy use data directly onto their smart phones. But that data will be only historical data via the energy supplier – not real-time use data, he added.

Skipping IHDs would also leave out energy users who do not have smart phones or who do not fully use them, Porter said. Some 2/3 of UK residents now have a smart phone, Deloitte Consulting said in a mobile consumer report this year.

Plus, smart phones would need a consumer access device (CAD) either within them or in the home to securely link to the smart meter for real-time data, he added. Consumers certainly could have energy use information sent to their mobile phones via an app, but for real-time data, the app would need to link to a CAD.

“Currently all the work done with IHDs supports the technology we have,” Porter said. “Throughout the rollout of smart meters, the technology will change. We’ve had discussions with the government and important consumer stakeholders and the IHD is the only way to inform the consumer.”

Each energy retailer will provide its own smart meters and IHDs, all of which have to be compatible with the technical specs of the AMI.

Better integration coming

In the next 10-15 years, smart meters combined with smart appliances and other technology will let renewables such as solar panels be fully integrated into the grid, he added. “I have PVs on my roof and the system is physically wired in to my house. The energy I don’t need is put back into the grid but there is no smart use of that.

“There’s no connection between the energy production from those PVs and the energy production on the grid,” Porter said. He envisions smart meters and associated technology enabling a system where excess energy produced by PVs at individual homes could charge EVs and power smart appliances on timers targeted to come on when the energy is available.

“This would help smooth out peaks and troughs linked to renewable energy sources,” he added. “If the market demands it, technology will be delivered at consumer-friendly prices.”

 

Walmart Nets Millions from DR, Automated Shopping by Sunlight

Smart Grid Today / Published 2011 / By Karen Haywood Queen

Smart Grid WalmartWalmart shoppers likely will not even notice when the air-conditioning setting at their local store bumps up 4° to 78° for several hours during peak demand periods this summer. But when a company as big as Walmart, the largest private employer in the US, takes action,the reduction in demand across the grid is significant.

Walmart has DR programs in place at 1,300-1,400 of its 4,400 US stores, Jim Stanway, the giant retailer’s senior director of global energy services, told us Monday. “Per store, we can briefly put 300-400 KW back onto the grid [by decreasing usage] when we go to demand response,” Stanway said. If each store hit even one DR period in the same week, the reduction in demand across the country would be as high as 470,000 KW for that week.

For the past four or five years, the retailer has been part of DR programs with utilities across the country, he said. The system works by linking a real-time energy data system to each store’s building controls. Most of the temperature adjustments are automatic.

Customers likely do not notice the change because it takes a few hours for the temperature to increase when the setting is changed. By then, the DR period is usually over, Stanway said.

The retailer has been working to reduce its carbon footprint and bolster its green credentials through energy-saving measures and the use of alternative energy such as thin-film solar. But the main impetus for participating in such programs is to save money. Walmart declined to release its savings.

The company has real-time energy- use systems in 1,500 stores, Stanway said. “That gives us electricity consumption at the main meter and sub-circuit levels in mostly 15-minute increments and some three-minute increments,” he said.

The real-time energy data also is useful for studying the impact of Walmart’s energy-efficiency measures, Stanway said. “When we do a lighting retrofit, we can use the real-time data to study energy consumption before and after, to make sure [that] installations were done properly and [that] we get a good return on investment.”

Walmart has what it calls a daylight- harvesting program at its stores built since 1996, Stanway said. Between 2,500 and 3,000 stores have the system, which includes skylights and sensors to detect the amount of sunlight.

“Whenit’sanice,sunnyday,thesensors in the store detect the amount of sunlight and feed that data through our control system. It dims the lights,” Stanway said. “If it’s bright enough outside, the lights will actually go off. If a cloud drifts over halfway through the day, the system will adjust and the lights will start coming back on. The way it’s designed, it’s a gradual change and invisible to the customer.”

Initially the challenges included a delay of up to 15 minutes for the lights to react to the sunlight sensors,Stanway said. “Now we’re down to a few seconds,” he said. The system is made by Novar, which has a Walmart support center in Bentonville, Ark, the retailer’s headquarters.

Daylight harvesting can save up to 75% of the electric-lighting energy used by a Walmart store during daylight hours, he said. Walmart declined to disclose the cost of the system or the payback time, but each system can save an average of 800,000 KWH/year, Stanway said. At 10¢/KWH, that is $80,000/year per store. With daylight-harvesting systems in 2,500 stores — the low end of the company’s estimate of how many stores have the system — that is a companywide savings of up to $200 million/year.

Walmart also has centralized monitoring of energy use in each store, with alerts when use rises beyond normal limits. Issues that might warrant an alarm include a refrigerator case left open, Stanway said. “The system issues alarms when something is outside parameters,” he said. “Some things can be adjusted and corrected remotely.” If it cannot be fixed remotely, a technician is sent to fix it.

“Walmart’s leadership is important — they’re demonstrating that energy management is cost effective,” Miriam Horn, director of the Environmental Defense Fund’s (EDF) smart grid initiative, told us yesterday. “Walmart got ahead of the rest of the world because they put in a lot of advanced energy-management technology. Having Walmart show the way has been really important.” The EDF has a presence in Bentonville to work more closely with the retailer, she said.

Walmart is participating in DR programs in at least 10 states, Horn said. The company has also installed advanced meters in some stores at its own expense. “They make the important point that for this to work for anybody, they have to have the data and pricing information,” she said.

Having the right incentives make a key difference, too. “In our conversations with Walmart, they’ve made the point that they’re rolling out the technology where the return on investment is best,” Horn said. “They do have a business case for making these investments. They have a plan to keep expanding. In each case, it depends on the policies at the utility, state and ISO level to determine whether there’s a business case for Walmart to do it.”

Revere Security Cryptographers Build on German Enigma Code

Smart Grid Today / Published 2011 / By Karen Haywood Queen

Smart Grid EnigmaCryptographers at Revere Security in Dallas have developed a cost-effective algorithm that is smart enough, short enough and fast enough to protect smart meters from hackers and terrorists, CEO Rich Stephenson told us recently. The firm devised the algorithm, called Hummingbird, in part by using simple but highly effective algebra.

The next hurdle will be persuading utilities to adopt the new encryption technology, said Chris Hanebeck, Revere’s VP of product marketing. Because the approach to encryption is so different from current systems, and utilities do not like to be the first to spend cash on new technology, “everyone is racing to be second,” he said.

Revere founder Eric Smith and two fellow researchers began working on cryptography about 10 years ago, backed by a few small investors, Stephenson said. Smith’s group started on the technology that would become Hummingbird in 2005, with funding from the Department of Homeland Security. Revere raised VC and incorporated in 2008. It now has 14 employees.

A key addition was Whitfield Diffie, best known for the invention of public key cryptography. Diffie, former chief security officer for Sun Microsystems, joined Revere Security in 2009. “He’s definitely a rock star in the small community of cryptographers,” Stephenson said. “He brought different ways of looking at Hummingbird to the company.”

For smart meters, the challenge is to fit in the encryption without overwhelming the meters’ primary function, Mitchell Thornton, professor of computer science and engineering at Southern Methodist University, told us. SMU is performing independent tests of Hummingbird for Revere.

Instead of adapting existing encryption technology designed for computers, Hummingbird was developed specifically for small, resource-constrained devices like smart meters, sensors and smart cards, Stephenson said.

Code designed for computers uses complex differential calculus and modal math. But resource-constrained devices don’t have the computational capabilities, memory or power supply to support such advanced math. Revere researchers have found a way to make algebra do the job using what are called fixed numbers, say 2.8, as opposed to floating numbers, such as 2.8 x 10 to the 32nd power, Thornton said.

Hummingbird’s algorithm is so efficient in terms of power use, memory and speed that it can run on an 8- or 16-bit microprocessor, Revere said. Similar software used in Itron Open Way smart meters uses more complex math and requires a 32-bit microprocessor, Stephenson said. “With Hummingbird being as small as it is, we can go back and retrofit existing smart meters that have been deployed,” Stephenson said.

That is a key issue, since many security experts have argued that current smart meters are not protected from hackers and terrorists. A skilled attacker could, Thornton said, turn off power to one home or an entire area and demand ransom; program smart meters to shave 10% off a customer’s usage; overload relay switches and cause fires in specific cases; or even shut down the grid in an entire nation.

QUOTE OF THE DAY: In public forums, you hear a lot of utilities saying: “We’ve got it covered. Security is not an issue.” What you hear in private is different. – Chris Hanebeck, Revere’s VP of product marketing

Revere is testing whether it is best to employ Hummingbird as hardware, software or a combination of the two, said Thornton, the SMU professor.

German code helped

Hummingbird’s design was inspired by the German Enigma code machine, which used rotors to encode messages before and during World War II. Computer encryption by necessity uses complex math. Smith improved on the Enigma concept using four simulated rotors instead of three real ones, allowing for the rotors to run in random instead of sequential order and creating a code that is harder to break. One of Diffie’s key contributions was much-simplified math, Stephenson said.

“Just because it’s based on Enigma doesn’t mean it’s only as good as Enigma,” Thornton said. Polish code breakers cracked Enigma just before World War II. “Using the principles of Enigma, Hummingbird is able to perform stronger encryptions than an Enigma machine. We can make the rotors go forward or backward. We can scale it up.”

SMU has been testing smart grid-related security for several years. “We have contracts with big, three-letter government agencies as well as small commercial concerns,” Thornton said. SMU researchers began testing Hummingbird four months ago and plan to continue tests for six months.

“So far I have not found a case where Hummingbird isn’t as good as or better than standard encryption,” Thornton said. “And I have reason to believe it’s going to be equivalent to or better than other standard encryption methods, but I haven’t fully verified it yet.”

Market yet to come

Revere is expected to turn its first profit this year, but not principally because of Hummingbird, said CEO Stephenso. The firm is splitting its focus evenly between Hummingbird and similar technology to protect RFIDs, for which there is a more ready market, he said. “They’re essentially fancy barcodes, and companies such as Wal-Mart use them to track containers,” he said.

Revere will be ready to support Hummingbird later, when utilities start adopting it, Stephenson said. “We’re just now getting into the [utilities] market. The biggest obstacle is that Hummingbird is not considered one of the standard algorithms.”