Factoring customer-owned generation into forecasting, planning, and operations.
Margarett Jolly (firstname.lastname@example.org) is Con Edison’s distributed generation ombudsperson. David Logsdon (email@example.com) is a distributed generation specialist and Christopher Raup (firstname.lastname@example.org) is manager of state regulatory affairs at Con Edison. The authors acknowledge the contributions of their colleagues Frank Cuomo, Jairo Gomez, Michael Harrington, Martin Heslin, Ahmed Mousa, and Robert Schimmenti.
As with most utilities, Con Edison has long planned its distribution system based on a unidirectional flow of electricity to customers. This design assumption has shaped system controls and analyses, energy markets, and operator training, along with many other aspects of equipment and operations, as well as critical business decisions like rate design and tariff rules. Historically, when customers provided for their own electric energy needs it was either for emergency back-up—for hospitals, water treatment plants, etc.—or for heavy-industry users that already had sophisticated technical operations and on-site expertise. In recent years a growing number of customers are installing, owning, and operating small to medium-sized electric generating systems, generally up to 20 MW in capacity, behind the meter.
Under restructuring, the New York State Public Service Commission (PSC) required jurisdictional utilities to divest most of their power plants and allowed customers to procure electricity from third parties. The intent of restructuring, to use competition to enhance customer choice, is becoming more fully realized as customers are increasingly able to select from a growing list of energy supply options. And customers have responded: most of Con Edison’s larger customers have third-party suppliers. Customer options include not only procuring supply from energy service companies—including green energy products—but also various customer-side technologies: energy efficiency (EE), building management systems, thermal and electric storage, demand controls and response (DR), and distributed generation (DG). DG technologies include solar photovoltaics (PV), wind, fuel cells, and combined heat and power (CHP) systems. Some of these technologies rely on business models that take advantage of available incentives, Con Edison DG rate offerings, financing, and third-party equipment operating and maintenance options.
The growth in customer-side resources is an opportunity for the utility to enhance the benefits to all customers by considering those new load reductions, but there are a number of questions utilities must address if they are to capture those benefits. Could the utility plan on customers responding to DR calls in order to clip the utilities’ peak load, rather than the more traditional assumption that these measures would only be used in emergencies? Could the utility target EE measures in areas of need and assume a success rate several years in advance that might defer the need for a capital upgrade? Could the utility determine that customers with on-site generation, operating in a consistent fashion, might be counted on as a load reduction in the utilities’ longer range plans?
For each of these questions, the answer in Con Edison’s territory appears to be “yes.”
Prior to restructuring, Con Edison presented its vertically integrated electric system plan to the PSC for approval, setting rates for both supply and delivery. Under deregulation, the utility’s primary responsibility is ensuring the adequacy of its distribution system under the PSC’s jurisdiction. Transmission and resource supply adequacy, under the jurisdiction of both the FERC and the PSC, is governed by the New York Independent System Operator (NYISO) planning process, which principally uses the market to send signals to facilitate a robust energy and capacity market, and oversees resource planning. The retail supply market is lightly regulated and retail suppliers compete in the NYISO marketplace. The increasing ability for customers to actively control their own energy supply might prove to be the linchpin in enabling the long-term sustainability of New York’s deregulated retail energy market.
The increasing focus on demand-side management (DSM) is a key development that reflects the shift in electric planning toward downstream solutions. Con Edison is re-examining the methods and associated costs of meeting load growth and is exploring satisfying system capacity needs through advanced modeling, improved asset utilization, and DSM approaches to defer capital expenditures.
Under the traditional utility model, each year the utility develops a load forecast based on past years’ experience adjusted for weather, expected economic developments, and other contributing factors. The distribution and transmission planning departments then run load-flow models to indentify pinch points, based on one-, five-, 10- and 20-year load-change expectations, and plan system upgrades to meet expected load growth. Such system upgrades include lower-cost measures such as transformer cooling or load transfers to less-burdened feeders or networks, and higher-cost investments like new substations or transmission lines. Each year this plan is revised to incorporate new information about load changes, including new and retiring businesses; changing customer demographics, equipment, and behavior; weather; improved modeling, etc.
Technical analysis has expanded the options for Con Edison engineers to use in meeting load growth beyond traditional T&D build-out, to include downstream customer resources and behaviors that prove less costly than traditional T&D. EE was the first of these options and it has recently been joined by more-complex DSM options.
Con Edison has incorporated EE programs into system planning since the company’s 1970s “Save-a-Watt” educational campaign, and a 1980s “Enlightened Energy” program that achieved a 740MW reduction in demand. EE programs have reliably demonstrated a viable alternative to costly capital improvements. Con Edison’s Targeted DSM program was launched in 2004 and has been targeted toward 30 of 64 networks. Under Targeted DSM, Con Edison issues competitive RFPs for customer-sited demand reductions in specific areas where T&D upgrades would otherwise be required. Such upgrades can be deferred by DSM that lowers loading on the distribution system by reducing peak demands on equipment.
DR has traditionally only been used in network emergencies, but has recently been built into system planning and forecasting and relied upon as a peak-shaving resource, improving asset utilization to prevent overbuilt distribution assets.
A vast, underutilized DR resource exists in the form of mostly diesel-fired emergency back-up generation. In New York City this resource represents more than 1.5 GW of potential generation. These back-up generators are eligible to enroll in DR programs, subject to environmental requirements and program criteria, and can earn extra income for these customers while adding to the utility’s menu of options for coping with load growth.
Rapid DG Growth
Customer adoption of DG—both renewable and natural-gas-fired—has seen a dramatic increase in Con Edison’s territory over the past five years, and this trend is expected to continue. Some of this is due to technological developments and customer interest in green energy, but most can be attributed to market and policy changes—particularly low, stable natural gas prices; state incentives, including property and other tax incentives; and the inherent efficiency of CHP. A meaningful number of customers have both the ability and desire to rely on DG for at least a part of their electric needs.
The forecast for Con Edison’s summer 2012 peak demand is 13,225 MW. And there is currently 160 MW of grid-connected DG in Con Edison’s service territory, 90 MW of which are natural-gas-fired CHP projects installed in the past three years alone. From 2012 through 2018 an additional 75 MW of large-scale customer-sited CHP is planned to be installed, based on discussions with interested customers. These anticipated projects, along with historic adoption rates and market trends, all feed the projection that CHP will comprise most of the 460 MW of new grid-connected DG by 2030.
Customer adoption of renewable energy in Con Edison has been virtually all rooftop solar PV, with a trend toward larger PV installations. Solar PV is expected to make up a small but increasing amount of DG—totaling at least 45 MW by 2015 and 125 MW by 2030, buoyed by state and federal incentives.
The high case projection, shown in red in Figure 1, reflects the possibility for increased adoption of CHP as a result of two potential accelerators. The first is that technology improvements and innovative financing could increase fuel-cell and microturbine adoption. And the second is that oil-to-CHP conversion might increase as local regulations require almost 8,000 customers to phase out using higher emitting #4 and #6 fuel oils for building heating.
Forecasting, Planning, and Operations
Prior to 2011, Con Edison’s practice was to add-back customer-sited baseload distributed generation to a customer’s system load, treating these resources as demand response and effectively eliminating the benefits that the customer’s DG could provide to the system. Con Edison has modified this practice such that a large DG project, running a reliable and tested technology to serve customer base loads over peak periods, can now be reflected in the forecast, resulting in the recognition of reduced demand in constrained areas. Existing continuously operating large-scale CHP is now incorporated into 10- and 20-year load relief plans, contributing capacity that, along with other DSM measures, is deferring multiple traditional T&D load-relief capital projects, realizing savings for the company and its customers. (See sidebar “How Con Edison Includes DG in the Forecast.”)
For example, 24 MW of summer peak-period baseload output of existing CHP capacity is defined as a load reduction in Con Edison’s current area substation and sub-transmission plans—some of which—depending on location, has allowed Con Edison to defer traditional, costly utility infrastructure investments. Notably, many of the new large CHP projects have faced technical challenges—such as equipment not operating as planned, leading to costly outages and high standby-rate backup charges. Until reliable operations are demonstrated, these aren’t included as a load reduction in load relief plans.
The criteria for capacity integration differ based on the contingency design of the area substation that feeds the network where the DG is located. For example, a substation with second-contingency design can include a reliable DG source as part of substation capability, as long as operating protocols are in place to back up the DG capacity. Protocols need to be in place by the summer the projected peak load exceeds the substation capability. The operating protocols would be called if the DG is out of service on a peak summer day in addition to having two substation transformers out of service. For first-contingency design substations, the same method applies, but the operating protocol must be in place assuming the DG is out of service as well as only one substation transformer. For networks with several independent DG installations Con Edison would review the diversity of DG installations to determine which should be included.
Taking a proactive approach to incorporating DG into company planning has yielded multiple operational benefits. Con Edison’s corporate long-range plans are now focused on examining cross-commodity synergies, and DG has been a natural focus for these efforts as it involves all three of the utility’s primary commodities—electric, gas, and steam. DG has been a central point for bringing these three divisions together to strategize the revenue and infrastructure implications of DG adoption. Gaining a better understanding of the costs and benefits of different approaches will help to ensure Con Edison can accommodate increased DG deployment and ensure revenue stability and positive rate impacts for customers.
Case Study: DG Delivery System Benefits
In one case in Manhattan, a customer served by a second-contingency design substation under a traditional load relief plan has for the past three years been running a 7.5 MW CHP generator during network peak periods, equipped with four-second-interval telemetry read at Con Edison’s control center. Analyzing the historical telemetry data has allowed engineers to comfortably rely on this DG capacity at the substation level, and thereby to defer future T&D load-relief efforts. In addressing the concern for assurance of capacity availability in factoring this particular generator into area load relief plans, the engineering team first set monitoring requirements on real-time interval data. The team ensured that working, reliable telemetry was in place for DG breaker status, output of kW and kVARs, as well as voltage, amperes, and power factor. This allows monitoring DG performance, including the coincidence of generator output with substation peak loads. This level of telemetry is already required under Con Edison specifications for new DG installations over 2 MW connected at medium-level voltage. This particular generator had more than two years of historical data that helped operators to understand the outage rate on weekdays during the summer period, average summer generator output, and to inspect any historical data communications problems. Results were a steady output of 7 MW throughout the past two summers, with a minimal and controlled outage rate.
This analysis adequately assures that the generator can be counted on as a reliable load reduction, but it doesn’t fully solve the problem of availability, as there is no contractual agreement with the customer to generate when needed. To address this, utility distribution-system operating protocols are being developed for the future years in which the projected peak loads of the network are expected to exceed the summer substation capability for cases when the DG is out of service. The operating protocol adheres to second-contingency design criteria, i.e., continued ability to meet load under circumstances where the DG is out of service on a peak summer day with two substation transformers also out of service. This operating protocol will be implemented when the DG is unavailable on a peak day during first contingency, and will consist of load-relief measures not already counted, including customer appeals for load reduction, emergency demand response, voltage reduction, use of customers’ emergency generation, or use of company-owned emergency mobile generation. Under these operating scenarios Con Edison will continue to provide service to all of its network customers as well as backup or standby power to the DG customer.
Maximizing DG Benefits
As a first step, other cases where CHP is located in stressed networks with planned load relief are being considered for additional savings, as are future DG projects that will be located in these networks. The most logical next move is to take the same evolutionary step with DG that Con Edison took with EE when the Targeted DSM program was adopted. Currently DG installation locations are somewhat random, with projects siting wherever customers find them viable. Con Edison has no way of predicting with any specificity where or when a customer will choose DG. Using existing public incentives to target DG installations to areas of the system that could benefit from increased capacity will get more bang for the buck—a similar approach has already created Solar Empowerment Zones in Con Edison service territory, where public incentives for solar PV are increased in day-peaking networks with planned load relief. Additional opportunities include assessing the potential for central dispatch of DG and enhanced data management as smart distribution evolves; the incorporation of DG into independent-system-operator planning processes; and leveraging the legislated phase-out of #4 and #6 fuel oils.
Con Edison might pursue several possible approaches to increase the grid-benefit of DG while still maintaining substation design requirements. Under one, the utility could contract for a reduction in back-up service with DG customers. The electric distribution company’s contractual obligation to serve load would be reduced; if the customer’s DG unit was offline when this contracted amount was exceeded, the customer would have to reduce load in some manner or agree to endure a partial outage. This reduction in the actual obligated load also would allow the utility to extend the DG capacity benefit to additional portions of the distribution system as well as area substation and sub-transmission feeders.
A second scenario would be to allow utility control and dispatch of customers’ interconnected or emergency backup DG. This would give the utility control over the generation, including the ability to ramp up generation when it’s needed the most; the customer would stand to benefit with a financial incentive for transferring this control and providing beneficial capacity at a peak time with a higher level of reliability. This improvement in reliability also would reduce the scale and costs of the utility emergency back-up plan. Con Edison’s DOE-funded Smart Grid Demonstration Project includes piloting distribution control room dispatch of the full menu of demand response—including start, stop, and load control of customers’ emergency and baseload generators.
It’s also possible, with increased adoption of DG, to shift to a more probabilistic approach for including DG in area substation and feeder load relief programs. Reliability of many types of DG units is well documented, and the reliability of components in substations and networks also is well understood. Probabilistic analysis can focus on how these mesh into an overall probability of achieving acceptable operations during summer load conditions.
And, lastly, utility ownership and operation of DG should continue to be considered. This would allow for efficient and timely deployment of strategically-sited DG that operates at high levels of reliability during system peaks. This scenario would leverage utility expertise in managing customer energy solutions to avoid large capital expenditures while also maximizing grid reliability and allowing operation of the utility’s equipment in times of high demand in a manner that best supports the most customers.
There are certainly many challenges that remain, including those internal to the utility—such as proper design of incentives and rates, and overcoming data and technology management hurdles. Standby rate design must ensure recovery from DG customers of the utility investments that provide full back-up to the DG customer. The costs of subsidies for DG must be transparent to policy makers and ratepayers—through clearly noted charges for renewable energy and system benefits on customers’ bills. Careful consideration also must be given so that DG installations don’t transfer an economic burden to other utility customers. For example, DG projects must pay for their full interconnection costs.
One of the primary technical concerns with interconnected DG is the potential to exceed the fault-duty limitations at substations. Under extreme fault conditions, customer-sited synchronous generators can contribute enough additional fault current to prevent substation breakers from interrupting properly. Customers have been able to meet fault-mitigation requirements through a growing array of customer-side fault-current mitigation technology, and further R&D is proceeding in this area.for technical fault current mitigation solutions
No matter what strategy is employed to overcome these challenges and realize the most benefits from changing customer behaviors, open communication remains key. For example, Con Edison hosts DG stakeholder seminars, provides technical interconnection training for developers, and publishes non-technical handbooks for customers. The company’s EE and DR departments have sophisticated marketing, measurement, and verification approaches that are good models for targeting DG and identifying customer opportunities.
Finally, while natural gas-fired DG has the technical potential to be cleaner than traditional central station generation, it’s important that DG resources be held to stringent environmental standards. Customers place a high value on clean air, particularly important in a dense urban environment; as such, utilities shouldn’t encourage the use of DG that lowers the local quality of the environment.
1. Gazze, C., Mysholowsky, S., Craft, R., Applebaum, B., “Con Edison’s Targeted Demand Side Management Program: Replacing Distribution Infrastructure with Load Reduction,” 2010 ACEEE Summer Study on Energy Efficiency in Buildings.
2. “Promulgation of Amendments to Chapter 2 of Title 15 of the Rules of the City of New York Rules Governing the Emissions from the Use of #4 and #6 Fuel Oil in Heat and Hot Water Boilers and Burners,” New York City Department of Environmental Protection, 2011.
3. “New York City’s Solar Energy Future: 2011 Update,” Meister Consultants Group, Inc., 2011, Prepared for the City University of New York and the New York City Solar America City Partnership, DOE Solar America Cities Initiative.