Chapter One: In The Beginning
The Distribution Resource Planning (DRP) process was both a response to fundamental changes in electricity markets and an attempt to shape the course of future changes in ways that would minimize overall system costs and maximize ratepayer benefits. One goal was to establish a new framework for the integration and operation of new Distributed Energy Resource (DER) technologies.
DER includes, but is not limited to: distributed renewable generation, energy efficiency, energy storage, electric vehicles, and demand response technologies. While many perceived the introduction and integration of these resources as a way to provide additional flexibility and visibility into even the most remote levels of the utility distribution grid, others saw an even greater potential for a market-based revolution that could forever change the utility distribution model.
In the aftermath of the Western Energy Crisis of 2001-2002, California had created the Energy Action Plan and Energy Action Plan II which established a vision for resource diversity and aligning new procurement with the state’s environmental objectives. In this document, the state priorities energy efficiency, demand response and distributed generation (all items in the DRP category) as top priorities. From these planning documents, the state launched multiple initiatives and incentive programs meant to increase resource diversity, to encourage renewable energy integration, and contribute to ambitious greenhouse gas reduction targets that were enacted via Gubernatorial executive orders and legislation, particularly AB 32 (2006), which required a reduction in greenhouse gas emissions to 1990 levels by 2020.
In addition to pioneering Renewable Portfolio Standard (RPS) goals for utility-scale alternative energy projects acquired via competitive solicitations, there was the California Solar Initiative (CSI) that set a 10-year goal for the regulated utilities to add 1,940 MW of small-scale solar photovoltaic (PV) units throughout the state at an expected cost of $2.37 billion.
Net Energy Metering (NEM) programs, though hard fought by utilities around the country, were blossoming in California, as homeowners could not only reduce their use of electricity from utilities by installing rooftop PV, but also offset their retail electric rate by injecting more energy into the grid than they used each month. In 2014, there were over 160,000 residential and small commercial NEM customers; by March 2015, that number would more than double to 325,000 NEM accounts.
Customer Adoption of Rooftop Solar in California, 1993-2019
The Self-Generation Incentive Program (SGIP) provided direct subsidies for the installation of customer-sited generation in the territories of investor-owned utilities (IOUs) under the jurisdiction of the CPUC. By 2014, the IOUs were providing over $75 million in direct support for behind-the-meter installations.
These and other initiatives greatly increased requests for interconnection from customers to the IOUs and local permitting agencies. And the utilities were beginning to express concern to regulators about potential adverse impacts on their distribution systems – which were never designed to accommodate such an influx of small-scale resources that could both alter customer load patterns and feed electricity back into the utility networks.
To break through a backlog of interconnection requests, the Commission led a nationally recognized settlement process to streamline its Rule 21 Interconnection Policies. The new regime updated the “fast track” process for connection applications. If customers/developers passed several screens that indicated the new resource would have limited impact on the grid, they could avoid costly and time-consuming engineering impact studies for their DER projects.
Along with this new process, the CPUC required electric utilities to report on the number of fast-track interconnection requests and their processing backlogs, beginning in the first quarter of 2014.
Immediately, the numbers were astounding.
Pacific Gas & Electric Company (PG&E), which was requiring some form of screening for every interconnection request no matter the size of the project or which support program it relied upon, had already been hit with over 35,000 interconnection requests and was having a hard time keeping up. Once fast-track kicked in, the numbers climbed from about 9,000 in the first quarter of 2014 to nearly 20,000 just a year later. Hundreds of fast-track applications were being delayed or kicked into more extensive engineering studies because the utility just could not process them fast enough.
And there was every indication that the avalanche would continue for the foreseeable future – which turned out to be the case, as illustrated by the two charts below (based on PG&E’s quarterly interconnection reports to the CPUC):
While the other electric investor-owned utilities (San Diego Gas & Electric Company and Southern California Edison Company) were not reporting the same level of interconnection activity, they raised serious concerns that on certain circuits, in certain parts of their service territories, the number of PV systems and in-home electric vehicle charging load could cause reliability problems. San Diego Gas & Electric Company (SDG&E) reported that some of its circuits were seeing PV penetration at 35 percent or more of the rated line capacity – when the engineering rule of thumb traditionally limited such interconnections to just 15 percent.
Where the IOUs saw potential challenges for traditional grid operations, DER developers saw opportunities for market growth. Looking beyond the installation of individual solar units and capture of tax credits, some companies foresaw the ability to aggregate multiple DER units into a resource that could potentially participate in wholesale markets managed by the California Independent System Operator (CAISO) and/or serve the distribution grid.
At the same time, clean energy proponents and consumer/ratepayer advocates believed that DER, if planned and managed properly, could eventually displace – at a lower cost – the need for expensive central-station generation, high-voltage transmission, and distribution infrastructure.
In the previous decade (from 2003-2012) CPUC jurisdictional utilities’ total distribution revenue requirements increased from $4.8 billion to $7.2 billion. According to Commission reports to the state Legislature, these increases in distribution costs were primarily due to capital additions and infrastructure improvements to the distribution system. Transmission revenue requirements were increasing at an annual rate of between 8.8 percent and 14.4 percent.
Certainly, to accommodate distributed resources there might be a need for utilities to invest in some system upgrades, but “non-wires alternatives” were anticipated to be more cost-effective than central station additions and grid expansions.
By the mid-2010s, these market trends, policy initiatives and visionary proposals were all converging on a new paradigm for utility distribution systems. What was needed were legislative and regulatory pathways to develop a comprehensive vision and structure for realizing the potential of DER and overcoming its technical challenges.
“The thinking at the time was that the grid was undergoing an evolution,” recalled Erik Takayesu (Vice President, Transmission, Substations, and Operations, Southern California Edison). “The grid would evolve from the traditional one-way system to a two-way system, integrating more distributed energy resources and eventually converging across different energy sectors. The DRP proceeding intended to outline a multi-phased focus starting with foundational enhancements in distribution planning and leading towards modernizing the grid. We’ve generally stayed on course. There’s been a number of innovations and improvements to distribution planning and identifying the technologies required to modernize the grid, and a lot of engagement with stakeholders.”
From these circumstances emerge the legislative and regulatory underpinnings of the DRP.