Making Sense of Smart Grid Blog

The eighth session of this course was devoted to the topic of how the Smart Grid intersects with the consumer. To discuss this perspective the teaching staff had invited the Bob Jenks, the Executive Director of the Citizens’ Utility Board (CUB), Lauren Shapton, PGE’s Manager of Mass Market products, and Scott Schull the director of Smart Commercial Buildings at Intel.

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Bob Jenks, Executive Director

Citizens’ Utility Board of Oregon

Bob Jenks started off the presentations by introducing the Citizens’ Utility Board which is an advocacy group representing the residential customers of utilities. There are currently approximately 43 consumer advocate offices across the country, but most of them are supported by government, or attached to government - sometimes as an adjunct to the Attorney General’s office. CUB is a bit different in as much as it is an independent, non-profit, non-governmental agency. Most of these ombudsman’s offices focus primarily on rates, but the Citizens’ Utility Board seeks also to represent the values of Oregonian consumers.

Certainly Oregonians are concerned about rates, but they also care about sustainability, climate change, a broad range of things. They’re working closely with PGE to close Boardman. They take a pretty broad view of representing their customers.

The Commission had an ongoing docket open to consider the Smart Grid. PUC staff put out a proposal, which the SGO supported. CUB is a member of the SGO group. But this shocked Bob because he thought it was a “huge barrier” to the implementation of the Smart Grid. In talking with the SGO and the commission staff he came to the realization that there were two distinctive ways to see the deployment of the Smart Grid and that’s really influencing the policies that people are putting in place today. He cautioned that we have to be careful lest we allow our visions to put barriers in place to prevent the development of the Smart Grid. The case in point was that the staff proposal had advocated a position that would “ban utilities from investing in Smart Grid applications on the customers’ side of the meter”. The theory was that such an investment would stymy competition and prevent the emergence of third parties introducing innovation into the marketplace.

Bob’s reaction to this was, “this is crazy!” He cited the small Emerald PUD, which introduced an automatic turn-down during critical peak times saving customers money automatically. To Bob that was a different approach to dynamic pricing – rather than charge customers more, they automatically saved them money in ways that customers might never even notice. To Bob, this was a different way to use the power of the Smart Grid. Rather than use Smart Grid’s control to earn more money, Emerald PUD used the capability to save their customers money.

Another example that Bob cited was the imminent introduction of large numbers of electric vehicles into the system. Their energy needs would shift from petroleum to electricity. Staff wants to have Time-Of-Use pricing for EV charging, which would encourage users to charge during the off peak periods. Bob’s concern is what happens when we have 500,000 vehicles? What happens when every car plugs in at 10 PM when off peak rates kick in? The heaviest drain on the system occurs during the initial part of the charging period, which would be between 10 PM and midnight. There will be a significant load from 10 -12. That kind of predictable load can be made by managed by the utilities - quite cheaply using CCCT’s.

But another way of dealing with this is to allow the utility to control when the charging takes place. This would allow the utilities to initiate the electric vehicle charging when the typical nighttime upsurge of wind energy provides an excess (given the reduced usage overnight) of power. The utilities could optimize their use of this renewable resource while still guaranteeing that the EV’s would be charged by a specific time in the morning. Such an approach would make optimal use of the intermittent wind resource, and it would avoid having to use natural gas to fire up a CCCT to provide the additional load on the system from 10 to midnight. This requires energy management tools “on the inside of the meter”. This leads Bob to conclude “it won’t work if you prohibit the utility from investing in applications on the customers’ side of the meter”.

The rebuttal has been that “aggregators” will come in and aggregate a large number of EV owners and then will sell this DR product at a cost just below the cost of firing up the CCCT. But Bob asks, “Why wait for a 3^rd party to aggregate these customers when the utility is already doing this”, and the utility is already communicating quite effectively with those same customers.

This led Bob to realize that there are a couple of competing models out there in how we set up the role of the utility. These two different perspectives reflect the regional differences in the development of utilities across the US.

In many of the eastern markets utilities sold off generation and are no longer integrated utilities. This structure is more suited to a deregulated market where the assets and services are disconnected and can compete individually. In the west, however, many of the utilities are still integrated and own their own generation. They compete on the basis of a bundle of generation, transmission and distribution assets and customer service. Many of the ideas for how the Smart Grid should be organized are influenced by the needs of these dis-integrated eastern utilities. A deregulated market structure suits their unbundled structure better than it suits the typical western utilities that still operate an integrated model. In Bob’s opinion, “if deregulation is a prerequisite for the Smart Grid, we’ll never get Smart Grid”.

Bob explains that when he was younger he was a grass roots organizer, but even radicals face limitations. He cited Saul Alinsky’s seminal book, Rules for Radicals, on organizing in which he states that if you want to change the world you have to start with the world that exists – not the world you imagine.

When we think about adapting our current electric system, we have to think about the world that already exists. The first thing that we have to realize in the Pacific Northwest is that we have vertically integrated utilities. We have rate-based investments and utilities earn a rate of return over time on those investments. The utilities don’t make money based on a percentage of the services they sell to customers; they earn a rate of return on the large investments that we ask them to make.

We could have them invest in Smart Grid. They could earn money from the Smart Grid, but once the customers have financed the assets they are entitled to the benefits at cost. This is the second important premise that affects our benefit from the electricity system –that it’s our right to have access to these resources at the cost of those resources. As consumers of these investments we should pay the historic costs, not the marginal rates or the market rates. Bob summarized this point by criticizing those that would have us use marginal costs or market rates, “the notion that market rates or marginal rates are the only ones that give economic efficiency is not one that we apply to our housing market or to a fair number of things in our daily lives, because it counteracts the full basis of the investment model”.

To the contrary, Bob felt that consumers were applying the investment model in which you buy things and then use them for the duration of their economic life. That was his second foundational truth about our current Pacific Northwest system.

The third thing to keep in mind is that in the Pacific Northwest, electric heat is common, as is poor insulation. We had a lot of houses built with poor insulation, because the energy in the Pacific Northwest has been so cheap. Retro-fitting houses is still a one-at-a-time process. Lot’s of our poor folks live in these houses. We have to be careful that we monitor the effects of these programs on the low-income sectors. It’s a slow process to bring our housing stock up to a level of efficiency that allows them actually benefit from the Smart Grid.

Bob is not a fan of dynamic pricing. That doesn’t mean that there aren’t good price signals in the system. They’re there, but they exist on the utility side. They buy peak power at the market price. They already face dynamic pricing. If the utility is the vehicle for investing in the Smart Grid, then having the utility affected by the price signal may be better than having the customer hit with it - because the utility has the resources to deal with higher marginal costs. The customer doesn’t have the resources to respond to these price signals. The utility has a economic model that rewards investment, they have access to capital, they have the expertise of the marketplace. Look at the utility to build that grid makes more sense. That’s  how he gets to the starting point of his thinking on Smart Grid

Dynamic pricing:

Smart Grid requires some sort of dynamic pricing to make the incentive effective. Lot’s of different types of pricing models have been tried, and studied. Bob thinks dynamic pricing hurts our most vulnerable citizens and you don’t get the results out of them. Most of the early studies said that 85% of the savings came from 50% of the users. Most of them are college educated and have disposable income to make the investment in the equipment. That makes sense since you need to be educated and have resources to understand how to respond. Several studies that low income users provide less energy savings, since their usage is less discretionary. Few have HVAC, for example. One of the biggest ways to get savings through dynamic pricing is to curtail heating in the winter; this will hurt the poor. He feels that critical peak pricing is about short-term decision-making, but for lots of people “life will get in the way” and won’t be able to respond and they will get penalized. He went on to assert that most of the studies of how dynamic pricing can work efficiently has been predicated on applications that can respond to these price signals automatically. Our grid can be smarter but our customers can be dumb and distracted. How do we get the stuff to happen without making the customers’ life immeasurably more complicated? He wants smarter appliances (to offset the dumb and distracted consumers).

To demonstrate this point he cited the Utah example of coordinating the use of HVAC over a local grid. The efficiency can be achieved from appliance set points, and less from dynamic pricing. He would prefer that the utility make the decisions on how to manage willing customers’ usage in a dynamically priced environment – rather than leaving that complication to the consumer. He prefers that the utilities control this process which they can do more cheaply that the consumers

What about privacy issues?

Much of the privacy issue is paranoia in Bob’s opinion. He tends to be less concerned with these privacy issues. The notion that Al Qaida might turn off his hot water worries him, but not enough to keep him awake at night. Most of these programs will be opt-in and customers should be able to set their own security levels.

Micro-Grids

He thinks that micro-grids and technologies that allow distributed generation offer some exciting opportunities – even at the local neighborhood level. Bob thinks we can begin to look at “a block as an energy system”. A lot DR and Smart grid technologies are inherently small scale.

What about Innovation?

Is Bob concerned that allowing the utilities to control the customer side of the meter, as his prior comments suggested? Utilities are not supposed to be experimenting and taking excessive risk. But they can buy technologies on the wholesale once the programs have been shown to work. They can buy this innovation using competitive bidding. You pull this innovation at the wholesales level.

Opt-in?

How about introducing TOU rates, but allow customers to opt out? Bob would prefer to allow customer to opt into DR, or DLC programs to make it simpler for them.

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Smart Grid and Customers

Lauren Shapton, PGE

Manager of Mass Market products

Barbara’s first job at PGE was being Conrad’s research analyst, so she has been examining customer attitudes for along time. And she supported Bob’s position that the complications that the Smart Grid introduces are a real problem. They were running several panels on home automation, but the moment they introduced the idea that the consumer was going to have to control their energy use, they became “livid”. They didn’t want control. It taught her that “what energy wonks want and what customers want are two completely different things.”

In 2000 she was hired to help customers take advantage of interval data. So now we’re ten years later and PGE is finally beginning to deploy interval data now.

PGE has always focused on customer satisfaction. She then explained how PGE did their generic residential customer segmentation. Most of it was based on their income and the type of housing they have:

• Country Traditional 12% - $123 – “past gas” beyond distribution reach of NW Natural. They have higher bills because they’re all electric. They tend to have higher bills.
• Suburban Affluent 38% - $94 – they’re not just suburban, they’re higher income users across the territory. They have higher bills because they more “toys” and larger homes. They may have gas, but they also have electric.
• Metro thrift 26% - $82 – north Portland, living in apartments. Apartments tend to be exclusive electric users. Their bills are not so high, but for their income they’re relatively high. They don’t fit our energy programs,  so PGE tries to have options for them that get around the split incentive barrier.
• Urban Mosaic 24% – the ethos infuses our entire territory - $72 – this group tends to exist only inside Portland – the “Portlandia” segment – not mainstream. This ethos does infuse their territory – way more green, way more concerned about global warming.
• Commercial segmentation is based on the type of businesses that they run.

In everything we do, PGE tends to think about these types of customers. Unlike Bob, who wants to keep the customers out, PGE wants to include them. They want to design programs that provide an interaction that is suited to the segment and the type of interaction that they are seeking.

Customer interactions:

• Minimizer – convenience bases
• Reactor – issue based
• Self directed – give them information and they will take it from there
• Assisted – wants some help, but allows PGE to control the rest.

PGE’s paper-based bill has very effective outreach. Their on-line format was state-of-the-art when it was introduced, but is no longer as full featured as it should be.

In 2009, they did a customer focus group on the Smart Grid. For some it meant that one person would be able to give them more in-depth help, but for others it represented a more impersonal, de-humanized system.

The focus groups revealed that customers wanted to partner with PGE; help them save money. They wanted PGE to improve the environment and they also wanted to be part of a larger community effort. Ultimately, the PGE customers wanted to be in charge. That may mean controlling it or ignoring it.

Reflecting upon her 16 years at PGE, she found that the programs that worked the best “are the ones that really makes sense to customers that we’re (PGE) is doing it”. If they see why PGE is doing it and they see it’s good for both PGE and themselves – then they support it. The ones that are “out there” didn’t work as well.

Looking at it from the utility’s perspective, Barbara showed how the peak usage was really expensive. PGE is just barely a winter peaking utility this peak load is about 20 hours per year. That’s why PGE wants to introduce Smart Grid, but she’s “with Bob” in that they want to do it right. She sited the example of Southern California Edison that introduced interruptible rates many years ago and told customers that it was cheaper every hours and they said that they would “never” interrupt power. They sold these cheaper rates to lots of customers for whom it was highly inappropriate, like libraries and nursing homes.

How is PGE compensated for selling less power?

PGE acquires saved energy from the Energy Trust of Oregon. Customers pay for the saved energy and PGE’s expenses are spread over their overall rate base. They basically charge the consumers a little more for a little less energy.

Barbara then explained the topology of the Smart Grid. When she got to the “customer portal”, she said that she simply “didn’t buy it”. In previous tests and focus groups she found that consumers tended to look at these monitors once and then forget about them. In her opinion, “the future is really in an app – something you can have on your phone –just like financial apps that show when your balance falls below a critical level”. The Energy Trust has a program called the Killawatt – which allows you to check out such a device. She summarized the problem as, “once you know…you know!”

Customer portals won’t work. You need to give customers something that provides value. You want to get a little more information so you can do a better job for them, and extend it from there. Make it something that is useful to the customer, but on their terms.

PGE is using Energy Tracker which will allow customers to see their internal data. They’re using a tool called Aclara (used to be called Nexis). It was started from a total geek, nerd format that required a lot of very technical information, but it did give you excellent information. Now the program offers some basic information, but if you tell it some more information it will give you better information.

Barbara then showed the various software screens that broke out the customer usage information. Aclara has a very sophisticated engine to analyze household usage – it’s based on the average user (localized) until you provide information that will allow the program to customize the analysis for your case. This will help customers manage the right things, such as changing the furnace filter rather than getting the kids to turn the lights off. It has phone alerts, but not analysis. The analysis considers hourly data (commercial is 15 minute intervals) and will be able to tease out the actual appliances, externalities (house guests) and adjust for the local weather.

PGE is also using O Power to show how usage compares with they neighborhood. PGE is working with the ETO and is part of a pilot that will be sending out letters. Their first letters got some vociferous responses, when people were outraged about how they compared with their neighbors.

Energy Tracker – they’re just starting to pull customers in to start using it. They will be able to advise customers about why their bills are running higher. They’re working with low-income customers to help manage their bills – even contacting them mid-month if they spot anomalous usage. It will ultimately help people choose the kind of TOU program, based on their prior usage.

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Intel’s Eco-Tech innovation office

Scott Schull, Intel, Director of Smart Commercial Buildings

Scott began by discussing the general context starting with “Planet Earth”. Currently mankind is consuming 1.5 times the resources of the planet and at current projection will be soon be consuming double the planet’s resources. Clearly consumption is outstripping available energy.

Only 2% of that energy requirement is being fueled by the demand from information and communications technology (ICT). Intel wants to use their smarts to solve the problems in the other 98%. Looking at it from another perspective, mankind build it’s first billion personal computers sometime during the 3^rd quarter of 2003. But we will have doubled the number of extant PC’s by 2014. However these computers will consume only half the energy while at the same time increasing their computing power 17 times.

Intel’s Eco-Tech innovation office

Intel’s Eco-Tech innovation office is a small group of people that are working across all business units to make the products more energy efficient and built in a sustainable manner. They are particularly focused on these areas:

• Water
• Buildings and home
• Transportation
• Extreme events

Intel has delivered a “proof of concept” of the home energy management product to the market. They are also developing technologies that will be able to listen to the current and “tease out” whether the appliance being used is a toaster or a hairdryer – within the next 2-3 years.

To do this requires some the development of some fundamental technologies.

These solutions can be designed along proprietary approaches, but Intel feels that to support more rapid diffusion of innovation this development should be done using open standards.

SG could help residences reduce energy consumption by 31%. SG could help commercial buildings by 10%. This means not just weatherizing, but also what you could do if you were able to provide real-time information. If the feedback units have the same technological basis you can deploy this capability across the world.

Bouygues Building project in France.

After 2020 French will require new commercial building to be “energy positive”. This is called the Grenelle d’Environment. This commercial complex is being built outside Paris. It’s currently rated as being “net 2 positive energy” – eight years ahead of the standard. They’re also exploring a micro-grid by tying together commercial building in a commercial campus. They haven’t integrated any EV. The windows are double paned with argon filled with photo sensitive strips on the outside. They have installed 20,000 sensors in the building for 1,000 employees and tying it into the building management system – not to push the occupants but turning the lights off behind them.

The Oregon Sustainability Center

PAE (Portland-based) did a study for the Oregon Sustainability building to understand how the energy use is distributed. The Sustainability Center is not a positive energy building. It’s designed to be a net zero: energy, net zero: water, and net zero: waste - within one year. The study showed what the typical consumption of a commercial building is. If you installed all the state-of-the-art energy efficiency you can save 63% of the energy – but you haven’t really engaged the tenants. To get up to 75% saving using the tenants you need to give them information about the impact of their behavior, or set policies. Intel is prototyping a personal energy interface, called POEM. Most people don’t like pie charts; Intel has adopted the garden as a visual metaphor for their personal energy manager. Intel will be proto-typing it with Bouygues Immobilier and the Oregon Sustainability is interested in it, too

Behind the scenes these tools combine the information about how the building is operating. They’re working with Allen Bradley and Schneider to collect the building performance and they merging it together with the information that it coming from the IT sensor database. You can analyze the intersection of those two loads and get some interesting information about how to control the energy use. So far it’s not tied together with “health, life and safety” issues. But there is a clear use case for it since you have much finer grain information.

Intel is also working on similar techniques applied to water usage. That’s probably another 5 to 10 years in the future. Schull also referenced crowd-sourcing information for disaster management using cell phone information. Finally, he reviewed some of the seed investments that Intel is making to support innovative solutions.

Class # 7 featured an energetic presentation by the OPUC's Robert Procter and a measured response from one of the founders of the NWPCC, Roy Hemmingway.

An overview of Economic, Institutional, and Rates issues affecting Smart Grid (SG) adoption, and OPUC SG activities.

-       Robert Procter, OPUC staff and lead for Smart Grid lead

Robert Procter is in charge of the Commission's investigation of what requirements should utilities meet as they plan and invest in modernizing the electric system. Some of his time is also involved in working on, but not leading, the Commission's investigation on infra-structure and power rates in support of electric vehicles. He is the commission's point person for the Smart Grid. U.C. Berkley grad with Masters in Agricultural economics and 19 years on the BPA staff.

In keeping with someone who gives a prominent place on this resume for his extended time living and work in the remote community of Joseph, Robert gave a boisterous presentation of the challenges facing the adoption of the Smart Grid.

He started with an intriguing analytical structure for examining the development of public policy. This endeavor, he asserted could be subdivided into three parts:

Framework for policy:

-       Structure

-       Conduct – what do you have to change

-       Performance – where do you want to end up

Where do we begin to consider the structure? Let’s look at what’s out there. What’s written on the subject, etc?  And we find that “we have this patchwork quilt of oversight over the Smart Grid adoption”.

Proctor’s assertion is that “one reason it’s hard to come up with a systematic strategy is because this patchwork quilt makes it difficult to get to some solution.”

Robert Procter’s initial thesis was that:

“The vast majority of SG actions, applications, and benefits will be determined by policy enacted into law at the state level and/or by state-level (includes sub-state level) private and public stakeholders taking action.

• The majority of emphasis in writings, panel discussions, conferences has been at the federal level.
• Once you move off of the bulk power system you move from the federal to the state, and sub-state, level.

It’s hard to envision a systematic SG strategy since the supervision is scattered and incomplete:

-       Feds have little role in most SG adoption matters.

-       Local jurisdictions usually have code development/enforcement powers.

Locally the oversight is handled through:

-       OR utility rates proposals, and

-       Nearly 40 different entities involved

-       Including many participating NGO’s (e.g., SGO).

The division of Federal and local oversight adds to the complexity:

-       FERC has legal authority over rates for the bulk power system for both power (includes ancillary services) and transmission products (think transmission. i.e., lines > 115kV).

-       State Commissions have authority over all other power rates.

-       BPA Transmission rates impact IOU cost of service for power delivery.

-       Link Between Residential Exchange and IOU Rates.

At the sub-state level there is also regulation that affects the implementation of the Smart Grid, such as:

-       Local jurisdictions generally have the oversight of the respective building codes and processes.

-       Homeowners (and condo) associations also exert some control.

-       And owners preempt renter’s influence.

Here are a few examples of how these jurisdictional conflicts:

o   Sub-meters installation permitting and inspection issues.

o   Building codes and building systems control integration

o   OR law requires use of utility-owned meters,

o   Homeowner (and condo) association control over EV charger installation

o   In some locations in California the installation of AMI has even been criminalized!

So what is the Jurisdiction of the Oregon Public Utility Commission?

The Oregon legislature has defined the OPUC Mission as, “Ensure that (private utilities provide) safe and reliable utility service…(that rates) are just and reasonable…while fostering the use of competitive markets…”

The OPUC has economic regulation over IOU’s in electricity and Natural Gas. It has little influence over COU’s. All COU’s manage their own businesses including setting rates. The OPUC has no authority over non-utility private parties (e.g., third providers of equipment to utilities or to customers of the utility). It has very limited ability to consider costs other than what utilities incur to provide service to its customers. For example social issues, such as the impacts of carbon emissions and/or the economic development (Job creation) aspects of Smart Grid are outside its purview and writ. Even though the risk of regulatory change that may lead to higher costs can be included in their deliberations, the Commission has much greater ability to consider the costs of enhanced reliability as opposed to the fairness and societal costs. The OPUC also has more ability to consider “fairness” than societal costs. Once requirements are defined in law – then the OPUC only interprets the law. It’s not optional.

The question was also raised as to whether privacy issues may affect OPUC’s jurisdiction over Citizen Owned Utilities (COU)? And indeed they partially affect that jurisdiction. At a much higher national level there has been a wrestling match over whether “the energy folks and the security folks” have control over the development and implementation of the Smart Grid. For now the energy folks are in control.

Who is controlling the development and implementation of the Smart Grid by the COU’s? There are 36 COU’s in Oregon and each has its own board of directors, which in some cases are the local municipal or county governing body. These supervisory councils are ultimately accountable to customers. Typically the Director of a COU reports to the city council. Fundamentally, though, the OPUC has little authority of the COU’s.

However, these COU’s purchase almost all their power from the BPA, so there is a potential to address the oversight issue via the authority of the BPA. But the BPA has always been very sensitive about the degree of influence that it seeks to overtly exert upon its client utilities.

The OPUC’s regulatory “posture”:

What Robert means by “posture” is where and how the OPUC can weigh in on the issues affecting the implementation of the Smart Grid and the strength and clarity of their mandate to regulate in the interests of a more efficient rollout of the Smart Grid.

Given the forgoing discussion about the patchwork quality of the oversight and the depth of the regulatory framework that is affected, it is not surprising that the OPUC is not as proactive as some might like it to be. The current regulatory structure puts the Public Utility Commission in a reaction-based mode. The legislature “proposes” the extent and scope of the oversight and the Commission “disposes” the oversight. The commission responds to the utility proposals.

That is what the Dockets UM1460 and 1461 are all about.

The OPUC hold the right to exert economic regulation over the IOU’s. In return for being granted a monopoly franchise the IOU’s have agreed to cede economic oversight to the OPUC. This was the essence of the fundamental bargain first struck by Insull when he realized that the public benefits derived from consolidated monopoly investment were far more efficient than unfettered completion. This economic oversight was designed to assure that customers got the benefits of lower costs typical of a natural monopoly, while the utilities were allowed to earn an allowed rate of return.

In summary there are two points that Robert wanted to emphasize:

-       The commission has jurisdiction over only a portion of the electricity delivery market. It is the final arbiter of what costs the utilities can incur and what rates they can charge. The mandate is pretty substantive, but …

-       The commission is in a responsive mode reacting to proposals put forth by the utilities.

-       One more

Some economic/financial issues affecting the implementation of Smart Grid adoption include:

-       Discount rate – what’s the cost of capital? The cost of capital is a HUGE lever and affects whether the programs pass the cost benefit tests on a SG investment.

-       Payback requirements – it passes the benefit cost test, but we don’t get our money back fast enough. Is the payback period appropriate?

-       Fed and state tax policy – we see this with appliances and solar investments - rebates, tax credits and tax deductions.

-       Local tax incentives/disincentives – back in the ‘70’s there were cuts in property tax for solar implementations.

-       Projected building ownership length – residential, but also an issue for commercial buildings. This also includes the “split incentive” problems arising from the different time periods affecting the owner and tenants of a building.

-       New use of existing commercial buildings – how does the HVAC system complement or make it more difficult for the new use?

The Commission also considers the rate design options. Smart Grid rate options include:

-       Flat energy rates – kilowatt hours that we consume over time

-       Tiered rates (inclining and declining blocks)

-       Time of use rates – we actually have voluntary TOU rates in Oregon. PGE has also got a pilot project using Critical Peak Pricing. Rates that have Time Of Use usually have at least three periods.

-       Variable Peak Pricing is slightly different. It is the hybrid of Critical Peak Pricing and Real Time Pricing. Robert indicates “Real Time Pricing in theory goes down to the second/minute, but if you can get it down to the hour you’re really accomplishing a whole lot”.

-       Robert, speaking with his economist hat on, says that without these mandatory rates, Smart Grid benefits are being left on the table.

Smart Grid allows for greater variation in rates by time – than we can do today. So we can have a whole lot more variation in our rates than we have today. We can apply technology in to monitor outages and get faster outage response. But to get better system efficiencies we need to get prices signals that reflect what the system costs to provide electricity by time of day.

Robert then quickly reviewed the Commissions’ 4 types of procedures:

1.    Ratemaking – very formal, very legalistic

2.    IRP

3.    Generic investigation – much more flexible

4.    A way to change administrative rules.

The OPUC decided not to define the Smart Grid:

Robert feels that doing so would have been a great waste of time.

What does the staff do in the development of orders, such as in the UM 1460 docket?

-       Staff develops timeline

-       They scheduled pre-hearing conference where parties worked out mutually acceptable schedule for ALJ review and approval.

-       They developed and issued straw proposals, prepared initial comments and closing comments.

-       Hemmingway pointed out that the OPUC tends to works on orders, rather than engage in rule making – which require rule-making proceedings. Hemmingway stressed that in this case of responding to an order, “We have yet to see exactly what the commission is going to rule on”.  In a rule making procedure the citizens would see the rule, but in this case it is entirely up to the administrative law judge The OPUC staff also is not included in the deliberation.

The staff and the commission and the staff do not interact in a formal (or informal) way. Staff is a party to an investigation, just like other interveners. The Commission may not privately discuss the investigation with the staff.

Robert’s final question was, “Where is the consumer in all this development of the Smart Grid?”

This concluded Robert Procter’s comments.

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The Smart Grid a Multi-Institutional Approach:

- Roy Hemingway

Roy Hemmingway, was the OPUC commission chairman. He was one of the original members of the Northwest Power Planning Council from 1981 to 1986 appointed by Oregon Governor Victor Atiyeh. Hemmingway graduated with a BA from Stanford in 1968, and a Law Degree from Yale University in 1972.

Robert began his presentation by asserting that wanted to broaden the discussion from what Robert Procter had presented. He reminded us that electricity was a unique product.

-       Buyers determine how much is produced,

-       The same amount must be continuously generated or the grid frequency drops until the system collapses.

-       And, finally, the seller cannot refuse to supply electricity.

His second point was that “not all kilowatt hours are created equal”.

The value of a kilowatt varies by:

-       Location – the proximity of the energy source and implicit line losses

-       Time of day – changes related to the daily load factor

-       Time of year – seasonal and weather related changes

-       System status – constraints, capacity

-       Predictability – weather events, grid events?

-       Reliability – hydro is relatively predictability; Trojan was only about 50% reliable.

-       The sustainability of the resource producing it.

According to Roy, the Smart Grid can deal with these issues to improve value of kWh. The traditional set of relationships between the energy generator and the energy consumer can be summarized as:

1.    Utility sells power to customer

2.    Customer pays the bill

3.    Regulator – governs the entire relationship between the customer and the IOU.

4.    Customer has no role but to consume and pay bill

The Smart Grid will fundamentally change this relationship. It will, as a consequence:

-       Promote the more efficient use of the electricity system.

-       Facilitate the use and integration of renewable energy

-       Encourage the development of new uses and new markets.

-       Integration of new types of generation

Roy then focused on one prosaic example: Water heater load:

After considerable discussion it was agreed that there was approximately 8,000 MW in the Pacific Northwest (85% of water heaters are electric). This is about the same as the wind power generation capacity.

Water heaters are useful to control for:

o   Power loss emergencies

o   Reserves

o   Balancing

o   Economics

Controlling the water heaters is a good idea for all the foregoing uses. SO how do we make it happen? As obvious and easy it appears; it’s not!

When we bring in those other parties into the relationship it complicated the issue. So let’s look at these different parties.

-       Government(s) – (or trade assn.) set codes for control equipment, mixing valves, plumbing and communications so that all water heaters will act together.

-       Business –design equipment, react to proposed code, builds new water heater, innovate new equipment and uses aggregate customers.

-       Customers – who actually gets the consumer involved?

Who will control the water heaters?

-       Utilities – reward customers for installing new water heaters and allowing control. Will they control it or will customers do that or will there be a third party to do so?

-       Customers – buy new water heaters and contract for control.

-       Regulators – decide who controls the water heater for what reasons and compensation to customer for control.

When you consider this simple example you can see how easily it can become incredibly complicated – even though it’s a no-brainer. More complex issues become excruciatingly complex. Roy’s point was that in addition to the important work needed to be done on the technical and regulatory side, figuring out the institutional relationships to make it all work together will also require tremendous work.

- Ken Dragoon, NWPCC

The Northwest Power Conservation Council was established by federal legislation to provide regional guidance on energy issues. The governors of the four Northwest states, Oregon, Washington, Idaho, and Montana appoint the Council members. The Council reviews regional power plan at least every five years and recommends funding for fish and wildlife programs to mitigate effects of hydropower development. It encourages broad public participation in regional energy issues. And it enjoys widespread credibility for its regional energy forecasts. They’re a multi-state compact – not federal agency.

Pie chart of NW energy installed capacity: Hydro 57% – “name plate” capacity = the resources are technically rated to be able to deliver this capability, without other constraints. Wind 9.75%

We can’t get all the hydro potential. We can’t load those resources all the time, because there isn’t enough water to run it consistently. We get about 40% from the hydro resources. This graphic represents energy potential in the Pacific Northwest, excluding those portions of Montana on the eastern side of the Continental divide.

Also energy capacity of Hydro is 48%

Rapid growth of wind

Ken Dragoon’s talk focused mainly on wind since he sees it as “motivating a lot … of activities in Smart Grid”. Show historical development since 1998. There has been a tremendous expansion in wind projects between 1998 and January 2011. He also discusses the solar projects and wave energy projects.

NW wind resources (name plate capacity) now tops 5,000 MW with another 2,000 MW under construction. This is a big change that has come to the PNW.

How and why is this happening?

-       $20/mWh production tax credit for the first ten years of production – when economy crashed it was changed to an investment tax credit and later into a grant program.

-       The states have renewable energy targets:

o   Montana, Washington and Oregon have an RPS

o    Idaho is lagging.

-       State Tax credits and incentives:

o   Oregon has the Business Energy Tax Credit (BETC)

o   Washington has a sales tax exemption

o   Montana has a sales tax exemption.

Ken was recently in China and discovered that they were accelerating their investments in renewable energy resources. China announces that they will get 1% of their energy from renewables by 2020. They are now #1 in wind installation. They cite climate change as the reason.

PNW has been growing by leaps and bounds. DOE did a study to see if we could hit 20% by 2030 – that would mean a 4 x increase. This is a big change. 5,000 MW of wind in the PNW now – Montana is 3^rd to 5^th place in terms of available wind resources. And it’s almost entirely untapped.

Wind poses challenges such as problems of accommodating the excess energy events. This is a variable resource and it’s hard to predict. We may know when a storm is coming in, but not exactly at what hour, so we could miss the event by as much as 3 hours and this is a huge amount in terms of scheduling.

They do have a reasonable notion of what will happen the next day, but not always what will occur on the next hour. In order to deal with this variability the energy system operators retain a generation reserve that is ready and willing to come up, or be turned off at a moment’s notice. This is not an entirely new problem, but with the amount of wind hitting the system now, it represents more events happening with greater volatility. Initially there had been a great deal of concern about this variability, but with more experience the energy system operators have become savvier.

One way to view the variable is to consider it as a reduction of load. The remainder represents our net energy resources. To the extent that wind differs from the forecast (load versus wind) the difference has to be taken up by our flexible units in generation reserve. Each balancing period is an hour; they may be shortened.

Review the reserves shown on the BPA site – 5 minute data on their system. It shows about 850 MW of reserve including that portion that can be decreased (“decs”) and that portion that can be increased (inc’s”).

-       Chief among power system operators concerns– having sufficient capability to increase or decrease generation levels as the combination of wind and load vary.

-       Larger impacts to balancing areas transmitting wind to meet demand outside their territory.

o   For example, Montana has lots of wind but little balancing generation or native load.

The balance of Ken Dragoon’s presentation concerned it self with various actions that could be taken by the various balancing authorities to increase the efficiency of the gird, such as:

-       Unifying trading practices to allow half-hour trading.

-       Implementing automated within-hour trading.

-       Sharing of imbalances across time and geography on sub-hourly timescales.

-       Consideration of Balancing Area Consolidation.

Ken then presented information from the National Renewable Energy Laboratory (NREL) that suggested that incremental improvements in the gird would likely permit us to reach the 20% threshold. He also cited the Irish study that suggested that even at 41% penetration of wind no storage was needed.

Finally he discussed the Danish model.

-       Denmark uses “waste” energy from power plant cooling systems to heat 60% of all buildings in district heating systems.

-       Large insulated hot water storage facilities decouple electric generation from building space and water heating needs.

-       At times when wind generation exceeds load and export capability, power can be used to heat water in storage facilities.

How does this example of using water heaters translate into the Pacific Northwest?

In the PNW we have more than a 2,000 MWa electric water heater load and a more than 4,000 MW of coincidental peak demand.

And how does this water heater capability compare with other storage technologies?

-       Very low losses compared with most other technologies.

-       Very low cycling costs and long lifetimes little affected by cycling.

-       Cost mostly proportional to maximum energy storage– not as sensitive to power levels.

The NWPCC is looking to implement end-use control strategies in the Northwest:

o   Electric Water Heaters

o   Electric Space Heat

o   Commercial and Industrial Processes

o   Municipal Water Pumping/Storage loads

We must change the paradigm so that demand is adjusted to meet supply. Henrik Bindslev, the Risø Director said it best. “The Danish power system will move from one where supply responds to demand, to one where demand responds to supply.”

_________________________________________________________________

Smart End-Use Energy Storage and Integration of Renewable Energy

Diane Broad, Principal Investigator/Recipient, Ecofys US, PE

Our final speaker of the evening was Diane Broad, who spoke about Ecofys’ projects to validate the energy storage concept using water heaters. Ecofys is a 300-person renewable energy company. Her focus is on how we generate power, how do we connect the grid, and how we make the grid more friendly to renewables.

The purpose of the project was to facilitate the rapid development and deployment of end- use controllable loads, providing both balancing services in the BPA balancing area and localized benefits to BPA’s customer utilities.

The initial scope of the project was to develop 1MW to 3MW of demand response with energy storage, in the service territories of 3 Consumer-Owned Utilities (COUs): Lower Valley Energy, EWEB and Cowlitz Co. PUD.

The project intended to deploy Steffes Interactive Water Heater Controls on 50 and 105 gallon water heaters, and Steffes Electric Thermal Storage whole-house furnaces (Residential). Steffes is based in North Dakota where water storage makes a lot of sense because of high differentially energy prices between night and day. For the Commercial and Industrial segment of this project EcoFys has partnered with EnerNOC to deliver their DemandSMART solution into cold storage warehouses.

One of the key technologies that Ecofys tested was the technology’s ability to “Control & Dispatch”. Thus the water heaters had to be accessible to both increase and decrease loads in response to need for balancing in the BA, and for cost savings to the utility. They tested several control methods, control signals and dispatch options.

During the 12 – 18 month operation of pilot programs, Ecofys planed to develop both technical and economic optimizations; create a Guidebook for Utilities including a business case and technology overviews.

On the residential side the project will install a 105 gallon water heater with iWHC (a thermal battery) that heats water to 170° F . The unit includes a mixing valve for consumer safety. This will be used for effective use of water heating as DR resource. For space heating and cooling the project includes a ETS Furnace, Forced Air or Hydronic. This is equivalent to a 10x larger battery and coupling it with air-source heat pump increases the efficiency even more.

For the Commercial and industrial applications this project is using an EnerNOC Site Server (ESS), a gateway device that establishes communication with the network and provides near-real time visibility into end-user energy consumption. The ESS also allows the NOC to remotely control loads in order to deliver demand response capacity.

EnerNOC’s two Network Operations Centers (NOCs) are staffed 24x7x365.  They feature advanced technology and a specialized staff to ensure that load reductions happen quickly, efficiently, and consistently for both the utility and end users. Finally, EnerNOC web-based energy management platform, PowerTrak® monitors energy consumption and enables end-user load control. DemandSMART also provides end- users with a web portal, and utilities with the ability to view load increase or decrease during demand response events.

Diane talked about the progress of the project with its many partners and diverse hardware solutions. Needless to say the project was delayed in some aspects and is only now starting to make progress – now that all the partners are on board.

Expected benefits for the Consumer-Owned Utilities:

The benefits for Consumer-Owned Utilities (BPA served utilities) in the region include the ability to implement very flexible resources when they deploy controllable loads like those in this project. The benefits include:

-   Cost savings by reducing peak demand charges

-   Cost savings by changing the utilities’ load shape, shifting energy use towards or away from certain hours of the day

-   Potential revenue from sale of balancing services

-   Potential for delaying investments in distribution system (substations, lines) by implementing grid-responsive control modes.

The Benefits for the BPA?

The BPA is searching for new resources for balancing reserves in part due to the increased impact of the variability of wind energy on the BPA system, and looking at energy storage options. Apart from these benefits, controllable loads have value to the BPA for load shifting, short-term curtailments, and load shaping.

Benefits for the Renewable Energy Industry?

This project introduces new resources for providing balancing reserves possibly contracted directly from the COU’s as self-supply. It provides an Economic Stimulus/Job Creation benefit since the installation of new water and space heating equipment creates jobs in the trades. Wider-scale implementation could have spin-off effects and synergies with other Smart Grid initiatives.

BPA cost/revenue impact:

If this project can validate the effectiveness of using water heaters, hydronic systems and the EnerNoc energy management tools, the BPA would get a new resource for balancing reserves and energy storage at lower cost than some other alternatives.

When implemented on a larger scale than these pilots, the use of controllable loads with storage is expected to provide a resource on the lower end of the current market cost for reserves of $5 to $15 per kw- month.         This project intends to clarify those costs. So far the Steffes ETS has been shown to cost 1⁄4 to 1⁄2 of competing energy storage technologies like pumped storage, CAES, batteries and flywheels.

DR is not just about curtailment but also about both increasing and decreasing load to help the grid operator. The Pacific NW has 82% electric water heaters which might be able to provide balancing services. This represents a significant opportunity for utilities to get cost savings by:

-       Peak shaving

Shaping the load throughout the day; shifting load from hours where it usually occu

This will all tie into my discussion with the class about where smart grid investment stands in the regulated world.  And what the potential avenues are for investment.  I’ll be trying to get across that DR in not an overnight resource, that it is not equal to a generating resource, that smart grid is an enormous paradigm shift for regulators most of which still struggle with simple and sensible investment in energy efficiency. We’ll be looking at some recent decisions by PUCs in the PNW on recovery of EE investments and speculate what that means for smart grid investment.

This lecture is a continuation of Conrad’s prior lecture in which he outlined how the existing Grid worked. In this presentation he poses the question, “What are the benefits that we derive from the Smart Grid?”

To start with let's review some of the more obvious benefits that accrue from the Smart Grid:

1.     Increased energy efficiency

2.     The ability to integrate variable energy from renewable sources

3.     Improved asset utilization

4.     Carbon reductions, by virtue of the increase renewables and less line loss

5.     And finally a more reliable grid with fewer outages, etc.

Increased energy efficiency:

But aside from some cost savings for the utility (no more meter readers) smart meters has no inherent benefits – all by itself. Some people refer to smart metering as the “foundation” or prerequisite for AMI (Advanced Metering Infrastructure). What does this mean?

It means that for the next generation grid to function more efficiently it can no longer be deaf and dumb; it will need to communicate information multilaterally across the grid. And for that we need to develop a standard for passing data between the discrete elements of the evolving grid. It will need to provide the interactivity that will empower 3^rd party aggregators and integrators to optimize the utilization of assets and multiple energy streams.

And that means knowing a lot more about the end-user. Therein lies the start of another major challenge to the evolution of the smart grid: privacy concerns.

Until now end-users have been oblivious of their energy usage and its pricing. But with the introduction of AMI (and variable pricing that it could enable) we have the opportunity to introduce the “invisible hand” – the curious concept that Adam Smith introduced in 1776 to explain the role of pricing in regulating demand and supply the marketplace.

PGE’s current implementation of AMI: PGE uses a “census” system that utilizes a tower-based approach which are fewer in number, but taller. They can aggregate 20,000 to 50,000 meters. Some utilities use a “mesh” network that runs collectors located on power poles or even meters to aggregate 1000 to 2000 meters. Most of the PGE meters talk to the tower using a licensed narrow band frequency. The data that is collected from this network, and others is collected in a meter data management system that allows you to collect and sort data for different applications. PGE is getting a web portal from Aclara that users will be able to gain access to their own data – using secure log in procedures.

PGE does have multiple AMI systems, including an industry standard MB 90 system, some types of meters that they can read via telephone modem and even 2,000 dedicated units that were installed using SmartSync that communicate over dedicated “comm units”.

So now that we have the physical underpinnings of a smart grid in place that can provide detailed usage data. How can we use it since it’s pretty boring stuff on its own? How can we get the end-users to engage with this data?

From Conrad’s perspective as a utility representative, initially the utilities will have to educate the consumer about the importance of the variable rates.  The variable rates and Smart Grid do not guarantee that their bills will go down, but if they ignore the variable rates their bills will likely rise. He continued, “Then we’ll get smart appliances, but we’ll have to teach the consumers that even though the appliances are smarter it does not allow the utility to control their homes. Eventually, we should arrive at point of collective understanding where the consumer comes to understand both the rates and their ability to respond to them.”

“What does that accomplish”, asks Conrad? Customer education will take years to have most of their customer base to understand variable rates enough to be able to respond to them effectively. Consumers have never really had to be conscious of their energy usage, but with Smart Grid and variable rates they will become more responsive. PGE will use information to teach consumers about efficient energy usage. Customers are more likely to take “tips” from the utility.

Conrad’s opinion is that the real time energy monitors will have little impact after people look at them once and then forget about them. But a real time energy management system will have value once we have smart appliances.

Integrating Renewable Resources:

The real benefit of the Smart Grid, according to Conrad is in integrating the renewable energy resources. By 2025 we will have to integrate almost 2000 MW of wind energy that is highly unpredictable. In contrast all the preceding discussion about Demand Response was targeted at addressing an occasional capacity constraint amounting to about 800 MW. The ability to facilitate this integration of renewable energy will be a huge challenge, according to Conrad.

Improved asset Utilization:

Improved asset utilization is a goldmine. Most of the peak demand comes from residential appliances. Unless you can find an easy way to operate energy savings programs to address these efficiencies, you won’t get much traction. Conrad’s contribution to this problem has been to champion a standard interface for appliances. Theoretically, such an interface would provide a 10 to 1 benefit/cost ratio that will hugely improve the utility for the consumer and boost program adoption. Cites his study with Whirlpool and PNNL.

Now Conrad explained a load duration curve that shows how much additional power is needed for a short period. Utilities have peaking plants to meet only this high demand. If we can reduce peak demand we can reduce very expensive power.

Carbon reduction:

Conrad sees electricity as the most efficient form of energy. “Just look at history.” he says, “we started off burning wood. That was very inefficient. Then we turned to coal” … that allowed for hotter temperatures and more sophisticated applications, including the development of powered machinery that stoked the industrial revolution. Today we are moving through a period of natural gas use, but Conrad sees that only as a transitional step to a final phase in which we will be using electricity that is entirely produced by renewable energy.

More Reliable Grid:

This benefits gets a lot of attention. Outages do cost money. The question is who is going to pay for more reliability and who will want a discount for less reliability?

Conrad then supplied a rudimentary estimate of what it would cost to pay for the structural improvements that would enable self-healing and a more reliable grid.

• Automate Switches per feeder – $100 Million
• New Substation to allow alternative Feed – $50 mil
• Upgrade and new Feeder circuits – $20 million
• Engineering and Management Application – $50 mil

The total cost would be around $26 mil per year, or about $3 per Customer per month. This would reduce outages from 105 minutes per year to only 20 minutes annually. This increased cost cannot be justified if it is all applied to the customers, so we need to look for other cost savings that accrue from this investment.

Decreased line losses of about $5 million/year would apply. Improving the rural distribution network would bring in about $9.5 million/year.

Decreased overtime for line crews adds another half million, but in the end that only covers about 43% of the costs. So we really need a better business case to justify the cost of improving the reliability of the grid.

The Real Killer Reliability App:

The real “killer app” of in achieving more reliability is the home storage back up system. Customers would pay about $10/month. The Utility would pay for most of the cost and the maintenance so that the utility could use the batteries in a non-outage period (most of the time) in order to help integrate wind energy, supply peak demand and reduces line losses on peak. Battery costs need to come down to make this work, but lots of people are working on this.

Conrad also mentioned the PGE ARRA funded Battery project in Salem that has installed a 1,3000 kWH battery project.

In his concluding remarks, Conrad stressed that all these benefits depend in part upon much greater customer participation and that will take a long time to achieve.

________________________________________________________________________

Smart Grid and Demand Side Management

- Jason Salmi Klotz, NEEA Senior Policy advisor

Previously worked with the CPUC on their AMI deployment. He also worked on demand response wholesale integration. He then joined the BPA to work on Smart Grid integration. Now he’s working for NEEA.

His focus for the presentation was:

• EE and the Smart Grid and DSM (Energy efficiency and Demand resonse and distributed generation).

• The California market has the potential to be the first of the Smart Grid because the way they’re creating their markets.

• Regulatory reality. And where the investment dollars are going.

Energy Efficiency and the Smart Grid impact the whole spectrum – but mostly from transmission to site loads. Energy efficiency within the smart grid will be present on all these areas – from transmission to the consumer. We’ll have the IT overlay on almost all of these sectors and that will give us real time information which will cause a blurring of the distinctions between Demand Response and Energy Efficiency because we’ll have very active management of all our resources.

So we’ll have demand response on a real time basis, which makes it look a lot like energy efficiency resource because you’re constantly managing it and are at that most efficient point of energy efficiency. Now it’s beginning to look a lot like demand side management. Most of us think about energy efficiency as being close to the consumer and the appliances that they use, but you can energy efficiency in the distribution or transmission wires, transformers. In the case of industrial applications, any through put can be tweaked to achieve greater energy efficiency.

When you look at the Smart Grid from a high level it looks “oh, so lovely”, but once you get down to the details it gets very complicated. Jason then promised to give us some examples of just how complicated it can get.

A Nodal system:

The first example is from a regulatory perspective, looking at what happened when California tried to integrate the main output of the Smart Grid, Demand Response into their new wholesale market system. The old system looked a lot like the Pacific Northwest: they had various balancing regions (NP, ZP, SP CA ISO). In the end everything had to be balanced so that the frequency was maintained and the grid didn’t crash.

In CA and New England, PJM and NY the pricing at the node, which can be equated to a substation. You can either inject power into a substation or pulling energy out of a substation.  In California they’re going to start with about 300 nodes and work their way up to 3000 nodes. And each node will have real time pricing at 5-minute intervals. They become essentially their own little marketplace. Anyone taking energy from the node is subject to that price.

For example if your in San Francisco you have one major distribution line that brings energy into the city and its congested; it’s over capacity and that makes the price go up. You have a lot of demand in San Francisco and that makes your prices go up. Even if the cost to generate the power is relatively low ($.05/kWh) in Sacramento by the time that energy reaches San Francisco the price has risen to $.15/kWh due to the distribution costs, congestion charges, constraints and demand.

At this point this transaction is going through one node, but in the future it could be several hundred nodes. The buyer and seller in this transaction are all at the CAISO (California independent system operator) level. The CAISO is the wholesale market in California. They have the demand and they have to find supply to match. Every energy transaction in California goes through the CAISO; every transaction has to be scheduled through the CAISO. Just because the nodal price in San Francisco is $.15/kWh doesn’t mean that the consumers will be paying that price. Currently PG&E levelizes the cost so that everyone pays approximately the same price. PG&E won’t be charging these rates in the immediate future, but maybe they might have to later. San Franciscans are worried about this new system because they see that in the future they may have to pay a much higher cost.

Jeff Hammarlund: So this is another example of the whether they charge a “postage stamp rates” or “railroad rates”. In the Pacific Northwest we had the same issue with regard to transmission rates.

FERC, who is the creator and regulator of these wholesale markets, has been forming markets since they issued Order 888 (www.ferc.gov/legal/maj-ord-reg/land-docs/order888.asp) in January 1998. They regulate the Independent System Operators (ISO) across the country.

Recently in 2007, they issued FERC Order 719, which required that all organized wholesale markets including:

• California ISO
• New England ISO
• New York ISO
• PJM – Pennsylvania, New Jersey and Maryland
• Midwest ISO
• (FERC does not regulate ERCOT in Texas, even though they are an ISO)

FERC Order 719 tries to introduce competition into the Wholesale markets:

With order 719 FERC instructed the Independent Systems Operators that they must allow Demand response to bid into the wholesale market. This was an important change, because until then all that existed in these markets was generation. This created the potential for a parallel, unregulated, demand response market especially in those less mature markets like the Midwest and California ISO’s.

FERC only regulates large wholesale markets, which means that they controlled only the generation of power. However, consumers purchase their power from the utilities that are regulated by state Public Utility Commissions. And demand response exists mainly at the customer, or “retail’ level. With Order 719 the FERC has effectively mandated that all this “retail” DR must be included in the wholesale market. Many people have interpreted this a jurisdictional grab by the FERC.

No states have rules over how DR is to be treated, but with FERC Order 719 all this retail DR is moved into the wholesale markets and the FERC argues it has jurisdiction over all DR. As a result of Order 719, when you send DR into the wholesale markets the FERC rules apply. Otherwise the PUC’s have jurisdiction.

Ken Nichols: Effectively there is no difference between an energy generator and an aggregator of demand response – they can both be used to satisfy energy needs so it makes sense to trade them in this wholesale market. Jason Salmi Klotz: Theoretically you’re right but there are flaws with this approach…

As soon as you send demand response into the whole sale markets the FERC has jurisdiction. But at the retail level it remains under the purview of the states. But not every state is the same, not every state has AMI, not every state has laws to protect customers from aggregators that want to bid it into the wholesale market.

Aggregated Demand Market hinges on unregulated Third Party entities.

Unless this kind of response is aggregated by an LSE (“load serving entity”, any power provider that serves the customer, whether public or private such as PGE or EWEB), it is aggregated by a 3^rd parties. They are also referred to as:

• CSP – curtailment service providers
• DRA – demand response aggregators
• DRP – demand response providers

These 3^rd party aggregators go to electricity users (usually commercial or industrial consumers) and offer to manage their energy usage, including the application of some demand response elements. For example, they might go to a major retailer and adjust how their elevators run, how their HVAC system runs, how their refrigeration operates. The resulting demand response capacity is then sold (bid) into the market.

Order 719 perpetuates an Inefficient Demand Response market structure:

The third-party aggregated demand response is incentive, pay for play driven. The aggregators offer to pay their customers a portion of the demand response value, or they will pay the customers on a monthly basis. These payments often come in lump sums, which make it more difficult for state regulators to implement rate changes to encourage demand response because the customer is used to receiving money. Jason suggests that “it takes a pretty savvy customer to understand how (aggregators) are going to do that, when its done and how its going to affect customers.”

Unless aggregated by the LSE, demand response aggregation is generally done by Curtailment Service Providers. CSP’s (Curtailment service providers) are not directly, statutorily, regulated by either states or FERC. Most of the demand response megawatts bids into the East Coast are produced by CSP’s.

If, for example, you’re a CSR located in California where:

• there are millions of customers that all have smart meters
• that can be curtailed and
• their real-time information can be transmitted so that
• the ISO can make a settlement
• based on the aggregated demand response bid made by the aggregator…

Then you’ve got a potential moneymaker!

But today no state regulator has control over this process. Jason’s point here is that the FERC’s bid to move the aggregated DR into the wholesale markets depends upon unregulated third parties.

How do CSR’s work?

They use a series of baseline assessments to determine how much energy you curtailed. They will take average usage and daily usage to make a series of regressive analyses to which they apply rigorous measurement and verifications standards. In California they look at the 10 previous days. All the ISO’s have a process for doing this, but they all have different rules about the measurement and verification. This is part of what NIST is trying to resolve with standardized protocols.

Order 719 perpetuates an Inefficient DR market structure:

On the wholesales market side you need to have high enough retail rates to incentivize the CSP’s/aggregators to bid into the market place. The CSP’s contract directly to PG&E, or SDG&E, or SCE to supply the Demand Response to the LSE (PG&E, or SDG&E, or SCE ) who can then take the DR to market, to the ISO and receive some sort of settlement. Or the LSE can offset this avoided demand with generation that they would have purchased in the market.

On his slide covering this aspect of the market, Jason points out “resale of demand implies that surplus exists in the marketplace”. He suggests this an inherent weakness. I’m not sure I understand this distinction.

‎Jason makes the case that from the perspective of the LSE’s – most non-decoupled entities would rather run demand response programs involving bid and settlement of retail demand than offer dynamic rates which reflect wholesale conditions. Why is this?

‎Programs require staffing, support structures, front and back office activities which can all be collected through the rate base, thereby allowing the IOU to collect more than if dynamic rates where in place.

‎

But the FERC wants to cut out the LSE’s role; they want the CSP to send the DR right into the wholesale market – to trade it as negawatts. This creates some problems.

CSP’s wishing to submit bids into the wholesale market must supply detailed information to the market, the LSE and the customers.

Including:

• Customer’s energy supplier
• Electric distribution company
• Pricing zone
• Dispatch contact information
• PNODE
• Retail rate
• Metering requirements

Despite these onerous information requirements this model has already experienced some difficulties.

• In 2006 PJM suspected baseline gaming by demand response providers
• In 2008 California had to amend aggregator contracts out of poor performance concerns. Aggregators were being paid for capacity that was never shown to exist.

In Jason’s opinion, the lack of regulatory oversight over the aggregator market is a significant weakness in the FERC model. He uses California as an example and urges us to consider that the state currently allows aggregators to operate within the state, but state regulator’s oversight of this market is only indirect (through the IOU’s with whom the CSP’s have a contractual relationship).  Despite the fact that no law prevents the CSP’s from bidding aggregated demand directly into the wholesale market, all aggregator DR is being sold exclusively to IOU’s. At the retail level the lack of oversight and regulation is even more ominous. Despite the complexity of the DR program obligations and their potential value for CSP’s – there are no rules governing the interactions between the CSP’s and their retail customers. This is a time bomb waiting to explode.

Scheduling issues arising under the proposed FERC market model

Another problem that arises under the proposed FERC market model is that it can create scheduling conflicts that could cause utilities to generate the very energy they just agreed to sell through a demand response program.

In the wholesale markets everything has to be scheduled and settled on a real time basis. Each of these wholesale markets has several different markets:

• 5 minute market,
• 10 minute market,
• 30 minute market (sometimes),
• 1 hour market,
• “Day of” market and
• “Day ahead” market.

In each of these markets you have generators providing an energy supply and load serving entities meeting the demand for energy. And each of these markets has to be balanced between supply and demand. That’s only two entities and it’s still really complicated. Now with the FERC proposal you are introducing another entity: the Curtailment Service Provider (CSP). The CSP is going to take some of this demand and bid it back into the marketplace.

Wholesale markets operate using gatekeepers, in this case they’re called “scheduling coordinators”. The scheduling coordinators act on behalf of the IOU’s, or the LSE’s and the generators. But the problem that has been happening in New England and California is that the CSP’s don’t use the same scheduling coordinators as the load serving entities in the regions that they’re operating in. So LSE’s like Pacific Gas & Electric don’t always use the same scheduling coordinators as the CSP’s the scheduling coordinators aren’t talking to each other. So it’s possible that they could buy demand for customers that don’t need it because they just curtailed it. The complexity of the bid and settlement process in the proposed FERC model has unintended consequences that create market inefficiencies.

Currently the California ISO is supposed to be the coordinating entity, but no rule requires them to do that in real time, which could prevent anyone from gaming the market. This is another example of the uneven regulatory coverage that exists and its inadequacy for providing effective oversight over the proposed FERC market model for Demand Response. FERC’s Order 719 is pushing the LSE’s to make room for CSP’s. This effort also represents almost $2 billion in investments to create this new market.

‎This Business Model Places the AMI Enabled Consumer in Jeopardy

‎

‎Consider that by 2012 California will be the first state to have all retail customers enabled with AMI.

‎         • Each customer will have sub-hourly metering data, which enables CSPs with enough information to meet measurement and verification requirements for sale of DR at the wholesale level.

‎         • CSPs will be able to sign contracts with end-users, even residential customers, for curtailments.

‎Most residential customers are not energy or business savvy enough to understand the implications of contractual relationships for demand response. And yet there is no regulatory oversight over this important market.

The Efficient market: Dynamic rates

Jason suggests that a more efficient approach would rely on dynamic pricing that permits customers to choose whether to incur costs or lower demand. It would apply downward pressure on the wholesale market prices without additional bid and settlement requirements.  He goes on to suggest that the LMP (locational marginal pricing) and nodal markets that the FERC and the ISO/RTO’s set up operate efficiently to charge proper market prices for delivered energy. In Jason’s opinion this model could be pushed down into the retail level to encourage demand response.

How much is the sleeve off your vest worth?

CAISO, NEISO, PJM and MISO all claim more than 2000 MW of DSM in their markets, yet back-up generators supply most of it in MISO and the eastern markets. This begs the question of how real this Demand Side Management really is. In CAISO 2100 MW of their 2500 MW of DR is comprised of emergency DR that is available only a few times a year and was used 5 times in the last 6 years. In reality only 400 MW is capable of dispatchable responsiveness in California.

What are the DR prospects for the Pacific Northwest?

The key questions to answer this questions concern the availability of money to invest in DSM and the Smart Grid. Will the regulators fund the smart grid in the Pacific Northwest? And if they do, what is the optimal investment model for the region?

The role of energy efficiency in supporting the Smart Grid:

Finally, will energy efficiency drive the smart grid investments, or will it be the other way around?

Energy efficiency is the most mature Smart Grid resource we have in the Pacific Northwest. Energy efficiency investments have risen from 1-2% to 4-5% on average across the region. Both NEEA and the BPA have been working to change the landscape for Energy efficiency appliances, technology and market transformation.

However, energy efficiency receives the most scrutiny from the regulators for every dollar spent. Recent efforts to get approval for Smart Grid investments in the region have run into resistance. The following two proposals were recently denied:

• WUTC DOCKET UE-090704 PSE (2009) request for a 7.4% increase is denied.  PSE begins deficit spending on EE programs.
• WUTC Avista Requested a 16.9% rate increase was told to return with a proposal for a 2.8% increase.

And increasingly DSM measures are being underfunded:

• PacifiCorp in Idaho is at a $3 million dollar budget deficit for its DSM measure in Idaho because the Commission has not approved proper recover in several years. PAC now proposes to cut back on DR expenditures in Idaho.
• IPC is operating a $17.5 Million dollar DSM deficit.  Proposing an increased rider percentage increase to cover costs.  IPUC has stated that may not allow IPUC to continue all DSM investments.
• NWE was recently allowed to propose a decoupling mechanism in Montana.  However in approving decoupling the Commission lowered NWE rate on equity form 10.25% to 10%. (National average is 11%)  This will cost the company roughly $1.5M per year of the decoupling mechanism.  And now the new commission is investigating their own prior approval of the de-coupling!

What’s the current state of the Smart Grid in the Pacific Northwest?

Coordination is key in the PNW but transparency is not ubiquitous.

• Many different balancing authorities
• Negative prices during wind events
• RPS continues to drive investment in wind, but we can’t balance it…

The BPA’s system is reaching capacity constraints, and there is no nodal model, nor congestion and constraint pricing. There is no mature real-time market for DSM resources to respond to.

‎         Smart Grid in the PNW will be different than in the rest of the country.

To survive it may have to look like an energy efficiency investment. But here Jason sees significant regulatory investment skepticism.

DSM resources take significant time to create and dispatch correctly to address gird issues, and finally the ratepayer needs to be brought into the discussion.

PSU’s third annual Smart Grid class is now about half way through the Syllabus and there seems still so much to consider about this evolving technology and energy delivery approach. It seems that the more we delve into Smart Grid the more we realize how vast the implications are.

After nearly a dozen classes I am also sensing that there is almost too much information being presented. At times the sheer volume of the in-class information and the readings is overwhelming. This  information intensity is exacerbated by a  disjointed progression of speakers whose availability trumps  a more logical progression.  That said, let’s return to covering the material offered by PSU’s PA 510 – their exemplary course on the the Smart Grid.

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This 5th session of the class hosted three distinct presentations. The first was Conrad Eustis’ presentations on regulatory trade off’s presented by the Smart Grid Technology. This was followed by James Mater’s presentation on the interoperability challenges inherent in the technology layers used to link the elements of the Smart grid. And finally Ken Nichols presented his perspective on energy trading in the western section of this continent.

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Trade offs in the Smart Grid

- Conrad Eustis

The introduction of the Smart Grid into a regulated electricity distribution system that hasn’t changed much over the last 100 years poses some fundamental questions about investment costs, social equity issues, environmental effects and economic impacts.

The regulators are grappling with questions like:

• should low income electricity users be subsidized?
• who should pay for these subsidies: ratepayers or taxpayers?
• At what cost should we pursue one policy trajectory over another?
• How expensive can we make electricity to preserve the environment?
• To what extent are regional assets accessible to the nation?

These are some of the knotty policy conundrums that regulators are grappling. According to Conrad, decisions by electric industry regulators are mostly based on economics and have to do with cost justifications – either direct (“hard”) costs or indirect (“soft”) costs.

The delivery of electricity entails much investment in physical infrastructure to permit energy delivery at a sufficient capacity to support society’s needs. Implicit in these decisions is the trade off between capital investment and operations & management costs. The more we invest in expensive capitol equipment the more we can reduce “O&M” costs. That’s one of the trade offs. Another might be represented by the how much we invest to create jobs? Or what investment is justified to preserve environmental health. To what degree should industrial or commercial users subsidize residential users? Or whether urban users should help pay for rural users? What about the acceptable cost of supporting an infrastructure that doesn’t compromise our national security?

To the extent that there are laws that require certain investments, no justifications are needed by the regulators. But there remains much “art” in how the social and environmental costs are included in regulators’ calculations. According to Conrad, many policy decisions are influenced by emotion or the “Movement Du Jour”.

But fundamentally regulators’ decisions are based on serving the public interest at a fair and reasonable price. In many cases the dynamic of a free market is considered to be the more efficient way to allocate resources, but in a regulated industry we need to ask whether there isn’t a cheaper way to achieve the desired end. That’s the whole point of having a regulated industry in the first place.

In general regulators are concerned with managing the costs of delivering electricity – from a financial perspective, from a social perspective and increasingly from an environmental perspective as well. Their mandates are usually circumscribed by the concept of delivering electricity at a fair and reasonable prices and supported by prudent investments.

Cost justifications can be successfully argued if it can be shown that the alternative energy source is less expensive than the conventional source, that the capacity is cheaper, or that the O & M costs are less. Indirect cost arguments might involve claiming that the expense was justified based on the job creation that the investments triggered. Increasingly environmental costs are also included – if they have not already been codified into environmental regulations that must be heeded. But as suggested above, the indirect costs of social and environmental impacts can often by influenced by emotional appeals and popular concerns.

But here, Conrad introduces an interesting caveat. Suppose you built a super energy efficient house with hyper effective solar panels and ultra efficient appliances. And suppose further, with the help of an overly optimistic nature, that this house achieved and even exceeded the net zero energy status – resulting in a net “export” of energy to the grid. Would the utility have to consider this energy source as a cheaper energy source (than conventional generation)? The answer is no, because of the cross-subsidies that understate the real costs of providing retail electricity, Why is this so? Because the utilities usually prefer to book some fixed costs (poles and wires) as variable costs in order to artificially lower retail electricity rates for residential users. Thus, when we add these variable distribution costs  to the exported power (from your “net-negative” home) the cost is much higher than the utility’s cost of generation.

Fundamental to this discussion of relative costs of power generation is a definition of the efficiency of energy generation. The second law of thermodynamics established the concept of entropy that explained how energy conversion always resulted in the loss of some of that energy. Lord Kelvin stated it as follows, “No process is possible in which the sole result is the absorption of heat from a reservoir and its complete conversion into work.” In other words, converting energy to power requires some loss. The degree to which this is true is the efficiency of the conversion process.

Most conventional generation Plants (except renewable energy sources) convert heat into electricity. The efficiency of this process is known as the heat rate, which measures the heat (expressed in Btu) required to create 1 kWh.

η (Heat Rate) = Btu of Heat to generate 1 kWh

The heat rate gives us a convenient way to compare the efficiency of various ways of converting energy into power. Conrad then proceeded to give a whole list of comparable conversion processes to illustrate their relative efficiency.

• Combined Cycle Combustion Turbine: Heat Rate ~7,000; η =49%
• New Coal Plant: Heat Rate 9,800;  η = 35%
• Low Speed Diesel On Liquid Fuel: Heat Rate 8,540 η = 40%
• Nuclear Plant: Heat Rate 11,000  η = 31%
• Simple Combustion Turbine: Heat Rate 11,400   η = 30 %
• High Speed Diesel:  Heat Rate 12,200 η = 28 %
• Automotive Diesel:  Heat Rate 14,200 η = 24 %
• Typical 4 cylinder engine: Heat Rate 18,000 η = 19 %
• PV Panel:  η = 6 to 35 % of energy in incident sunlight

Knowing the energy conversion rate is not enough to evaluate the practical costs of operating costs of a plant. To do this we need to look at the levelized plant operation costs that take into account the cost of the fuel and the maintenance costs for the plant – as well as the time during which the plant will actually be in operation.

First we determine the levelized annual (cost) requirements (“LAR”) of the plant- expressed in mills per kWh. We multiply this LAR times the cost of the plant per KW capacity. This all-in plant cost is then divided by the utilization (expressed in mills) – that is, 8760 hours divided by 1000 times the capacity. The product of this fraction gives us the hourly cost of operation of the plant (expressed in mills) and adjusted to show the actual usage. This capital cost (aka “overnight installation cost” ) represents the cost of building, financing and operating the plant on an hourly basis – and adjusted to reflect the actual percentage capacity at which the plant is utilized (expressed in mills).

To complete the cost calculation we need to add the effective heat conversion rate and the fuel costs (expressed in mills). The combination of the construction and maintenance costs times the effective conversion rate at the prevailing fuel costs provides you with the levelized plant operational costs.

Conrad then presented several other examples of calculating the levelized costs for various projects such as a wind farm (8.5 cents/kWh), PV panel 3 KW home installation ($9.5 cents/kWh), D cell battery ($16/kWh). The Simple Cycle Combustion Turbine is the lowest cost plant that PGE can build. This is an important example because if we’re using this plant to deal with peak load for 87 hours per year – this is the cheapest resource they can build. At that point it costs $1.87 per kWh. But what’s more important is the fixed cost per kWh. This is the “bogie” of the demand response program. If you’re trying to beat the cost of building a simple cycle CT plant, the cost of the energy is no longer the relevant measure. What’s relevant is the cost to displace one KW of the existing capacity.

He also provide the calculation for a DR program.

One of the important points in this discussion centered on the idea that the variable cost (fuel) calculation makes a dramatic difference in setting the cost. Most capital intensive plants are very sensitive to  part time operation, so even though the fixed costs stay the same the reduced operation time materially affects the levelized costs. This is a challenge for independent power producers which is why they rely on fixed contracts, otherwise the risk is way too high. For peaking plants that may run only about 1% of the time the cost of running the plant rises significantly, because most of the time the plant sits idle, but the financing and construction costs must still be born.

With respect to PV panels the efficiency of the conversion rate makes a difference since space is limited on roofs. Efficiency also makes a huge difference in the amount of land you have to purchase. If you have a large installation it will increase the amount of wires that you will have to use – that’s a significant cost.

In response to a question about German subsidies for PV installations which eventually became very prevalent, Conrad explained how the German subsidies that were as high as 40 cents per kW (versus 10 cent base rate) were effectively pushed to all the base rate users. That meant that a substantial subsidy had to be shared among all the other users. With ever greater numbers of installations these expanding subsidies were getting pushed to a smaller group and that eventually forced a reduction in the subsidies.

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Smart Grid Interoperability

- James Mater

James Mater is one of the founders of the Smart Grid Oregon – one of the nation’s first industry associations focused on promoting the advancement of Smart Grid technologies and companies that produce goods and services to support the successful implementation of Smart Grid. He is also the co-founder, Director and Smart Grid Evangelist of QualityLogic, a firm developing test and certification tools for the technology market, and currently expanding into verification of Smart Grid interoperability requirements.

He started out his presentation with by quoting from George Arnold’s testimony to Congress this past July.

In a word George Arnold was pointing out that efforts to achieve any sort of standardization are encumbered by what are effectively 3100 “silos”, each intent on seeking their own home grown solutions. Achieving any standardization would be a huge task, George Arnold warned. He ought to know. George Arnold came out of the telecom business where he helped to develop the wimax standard. However, in the telecommunications industry they only have 3 standards organizations, but Smart Grid has 15 standards organizations.

NIST echoed this concern when in their January 2010 Framework and Roadmap for the Smart Grid, they declared that the “lack of standards may also impede future innovation and the realization of promising applications“.

Yet the opportunity was enormous. In the same report NIST forecast that the, “U.S. market for Smart Grid-related equipment, devices, information and communication technologies, and other hardware, software, and services will double between 2009 and 2014—to nearly $43 billion…the global market is projected to grow to more than $171 billion, an increase of almost 150 percent.”

In an observation that may seem out of place in the highly regulated electricity market, NIST went to so far as to declare that “standards enable economies of scale and scope that help to create competitive markets in which vendors compete on the basis of a combination of price and quality“.

James Mater then reviewed the NIST conceptual model. In the terminology being used for Smart Grid discussions, each of these seven “cloud” categories is called a “domain.” Within any particular domain, there may be a number of different “stakeholders”. The framework being used by NIST to coordinate this effort identifies 22 stakeholder groups, from “appliance and consumer electronics providers” and “municipal electric utility companies” to “standards-development organizations” and “state and local regulators.”

He also went on to consider how that model looked when overlaid over the existing structure of a utility, which had already moved towards some degree of proprietary automation.

These slides, already presented by Conrad Eustis, showed the difficulty of trying to achieve economies of scale on an incremental basis. Interoperability was achieved but in a proprietary manner that denied the benefits of economies of scale and innovation that accrues from open standards and competitive markets. Moreover, the challenge is even more complex when we consider the whole panoply of systems that are used in the context of a major utility. Each of these systems, whether they be management software, or operational tools are supported by a proprietary enterprise service bus that communicates bilaterally, but not universally. This is the challenge that faces the designers of the interoperability standards that have to connect to many stand-alone systems.

This is the task that has been assigned to NIST – mapping the standards for Smart Grid.

Who is active developing the Smart Grid standards?

NIST has published 25 of the most important standards. Open ADR, which facilitates DR in commercial buildings, has just been published as a standard. NIST is now identifying the “critical” standards in every domain. So far there are about 33 standards which enjoy a degree of consensus. And there are another 70 for consideration…The standards for security are the last to get promulgated, in part because they are a foil for the nay-sayers. And to certain, security for the Smart Grid is a serious challenge that needs a solution that is at least as reliable as we expect when flying aircraft or banking.

So who are they key players involved in developing the Smart Grid standards?

• NIST
• Smart Grid Interoperability Panel
• GridWise Architecture Council (GWAC)
• UCA International
• GridWise Alliance
• EPRI/EEI
• Zigbee, Wi-Fi – low power radio inside buildings
• IEEE PES/2030 – institute for engineering
• SDO’s
• ISO – international standards; technology standards
• IEC – Geneva based – active in generation & transmission
• ANSI – working on meters
• NAESB – industry group
• NRECA
• State Legislatures
• Federal/State Regulators
• FERC
• NERC
• State PUC’s
• International standards bodies
• Oasis – good at internet standards
• Ashrae – heating & HVAC
• Bacnet – standard for commercial buildings
• OPC

The most active of these groups include the following:

The GridWise Architecture Council:

The GridWise Architecture Council, GWAC, is DOE sponsored and has 13 council members from different parts of the domain. Under the Energy Independence and Security Act (EISA) of 2007, the National Institute of Standards and Technology (NIST) has “primary responsibility to coordinate development of a framework that includes protocols and model standards for information management to achieve interoperability of smart grid devices and systems…” EISA requires that NIST consult with GWAC to define the standards and set up investment grants.  The GWAC also sponsors 3 annual conferences:

• Connectivity week
• Gridweek
• Interop

The Gridwise Architecture Council has enormous influence. They are developing the context setting framework, and designed the GWAC stack, which is adapted from the highly successful OSI layered stack that helped to stimulate innovation in the computer industry.

To carry out its EISA-assigned responsibilities, NIST devised a three-phase plan to rapidly establish an initial set of standards. In April 2009, the new office launched the  plan to expedite development and promote widespread adoption of Smart Grid interoperability standards:

• Engage stakeholders in a participatory public process to identify applicable standards, gaps in currently available standards, and priorities for new standardization activities.
• Establish a formal private-public partnership to drive longer-term progress.
• Develop and implement a framework for testing and certification.

Smart Grid Interoperability Panel (SGIP):

The Smart Grid interoperability panel (SGIP) is the way NIST interacts with industry. Some of the SGIP players came from GWAC. They are working on Smart Grid standards, developing priority action plans, and designing the testing and certification standards. SGIP developed the Smart grid conceptual model (see earlier graphics with various domains shown as clouds) and are working on the Smart Grid cyber security solutions. They are also working on the interoperability knowledge base (IKB). Importantly they also run the SGIP Twiki for technical collaboration.This wiki is an open collaboration site for the Smart Grid (SG) community to work with NIST in developing this framework. The board of the SGIP is chosen from across industry and government.

SG Architectural Committee: Semantic Model work

A canonical data model (CDM) is a semantic model chosen as a unifying model that will govern a collection of data specifications.

NERC:

NERC Critical infrastructure protection (CIP) standards require compliance every 6 months. There is a $1 M penalty per violation per day. Industry was shell shocked by these requirements. Industry is very anxious about any standards that might be in conflict with the CIP. Actually the CIP is comprised of a whole family of standards – that essentially require you to document everything you do. These CIP standards were originally devised and implemented to prevent big blackouts – so they’re both rigorous and heavily enforced.

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Smart Power Pricing, Space and Time

-Ken Nichols

Electricity futures are the most volatile commodity…because it can’t be stored.  Futures prices are based on quantity, location and time. This mirrors futures contracts in other commodities such as orange juice for which a typical future’s contract might specify:

Quantity: 15,000 lb of Frozen Concentrate OJ

Locati0n: exchange certified warehouses in California and Florida

Time: 1st business day of the month

For Natural Gas, the primary distribution point is known as “Henry Hub” which is located ii Louisiana. But other locations can be specified, though the price of natural gas delivered elsewhere will vary because of constraints and cost of transportation. This variance is called the “basis price”.

Apparently there are two variants to trading energy futures: financial trading instruments, referred to as “Space Contracts” and “Physical Contracts”.  Physical contracts are traded bilaterally and are more likely to be delivered. Some “Space contracts” also offer a conversion price that allows buyers to secure a theoretical amount of energy, but then later convert the contract into a physical contract for actual delivery if the energy is ultimately needed.

The NERC interconnections:

The North American Electric Reliability Corporation’s (NERC) mission is to ensure the reliability of the North American bulk power system. NERC is the electric reliability organization certified by the Federal Energy Regulatory Commission to establish and enforce reliability standards for the bulk-power system. NERC also maintains the large regional electric transmission networks that span North America.

NERC sets rules for regional system operation, reliability. It sets the reserve margin requirements and schedules transmission, etc.

The three systems that span North America are a contiguous AC system. They are linked by small DC inter ties. In particular there is a small utility in northern Texas, Tres Amigas, located in the ERCOT interchange that has limited connectivity to both the Western Electricity Coordinating Council (WECC) and to SW Power Pool (SPCC) which is part of the Eastern Interconnection. The following are the major transmission pools:

• Florida Reliability Coordinating Council (FRCC)
• Midwest Reliability Organization (MRO)
• Northeast Power Coordinating Council (NPCC)
• ReliabilityFirst Corporation (RFC)
• SERC Reliability Corporation (SERC)
• Southwest Power Pool, RE (SPP)
• Texas Reliability Entity (TRE)
• Western Electricity Coordinating Council (WECC)

These players can be further distinguished as Independent System Operators (ISO’s)  and Regional Transmission Operators (RTO’s). Both of these organizations are interested in improving the quality of the information supporting the market transactions and the effective consolidation of operations by the multiple owners of transmission. By driving down the physical barriers between the various regional electricity pools, NERC is encouraging increased integration of a national electricity market. For that reason it has not been fully embraced by Pacific Northwest regional energy providers, because they enjoy a substantial energy price advantage, as a result of the hydroelectric potential in the Northwestern region.

ISOs and RTOs are interested in market transactions and consolidated operations of multiple owners of transmission.

RTO’s

• Midwest Independent Transmission System Operator (MISO), an RTO despite the ISO in its name
• ISO New England Inc. (ISO-NE), an RTO despite the ISO in its name
• PJM Interconnection LLC (PJM)

Non-RTO transmission organizations:

• ColumbiaGrid
• Northern Tier Transmission Group

ISO’s

• Alberta Electric System Operator (AESO)
• California ISO (CAISO)
• Electric Reliability Council of Texas (ERCOT)
• Independent Electricity System Operator (IESO), operates the Hydro One transmission grid for Ontario, Canada
• New York Independent System Operator (NYISO)

Ken Nichols discussed the formation of the RTO’s and ISO’s. He explained that, “the PJM, New England and New York ISO’s were established on the platform of existing tight power pools. It appears that the principal motivation for creating ISO’s in these situations was NERC Order No. 888 that required that there be a single systemwide transmission tariff for tight pools”. In contrast, Ken asserted that “the establishment of the California ISO and the ERCOT ISO was the direct result of mandates by state governments”. The Midwest ISO is unique; it was neither required by government nor based on an existing institution. Apparently, “two states in the region required utilities in their states to participate in either a Commission-approved ISO (which occurred in Illinois and Wisconsin), or sell their transmission assets to an independent transmission company that would operate under a regional ISO (applied in Wisconsin).”

The only ISO’s  are Texas, California, and Alberta and the New York ISO (NISO). The Western half of the United States is dominated by the Western Energy Coordinating Council (WECC). California is an ISO; however SMUD, TID and LDWP are independent utilities operating inside California ISO. The CA ISO and AESO are only ISO’s in the western market. The rest of WECC are “Balancing authorities” and each of them has control of what’s coming in and out. In this region the BPA plays that role. Balancing Authorities are responsible for balancing schedules, managing transmission, and keeping the electricity at 60 Hz frequency.

PJM is the darling of the Smart Grid promoters. It is an RTO (facilitating transmission and markets across the several states in which it operates).

For energy traders operating in the western market  there are several distinct locations upon which the prices are predicated. These include:

• COBB Mid Columbia,
• Four corners,
• Palo verde,
• South of Path 15
• North of Path 15

Pricing based for energy is based on the Platts month ahead pricing. It is divided into  “On Peak” (6am to 10pm) and “Off Peak” (10pm to 6am). Trading is usually done in blocks of 25 mega watts.

The Energy Market handles both financial or futures markets, defined in specific delivery location requirements, delivery times, and quantity. The trades are cleared through an exchange or clearinghouse.

An example would be: “Mid-C, off peak, 25 MWh block, March delivery”.

Physical contracts can be same as financial, but bilateral trades (mainly financial/speculative) permits more flexibility in the terms.

The proposed WECC Energy Imbalance Market  (EIM):

The proposed EIM is a sub-hourly, real-time energy market providing centralized, automated, generation dispatch over a wide area. However, unlike an RTO, it would not replace the current bilateral energy market, but would instead supplement the bilateral market with real-time balancing. The automation of the EIM would allow for a more efficient dispatch of the system by providing access to balancing services from generation resources located throughout the EIM footprint and optimizing the overall dispatch, while incorporating real-time generation capabilities, transmission constraints, and pricing.

While the EIM market design has many similarities to those administered by ISOs and RTOs, this proposal does not include implementing an RTO in the Western Interconnection. The EIM could utilize tools and algorithms that have been successfully implemented in other centralized markets, but an EIM would not include a consolidated regional tariff for basic transmission service (e.g. network or point-to-point). But the EIM would use a coordination tariff to address provision of generation and load energy imbalance, replacing some Ancillary Service Schedules of participating transmission provider tariffs.

This was the third class of PSU’s 2011 iteration of the Smart Grid Course – a path breaking instructional offering that for the last three years has been delivering the best thinking and newest developments pertaining to the implementation of this new technology and the evolution of this new paradigm for energy delivery.

In this third class, PGE’s Steve Hawke, SVP for Transmission and Distribution talks about how he views the Smart Grid challenges. He sees this as an opportunity to introduce more effective market signals to replace the cumbersome direction of regulation.

Jeff Hammarlund followed this presentation with a review of how the current electrical distribution system evolved from Edison and Westinghouse’s days – with a special emphasis on implementations that shaped the Pacific Northwest T&D environment.

Finally, Conrad Eustis, Director, Retail Technology Development at PGE, then introduced the basic elements the Mart Grid interoperability challenge and how PGE was trying to comply with the NIST interoperability model. This presentation was continued on January 31^st and served as the foundation for Linda Rankin’s presentation of system architectures.

Guest Presenter: Steve Hawke

And to help us on our way to becoming even smarter about Smart Grid, we were honored to have Steve Hawke, Senior Vice President, Customer Service, Transmission and Distribution at Portland General Electric talk to us about why PGE is so supportive of the Smart Grid.

The gist of his energetic presentation was that the energy paradigm was rapidly changing and that new aggregators were entering the field whose business models might eventually pose a huge threat to large and even mid-sized electric utilities, like PGE.

PGE is a regulated monopoly.

PGE is mid-size company. It’s not so big that they’re hampered by their internal processes and/or the costs of embarking on new investments, nor are they so small that they haven’t got the resources. PGE is trying to be a “good early adopter” and pick their “sweet” spot. Like all other companies PGE has to consider its (business) environment.

All providers of energy are regulated monopolies in the United States. PGE is regulated by a public utility commission. Municipal boards regulate municipal utilities; customers regulate their cooperative utilities. They are regulated because they’re capital intensive. Building a transmission line from Boardman to Salem costs $1 billion. And when you invest that kind of money and later PacifiCorp builds an identical line right next door spending the same investment again it is not an efficient use of public resources – this is the basis of the regulatory structure that has evolved since the early 1900’s. The way we provide electric service in this country has been developed around a regulated monopoly business model. That’s not a given for all time. There have been lots of previous monopolies that are no longer regulated:

Grain silos, insurance salesmen and even movie ticket sales were once regulated. AT&T was the biggest regulated monopoly. In 1981 MCI introduced the first mobile phone. Initially MCI attacked only one tiny part of AT&T’s service – the long distance routes from Los Angeles to New York. The legal basis for the challenge was that competition could provide a more reliable and lower cost service. Eventually this argument stripped AT&T of its lucrative business lines. AT&T was left with only their least profitable lines and could no longer cross subsidize its remaining services. Within 10 years the AT&T business model collapsed.

So over the course of the last three decades we’ve seen a change from a $12 per month regulated land line service to the home replaced by a smart mobile phone line, with internet and cable that can supply various data formats pouring out nearly unlimited data streams that cost somewhere between $250 and $300 per month. That’s the value proposition that we get when you replace the regulatory structure with free market competition. That’s what you get when technology, “legal” and politics support a change from a regulated monopoly to a competitive enterprise.

Deregulation has been tried.

The idea was that technology had developed to the point that utilities could offer unlimited supply. It was presumed that investors would build speculative power plants that would drive down the cost of energy. It turned out to be too early for that business model. It failed miserably.   Prices went up and California went into a tailspin. The legacy of that disaster still haunts the industry. The regulated business model is not sacrosanct and changes in a number of different ways when attacked.

How does PGE see its business environment?

1.     Electricity is the most important product over the last century.

2.     Electricity will see increased use until 2080. We will need 8-12 times more power on the planet than we have now; in the US we’ll need twice the energy we use now.

3.     A system that takes 3 million years to set up but is used up in 80-90 years is not sustainable. The transportation system burns up 24 times more energy each day than all the generation plants in the country, mainly because the car is so inefficient. From the utility’s perspective, you can’t just look at one part of the environmental problem. You have to look at the entire system when you’re trying to decide where do you want to spend your time trying to solve the carbon problem? In other words, the transportation system is another place where PGE might be able to derive more energy savings to meet their energy savings goals. Hence PGE’s support for the emerging EV industry…

4.     The North American transmission and distribution system is the most complicated system in existence. It has a product that moves at the speed of light and circles the equator 7.5 times in a second, and yet we choose to have more than 3000 people manage it! It has evolved organically; you would never plan to run it the way it is currently managed! From the utility’s perspective they are saddled with an antiquated delivery infrastructure that desperately need renovation.

5.     According to the basic law of thermodynamics everything gets reduced to heat. Heat is the common currency of energy. Energy efficiency is about conserving heat; industrial efficiencies try to reduce line loss and heat dissipation. Over time we will begin to consider how we reduce all emissions. We’ll eventually have to consider how to reduce emissions of all chemical substances. In the end we’ll be talking about heat as a currency. From the utility’s perspective, the current focus on carbon is just the beginning; we will have to reconsider all emissions.

6.     Utilities have a load curve that resembles a (two humped) “Bactrian camel”. Of course, the ideal load curve for a utility would be a flat load curve so that a steady and cheap energy source can satisfy the demand and minimize loss of heat. Similarly to the regulated telecommunications business model, utilities blend the different cost structures of their businesses to develop the most compelling value propositions for the different customers classes that they serve. This blending of cost structures depends upon their ability to cross-subsidize different business products.

7.     Legal challenges to this regulated monopoly business model tend to focus on those lucrative business products and services that sustain the cross-subsidization of less profitable, but necessary product lines. Typically sophisticated services aimed at mid-sized businesses are priced well above their delivery costs. Legal challenges to the regulated monopoly business models have contended that precisely these lucrative services can be reliably delivered at a much lower cost. No doubt this is true, but the gradual deregulation of the profitable lines of business will eventually collapse the utilities’ ability to cross-subsidize the portfolio of products they are required to provide. The most successful way to attack a regulated business is to “skim off the cream”, or acquire the most lucrative customers while leaving the regulated model with the less profitable customers.

Why is this relevant to PGE? If a competitor were able to skim off those customers with a flatter load curve, they would be able to provide those customers with a lower cost solution and still generate enough profit for shareholders. Unfortunately, this gradual syphoning off of customers with flatter load curves will undercut the utilities’ ability to profitably serve those customers with a more variable load curves.

Today PGE is able to provide its customers with reliable service because they are able to aggregate all the customers in a territory. But what if another unregulated competitor were to be able to aggregate these same energy users and “cream skim” the most lucrative customers? Who might these more efficient aggregators be? Possibly Google – they also have all the customers in the country. Any technology that can provide energy storage, or that could bypass wires would have a significant competitive advantage.

The question that PGE is seeking to answer is how to survive the gradual deregulation of the energy industry. It may take as long as fifty years to bring down the cost of energy delivery to a deregulated price point. Deregulation may also engender a more distributed infrastructure that can withstand security challenges.

__________________________________________________________________________

Wiring the Smart Grid into History: the Historical Precedents of the Smart Grid.

Jeff Hammarlund

Jeff quickly summarized the “key components of a systems framework to support the smart grid” that he had discussed at the end of the class on January 18^th.

Drawing in part from the work of Mark Johnson and Josh Suskewicz of Innosight, Jeff had postulated that new clean-tech initiatives like the smart grid had the best chance for success when a systemic framework was established that offered four interdependent and mutually reinforcing components.  They were:

1. An enabling technological system. A technological breakthrough is not enough. Edison recognized this with the invention of the light bulb. Although he did borrow a few components from the legacy lighting systems, but he wouldn’t have been successful without the development of an enabling technology system that produced wires, generators, meters, transmission lines, and new appliances that had to be built from the ground up.

2. An innovative business model.  Success requires combining a technological breakthrough with a business model that provides value for both the customer and the company.

3. A market adoption strategy that ensures a foothold. The smart grid and other clean-tech systems, like the systems they are intended to modify or replace, are complicated. They are fraught with unknowns and how best to integrate their parts won’t be clear at the outset. Smart Grid advocates need to be humble, nimble, and willing to act when their initial hunches turn out to be wrong.  When possible, they should incubate their new ventures outside demanding, competitive marketsundefinedin foothold markets, where the value proposition offered by even early-stage technologies and business models is so great that customers are willing to overlook their shortcomings. Portland might serve as such an accommodating incubator for hosting a pilot that links demand response programs with electric vehicles via the emerging Smart Grid.

4.  A favorable government policy.  Federal support for the smart grid has been vital, particularly given the depressed economy.  But it is not without risks.  Government support is most effective when it is directed not just at new technologies but at new business models as well. For instance, in the early 1900’s, Samuel Insull’s development of the regulatory concept of a “natural monopoly” and the related concept of a “load factor” were instrumental in producing a regulatory compact that allowed the industry to develop more compelling value propositions while still responding to public policy requirements.

A Short History of the electrical industry in the Pacific Northwest.

- Jeff Hammarlund

After this brief review of favorable systemic conditions, Jeff began to outline the original development of electricity, and the early transmission and distribution systems. He described Edison’s opening of the Pearl Street Station on September 4^th, 1882 near Wall Street. The original $160,000 power plant served an area of only 1/6 sq. mile and included the stock exchange, two newspapers and several prominent investment banks.

Jeff then described the fierce competition between Westinghouse and Edison. The population remained very skeptical of this technology fearing electrocution. Edison actually founded the first co-generation plant when he used the steam from his powerhouse to heat nearby offices. But the limited reach of the DC current meant that Edison had to build twenty separate transmission and distribution systems. Nonetheless, Edison also believed that only direct current (DC) transmission lines could make it possible to transmit power over longer distances, such as the 14 miles that separated Oregon City and Portland – his first demonstration projects in the West. Much of this history that Jeff summarized was gleaned from his 2002 draft article on Oregon’s Role as an Energy Innovator. The following citations (in italics) are taken from the above reference article.

The Battle of the Currents

When Edison refused to listen, Tesla quit and joined forces with Edison’s chief rival, George Westinghouse. The Pittsburgh-based industrialist had just bought out some of Edison’s other competitors and boasted that his new Westinghouse Electric and Manufacturing Company would become “the most progressive” company in the field. As a young man, Westinghouse had been an inventor in his own right; his most famous invention was the railroad air brake on his 23rd birthday. He was both excited by Tesla’s inventions and intrigued by the young Serb’s claims that he was a “scientific mystic” whose inventions came from “spiritual visions.” After purchasing the rights to Tesla’s 40 AC patents, including the polyphase AC and the induction motor, Westinghouse hired the young emigrant as director of research. Together, they began to develop and market Tesla’s inventions. Thus began the “Battle of the Currents” between the two camps. …Tesla insisted that his system offered two important advantages. First, the electricity could travel much further, possibly many miles from a remote power plant to a population center. Second, the voltage from a single polyphase AC system could be stepped up or down to meet the specific power requirements of residential, commercial, or industrial customers.

The operators of Willamette Falls Electric where the first long distance transmission line to Portland was to be installed were not cowed by Edison’s scare tactics. After the success of the initial DC transmission, they nonetheless switched to AC. The Willamette Falls Electric transmission test confirmed Tesla’s contention that transmission with AC would significantly reduce power losses over the lines. In fact, the amount of line losses was even less than Tesla had anticipated.

Henry Villard and the Genesis of PGE

In January of 1880, just three months after Thomas Edison invented the incandescent light bulb, shipping and railroad magnate Henry Villard, owner of the Oregon Railroad and Navigation Company, gave Edison’s fledgling company its first commercial order. Four small electric generators called dynamos were placed in the engine room of Villard’s new ship, the SS Columbia. Each generator lit 60 small lamps of 16 candlepower. Once the ship reached Portland in the fall of 1880, wires were strung from ship to shore to light up a lamp hung from the porch of Portland’s Clarendon Hotel. “The powerful rays lighted up the whole neighborhood to the brightness of day,” proclaimed The Oregonian. Sensing the significance of the event, an accompanying editorial boasted, “The enterprise of a Western railroad gives Edison’s greatest invention, the electric light, its first practical use while the conservative East is still trying to laugh it off as a ridiculous joke.”

Villard began to invest heavily in the fledging Edison General Electric Company and, by 1888, had been elected as the company’s president. The novel idea of festoon lighting appealed to many Northwest shop owners, most notably the proprietors of our popular saloons, and soon many companies sprang up to offer this service. In Seattle alone, nearly 30 minuscule start-up companies placed dynamos in their basements and competed for this cutting edge business. But start-up costs were high and potential customers were more curious than convinced in the viability of electricity. . Most failed in the financial panic of 1893.

In more laid-back Portland, a firm that built hydraulic elevators bought three steam dynamos in 1884. Using excess steam from the elevator company’s boilers, each dynamo powered 20 light bulbs. Under the grandiose name of United States Electric Light and Power Company, the tiny company soon proved itself to be the most successful utility in town. This was the predecessor of today’s PGE.

Insull and the Regulatory Compact

From the beginning, the most successful electric holding company was J. Pierpont Morgan’s Electric Bond and Share Company. When J. Pierpont Morgan died in 1912, his son, J.P. Morgan, Jr., continued his efforts to use the holding company structure to consolidate the utility industry. Morgan Jr.’s goal was to make the United Corporation the dominant power in the utility industry. While he never fully succeeded, he and his 17 partners controlled 13 utility holding companies which controlled a network of utilities from coast to coast.

The only large utility holding company independent of the House of Morgan was controlled by Thomas Edison’s former personal secretary, Samuel Insull.  After witnessing Edison lose control of his Edison General Electric to the elder Morgan, Insull moved to Chicago to manage a fledgling utility and he quickly demonstrated remarkable business acumen and political savvy to make his utility, now known as Commonwealth Edison, into the dominant regional energy provider.

Insull proved to be one of the most innovative leaders in the young electric utility industry. He was the first to demonstrate the profitability of linking central generating systems, small towns, and rural areas with extensive distribution systems. And he was one of the leading proponents of state regulation of inventor-owned utilities.

Insull argued that utilities were “natural monopolies”. He insisted that competition was not in the best interests of either company owners or the customers since competing power lines and power plants increased costs for consumers and reduced company profits. The costs of generating, transmitting, or distributing electricity would be lower if only one company handled all these functions in a particular area.

Insull’s vision was to establish electricity as an “essential service” and to assign utilities specific service territories. In return, the utilities would agree to serve all the customers in their territories and they would be granted a set rate of return for their services. They would be regulated according to their ownership. Municipal electric companies were regulated by city councils, rural cooperatives by their customers, investor owned utilities by the public utility commissions, and public utilities by their county commissions.

In ’35 NW had 8 IOU’s and 42 citizen owned utilities. The scope of state authorities varied. The federal wholesale rates and the local retail rates were regulated to be “just and reasonable”. The basic principles used by the regulatory bodies was:

• That utilities were to operate safely and reliably
• At rates which were both just and reasonable.
• Utilities could recover prudently invested costs, and
• They were allowed to earn a reasonable rate of return.

At this point, Jeff concluded his presentation in order to give Conrad sufficient time to present his overview of how utilities structure their responsibilities and how that relates to the successful implementation of the  Smart Grid.

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Utility Operations, Today

-  Conrad Eustis

Towards the end of the class Conrad began his presentation on how utilities operate today and the implications of the management structure on the implementation of the Smart Grid.  Conrad began with an explanation of the National Institute for Standards and Technology’s (NIST) model for the Smart Grid.

The NIST conceptual model divides the functions into four categories:

1. The service provider

2. The markets – where we get energy

3. Operations, including:

a.      power generation

b.     transmission operator

c.      distribution and repair

d.     Customer premise management

All these elements should be interoperable!

Initially Conrad began to map out the major functions of an actual electric utility.

For instance, the typical service provider functions included:

• Develop Product Offers
• Start/Stop Service
• Read Meter
• Calculate Bill
• Answer Questions
• Acknowledge Outage

The operations function included the following tasks:

• Acquire Energy for Tomorrow
• Maintain Grid Stability
• Reroute Power to minimize customers out of power
• FERC:  Control Area Operator
• Repair Broken Wires
• Distribution Sys Operator

The transmission and distribution functions included:

• Create new Services
• Upgrade Plant as Required
• Create and Monitor Telemetry

And finally, the bulk generation function included:

• Build, Operate and Maintain Power plants

Then he mapped PGE’s officer positions to the NIST model.

• 7 administrative officer positions were directly related to the Service Provider role.
• 3 operational roles mapped to Operations,
• 1 executive mapped to the transmission and distribution functions, and
• 1 executive was assigned to the bulk generation function.

The clear lessons to be learned from this superimposition of the theoretical NIST model over an actual utility was that there are many areas where the interoperability function had just been initiated and was not yet completely interoperable. In most cases the interoperability had not yet been addressed, and in many other cases it was still under construction.

That concluded the third session of the Smart Grid Class on January 24^th, 2011.

This second class was devoted to laying the foundation for the examination of Smart Grid. Conrad Eustis provided a primer on electricity and the basic infrastructure of a “dumb” electric grid. Jeff started to lay out the history of energy policy. Some time was spent on class communications logistics, the course textbook (Smart Power by Peter Fox-Penner), and the small group learning exercise. This blog will not concern itself with logistics or the small group learning exercise, but will focus instead on the substantive lectures focused on the Smart Grid, and partially on the readings for that week.

Conrad Eustis led of the class by presenting what he calls “Grid 101”, beginning with the basics of how electricity works. Starting at the most basic level, he explained that electricity is the flow of electrons along a conductor such as a wire. The rate at which the electrons move is measured in amperes, or “amps”. But as we all know homes are equipped with sockets that provide both 120 and 240 volts of power. How does voltage relate to amps?

Voltage measures the charge inherent in the flow of electrons. This would be similar to the water pressure in a pipe held at various angles. A flat pipe has no ability to exert power, whereas a pipe held at a 45° has some pressure, and a vertical pipe has the greatest pressure. The voltage refers to the “pressure” driving the electrons and their commensurate ability to do work.

Thus the power that an electrical charge exerts (expressed in watts) is a combination of the voltage and the rate of flow (amps). However, as we know most voltages are fixed (for example 120 or 240 for households) thus watts are proportional to the current flow (amps). For example:

• A 1,200 watt hair dryer consumes 10 amps of flow on a 120 voltage line.

• A 5,520 watt clothes dryer consumes the flow of 23 amps with a 240 voltage line.

By definition a 100-watt appliance uses 100 watts in an hour, or 100 Wh, or 0.1kWh (zero point one kilowatt hours). Kilowatts per hour, “kWh”, is the comprehensive unit of measurement for energy consumption since it combines amps, voltage and time.

Now we get to another important distinction: the difference between energy and power.

The 1st Law of Thermodynamics states that energy simply exists; it can neither be created nor destroyed. The 2nd Law of Thermodynamics states that energy can be transformed from one from to another. It can be harnessed to enable work. “Power” is the rate at which we use that harnessed energy.

In the electric industry “capacity” and “demand” are also used instead of “power”. For people in the electric industry power is also an attribute of the electrical delivery system or power conversion unit. In other words they consider that their delivery infrastructure, and/or specific devices are designed or rated to accommodate specific amounts of energy. Applying too much energy reduces efficiency and increases the amount of energy lost through heat diffusion. When efficiently consumed, energy creates value (e.g., 1000 kCal/day, about 4 oz of fat, (~50 watts) keeps an adult warm).

The 2nd law of thermodynamics also states that no transformation is 100% efficient. When energy is transformed some of it leaves the system, often in the form of ambient heat. Another way to say this is that Energy flows from an organized state to a disorganized state, from high availability to low availability. This is referred to as entropy. But not all systems experience a net exodus of energy. An “anti-entropic” system benefits from external energy sources that replenish and increase the amount of available energy. Thus Earth benefits from 174 billion MW of solar energy that radiates into our system every day. Most systems and living organisms progress from an anti-entropic state, to a state of equilibrium, and finally to an entropic state until all energy has escaped and the system ceases to exist.

Such a digression into the Law of Entropy (2nd law of thermodynamics) is probably more relevant to a broader discussion of sustainability, but for now we are primarily concerned with the transformation of energy into power and the delivery of that power across the country to the end-users.

As Conrad stated before, to produce power we must transform energy into a form that can be harnessed. We can use kinetic energy, chemical energy, nuclear, potential, solar, wind, wave and geothermal energy, but for the purpose of supplying the grid we will need to produce a steady stream of electrical power. The generation plants are typically rated by the amount of energy that they can produce in a single day. So a 1 MW plant that operates all year produces 8,760,000 kWh. Yet if that same plant only operates for 4 hours every year it produces only 4,000 kWh. Since these plants have a high fixed cost it is desirous to run them continuously.

Note that the levelized cost of the renewable energy sources is significantly higher than the fossil fuel energy sources, with wind estimated to cost $.10/kWh and biomass coming in at $.095-.099/kWh. Of particular interest was the slide that Conrad presented that showed the costs of new power plants. Note the rising cost of the pulverized coal (PC) and the integrated coal gasification combined cycle (IGCC) plants, as the cost of carbon emissions rises. The carbon cost of the natural gas combine cycle (NGCC) turbines also rises, but because their carbon footprint is less the increase is not as dramatic.

Conrad now provided a brief overview on PGE:
Operating in 52 Oregon cities, Portland General Electric Company serves approximately 816,000 customers, including nearly 100,000 commercial customers. PGE has a diverse mix of generating resources that includes hydropower, coal and gas combustion, wind and solar, as well as key transmission resources. Their 13 power plants have a total combined generating capacity of 2,434 megawatts.
PGE began back in 1889, when a generator at Willamette Falls in Oregon City produced power to light 55 street lamps 14 miles away in Portland undefined the first long-distance transmission line in the nation.

Key facts:

·       Service Area 4,000 Sq Miles

·       Population Served 1.6 Million

·       Serves 710,000 Residential Customers

·       Average Residential use 11,000 kWh (1.25 kWa)

·       100,000 Commercial and Industrial

·       Total Sales 20 Billion kWh

·       Annual Revenue about $1.7 Billion

·       825,000 Meters, 180,000 Street Lights

·       4,000 MW Peak Demand (winter & summer)

o   In winter 2,100 MW from Residential average 3 kW

o   Each service drop supports 24 to 48 kW

Discussion of Grid Infrastructure:
The balance of Conrad’s presentation was a detailed explanation of the generation, transmission and distribution system that makes up today’s “dumb” grid. According to Conrad, PGE produces about 1/200th of the nation’s electric energy.

PGE is a vertically integrated utility owning both the generation, the transmission and distribution facilities. It is not self sufficient in power and depends upon long-term contracts and purchases on the spot market to fill in the additional demand. PGE typically has higher household usage rates because of the demand for heating and cooling – so they are both winter and summer “peaking”. PGE owns most of its own transmission and distribution equipment except where it uses BPA substations and lines.

A giant ring of bulk substations surrounds Portland and Vancouver so that power delivery is redundantly supplied – power can circle to the customer in either direction. This ring consists of 10 Bulk Power Substations that create 115 KV Transmission Feeds to about 90 Distribution Substations.

The local transmission and distribution infrastructure is made up of:

• 1,600 Miles of Transmission
  
• 12 Bulk Power Substations
  
• 158 Distribution Substations
  
• 260 Distribution Transformers (Transmission to 13kV)
  
• 585 Feeders, about 18 Switches per feeder
  
• 220,000 Power Poles Owned; Rent on 43,000 Poles
  
• 15,500 miles of Primary Voltage distribution Circuits (half underground)
  
• 190,000 Utilization Transformers (e.g. 7.6 kV to 240 V)

The book value (what was originally paid for it) of all this hardware is between $3 – 4 billion, but after depreciation it’s only about $1 billion. But to replace it today would cost closer to $10 billion. All of this equipment must be mapped out and tracked to ensure timely maintenance and effective system repair.

What followed was a pictorial guide to the transmission and distribution system featuring enough poles and wires to satisfy any linesman’s nightmares. But without delving into the details of all the pole configurations to be found, the following key observations should be noted:

• To move electricity over greater distances it is more efficient to do so at a higher voltage. But requires that the power be “stepped down” as it is distributed to customers and households. Using higher voltages decreases line loss, which is often estimated at 9-10%.
  
• The DC intertie transmission lines moving power across the region (from BC to California) covering as much as 865 miles typically carry voltages of 500 kV – these are not part of PGE equipment, but belong to the BPA.
• The AC transmission lines that carry the power from 50 to 500 miles into the bulk power substations at voltages of 500kV and 230kV serve the next biggest transmission requirements.
  
• From the bulk power substations to the distribution substations the lines “transmit” 110 KV, or in older areas 57 KV.
  
• At the local distribution substation the power is then “transformed from 110 KV to primary voltage of 7,200 in our system.
  

• Finally, the power is routed via feeder lines to 2,000 – 3,000 customers. At PGE these feeder lines typically carry 7,200 volts in order to reduce line loss, and each feeder has a breaker. “One wire to ground is 7,200 volts; phase to phase (there are three phases) are 13,000 volts.” At regular intervals “service drops” connect to individual customers.

• Feeders:
  
  • Typical Voltages 25 kV, 13kV, 4kV
  • Starts with Breaker at Substation
  • Serves One Lg. Industrial or 500 to 6000 residential
• Service Drops:
  
  • A few Large Industrial Customers at Transmission Voltage e.g 110,000 volts
  • Several Hundred at Primary Voltage 13,000 volts
  • Most At Secondary Voltage Via Utilization Transformer that Serves 1 to 12 customers
  • Secondary Service Drop Distinctions
  • Number of Phases 1, 2, or 3
  • Wye or Delta Wiring
  • Voltage 480, 277, 240, 208, or 120
• The system is designed to accommodate power going in one direction, which poses a problem for the smart grid, which envisions two-way communication.

Transmission and Distribution points to remember:
• System Design for Power Flow in 1 Direction
• When a Wire Breaks you still need to roll a crew to fix it
• Protection Device Designed to Protect Wires and Transformers. Every fuse is an engineering design task.

After a break the class reviewed the mechanics of Small Group Learning, and the formation of said small groups. They subsequently met after class to assign roles and adopt norms.

Jeff began his “History of Energy Policy and its Implications for the Smart Grid”, but was soon cut-off by the end of class. His presentation will be included in the next blog.

Introductions

It was hard to tell from the assembly of people gathered in front of room 303, who was teaching the class and who was attending. There were lots of familiar faces from the local utilities, from the BPA, energy efficiency consultants, lobbyists, regulators, Intel employees and several veterans of Jeff’s previous Smart Grid classes who were taking the course simply to absorb the updated information.

This year’s iteration of this cutting edge course, Smart Grid and Sustainable Communities,  is being taught by:

Jeffrey Hammarlund, Adjunct Professor, PSU’s Mark O. Hatfield School of Government; President, Northwest Energy and Environmental Strategies; and Oregon Caucus Chair, NW Energy Coalition;

Conrad Eustis, PSU Adjunct Professor and Director, Retail Technology Development, Portland General Electric.

James Mater, co-founder and Director, QualityLogic, and founding board member, Smart Grid Oregon;

Ken Nichols, Smart Grid Consultant and ex-TransCanada energy trader; plus many other nationally and regionally known experts on various aspects of the Smart Grid. __________________________________________________________

What is Smart Grid?

As might be expected the first order of business was to try to define the amorphous concept loosely referred to as the “Smart Grid”.

Citing the Electric Power Research Institute (EPRI), we were reminded that, “it matters how you define the problem; it can make a difference on the solution you arrive at.” In all, EPRI catalogued over 80 different definitions of the Smart Grid! Two other perspectives, worth calling out included definitions offered by Jesse Burst, the editor of the Smart Grid Newsletter: Smart Grid – the application of digital technology to the electric power infrastructure. Thomas Friedman’s vision of the Smart Grid included the following scenario:

“In the early years of the Energy-Climate Era, we progressed from an Internet thatconnected computers and the World Wide Web that connected content and Web sites…to an Internet of Things: an Energy Internet in which every device – from light switches to air conditioners, to basement boilers, to car batteries and power lines and power stations – incorporated microchips that could inform your utility either directly or through a special device, of the energy level at which it was operating, take instructions from you or your utility as to when it should operate and at what level of power and tell your utility when it wanted to purchase or sell electricity.”

Jeff Hammarlund then offered, if not a definition, then at least a set of characteristics that helped to define a framework within which Smart Grid could be said to be evolving. His definition, like the preceding ones, reflects upon the definer’s perspective – in Jeff's case, his experience drafting energy policies.

1. Smart Grid is not a thing or an end state.
2. It involves a combination of values and characteristics that differ markedly from the present energy delivery system.
3. It is a technology enabling process that will support new technologies, services, products and markets for the benefit of utilities, society and the environment.
4. Smart Grid constitutes a process or journey that leverages new ways of measuring the energy market.

Smart Grid is what it delivers – defining the scope of its potential contributions.

The second part of the class was delivered by Conrad Eustis, a PGE engineer with deep Smart Grid knowledge. Unlike Jeff’s policy driven perspective, Conrad’s “take” on Smart Grid was a more “bottoms-up” definition based on its expected benefits.

He began by considering the different classes of benefits that might be derived from the implementation of Smart Grid technology:

1. Reliability – driven by the expensive loss of business continuity suffered during the East Coast Black out of 2003, utilities and their customers want to avoid another scenario of cascading failures that takes down the entire eastern seaboard. Investment in a more intelligent and communicative grid would be a start, and the designation of some ARRA monies for this purpose has help catalyze such efforts.
2. Economic – The cost of the economic dislocation caused by both intermittent and major service interruption is said to cost the nation over $100 billion. Increasingly, as our nation’s infrastructure is automated through computerized management, the cost of outages becomes ruinously expensive, as an ever broader array of pivotal management functions become energy dependent for both analysis and execution.
   
   
   
   
   
   
   
3. Security – Our current system for managing energy generation, distribution and planning future investments is based on an antiquated and uncommunicative system. Not only is it rife for failure, but it is increasingly vulnerable to sophisticated attack, or to the stresses of natural disasters.
4. Efficiency - The Smart Grid should optimize asset utilization and allow utilities to operate more efficiently. Operationally, it should improve load factors, lower system losses and dramatically improve outage management. Additional grid intelligence should inform planners and engineers to build what is needed, when it is needed, to extend the life of assets, and to anticipate imminent failures, while at the same time maximizing labor deployment. Operational, management and capital costs should be reduced.
5. Safety – A more intelligent grid should vastly increase the safety of the electrical delivery system. Not only will this affect the safety of power infrastructure workers by permitting intelligent switches, and more robust safety systems, but it will also ensure the reliability of end-use devices throughout society upon whose uninterrupted operation is critical for society’s safe operation.
6. Environmental benefits – not only will reduced energy use contribute to a lessening of carbon emissions, but more efficient allocation of energy to integrate renewable energy will become increasingly important.

The Pacific Northwest Perspective

Here in the Pacific Northwest there is particular interest in the implementation of the Smart Grid. The BPA in conjunction with Batelle is currently running the largest Smart Grid project in the country here in the Pacific Northwest.

The Smart Grid Oregon Association is one of the first organizations across the nation to bring together representatives from utilities, governmental agencies, energy consultancies, third party service providers, engineering firms, equipment manufacturers, environmental groups, non profit groups and regulators to envision and evolve a common vision for the statewide and regional implementation of the Smart Grid. The association has already convened one conference that attracted local, regional and national experts to address the emerging regulatory, equity and market models upon which regulatory and incentive structures can be erected.

The Portland State University courses devoted to the evolution of Smart Grid implementation represent a unique contribution, and serve to provide a base of educated managers that can participate in the ongoing design of the regional implementation.

The Oregon Public Utility Commission (OPUC) has also been quite active in seeking to lay out a framework through which a comprehensive set of regulatory guidelines can be established that both safeguard the public investment, ensure stable and economic power, even as we begin to rethink the basic underlying concepts involved in the delivery of energy resources across the region.

Beginning from today’s status quo…

Having provided a parallel definition of the Smart Grid derived from an engineering perspective (as opposed to a policy-centric viewpoint), Conrad Eustis began to lay the ground work for exploring the structural aspects of a Smart Grid. To do this he began to lay out the fundamental elements of today’s mostly “dumb” grid.

He described the network of Power generation plants that distributed their energy to bulk power distribution hubs, which in turn routed the needed energy to the sub-stations and the neighborhood feeder lines, ultimately arriving at individual residential, commercial and industrial premises. This grid was designed to flow outwards from the generation plants to the end-user consumption nodes. There was/is virtually no ability for the distribution system to track its own performance, and the primary way that utilities learn about outages is from customer calls. Most of the technology in use today has not communication capabilities, either from the consumption point back up the line to the generation source, or from the generator down to the consumer.

Conrad Eustis acknowledged the current fascination with the Smart Grid topic. “Lot’s of people are stepping up to the IT challenges, but there is no shared vision.” Moreover the regulatory approval path is interminably long with some approvals taking more than a year to be granted. Finally, he also acknowledged that with the introduction of AMI technologies at the consumption end, the amount of data will be increased exponentially making analysis of energy usage patterns even more complex. Finally, he also reiterated the lack of standards and the utility’s preference for using proprietary metrics rather than support standardization. Even when technologies have been adopted, Conrad pointed out it can still take decades to adopt and integrate a new technological standard, such as the DSL technology for transmitting data over phone lines. He expects progress on Smart Grid issues to be equally slow – predicting that it would take further decades to fully implement Smart Grid in the United States. “When you automate you have to do it right” he cautioned.

More fundamentally, Conrad indicated that the utilities are also cognizant that this evolution of the energy market will change the basis upon which their business models rest. With the entrance of altogether new players into the mix, as well as increased uncertainty about how this market will segment service delivery there is more than enough anxiety to go around.

Review of the Class structure and readings

Following Conrad’s presentation, the balance of the class was devoted to reviewing how the materials would be broken down into the various class segments. Some of the later classes were reserved to as-yet unannounced topics, as Jeff felt current events would mostly likely generate new material by that time.

The major topics that the class would cover were:

• Integration of wind energy
• Review of the Pacific Northwest Smart grid project
• Regulatory issues
• Customer concerns
• Sustainability and environmental benefits of Smart grid

- Jim Thayer