## 1 Introduction  
Substation planning is heavily reliant upon identifying the proper capacity for its transformers. Substation bus work and breaker equipment is designed to support the total specified MVA output as defined by the transformer capacity, which can vary from utility to utility depending upon operating conditions [1]. Increased implementation of demand side management (DSM) to control high penetrations of energy storage (ES) applications and electric vehicle (EV) charging can greatly affect the demand profile substation transformers typically experience. When the effects of EV charging and ES applications are combined with the output of photovoltaic (PV) systems, the existing capacity limits of installed substation transformers can be affected. The nameplate rating of a transformer is based upon given criteria established by IEEE Std. C57.91-2011 [2]. The ratings are determined by identifying the MVA output (under specific operating conditions) that produces a specific transformer internal temperature, which dictates the normal and emergency capacity ratings of the unit [2]. Acceptable operating temperatures are established based upon safety limits for oil temperature and the location on the conductor windings that experience the highest temperature, which is commonly referred to as the hottest spot. Dielectric breakdown of the insulation occurs more rapidly at the hottest spot location. Transformer aging typically refers to the condition of the insulation at this winding location [2]. These standards, which measure hottest spot effects as a function of demand, allow utilities to compare the operation of units manufactured by different companies, who still must comply with the same rating standards [1]. The utilized capacity of a transformer, which may be different from the actual nameplate rating, is usually tied to the end of life of a given unit [1]. Utilities determine the units capacity limits by identifying the peak output that a unit can produce without severely reducing the amount of expected life, which is estimated at approximately 180,000 h or 25 years [2]. Many transformers in use today were designed or specified based upon a specific peak energy demand and load factor. As the penetration of distributed energy resources (DER) increases on the distribution system, utilities will seek to control their usage and output through DSM programs to optimize the operation of the grid, prolong the need for adding capacity, prevent the need to run less efficient peaking generators, and prolong the life of distribution and transmission equipment [3]. Unfortunately, in high penetrations these energy applications augment the load profile typically experienced by a substation transformer [4; 5]. The power industry paradigm that has been in existence for nearly a century is changing from one that leans heavily upon centrally owned power plants to one that consists of thousands of energy suppliers in the form of residential PV and ES systems. The increased number of sources, which are not directly controlled by utilities, introduce uncertainty in the stability of the system. To promote stability and increase overall system efficiency, utilities and government agencies implement numerous programs to indirectly control residential generation and energy usage. For cases where the penetration of customer participation is high, substation transformers may experience operating conditions sufficient to lower existing capacity limits [6]. substation transformer derating due to a DSM program was first documented in the publication by Staats, which attempted to address transformer capacity derating due to high penetrations of electric vehicle (EV) charging [7]. High penetrations of PV systems, ES applications, and EV charging can severely modify the characteristics of a power transformer's daily load profile, which historically allowed for a cooling down period at some point during the day [1; 2; 6; 8].