39 Miss. Code. R. 1-29- 107
All regulated gas and electric utilities shall report to the Commission annually on their efforts to improve energy delivery, through modernization of existing infrastructure, improvements to lower energy delivery costs ( e.g., by expanding access to supply alternatives or relieving congestion in the delivery system), and/or through expansion of energy delivery to additional customers.
Within sixty (60) days of the Commission's final approval of this Rule, each utility subject to the provisions herein shall present for Commission approval a proposed plan or schedule according to which the utility will meet the reporting requirements of the Annual Energy Delivery Plan. At a minimum, the Annual Energy Delivery Plan shall include the information referenced in Subsections 1-6 below, and each utility's Annual Energy Delivery Plan shall be reviewed by the Staff. If the Staff believes the use of consultants is necessary or helpful in its review of a utility's Annual Energy Delivery Plan, the utility shall be required to pay for the cost of such consultants and allowed to recover said costs in rates.
Electric and Gas Utilities regulated by the Commission shall implement a Demand Side Management ("DSM") Portfolio for customers that is designed to achieve cost-effective energy and/or demand savings, considering factors such as: quantifiable and achievable savings, customer reliability benefits, cost effectiveness, rate impacts, and customer interest and participation potential. The Annual Energy Delivery Plan shall include a description of all programs in the DSM portfolio.
Well- designed DSM offerings provide opportunities for customers of all types to adopt energy efficiency and demand saving measures to increase control and provide greater opportunities to reduce their energy bills. For purposes of this rule, demand-side management includes energy conservation, energy efficiency, demand response, distributed energy resources, and strategic load growth as specifically defined herein.
Energy conservation and efficiency may include educating customers about practical tips and ideas to reduce energy usage (e.g., suggested winter and summer thermostat settings) and reducing the rate at which energy is used by equipment and/or processes while maintaining or improving the customer's existing level of comfort and end-use functionality. Such reductions in energy usage may be achieved, for example, by substituting more advanced technology or improving the thermal properties of a building. Energy conservation programs can be included in portfolios of energy efficiency plans.
Demand response offerings lower peak demand. Options may include direct load control efforts ( e.g., via air conditioner cycling) and interruptible rates (providing rate discounts in exchange for the right to reduce a customer's energy demand during a specified number of hours each year coinciding with high energy demand and/or emergency conditions). Distributed energy resources ( e.g., energy storage) are another option.
Strategic load growth may benefit customers through increased use of utility services resulting in potentially decreased customer rates. Strategic load growth may occur as a result of new customers being added to the utility's system (e.g., through economic development), or it may consist of growth in the loads of existing customers (e.g., electric vehicles or industrial electric process equipment that is more economical for a customer). The purpose of strategic load growth programs should be to incentivize the more efficient usage of utility infrastructure and resources. In order to ensure that strategic load growth programs are beneficial to all customers and do not conflict with energy efficiency policies established in this Rule, any strategic load growth project or program shall require Commission approval.
Strategic load growth may also address the Commission's statutory policy objective to foster, encourage, enable and facilitate economic development in the State, and to support and augment economic development activities, and to take every opportunity to advance the economic development of the State. This may include the encouragement of universal access to utility services through infrastructure expansion to areas that currently do not have such services.
Cost-effectiveness tests measure and value the benefits and costs of demand-side management investments relative to long-term supply options. Evaluation of cost-effectiveness is only one aspect of long-term integrated resource and energy delivery planning; enhancing reliability and managing potential risks must also be considered in the planning process.
Electric and Gas Utilities must demonstrate that they have evaluated the cost-effectiveness of their proposed demand-side management investments at a portfolio level using at least three industry-accepted tests, including the Total Resource Cost test and the Utility Cost Test, and provide results of the analysis within the Annual Energy Delivery Plan filing. The results of the analyses should also provide details on the reliability and risk impacts of the utility's planned demand-side management investments.
Electric and Gas Utilities shall also include in their Annual Energy Delivery Plans the inputs and assumptions used in their cost-effectiveness analyses. The near-term and longer-term impacts on customers and on utility financial integrity must be factored into the final decision to proceed or not to proceed with any demand-side management investment.
The primary goal of demand-side management is to defer or avoid energy usage and for customers to achieve the concomitant savings without requiring them to involuntarily sacrifice comfort or reliability, or accept undue risks. Additionally, demand-side management can be useful in reducing customer demands which, in the long run, may reduce or delay investments in fixed costs needed to meet peak demands (e.g., generation, bulk transmission). Further goals include providing new and innovative options to customers to help meet their energy needs, mitigating environmental impacts, and fostering increased modernization of the energy grid. The Commission recognizes and accepts that this goal of avoiding energy usage, if not properly addressed, can be detrimental to utilities and their owners under traditional cost-of-service ratemaking, especially where utilities are adequately meeting their obligation of producing low-cost, reliable energy services. For utilities operating under formulary rate plans, reduced revenues resulting from energy efficiency measures are already addressed in the existing plans. The Commission recognizes, further, that accomplishing the goals of demand-side management requires actions on the part of both the utility and its customers, which is different from actions associated with a utility adding a new supply resource. Therefore, utilities shall be allowed an opportunity to recover the reasonable and prudent costs incurred by them in making demand-side management investments, including, where applicable, an opportunity to earn a reasonable return thereon.
In its Energy Delivery Plan, each utility may propose an approach to earn a return on demand-side management investments in its Formula Rate Plan in order to place such investments on more equal footing with other supply-side resource and infrastructure investments on which utilities earn a return. Each year, the utility shall identify in its Energy Delivery Plan the specific demand-side management investments on which the utility seeks to earn a return as well as the specific demand-side management costs the utility intends to expense in the upcoming calendar year. The method reflected in the Energy Delivery Plan shall also be reflected in each utility's annual Formula Rate Plan filing and subject to approval by the Commission as part of the annual Formula Rate Plan review.
Demand-side management investments may include, but are not limited to, equipment, incentives and rebates, marketing and delivery, direct installation costs (including plumbing installations), and any administration costs. Incentives may include information, technical assistance, leasing programs, product promotions and direct financial inducements. Financial inducements may include, but are not limited to, rebates, discounted products and services, appliances and alternative financing arrangements. Any financial inducements undertaken by a utility intended to be reflected in the utility's rates, must be incorporated under and meet the cost effectiveness requirements described in this rule.
Utilities may also propose a mechanism to adjust budgets and cost recovery to respond to customer demand, to take advantage of market opportunities, to deal with oversubscriptions and to avoid stop-start funding.
Cost recovery should be addressed in each utility's formula rate plan and demand-side management expenditures, including any prudently incurred over or under recovery of actual expenditures in an annual period, may be allowed in the formula rate plan test year.
Every three years, unless modified by the Commission, the Staff may review and comment on the cost recovery approach(es) utilized by each utility with respect to demand-side management investments and expenditures.
Third-party evaluation, measurement and verification ("EM&V") shall not be required where the utility offers to provide its analyses used in evaluating demand-side management investments to the Staff and any public witnesses in conjunction with the Evaluation of Demand-Side Management Offerings. Where a utility chooses not to make its analyses available, the utility shall contract with an independent third-party vendor to conduct EM&V, utilizing accepted industry standards, and shall file the report of the third- party vendor with the Commission. If Staff believes the use of consultants is necessary or helpful in its review of a utility's EM&V analyses, the utility shall be required
to pay for the cost of such consultants and allowed to recover said costs in rates.
Anticipated investments in DERs should be included as an appendix to the Annual Energy Delivery Plan developed by each utility. Recovery of demand-side management investments should be addressed in each utility's formula rate plan as a known and measurable change.
All regulated electric utilities shall also include as an Appendix to their Annual Energy Delivery Plan the annual avoided cost calculations utilized in connection with the Mississippi Renewable Energy Net Metering Rule.
Each electric utility shall also include in its Annual Energy Delivery Plan a list of new transmission lines and other associated facilities which are under construction or for which there are specific plans to be constructed during the relevant planning horizon, including capacity and voltage levels, location, cost estimates and schedules for completion and operation, to the extent such have been developed. This includes reporting relevant collaborative transmission planning projects occurring within the context of any regional planning organization such as the Midcontinent Independent System Operator or the Southeastern Regional Transmission Planning group.
To the extent practical, the utility shall include similar information about its distribution plans. The utility shall also include a discussion of the adequacy of its transmission and distribution systems, including the reliability, resiliency and storm hardened condition of the transmission and distribution systems.
Reasonable and appropriate vegetation management is essential to ensuring the resilience, as well as protecting the safety, of the energy grid and related environment. Effective vegetation management, along with other grid resiliency measures, are important factors in the prevention of and recovery from electric system outages. The Commission, however, recognizes that factors outside the utility's control, such as weather, can significantly impact the need to change vegetation spending from year-to-year. Similarly, federal mandates to address grid resiliency are also often outside the utility's control.
To allow utilities to effectively manage vegetation growth and to more quickly improve grid resiliency at the distribution level, the Commission shall allow utilities exact recovery of all such related contract work costs. Therefore, utilities may remove all vegetation management contract work costs and Commission-approved grid resiliency costs from base rates and reflect them through an alternative exact cost recovery mechanism. If a utility continues recovery in its Formula Rate Plan, such utility may defer and amortize such costs over five years with Commission approval.
Any such costs treated pursuant to this Section that are approved for alternative cost recovery shall be audited by the Staff in its review of the utility's Annual Energy Delivery Plan. Every four years, unless modified by the Commission, the Staff shall review and comment on the vegetation management plans of each electric utility. If the Staff believes the use of a consultant is necessary or helpful in its review of a utility's vegetation management plan, the utility may be required to pay for the cost of such consultant and to recover said costs in rates.
In its Annual Energy Delivery Plan, the utility shall address how it proposes to reach low-income customers in relation to planned demand-side management and DER investments. The utility shall also address whether it proposes to provide demand-side management offerings directly or indirectly through financial support of programs for low-income households. To foster increased demand-side management and DER investments that will benefit low-income customers, the Commission shall exempt from the proscriptions set out in Chapter 22 of these Rules and allow recovery as cost of service of up to $350,000 per year of utility charitable contributions to non-affiliated organizations that directly aid low-income customers to foster increased access to demand-side management and DER options. To further workforce and economic development, utilities shall be allowed to recoup as cost of service an additional $350,000 per year of utility charitable contributions for STEM scholarships for minorities and scholarships for training in the utility industry and to non-profit and state or local governmental entities that provide early childhood education, workforce development, and career and technical training.
The Commission also recognizes that, for many customers, lacking access to affordable capital impedes adoption of demand-side management and DER. To encourage the development by utilities of tariffed on-bill offerings and on-bill financing options, any Commission-approved tariffed on-bill offering or on-bill financing program that focuses on demand-side management or DER 1 shall be exempt from Rule 8.125.2 of the Commission's Rules and Regulations Governing Public Utility Service.
The Commission recognizes that existing and emerging technologies and information, and the data such technologies provide, may enable more efficient, cost-effective, and reliable service. Increased broadband access and the security, storage, and use of data are two examples. The Commission recognizes the benefits of utilities accumulating, storing, and utilizing customer data to improve service, enhance reliability, and provide new and innovative offerings to customers, and therefore recognizes that customer data is affected with the public interest. Recognizing that customer data has inherent value and should be protected from public disclosure, public utilities are hereby entrusted as the custodians of customer data and should seek to capture that value for the benefit of customers as approved by the Commission. Utilities also must ensure that customer data is reasonably secure. Within the Annual Energy Delivery Plan filing, the utility shall set out its perspective on the availability and benefits of existing and emerging technology and how the utility is utilizing customer data as it relates to enhancing utility service.
While ensuring service at the lowest, reasonable cost is a hallmark of the Commission, the public interest is served by improving reliability (e.g., resiliency and storm recovery and hardening and grid modernization), promoting economic development (e.g., attracting businesses to locate or expand) and providing customer access to enhanced services (e.g., expanding natural gas service and new technologies to aid in providing public utility service). The Commission encourages utilities to make new investments that incorporate, in some measure, all three components.
To encourage investment of the type mentioned above and which are hereby deemed to promote the public interest, the Commission creates by operation of this Rule what shall be known as Enhanced Grid Investments ("EGI"). Utilities are authorized under this provision to make EGI up to $25 million annually. Anticipated EGI shall be designated as such in the Annual Energy Delivery Plan, and the Staff shall review EGI to confirm that the designated EGI is reasonably likely to improve reliability, promote economic development and improve customer access to modern service during the depreciable life of the investment. EGI implemented pursuant to this provision shall not require a facilities certificate, unless comprised of new generation and transmission. EGI investment shall be depreciated over the life of the asset but in no event sooner than 10 years from the in-service date. Nothing herein precludes a utility from proposing in its Annual Energy Delivery Plan additional investments supporting reliability, economic development or new technologies in excess of the amount described in this provision.
Expansion of fiber optic infrastructure is of particular importance to the Commission because such expansion is consistent with a number of policy drivers that underlie public utility regulation, including the availability of adequate and reliable service, continued service to customers consistent with the level of service needed to promote the public welfare, and with the authorization and empowerment provided by the Legislature to the Commission to take every opportunity to advance the economic development of the state. As with reliability benefits, the benefits of fiber optic infrastructure - while real - are difficult to quantify. To allow utilities to more quickly modernize their services and communications through fiber infrastructure expansion, utilities that are rate regulated by the Commission may, on an annual basis, invest up to $10 million in fiber infrastructure (or other utility communication technology that could, as a secondary benefit, enable internet access) that extends to the utility's customers' premises. Such investment shall be recorded to a regulatory asset to be included in the utility's rate base, subject to Commission approval in the utility's annual formula rate plans, and shall be amortized over a period no longer than ten years. Because of the inherent, yet difficult to quantify benefits of such investments, no cost/benefit analysis shall be required.
This section shall be revisited five (5) years after the effective date of this Rule.
Anticipated investments in demand-side management and DERs shall be included as Appendix A to the Annual Energy Delivery Plan developed by each utility in accordance with this Rule. This report also shall include:
If Staff finds, after reviewing a utility's Appendix A, that a demand-side performance measure is not sufficiently promoting adequate investment, then Staff may recommend that the Commission establish an individual savings target for the utility. The Commission may hear the matter after proper notice and issue an appropriate order.
1 Any such programs require and shall continue to require to separate Commission approval prior to implementation.
39 Miss. Code. R. 1-29- 107