Towards a Smarter Grid


Dominion Virginia Power is using big data to increase the reliability of its electric distribution network. The result: Fewer disruptions and shorter outages for customers.

by James A. Bacon

One day earlier this month, 10,000 people living in Fairfax County lost their electric power around 7:30 a.m. Thanks to sensors and devices that Dominion Virginia Power had installed in its electric distribution system, company operators were able to quickly identify and isolate the problem. Fifteen minutes later, they had restored service to 9,000 residents; within half an hour, electric power was back online for everyone.

If you’re a Dominion customer and it seems as if you’re suffering fewer and shorter electrical outages, it’s not your imagination. Harnessing data to target maintenance spending with better precision, the power company has made a concerted effort over the past decade to improve the reliability of its electric service. Since 2008, Dominion’s 2.5 million customers have experienced a 26% decline in minutes lost to routine service disruptions (excluding major storms) when calculated on a three-year rolling average.

“We’re data driven. We’re a six-sigma company,” says Steven Chafin, director of reliability. Dominion, he says, has evolved from a company employing rough industry rules of thumb to one that collects data across the distribution system to drive continuous improvement.

Average customer minutes without electric service, excluding major storms, three-year rolling average

System Average Interruption Duration Index (SAIDI): three-year rolling average of annual customer minutes without electric service, excluding major storms.

Comparing reliability performance to that of other power companies is difficult because each utility contends with different terrain, weather and settlement patterns. Dominion benchmarks against itself, tracking the performance of 35,000 miles of overhead electric lines, 22,000 miles of underground lines and thousands of miles of high-capacity transmission lines. The numbers exclude major storm events, which are so random and are of such a magnitude as to obscure trends in routine operations. Five different events since 1998 — the Christmas Eve ice storm, Hurricane Dennis, Hurricane Isabel, Hurricane Irene and the Derecho wind storm — caused massive outages that took eight to fifteen days to fully restore.

A 2015 J.D.Power survey of electric utility customers found that the quality and reliability of electric power is a major factor influencing customer satisfaction nationally. Dominion scored a customer satisfaction ranking of 684, above average for large utilities and an improvement from 661 in 2013.

The heart of Dominion’s reliability initiative is a portfolio of more than a dozen programs ranging from tree-and-brush clearance to the upgrading of neighborhood transformers. “We adjust our investment in these programs annually,” says Chafin. The company allocates capital to programs that offer the greatest bang for the buck.

In 2015 more than a quarter of Dominion’s reliability spending was dedicated to clearing trees and brush, the greatest source of downed power lines, Chafin says. The company once hewed to a regular, three-year cycle for pruning vegetation near overhead lines. It was a reasonable rule of thumb, but analysis of the data showed that tree-related outages could be improved — some places need trimming more frequently, others less often, depending upon how fast the trees grow and the voltage of the line, among other factors. (Higher-power lines increase the chances of electricity arcing from the line to a nearby tree.)

The second largest reliability initiative is the “capital asset rebuild” program. Much of Dominion’s capacity was installed in the 1930s, ’40s and ’50s, an era with less advanced technology and less rigorous performance standards. Improving the design of older distribution facilities and rebuilding them to current standards reduces the number of disturbances.

Under its circuit reconditioning initiative, Dominion began ranking the performance of each of its 1,800 circuits for preventable failures and prioritizing the worst performers for fixing. Then, diving deeper, the company started collecting data on breakers, reclosers and fuses in each circuit, some 180,000 devices in all.

The neighborhood transformers program addresses increasing demand in residential neighborhoods. In the 1930s, ’40s and ’50s, the company installed distribution lines and transformers to meet electricity demand of an era before air conditioning, big-screen televisions, computers, appliances and other energy-sucking devices. The same houses today draw more electricity and transformers can get overloaded. To deal with the problem, Dominion has replaced 4,000 transformers during periods of low demand. That proactive maintenance, says Chafin, is preferable to waiting until a transformer blows out on a hot summer afternoon.

As much as electric customers fume at routine disruptions, the lengthy storm-related outages are the ones they really remember, says Le-Ha Anderson, manager for media relations. “When electricity stops, life kind of stops.”

Last year Dominion submitted to the State Corporation Commission (SCC) a plan designed to reduce the length of major-storm outages by burying critical stretches of overline wire. High winds blow branches and other objects into power lines and knock them out. Undergrounding the electric distribution system statewide would be prohibitively expensive — on the order of $83 billion, according to an SCC report. That would amount to thousands of dollars per customer and cost generations to complete, Chafin says. The benefits don’t justify the cost.

After examining the data, however, Dominion discovered that 20% of overhead lines were responsible for a disproportionate percentage of outages and time lost. By burying just the most outage-prone tap lines (the small lines that stem from feeder lines to individual houses), the company calculated, it could cut average restoration times after major storms in half. Dominion said the program would cost only $2 billion up front. (An SCC report concluded that the program would cost customers $6 billion in capital costs, property and income taxes, and financing costs over the life of the assets.)

In a hearing before the SCC last year, Dominion asked the commission to approve the first stage of the project, covering 526 miles of tap lines at an initial investment of $263 million. The project would require a rate adjustment of $24.4 million in the first year, less than $1 per month on the average electric bill.

Consumer groups opposed the petition. Testified the Attorney General’s consumer counsel:

Despite the unprecedented size of the proposed [Strategic Underground Plan], the company has not conducted a cost-benefit analysis, has not provided any estimate regarding reliability improvements or economic benefits to customers, and has not considered any lower-cost alternatives.” Based on this record, we cannot conclude that it is reasonable, and in the public interest for Dominion to invest $263 million — and ultimately to charge customers over $700 million — for the first portion of the SUP…

The SCC proposed instead that Dominion conduct a pilot program targeting tap lines with the worst reliability record to gather data for a realistic cost-benefit analysis. Dominion has not publicly said whether it plans to submit a new proposal.

Meanwhile, the company is applying a cautious test-and-learn approach to integrating solar energy into its energy mix. Dominion worries that the intermittent shining of the sun creates fluctuations in voltage that could disrupt the transmission and electric systems. With new solar projects in its North Carolina service territory and the proposed Remington industrial-scale facility in Virginia, the company is building experience with solar that will enable it to model the impact of larger-scale projects in the future, says Anderson.

Whatever the future of solar facilities and underground lines, Dominion’s collection and analysis of data is likely to improve reliability in routine operations for years to come.

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11 responses to “Towards a Smarter Grid

  1. I don’t know where these consumer groups are coming from in opposing the burial of the most troublesome lines. They want alternatives from DVP… well how’s having your power knocked out during storms for an alternative? NoVa folks probably still have nightmares about that nasty derecho storm in June of 2012 which left them in the dark for days.

    We ought to be able to reach an agreeable price tag and start digging the trenches ASAP. Is it that DVP wants more money than is reasonable?

  2. This is puzzling to me as well. Any good utility executive would have asked for a comprehensive business case to be made before approving an investment of $263 million. However, according to the Attorney General:

    “Despite the unprecedented size of the proposed [Strategic Underground Plan], the company has not conducted a cost-benefit analysis, has not provided any estimate regarding reliability improvements or economic benefits to customers, and has not considered any lower-cost alternatives.”

    Either Dominion did not provide its detailed information to the SCC or it just wanted to make a large investment on which they would recover a long term return (and also provide higher reliability to its customers). Usually a thorough analysis will support under-grounding in certain locations.

    Dominion has intelligent people and they are pursuing the grid improvement and grid information programs that are occurring in utilities around the U.S.

    The important issue is whether they are willing to share this information and collaborate with customers and third-party organizations to develop the distributed generation and demand management projects that will make the grid more resilient, improve reliability, cut customer costs and avoid costly additions in grid and generation capacity. These are the issues that are being actively pursued in a number of other states. Holding off any serious review of these issues until at least 2022 will put Virginia far behind other states in developing a modern and affordable energy system.

    States actively pursuing this are creating an environment attractive to innovative businesses and workers, exactly what Virginia needs to do more of. Instead of having rates slightly higher than our neighbors, we should be seeking ways to have an innovative, lower cost energy system that is enticing to new enterprises. The business activity going on relating to the demonstration projects associated with the REV program in New York State is impressive. California, Minnesota and Massachusetts are also pursuing similar programs. If we don’t move forward, North Carolina will far surpass us and Virginia will be left behind. The Governor has made the development of innovative new industries a priority for his administration. Why are we not taking advantage of this opportunity?

    DVP can certainly win by shifting to gaining revenues from energy services. My only thought is that Dominion Resources depends on the steady cash flow from DVP to help fund its other subsidiaries and is threatened by a program that might provide profitable returns but on lower revenues.

    • It leaves me baffled. Jim, ANY well-run utility today ought to be “using big data to increase the reliability of its distribution network.” This is simply the result of vastly better COMMUNICATIONS than there used to be.

      When I first started with the electric industry, there was essentially no feedback from recipients of electric power until one of two things happened: the customer called and said his lights were out, or, the utility determined on its own that something significant had happened at the substation level. In the first category, we moved from plotting customer phone calls on a paper map to plotting them electronically, and then to differentiating the patterns of outages associated with particular pieces of equipment (in order to identify likely equipment failures), and associated with particular storm types and storm radar scans (in order to send repair teams out to likely damage areas even before the calls came in). In the second category, we began to install monitoring equipment that would call the control center automatically if certain equipment failed. Both these efforts accelerate in the 80s as computers and computer data links became commonplace.

      But there was a major technical impediment: it is difficult to send communications over power lines through a transformer. Thus retrieving data from a distant substation meant installing a separate wire or radio signal for this communication, plus sensors and processors to send the data, which was a huge task. More recently however, with the spread of cell phone technology in the late 90s and the development of computer programs that could analyze what the flow of electricity indicated and pinpoint specific equipment problems, it’s become commonplace to track such things. Indeed Dominion would be negligent if it didn’t!
      In response to all that data, it also makes sense that Dominion is now spending more in a targeted way on reliability improvements, including tree trimming and, if warranted, undergrounding. Frankly it’s surprising to me that after 20 years of collecting such data, and having now apparently found 1/4 of $1 billion in beneficial undergrounding to be done, Dominion would just now be getting around to proposing a distribution undergrounding initiative this significant. Moreover, having taken so long to pull together such a study, they went and submitted their proposal to regulators without any of the analyses that THEY MUST HAVE ALREADY DONE to support such a proposed sizeable capital expenditure internally to their own management. That comes across as a combination of chutzpa and arrogance that doesn’t reflect well on DVP.

      One other comment. You say, “Dominion benchmarks against itself . . . . The numbers exclude major storm events, which are so random and are of such a magnitude as to obscure trends in routine operations.” Yet you say the undergrounding initiative is “to reduce the length of major-storm outages by burying critical stretches of overline wire.” So it’s unclear to me whether Dominion’s undergrounding proposal has anything to do with day-to-day reliability statistics as opposed to storm recovery times. If it’s just the latter, that’s an awfully big pricetag for system weather resilience that, maybe, should have been built into the system already through many years of steady improvements and not tacked on as an extraordinary improvement surcharge during a so-called base-rate freeze. Rowinguy picks up on this point more bluntly below.

      • “It’s unclear to me whether Dominion’s undergrounding proposal has anything to do with day-to-day reliability statistics as opposed to storm recovery times.”

        My understanding is that the proposal is driven by the reduction in storm recovery times, not day-to-day reliability statistics. Dominion’s thinking is that people can handle outages of a few hours without major disruptions to their lives. But knock out their electricity for 8 to 10 days, and you create major problems. The idea is to cut those lengthy periods of time in half.

        You and others raise legitimate questions of why Dominion hadn’t prepared solid, defensible ROI analyses for this project. As I recall, this was a first-in-the-nation kind of a proposal. The ROI as measured by reduced maintenance expenses would be trivial. The real benefit goes to potentially tens of thousands customers who have their electricity back on, say, in three days instead of six — in incidents that occur maybe once every two or three years. What kind of economic value do you place on that?

        • You know, in the context of new power plants at a billion plus a pop and a 550 mile pipeline and a multi-million dollar river crossing, offshore wind and onshore solar – Dominion would seemingly have a lot of experience and practice looking at ROI….

          Here you have the SCC and the AG riding herd on something that almost seems like it ought to be a normal business case issue unless of course Dominion is just asking for a rate increase…

          Now – I don’t know how many folks have been without power for 10 days but I can tell you if you’re out for 5 days – things get pretty grim. All your refrigerated food is gone, hot showers are gone, and mold starts to grow on things if the outage is in summer and not much better if during a snowstorm.

          Modern homes were not designed to operate without electricity.

          Many folks will leave their homes and go to friends or family or motels in multi-day outages.

          Not sure I’d categorize this issue as “smart grid”…

  3. yes… having the same problems. The SCC and the AG have to decide if Dominion has made a business case?

    or… Dominion HAS made the business case and basically has decided that there is no savings or even a break even with respect to putting underground – and – as a result – they need to charge for it as an add-on service?

    in DVP’s defense – taking down trees in residential areas is a lose-lose.

    and how do you go through a neighborhood and get agreement from enough people to add fees to their bills for undergrounding ?

    My bet is that if you went to most neighborhoods and presented that proposal to people that you’d not only not get 100% support, you may well get people who demand that you do it – and not charge more which is not that different from how people think about roads and schools.. they want more – but they don’t want to pay more. They believe that there is waste and that they should not have to pay more – just get the agencies to cut waste.

    Am I right?

    • Building or improving distribution lines are rate base items. They are not usually charged to individual property owners. In simple terms the net present value of the cost to underground the lines (which is much more expensive than stringing them on poles), including the cost of financing would be compared to the NPV of the expected costs of tree trimming and rolling trucks and crews for storm repair for that segment of line over the next 20- 25 years. If the undergrounding is less, then it makes sense to do it. Apparently, this type of analysis and the assumptions used was not presented to the SCC. It is the function of the SCC to examine proposed utility expenditures and determine if they are reasonable and have a positive value to ratepayers. The AG has a consumer protection group which performs a similar function. Both seemed to agree that in this case, based on the information that Dominion presented, they could not confirm that ratepayers would save money in the long-term. So they believe it does not make sense for Dominion to get a rate boost to recover the costs of the program (plus a return to shareholders).

      I would hope that Dominion provides the requested information at least for the smaller test area that was requested.

      The investment Dominion is making in upgrading old distribution facilities and adding modern sensors does reduce outages and trucks don’t have to roll to survey a large area trying to find a problem. The new sensors report exactly where the problem is and sometimes where a problem is about to occur, so it can be repaired more quickly. This is reducing the length of customer outages as shown in the graph.

  4. There is a critical ratemaking aspect to this Dominion case that Jim has not touched on. DVP’s entire distribution system costs are recovered in its base rates, the ones the SCC formerly reviewed every two years, but, due to legislation enacted in 2015, will be foreclosed from reviewing again for DVP until 2022. Those rates are “frozen” until that time.

    Why did DVP propose this undergrounding program just now and not, say, 5 years ago? Because in 2014, those friendly guys on the Hill enacted another piece of legislation that allowed the Company to propose such a distribution “hardening” program and have all THOSE costs recovered in a rate adjustment clause, with guaranteed profits recovered dollar for dollar. So, costs recovered via the “frozen” base rates would go away (but still be collected, since base rates cannot be changed) while new distribution costs would flow through to customers via the automatic adjustment charge.

    The Company filed a very porous case for transferring these costs and the SCC denied it. I expect DVP will do more due diligence and come back again several times before the rate base freeze ends in 2022. Plus, the costs, as Tom notes, will be collected from all DVP customers, including those whose distribution lines won’t be improved at all.

    • Our subdivision is more than 25 years old. The electric lines are underground.

      I remember asking about it at the time it was done and if I recall correctly, I was told that when you look at the costs over a 30 year timeframe, i.e. trimming vegetation… outages from storms and treeing falling on lines, etc.. that it was cheaper to put the lines underground – but required more upfront money.

      Most, if not all new subdivisions in our area – have buried lines so I’m assuming we’re talking about retrofit… and in that case – the issue would be – should all ratepayers – including those who already under underground lines and those who live in condos, apartments, etc – be paying to retrofit?

      or have I got this all balled up?

      • Dominion may have charged the developer of your subdivision for burying the underground lines — in which case, you’re paying for them without realizing it. You benefit from superior aesthetics and reliability; Dominion rate payers benefit from lower maintenance costs.

  5. TomH, I too cannot understand why Dominion is running into a buzz-saw here. It should be a pretty straightforward analysis: increased investment versus decreased maintenance cost, with a bonus of better customer relations due to improved routine reliability, fewer wires hanging in view, and improved tree-scape.

    Generally suburban customers want more distribution undergrounding than the utility will push for; in fact, around Washington DC the typical suburbanite wants u/g to the max for aesthetic reasons more than anything else (offset in specific locations by dismay at denuding residential neighborhoods of their existing tall trees at the time the lines are first buried). Some DC suburbs require undergrounding, and customers in those suburbs pay a distribution surcharge to defray the net extra cost (extra investment less operational savings), on the theory that other customers who still have overhead lines in their neighborhoods shouldn’t have to pay extra for a benefit they don’t receive.

    Dominion operates a more rural than suburban system as a whole, plus much of their last-mile-delivery is done by distribution coops and municipal utilities they sell to at wholesale. Generally there’s a lot less undergrounding on a rural electric system. Through industry groups there is plenty of information out there about the tradeoffs utilities across the country have identified from undergrounding — i.e., where it is cost beneficial and where not — but as Jim notes, “Dominion benchmarks against itself.” Perhaps this is just a case of Dominion going in to the SCC without data that’s readily available out there from elsewhere. Perhaps Dominion doesn’t know what its costs will be and thought it could figure it out on the fly.

    There are potential utility ratemaking subtleties here. For example, others have pointed out that Dominion has a slight incentive to prefer the investment (rate base) over the expense side of the equation. And what are Dominion’s existing distribution costs that would be impacted by undergrounding? Dominion’s particularly opaque rate design doesn’t help; in many other parts of the country the distribution rate (i.e., recovery of the distribution rate base and expense) is kept separate from the generation and transmission rate, but Dominion combines these components in the older manner of an integrated utility, then breaks out its most recent generation (and other) projects incrementally in discrete “riders.” This may be the best way to meet the requirements of the ratemaking process dictated by the GA, but Dominion wrote the book on that process. While this project-oriented approach puts the costs OF THAT PROJECT on the table, it can make it very difficult to look at alternatives and compare outcomes. If Dominion really didn’t provide its current distribution costs for context plus an analysis of how they would be impacted, I’m not surprise the AG would conclude, “Despite the unprecedented size of the proposed [Strategic Underground Plan], the company has not conducted a cost-benefit analysis, has not provided any estimate regarding reliability improvements or economic benefits to customers, and has not considered any lower-cost alternatives.” This damning summation certainly implies Dominion filed a black-box “just give me a thumbs up” rider request; and frankly I’m surprised the SCC staff thinks a pilot program alone will provide enough additional data to act on the original rider request.

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