distributed energy resources

Recently, the staff of the New York State Department of Public Service issued its recommendations in the Value of Distributed Energy Resources Proceeding. The 68-page report provides a comprehensive discussion regarding the compensation and valuation of distributed energy resources (DER). Among its many recommendations, the report provides that existing rooftop solar systems should continue to receive compensation under their current net energy metering (NEM) contracts for a period of 20 years from the date of initial operation. However, customers can also leave NEM and adopt the new proposed compensation method. Other recommendations include:

  • Utilities would develop fee-based, “Virtual Generation Portfolios” – a pool of new DER projects that will be developed in conjunction with private energy companies.
  • Interim measures for Community Distributed Generation (CDG) projects that are in the advanced stage of development. For a limited 90-day period, a specific amount of CDG projects can qualify for compensation under the current NEM framework in order to aid the transition to the new methodology and ensure that early CDG development can deliver on increasing DER access to all New Yorkers.
  • Distributed Generation projects, such as solar for large commercial customers, fuel cells, farm waste generators and micro combined heat-and-power would also transition to the new methodology following action by the New York Public Service Commission.
  • Behind-the-meter generation should be recognized for its environmental value and for contributing to the state’s overall Clean Energy Standard (CES) goal. 

Initial comments on the report are due December 5, 2016, with reply comments due December 19, 2016. Action by the New York Public Service Commission on these recommendations is expected in January 2017. 

The Public Utilities Commission of California (CPUC) recently introduced a draft regulatory incentive proposal addressing issues regarding the utilities’ business models, financial interests and role with respect to distributed energy resources (DER) deployment. Given the potential magnitude of this rulemaking to the utilities’ business models, I suggest that utilities and other stakeholders nationwide follow this docket closely.

The pilot program is offering regulatory incentives to the state’s three large investor owned utilities (IOUs) for the deployment of cost-effective DERs. The current proposal offers a shareholder incentive for the deployment of cost-effective DERs that displace or defer a utility expenditure, based on a fixed percentage of the payment made to the DER provider (customer or vendor). Below is a quote from the order that explains the concept:

“There are two roadblocks . . . to understanding financial value. Many in the regulatory community believe that:  (1) the utility’s return on equity is the sole value driver; and (2) regulators set returns on equity at a rate equal to the cost of equity. Neither of these perceptions is correct, and understanding why is key to developing effective utility incentive mechanisms. 


Many regulatory reform discussions focus on the utility’s return on equity as the sole driver of financial value, but that does not align with the concept of investor value creation. It is not the absolute level of a company’s return on equity (r), but rather the difference between r and its cost of equity (k), that creates the value opportunity that drives the stock price. (Appendix B, p. 6)

This discussion leads to the following correction to the investment incentive proposition espoused by many:

INCORRECT:  r > 0 utilities have an incentive to expand 

CORRECT:  r > k   utilities have an incentive to expand 

  r = k   utilities are indifferent as to whether they expand

  r < k   utilities have a disincentive to expand Capital, like any other input to a production process, is not free.

This should have intuitive appeal. Does it seem likely that utilities would rush to expand their facilities if regulators allow them to earn, for example, a 2 percent return on such investment? Clearly there is some minimum acceptable level of return. The cost of capital, by definition, is that minimum return hurdle.

This corrected incentive structure should give some readers pause. Many, if not most, regulators say that they set utility rates of return equal to the cost of capital. If that condition held, utility management focused on creating value should not care whether it ever makes any plant investment. Just as buying apples for 50 cents and selling them for 50 cents creates no value for the grocery store owner, raising capital at a cost of 10 percent to invest in assets that earn 10 percent is similarly a financial wash—no matter how large the investment, it creates no investor value. (Appendix A, p. 3)” 

Comments and responses to the questions are to be filed no later than May 2, 2016. Reply comments may be filed not later than May 16, 2016. Some of the questions to be addressed are:

  • Is the proposed incentive, in the range of 3.5% grossed up for taxes, approximately correct?
  • Are there other disincentives to the deployment of DERs that this proposal does not address that should be considered at the same time? If so, please explain.  
  • Is the suggested process for identifying and approving DER projects that would generate an incentive reasonable and appropriate? How could the process be improved? 

The Electric Power Research Institute (“EPRI”) has launched a three-phase initiative regarding distributed energy resources (“DER”) and grid integration. Phase I was completed this month with the release of The Integrated Grid, Realizing the Full Value of Central and Distributed Energy ResourcesIt is a concept paper designed to frame the issues necessary for consideration by stakeholders such as utilities, regulators, and customers, as well as distribution and DER vendors. DER includes forms of electric generation supply such as small natural gas-fueled generators, combined heat and power plants, electricity storage and solar photovoltaics (PV) on residential rooftops and in larger arrays. Typically, these generation sources must be connected to the distribution system. One of the most significant and important elements of the report is that it highlights a critical distinction between connection and integration. Being connected to the grid is not the same as being integrated into the grid.

In most service territories, the current distribution system was not designed to accommodate an expansive amount of DER while sustaining high levels of electric quality and reliability. Unlike centralized power plants, technical characteristics of certain types of DER, such as variability and intermittency, present challenges that must be addressed to facilitate long term grid integration. According to the report, in order to maintain established standards of quality and reliability, DER must be integrated into the planning and operation of the electric grid. To facilitate DER’s integration, the report presents a call to action in four key areas:

  1. Interconnection Rules and Communications Technologies and Standards
  2. Assessment and Deployment of Advanced Distribution and Reliability Technologies 
  3. Strategies for Integrating Distributed Energy Resources with Grid Planning and Operation
  4. Enabling Policy and Regulation

Phase II of the initiative will encompass a six-month project to develop a framework for assessing the costs and benefits of the combinations of technology that lead to a more integrated grid. Phase III will include demonstrations and modeling using the analytics and procedures developed in Phase II to provide comprehensive data and information to stakeholders, hopefully yielding successful and cost effective integration of DER.

With another round of storms expected to yet again pound most of the East Coast this weekend, let me remind everyone to acknowledge the first responders braving often dangerous conditions to restore and maintain your electricity. It has been a rough winter and many may feel like they are always losing power. However, this fact from the report reminds us that electricity is usually there when we need it:

Today’s power system has served society with average annual system reliability of 99.97% in the U.S., in terms of electricity availability.

– The Integrated Grid, Realizing the Full Value of Central and Distributed Energy Resources, page 9.

Later this year, NIST expects to release a draft of the Framework and Roadmap for Smart Grid Interoperability Standards (“Framework”) document for a formal 60-day public comment period and the final version of the document is planned for publication in the first half of 2014. However, those attending the SGIP Inaugural Meeting received an advanced look at the new Framework.

NIST says the smart grid will ultimately require hundreds of standards. To prioritize its work, NIST chose to focus on seven key functionalities plus cybersecurity and network communications. Together, they create nine priority areas:

  • Demand response and consumer energy efficiency: Provide mechanisms and incentives for utilities, business, industrial and residential customers to modify energy use during times of peak demand or when power reliability is at risk. Demand response is necessary for optimizing the balance of power supply and demand.
  • Wide-area situational awareness: Utilizes monitoring and display of power-system components and performance across interconnections and over large geographic areas in near real-time. The goals of situational awareness are to understand and ultimately optimize the management of power-network components, behavior and performance, as well as to anticipate, prevent, or respond to problems before disruptions arise. 
  • Distributed Energy Resources (DER): Covers generation and/or electric storage systems that are interconnected with distribution systems, including devices that reside on a customer premise, “behind the meter.” DER systems utilize a wide range of generation and storage technologies such as renewable energy, combined heat and power generators (CHP), fixed battery storage and electric vehicles with bi-directional chargers. 
  • Energy Storage: Means of storing energy, directly or indirectly. The most common bulk energy storage technology used today is pumped hydroelectric storage technology. New storage capabilities — especially for distributed storage — would benefit the entire grid, from generation to end use.
  • Electric transportation: Refers primarily to enabling large-scale integration of plug-in electric vehicles (PEVs). Electric transportation could significantly reduce U.S. dependence on foreign oil, increase use of renewable sources of energy, provide electric energy storage to ameliorate peak-load demands, and dramatically reduce the nation’s carbon footprint. 
  • Network communications: Refers to a variety of public and private communication networks, both wired and wireless, that will be used for smart grid domains and subdomains. An interface is a point where two systems need to exchange data with each other. Effective communication and coordination occurs when each of the systems understand and can respond to the data provided by the other system, even if the internal workings of the system are quite different.
  • Advanced metering infrastructure (AMI): Provides near real-time monitoring of power usage. AMI consists of the communications hardware and software, and the associated system and data management software, that together create a two-way network between advanced meters and utility business systems, enabling collection and distribution of information to customers and other parties, such as the competitive retail supplier or the utility itself. 
  • Distribution grid management: Focuses on maximizing performance of feeders, transformers and other components of networked distribution systems and integrating them with transmission systems and customer operations. As smart grid capabilities such as AMI and demand response are developed, and as large numbers of distributed energy resources and PEVs are deployed, the automation of distribution systems becomes increasingly more important to the efficient and reliable operation of the overall power system.
  • Cybersecurity: Encompasses measures to ensure the confidentiality, integrity and availability of the electronic information communication systems and the control systems necessary for the management, operation and protection of the smart grid’s energy, information technology and telecommunications infrastructures.

Given the importance and magnitude of the smart grid, at the most basic level just about everyone you know is a stakeholder. According to NIST, the stakeholder groups who may find Framework 3.0 most useful include:

  • Utilities and suppliers concerned with how best to understand and implement the smart grid (especially Chapters  4, 5 and 6);
  • Testing laboratories and certification organizations (especially Chapter 7);
  • Academia (especially Section 5.1 and Chapter 8); and
  • Regulators (especially Chapters 1, 4, and 6, and also Section 3.5).