Category Archives: Power Grid Network Projects

Gauteng broadband project ‘faces axe’

The South African province, containing Johannesburg and Pretoria, approved the  multibillion integration of existing network infrastructure to provide cheaper access to broadband Internet services.  The government intended to spur economic development and attract more business investment.  After building the R 20 billion GAUTRAIN, there is not a cent left for this project.

Meanwhile, GBCN’s partner, TWU Broadband Communications, has formally offered to fund, build, and operate Power Grid Networks on the local electricity distribution grids of the City of Tshwane (Pretoria) and Ekurhuleni (an even larger adjoining municipality).

These Power Grid Networks will provide smart grid management services and broadband communications for end-users, customers, as well as all cellular carriers operating in these Municipalities.

The RSA government has touted the need for “public / private partnerships” to bring private sector solutions to infrastructure problems.

Well, here it is…

Quote from SMART GRID TODAY:  “…Consumers are failing to understand the value of the smart grid, and some essential technology can actually get in the way of helping them gain that understanding, Erich Gunther, administrator of the Smart Grid Interoperability Panel (SGIP), told us yesterday.   In technical meetings with Southern California Edison and other players this week, “one topic that keeps coming up is just how important it is to spell out the value of the smart grid for consumers,” Gunther said.

QUOTE OF THE DAY: Whether the backlash against the smart grid is justified or  not, the consumer is obviously not  understanding its value.–Erich Gunther, administrator of the  Smart Grid Interoperability Panel…”

In the classic buyer-seller relationship, the seller presents a clear value proposition to the prospective buyer, and the buyer decided whether or not to purchase.

The Smart Grid’s systemic value is illusory, because it can only be understood by a rate-payer in terms of a series of limited and well-defined retail value propositions.  This rate-payer, free to say yes or no, must be convinced by this value proposition to say yes.

One solution at a time.

Maryland’s PSC decides in favor of  ‘rate-payer’ advocates against smart grids.

LESSONS LEARNED:  Smart Grids’re Having A Hard Time Paying For Themselves Upfront…

BG&E Takes Its Smart Grid Case to Regulators – Staff, www.baltimoresun.com, 11 Nov 2009

Baltimore Gas & Electric (BG&E), armed with a $200 million Smart Grid Federal ARRA stimulus grant, took its case before the Maryland Public Service Commission (PSC).

The BG&E proposal combined smart meters with a new time-of-use price structure. BG&E also asked for authority to apply a surcharge on electric bills to help recover its project cost that includes replacing two million meters by 2014. The new pricing structure would increase per kilowatt-hour charges during times of peak demand during hot summer weather.

The PSC was asked to approve the pricing plan and the project cost recovery surcharges. The $200 million in federal stimulus cash will lower the surcharge and takes what “already was a strong business case and makes it stronger.”

Deployment of the smart meters is supposed to provide several benefits: real-time information for consumers so they can better control their energy use, automated meter reading, service disconnections and reconnections and outage detection—which could result in customer savings.

BG&E does have one problem: Consumer advocates don’t like it and they say so.

“We view it as too much too fast,” an advocate was quoted as saying in the Baltimore Sun. The speaker, Paula Carmody of the Office of the People’s Counsel, said advocates question if the project is the best, most cost-effective way to cut costs. The project is expected to cost roughly $800 million over the lifespan of the meters.

State regulators deny ‘smart grid’ proposal – L.F.Kay & H,Cho, www.baltimoresun.com, June 21, 2010,

A high-tech proposal promoted as a way to save utility customers billions of dollars and help them better control energy use was thrown into doubt Monday, after state regulators denied BGE’s request that rate-payers shoulder most of the upfront costs.

The Maryland Public Service Commission ordered that Baltimore Gas and Electric Co. should contribute some of the $835 million cost to deploy the “smart meter” technology.

“The proposal asks BGE’s ratepayers to take significant financial and technological risks and adapt to categorical changes in rate design, all in exchange for savings that are largely indirect, highly contingent and a long way off,” wrote members of the PSC in its order.



BGE President Kenneth DeFontes said he was “dumbfounded” by the PSC’s decision — and it’s not clear whether the utility will revise the application.
”At this point, it’s hard to see how we could pursue it with the constraints that the commission has put down,” he said.



BGE officials claim smart meter technology would allow two-way communication between customers and the utility. Consumers could track their electricity on an hourly basis. The utility would benefit from immediate information about outages and other system problems on the grid, automate meter readings, saving the utility money on meter readers.



The plan was estimated to cost a total of $835 million over the 15-year life of the meters, which BGE officials sought to recover through bill surcharges that the PSC had to approve. BGE received $200 million in federal ARRA stimulus grants through the U.S. Department of Energy, which would have decreased the cost of the initial five-year deployment.


The surcharge would start at 38 cents a month for electricity customers and an additional 44 cents for those who also use natural gas. Over the course of the 15-year program, it would rise to an average of $1.24 a month for electricity customers and an additional $1.52 for gas customers.

BGE officials have claimed that the company’s 1.2 million customers would save as much as $2.6 billion over the life of the meter.



The commissioners wrote that they understood the federal grants would help offset some of the costs that consumers would face. However, commissioners said that even a $200 million “discount” on an $835 million rate-payer investment cannot dictate the outcome here.



Representatives of the advocacy groups said they were pleased with the commission’s decision.

”I think it was a very difficult decision for the commission to make, but obviously, it was the right thing to do, given the amount of money that was at risk for consumers and the related impact on their lives through pricing schemes,” said Paula Carmody of the state Office of the People’s Counsel, which represents consumers who go before the PSC.



In their order, commissioners wrote that customers would begin paying a surcharge to cover the costs of the project long before they would reap any benefits from the new meters, which would have been installed through 2014. They also objected to approving a proposal that included mandatory “time-of-use” rates that charge residential customers higher electricity prices at peak times. Any future proposals should include an option for rate-payers to opt in or out of time-of-use metering, the commissioners wrote.

The majority of the estimated $2 billion in savings stems from consumers reducing their energy use during peak hours, according to the commission. But in their order, commissioners noted that BGE’s $835 million smart grid proposal would not provide its customers with the in-home displays and devices they would need in order to know how much energy they were using when. A BGE website would show data — but only from the previous day.

If you are interested in where we’re at with Electric Vehicles this report from the Institution of Engineering and Technology — Battery Cars — will get you right up to date.

While traveling over the continent of Africa at the end of the 90s, it became clear that right of way was the most expensive, hard-to-create, and hard-to-operate-and-maintain asset in every country.  Power authorities struggled to get the legal right and the funds to create transmission paths from their plants and dams to their customers.  At the same time, telecom companies were forced by economics to use a European country’s satellite connections and to pay them what amounted to a transfer fee on every call outside their country – even if the call was connected to a neighboring African country.

But neither the power nor the telecom service providers thought to build along a common right of way.  They seemed to always operate separately.  On realizing this, I went out of my way on a number of occasions to put together power people I met with telecom commissions (the telecom commissions of Economic Community of West African States and the Southern Africa Development Community with Eskom and the Southern Africa Power Pool).

The important idea we began to discuss together was to focus the revenue streams of power transmission and telecommunications along the same right of way to nourish this common carrier path’s sustained operations and maintenance.

A power grid network can evolve this common carrier pathway into transformative opportunities, such as:

• The power grid right-of-way can deliver powerful new communications technology solutions through its universal customer access
• Building an extreme-capacity broadband network on the power grid can provide dedicated and secure support for all the smart grid applications it will take to maximize energy efficiency
• This broadband network can be designed to be self-aware and self-healing – allow more reliable management of electric distribution and communications through network faults and power outages.
• An intelligent broadband power grid network can service multiple public utility or rural electric cooperative grids – without sacrificing each local smart grid’s managerial autonomy.
• An intelligent network built on power grids can defeat power theft and manage customer accounts
• A power grid network built through multiple public utility or rural electric coop distribution grids can buy both network and smart grid hardware & software with much higher economies of scale.
• A network of multiple local power grids can generate sufficient communications service revenues to both subsidize smart grid apps and enable the power grid network to operate profitably.

Advanced communications services and local power grids can flourish in the reciprocal relationship of a power grid network.

Power utilities leasing out their right of way for telephone links can provide ancillary revenue, but insufficient to fund and manage the smart grid.

Telecom companies offering standard “plain-old-telephone-services” and internet access over power grid utility pole lines confront dual limitations in both traffic and profit margins that universal service funds can never adequately address.

The community’s scarce resources can be better deployed for everyone’s benefit than they are now.  This power grid network offers one real solution.

See:  USrural project

In designing the Power Grid Network, we have to examine those ‘Smart Gridders’ out there on the “Bleeding Edge” carefully – their mistakes can reveal our solutions.

Who gets the benefit of smart meters is important. Regulators in the U.S. are weighing in to stop ‘one-sided business cases’ for smart meters in their tracks:

Dominion Virginia Power extends a smart meter field test before going all out with a $600 million rollout. Duke Energy scales back a $450 million rollout after getting slapped by Indiana regulators. And PG&E’s smart meter program, taking punches from fighting-mad customers for months, will get audited courtesy of state regulators.

Dominion’s overall plan calls for replacing all 2.4 million meters in its service area with smart meters. About 55,000 thousand meters are now being tested in two locations.

Dominion says it’s still committed to a Smart Grid and that the extended test phase is intended to address any concerns about the metering project. But the State Corporation Commission (SCC), which is beginning hearings on Dominion requests to put in place up to 12 demand response programs and rate hikes to pay for them, isn’t pumped about the utility’s smart meter program.

“The actual benefit value realized by ratepayers will be less than the costs borne by ratepayers,” Howard M. Spinner, economics and finance division director for SCC, was quoted as saying in the Richmond Times-Dispatch. “The project is likely to save only 60 percent of the energy claimed by the company.”

A Dominion spokeswoman said customers will help pay the cost of the smart meters, but will pay less over time.

While a Duke meter rollout in Ohio will hum along as planned, the company is cutting back a proposed Indiana Smart Grid project involving 800,000 meters and other digital equipment because regulators said it cost too much and that Duke hadn’t shown that it would do customers much good.

Beleaguered PG&E — sued over its meter program by customers who blame the new technology for electric bill overcharges — is going to get audited. The California Public Utilities Commission (CPUC) is going to hire a consultant soon to conduct an independent audit of the utility’s program.

While PG&E said it field tested over 1,700 meters and found no problems, that hasn’t cooled off customers infuriated by the alleged overcharges and the company’s tiered rate system. Under the system, rates per kilowatt-hour increase as more power is used and the customer climbs into the highest tiers. Its highest tier, 47.39 cents per kilowatt-hour, is well above Southern California Edison’s highest rate of 34.25 cents per kilowatt-hour, not to mention the 11.47 cents in Austin, Texas.

We should develop a careful, gradual demand response introduction and marketing plan – starting with “positive gain” introductions, moving on the institutional business cases, and discussing the benefits and the costs of ‘smart pricing’.  The most important investment it requires is time, then engagement.   ‘Smart pricing’ will only succeed to the extent that customers actually know they benefit from it.

What Is USrural To Us?

• Financial partner that pays for building and expanding our community’s smart grid
• Operating partner that manages and maintains the community smart grid under our direction
• Research and development partner that will exploit ‘lessons learned’ on  each ‘best-of-breed’ smart grid application it deploys in multiple power grid networks
• Provider of subsidized Internet access for our community’s schools, libraries, & medical facilities

What Does USrural Bring To The Table?

• Financial Resources for the community smart grid
• Telecommunications Expertise / Manpower that’s independent from vendors
  • New Technology Solutions Powering Extreme Capacity Broadband
• Vendor Independent Smart Grid Research / Development / Deployment Expertise

What Would Be Our Responsibilities In A Relationship With USrural?

• Provide right-of-way for smart grid and broadband/mobile apps
• Set smart grid strategy based on customer benefits / requirements
• Direct when and how smart grid apps operate
• Approve data integrity and security of all customer data that adjudicates service disputes
• Pay service fees only for actual smart grid usage

What Would Our Benefits Be From A Relationship With USrural?

• Eliminate up-front community smart grid and communications Capital Expenditures we face
  • Remove urgency to raise energy tariffs in order to repay these new investments “on time”
• Roll out ‘best-off-breed’ smart grid apps one at a time, based on their benefits to our customers
  • Reducing service disruption, accommodating new energy demand without increasing supply
  • Changing how and when smart grid costs impact energy tariffs
• Subsidized broadband for our community’s public institutions
• Subsidized ops & maintenance for the community power grid network
• New Resources with which to develop our community’s economy
  • New local jobs
  • New and more cost-effective local communications service to support new commerce
  • More reliable / efficient / cost-effective energy to prompt new enterprise moves into the community

What Does USrural Seek From A Relationship With Us?

• Universal access right-of-way to all customer sites within our communities’ service footprint
• New smart grid and communications service usage revenues
• Partner whose continued viability is assured by developing our community’s economy

PGN’s Customer Access Network

Power Grid Network – Bulk Dist

Penny Wise and Rand Foolish

In the RSA, regulators and utilities are focused on “smart meters.”  However, without providing customers with smart price signals, it is doubtful that the purported benefits of smart meters will accrue.  Much of the policy debate over smart meters thus far appears to focus on how to get the meters installed and who should pay for them.

However, there are many applications that smart grids must employ to create this major investment’s benefits.

Advanced Metering Infrastructure (AMI) requires high-bandwidth communications to allow large quantities of data to be transferred every now and then. Smart grid sensors require high latency to allow small quantities of data to be moved from the location where it is captured to another where a tool will perform an analysis. Failure to keep the end game in mind is likely to result in substantial increases in overall capital outlay, which will ultimately undermine the business case benefits of the smart-grid initiative.

How Much Is Enough Bandwidth?

“A survey of the 15 most recent experiments conducted in the U.S. Canada, Australia, and France has been conducted with the dynamic pricing of electricity.  We find conclusive evidence that residential customers respond to higher prices by lowering their electricity usage.  The magnitude of response depends on how much prices increase, the prsence of central air conditioning, anad th availability of two-way programmable communicating thermostats and always-on gateway systems that remotely control multiple end-uses – that is, ‘enabling technologies’.

“…Time-of use rates induce a drop in peak demand that ranges between 3% and 6%.  Critical-peak pricing rates induce a drop in peak demand of between 13% and 20%.  When accompanied with the above-described ‘enabling technologies’ the later set of rates lead to a drop in peak demand from 27% to 44%.

“..These results have big impacts on reliability and least cost operation of a power system facing escalating power demand and capacity costs.

“Smart Meters and Smart Pricing – Survey of the Experimental Evidence”, Ahmad Faruqui and Sanem Sergici, The Brattle Group [http://www.hks.harvard.edu/hepg/Papers/2009/The%20Power%20of %20Experimentation%20 01-11-09_pdf]

“…There were two main objections to the conclusions I reached and in the substantiation of the data I used.  The first was based in existing utility practices: A meter read only contains basic information about the identity of the power meter, the time stamp, and the meter reading itself: around 14 bytes per read, resulting in a belief that such a small amount of data would never amount to anything like the avalanche previously described.  The second objection was that there was little likelihood that such data was going to be stored for long, meaning, I guess, that we could design the system as though it had never arrived at all. Many of the questions came from individuals with strong/long histories in utilities, so I felt it my responsibility to validate my data.

 While I consider myself to be relatively well-versed in the core of these topics, I decided to go back to Austin Energy, and understand better the reality of the situation from the folks who are actually doing the job, and who are considering these concerns as fundamental parts of their planning for successfully serving their clients on the new grid in the years to come. We called Andres Carvallo and Karl R. Rábago at Austin Energy, and they helped us understand the world and the Smart Grid that they are planning for.

“Smarter Grid vs. Simpler Meter Reading — … These gentlemen expect to coax rich two-way data communications from the new grid infrastructure. While time, location, and power used are at the heart of a meter read, there is much more to be learned.  Some examples are:

“Device Health Information – Watch for varying temperature, periods from outage, battery power, heartbeat, and other variables, the system can better predict and recover from failures.

“Real-Time Monitoring – Real-time monitoring may be in demand almost immediately, as customers recognize there is now more information with which they can manage their energy.

“Energy Services Provision Trumps Energy Provision Services – Newly informed and empowered customer base will spawn new requirements for functionality that is logically delivered by the provider. Power providers are now actively thinking about services that they can offer over the new and smarter infrastructure. Things like profiled energy use: “I am going away, manage my power” or “There is a spike in prices, manage me down by 10%” or “I only want to use power that is generated from renewable resources.” These all require data, new interfaces, and a channel over which all of the control and monitoring information can be passed.

“Networking Overhead – Given the complexity, regularity, and importance of this data, a protocol (like IP) will be adopted to package up and send all of this data to central systems for analysis, aggregation, storage, and action. Protocols generate their own overhead and two-way data communications.

“Other Factors – We are only just beginning to see the potential for Smart Grid and Soft Grid enablers — even my estimates are likely to be low, particularly with real-time monitoring and data analysis.

“Based on this analysis, the numbers are far from a simple 14-byte read, and are more likely in the range given by Andres of 4,000 to 16,000 bytes (128,000 bits to be transmitted) per reading. If we estimate the maximum case, the numbers are even higher than I had referenced in the earlier article. Let’s not think about real-time (the numbers are mind-numbing), but instead look at a simple check every 5 minutes:

“12 (reads/hr) X 24 (hrs/day) X (365 days/yr) X 16K (bytes/read) yields roughly 1.7GB/meter/year

“Multiply that by the number of meters you deploy in your footprint, the challenge is clear.  For more reality, take that number and multiply by 5 for readings every minute, or by 300 for readings every second. 

This is a problem because rushed, tactical, and incremental hardware additions will not make that data secure. It has to be expected that as organizations run out of room for data, they will simply rush to add more. Caught in a flood of data, the pressures for survival and successful operation will naturally trump any meaningful consideration of re-architecting data storage for adequate and appropriate security.

“For utilities that recognize the Smart Grid will need data, will need security, and will likely grow to fill whatever space is available, the call is clear. Plan for an avalanche, plan for a flood. Create systems and segregations that will allow for managing these flows reliably. The data surge is coming, and you can either surf it, or be pounded by it. You certainly will not be able to ignore it.” — “That Smart Grid Data Surge We Mentioned Earlier?  You Can’t Ignore It”, 3 Nov 2009, Jack Danahy, SmartGridNews.com

The municipal energy company views the utility of the smart grid system as first and foremost operational cost mitigation, second energy demand management (i.e., moving demand to off-peak rather than limit the amount of energy available), and then third, customer-end user benefits.

But it is clear that for a smart grid system to deliver sufficient benefits to justify its cost, all these applications must be deployed. To date, very little is understood about the bandwidth utilization profiles of smart grid applications, since so few have been implemented.

Silver Spring Networks sells a 19,600 bits per second radio mesh network of smart meters.  But GE thinks that while 100 kilobits per second might be fine for reading electric meters’ gross usage statistics, 1 to 2 megabits per second is required to have enough information and communications to automate the distribution grid in real time.

Says Larry Solecito, CEO of GE Digital Energy, “if you’re doing distribution automation, you require very fast response times.  You cannot miss a read on a communication. With that speed and reliability, you will damage a transformer, you’ll break a generator, and you may even have a customer safety issue.”

The Pacific Crest Mosaic Smart Grid surveyed 20 industry leaders with budgeting or technology selection responsibilities from 1-23 July 2009.  They listed and ranked smart grid applications in the order of of their importance to the utilities, as follows:

1. Advanced Control (real-time)
2. Fault Detection and Isolation (real-time)
3. Substation Automation and Diagnosis (real-time)
4. Demand Response (smart pricing)
5. Firming and Integration of Variable Renewable (distributed energy sources)
6. Asset Management
7. PHEV (Electric Vehicle) Integration with the Power Grid
8. Load Forecasting and Capacity Planning
9. Workforce Management (reading meters remotely)
10. Voltage Monitoring
11. Carbon Compliance

Analysis of a Utility’s Description of its Smart Grid Usage Profile

“…Austin Energy’s CIO Andres Carvallo says that Phase 1 of his company’s smart-grid project completed in July 2009, when a half-million smart-meter devices were implemented across the company’s footprint.  “Our total information online was 20 terabytes (20,000,000,000,000 bytes).

“But right now, we are capturing data from the smart meters every 15 minutes – that requires 200 terabytes of storage space, since we’re doubling up with a second disaster recovery site. (This 100 terabytes of transmission to the smart grid management system over the network occurs over 1 year, every year, with each year’s data records having to be protected, retained, and readily accessible on-line for at least seven years to address potential dispute resolutions).

“If we move to reporting the meters once every five minutes, that 200 terabytes becomes 800 terabytes of storage space (or 400 terabytes transmitting in from the meters to the system over the network).

“If we move the reporting frequency to once every minute, this then requires 1.5 petabytes of storage space (or 750 terabytes transmitting in from the meter to the system over the network)…”  — “That Smart Grid Data Surge We Mentioned Earlier?  You Can’t Ignore It”, 3 Nov 2009, Jack Danahy, SmartGridNews.com

What is the throughput capacity required on the network for 500,000 meters to transmit their reports every 15 minutes?

At 30 megabits per second dedicated capacity, 500,000 meters can transmit their reports in 12.68 minutes, so they can be ready to retransmit during the next 15 minute reporting increment.

What is the throughput capacity required on the network for 500,000 meters to transmit their reports every 5 minutes?

At 100 megabits per second dedicated capacity, 500,000 meters can transmit their reports in 3.81 minutes, so they can be ready to retransmit during the next 5 minute reporting increment.

What is the throughput capacity required on the network for 500,000 meters to transmit their reports every 1 minute?

At 400 megabits per second dedicated capacity, 500,000 meters can transmit their reports in .95 minutes, so they can be ready to retransmit during the next 1 minute reporting increment.