1. A. An electric system planning process shall align with the following components for each planning cycle and scenario and related requirements specified in this chapter:

   1. (1) Considerations feeding into types of projections;
   2. (2) Goals/ objectives;
   3. (3) DER forecast;
   4. (4) Load forecast;
   5. (5) Hosting capacity assessment;
   6. (6) Grid needs and locational value assessment;
   7. (7) Identify possible solutions to grid needs;
   8. (8) Screen and evaluate possible solutions;
   9. (9) Choose solutions and publish plan;
   10. (10) Program and project design; and
   11. (11) Assess results.

2. B. Considerations Feeding into Types of Projections.

   1. (1) Time Horizons for DER and Load Forecasting.

      1. (a) DER and load forecasting processes for electric companies other than electric cooperatives and municipal electric companies shall include at least three planning time horizons:

         1. (i) 1 to 3 years;
         2. (ii) 4 to 6 years; and
         3. (iii) 7 to 10 years.

      2. (b) DER and load forecasting processes for electric cooperatives and municipal electric companies shall include at least two planning time horizons:

         1. (i) 1 to 3 years; and
         2. (ii) 4 years up to 20 years.

   2. (2) Level of Granularity. The granularity of information in an electric system plan may vary as described in other sections of this regulation.

      1. (a) As a near-term objective:

         1. (i) Information shall be provided in an Electric System Plan at the substation level; and
         2. (ii) Feeder-level information shall be provided as part of the planning process for feeders where there are identified system constraints;
      2. (b) As a longer-term objective, electric companies shall report on progress regarding incorporating more granular electric system and customer information and data into forecasting and planning processes in their electric system plan or annual electric system plan update.

   3. (3) Scenarios/Projections to be Analyzed. An electric system plan shall include a minimum of two scenarios to provide a range of outcomes to inform planning analysis and the determination of the scale and pace of grid needs:

      1. (a) A baseline scenario; and
      2. (b) A goal scenario.
      3. (c) The Commission may request an electric company to analyze scenarios in addition to a baseline scenario and goal scenario.

   4. (4) Data Sources, Scope, and Access. Electric companies shall provide for data collection and access that:

      1. (a) Allows stakeholders the opportunity to provide data inputs at pre-identified time periods defined by the electric company;
      2. (b) Provides collected data in a format that can be easily accessed by stakeholders; and
      3. (c) Provides stakeholders transparency into data sources, data and assumptions used to develop electric system plans and annual electric system plan updates.
   5. (5) Already-Approved Resource Retirements and Additions. Electric companies shall consider in their electric system plans whether distribution-level electric system planning can be used to mitigate potential gaps caused by generation retirements.
   6. (6) PJM Wholesale Markets. Electric companies shall consider DERs and VPPs that participate in the PJM wholesale markets in electric distribution planning as applicable.
   7. (7) Resource Costs and Capabilities. Electric companies contracting decisions to implement electric system plans and annual electric system plan updates shall be left to electric company discretion.
3. C. Goals/Objectives. An electric system plan shall promote applicable State policy goals pursuant to Public Utilities Article, §§7-801—7-804, et seq., Annotated Code of Maryland, and other applicable goals and targets as directed by the Commission.

4. D. DER Forecast. An electric system plan shall account for the following considerations for each electric system planning cycle and scenario.

   1. (1) Electric companies shall develop separate forecasts for each relevant DER type, including energy efficiency, demand response, distributed generation, energy storage devices, VPPs and managed EV charging-discharging.
   2. (2) Electric Companies shall develop hourly DER forecasts.

5. E. Load Forecast. Load forecasts shall account for the following considerations for each planning cycle and scenario as follows:

   1. (1) Electric companies shall incorporate load impacts of current and future transportation and building electrification based on known information and assumptions; and
   2. (2) Electric company distribution-level forecasts in aggregate shall be aligned to a reasonable extent with available electric company developed transmission-level forecasts and with PJM-developed system-level forecasts with an explanation provided in electric system plans for any differences and the associated factors, including differences in assumptions.

6. F. Hosting Capacity Assessment. An electric system plan shall account for the following considerations for each planning cycle and scenario.

   1. (1) Hosting capacity calculations shall be determined using a circuit-specific calculation including installed and forecasted DER interconnections.
   2. (2) DER forecasting shall be incorporated into reserve hosting capacity determinations and the rightsizing of hosting capacity upgrades.
   3. (3) Electric companies shall establish methodologies for calculating available hosting capacity and, in the annual electric system plan update and electric system plan, discuss planned hosting capacity capability improvements.

7. G. Grid Needs and Locational Value Assessment.

   1. (1) Grid Needs Assessment.

      1. (a) An electric company’s grid needs assessment shall include current and forecast distribution substation and feeder constraints identified as part of each planning cycle, including the timing, magnitude and other relevant characteristics for each identified system constraint.
      2. (b) The annual electric system plan update shall discuss changes to an electric company’s grid needs assessment that may occur between planning cycles.
      3. (c) Electric companies shall cost-effectively pursue industry best practice methods and analytical tools to improve their planning analysis and processes, the choice of which to adopt shall be at the discretion of the electric companies.

   2. (2) Locational Value Assessment.

      1. (a) An electric system plan shall provide locational value for each identified electric system constraint.
      2. (b) Locational value shall include the potential deferral or avoided value of a traditional wires solution.
      3. (c) Electric companies shall develop a locational value assessment using the Commission's uniform benefit cost analysis framework.
      4. (d) Electric companies shall report on the progress towards implementation of locational value assessments at annual technical conferences.

8. H. Identify Possible Solutions to Grid Needs. An electric system plan shall account for the following considerations for each planning cycle and scenario:

   1. (1) Near-Term Objective.

      1. (a) An electric system plan shall identify solutions for identified grid needs.
      2. (b) Electric companies shall identify non-wires solutions considered to address system constraints.
      3. (c) For any proposed upgrade projects resulting from Regulations .03H and .03I of this chapter, future hosting capacity constraints that incorporate DER forecasts shall be considered.

   2. (2) As A Longer-Term Objective.

      1. (a) Electric companies shall assess the feasibility of utilizing new cost-effective technologies and methodologies for solutions to grid needs.
      2. (b) Electric companies shall report on the progress towards utilizing new cost-effective technologies and methodologies at annual technical conferences.
   3. (3) Pursuant to Public Utilities Article, §7-804, Annotated Code of Maryland, electric companies shall consider investment in, or procurement of cost-effective demand-side methods and technology to improve reliability and efficiency, including VPPs.

9. I. Screen and Evaluate Possible Solutions.

   1. (1) An electric company shall screen and evaluate possible solutions for each planning cycle and scenario.

   2. (2) The electric system plan shall include the criteria used to evaluate possible solutions, including cost-effectiveness considerations.

      1. (a) Electric companies shall evaluate cost-effectiveness for alternatives considered, if applicable.
      2. (b) Electric companies shall utilize the Commission's Unified Benefit Cost Analysis framework for solutions involving DERs in determining cost-effectiveness.

10. J. Choose Solutions and Publish Plan. An electric company shall choose a solution or solutions for each scenario and publish a plan for each planning cycle as described in Regulation .04 of this chapter.

    1. (1) Electric companies shall present their rationale for solution selection in electric system plans, including why alternative solutions were not selected.
    2. (2) Information and data shall be provided in an electric system plan at the substation level.
    3. (3) When project solutions are proposed in response to system constraints, electric companies shall provide feeder-level information, where applicable.

11. K. Program and Project Design.

    1. (1) Program and project design including construction, procurement, and electric company contracting are factors in the electric companies’ mandate to provide safe and reliable service and a consideration in overall cost which shall be estimated in electric system plans.
    2. (2) Program and project design including construction, procurement, and electric company contracting decisions shall be left to electric company discretion in executing an electric system plan although these factors will remain subject to review in rate cases.

12. L. Assess Results. An electric company shall account for the following considerations for each planning cycle:

    1. (1) An electric company shall assess the results of their electric system plans to determine lessons learned and changes to future planning assumptions.
    2. (2) Rate case filings shall provide explanations for projects that do not reconcile with electric system plans.

Authority: Public Utilities Article, §§1-101, 2-113, 2-121, 7-216, and 7-801—7-804, Annotated Code of Maryland

Effective date: November 24, 2025 (52:23 Md. R. 1140)