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.

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.

In a recent order, the Massachusetts Department of Public Utilities (“Department” or “DPU”) stated that time varying rates are an essential component of grid modernization. As a result, the design of basic service must change to incorporate time of use (“TOU”) rates for all customers, including residential customers. The Department noted that in 2013, the average wholesale market price of electricity over the course of the year was $56 per megawatt-hour (“MWh”), but the peak wholesale price in the summer reached nearly $870 per MWh and in winter nearly $1,300 per MWh. However, despite the volatility in the wholesale market, basic service customers’ rates did not reflect the time varying nature of electricity supply costs. The Department sees this as a problem. (Warning: DPU should take a short flight down to PJM land where customers’ exposure to last winter’s price spikes is still being discussed.) Nevertheless, DPU is concerned because under the current basic service structure in Massachusetts, rates do not reflect the time varying nature of electricity supply costs. Additionally, customers who are able to shift more of their electric usage to off-peak/lower wholesale cost hours subsidize customers who use more electricity during hours with higher wholesale electricity prices.

The Time Varying Rates Order describes a policy framework that will require electric distribution companies to offer two basic service TOU options:

  1. A default product with time of use pricing that includes a critical peak pricing (“CPP”) component. Under this TOU pricing structure, the retail electricity price will be higher during certain hours of the week when customers typically use more electricity and wholesale energy prices rise (e.g., the “on-peak” hours of noon to 8:00 p.m. each weekday) than during the remaining hours of the week when electricity usage and wholesale prices are typically lower (i.e., the “off-peak” hours).
  2. A flat rate with a peak time rebate (“PTR”) option. With a PTR, customers will receive a rebate if they lower their electricity use relative to a pre-established baseline during times when wholesale hourly energy prices are highest. Thus, under PTR, customers will have an incentive to lower their electricity usage when it is most critical to do so, but even those who ignore the incentive will be insulated against higher peak prices because they will pay one price for all electricity consumption.

The Department anticipates that the on-peak rate will be higher and the off-peak rate lower than a flat-rate product. Thus, customers who respond to price signals by reducing on-peak energy consumption will pay less than they would under a flat rate.

Written comments regarding this policy framework may not exceed 25 pages and must be submitted no later than the close of business (5:00 p.m.) on July 3, 2014.

This month the Environmental Protection Agency (“EPA”) released its Clean Power Plan proposal. The Plan cuts carbon pollution from existing power plants, which according to the EPA is the single largest source of carbon pollution in the United States. The Agency says the proposal will protect public health, move the United States toward a cleaner environment, fight climate change and continue to supply Americans with reliable and affordable power. Milestones and goals of the plan include:

  • Reduce carbon emission from the power sector to 30 percent below 2005 levels
  • Reduce electricity bills by approximately 8 percent by increasing energy efficiency and reducing demand in the electricity system.

The Clean Power Plan provides guidelines for states to develop plans to meet state-specific goals to reduce carbon pollution and gives them the flexibility to design a program that makes the most sense for their unique situations. States can choose the right mix of generation using diverse fuels, energy efficiency and demand-side management to meet the goals and their own needs. It allows them to work alone to develop individual plans or to work together with other states to develop multi-state plans. States better get busy because a year will fly by. Here are the proposed state plan dates:

June 30, 2016 – Initial plan or complete plan due
June 30, 2017 – Complete individual plan due if state is eligible for a one-year extension
June 30, 2018 – Complete multi‐state plan due if state is eligible for two-year extension (with progress report due June 30, 2017)

EPA is accepting comments and will hold four public hearings for the Clean Power Plan the week of July 28, 2014. The hearings will provide interested parties the opportunity to present data, views or arguments concerning the proposed action. The hearings will be held on:

The New York State Public Service Commission (“PSC” or “Commission”) recently petitioned the U.S. Court of Appeals for the Second Circuit to force the Federal Energy Regulatory Commission (“FERC”) to respond to the PSC’s pending requests for rehearing of FERC’s decisions to create a new capacity zone (“NCZ”) in the lower Hudson Valley. The PSC states that as a result of the NCZ, residential customers using 600 kWh/month in the lower Hudson Valley would experience increases in their total electric bill of between six percent to thirteen percent and industrial customers could experience a ten percent increase, causing unnecessary and unreasonable electricity price increases in the lower Hudson Valley.

Pending full judicial review of FERC’s decisions, the PSC has filed an emergency motion asking the Court to issue a stay of FERC’s decisions implementing the upcoming capacity auctions in the NCZ and ensure consumers are not harmed further. However, in previous pleadings, the New York ISO (“NYISO”) states that the NCZ Study determined that the Upstate New York/Southeast New York (UPNY/SENY) Highway interface into Load Zones G and H was constrained because it was bottling 849.2 MW of generation from Load Zones A through F, and therefore, NYISO is required to create a new capacity zone.

Entergy Nuclear also supports the creation of the new capacity zone and asserts that the erosion of the electric system in the lower Hudson Valley over time provides proof of the harm that results when inaccurate price signals fail to adequately value capacity in a region. It states that the capacity price signal for the lower Hudson Valley zones was suppressed by the excess capacity levels in the remainder of the Rest-of-State region that cleared against the NYCA curve, but were not deliverable to the lower Hudson Valley zones due to the UPNY/SENY constrained interface.

FERC has stated it does not believe the new capacity zone will result in unjust and unreasonable rates. Higher capacity prices in the new capacity zone will help to encourage the development of new generation and/or transmission capacity to help alleviate the constraint NYISO has demonstrated. FERC’s position is that the price changes promote efficient decisions and are not unreasonable. The NCZ capacity auctions have begun and the PSC has filed a Petition for a Writ of Mandamus and Emergency Motion for Stay to prevent what it believes is irreparable harm to customers in the lower Hudson Valley:

Because FERC has not acted prior to the implementation of the NCZ capacity auctions, New York electricity ratepayers face the possibility of paying an additional $158 million for electricity in the summer of 2014, without realizing a corresponding benefit. If the Court reverses FERC it will be difficult, if not impossible, to rerun the auctions to reflect whatever relief the Court provides.

– PSC Petition and Motion page 10

These are interesting grid management issues. The industry will be watching the Second Circuit.

Because the grid is so critical to all aspects of our society and economy, protecting its reliability and resilience is a core responsibility of everyone who works in the electric industry.

– Federal Energy Regulatory Commission (“FERC”) Acting Chairman Cheryl LaFleur

This month, FERC directed the North American Electric Reliability Corporation (“NERC”) to develop Reliability Standards requiring owners and operators of the Bulk-Power System to address risks due to physical security threats and vulnerabilities within 90 days. The Reliability Standards will require owners and operators of the Bulk-Power System to take at least three steps to protect physical security:

  1. Owners and operators must perform a risk assessment of their system to identify facilities that, if rendered inoperable or damaged, could have a critical impact on the operation of the interconnection through instability, uncontrolled separation, or cascading failures of the Bulk-Power System.
  2. Owners and operators of critical facilities must evaluate potential threats and vulnerabilities to those facilities.
  3. Owners and operators must develop and implement a security plan to address potential threats and vulnerabilities.

FERC recognizes that compliance with the Reliability Standards described above could contain sensitive or confidential information that, if released to the public, could jeopardize the reliable operation of the Bulk-Power System. As a result, NERC is also directed to include in the Reliability Standards a procedure that will ensure confidential treatment of sensitive or confidential information but still allow for the Commission, NERC and the Regional Entities to review and inspect any information that is needed to ensure compliance with the Reliability Standards.   

The industry understands the continuing need to address physical security and resilience. This latter point is critical because absolute protection from attack, physical or cyber, can never be promised. It is a risk embedded in our freedom. So a healthy ongoing focus on resilience is critical and grid owners and operators address these issues frequently if not daily. So I can’t help but wonder whether the recent media frenzy about Metcalf and a looming national blackout has FERC fighting back, not just with statements but this order.

Last week the Federal Energy Regulatory Commission (“FERC”) issued a final rule allowing interstate natural gas pipelines and electric transmission operators to share non-public operational information to promote the reliability and integrity of their systems. After extensive technical conferences with stakeholders from both the electric and gas industries, Order No. 787 adopts the revisions to Parts 38 and 284 of the Commission’s regulations as stated in the Notice of Proposed Rulemaking without modification.

The new rule provides explicit authority to interstate natural gas pipelines and public utilities that own, operate, or control facilities used for the transmission of electric energy in interstate commerce to voluntarily share non-public, operational information with each other for the purpose of promoting reliable service or operational planning on either the public utility’s or pipeline’s system.

To protect against undue discrimination and ensure that the shared information remains confidential, the rule also adopts a No-Conduit Rule that prohibits recipients of the information from disclosing it to an affiliate or a third party. However, the No-Conduit Rule applies only to the information that an interstate natural gas pipeline or an electric transmission operator exchange pursuant to this final rule. The No-Conduit Rule does not affect current communications among interstate and intrastate natural gas pipelines, local distribution companies and gatherers regarding conditions affecting gas flows between these physically interconnected parties, nor does it affect communications between transmission system operators and load serving entities.

The rule refers to both interstate natural gas pipelines and public utilities that own, operate, or control facilities used for the transmission of electric energy in interstate commerce collectively as “transmission operators.” An electric transmission operator can seek Commission authorization if they wish to share information received from an interstate pipeline with a local distribution company.

Ever wanted to gain a better understanding of capacity markets? The Federal Energy Regulatory Commission (“FERC” or “Commission”) will provide the perfect opportunity. On September 25, 2013, the Commission’s staff will hold a technical conference to consider how current centralized capacity market rules and structures in the regions served by ISO New England Inc. (ISO-NE), New York Independent System Operator, Inc. (NYISO), and PJM Interconnection, L.L.C. (PJM) are supporting the procurement and retention of resources necessary to meet future reliability and operational needs.

To provide a common foundation for the conference, the Commission’s staff has released a report Centralized Capacity Market Design Elements. Representatives from ISO-NE, NYISO, and PJM will provide a brief overview of the goals and basic structure of their respective centralized capacity markets, including a discussion of why each region chose key market design elements and how each market is achieving its stated goals. There will also be a discussion about basic design elements of centralized capacity markets, such as the forward commitment period, the demand curve and the establishment of locational and regional planning requirements, as well as the interaction among these design elements with energy and ancillary services markets. Some of the issues that will be addressed include:

  • What are the metrics used to measure the success of the centralized capacity market?
  • What design elements are key to the functioning of the centralized capacity market in your region?
  • What are the key challenges facing centralized capacity markets in your region?
  • How is each RTO/ISO going about addressing those challenges?

The conference on September 25, 2013, will be held at the Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426. It is expected to run from 9:00 a.m. to approximately 5:00 p.m. It is free and open to the public. Additionally, there will be a free webcast that will allow you to listen to the conference, but not participate. Additional details can be found in the Notice and Agenda.

The Public Utility Commission of Texas (“Commission”) says that after years of vetting smart meter deployment through public hearings, workshops and four contested cases, no one objected to orders requiring full deployment and cost recovery of advanced meters. And when health and safety concerns were subsequently raised, the Commission evaluated these issues and concluded they were unwarranted. As a result, smart meters are standard in Texas. Usually this provides regulatory certainty.

But for an industry that provides for eminent domain, things have gotten interesting. For example, approximately 40 of more than 2.2 million of CenterPoint Energy’s customers object to smart meters and want the right to opt-out…and they are going to get it. For less than 0.002% of its customer base, CenterPoint must retain someone to read meters and put trucks on the road for move-ins/move-outs and other related services. They have to do this because the Texas Public Utility Commission recently decided that although smart meters are standard and safe, public interest requires transmission and distribution utilities to offer alternative metering to those who want to decline the benefits of advanced meters. This month new amendments were adopted to provide for Non-Standard Metering Service commonly known as opt-out. The new rules:

  • Require a transmission and distribution utility (“TDU”) to provide non-standard or alternative metering service.
  • Require the TDU to obtain and retain written customer acknowledgement regarding the negative consequences of opting-out.
  • Allows the TDU to separately charge for the costs associated with opting-out.

Regulatory certainty?

Natural gas as a fuel source for electric generation has increased and the trend is likely to continue, resulting in an ongoing dialog regarding the interdependence of the natural gas and electric industries. In February 2012, the Commission began to formally examine the issue by seeking comments and over time convening technical and regional conferences. On July 18, 2013, the Commission issued a Notice of Proposed Rulemaking (“NOPR”) proposing to revise Parts 38 and 284 of the Commission’s regulations to provide explicit authority to interstate natural gas pipelines and public utilities that own, operate or control facilities used for the transmission of electric energy in interstate commerce to share non-public, operational information with each other for the purpose of promoting reliable service or operational planning on either the public utility’s or pipeline’s system.

The Commission wants to remove barriers to the sharing of non-public, operational information for day-to-day operations as well as during emergencies. To balance the risks associated with such open communications, the Commission also proposes to adopt a No-Conduit Rule which prohibits recipients of the non-public, operational information from subsequently disclosing or being a conduit for subsequently disclosing that information to any other entity. A few other interesting highlights of the NOPR are:

  • The proposed changes would not override existing tariffs that prohibit such communications. A filing to revise the tariff would be necessary.
  • The Commission seeks comment on whether the proposed rule should require that, to the extent the non-public, operational information exchanged between transmission operators involves customer-specific information (such as information about individual generators), the transmission operators must seek to include the customer as part of a three-way communication.
  • The Commission seeks comment on whether a generator should be required, at the request of the electric transmission operator, to provide its electric transmission operator with information pertaining to any communications received from a natural gas pipeline regarding potential failures by the generator to conform to flow rates or nominations.

Comments are due August 26, 2013 and must reference Docket No. RM13-17-000. They may be submitted electronically via the eFiling link on the Commission’s website at or submitted by postal mail to:

Secretary of the Commission
888 First Street, NE
Washington, DC 20426