Economics#
Key Message - Economics
Interoperability is key to the economics of the future grid. The traditional means of ratemaking and cost recovery are under strain as growth in distributed energy resources and changing customer capabilities alter traditional economic dependencies. Reducing information asymmetry through interoperability helps ensure the technical and economic benefits from grid modernization flow across smart grid participants and accrue to all stakeholder classes. Interoperability is therefore a critical enabler of customer empowerment and value creation. Interoperability can minimize transaction costs and entry barriers to market participation, thereby facilitating the creation of new participatory and economic opportunities across >the system and enabling customer choice as they seek to integrate their equipment into the system’s value network. Interoperability reduces limitations caused by asset specificity, and in this way >facilitates combinatorial innovation and value stacking which can improve stakeholder value propositions across the sector.
The electric grid exists to serve the energy needs of a dynamic economy. The growth of the sector over the last century and the success of its stakeholders in realizing improvements while operating continuously are evidence of the system’s efficacy. Electrons are incredibly high-quality energy carriers that can be used for any application.
The challenges confronting the electric grid are manifold. With new problems comes the inevitable call for new problem-solving capacity. This combination of challenges and solutions adds complexity to the power system discussed throughout this Framework.
Acknowledging that “every increase in complexity has a cost” [ Tainter J, Allen T, Hoekstra TW (2006) Energy transformations and post-normal science. Energy 31:44-58. ], this chapter presents a discussion of the central role for interoperability in ameliorating such costs and adding new value to the system. Through improving interoperability, the core mission of serving the energy needs of a diverse and dynamic set of customers will be ever-more achievable.
Economics of the Conventional Utility#
The electric industry in the United States is both highly diverse and highly fragmented. It consists of a mix of entities, ranging from heavily-regulated utilities whose profitability and system investments are determined through public hearings and dockets with utility commissions, to those which operate competitively in deregulated markets. Utilities include investor-owned utilities, quasi-governmental entities, municipalities, and cooperatives. In total there are more than 3,000 utilities spread across the 50 states. Some are regulated by state or federal regulatory commissions. Others are overseen by government entities, or in the case of cooperatives managed as not-for-profit entities for their members by their governing boards. In addition to utilities, there are numerous companies that participate in the competitive generation sector, either as their core business or, in the case of co-generators, as a byproduct of their core business activities. The emergence of DERs which may be owned by utilities, competitive or collective entities, or individuals—and also the incorporation of demand response resources into conventional energy markets—complicates the supply-side economics. Finally, there are competitive electric service providers that serve as intermediaries between customers and markets, providing energy services to customers or as aggregators of loads and/or services to markets.
The function of any given utility typically includes three services: generation, transmission, and distribution. In states that have restructured, the investor-owned utility has sold off its generation assets to a third-party owner, and the transmission system is operated by a Regional Transmission Operator (RTO) or Independent System Operator (ISO). Additionally, those states may also allow customers to choose a competitive supplier to provide their electricity needs, which leaves the monopoly as the “poles and wires” company responsible for distributing the electricity to end use customers.
In other states, vertically integrated utilities, which own generation, transmission, and distribution assets, operate as regulated monopoly providers of electricity to end-use customers. Some vertically integrated utilities are in organized wholesale markets, operated by an ISO or RTO, and others operate in less structured markets.
Utility costs are typically differentiated between capital and operating and maintenance (O&M) costs. In general, capital costs earn a higher return on equity (ROE) than O&M costs. The ROE is set by the regulator during the rate case or during a separate cost of capital proceeding. Examples of capital costs include construction of new infrastructure, like a power plant, transmission line, or substation. Examples of O&M costs include maintenance costs for power lines, operational efficiencies, or utilization of software as a service or cloud-based services.
Due to this structure, utilities earn more profit via capital projects than O&M projects, which impacts utility investment strategies. This becomes important when consideringinteroperability, as it may be competing against a capital project which earns a higher ROE.
Costs are also treated as either long-term and variable, or short-term and fixed. Costs that are treated as variable are recovered through the variable component of the rate and recovered through volumetric charges. Treating certain costs as fixed allows the utility to have greater certainty in recovery of those costs, as the regulator considers costs associated with those investments as necessary for service provision. This has a significant impact on the rate design and bills as a high fixed charge, while providing the utility greater certainty on the recovery of its authorized revenue requirement. This means fewer costs are recovered in the variable rate. When variable rate cost recovery diminishes per this relationship, the price signal to customers is muted and limits the ability of the customer to invest in technologies to lower their bills.
Review of utility costs is traditionally based on least cost ratemaking. This means that the utility is to spend the least amount of money needed to provide safe and reliable electricity service, plus a rate of return (i.e., profit). As the utility industry grew, the ability of the utility to scale large assets was a preferred means of meeting utility service obligations, and so large capital investments were regularly considered least-cost.
Additionally, the early models of utility economics focused on the societal goods of expanding access and increasing electricity use. This meant that, by expanding the rate base, utilities could recover their costs across more kilowatt hours and provide sufficient electricity to an expanding set of customers.
Evolution of the Distribution Utility#
The electricity network exists to provide customers with access to electricity to power their lives and industry. As described in the Chapter Operations, the integration of modern technologies and resources means the electricity system is embarking on a substantial evolution towards a two-way delivery system with the capability of relying on local resources to meet system needs. This will result in the distribution utility taking on additional roles that it has not fulfilled in the past, including more detailed modeling of the distribution system, customer demand, and optimization and utilization of resources located either at the customer site or close thereto.
Distribution utility operations are changing with increasing DER adoption. Whereas in the past the distribution system delivered electricity to end use customers, the distribution grid must now be organized and operated to handle two-way electricity flows. The emerging power flow complexity hints at an underlying transition in domain function and actor role. Where distribution utilities were built to service customers who were purely consumers of electricity, utilities may now be the recipients of services provided by customers, or even the facilitator of the exchange of services between customers.
Just as two-way electricity flows complicate system operations, system economics become similarly more challenging. Where utility cost recovery has historically been manageable through simple tariff structures consisting of energy and demand charges (see Appendix E - Cost Recovery, Rate Design, and Regulation), the economics of cost recovery will have to change as technology allows customers to self-supply energy or locally develop and exchange services.
Evidence has also emerged in recent years of an ongoing disruption of the historic linkage between energy consumption and economic growth. Although absolute electricity consumption continues to rise across the country (see Figure 1 below), the decoupling of economic and societal outputs from energy consumption has yielded a flattening (and even a decline) of per-capita electricity consumption across the country.
There are many ways to describe the future organizational and operational structures of the electric utility, but a commonly used term is that of the distribution system operator (DSO). No single business model or market function is implied through our use of the DSO term. Yet as has been described throughout this Framework, the DSO must provide some additional capabilities which allow the system to utilize and optimize resources other than those owned by monopoly utilities in servicing customers and other market participants. This, in turn, impacts the utility business model.
As the utility business model evolves, so too must the mechanisms by which utilities recover costs. One approach is to move to a performance-based ratemaking scheme. This type of regime provides utilities with additional revenue for achieving certain performance metrics, such as enhanced reliability, faster integration of DERs, or customer satisfaction rates. This type of cost-recovery is intended to offset the capital bias inherent in cost-of-service ratemaking (see Appendix E - Cost Recovery, Rate Design, and Regulation).
With expanding distribution utility functionality, modernizing business models, and DER proliferation, the mechanisms used to ensure optimal deployment of grid resources can be expected to change.
For example, in California the distribution resource planning process includes analyses, by line segment, of the hosting capacity as well as the value of DER on the grid at that location. Distributed resources, including demand response and non-wires alternatives, can therefore be sited in specific locations where it can be expected to provide greater optimization of the grid as a whole. More broadly, through incorporation of economic signals linked to spatial, temporal, and topological optimization constraints, incentives will exist to locate and utilize DER where it provides the greatest value to the grid — including to customers.
Developing economic mechanisms to optimize DER deployment and utilization will likely increase overall asset utilization, and create a virtuous cycle where legacy infrastructure can be maintained for a longer service life. For example, deployment of demand response and/or energy storage resources may prove to be a more economical solution to alleviate an overcapacity constraint on a feeder or substation — as opposed to a more traditional approach of rebuilding infrastructure to increase capacity. These non-wires alternatives are regularly employed as alternatives to distribution system construction investments.
Placing resources closer to the load they serve can additionally be expected to reduce overall cost and physical energy losses of delivering energy to customers.
Identifying locational net values for DER, including possible development of locational marginal pricing and distribution-level energy markets for energy and other grid supporting services, can be expected to effectively flatten the load, increase the utilization of existing assets, and broaden the participation in energy market or optimization services. Participation would expand directly through individual DER ownership, and indirectly with the participation of aggregators and energy service providers. The same distribution-level incentive can help ensure all market participants are equitably compensated for the energy and services they provide. This is an especially important consideration as customers are presented with an ever-increasing range of energy investments that offer the potential for economic value previously unavailable to them and independent of the local utility.
A discussion of some specific utility organizational and operational structures is found in Appendix F - Distribution Platforms and Markets.
Factors Affecting — and Benefits From — Interoperability#
The electric power sector stands on the precipice of a period of great “combinatorial innovation” just as expectations of and within the industry are changing rapidly. Increasing technical and organizational modularity within the sector have opened opportunities for innovation by incumbents and new entrants. Recent developments are consistent with past historical experiences in which a “set of technologies comes along that offers a rich set of components that can be combined and recombined to create new products”. Modular and distributed energy resources, coupled with entrepreneurial capabilities and encouraged by an awakening customer base, promise to remake the structure of electricity markets and value creation.
The current influx of information and communications technology (ICT) to the electric grid has brought with it organizational perspectives and processes for the accelerated development and deployment of new technologies. Other sectors extensively impacted by ICT exhibit rapid rates of technological adoption, one of the major drivers of which has been a relaxing of the requirement for detailed modeling and analysis prior to technology adoption. While electric utilities cannot forgo the economic analysis to justify equipment expenditures or the detailed examination of operational models prior to technology adoption, customers accustomed to the ICT-enabled conveniences of digital service offerings available in other sectors have formed new expectations about the electric services they consume.
Electric utilities face significant uncertainty with respect to their future operating environment. Managers (and regulators) are therefore concerned with the pursuit of no-regrets moves that will pay off regardless of how the uncertainty is ultimately resolved. Cost-cutting initiatives are prototypical examples of such regret-free strategies. One important source of uncertainty in the electric power sector has to do with the cost of integrating new technology with the legacy grid and ensuring interoperability.
Uncertainty over integration costs may provide an impetus for investment in smart grid research, development, and deployment activities as firms seek to uncover actual cost structures through exploratory efforts. However, a lack of consensus regarding which standards are most important for interoperability—or even how to select requirements to achieve interoperability through existing standards may constrain the set of no-regrets moves and constitute a barrier to investment in distributed energy resources and other emerging technologies. In the near term, as system integration is pursued in an ad hoc manner, a high-degree of solution specificity is to be expected.
The complexity of the electric power sector value chain is increasing with the proliferation of specific solution implementations for a range of new operational challenges, especially DER and customer-owned asset integration. Asset specificity often results from efforts to meet technical or regulatory requirements and meaningfully contribute to the value chain. Increasing specificity leads directly to rising transaction costs as the technology stack supporting transactions becomes more diverse and complicated to maintain. Specificity may then act as a barrier to more extensive utilization of devices and systems.
Interoperability offers a strategy set through which to reduce “specificity barriers” and engender an environment conducive to combinatorial innovation by all stakeholders. Highly specific solutions to electric grid challenges are present on both the demand and supply sides of electricity markets. Consequently, interoperability strategies can improve stakeholder value propositions across the sector.
On the demand side of electricity economics, interoperability is crucial to customer empowerment. A variety of concerns affect customer opportunity in the legacy grid, among which interoperability can help address:
- Information asymmetry: Enhancements to interoperability should reduce informational imperfections that can afflict electricity markets and manifest as pricing conditions that traditionally favor producers—who are likely to enjoy an informational advantage—over consumers. Interoperability enhancements should reduce information asymmetry and better inform customers about their own electricity-use decisions and technological investments. This in turn should allow for improved economic return on these actions and likely improve technology adoption outcomes.
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Value stacking: Customer assets that often sit idle due to lack of outside options for application could be matched with new opportunities as interoperability increases and barriers to providing grid services fall. Capacity utilization and thus the value proposition of economically efficient customer assets55 will generally increase with the level of interoperability that exists between those assets and the rest of the electric grid.
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Customer choice: Interoperability improvements can reduce barriers to entry and transaction costs paid by customers as they seek to integrate their equipment into the sector’s value network. Absent an environment that allows universal access to the full range of opportunities, customers may be required to select devices and systems for feasibility of integration rather than the operational or economic value propositions they offer.
Complexity and cost structures
The electric power sector is confronting a complexity problem. Operational fragmentation and increasing specificity of assets means the process of producing and delivering electricity to customers has more — and more varied — stakeholders than ever. Regulatory status varies across the value chain, and coordinating value-adding activities in a manner that is consistent with customer expectations and regulatory requirements is costly. In many cases, it simply costs too much to make the fragments of the grid interoperate effectively. This lack of interoperability is the primary barrier of consequence to realizing the potential for combinatorial innovation in the electric power sector.
Interoperability investments will reduce, though not eliminate, some barriers to sectoral entry. Though some incumbents may be slow to embrace interoperability, support for greater standardization in pursuit of lower interoperating (transaction) costs is expected as the benefits become manifest.
As interoperability improves and entry barriers are reduced, more participants are likely to enter the sector, which may bring additional capital investment resources to the electric grid. This is especially important as investment requirements for the grid are expected to rise substantially in the coming decades [110]. Interoperability improvements may therefore relax two important binding constraints on the electric grid: the constraint on capital available for investment, and the feasible set of investment opportunities for smart grid assets.
Trust and assurance
Realizing an interoperable grid to enable growth in valuable services requires surmounting numerous challenges. Stakeholders must be able to trust that the electric grid on which modern society is built will continue to be reliable; such trust can be built on assurance. One working definition of assurance is “our estimate of the likelihood that a system will fail in a particular way”, which falls within the CPS trustworthiness concerns of reliability and resilience described in Mapping CPS Aspects and Concerns to the Electrical Grid.
Previous trustworthiness discussions in this Framework focused on the effects operational trustworthiness would have on informational—and thus interoperability—requirements. Here, trust and assurance are examined from the perspective of the risk that components or systems will not be able to interoperate. Assurances that reduce the expected costs of integration improve the value proposition of investment options, encouraging more rapid and extensive technological adoption.
The interoperability assurances needed to accelerate adoption of smart grid technologies vary with the specific technology considered and the stakeholders in whom trust must be cultivated. There will always be costs associated with obtaining this assurance, although systematic approaches to achieving desirable assurances will prove more cost effective than ad hoc alternatives. The gap between these approaches will likely widen over time as interoperability strategies mature and evaluative organizations learn by doing.
Some might worry that movement towards standards will diminish product and service differentiation or limit innovation. Yet vendors can in fact differentiate their products and earn increased markups over marginal costs on products for which they can supply the necessary interoperability assurances to address their customers integration challenges. Implementers might willingly trade ballooning integration cost structures for set testing and certification costs.
Integration costs place an upper bound on an organizations’ willingness to pay for the testing and certification programs designed to obviate implementation barriers. Electric sector organizations can choose to opt in to employing assurance mechanisms that demonstrably reduce integration costs relative to in-house approaches. As the cost of systems integration rises with complexity, the opportunity for assurance mechanisms to create value will improve.
Testing and certification
Stakeholders across the electric power sector can generally agree that greater assurances with respect to equipment and system performance are needed, yet it is unclear how to share the burden — and benefits — of overcoming interoperability challenges. Testing and certification programs can reduce barriers to interoperability. Identifying and mitigating the barriers to these efforts is a necessary step towards achieving this goal.
The fixed costs associated with developing a testing and certification program can be considerable. Markets for specific testing and certification services must be sufficiently large to induce entry by testing and certification organizations. However, the electric power sector’s high levels of specificity and complexity have yielded a large enough number of interoperability relevant standards that the certification market for each is relatively thin. Thus, developing testing and certification programs remains relatively unlikely.
Two approaches to increasing the availability of testing and certification services include reducing complexity of implementation and diminishing the barriers to entry. The development of interoperability profiles can help accelerate development of the testing and certification programs through reducing implementation complexity. An interoperability profile can define a subset of a given standard or set of standards on which stakeholders have agreed to focus their efforts. The crucial tradeoff in this approach is one that reduces degrees of freedom in implementation for decreased integration cost.
Another approach to increasing the availability of testing and certification programs is to develop affordable tools such as test harnesses60 that can be employed by stakeholders to troubleshoot common implementation problems. This can free testing and certification organizations to focus their efforts on the most vexing system integration problems facing the sector.
Economics and Challenges of Certification Institutions#
Achieving high levels of interoperability can be very costly. That interoperability is difficult to quantify does not mean it is unachievable, but rather calls for advances in the sector’s measurement capabilities. And while interoperability can be hard to measure directly, the concepts of increasing transaction and integration costs are far more tangible. A low level of interoperability is prevalent in the market for smart grid solutions in part because utilities and other implementing stakeholders have a limited ability to discern between high and low interoperability options before they undertake systems integration efforts. This means that vendors are incompletely compensated for engaging in costly efforts that could improve the interoperability of their products.
While smart grid investments are demonstrably capable of providing operational benefits to electric grid stakeholders, uncertainty and costly systems integration efforts are dissipating an unacceptable portion of the potential gains. Testing and certification programs “mostly exist in order to deal with failures caused by asymmetric information”. They can help quantify the interoperability of prospective solutions, informing stakeholders of relative costs, reducing uncertainty, and rewarding vendors that work to reduce systems integration costs with additional business. Firms that are unable or unwilling to pursue strategies that meet implementers needs for lower integration costs through greater interoperability will encounter a competitive disadvantage as these costs are brought into the light. In the long run, the informational improvements offered by third-party testing and certification programs will reduce the influence of actors whose lack of interoperability dissipates value.
While third-party testing and certification programs are not silver-bullet solutions for improving interoperability, thoughtful design and expansion of such institutions will be net- beneficial to grid modernization. Past experience argues for the presence of five features that support reliable third-party certification programs: consumer demand, brand competition, interdependence, concentration of market power, and consumer vigilance. These prerequisites are largely satisfied in the market for smart grid interoperability testing and certification services. However, efforts to improve outcomes may want to focus on areas where these prerequisites are not always met in full.
Challenge: consumer demand
Grid modernization will require massive expenditures by thousands of utilities and a rising group of service providers. Therefore, there will likely be sufficient consumer (in this case, utility and service provider) demand for third-party certification of the many systems that are envisioned to constitute the smart grid of tomorrow. The need for these services should induce entry into the certification market, especially if certification becomes either a regulatory or procurement requirement.
Challenge: interdependence and accountability
Market spoilage can occur when poor quality products or services persist long enough to affect customer value perception. In a testing and certification environment, certifications that do not adequately guarantee interoperability can affect not only the reputation of the certification agency, but left unchecked could damage the opportunities for competing firms as customer expectations decline.
The nature of ensuring interoperability between diverse systems means testing and certification programs most likely enjoy a sufficient degree of interdependence to hold each other accountable for poor performance. If the certifications provided by one firm prove unreliable to others in the process of providing upstream or downstream certification, these third-party certifiers will have an incentive to discipline the bad actors.
Challenge: concentration of market power
Large numbers of firms acting in diverse regulatory and economic regimes rais the expense and complexity for achieving accountability, regardless of the objectives. While many firms operate in the electric power sector, market power can be concentrated for certain functions. For testing and certification, the concentration of market power within a relatively few organizations makes enforcement of the above described discipline necessary to achieve accountability less costly and more credible.
Challenge: consumer vigilance
The critical nature of the business of electric utilities virtually assures the customer vigilance necessary to make testing and certification programs successful. If poor certification services are responsible for electric service outages, utilities will find out and action will be taken to prevent further interruption to a sector that is a fundamental input to the modern economy and is substantially compensated based upon service reliability. Any third-party testing and certification programs that develop a reputation for failing stakeholders will undoubtedly be eliminated by market forces.
Interoperability Benefits#
Grid modernization benefits will be substantial and sweeping. Interoperability is foundational to ensuring that new technologies can be cost-effectively integrated with the legacy system. It is also foundational to ensuring that diverse, distributed, and decentralized stakeholder groups can realize the anticipated benefit streams of grid modernization.
Minimizing transaction costs
Transaction costs are the costs of running an economic system, and high transaction costs are known to impede or completely block the formation of markets. The ongoing rise of modular and distributed generation and delivery technologies has brought with it an emphasis on employing aggregates and composites of these systems for integration with the electric power system. One consequence of this modularity and combinatorial innovation is that transaction costs increasingly constitute system level production costs. Greater interoperability will drive down transaction costs for the electric power sector, thereby allowing the creation of new market opportunities to obtain value for system stakeholders.
Improvements to technical and organizational interoperability will enable the dynamic assembly and reconfiguration of optimal value chains in accordance with changing conditions, opportunities, and threats to operation. The subsequent increase in available options and improvement in flexibility will drive efficiency gains in the dispatch of generation, transmission, and distribution segment assets in service of customer needs.
Interoperability will place downward pressure on information, integration, coordination, and transaction costs, opening up new value propositions. Some resource pairings for which coordination would presently prove uneconomic will — through greater interoperability and improved cost structures — be able to serve customers more frequently, leading to higher capacity utilization. Rising trading volume in services provided between increasingly interoperable nodes of the grid can fortify thin markets and provide liquidity that is attractive to other potential market participants. The presence of a virtuous cycle between new entry and market liquidity may further accelerate grid modernization.
The fall in transaction costs will lead less efficient combinations of resources to be foregone to the benefit of operators and their customers. Some resources that might otherwise have been rendered obsolete will be able to continue providing services due to the improved marketability of their offerings that comes with lower transaction costs. Old assets may also be repurposed in line with the changing requirements of grid operators and those they serve.
By extending the useful life of the existing generation fleet and delivery assets, construction of new resources for which capacity utilization is expected to be low may be avoided.
Lower transaction costs will also enable smaller distributed resources to compete in the provision of energy and ancillary services, which could induce an accelerated pace of adoption for these emerging technologies. With time, such decentralization may reduce the criticality of any individual asset contributing to the grid, improving the resilience of the grid against diverse hazards. A grid with more options from which operators may choose could realize lower production costs while proving to be more reliable.
Creating value
To the extent that greater interoperability can reduce the cost of integrating new systems with the existing grid, modernization efforts may unleash new opportunities for sales growth. Electric vehicles are one clear opportunity for the electric grid to achieve growth through improving interoperability with increasingly ubiquitous transportation assets.
Interoperability enhancements that improve observability and control of electric vehicle charging will make it operationally easier and more profitable for utilities and service providers to coordinate grid assets to meet customer needs.
Greater interoperability can also encourage flexibility among electricity consumers. For most of the electric power sector’s history, customers were relatively unresponsive to the fluctuating cost of serving a load because the price paid by most consumers was static and did not reflect underlying costs. Interoperability enhancements can reduce the transaction costs associated with dynamically communicating information on operating costs and conditions to relevant stakeholders, and therefore increase the price responsiveness of end customers. These relatively elastic consumers will be better equipped to shift their consumption patterns to account for price variability, which will improve capacity utilization for existing generation assets.
The opportunities for the exercise of market power by generation owners also falls with the increasingly elastic demand interoperability engenders. Prices will therefore move towards competitive equilibrium levels as interoperability improves.
Conclusion and Future Work#
With more than 3,000 utilities in the United States, the importance of interoperability to the utility, marketplace, and customer cannot be overstated. While specific requirements and functions will always be made at the local level, as the rollout of any given investment will not be uniform across the country or state, a foundation of interoperability and open standards provides the building blocks for successfully meeting system needs.
Interoperability is a key component of ensuring the technical and economic benefits from grid modernization flow across stakeholder interests throughout the evolution of the electricity system. Utilities are investing in substantial updates to their infrastructure, and customers are increasingly seeking to achieve additional savings and benefits from investments in DER. Interoperability driven by open standards can help lower transaction and implementation costs associated with DER and other investments.
Interoperability provides benefits that are often lost in the larger context of a utility rate case.
However, investments without consideration of interoperability will limit the ultimate reach of a technology, may be more expensive than necessary, and may not enable a grid that is ready and capable of integrating and optimizing the new resources coming to the distribution system. The costs associated with the absence of interoperability are growing as our distribution systems become more advanced and customers seek to realize greater savings from their investments. Effective testing and certification programs will assist in showing these savings, but regulators should ensure that interoperability is an identified component of any utility investment.