Industry Wide Collaboration to Drive Solar Costs Down Through Efficient Data Exchange

By: Gatsheena Beauplan 

The Orange ButtonSM initiative has launched! As part of the U.S. Department of Energy SunShot initiative, the Orange Button initiative is designed to standardize data across the solar project lifecycle, enhance data quality, and make solar transactions more efficient.  By creating solar data standards, open marketplaces, and tools for accessing data by the private sector, Orange Button aims to improve market transparency in a self-sustaining manner.

The SGIP (Smart Grid Interoperability Panel) and partner SEIA (Solar Energy Industries Association) are tasked with organizing a wide array of market participants to drive strategy and to collect business requirements from a variety of perspectives.  Through this collaboration, collective output will be incorporated into the design and implementation of specific data tools aimed to facilitate the Orange Button objectives. To accomplish its goals, SGIP and SEIA are forming five Strategy and Business Requirements Working Groups. 

The groups include:

  • Deployment – Focused on the data needs associated with structural and electrical safety and other permitting concerns. This working group will include building code and safety standards experts, project developers, and other relevant stakeholders.
  • Financial Engaged in supporting efficient finance for projects, as well as efficient financial reporting practices during project operation. This working group will examine data practices for tax and accounting systems, streamlining information exchange between banks and developers to assess development risk, and the data exchange environment necessary to conduct effective financial asset management activities.
  • Grid Integration – Focused on the data needs for utilities, ISOs, and solar developers with regard to new utility-scale and behind-the-meter connections.
  • Real Estate – Focused on data requirements of the real estate industry (as they are relevant to solar projects) to deploy projects at various types of commercial real estate (e.g., owner-occupation of buildings, types of lease structures held by tenants).
  • Solar O&M – Focused on all data requirements behind project operations and maintenance practices and cost models.

Interested in joining one of the Orange Button Strategy and Business Requirements working groups listed above? Click the register button below:

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For more information on the Orange Button initiative, click here to view the Orange Button Overview webinar that was hosted by SGIP on May 26th, 2016.

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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. 

THE VALUE ENGINE:  (r-k) 

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? 

In accordance with President Obama’s 2014 Memorandum establishing the Quadrennial Energy Review (QER), the Department of Energy (DOE) recently announced it will begin the second installment of the Quadrennial Energy Review (QER 1.2) aimed at developing findings and policy recommendations to help guide the modernization of the nation’s electric grid. According to DOE’s briefing memorandum, QER 1.2 will focus on ensuring the electric grid’s continued reliability, safety, security, affordability and environmental performance through 2040. It will include an analysis of the fundamental elements that comprise the electricity system, including end use, distribution, transmission, grid operations and planning, generation, markets, finance and security.

Stakeholders are invited to both provide their own views on key issues to be addressed, as well as to respond to any or all of the framing questions in their comments. Additional insights and recommendations for Federal action to address challenges and opportunities associated with modernizing the Nation’s electricity system are welcomed. Here is a snapshot of the Framing Questions for QER 1.2:

Distributed Energy Resources (DER): Demand Response, Distributed Generation and Distributed Energy Storage 

  • How should DER value streams be assessed from different perspectives—customer, utility and society? 
  • What are the major barriers to distributed generation deployment, including financial, technical, transactional and distribution system limitations? 
  • What policies and regulations enable demand response to support variable energy resources at utility scale?

Electricity Consumption and Energy Efficiency by Sector (residential, commercial, industrial, transportation) Status, Trends and Barriers

  • What levels and patterns of electricity consumption exist today and are forecasted for 2040 in the industrial, commercial, residential and transportation sectors?
  • What business models and methods of customer engagement have been most successful, or show he most promise, for deploying residential efficiency measures? What is the role of policy in facilitating these models and methods?  

Electricity Markets

  • What frameworks and metrics can characterize regional markets and degree of market regulation?
  • How have markets performed across different criteria since restructuring?
  • How can policy levers be employed to remove barriers in each type of market to facilitate policy goals? 
  • Are there barriers to cleaner and more efficient generation given cost of capital differences?  

Electricity Finance 

  • How sensitive are costs to inputs (commodity prices, construction costs, technology costs)?
  • How do costs change under alternate financial scenarios (interest/debt/capital)?
  • What are the end user cost distributions under alternate DG/centralized scenarios?

Electricity Valuation 

  • How are uncertainty and risk taken into account under electricity valuation practices?
  • What value streams do electricity technologies provide to the system that are or are not monetized (and to which stakeholders do they accrue)? 
  • Do grid operators and policymakers manage tradeoffs among value streams?

Jurisdiction and Regulations

  • How did existing jurisdictional boundaries and policies evolve? What are the authorities for oversight of the electricity system? What are the responsibilities vested at each level?
  • What policy levers that exist at each level that may be challenged by the growing blurring of jurisdictional lines?
  • Distribution-level planning is becoming increasingly important: DER requires utility planners to achieve better integration of transmission planning and distribution planning and coordination between the Feds and the states.  How do wholesale and retail markets complement each other (from a jurisdictional perspective)? 

Here is the schedule for public input meetings. You can visit the QER website for additional details.

Boston, Massachusetts–April 15, 2016

Salt Lake City, Utah–April 25, 2016

Des Moines, Iowa–May 6, 2016

Los Angeles, California–May 10, 2016

Austin, Texas (Date TBD)

Atlanta, Georgia (Date TBD)

All comments can be submitted here up to July 1, 2016. 

It’s a great day for the Federal Energy Regulatory Commission (FERC) and supporters of demand response. Today, the United States Supreme Court issued its decision in FEDERAL ENERGY REGULATORY COMMISSION v. ELECTRIC POWER SUPPLY ASSOCIATION ET AL., upholding the FERC’s authority to regulate wholesale demand response as well as FERCs method of compensating demand response participants. In the 6-2 decision, the Supreme Court ruled:

  • The practices at issue directly affect wholesale rates.
  • The Federal Power Act (FPA) provides FERC with the authority to regulate the wholesale electric market.
  • FERC has not regulated retail sales.
  • FERC’s method of compensating demand response participants at locational marginal pricing (LMP) is not arbitrary and capricious.
  • A contrary view would conflict with the FPA’s core purposes by preventing the use of a tool (demand response) that will curb prices and enhance reliability in the wholesale electricity market.

Today, the Federal Energy Regulatory Commission (FERC) will hold a Technical Conference to discuss policy issues related to the reliability of the Bulk-Power System from 10 a.m. –  4 p.m. The Commission will also accept written comments regarding the matters discussed at the technical conference. The Commission states that written comments regarding the matters discussed at the conference should be submitted in Docket No. AD15-7-000 on or before July 9, 2015. There will be three informative panels:

Panel I:  2015 State of Reliability Report

This panel will address the North American Electric Reliability Corporation’s (NERC) recently released 2015 State of Reliability report. Here are a few of the questions panelists will address:

  • What does the 2015 report show about the effectiveness of NERC’s reliability activities and related industry efforts? 
  • What progress has been made with respect to the recommendations in the 2014 report and what are the obstacles to continued progress? 
  • What priorities have been identified in the 2015 State of Reliability report and how are these different from the 2014 report? 
  • Does the 2015 report indicate that more resources should be directed to particular reliability risks or areas?  
  • Are there other significant issues that require analysis or changes in the planning and operation of the bulk power system during the next 1-5 years?

Panel II: Emerging Issues

This panel will tackle emerging issues such as changes to our nation’s fuel sources and power supply portfolio, federal and state policies on renewable and other resources, and new environmental regulations. Here is a sampling of the questions panel II will address:

  • What emerging issues are going to challenge NERC and industry? How are these issues being considered in long-term, seasonal and operational planning studies?  
  • What progress has been made by NERC’s Essential Reliability Services Task Force in developing new approaches to the “reliability building blocks” (voltage support, ramping capability, and frequency support) needed for reliability and for ensuring their provision as the resource mix changes? 
  • Are any changes in reliability standards or other regulatory requirements needed or appropriate?  
  • Are additional efforts needed to maintain reliability as the growth of natural gas-fired generation continues? What specific additional improvements still need to be made? 

Panel III: ERO Performance and Initiatives 

NERC identifies various evolving issues that face the bulk power system and develops initiatives to address those issues. Some of the issues Panel III will address include: 

  • Explain the feedback loop from event analysis and compliance monitoring and enforcement to standards development. 
  • What are some examples of how Standards were modified or developed as a result of bulk-power system events?
  • What are the initial results of the risk-based Compliance Monitoring and Enforcement Program? 
  • What specific improvements to reliability performance, reduction to reliability risks, and increased compliance efficiencies are NERC and the industry experiencing as a result of this initiative?

The conference will be held at:

Federal Energy Regulatory Commission
Commission Meeting Room
888 First Street, NE
Washington, DC 20426 

If you can’t get to D.C. today, a free webcast of this event is also available through www.ferc.gov.  A link is posted on the Technical Conference Event page. There you can also find panelists statements and the full agenda.   

Vice President Joe Biden recently spoke in Philadelphia to announce the release of the Quadrennial Energy Review (QER). According to a White House fact sheet, “the QER is envisioned as a focused, actionable document designed  to  provide  policymakers, industry, investors, and other stakeholders with unbiased data and analysis on energy challenges, needs, requirements, and barriers that will inform a range of policy options, including legislation.” The first installment of the QER examines how to modernize our nation’s energy infrastructure and is primarily focused on energy transmission, storage, and distribution (TS&D), the networks of pipelines, wires, storage, waterways and railroads. Each chapter provides recommendations to improve or remedy the issues discussed. At 347 pages, the QER provides an in-depth overview of the energy issues impacting our nation. If you are not interested in all of the topics or simply want to save some memory space, the Review’s homepage provides an individual PDF of each chapter. Here is a listing of the chapters:

Ensuring the Resilience, Reliability, Safety, and Security of TS&D Infrastructure

Modernizing the Electric Grid

Modernizing U.S. Energy Security Infrastructures in a Changing Global Marketplace

Improving Shared Transport Infrastructures

Integrating North American Energy Markets

Addressing Environmental Aspects of TS&D Infrastructure

Enhancing Employment and Workforce Training

Siting and Permitting of TS&D Infrastructure 

After a brief hiatus, Smart Grid Legal News is back! So many issues and not enough time or space so I thought I would start with the basics. I recently had the pleasure of meeting Christine Hertzog, managing director of Smart Grid Library, to discuss Smart Grid Dictionary, now it its sixth edition. At 466 pages, Smart Grid Dictionary covers acronyms and terms that are not just smart grid related but industry related. If you are new to the industry, the book will quickly become a well-worn staple. Veterans might find it useful to zero in on terms you might gloss over. Like most good ideas, Smart Grid Dictionary was created out of necessity. Trying to navigate an industry riddled with acronyms can be challenging. So for her own use, Christine began keeping a list of terms she hears often and soon Smart Grid Dictionary was born. Perusing through the dictionary, some of the terms that I take for granted, like classes of service or rate case, made me smile as I thought about how they could be confusing to those not enmeshed in this regulatory world. Below is a random sample of terms found in the Smart Grid Dictionary:

ADA (Advanced Distribution Automation)
A collection of intelligent sensors, remote controllers and bi-directional communications to manage distribution grids – covering substations to AMI assets.

Classes of service
A class or group of customers with similar characteristics that have a common rate for electric service. Some common classifications are residential, commercial, industrial and transportation.

Electric industry restructuring
The reconfiguration of vertically integrated electric utilities into markets with competing sellers, allowing customers to choose their suppliers but still receive delivery over the power lines of the local utility. Generation is now generally competitive, transmission is regulated by FERC (Federal Energy Regulatory Commission) and distribution falls under state jurisdictions.

ICAP (Installed Capacity)
A monthly market run by an ISO (Independent System Operator) that provides generators compensation for locating units in specific regions based on the net capacity the unit provides to the market after accounting for forced outages at the unit.

IEEE 2030.5
This standard incorporates Smart Energy Profile (SEP) 2.0. It defines application message exchange mechanisms, the exact messages exchanged and the security features used to protect the application messages. This enables utility management of the end user energy environment, including demand response, load control, and time of day pricing among other functions.

The Citizens Utility Board (“CUB”) and the Environmental Defense Fund (“EDF”) recently filed a joint petition asking the Illinois Commerce Commission (“ICC” or “the Commission”) to initiate a proceeding to adopt the Illinois Open Data Access Framework (“Framework”). They hope the Framework will become the governing standards for access to customer usage data by customers, utilities and third parties. One interesting point about the proposed Framework is that the utilities are guardians of the data (sounds like a movie my son would like) but not owners of it. Below is the paragraph discussing ownership:

Customer is principal owner of retail electric consumption data. The customer has the ability to authorize third parties to access individual customer data, and the customer can revoke that access at the customer’s discretion. The utility serves as the guardian of retail electric consumption data, and must allow access to third parties where the customer has authorized it.

You can read CUB’s and EDF’s prefiled testimony and other pleadings by going to the ICC’s website. The case number is 14-0507. Com-Ed and Ameren Illinois have intervened in the case.

Before the chill of last winter’s polar vortex, many in the industry may not have even heard the term uplift payments. If you are still wondering exactly how it works, the Federal Energy Regulatory Commission (“FERC”) has a docket and workshop for you (Docket No. AD14-14-000). At this docket you will find an educational staff report on uplift payments in RTOs/ISOs. On Monday, September 8, 2014, FERC will hold a workshop to explore the technical, operational and market issues that give rise to uplift payments and the levels of transparency associated with uplift payments. The daylong informative workshop will begin at 8:45 a.m. and conclude at 5:15 p.m.

Panel 1 will address the basic issue of “What is uplift?” and explore issues that give rise to uplift payments as well as:

  • Drivers of uplift payments in RTOs/ISOs
  • Uplift payments that have been highly concentrated and persistent on a geographic or resource basis
  • Technical, operational and market issues driving uplift payments
  • The relationship between uplift payments and unit flexibility

Panel 2 will explore the impact of uplift on market participants.

Panel 3 will explore the adequacy of and the potential to enhance uplift transparency and recent market design changes that may address some of the causes of uplift.

Panel 4 will explore broader price formation issues and discuss next steps.

This agenda provides further details. As expected, the event will be held at the Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426. This workshop is free of charge and open to the public.

This week the state of New Jersey took an innovative step in its continuing quest to remain Stronger than the Storm. The N.J. Board of Public Utilities (“BPU”) approved Docket No. QO14060626, a subrecipient agreement with the N.J. Economic Development Authority (“EDA”) to work jointly in the establishment and operation of the Energy Resilience Bank (“ERB”). The EDA and BPU also announced the hiring of staff to fill two ERB leadership positions. Utilizing $200 million through New Jersey’s second Community Development Block Grant-Disaster Recovery allocation, the ERB will support the development of distributed energy resources at critical facilities throughout the state with a primary goal of improving resiliency.

Superstorm Sandy caused extensive damage to New Jersey’s energy infrastructure, disrupting delivery of electricity, petroleum and natural gas to consumers across the state, and leaving an estimated five million residents without electricity. Distributed energy resources, including combined heat and power (CHP), fuel cells (FC) and off-grid solar inverters with battery storage, allowed some critical facilities, such as hospitals, wastewater treatment plants and universities, to remain operational while the electric grid was down. The launch of the ERB will enable many more such facilities to remain operational during future outages. In addition to providing resilience, the benefits of distributed energy resources also include lower and stable energy costs, a cleaner environment through reduced emissions, and increased overall efficiency.

BPU President Dianne Solomon said, “Increasing energy resilience, whether through the Energy Resilience Bank, the BPU-approved resiliency improvement measures implemented by utility companies or NJ’s Clean Energy Program, will minimize the potential impacts of future widespread power outages due to major storms like Superstorm Sandy.”

Governor Christie’s press release says the Energy Resilience Bank is the first of its kind in the nation to focus on resilience.