N.D. Admin Code 69-09-12-04 - Filing requirements

1. The resource plan must describe the:

a. Key data, assumptions, model inputs, information used in producing forecasts and models, and how uncertainties in assumptions were incorporated into the analysis;

b. Type, cost, and relevant operating characteristics of demand-side and supply-side resources considered and a description of the type and cost of additional transmission facilities necessitated by the resources;

c. Modeling and methodological approach to load forecasting, an assessment of load forecast uncertainty, and the cost and effectiveness of existing and future utility and state-sponsored conservation and load management efforts;

d. Projected load for the electric public utility over the planning horizon and the underlying assumptions for the projection. The information must be as geographically specific as possible and describe how the electric public utility will meet the projected load; and

e. Criteria used in determining the appropriate level of reliability, including any required reserve or capacity margin seasonal accreditation levels and how the determinations influenced the resource plan.

2. The resource plan must include:

a. A robust set of scenarios and sensitivities, including changes to the resource mix, fuel prices, load, resource costs, inflation, operating and maintenance costs, capital costs, transmission interconnection and network upgrade costs, congestion costs, renewable integration costs, and resource accreditation.

b. Reliability and resource adequacy assessments using quantitative metrics capturing the size, frequency, duration, and timing during extreme weather events and normal weather conditions for the fifth, tenth, and final year of the planning horizon. The assessment should include the annual expected unserved energy, the annual expected cost of unserved energy, peak seasonal capacity shortfall in megawatts, number of negative capacity shortfalls, average capacity shortfall in megawatts, longest hourly capacity shortfall, and number of hours requiring the utility to use the maximum available energy imports during a capacity shortfall.

c. Reliability and resource adequacy assessments using quantitative metrics, including expected unserved energy during correlated natural gas-fired generation fuel delivery outages for the fifth, tenth, and final year of the planning horizon.

d. A description of energy conversion facilities and associated interconnection and network upgrade and new transmission facilities the electric public utility intends to own and operate, or from which the utility intends to purchase energy output during the ensuing planning horizon, and the energy conversion facilities to be removed from service over the planning horizon.

e. Plans for energy conversion facility retirements, asset extensions, derates, market purchases and sales, and how scenarios affect cost, affordability, reliability, and resiliency.

f. To the extent possible, qualitative benefits and quantitative value of baseload and load-following generation resources and the value of proximity of such resources to load.

g. The estimated annual and total revenue requirement broken out by new and existing resources by cost category, such as generation, transmission, fuel, and energy efficiency.

h. Any other information as may be requested by the commission.

3. The resource plan must include information on:

a. Expansion of, improvements to, and more efficient use of existing electric public utility generation, distribution, and transmission facilities;

b. Opportunities for energy conversion facilities, including economic opportunities to partner with other utilities in constructing and operating new facilities and extending the useful lives of existing facilities;

c. Opportunities to pursue power purchase agreements with or develop baseload and load-following generation within the state;

d. Opportunities to pursue power purchase agreements, demand- or supply-side resources, or develop generation;

e. Distributed generation, including generating capacity provided by cogeneration technologies relying on renewable resources, nonutility generation, and other sources;

f. Recent or expected changes to generation dispatch across all generation technologies;

g. Opportunities for existing and planned transmission facilities to reduce congestion, transmission line losses, energy costs, and to increase export or import capability;

h. The accuracy of the peak demand and energy forecasts compared to the previous integrated resource plan forecasts and an explanation for the causes of any deviation from the previous integrated resource plan forecasts;

i. The risk of fuel supply disruption due to extreme weather or market events; and

j. How the electric public utility intends to reconcile potential jurisdictional differences in resource selection.

Notes

N.D. Admin Code 69-09-12-04

Adopted by Administrative Rules Supplement 2022-387, January 2023, effective 1/1/2023.

General Authority: NDCC 49-02-04

Law Implemented: NDCC 49-05-04.4, 49-05-17