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We all have a lot of hope for what is going to happen with regard to energy production and consumption in this country after the magic day of 1/20/09. There is a lot of excitement out there for wind, solar, bio – but I’m here to tell you that some very non-high tech stuff is going to stop the US from ever taking advantage of alternative energy in any sort of meaningful way.
The grid – that network of cables big and small, poles big and small – frankly is designed and works almost exactly the same way it did when Thomas Edison flipped the switch for New York City’s first customers in 1882. Our system is based on bringing the cheapest power, through power generation plants, to the most people – and is controlled not by a federal system, but by interlocking state and regional systems, encompassing 164,000 miles of high voltage transmission lines and more than 5,000 different local distribution networks…all controlled at the local level by substations using electromechanical switches – the same sorts of devices developed in Edison’s time.
And while it tends to work pretty well under ordinary circumstances and under power outages, it is also operating extremely close to the edge in terms of total capacity of the system as well as the age of various components in the system. It also has no real flexibility in terms of handling or reporting sudden influxes of energy or drops in demand, which is exactly what engineers face in countries such as Germany(which are way ahead of us in terms of wind power generation) – they are literally having to order expensive energy ‘on the fly’ as their banks of wind turbines generate…or not.
“While this structure has served remarkably well to deliver cheap power to a broad population, it’s not particularly well suited to fluctuating power sources like solar and wind. First of all, the transmission lines aren’t in the right places. The gusty plains of the Midwest and the sun-baked deserts of the Southwest–areas that could theoretically provide the entire nation with wind and solar power–are at tail ends of the grid, isolated from the fat arteries that supply power to, say, Chicago or Los Angeles. Second, the grid lacks the storage capacity to handle variability–to turn a source like solar power, which generates no energy at night and little during cloudy days, into a consistent source of electricity. And finally, the grid is, for the most part, a "dumb" one-way system. Consider that when power goes out on your street, the utility probably won’t know about it unless you or one of your neighbors picks up the phone. That’s not the kind of system that could monitor and manage the fluctuating output of rooftop solar panels or distributed wind turbines.”
In order for the United States to be able to even start to take advantage of alternative energies, we must do two things: invest in new and expanded infrastructure in places where the energy IS (which is usually where people are NOT, which makes it very expensive and not attractive for utilities to invest) and second, we need to put the entire national grid on a new ‘smart grid’ system, which will literally put power producers and users into a self-balancing organization. If wind or solar generation drops, a smart grid system can balance power consumption right down to the appliance level, and will also tell customers what is happening at any given time.
“..Xcel Energy and several vendors are investing $100 million to install a smart-grid infrastructure in Boulder, CO…installing two-way electric meters in 50,000 homes. Homeowners are getting software that lets them view and manage their energy consumption on the Web, and some of their appliances are being fitted with switches that will let the utility shut them off remotely during periods of high demand…Smart-grid technologies could reduce overall electricity consumption by 6 percent and peak demand by as much as 27 percent. The peak-demand reductions alone would save between $175 billion and $332 billion over 20 years, according to the Brattle Group, a consultancy in Cambridge, MA. Not only would lower demand free up transmission capacity, but the capital investment that would otherwise be needed for new conventional power plants could be redirected to renewable. That’s because smart-grid technologies would make small installations of wind turbines and photovoltaic panels much more practical..”
The challenge to both of these is the way the system is regulated presently, with a patchwork or state and regional organizations along with FERC, the Federal Energy Regulatory Agency. FERC basically can do things like overrule state level decisions on siting transmission lines, but only in US DOE critical energy areas(there are two on the East Coast that have been so designated and even in those areas, problems and delays exist). So far, FERC cannot force states to work together (such as in the situation recently where SoCa Edison proposed a major transmission line from LA to Phoenix to bring solar energy to Southern California – the state of Arizona rejected the idea), which puts bringing energy from areas such as ‘the empty corridor’ in the Midwest into doubt. At the same time, there is no federal policy on renewables; there are people who feel that one of the problems with this is that renewables need to become more lucrative than current coal-fired or natural gas fired electricity. If this were to happen, the thinking goes, utilities will be more interested in investing in grid capacity. At the same time, however, as long as the grid at the local level, still operates with 19th and early 20th century electromechanical devices, the communication between production and use does not exist and the system will not work very efficiently.
So, I think the discussions need to be made at the right level, which is national policy, and national investment – an expansion and total top-to-bottom rebuild – no more ‘tin cans and pieces of string’ technology. Otherwise, the whole discussion of renewable, of ‘energy independence’ is sort of moot.
23 Comments
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Excellent job. Thanks.
Obama stated just last week, that he was committed to rebuilding the national energy grid, going to a smart grid model, in order to support alternative energies. I’ll try and find the comment.
This is a much more complicated situation than one originally thinks. More investment will mean more jobs.
One of the major question is what the role will be for the utilities – these are publicly-owned (that is by stockholders)entities. They have assets on the balance sheets. This could change their organization and frankly their existence. This whole thing needs to be done…but HOW?
Toby, thanks very much. FWIW Scarecrow knows a ton about the utilities.
ooo, in which case, I hope he stops by…
Agree.
I don’t know much about the whole set-up. I believe the new generation of transmission lines are called HVDC (High Voltage Direct Current). I believe that’s the technology that allows power generators to come on board more easily than is now the case.
Another increased drain on the grid will be electric vehicles and hybrids.
Because the smart grid allows more power generators, it automatically decentralizes the entire system. That increases redundancy and security.
Building a new smart grid is number one on my list for stimulus projects.
The information you provided about the two-way meters was very much appreciated. Prior to reading your post, I had no knowledge of that part of the complicated equation.
One of the problems with the grid as it now stands is the whole issue of ’scheduling’ your power into the grid. If you have power to sell into the system and ‘the hose’ (the grid) is fully scheduled by other providers…you may as well have a load of manure as power to sell – you can’t sell it if you can’t get it to where it’s needed. That is one of the issues with the capacity of the grid. It’s basically fully scheduled as it is.
Good stuff, Toby. Thanks for the Talbot article link. Coupla observations:
1. The “Smart Grid” is a catchall phrase for several pieces that don’t all have to be done at once. Break the system down into (1) high voltage transmission — the big lines/towers, (2) low-voltage distribution, that carry power from the transmission lines/substations to end users; and (3) the metering at the end user — your home.
(1) We don’t have all the transmission we’d like to have to the major wind resource areas. If we build it, we’ll have to allocate the costs to . . . whom? Presumably the “beneficiaries,” which include the generators at one end, the consumes at the other. FERC will play a role in deciding and the rules remain unclear
(2) Distribution system in older cities were build decades ago and need a lot of replacement/upgrades. Most of our “outages” happen there; lines break down, transformers blow up, switches stop working. These systems are owned by you local utilities, and paying for those upgrades is a cost that goes straight to the utility rate base — it collects additional rates to pay for the cost plus reasonable rate of return (profit).
(3) “Smart” meters could be installed now, without (1) and (2) fixes. One upgrade allows the meter to measure energy use each hour, rather than cumulatively over the month. You’d then be billed for each hours use times the price during that hour. That also means your billing system has to change. Some states are doing this, but most not. A “smarter” meter is two way — it measures energy use and sends that info back to the utility, but it also sends the hourly price back to the customer — two way communication. Your “smart appliances” can then be programmed to use energy when it’s cheaper and less when it’s costly. The rates would vary each hour. California is planning to do this in their new building standards. Others will follow only if prodded.
2. A key institutional piece is “Regional Transmission Organizations.” These regional quasi-govt entities operate the huge regional grids in half the US. Their rules allow open access to competitors, facilitate renewables, don’t discrminate, and they operate wholesale markets where anyone can buy/sell electricity in real time. In the other half of US, large utilities still operate the grid: they do discriminate against competitors, and renewables only get on if the utility owns/controls them. It’s a barrier to entry. RTOs need to go national, but it’s hugely controversial.
The biggest issue is not just the capacity of the grid but who operates it and under what rules.
My big question and I do not have an answer for this is how we get the utilities to get on board with a national system. You are soooo right about old urban area infrastructure – the entire system inside New York City is an absolute wreck, frankly – as I recall, every summer for the past three years(or is it 4?), there has been a major outage that has come from Queens or the Bronx. This is ConEd and they got slapped with a big fine and an extremely nasty rating from the PSC because of their terrible record of service and maintenance. This is a huge undertating. And frankly, even without looking at smart grid, the United States has a horribly antiquated, poorly maintained system — the case of the outage that started in Ohio and then moved east to New England and up into Ontario was a very stark example — the number of substations and ‘handoff-points’ (where power goes from Ohio to PA) that were under emergency maintenance and repair conditions (not scheduled maintenance outages) was really quite amazing at the time.
A major reason the grid is so stressed now is because of the industry restructuring that has taken place under the general label of “deregulation.” The transmission grid (In the utility industry “transmission” refers to the high-voltage lines that move bulk power from the points of generation to substations in the general vicinity of the customers; “distribution” consists of those lines, transformers, etc. that move it from there to your home, office or factory.) was built when the industry was vertically integrated and geographically segmented. That is, utility companies had a defined service area in which they generated the power, transmitted it to the vicinities of its loads, and distributed it to those loads. Interconnections between utility companies, which began in the 1920s, IIRC, and really accelerated after World War II, were undertaken first and foremost to improve reliability, and secondarily to achieve economies of scale. The practical size of generating plants increased steadily after the war, and as they did the operating and maintenance costs dropped, both in terms of capacity (megawatts) and energy (megawatt hours). Thus, two companies that both needed more generation could save by building one large unit and sharing the output rather than by each building a smaller one.
The deregulation advocates, many of whom came from various fuel industry backgrounds (oil & gas, especially), were mostly interested in deregulating the generation piece. And thus that’s where the greatest restructuring towards competition has taken place. There has also been some competition introduced at the retail end-user level, in which case the distribution company becomes like a common carrier.
The transmission piece in the middle, however, is problematic because it does not really lend itself to a viable business model on its own. Yet the grid has been hugely stressed by what’s going on in the other two functional areas, but especially in generation. For example, in 1996 the Tennessee Valley Authority system control center handled 20,000 energy sale or purchase transactions involving itself and other utilities. In 1999, in just three years as deregulation ramped up, that number had increased to about 300,000! A great many of these, probably a large majority, were wheeling transactions in which TVA was simply moving power across its system from seller to buyer. In other words, a grid that represents billions of dollars of sunk investment that was made during an era when one business model dominated, is now being asked to serve the needs of a radically different one in which there’s no clear incentive for anyone to strengthen the transmission system to handle it.
Yes, absolutely – and while the system is ‘wheeling’ power across the grid — it is taking up capacity. The whole deregulation issue is another story altogether – it has encouraged utilities to not build, not maintain, not expand. There is no money in it for them so they don’t. Which is why you have problems like utility fires caused by brush and trees out in California causing those huge fires wildfires.
Wrt to whether “deregulation” overloaded the system, I don’t think that’s true. I agree the grid is being used differently from how the original utility owners thought it would be used, but it’s not being used beyond it’s safe operating capacity. The system operators, whether RTOs or utilities, don’t allow flows to exceed safe operating limits, and they adjust generation dispatch every five minutes — which changes the flows — to ensure that doesn’t happen. This is standard industry practice in all of US (and most of world).
“Dergulation” is a misnomer; nothing was dereglated; the regulations changed, and new entities, RTOs, were created. Their operations are subject to heavy oversight. In fact key parts of the electricity sector are more regulated today than ever. [Disclosure: I sometimes work for/with RTOs]
The Ohio-based outage in 2003 was not caused by inadequate transmission; the original NERC reports found grid monitors that tell the utility control room operators what’s happening failed, so the utility grid operators didn’t know a line had gone out. As soon as that happens, flows instantly redistribute along all other possible transmission paths, and some became overloaded and also started tripping off generators (auto shutdown to protect the generator) — it became an uncontrollable chain reaction as generators tripped, more lines failed or automatically disconnected, etc — and because the guys in the control room couldn’t tell what was happening, they didn’t warn their neighboring utilities or RTOs. Because the entire Eastern Interconnection is all one grid, the cascading failures kept propagating through the system through every piece that didn’t automatically disconnect. [That’s one official theory; there are others.]
Deregulation had nothing to do with that event, unless you want to argue that Ohio regulators failed to give the utility (First Energy) enough money to maintain good control room monitors, etc.
Since then, that utility has joined an RTO, and the RTO operates it’s transmission system and generation dispatch within a much larger grid — from a huge control room with monitoring screens that can see the entire Eastern grid — every line, evern generator, every load, all the flows. That system wasn’t in place in 2003.
“Deregulation” sometimes refers to (1) allowing non-utility generation to compete (federal policy); and/or (2) allowing consumers to choose non-utility suppliers (state policy choice) and other things. No matter what, retail rates are still set by state regulators. Different areas did different things. But the biggest transformation of the sector, which could have happened anyway, was the creation of RTOs and transmission-owning utilities joining them, so that these large regional organizations run the transmission system across large multi-state grid regions, rather than each utility trying to operate its little piece of the interconnected grid.
Utilities still own the transmission and distribution system, and for the most part, they must get funding for T&D maintenance, repair, and replacement from their state Public Utilities Commission (or in NY, it’s the NY Public Service Commission). So-called “deregulation” focused on generation competition and some retail competition (in NY and some other states), but in every state, T&D were always regarded as “natural monopolies.” T&D weren’t “dereulated,” they were left as utility responsibilities.
Refurbishing the T&D system could take billions, but it’s up to the utiltiy owners to do this and up to the state regulators to approve the funding and allow collection of the costs in our rates. [although there are some regional transmission lines mandated under federal rules]
HVDC transmission isn’t all that new. I believe the first installation here in the States was back in the 1930s. DC transmission is appropriate in specific circumstances where either its cost or operational trade-offs are advantageous. In terms of dollars, it costs less to build each mile of the power line (capacity being equal) but the termination equipment at each end is much more expensive. Operationally, unlike a standard AC transmission line on which the power flow is determined by the physics of the grid and what’s happening in the power system at each instant, the power being transmitted on a DC line can be precisely controlled regardless of what else is going on in the power system.
The modern era of its use started with the North/South DC intertie between BPA’s Celilo (sp?) Substation in Oregon’s Columbia valley and Southern Cal Edison and LA Dept of Water & Power’s jointly owned Sylmar station in the San Fernando Valley. It was built in the 60s and justified on the basis of seasonal diversity: power moved north during the Pacific Northwest’s winter peaks and south during the hot weather in Southern California. In the case of this 900 or so mile line both the cost and operational advantages were in DC’s favor.
Another common HVDC use is for moving energy from remotely located power plants to market. One utility here in Minnesota owns a mine-mouth lignite fired plant in west central North Dakota, and another one has a long-term contract for another plant’s output, and each has a 400 or so mile DC line that delivers the power. Canadian utilities also use DC extensively for exporting the energy generated by hydroelectric plants near Hudson Bay.
There are also applications for HVDC where the power is transmitted over distances measured in hundreds of feet (or even less) rather than miles. These are points at which two separate, otherwise unconnected grids can transfer power between each other. Here in North America there four such major grids: the Eastern Interconnect, which is essentially everything east of the Rockies in the U.S. and Canada except Texas, Quebec and the aritime provinces; the Western Interconnect, consisting the Rockies and westward; Texas; and Quebec and the maritime provinces.
There are a number of points where utilities of two interconnection grids bring transmission lines into the same substation and interconnect them with a HVDC line only a few score feet long. With DC, they can exchange power regardless of instantaneous differences in frequency and phase angle. There have been some suggestions that the larger grids, especially the Eastern Interconnect, should for reliability purposes be split up into smaller units which then will be interconnected via DC. There are all sorts of complications involved in doing this and I would be surprised to see it happen soon, if ever.
You know, you are right; I’m mixing up my events; all of those outages in Ohio took place several years prior when the price of electric went sky high – excuse me – my error.
I am only familiar with only one utility in my area – I can tell you that before deregulation, it used to have a whole department filled with engineers and specialists who did the design, construction, etc. etc. for the growth and repair of the transmission system. After ‘deregulation’ all of those people disappeared – the entire department disappeared. Line crews did not. Another department, for example, with the specialists who were able to put together the supply and rebuilding effort during that huge ice storm that crippled Upstate New York, Ontario, Quebec, and upper New England in the late 90s…has disappeared. After deregulation, there was a huge contraction in areas such as these – the company is probably one-third of the ‘before deregulation’ size. Other utilities in Upstate New York are basically in the same condition. Even if the PSC authorized T&D money to do a huge project such as this, it would require out-sourcing because the sheer people and brain power that used to exist inside the corporations no longer is there.
I agree; What that utility experienced is common; my only point is that since T&D were left as regulated utility monopolies, the move to “competition” should not have affected them directly. Utilities and state regulators chose to let this happen, not because it was intrinsically required by the restructuring of the industry. My sense is that the T&D budgets are making a comeback, after many in the industry claimed there was underinvestment. Also, in the RTO regions — all of NE, NY Mid-Atlantic and Midwest — RTOs have encouraged more Transmission development to improve reliability and relieve congestion — and states are started to be more supportive — though transmission often takes years to permit/build.
Very good description. The only thing I’d add is that ERCOT, the Texas interconnection you list, is only connected to the Eastern and Western Interconnections by contollable HVDC — because Texas wanted to claim it’s not really connected sufficiently to the rest of the US to be part of interstate commerce, and hence what happens on the Texas grid is not subject to Federal jurisdiction (FERC rules).
What’s interesting is that after trying a somewhat different set of market/pricing rules from Eastern RTOs, they are now in the process to converting voluntarily to essentially the same operational/market rules used by the Eastern RTOs. There is a common set of rules for all US RTOs now, even though Texas/ERCOT is not subject to FERC.
Yes and no. While operating procedures and the control systems that implement them do not allow line capacities to be exceeded in normal operations, from what I hear they’re definitely being operated closer to the red lines than they use to be pre-dereg days. This makes the grid more vulnerable when s**t happens, as it always eventually does. As you pointed out regarding the 2003 Eastern blackout, First Energy’s EMS would probably have alarmed the overload of the line that became the first domino to fall by sagging into the trees. An EMS failure is one of worse kind of s**t that can happen, since it not only blinds the operators in terms of real time visibility, but also deprives them of their contingency analysis tools. Actually, First Energy had a pretty good, state-of-the-art EMS at the time. I don’t know what specifically went wrong, but all EMS suppliers have their issues. In FE’s case it apparently hit at a particularly bad time.
You’re right that “deregulation” is a misnomer. I only use the term since it is so commonly used by everyone else when discussing the electric utility business model changes of the past quarter century. Because of the migration to a market-based model the public service culture that previously prevailed in the industry has been undermined to some degree (but not entirely, fortunately). This was most flagrantly apparent in the machinations of Enron and their ilk during the California energy crisis at the turn of the millennium. As a result, at the operational level the industry has become more regulated than ever.
I think another change that might even make things more expensive is the effect of the natural gas companies’ wandering around Upstate NY and Northern PA and making offers to landowners for drilling rights. People are very aware now of ‘negotiating position’. I think getting easements to put up more transmission structures is going to be much more onerous and expensive. We’ve already seen what happened with the ‘critical corridor’ case with NYRI. So, I’m thinking that “building more and better’ may be even more complicated.
Thanks very much.
Thanks, Toby. That was very helpful.