As utilities plan their capital budgets for the next few years, investments in advanced distribution systems face an uncertain future. Customers question the value—and propriety—of some programs,...
Capturing Distributed Benefits
Factoring customer-owned generation into forecasting, planning, and operations.
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.