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The Great DER Divide

Embracing IT-OT Convergence

SPECIAL COVERAGE: UA SUMMIT 2016, Pgs. 34-37

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Features

20 PURPA MANIPULATION Renewable advocates see it differently, but utilities nationwide say the abuse of the spirit, if not the letter, of PURPA is a regular occurrence.

24 DECOUPLING GETS HOT Proponents say it helps keep revenues stable while boosting energy efficiency, the adoption of solar and other DER programs.

64 MARKET REFORMS Japan is on its way to becoming the largest retail electricity market open to competition in the world.

SPRING 2016

Departments OUR TAKE

4 The Great DER Divide

INTRODUCING

6 Five Questions for NARUC’s Travis Kavulla

BUSINESS EDGE

8 Spare Transformers: The Answer to Extreme Weather Risks?

10 Energy Storage Brings Old Plant Back to Life

12 Obama Gives New Boost to Nulcear Energy

14 Drones Doing T&D Maintenance, Storm Duty

16 Corporate America Sets Renewable Power Record

18 Electricity Comes Free in Texas Time-of-Use Plans

UA SUMMIT 2016

34 Space-Time Insight Hopes for Lift from Rift

35 Gartner’s CD Hobbs Talks Big Data and the Future for Utilities

36 Entergy Injects Analytics into Maintenance

TECH FRONTIER

42 Cybersecurity Law Gives Feds New Power to Protect the Grid

44 Regulators Weigh Utility Supply-chain Cybersecurity Rules

46 GE, Accenture Develop Pipeline Safety Software

47 Utilities Embracing IT-OT Convergence

49 On The Horizon? Next-generation Nuke Reactors

51 ABB, Microsoft Join Forces on EV Stations, Other Fronts

52 Consumers Energy Goes Cellular with Electric, Gas Meters

53 MESA, Vanadium Batteries Put to the Test in Pacific Northwest

55 Storing Energy in Underwater Balloons

INDUSTRY VOICES

56 A New Vision for Distributed Energy Resource Planning

58 Back to the Future: Yesterday’s Industry Innovations Have Come Full Circle

60 For Better Oucomes, Let’s Reward Utilities for Performance

FINAL TAKE

64 U.S. Firms Ready to Assist Japan in Electric Market Reforms

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The Great DER DivideIT’S BEEN SITTING on my desk for a couple of weeks and, to be honest, it’s a downer.

I’m talking about a survey from the consultants at West Monroe Partners on how the electric utility industry is coping with the rise of distributed energy resources.

Grab yourself your beverage of choice if you already know the answer to this.The two most telling (and depressing) findings: 82% of the utility executives surveyed said

their residential customers are adding DERs to their systems, while 59% say they plan to make no or just minimal investments to support DERs.

What’s more, nearly half of residential customers surveyed said they’re considering install-ing DERs in their homes in the next two years.

Talk about a disconnect.If you really needed yet more evidence that the utility business has left itself as a prime

target of some upstart — or should we call them “disrupters,” as is vogue nowadays? — this report offers it.

Want to hear more?OK, 80% of utilities say they have DERs on their system but only 37% have services,

systems or technologies in place to support them.Or, how about this nugget? Nearly 80% of regulators feel existing rules allow and encour-

age utility ownership of DERS, but just over half of the utility execs surveyed agreed.So what we’ve got here is either a) utilities failing to heed market demand or b) regulators

failing to heed utility requests for permission to do so.Either way, it’s not good for anyone but third-party service providers. And that, in my

humble opinion, is just a shame, not to mention an invitation for all kinds of abuses (of the fi-nancial sort, in particular) and dysfunction (reliability? What an old-fashioned notion, right?).

Utilities undoubtedly are at least partly to blame for this. According to West Monroe’s survey, utility execs are almost three times more likely than regulators to report lack of execu-tive buy-in as an obstacle to DER support. But this, I’d suggest, mostly stems from a failure by regulators to give utilities the green light to recover their costs in integrating DERs. So the regulators are at fault, too.

The better news in all of this is that some regulators are evolving their thinking. Seventy-seven percent of those surveyed said they plan to formally review the technology costs and performance of DERs. A good number (60%) are considering changing tariff designs to pro-mote the addition of DERS. Regulators in New York, California, Massachusetts, Minnesota and Hawaii are certainly thinking along these lines.

On the other hand, too many utilities still view DERs as a threat. That has to change for any shift in regulatory philosophy to work. Utilities still have plenty of options available if they want to combat the rise of DER competitors. That includes using unregulated subsidiar-ies to invest in DERs. West Monroe points to what AES did through its acquisition of Main Street Power, or Duke Energy, through its investment in REC Solar.

Whatever they do, isn’t it time to take command rather than letting yet another governor or billionaire tech CEO make a DER splash?

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» INTRODUCING

5 Questions for NARUC’s Travis KavullaBY MATT WHITTAKER

FACED WITH RISING competition from renewable energy, a federal mandate to slash carbon emissions

and privacy concerns over the data collected by an ex-panding smart grid, electric power industry regulators have a lot to think about nowadays.

It’s against this backdrop that Montana’s Travis Ka-vulla took over as president of the National Association of Regulatory Utility Commissioners in November 2015.

EnergyBiz got on the phone with Kavulla to dive into five of the most pressing areas facing regulators.

ENERGYBIZ On the Clean Power Plan

KAVULLA Historically, with utilities wanting to run as reliably, cheaply and efficiently as possible, environmental concerns were externalities, Kavulla said. With the new rules, those concerns are being internalized, he said.

But utilities commissioners need to continue to insist upon a least-cost approach, Kavulla said.

That could include insisting on the least cost per ton for carbon mitigation, which would involve trading allowanc-es where power plants that are reducing their emissions could sell emissions allowances to other plants, he said.

Under that scenario, a key question would be how to allocate those allowances, whether to allow regional or na-tional trading, he said.

“Those questions are very much in play,” he said.

ENERGYBIZ On the climate talks in Paris

KAVULLA “Paris, despite all the fanfare, is an amalgam of aspirational goals,” he said. “It has no real legal enforce-ability as does U.S. federal and state law.”

Some people are using the Paris talks to say the CPP is insufficient and that the nation needs to invest in “deep decarbonization,” he said. That might be a hard sell for utilities commissioners, he said.

Even though Kavulla said he doesn’t really agree with the CPP, he acknowledges it is the law of the land, for the moment.

For the first time, it is a rule that puts a price on carbon dioxide, but that is fragmented among 49 states that have to implement their own goals, he noted. (Vermont is not included in the plan because it doesn’t have fossil-fuel-fired plants.)

That leaves it up to the states to knit together a plan for trading what is now a perfectly liquid commodity, he said. A national trading scheme would probably be hard to swallow for many people and would be politically con-tentious, he said. But a regional trading scheme could work, he said.

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» INTRODUCING

ENERGYBIZ On what’s pending in Congress this year

KAVULLA A bill has passed the Senate Energy and Nat-ural Resources Committee that includes money for states to engage in grid modernization, he said.

He is interested in whether that bill will survive, what will get amended and the extent to which the legislation would help states harness the power of Big Data.

Such data could help identify points of weakness in the grid where investments are needed in a smarter way than a utility simply saying its poles are 40 years old and need to be replaced, he said.

Some issues that could be looked at would include where a line is snagging, where there are voltage stability problems and where there are physical or cybersecurity is-sues, he said.

ENERGYBIZ On data privacy and the challenges

posed to utilities

KAVULLA There are a number of states, such as Califor-nia, that are trying to deal with that issue, he said.

Customers should be able to have claim on and use their discrete data, but researchers, utilities and grid plan-ners should be able to use the data, too, he said.

The concern is that power companies will sell the data to third parties. Experts say investing in security tools and monitoring for compliances are musts.

ENERGYBIZ On what he hopes to accomplish in his

year-long term as NARUC president

KAVULLA Kavulla wants NARUC to create a pricing manual for distributed energy resources such as rooftop solar. Roughly 20 states have taken action on that, creating a wealth of information, he said. But their approaches are all over the board and tend to represent interest groups such as the solar industry or the utility industry, he said.

He anticipates the manual will help identify categories of costs within bundled retail rates. It will also help show the value of benefits a system, such as rooftop solar, offers to the grid.

He expects a draft professional manual from NARUC out in the summer and a final manual to be available in the fall.

Customers should be able to have claim on and use their discrete data, but researchers, utilities and grid planners should be able to use the data, too.


» BUSINESS EDGE

Spare Transformers: The Answer to Extreme Weather Risks?BY RAKESH SHARMA

THAT BAD WEATHER CAN damage property and lives is already known. It also has turned out to be the

leading cause of power outages in the United States. And that, in turn, has helped spur the formation of a consor-tium of electric utilities that plans to create a national stockpile of hard-to-replace spare transformers.

The Lawrence Berkeley National Laboratory and Stan-ford University, in a study published last year based on re-sponses from 195 utilities, found that in the past decade or so, the average duration of weather-related customer interruptions increased by 260% to 370 minutes.

Climate Central, a science and journalism group, put out an earlier study saying the number of major weather-related outages doubled to more than 900 between 2003 and 2012.

“A significant number of the minutes that customers experience having their lights out are still the result of big storms,” said Joseph Eto, the lead author and researcher at Lawrence Berkeley National Laboratory.

Calculating the cost of such events isn’t easy, but a 2013 White House report concluded that weather-related blackouts cost the U.S. economy at least $18 billion and as much as $33 billion from 2003 to 2012.

Utilities, of course, spend tens of billions of dollars annu-ally to harden, or upgrade, their distribution infrastructure.

Beyond the effect on customers, power outages due to adverse weather can be expensive for utilities in a couple of ways.

First, there are the direct costs associated with dam-aged facilities. For example, Hurricane Katrina damaged all but three of Mississippi Power’s transmission lines. In addition, 65% of the company’s total distribution facilities were damaged.

In the absence of immediate government assistance, the company deployed an army division’s worth of personnel to restore power and provide medical assistance. The total repair costs for the power outage that resulted from Ka-

trina are estimated to be $300 million, according to Bill Snyder, a spokesman for the company.

Second, power outages can also translate into a number of ancillary, though still direct, costs. For example, the larg-est winter storm ever to hit the Dallas area in December 2013 pressed 5,000 workers from Oncor Energy, the local utility supplier, to work 16-hour shifts to restore power to affected areas. The company was also forced to increase its tree-trimming budget to $35 million after a similar storm hit its services in 2014.


» BUSINESS EDGE

To counter the growing disruption to power supplies, power utilities have put a number of measures in place, including investing in all kinds of technology.

According to Geoff Bailey, spokesman at Oncor Ener-gy, the company has increased its average projected capital expenditure budget to $1.5 billion a year through 2020 for such work. A lot of those dollars are spent on infrastruc-ture improvements. But the company also has invested in communication technology to bolster customer service during outages. Bailey said the company provides updates to customers through multiple platforms, from social me-dia to individualized text messaging, and other channels during outages.

Last year, the Texas-headquartered utility also proposed a grid-integrated energy storage plan, which would entail constructing a battery storage and microgrid system. Ac-cording to Bailey, Oncor’s goal in part was to spark a na-tional dialogue about the role that battery storage can play

in enhancing reliability. It has already implemented a pilot project that places storage on the grid at six test locations in south Dallas. Bailey said the test units saved an average of 57 minutes of outage time in 2015.

Mississippi Power constructed a new state-of-the-art operations center with its own emergency power system and water source as backup after Hurricane Katrina bat-tered its operations. Snyder said the facility can operate for up to 72 hours completely isolated from all outside utility sources.

Spare transformers have also emerged as another po-tential way to address the problem. However, because most transformers are manufactured abroad, there is a considerable time lag involved in bringing them here.

According to Joydeep Mitra, a Michigan State Univer-sity professor and utility reliability expert, it can take up to 18 months to two years to bring new transformers into the country.

That’s why utilities are banding together to create a consortium called Grid Assurance to buy spare mobile transformers, circuit breakers and other equipment. Last year, eight power companies, ranging from Duke Power Co. to Southern Power, came together on the project. The idea is that the reserve capacity enabled by these initiatives — stored at secured warehouses — can be immediately pressed into action in the aftermath of extreme weather.

The equipment also could be used in case of cyber and physical attacks, solar storms, electromagnetic pulses, earthquakes and other natural disasters.

Grid Assurance last month asked FERC to give its blessing to move forward — including an assurance that utilities can recoup the cost of purchasing spare service and parts from the consortium. It hopes to hear back in the next few weeks.

Weather-related outages will, of course, remain part of life for utilities. “Unless you live in the Southwest United States or in a desert, a part of your distribution line will al-ways pass through wooded areas (or come in contact with trees),” said Mitra.

“And there is always tension between customers and electric utilities regarding cutting down trees,” he said.

Even with a smart grid, the replacement of coal- or gas-fired plants with less-reliable renewable sources such as wind also will pose reliability challenges.


» BUSINESS EDGE

THE INSTALLATION OF a 2-MW battery-based en-ergy storage system at a retired coal plant in New

Richmond, Ohio, is being billed as a sign of the grow-ing potential of repurposing shuttered sites for grid-scale energy storage.

In addition to being completed in record time — about four months — the Duke Energy project, which provides frequency regulation services to the North-eastern PJM market, is also seen as a way for Duke to make money on a 60-year-old plant it was ready to mothball.

Related: The future of utility-scale energy storage could soon be on display in the Pacific Northwest. Page 53.

The system at the old W.C. Beckjord plant is de-signed to instantaneously absorb excess energy from the grid and release it in seconds, as opposed to a power plant that could take 10 minutes or more to ramp up.

“These are the big leagues,” said Matt Roberts, ex-ecutive director at the Energy Storage Association. “There are no tax credits associated with these projects and they are being justified on their own merits.”

Although he declined comment on specific cost im-plications of the project, Phil Grigsby, senior VP for commercial transmission at Duke Energy, said the util-ity went ahead with the project because it saw “a com-mercial opportunity to monetize” its operations in New Richmond.

“If these (energy storage) systems become more de-veloped and other applications that we don’t even fore-see … follow, then costs will continue to come down and use of energy storage for reliability or arbitrage may come to bear,” Grigsby said.

When it was closed last year, the New Richmond facility comprised a mix of coal- and oil-fired power

Energy Storage Brings Old Plant Back to LifeBY RAKESH SHARMA

plants and generated 1.43 GW in power capacity. But, Grigsby said, the plant had become uneconomical. In the end, the utility took a $1.4 billion write-off and moved to close the plant.

However, certain assets, such as a substation, were reused in its new life. LG Chem supplied the lithium-ion batteries used in the project and Parker Hannifin provided a 2-MW conversion inverter.

San Francisco-based Greensmith Energy provided its GEMS software platform, playing the pivotal role of interconnecting different parts of the project. Ac-cording to John Jung, CEO of Greensmith, the GEMS platform orchestrates the entire system of systems, in-cluding batteries, inverters, HVAC and sensors. “Maxi-mizing an energy storage system’s frequency regulation score while minimizing battery degradation throughout the system’s life is no trivial task,” Jung said.

Beckjord Power Station New Richmond, Ohio. © Aesopposea, Wikipedia


» BUSINESS EDGE

A Growing Market

The New Richmond project was part of the Depart-ment of Energy’s smart grid energy storage demonstra-tion program, which has 32 projects and a budget of $1.6 billion.

How many more such projects might arise remains to be seen, though the potential seems good. According to a recent report by the Energy Storage Association and Greentech Media, the U.S. deployed 60.3 MWh of energy storage in the third quarter of 2015. That figure is double the amount deployed last year. In total, this year’s deployment of energy storage is on track to ex-ceed 192 MW, representing a three-fold increase from last year’s figures. “The growth curve for energy storage systems is beginning to resemble a hockey stick pro-gression,” said Roberts. He noted that the current set of projects represented only “2% of what we’ll see in the future.”

A majority of these deployments have taken place in the Northeastern PJM market. However, utility-scale energy storage has also begun to appear in proposal re-quests and grid planning in other states, such as Geor-gia and Vermont.

In part, that’s because regulators in recent years have created new incentives that reward utilities for finding ways to boost reliability without having to spend more. At the same time, battery prices have been falling.

Also, development of sophisticated software plat-forms has dramatically reduced deployment time and costs for such projects. “A dollar spent on control soft-ware, such as GEMS, delivers more of a boost in system performance, longevity and ROI than a dollar spent on hardware, including batteries,” Jung said.

Finally, utilities are learning from their own or oth-ers’ experiences. For example, Duke Energy opted for lithium-ion batteries (instead of lead-acid batteries) at the New Richmond project based on its experience with the latter at a previous project.

That said, the quantity and volume of such projects are still not substantial enough to make a difference to the overall market.

“The battery industry needs to transition from small pilots to larger and broader commercial deployments,” Jung said.

Grigsby said the potential for profits from such proj-ects depends on rates at different times of the day. “The pricing is different during the day in different markets and that makes a difference to the number of hours that you can monetize,” he said. “We have not found a proj-ect (in other markets) that makes sense yet.”

Now that the project is done, Duke Energy will op-erate a total of 4 MWs of energy storage at Beckjord, where a separate 2-MW battery system already exists. Duke Energy also owns and operates a 36-MW en-ergy storage system at its Notrees Windpower Project in Texas.

According to research firm IHS, Duke Energy owns nearly 15% of the grid-connected, battery-based energy storage capacity in the U.S.

The system at the old W.C. Beckjord plant is designed to instantaneously absorb excess energy from the grid and release it in seconds, as opposed to a power plant that could take 10 minutes or more to ramp up.


» BUSINESS EDGE

THE U.S. NUCLEAR energy industry may have some-thing to cheer about.

Just how things might turn out is anyone’s guess, but the Obama administration has mounted a renewed push for nuclear power as a clean-energy solution.

The administration’s effort includes a recent proposal from President Obama to set aside more than $900 million for the Department of Energy for nuclear energy programs. The DOE also is expanding its $12.5 billion loan guarantee program to help speed along the development of advanced reactor projects. These new, smaller reactors have safer oper-ating systems designed to prevent catastrophic failures such as the 2011 incident in Fukushima, Japan.

Related: R&D on the next generation of nuclear energy re-actors is getting renewed attention. Page 49.

Also, House leaders have introduced the Nuclear En-ergy Innovation Capabilities Act to help the DOE lure private-sector investors to support next-generation reac-tor technologies.

The White House’s efforts include a new Gateway for Accelerated Innovation in Nuclear (GAIN) program. The program includes a new single point of contact at the Idaho National Lab, to again help accelerate development, and the publication of a nuclear energy infrastructure database.

The GAIN program also includes the establishment of a light-water reactor research, development and deploy-ment group.

These initiatives were all announced ahead of the mul-tination climate talks in Paris, the aim of which is to re-duce greenhouse gas emissions.

James Hansen, a former NASA climate scientist, and three other leading climate scientists used the talks to urge participating nations to focus more on nuclear energy.

Obama Gives New Boost to Nuclear EnergyBY R. KRESS

“Nuclear, especially next-generation nuclear, has tre-mendous potential to be part of the solution to climate change,” Hansen said during a panel discussion at the COP21 conference. “The dangers of fossil fuels are staring us in the face. So for us to say we won’t use all the tools [such as nuclear energy] to solve the problem is crazy.”

Although nuclear energy last year generated about 60% of carbon-free electricity in the U.S., the nuclear energy industry has been facing an existential threat for some time. With natural gas prices plunging in recent years, nuclear energy is having a harder time than ever competing.

Advocates say that without the incentives and subsidies allocated to other clean energy sources — like wind and solar power — the industry is at a serious disadvantage.

They also warn that when the price of natural gas inevi-tably rises, without the funding and support now available, adding more nuclear power to the mix when it’s needed won’t be easy.

“You won’t be able to do that. The plants [will be] gone. They [will have gotten] priced out of the market. They’re gone and you can’t restart them,” said Gary Was, profes-sor of nuclear engineering and sustainable energy at the


» BUSINESS EDGE

University of Michigan. “You’ll have to build new plants. What a waste of capital when we have these perfectly good plants that are functioning.”

“[Nuclear power is] the only source of baseloaded, car-bon-free electricity on the planet,” Was continued. “You can’t have base load from solar and wind because of their intermittency. [Nuclear power is] on-demand — that’s highly prized and valued.”

Although President Obama has supported nuclear power for years, Was is skeptical about the administration’s commitment to the sector. He sees the GAIN announce-ment as positive but not substantial in terms of providing the support needed for more research and development.

“While the rhetoric is nice, I don’t see it substantially addressing the stumbling blocks [faced by the industry],” Was said. “I think the announcement [on GAIN] shows the length that [President Obama] is willing to go. But beyond that, I have no idea. He’s in his seventh year and just now he’s coming out with this GAIN statement. One would have to ask why. If it takes that long, is your heart really in it?”

Charles Ebinger, senior fellow in the Energy Security and Climate Initiative at the Brookings Institution, is

similarly skeptical that the president will put up an impas-sioned fight for nuclear power.

“[The president would] be fearful in the context of his climate agenda that he’d lose too many supporters if it sounded like he was coming out in support of the nuclear industry,” Ebinger said.

Ebinger believes the administration’s real aim is to keep existing nuclear power plants up and running for fear that they would be shut down at a time when the world is fo-cusing on developing non-carbon-emitting power sources.

“I think that in the U.S. context ... there may be a revival of support for keeping the current plants that still have a useful life remaining. But I don’t think you’re going to see any incentives for any new nuclear power plants beyond the loan guarantees that are already out there for the in-dustry,” Ebinger said.

The issue strikes at the heart of what nuclear advocates see as an uneven playing field for nuclear power: renew-ables like wind and solar receive financial incentives while nuclear energy does not.

A better climate policy, they say, should be technology-agnostic and give equal footing to any power generator that does not emit greenhouse gases.

“Take off all the subsidies for wind and solar and nuclear and just impose a carbon tax,” Was said. “That way you let the market sort itself out. You’re not pick-ing losers, you’re simply saying if you emit carbon you pay for it. If you don’t, you benefit. Then, whatever technology is economical will win. Zero emissions technology will win. That would take care of the issue with coal and low gas prices suppressing innovation in the nuclear industry.”

The politics on that proposal are likely to make it im-possible to implement. But to Dr. Andy Klein of Oregon State University, a board member for the American Nu-clear Society, politics are beside the point: without nuclear energy, he believes there is no way the world will reach its more ambitious emissions reduction targets.

“We need to think of clean energy technology as being the majority of electricity generation in 2050,” he said.

The president did give nuclear another boost earlier this year with his Clean Power Plan, which will count newly built nuclear plants toward states’ compliance with the law. The industry, however, wanted existing plants to count, too.

Nonetheless, the Nuclear Energy Institute was happy about the administration’s GAIN announcement. Its press release on the program was headlined, “Top reasons the White House supports nuclear energy.”


» BUSINESS EDGE

WHILE WALMART AND AMAZON are trying to figure out how to deliver purchases to your door with fly-

ing drones, a growing number of utilities are already using unmanned drones to augment their T&D asset mainte-nance programs.

One of the latest to do so was PPL Electric Utilities, which serves eastern Pennsylvania and which received permission from the Federal Aviation Administration to begin using drones for routine and post-storm inspections of transmission lines and other field assets in rugged and other hard-to-reach terrain.

Other utilities now using drones include San Diego Gas & Electric, Florida Power & Light, Southern Co. of Atlanta and Commonwealth Edison Co. of Chicago.

The Electric Power Research Institute thinks that most utilities will be operating drones at some point soon, help-ing them cut costs and improve worker safety.

PPL now flies three six-rotor drones a few times a month, operated by two engineering staff members who are also licensed pilots. PPL also contracts with Hazon Solutions to fly drones on their behalf — including an eight-rotor model that can stay in the air longer.

These off-the-shelf drones are equipped with cameras that shoot still photos and videos, including infrared (for temperature scanning). Imagery is transmitted in real time to the base station, where it is viewed by the drone opera-tor as well as by utility maintenance experts. Images from the drones are used when submitting work orders. PPL is also considering adding sensors (ohmmeters) to measure electrical fields.

As PPL spokesman Joe Nixon explained, “I wouldn’t even call it a pilot program. We’re just gradually starting to integrate drones into our overall line maintenance and inspection activities.”

The drones provide an excellent close-up view of equip-ment that can be challenging to inspect — especially the

Drones Doing T&D Maintenance, Storm DutyBY AMY GAHRAN

clamps, bolts, connections and cross-arms on transmission lines and towers, or substation components.

“Our inspectors can look at the live video coming in and see a missing bolt or a cracked cross-arm,” said Nixon. “This can help us pinpoint our repair and replacement op-erations, as well as deploy manned helicopters only where they’re really needed.”

The FAA regulates drone operations fairly tightly, es-pecially for commercial users. PPL was granted a Section 333 exception, which limits its drones to no more than 200 feet above ground level, within sight of the operator — and the operator must be a licensed pilot. Flights are generally not allowed in residential areas (it’s not legal to fly them over peo-ple’s heads or homes), which makes drones more useful for checking transmission lines and substations than distribu-tion lines.

Previously, drone operators had to file flight plans, but FAA rules passed last March lifted this requirement for flights under 200 feet by drone operators holding Section 333 exceptions.

Nixon noted that PPL’s increased deployment of smart grid technology dovetails well with its use of drones for inspections. “We now have much better fault location, so we know very quickly exactly where we need to do an in-spection. This greatly reduces the time to get a drone in the air — which is almost always much faster than it would take to get a helicopter in the air.”

Meanwhile, San Diego Gas & Electric began flying

We can get them off the ground, do an inspection, and back down in less than 15 minutes.


» BUSINESS EDGE

drones for transmission line maintenance last March, after receiving its Section 333 exception. These flights occur in the less-populated eastern portion of SDG&E’s service territory. “Our exception allows us to fly up to 400 feet, but we generally stay below 100 feet,” said Jamie Exon, the company’s electric distribution operation manager, who runs SDG&E’s fledgling drone program.

“We can get them off the ground, do an inspection, and back down in less than 15 minutes,” Exon said. “We’ve already caught a number of poles that needed replacing.”

SDG&E’s drones are smaller four-rotor models — in-cluding the DJI Inspire 1, a drone becoming popular with filmmakers. These are equipped with cameras for video and still images.

SDG&E is testing infrared imaging, and is consider-ing adding LIDAR capabilities to some drones to en-hance surveying, modeling and planning for network expansions and upgrades. The utility is also considering buying a larger helicopter-style drone (with a bigger battery to support a wider flying range), if it someday

becomes permissible to operate drones beyond the cur-rent line-of-sight limitation.

So far, a big lesson that SDG&E has learned from its drone experience is that when one department starts using drones, others get interested. “When we talked about what we were doing, people at our mission-crit-ical facilities started asking us to help them with in-specting their equipment. Once you get started, expect that you’ll find new areas for growth that you didn’t plan,” Exon said.

Drone regulations are a moving target. By Nov. 20, a Department of Transportation task force is expected to present recommendations for registration of drones. Also, when new FAA drone rules are released in June, the current pilot’s license requirement may be relaxed to allow a less-stringent certification process for com-mercial drone operators.

So far, in the U.S., drones are only being used for inspec-tion operations. But in Asia, they’re sometimes being used to assist with stringing power lines in remote locations.


» BUSINESS EDGE

LARGE CORPORATIONS PUSHING to meet sustain-ability goals are turning to long-term power pur-

chase agreements with utility-scale renewable power developers in record numbers.

According to the Rocky Mountain Institute, U.S. employers in 2015 signed power purchase agreements for a total of 2 GW of off-site renewable capacity.

“These numbers are moving very fast,” said Herve Touati, managing director of RMI’s Business Renew-ables Center, which serves as a resource and matchmak-er for large corporations and renewable power develop-ers. “(In 2014) that total was 1.2 GW, and in 2013 it was only 0.5 GW.”

More such deals are expected. Forty-three percent of the Fortune 500 have goals to reduce their carbon foot-print, cut energy use, or power a portion of their opera-tions with renewable energy, according to the institute.

An RMI report said that by 2020 some parts of the U.S. could see “grid parity,” in which the cost and reli-ability of solar and battery storage systems is about the same as buying electricity from a utility.

Utilities have been concerned about the loss of cus-tomers but many in the industry say some of the more dire predictions are overblown and that regulators are, in fact, working with them to ensure a more stable fu-ture for the grid.

Regulators “want healthy utilities that are capable of making the investments needed for customers,” First-Energy Corp. CEO Charles Jones Jr. said during a panel discussion at the EEI Financial Conference this month in Florida. “It’s not in anybody’s best interests to let them become unhealthy.”

At the same time, renewable providers are doing all they can to capture market share.

Corporate America Sets Renewable Power RecordBY AMY GAHRAN

In one of the most recent such deals, Owens Corning, a founding member of RMI’s center, signed a PPA to procure 125 MW of capacity from the Wake Wind Energy Facility in Texas, owned by Invenergy. The length of the contract was not disclosed, but Owens Corning confirmed that it is substantially longer than the three- to five-year power supply contracts that previously were typi-cal for the company.

The key to gaining support within the company for such a contract was to start with smaller renewables investments, said Chief Sustainability Officer Frank O’Brien-Bernini.

Owens Corning is working to halve its greenhouse gas “intensity” by 2020 (compared with its 2010 baseline). In 2013, it made its first major foray into renewable genera-tion, with the installation of a 2.7-MW ground-mounted solar array at an insulation manufacturing plant in Delmar, New York. Also, the company recently completed the in-stallation of a canopy of solar panels on the 11-acre park-ing lot at its Toledo, Ohio, headquarters.

“Given the size of our energy demand, we know that we simply don’t have enough real estate to make the huge emissions impact we need through on-site re-newables and efficiency alone,” said O’Brien-Bernini. “When we started looking at offsite options, we real-ized that wind energy is very economically attractive now, for the scale we need. Also, we already had close ties to this market, since we provide materials used in wind turbine blades.”


» BUSINESS EDGE

Owens Corning, however, faced a common hurdle to completing the wind power deal.

As Touati explained it, “Many companies have poli-cies prohibiting long-term supply contracts. But once a company is convinced that they need to examine off-site options for renewable energy, that means they’re considering huge contracts — often $200 million in value over, say, 15 to 20 years. How do you think a typi-cal CFO will react to that? Some of our objectives are to offer guidance on how these contracts make financial sense, how to address legal concerns and how to handle the accounting treatment.”

Like many large corporate renewable PPAs, the Owens Corning deal was structured as a “contract for difference.” Through this mechanism, a wind or solar farm operator is paid the difference between the cost to generate renewable electricity and the average mar-

ket price for conventionally generated power. O’Brien-Bernini explained that, in effect, Owens Corning is paying Invenergy to add more wind power capacity to the grid, and the direct return on this investment is the price paid for electricity on the wholesale power market.

The contract for difference model was pioneered in the U.K. Later this month, the

Carbon Disclosure Project (an international organization that works with shareholders

and corporations to disclose corporate green-house gas emissions) is expected to release updat-

ed guidance for formulating and executing contracts for difference.

In addition to recouping its investment in wind pow-er, Owens Corning receives a U.S. Renewable Energy Credit — a tradable commodity that companies use to reduce their carbon footprint and that allows them to register progress toward sustainability goals.

O’Brien-Bernini said it helped a lot to get the com-pany’s finance and legal departments involved early in the process. “We conducted many kinds of financial and sensitivity analyses to get everyone comfortable with this approach to agreements,” he said.

“Our company already makes long-term commit-ments when rebuilding a major asset at a plant, or when constructing a new plant,” said O’Brien-Bernini. “It’s not like long-term commitments are foreign to us. We just have to ease people into long-term thinking about energy supply. How we already think about capital ap-plies here.”

The key to gaining support within the company for such a

contract was to start with smaller renewables investments.


» BUSINESS EDGE

TIME-OF-USE PROGRAMS in which power providers charge customers different rates at different times to

influence when they use electricity have been around since the start of the 2000s.

Now, with the growth of smart grid technology and in-termittent energy sources, as well as the desire of utilities and grid operators to reduce peak loads, these programs are spreading across the continent.

Perhaps the most extreme example can be found in Texas, where some retail electric providers have programs that enable customers to use power for free at certain times in exchange for paying slightly higher rates at other times.

Factors driving the time-of-use programs offered in Texas include:

• A competitive market structure in which most elec-tric customers buy power from retail electric providers rather than the operator of their local grid.

• An abundance of wind power, particularly at night.

• A statewide grid that is virtually isolated from other regional power grids, meaning that the wind power generated in Texas remains in Texas where it drives down electric prices.

• The desire by the state grid operator, the Electric Reli-ability Council of Texas, to shift power consumption away from peak demand times, particularly in sum-mer, when Texans throttle up their air conditioners.

The desire to shift power consumption away from peak demand times, which, as in Texas, are late afternoons and early evenings on hot summer days, also is behind some demand-response and dynamic-pricing programs imple-mented by utilities in the Northeast.

Planned time-of-use plans in California also are meant to shift power consumption from peak demand hours, and Hawaii is in the early stages of rolling out time-of-use

Electricity Comes Free in Texas Time-of-Use PlansBY PETER KEY

plans designed to take advantage of the abundance of solar and wind power in the state.

Still, none of the variable-rate plans offered elsewhere in the country are as aggressive as the ones in Texas, which enable users to get electricity for free at certain times in exchange for paying slightly higher rates than they would otherwise pay at other times.

TXU Energy Retail Co. LLC has two residential plans that push free power: TXU Energy Free Morn-ings & Evenings, which provides electricity without charge from 7 a.m. to 10 a.m. and 7 p.m. to 10 p.m.; and TXU Energy Free Nights, which does the same thing from 9 p.m. to 6 a.m.

The Irving, Texas-based company designed the plans to be easy to understand, deliver clear benefits and be some-thing that consumers could relate to.

“Time-of-use plans historically were confusing and led with a stick, so to speak, with consumers afraid of the cost of services during peak periods,” Juan Elizondo, TXU’s senior manager for corporate communications, said in an email. “We changed the paradigm to give consumers a clear reason to shift into the nonpeak periods.”

The plans have worked. Elizondo said more than 100,000 of TXU’s 1.5 million customers have signed up since TXU began offering them in 2012.

“More importantly,” he said, “TXU Energy Free Nights remains one of the most recognized plans in the Texas market. That means we get consideration from consum-ers even if they don’t ultimately sign up for it. That, too, is important” because it enables the company to differentiate itself in a marketplace of about 50 retail electric providers.

Statewide, the number of residential customers enrolled in TOU plans grew from 135,320 in 2013 to 290,328 last year, according to the Electric Reliability Council of Texas. The growth was due to more than 220,000 new TOU cus-tomers in 2014, which more than overcame the 62,794 who dropped out of such plans during the year.


» BUSINESS EDGE

None of the plans would be possible without smart grid hardware and software, such as that provided by Cei-va Energy, which grew out of its parent company, Ceiva Logic Inc., a maker of connected digital photo frames that was founded by former executives of the Walt Disney Co. and is based in Burbank, California.

In addition to working with retail electric providers in Texas on their plans, Ceiva helped London-based Nation-al Grid plc roll out a demand-response program to 11,000 homes in Worcester, Massachusetts. The program deliv-ered lower rates nearly all the time to participants willing to pay higher rates during anticipated periods of very high demand, which National Grid designated as peak events. One thousand of the participants also agreed to use Cei-va’s technology to get messages from National Grid prior to the peak events so they could use as little power as pos-sible during them.

Participants in the overall program saved from $20 to $80 on their monthly electric bills. Also, the 1,000 who agreed to use the technology that provided them with messages from National Grid about peak events reduced

the amounts they would have paid during those events by 20%, Ceiva said.

Chicago-based Exelon Corp.’s Baltimore Gas & Elec-tric Co. subsidiary has run a dynamic pricing program the past three summers. The program, which was rolled out as BGE rolled out its smart meters, gives rebates of $1.25 to customers for each kWh they shave from their normal usage from 1 p.m. to 7 p.m. on days designated by BGE as energy-savings days.

BGE has been helped with its program by Opower Inc., which has developed a platform using behavioral sci-ence to provide utilities with customer-engagement ser-vices. BGE used the Arlington, Virginia-based company to send personalized messages to customers just prior to and after energy-savings days. The messages let the cus-tomers know BGE was declaring an energy-savings day and showed them how much they saved on that day.

The program enabled customers to save nearly $13 million in its first two summers, according to BGE and Opower. The key, said Nicholas Payton, Opower’s associ-ate director for product marketing and strategy, was the customer engagement, especially providing customers with nearly immediate feedback on their savings. As a result, more than 70% of BGE’s customers reduced their power consumption on energy-savings days. Payton said similar programs without behavioral components were tested in California and produced very little savings.

“Behavioral demand response is really, in our view, the key to unlocking the potential for residential demand re-sponse,” he said.

California’s utilities have been offering TOU programs for about as long as the programs have existed. But the California Public Utilities Commission has ordered the state’s three investor-owned utilities to make them the default plans by 2019. Some in California are concerned that the plans there will have to be modified as more solar power comes online in the state.

In Hawaii, time-of-use plans are being designed to take into account the amount of solar power in the state from the get-go. Honolulu-based Hawaiian Electric Cos. recently proposed a plan that generally would make power least expensive from 9 a.m. to 4 p.m., most expensive from 4 p.m. until midnight, and in-between from midnight un-til 9 a.m.


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BY R. KRESS

PURPA?GAMINGCharges of Abuse Amid a Push for Reform

WHEN BERKSHIRE HATHAWAY Energy’s PacifiCorp put out a request for proposals in 2008 for renew-

able energy, one of the bids it received came from Cedar Creek Winds.

As it turned out, Cedar Creek wanted to build a 150-MW wind farm in Idaho at a price PacifiCorp, based in Portland, Oregon, thought was just too high. The bid was rejected, although that wasn’t the end of things.

“Next thing we know, the developer had simply recon-figured the project as five separate projects, each one rough-ly 25 MW to 27 MW and each one just over a mile apart from the other, each with a different name,” said Jonathan Weisgall, VP for legislative and regulatory affairs for Berk-shire Hathaway Energy.

Cedar Creek, according to Weisgall, hadn’t merely re-configured the project; it had purportedly gamed the Public Utility Regulatory Policies Act of 1978, the landmark law credited with helping the U.S. renewable energy industry get on its feet. And it wasn’t the only renewable producer doing so, he said.

Renewable developers see matters differently, but the abuse of the spirit, if not the letter, of PURPA is a regular occurrence, according to Weisgall and other utility industry representatives.


Because the law was designed to give smaller power players a leg up in entering the energy market, the size of a project — along with its location — determines whether it is a qualifying facility (QF).

Under Federal Energy Regulatory Commission rules, such projects must be a mile apart. Also, in areas where competitive power markets exist, a QF cannot exceed 20 MW. In areas outside of a competitive market, a QF can be up to 80 MW. Renewable projects need the QF des-ignation in order to sell power to a host utility at the util-ity’s avoided cost. That’s the incremental expense a utility would incur to generate the energy itself, were it not buy-ing it from the QF.

Utilities complain that renewable projects have long been abusing PURPA’s one-mile rule by disaggregating larger, single projects and divvying them up into smaller ar-rays, each located just over a mile apart. The abuse, utilities say, forces them into costly, often above-market contracts that will cost customers billions of dollars in rate hikes.

A Wider Problem

PacifiCorp, for one, estimates that such abuses will cost its customers up to $1.1 billion in the coming decade by locking the company into unneeded electricity contracts at rates up to 43% higher than market price.

Kathy Steckelberg, VP of government relations for the Edison Electric Institute in Washington, D.C., said that one-mile rule abuses are an industrywide problem. “We have a significant number of member companies having problems with abuses of the one-mile rule. It’s definitely not just a [Berkshire Hathaway Energy] problem,” she said.

Once Cedar Creek’s proposal was split into five QFs, PacifiCorp was effectively forced into power purchase agreements with them all, Weisgall said.

“It was pretty much the same original project that was priced too high and [the reconfiguration] got them from not being [a QF under] PURPA because they were over 80 MW to [qualifying],” he said.

Seattle-based Summit Power, developer of the Cedar Creek project, has a different take on the way that its wind farm project was configured. “We weren’t just going to PacifiCorp and we weren’t just offering a 150-MW con-figuration. We were doing what developers do, which is configuring our assets around the opportunity,” said Dana Zentz, senior VP of commercial development for Summit.

“We did the responsible thing for our side of the table and said that we could have the certainty of a purchase of

power within the rules of PURPA, so we did that,” Zentz said. “For us, the path we took related to PURPA was just one of the things we could have done. We could have sold to SoCal Edison, we could have sold to Idaho Power Company — and we pursued all those avenues. But with PURPA, it was more certain, more direct and quicker for us and we chose it. But we never have had any intention to game anything, break any rules or do anything that wasn’t permitted for us to do. Never.”

Zentz believes utilities are fighting back against the one-mile rule now because of the volume of power they’ve been forced to buy — seeing more developers arrive with projects than before.

In the ensuing years, Cedar Creek has either sold off or dropped the projects that involved PacifiCorp.

But in testimony before Congress in May, Weisgall listed a number of similar instances involving Pacifi-Corp over the years in which large renewable projects were disaggre-gated to skirt FERC’s one-mile rule.

For example, Pittsburgh-based EverPower Wind Holdings is seek-ing PURPA contracts with Paci-fiCorp for three 80-MW projects that are all adjacent to each other in Montana but are spaced one mile apart. The projects will share a common 230-kV transmission line they’re building into PacifiCorp ter-ritory in Wyoming. Although each of the projects will be owned by in-dividual limited liability companies, Weisgall testified that they will be operated as a single entity. EverPow-er said it had no comment.

In eastern Oregon, a 64.5-MW wind project was disaggregated by developer John Deere Renewables in 2008 into nine QF projects ranging between 1.65 MW and 10 MW. In his testimony, Weisgall argued that the nine projects operate as a single wind project and deliver electricity to one single interconnection point on the Paci-fiCorp system. The project was later purchased by the Ex-elon Corp. Exelon did not provide comment on the mat-ter by press time.

REGUL AT IONS

We did the responsible thing for our side of the table and said that we could have the certainty of a purchase of power within the rules of PURPA, so we did that.

— Dana Zentz


In Utah, PacifiCorp has had to take on several 50-MW to 80-MW solar PV QF contracts. Weisgall noted the developer had first secured a large generator intercon-nection agreement exceeding 80 MW before developing the multiple QF projects that would employ it. He said SunEdison’s Escalante I, II and III projects — each 80 MW — meet FERC’s one-mile rule but are managed as a single project. SunEdison responded by providing public service commission orders and testimony filed by Rocky Mountain Power, a PacifiCorp division, showing that the PPAs were not opposed.

Among others, Madison, Wisconsin-based Alliant En-ergy said it has also encountered instances of developers intentionally structuring projects to use the one-mile rule to their advantage. John Rainbolt, Alliant’s federal affairs chief, pointed to a project under development north of Des Moines, Iowa, in which Italian developer Building Energy has divided up a 30-MW project into 10, 3-MW turbines.

“That blows well past the 20-MW cap in Iowa. They’re getting around it by dividing up the individual turbines into separate LLCs … while the ownership is basically uniform,” Rainbolt said. “Our customers essentially pay for PURPA power at 20% higher-than-market-based wind prices.”

Building Energy did not respond to a request for comment.

What Will FERC Do?

Responding to the rising tide of utility anger about the one-mile rule, FERC has agreed to hold a technical con-ference on the issue in the coming year.

It did so after the chairs of three congressional ener-gy committees and subcommittees, including Sen. Lisa Murkowski of Alaska, Rep. Fred Upton of Michigan and Rep. Ed Whitfield of Kentucky, wrote the agency a letter and referenced these alleged abuses, calling on it to review the nearly 40-year-old legislation.

“A technical conference should consider a range of is-sues, including whether the one-mile rule established by the commission for determining whether facilities are ‘lo-cated at the same site’ for purposes of determining their status as small power production facilities under PURPA has been subject to abuse,” the letter said.

Adding significantly to the tension surrounding the one-mile rule is a provision known as an irrebuttable presump-tion — meaning that it is a hard-and-fast rule and cannot be challenged, even when there is evidence of possible abuse.

Utilities are hoping FERC will decide that alleged rule violations can be contested.

“That’s all we’re really trying to do,” said Weisgall. “You can still lose but at least you get the chance to rebut the presumption.”

Randall Davis, an energy lawyer who served as the Spe-cial Assistant to the President for Energy and Natural Re-sources during the Reagan administration, said that many instances of abuse of the one-mile rule are not contested because of the irrebuttable presumption.

“In a lot of these cases, utilities don’t even bother bringing them forward because FERC sees that [the fa-cilities are] one mile apart and says a rule is a rule,” Davis said. “Given the reception that a handful of cases have had going to FERC challenging [the one-mile rule], there are not a lot of them that are on the public record. … If you have an arbitrary rule that you can’t rebut — even with facts — there are going to be cases of abuse.”

As Weisgall sees it, next year’s technical conference could help remedy the problem by bringing more of these cases to light.

“It could be that a technical conference like this might well build a record or provide some sort of policy ground-work to support either a FERC decision to change that one-mile rule or to give Congress enough support for a legislative reform,” Weisgall said.

FERC members don’t comment on ongoing matters, but former FERC Chairman Jon Wellinghoff said he would like to see a larger examination of PURPA to ex-plore how changes in the energy market and new technol-ogy have made a difference.

As for the one-mile rule in particular, Wellinghoff said he would have been open to making it a rebuttable pre-sumption — a somewhat surprising point considering the fact that he was chairman of the commission when it ruled in a 2012 case that the rule could not be rebutted.

“I think it should be one that can be rebutted,” Welling-hoff said of the one-mile rule. “Any rule can be modified to allow for unusual circumstances, and there may be in-stances where that might be appropriate. … I think you have to look at it on a case-by-case basis.”

Whatever happens, EEI’s Steckelberg sees the moment as an opportunity to educate lawmakers about PURPA. “It’s been a long time since Congress had a robust discus-sion on PURPA. This is a way of getting everyone think-ing about it again and getting the current state of the mar-ket out on the table,” Steckelberg said.

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R ATES


A GROWING NUMBER of states are moving toward utility revenue de-coupling, an approach that proponents say helps keep revenues sta-

ble while boosting energy efficiency, the adoption of solar and other dis-tributed energy resource programs.

Pennsylvania this winter became the latest state to move in this direc-tion. The Keystone State’s Public Utility Commission plans to hold a hear-ing soon on the tactic, which aims to separate the amount of money earned by utilities from the amount of electricity or gas sold.

“The current system basically rewards utilities for increasing their sales of power, which from an environmental perspective discourages efficiency and encourages pollution,” said Dick Munson, director of the Environ-mental Defense Fund’s Midwest Clean Energy program.

In states where decoupling has already been adopted, regulator-ap-proved rates are periodically automatically adjusted to keep revenue steady as usage goes up or down. That happens when atypically hot or cold tem-peratures boost consumption or when more consumers adopt conservation and home-generation technology.

BY STEVEN MELENDEZ

THERISEONUTILITY

REVENUE DECOUPLING

R ATES


“The [Pennsylvania] PUC’s decision represents a win for grid modernization and distributed energy resources like energy efficiency, energy storage and rooftop solar in the Keystone State,” Munson wrote in a recent blog post.

The EDF and other advocates, which include trade groups such as the Edison Electric Institute and the American Gas Association, say decoupling makes it easier for utilities to support energy conservation programs to shift power consumption to cheaper off-peak hours as well as to rooftop solar, because decreased consumption will no longer hurt their bottom lines.

“The principal point of it is to make sure that a large obstacle to utility engagement in support of efficiency is removed,” said Ralph Cavanagh, co-director of the Natu-ral Resources Defense Council’s energy program. “I’ve seen abundant evidence that it really does make a palpable difference.”

At least eight states now have their own decoupling proposals in the works, Cavanagh said.

If Pennsylvania’s regulators move forward, it would join 15 other states with decoupling rate struc-tures in place for electric utilities and 22 with such plans in place for gas companies, Cavanagh said. Advocates of revenue decoupling often point to Califor-nia, where the practice was introduced in 1981, as an ex-ample of why more states should embrace it.

California’s energy rates are often higher than those in other states, but its consumers still generally see smaller bills thanks to the state’s conservation programs, advocates say.

“Though California is often maligned for its high electricity retail rates compared to the rest of the U.S., the state’s energy efficiency policies have reduced overall energy bills for its residents and businesses,” a study by the NRDC and the California Energy Commission said. “Since 1973, on a per-capita basis, energy bills in Califor-nia have averaged $100 per year less than U.S. bills.”

Exact decoupling policies vary from state to state, in-cluding how frequently rates are adjusted, whether there’s a cap on the extent to which rates can fluctuate and whether utilities’ allowed revenues are adjusted based on customer base size, weather or other factors.

Rate fluctuations are generally within 2 percentage points, meaning about $2.30 per month for the average residential electric customer, and $1.40 per month for the average gas customer, according to a 2013 report by energy industry consultant Pamela Morgan.

Pennsylvania utility PECO, which serves more than 1.6 million electric customers and 500,000 gas customers

in the state, will hold its own public meeting seeking input on the revenue decoupling plan. The utility is looking for-ward to working with the PUC to explore the possibilities, a spokesman said.

Advocates say periodically adjusting rates is a better way to go than simply adding fixed charges to custom-ers’ bills, in part because doing so still gives customers an incentive to keep their electric or gas consumption down.

“If you put a lot of utility bill into the fixed charge, then the customer doesn’t have much opportunity to save mon-ey by reducing … usage,” said Sean Gallagher, VP of state affairs at the Solar Energy Industries Association.

One downside, though, is that the frequent rate chang-es make it harder for customers to plan based on what en-ergy will cost in the future, particularly for large businesses that use a lot of power.

“From a business perspective, it’s very difficult to plan your energy budget in a regime of decoupling,” said John Hughes, president of the Electricity Consumers Resource Council, a group that represents primarily large power consumers and which has generally opposed the practice.

The group also worries that by guaranteeing a fixed revenue, decoupling essentially transfers market risk from utilities to consumers and gives utilities less incentive to provide high-quality service and reliable power.

“Decoupling’s easy money,” Hughes said. “They get their fixed costs recovered no matter what they do.”

Similar arguments doomed a Maine experiment with revenue decoupling in the early 1990s, when a decline in power consumption during a recession nonetheless effec-tively resulted in rate increases for Central Maine Power customers.

The resulting public outrage prompted the utility and its regulator to agree to end the experiment, though a later report by the National Association of Regulatory Utility Commissioners argued that even without decoupling, the decline in revenue likely would have resulted in the utility ultimately pursuing a rate increase anyway.

In any case, proponents say decoupling can be joined with other incentive programs to reward utilities for pro-viding better service or boosting conservation — along with decreases in their profits in exchange for the de-creased financial risk.

“You can also reduce the utility’s allowed return on equity — the percentage of profit — to reflect the fact that their risk is lower,” said Gallagher. “Their risk is lower under a decoupling regime because they’re more or less guaranteed to recover their costs.”

R ATES


BREAKAWAY

BOULDER, COLORADO’S HIGH-PROFILE push to form its own utility has been underway for years, but is now

among a growing number of similar breakaway efforts to have cropped up around the country.

Campaigns to form community-owned or nonprofit electric utilities were under way in at least five areas of the country in the past year. Along with Boulder, such efforts remain active in Hawaii and California, and had been under way in Washing-ton, D.C., and Santa Fe, New Mexico, earlier in the year.

BY PETER KEY

UTILITYRESTRUCTUR ING

EFFORTS

PICK UPSTEAM


Of the active efforts, Boulder’s, which began several years ago, is the furthest along and seems most likely to succeed, although Minneapolis-based Xcel Energy Inc., which provides power to Boulder, has opposed it.

Hawaii’s efforts have some support, too, but are still in the exploratory stages. Like Boulder’s effort, they are opposed by the local utility, Honolulu-based Hawaiian Electric Industries Inc.

The California effort would be a ballot initiative to form a statewide utility, but the man behind it said he doesn’t have the financial backing necessary to gather enough signatures to get the initiative on the ballot in November.

The nonprofit behind a rejected effort to buy Wash-ington’s grid is looking into other ways to restructure the city’s electrical-distribution system, and the effort in Santa Fe is dormant, if not dead.

If these efforts do, indeed, represent a trend, it would be a new one.

The number of utilities owned and run by local gov-ernments has remained constant over the past decade, ac-cording to Ursula Schryver, VP of education and customer programs for the American Public Power Association, which represents them.

Schryver said the number of groups contacting the APPA about forming publicly owned utilities also has re-mained constant at about 20 a year.

The number of electric cooperatives also has stayed about the same, according to Tracy Warren, a spokes-woman for the National Rural Electric Cooperative As-sociation. Warren said she has seen increased interest in forming electric co-ops, “but it’s in places like blogs,” and hasn’t manifested itself in an increased number of calls to her organization.

Publicly owned utilities make up the majority of the na-tion’s electric utilities, but investor-owned utilities, or IOUs, serve the majority of the country’s power customers.

According to the American Public Power Association’s 2015–2016 Annual Directory & Statistical Report, there are 2,013 publicly owned utilities, which amount to 60.9% of all electric utilities in the country. There are 877 coop-eratives (26.5%), 218 power marketers (6.6%), and 189 IOUs (5.7%). (The National Rural Electric Cooperative Association says it has 905 members, 28 more than the APPA’s figure for the number of co-ops in the country.)

IOUs have 101.2 million customers, or 68.4% of the to-tal, followed by publicly owned utilities with 21.4 million customers (14.5%), and co-ops with 18.9 million (12.8%), according to the APPA.

Forming a public utility or co-op is a long, complicated effort that requires a plan, the willingness to stick to it and also to adjust it as necessary, and the financial wherewithal to build an electric infrastructure or buy one from its own-er, which is often an IOU that doesn’t want to sell it.

The effort that’s furthest along is in Boulder, where vot-ers have agreed to pay a tax on their electric bills to pursue the idea. “With the money, we have done a detailed analy-sis of whether it’s feasible to create our own utility,” said Sarah Huntley, the city’s communications manager.

The city has concluded that it is, in fact, feasible and has been battling Xcel in court and before the Colorado Public Utilities Commission over the effort. “We’re cur-rently operating under a timetable where we’d like to have control of Xcel Energy’s assets by the end of 2017,” Huntley said.

A big driver of Boulder’s effort is the desire on the part of the city’s residents to embrace rooftop solar generation much more rapidly than Xcel wants to, Huntley said.

Rooftop solar generation is also a factor in Hawaii, which has so much of it that the state’s Public Utility Commission recently approved a proposal supported by Hawaiian Elec-tric Industries to end net metering in the state.

That was another thorn in the side of HEI customers and Hawaii officials, who have long been upset that they

A big driver of Boulder’s effort is the desire on the part of the city’s residents to embrace rooftop solar generation much more rapidly than Xcel wants to.

RESTRUCTUR ING

— Sarah Huntley


pay the highest electric rates in the nation and are less than thrilled with HEI’s agreement to sell itself to Juno Beach, Florida-based NextEra Energy Inc.

The island of Kauai is served by a co-op, the Kauai Island Utility Cooperative. “Its success is a reason that people are looking at co-ops for other parts of Hawaii,” Warren said. Elected officials and groups led by the solar industry and environmentalists are looking into forming alternatives to the HEI subsidiaries that serve the islands of Oahu, Hawaii, Maui, Molokai and Lanai.

A proposed acquisition also was a factor in a nonprofit’s effort to take over the local distribution grid in Washing-ton. Pepco Holdings Inc., which is based in and serves the nation’s capital, is seeking to be bought by Chicago-based Exelon Corp. for $6.8 billion.

A nonprofit called DC Public Power offered to buy Pepco’s grid in Washington so Exelon’s acquisition of Pepco wouldn’t have to be approved by the Public Service Commission of the District of Columbia. The offer would have removed a big obstacle to the deal, which regula-tors in the four states with Pepco operations — Virginia, Maryland, Delaware and New Jersey — have approved, but Exelon turned it down, said Michael Overturf, DC Public Power’s president.

RESTRUCTUR ING

DC Public Power last month released a report in which it proposed dividing Pepco’s D.C. grid into microgrids, each with 5,000 to 20,000 customers, and seeking opera-tors for each microgrid on a competitive basis.

In California, the secretary of state has given an ac-tivist named Ben Davis Jr. permission to begin collect-ing signatures for a ballot initiative that, if approved, would establish a statewide utility that would replace most of the state’s IOUs, including the San Francisco-based Pacific Gas & Electric Co., Rosemead, Califor-nia-based Southern California Edison and San Diego Gas & Electric.

Davis must gather 365,880 signatures by April 26 to get the initiative on the November ballot. He said last month he hasn’t begun gathering signatures and is hop-ing to attract some big donors to finance that effort, as he doesn’t have the infrastructure to fund it with small dona-tions or crowd funding.

Santa Fe’s effort to create a municipal utility could be on its last legs. The Public Service Co. of New Mexico has said it has no intention of selling its grid in Santa Fe and the city attorney earlier this year advised city councilors that trying to take over the grid through eminent domain would be a long and difficult effort that might not succeed.

THOUGHT LEADERSHIP — SPONSORED BY ITRON THOUGHT LEADERSHIP — SPONSORED BY ITRON

Distributed Intelligence and the Pathway to Smarter Energy, Water and CitiesBy Arun Sehgal, Director of Business Development and Engineering Advisor for Itron’s CTO Office

IMAGINE DETECTING OUTAGES 50 percent faster or

increasing the accuracy of energy theft detection by

300 percent. What if you could detect a methane leak in real

time and automatically shut off gas remotely to prevent a

dangerous situation or identify unsafe grid conditions before

they become a safety hazard to the customer? Or listen for

the acoustic signature of water leaks below the streets to

reduce non-revenue water and effect repair well before they

become costly and damaging main breaks. All of this and

much more is possible by applying the power of distributed

intelligence in smart meters and connected sensing devices to

many operational challenges.

With distributed intelligence, data analysis and operational

decisions can be made in the field, at the edge of the distribu-

tion network — not just in the back office — in near real time.

Today’s smart metering networks do a good job of gather-

ing information. But today’s operational challenges require

utilities to do more than just collect reams of data for billing

and subsequent analysis in the back office. Stated simply, it’s

better to solve some problems closer to where the problem is

occurring based on actionable data so decisions and action

can be taken immediately.

Yet, these use cases also require high-performance and reliable

communications. Fortunately, the same intelligence that en-

ables high-resolution data processing in edge devices can also

apply its brainpower to software-defined communications to

solve key communications performance and connectivity chal-

lenges associated with smart grid and smart cities applications.

The result is a system, such as Itron’s OpenWay Riva™ commu-

nications platform, with the following attributes:

a) A state-of-the-art communication network that offers

a standards compliant implementation, fast and robust

radio frequency and PLC network that assures con-

nectivity to the hardest-to-reach areas at the fastest

possible data rate. This connectivity dynamically adjusts

the network data rates to ensure that no node or device

is left unconnected. The network can form either a mesh

or a star configuration as the topography requires to

form a single, unified network for both powered devices

(like smart electricity meters, distribution automation

devices, other smart city sensors) and battery powered

nodes (like gas and water meters and sensors).

b) The ability to offer peer-to-peer connectivity to various

sensors and nodes to exchange near-real time informa-

tion that leads to localized decision making by a pow-

erful computing platform at each node. This enables

greatly enhanced grid and smart city functionality that

helps improve safety and reliability of the grid, gas and

water distribution systems, and smarter cities.

c) A communication network that offers a carefully ar-

chitected balance between data rates, system latency

and network infrastructure required to support current

and future use cases in the most cost-effective manner.

This coupled with a standards-driven network layer and

application security provides an ideal environment for in-

novation to deliver business outcomes that are simply not

possible with current generation technology. Utilities no

longer want just information from their networks – they’re

demanding grid intelligence and exception management

that streamlines their operations and lets them focus on

growing their businesses and improving their cities.

d) A vibrant ecosystem of innovative developers who are

combining their skills to offer newer applications and

sensors on this active grid to solve problems in new

and more cost-effective ways. These developers and

partners work in a standards and interoperability-driven

environment to provide new applications that run on the

network and platform.

With these attributes, distributed intelligence opens up

an entirely new frontier of opportunities for improving the

efficiency, reliability and safety of energy and water distribution

systems. Here’s how:

Electric UtilitiesWith these capabilities in place, electric utilities can use this

distributed intelligence to solve specific business challenges

that, until now, were neither practical nor affordable to solve.

Key to these use cases is the ability of the system to maintain

a continually accurate and updated connectivity model of

meters in relation to distribution infrastructure. Applications



Distributed Intelligence and the Pathway to Smarter Energy, Water and CitiesBy Arun Sehgal, Director of Business Development and Engineering Advisor for Itron’s CTO Office

IMAGINE DETECTING OUTAGES 50 percent faster or

increasing the accuracy of energy theft detection by

300 percent. What if you could detect a methane leak in real

time and automatically shut off gas remotely to prevent a

dangerous situation or identify unsafe grid conditions before

they become a safety hazard to the customer? Or listen for

the acoustic signature of water leaks below the streets to

reduce non-revenue water and effect repair well before they

become costly and damaging main breaks. All of this and

much more is possible by applying the power of distributed

intelligence in smart meters and connected sensing devices to

many operational challenges.

With distributed intelligence, data analysis and operational

decisions can be made in the field, at the edge of the distribu-

tion network — not just in the back office — in near real time.

Today’s smart metering networks do a good job of gather-

ing information. But today’s operational challenges require

utilities to do more than just collect reams of data for billing

and subsequent analysis in the back office. Stated simply, it’s

better to solve some problems closer to where the problem is

occurring based on actionable data so decisions and action

can be taken immediately.

Yet, these use cases also require high-performance and reliable

communications. Fortunately, the same intelligence that en-

ables high-resolution data processing in edge devices can also

apply its brainpower to software-defined communications to

solve key communications performance and connectivity chal-

lenges associated with smart grid and smart cities applications.

The result is a system, such as Itron’s OpenWay Riva™ commu-

nications platform, with the following attributes:

a) A state-of-the-art communication network that offers

a standards compliant implementation, fast and robust

radio frequency and PLC network that assures con-

nectivity to the hardest-to-reach areas at the fastest

possible data rate. This connectivity dynamically adjusts

the network data rates to ensure that no node or device

is left unconnected. The network can form either a mesh

or a star configuration as the topography requires to

form a single, unified network for both powered devices

(like smart electricity meters, distribution automation

devices, other smart city sensors) and battery powered

nodes (like gas and water meters and sensors).

b) The ability to offer peer-to-peer connectivity to various

sensors and nodes to exchange near-real time informa-

tion that leads to localized decision making by a pow-

erful computing platform at each node. This enables

greatly enhanced grid and smart city functionality that

helps improve safety and reliability of the grid, gas and

water distribution systems, and smarter cities.

c) A communication network that offers a carefully ar-

chitected balance between data rates, system latency

and network infrastructure required to support current

and future use cases in the most cost-effective manner.

This coupled with a standards-driven network layer and

application security provides an ideal environment for in-

novation to deliver business outcomes that are simply not

possible with current generation technology. Utilities no

longer want just information from their networks – they’re

demanding grid intelligence and exception management

that streamlines their operations and lets them focus on

growing their businesses and improving their cities.

d) A vibrant ecosystem of innovative developers who are

combining their skills to offer newer applications and

sensors on this active grid to solve problems in new

and more cost-effective ways. These developers and

partners work in a standards and interoperability-driven

environment to provide new applications that run on the

network and platform.

With these attributes, distributed intelligence opens up

an entirely new frontier of opportunities for improving the

efficiency, reliability and safety of energy and water distribution

systems. Here’s how:

Electric UtilitiesWith these capabilities in place, electric utilities can use this

distributed intelligence to solve specific business challenges

that, until now, were neither practical nor affordable to solve.

Key to these use cases is the ability of the system to maintain

a continually accurate and updated connectivity model of

meters in relation to distribution infrastructure. Applications



for electric utilities — including real-time diversion detection,

detection of unsafe grid conditions, outage detection and

analysis, and transformer load management — have the

potential to significantly improve the return on investment for

smart metering technology.

• High Impedance Detection: High-impedance connec-

tions (HIC) or “hot spots” on the low-voltage distribution

system represent a serious and ongoing safety risk, as well

as causing customer voltage problems and utility energy

losses. By continuously calculating and monitoring imped-

ance throughout the lower voltage system, distributed

intelligence changes the game in for HIC detection. This

provides a practical and cost-effective way for utilities

to identify these losses, voltage anomalies, and potential

safety issues before they become a safety hazard or a

costly liability.

• Outage Detection & Analysis: By combining locational

awareness on the grid with peer-to-peer communications

at the edge of the network, the meters systematically

and continuously valuate the status of nearby meters and

devices to quickly model and localize outage events and

report reliable and actionable information back to the

utility in near real time. The utility receives accurate and

actionable information, including the scale and location of

the outage, affected meters and affected transformers, in

a compressed timeframe.

• Transformer Load Manager: Distributed intelligence al-

lows the load on individual distribution transformers to be

analyzed continuously and managed locally in real time.

Meters with embedded intelligence communicate with

each other locally and continually calculate the total load

on the transformer and they know when transformer is

approaching overload conditions, whether from the line

side or customer side. When this occurs, a distributed

analytic running on the meters determines whether to

shut off controlled loads behind the transformer, turn

on or increase local distributed generation behind the

transformer, or take other actions to reduce transformer

loading below allowed levels.

• Diversion Detection: Diversion detection can now be

based on real-time, continuous and localized analysis of

changes in electricity current flows and voltage levels in

the distribution network to distinguish legitimate metered

loads versus those from theft. Through the meter’s ability

to communicate directly with other meters at different

levels of the network, and knowing exactly where they are

located are on the distribution system, the system identi-

fies when current is drawn on the secondary of a trans-

former that did not go through a meter, greatly increasing

the increasing the accuracy and timeliness of diversion

detection.

Gas UtilitiesDistributed intelligence also combines peer-to-peer commu-

nications and analysis of data throughout the gas distribution

network to aid in pipeline safety. Utilities can pair methane

sensors, seismic sensors, flood sensors and more with remote

disconnect valves, enabling the utility to potentially mitigate

dangerous situations and improve the safety of communities,

employees and first responders.

• System Integrity: New applications are emerging to moni-

tor pressure, temperature and pipeline stress via strain

gauges and cathodic protection, all using the same net-

work. This helps gas utilities engage in pipeline integrity

management, perform pressure studies and meet check in

dates for cathodic protection reports.

• Methane Detection: Methane sensing applications help

keep utility personnel and customers safe by monitor-

ing for unsafe or changing levels of methane and system

leaks. Further, remote disconnect valves can be paired

with the methane sensor to shut off gas service when

elevated levels of methane are detected.

Water UtilitiesFrom leak detection to remote disconnect and advanced

sensing, distributed intelligence enables water utilities to better

manage and conservation water resources.

• Leak Detection: With acoustic leak sensing, analysis and

presentment software, utilities are able to continuously

monitor their entire distribution network — that includes

both sides of the meter — for leaks. Leak detection

software enables utilities to identify and prioritize

potential distribution leaks for maintenance, reducing

water loss and enabling utilities to address leaks prior to

them becoming costly main breaks.

• Remote Disconnect: The advanced functionality of a

remote disconnect valve enables utilities to disconnect or

limit water flow to an end customer. It reduces the need

to roll a truck to perform this function, saving the utility a

significant amount of money while enhancing the safety

of field crews.

• Advanced Sensing: With distributed intelligence, utilities

can deploy additional sensors in the water distribution

system to monitor pressure and water quality. These

sensors will enable utilities to continuously monitor the

distribution system pressure and water quality, while

also correlating with other data, to enhance analysis

and reporting.

The Future of Distributed Intelligence With distributed intelligence, utilities can capitalize on the

potential of connected devices that have the computing power

to not only measure and communicate, but to solve problems

in the distribution network in real time. Data analysis and

decisions can take place where it makes the most sense — at

the edge of the network rather than only in the utility back

office. Devices dynamically detect theft situations, leaks or

system inefficiencies, improving safety, reliability and ultimately,

profitability. This is true edge intelligence.

About Arun Sehgal

Arun Sehgal works as the director of business development

and engineering advisor for Itron’s Chief Technical Officer.

Sehgal has worked at Itron for 15 years and has been involved

in creating Itron’s technology roadmap for networking prod-

ucts. In his current role, Sehgal is spearheading the technology

evangelization of Itron Riva™, the company’s next generation

computing and networking technologies for smart cities, smart

utilities and smart communities.



» UA SUMMIT 2016

OCULUS VR’S RELEASE of its Rift virtual-reality headsets this spring was a big deal for gamers.

It also could be a big deal for the electric-power indus-try and other industries with lots of infrastructure spread out over wide areas.

Space-Time Insight, a San Mateo, California, devel-oper of visualization and analytics software, has been test-ing applications for the Rift with several electric and gas utilities it’s not permitted to identify.

The company demonstrated a pilot Rift application that combines virtual reality and analytics at last fall’s Utility Analytics Week conference in New Orleans.

In the demo, the person wearing the headset (and a glove that’s visible in the virtual world seen by the head-set’s wearer) visits a virtual substation and views two dif-ferent pieces of equipment that are obviously in distress.

One, a circuit breaker, has a green cloud of gas that represents invisible and poisonous sulfur hexafluoride

coming out of it, and the other, a transformer, has a large, red cylinder hover-ing over it because its in-

sulation oil is low. In both instances, the Rift wearer

is able to see what would be real-time data about the

equipment if the headset were hooked up to the computer sys-

tem of the electric company that owned the substation, and press buttons to summon a repair crew.

Space-Time Insight’s prototype application for Rift has three potential uses, said Steve Ehrlich, Space-Time Insight’s senior vice president for marketing and product management. A utility’s control-room workers could use it to try to get a better sense of problems in a location before sending a truck to that location. Workers throughout a utility could use it to familiarize themselves with and train themselves on equipment. And someone in a control room could use the app while talking to someone in a substation to get a better idea of what that person is seeing.

“We see many, many interesting benefits coming from this technology and really the merger of virtual reality and data analytics,” Ehrlich said.

Space-Time Insight is also working with a utility on using Lidar to create virtual views of vegetation, particu-larly trees, in the utility’s territory. In Lidar, objects are tar-geted with a laser and the light that reflects from them is analyzed to gather data about them. The virtual views of vegetation would be created from point clouds of data col-lected by laser scanners connected to planes or drones. The images of the vegetation created by Lidar could be made clearer by overlaying them with images of the vegetation taken on the ground.

Space-Time Insight Hopes for Lift from RiftBY PETER KEY

Continued on page 62...


WITH THE ABILITY of preventative analytics to pin-point energy use statistics, the electric power industry

is awash in reams of data nowadays. But not all of it may prove as useful as hoped, and there are other hurdles that will have to be navigated as utilities put Big Data to work.

EnergyBiz got on the phone with noted industry futur-ist CD Hobbs, a vice president and executive partner with Gartner Executive Programs, to chat about trends in ana-lytics and how utilities can best put the numbers to use.

A bright future powered by data

“Big Data and analytics are the future of utility opera-tions,” Hobbs says.

The potential combination of data from field sensors in a utility’s operating environment with weather, business and other outside data offer decision-making tools that utilities have always imagined having, Hobbs says. The trend represents the biggest opportunity for intelligent operation of the grid and management of utility assets since the beginning of the industry, he says.

Hobbs envisions self-healing systems and predictive analytics that will improve load maintenance and control. Management in the future will be much more scientific than the last century’s tactics that relied more on intuition and “blunt force,” he says.

Analytics can have the most impact on the operation of distribution and transmission systems and the ability of a utility to show they’re operating efficiently, he says.

One company in the gas sector has installed turbine sen-sors that have helped it improve output and reduced un-scheduled maintenance, he notes. Sensors are also allowing much more data collection from meters, letting companies determine the precise location of problems in the distribu-tion system as part of smart-grid implementation.

One area in which data is making a difference is load forecasting. Now companies can collect meter data every 15 minutes, whereas before the industry had to rely on old and limited data, he says.

Growing pains

Data collection has led to some consumer backlash, as we all know. It could be perceived as an invasion of privacy, especially if technology allows data to be collected from be-hind the meter, such as when appliances or air conditioning are turned on.

Hobbs says there is the potential for laws to be estab-lished that say only data from in front of the meter can be used.

Another struggle Hobbs sees is in how companies de-termine the cost savings of an outage that was prevented using analytics. In other words, what is an outage that doesn’t happen worth?

One way utilities could determine the cost savings would be to show what they have spent on solving similar problems in the past and then show what they are now spending while using predictive analytics, he says.

Another coming challenge is cultural. Currently, opera-tions engineers don’t always talk to information technol-ogy people, but that’s what it’s

Gartner’s CD Hobbs Talks Big Data and the Future for UtilitiesBY MATT WHITTAKER



» UA SUMMIT 2016

WHEN YOU HEAR ANALYTICS, you might think numbers, stats and data all floating and swirling

around like a crazy math-geek sequel to Pixar’s hit flick, “Inside Out.”

When Entergy’s John Scott and Eddie Himel hear analytics, they think circuit breakers, load tap changers (LTCs) and maintenance all cleaned up and organized like a simplified, smarter sequel to the old Excel spread-sheets they once used.

They think: No more tinkering; now it’s high tech.Scott is the senior grid manager and Himel is the asset

management substation manager for the massive utility. Entergy’s condition-based maintenance program, they say, began in earnest in 2007 with a focus on low-voltage oil circuit breakers. Why such a specific focus? Well, they have a lot of them, and getting around to all of them with their time-based maintenance program was difficult and took a whole lot of resources. (They also admitted that, as it was a pilot, those breakers being cheaper with a lower chance of causing reliability issues to the grid if something went awry played a significant role in their choice as well.)

But those potential worry spots never materialized. The program was such a success that, by 2009, they were expanding. They pushed out to include load tap chang-ers, high-voltage oil circuit breakers and transmission line motor-operated switches.

So, how does all that hardware intersect with the world of analytics? At one major spot: all that data. (That’s what takes us from tinkering to high tech.) Information that used to be kept on paper, in spreadsheets or on discs, that was once compared by human eyeball can now be com-pared digitally — and used for better predictions, too.

“When our employees do their monthly routine substation inspections, they collect data on each asset’s as-found condition,” Himel said. “They then enter that data into the computerized system running the main-tenance algorithm.”

And every day that very valuable data adjusts the al-gorithm, informing which assets need a little preventative TLC, which can last longer, which are iffy and which are happy as little clams. Yes, every day.

“We’re constantly evaluating that information and tweaking the algorithm,” Scott said. “What results is a main-tenance program that’s truly responsive to the needs of the system it supports. The data helps us learn, and then we use that knowledge to make our maintenance system smarter.”

And these days, everything has to be smarter, from the phone in your pocket to the substation bringing the power to charge it.

The value of that data to Entergy and any utility, really, lies in the analytics, the evaluation of those data sets to create programs that put science behind which assets are targeted for repairs and replacement rather than the old gut feeling or eyeing of a potential issue.

“Data analytics really provides us the biggest bang for our buck with our maintenance program,” Scott said.

There are other layers as well. Knowing which asset is A-OK and which is in trouble in near real-time allows for efficiency. They can shift needed resources away from the assets in good health to others in need without it all being a guessing game of redistribution. That keeps costs lower and the system healthier. Lower costs mean lower bills on the customer end, and a robust system means better reli-ability. It’s all connected.

Ask Scott and Himel for an interesting story centered on analysis, and they’ll tell you about unexpected surprises (of the good kind).

“When we first launched the low-voltage oil circuit breaker algorithm, we redeployed more than 6,252 man-hours,” Himel said. “We saw similar impacts when we launched the programs for other assets and nearly elimi-nated LTC failures.”

Suddenly, Scott added, they were able to meet system needs by reshaping maintenance strategies when before

Entergy Injects Analytics into MaintenanceBY KATHLEEN DAVIS


» UA SUMMIT 2016

they started with those strategies and just hoped fervently they met those system needs.

But no new program or strategy comes to fruition without leaping a hurdle or two. And this one was no ex-ception. At first, it was a bit wearing on employees who had to juggle their maintenance tasks and lots of extra data collection and entry. Himel and Scott admit it was differ-ent work for those employees, and that presented some challenges in getting back good data.

“We all know that changing routines and culture can be difficult,” Himel said. “We spent significant time ex-plaining how this new work fit into the larger picture of

what we were trying to accomplish and demonstrating its value to employees. We had to make a compelling case to employees that these new tasks would result in a healthier system for us and better service for our customers.”

And educating those front-line employees on the ben-efits of these programs — along with honestly asking for employee input — is the top bit of advice Himel and Scott would give to other utilities looking to establish similar programs. You may think it’s all about analytics and the algorithms, but it’s really about the people and the per-sonalities first.

“Make them a part of the process,” Scott said. “And make the process transparent. Explain the benefits early and often.”

Added Himel, “You may need to start slow. If you gain some small wins early, you can use those to leverage future buy-in and expansion. And don’t forget that change is dif-ficult for many people.”

In the end, it all worked out, though, for people, data, analytics and load-tap changers. And now the program is moving along smoothly. In fact, they plan to expand again to more assets. And there are new horizons in other main-

tenance areas, too, based on the success of this program.“The analytics we have now are also informing data-

driven goals for proactive and reactive maintenance at Entergy,” Scott said. “Within the next few years, we’re shifting resources from reactive to proactive maintenance, aiming for a 30% reduction in reac-tive maintenance.”

THOUGHT LEADERSHIP — SPONSORED BY QUANTA SERVICES THOUGHT LEADERSHIP — SPONSORED BY QUANTA SERVICES

Record Energized Reconductor Project Brings Reliable Power to South Texas

THE ENERGIZED RECONDUCTOR of the Lower Rio

Grande Valley (LRGV) is a landmark project for Quanta

Services, American Electric Power (AEP) and the utility

industry. The 240 mile project capitalized on multiple innova-

tive technologies from across the industry, allowing AEP to

provide an immediate solution to the problem of reliable

electricity while addressing future load growth. This challenge

was met by Quanta Energized Services (QES), an entity of

Quanta Services, who is the recognized industry leader for live

line work. Their forward thinking allowed for the entire 240

miles to be completed while in an energized state.

The LRGV is served by two 345-kV transmission lines that

originate in Corpus Christi, 120 miles to the north, and account

for the bulk of the electricity carried into the LRGV. The lines

are in a precarious position due to the LRGV’s dependency on

them to supply the majority of the power to South Texas, as well

as their proximity to the Texas Gulf Coast exposing them to cor-

rosive salt spray and making them susceptible to storm outages.

In February 2011 South Texas experienced record winter tem-

peratures which dropped as low as 20 degrees Fahrenheit. For

a region accustomed to average February temperatures in the

mid 60’s, these temperatures were crippling. Panicked residents

flooded the stores in search of portable heaters. This immediate

demand for electricity in conjunction with downed generation

due to prescheduled maintenance caused an overload of the

electric transmission system resulting in rolling blackouts.

Steady Load and Population GrowthSummer highs in the LRGV routinely hit triple digits, this com-

piled with a 30% population growth from 2000-2010 resulted

in AEP’s peak electric demand increasing from 1000 MW in the

summer of 2000 to a summer record peak demand of 2220 MW

in 2010. While an increase in load over a decade is to be expect-

ed the 514 MW jump from the previous summer during the 2011

winter storm (2220 MW to 2734 MW) was outside all modeled

projections. Furthermore, due to continued growth, the projected

2016 summer peak load was expected to reach 2800 MW with a

forecasted summer 2020 peak load of over 3000 MW.

An immediate plan was needed to supply relief to the cir-

cuits most affected by the short term seasonal spikes. How-

ever, this plan also had to offer a long term solution to address

the load increases for 2016, 2020 and beyond. AEP, as well

as the Electric Reliability Council of Texas (ERCOT), needed

a solution that could meet the pressing reliability demands

while safely maintaining the aggressive schedule. ERCOT was

presented with a number of traditional cold constructions op-

tions, running the gamut of temporary upgrades to complete

overhauls. However as AEP looked into permitting, rights of

way (ROW) acquisition and various customer disruptions it

became apparent that these variables had a very real chance of

interrupting or adding unforeseen costs to the project. How-

ever the biggest area of concern was that ERCOT could only

grant outages in the spring and summer months, if at all, and

the lines would be required to be back in service within hours

whenever system anomalies warranted. Taking these limita-

tions into account, it was apparent that a traditional construc-

tion solution would only add additional delays to an already

time sensitive project and therefore could not be counted on as

a reliable option to meet the 2016 completion schedule.

Partnering on a Progressive Option AEP approached Quanta Energized Services (QES), to dis-

cuss their live-line planning capabilities and North Houston

Pole Line, a Quanta Services entity, about their construction

expertise and cable manufacturer CTC Global for their ACCC

Lightweight Core Conductor. A plan was conceived to recon-

ductor the entire 240 miles while keeping it in an energized

state. While smaller energized projects had been successfully

completed in the past, an energized reconductor project of this

size and length had never been attempted. In early spring 2011,

AEP’s plan to perform the energized reconductor of the exist-

ing 345-kV transmission lines was approved by the regional

planning group at ERCOT.

A year before the first lineman hit the right-of-way Quanta

Energized Services technical advisors went about develop-

ing detailed, project-specific work procedures with calculated

man-hours, sequencing, schedules and anticipated resources.

Among the unique aspects of these one-of-a-kind work proce-



Record Energized Reconductor Project Brings Reliable Power to South Texas

THE ENERGIZED RECONDUCTOR of the Lower Rio

Grande Valley (LRGV) is a landmark project for Quanta

Services, American Electric Power (AEP) and the utility

industry. The 240 mile project capitalized on multiple innova-

tive technologies from across the industry, allowing AEP to

provide an immediate solution to the problem of reliable

electricity while addressing future load growth. This challenge

was met by Quanta Energized Services (QES), an entity of

Quanta Services, who is the recognized industry leader for live

line work. Their forward thinking allowed for the entire 240

miles to be completed while in an energized state.

The LRGV is served by two 345-kV transmission lines that

originate in Corpus Christi, 120 miles to the north, and account

for the bulk of the electricity carried into the LRGV. The lines

are in a precarious position due to the LRGV’s dependency on

them to supply the majority of the power to South Texas, as well

as their proximity to the Texas Gulf Coast exposing them to cor-

rosive salt spray and making them susceptible to storm outages.

In February 2011 South Texas experienced record winter tem-

peratures which dropped as low as 20 degrees Fahrenheit. For

a region accustomed to average February temperatures in the

mid 60’s, these temperatures were crippling. Panicked residents

flooded the stores in search of portable heaters. This immediate

demand for electricity in conjunction with downed generation

due to prescheduled maintenance caused an overload of the

electric transmission system resulting in rolling blackouts.

Steady Load and Population GrowthSummer highs in the LRGV routinely hit triple digits, this com-

piled with a 30% population growth from 2000-2010 resulted

in AEP’s peak electric demand increasing from 1000 MW in the

summer of 2000 to a summer record peak demand of 2220 MW

in 2010. While an increase in load over a decade is to be expect-

ed the 514 MW jump from the previous summer during the 2011

winter storm (2220 MW to 2734 MW) was outside all modeled

projections. Furthermore, due to continued growth, the projected

2016 summer peak load was expected to reach 2800 MW with a

forecasted summer 2020 peak load of over 3000 MW.

An immediate plan was needed to supply relief to the cir-

cuits most affected by the short term seasonal spikes. How-

ever, this plan also had to offer a long term solution to address

the load increases for 2016, 2020 and beyond. AEP, as well

as the Electric Reliability Council of Texas (ERCOT), needed

a solution that could meet the pressing reliability demands

while safely maintaining the aggressive schedule. ERCOT was

presented with a number of traditional cold constructions op-

tions, running the gamut of temporary upgrades to complete

overhauls. However as AEP looked into permitting, rights of

way (ROW) acquisition and various customer disruptions it

became apparent that these variables had a very real chance of

interrupting or adding unforeseen costs to the project. How-

ever the biggest area of concern was that ERCOT could only

grant outages in the spring and summer months, if at all, and

the lines would be required to be back in service within hours

whenever system anomalies warranted. Taking these limita-

tions into account, it was apparent that a traditional construc-

tion solution would only add additional delays to an already

time sensitive project and therefore could not be counted on as

a reliable option to meet the 2016 completion schedule.

Partnering on a Progressive Option AEP approached Quanta Energized Services (QES), to dis-

cuss their live-line planning capabilities and North Houston

Pole Line, a Quanta Services entity, about their construction

expertise and cable manufacturer CTC Global for their ACCC

Lightweight Core Conductor. A plan was conceived to recon-

ductor the entire 240 miles while keeping it in an energized

state. While smaller energized projects had been successfully

completed in the past, an energized reconductor project of this

size and length had never been attempted. In early spring 2011,

AEP’s plan to perform the energized reconductor of the exist-

ing 345-kV transmission lines was approved by the regional

planning group at ERCOT.

A year before the first lineman hit the right-of-way Quanta

Energized Services technical advisors went about develop-

ing detailed, project-specific work procedures with calculated

man-hours, sequencing, schedules and anticipated resources.

Among the unique aspects of these one-of-a-kind work proce-



dures was the ability to adapt to job irregularities. A necessary

adaptation that occurred early in the project was related to the

bundled conductor, which sat in a vertical configuration rather

than the tradition horizontal configuration. To most efficiently

tackle this issue the team needed to adapt both the equipment

and the procedures. This first test proved to be a calling card

for the entire project as procedures were continually updated

to make the project safer and more efficient.

State-of-the-Art TechnologiesThrough these collaborative partnerships, a number of innova-

tive technologies were applied that allowed for an accelerated

work schedule to ensure that the required in service date for

the upgraded line was achieved. The technological advances

that made this project possible were:

• Quanta Services Energized Barehand work methods

and proprietary LineMaster Robotic Arm made it pos-

sible for all 240 miles of 345kV conductor to be removed

and replaced without interrupting the flow of electric-

ity. Attached to a boom on a ground-based vehicle, the

LineMaster Robotic Arm safely moves and securely holds

energized power lines while the conductors, insulators

and structures are maintained, replaced or rebuilt. In ad-

dition to the practical importance of the robotic arm, the

barehand work methods were developed by a team which

collectively has more than 400 years of energized work ex-

perience, starting with the first-ever energized reconductor

project in 1990.

• The use of Aluminum Conductor Composite Core (ACCC)

to replace the existing conductor. While the same diam-

eter as the original conductor, the ACCC is comprised of

28% more aluminum making it lighter. The extra aluminum

doubles the conductivity capacity of the lines, while reduc-

ing sag overtime due to less weight and heat. This meant

that AEP could replace the old conductor without widen-

ing clearances or causing tower modifications and rebuilds.

Also of great importance due to the location of the job, the

ACCC is more resistant to corrosion and has the ability to

handle future increases in load.

Project ExecutionThe project called for an aggressive schedule to ensure that the

line would be upgraded by the required date. The project was

divided into five segments between the substations. Doing so

resulted in several strategic as well as financial benefits:

• It reduced the risk on the entire system serving the LRGV;

• It prioritized the line sections between the substations,

so that the completed areas could immediately reap the

benefits of the system upgrade;

• It created five smaller projects, which increased the ef-

ficiency of scheduling materials, equipment and crews, as

well as minimizing the project costs.

An energized reconductor of this size required careful plan-

ning. Processes and work procedures for each task had to

be developed. A group of Quanta technical advisors collabo-

rated together to produce these procedures. As the project

progressed, lessons were learned and these procedures were

further refined and revised.

The barehand work method was instrumental to the work

that was performed on the energized conductors. When

working barehand the lineman wear conductive suits and are

bonded to the conductor, putting them at the same potential

as the energized conductor allowing them to physically touch

the energized conductor and equipment. To support conduc-

tors while unclipping or clipping, the LineMaster Single Point

Lifter robotic arm was used. This tool provided safe, secure

and controlled support of the energized conductors.

In order to replace conductors in an energized state, a

temporary support for a phase conductor needed to be es-

tablished. This was done by installing temporary structures at

the edge of the right of way next to the existing line. Since the

temporary structures were installed in the ROW, no additional

land or the timely permits associated with land acquisition

were required.

The new conductor was then installed in its permanent

position, clipped in and sagged. Load from another phase

transferred to this new conductor and the old conductor was

de-energized. The old conductor was then reconductored. This

was repeated, until all three phase conductors were replaced,

without any interruption to the electrical service. This was per-

formed section by section, on average 20 to 30 miles. This plan

allowed for the reuse of existing structures, therefore minimizing

the impact on landowners and negating any of the timely per-

mits associated with land acquisition and construction.

Other realized cost savings during construction were the

energized crews’ ability to perform out of the scope upgrades,

such as replacing damaged V-string insulators and the upgrade

of existing shield wire with OPGW fiber. This type of work often

requires months of planning to get the necessary outages,

which can be cancelled at any time, resulting in wasted revenue

and man-hours. This is one of the factors that led ERCOT to be

able to take back every scheduled outage because construc-

tion and repairs were made while the line was energized. The

state-of-the-art and proprietary technology used on the ener-

gized reconductoring, led to ahead of schedule completion of

the project, despite adapting to inconsistent outage schedules

and record-setting inclement weather.

While numerous factors played an important part in the

success of this project, from state-of-the-art equipment, to

extensive training, none were as important as the detailed work

procedures. The work procedures, developed by the techni-

cal advisors, were developed specifically for each part of this

project. Making the scope even more unique, was the fact that

it was under continuous evolution. Methods of success and

failure from the field, were used to further refine these proce-

dures. As work procedures were refined and the crews became

experienced in these procedures and work methods the result

was a gradual to substantial improvement in productivity, al-

lowing the project to finished eight months ahead of schedule

and millions of dollars under budget.

The Future of Transmission ConstructionIn South Texas with the completion of the Energized Reconduc-

tor Project, Quanta Services and AEP have ensured numerous

communities in the LRGV that their need for reliable power today,

tomorrow and well into the future will be met. Lights will stay

on, homes will be cooled and heated, schools will stay in session

and hospitals will continue to save people. Quanta Services has

shown that with the use of innovative technology and the lessons

learned from the project they are more than ready to tackle all

future challenges. By creating a partnership between Quanta Ser-

vices and AEP a solution was created that ensured the foundation

built from the world’s longest energized project will continue to

benefit future utility customers around the globe.



» TECH FRONTIER

WITHIN THE $1.1 TRILLION spending bill signed by President Obama last fall is a legal framework for

sharing information about digital security threats that upset privacy advocates but which energy industry of-ficials say will help keep the nation’s electric grid safe from cyberattacks.

“While the electric power sector already engages in sig-nificant information-sharing, and has in place mandatory and enforceable reliability and cybersecurity standards, taking steps to improve the sharing of actionable security information between the government and industry is vital to protecting the electric grid from all possible threats,” Edison Electric Institute President Tom Kuhn said in a statement after the legislation was passed.

The new law, known as the Cybersecurity Act of 2015, grants legal protection to private companies and govern-ment agencies sharing what they know about digital secu-rity risks and potential attacks. Under the law, companies are exempt from antitrust scrutiny and other forms of li-ability for working together to share threat information.

Related: Regulators weigh utility supply-chain cybersecu-rity rules, .

The law’s passage comes at a time of increased atten-tion to potential cyber vulnerabilities in the electric grid. An electrical outage last month in Ukraine is said to be the first attributable to a digital attack, which that coun-try’s security authorities have reportedly blamed on Rus-sia. And in the United States, the Associated Press, citing anonymous sources, reported late last month that foreign hackers have apparently penetrated utility operational net-works about a dozen times within the past decade.

National Security Agency Director Adm. Michael Rogers told lawmakers last year that China and one or two other countries are capable of such digital attacks. Iran also is suspected of being in that camp.

Organizations in the electric power sector had been sharing security information even before passage of the cybersecurity act, said Scott Aaronson, EEI’s senior direc-tor of national security policy.

“Not all, but a lot, of what this legislation clarifies is already happening between the government and the in-dustry when it comes to cyberthreat indicators,” he said.

Those indicators can be anything from vulnerabilities in commonly used software to evidence of ongoing attacks or infections by malicious software, he said.

“It is malware, it is threat signatures, it is bad [Internet protocol] addresses, it is vulnerability information, and it is forensics on known attacks,” said Aaronson. “It runs the whole gamut and sort of speaks to the necessity of sharing information — there is a lot of it.”

Some of the sharing is done through direct relation-ships between individual utilities and government agen-

Cybersecurity Law Gives Feds New Power to Protect the GridBY STEVEN MELENDEZ

An electrical outage last month in Ukraine is said to be the first attributable to a digital attack, which that country’s security authorities have reportedly blamed on Russia.


cies, and some is done through the North American Elec-tric Reliability Corp.’s Electricity Information Sharing and Analysis Center, he said.

NERC didn’t respond to requests for comment, but its 2014 Cyber Risk Preparedness Assessment emphasized the importance of sharing cybersecurity data with law en-forcement and the sharing center.

“These organizations can provide additional resources, context, and coordination during incident response and can improve an entity’s effectiveness in responding to and mitigating the impact from an attack,” the report said.

The new law has the potential to take “the general counsel’s office out of the equation” and enable more real-time sharing, Aaronson said.

“There’s the popular line that an adversary is attacking us relentlessly, and we’re calling meetings,” he said. “The second you call a meeting, you’re losing.”

The law also calls on U.S. national security officials, including the Director of National Intelligence, the At-torney General and the Defense and Homeland Security secretaries, to establish frameworks for sharing cyberse-curity information between federal agencies and private industry — something Aaronson welcomed.

“We as a sector certainly see traffic on our networks that can be troubling … so to the extent that the informa-tion or the threats that we see can be communicated to the government to the benefit of everybody, that is a good thing,” he said.

Privacy advocates, on the other hand, expressed con-cerns the law would leave Americans little recourse if their personal information was shared without their permission in the name of cybersecurity.

“Companies face no liability — even when bad things happen — for information that is shared with DHS or potentially other agencies designated by the president (which could include the FBI),” American Civil Liber-ties Union legislative counsel Neema Singh Guliani said. “So, consumers have little opportunity for redress in cases where their private information is shared without consent or even notice.”

The law does require agencies and companies to take steps to remove any personally identifiable information “not directly related to a cybersecurity threat.” Privacy groups, however, argue companies could still claim private information, like IP addresses and suspect email attach-ments, are related to cybersecurity.

“Americans demand real solutions that will protect them from foreign hackers, not knee-jerk responses that allow companies to fork over huge amounts of their cus-tomers’ private data with only cursory review,” Sen. Ron Wyden, D-Ore., said in a statement opposing the bill.

But those concerns may be less of an issue for the elec-tric power industry, which is more interested in sharing information about threats to its operational systems than about sharing records from billing systems and other data-bases that would contain confidential customer data.

“Our companies do bill their customers, and so there is credit card data, there is PII on information technology sys-tems and we work very hard to protect that,” said Aaronson, using a common abbreviation for personally identifiable in-formation. “We really are looking more on the operational side of the system, and that does not have the same PII concerns that we really have on the IT side.”


» TECH FRONTIER

THE UTILITY INDUSTRY isn’t happy about the idea of mandatory standards, but federal regulators are

weighing rules designed to deal with security vulnerabili-ties posed by technology installed throughout bulk power transmission networks.

This winter, the Federal Energy Regulatory Com-mission held a technical conference to begin to map out where new federal standards for utility supply-chain cy-bersecurity might make sense.

The risks, experts agree, are enormous. On Dec. 23, 2015, the first power outage believed to have been caused by a cyberattack left 80,000 customers in the Ukraine without power for six hours. The incident has drawn wide-spread attention from utilities and regulators around the world. Washington-based SANS ICS, in a report on the attack, said hackers likely caused the outage by remotely

switching breakers to cut power, after installing malware to prevent technicians from detecting the attack.

In the U.S., the utility industry is gearing up to meet an April 1 compliance deadline for the latest North Ameri-can Reliability Corporation standard, CIP 5, which in-cludes cybersecurity requirements not specifically related to the utility supply chain. FERC’s effort seeks to close this gap.

Last summer, FERC and NERC proposed seven up-dates to CIP reliability standards. These updates seek to address risks to industrial control system hardware, soft-ware, communications and services associated with bulk electric system operations, and also to develop new secu-rity controls for supply-chain management.

In this proposed rulemaking, FERC noted, “These malware campaigns represent a new type of threat to the

Regulators Weigh Utility Supply-chain Cybersecurity RulesBY AMY GAHRAN


In public comments to FERC, a coalition of utility trade associations has opposed mandatory supply-chain cybersecurity requirements.

reliability of the bulk electric system, where malicious code can infect the software of industrial control systems used by responsible entities.”

In public comments to FERC, a coalition of utility trade associations has opposed mandatory supply-chain cybersecurity requirements.

“While the trade associations agree that CIP and cy-bersecurity risks form a high-priority strategic matter for the electric industry, no events or disturbances have taken place that indicate a problem or emerging pattern or trend,” the group said in a statement.

The coalition includes the Edison Electric Institute, the American Public Power As-sociation, the National Rural Electric Cooperative Asso-ciation, the Electric Power Supply Association, the Elec-tricity Consumers Resource Council, the Transmission Access Policy Study Group and the Large Public Power Council.

According to Scott Aar-onson, managing director of national security policy at EEI, the industry’s preferred approach would be coordi-nation across the industry, in collaboration with gov-ernment and supply-chain vendors, rather than the imposition of regulatory re-quirements absent that feed-back.

The Ukraine attack and other incidents illustrate how the line between cybersecurity and physical security of as-sets is getting blurry — challenging the traditional divi-sion of information technology and operations technology within utilities.

As Aaronson observed, “I don’t differentiate between cyber and physical threats anymore. We have a digital overlay for our physical infrastructure. We can operate the assets independently of that overlay if necessary, but far

less efficiently. From a threat perspective, all physical at-tacks have cyber implications, and vice versa. So response must be holistic.”

Whatever emerges from the effort to craft new utility supply-chain cybersecurity standards, EEI has identified four areas that it says deserve closest attention:

Information flow. It’s crucial that accurate informa-tion about system and device conditions gets to the right people, from CEOs and government officials to field op-erators, instantaneously. The challenge is ensuring the ac-curacy of data from network devices, and the integrity and redundancy of communication networks.

Tools and technologies. Aaronson noted that many technologies developed by the federal government, especial-ly for defense and intelligence, could be applied to improve situational awareness on bulk power networks. NERC’s Electricity Information Sharing and Analysis Center is a hub of communication and collaboration in this effort.

Incident response. “This is about resilience,” said Aaronson. “With the Deepwater Horizon incident, all of the other oil companies said, ‘That’s not our well, not our problem.’ But the power grid is one big machine with thousands of owners and operators. We all have a vested interest in mutual resilience. If one of us is hit by a cyberat-tack, the rest of us need to kick in to support the response, like a bucket brigade. This can be organized through part-nership at a very high level, involving CEOs and top ad-ministration officials.”

Cross-sector coordination. Supply-chain cybersecu-rity involves more than just electric utilities. Active coop-eration with related sectors such as manufacturing, tele-com and transportation/warehousing is key. Coordinating councils could support this goal.

Whether FERC and NERC push forward on supply-chain cybersecurity standards remains to be seen. But such standards would not address cybersecurity in local distri-bution networks, where vulnerabilities also exist.

In the meantime, utilities may work to strengthen their corporate policies on supply-chain cybersecurity — perhaps building on industry and government initiatives, such as Supply Chain Risk Management from the Na-tional Institute of Standards and Technology. Also, state public utility commissions and local officials might also seek to regulate distribution-network cybersecurity.


» TECH FRONTIER

THE INDUSTRIAL INTERNET has gone underground. GE and Accenture have announced their first

customer for what they’re calling the Intelligent Pipeline Solution, which promises to help natural-gas utilities and other operators monitor their pipelines in real-time us-ing the same communication network that undergirds the Angry Birds app.

“Pipeline operators run a risk assessment once a year,” said Accenture’s Jeff Miers, midstream lead at the compa-ny’s North America resources division. “With Intelligent Pipeline Solution, they can access risk analytics every day.”

There are more than 2 million miles of pipeline around the world, a lot of it aging. More than half of America’s pipes were laid before 1970, which means they are ap-proaching their life expectancy. According to federal sta-tistics, there were more than 5,000 significant pipeline incidents resulting in 360 fatalities and 1,365 injuries na-tionwide between 1995 and 2014.

For some, the problem is immediate. The city of Chi-cago, for example, has been working to replace its natu-ral gas pipelines for several years now. Last year, Google Street View teamed up with the Environmental Defense Fund, a nonprofit group, to identify methane leaks in the city’s underground infrastructure. They found 350 leaks

in the 100-year-old system. Methane is a greenhouse gas that traps heat in the earth’s atmosphere and contributes to global warming.

Jennifer Block, a spokeswoman for Peoples Gas, the company that manages Chicago’s pipelines, said many of the city’s underground pipes are made of cast iron, ductile iron, and steel, as well as plastic and polyethylene. Gener-ally, metal pipes have the high-

GE, Accenture Develop Pipeline Safety Software BY ALLEN TAYLOR


Pipeline operators run a risk assessment once a year. With Intelligent Pipeline Solution, they can access risk analytics every day...

Accenture’s Jeff Miers, midstream lead at the company’s North America resources division.


IN THE 1990s, convergence was a popular term in the telecommunications industry, where it referred to the

merging of phone, video and Internet services and providers.Now, it’s a buzzword in the electric-power industry,

where it refers to the growing linkages between informa-tion technology and operations technology.

Gartner Inc. named IT/OT convergence as one of its Top 10 Tech Trends Impacting the Utility Industry in 2015. The Stamford, Connecticut-based IT research and consulting firm said convergence will enable power com-panies to move from energy-provisioning business models to digital business models.

That doesn’t mean power companies’ first concerns won’t always be keeping their customers’ lights on and machines running. What it does mean is that they will use data from both their business and operations sides to do so in ways that are more reliable, save money and energy, and better serve their customers.

Power companies “see if they make this type of transi-tion, then that can change a lot of the way they do busi-ness,” said Scott Koehler, vice president of global strategy for smart-grid IT at Schneider Electric S.E., the Rueil Malmaison, France-based energy-management and auto-mation company.

The largest technological driver of the convergence is the development of ubiquitous computing and connectivity.

The equipment in generation, transmission and distri-bution systems has long had some intelligence, even if it consists solely of the equipment’s ability to detect a lim-ited range of problems and shut itself down or disconnect itself in response to one of them.

Now, however, the equipment’s intelligence has in-creased; the amount of intelligent equipment has in-creased; and much of the equipment communicates its status in real or near-real time.

That makes possible — and is made possible by — the deployment of smart-grid technologies, including ad-vanced metering infrastructure and synchrophasors.

But the effects of ubiquitous computing and connectiv-ity reach beyond the grid and into power plants and grid control rooms. There, over many years, equipment went from being controlled by a combination of automation technologies and humans to being controlled by software systems with human oversight.

Those systems, including supervisory control and data acquisition, or SCADA, systems, and various brands of operating systems, also are capable of producing real-time and near-real-time data. And the Internet enables that

data to be sent to every party interested in it — includ-ing the companies that own the equipment the systems control and monitor, the operator of the grid that takes the power from the equipment, and the companies that make and maintain the equipment.

One result is that power generators’ expectations have changed, said Wally Walejeski, the product manager for utilities for Meridium LLC, a Roanoke, Virginia-based developer of asset performance management software. They now want to avoid not just the outright failure of a piece of their equipment, but any condition that could prevent them from producing the power they are con-tracted to produce.

Utilities Embracing IT-OT ConvergenceBY PETER KEY


» TECH FRONTIER

The IT/OT convergence both makes that possible and is necessary for it to be possible. Not only is it no lon-ger enough to have a wise engineer with the mechanical equivalent of Spider Sense who can tell that something is wrong with a piece of equipment by listening to it or putting his hand on it, Walejeski said that such people no longer exist.

Instead, today’s workers look up the operating history of a piece of equipment and the readings it’s presently pro-ducing to see if any action needs to be taken.

“Tying [the historical] data sources with real-time in-formation, sensor-based information, just makes the deci-sion process that much better,” Walejeski said.

Of course, the workers aren’t making decisions by crunching the historical and real-time data themselves. For that, they need analytics.

Once the province of IT — which is why they origi-nally were called “business analytics” — analytics have not only moved into OT, they’ve spread to its far corners. Power companies not only can analyze historical data, they also can analyze data as their equipment is sending it in, and compare that analysis to previous analyses of his-torical data to see how their equipment is functioning in ways they never could before.

“In order to understand the patterns you have to look for [in the data being streamed], you have to analyze the historical data,” said Alyssa Farrell, manager of the global energy practice at SAS Institute Inc., a Cary, North Caro-lina-based developer of analytics software.

Streaming analytics has existed for a while — a com-mon example, Farrell said, is the analytics being performed on data that airplanes produce as they fly.

But, she said, it’s really taken off over the past decade, in part because that’s how long OT systems have had enough intelligence built into them to make streaming analytics possible.

In the power industry, Farrell said, streaming analytics, and the IT/OT convergence it makes possible, have taken off more recently, in part because the costs of various sen-sors had fallen to the point that installing lots of them was economically feasible, and in part because the American Recovery and Reinvestment Act offered grants for the in-stallation of some of them, such as synchrophasors.

The growth of distributed intermittent generation also has played a part, as power companies and grid operators need real-time information about it to keep their systems functioning smoothly.

“As soon as the clouds come over and the wind stops, they need to switch to a different kind of peaking plant or a different dis-tributed resource,” Farrell said.

Despite the wonders it prom-ises to produce, the IT/OT con-vergence is not without problems.

For one thing, it involves con-necting systems that, however similar they may be now, were once very different. After all, much OT had to function in extreme conditions, while IT’s backbone was computers in spe-cially designed rooms with highly monitored environments.

Additionally, OT is still mis-sion-critical, while much IT is not. A company’s power plant failing is much more seri-ous than a website glitch that prevents its customers from paying their bills online for a few hours.

“The OT … tends to be highly specialized, highly specific and in every case business critical, if not out and out safety and personnel critical,” said Steve Sarnecki, vice president for the federal and public sector of OSI-soft LLC, a San Leandro, California-based developer of operational-intelligence software.

As a result, Sarnecki said, there are times when IT and OT systems need to be separated, and the connections be-tween them must be designed to reflect that.

The connections between IT and OT systems also must reflect the fact that they are potential gateways for hackers interested not just in stealing the identities of electric-utility customers, but in attacking the country’s power grid.

“There’s a move for the utilities to monitor these inter-connects, so they can make sure they’re behaving as ex-pected,” Sarnecki said.

Additionally, the urge to keep operations technology isolated to protect it has been built into the DNA of pow-er companies for decades. But that’s changing, too.

For example, nuclear-power operators used to be against the idea of digital controls, Sarnecki said. “But in recent times, they’ve started to become more comfort-able [with them] and almost desirous of moving toward digital capabilities.”

Despite the wonders it promises to produce, the IT/OT convergence is not without problems.


» TECH FRONTIER

RESEARCH AND DEVELOPMENT that began decades ago on the next generation of nuclear energy reac-

tors is getting renewed attention from the public and pri-vate sectors.

These Generation IV reactors promise to generate a more efficient and economical form of base load power and, in some cases, even offer a chance for nuclear energy to be considered truly renewable: recycling its own waste to run and produce power.

“Companies are revisiting technologies that have been looked at since the 1950s and seeing them in a new light,” said Dr. John Kelly, deputy assistant secretary for nuclear reactor technologies in the Department of Energy’s Of-fice of Nuclear Energy.

Kelly, who is also the chair of the Generation IV In-ternational Forum, said growing concerns about climate change have helped fuel the interest in developing and funding nuclear energy innovation.

“Everybody’s getting it: there’s a connection between CO2 emissions and climate change,” he said. “There are a lot of people that have significant resources — private equity — that are very interested in saving the planet. When we talk to nuclear engineering students, they want to help save the planet. There’s a commitment from those in the older generation who have made a signifi-cant amount of money and the kids who want to get into the game as well.”

“We’re working on the licensing and engineering to get to the point where [Generation IV nuclear reactors] can be sold to utilities in 2020 or 2025. That’s when we think they’re going to be making the decision to retire their coal plants and we want to give them a nuclear op-tion,” said Kelly.

To that end, the government is pushing initiatives that would accelerate Generation IV technologies. Also, earlier this month, lawmakers introduced the Nuclear Energy Innovation Capabilities Act, which, among other provi-sions, would encourage technology transfers from govern-ment-run labs to ones in the private sector.

Here’s a look at the six types of Gen IV nuclear reactors being studied today:

• Very high temperature reactor: This type of reactor produces, as its name suggests, very high temperatures that far exceed any seen in the standard water-cooled reactors in use today. Furthermore, it produces elec-tricity more efficiently than current reactors, so less of the energy it produces goes to waste. It uses a graphite neutron moderator and a once-through uranium fuel cycle — meaning that the uranium is not recycled. It can employ a reactor that sits either in a pressure vessel where graphite blocks are stacked in a cylinder around it or in a bed of pebbles made of fuel. The con-cept dates back to 1947, and several are in operation in Japan, China, Germany and the U.K.

• Supercritical water-cooled reactor: This technology presents a significant upgrade over water-cooled reac-tors, operating at a higher pressure and temperature while using a once-through cycle. Furthermore, the water always remains in a fluid state. Also, this tech-nology can be implemented in incremental upgrades to existing water-cooled reactors — a notable differ-

On The Horizon? Next-generation Nuke ReactorsBY R. KRESS


» TECH FRONTIER

ence from all of the other Gen IV systems. And it has much improved thermal efficiency over water reactors — about 45% compared with the 33% ef-ficiency seen today.

• Molten salt reactor: There are two major classes of reactors employing molten salt. The first uses it as fuel. Unlike today’s standard reactors, the molten-salt-fueled reactor does not use a solid fuel rod. Instead, the fuel is dissolved in the molten salt and circulated around the reactor. A major benefit of this technology is that it removes the contaminants that would otherwise affect the operation of the reaction while it is running. However, it could face licensing challenges because the barriers found in a standard reactor are eliminated when the solid fuel is dis-solved in the salt.

The second type of molten salt reactor uses the technol-ogy as a means of cooling. In fact, the very high tem-perature reactor could use molten salt cooling to allow it to be smaller and more economical. “The nuclear fuel is very similar to that of a high temperature reactor,” explained Dr. Edward Arthur, of the Nuclear Engi-neering Department at the University of New Mexico. “The uranium in the reactor is encapsulated in graphite pebbles and spheres. Molten salt flows through chan-nels and provides the cooling for that reactor. The mol-ten salt coolant operates at low pressure, which allows for some very interesting safety enhancements while maintaining high-efficiency operation.”

Fast Reactors

The following three types of Gen IV technology are all known as “fast reactors.” All three are capable of being closed-fuel cycles — meaning that they can eliminate the bulk of radioactive nuclear waste by recycling it and using it as a power source.

• Sodium-cooled fast reactor: Dr. Arthur called the so-dium-cooled fast reactor the most mature among the Generation IV technologies. GE Hitachi’s PRISM technology employs a sodium-cooling mechanism and has already won grants from the DOE. GE Hi-tachi is awaiting news on its most recent submission to the DOE regarding Prism and whether it will be awarded up to $40 million in funding.

“The ironic thing is that the U.S. spent about $6 bil-lion developing the technology of the sodium-cooled fast reactor,” said Dr. Arthur. “So it’s just a matter of moving ahead and updating it for the 21st century and moving toward commercialization. The technical basis is there and has been demonstrated. It’s not a paper reactor.”

• Gas-cooled fast reactor: Much like its sodium-cooled counterpart, the gas-cooled fast reactor is a closed-fuel cycle that minimizes waste and long-term need for ura-nium resources. It employs the same reactor technology that’s seen in the very high temperature reactor. How-ever, this design uses helium as its coolant to transfer heat to a gas cycle that drives a turbine whose waste then drives a steam turbine. “The French were putting money into it,” Arthur said. “But honestly, I don’t be-lieve there’s much interest in it anymore.”

• Lead-cooled fast reactor: This technology sinks the nuclear core into molten lead to provide a low-pres-sure, thermodynamic cooling process. Like the other fast reactors, it uses a closed-fuel cycle to dial back on uranium enrichment and production of nuclear waste. This technology also features some safety enhance-ments given that lead is relatively chemically inert and is low-pressure. What’s more, lead is easily obtained and could be deployed in reactors on a large scale.

“The Russians were pushing it heavily because they had experience in lead-cooling technology,” Arthur said. In the U.S., Pennsylvania-based Westinghouse is putting its efforts behind the lead-cooled system in its bid to win DOE funding.

Reaching The Market

As Arthur sees it, the advanced nuclear reactors most likely to reach the market are those that employ sodium coolant fast technology and possibly very high tempera-ture reactors employing a molten salt coolant.

Although Kelly did not want to say which technolo-gies he supports for fear of prejudicing applications from the industry, he noted that the DOE program has largely focused on the sodium coolant fast reactor and the very high temperature reactor.

“Those are the two that we’re investing in the most. But we have people following the lead fast reactor, the molten salt reactor and the gas fast reactor. We have involvement in most of the systems,” Kelly said.


AN ELECTRIC-VEHICLE fast-charging services plat-form launched last winter by ABB Ltd. and Micro-

soft Corp. likely will be the first of many joint offerings by the two companies.

“There are all sorts of different initiatives where dif-ferent parts of ABB and different parts of Microsoft are working together,” said Rick Nicholson, the global head of product management and marketing for ABB’s enterprise product software group.

The first initiative to become public is aimed at strengthening ABB’s relationship with existing and po-tential customers of its charging stations, which include government agencies, power companies and retailers.

In the short term, ABB’s and Microsoft’s platform will make the server network that supports ABB’s EV charg-ing station more robust and more redundant, said Andy

Bartosh, who directs ABB’s EV charging infrastructure business in the United States. In the long term, Bartosh said, the platform will enable ABB, which is based in Zu-rich, Switzerland, to offer customers more in-depth ana-lytics capabilities.

Bartosh wouldn’t say what those capabilities might be, but they could include being able to predict anything from when a station needs a particular maintenance procedure to the amount of traffic a station is likely to see at specific dates and times or under specific conditions.

ABB and Microsoft have begun deploying the plat-form and will be finished by the end of the year, Bartosh said. ABB doesn’t disclose how many chargers it has de-ployed, he said.

The multiple collaborations between ABB and Micro-soft grew out of a longstanding relationship between the companies that goes up to the C-suite level.

ABB, which provides automation and power equipment, systems and software, is one of the largest users of Red-mond, Washington-based Microsoft’s Office 365 software.

The companies also share a view of how the ubiquitous high-powered computing made possible by cloud com-puting, mobile technology and Moore’s law is changing the business landscape.

“The uber-transformation that is going on here is a transition from a focus on selling a product to a focus on selling a service and an experience around that service,” said Sanjay Ravi, Microsoft’s worldwide managing direc-tor of discrete manufacturing. “In the past, you would have actually sold a fast-charging EV infrastructure. In the fu-ture, you’ll be selling services that this fast-charging EV infrastructure can enable.”

To enable itself to do that without embarking on a budget-busting technology-development spree, ABB is working with Microsoft on numerous fronts.

ABB’s enterprise software group, which provides en-terprise-asset-management software, workforce-manage-ment software, real-time monitoring and control systems, and industry-specific applications, is collaborating with Microsoft in three areas — cloud computing, analytics and mobility.

Although the EV charging platform is a good example of how ABB can use the cloud to make the kind of sweep-ing transition Ravi talked about, the company’s enterprise software group is working with Microsoft on something more basic — using Microsoft’s Azure cloud to provide its software to customers who prefer accessing the software that way to having it installed

ABB, Microsoft Join Forces on EV Stations, Other FrontsBY PETER KEY



» TECH FRONTIER

MICHIGAN’S CONSUMERS Energy has begun to col-lect its customers’ electricity usage data as well as

natural-gas consumption data via the same Itron Inc. smart meter. It is doing so through one of the few shared large-scale cellular networks in operation.

The effort is part of a larger $750-million modernization push in which the state’s largest utility has already installed more than 800,000 cellular-enabled smart meters.

“We are one of the first large utilities in the country to utilize the cellular solution,” said Dennis McKee, communi-cation director for the Smart Energy Program at Consum-ers, which provides service to a total of 6.6 million Michigan residents. “It provides us great coverage in our service terri-tory, which is a combination of extensive rural areas and a multitude of more densely populated urban areas.”

Cellular smart meters are expected to become more common as cellular service rates decline.

Consumers plans to install more than 1.1 million more of the smart meters, which are made by Liberty Lake, Wash-ington-based Itron Inc. The biggest smart meter company in North America, Itron has been pushing in this direction since acquiring SmartSynch, a cellular smart meter com-pany, for $100 million in early 2012. The deployment it’s doing for Consumers had been a SmartSynch account.

The meters use existing 4G cellular networks to transmit

daily readings, broken down hour-by-hour, to the utility, re-ducing the need for manual readings and the likelihood of estimated bills when meters can’t be accessed.

For customers who receive both gas and electric ser-vice, the company has now installed more than 60,000 gas meter modules, which transmit daily natural gas consumption readings to the electric meters for cellular upload to the utility. Consumers is planning to install 610,000 of the modules.

Having one device communicate with the utility helps keep things simple and more cost-effective, said Share-lynn Moore, Itron’s vice president of global marketing and public affairs.

“I think the trend is one network, many things,” she said. “It lowers the cost of network deployment.”

The meters receive gas readings through a radio frequen-cy transmission from the gas meter modules and upload both readings to Consumers through cellular networks run by Verizon and others, said Moore.

Utilities use a variety of networks to receive smart meter data, typically combinations of cellular transmissions, wired transmissions through the grid itself and transmissions through radio-frequency networks.

California’s Pacific Gas and Electric, for example, has deployed more than 9 million smart meters that collect daily gas readings and electricity readings every 15 min-utes, sending them to the utility through the company’s own wireless communication network. And Tennessee’s Memphis Light, Gas and Water is in the midst of a proj-ect to install smart meters to track all three services, which the utility says also have the potential to quickly detect outages, leaks and other problems.

In general, smart meters are most commonly deployed by those natural gas companies that also provide electric service — particularly in areas where regulators allow them to combine metering hardware for additional savings, ac-cording to Oracle Utilities.

Consumers plans to enable its smart meters to detect and report outages and let custom-

Consumers Energy Goes Cellular with Electric, Gas MetersBY STEVEN MELENDEZ



THE FUTURE OF utility-scale energy storage could soon be on display in the Pacific Northwest.

Three Washington state utilities are deploying a total of five cutting-edge battery storage systems that will be evaluated by the Pacific Northwest National Laboratory in Richland, Washington. Three of the systems were con-structed according to a set of standards designed to make utility-scale storage systems easier and cheaper to build, and two use a new type of battery system based on tech-nology developed at the lab.

The utilities received a total of $14.3 million from the state’s Clean Energy Fund for the energy-storage projects and had to put up an equal amount themselves.

“In all three cases, it really was a situation where they wanted to try out some new technologies that could be in-tegrated into their systems, but [the technologies] weren’t at the stage of maturity to be able to justify all of the costs” of the projects, said Tony Usibelli, director of the Wash-ington State Energy Office, which administers the Clean Energy Fund.

The utilities that received the funds are Bellevue-based Puget Sound Energy, Spokane-based Avista Corp. and the Snohomish County Public Utility District, which is headquartered in Everett.

The Puget Sound Energy and Snohomish PUD proj-ects use the Modular Energy Storage Architecture — or

MESA, Vanadium Batteries Put to the Test in Pacific NorthwestBY PETER KEY


» TECH FRONTIER

MESA — set of specifications and standards, which were developed by a group of utilities and their suppliers.

Puget Sound Energy, the Snohomish PUD, the Pa-cific Northwest National Laboratory and UniEnergy Technologies LLC, which is making batteries based on technology it licensed from the lab, are among the group’s founding members. Contributing members in-clude Juno Beach, Florida-based NextEra Energy, Char-lotte, North Carolina-based Duke Energy Corp. and Bethesda, Maryland-based Lockheed Martin Corp., an indication that the group has attracted some pretty big movers and shakers in the electric power industry and its supply chain.

MESA is meant to solve a problem that often plagues early deployments of a technology, which is that each development is treated uniquely, increasing the time and effort required.

“When we first got into energy storage, there was a lot of non-recurring engineering going on, so when each sys-tem was designed, we were redesigning how components connected and communicated with each other,” said Jason Zykowski, the Snohomish PUD’s manager of substation engineering.

“MESA creates a model for power conversion systems, batteries and power control systems, so [the way they con-nect and communicate] doesn’t have to be recreated on every project,” Zykowski said.

The Snohomish PUD is finishing deploying the second phase of one project and then will turn its attention to another. The utility deployed a 1-MW lithium-ion battery at a substation last year and is just finishing deploying a second at the same substation. It plans to use the batteries to integrate renewable generation sources into its system and to do peak shifting.

“They’ll demonstrate the MESA standards — that was one of the goals of this first system — and allow us to become familiar with energy storage and how it’s useful in our system,” Zykowski said.

The second Snohomish PUD project will feature a 2.2-MW vanadium-flow battery system made by Mukilteo, Washington-based UniEnergy Technologies. That project will enable the Snohomish PUD to evaluate the MESA standard with a vanadium-flow battery and compare the performance of a vanadium-flow battery to the perfor-mance of a lithium-ion battery.

Avista has been testing a 1-MW/3.2-MWh battery storage system using UniEnergy Technologies’ vanadium-

flow batteries at Schweitzer Engineering Laboratories Inc. in Pullman, Washington, since April. The system stores power generated by renewable sources and distrib-utes it when it’s needed.

Puget Sound Energy’s project is next to a substation in Glacier, a small town in the foothills of Baker Mountain that experiences frequent power outages because it’s in the midst of a lot of very large trees. The utility is putting in a 2-MW/4.4-MWh lithium-ion battery system that will use controller software developed by a Seattle company, 1EnergySystems Inc., and is designed according to the MESA set of standards.

Puget Sound Energy expects to have the system fully operational by spring. The system will use power from the utility’s grid to charge itself. The utility plans to use the system to reduce demand peaks and to provide power to Glacier during outages. Ray Lane, a Puget Sound Energy spokesman, said the system would be able to power the town for about eight hours.

The Washington State Energy Office contracted the Pacific Northwest National Laboratory to do an extensive technical and economic analysis of the projects, Usibelli said. Among other things, the lab will evaluate if the stor-age technology can be used to better integrate intermit-tent generation sources, such as wind and solar power, and to improve utility-system operations.

Utility-scale storage is expected to be big business in the coming decade. According to a forecast from Navigant Research, the market will exceed $2.5 billion in revenue by 2023.

MESA is meant to solve a problem that often plagues early deployments of a technology, which is that each development is treated uniquely, increasing the time and effort required.


A RANGE OF ENERGY storage options is becoming in-creasingly available to respond to the growing share

of renewables on the grid. But batteries alone may not ad-dress all of the potential needs for power reliability — par-ticularly as peak demand calls for power often at the times that renewables are least able to respond.

Enter Hydrostor, a Canadian startup that has launched the world’s first underwater compressed-air energy-stor-age solution.

Hydrostor recently brought online a grid-connected, 1-MW system using inflatable balloons positioned 180 feet below the surface of Toronto’s Lake Ontario. The system — capable of holding enough energy to power 330 homes — will be operated by Toronto Hydro. The utility intends to use the Hydrostor system to store electricity during off-peak hours and then tap into it as demand grows.

“We founded the company five years ago looking at small-pump hydro and realized that it’s tough to make those economics work,” Hydrostor CEO Curtis VanWal-leghem said of his company’s genesis. “So rather than pump water to an elevation, why not pump air underwater?”

The material used for the underwater balloons is the same used to raise sunken ships from the ocean floor.

VanWalleghem says it’s easiest to understand Hydros-tor’s technology by realizing that it acts much like an un-derwater air battery. Except, instead of storing energy in the form of a chemical reaction the way that a traditional bat-tery would, it uses compressed air. When power is needed, a worker opens a valve on shore and the air rushes up to spin a turbine. VanWalleghem says there are hundreds of thousands of places in the world that could effectively sup-port such a system.

“Compressed air is a pretty well-known technology,” VanWalleghem said, referencing the McIntosh Power Plant in Alabama by way of example. The 110-MW facil-ity has been operational for nearly two decades. “But the challenge with [compressed-air energy storage] is where do you put the air? All that our company has done is come up with a way of storing it underwater. That’s really where our innovation comes in.”

By reimagining compressed-air energy storage, VanWal-leghem says that Hydrostor offers the most cost-effective energy storage solution for longer duration load-shifting applications — if, of course, the city implementing it sits on a large lake or ocean. In addition to its Toronto system, Hy-drostor has another on the way in Aruba. Currently, there are no applications in the works for Hydrostor in land-locked cities or in the U.S.

“It’s tough to compete on the mainland with natural gas — especially the way the prices are right now in the U.S.,” VanWalleghem said. “[Our growth strategy] most-ly has to do with the economics and finding the lowest hanging fruit.”

Growing cities with a shoreline that are in need of back-up power for peaking capacity remain the most attractive markets for Hydrostor, according to VanWalleghem. For now, he sees providing backup power for water treatment plants as the most viable application.

“[Water treatment plants] are all on the water and they have the technology to pull the water in already. Because most of the plants pull in lake or ocean water and service it before providing it to the community, they already have the rights and easements needed

Storing Energy in Underwater BalloonsBY R. KRESS



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HOLISTIC PLANNING FOR distributed energy re-sources is a term popping up more and more in dis-

cussions of energy transition, where it runs the risk of be-coming one of those industry buzzwords that people use without clearly defining what they mean.

In the broadest terms, holistic processes provide a com-prehensive approach to an issue or problem. In the specific context of distributed resources, the term is seen as an al-ternative to the centralized, top-down planning processes that historically have been the foundation of grid reliabil-ity, safety and affordability.

Still, by their very nature, the suite of fast-changing and complementary technologies known as distributed energy resources — ranging from solar and storage to demand response, electric vehicles and energy efficiency — requires an even more calibrated and sophisticated approach. Beyond their dynamic nature, distributed technologies move the focus of resource decision-mak-ing from utilities to customers.

That is, customers adopt technologies on their side of the meter, an opaque interface that can leave utilities un-aware of potential effects until they have to mitigate issues of reliability or safety at the distribution system level.

In this view, distributed resources are potentially dis-ruptive, unpredictable and problematic. The Solar Electric Power Association, through its research and advisory work with utilities, is seeing the beginnings of a shift in focus, as noted in our recent report in partnership with Black & Veatch, “Planning the Distributed Energy Future.” Utili-ties are looking at ways to actively channel customer inter-est in distributed energy technologies to choices that also result in an electric grid that functions more efficiently.

The kind of holistic planning we envision goes a step further toward aligning customer solutions with grid so-lutions, while providing a critical driver for utilities to de-velop sustainable business models. Here are four guiding principles for utilities:

Know Your System: Understand the value distributed resources represent for your distribution system.

If a utility doesn’t have visibility — that is, doesn’t know what’s happening on its distribution system — it may not have a full understanding of the resulting challenges distributed resource integration may raise. In particular, determining the hosting capacity of individual circuits, or how much load they can carry, will be critical.

Expanded visibility, with robust analysis, can help iden-tify grid locations where capacity for distributed resources both exists and can provide optimal benefits for different stakeholder groups.

Simply put, if a utility doesn’t have extensive informa-tion about its distribution system, it can’t identify where the challenges and opportunities might be. Once a utility has isolated or identified areas that have potential for dis-tributed energy deployment, the next questions are which of its customers to involve and what technologies are most likely to engage them.

Know Your Technologies: Consider integrating tech-nologies and programs.

Flexibly deploying distributed energy technologies can maximize overall system performance. Instead of a program focused on a single technology, an integrated framework employing a portfolio of distributed resources can provide a broader range of benefits to the distribution system. For example, Southern California Edison has a Preferred Re-sources Portfolio in which different distributed resources are combined to curb future energy and capacity needs.

Complementary distributed technologies can also be used to mitigate the potential risks of high renewable energy penetration — solar paired with storage enhances dispatchability. Finally, pairings can be designed to create a more compelling business case for customer adoption than a single technology on its own. In Minnesota, for example, the Steele-Waseca Cooperative Electric utility

A New Vision for Distributed Energy Resource PlanningBY JULIA HAMM


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has leveraged a community solar project to build customer enrollment in a demand response program.

Know Your Customers: Proactively engage your cus-tomers to optimize distributed resource deployment.

Of course, just because something is technically and economically possible that doesn’t guarantee customer adoption. To predict success, a utility’s system planning ef-forts should fully integrate customers’ perspectives through outreach and customer engagement initiatives. The benefit here is that instead of worrying about thousands of deci-sion points, utility managers will be able to build models and tailor products and services based on expectations of what will appeal to particular market segments.

Utilities also can use predictive analytics and forecast-ing to understand the nexus between customer behavior and grid effects. One example would be augmenting cus-tomer profiles with data on how individuals may respond to particular distributed technologies.

Such research can help identify the distributed resources that are technically and economically feasible within a par-ticular service territory based on customer interest and de-mand. The Sacramento Municipal Utility District (SMUD) worked with Black & Veatch to develop locational esti-mates about customer adoption of distributed resources and model effects on the bulk and distribution systems.

Know Your Market: Guide distributed resource de-ployment through targeted marketing, incentives and programs.

Working from such predictions, utilities can estimate what actual program effects are going to be and make smart investments to find solutions for certain problems. At best they can develop well-tailored programs that cus-tomers might actually like, while also targeting incentives and programs for customers in locations that will optimize system benefits.

Across the country we are seeing examples of utilities and regulators adopting pieces of this approach, but not yet integrating fully holistic strategies. The reticence to venture into the unknown is understandable. But, instead of distributed resource planning being some-thing utilities do only when legislators or regulators say they have to, a holistic, integrated approach to the issue could become a powerful tool for transition at all levels of the system.

We have only begun to tap the potential of these new technologies. They will continue to evolve, as will custom-er expectations, producing ever-widening opportunities for growth and innovation.

Julia Hamm is SEPA’s president and CEO. She can be reached at [email protected].


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THE VISION FOR INNOVATION in today’s electric util-ity industry was struck more than 100 years ago.

Thomas Edison, Nikola Tesla, Elihu Thomson, Frank Sprague and others defined turn-of-the-20th-century in-novation in their invention, research, development and commercialization of technologies that gave birth to the electric utility industry of today. And they didn’t confine their sights to generation, transmission and distribution, the three pillars of the electric utility industry.

These innovators also set their sights on electric ve-hicles, solar energy, off-grid homes supported by battery storage, and hydroelectric power. Here are some examples:

In 1912, Edison unveiled his experimental “Twen-tieth Century Suburban Residence” in West Orange, New Jersey. Designed to showcase his batteries, the energy-self-sufficient house was powered by a genera-tor that charged a bank of 27 cells in the basement, and featured luxuries like air heating and cooling units, a washing machine, an electric cooking range, and light bulbs throughout the house.

In 1914, Edison collaborated with Henry Ford to de-sign a $900 electric vehicle with a range of 100 miles. It never became commercially popular, partly due to the large size of the battery.

Edison was also an early proponent of renewable en-ergies. In 1931, not long before he died, Edison told Henry Ford and Harvey Firestone: “I’d put my money on the sun and solar energy. What a source of power! I hope we don’t have to wait until oil and coal run out before we tackle that.”

Tesla was instrumental in advancing turbine science, the installation of the first hydroelectric power station at Niagara Falls and, most importantly, the perfection of his alternating current system.

So, although we tend to think of such innovations as something quite new, there are numerous examples that owe their beginnings to innovative minds working in the industry nearly 100 years ago.

The electric utility industry has spent the years since Edison’s time perfecting transmission and distribution, and building the architecture and infrastructure necessary to generate, transmit and distribute power reliably and safely to customers. And now, in part due to the pressures and challenges faced by utilities today, the industry is undergoing another significant transformation, sup-ported by rapid technological innovation.

Over the past few decades, utilities have begun to face mounting pressure, includ-ing demands of the changing customer relationship, demands around big data, environmental and financial demands, de-mands around the types of generation to be used to create electricity going forward, and demands caused by customer-owned resources at the grid’s edge. As a result, utilities are increasingly looking to next-generation, innovative technologies to assist, particu-larly in those areas that aid utilities in providing new value in the ways in which they interact with their customers and strategically operate their infrastructures.

Looking back, it was a lack of strategic infrastructure that kept Edison’s and Tesla’s “edge of grid” inventions — electric vehicles, battery technology, distributed gen-eration and smart devices — from gaining traction in the late 19th and early 20th centuries. That basic infra-structure now exists, but it is undergoing transformative changes in order to handle all of the new and complex demands upon it.

Back to the Future: Yesterday’s Industry Innovations Have Come Full CircleBY RODGER SMITH


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Innovation Will Lead Grid Transformation

Flexibility is the key to that transformation. Managing the 21st-century electricity grid will require the increased use of technology for real-time operation and optimiza-tion of a new grid platform — one that incorporates new distributed processes at the edge of the grid. These distrib-uted processes, from demand response, electric vehicles, and dispatchable energy storage to microgeneration and islandable microgrids, will need to be managed, modeled and optimized in real time as supply and demand becomes an increasingly complex equation.

How will this play out? Just as it did a century ago, the electric utility industry will continue to transform through innovation. Here are just a few areas in which I think in-novation will play an important role going forward.

As the distribution utility continues to evolve, it is be-coming a plug-and-play platform, managing a complex, multi-faceted web of energy transactions — a utility in-ternet, if you will, that includes the use of social media and handheld devices to make the utility infrastructure easier for the consumer to use. Taking this even further, I believe we will soon begin to see a consumer-driven, crowd-sourced transactive energy market, rather than one in which all the energy assets are owned by the utility.

The smart meter is another area in which innovation will continue to occur. There will come a time, I believe in the near future, when the meter will become a grid tool that can collect and aggregate data from sensors and smart

appliances within the home or business and dispatch it to the appropriate parties. This data will enable the utility to identify usage patterns within the home or business and predict and suggest maintenance schedules for those ap-pliances and other serviceable items. The meter will also be the conduit through which software upgrades are pushed to those same sensors and smart appliances.

Just as Edison believed, increasingly affordable and in-novative battery storage will play a considerable role in the distributed grid. Economical, efficient, reliable microstor-age will allow distributed energy resources to be more cost-effective and will provide increased reliability to the grid as well as efficiency and flexibility of use by both the utility and the consumer.

Embracing Change Within the Utility

By embracing change through innovation, today’s utili-ty is in a prime position to remain in the driver’s seat of the new, distributed grid. Affordable, reliable, clean electricity will remain of paramount importance to consumers. As the owner and manager of the plug-and-play distribution platform described earlier, the utility is well placed to be the key interface between distributed supply and distrib-uted consumption.

In order to remain in the driver’s seat, though, it will be necessary to innovate. Internally, utilities must exam-ine existing business processes for ways to provide services beyond the meter that utility customers are looking else-where to obtain. Externally, the utility must be the cata-lyst to bring regulators, suppliers, lawmakers and financial institutions together for a common vision of the utility industry. The commonly espoused idea that technology is 10 years ahead of utilities and utilities are 10 years ahead of the regulator can no longer apply to this industry. All of the key stakeholders must be on the same page for this industry to innovate the way it must innovate to take care of its customers.

The seeds for today’s continued innovation were plant-ed nearly 100 years ago. In the words of Nikola Tesla: “The scientific man does not aim at an immediate result. He does not expect that his advanced ideas will be readily taken up. His work is like that of the planter — for the future. His duty is to lay the foundation for those who are to come, and point the way.” Rodger Smith is senior VP and general manager of Oracle Utilities.

I’d put my money on the sun and solar energy. What a source of power! I hope we don’t have to wait until oil and coal run out before we tackle that.

— Thomas Edison


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THE TRANSITION TO a smarter, cleaner, more cus-tomer-centric electricity system has been accompa-

nied by a lot of conflict. Examples abound, from recent fixed-charge skirmishes in Wisconsin and now Indiana, to FirstEnergy’s attack on competition and clean air in Ohio, to Nevada’s recent steps to rewrite the terms of existing net metering contracts.

These conflicts are a predictable result of the way we regulate utilities. The many challenges that are forcing electric utilities to reinvent themselves — rapidly evolving technologies, increasing competition, changing customer needs and stricter environmental controls, among others — require a new style of regulation. Adding incentives to standard regulation, as some states are considering, is a good start, but more fundamental reform will ultimately be needed. It’s not too soon to start.

Many argue that utilities must evolve, but few seem to have a clear idea of what business models utilities are evolving toward. Given that uncertainty, the best course is to adopt a style of regulation that gives utilities some running room. Modern regulation must cede tactical deci-sions to utilities while pointing them to strategic priorities. Regulation should empower utilities to make changes and offer them a financial upside for innovation, while giving them the ability to remain financially secure.

New York Public Service Commissioner Peter Brad-ford famously remarked that “all regulation is incentive regulation.” By that, Bradford meant that every system of economic regulation promotes certain behaviors in regu-lated firms. To regulators, these behaviors can be good or bad, helpful or counterproductive. In many ways, the job of a regulator is not to determine whether to provide in-centives to a utility, but rather which behaviors to incen-tivize by the choice of regulatory systems.

Today’s predominant regulatory approach dates mostly from the 1950s and 1960s, when the task of utility regu-lation was much simpler. Utility average costs often fell

when a new utility power plant was built, and society was mostly unaware of the environmental impact of energy production. Regulators’ main duties were to enable utility growth, facilitate widespread access to electricity and pass on cost savings to consumers. Ahh, the good old days.

It turns out that incentives inherent in traditional cost-of-service (COS) regulation don’t jibe well with the goals that society now has for electric utilities. Three familiar examples illustrate the point. Basing utility revenues on investment levels might sound fair, but it may also induce a utility to over-invest in physical plant to grow earnings. Allowing utilities to recover costs in periodic rate cases can devolve into cost-plus thinking and reinforce disincentives for firm efficiency. Finally, basing a utility’s revenues on electricity sales collides directly with society’s goal of bet-ter end-use energy efficiency.

There are many ways to say it, but basically, COS regu-lation is not compensating utilities for what society wants them to achieve.

For Better Outcomes, Let’s Reward Utilities for PerformanceBY RON BINZ AND DAN MULLEN


I NDUSTRY VO ICES

What are some alternatives? Revenue decoupling breaks the link between commodity sales and utility rev-enues, and has been tacked onto traditional COS regula-tion in some states. Targeted incentives can help combat some other undesirable outcomes of COS regulation.

But neither of those modifications cures the most im-portant, inherent biases created by COS regulation. To do that, regulation must provide utilities with an adequate revenue stream without explicitly tying those revenues to investment. Instead, revenues should be tied to the lev-el of service provided by a utility. And rather than drive specific investment decisions, regulation should turn over decisions about how best to serve customers to the utility, while ensuring that the utility, if it acts smartly, will earn a fair rate of return (ROR).

One way of implementing this much-needed reform would be to adopt a revenue cap style of incentive regula-tion. There are three key features of this approach:

1. The plan would operate for a meaningfully long peri-od of time, such as five to eight years. A standard rate case would set the initial revenue cap, which would then be adjusted in each subsequent year according to an external index. A good starting point for the rate of increase in annual revenues might be the rate of inflation, plus a factor for the change in number of customers. Actual revenues would be trued up or down annually to the revenue cap.

2. A utility could earn additional revenues for superior performance on a set of metrics approved by regu-lators. Incentives could be oneway (upside only) or two-way (upside and downside), or a mix depending on the specific goal. The level of incentives would be significant relative to earnings.

3. In response to extraordinary unanticipated invest-ment needs (e.g., storm repair or new environmental requirements), regulators could adjust the revenue cap during the cap period.

Variations exist. For example, earnings above (or below) a specified level could be split with customers, but this would limit the utility’s financial upside and therefore dull its incentive (and perhaps its performance). While a util-ity’s earned rate of return should be monitored, it wouldn’t be used to set allowed revenue levels.

In brief, this approach gives utilities a trajectory of rev-enue levels sufficient to deliver on a business plan that

responds to a state’s energy goals. The utility must then manage to that level of revenues. Investment decisions will be made without the bias of rate of return on rate base; increased efficiency redounds to the benefit of sharehold-ers. Revenues are decoupled from sales; a utility could not earn more simply by selling more electricity. Finally, an overlay of performance measures would directly promote desired utility behaviors and allow exceptional revenues when warranted.

To be fair, this approach raises important questions. Will utilities respond to the opportunity to increase earn-ings with better performance? Will consumers feel they’re getting enough value for what the utilities are being paid? Will Wall Street be comfortable with utility performance meaningfully affecting revenues, up or down?

These questions can and should be addressed. But given the challenges facing today’s utilities — and the inability of traditional regulation to meet them — state electric-ity regulation should move to revenue cap regulation with performance incentives, and the sooner the better.

Ron Binz is the principal of Denver-based Public Policy Consulting and former chairman of the Colorado Public Utilities Commission. Dan Mullen is a writer and consultant specializing in clean energy issues. Binz and Mullen joined Rich Sedano and Denise Furey in writing the report, “Practicing Risk-Aware Electricity Regulation: What Every State Regulator Needs to Know,” for which Binz was lead author.

Many argue that utilities must evolve, but few seem to have a clear idea of what business models utilities are evolving toward.


Utilities could use the app to increase their ability to determine which trees near their power lines need to be trimmed without hav-ing to send personnel out to in-spect them. The app also could use predictive analytics based on the types of trees and how much rainfall an area gets to determine

when utilities will need to trim trees in the future.Space-Time Insight can provide its software to cus-

tomers from the cloud, by putting it on the customers’ premises, or both. It also can provide customers with a de-velopment platform for building their own apps.

Ehrlich said the company doesn’t know when its soft-ware for the Rift will be available because, despite its work on prototypes, it doesn’t know what its first apps will be.

“A lot would depend on when the first customer is ready to go because we would want to work with them to make sure we have the user interface right and the func-tionality they need,” he said. “It’s always hard to build software in a vacuum. It’s very important to have a cus-tomer to work with, at least initially, who could give you the specific use cases.”

Continued from page 34.

going to take for utilities to be-gin using the right data to create actionable intelligence, Hobbs says.

There will be an increasing need for data scientists with backgrounds in mathematics who can help create useful intel-

ligence and build useable models, he says.Utilities are also going to have to change the way they

interact with customers amid the rise of “prosumers” who are sometimes consuming electricity and at other times providing it, he says.

Renewables will lead to more customers with generat-ing capacity they will want to sell to the grid or to other customers. Electric cars will even have available power to sell to utilities if need be, he says.

Hobbs noted that at the moment, there isn’t an active market in which consumers can sell to each other, given distribution constraints, but that will need to change.

Not all data is created equal

Identifying data that’s truly valuable and funneling it into a decision tool that yields actionable information to squeeze the most efficiency out of the grid is a huge chal-lenge, Hobbs says. “The biggest myth is all Big Data is useful.”

Hobbs explained that at the moment, utilities are over-whelmed with data, and just storing everything without knowing what’s useful could lead to data storage problems. The utility industry is behind other sectors in how it uses analytics and has to rely on third-party vendors. Utilities will eventually start doing more in-house analytics, but that could take four or five more years, he says.

There is going to be a long period of data collection and testing before the industry really knows what’s useful and worth paying attention to, he says.

The low-hanging fruit of what is useful is machine per-formance data, and data to help with voltage management will also yield payoffs, Hobbs says. But he notes that the total set of data what will be useful and that which should be ignored remains to be sussed out.


est failure rates.“Metals are prone to corro-

sion,” she said, adding, “when it comes to replacing pipelines, we have a calculation we go through and overlay that with a neigh-borhood map for each segment of the pipe.”

She said her company uses the standards set by the Pipeline and Hazardous Materials Safety Administration, a division of the U.S. Department of Transportation. It’s what Miers calls an analog approach to pipeline manage-ment, in contrast to the more systematic approach taken by the GE-Accenture partnership.

“Some operators have a variety of databases, which they update by hand,” he said.

With Intelligent Pipeline Solution, pipeline opera-tors can monitor their entire system in near real-time and make decisions based on current information.

Intelligent Pipeline Solution integrates data from a number of areas including the National Oceanic Atmo-spheric Association and the U.S. Geological Survey. Other data sources include inline inspections, pipeline attributes,



to use that waterway,” VanWal-leghem said.

In terms of the environmen-tal impact of bringing energy infrastructure underwater, Van-Walleghem says his company is determined to be a net positive in its applications in Toronto and Aruba.

In Aruba, where protecting the island nation’s marine wildlife is vital, Hydrostor installed fish habitats along with its system’s ballast.

“If we’re going to do something about climate change and move our grids to 100% renewables, then there needs to be a lot of storage added,” VanWalleghem said. “We’ll need a whole suite of potential solutions. Batter-ies have a great application for homes and vehicles, but they’re nowhere near as cost-effective as our solution if you’re near a coast.”


risk scores, planned assessments, leak histories, emergency valve locations, and precipitation and fault lines.

The cloud-based software features a smart dashboard for enterprise-level management, predictive risk monitor-ing tools, automated event alerts, and a geospatial visual-ization tool.

Columbia Pipeline Group in Houston, Texas has signed on as Intelligent Pipeline Solution’s first custom-er. A spokesman for the company said his company was pleased with how the product is developing thus far.

CPG is located within the Marcellus and Utica shale areas and operates 15,000 miles of interstate natural gas pipelines.

on their premises.In the analytics area, ABB’s

enterprise software group is standardizing its analytics and business-intelligence offerings on Microsoft’s tools, such as Microsoft Power BI, which en-ables users to create personal-

ized reports and dashboards using natural language and drag-and-drop gestures.

In mobility, ABB is making sure its apps can run on Microsoft’s Surface tablet computers, which, while they haven’t been popular with consumers, are widely used by companies whose computers run on Microsoft’s Windows operating system.

Nicholson, who heads product management and mar-keting for ABB’s enterprise product software group, said the company’s work with Microsoft not only should help it keep its existing customers happy, but also could help it extend its customer base.

For example, he said, a customer that’s been treating ABB’s software as a capital expense might want to treat it as an operating-and-maintenance expense. By helping the customer move the software from its computers to Mi-crosoft’s Azure cloud, ABB can enable the customer to do just that.

Making its software cloud-based also could enable ABB to land some smaller customers that can’t afford to buy its software and the servers to house it.

“It could open up another segment of the market in which we haven’t had a large presence in the past,” Nicholson said.


ers track their day-to-day usage online, the company said. The hour-by-hour data collected by the smart meters may also enable new rate options letting custom-ers buy cheaper power at off-peak times, McKee said.

The overall program is expect-ed to deliver a total $1.9 billion benefit to consumers, the company estimated in regulatory filings, he said.

The utility’s deal with Itron includes a 20-year mainte-nance agreement — though much of that maintenance will be in the form of automatic, over-the-air firmware updates similar to those that cellphones receive, said Moore.

Residential customers don’t have to be home to have the new meters installed, the company said in a statement, though they’ll be given about 30 days’ notice before the me-ters are installed and can schedule an appointment if they wish. Should they wish to opt out of using smart meters altogether — something some utility customers have done amid privacy concerns — they can pay a one-time fee of $69.39 and a $9.72 monthly meter reading charge, the company said.



» FINAL TAKE

U.S. Firms Ready to Assist Japan in Electric Market ReformsBY ALLEN TAYLOR

JAPAN’S MOVE TO OPEN its electric energy sector to new entrants presents a ripe business opportunity

for U.S. consultancies and other firms and organizations wanting to help it make the transition.

Once it’s complete, Japan’s will be the largest retail elec-tricity market open to competition in the world.

The switch is scheduled to take place on April 1 for electric retail markets and two years later for the wholesale and gas markets.

As part of the transformation, power companies will spin off their power transmission and distribution operations into separate units. At the moment, 10 regional utilities handle all aspects of electricity operations within specified regions, from generation to transmission and distribution.

The Japanese government began pushing for the over-haul after the 2011 nuclear crisis at the Fukushima No. 1 plant exposed vulnerabilities in the grid, with shortages and higher electricity prices.

Ross Malme, a partner at Skipping Stone, an energy consultancy with offices in Atlanta and elsewhere in the U.S., said the opportunity presented by the makeover has grabbed a lot of people’s attention.

“There are close to 800 (electric power) retailers in Ja-pan,” he said. “Not all of those will make it, due to con-solidation and so forth.” Still, that’s 800 companies that have signaled their intent to enter the market. There are no more than a couple of hundred companies vying for customers in the few U.S. markets where electric power competition exists. Put another way, there are 30 million electricity meters in the U.S. open for retail competition; the Japanese market is going to be three times larger.

Skipping Stone is one of a number of U.S.-based com-panies that are involved in helping Japan make the transi-tion. Here’s its story, followed by those of two others.

Skipping Stone

There’s nothing marginal about the role Skipping Stone is playing in Japan. It’s helping Tokyo Electric Power Co. (TEPCO), Japan’s largest electric utility, to manage what’s called the Open Innovation Program (OIP), a clearing-house for receiving applications to enter Japan’s electric energy markets.

Skipping Stone’s relationship with TEPCO began when a representative of TEPCO downloaded a white paper from Skipping Stone’s Demand Response Library, a free depository of articles, white papers and other energy-related reports. Malme called the company to follow up. That’s when TEPCO began talking with Malme about its role in the transformation.

“I was humbled they’d consider us,” he said. “[But] we know something about customer choice. We’re very good at understanding markets.”

Skipping Stone did an analysis of the Japanese energy market and determined that the Ministry of Economy, Trade, and Industry (METI) — the equivalent of a con-glomeration of FERC, DOE, NERC and state PUCs in the U.S. — was ill-equipped to regulate innovation.

“We needed to bring an innovative model to Japan,” he said. “That’s where the OIP started.”

Malme and his staff also realized international play-ers would be important in addressing Japan’s energy con-


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cerns, so they put together some profiles of companies they thought could help and contacted them. As a result, several U.S. companies are planning to enter the Japanese market, and some of the Japanese companies involved are taking a reciprocal interest in U.S. markets.

“The competition has already begun for larger custom-ers,” Malme said.

Green Charge Networks

Itochu Corp. is hoping for some of that business.Hiroaki Murase is the manager of the lithium-ion bat-

tery business unit at Itochu, an international diversified business network based in Japan. Three years ago, while attending an industry conference, he met the owner of Green Charge Networks, a California-based company that specializes in energy storage systems.

“We thought we could help supply the competitive hard-ware in Asia,” Murase said. So Itochu acquired a minority stake in Green Charge Networks and took on the role of marketing the company’s products to Asian markets.

Naturally, Murase believes the Green Charge Networks solution has a lot of potential.

“The system decides the best way to charge and dis-charge electricity based on local information,” he said. That includes weather forecasts as well as information re-

lated to individual energy usage. “The software itself has a strong point-on-point local use as well as aggregated use, and they’ve proved it works perfectly in U.S. markets.”

The Japanese electric system includes some smart grid technology, but it’s still primarily traditional. As the gov-ernment works to upgrade everything, Murase said, smart-home energy management systems designed to optimize electricity usage will become more commonplace.

Battery storage, in other words, will have a big role to play in the new Japanese electricity market.

OpenADR Alliance

When you enjoy the position of being the only global standard, it seems only natural that you’ll be called upon to consult with new markets. That’s how the OpenADR Alliance, based in California, got involved in Japan’s move to a competitive market.

ADR is an acronym that stands for Automated De-mand Response. The mission of the alliance is to foster the development and adoption of demand response standards worldwide.

Barry Haaser, managing director of OpenADR Al-liance, said that, after testing OpenADR for several months, “the Japanese government decided it would be wise to adopt it as a national standard and use it as a part of their grid framework.”

The work has kept things busy at the alliance.“We provide as much support as possible to facilitate

the process,” Haaser said. “We’ve expanded our capabili-ties to add a lab for testing and certifying products in order to expedite the process. We also help facilitate meetings and discussions on various technical issues that come up from time to time.”

About one-third of OpenADR Alliance’s membership is in Japan, and most of those companies exclusively serve the Japanese market, Haaser said.

SAFETY. QUALITY. RELIABILITY.

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