POWER SECTOR (E MARTINOT, SECTION EDITOR)

Distribution System Planning and Innovation for DistributedEnergy Futures

Eric Martinot1 & Lorenzo Kristov2 & J. David Erickson3

Published online: 25 April 2015# Springer International Publishing AG 2015

Abstract In the future, electric power distribution utilitieswill need to plan, operate and innovate in a variety of newways to contend with the changing nature of electricity systemresources and opportunities. A distributed energy future leadsto changing paradigms, changing needs in planning and inno-vation by distribution utilities, and changing regulatory direc-tions. The changing paradigm encompasses two-way powerflows, local integration and balancing, functional control ofdistributed resources, the changing nature of the boundarybetween transmission and distribution systems, the changingnature of resources and customers, and new business models.Changing needs in planning and innovation include handlingtwo-way reversible power flows; interconnecting storage andelectric vehicles; controlling flexible-demand resources; dis-tribution system monitoring, analysis and modeling; renew-able energy output forecasting; smart inverters; and data net-works, analysis, and storage. Examples of changing regulato-ry directions are seen in New York, California, and Australia.

Keywords Distributed generation . Power systems .

Renewable energy integration . Smart grids . Electricityregulation

Introduction

Power systems are clearly evolving at accelerating rates. Inrecent years, a lot of attention in the literature has focused onongoing and future changes in thinking about power systemarchitecture, operation, and integration of distributed re-sources like renewable generation, energy storage, anddemand-side flexibility (demand response). In addition, theintegration of electric vehicle charging, and heating andcooling infrastructure (i.e., combined-heat-and-power plants,chillers, and thermal energy storage) with electric power sys-tems represents another level of future integration. These dis-tributed resources and integration opportunities are changingthe nature of planning, operation and innovation for distribu-tion systems in fundamental ways [1–10].

Historically, distribution systems have been plannedaround two main principles: forecasting changes in customerload and planning upgrades and extensions on that basis; andanticipating equipment replacement needs as equipmentreaches the end of its useful life. These planning questionshistorically had to be addressed only for the purpose of pas-sive one-way delivery of energy from the high-voltage trans-mission grid to the end-use customers. Distribution systemdesign and planning was thus quite standard and changed littleover the decades. Distribution utilities did not necessarily needto be innovators, just good forecasters and planners, and couldfocus primarily on safety and reliability [11, 12].

In the future, distribution utilities will need to plan, operateand innovate in a variety of new ways to contend with muchhigher penetrations of distributed energy resources, and con-sequent two-way power flows and added reliability chal-lenges. Moreover, demand response, storage, smart inverters,micro-grids, and a host of other emerging technologies areappearing on the Bcustomer side of the meter^ in new ways,posing further challenges for planning and management.

This article is part of the Topical Collection on Power Sector

* Eric Martinotcontact@martinot.info

1 School of Management and Economics, Beijing Institute ofTechnology, 5 Zhongguancun South St., Beijing 100081, China

2 California Independent System Operator, 250 Outcropping Way,Folsom, CA 95630, USA

3 California Public Utilities Commission, 505 Van Ness Ave., SanFrancisco, CA 94102, USA

Curr Sustainable Renewable Energy Rep (2015) 2:47–54DOI 10.1007/s40518-015-0027-8

Distribution utilities will be required to monitor, collect, ana-lyze, and use data in new ways, and will be required to ana-lytically model their distribution systems to a degree far be-yond current practice. And utilities will be required to use awide variety of information and communication technologiesto achieve the necessary integration of all of these elements.

Over the past several years, there has been a growing bodyof literature that addresses this new era of distribution systemplanning and innovation [13–24]. However, the literature isstill far from being identifiable as a coherent body of work,and appears across several categories of research and practice.For example, Bsmart grid^ literature is a subset of distributionsystem planning and innovation, and tends to focus more onthe data and communication tools to enable and achieve var-ious distribution system innovations, rather than starting fromthe broader planning, operational and innovation needs andfunctions themselves [25–29].

A distributed electric power future leads to: (a) changingparadigms; (b) changing needs in planning, operation and in-novation by distribution utilities; and (c) changing regulatorydirections. These three elements are each summarized in turnbelow.

Changing Paradigms

A new paradigm for thinking about the role and function ofdistribution utilities has been emerging in recent years. Thisnew paradigm also considers the changing technical role ofthe distribution system itself, relative to the bulk power grid, inproviding power-system services including reliability andflexibility.

A number of recent papers point to different aspects of thisparadigm. For example, Kristov and De Martini [15] intro-duce the terms Bintegrated distributed electricity system^and Bdistribution system operator (DSO)^ to denote, respec-tively, a new electric system paradigm and an expanded func-tional role for the distribution utility (see Table 1).

The changing paradigm encompasses at least seven maindimensions:

1. Maintaining reliable distribution system operation withtwo-way, multi-point, reversible power flows. As the vol-ume and diversity of distributed resources increase, powerflows at the distribution system level can become two-directional. Unless accounted for in system design andoperation, frequent reversals in power flow can have se-rious consequences in distribution system operation. Inorder for distribution utilities to properly manage distribu-tion systems, they must implement voltage monitoring,telemetry, and real-time control of components like trans-formers in response to dynamically changing conditions.And theymay also need to actively manage customer-side

resources. All of these things represent first-time innova-tions for distribution utilities, as historically, systems havebeen designed only for one-way flows and no customer-side control [25].

2. Integrating and balancing distributed resources and loadat the distribution level in order to shape the load profileand peak demand as seen by the bulk power system at thetransmission-distribution interface (T-D interface) substa-tion. New approaches to distribution system integrationcan create Bmulti-function^ distributed resources that pro-vide services to the bulk power system beyond simplyenergy delivery. In addition, the system can attain thecapability to manage resource variability locally and startto function with some degree of autonomy. Distributionsystem integration can present more Bbounded andpredictable^ behavior to the bulk grid, with specific loadcharacteristics and timing. To the degree to which thisdistribution-level integration results in a predicable (oreven programmable) load curve, this can reduce the needfor transmission and generation investments in bulk sys-tem flexibility, ramping, and reliability [14, 15].

Local self-balancing can occur at several geographicallevels within a distribution system, for example, on anindividual feeder, or at the level of a single (low-voltage) distribution substation, or for everything con-nected to an entire distribution network below a single(high-voltage) transmission-distribution substation. Atwhatever level, the DSO starts to integrate and balancevariable distributed generation, flexible and controllableloads (including electric vehicle charging), storage, andsmart inverters capable of providing grid services, likebalancing and ramping. Another emerging developmentis the possibility of creating local energymarkets operatedby the DSO, outside of the bulk-grid markets, throughwhich local-distributed resources offer energy to localend-users (see New York REV case later in this paper),as well as grid services to the DSO, such as grid servicesto enable local self-balancing, or services to either shortenor eliminate outages caused by accidental events [16].

3. Functional control of distributed resources for purposes ofproviding real-time balancing and flexibility, as well asother services, such as reactive power and frequency con-trol to the local or bulk grid. How can control of distributedresources provide flexibility? Today, distributed resourcesare seen and modeled by system operators predominantlyas load or load modifiers (load reducers), not as generation.In the future, control of distributed resources can provideflexibility to the bulk grid, but there are many alternativeframeworks for how this flexibility is controlled, and whoreceives economic value from the grid services provided.Do distributed resources participate in wholesale markets,either individually or aggregated by intermediaries? Doesthe TSO dispatch these resources, or does the DSO? If a

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distribution-level resource wants to provide service to boththe bulk system and the distribution system simultaneously,which entity has priority? How does the DER owner/operator participate in any market-based dispatch of theDER? Are there a set of pre-approved autonomous-operat-ing regimes? All of these questions face technical, econom-ic, regulatory, and political issues that are just be-ginning to be explored by regulators and stake-holders [14–17, 30].

4. New ways of defining and managing the boundary be-tween transmission and distribution (T-D interface) interms of all the market, technical, service, and coordinationfunctions necessary to reliably and optimally operate thewhole power system. Historically, in vertically integratedmonopoly utilities, there were operational and architecturaldifferences between transmission and distribution systems,but their operation and planning were performed by a sin-gle entity, whether public or private. Then, in jurisdictionsthat restructured their power sectors in the 1990s and2000s, the operational and planning functions of the trans-mission system were assigned to newly created transmis-sion system operators (TSOs).1 From an electrical perspec-tive, there was effectively no change: power still flowedfrom central station generation over the transmission net-work, then across the T-D interface substations into distri-bution circuits that passively transmitted energy one way toend-use customers. The significant changes of pastrestructuring were largely organizational, with the new in-dependent TSOs becoming operators of both the high-voltage grid and the wholesale markets through whichbuyers and sellers of bulk power and capacity transacted.In some areas, the T-D interface also became a more sig-nificant regulatory boundary; in the United States, for ex-ample, transmission and wholesale markets are regulatedby the federal government (FERC), while distribution sys-tems and retail markets, where they exist, are regulated bystate governments. But now, with the accelerating prolifer-ation of distributed resources, that boundary is blurred andis opening economic and public policy debates as to the

1 Transmission system operators may be abbreviated as BTSOs^, BISOs^or BRTOs^ depending on jurisdiction. This paper uses BTSOs,^ althoughthe functions of such organizations also differs across differentjurisdictions.

Table 1 Future integrated distributed electricity system

Kristov and De Martini [15] point to future distribution systemoperators (DSOs) at the heart of a future Bintegrated distributed^electricity system. In this future system, a DSO is Ba single entity[that] operates each local distribution area and is responsible forproviding reliable real-time distribution service.^ And the DSO’soperational responsibility for the local distribution area mustencompass all activities required to maintain safe, reliable, efficientdistribution service to customers and connected distributed energyresources (DER), as well as a stable interface with the transmis-sion grid. This means the DSO must coordinate operations of theinterconnected DER, micro-grids and self-optimizing customers,and schedule interchange with the TSO at the T-D interface. Sucha system requires an integrated and coordinated operationalparadigm that clearly delineates roles and responsibilities betweenthe transmission system operator (TSO) and DSOs. In this newparadigm, Kristov and De Martini outline four basic functions thatspan across the TSO-DSO boundary:

1. Distributed reliability services support reliable real-time distributionsystem operations. The concept of Bdistributed reliability^ is itselfnew. Kristov and De Martini define it as a Bfederated reliabilityparadigm^ in which DSOs, and potentially micro-grids andself-optimizing customers, have responsibility and accountability forthe reliable real-time operation of the respective electric systemsunder their operational control. Underlying this concept is therecognition that many types of DER and independent micro-gridswill be capable of providing such services. Reliability services willbe provided by diverse DER, according to their performancecharacteristics and capabilities, to the local distribution system towhich they are connected. These services may be provided to theDSO via tariffs, bilateral contracts or other means, to enable the DSOto reliably operate the distribution system and manage variability atthe T-D interface, and may also be provided to other entities acrossthe distribution system, such as municipal utilities. The DSO’s abilityto use locally provided reliability services will enable it to maintain amore stable and predictable interchange with the TSO at the T-Dinterface, thereby relying less on the TSO to provide energy balancingand other real-time services, and even utilizing DER with appropriateperformance capabilities to provide such services back to the TSO.

2. T-D interface reliability coordination ensures that DER-provided ser-vices are properly coordinated, scheduled and managed in real-time sothat the TSO has predictability and assurance that DER committed toprovide grid services will actually deliver those services across thedistribution system to the T-D interface. The DSO must ensure that theDER providing reliability services don’t have any conflicting servicecommitments, such as offering the same capacity to serve both the TSOand the DSO or another entity. This coordination also involves ensur-ing that DER dispatch (via direct control or economic signal) doesn’tcreate detrimental effects on the local distribution system, and willrequire schedule and dispatch coordination at the T-D interfacebetween the TSO and DSO. At a minimum, the DSO will likely be thebest positioned entity to forecast net load in each local distribution areaand net power flows across the T-D interface.

3. Energy transaction coordination across the T-D interface meansthat, at a minimum, the physical aspects (not the financialaspects) of energy transactions will need to be coordinated bythe DSO. This does not mean that DSOs will operate balancingmarkets or dispatch wholesale-market resources, which canremain the sole responsibility of the TSO. The DSO will,however, need to coordinate with the TSO energy and capacitydelivery schedules to ensure operational integrity of thedistribution system.

Table 1 (continued)

4. Dispatch coordination is a possible extended model of a DSO withexpanded functional responsibilities in addition to those above. In thismodel the DSO provides a single point of control on the distributionside of a T-D interface for the purpose of operational dispatch coordi-nation of all DER in the local distribution area that intend to participatein wholesale energy and/or ancillary services markets under TSOcontrol.

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best market, regulatory, and technical control structures andways to develop power systems at least cost to consumers[14–16, 20, 25].

5. The changing nature of resources. BResources^ tradition-ally were large power plants. In the future, Bresources^will increasingly encompass many demand-side mea-sures, like automatic demand response and dynamic pric-ing, which can be viewed in comparison with (and inmarket competition with) the historically traditional re-sources. Combined-heat-and-power plants will be com-bined with heat storage to allow very flexible electricityoutput while still keeping heat supply constant. Air con-ditioners (chillers) with thermal storage will be able toshift their demand over a several hour period upon com-mand. All of these can be considered Bresources^ [9, 10,31–34].

6. The changing nature of customers. Similarly, Bcustomers^traditionally meant end-users or consumers of electricitytypically located at an end point of a distribution circuitand wholly dependent on that circuit and on the upstreamtransmission system and central generation to supply theirneeds. In the future, the definition of customers must ex-pand in at least two ways. First, many end-users areinstalling supply and storage facilities Bbehind the meter^on their own premises and, as a result, are able to alter-nately consume energy from and supply energy to thegrid. The term Bprosumers^ has become a widely usedterm to express the fact that the same entity may be botha consumer and a producer, at different times. Indeed,many such Bprosumers^ are becoming able to providethe majority, or even all, of their own power needs (al-though likely still relying on the grid for back-up).Second, distributed energy resources themselves must bethought of as Bcustomers^ of distribution utilities, sincethese resources rely on DSOs to operate the distributionsystem in a manner that allows the distributed resources toearn revenue from selling (surplus) energy, and/or fromselling grid support, like balancing or ramping. From theperspective of the DSO, the Bcustomers^ that depend onand pay for its distribution-grid services will comprise amuch larger and diverse category in the future.

7. New utility business models and the changing nature ofdistribution utilities themselves. New business modelsthat take advantage of the preceding dimensions of a par-adigm change will also be required for utilities to fullyembrace the changes, or even to survive as profitable en-tities. Many examples around the world can be found ofsuch new and emerging business models. And distribu-tion utilities themselves are evolving into a much morediverse array of configurations and structures, which arestarting to be called names like Bmicro-utilities,^ B(local)energy service providers,^ and Bsmart integrators^ [27,35, 36].

Changing Needs in Planning, Operationand Innovation

Eight of the most significant categories of planning, operationand innovation needed by distribution utilities in the future areoutlined in this section.

1. Handling two-way, reversible power flows. This requiresreal-time monitoring of voltages along distribution lines,something that distribution utilities have not needed to dohistorically, and then adjusting the distribution system(primarily through adjusting transformers) to achieve thecorrect voltages with two-way power flows. This alsorequires changing the band of acceptable operating volt-ages, so as to allow some voltage Breserve^ in case ofvoltage rise from distributed generation. Traditionally,utilities have operated distribution grids almost Bblindly ,̂without any data measurement of system conditions. Inthe future with two-way power flows, utilities will have tooperate not only with Bsight^ but also Bforesight^ [17,20]. Palensky and Kupzog [25] write (p. 207): BGivenan appropriate automation infrastructure enabling remoteaccess to voltage and reactive power measurements, adistributed control system can be designed that not onlykeeps voltage in its limits but also optimizes other aspects,such as maximum renewable power utilization and/orminimal distribution losses.^

2. Interconnecting storage. The interconnection of distributedstorage is partly a technical issue—how to model the op-eration of a storage resource to ensure that the distributionsystem is technically able to support the physical intercon-nection. This requires understanding its programmed oper-ating regime in terms of when and whether charging anddischarging coincides with distribution system peaks. Forexample, in California, current interconnection require-ments under BRule 21^ specify that storage must be treatedlike a load in calculating the worst-case situation, whichthen carries over to specifying the necessary distributionsystem upgrades to accommodate that storage. But aBworst-case^ situation would typically be at peak periodsof the day, while under plausible operating regimes, storageduring peak periods would not be operated as a load, butrather operated as a generator (to take advantage of peakpricing). If operated only as a generator at peak periods,interconnection costs may be lower, resulting in economicsavings. But the planning framework under Rule 21 is notyet adapted to such considerations [37, 38].

Storage interconnection also represents a broader mar-ket design and regulatory issue. The first regulatory prob-lem is how to define distributed storage for regulatory pur-poses. Is it generation? Is it load? Is it both? Is itdispatchable? What tariffs should apply? Should the defi-nition and regulatory treatment be different if the storage is

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used only to buy and sell from the grid (with no self-consumption of stored energy as load), or if the storage isalso used for internal consumption purposes (i.e., storinglocal generation or purchased power for later consump-tion)? Distribution system planning will depend on the an-swers to such questions.

3. Interconnecting electric vehicles. Electric vehicles may beconsidered a unique category of energy storage, and dis-cussions are underway in many jurisdictions about how totreat electric vehicles—as load, as demand response, or asstorage. Interconnection of EV charging may or may notfollow the same interconnection rules and tariffs as con-ventional battery energy storage would. As a unique re-source, electric vehicles may need different tariffs andrules. For example, the non-fixed geographic location ofelectric vehicles when connected to the distribution sys-tem creates challenges in terms of providing dependablestorage capacity or energy. Modeling the behavior of largenumbers of electric vehicles will require more experiencewith how operators use their vehicles, and where andwhen they connect to the distribution system [27].

4. Controlling flexible-demand resources (Bdemandresponse^). Demand response has great potential to pro-vide flexibility to future power systems [9, 10, 31]. Butvirtually all demand response takes place physically at thedistribution level. What types of control for DR resourceswill exist? Will DR be controlled by the customer in re-sponse to dynamic prices and/or system conditions? Orwill it be controlled by the distribution utility? Or by theISO/TSO? Or by a third-party aggregator? Distributionsystem planning will depend on the answers to such ques-tions, and the acceptable range of possibilities as deter-mined by regulators.

5. Distribution system analysis and modeling. Distributionutilities will need to undertake new levels of analysis andmodeling of their distribution systems, far beyond theirtraditional practice. In the words of De Martini [14]:BAnalysis today requires both the traditional power engi-neering analysis as well as an assessment of the randomvariability and power flows across a distribution system.Such an analysis would include real and reactive powerflows under a variety of planned and unplanned situationsacross a distribution system, not just a single feeder…Evolution to a more network centric model for a distribu-tion system to enable bi-directional power flow under-scores the need for a fundamental shift in planninganalyses.^ This can include, for example:

& Modeling the technical distribution system, includingreal-time state estimation based on real-time data, toenable rapid interconnection studies in response tocustomer requests for interconnection and to managegrid operation.

& Conducting sophisticated demand forecasting, in-cluding using stochastic models, metering data, cus-tomer surveys, and bottom-up aggregation of differ-ent load categories and parameters.

& Calculating and applying Blocational value^ of re-sources. BLocational value^ takes into account wherethe resource is located within a distribution systemand how the resource at that location can reduce fu-ture distribution system investment needs (i.e., post-poning or avoiding network upgrades based on thepresence of distributed resources) [47].

& Calculating and applying distributed resource valueother than locational value. New metrics and method-ologies for calculating a variety of economic values ofdistributed resources.

& Calculating Bintegration capacity.^ This analysisshows how much DER can be integrated in differentlocations of the distribution network.

6. Renewable energy output forecasting using day-aheadand real-time weather forecasting. Distribution utilitieswill need to forecast renewable generation on their sys-tems in the same way that TSOs do, to aid in balancingsupply and demand locally, and in managing power flowswithin the distribution system.

7. Smart-inverter practices, codes and standards, and con-trol. Smart inverters can provide voltage and reactivepower support to the distribution grid that can mitigateover-voltage problems from distributed generation andincrease the integration capacity of distributed generation[39, 40]. Smart inverters can also provide grid reliabilityservice and flexibility, by altering their output in real-timein response to system needs for ramping. And smart in-verters can potentially provide a range of other advancedgrid services like islanding operation and black start ca-pability. One key consideration is who will control thesesmart inverters, the owner of the distributed resource, theDSO, or potential third-party aggregators? Another con-sideration is the optimal arrangement of controls in a giv-en distribution system area for local voltage and reactivepower support, in terms of howmuch is provided by smartinverters (and whether all DER needs to have smart in-verters) versus how much is provided by DSO-ownedequipment. California is the only state in the U.S. to haveso far adopted smart inverter standards (which so far arefor voltage and reactive power support only) [41].

8. Data networks, analysis, and storage. There is a verybroad need to design the communications and data man-agement infrastructure to support the operational require-ments described in this section. For example, the need fordistribution-grid monitoring and state estimation from acombination of customer meters, voltage and power flowline monitoring, and/or transformer monitoring. And the

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need to process and use the information in variety ofways, for example establishing real-time voltage controlset-points for distributed energy resources, and day-aheadforecasting and optimization of necessary control actions.

A number of distribution utilities around the world areactively engaged in moving into this new paradigm ofdistribution planning and innovation. Unfortunately, thereare few case studies in the literature as yet. One innovativecase is EWE Netz in Germany; see Table 2.

Changing Regulatory Efforts Aimed at DistributionSystems of the Future

Regulatory frameworks for distribution utilities vary greatlyaround the world, but most share a common feature: asBnatural monopolies,^ distribution utilities get a regulated rateof return on their investments in necessary distribution systemupgrades. Investment toward new Bintegrated^ paradigms isnot necessarily possible under existing regulatory frame-works. For example, distribution utilities may not be able toinclude research and development costs in their regulated rev-enue base. Thus, an important part of the literature also coverspolicy changes that may be necessary to bring about the plan-ning and innovation discussed in this paper; see for exampleNewcomb et al. [22] and Wiedman and Beach [23].

Three notable examples follow of regulatory frameworksthat have evolved in recent years to explicitly address thefuture needs of distribution planning and innovation. Theseexamples are all of jurisdictions facing increasing shares ofdistributed energy resources, particularly solar power. In thefuture, many regulatory efforts across the world could be driv-en by the urgency of the needs discussed in this paper, as theshare of distributed resources in specific jurisdictions grows tohigher levels.

New York: New York started a BReforming the EnergyVision^ initiative in 2013 that envisions a Bdistributedsystem platform^ (DSP) for integrating distributed re-sources. The platform will allow energy from distributedresources to be tracked, forecast, and traded within thedistribution system. The vision includes several elements,such as: retail-level energy markets; opportunities fornew retail-level energy services; market-based distributedenergy resource (DER) contribution to system balancing,flexibility and reliability; demand management on a day-ahead or real-time basis; expanded access to system in-formation by customers and DER providers to help themcalculate time-based and location-based economicvalues; demand-response tariffs, including tariffs for stor-age; regulatory oversight of DER providers; and limits onownership of DERs by distribution utilities themselves.The vision is that this new platform will facilitate wide-spread deployment of DERs, two-way power flows, ad-vanced communications, distribution system monitoringand management systems, and automated controls of en-ergy sources and loads. And the DSP will coordinate itsretail markets with the New York ISO’s wholesale mar-kets; for example the ISO could accept demand-reductionbids by the DSP in the wholesale market [44–46].California: Assembly Bill (AB) 327 passed theCalifornia Legislature in 2013. The bill amends PublicUtilities Code Section (§) 769 and requires utilities tosubmit Distribution Resource Plans (DRPs) that recog-nize, among other things, the need for investment inupgrading the distribution system to integrate cost-effective distributed generation, and for actively identify-ing barriers to the deployment of distributed generation.Such barriers include adequate safety standards related totechnology or operation of the distribution circuit, forexample. Section 769, together with a new CPUC regu-latory proceeding on this subject that opened in August2014, constitute a major new push in California to ad-dress distribution system planning and innovation in thefuture, and for addressing the needs of balancing andintegrating distributed renewables in the most effectivemanner, such that distribution systems themselves con-tribute to overall power-system flexibility and reliability[47–49].

Table 2 EWE Netz

EWE Netz is a distribution utility serving north-west Germany, based inOldenburg. EWE has a high penetration of renewable energy on itsgrid; in 2013, 70 % of the power consumption by EWE’s customerscame from local renewable energy sources. EWE is already doing anumber of things to integrate and balance renewables on the distribu-tion grid that go well beyond current practice of most distributionutilities, and also go beyond current regulatory requirements for DSOsin Germany: (a) EWE has its own weather/renewable energy outputforecasting system. (b) EWE does its own curtailment orders based onlocal grid capacities. (c) Voltagemonitoring in certain areas, along withvoltage stabilization measures. All medium-voltage distribution sta-tions have been integrated into a fiber-optic network. (d) EWE hasdeveloped and maintains a real-time model of the whole distributiongrid. It can use this model to approve interconnections of new renew-able capacity in real-time. (e) Research and grid planning are done at amore sophisticated level than previously [42].

EWE also conducted a number of BeTelligence^ pilot projects during2010–2012 that included (a) residential demand response; (b) Bvirtualpower plants^ consisting of distributed renewables and demand re-sponse from refrigerated warehouses, for local scheduling andbalancing of renewables. (The idea was to create a power plant thatcould be reliably scheduled and operated, with local balancing of re-sources.) (c) a local energy marketplace for local buying and selling,with energy traded in 1-h and 15-min contracts, including wind farms,solar PV systems, combined-heat-and-power plants, and on the de-mand side, electric vehicles and refrigerated warehouses [43].

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Australia: In 2013, Australia enacted a Bregulatory in-vestment test for distribution^ that requires all DSOs toassess Bnon-wire^ alternatives such as demand manage-ment and distributed generation when contemplating anynetwork-upgrade project greater than A$1 million. DSOsin Australia are also required by national policy to produceBDistribution Planning Annual Reports^ with 5-year plan-ning horizons. One such plan is by the DSO for the state ofSouth Australia, SA Power Network, which has developeda 15-year BFuture Operating Model 2013–2028^ in whichit presents its vision of its distribution network in the next15 years. This DSO forecasts expected penetration of DERover the next 15 years, including customer adoption of DRand other demand-side measures, as well as penetration ofelectric vehicle charging, and anticipating the need toman-age two-way power flows and integrate the levels of DERexpected [50, 51].

Conclusion: Toward a More Coherent Literature

The literature on distribution system planning and innovationis widely diverse and scattered among several subject catego-ries. These include Bdistributed generation,^ Bpower systemsof the future,^ Bsmart grids,^ Bintegrated grids,^ and severalothers. In the future, a more cohesive and readily identifiablebody of literature should emerge that addresses the paradigmchanges, needs for planning and innovation, business models,regulatory models and approaches, and real-world cases ofactual planning and innovation at the distribution level, aspointed to and suggested in this paper.

Acknowledgements This paper benefited from the research contribu-tions of Romain Zissler, and from the support of the Japan RenewableEnergy Foundation and the Institute for Advanced Sustainability Studies.

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