Wednesday, September 14, 2016

Smart Power: Climate Change, the Smart Grid, & the Future of Electric Utilities

Book Review: Smart Power: Climate Change, the Smart Grid, & the Future of Electric Utilities: Anniversary Edition – by Peter Fox-Penner (Island Press, 2010, 2014)

This is an excellent book that delves into the changing utility models taking shape with new sources of distributed energy, often renewable, and smart grid technologies that can make the electric grid more efficient and more responsive, yet still keep it stable and reliable.

The new edition begins with four long forwards, the first by retired Duke Energy CEO and chairman Jim Rogers. He credits the “pressures of climate change” and the “capabilities of emerging technologies” with forcing the utility industry to begin to change from their outdated business models and regulatory structures. Trends that have been occurring will continue: less coal, more natural gas, probably not much change in nuclear, more wind, more solar, more distributed resources, more battery storage, and more renewables-based peak load shifting. Rogers echoes Dr. Fox-Penner’s two main conclusions: changes are needed in utility business models and utility regulations.

The next forward is by Daniel Esty, a professor of environmental law and policy at Yale. He notes the unexpected rise of shale gas and oil through fracking and horizontal drilling which brought vast new and abundant gas supply onto the market, quickly making gas cheaper than oil and coal which had not been the case before. Now gas is the cheapest and the lowest emissions fossil fuel, and this will likely be the case for at least the next decade or two, he notes. He mentions state incentives, including making private capital available for solar startups and standardizing energy service company (ESCOs) contracts. His state, Connecticut, has implemented these projects to make renewable energy cheaper. They have also begun buildout of a system of microgrids powered with small gas turbines, fuel cells, and biogas from anaerobic digesters. These are forms of distributed generation (capable of offgrid “islanding”) in addition to most renewable sources, especially if they have battery backup. He also notes the need for a change in utility business models with other sources of revenue besides selling energy. One is selling energy services where energy efficiency is commodified. Another is managing demand fluctuation (demand response services). Others are managing microgrids and providing backup power for distributed resources. 

The third forward is by Daniel Dobbeni, a principal in several companies. He notes that utilities and power sources are affected by events and policies (Fukushima in Japan, carbon markets and laws in Europe, etc.) He notes that the effects of renewables on the grid (need for backup/peak generation and equipment to balance supply and demand of loads) has been largely ignored until now. He notes the potential for stranded assets in the form of transmission lines that could come about as new technologies replace them. He notes that the focus of energy policy in Europe shifted from competitiveness to sustainability, culminating with the 2007 renewable energy directive, with new infrastructure from 2013 onward focused on connecting Europe as a whole. Europe has adopted a common market model for the power industry, unlike other areas such as in the U.S. Power ‘flexibility,’ such as demand side management, is required in the increasingly distributed energy systems. The European model is to be watched and studied so better models can follow it.

The final forward is by Lyndon Rive, cofounder and executive officer of SolarCity. He focuses on the potential for economic catastrophe due to climate change. Making the grid cleaner and more efficient should be vastly accelerated, he notes (as any solar executive should/would). His focus is to do away with the old utility business models faster to save money since the transition to renewables is inevitable and doing otherwise would be wasteful. He sees midday “overgeneration” from solar more as an opportunity than as a problem, one that might be used for water desalinization and electrification of transportation. He says the old U.S. utility monopoly model of “sole source/cost plus,” where competition is suppressed and profits are guaranteed, is economically undesirable and unsustainable. NASA migrated away from such a model quite successfully and so should U.S. utilities, he says.

Fox-Penner starts out with an account of the first electric revolution. Electric machines and electromagnets in foundries led to drastic increases in work output in the late 1800’s. He talks about the industry developed by Insull, one of Thomas Edison’s staff who became the CEO of Commonwealth Edison. Power was aggregated into what we know as the “grid” and power was sold to take advantage of economies of scale. The model was monopoly with the more power consumed the cheaper the cost per unit of power for the consumer. He also noted that regulation of the industry would provide both stability and protections. It was Insull’s vision that influenced the investor owned utility (IOU) model that has been the standard in the U.S until recently.

The second electric revolution is in progress. Two of the main motives are the need to reduce greenhouse gas emissions and the need for energy security. Renewable energy, energy efficiency, and replacing high carbon fossil fuels (coal) with low carbon fossil fuels (gas) are the three main ways of reducing carbon emissions in the electric sector. Securing domestic energy supply (oil, gas, coal, nuclear, and renewables) helps reduce our dependence on foreign suppliers, particularly on OPEC countries and oligarchies like Russia who use energy as political leverage. Electric transport via EVs can also help us with both. Such needed changes, says Fox-Penner, will be both challenging and expensive for utilities and their rate-payers. Implementation of the so-called “smart grid” with software embedded technologies to optimize efficiency, balance local grids, and buy and sell energy at different rates, will happen more and more over the next few decades. Less coal, more gas, and more renewables will be on the grid. More battery and other energy storage projects will be added. Grid management will be complexified and yet it will be more efficient overall. Fox-Penner mentions three objectives: “creating a decentralized control paradigm, re-tooling the system for low-carbon supplies, and finding a business model that promotes much more efficiency. The consumption model where utilities profit strictly from sales of power is not sustainable. Electric power demand in the U.S. has been flat for a while and is expected to stay there. This is due to efficiency increases and reduction of waste usage on both sides of the meter. One question is how investor owned utilities can remain viable – can remain profitable while meeting all these challenges. New business models are required. Some utilities have and will be resistant while others have or are adopting new economic paradigms.

Electric deregulation is the next issue. In 1990 the consensus was that the electric utility industry should follow airlines, natural gas suppliers, telephone companies, and trucking firms in allowing markets rather than regulators to set prices. Deregulation was oversold, says Fox-Penner, and executed poorly, resulting in the California energy crisis. Early problems have been fixed with better oversight and better market designs but there are still problems. Twenty-three states originally implemented deregulation but eight of those have suspended it or scaled it back. Analysis indicates some regulation is required for successful power markets. 

The three vertical stages of power production from an engineering perspective are: generation, transmission, and distribution. When a company owns all three of these aspects it is said to be vertically integrated. Only some of the U.S. power industry is vertically integrated. Wholesale, or “bulk” power trading between generators and distributors is subject to pricing set by the Federal Energy Regulatory Commission (FERC). This includes control of high-voltage transmission systems. The authority to build transmission systems resides in the individual states through their public service commissions (PSCs). The PSCs set rates for transporting power over these systems. Residential, small-commercial, and large-commercial pricing is at different rates. There are also generators owned by federal, state, and local governments which are subject to less wholesale and transmission regulation as are government and customer owned (co-ops) distribution systems. All the government and customer owned utilities are thought to be less likely to charge unfair prices so they are less regulated. In a deregulated market it is the market itself that sets prices for the wholesale market – transmission and distribution are still regulated by FERC or PSCs.  In 1994 FERC was permitted to create an “open access” system in which any generator could use anyone else’s transmission system (first-come, first-served) to deliver power to a state-regulated system. FERC also began allowing some generators to sell wholesale power to other utilities, not end users, at deregulated rates. In order to develop fair competition in all power markets there are three requirements: 1) enough competing power generators (deconcentration), 2) a transmission system large enough to accommodate all generators, and 3) “open access” rules. If markets can allow buyers to react to price changes then they will be more functional. Power prices tend to vary hour to hour. Unfortunately, there are very few places where all these conditions occur currently but some regional power markets are testing new dynamic pricing, or ‘time-of-use’ models.

Deregulation in the states that adopted it was given as a consumer choice so that consumers may choose a provider or choose not to participate in the deregulated market. This is likely due to the previous deregulation of telephone service where consumers were forced to choose a provider. Since deregulated prices were expected to drop the non-deregulated (provider of last resort, POLR) prices, the new prices were set 10% lower and frozen for five years. However, in many areas deregulated providers could not compete with POLR rates. At the time the cost of fuels rose and deregulated providers had to raise their rates but POLRs could not which made POLRs cheaper than deregulated sellers, a situation opposite of what was intended. This was not the case everywhere and some deregulated providers were/are able to offer lower prices. In May of 2000 hourly electric prices in California began spiking. Energy was in short supply, especially natural gas. This caused intentional blackouts and rolling blackouts for consumers. Prices up to 10 times the previous averages continued in the northwest. The FERC stepped in to provide caps on prices and other measures. By July 2001, the crisis was over. It cost Californians $33 billion more than the previous year’s cost! This gave deregulation a bad reputation. By 2006-2008 when the POLR 10% off rates expired they went up considerably, further bashing the customer advantage claims for a deregulated power industry. Fox-Penner suggests that the relative failures and turbulent history of deregulation in the power industry have galvanized resistance to further “changes,” some of which are necessary to adapt to changing energy sources and business paradigms. Deregulation was only adopted by some states so it further confuses and adds to the already significant variability of generation owner-types and regulation models. The U.S. power industry as a result is quite heterogeneous which makes adopting new regulations and business models and getting new projects going difficult, especially as smart grid technology advances.

Next he goes through some early (2005) dynamic pricing/time-of-use pricing experiments where energy consumers could alter their daily power use to take advantage of the best prices, through smart grid software embedded technology. The results were excellent in keeping power use down, with the possible application of decreasing power spikes that require extra generation usually provided through idling and ready power plants (peaking plants) built for demand peaks.

He explains how second-by-second balancing of power supply and demand on the grid happens with system operators constantly monitoring it at a control center called the ‘balancing authority.’ System operators typically have ‘reserve capacity’ in the form of demand “peaking” plants. Typically for every 100 MW of baseload capacity there is 15 MW of reserve capacity, so 15%. About 5 MW, or 5%, will be ready and idling at any given time, burning fuel and producing emissions. 

Another feature of power use assessment is its one-way nature. The old “dumb” meters measure how much power we use over the course of a month, the billing period. Pricing may vary by season but that is about it. New smart meters keep track of hourly power use and may charge according to times, the price per kilowatt-hour varying with established demand periods. The technology is capable of responding to “dynamic pricing” which may change minute-by-minute and communicating back and forth through high-speed internet. In the past utilities encouraged more power use by dropping prices as power use increased through the month, so-called “declining block rates.” Dumb meters are like charging for groceries by weight rather than by item as one utility executive puts it.

Fox-Penner gives a kind of average scenario where the cost for a utility to generate one kWh varies from 2-3 cents in the dead of night to 8-20 cents in high demand periods from hot or cold days when old and inefficient plants in reserve are turned on. Another potential feature of smart meters is that they can work with smart appliances to respond directly to price changes or simply programmed to run at lower demand/lower price times of the day or night. Smart meters are also more useful for integrating renewables and other distributed sources and battery storage. Thus the end users can self-balance their own power supply and demand. During high demand times if enough users reduce their power usage with smart appliances then there may be no need to turn on expensive reserve capacity. Fox-Penner says that while system operators do employ demand response software that they will still balance the grid manually for a long time to come. 

The smart grid offers three basic advantages: 1) greater customer control over energy use and costs, 2) enabling of local small-scale power production, and 3) a more reliable and secure grid. However, he notes, there are complications. Smart meter technology that regulates the downstream distribution end of the grid is different from high-voltage transmission coming from the upstream generation end where many power plants feed in. Hourly dynamic pricing and trading has long been a feature at this generation-transmission end as has been smart computerized control and switching. Even so, he notes, new software technologies can still improve that end. Such technologies will allow better “situational awareness’ of grid issues and disruptions than previously. Smart grid technology will make it easier to incorporate storage. Having energy storage available means the grid can respond to demand and balance the grid instantaneously and at low cost with the stored energy. Utility-scale storage as well as storage associated with distributed resources on the other end can both be utilized and eventually optimized. However, cost of implementation, battery life, and other issues keep it from being implemented widely. Local distributed generation allows two-way flow of the grid which can be advantageous to the local generators and to the grid as a whole. The smart grid can provide self-activating tools to increase grid reliability and prevent blackouts.

Next he goes into real-time pricing, or time-of-use (TOU) rates, a feature likely to happen more and more in power markets as smart grid tech advances. In TOU pricing the utility may set the daily variable rates in advance. In ‘critical peak pricing’ (CPP) the utility may warn users say a day in advance of expected high demand and high prices so they can plan accordingly. In real-time pricing (RTP) new rates may be set every hour. Such variable rates are designed to be neutral to the utilities (prices are shifted so that the utility makes the same amount of money no matter how much power is used) in terms of power sales but beneficial to consumers. Dynamic pricing advocate Ahmad Faruqui found that typical TOU rates can reduce demand peaks by about 5% and CPP can reduce them by up to 20%. Fox-Penner notes that if this could be sustained as a national average then about 200 medium-sized power plants could be eliminated! So too can their carbon emissions and pollution. This can happen in a fully developed smart grid automatically by programming devices to respond to expected and short-term price changes. Kurt Yeager formerly of the Electric Power Research Institute calls it ‘prices to devices.’ Smart thermostats are now more widely available and many other devices are being outfitted with these ‘enabling technologies.’ Customers can save over a hundred dollars a year while helping the utilities save money (by not building and using more reserve capacity and associated grid) and help a little to mitigate climate change and pollution. By not having to turn on expensive reserve capacity the overall pricing can be reduced as well which benefits not only those provided the ‘demand response’ by reducing their usage, but all users on the system. It takes about 5% of demand drop through demand response to lower prices for all so these benefits should be quite achievable as the tech advances. Those who provide the demand response by lowering their usage through smart tech will of course save much more than the other users. Avoiding the building of more reserve capacity and associated grid is called avoided capacity cost as the reserve capacity is now provided by built-in demand response. This may easily become the largest benefit of DR as it is advanced. Another pricing mechanism is increasing, or inclining block rates. This is simply raising per kWh prices with excess use per customer. This has long been done and was first implemented by Insull – no smart tech required. 

The barriers and resistance to DR and dynamic pricing come from the utilities who have to pay for and implement the smart tech. Changing tens of millions of meters from dumb to smart, or installing ‘advanced metering infrastructure’ (AMI) is quite expensive. However, it does allow utilities to eliminate meter readers as meters can now be read electronically. As smart grid tech advances the cost scenarios will become more familiar to utilities and regulators so business cases can be more predictable. Some users are not able to change their use patterns much such as those who do their most business at times of high demand so they argue that dynamic pricing could hurt them but of course the overall drop due to DR would mitigate this somewhat. However, research indicates that only a few percent of users would end up with higher bills due to well-designed dynamic pricing. Right now we should be around 50% give or take of smart meter implementation, or AMI, in the U.S. The shift from flat power rates to variable ones will save customers quite a bit of money and a little carbon as well.

Next we come to the regulatory realm. The main goals of utility regulation are to keep utilities from making excessive profits or from incurring excessive losses. Regulators and utility executives face significant uncertainty regarding the results of smart grid investments and it will take time to evaluate them. The benefits are large, mostly external to utilities, but not easy to measure quantitatively. Large upfront capital investments are required. Regulators will have a lot to consider. Both DG and DR can add significantly to ‘avoided capital costs’ for utilities, costs which are much greater than energy saved costs. However, figuring avoided costs is not easy. Congress dictated in the 1980’s that states must determine avoided costs every few years and there are many different methods of determining them. Part of the difficulty is that the grid is highly connected and determining avoided costs requires making detailed and extensive hypothetic cases. Wholesale prices are also regional now as different regional markets sell electricity at different rates. Transmission can be considered the difference in costs from the two markets it connects. This is also how natural gas is regionally priced. It is considered a reasonable approximation of value. However, there are requirements: knowledge of daily price fluctuations, knowing the value of scheduled power, requiring DG and DR to keep safety margins of power, and planning for blackouts. Fluctuating hourly prices in wholesale markets benefit small DG and renewables generators, say DG advocates. At press time, 42 states had net metering so that distributed generators, including rooftop solar generators, could sell their power to the grid at the same rate as they buy it. In terms of avoided costs it is actually best to install DG or DR in the middle between generation and end-user distribution. The author mentions Amory Lovins work on DG and his 2002 book – Small is Profitable – as a monumental text on DG. He catalogued many other side benefits to DG. However, most are nearly impossible to measure. For instance, having DGs would make terrorist attacks less disruptive. 

More downstream distributed energy sources also mean that the distribution ends of the grid will need to be reengineered and that will cost and also raise local issues. Fox-Penner gives a scenario where a new solar DG generator will temporarily enjoy selling energy for high cost with those around them also having to pay that high cost until the utility upgrades the system in that area after which the DG will profit less and those around them will be relieved. Such seemingly unfair changing pricing may cause disputes and resentment. Such occurrences have happened on the high voltage end, slowing development. 

Two-way communication between grid operators and customers and their devices will be necessary for full smart grid implementation and software platform standards will have to be developed. This is happening now. This is a requirement for “plug and play interoperability.” Non-profits like the Institute for Electrical and Electronics Engineers (IEEE or I-triple-E) will likely write up the standards. Agreeing on standards has been no easy matter in the past and there are many standards to consider in expanding the smart grid. Cyber-security is another issue in smart grids. With many different languages and protocols in ‘supervisory control and data acquisition (SCADA) systems, the smart grid can be vulnerable to hackers. Russian and Chinese hackers are said to be already mapping U.S. power systems. 

The next topic addressed is total electricity sales, or power usage. This has remained flat for a while in the U.S. and is projected to stay that way. This is due to vastly increasing efficiency from all parts of the system. LED lights are an example from the user end. Utilities, particularly IOUs, have long planning times and significant investments to build generation. If planned power plants are built and later found to be not needed there is a huge sunk cost. If they are not built and there are blackouts, the consequences can be equally severe. Lower sales make it harder for the utilities to invest in low carbon energy and the smart grid. There is no incentive for them. An earlier example is nuclear plant cost overruns in the 1980’s which caused electric rates to skyrocket and bond defaults.
Renewables expansion will require more transmission lines, particularly from areas with rich wind resources that in the U.S. are typically remote from populations. People have resisted large transmission expansions in scenic areas. Transmission regulation is a mix of states, FERC, and regional transmission organizations. Different types of lines have different purposes and abilities. He compares AC and DC high-voltage lines. DC is unidirectional and AC is two-way, or bidirectional. DC lines lose less energy as they traverse long distances (in one direction only) so they can be more economical in certain situations. DC lines move hydroelectric power from the Oregon-California border to Los Angeles and from Canada into New England. They are better for moving power under water and can be used for offshore wind. Apparently, there are only about 15-20 of these DC lines currently in the U.S. Another new transmission technology is superconducting cables which can handle 3-4 times as much current as regular wires. Grid expansion planning is generally difficult in the deregulated markets due to jurisdictions and rules. There are often debates about who should pay for new lines, especially those traversing multiple states and power market regions. New lines will be needed, especially with utility-scale renewable power plants – which will be required to help meet carbon reduction goals and state RPSs. Unfortunately, the best wind, geothermal, and solar resources in the U.S. tend to be in areas with poor transmission infrastructure in addition to being far away from population centers where the power is needed. The bottom line is that a low-carbon future requires more transmission per kWh than our current high-carbon grid. A new transmission superhighway is in the planning with large power volume lines, both AC and DC proposed. Even so, a “supergrid” does raise some reliability and security issues if large amounts of power are coming from single sources. DERs can provide downstream reliability enhancements but upstream disruptions would still be problematic.  

Availability, cost, and reliability are the three main issues with low-carbon energy sources. Natural gas peaking plants used to back-up renewables are the best cost effective means for doing that. Combined cycle gas turbines (CCGT) are the most efficient power plants with energy conversion efficiency over 60%. Their cost per kWh is also the lowest of all power sources. They emit far less carbon and pollutants than coal.  Thus coal-to-gas switching is happening on a big scale and is by far the main reason U.S. greenhouse gas emissions have dropped. The big risk for these plants is high gas prices. Gas prices will likely remain quite low but gas needs to be available to new plants in order for more switching to occur so pipeline expansions are required. Many have been delayed recently due to public opposition. Low-carbon coal plants that use gasification and/or carbon sequestration are very few and far between and are still after many years not widely deployed. I think CCGT gas plants with some carbon sequestration will make these plants nearly as clean as renewables and will be a better deal than any coal plants. Carbon capture and sequestration (CCS) is simply quite expensive and will only be used in a world with carbon prices. It may be better to switch to gas then incorporate some sequestration with gas exhausts. Due to the scattered nature of power plants large networks of CO2 pipelines would be required which people tend not to like and CO2 leaks high enough in certain areas could be poisonous.

20% of U.S. power comes from nuclear plants and most are set to be retired over the next 40-50 years. Will more nuclear replace them? Maybe, maybe not. Costs, safety, security, waste storage, and decommissioning costs are the major issues. 

Wind power will continue to grow, mostly onshore but some offshore as well. Currently wind makes up about 4.5% of U.S. electricity. That could double in the next decade. The availability and cost of transmission limits wind, especially from its best sources in the Great Plains where transmission is scarce. Variability and so reliability is also an issue. Wind is most available when least needed. Storage of excess wind power would be ideal but storage technologies are currently far too expensive even if there are many projects operating and some mandates. When these “grid integration” issues are added the economics of wind power drop significantly.

PV solar has similar availability problems but is significantly more unpredictable than wind due to clouds and there is far less sun in winter. It does have the advantage that peak generation is close to high electric demand times. Even so, without demand or storage for the excess supply during peak generation times there will be grid integration issues with massive solar deployment. Solar economics, rooftop, utility scale, or solar thermal can’t even come close to the economics of CCGT gas, even with significant direct subsidies. Concentrated solar power (CSP), also called thermal solar, has been built in the U.S. southwest but the economics and the performance have been poor so far. It also tends to be in areas that require transmission upgrades.

Biomass power comes from four sources: wood waste from paper and furniture makers, forestry residue, agricultural residue, and methane from landfills and anaerobic digesters. The attribution of biomass as “net-zero carbon,”  while technically close to being true (it is carbon lean rather than carbon zero) , should be caveated with the fact that the carbon is entering the atmosphere much faster than it would have naturally. This is also true of biogas from anaerobic digestion. 

Geothermal and hydroelectric power will see some growth but overall the places it can be developed are small and there are some environmental risks with both. Hydrokinetic power from ocean tides and waves is also in this category of making small contributions to the energy picture. 

California defines DG as sources less than 20MW that connect to the local distribution grid rather than to the high-voltage grid.  The four sources are combined heat and power (CHP, also called cogeneration) – which are usually small gas microturbines; wind; small PV solar plants; and fuel cells. CHP utilizes waste heat to heat buildings. Factories and residential complexes utilize these 5-20 MW sources around the world, with the heat often being delivered through steam tunnels. Utilities have not been cooperative with CHP developments since it decreases their sales but more CHP means less carbon emissions so there should be no opposition. Small home-sized CHP gas microturbines are being used more and more by property developers. They are currently higher cost than grid power but are expected to drop as the technology advances. Siting energy using equipment is a challenge in these systems. They can also be used stand-alone as offgrid islands in many cases. Small-scale wind is simply too expensive although there is some development. The same is true of fuel cells. Costs could come down in the far future but now they are not at all economic. The costs of DG are often better than they appear due to the avoided costs they provide to the grid utilities which are hard to measure and often depend on siting and local grid circumstances. CHP is the cheapest current form of DG. “Observable” costs of DG (without accounting for costs avoided) are still 2-3 times as conventional large-scale power sources. Regulation and subsidies help but not enough. Currently there are 76-85 GW of CHP plants at 3300 sites but this could be expanded to an additional 80-100 GW by 2030. He doesn’t predict the DG revolution will truly begin until about 2030 and suggests most of it will be CHP, small and large. He gives two possible scenarios for future power: ‘small-scale wins’ which favors DG and ‘traditional triumphs’ which favors utility-scale centralized power projects on a more traditional grid. Either way the smart grid will be built. 

Fox-Penner shows comparison charts where gas is the cheapest of all sources as long as gas costs are less than $6 per MCF. Current projections put gas prices at $3-4.50 through 2020 so gas is by far our least expensive power source. Solar PV remains the most expensive energy source even with tax credits. Even with a price on carbon, gas would still be the least expensive and solar the most expensive. Only if the carbon price were above about $50 per ton would it change. Nuclear and carbon sequestration require long lead times and by 2030, he says, we will know if they will be a big part of the picture or not.

Problems with scenarios of complete renewables are many and include increasing costs per kWh as more renewables are added to the grid. Even in the distant future mixed energy sources will likely be used including gas, hydro, and nuclear – all which can provide baseload power. Thus most power providers now and in the future have diverse power source portfolios, used to satisfy demand, reliability, low carbon mandates and pollution mandates such as the Clean Power Plan. The shift toward renewables and smaller sources is indeed inevitable but how much and how fast are the questions.

Next he explores in detail new power provider business models. First is finding a way to commodify and incentivize energy efficiency (EE) so that providers can profit from it as well as power sales. EE is a straightforward investment for someone who buys power but not so for those who sell power. EE also offers the best potential source of carbon emissions and pollution reductions, so these investments are also emissions reduction investments which makes them doubly valuable. Thus carbon pricing would further incentivize them as well. He goes through the barriers to EE adoption: 1) information, 2) capital availability, 3) transaction costs, and 4) inaccurate prices. First accurate information must be obtained about comparative efficiencies of energy sources and technologies big and small on each system. This is true on utility-scale as well as home-scale end-user efficiencies. People especially need to understand efficiency and the potential benefits before they invest in it. Capital availability is simply that. Efficiency is an upfront all-capital cost where 100% must be paid out before savings are realized. Utilities have many projects like new plants, transmission build-out, and smart grid expansion – so EE must compete for capital. Transaction costs refer to the disruption effects of contractors adding the new measures which may cause occupancy delays in new housing and building projects. Inaccurate price signals refer to the common situation that the builder will not be the one paying the bills but will be the one choosing the energy systems and appliances so has no incentive to look at potential energy use costs. One help to some of these problems is when free energy audits and sometimes installation advice are provided by organizations or utility companies. Appliance efficiency standards have saved massive amounts of energy and have saved consumers massive amounts of money. However, the construction and real estate industries as well as appliance manufacturers routinely oppose them because they increase their costs and change construction and manufacturing practices. Building efficiency codes and appliance efficiency standards are surefire ways to save energy and emissions and need to be further pursued. Utility efficiency programs can also be effective – offering free energy audits, low-interest loans, rebates, and free technical assistance. State government incentives and financing have also worked to enable EE. Private sector EE has also been fairly successful through energy service companies (ESCOs) utilizing ‘shared savings’ business models whereby the ESCO pays for the EE upgrades and recoups their money and a certain amount of profit over time while the customer enjoys cheaper energy costs that drop even more when the ESCO is paid off. This is a great model for companies since the ESCO does all the work but often they don’t do the full EE upgrade but only partial ones with rapid paybacks except in government installations where the government mandates full slow payback EE upgrades which are better in the long run. To mandate utility EE there is the Energy Efficiency resource Standard (EERS) whereby the utility or seller of electric power has to meet a certain percentage of sales growth through energy savings through efficiency upgrades. Thus they are mandated to save a certain amount of energy in addition to selling it. About half of U.S. states have some version of EERS. Utilities can often raise capital at lower interest rates – they are credit worthy because they are providing an essential service. This gives them an advantage in investing in EE by loaning to their customers. They are an ideal low hassle financing entity. On the downside utilities face ‘divided incentives’ – selling energy vs. saving energy. Government control of EE programs also has downsides: changing administrations changing the rules and complaints about excessive government loans (as in the DOE paying for weatherizing upgrades) since EE is capital intensive. Further government control could involve tax increases which are unpopular. He gives the three approaches as 1) requiring utilities to control EE against their own financial interests (as is mostly done today), 2) letting the government do it, 3) changing regulation and utility business model to give them an incentive to implement EE. He notes that none of these are done (enough) today. He thinks utilities can do it best and can find more opportunities for EE if they had an incentive to do so.

Finally, he gets to business models. First he describes the two “triads” (referring to generation, transmission, and distribution) - business models in place today. Then he describes what he thinks will be the two possible models that will dominate the future. The first model of today is the traditional vertically integrated utility that owns generation, transmission, and distribution. This is the integrated regulated public/cooperative structure of 36 states. The second model is the de-integrated, deregulated generation and regulated grid which occurs in 14 states. The FERC regulated transmission is open-access – any company can put energy onto it if there is capacity. Vertically integrated companies have probably been the most economically successful but that was before the advent of the smart grid and the necessity to reduce emissions. After deregulation and de-integration in the U.S. and Europe the percentage of vertically integrated companies dropped but after a while they came back up again with many re-integrating for the economic advantages. Will integration with its economic efficiencies survive the smart grid? Regulation arose due to the belief that power companies were natural monopolies with economies of scale. These days only transmission and distribution are considered natural monopolies. Generation and retailing are not considered so. Competition in generation could lead to cost benefits for consumers. Thus it was generation that was deregulated in the 1990’s. With deregulation the owners of transmission and distribution would be required to utilize the lowest cost generation whether they owned it or not or they would not be allowed even to own generation. Many now say that as generation becomes less centralized and more distributed there will be more benefits to deregulated competition. Theoretically they should work even better with dynamic pricing. Fox-Penner goes into detail comparing these models. Smart-phone controlled home-energy management responding to dynamic price signals will be possible when the smart grid is fully employed and will likely be a major feature of demand response and peak shaving. Such innovations will likely be easier if regulated distributors have less control and there is more deregulated competition. Competition and dynamic pricing are a good match but traditional utilities may be able to manage it as well. 

Now we come to his two (and a half) business models for the future of utilities. First is the Smart Integrator (SI) model which is “a utility that operates a regulated smart grid offering independent power and other services at market prices.” Decoupling sales to profits can remove disincentives. The second model is the Energy Services Utility (ESU), which “is vertically integrated, regulated, and must have strong EE incentives built into its regulatory structure to offset its regulated profit motive.” He notes that these two models are really not much different at all than the models available today – just that sales and profits are decoupled in the SI and efficiency is set as a core mission in the ESU. The other differences are that the ESU may own some or most of its power supply and is regulated and the regulators set prices while in the SI the market sets prices. The half model (of the two and a half) is a Smart Integrator in which distributed generators (DG) are owned mainly by communities rather than mainly by individuals. Mid-scale generation may be owned by individuals, businesses, DG management companies, utilities, or communities. Community energy systems (CES) may become a public power model not unlike municipal power companies owning mid-scale DG and becoming the CES.

The mission of the Smart Integrator is to deliver power with superb reliability and maintain mostly downstream wires and assets – but it does not own or sell the power. The SI will work mainly as a distribution company (distco) controlling the two-way flow of electrons to and from DG in response to prices and so must have an ‘open architecture’ format to let more sources in when needed and turn them off when not needed. The whole two-way system will be managed with software, sending price signals and switching sources on and off in real-time. Hourly spot trading prices will have to be determined, but this mechanism of management can get both expensive and complex. Germany is currently having to deal with this as millions of new DG resources that send and receive energy must be managed. Geographical situations where advantages of local DG providers get too strong may have to be regulated in some way. Determining the value of DG and DR services in avoiding expansion costs is not easy nor is how to reward them for their services. Software and software platform evaluation, costs, and agreement are currently big issues and these problems will have to be worked out. Information management will become more important as more DG is added to systems. Software needs to be queried and analyzed in order to provide decision support. More expertise in IT and regulatory economics will be needed in addition to electrical engineering. Regulated utilities set rates according to ‘cost of service’ or rate of return plus an agreed upon profit. This is the sales component by which rates are set for customers every few years. These fixed costs per kWh set in such a way do not encourage EE. The sales incentive exists even for the SI. ‘Decoupling’ is the current solution to mitigating sales incentives and replacing them with energy savings incentives where the SI or other utility is paid for saving energy. This is a short-term fix, he says. Investors will see it as sales declining which is not what Wall Street likes to see! This is especially the case for companies that own generation. If SIs just deliver power the drop in sales won’t affect their profit. Another issue is who provides customer service – will it be the SI itself in a business-to customer (B2C) or a third party software vender-type provider in a business-to-business (B2B) format?

The Energy Service Utility (ESU) will differ from the SI in two main respects. “The ESU will not necessarily have an incentive to cooperate with local generators who want to connect and sell power into its smart system.” It may view them as competition. Second is the disincentive to help customers reduce their power use due to the ESU’s ownership of generation. These two issues will require regulatory interventions. Letting in local generators, or open-access, and incentivizing such access will require regulation. The only difference here between the SI and the ESU is that the ESU owns generation and other generators would be seen as competitors. Another issue is that utilities often will go to the bare minimum to comply with any EE mandates rather than beyond. EE is considered a public goal and should be pursued as much as possible as such so it needs to be incentivized in such a way as it will indeed be pursued as much as possible rather than bare minimum. If utilities get to keep higher percentages of the value of energy they help their customers save then they will be encouraged to save more – simple as that. This has been successful with PG & E in California. Thus the public goal of saving energy is aligned with the business interests of the utility. Even so, the sales profits from PG & E and others still far outweigh (by nearly 10 times) the efficiency profits. Next he considers Duke Energy’s Jim Rogers’ “Save-a Watt” program where home efficiency improvements would become automatically provided by the utility, the costs avoided by deferring new plants would be part of the utility’s profit, and the heavily-regulated planning and approval cycles would be eliminated. The problem is that regulators were/are averse to ceding control of money allocation and investment to the utilities. Rogers’ plan was seen as too lucrative for the utility. It was approved in four states after some tweaking and lowering the profit a bit. Rogers plan called for the possibility of charging customers not for kWhs but for heat, light, and other units – what he called “value billing.” Utility executive Ralph Izzo calls a similar idea “universal access to energy efficiency.” For an ESU to be able to pitch its ability to investors to paradoxically create more value by selling less energy it will have to be able to sell its energy services in such a way as to out-compete an SI and size and site its investments in new generation and transmission in a more precise way. It will also have to manage effectively the Smart Grid. 

Defining utilities missions as selling energy services rather than energy is not new – Edison first sold light, not power. While Amory Lovins and others promoted selling energy services back in the 1980’s it was impractical then because the services could not be measured. Now with IT technologies, dynamic pricing, and automation we can measure them much better. The idea can be extended to other realms – instead of buying products we can rent them while those we rent from take them back to be recycled. Many products are like this. Software-as-service models are standard in some industries. 

Much of the regulatory hurdles to overcome will revolve around how to measure the benefit of investments, how to allocate system costs, and how to blend markets and regulations. Changes in regulation, the smart grid, more decentralized distributed generation, more demand response provided by distributed generation, more focus on decarbonization, and more regional, state, and grid-to-grid cooperation will be the requirements of the future as smart power arrives in full. He notes that public utility commissions have in the past been unduly criticized for some decisions and that has affected their propensity to innovate and take risks with new technology which may be required in the new environment. The California energy crisis and the perceived failure of deregulation has also had negative effects on experimenting with new models and technology integration. State commissions, he says, need their independence restored, and less government oversight. He advocates for regulator training programs and accreditation for commissioners. They need to be well-educated on current trends and technologies. Basically, the public utility commissions need an upgrade, he says.  Decentralized DG will include more and more community-owned sources, co-operatives, and community municipal utility-owned sources. Their ESU formats will be slightly different than those of IOUs. 

Fox-Penner suggests that the SI and ESU models will likely both occur and if one is revealed as better, then that one will win out but it may also be that both will remain. He calls for better national policy on EE and to better inform state regulatory policies – but other than that no new federal laws are needed. 

In the Afterword he gives four pillars to the new power paradigm: adequacy, reliability, universally affordable service, and rapid decarbonization. These changes will be paid for by customers and financed by investors. There is the grid and the increasingly important “grid edge” which is the decentralized distribution and microgrid technologies that will grow. So far, he says, Germany, California, New York, and Hawaii have been at the forefront of these changes to new models. These changes have not been without problems. Traditional utilities in Germany have been hit with revenue losses and low spot prices. When this has happened the U.S. the utilities have requested higher rates for all customers. While they do see some saving from DG it has not been enough to offset revenue losses. Such revenue losses will cause distribution companies to become Smart Integrators while government and customer-owned power companies have moved toward the Energy Services Utility model. 

This book is essential reading for anyone wanting to understand the dynamic state of the current and future power industry. New developments happen frequently. Battery and other energy storage is now entering the picture more and more, both at home-scale and utility-scale. There are state battles occurring with net metering and feed-in tariff rules. There are new renewables mandates and some that have been scaled back. Gas continues to replace coal. Wind continues to grow. Future nuclear and CCS-endowed coal continued to be uncertain but may happen in the 2020’s. More microgrids, community energy, and dynamic pricing experiments are happening. Regional carbon pricing mechanisms have been established and are functional. EVs are set to take-off in the 2020’s and 2030’s. Efficiency improvements continue at all levels. I enjoyed this one as energy is a big interest of mine.

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