MASTER IN CITY SCIENCES Final Master Thesis
2014/15
Alberto Quintanilla Cabañero
ADVANCED GRID 2.0 INITIATIVES AND THE INTRODUCTION OF DISTRIBUTED ENERGY RESOURCES DISCUSSION OF PRICING PROPOSALS “Clean energy is inherently more local, more distributed, more accountable. While Germany’s big four utilities own the bulk of the fossil and nuclear generating capacity, they own only a small proportion of its renewable energy capacity; the general public owns many gigawatts of the latter either directly or via retail funds. Some may find wind farms ugly, some may find them beautiful; either way, they make us talk about the trade-offs we are making to generate electricity. In the past, there were no discussions about the relative aesthetics of open-cast coal mines and gas fields in far-away countries. Energy efficiency happens in all of our homes and offices. People with solar panels on their roofs look at their utility bills in a completely different way from those that do not. Around the world there is new interest in mutualizing municipal utilities. Even the gas industry, in future, is going to be local, with fracking coming soon to a village near each of us, as it already has in some parts of the U.S” Michael Liebreich, Chairman of the Advisory Board. Bloomberg New Energy Finance
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
ACKNOWLEDGEMENTS I would like to thank Paulina Beato for the effort done overseeing this work, her patience with my lack of knowledge and my stubbornness defending it. Thanks for being so available. Thanks also to Óscar García for all his support and flexibility. I´d like to thank all the lecturers at the Master in City Sciences, and specifically the Area Coordinators, for the extraordinary things they have shared with us. Special apologies to all my colleagues in the Master, who suffered how hard it can be to team up with me. And special thanks to the Master Coordinator, Nacho. Last, I would like to thank Silvia and Eva for being there.
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
CONTENTS Acknowledgements ....................................................................................................................................... 2 Introduction ................................................................................................................................................... 4 Grid Parity ..................................................................................................................................................... 5 Renewable Vs Conventional Energy Sources: Market Trends ................................................................. 5 Analysis of the Levelized Cost of Energy for several technologies .......................................................... 5 Definition of LCOE ................................................................................................................................ 6 Analysis of technologies and scenarios ................................................................................................ 6 Conclusions ........................................................................................................................................... 8 New Paradigms in Distribution ...................................................................................................................... 9 The Grid Edge ........................................................................................................................................... 9 Challenges and opportunities.................................................................................................................. 10 New York “Reforming the Energy Vision� ............................................................................................... 10 California ................................................................................................................................................. 11 Texas DER Integration Model ................................................................................................................. 12 Energy Billing in the Grid Edge: Beyond Net Metering ............................................................................... 13 Objectives of a new Pricing Schema ...................................................................................................... 13 Current tools ............................................................................................................................................ 14 Towards a new schema .......................................................................................................................... 15 ERCOT Light and Heavy DER proposals: analysis of a Utility 2.0 pricing scenario ............................... 15 Background ......................................................................................................................................... 15 DER Light Price Calculation ................................................................................................................ 17 DER Heavy.......................................................................................................................................... 20 Conclusion........................................................................................................................................... 21 Future Research: more sophisticated pricing schemas .............................................................................. 22 Further steps in pricing design ................................................................................................................ 22 Cost-Benefit Analysis .............................................................................................................................. 23 Platform Economies ................................................................................................................................ 23 References .................................................................................................................................................. 24
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
INTRODUCTION The Energy Landscape is evolving together with society. Only a decade ago, fossil fuels and traditional generation were ruling the market, and huge investments in large plants were made all over the world. Now, the generation mix in all countries is moving towards an increase of the renewable energy portfolio. Countries are seeking to declare themselves carbon-neutral, and expensive generation assets such as Combined Cycle Plants are heavy burdens for their owners. In the beginning of 2000s, environmental concerns were behind this trend. But now, with more mature technologies, there are also pure economical drivers. It is widely said that renewable energies are reaching grid parity, the turning point where they get more attractive than conventional technologies in terms of cost. The fact that renewable energy can be connected near where it is consumed (the loads), at the distribution level, and can be done in small, decentralized installations completely changes the game. We are moving from a traditional centralized generation, transmission and distribution scenario to a distributed and decentralized approach where anybody can be a producer: Distributed Generation, Grid Edge or Grid 2.0, with implications at technical, business and regulation levels. Specifically, pricing strategies have to evolve. The electricity business has been based so far on the assumption that the flow of power is always one-way, from generation into the networks and eventually reaching the customers. However, Distributed Generation implies that the energy can flow in both directions. Therefore, a new tariff system must be carried out considering all costs and benefits associated. In order to adapt to this paradigm shift, some institutions are developing initiatives, with the lead of the US Public Administrations, addressing all these aspects in innovative ways, and of course including new pricing schemas. Although New York and California have made the more visible efforts, Texan utility ERCOT´s proposal provides a very feasible pricing strategy based on their already existing infrastructure of nodes where traditional generation is priced. Adapting the market and the pricing structure to the Grid Edge can bring benefits also for the utilities and the society: mechanisms for avoiding or delaying infrastructures are now available. The first part of this paper (Grid Parity) deals with energy costs, overlooking to the current situation of different technologies, focusing on renewable sources. LCOE benchmarking is used to discuss the achievement of Grid Parity. The second part (New Paradigms in Distribution) develops the concept of Grid Edge, its opportunities and challenges, and presents some of the most interesting initiatives impulsed by the US Agencies. The third part (Energy Billing in the Grid Edge: Beyond Net Metering) focus on how the updated pricing strategies in Grid Edge should look like, and uses the case of ERCOT to display advantages, drawbacks and weak points. The last part (Future Research: more sophisticated pricing schemas) points out some unresolved issues and how other initiatives can tackle them, as a means to open new ways for research.
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
GRID PARITY RENEWABLE VS CONVENTIONAL ENERGY SOURCES: MARKET TRENDS Installation of Renewable Energies (REs) has accelerated its expansion across the whole world in the last decade. For instance, the installed photovoltaic capacity has increased 10 times, shaping an $83 Billion industry, and it is expected to double again until 2018.
(Sources: IEA, Bloomberg New Energy Finance (BNEF), European PV Industry Association (EPIA))
In the United States only, 1306 MW of solar photovoltaic power were installed in the first quarter of 2015. This accounts for more than half of the total new electric generation capacity in the period. [1] Historically, this growth has always been driven by the Public Administrations through incentives inspired by environmental reasons, and in fact only 25% of the residential solar installations came online without any kind of state support. This and other long-term strategic concerns (preservation of fossil fuel for exports, energy independence…) are still pulling, but now the market is also an active driver. The term “Grid Parity” is meant to describe the point in time, at which a developing technology will produce electricity for the same cost to ratepayers as traditional technologies. That is, when the new technology can produce electricity for the same cost as the electricity available on a utility’s transmission and distribution grid. [2]
ANALYSIS OF THE LEVELIZED COST OF ENERGY FOR SEVERAL TECHNOLOGIES Is it possible to asseverate that grid parity has been achieved for renewable energies? Of course, this depends on the scenario and probably the answer is negative for a lot of them. But the figures that have been displayed above regarding market penetration are a powerful evidence on that there are also places where this is already happening. In order to provide an educated answer, we can base on one of the standard indicators for the sector: LCOE.
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
DEFINITION OF LCOE The Levelized Cost of Electricity (LCOE) generation is a common benchmarking tool used to compare costs across different energy technologies. Conceptually, it measures the constant (in real terms) price per unit of electricity generated that would equate the net present value of revenue from the plant’s output with the net present value of the cost of production [3]
The numerator measures the net present value of the costs incurred to construct and operate the generation technology. The life span of the technology is L. The discount rate is i. Ct captures the installation and operating costs incurred in time period t. These costs are dominated by the up-front module installation and BOS costs incurred in t = 0. Ongoing operation and maintenance (O&M) costs (including the costs of periodically replacing components) are also incurred over the life of the project. Denominator summarizes the expected energy output in the plant’s life span. When evaluating different capacity expansion options to meet a specific, well characterized need identified by a power producer or regulatory body, LCOE can provide a screening tool that simultaneously considers fixed and variable costs in a single metric.
ANALYSIS OF TECHNOLOGIES AND SCENARIOS Following this methodology, several technologies can be compared in terms of costs per energy unit. Without considering social or environmental externalities, nor other costs associated to reliability, some alternative technologies are in a comparable LCOE range to conventional generation. The following picture lists several technologies with their calculated LCOE across the United States.
(Source of pictures: Lazard).
Specifically, we can focus on Solar PV for the residential market, which looks very competitive already in the range of $180 – 265 per MWh. Of course, there are more aspects to take into consideration, such as the possibilities for universal geographical location, continuity of supply or load following, which cannot be achieved with all energy
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
sources. In particular, another main issue is the dependence of fuel costs. If we consider the latter into the equation, the former graph displays even more advantages for the REs in general.
With the current energy costs, solar energy is in good relative position to other peaking technologies in many geographies. However, solar lacks the dispatching capabilities of these technologies unless storage is introduced.
Global Markets, where fuel costs are higher than in the US, depict an even more favorable situation for solar.
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
If we think of the forecasted evolution of LCOE, prospects look even more optimistic, considering expected evolution of the costs until 2017.
Renewable energy projects are significantly sensible to capital cost (interest rates), reflecting essentially the return on, and of, the capital investment required to build them.
CONCLUSIONS The comparison of RE with conventional sources is positive when considering peaking technologies, but not so when it is base load what we are taking in consideration. Forecasts for 2017 are more optimistic, but it is clear that being able to follow load with REs makes them much more attractive for investors.
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
NEW PARADIGMS IN DISTRIBUTION THE GRID EDGE Qualitatively, there is a key factor in the installation of RE that contrasts with conventional generation: most of the new RE is installed at the distribution level. For instance, in the US, roughly 50% of the photovoltaic new installations were residential and commercial, the other 50% were utility-scale solar farms. [1]
(Source: SEIA.org)
This means a shift in the power distribution market scene from the conventional, centralized organization towards what is called Grid 2.0, or Grid Edge. Grid Edge comprises the technologies, solutions and business models advancing the transition towards a decentralized, distributed and transactive electric grid. When we talk of Grid Edge technologies, we are talking about Distributed Energy Resources (DER), small-scale power generation or storage technologies connected near the users. These technologies include solar (typically rooftop photovoltaic), small wind power systems, microturbines or batteries. But also practices such as Energy Efficiency in buildings and Demand Response, or even the deployment of Electric Vehicles are enclosed under the Grid Edge’s umbrella. Although the term Grid Edge may evoke remote places at the end of the power lines, we have seen there is a strong component of residential and commercial installations. Cities account for most of the electrical consumption and many utility customers are hosting these kind of technologies at their homes or premises in common neighborhoods. Universities and Research Institutions Campus, or Data Centers are typical places where DER systems are built.
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
CHALLENGES AND OPPORTUNITIES The new situation opens lots of opportunities, but it creates also some challenges:
Stabilization and Availability of the energy supply must be addressed in a completely different way in a context with many geographically distributed generation points. New Business Models will appear. For the existing actors, their relative position in the market could change. Opportunities open for new companies disrupting with new innovations, or aggregating existing technology in innovative ways. But the main concern (and the driver to most of the moves) is the adoption of new Pricing Strategies. Most tariff systems have been designed prior to the existence of Distributed Generation. The development of new technologies and practices enables a more granular calculation of the energy costs, so tariffs can be more accurate and consider the bi-directional character of the new system. But there are lots of risks associated to that, ranging from cross-subsidization to grid defection.
NEW YORK “REFORMING THE ENERGY VISION” The State of New York has begun a process to shape the future Distribution grid at a market level and redefine the role of the current actors, called “Reforming the Energy Vision” (REV). The final six goals [4] REV is pursuing are:
Enhanced customer knowledge and tools that will support effective management of their total energy bill Market animation and leverage of ratepayer contributions System-wide efficiency Fuel and resource diversity System reliability and resiliency Reduction of carbon emissions
The REV foundational document is the straw proposal authored by the staff of the Department of Public Service (DPS), which advocates for the following actions:
The development of one (or several) “Distributed System Platform” (DSP) that will be the integrator of distributed generation and other DERs, including energy efficiency, demand response and electric vehicles. The DSP will also provide the interface between the wholesale conventional power system and the retail markets that now include customer load (consumers) but also new sources of supply and energy services. By pursuing a DSP-based market, New York will be the first entity to host the concept of a distribution system operator (DSO), as has been proposed by various forums [5]. The straw proposal describes a DSP as a flexible, competitive platform on which multiple technologies and services can flourish, which will “foster broad market activity that monetizes system and social values, by enabling active customer and third-party engagement.” Together, DSPs and New York utilities (in case they are different entities) will be required to coordinate responsibilities for market operations, grid operations, and integrated system planning that achieves REV policy goals. Transparency and Open Data sharing that allows market participants to compete on a level playing field. To this end, the straw proposal recommends that transparency be a central principle,
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
including the availability of detailed customer data based on which service providers can assess the market and system-level data to identify where network constraints occur and therefore where DER solutions are most valuable. The modification of Utility Net Plant reconciliation mechanisms or "clawbacks". These allow utilities to remove the earnings benefits of capital spending that don´t reach the projected performance, in order to prevent utilities from removing the capital investments that would thus go back to customers. The straw proposal suggests a more efficient use for that money: “At a minimum, utilities should not have a disincentive to use operating resources or third-party assets in lieu of utility capital investment, where the former are more efficient and effective”. [4]
Utilities should hold on to those carrying costs if DERs supplant the capital investment. The goal would be to make the utility "indifferent to whether the utility or a third party funded the DER. An example of this was recently made by Consolidated Edison [6], a utility operating in New York (and therefore, a candidate to play the future DSP role), that deferred a $1 billion investment in infrastructure (a new substation serving Queens and Brooklyn boroughs) and traded it for minor upgrades in existing substation plus some demand-side efficiency measures such as incentives to replace inefficient appliances and air conditioning units, new building management systems, battery systems that can be tapped for hours at a time and even a few microgrids. But the main effort will be in Demand Response programs. A new system for retributing investments. DSP markets will need to send strong price signals for benefits and costs that currently are not monetized. The straw proposal recommends that a full accounting of benefits and costs be applied for major grid investments and utility programs and, where appropriate, in day-to-day operating decisions and price signals. Notably, the straw proposal identifies a set of benefits and costs, including a number of externalities such as carbon emissions that should be assessed. The generation of these signals will push utilities away from the current way of doing business (rate-based assets) toward market-based earnings (MBE). Those earnings will be initially based on new performance incentives, referred to as "earnings impact mechanisms" (EIMs): peak reduction, energy efficiency, customer engagement and information access, affordability and interconnection.
As a result of the implementation of the DSP, DPS staff expects that new business models will appear trying to tackle the above listed REV objectives at all levels of the Energy Market. They fostered the implementation of demonstration projects that can provide technology and business choices beta-testing with a limited group of customers. Demonstrations can also serve to measure and predict customer responses to programs and prices associated with future DSP markets. [7]
CALIFORNIA California is one of the most avant garde states in the creation of regulations and market structures to integrate DERs into its grid. They are launching several simultaneous initiatives led by public agencies.
The California Independent System Operator (CAISO) is creating a new figure, the Distributed Energy Resource Providers (DERPs) [8], and the set of rules for how these new actors can
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
aggregate and dispatch DERs to serve the same grid markets open to utility-scale energy installations today. In particular, CAISO outlined a pricing schema based on pricing nodes, but imposes some technical limitations. DERP sources can be distributed along several pricing nodes [9] (Pnodes) or concentrated in one, but in the first case the total aggregated power cannot exceed 20 MW (no limitation for DERs in a single Pnode). Besides, any DERP serving more than a single Pnode must be limited to a single type of technology. Prospective DERPs will also be limited in how they pull together systems that are scattered across California, by a rule that limits aggregations to a single sub-load aggregation point (sub-LAP). These are the roughly two dozen regions of the state where CAISO has determined that historic congestion patterns tend to lead to price divergences between two parts of a grid. The CAISO proposal also eases up some of the current telemetry requirements for the connected resources. The California Public Utilities Commission (CPUC) has also released a code (AB 327) requiring the electrical corporations operating within its territory (PG&E, SDG&E, SCE) to create Distribution Resources Plan [10] (DRP) proposals. According to the Code, these plan proposals will “identify optimal locations for the deployment of distributed resources.” Each one of these proposals must be reviewed by CPUC, and it may modify any plan as appropriate to minimize overall system costs and maximize ratepayer benefit from investments in distributed resources. The key part of the plans is the Integration Capacity Analysis [11] (ICA) that the CPUC ordered to be included. In practice, the Analysis adopts the form of maps where each utility displays its grid’s capacities to assume generation or consumption. ICAs could become a substitute for the traditional interconnection process, as a kind of grid-wide preliminary study of available interconnection capacity. They should be updated by each utility at least each month (or even better in real time). A major advantage of distributed resources is that they provide many additional distribution grid benefits. The CPUC’s DRP process is already studying the locational benefits of distributed resources. If the grid sees benefits provided by particular resources in particular locations, it would make sense to plug these values into the maps as an appropriate contract value for the technology at issue, above and beyond the value of the generation alone. According to the report of one of the companies participating in the process: “To address the quantification of locational benefits of DERs, the CPUC instructs the utilities to develop a Locational Net Benefits Methodology (“LNBM”) that specifies the net benefits that DERs can provide in a given location” [11]
TEXAS DER INTEGRATION MODEL The Electric Reliability Council of Texas (ERCOT) is considering three key classifications in integrated DERs: DER Minimal, DER Light, and DER Heavy (not mutually exclusive) [12]. All three of the proposals include the ability for DERs to be aggregated into larger blocks of energy. The base for this work was ERCOT’s Aggregate Load Resource (ALR) classification that allows individually metered demandresponse sites to be aggregated for participation in the state’s grid.
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
ERCOT’s new effort isn’t about a completely new market structure, but is about making existing products accessible to substantially more participants.
DER Minimal is basically Net Meteringa though with some improvements in current rules. In terms of how much resources would get paid for that aggregated energy, what they can earn is based on the Load Zone Settlement Point price (an average price for whichever of the state’s four “load zones” the DER happens to be sited). These load zones cover broad parts of the state’s west, north, and south regions, as well as the Houston area. While certain locations within each zone might experience high prices during different times of the day, based on transmission and distribution constraints that make it more costly to serve load in that location, there’s no mechanism today for linking DER payments to these locational marginal pricing (LMP) nodes. DER Light would take the important step of allowing aggregated DERs to get paid the locational marginal price for the energy they export to the grid. That could be either higher or lower than the average zone price, but it has the virtue of more closely tying the value of the electricity the DERs are generating to its value for the local grid, at the time it’s being generated. DER Heavy brings another layer of potential revenue streams to aggregated DERs, by allowing them to play into ERCOT’s energy and ancillary services. These offer more lucrative payments for resources that can respond to signals from ERCOT to supply or absorb power to balance fastchanging grid conditions, and would require the same kind of real-time communications links and metering that ERCOT requires of the big power plants or cogeneration facilities that serve these needs today.
ENERGY BILLING IN THE GRID EDGE: BEYOND NET METERING The paradigm shift of power distribution means that besides the grid offer of services to customers, now also customers can offer services to the network. The unidirectional tariff system must be reformulated. According to the Electricity Innovation Lab (e-Lab) in its recommendations for rate development: “There is a looming disconnect between the rapidly evolving new world of distributed energy technologies and the old world of electricity pricing, where relatively little has changed since the early 20th century. By changing electricity pricing to more fully reflect the benefits and costs of electricity services exchanged between customers and the grid, utilities and regulators can unleash new waves of innovation in distributed energy resource investment that will help to reduce costs while maintaining or increasing system resilience and reliability.” [13]
OBJECTIVES OF A NEW PRICING SCHEMA It has been forecasted that DERs (solar plus storage) will outcompete grid power in the coming years [14], bringing urgently to the table the issue of accurately pricing energy and associated services. The future pricing strategies should fulfill the following objectives:
a
See next section for a definition of Net Metering
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
Currently, grid costs include the cost of capital investments required for building the distribution lines and substations, the generation resources sized enough to provide 100% availability, stability and quality of supply, and the operation and maintenance costs (these include fuel costs if applicable). In principle, if we are attaching to the grid new users with capability to inject in the grid or at least consume less due to DERs, our pricing strategy should be capable of covering the incremental costs of upgrading the grid infrastructure if this is required to maintain service quality.b Avoid grid defection by consumers, in order to ensure viability and equity. If early adopters find more economic unattaching themselves from the grid with autonomous renewable generators and batteries, fixed costs must be shared among the fewer users who stay, increasing their bills and cancelling the increasing returns. Less privileged ones won´t be able eventually to stay connected, feeding a spiral of death with increasing prices for the decreasing amount of users and ending up in the non-viability of the grid system. But at the same time, the introduction of cleaner technologies and practices that improve the natural environment and the viability of a more sustainable economic model in the mid or long term must be stimulated, or at least, not discouraged.
CURRENT TOOLS There are currently several methods the utilities are using for DER pricing as add-ons to the conventional pricing, independently or in combinations, in different scenarios:
Incentives, feed-in tariffs: Utilities are forced to buy energy from specific sources at fixed rates, usually designed by the regulator, and usually with an incentive to the seller provided by the Public Administration. The goal of such incentives is the development of a local industrial sector, the fulfillment of some objectives related to energetic independence or a more sustainable energy mix and/or pollutant emissions. Tolls / fees: Some countries are applying taxes to the generation at consumer level in order to compensate Infrastructure Resources made available to DERs that cannot be charged as a proportional component of user's consumption (as the producer/consumer has an alternative to this consumption). Net Metering: Energy consumed by a producer/consumer is added to the Meter reading, and Energy produced is subtracted, so the final charge is the balance of both amounts. This is the most popular approach for utilities that are currently accepting DERs in their grid, and is the main claim of the DER sector stakeholders where they are not.
However, there are several issues related to these practices, and the correct pricing signals are not reaching the customers:
b
In some countries feed-in tariffs have proved self-defeating, driving to an unbalanced growth of the installation renewable energy, careless of their integration to the grid and the consequences in its stability [15]. In some cases, incentives have been a posteriori cancelled inflicting serious damage to investors [16]. The application of fees to DER avoiding consumption, if not applied carefully, can push users to grid defection when it is more advantageous for them to install some extra power (and possibly
It will be later discussed how the introduction of DERs and the modernization of the pricing schemas can make these upgrades unnecessary or at least delay them.
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
storage) and be self-sufficient in an isolated Microgrid than to pay the fee just for the little energy they are not able to produce. Net Metering, although widely extended, has a huge drawback for the DSO: it is ignoring the different energy costs across the different times of the day. A user could consume energy at peak slots and inject at valley time when the demand is lower, only paying for the balance with no penalization.
TOWARDS A NEW SCHEMA The initiatives that have been already introduced in the previous section include some proposals that can help create a new framework for energy pricing, more adequate for the integration of DERs. It has been displayed how DER can cause the grid defection of some users and begin a spiral of death for the electricity grid. Partly, this is because these users do not perceive that the costs they are being charged for (e.g. conventional generation resources) are providing them with any service. In the current Industry´s approach, high capital investments are required for the grid upgrades needed to supply new users. However, as shown by previous experiences [6], it should be possible to minimize the incremental cost of infrastructure, or even transfer this cost to the DER owners with an adequate policy. These way, incremental costs of providing grid services to users are limited and their perception is not so negative. In the other hand, we have seen how Net Metering is attractive to DER promoters and owners, but not that much for utilities. More sophisticated approaches can be used though that can satisfy both sides. By valuating the energy at each point and time, DER owners can be paid/charged for their production/consumption according to the real cost/benefit the utility has. In fact, e-Lab [13] advises to increase rate complexity for mass consumers along 3 continuums:
Attribute unbundling (what): shifting from fully bundled pricing to rate structures that break apart energy, capacity, ancillary services, and other components Temporal granularity (when): shifting from basic or inclining block rates to pricing structures that honor the time-based aspects of electricity generation and consumption (e.g., peak vs. off-peak, hourly pricing) Locational granularity (where): shifting from pricing that more or less treats all customers within a distribution network equally to one that recognizes that their location within the system impacts the cost of delivering electricity to them and the value their DERs can provide
ERCOT LIGHT AND HEAVY DER PROPOSALS: ANALYSIS OF A UTILITY 2.0 PRICING SCENARIO BACKGROUND ERCOT provides the flow of electric power to more than 24 million customers covering about 75 % of Texas’s territory and about 90 percent of its load. ERCOT’s grid is distinct from the other two major U.S. grids (the Western Interconnect and Eastern Interconnect), thus it is not bound by the Federal Energy Regulatory Commission (FERC) jurisdiction and its market rule-making process is the most flexible in the nation. If something improves electric reliability and market operations, it likely can be done here.
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
ERCOT features complete retail competition for most of its area of influence, including around the state’s two largest cities, Houston and Dallas. These Metro areas, and the next two largest San Antonio and Austin have different market organizations, ranging from Cooperatives to Municipal Monopolies. Nevertheless, Texas remains a fertile market environment for DERs. ERCOT’s wholesale open access power portfolio features about six basic products:
Day ahead Real-time Regulation (immediate responding resources: energy production up or reduction down) Responsive (or “spinning”) reserve (fast, but slower than regulation) Non-spin (slowest, but still relatively quick, responding balancing power) Emergency Response Service
ERCOT determines energy pricing at ca. 10,000 nodes called locational marginal pricing points (LMPs), with participants settled at about 900 settlement points based on nearby LMP averages. The real time prices across the whole network is public through ERCOT’s platform (Figure B ERCOT’s LMP Contour Map). Competitive retail service providers pay ERCOT prices based on four different load zone prices (West, South, North, and Houston), and there are four other load zone prices, including for Austin Energy, Pedernales Electric Cooperative (via the Lower Colorado River Authority), and CPS in San Antonio.
Figure A Texas Load Zones (source: TexasHomeElectricity.com)
So, the comparison between the ca. 900 settlement points viable for generators, but just 8 points available for pricing to most loads makes the geographic pricing range of decision for DER promoters or just normal users less competitive. Yet there’s an opportunity present in those ~900 settlement points. e-Lab’s Rate Design for the Distribution Edge advocated locational granularity (i.e., geographic variability) as one of three vectors for increasing rate sophistication [13] to promote more optimal grid deployment of DERs. ERCOT’s new rules may begin to rebalance this situation, yielding greater geographic pricing options for DERs.
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
As already discussed, ERCOT has proposed three participation types, of which one or more would be selected upon registration: 1. DER Minimal 2. DER Light 3. DER Heavy Nothing will be added to DER Minimal as it is very similar to conventional Net Metering, we will be focusing in DER Light.
DER LIGHT PRICE CALCULATION DER Light’s registered users can participate of the ERCOT’s Day-ahead / Real-time Energy delivery and Emergency Response programs.
(source: Rocky Mountains Institute)
Locational Marginal Pricing Points’ price for retailers is determined in real time based on the marginal cost of delivering a kWh at that point, in a nodal pricing schema. At a given LMP the energy cost will be: Cost = Fixed costs + Variable costs Cost = Fixed costs + + Generation Costs ($/kWh) * kWh * (1 + Losses (kWh/km) * km) Cost = Generation Fixed Costs (investment) + + Distribution Fixed Costs (investment in grid + stability/availability) + + Generation Costs ($/kWh) * kWh * (1 + Losses (kWh/km) * km)
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
Therefore, we can infer that the costs will increase, for a conventional scenario, with distance between the generation source delivering the power and the LMP. It is actually a little bit more complicated than this, as the solution of the nodal network is far more complex and depending also from other factors such as congestion in the lines. DERs typically provide power locally and avoid distribution losses. Thus, 1 kWh of energy generated at the customer’s location would reduce the total generation as measured by the system operator by more than 1 kWh. However, in some situations, such as very high penetration levels where solar production is considerably greater than the original load, the reverse flow of power generated could even result in increased losses [17].
Figure B ERCOT’s LMP Contour Map (source: GreenTechMedia.com)
In the contrary DER cost, for a rooftop solar owner for instance, has no variable component. For simplicity, we will consider the fixed cost is the LCOE determined for the installation when built. Cost = Generation Fixed Costs (investment) = LCOE
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
Considering a very simple scenario, with a conventional source and a single distribution line with several LMPs.
The marginal cost for conventional generation will increase with distance, reaching a point where it will be above the LCOE of the rooftop solar. This is indifferent for DER Minimal users, as the energy they inject is effectively priced at a fixed rate, but it is then when it begins being more convenient for DER Light registered customers to offer energy, instead of keep ERCOT buying from the conventional generation. The DER owner is paid a surplus over his LCOE (therefore effectively reducing it) and ERCOT is paying less than the conventional generation variable costs. Of course, as we said, this situation is variable with time, resulting in hours when some DERs will have advantage injecting energy into the grid and others won´t. In any case, if they are getting paid enough, this results in an effective reduction of LCOE that makes the attachment to the grid very attractive.
Cost per kWh delivered
DER (LCOE)
Conventional at LMP2
Conventional at LMP3
Theoretically, a point would be reached where the marginal cost is so high that it is more convenient for ERCOT to invest in new infrastructure (another generation source) to avoid increasing transmission losses, instead of keep paying DER Light customers. We will later discuss if this is really a turning point for investments decisions, or they can be further delayed.
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
In our example, a new generation plant similar to the one in LMP1 is built by a Generation company and connected to ERCOT grid in LMP3.
The maximum cost of energy would be at the middle of the line (LMP2). Although the variable costs remain the same, the Generation fixed costs have doubled. Marginal price of the energy at LMP2 is the same as it was before, but to a DER owner it becomes now much more attractive to stay out of the grid, because although the marginal component of the price of energy might be under his LCOE, the fixed costs have increased and the area price will increase (we have to keep in mind that the energy they need to buy to cover its load is at fixed rates).
Cost per kWh delivered
DER (LCOE)
Conventional at LMP2, 1 plant
Conventional at LMP2, 2 plants
DER HEAVY Of course, the difference between the prices for the different services (or products) delivered by ERCOT and cited above is given by the Generation costs, as it is not the same the variable cost for base generation (e.g. nuclear, with low variable costs) than quick response such as diesel or gas. DER Light registered users are supposed to opt-in only to participate of the more basic services. But, with a higher investment in the more advanced metering and communication infrastructure required by ERCOT,
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
it is possible to accept DER Heavy proposals and enter the Regulation, Spinning and Non-Spinning reserve markets.
(source: Rocky Mountains Institute)
The economics are similar, but prices (and investments) are higher. However, DERs have a great advantage over conventional plants performing regulation and ancillary services, and it is the ability to aggregate DER points. This could open even more potential for solar-plus-storage systems, which can “bank” their power to inject it into the grid when grid prices spike.
CONCLUSION Does it makes sense to invest in DER payments beyond the point where marginal costs could be minimized by infrastructure?
As seen, it increases involvement of the DER owners with the grid by sending the appropriate price signals. Staying attached to the grid becomes attractive for DER owners as they get payments according to their contribution to the service in the area. Besides, it increases welfare as Capital investments in infrastructure by ERCOT will be traded-off for the variable costs of buying energy from DERs. Risk in huge, one-time investments is minimized, transferred to DER owners, and shared among small upgrades of capacity. The utility would be paying according to the Local Marginal Price (plus an incentive based on the infrastructure savings), so they are never paying more than they would if they had to buy the energy in the conventional energy markets.
Of course, this model requires transparency in the Local Marginal Price calculation, so a commonly accepted way of calculating locational net benefits should be used, based in the fixed and variable costs of transport and distribution.
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
Users (both consumers and producers) need to have access to a platform with the most accurate information about prices and know when and where it is more valuable to export energy into the grid. It is clear that the 10,000 LMPs infrastructure created by ERCOT and published in their LMP Contour Map fulfills these needs for adequate information. In the other hand, DER new market participants have to increase their investments in the telemetry and metering technology required by ERCOT to have real-time access to their measures and to quickly respond to bid processes (in DER Heavy). “There are resources being installed in the commercial and industrial world, largely for doing demand charge management,” or limiting expensive spikes in on-site electricity demand. “That can be a compelling value stream to get some storage, or micro-turbines, or similar energy management systems, in place in a commercial facility.” [12] In the future, “if that same asset could have an easy path to participating in the wholesale market, then you could bring in additional revenue, which could make installing that resource much more compelling.” [12]
FUTURE RESEARCH: MORE SOPHISTICATED PRICING SCHEMAS FURTHER STEPS IN PRICING DESIGN As we have noted, the application of ERCOT’s DER Light and Heavy proposals are important steps towards the new Grid 2.0. Nevertheless, there are still several aspects where a lot can be developed. Concerning rates, LMP-based pricing is in line with e-Lab’s rate development recommendations in terms of time and location granularity. The split between the different products available to DER aggregators and owners also provides some attribute or service unbundling. However, this granularity is only on the energy purchase side, assessing the price the utility is paying for DER production, but its benefit for customers is geographically dissolved in the 8 load zones prices. For DER owners, this means Net Metering has improved but not reached a perfect Net Value Metering schema, as the price of imported energy is still only slightly linked to its real cost. Moreover, the mechanism for price setting, although transparent, does not implement the benefits of an open market and is dominated by the utility. Prices have no connection with supply-side changes in DERs, and only indirectly with demand. Although this is not negative per se, has some drawbacks for customers and DER owners in this particular situation:
In principle, prices are controlled only by a part of the supply, the conventional sources the utility is using to determine costs at LMPs. Customers would not benefit from the price reduction caused by the increase in generation choices. Demand can raise prices by congestion in conventional generation sources and lines, but this would not affect the capacity of local DERs to supply energy, thus the price increase would not be real. This would happen because in DER Light prices are not fixed by an offer-bid process, and it is the utility who is setting them.
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
Thus a second stage of ERCOT offers should include:
LMP prices calculation taking also into account the available DER. Transferring price granularity to the end customers. It would send them powerful price signals, but is a little bit more challenging as it might cause trouble with users at one LMP would paying different than those connected to the next one.
Before any implementation, impacts on the market behavior should be investigated.
COST-BENEFIT ANALYSIS If Net Metering policies are eventually to be abandoned, DER owners and promoters need means to assess the locational opportunity of their investments. California’s ICA mechanism is a very valuable tool in order to be informed about competition and the potentiality of the investment. They establish a cap to a certain kind of DER technology the grid can assume at a given point. Increasing the presence of Solar Energy, for instance, should update the ICA in the area reducing the grid´s capacity for Solar and increasing proportionally the need for DR or storage, or any other means to compensate the generation curve. Investors can be aware of the size of the current and future market in a given area (consumers) and the presence of the different DER technologies serving it. They can thus make forecasts of the likely ranges of energy service cost and plan the return of their investment. By introducing DERs in the grid, we have highlighted that utilities can get benefits in terms of delays in infrastructure building, or even their complete avoidance, while minimizing the risks. For welfare maximization, these benefits should by no means impose service degradation and if possible, they should be shared with customers. NY REV Proposal sketches that these trade-offs could be assessed using EIMs for retribution of the benefits provided by DERs, but does not go deeper on how to price them.
PLATFORM ECONOMIES DER Light and DER Heavy provide, as above said, some split in products with different price ranges. But it does not fully cover the complexity of Energy Services outside the pure energy delivery required for safe electric power. Traditionally these services were offered by the Utilities as well, but in a Grid Edge context they can also be provided by DERs or other companies. The way how these complementary services can be aggregated, offered to customers and priced is not clear. Distributed System Platforms, as envisioned by NY REV, could be the answer, but its model is still under construction and defines a very interesting field of study.
Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
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Advanced Grid 2.0 Initiatives and the Introduction of Distributed Energy Resources Discussion of Pricing Proposals
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