In Act III, we search deeply within ourselves to discern if the protagonist provides answers to the modern vexations that ail us. Come let us listen to Friedman Milton as he disarms the protagonist.

Black and White–or Gray?

The Bradley Project seems to dichotomize the world into free market capitalism and political capitalism. To paraphrase George Orwell, free markets good; political markets bad.

I have no quarrel with Bradley’s conclusion that both energy generally and natural gas and electricity in particular have been victims of political capitalism in all its hoary forms. I disagree, however, with the Bradley Project’s hostility to addressing market failures.

The energy industry, more than any other industry I can think of, has some serious market failures in the classic sense defined by economists. For example:

· Market power problems in gas and electric transportation and distribution;

· Externalities in every supply option, including renewables;

· Public goods issues in basic research and some free rider problems;

· Information asymmetries in various industry segments (let a marketer try to get customer load information from a regulated utility).

Finding the right policy in light of these market failures, while not compromising market forces, is what makes energy policy so treacherous and complex.

Frankly, the economics profession has been asleep at the switch on this one. Electric and gas transportation has more similarities to highways, airports, movie theatres, the stock market, MF Global, and Microsoft Windows than it does to traditional commodities such as hamburgers, shirts, or cars.

Economic academic literature is replete with silo-based analysis on each of these network or coordination industries (I call them Plexus Functions) but completely fails to observe and thus offer a unifying theory of public policy on these types of assets and functions, which does exist, and will be the subject of a future article. But this is about the Bradley Project.

Bradley only minimally acknowledges these types of problems and offers little advice as to addressing them. The overwhelming impression one gets from his first two books is that any form of government intervention is adverse to capitalism, competition, and efficiency.

But sometimes a cigar is just a cigar, to quote Sigmund Freud. There is nothing wrong with a company pursuing profit by making rational adjustments to new government policies that promote efficiency.

Yes, Bradley will rebut that the U.S. has done a generally miserable job of implementing sound economic policy to efficiently address these failures. Rather, the result has been compounded government failures that dwarf the costs of the market failures. And he is right.

Good Middle-Way Government

But there is a third model between laissez-faire capitalism and political capitalism: sound implementation of coherent public policies to address market failures, with a strong recognition of the Public Choice-Government Failure implications of many interventions.

I will suggest two examples supporting this third model: natural gas reforms and clean air regulations.

The Reagan and Bush I Administrations did a terrific job between 1983 and 1992 of reforming natural gas regulation by putting in place sound, market-based policies that have resulted in tremendous benefits to America (truth-in-advertising: I worked on these reforms as an official in both Administrations).

We don’t have time to dwell on detail, but Bradley calls much of this reform “infrastructure socialism.” By that he means that we used very heavy-handed government power to force gas transmission systems and to some extent local distribution companies to adopt a common carriage obligation so that producers and customers could deal directly with each other rather than use these natural monopolists as intermediaries. This was called open access, or, more precisely, mandatory open access.

Chaos in natural gas markets would be an understatement as to the period from the winter of 1972/73 to around 1985. Yet radical, market-oriented reforms were implemented that promoted natural gas competition on both ends of the pipeline. These reforms have stood the test of time and natural gas has made an enormous contribution to energy, the environment, and the economy. It is today the one sharp arrow in our energy quiver.

Enron Reconsidered

Enron at its birth made responsible adjustments to the new regime and built a great natural gas company. There is nothing wrong with a business taking advantage of changes in government rules promoting competition and efficiency for its own profit, and that’s what Enron did in natural gas.

Paradoxically, Enron jumped the shark after its natural gas successes, ultimately leading to the debacle of bankruptcy. It did not have to end this way and would not have if Richard Kinder had replaced Ken Lay as chairman in 1997 as both men originally planned. (Bradley will undoubtedly cover this in his trilogy finale.)

Those of you who have grey hair remember the smog problems of the early 1970s. While it got off to a rocky start, amendments to the Clean Air Act now allow for SOx and NOx trading that promotes efficient internalization of an environmental externality. One might quibble, but it seems undeniable that we have made massive progress on air pollution in a cost-effective manner.

Power Crisis Ahead?

So what does government need to do? While very often in the news headlines, we will not have an oil crisis, a natural gas crisis, or a climate change crisis any time soon. So government need not focus action on any of these. Rather, to quote John Galt in Ayn Rand’s Atlas Shrugged, government should “get the hell out of my way.”

The electricity industry, however, is far more likely to be in crisis over the next decade, largely from six phenomena.

· First, generation options are being taken off the table at both the state and federal level. Try to build a coal or nuclear plant.

· Second, promotion of renewables and electric cars, not to mention increasing reliance on digital technology impose increased demand for electricity infrastructure.

· Third, much of this new demand exposes the reality that the function and technology of electric transmission has changed radically, but we still have a set of policies intended for the 19^th century. If Edison were to come back, he would recognize today’s electric industry. Radical reform of electric transmission policy is needed.

· Fourth, one aspect of this transmission policy is to significantly preempt much of current state jurisdiction over electricity. We did it in trucks, planes, railroads, and phones. While electricity may have been intrastate commerce in the 1920s, no one can deny that it is today interstate commerce.

· Fifth, at both the wholesale and retail levels we have an incomplete transition from a highly regulated model to a competitive model. This can only be fixed by national policy.

· Sixth, seriously distorted prices set by regulation. The best analogy I ever heard to promote an understanding of utility pricing related to beef (I heard it from former FERC Commissioner Nora Brownell, herself a former state regulator). Suppose the government dictated that filet mignon and ground beef be sold for the same price. Now think about the implications for supply of both beef products. That’s a near perfect explanation of paying the same for a kWh of electricity on the hottest day of the year and at 2 am in the fall or spring.

Electricity is ever more increasingly the central nervous system of the US economy. While it gets far less press, these challenges will prove intractable over the next decade.

California

In electricity, Enron was fully in the grip of self-interested political capitalism for most of its ventures from about 1990 on. My favorite example of this is the California electric reform legislation that almost cratered California’s economy and gave us Governor Schwarzenegger. It passed the California legislature unanimously by a vote of 114 to 0 and was signed by a Republican Governor.

Yet it was a disaster, and capitalism got much of the blame. So, in general, I agree with the Bradley Project’s point about the fall of Enron, not only the rise, being a result of the perils of political capitalism.

Conclusion

Why is it important to articulate the legitimacy of some intervention when there are serious market failures? Why not just argue that all such interventions always lead to inefficiency and calamity? Legitimacy. It is the calling card to be part of the debate. The economic theory on these issues is too sound to be ignored.

I have been vilified on many occasions by those with a more libertarian streak for my advocacy to adopt the framework of economists, rather than anti-government ideologues. Many may actually be correct that there are very few market failures worth correcting.

But their failure to admit that some might and have been successful often relegates them to academic theorists rather than advocates relevant to the real world market practicalities of the debate. Frankly, market advocates need all the help we can get.

In Act IV, we will conclude with the search for a hero.

Is the right track (1) upgrading the grid capacity and implementing new transmission lines to facilitate the integration of utility-scale wind and solar or (2) the implementation of smart meters to match (read restrict) demand to the erratic and unreliable supply of these?

Absolutely not. Such ill-advised initiatives will require an unacceptably large investment in grid elements that will likely all too quickly become irrelevant as the  needed electricity infrastructure changes are engineered and introduced in the future.

But first things first: what is meant by Distributed Generation (DG) and the smart grid?

Distributed Generation (DG)

One of the primary purposes of DG is to meet some level of local demand, not feed the grid. The imposition of mandated levels of renewable energy (RES) and Feed in Tarrifs (FIT) with premium prices to incent the deployment of wind and solar creates a “gold rush” for the latter. Industrial-scale wind and solar generation plants are like traditional generation sources in that they produce electricity to meet demand elsewhere, and in the case of wind and solar often at great distances. They are geographically distributed, and this is one element of differentiation from conventional electricity generation sources, but this is because the fuel, wind and sunlight, is dispersed widely. This is not DG.

The correct view of DG involves small-scale generation sources, for example roof-top solar and possibly micro wind turbines (better designs are possible) as well as many other non-utility scale generation means, and this list can be quite long. These will be integrated within micro-grids that contain intelligence to manage local production, storage (which is feasible even today at this level and shows considerable promise for the future) and use, as well as connection to the grid through intelligent gateways. Micro-grids can serve many types of “communities”, for example residential (especially in rural areas), combinations of commercial/industrial/residential communities, and college campuses. Such “concepts” are already being experimented with, for example at the University of California, San Diego, (USCD) including a gas turbine/combined heat and power system, and solar and fuel cell technologies described here and electric cars here. A quote from Byron Washom, the campus’ director of Strategic Energy Initiatives is appropriate.

“UCSD will become a laboratory where technologies can be tested and consumers’ behavior can be analyzed.”

Ignore the hype in the above examples, but applaud the approach as summarized by Washom. Also note the focus on consumer behavior at the same level as the technologies.

Will the “smart” meters being installed today be compatible with this yet-to-be architected and engineered smart grid? It is unlikely and represents potential high stranded costs that will encumber future generations. Today smart meters appear to have the major purpose of providing a means to raise electricity rates through aggressive time-of-day pricing to help fund the large investment needed, primarily for wind plants, and the extra transmission and generation facilities required to support them.

The Smart Grid

In a brochure by the Department of Energy (DOE), short term initiatives, as described in the second paragraph above, are labelled the “smarter” grid, supposedly on the track to the “smart” grid. Even without any knowledge of the issues involved, anyone familiar with unbelievable promises all too evident in some commercial advertising will recognize the warning signs. Here is a quote from the DOE about “smarter grid” initiatives (emphasis added):

• Ensuring its reliability to degrees never before possible.
• Maintaining its affordability.
• Reinforcing our global competitiveness.
• Fully accommodating renewable and traditional energy sources.
• Potentially reducing our carbon footprint. [interesting qualification]
• Introducing advancements and efficiencies yet to be envisioned.

More information on this and the warnings from The North American Electric Reliability Corporation (NERC) have previously been described here.

The reality is no one knows what the smart grid will ultimately look like. It represents a major shift in our electrical energy infrastructure, which will necessarily take a long time to effect, in part because there will be social impacts on any such major restructuring. As previously mentioned, this and a reasonable time frame for the development and extensive implementation of the many technologies involved within a properly engineered architecture is the second half of the 21^st century.

Restating this, aggressive implementation initiatives taken today are likely premature and have questionable motives. In the same way no one knows what the likes of transportation, communications, information processing, education, world government, health care, food production and urban development will look like in the same time frame. Effective changes in all of these will be an evolutionary process, not a revolutionary one. Electricity generation and distribution is as fundamental as these and the fervour being exhibited about revolutionizing it in a short time frame is simply misinformed.

An article in the April 2021 issue of Power Magazine, “The Smart Grid and Distributed Generation: Better Together” provides a good background on these issue. Amidst all the detail though, a few matters need emphasizing to properly provide a framework to make sense of this important infrastructure shift.

• No one knows what the smart grid will ultimately look like, so there should be no early major investment in deploying technologies until this is better understood.
• One of the primary functions of DG is to meet some level of local demand, not feed the grid.
• We should not be distracted by discussions about the extensive implementations of concepts (e.g. utility-scale electricity storage, wide-spread impact of electric vehicles), which may only be realizable in the distant future.
• Cyber security must be a major development initiative and this further emphasizes (1) the need to avoid overly hasty implementations and (2) the importance of the localized nature of the most likely smart grid architecture as opposed to grid-wide approaches.

[Editor’s note: For more commentary on the smart grid click on the Smart Grid sub-category under Policy Issues. The NERC report is recommended reading for a more complete understanding of the issues.]

The “simultaneity problem” is not shared by oil or natural gas or coal. It is a tough reality for electricity that Thomas Edison and countless inventors since him have tried to solve via affordable battery storage. 

So where are we today in terms of cost per kWh to use batteries to store power and, in the case of intermittent technologies, firm power? For utility scale battery systems, expect to pay between $1,000/kW and $4,000/kW, according to the Electricity Storage Association. The DOE’s optimistic assessment estimates those costs will drop to around $500/kW by 2012.

Such adds at least a half cent per kWh to the cost of electricity.

Latest Technologies

There are about a dozen technologies vying for a piece of the utility-scale energy storage market, especially advanced battery technologies such as lithium ion and sodium sulfur batteries, pumped hydro, and compressed air energy storage. In this post, we’ll review the state-of-the-art of battery technology, a few interesting projects, and get a glimpse of the next generation of utility-scale batteries.

You should also note the few U.S. projects over the past few years and the large number number of battery technology companies chasing those projects. Several companies have since left the battery market or redefined their products. Little data on installed costs is available but included when available. Expect a major market shake-out over the next year or two.

The ongoing dissolution of the traditional electricity sector structure also seems to call for increased reliance on big batteries wherever feasible. One consequence of deregulation is that, in many states, generation and T&D are no longer planned in an integrated fashion by one entity—the local utility. Energy storage in general, and batteries in particular, can help stabilize the intermittent nature of nondispatchable renewable energy sources, for load leveling and peak shaving, substation standby power, or as fast acting reserves for system regulation control (ancillary services). Storage also has a critical role to play in securing the nation’s energy infrastructure, much as the Strategic Petroleum Reserve does for oil, and bulk gas storage does for balancing seasonal natural gas demand and supply.

Many Battery Technologies

New and rechargeable sodium-sulfur, vanadium redox, and zinc-bromide batteries—as well as nickel-cadmium batteries, which went commercial decades ago—have already demonstrated their ability to act as generators as large as 10 MW but the capacity must grow substantially to meet the growing need for reliably energy storage.

Table 1 summarizes many of the available energy storage options and the status of and future prospects for several battery technologies that either currently offer bulk energy storage capability or promise to do so in the near future. The following discussions and case studies explain how the new bulk-storage batteries work and how pioneers are using them to solve a number of common T&D problems.

1. A comparison of today’s bulk electricity storage technologies. Source: Platts

Sodium-sulfur: A Hot New Battery

Ford Motor Co. is credited with launching the development of the sodium-sulfur (NaS) battery in the 1960s for vehicular applications. However, today’s next-generation NaS batteries are the end result of more than a decade of R&D by NGK Insulators, Ltd. and Tokyo Electric Power Co. (Tepco). Tepco had identified the technology as the best candidate for replacing central pumped-hydro energy storage in Japan. NGK, which supplied the expertise in ceramics that was crucial to the development of the technology, is today the only supplier of NaS batteries for bulk storage applications.

Sodium-sulfur batteries use molten sulfur as the positive electrode and molten sodium as the negative electrode. These active materials are separated by a solid, ceramic electrolyte that conducts sodium ions (Figure 1).

1. Sodium-sulfur (NaS) battery operation. A solid ceramic electrolyte separates the liquid sulfur positive electrode from the liquid sodium negative electrode. Source: NGK Insulators Ltd.

During discharge, positive sodium ions flow through the electrolyte to combine with the sulfur, forming sodium polysulfides. Electrons flow through the external circuit of the battery to create a potential difference. Charging of the battery releases positive sodium ions from the sodium polysulfides, sending them back through the electrolyte to recombine as elemental sodium. To keep the electrodes in the molten state, the battery is kept at a temperature of about 570F. NaS modules also include an electric heater to keep the reactants molten, and thermal insulation to reduce heat losses.

NGK’s commercial-scale NaS battery production facility—which opened in April 2003 in Komaki, Japan—has an initial capacity of 65 MW/yr that can be expanded to 200 MW/yr. Modules are currently available with ratings of 50 kW/360 kWh or 430 kWh for peak-shaving (PS) applications and 50 kW/360 kWh or up to 250 kW for short-term power quality (PQ) applications. Units can be combined to provide up to 20 MW for PS, and up to 100 MW for PQ applications. PS modules are optimized to deliver long discharges with modest voltage drop, while the PQ modules are designed to deliver short pulses of power.

The commercial version of the NaS battery has been demonstrated at about 190 sites totaling more than 270 MW in Japan since April 2004. One system installed at a Japanese semiconductor factory was rated at 1 MW/7 MWh for peak shaving duty and supplied up to 3 MW for 13.5 seconds to improve power quality. The system also proved its ability to lower the factory’s cost of energy by shifting some purchases from on-peak to off-peak hours, and to protect important loads from short outages. Another of its benefits was leveling the local utility’s demand.

Today, there are a total of 9 MW of NaS batteries installed in the U.S. In one U.S. demo of the NaS battery, a system was installed in September 2002 at an American Electric Power Co. office building in Gahanna, Ohio. It can simultaneously provide 500 kW for up to 30 seconds for PQ needs and 158 kWh at up to 100 kW for PS. Alternatively, the system can provide 300 kW for 30 seconds for PQ and 720 kWh at up to 100 kW for PS. The largest installation is 34 MW, 245 MWh unit for stabilizing a 51 MW wind farm in northern Japan.

Compared to conventional lead-acid batteries, NaS batteries offer three to five times the energy density and more and deeper discharge cycles. The units are easily sited indoors or out since they are clean, quiet, and vibration-free and their operation is insensitive to ambient temperature. Their major downside is their capital cost; where lead-acid batteries run about $400 to $900/kW, the current NaS modules—which are nominally rated at 50 kW each—are priced at $1,800/kW.

Flow Batteries: Pros and Cons

Flow batteries (FBs) are a relatively new class of electrochemical device. They can store large amounts of electrical energy (from tens of kWh to tens of MWh) and deliver it either slowly over several hours, or within milliseconds or minutes as high-power pulses. The versatility of FBs suits them for a wide range of applications, from energy management to power quality and reliability.

There are three different types of flow batteries, and they use different chemicals to store energy. Two, which use zinc-bromide and vanadium electrolytes, are currently in the early stages of commercialization. Until recently, the third type—the Regenesys battery, which uses sodium-bromide and sodium-polysulfide electrolytes—seemed to have a bright future. A few years ago the German utility giant RWE, Regenesys Technology Ltd.’s corporate parent, abruptly pulled the plug on the R&D effort and a large project with the Air Force was cancelled. Later, RWE sold its intellectual property rights to the technology to Vancouver-based VRB Power Systems Inc. that has since gone bankrupt, so the future of the Regenesys battery is murky at best. The Regenesys Technology website finds their thermal storage interests are focused on integration with solar thermal systems

Flow batteries will have—at least initially—higher capital costs than lead-acid batteries (typically, $350/kWh vs. $200/kWh for a load-shifting application, excluding power conditioning and balance of plant costs), but they also have a much longer cycle life. Accordingly, zinc-bromide and vanadium batteries may be economically attractive to certain users for certain applications. And their cost is certain to fall as production ramps up to commercial levels within the next few years and the economies of scale kick in.

The big operational advantage of flow batteries, which use reversible reduction-oxidation (redox) reactions, is that they allow either power or energy output to be optimized in real time. In a conventional battery, both electrodes are immersed in the same ion-conductive electrolytic solution. During discharge, oxidation at the battery’s negative electrode (anode) liberates electrons. The electrons then leave the anode, flow through the external circuit to which the battery is connected and perform useful work, and are returned to the positive electrode (cathode). At the cathode, reduction recombines the electrons with positive ions in the electrolyte.

The process is similar in the flow battery, except that each electrode is immersed in a different electrolyte, and the two electrolytes are separated by an ion-exchange membrane. To discharge electricity, the two electrolyte solutions are pumped from separate tanks into half-cells along either side of the membrane (Figure 2). To store electricity, current is put back into the system to return the electrolytes to their original chemical states, recharging the battery.

2. Representative flow battery design. Flow batteries store electrical energy chemically in tanks separated from the electrochemical cells. Each tank contains a different electrolyte solution. Electrolytes are pumped through half-cells, exchanging ions across selective membranes during charging and discharging, producing or absorbing electrons. Source: Platts; adapted from Regenesys Technologies Ltd

 NiCad Batteries: Less Costly than They Seem

Nickel-cadmium (NiCd) batteries have powered portable electronic devices for decades. However, their relatively high capital cost has prevented their widespread use in large stationary applications. Nevertheless, there are certain utility market niches in which NiCads can compete on a lifecycle-cost basis with conventional lead-acid batteries because the former can work in extreme temperatures and deliver lots of current over a short period.

Indeed, a phenomenon related to discharge speed is what prompted the Golden Valley Electric Association to choose nickel-cadmium units to power its Battery Energy Storage System (BESS). Commissioned in late 2003, the GVEA system (Figure 3) is the biggest of its kind in the world. With the internal NiCad units connected in series to create a 5,000-VDC battery, BESS is capable of providing 27 MW of AC current for 15 minutes, or up to 46 MW for long enough to start up a backup generator to replace one that fails. GVEA expects about 30 of these events per year in Alaska’s unforgiving climate.

GVEA chose nickel-cadmium batteries to power BESS (which happens to be in a controlled-temperature facility) because their capacity degrades slowly and linearly when they are discharged rapidly.

3. At the heart of the Golden Valley Electric Association’s Battery Energy Storage System are racks holding 13,760 nickel-cadmium modules. Connected in series, the modules function as a 5,000-VDC battery. Courtesy: Golden Valley Electric Association

 Perhaps Vanadium Redox

The two major suppliers of vanadium redox batteries are Tokyo-based Sumitomo Electric Industries Ltd. (SEI) and VRB Power Systems Inc. (VPS). Both companies rely on intellectual property held by Sydney-based Pinnacle VRB, Ltd., in which VPS owns a controlling share. Prudent Energy Inc purchased the assets of VPS in January 2009 after VPS declared bankruptcy and now markets the products. In addition, a third company—Reliable Power, Inc.—was authorized by Sumitomo to sell vanadium redox batteries in the U.S. although a recent check found no web site for the company.
SEI has been developing vanadium redox batteries since 1985 and manufacturing and marketing them since 2001. SEI markets megawatt-scale systems directly in Japan, where 11 projects representing more 3.7 MW and 13.8 MWh are in operation.

To date, VPS (now Prudent Energy Inc) has installed eight systems, according to information on their website. One is a 200-kW/1,000-kWh battery connected to a hybrid wind/diesel-powered microgrid on King Island off the south coast of Australia. The other is a 350-kVA/2.4-MWh system (Figure 4) that provides peak shaving and voltage support for a 200-mile-long, 25-kV feeder on the PacifiCorp grid near Moab, Utah; it began operation in March 2004.

4. On the job. VRB Power Systems dedicated this 350-kVA/2.4-MWh vanadium redox battery near Moab, Utah, in March 2004. It provides peak shaving and voltage support on a 200-mile-long PacifiCorp feeder. Courtesy: VRB Power Systems Inc.

 Consider Zinc-Bromide

Currently, ZBB Energy Corp. is the only company working to commercialize the zinc-bromide flow battery. The firm has its headquarters and a new production facility in Menominee Falls, Wis., but its research, development, and marketing efforts are based in Perth, Australia. Greg Nelson, the company’s chief operating officer, characterizes the company’s efforts as being in the small-scale demonstration phase.

To date, ZBB has largely focused on demonstrating the technology in the utility market. The company has built energy storage systems whose outputs range from 50 to 500 kWh for PG&E, Melbourne-based United Energy Ltd., Detroit Edison Co., Osaka-based Daihen Corp., and Sandia National Laboratories.

A commercially available 500-kWh grid-interactive storage system is the company’s basic building-block product. One system should satisfy most industrial energy storage needs, and several can be combined into multi-megawatt-hour sizes for utility applications (Figure 5). For example, four of the trailer-mounted systems are scheduled to be installed this year to provide 2 MW of peak-shaving support to a stressed PG&E substation.

5. One-stop shopping for moving and storage. This turnkey zinc-bromide flow battery from ZBB Energy Corp. can supply 250 kW for up to two hours. Delivered inside a standard shipping container, it is trailer-mounted, making it relocatable. Courtesy: ZBB Energy Corp.

Mobile Batteries

Today, frequency regulation is an ancillary service bought by the hour, the day prior to utilization, and dispensed on an as-needed basis by dispatch communiqués and provided by the ancillary service provider on a 15-minute basis. New battery technologies can also mitigate those electricity supply challenges.

Altair Nanotechnologies (Altairnano), a provider of energy storage systems, has developed a lithium-titanate battery system to mitigate some of these ancillary services difficulties. The power storage system provides frequency regulation on a 1-second dispatch basis, as needed.

AES, one of the world’s largest power companies, understood the game-changing possibilities of Altairnano’s technology for mitigating major frequency regulation problems. With AES, Altairnana developed a 2-MW, 500-kWh system with the capability of producing 1,000 amps at 1,000 volts that was designed and built to fit inside two 53-foot trailers. The Altairnano battery system was recently pilot-tested at AES’s Indianapolis Power & Light location. KEMA served as the test contractor, providing independent third-party analysis.

The lithium-titanate battery system exhibits three times the power capabilities of existing batteries and can be described as the combination of a battery and a supercapacitor. This means power can be extracted from as well as inserted into the battery. Altairnano’s lithium-titanate technology is unique because it lacks a solid electrolyte interface (SEI), as shown in Figure 6.

6. A comparison configuration of a typical lithium-ion battery with a new lithium-titanate battery. Source: Altair Nanotechnologies

The SEI is a “film” on the anode that is an internal resistor that limits power output and generates heat in a standard lithium-ion battery. Therefore, the lack of an SEI allows the lithium-titanate battery to work efficiently in extreme temperatures and eliminates thermal runaway risk. This battery’s operating temperature range also is wider than that of other technologies: from –40C to 55C (–40F to 131F). This capability eliminates the need for supplemental heating when the battery is used in low-temperature environments.

Inside the AES 53-foot trailer (Figure 7) reside numerous Altairnano Super Modules installed in racks (Figure 8). The batteries are air-cooled (the black circles in Figure 9 are the fans) in order to mitigate I² R heating in the modules. An air-conditioning system for the trailer keeps the temperature below 55C (131F).

7. The Altairnano/AES 1-MW system can produce 250 kWh and is contained within a single 53-foot trailer. Courtesy: Altair Nanotechnologies

8. The batteries are arranged in racks within the trailer along with air-cooled fans, air conditioning, and various computer monitoring systems and controls. Courtesy: Altair Nanotechnologies

Various computer systems monitor and control all the Super Modules and associated systems. A battery management system monitors battery cell temperatures, balances the cell voltages as needed, and keeps track of the battery charge state. A programmable logic controller interfaces with three single-phase Parker Hannifin SSD inverters, one for each phase of the three-phase system. The Parker Hannifin SSD power inverters were coupled to isolation transformers and fed into a step-up transformer with the battery side running three-phase 480 V and the grid side operating at 13.8 kV. A supervisory control system monitors and interfaces with the step-up transformer sending and receiving power from the grid.

Independent Test Results

The AES pilot test at Indianapolis Power and Light was considered by all a significant success in the application of power storage devices for grid application. According to KEMA, the prototype units in their current state are suitable for use in future market pilot activities designed to help better define the application requirements and demonstrate the potential of this technology.

KEMA’s report noted that, “A key performance finding was the maximum unit storage capacity for each of the two one megawatt systems was approximately 300 amp-hours with a capacity of delivering 250 kWh at a rated output of 1,000 kW for 15 minutes. Each unit was able to dispatch at any power level between 1-MW discharge to 1-MW charge within one second. Due to the battery and inverter technology used, response actually occurs within cycles. The round trip efficiencies are on the high end of various options. It is important to note that even with a 90% round trip efficiency, a 250 kWh system requires the replacement of 25 kWh when the total discharge is considered. Other systems that have a 60 to 70% round trip efficiency will not provide the economics necessary when the losses are included in the calculations. Also, the Altairnano system has over a 7-year life when the CAISO standard dispatch model is applied. The cycle life of other electrochemical systems cannot approach this lifetime.”

Next Generation: Air-Fueled Battery

Researchers around the world, meanwhile, are reporting breakthroughs on existing and novel technologies. The University of St. Andrews in the UK, collaborating with colleges from Strathclyde and Newcastle, in May claimed to have designed a new type of air-fueled battery that can provide up to 10 times the energy storage when compared with designs currently available.

The STAIR (St. Andrews Air) cell capacity is based on rechargeable lithium batteries, which are currently composed of a graphite negative electrode, an organic electrolyte, and lithium cobalt oxide as the positive electrode. Instead of lithium from the layered intercalation compound (lithium cobalt oxide), the STAIR uses a porous carbon electrode. The oxygen, which will be drawn in through a surface of the battery exposed to air, reacts within the pores of the carbon to discharge the battery. The university has discovered in the course of its four-year study that the carbon component’s interaction with air can be repeated, creating a cycle of charge and discharge (Figure 9).

9. Researchers from the University of St. Andrews in the UK have designed an air-fueled battery that they claim could last 10 times longer than designs currently available. As the diagram of the lithium-air STAIR (St. Andrews Air) cell shows here, oxygen is drawn from the air and reacts within the porous carbon to release the electrical charge. Courtesy: University of St. Andrews

Initial results from the project found a capacity to weight ratio of 1,000 milliamp-hours per gram of carbon (mAh/g), while recent work has obtained results of up to 4,000 mAh/g, the researchers said. The researchers expect that the battery is about five years away from commercial availability, however.

In May last year, a Canadian research team at the University of Waterloo reported it had laid the groundwork for a lithium-sulfur battery that could store and deliver more than three times the power of conventional lithium ion batteries. As reported in the online issue of Nature Materials, the team overcame the challenge of keeping the electrically active sulfur in contact with a conductor, such as carbon. The team chose — at a nanoscale level — a member of a highly structured and porous carbon family called mesoporous carbon.

Filling the tiny voids then proved simple: Sulfur was heated and melted. Once it came into contact with the carbon, it was drawn or imbibed into the channels by capillary forces, where it solidified and shrunk to form sulfur nanofibers. Scanning electron microscope sections revealed that all the spaces were uniformly filled with sulfur, exposing an enormous surface area of the active element to carbon and driving the exceptional test results of the new battery. The research team continues to study the material to work out remaining challenges and refine the cathode’s architecture and performance.

Portions of this article were previously published in POWER magazine and POWERnews. Sr. Writer Sonal Patel also contributed to this article.

[Yesterday's post discussed how FERC failed to implement the siting authority granted in the Energy Policy Act of 2005 and examined a case study about why it failed. Part II looks at Obama’s “green power” superhighway, the recent work by regional transmission planning organizations to bring renewable energy to market, and the extremely high costs to do so.]

Public policy has long supported the ability to construct new transmission lines that relieve congestion and reduce the cost of energy to consumers. However, it is another question entirely to construct a new “green” coast-to-coast transmission corridor given the mess our transmission system is in today and its prohibitive cost. Critics have complaint that it is throwing good (transmission) money at bad (renewable) generation money.

Slowly, regional system operators are resolving transmission bottlenecks and improving the smooth flow of energy in their service territories. The good news is that virtually all of the most important regional projects are likely to be in-service well before our Washington representatives will complete their transmission siting authority “power grab” (not that it will change their game plan). Also, regional transmission planning organizations are actively promoting and siting transmission lines. The regional system is working and they don’t need FERC or congress to help to fix it.

The local siting processes are working (regardless of how you feel about siting renewables-only transmission lines) but the costs for constructing this transmission is extremely expensive per unit of energy generated given the periodicity of the output from wind and solar power plants. Costs of constructing new transmission for renewable projects can easily equal a quarter of the cost of building the power plant alone. In ERCOT, the price is over $2 million per mile to bring renewable energy into the existing grid and will add at least 5 cents/kWh for the transmission portion of the cost of renewable electricity alone—more than double the cost of electricity from our existing fleet of nuclear power plants and 60% more than the cost of coal-fired electricity at the busbar. The Western Interconnect planning process is currently identifying likely renewable sites and looking at transmission line corridors.  

FERC: Try, Try Again

In Part I we discussed how federal siting authority of new transmission lines was granted under the Energy Policy Act of 2005 (EPAct) yet FERC’s implementation of that authority failed judicial scrutiny. In addition, the case study presented concerning adding an interconnection between Southern California and Arizona clearly shows that there are many other issues that must be considered when establishing the need for FERC to intercede on behalf of one state or another. In my mind, the most significant issue, and the Arizona Corporation Commission agrees, is that a state must completely exercise their ability to construct local power generation facilities before attempting to cross connect to an adjacent state. Merely needing the power is no reason for the federal government to exercise its eminent domain powers when there is an unwillingness to construct new plants.

Today, we now hear the next stanza to this same tired tune. We continue to be told that a complete overhaul of the U.S. power delivery system is required but now the grid updates must also accommodate the higher levels of renewable energy expected to be generated over the next decade. Senator Harry Reid (D-NV) gave us a look at our future when, at a conference in February hosted by the Center for American Progress Action Fund, a group organized by John Podesta, proclaimed, “My legislation (referring to another round of legislation he promised to introduce that will speed approvals of transmission lines) will require the president to designate renewable energy zones with significant clean energy-generating potential.” Reid went on to explain that the federal government should be given the authority, through FERC, to overrule state and local governments that slow the development of Obama’s promised 3,000 miles of new interstate transmission lines.

The proposed legislation would also provide FERC the power of eminent domain should states be unwilling to yield to the inevitable pressure from Washington to approve the plans. “We cannot let 231 state regulators hold up progress,” Reid said. “They should be given every opportunity to see if we can work this out through the state regulators. If that can’t be done I think there are very few alternatives for the American people,” other than eminent domain. But any delays or obstacles would be quickly settled, Reid said. “Whatever we pass at the federal level trumps all that,” he said.

John Podesta, president of the Center for American Progress, said a stronger federal siting authority is needed, given that the 4th U.S. Circuit Court of Appeals ruled that FERC’s interpretation of its backstop siting authority under the 2005 energy bill was too expansive.

“It’s time to get back to the table and find a way so that states and regions can plan for the transmission that they need but that the federal government has a role to play to make sure that gets done,” Podesta said.

Reid has yet to provide any details of his proposed bill but a legislative aid said the bill would contain four main components: an interregional planning component, federal siting authority, a national cost allocation plan and a requirement that any generation that connects to the grid meet “green” standards. The four parts appear very similar to a plan produced by the Energy Future Coalition and the Center for American Progress.

Thankfully, Reid’s proposed legislation has yet to see the light of day given the extraordinary costs involved with constructing new national interstate transmission lines. For example, grid operators in the eastern half of the U.S. earlier released in August a study estimating that more than $80 billion in new transmission infrastructure would be needed to get 20% percent of the region’s electricity from wind generation by 2024.

Does Siting need Fixing?

The Federal Energy Regulatory Commission (FERC) recognizes the challenges posed by bringing electrons from new and disparately located renewable energy sources to population centers. In late May, FERC announced a series of transmission planning meetings that will focus on “wider integration of regional energy resources into the nation’s power grid.” In essence, renewable energy generation, principally wind energy, is located where the transmission infrastructure does not exist, and other distributed energy resources are located in transmission-constrained regions.

According to FERC Chairman Jon Wellinghoff, “Planning is one of the three legs on the transmission policy stool—the others are siting and cost allocation—and all are crucial to meeting the goals of assimilating demand resources, renewable energy and distributed generation into the grid for the benefit of consumers.” Here we go again.

From Market Pull to Product Push

Historically, electric utilities dictated when, where, and how much new generation would be added. Their integrated resource plans (IRP) determined the timing of plant additions, the fuel sources, and the location of the new generation resources. Transmission planners followed the lead of utilities to route the necessary transmission capacity while also seeking to lessen area congestion, if necessary. Traditionally, new power generation resources—and, by extension, new transmission—responded to a market pull: predicted load demand. The role of the state and local governments was oversight, providing access to transmission, and setting rates.

In contrast, renewable mandates have upended the traditional approach to developing an IRP. Rather than anticipated customer demand driving generation and transmission decisions, government mandates are now in the driver’s seat. Twenty-nine states and the District of Columbia have a renewable portfolio standard that requires utilities in those states to supply some percentage of renewable electricity by a date certain.

For instance, the California Public Utility Commission requires that 33% of that state’s power originate from renewable energy sources by 2020. In order to achieve this extraordinary goal, all new power generation procured by the state’s utilities must come from renewable energy sources. In this new world, the “pull” of market demand has been supplanted by a government-mandated “technology push” that determines which renewable developers pushing new power into the system in response to state-mandated levels of renewable power have access to limited transmission infrastructure.

One of the other challenges to building new transmission capacity to move renewable energy long distances that was discussed by Wellinghoff is identifying acceptable siting locations for renewable energy facilities. In spite of FERC’s interest is being part of that decision process, much progress has been made at the local level that makes FERC irrelevant in siting transmission lines in practice.

Transmission Planning Out West

One important initiative toward this goal in the Western Interconnection is the Western Governor’s Association’s (WGA) Western Renewable Energy Zones (WREZ) study. In the WREZ study—which covers 11 western states, two Canadian provinces, and areas of Mexico that are part of the Western Interconnection—as many as 50 zones with substantial renewable resources are in the process of being identified so that renewable projects can be expedited and transmission projects can be planned in advance.

The ultimate goal of the WGA is to “develop 30,000 MW of clean and diversified energy by 2015.” The approach used by WGA is to first identify regions with high potential for generating renewable energy—solar, wind, geothermal, etc by involving all the relevant stakeholders. The results of these studies in turn drive transmission planning.

The most recent draft map from the Western Governor’s Association illustrates Qualified Resource Areas as those areas with a high density of developable renewable energy resources after screening for known technical and environmental limitations for which data are available. These data will be used to determine Western Renewable Energy Zones (WREZ) in the Western Interconnection.

The state with the largest installed wind power capacity has already identified Competitive Renewable Energy Zones (CREZ) within the ERCOT Interconnection. In March, the Texas PUC assigned approximately $5 billion of transmission projects to be constructed in these CREZ that will eventually transmit 18,456 MW of wind power over more than 2,300 miles of new transmission lines from power-heavy West Texas and the Panhandle to highly populated metropolitan areas of the state. To put the magnitude of these numbers into perspective, the cost of transmission is over $2,000,000 per mile or over $270/kW of installed capacity.

The regulatory body expects that the new lines will be in service within four or five years. The Texas PUC took about three years to select the most productive wind zones in the state, designate them as CREZ, and devise a transmission plan to move power generated from those zones to various populated areas in the state. Many of these new transmission projects will begin construction later this year.

As an aside, T. Boone Pickens’ investment in his now delayed plan to build 1,000 MW of wind power in the Texas panhandle is in jeopardy. The ERCOT transmission plans do not extend the wires far enough into the Panhandle to reach Pickens’ projects. Pickens now has 687 wind turbines available that cost him a cool $2 billion that he hopes to recycle on a number of smaller projects in the U.S. and Canada. That’s a lot of wind turbines.

The Cost of New Transmission Is Substantial

More insidious are unpredictable transmission costs. Power sellers, buyers, and investors adamantly want price certainty in the total delivered cost. However, congestion charges can make the delivered price vary, especially in locational marginal pricing.

Everyone wants to know the answer to the question: What is the added premium to deliver renewable energy? Many transmission networks have both fossil fuel and renewable generators sharing the same network. Certainly, intermittent renewable sources have higher system-integration costs. Load balancing is more involved as well.

A recent Lawrence Berkeley National Laboratory study may provide an early answer to the cost question. Lawrence Berkeley National Laboratory (LBNL) recently issued a research report that examines the expected costs for new transmission infrastructure that would be needed to support an accelerated program for renewable energy projects, particularly wind energy. The report, “The Cost of Transmission for Wind Energy: A Review of Transmission Planning Studies” was released in February 2009. (A copy of the report can be downloaded at http://eetd.lbl.gov/ea/ems/reports/lbnl-1471e.pdf.)

The authors’ objectives in preparing this report were threefold: to define the transmission costs for a rapidly growing wind power industry, to discuss different transmission planning approaches, and to examine the models used to estimate future wind deployment. Our interest is this article is to focus on the transmission cost estimates prepared by LBNL.

The cost estimates are based on a review of 40 transmission planning studies completed between 2001 and 2008 by various developers, independent system operators/regional transmission operators, state agencies, and individual utilities. There is a wide range in transmission costs, although the costs are generally less than $500/kW. The cost of the median study scenario was $300/kW, or about 15% to 23% of the typical installed cost of a wind turbine plant. These numbers are quite consistent with the $270/kW from ERCOT discussed above.

The authors also concluded that variation in the study methodologies used in these 40 transmission siting studies and the characteristics of the specific grid may affect transmission installation costs (see table). Depending on the original purpose of the transmission line under study (whether it was congestion or deliverability focused), the authors concluded that the purpose affected the costs of adding wind energy to the mix.

Estimated Installed Cost of Wind Transmission Based on Three Higher-Level Studies of Wind Transmission. Source: LBNL

Study

Wind Capacity

Unit Cost of Transmission for Wind Power

10% Wind Energy by 2030: AEP 765 kV Overlay Study

200-400 GW

$150-$300/kW

20% Wind Energy by 2030: Wind Deployment System

290 GW

$207/kW

Annual Energy Outlook 2008 Projections for 2030: National Energy Modeling System

40 GW

$450/kW consisting of $316/kW for transmission and $133/kW for “long-term” multipliers

The study also reviewed three high-level wind transmission–only studies, as shown in the table above. These costs are generally consistent with the median cost identified in the original study sample of $500/kW, or about 25% of the $2,000/kW cost of constructing a new wind project.

The study also concluded that the historic cost of transmission was in the range of $35/MWh to $79/MWh with an average of $45/MWh. Using reasonable economic assumptions on the ERCOT transmission projects and a 33% capacity factor, the transmission lines add about $50/MWh to the price of power generated by the wind projects. For perspective, existing nuclear plants as an industry deliver power to the grid at less than $20/MWh and coal plants are in the range of $30 MWh.

Another Approach: Requiring Backup Power

Nevertheless, renewables do add additional costs to the whole system. For instance, speedy ramp-up of backup power is essential when a wind farm goes down with as little as one-hour warning. Reliability issues kick in as well.

For example, an ERCOT report concluded that only 8.7% of historic wind generation was produced during peak power hours limiting its effectiveness in trimming system peak demand.

Someplace in the delivery chain this intermittency of energy production versus load demand must be smoothed out. Utilities traditionally have taken on this burden themselves. Typically, a utility backfills wind/solar gaps with gas-fired plants to make up for any shortfall in energy production based on a number of factors, including the season, weather, and the region’s operating experience. Using the same approach with very remote wind and solar farms isn’t as straightforward. To do so would make the entire long-distance energy delivery chain, in effect, run intermittently—if the remediating, balancing measures are not applied.

A more recent procurement practice is for the electric utility to insist that the renewable producer directly supply steady, baseload-style power. In particular the utility expects the renewable power producer to have its own storage or natural gas backups. An example would be Xcel Energy’s April 2009 request for proposal for 600 MW of solar thermal that is “fortified” in this way.

Conclusion

Central planning based on temporary political majorities–or, dare one say, ‘political whim’–is not a viable long-term electricity policy. Free-market incentives to expand and build are preferable, and do not expect a 3,000-mile ‘green’ superhighway as a result.

— Also contributing to this article was Sonal Patel, POWER senior writer, and Martin Piszczalski (Ph.D), an industry analyst with Sextant Research

[Yesterday's post discussed how FERC failed to implement the siting authority granted in the Energy Policy Act of 2005 and examined a case study about why it failed. Part II looks at Obama’s “green power” superhighway, the recent work by regional transmission planning organizations to bring renewable energy to market, and the extremely high costs to do so.]

Public policy has long supported the ability to construct new transmission lines that relieve congestion and reduce the cost of energy to consumers. However, it is another question entirely to construct a new “green” coast-to-coast transmission corridor given the mess our transmission system is in today and its prohibitive cost. Critics have complaint that it is throwing good (transmission) money at bad (renewable) generation money.

Slowly, regional system operators are resolving transmission bottlenecks and improving the smooth flow of energy in their service territories. The good news is that virtually all of the most important regional projects are likely to be in-service well before our Washington representatives will complete their transmission siting authority “power grab” (not that it will change their game plan). Also, regional transmission planning organizations are actively promoting and siting transmission lines. The regional system is working and they don’t need FERC or congress to help to fix it.

The local siting processes are working (regardless of how you feel about siting renewables-only transmission lines) but the costs for constructing this transmission is extremely expensive per unit of energy generated given the periodicity of the output from wind and solar power installations. Costs of constructing new transmission for renewable projects can easily equal a quarter of the cost of building the generation alone. In ERCOT, the price is over $2 million per mile to bring renewable energy into the existing grid and will add at least 5 cents/kWh for the transmission portion of the cost of renewable electricity alone—more than double the cost of electricity from our existing fleet of nuclear power plants and 60% more than the cost of coal-fired electricity at the busbar. The Western Interconnect planning process is currently identifying likely renewable sites and looking at transmission line corridors.

 FERC: Try, Try Again

In Part I we discussed how federal siting authority of new transmission lines was granted under the Energy Policy Act of 2005 (EPAct) yet FERC’s implementation of that authority failed judicial scrutiny. In addition, the case study presented concerning adding an interconnection between Southern California and Arizona clearly shows that there are many other issues that must be considered when establishing the need for FERC to intercede on behalf of one state or another. In my mind, the most significant issue, and the Arizona Corporation Commission agrees, is that a state must completely exercise their ability to construct local power generation facilities before attempting to cross connect to an adjacent state. Merely needing the power is no reason for the federal government to exercise its eminent domain powers when there is an unwillingness to construct new plants.

Today, we now hear the next stanza to this same tired tune. We continue to be told that a complete overhaul of the U.S. power delivery system is required but now the grid updates must also accommodate the higher levels of renewable energy expected to be generated over the next decade. Senator Harry Reid (D-NV) gave us a look at our future when, at a conference in February hosted by the Center for American Progress Action Fund, a group organized by John Podesta, proclaimed, “My legislation (referring to another round of legislation he promised to introduce that will speed approvals of transmission lines) will require the president to designate renewable energy zones with significant clean energy-generating potential.” Reid went on to explain that the federal government should be given the authority, through FERC, to overrule state and local governments that slow the development of Obama’s promised 3,000 miles of new interstate transmission lines.

The proposed legislation would also provide FERC the power of eminent domain should states be unwilling to yield to the inevitable pressure from Washington to approve the plans. “We cannot let 231 state regulators hold up progress,” Reid said. “They should be given every opportunity to see if we can work this out through the state regulators. If that can’t be done I think there are very few alternatives for the American people,” other than eminent domain. But any delays or obstacles would be quickly settled, Reid said. “Whatever we pass at the federal level trumps all that,” he said.

John Podesta, president of the Center for American Progress, said a stronger federal siting authority is needed, given that the 4th U.S. Circuit Court of Appeals ruled that FERC’s interpretation of its backstop siting authority under the 2005 energy bill was too expansive.

“It’s time to get back to the table and find a way so that states and regions can plan for the transmission that they need but that the federal government has a role to play to make sure that gets done,” Podesta said.

Reid has yet to provide any details of his proposed bill but a legislative aid said the bill would contain four main components: an interregional planning component, federal siting authority, a national cost allocation plan and a requirement that any generation that connects to the grid meet “green” standards. The four parts appear very similar to a plan produced by the Energy Future Coalition and the Center for American Progress.

Thankfully, Reid’s proposed legislation has yet to see the light of day given the extraordinary costs involved with constructing new national interstate transmission lines. For example, grid operators in the eastern half of the U.S. earlier released in August a study estimating that more than $80 billion in new transmission infrastructure would be needed to get 20% percent of the region’s electricity from wind generation by 2024.

Does Siting need Fixing?

The Federal Energy Regulatory Commission (FERC) recognizes the challenges posed by bringing electrons from new and disparately located renewable energy sources to population centers. In late May, FERC announced a series of transmission planning meetings that will focus on “wider integration of regional energy resources into the nation’s power grid.” In essence, renewable energy generation, principally wind energy, is located where the transmission infrastructure does not exist, and other distributed energy resources are located in transmission-constrained regions.

According to FERC Chairman Jon Wellinghoff, “Planning is one of the three legs on the transmission policy stool—the others are siting and cost allocation—and all are crucial to meeting the goals of assimilating demand resources, renewable energy and distributed generation into the grid for the benefit of consumers.” Here we go again.

From Market Pull to Product Push

Historically, electric utilities dictated when, where, and how much new generation would be added. Their integrated resource plans (IRP) determined the timing of plant additions, the fuel sources, and the location of the new generation resources. Transmission planners followed the lead of utilities to route the necessary transmission capacity while also seeking to lessen area congestion, if necessary. Traditionally, new power generation resources—and, by extension, new transmission—responded to a market pull: predicted load demand. The role of the state and local governments was oversight, providing access to transmission, and setting rates.

In contrast, renewable mandates have upended the traditional approach to developing an IRP. Rather than anticipated customer demand driving generation and transmission decisions, government mandates are now in the driver’s seat. Twenty-nine states and the District of Columbia have a renewable portfolio standard that requires utilities in those states to supply some percentage of renewable electricity by a date certain.

For instance, the California Public Utility Commission requires that 33% of that state’s power originate from renewable energy sources by 2020. In order to achieve this extraordinary goal, all new power generation procured by the state’s utilities must come from renewable energy sources. In this new world, the “pull” of market demand has been supplanted by a government-mandated “technology push” that determines which renewable developers pushing new power into the system in response to state-mandated levels of renewable power have access to limited transmission infrastructure.

One of the other challenges to building new transmission capacity to move renewable energy long distances that was discussed by Wellinghoff is identifying acceptable siting locations for renewable energy facilities. In spite of FERC’s interest is being part of that decision process, much progress has been made at the local level that makes FERC irrelevant in siting transmission lines in practice.

Transmission Planning Out West

One important initiative toward this goal in the Western Interconnection is the Western Governor’s Association’s (WGA) Western Renewable Energy Zones (WREZ) study. In the WREZ study—which covers 11 western states, two Canadian provinces, and areas of Mexico that are part of the Western Interconnection—as many as 50 zones with substantial renewable resources are in the process of being identified so that renewable projects can be expedited and transmission projects can be planned in advance.

The ultimate goal of the WGA is to “develop 30,000 MW of clean and diversified energy by 2015.” The approach used by WGA is to first identify regions with high potential for generating renewable energy—solar, wind, geothermal, etc by involving all the relevant stakeholders. The results of these studies in turn drive transmission planning.

The most recent draft map from the Western Governor’s Association illustrates Qualified Resource Areas as those areas with a high density of developable renewable energy resources after screening for known technical and environmental limitations for which data are available. These data will be used to determine Western Renewable Energy Zones (WREZ) in the Western Interconnection.

The state with the largest installed wind power capacity has already identified Competitive Renewable Energy Zones (CREZ) within the ERCOT Interconnection. In March, the Texas PUC assigned approximately $5 billion of transmission projects to be constructed in these CREZ that will eventually transmit 18,456 MW of wind power over more than 2,300 miles of new transmission lines from power-heavy West Texas and the Panhandle to highly populated metropolitan areas of the state. To put the magnitude of these numbers into perspective, the cost of transmission is over $2,000,000 per mile or over $270/kW of installed capacity.

The regulatory body expects that the new lines will be in service within four or five years. The Texas PUC took about three years to select the most productive wind zones in the state, designate them as CREZ, and devise a transmission plan to move power generated from those zones to various populated areas in the state. Many of these new transmission projects will begin construction later this year.

As an aside, T. Boone Pickens’ investment in his now delayed plan to build 1,000 MW of wind power in the Texas panhandle is in jeopardy. The ERCOT transmission plans do not extend the wires far enough into the Panhandle to reach Pickens’ projects. Pickens now has 687 wind turbines available that cost him a cool $2 billion that he hopes to recycle on a number of smaller projects in the U.S. and Canada. That’s a lot of wind turbines.

The Cost of New Transmission Is Substantial

More insidious are unpredictable transmission costs. Power sellers, buyers, and investors adamantly want price certainty in the total delivered cost. However, congestion charges can make the delivered price vary, especially in locational marginal pricing.

Everyone wants to know the answer to the question: What is the added premium to deliver renewable energy? Many transmission networks have both fossil fuel and renewable generators sharing the same network. Certainly, intermittent renewable sources have higher system-integration costs. Load balancing is more involved as well.

A recent Lawrence Berkeley National Laboratory study may provide an early answer to the cost question. Lawrence Berkeley National Laboratory (LBNL) recently issued a research report that examines the expected costs for new transmission infrastructure that would be needed to support an accelerated program for renewable energy projects, particularly wind energy. The report, “The Cost of Transmission for Wind Energy: A Review of Transmission Planning Studies” was released in February 2009. (A copy of the report can be downloaded at http://eetd.lbl.gov/ea/ems/reports/lbnl-1471e.pdf.)

The authors’ objectives in preparing this report were threefold: to define the transmission costs for a rapidly growing wind power industry, to discuss different transmission planning approaches, and to examine the models used to estimate future wind deployment. Our interest is this article is to focus on the transmission cost estimates prepared by LBNL.

The cost estimates are based on a review of 40 transmission planning studies completed between 2001 and 2008 by various developers, independent system operators/regional transmission operators, state agencies, and individual utilities. There is a wide range in transmission costs, although the costs are generally less than $500/kW. The cost of the median study scenario was $300/kW, or about 15% to 23% of the typical installed cost of a wind turbine plant. These numbers are quite consistent with the $270/kW from ERCOT discussed above.

The authors also concluded that variation in the study methodologies used in these 40 transmission siting studies and the characteristics of the specific grid may affect transmission installation costs (see table). Depending on the original purpose of the transmission line under study (whether it was congestion or deliverability focused), the authors concluded that the purpose affected the costs of adding wind energy to the mix.

Estimated Installed Cost of Wind Transmission Based on Three Higher-Level Studies of Wind Transmission. Source: LBNL

Study

Wind Capacity; Unit Cost of Transmission for Wind Power; 10% Wind Energy by 2030 (AEP 765 kV Overlay Study)

200-400 GW @ $150-$300/kW

20% Wind Energy by 2030: Wind Deployment System

290 GW @ $207/kW

Annual Energy Outlook 2008 Projections for 2030: National Energy Modeling System

40 GW @ $450/kW consisting of $316/kW for transmission and $133/kW for “long-term” multipliers

The study also reviewed three high-level wind transmission–only studies, as shown in the table above. These costs are generally consistent with the median cost identified in the original study sample of $500/kW, or about 25% of the $2,000/kW cost of constructing a new wind project.

The study also concluded that the historic cost of transmission was in the range of $35/MWh to $79/MWh with an average of $45/MWh. Using reasonable economic assumptions on the ERCOT transmission projects and a 33% capacity factor, the transmission lines add about $50/MWh to the price of power generated by the wind projects. For perspective, existing nuclear plants as an industry deliver power to the grid at less than $20/MWh and coal plants are in the range of $30 MWh.

Another Approach: Requiring Backup Power

Nevertheless, renewables do add additional costs to the whole system. For instance, speedy ramp-up of backup power is essential when a wind farm goes down with as little as one-hour warning. Reliability issues kick in as well.

For example, an ERCOT report concluded that only 8.7% of historic wind generation was produced during peak power hours limiting its effectiveness in trimming system peak demand.

Someplace in the delivery chain this intermittency of energy production versus load demand must be smoothed out. Utilities traditionally have taken on this burden themselves. Typically, a utility backfills wind/solar gaps with gas-fired plants to make up for any shortfall in energy production based on a number of factors, including the season, weather, and the region’s operating experience. Using the same approach with very remote wind and solar farms isn’t as straightforward. To do so would make the entire long-distance energy delivery chain, in effect, run intermittently—if the remediating, balancing measures are not applied.

A more recent procurement practice is for the electric utility to insist that the renewable producer directly supply steady, baseload-style power. In particular the utility expects the renewable power producer to have its own storage or natural gas backups. An example would be Xcel Energy’s April 2009 request for proposal for 600 MW of solar thermal that is “fortified” in this way.

Conclusion

Central planning based on temporary political majorities–or, dare one say, ‘political whim’–is not a viable long-term electricity policy. Free-market incentives to expand and build are preferable, and do not expect a 3,000-mile ‘green’ superhighway as a result.

— Also contributing to this article was Sonal Patel, POWER senior writer, and Martin Piszczalski (Ph.D), an industry analyst with Sextant Research

Transmission siting controversies are increasing given the growing number of renewable energy projects that want to interconnect with scarce transmission capacity. Now, another layer of complexity is in play due to the potential of a national renewable portfolio standard that portends hundreds if not thousands of new renewable projects that will all seek priority for grid access.

There are new renewable projects in development today that are already in the queue waiting for transmission capacity on existing lines or the construction of new lines because of the prohibitive costs of transmission upgrades. Other projects are so remote that only a purpose-built transmission line can bring the energy to market.

Adding uncertainty to uncertainty, Congressional leaders have proposed constructing new transmission lines dedicated to moving only renewable energy coast-to-coast whereby state’s rights will be of secondary importance. Regardless, ratepayers will end up paying the tens of billions of dollars for these new lines and further driving up the cost of electricity.

Below, we discuss how FERC failed to implement the siting authority granted in the Energy Policy Act of 2005 and provide a case study on the reasons for failure. Part II (tomorrow) will look at the latest rendition of the siting authority power grab: Obama’s promise of a 3,000 mile coast-to-coast “green power” superhighway. We’ll also discuss the recent work by regional transmission planning organizations to bring renewable energy to market and the costs to do so. It won’t come as a surprise that the costs are extremely high.

New Transmission Sites May Take Years

Siting new transmission lines is an exercise in patience and endurance. The industry has plenty of war stories about state, county or local authorities being unable or unwilling to approve new transmission projects, especially projects that merely transit through a state to get energy to an out-of-state market. One of the long running and always contentious debates is the resistance of Connecticut residents to allow transmission of electricity generated upstate to pass that power through to New York City.

One of the most egregious examples of how a project can become a career in my memory is AEP’s Wyoming-Jackson Ferry line completed in 2006—16 years after the project’s launch, 14 of which were spent wrangling over siting.

Another example; a plan hatched in the late 1980s to move surplus power from coal power-rich West Virginia to power-short New Jersey and New York crashed in the early 1990s due to the opposition of Pennsylvania. Delegates from the Keystone State asked, appropriately, “What’s in it for us?” The answer: “Not much.” Pennsylvania responded, “No thanks.” End of project, after nearly a decade of contention.

Congress has made numerous attempts to reduce these delays and shorten the time required to add new transmission capacity where it is most needed. And each time the new laws have failed miserably.

The most recent attempt was provisions in EPAct that gave FERC the authority to override state and local opposition to the construction of interstate transmission lines if the agency determines that they will reduce system congestion. In April 2007, the Department of Energy designated two regions that qualify for such treatment as “national interest electric transmission corridors.” One covers a broad territory stretching from Maryland to New York and as far west as Ohio. The other includes a large chunk of southern California, southern Nevada (including Las Vegas), and parts of Arizona all the way to Phoenix.

In announcing FERC’s plan at the time, then-Energy Secretary Samuel Bodman said, “The parochial interests that shaped energy policy in the 20th century will no longer work.” Maybe so, but instead of serving the “national interest,” the proposed corridors look a lot like a lot of poaching routes to me. Their result was said to enable regions that have resisted building generation locally—in hopes of buying cheaper power from other regions—to avoid paying the full costs of “their” power. The problem with this plan is that it saddles out-of-state generating regions with the environmental and lost-resources costs and consequences.

California Dreamin’

The Sunrise Powerlink is certainly the most ambitious project developed by San Diego Gas & Electric (SDG&E) in many years. The recently approved project is running a new 150-mile transmission line east from San Diego into the deserts. SDG&E claims the link will spur development of renewables (geothermal and solar), lower transmission system congestion costs, and “reduce subsidies paid to local, aging power plants that are more expensive to operate.”

The second and third justifications are closely related and often given short shrift by the media. In the report backing its national corridor designations, the DOE states that one of the biggest reasons it considers the southern California grid “troubled” is the high cost of running those old plants in California—typically gas-fired units in urban areas. No surprise: SDG&E hasn’t built a new power plant in its service territory in more than 30 years.

In the interest of full disclosure, I worked on the design and construction of SDG&E’s last major power plant project Encina Unit 5 when it was constructed in 1976-78. I was also present when then-CEO Tom Page announced in 1978 that SDG&E was not going to construct any more plants but would become a “wires” company and in the future import energy from other sources rather than construct any new plants. To do so was a pure business decision made at the time given the resistance of local governments and citizens to building any more power plants. This business plan was a conscious decision to avoid building local generation and rely solely on imported energy to cover load growth. To their credit, the plan has worked for over 30 years, but now Arizona has the surplus power capacity and a growing population and is unwilling to share their electricity resources. This is a game changer for Southern California.

Buddy, Can You Spare a Megawatt?

I recently drove my 4WD truck to the top of a small mountain just south of the Palo Verde Nuclear Generating Station in Arizona, about 100 miles from the California border. The power park view warms a power engineer’s heart: The three-unit 3,739-MW nuke lies to the north, and to the south sit Sempra’s 1,250-MW Mesquite Generating Station, Pinnacle West Energy’s 1,136-MW Redhawk Power Plant, and LS Power’s 713-MW Arlington Valley Energy Facility. Travel over the next hill and south a few miles and you’ll find the 2,400-MW Panda Gila River Project. All but Palo Verde are gas-fired combined-cycle plants.

I’d venture that a big chunk of the more than 9,200 MW is just aching to find a path into Southern California. Why? The average retail electricity price is almost 50% higher there than in Arizona: 15 cents/kWh vs. 8.5 cents/kWh. Finding new customers willing to pay more for the same commodity would be a business coup for the plants’ owners. The only hurdle would be permitting the new lines needed to deliver it. But the Arizona Corporation Commission (ACC) has a different vision of how that power will be used—generate it in Arizona, use it in Arizona.

To its credit, the ACC saw through the “master plan” scheme and unanimously voted down a Southern California Edison (SCE) proposal to build a 231-mile transmission line to connect the power park to a substation near Palm Springs (and ultimately to the Sunrise Powerlink and points west). SCE execs argued that the link would “increase the state’s ability to transmit energy.” What they really meant was the ability to transmit energy to Southern California. Bill Mundell, an Arizona energy commissioner, explained the rejection succinctly at the time: “I don’t want Arizona to be the energy farm for California.” Commissioner Kris Mayes added, “You [SCE] are trying to drop a giant extension cord into Arizona.”

The final meeting on the project turned a bit testy when commissioners quizzed Dian Grueneich of the California Public Utilities Commission about her state’s recent lack of progress building new power plants and transmission lines. Mundell asked, “Why should Arizona put its natural resources, environment, and future energy supply on the line while California does relatively little?”

That’s indeed what California is asking Arizona to do, in an updated version of Aesop’s fable of the grasshopper and the ant. And that’s precisely why the entire national interest corridors program will face challenges from power “donor states.” In California’s case, taxing that nasty coal-fired power coming into the state up north and strong-arming its neighbor to the east for a bigger slice of existing gas-fired capacity is an energy plan doomed to failure. Nevada, keep an eye on these guys.

New Developments

Unable to convince Arizona’s utility commissioners to approve the new power line, the California utilities did just as was expected: ask FERC to step in and exercise some of that authority vested in them by EPAct to make Arizona plug in their extension line. FERC tried to mediate the disagreement with no success and subsequently developed an order forcing Arizona to agree to the interconnection. The inevitable federal court case resulted.

In February 2009, a federal appeals court slapped FERC’s hand for overreaching the authority granted to the agency by EPAct when it took an “expansive interpretation” of the law in asserting its power to override state decisions.

The U.S. Fourth Circuit Court of Appeals in Richmond, Va., issued its decision in a case brought against the regulatory commission by the Piedmont Environmental Council and multiple states and parties—including the New York Public Service Commission (PSC) and the Minnesota Public Utilities Commission (PUC).

At the heart of the matter was the authority granted by EPAct, which allowed the commission to approve interstate power lines after the affected state had “withheld approval for more than a year.” But in an issuance of a final November 2006 rule, FERC substantively interpreted the phrase, “withheld approval for more than one year” to include a state’s denial of a permit within the one-year statutory timeframe.

The petitioners had filed requests for rehearing on FERC’s final rule, arguing that the agency had erred in its interpretation. The parties also asked the court to review several rulemaking decisions FERC had made with the application of that interpretation.

“FERC’s interpretation is contrary to the plain meaning of the statute,” wrote Judge Blane Michael for the majority. “Simply put, the statute does not give FERC permitting authority when a state has affirmatively denied a permit application within a one-year deadline.”

Michael said that FERC’s standing interpretation would mean that state commissions would lose jurisdiction unless they approved every permit application in a national interest corridor. “Under such a reading it would be futile for a state commission to deny a permit based on traditional considerations like cost and benefit, land use and environmental impacts, and health and safety. It would be futile, in other words, for a commission to do its normal work,” he wrote.

The court’s decision now sets hurdles for FERC-approved projects whose public commissions have issued denials but that hasn’t slowed down the pressure to overhaul (again) the provision of the EPAct failed to pass judicial scrutiny.

In essence, FERC powers granted under EPAct were neutralized by the appeals court’s decision and Arizona’s rejection of the construction of a new transmission line stands.

But, this court decision doesn’t bring an end to the push for federalizing transmission siting authority. Far from it. The next page of the game plan uses the supposed need for a “green” coast-to-coast transmission superhighway as cover for nationalizing all future transmission siting decisions.

— Also contributing to this article was Sonal Patel, POWER senior writer

There is no doubt that, if we’re going to build more central station wind, solar, or nuclear power plants, we’re going to have to build more wire to get that electricity to consumers.  But the price signals we’re seeing in electricity markets suggests that building a small number of remote power stations with a lot of wire to get that power to market is less efficient than building a relatively large number of smaller, more accessible power stations with fewer long distance transmission lines.  The reason we don’t have more long distance transmission, after all, is because it has been more than 30 years since large central station power plants made more economic sense than smaller, more local power generation. 

What almost everyone on both the Left and Right miss is that transmission and generation are economic substitutes for one another.  The optimal (most efficient) mix of the two is an economic puzzle, not an engineering puzzle, and the best means of solving that puzzle is to ensure that prices for both are correct and to then let market actors to sort this out.

Ironically, it may very well be that, to the extent that there is suboptimal investment in transmission, the culprit is primarily vertical de-integration, not local “not-in-my-back-yard” sentiment.  That is, the wave of state-induced restructuring (popularly but inaccurately known in some quarters as “deregulation”) might be the real problem here.     

As an aside, it’s interesting to me that the Left is all a-gog over a massive federal program to build this transmission super-highway and in so doing preempt state siting authority.  Since when did the Left support dropping the hammer on local communities or property owners who object to development because of concentrated costs and diffuse benefits?  And haven’t many of these same parties at one time or another echoed Amory Lovins and evangelized for “distributed energy” - that is, an electric power system characterized by neighborhood or even on-site power generation and a correspoding abandonment of the “big power, big-wire” model? 

I don’t have any brief one way or the other, but I can’t believe that central planning works surprisingly well when it comes to electricity markets but, for some mysterious reason, not very well anywhere else.  The fact that the grid at present is essentially a public commons certainly requires some central planning from somebody just to stay in operation.  This implies the need for policies to privatize that commons and return the electricity planning back to market actors.

Update: Lynne Kiesling comments on the conference and nicely hits another issue – the “smart” part of the grid conversation that is frequently overlooked.  My take - when residential consumers get – and pay! – accurate price signals for the electricity they are buying, pigs will fly.