The New Era of Distribution Resource Planning: Part 2

Jan 26, 2017

In this two part series, we look at how distribution resource planning is flipping from top-down to bottom-up due to the influx of DERs. The transition can be disruptive, but we explore the strategies and tools that today’s utilities and their commissions are successfully applying to stay on top of the challenges and capitalize on opportunities.

How utilities can assess the value of DERs and develop a DRP 2.0 Perspective

As discussed in our previous post, the rapid deployment of DERs poses new challenges for utilities. Not only must grid planners assess their own options for DER deployments in many states, but customers are also adding their own resources to the grid, and doing so unevenly, which makes the long-term forecasts done previously much less reliable and can lead to strain on substations and distribution lines serving the areas where these resources are clustered. This isn’t necessarily a bad thing, however, as these distributed resources can provide significant value to grid operations and be used to defer or replace costly capital expenditures that would otherwise be necessary.

Utility and commission deliberations regarding DER integration center on how to assess the value that DERs provide to the grid. DERs have unique potential to provide range of services, including:

  • Producing energy
  • Reducing transmission congestion and defer investments
  • Deferring or avoiding growth-related distribution investments (if coincident with local peaks)
  • Deferring or avoiding the need for new peaking generators (if coincident with system peaks)

Complicating this transition is that the value DERs provide is highly dependent on a variety of factors including their location, operational characteristics, load forecasts, and existing grid conditions. And if DERs are going to be used to defer or replace traditional grid investments, the value they provide must be known and well understood. Benefit-cost methodologies for distributed resources of specific technologies have been developed and implemented for many years, but their calculations tended to focus on system-wide or regional value assessed on the cost-effectiveness of rate-funded programs. This approach is not sufficient for comparing value across multiple types of DERs in different locations and with different temporal characteristics; nor does it allow for the valuation of the beneficial interaction of multiple DERs of various types, and with differing load shapes, such as with solar, wind and storage. A methodology is needed that can account for the locational and temporal value that DERs provide to a dynamic energy grid while also assessing the capacity deferral potential they can offer the distribution system.

 

 

Nexant has been on the forefront of these efforts and has developed a methodology for assessing DER locational capacity value. Our approach is a working methodology, currently in use by key deferral demonstration projects, including the Brooklyn Queens Demand Management Program (a NWA project described in ConEd’s DSIP filing) and Central Hudson’s Targeted Demand Response program (described in their Distribution System Implementation Plan filed in June 2016). Based on our work, we have developed an approach that is applicable to utilities across the country and can assist in their transition to DRP 2.0. The simplified steps in this process include:

  1. Assess current capabilities
    1.  Analyze utility's current processes, hosting capacity, and load serving capability.
    2. Technical Analysis: System capacity analysis and deferral potential. Analysis of grid constraints and on integration and interconnection of DERs. Development of solution alternatives.
    3. Economic Analysis:  Valuation of local resources. Pricing and market analysis.
  2. Forecasting
    1. Granular demand and DER forecasting. Inclusion of DERs in infrastructure plans and assessment of impacts on grid safety and reliability.
  3. Procurement
    1. How and where to procure and implement distributed resources.
  4. Define Objectives
    1. Determine utility objectives and priorities. Incorporate state policy and utility commission regulatory mandates into planning.
  5. Create DRP 2.0 Plan
    1. Create an optimized and integrated resource plan designed to best meet utility objectives while delivering cost-effective and reliable energy.

Maximizing DER value is a long-term portfolio optimization project

DERs and demand-side management (DSM) work together to shave peaks and fill valleys in utilities’ local and system loads. The synergies between customer-side resources - including load control, distributed generation, energy efficiency, demand response, and storage - are already beginning to change grid scenarios for distribution planners.

  • Load Control – Targeted DSM shifts load away from peak times and can serve as energy storage (e.g. AC precooling and water heaters). Shifting usage coincident with production amplifies the value of inflexible generation.
  • Generation – Customer-side generation provides local energy resiliency, reduces reliance on distant generation, and offers a long duration.
  • Efficiency – Energy efficiency or conservation also reduces reliance on generation (both distant and local) and is “always on.”
  • Storage – It’s no wonder that storage was the hot topic of 2016. Storage is completely flexible, ramps quickly, provides voltage regulation, enables the staggering of fleets, and stores energy from inflexible generation for peak use.

To avoid or defer distribution investments, incremental DER distribution capacity needs to be procured in advance. If they show up at the last minute, unannounced and unaccounted for, there may not be enough lead time to incorporate them into planning. The approach for valuation and integration depends on the planning horizon and degree of uncertainty.

Emergency
Load Reductions

<1 year

  • Construction needs to happen
  • Reductions are only for temporary relief
  • Reduction needed exceeds contractual commitments

Contractual Targeted
Demand Management

2-5 years out

  • Specify the need and request DER bids
  • Price is based on competition, decreasing prices
  • Contractual obligation for DERs to address the local needs
  • If bid prices exceed the cost of T&D infrastructure do not procure
  • Once resources are contracted, treat as incremental capacity
    (but watch and reassess performance)

Incentivize permanent
reductions and shifting

5+ years

  • Focus energy efficiency and solar to adjust the growth trajectory
  • Requires location specific values that are time-differentiated
  • Provide long term price signal
  • Adjust signal as resources are added

While the value methodology is the same, each utility has its own landscape and horizon. Any DRP 2.0 analysis will need to take into account a wealth of historical load patterns, locational resources and unique generation constraints to assess the ability of DERs to deliver resources where they are most needed. Perhaps 2017 is the year to explore your own utility’s options for using a locational value methodology in the transition to DRP 2.0.