Making Sense of Smart Grid Blog

Eran Mahrer – Solar Electric Power Association

 

The State of Solar

 Our second class session brought the course up to full speed this spring term with a very impressive talk by Eran, who introduced us to SEPA and gave a quite fast paced and information filled presentation on the solar market today, including a look forward to consider future solar industry developments that have a grid component with some thoughts on advanced distributed solar integration.  Eran is the Vice President of utility strategy at SEPA, he was formerly director of Arizona Public Service’s renewables program.

SEPA

It’s a non-profit education oriented organization, which makes it somewhat different than many other non-profit industry groups in that it’s 501 c3 status means education only and no lobbying allowed.  SEPA members are 60% solar industry and 40% electric utilities.  The core mission is to facilitate a conversation between the two groups.  With its broad utility membership comprised of 420 utilities that according to Eran, have 94% of the interconnected Solar in the US, SEPA stakes out middle ground between the two camps, advocating ways for solar to best fit in with the utility industry structure (with some evolution required). 

This last note is important, as there are an increasing number of voices coming from the solar sector that take a decisively adversarial tone toward utilities.  More on this later when we get to net metering, the discussion around this hot button issue was one of the highlights of the evening.

Drivers for Solar Today

We know solar power is a hot topic these days, but what are the main forces behind the recent growth? Eran gave us a list of drivers to start off his talk on the state of solar:

•         Renewable requirements & goals
•         RPS requirements for utilities to acquire renewables, increasingly that means turning to solar. 

•         Economic development interests
•         Local job growth for solar installers has been an attractive selling point.

•         Lower solar costs
•         PV costs have fallen fast.  More on that later.

•         Customer interest / Competition for customers
•         Customer choice playing a larger role.

Competition

To further explain the last solar driver, Eran briefly outlined the experiment with electricity deregulation in some parts of the country with a very short description; one that I think is condenses a lot of history into a sentence:

“The idea of competition, or choice in the energy space has really been en vogue, but at the end of the day, when customers were faced with choices: do you want big electric generator X, or big electric generator Y, and their portfolios didn’t look much different…it was more headache than action driven.”

Customer choice sure was en vogue back in the mid 90s, but along with a lot of other things from that time, it just doesn't work the same way today.  Then, it wasn't so much customers that wanted customer choice as it was academics, regulators, industry groups, and legislatures trying to forge a better electricity system in the mold of successful airline, telecom and natural gas deregulation initiatives that had come before. Suffice to say electricity is different than those industries, so much so that headache more or less describes the overall progress since then on giving customers the power to choose their electricity supplier.  Texas has gone the furthest along this road, and after more than 10 years of retail choice, I understand it mostly still works about the way Eran described it, with little differentiation between sellers.

Nexus on the Customer

There’s something that we have today though, that we didn't have in the 90s: cheap solar PV.  It appears the price decrease, along with new financing methods, are serving to put the customer back in customer choice, as it is becoming clear in some regions, including Oregon, that customers are happy to buy electricity from a solar company of their choice, to whom they grant permission to install a PV array on their property.  In many areas, the recent introduction of the solar power purchase agreement between customers and solar companies marks the first time customers have ever been presented with a choice for electricity supply other than their incumbent utility.

With solar as an option, Eran noted the relationship between customers and utilities has changed.  Starting 6 or so years ago, when PV installations began to take off, customers started to demand more information from their utility, speeding up the movement toward straightforward data availability.  Since then, the increasing number of participants who have used that data to design and install solar power have shifted the traditional line in the sand between utility and customer in some regions, creating what Eran called a “very public battle for the nexus on the customer.”

This topic might not be at the forefront in the NW, but in the sunnier states to our south, there certainly are some public battles heating up, largely over net-metering policy.

Here’s a video of a conference panel held in Phoenix on April 22, so you can see how heated the discussion is getting in Arizona.

http://www.ustream.tv/recorded/31972337

Rapid US Market Growth

“In 2012, we installed more solar than all prior years combined except 2011”

“There’s no forecast for slowing”

Eran’s comments pretty much sum up the state of the industry.  It’s booming.  There are some important details inside the numbers though, about which he provided some insight.  Here is a chart from a GTM Research report looking back at 2012.  http://www.greentechmedia.com/research/ussmi

Eran spoke to SEPA projections for years beyond 2012, predicting growth rates on par with that of 2011 to 2012.  Not exponential, but steady.  An important date looms in 2015, when the Federal investment tax credit for solar power is set to decrease or go away, so utilities that have RPS procurement needs want to have the solar they acquire in service before that date, which means heavy utility solar presence in ’12, ’13 and into ’14, but after that likely a big drop-off.  SEPA thinks this will be balanced by an increase in non-utility residential and commercial installations that are currently on a significant upward trend.

Solar Benefits/Concerns

Driving procurement of new solar generation are the benefits we’ve heard about:

•         Decreasing costs
•         Regulatory compliance
•         Fixed price electric outputput

But there are some concerns that are go along with those benefits:

•         Solar is not yet the lowest cost resource
•         Portfolio saturation
•         Declining electricity sales

To color the bullet points above, Eran cited a criticism of the utility regulatory structure: pressure to keep costs low in the short run at the possible risk of passing up investments that will lower costs in the long term.  The last point has to do with customer owned PV in this context; such customers purchase fewer kWh of electricity, putting upward pressure on rates.  Eran commented that utility boardrooms worry that these higher rates will then give a stronger price signal for people who have not yet adopted solar to do so, thus raising rates again for those who don’t have their own generation capability.  This has been called a “death spiral;" some now use the term “unraveling effect.”

Utility Scale Solar / Siting

To start off the part of his talk on solar pricing, Eran spoke about utility scale solar.  He recalled his experience at Arizona Public Service when it was signing its first contracts with solar developers in 2007, the price was $8/watt.  APS thought that was a good price.  Then in 2009 the price had come down to $5/watt, and in 2010 when APS received bids for installed PV lower than $3/watt solar became that utility’s lowest cost resource, even with integration costs baked in. 

Staying on utility scale solar, Eran raised some of the difficulties with utility scale solar, mainly siting, permitting and transmission interconnection. Since it’s really difficult to build solar plants in the desert Southwest, be they thermal (solar tower) or PV, there’s a move toward smaller systems, interconnecting at lower voltage, closer to the load centers.  That means rooftops.  So onto commercial and residential rooftop solar the discussion went.  First more on pricing.

Price of Solar

Eran showed a figure from a Lawrence Berkeley Lab study on solar pricing:

http://eetd.lbl.gov/EA/EMP/reports/german-us-pv-price-ppt.pdf

There are 4 cost categories:

•         Soft Costs BOS
•         Hardware
•         Inverter
•         PV Module

The fastest way to reduce the price of installed solar PV is no longer to target the modules themselves; it’s now installation costs that are front and center.  To that end, the comparison with Germany highlights areas where there’s still potential to drive down costs in the “balance of system” category that is comprised mainly of customer acquisition and financing.  A solar company needs to spend about $2000 to find a customer, and then it has to finance the project which, Eran says is very possible, but lenders are charging a premium.  Add in permitting costs and delays, and that is more than half the project budget before hardware.

Why is it cheaper in Germany?  It’s not because German labor is cheaper, nor is it the cost of the PV module, which is actually slightly lower in the US.  Financing, permitting and installation are vastly easier in Germany.  Banks readily give out solar loans at very low rates.  Permitting and installation methods are standardized and simple across the country, as is the feed in tariff that utilities pay for solar output, and it’s guaranteed.

Cash on the Spot

This guaranteed FIT in Germany makes for simple financing: you walk into a German bank, fill out a single page form, cash is issued on the spot since the bank doesn't see any risk in the transaction, and you use it to pay the installer. 

If it was that easy in the US, more homeowners might get a loan from their bank, and buy a solar system themselves.  Aside from laying out cash for a system, as some do, especially when incentives are high, most will look at the loan their bank gives them for solar, if they are given one at all, and choose to lease or sign a power purchase agreement. 

Solar Lease / PPA

These two financing models were covered in class, but I’m going to get into more detail, if only because I became interested after Eran’s talk and did some research.

If you want solar but don’t want to lay out the capital, there are two options, you can lease the system from a third-party, or you can let the third-party own that system and you sign a PPA and buy the power it produces.

Is it Legal?

The first question I had about the PPA model: is it allowable to sell electricity if you’re not the incumbent utility with exclusive service territory?

The answer: in some states yes, other states no.  In Oregon, sellers of wind and solar electricity are specifically not defined as public utilities and therefore exempt from PUC regulation, and can operate within a utility’s territory.  California also allows third-party sales from non-conventional electricity sources like solar if the generator is located on the buyer’s property.  A good resource for this information is this NREL paper: http://www.nrel.gov/docs/fy10osti/46723.pdf

In some states third parties are not allowed to sell power to customers via a PPA.  In some of those states leasing has become a popular option.  But a lease can complicate tax credit applicability as it’s much easier to access that revenue source as the owner of the generating unit.

When a tax-exempt entity wants to go solar, it cannot benefit from federal and state tax credits without bringing in a third-party with a tax appetite to own the system.  The PPA model fits those needs well and is in use in Oregon and elsewhere.

In the news lately was the single solar PPA contract in Iowa, between a solar company and a municipality for rooftop PV electricity generated by a rooftop array on one of its buildings.  It's in place thanks to a recent favorable court ruling after the local utility challenged the contract.  The solar seller, Eagle Point Solar was deemed by the court not to be a public utility, so it wasn't violating rules granting exclusive service territory to the utility.

Find out more about this here:  http://www.midwestenergynews.com/2013/04/12/court-sides-with-iowa-solar-installer-in-dispute-with-utility/

One final note about PPAs.  A significant policy driver spurred on their development and growth between 2006 and 2009.  The federal residential ITC had a cap during those years of $2000, while the commercial ITC was 30% of system cost, unlimited in dollar amount.  So clearly that difference alone had a major effect on consumer decisions to take PPAs instead of purchasing outright.

Net Metering

All of these solar financing models appear to be reliant on another key policy Eran described as:

“A transaction mechanism, facilitated by PURPA, that legislators and regulators have adopted in order to facilitate an exchange between a rooftop customer’s energy and the utility grid.”

We had a good discussion on the pros/cons of net metering, where the utility effectively pays solar owners retail rates for generation when it is excess of the customer’s needs.

More to come in part II of the State of Solar, on net metering and using the smart grid to integrate solar power into the distribution grid.

Welcome to Portland State University’s Smart Grid for Sustainable Communities Version 4.0, Spring 2013: Making the Smart Grid Work in the Real World.

We kicked off the spring session of the Smart Grid series last night with introductions from course participants and faculty members.  Then it was on to what the course offers this term.  In addition to the always impressive lineup of guest speakers, there will be team projects that are intended to give students real-world experience.  That was the focus of the class so I’ll get right into the projects we’re considering.  For Faculty introductions please see my previous post covering the first class meeting in January.

  http://www.smartgridoregon.org/Blog?mode=PostView&bmi=1190148

Projects:

 PSU Smart Clean Energy Upgrade, Smart Grid/Demand Response component.

Jeff and Sean Green spoke about a project on the PSU campus exploring a smart grid angle on the University’s clean energy and climate plan goals.  Sean and the PSU Facilities department have secured grant funding from the US DOE and are in the process of requesting more from BPA for a lighting retrofit demand response and energy efficiency project on campus.  Sean, a PSU student and smart grid class member is working to prepare the BPA grant application, due in early May.

PGE Smart Power Project

PGE has a very impressive smart grid project underway in Salem using a 1.3 MW battery and upgrades to the feeder to which it’s connected.  There are two directions the class project could go.  Mark Osborn described them:

•         Energy Arbitrage

The concept is simple: buy low and sell high.  But in practice there are many unresolved details here that need to be considered, such as what tariff to use for interconnection of a battery to a utility’s distribution grid?  Probably needs to be created, and our class could help.

•         Microgrid / High Reliability Zone

This one is an opportunity to dive into both the engineering and policy required to make upgrades that create a high performance section of PGE’s grid.  Or maybe even a microgrid, where that section has the ability to separate and become an electrical island.

Smart Meter Consumer Data Study

James Mater spoke about meter data availability, how it could be beneficial to many parties such as university researchers and government entities, and how difficult it might be to get it from utilities.

Oregon Convention Center

Jeff introduced a project to explore smart grid and demand response options for the Convention Center, and I shared some thoughts on looking into what it would take to monetize its potential demand response resources by participating in a developing inter-regional electricity market.  The OCC has energy efficiency activities underway in partnership with the Energy Trust of Oregon, which generally doesn't get involved in DR, meaning there could be room for our class to make an exciting contribution.  Erin Rowland is the OCC sustainability coordinator and an alumnus of this class.

-Bill Henry

The Smart Grid and the Consumer

Course faculty Michael Jung organized session 7, focusing on consumer views about the smart grid and approaches to consumer engagement with guest speakers:

Patty Durand – Executive Director, Smart Grid Consumer Collaborative

Bob Jenks – Executive Director, Citizens Utility Board of Oregon

Lisa Magnusson, Senior Director of Marketing & Brand Programs, Silver Spring Networks

Michael introduced the session by offering his thoughts and observations on how consumers fit into the utility business and recent smart grid development, namely that consumers haven’t been involved to the extent they should.  In fact, he says they've been left behind by an industry focused on engineering and economics.  Customers have traditionally just been assumed.  Too often utilities have assumed customers would be there to buy their electricity, to make decisions that were expected of them, took them for granted, and got on with the engineering work at hand. 

Michael sees this as a potentially risky trend; you can’t assume the consumer.  As the smart grid has developed, there have recently been clear reminders of this notion.  We got to hear three perspectives.

 

Patty Durand

The Smart Grid Consumer Collaborative, based in Atlanta, is a nonprofit group founded by Jesse Berst three years ago that consists of a broad membership from utilities to technology companies to nonprofit groups.  Smart Grid Oregon is a member.  Their mission as it appears on their website:

Berst founded SGCC because he recognized that digital technology was headed for an intersection with utilities and the electricity grid, but saw there was insufficient work being done outside utilities to understand what consumers want.  SGCC has used a nationally representative telephone survey of residential customers tracking smart grid:

•         Public awareness
•         Favorability
•         Understanding

SGCC has reached over 3000 consumers in three waves of surveys.  Patty mentioned some statistics about their survey; it has a 95% confidence interval for the results she shared.  The residential customers are segmented into five groups:

Concerned Greens: They comprise about 31% of the residential electricity market. They are most protective of the environment and supportive of Smart Grid initiatives. They are highly likely to participate in energy management programs.

Young America (23%) doesn’t know much about smart grid, but are interested in learning about its potential for environmental benefits and cost savings.

Easy Street (20%) consumers have the highest income of any segment and are reluctant to change their personal behaviors.

DIY & Save (16%) consumers are frugal and have a do-it-yourself lifestyle. Their biggest concern is providing for their families, not global environmental issues.

Traditionals (11%) are set in their ways and don’t see the need for energy reform.

Survey Results Main Points:

From the first survey results she showed, there was a significant trend revealed about smart grid: not very many people know about it.  There may be consumer backlash going in California, and some people around the country are very involved, but overall, it’s a relatively unknown concept to the broader public.

Second, the top benefit counsumers would want was making it easier to connect renewables, found to be of higher importance than saving money.  This surprised Patty, before the fact, she expected saving money to come out on top.

Third, consumers consistently showed they wanted real time energy data.  Patty contrasted this with many utility industry insiders who often say people don’t want this and will get bored if they had it.  Apparently nobody asked the customers, who the SGCC survey indicates are indeed interested.

Low Income Consumers

Patty moved on to research SGCC commissioned on low income consumers.  She says these customers are often used a football of sorts and kicked around along with various views and opinions about rate setting issues.  For low income customers, awareness of the smart grid is lower than the general population, as is overall favorability of smart grid.  When these respondents were read a list of the benefits, they were ranked in a similar way to the general survey. 

Videos

Patty showed a utility success story clip form California, and a 4-video SGCC put together called Separating the Facts from the Fiction about Smart Meters.  According to patty, it’s a myth busting video with responses to anti smart meter activists from a group of their utility members. 

http://www.youtube.com/watch?v=Nij-_gAMj-4

Conclusions

The main takeaway form patty’s talk, in my view was that survey data found support for the notion that consumers want to be able to access better information about their energy use and be the one in control of it.  Overall, for the general population across the country there appears to be a large appetite for energy management offerings that remain mostly untouched by what utilities have done so far. 

 

Bob Jenks

Bob is the Executive Director of Citizens’ Utility Board of Oregon, a nonprofit that represents residential utility customers, primarily before the OPUC.

Michael introduced Bob by referring to consumer advocates around the country, and how CUB doesn’t quite fall into the buckets that often describe the others, such as advocates who have become cozy with utilities, or the opposite, advocates who like clockwork oppose any utility proposal.  CUB and Bob are a little different, acting not only in the interest of Oregonians when it comes to rates, but as well values; environment is very much on the radar at CUB, it can often be difficult to say that about many of the others.

I recommend reading Jim Thayer’s post on Bob’s talk for the smart grid class two years ago: http://www.smartgridoregon.org/Blog?mode=PostView&bmi=545004

Bob started his talk by both voicing concerns about two specific proposals, before he voiced his optimism about the future of the smart grid.  He noted:

• PGE AMI
• Bob opposed the project.  More on this later.

• OPUC Staff proposed mandatory TOU rates for customers with EV chargers
• He says he’s probably the biggest obstacle to mandatory time-varying pricing.

Nonetheless he’s a big proponent of the smart grid, and he doesn’t see any conflict between that and the various positions he’s taken on specific issues in the past

The trouble with some smart grid advocates, in Bob’s view is the approach they take to promote their favorite technologies and services.  He thinks these should aim to make people’s lives simpler; instead he too often sees the message heading in the other direction, toward complication and difficulty. 

Bob encourages a healthy level of skepticism from consumers when their utility seeks to make an investment, smart grid or otherwise, since it will have to be built into rates and probably cause them to go up. 

It’s Gotta Have Value

Bob explained the way he looks at proposals like this, I’ll paraphrase: your bills will go up in the short run, even if promised savings from an investment don’t show up as intended further along.  That’s why he likes to look at each one and evaluate it individually.

One area where utilities should be spending money is energy efficiency.  He said PGE spends more on energy efficiency per customer than any other utility in the country.  That costs money, to the tune of 5.5% of his bill every month.  But in the long run it pays off; especially encouraging is the 30 year history we have with energy efficiency practices in the NW.

Back to those first two concerns Bob voiced at the top of his talk.  For those, the value wasn’t there or the idea wasn’t fair to all who would be affected. 

AMI

He explained the reasons for his opposition to PGE’s AMI investment, noting the main cost justification was that PGE could lay off meter readers and use radios in the meters instead to do the same job.  He thought it was a shortsighted decision to focus only on the meter reading savings while leaving out smart grid benefits networked meters could bring to PGE and customers.  He said it would have been wise to figure out what the meters could do and watch what utilities in other states, namely California are doing with them.

About the NW

We’re a system that’s no longer growing as fast as it used to, success in energy efficiency is one of the reasons why.  Bob noted peak loads in the last 5 year were down from previous years. 

The biggest challenge we have to take on is no longer load growth, but integrating renewables, given Oregon’s RPS policy.  Bob explained his views on the changing nature of what a utility does, moving away from operating a small number of very large power plants toward a system that must greater numbers of smaller generators, many of which are variable renewables.  

Lisa Magnusson

Lisa spoke about Silver Spring Networks' experience with AMI deployments around the country.

Mark Osborn – Smart Grid in the NW.

Mark gave a very informative talk about some exciting projects he worked to develop at PGE. 

DSG

First was PGE’s dispatchable standby generation (DSG) program, a unique aggregation of backup generators across its service territory that are linked to PGE’s control room with a customized computer system.           

The central feature of DSG is the enrollment of a number of backup diesel generators at customer locations that enter into agreements with PGE allowing it to call upon them when it needs that kind of resource.  They are connected in parallel with PGE’s wires, so when running they serve both customer loads and feed power back into the grid.  In exchange for the use of the generator, PGE pays certain expenses including fuel and generator testing, which needs to be done regularly to ensure they're working properly.

PGE can hold these generators as fast responding reserves, which it always must carry, and be ready to ramp them up in the case of a contingency.  DSG qualifies as non-spinning reserve, a characteristic of the time needed to reach full power.  

Blog 6 Part I PA 510 2.21.13

Week 6 was devoted to smart grid technology, with lectures from Lawrence Beaty on control systems used by utilities and Mark Osborn, who gave us some insight into a few of PGE’s innovative projects.

Lawrence Beaty – An Introduction to SCADA – Fundamentals and Implementation.

Lawrence Joined class remotely from Idaho State University, covering SCADA systems (Supervisory Control & Data Acquisition).  He explained these systems as powerful tools that exchange data collected from remote telemetry units (RTUs) with a master unit, usually located in a control room, which is able to send control commands out to the RTUs.  The master unit contains a human-machine-interface (HMI) that shows operators a comprehensive view of the system, and makes possible intelligent control actions.  Electric and water utilities rely extensively on SCADA to manage their systems, as do many other organizations that need to manage complex systems, such rail transportation and chemical plants. 

SCADA systems perform 4 main functions:

• 1.      Data acquisition
• 2.      Networked data communication
• 3.      Data presentation
• 4.      Control

To perform these functions SCADA systems have 4 primary components:

• 1.      Sensors and Control Relays
• Sensors monitor inputs and outputs in two ways: discrete (e.g. on/off) or analog (e.g. voltage level).   It takes this data, digitizes it and sends it to the RTU.  A relay is the piece of equipment that directly interacts with the physical system upon receiving a signal from an RTU

• 2.      Remote Telemetry Units (RTUs)
• Specialized computers deployed in the field, such as at a substation, that communicate with all sensors and relays at that site.  It must have a redundant power supply and is built to survive in a rugged industrial environment.
• 3.      SCADA Master Units

• Computer consoles that serve as the central processor for the SCADA system.  It enables both human control with an HMI, and built-in automatic control in response to sensor inputs.

• 4.      Communication Network
• Connects the master unit and control room to the RTUs.  Typically it puts SCADA data on ethernet and internet protocol for transport and connects RTUs to master units using a closed network that doesn’t expose data to the open internet. 

Lawrence asked the class to come up with everything that needs to be monitored from a substation, answers included:

•         Volts
•         Amps
•         VARS (Volt-Ampere Reactive)
•         Temperatures
• o   Transformer windings
• o   Transformer oil
• o   Ambient
•         Breaker status
•         Discrete alarms
•         Relay status

One of the primary applications of SCADA systems is managing a utility’s distribution grid.  The substation functions covered by Mark Osborn in week 3 are put into practice by RTUs, connected to the utility’s distribution grid control center.  The system gives operators a total view of the system with ability to access a lot of data coming in from each SCADA node.  Lawrence noted this presents a dilemma to SCADA system designers, as operators could be overwhelmed with data at a time when critical decisions need to be made.  It’s important to process, filter and prioritize data to be presented by the HMI, with greater detail available in response to user requests. 

Electricity distribution networks can transition from a steady state to a crisis situation in seconds, so action needs to be taken quickly, with a need for both automated protection equipment and commands form the control room.  Data presentation to operators is designed such that attention is directed toward the problem location.  Often this is done with alerts and alarms that notify operators of a status change when a hazard is approaching or has already occurred.  An example is current flow at each measured location on the grid.  An operator cannot look at readings for all of them at once, but if one in particular is reading outside its normal level, an alert pinpoints the substation that might soon need attention.

 

Security

All of this data flowing in near real time presents security challenges, especially as utilities find operational advantages in bringing together previously separate systems to create integrated networks.  Lawrence presented three components to security for SCADA systems:

Did the data go where it was intended to go, and nowhere else?

Systems need to be in place that ensure this is the case, that are able to determine if control signals received at an RTU are the same as those sent by the master unit.

Did the data contain what it was supposed to contain?

Was it corrupted, through either computer errors or malicious intent?

Speed at which security and data processes are occurring

At the same time utilities need SCADA systems to function more quickly, to transmit readings and control signals with less latency in order to enhance grid reliability, there is a potentially conflicting need to do more to ensure security and data integrity of those communications. 

EMS, DMS and SCADA

Energy Management Systems are used by grid operators (balancing authorities like utilities, BPA, and ISOs) to perform a suite of functions essential to running their high voltage transmission networks.  An EMS is more expansive than a SCADA system, carrying out tasks that require more analysis such as deciding which power plants to use and running contingency analyses.  SCADA is more about supplying data and furnishing control capability, which it does to an EMS, and as well to distribution management systems (DMS) that run the lower voltage distribution wires, leaving the more advanced grid operation functions to these systems.  

Electronic Energy Tagging

In 1992 when Congress passed that year’s Energy Policy Act, development of business practices and information systems was beginning to take place that would later enable expanded commerce in electricity between utilities and non-utility independent power producers.  This practice became reality after FERC issued order 888 in 1996 that required most transmission operators to allow and support open, non-discriminatory access by any electricity generator to their wires that had been in most cases previously only used by that operator’s own power plants.  

Not only was Order 888 a landmark order that changed the course of the electricity business, it required new information systems that would organize transmission providers so as to effectively fashion workable transactions between buyers and sellers of a commodity that travels near the speed of light.  FERC issued Order 889 to accompany 888, requiring creation of a web-based system to do this, calling it the open access same-time information system (OASIS).  This system posts for sale to other parties a transmission owner’s available transfer capability, the capacity remaining on transmission lines once the transmission owning utility meets its own loads.  Electronic tagging of schedules and flows plays a central role.

But enough of the history lesson, on to Lawrence’s explanation of what E-tags do for the grid and how they have been improving over time.  He said making an electricity transaction work is difficult since one cannot “color” an electron that is to be sold from one party to another, rather a generator’s output flows on all parallel paths through the grid; making these transactions work properly has been a long process.  It began in 1997 with NERC tag 1.0, a simplistic version that focused on the “physical path” over which power was to flow from a transaction source through each power system component to sink.  Since electricity does not flow across a defined physical path, greater information was needed about all power flows so as to present an overall picture to operators responsible for reliable grid operation.  This came in the renamed E-Tag 1.6, going into effect in 2000, at the same time as a requirement that all flows be tagged, and the system redesigned to more readily function in real-time.  This allowed operators the ability to better understand the effects on the grid of the growing volume of transmission sales, and tags that threatened reliability curtailed or denied before they took place.   

More to come in part II on Mark Osborn’s lecture on PGE’s distributed standby generation system and its Salem Smart Grid Project.  

Week five featured two guest speakers and a planned lecture by James Mater on interoperability that was cut a bit short.

Our guests were:

Ken Dragoon – Ecofys-US

Lee Hall – Bonneville Power Administration

Both are deeply involved in NW smart grid projects, on different ends of a pilot project funded in part by a BPA program called technology innovation that is investigating use of DR for renewable integration.  Lee Hall works to manage this project for BPA, and Ken Dragoon works for Ecofys, a dutch-based renewable energy consultancy that was the lead contractor.

Ken Dragoon – Role of Demand in Achieving a Low Carbon Grid

Ken has been an active proponent of wind power for many years, and a NW electricity industry expert longer still, having worked for PacifiCorp and BPA.  Before joining Ecofys, he represented wind generators with the Renewable Northwest Project, and more recently worked as the lead for the Oversupply Technical Oversight Committee, part of the Wind Integration Forum at the NW Power and Conservation Council.  So Ken knows wind, and he decided to share his knowledge in a book he published in 2010.

He started out by clearing the air of what he called toxic metaphors that he thinks shape many people’s conception of renewables and the electricity grid.  Metaphor myths in bold and his answers following:

“We are running out of hydro system flexibility to integrate wind”

The reality here is a big improvement in recent years, integrating more wind while using fewer resources.

“We need to back up the wind.”

We back up load, not wind.  We add and subtract resources to make sure load is served, not to “flatten” out wind generation.

“Power system operators must ensure that generation and load match at every instant.”

There’s not an operator in a control room watching every minute or every second to make sure supply and demand always match, conservation of energy makes sure that’s true. 

Capacity?!

Different people attach different meanings to this word.  If you’re talking to someone about capacity, there’s a good chance that person is working with a different definition than you are.

I suppose I’m guilty of perpetuating these metaphors, having followed BPA’s travails with wind integration, used the “back up wind” and “load generation always must balance” comments many times in lay parlance.  I completely agree about capacity definition ambiguity. 

My comments on load/generation balance relate to my own initial misconceptions about how this really works, instilled from hearing many people voice that same line.  Ken is right that there’s not an operator at the switch turning power plants up and down every few seconds to exactly match load.  Utilities have automated systems that do this, called automatic generation control, sending signals to generators calling on them to expediently ramp up or down, but this doesn't quite get the grid all the way to supply/demand balance. 

Instead it is indeed conservation of energy that does the rest, with the inertia in the spinning mass of many large synchronized generators that naturally absorbs and rejects energy, smoothing variations in supply/demand balance and stabilizing the system frequency.  If we move toward a system that has fewer large central generators and more smaller units that have less spinning mass, (or none at all in the case of solar with with inverters) there will in likely need to be more of those second-to-second adjustments by the grid operator Ken was speaking of, usually called frequency regulation.  Here is an electricitypolicy.com article that explains this in more detail.

Ken next showed the class a snapshot of BPA’s system over a typical week:

While BPA’s operators may not be making very many adjustments second-to-second, they certainly are over the course of an hour, the typical electricity interchange scheduling interval in the NW.  A wind farm owner located in BPA’s balancing area that wants to ship power to California, a common arrangement, will submit a schedule to BPA prior to the start of the hour.  As we know, the wind output is likely not to exactly match that schedule, so the enormously flexible hydro system BPA controls stands ready to ramp up and down as needed.  That is to say BPA, as does every balancing area, holds in reserve the amount of generation that is expected to be required to handle not just ramps in wind generation, but fluctuations in load and contingencies such as unexpected loss of a power plant.  As can be seen from the image above, there is often significant movement of both the total wind and hydro generation on BPA’s system. 

Ever ongoing at BPA, it seems, is a process to determine how much money to charge that wind farm owner who relies on BPA to support an hourly schedule.  Initiatives underway currently include scheduling every 30 minutes, and an option for the wind owner to self-supply this balancing energy.  Notable and not mentioned in class was the recent FERC order 764 that will set in motion a move toward scheduling every 15 minutes, an effort to level the playing field for variable renewable resources by lessening balancing reserve requirements.  BPA doesn’t have to follow FERC orders, however they are compelled to try.  But that is another topic for another lecture.

Below is an image showing BPA’s balancing reserve deployment.  Current BPA load, generation information is always available and I recommend everyone in the course check it out.

http://transmission.bpa.gov/business/operations/wind/

Net Load

One more important concept on renewable generation before Ken got into solutions.  Combining load to be served on an electric system with renewable generation produces a net load.  The result is a decrease of net load at times of high renewable production, lessening the need to use conventional resources during those hours.

Going Beyond 20%

Ken talked about parts of the world that have set aggressive renewable energy goals, such as Denmark, Ireland and California.  Denmark has 20% wind today, headed for 50% by 2025.  The Danish wind energy accomplishments are often qualified by their advantageous location with transmission connections to both north to Norway and south to the broader continent, allowing support from both directions for wind balancing.  I've heard numerous times Denmark is able to make use of Norwegian hydro resources for storage and shaping.  Ireland on the other hand, has only weak transmission links to the UK, and decided not to invest in more lines or storage as they pursue 40% wind electricity.  Instead Ken says they will rely on flexible natural gas plants and at times, wind curtailments.

Ireland All Island Electricity Grid Study:http://www.dcenr.gov.ie/Energy/North-South+Co-operation+in+the+Energy+Sector/All+Island+Electricity+Grid+Study.htm

Going beyond 20% will take more than incremental improvements in current grid operations, in Ken’s view; rather it will require “more concentration.”

Inspiration for some of the changes required can yet be taken from Demark, which has seen a major transformation in energy supply above and beyond wind power accomplishments.  Denmark was once heavily reliant on coal and oil, and in response to oil price shocks in the 1970s made a move toward distributed combined heat and power (CHP) and district energy systems that today supply the bulk of heating and electricity in the country.  60% of all buildings there are connected to district heating systems.  Further, the use of thermal storage disconnects heat use in many of them from the heat source.  Ken recognizes the possibility to make greater use of wind energy in this way; hours of excess generation can be buffered by water storage tanks that can then supply heat in hours of deficit.  Below is a picture of large insulated storage tanks that serves Copenhagen.  They are today connected to a CHP plant.

Back in the NW, there are no tanks this size, and district energy systems are few and far between compared to the landscape in Denmark.  Still, it may be possible to employ the same strategies by coordinating the use of many conventional tanks located in most homes.  Ken also notes there are district energy systems in the region that could benefit from thermal storage, mainly in industry, military and university settings, including PSU.  He said Ecofys is interested in partnering with a district energy system operator on a thermal storage project.

Like Conrad Eustis as PGE, Ken wants to organize use of hot water tanks such that they work as a large thermal battery, at a potential cost much lower than other energy storage technologies.  The Ecofys technology innovation project has been investigating this plan, placing controllable water heaters and other thermal storage equipment in operation across the NW, exploring the capability of these units to support renewable integration.  Also shared with Conrad is Ken’s thought that commercialization of water heater controls is best done at the factory for a minimal incremental cost.  He gave a description of a future market he envisions for these appliances where homeowners in need of a new one can choose between a standard unit or one that’s ready to connect with utility signals, perhaps including a discounted price. 

Concluding Ken’s talk were a few questions and discussion of whether anyone would want to have a utility or another entity controlling devices inside the home.  It was clear most think not everyone would want to participate, and certainly no one should have to.  Ken commented that participants in the Ecofys pilot largely did not have these concerns, mainly because they typically received the benefit of increased service from a more capable water heater.  All the better if it comes with a discounted monthly bill or a check from the utility or other company that figures out how to best aggregate end users, manage interactions appropriately, and market this concept.

Besides water heaters, Ecofys is involved in DR projects for cold storage warehouses and data centers.

Lee Hall – Demand Response, Energy Storage and Smart Grid

Following Ken Dragoon’s talk that gave an introduction to wind in the region and in particular on BPA’s system, Lee Hall explained a bit more about Bonneville, part of DOE, that does not own dams, but markets power from the Federal Columbia River Power System.  A striking statistic Lee mentioned right off the bat is the penetration of wind power capacity inside BPA’s balancing authority area, in proportion to peak load.  It’s now about 40%, highest in the US, and fifth in the world.

Ken and Lee both showed a few of the same slides covering BPA’s wind growth and system management, including the image below, taken from the BPA website showing the astounding growth of installed wind capacity from about 2005 through the present.

BPA was an early leader in connecting wind farm developers to transmission lines, and in that way attracted many of them to the NW.  As we've learned, dealing with all of that wind has been a challenge, so to best continue BPA’s mission of providing low rates to its customers, it has been open to all cost effective options for supply of balancing services.  It certainly looks like smart energy management and DR will be among those low cost options going forward.  But we’re not there just yet, a great deal of research still has to be done along with increasing the scope beyond pilot projects to a commercial scale.  

There are also a number of benefits DR can deliver to BPA and the utilities it serves beyond wind integration.  One that Lee cited a few times is the possibility to defer transmission investments through peak demand reduction.  Since BPA is the region’s largest transmission operator, maintaining and building lines is a major cost center that could be more effectively managed if the right parties see the value of deferring payments to expand the system. 

Testing BPA has recently completed, with Ecofys and other partners include:

•         Commercial and public building load control
•         Residential and commercial space heating energy storage
•         Water heating energy storage and load control
•         Industrial process load control and energy storage
•         Large farm water management system load control and storage
•         Small-scale battery storage
•         Load increase using aquifer recharge opportunities.

From this experience Lee highlighted four areas of near-term benefit or BPA and utilities:

Capacity

The rates BPA charges many of the utilities it serves include incentives to limit peak demand, done by instituting higher demand charges in recent years, so some of them are investing DR on their own to limit their exposure.

Balancing Reserves

DR as a resource BPA can call upon for reserves to augment the hydro system and purchases of conventional resources.

Generation Oversupply Management

Springtime high river flows can reduce balancing reserves available from the hydro system.  In past years, wind generation has at times been curtailed.  DR could shift greater load toward the hours when this occurs.

“Non Wires” Peak Load Reduction.

Transmission investment deferment as described above.  Transmission construction starts at about $ 1 million/mile. 

In closing, Lee noted the need to effectively coordinate and communicate between all of the parties that are likely to be involved as DR scales up among NW public power utilities.  There will be benefits to BPA, the local utility, and to the end use customer.  Work on how best to structure the share of benefits between the participants is underway currently, and is likely to undergo refinements as projects are deployed and money is invested to go beyond the pilot stage.

James Mater – Smart Grid Interoperability and Standards.

James took a short time at the end of class to begin his lecture on standards.  To start he referenced a National Institute of Standards and Technology (NIST) report that assessed the utility picture in the US with regard to standardization and interoperability.  In short, there are over 3000 utilities, and many have traditionally done things their own way, with the exception of electrical standards such as plugs.  The focus on physical standards has been at the expense of software and information standards, according to James. 

He gave an example describing meter data management, which I’ll expand on a little.  In the past, systems to collect and process data were customized, where one utility might have a completely different format than a neighbor utility.  If these two utilities then decide they want to link meter data systems to their billing systems in different ways, perhaps for a new time-varying rate option, two customized upgrades are needed, perhaps by two separate vendors.  That might be good business for the vendors and system integrators selling and maintaining proprietary systems, but it’s probably not in the best interest of the industry as a whole to continue doing business this way.  If both utilities were using an industry-wide standard, many experts today think there’s a good chance the cost to make such an upgrade would be lower and the quality higher, since more robust competition would occur between sellers when the playing field has been standardized. 

GWAC Stack

James described the Grid Wise Architecture Council’s Context Setting Framework, or stack.  It’s inspired by the Open Systems Interconnection 7 layer reference model (OSI model) that separates networking communications functions into layers so as to break the whole system into components that work together. 

-Bill Henry

During Conrad Eustis’ lecture on the advanced metering infrastructure project he spearheaded at PGE, a class discussion began to develop when James Mater asked about the capability of smart meters to provide usage data to customers in real time.

Conrad’s answer went something like this: it is possible to do that, but not recommended because truly real time information (display of instantaneous power use) would fluctuate so often it would be hard for customers to grasp what’s going on in that granular data and wouldn't be able, or want to take substantive action.  He asserts that if you’re watching a display show increasing power use while cooking dinner, you’re not going to stop cooking. 

His preference is to evaluate historical use for patterns that can direct customers toward simple steps they can take to save money, to focus analytical effort on total energy, kWh, and dollars, not instantaneous power, kW. 

There’s a little more to the part about it being possible to connect customers with real time data; simply, right now PGE’s smart meters are not ready.  A little smart meter background: most deployments around the country install meters with two radios, one for sending information to the utility, and the other intended to send data into a customer’s premise, such as to a real time display.  PGE decided to omit the second radio to save money, and that was a probably a good call, since the communication method it would have used is today quickly becoming obsolete.  At the time, Conrad decided the in-home communication capability could be added later for those who wanted it, and so far he said, nobody has asked for it. 

That brings us to the title question of this post, who wants it?  In class, there were a number of questions and comments that differed somewhat from Conrad’s views on this topic.  My personal opinion about real time information is simple: I want it.  If I had such a device, I think it would be easier to be more engaged with household energy use and save money by shifting use (I have PGE’s time of use rate).  Sure, I could pour over the historical data viewing tool PGE provides on the web, and I have, and that would likely give me the most detailed and accurate picture of what drives my monthly bill.  But it’s hard to beat real time feedback; when you flip a switch, you can see what happens.  So I’ll make immediate, if less comprehensive information my preference.  What’s yours?

-Bill Henry

Class meeting 4 featured a two part lecture by Conrad Eustis, a Portland General Electric smart grid expert and former faculty member for this course.  Mark Osborn also lectured on smart grid basics and energy storage, and two student groups completed short presentations on our first group assignment.

Solar Output

Before Conrad’s lecture, Mark Osborn spoke for a few minutes about calculating the output of a solar array, in response to a question on the topic from the previous class meeting.  He referenced a website run by the National Renewable Energy Laboratory called PV Watts that can be used to estimate solar energy generated by location for a given PV system size.  A PV system will only produce its rated output at noon in the summer, other times it will be lower, so this website is an easy way to find out a yearly total kWh estimate.  I recall the question was about how to plan and size a PV system; usually when participating in a utility net-metering program, the goal for the solar designer is to match annual total electricity consumption with total annual solar output.

http://rredc.nrel.gov/solar/calculators/pvwatts/version1/US/Oregon/Portland.html

Conrad Eustis - Tradeoffs in the Smart Grid

Conrad gave us a utility viewpoint on some topics we’ve covered in class so far and introduced some new ones.  Broadly, he talked about:

•         Utility investments balancing costs vs. benefits and other factors.
•         Electricity generation efficiency
•         Calculating levelized cost
•         CO2 emissions
•         AMI (advanced metering infrastructure)
•         Demand response basics
•         Water heater demand response

Conrad’s first presentation carried a title that explained a great deal about the approach he takes to developing business plans and conduct analysis at PGE: “Tradeoffs in the Smart Grid…you can’t get something for nothing.”  He took the first few minutes to explain more about these tradeoffs, offering examples by posing questions about raising electricity rates; would you like to pay more for electricity if it was generated with a larger proportion of renewables?  How about for reduced yearly outage time?

Investment decisions by regulated utilities are an extended exercise in balancing tradeoffs, according to Conrad.  He emphasizes economics as the main focus by utilities and regulators who approve or disapprove their investments.  But there are certainly other influences throughout the process, for which he adds two categories, social and environment.  It’s not easy to find ideas that satisfy all three at the same time.  It may be simple to come up ideas that are great for the environment, but they may be lacking in the other areas, so he cautions that as we move toward solutions that put more emphasis on environment, we keep in mind economics because some such options might simply be too expensive to be given very much consideration by an economics focused regulatory system.  Here’s a summary of the latter two categories of investment justification:

Environment

It’s a combination of regulators, legislators and courts that define requirements that oblige utilities to make investments that benefit the environment.  This category goes beyond state regulatory commissions, since the EPA calls a lot of the shots, as do federal courts in the NW on Columbia River matters.  Utilities must comply with federal laws (example: clean air act), as well as state laws (example: renewable portfolio standard), so commissions don’t perform the same cost benefit analysis for these mandates as they would for other investment proposals. 

Social

Regulators and participants in the utility commission process take steps to make electricity pricing fairer to low income customers, largely not involving taxpayers.  It’s worth expanding here slightly on what Conrad said to note that many states intend that when subsidy is directed toward low income electricity customers, it is to come through ratepayer cross-subsidization, and not by redistribution of taxpayer wealth. 

Conrad also talked about ratepayer equity concerns that seem likely to be on the rise in overall importance, linked as they are to adoption rates of demand-side programs such as energy efficiency and demand response.  When customers make these investments that cause their bills to decrease, it doesn’t always mean utility costs went down an equal amount.  If not, more revenue is needed to make the utility whole.  If it comes through a rate increase, the impact will be felt more acutely by those customers who did not or were not able to invest in efficiency or DR; disproportionally these are low income customers.  Some argue this is the most important issue up for debate when it’s time to evaluate demand-side procurement options; they bring with them equity complications that I think are far from simple to sort out.

Solar net-metering programs present a similar equity challenge.  They allow a customer to reduce their bill to zero when solar generation matches or exceeds electricity consumption.  Utilities argue there is still a cost associated with serving that customer; today these costs would be spread across the other customers not taking part in net-metering. 

Bottom Line

Summary of the regulatory & policy portion of his lecture:

• Laws trump costs.
• Utilities build and buy renewable electricity even though it is more expensive than conventional resources to comply with state laws.

• Regulatory decisions made in the public interest
• This generally means dollars and cents, lowest cost.

• “In the public interest” can be broadly interpreted
• As a result, other social “soft” issues are brought into the regulatory process

• Free market is desirable but requires higher ROE
• Public utilities subject to economic regulation generally require a lower return on equity than private businesses, a key disadvantage to be considered when markets are discussed.

Efficiency and Heat Rates

Next, it was time for some efficiency and cost numbers.  Conrad spoke about energy conversion efficiency; for a thermal power plant it’s called the heat rate, defined as: Btu of heat to generate 1 kWh; lower is better.  A thermal power plant is one that uses heat from any source to spin a generator, commonly they are fueled by natural gas or coal.  Conrad provided a list of heat rates and efficiencies for various power plants, ranging from a natural gas fired combined cycle combustion turbine (7000 Btu/kWh, 49% efficient), to a typical gasoline engine used for power generation (18,000 Btu/kWh, 19%).  When fuel is burned in these machines, a portion of its energy is converted to electricity; the remainder usually goes to heat, sometimes called waste heat.  This heat is sometimes put to use (cogeneration, also called combined heat and power), but it is often discarded to the atmosphere.  He included a diagram showing fuel input and heat and electricity output of a generator:

Levelized Plant Cost

Representing the costs of a power plant as a levelized cost per unit of electricity over its lifetime is a comparison tool Conrad suggested the class learn so as to best compare and contrast different power plant options.  He boiled down what he called a huge utility spreadsheet to a single formula:

Main inputs to this formula:

• Plant capital cost $/kW

• O&M $/kW-yr
• Cost for operations and maintenance per year compared to plant size

• Capacity factor
• The formula spreads costs over the number of operating hours per year; if it only runs a small number of hours per year, it will result in a high levelized cost.

• LARR (levelized annual revenue requirement) $0.13/yr
• Utility cost of equity & debt, profit and taxes accounting lumped into a single number to enable back-of-the-envelope plant cost estimates.

CO₂ From Fuels

Conrad showed us how to calculate a power plant’s carbon emissions.  It’s as simple as pounds of carbon dioxide that result from burning a Btu of fuel.  Two important fuels are listed the units are in millions of Btu (MMBtu):

• Natural gas:
• 1 MMBtu will emit 166 lbs of CO₂

• Coal:
• 1 MMBtu will emit 206 lbs of CO₂

 

AMI (advanced metering infrastructure)

Portland General Electric completed between 2008 and 2010 one of the most successful AMI roll-outs in the country, deploying over 800,000 smart meters across its service territory.  These meters communicate customer usage data by radio to a local collector which feeds into PGE’s computer systems for billing and other functions.  What is most impressive about PGE’s smart meter program, in my view, is the relative ease and speed with which it was undertaken, with cooperation from the state regulator and general lack of opposition from the public.  This is in contrast to smart meter programs in other states that face more trouble justifying the cost to regulators and growing resistance from customers and consumer groups who don’t like the radio communication technology or for various other reasons, such as privacy concerns or rate increases, have been attempting to slow deployment.  This is probably most acute for Pacific Gas & Electric in California; I’ll take a paragraph to describe what has happened there. 

PG&E first deployed their smart meters in Bakersfield in 2009, which in an example of horrible timing coincided with an entirely separate rate increase and a hot summer.  As a result, many customers associated the higher bills they were paying with their new smart meters, leading to unexpected media coverage and lawsuits about meter accuracy, among other things.  After that first episode, the ranks of activists concerned about the ratio transmitter in the meters began to grow and it’s generally been a bumpy AMI road for PG&E ever since.

Back here in the NW, PGE didn’t really have any of these problems; it swiftly and rather quietly, installed them across its service area.  One big reason for this success has been Conrad’s work on various advanced metering efforts since 1993.  He said it was the technology price point that by 2006, the solid state metering and radio electronics had finally dropped low enough to make such a project palatable to the utility and to regulators.  Conrad had already been building a business case that showed savings to ratepayers; by 2008 PGE had vendors, regulatory approval and installation contractors.

Conrad Described AMI as building a system that looks like a cellular telecom network, that’s dedicated for utility use.  It cost $145 Million, in addition to $30 Million needed for accelerated depreciation for the old meters that were retired a little early.  Conrad’s business case offset these costs by reducing the operating costs (meter readers are no longer needed), and increasing functionality to both the utility and customers.  

More to come about advanced metering benefits to consumers in my next post on real time data access.

Mark Osborn – Smart Grid Elements and Theory

Mark next covered more grid basics, following on from his previous class lecture on electricity essentials.  He mentioned the Northeast blackout of 2003 that was the second most widespread power failure in history after one in Basil in 1999.  It was a cascading blackout, where initial failures occurred that overloaded an adjacent portion of the grid, resulting in yet more problems when protection equipment serving additional transmission lines and power plants tripped them offline for safety and damage prevention.  This process “cascaded” across the grid, starting in Ohio where a transmission line sagged into a tree, reaching as far as Massachusetts and Ontario.  

This event caused some rethinking of the way the grid is managed, and helped accelerate the movement toward smart grid technologies and business models that bring greater reliability to the bulk power grid and benefits to consumers.  According to Mark, the push to make the grid more reliable, combines with aging infrastructure, increased penetration of variable renewables, and an increasingly aware and eager consumer, to set the stage for some major changes to the electric system and of course big opportunities for those with smart grid solutions.   

Here’s a summary of Mark’s key elements of the advancements that could result in higher reliability, greater flexibility, lower cost and greenhouse gas reductions.  He drew from sources such as one of our course texts by Peter Fox Penner, and IEEE papers.

• Hierarchical Control – grid status & conditions
• One of the improvements being made today in response to the 2003 blackout is greater visibility by grid operators to real time status, one type of equipment involved here are phasor measurement units (PMU), we’ll talk more about them later in the class. 

• Flexible Generation – ramping capability in response to renewables

• Transmission Availability
• Work is needed to improve the performance of transmission lines to move more wind and solar power.

• Distributed Generation – resources close to load
• Resources such as CHP, solar, and storage can reduce the need for new transmission lines.

• Demand Response – modify customer demand

• Self Healing – fast switching and microgrids
• Better ability to isolate problems, and allowing pockets to island themselves (microgrids) preserving reliability there and lowering grid stress elsewhere.

• Advanced Metering Infrastructure

Mark described a typical load shape today in the NW, and showed how power plants are dispatched to match it, over all hours of the day.  Below is a simplified diagram he made, displaying fist the load shape without generation, and then bringing on power plants as needed throughout the day.

That’s what things look like today, however, with an increased reliance on renewables, utilities will need to adjust schedules and resources to meet changing system needs.  The example mark gave to illustrate this is a mismatch between typical solar generation patterns and the daily load shape.

Storage and Demand Response

The figure above shows an excess of solar generation in this hypothetical case in the middle of the day.  Storage for use at a later time is one way of making the two curves match.  Another way is to use demand response to adjust the time of day consumption occurs so that it is a better match for the generation peak.

Conrad – Demand Response

Conrad continued his lecture, moving into demand response and a program he’s working on at PGE to connect electric water heaters in the region with a utility signal.

He defined demand response as:

• The reduction of electric usage in the premises based on utility price or other signals especially during times of high use.

Demand response is one of those terms that like smart grid, can have many interpretations.  I’ll only add that in some applications, the definition can include both an increase or a decrease in usage as DR moves into grid support services other than peak load reduction, the traditional way it has been used, especially in other areas of the country, notably the East Coast and California.

An informative chart helps explain the traditional DR application for peaking use.  It is a representative load duration curve for PGE showing the number of hours each type of power plant operates per year.

The load duration curve is missing content on the right side of the graph (it goes all the way to 8000 hours), but let’s focuses on the left side that shows generation resources that are used the fewest number of hours per year.  These are generally the most expensive, such as the simple cycle combustion turbine (SCCT) that has a lower efficiency level than a combined cycle plant, and a high cost for fuel, so this chart depicts it would operate for only 300 hours per year.  Traditional DR participants seek to displace the need for this type of power plant.  Below is a generic image showing peak load reduction DR participating in the New England ISO market.

Water Heater DR in the NW

The NW uses electric resistance water heaters to a greater extent than many parts of the country, and I’ve often seen a figure of 3 million of them operating in the region.  Conrad and many others are keen to find ways to interact with water heaters and the customers using them in ways that support grid operators. 

Standardized Communications

Conrad has identified lack of standards the biggest barrier to DR at the household appliance level.  If manufacturers sold appliances such as water heaters with a standardized communications system, many argue utility DR programs could be implemented much more economically than an alternative using a customized retrofit approach.  He has been active at the national level trying to convince appliance manufactures to build in at the factory a newly developed plug standard, ANSI/CEA-2045.  Customers and/or utilities could then plug into it a simplified device that could talk to a demand response program operator using a multiple communications methods, such as Wi-Fi and internet. 

Conrad estimates PGE can cut 0.6 kW of peak demand per water heater (max demand 4.5 kW).

There will definitely be more content ahead covering standards and what they mean for the industry.

Mark Osborn - Energy Storage

Energy storage types that Mark talked about:

• Thermal energy storage
• End use hot or cold storage to shift energy consumption associated with heating and cooling
• Solar thermal storage at solar thermal power plants allowing them to continue to produce electricity during cloudy periods or at night.

• Pumped Hydro
• Water is pumped from a low reservoir to a high reservoir.  At some later time it turns around and flows back down powering a generator.

• Compressed air energy storage
• High pressure air injected at high pressure, usually in an underground cavity

• Rechargeable batteries

In part II of class session 3, I’ll cover the rest of Mark Osborn’s lecture about the power system in place today.  After covering the basics of generators and the high voltage transmission network, Mark spent some time on the distribution grid, looking at the equipment located at distribution substations used to regulate voltage (tap changing transformers) and protect assets in the event of a fault (circuit breakers). 

A tap changing transformer can modify the ratio between its windings, giving it the capability to manipulate voltage on a section of the distribution grid, helpful to utility operators who are in control of these devices using SCADA (supervisory control and data acquisition), to make adjustments when usage on that section causes voltage to increase or decrease. 

Circuit breakers can interrupt current flowing through a substation when necessary.  Much the same way one of these functions to cut off a circuit in a house when it becomes overloaded, a circuit breaker at the utility scale ups the ante considerably, with hundreds of them standing ready to protect billions of dollars in grid assets when a problem occurs.   

One problem that occurs all too often in the NW is a tree that falls upon a power line.  This could cause a fault in its circuit, meaning in some cases current will flow into the ground.  It is to handle this type of circumstance that the substations we see all over the grid are configured with what seems to be such large and extensive amounts of equipment.  The fallen tree has created a short path to ground over which a large current will flow, threatening to overload everything near it.  To stop it, a simple switch won’t do; the elevated current level would find a way right across it and keep flowing.  Circuit breakers are built to interrupt fault current, many times greater than ordinary flows.  They do this by suppressing an arc using a housing containing mineral oil, a vacuum or sulfur hexafluoride gas.

Utility control of protection equipment like circuit breakers using SCADA systems allows for operation schemes that have been developed to keep the lights on to as many customers as possible when there’s a problem.  A Recloser was discussed as one such tool that seeks to determine if a fault that has been detected is momentary or will last longer and require restoration operations.  We heard that many faults are short lived, with a quick resolution (the tree falls off the line).  Upon the first signal of a fault, the appropriate circuit is cut off, then the recloser turns it back on to determine if the fault will continue or has ended.  If it’s over at that point, only a flicker in the lights would result.  If not, the recloser stays open, that circuit goes down, and utility crews head out to look for fallen trees or other mishaps.

Other topcs covered:

Residential and Business Service

The prospect of DC distribution

Balancing Areas, Interchange, daily load curve, and power marketing.

The third class took a step forward in time as Mark Osborn explained the grid we have today, drilling down to the physics of an electricity generator and then describing what transmission and distribution networks look like before speaking about how electricity flows are managed, bought and sold across those lines and between utilities.

Mark started right off on electric power generation, giving us a simple physical demonstration by holding a magnet over a coil of wire and beginning to rotate the magnet.  He had connected a meter and it showed a fluctuating voltage as he spun the magnet.  He was causing a current to flow in the wires, motivated by a potential to do work, or voltage, delivered from the spinning motion of a magnet in the presence of a coil. 

The meter display showed the relationship between the spinning motion and the voltage level.  Mark noted the voltage was changing along with the orientation of the magnet, switching between positive and negative as it rotated.  The rotating magnet subjects to coil to a time-varying magnetic field, causing what electrical engineers call electromagnetic induction.  The moving magnet induces electrons to move around in the wires.

Mark's display illustrates an AC generator where the electric charge direction reverses as a magnet rotates (the rotor) inside a stationary portion of the machine housing coils of wire (the stator), and voltage follows a sine wave pattern as it oscillates between positive and negative. 

Going back to Edison’s time, Mark explained how a generator much like the one he demonstrated was fitted to produce DC power.  Edison used a commutator, a switch that redirects current flow out of the generator to prevent voltage from going negative.  Mark used a website with a generator animation to show the AC and DC configurations of a simple generator.  Two screenshots are included below.

http://www.generatorguide.net/howgeneratorworks.html

First, the AC version is shown with the sine wave voltage form:

Then a commutator is added that switches the current output such that voltage does not occupy the negative region on the voltage graph to produce DC:

When Tesla was building DC generators for Edison, he had to spend a great deal of time making the commutator work as intended.  It has to complete a switching action two times for every revolution, making it a complicated device and causing headaches for Tesla.  He solved the problems, but also decided he wanted to remove it entirely and send AC over the wires.  Mark read an excerpt from a speech he gave in 1888 that promoted AC over DC.  He asserted that all generators were AC machines and not only was DC a manipulation external to the generator, but it was also of inferior usefulness.  The latter point he illustrated with an example the electric motor, which he found needed to use AC to work properly.  It did not make any sense in his view to use DC at all if there was a motor at the end of the line that used AC. 

Fast forward to Modern AC power systems, which operate at 60 Hz, meaning the voltage sine wave completes 60 cycles per second.  They also utilize more than one set of coils, called windings, in the stator to create three separate sine waves called phases.  Mark's slide below shows a 3-phase generator; the spinning rotor motivates the phases as it passes each of the 3 stator windings (also called field coils in the slide).

This 3-Phase system sends electricity out of a generating station on 3 separate wires.  The picture below shows a large transmission line leaving a power plant.

As we learned from the battle of currents, AC power works well for transmitting power long distances at high voltage.  The transmission line pictured carries power that has been elevated to a very high voltage to allow more power to be shipped a long way with low line losses.  The ability to readily step up or down the voltage level using a transformer is the most important advantage of AC.  Large transmission lines use 115,000 to 750,000 V, while most all customers are served below 500V, so a network of transformers located across the grid raise and lower voltage as needed. 

A transformer is a remarkably simple piece of equipment, at least in concept.  It is made of coils of wire wrapped around a magnetic core, usually Iron.  Incoming wires carrying one voltage are coiled around the core a specific number of times, while the outgoing wires coil around the core a different number of times and will leave the transformer at a different voltage.

Transformers can be found in utility substations, nodes in their high voltage transmission networks where equipment is housed to manage power flows and one of the locations where voltage may be reduced to supply the smaller lines that run throughout cities.  Mark showed a picture of a substation outside of Portland where a large 500 kV transmission line terminates, with the energy it carries distributed among many smaller lines, called subtransmission lines, that reach into the city.  These lines, usually in the 60 to 115 kV range, supply another set of substations where voltage is stepped down yet again and routed to the lines that serve homes and businesses.  These lines, called distribution feeders, still use voltage that is too high for most users, so there are a final set of transformers, often mounted on poles that step down the voltage to the correct level for each customer.  One of Mark’s slides had the picture below that shows two sets of wires carried by the same pole.  Above are the subtransmission lines and the three lines below are distribution lines.  A transformer can also be seen on the pole that taps into the distribution lines and is connected to customers in the immediate area. 

After explaining transformers, there was a question from the class about differences between AC and DC transmission lines.  There are today a limited number of examples of long haul transmission lines that use high voltage DC. There was some confusion in the class about the use of DC in this way in light of what we recently learned about the battle of currents, in much the same way I was confused when I first learned of the concept of these large DC transmission lines.  It turns out that all else equal, DC has lower resistance than AC, and would do very well to transmit power even more effectively than AC.  But the catch here comes attached to the all else equal part; creating DC at the high voltage required is remarkably difficult and very expensive.  It is only done when a transmission line is very long, making it worth the extra expense for converter stations at each end that are much more extensive than what is normally used for an AC line.  A west coast example illustrates the distance over which DC lines are used.  The Pacific DC intertie is a line that runs between The Dalles and Los Angeles.  It does not connect with the rest of the grid at any point in between.  I’ll speculate that if it was required for this line to supply power to a point in the middle, an AC line would perhaps be more economical.  Below is a picture of the PDCI.  Note, also depicted is an AC intertie from OR to CA that exchanges energy with numerous substations along the way.

 More to come in part II of blog 3, there will be more on the distribution system and a description of the wider power system, interchange between utilities and electricity markets.

-Bill Henry