While blockchain technology is most closely associated with the cryptocurrency Bitcoin and more recently the financial industry, there is a new category of tech companies that are focused on using blockchain technology to reshape the energy industry. These companies are using blockchain in order to help utility companies track renewable energy credits, facilitate metering and billing, manage energy data such as market prices and cut out intermediaries such as retailers.

Last year, over 320 million dollars was invested in 120 start-up companies that are using blockchain to transform the way the energy industry conducts business. Blockchain is a relatively new technology which uses digital blocks of transactions to permit an individual party to conduct and bill a transaction directly with another party. All transactions that take place on the blockchain are verified by a decentralized network of computers and are recorded on a distributed ledger. Blockchain provides a secure way to do anything from executing smart contracts to tracking supply chain data. Robert Hacket, a writer for Fortune.com, defines blockchain in one of his recent articles:

“Though it sounds like a series of defensive maneuvers ripped out of an NFL playbook, the blockchain is actually a way to structure data…This coding breakthrough—which consists of concatenated blocks of transactions—allows competitors to share a digital ledger across a network of computers without need for a central authority. No single party has the power to tamper with the records: the math keeps everyone honest. Forty of the world’s top financial firms are experimenting with the tech.”

PHOTO CREDIT: McKinsey & Company Electric Power & Natural Gas

In New York, utility companies Avangrid, Con Edison, National Grid, the New York Power Authority and Indigo Advisory Group have come together to explore different use cases for blockchain within their businesses. In a recent article by the group, they determined that the best use cases for blockchain within utility companies include automating customer management, automating clearing and settlement, tracking renewable energy credits, increasing cybersecurity, and connecting electric vehicles to the grid. The New York consortium and other companies within the energy industry have determined that the above use cases for blockchain in the industry will increase efficiency by streamlining data management, metering, and billing. Furthermore, they have determined that the use of blockchain within the industry would decrease overhead for utilities and lower costs to consumers by facilitating the metering and billing process between the utility and the consumer instead of involving intermediary retailers and brokers.

Although blockchain technology is still in its infancy, it is only a matter of time before the technology revolutionizes the way the energy industry operates. Stephen Callahan, Vice President of Energy, Environment & Utilities, Global Strategy, at IBM boldly predicts, “What the internet did for communications, blockchain will do for trusted transactions, and the energy and utilities industry is no exception.”

Lawyers, consultants and business leaders working in the rates and regulatory area will find the recently released Pennsylvania Public Utility Commission’s (PaPUC or Commission) Guide to Utility Ratemaking helpful, even if you don’t practice in Pennsylvania.

The original Rate Case Handbook was first published in 1983. The handbook served as a valuable resource for energy and utility practitioners. Just as before, the updated guidebook is well laid out and manages to make complex information easy to digest.

In the new edition, readers are given both a general overview of how each utility (water, gas, telecom and electric) service is produced, priced and delivered, as well as a thorough synopsis of the legal and administrative structure of the PaPUC. The 181 page handbook is comprehensive and provides information on the following:

While many of the foundational principles outlined in the original handbook have retained their applicability, technological advancements and discoveries from Marcellus Shale to smart meters and distributed generation commanded special attention in the new update. A big thank you to authors James H. Cawley, former PaPUC Commissioner, and Commissioner Norman Kennard, as well as to those who aided in the completion of the project. It provides a relevant discussion on modern ratemaking issues.

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? 

On June 30, 2014, the Supreme Court declined to hear Kansas City Power & Light Co.’s appeal of a lower court’s affirmation of the Missouri Public Service Commission order denying the utility the right to recover FERC-approved transmission costs, estimated at $100 million. The costs are for delivering power 500 miles from a natural gas plant in the Mississippi Delta to western Missouri customers. The Missouri PSC approved the purchase power but concluded the $5 million yearly interstate transmission cost at FERC-approved rates wasn’t “just and reasonable” because the plant was only used to meet summer peak demand. However, KCP&L was paying for transmission access all year and passing that cost on to its customers. KCP&L argued the decision to disallow FERC-approved transmission costs violated the supremacy clause of the U.S. Constitution, which gives federal law jurisdiction over state law.

The impact of the ruling further supports the concept that FERC approval no longer provides certainty regarding cost recovery. Billions of dollars in interstate transmission costs may or may not be recoverable from customers. It is already a hot summer and things could really heat up to the extent other state utility commissions consider denying recovery of FERC-approved transmission costs related to the growing area of distantly-sited generation, especially the popular natural gas and wind generation.

And there is more… I find the most interesting thing about this case is the fact that the Missouri PSC approved the recovery of the cost of the generation facility in base rates, yet denied the cost to transmit the power from the approved facility.

Bonus: The Solicitor General explains why cert should be denied.

Recently Commission staff provided a Briefing on Smart Meters: Technical Information and Regulatory Issues to the Florida Public Service Commission. As previously reported, the FPSC held a public workshop last year to gather information and address concerns raised by customers. The Briefing summarizes the workshop. Although many of the typical issues are raised, I think utilities will find staff’s conclusions most interesting. For example, tucked on pages 2 and 4 are insightful conclusions I consider headline-worthy:

The FPSC has jurisdiction over cost recovery of smart meters, but does not have specific statutory authority over the smart meters themselves… RF emission standards are established by the Federal Communications Commission (FCC).

Briefing, page 2

The FPSC does not have regulatory authority over any potential health effects from smart meters; the FCC is the entity that has jurisdiction over the issue.

Briefing, page 4

Yes, the Briefing is an interesting read. Staff also wonders what will happen to the 25,000[1] customers FPL estimates are on its hold list because of smart meter concerns. Right now the costs to read these customers’ analog meters are socialized among most ratepayers, which can reduce the overall savings that may be achieved by smart meters. Staff expressly states it believes all charges should be cost-based to ensure any subsidization is kept to a minimum.

Finally, staff suggests that the Commission continue to monitor the issues, but not take any specific action at this time.

[1] This figure represents .5% of all of FPL’s smart meter installations. Briefing page 6.

Most people in the industry agree the electric infrastructure is outdated and requires extensive upgrades. It’s when you get to the “How?” and “Who pays for it?” that the war begins in many jurisdictions. And if you think that having a law that supports the upgrades and implementation of the smart grid settles the matter, think again. Last year, Illinois passed the Energy Infrastructure Modernization Act (“EIMA”), yet implementation has been anything but routine. In a show of force between regulators and law makers, electric utilities in Illinois found themselves holding the cost recovery bag. Last May the Illinois Commerce Commission (“ICC”) found that Ameren’s Smart Grid Plan failed the customer cost benefit test. The ICC also disallowed key costs in ComEd’s first formula rate case under EIMA. According to ComEd, it will now face a reduction in funding of nearly $100 million per year in 2014 and beyond. These are dollars that cannot be recovered and subsequently reinvested into the system, jeopardizing the grid modernization programs and related customer benefits. ComEd has appealed the ruling in court, but that decision may take up to two years.

In a battle between regulators and law makers, on November 29, 2012 the Illinois Senate passed Senate Resolution 821 which states in part:

RESOLVED, BY THE SENATE OF THE NINETY-SEVENTH GENERAL ASSEMBLY OF THE STATE OF ILLINOIS, that we express serious concerns that the Illinois Commerce Commission Order, entered on May 29, 2012 in Commission Docket No. 11-0721, fails to reflect the statutory directives and the intent of the Illinois General Assembly by: (1) not allowing Commonwealth Edison Company to earn a return on what is commonly referred to as, identified in the FERC Form 1 as, and what the General Assembly referred to as a pension asset in subparagraph (D) of paragraph (4) of subsection (c) of Section 16-108.5; (2) assessing interest on those amounts to be credited or charged to customers as set forth in subsection (d) of Section 16-108.5 of the Public Utilities Act at an amount that is not based on the utility’s weighted average cost of capital; and (3) determining rate base and capital structure using an average, rather than  the year-end amounts as reflected in FERC Form 1…

Not sure if the resolution swayed regulators, but in true Chicago-style politics, the ICC issued an order on December 5, that allows ComEd to proceed with its revised smart grid deployment plan in 2015 but makes it clear it is not happy about the delay:

Allowing the Revised Plan to go forward is accepting, at least for now, that meters will not be installed until 2015. This is regrettable, because the benefits to ratepayers are greatly reduced with the delayed deployment. But because of the impossibility of implementing the Original AMI Plan and the shortcomings of the proposed Revised Plan, the Commission is left with only bad options. – ICC Order page 32

One thing is clear, the battle in Illinois will continue. The order requires ComEd to describe in detail their efforts accelerate implementation when the company files its April 2013 AMI Plan Progress Report.

The Smart Grid Research Consortium has created a smart grid test that scores utilities in six categories:

  • AMI/DA Investment/Planning Scope
  • Customer Engagement Investment/Planning Scope
  • Other Financial Items
  • Utility Customer Detail
  • Investment Analysis Quantitative Framework and
  • Ease of Use/User Interface/Results Presentation

The questions are designed to provide utilities with guidance when making smart grid investments. I think the Smart Grid Investment Quotient Scorecard is a tool that regulators will also find helpful. The Scorecard is designed to reflect current, past or future investment analysis. The figure below shows a section of the scorecard that addresses customer engagement.


II. Customer Engagement* Investment/Planning Scope

(Maximum Category Points: 20)

Does your investment analysis/planning process:


a. Consider reductions in power costs (purchased and/or generated) associated with customer engagement technologies and programs? If yes, add 5 points.

b. Consider financial benefits of deferred capital investments associated with customer engagement technologies and programs? If yes, add 3 points.

c. Use information on your utility’s customer class/end-use (e.g., residential AC) hourly loads (rather than generic estimates) to model peak period hourly load impacts over the planning horizon? If yes, add 10 points.

d. Reflect changes in future hourly loads over the planning horizon as a result of changes in customer counts, equipment saturations and efficiencies and other factors? If yes, add 2 points.

*Includes PCTs, monitors, pricing, information programs, etc.

Snapshot taken from Score Your Smart Grid IQ (Investment Quotient) pg. 2


If your plan does not include distribution automation, the highest grade you can receive is a B. I think that is appropriate given that many in the industry have been saying: The Smart Grid is more than Smart Meters! This Scorecard adequately demonstrates that point.

Dominion Virginia Power received SCC  approval to offer an electric vehicle recharging pilot program. The pilot is designed to test whether electric vehicle owners will choose to recharge their vehicles during off-peak hours – typically overnight – in exchange for lower electricity costs. Interested customers will be able to sign up for the pilot program beginning Oct. 3, 2011. Dominion will partner with car dealerships and charger installation vendors to build customer awareness.

The two experimental rate options as a part of the pilot are:

Electric Vehicle only – This option is for charging the electric vehicle only. The company estimates that it would cost about 43 cents on this rate to charge an electric vehicle overnight with enough electricity for a typical 40-mile commute. Customers electing the electric vehicle-only rate option will have a second meter installed to measure the energy use specific to recharging the vehicle.

Whole House – This option allows customers to take advantage of lower prices for many household activities. The pricing would change during the day to encourage the off-peak charging of electric vehicles and use of other household appliances, such as the dishwasher and clothes dryer. The company estimates that it would cost between 41 cents and 49 cents on this rate to charge an electric vehicle overnight with enough electricity for the daily commute.

Each rate option would be limited to 750 participants who would have to stay enrolled for at least one year. The pilot, expected to cost $825,000, will terminate Nov. 30, 2014. It looks like House Bill 2105 was passed right on time. This new law, effective July 1, 2011, will allow Dominion to annually recover the cost of the pilot program. However, the Commission’s order does not allow the company to recover any lost revenue as a result of the pilot.

Virginia has been identified by industry experts as potentially one of the hottest markets for plug-in electric vehicles based on the state’s relatively large number of first-generation hybrid vehicles. Dominion believes there could be 86,000 electric vehicles in the state – equal to 5 percent of all vehicle sales – by 2020. If charged on peak, these vehicles could lead to an increase in the amount of peak-demand electricity the company must supply that year by about 270 megawatts, which is the equivalent of powering 67,500 homes.

Ted_Wood.jpgToday I would like to introduce you to my colleague Ted Wood. Ted is a patent attorney with the law firm of Sterne Kessler Goldstein & Fox and is at the forefront of the smart grid cyber security and innovation discussion. He has some great ideas to help smart grid technology developers and is passionate about what innovation means to our energy independence and security.

Evers: Ted, how is innovation relevant to those in the energy industry and to businesses that rely on reliable energy delivery?

Wood: Thank you for the opportunity to discuss my views concerning the role of innovation. Innovation does and will continue to play a critical role in reducing vulnerabilities to the power grid. A recent article in the Washington Post citing top government intelligence officials indicated that “a major cyber attack somewhere in the United States is increasingly possible.” The article went on to warn that an assault on America’s power grid system “represents the battleground for the future.” Based upon this article and several others, as well as my own observations and analyses, it goes without saying that a successful cyber attack on the grid could have a devastating impact on our national security, economy and our way of life.

Evers: Ted, I agree. One of the goals for the smart grid is for it to operate resiliently against attack and natural disaster. A smarter grid protects against outside forces by incorporating a system-wide solution that reduces physical and cyber vulnerabilities and enables fast recovery from disruptions. What is the connection to innovation?

Wood: Innovation = grid resiliency

Evers: OK, connect the dots for me.

Wood: Through innovation, new technologies can emerge to help enhance the grid’s resiliency. Such technologies should address protecting the grid from cyber and other attacks, detecting when failures occur and responding and recovering accordingly. Successful innovation includes creativity, investment and intellectual property (IP) protection. Investment is essential to transforming creativity into tangible technologies and IP protection is a significant factor considered by investors when deciding in which technologies to invest to maximize their returns. And it is critical to have strong IP protection in place before entering the marketplace.

Evers: So it’s a cycle. Innovation → Investment → IP protection→ safer, smarter grid?

Wood: That’s right. However, I would adjust your model a bit:

Innovation → IP protection → Investment → safer, smarter grid. Most investors want to know the IP protection is in place first.

Evers: So Ted, with all of the American Recovery and Reinvestment Act funding, the race is on. I imagine there are a lot of great ideas out there and the developers may feel like they can’t get to the marketplace quick enough. Any ideas on how you can help them? Admittedly I am not from the Patent and Trademark Office, but I have been involved in getting regulatory approvals for a long time and they usually don’t occur at the speed of innovation.

Wood: Recognizing the urgency of cyber security and the development of the smart grid, I believe that some sort of Grid Resiliency patent incentive program might help to spur grid resiliency innovations. The objective of one such program, for example, would be to streamline the examination of patent applications specifically focused on technical innovations to reduce vulnerabilities by ensuring the grid’s resiliency. This streamlined process could help improve the revenue stream for innovators by increasing the development speed of their products and technologies. For example, patent applications covered under such a program would include resiliency-enhancing technologies that could be added to existing grid components and systems, as well as resiliency-enhancing technologies integrated into next-generation components and systems. The intent is to leverage the U.S. patent system to encourage grid related R&D investments and innovations which would reduce the grid’s vulnerabilities. There are other programs, some already underway at the US Patent and Trademark Office, to encourage innovation across the board. These programs could be used to spur grid innovations.

Evers: That is great! What is the current status of the Grid Resiliency Patent Incentive Program?

Wood: We are vetting a number of different ideas through different means, such as industry blogs and discussions with industry and government representatives. The goal is to try and find the right mix of ideas that will help promote innovation and R&D investment in grid resiliency enhancing technologies.

Evers: I can imagine there are a lot of entrepreneurs hoping to participate. It will be a game changer for those who need funding as soon as possible. Please let me know when this is finalized. What are the other programs at the PTO that can be leveraged by smart grid innovators?

Wood: There are two that come to mind. The first is the Green Technology Pilot Program, which provides for accelerated examination of patent applications related to development of renewable energy sources, energy conservation etc. A few of the technical categories covered by this pilot program also related to smart grid. The second program is the newly implemented Track 1 initiative. Track 1 provides for accelerated examination for applications for payment of a $4,000 fee. Given the limited scope of the green pilot program with respect to grid resiliency and possibility that all innovators may not have access to Track 1 given the required fee, there may still be room for additional programs or incentives to spur grid resiliency innovations.

So Linda, I am going to switch things up a bit and if you don’t mind, I have a few questions for you?

Evers: Sure, but let me remind you…it’s my blog. (laughing)

Wood: I think the next roadblock is getting the utilities to try the new products. I know you represent a lot of utilities so I wondered if you had any insight to share on this issue?

Evers: Absolutely. …cost recovery.

Wood: My turn. Please connect the dots for me.

Evers: Ted, you are talking about new technology. The developer should expect to demonstrate to the prospective utility client that the benefits outweigh the risks. We take risks everyday or nothing would get done. In the case of the smart grid, we know the cost of doing nothing is high. However, it will be an extremely expensive undertaking to fully develop the smart grid. Utilities are very careful when making investments out of concern they will not get the cost recovery they seek from state regulatory agencies.

Wood: But developing the smart grid is a huge priority for our country. I would think the state regulators would be supportive?

Evers: I know this may surprise to you, but there is a fair amount of regulatory uncertainty in this area. Views towards the smart grid will vary by state and some states have laws that require aggressive action in this area. Generally, utilities have to summit their plans to their state PUCs for approval. Part of the approval process is making the business case to support the proposed expenses. And let me tell you, 2010 was a rough year for smart grid approvals, particularly the cost recovery issue, in spite of Uncle Sam contributing $4.5 billion.

Wood: Really?

Evers: Yes! Maryland, Connecticut, Indiana and Ohio to name a few. And in California and Maine, the regulators are acting on one of my favorite lines: “I reserve the right to change my mind,” and are contemplating revising plans they have already approved, notwithstanding the fact that these utilities have already implemented most of the plan.

So for the innovators out there, the best way to get selected is to educate, educate, educate. Spend time explaining to regulators and consumer advocates the importance of your product to the grid. In the end, how does it benefit customers? Ideally, the product should be apart of the utility’s plan that gets approved.

Ted, it will happen slowly at first – layer by layer, but we will get there. Remember when cell phones first came out? For the first few years they were big and clunky and really only used by executives. And now just last year, even to my surprise, off we went to buy my son an iPhone for his 13th birthday. Progress can be like a sluggish car, slow to get going but it can hold its own on the highway. One day you will look around and bam: you will be driving to Pennsylvania to visit my family without any thought as to where you will charge your electric car; people will just know not to wash clothes and dishes in the afternoon; their appliances will conveniently start the laundry and dishes for them at 2:00 am and utilities will restore service before you even know there was an outage. All these great smart grid related things will be happening and as a county we will be more energy efficient.