On January 5, 2018, the Pennsylvania Public Utility Commission (“PUC” or “Commission”) reserved a public docket to review the impact of the Tax Cuts and Jobs Act, the federal tax reform bill that was signed into law on December 22, 2017, on utilities and companies under the PUC’s jurisdiction.  The PUC has not issued a tentative order or any further guidance or details regarding the scope and objectives of the proceeding.

The Tax Reform Act of 2017 lowers corporate tax rates from 35% to 21%.  Because income taxes are a significant component of a public utility’s revenue requirements, the Commission will be investigating potential means by which to provide the benefits of the Tax Reform Act of 2017 to customers.  Regulators and consumer advocates in other states, including Oklahoma, Kentucky, Michigan, and Montana, have already begun taking steps to investigate the impact of the Tax Reform Act of 2017, including potential refunds or rate reductions for consumers.

We will provide additional information through this blog once the PUC issues more information regarding its proceeding.

In April 2017, Energy Secretary Rick Perry issued a request for the Department of Energy (DOE) to organize a study examining electricity markets and reliability.  The request was looking to explore three specific concerns: 1) The evolution of wholesale electricity markets, including the extent to which federal policy interventions and the changing nature of the electricity fuel mix are challenging the original policy assumptions that shaped the creation of those markets 2) Whether wholesale energy and capacity markets are adequately compensating attributes such as on-site fuel supply and other factors that strengthen grid resiliency and, if not, the extent to which this could affect grid reliability and reliance in the future; and 3) The extent to which continued regulatory burdens, as well as mandates and tax and subsidy policies, are responsible for forcing the premature retirement of baseload power plants.

As one may imagine, this request led a number of environmental and intermittent resource groups to question exactly what this exercise was attempting to accomplish and if its findings would be politically focused.  After months of abundant speculation, on August 23, 2017 the DOE released its findings.  While the principal conclusions of the study will not come as a surprise to those in the electricity markets, the study seems to take a solid “middle of the road” approach.

Perhaps most significant in this otherwise extensive and unclear report was that the DOE did not find that renewables are a threat to grid reliability and also did not obviously state that coal was necessary for grid reliability.  They specifically said, “Hydropower, nuclear, coal and natural gas power plants provide [essential reliability services] ERS and fuel assurance critical to system resilience”.  By grouping these fuel sources all together they relax the discussion around each of these fuel sources, predominantly coal and nuclear.

The main take away from the study is that favorable economics of natural gas-fired generation was the primary driver of baseload (i.e. coal and nuclear) power plant retirements.  Low growth in electricity demand (attributed to some permanent loss of load from the economic downturn and energy efficiency policies) coupled with the expansion of renewables on the grid have also played pertinent roles in baseload retirements.  The report also touched on adverse economic impacts of the requirements for regulatory compliance for some baseload plants.  DOE primarily named coal and nuclear costs to implement the  Mercury and Air Toxics Standard (MATS), the EPA’s Clean Power Plan and the Cooling Water Intake Rule as reasons cited for additional plant retirements.

The report was expected not only to analyze but also provide “concrete policy recommendations and solutions”.  In this space, the recommendations presented were less concrete and particularly vague.   The bulk of the recommendations focused on FERC.  Some of those suggestions included having FERC expedite their ongoing efforts with states, RTO/ISOs and stakeholder input to improve energy price formation , studying and making recommendations on regulatory mechanisms to compensate grid participants for services necessary to support reliable grid operations and working to expeditiously process LNG export and cross-border natural gas pipeline applications.  The report also calls on DOE and other Federal agencies to accelerate and reduce costs for licensing, relicensing and permitting of grid infrastructure like nuclear, hydro, and coal providing some hazy “specific reforms” for these technologies.

The DOE is looking for the public to submit comments regarding this study, although it is also unclear who is receiving these comments and how long this window will be open. The report will not end the ongoing debates in various states regarding whether nuclear and/or coal generation resources should be subsidized to ensure that all existing plants remain in operation, even if particular plants are inefficient or uneconomic.  It also fails to address whether wholesale market changes adopted after the Polar Vortex (such as PJM’s Capacity Performance product) are sufficient to provide the additional compensation and market signals to ensure generation reliability.

For additional information, please reach out to: Amy York (ayork@mcneeslaw.com) or Pam Polacek (ppolacek@mcneeslaw.com).

Under settlements approved by the Public Utilities Commission of Ohio (“PUCO”), many customers can reduce their transmission bills if they are capable of managing their contributions to the zonal single coincident annual transmission peak.

This opportunity arises out of the complicated system of regulation of electric services that has developed in Ohio.  As part of the introduction of competition in the sale of electricity in Ohio that became effective in 2001, Ohio law requires electric distribution companies to unbundle electric service into generation, distribution, and transmission services.

The price regulation of the services varies by service.  In general, the PUCO is without jurisdiction to regulate generation services prices, and generation service can be secured from competitive providers.  Distribution service can be secured only through the electric distribution utility and is priced through traditional cost-based regulation.

Transmission services, however, have developed in a more complicated legal environment.  Under Ohio and federal law, the electric distribution utilities retain ownership of transmission facilities, but operation of the facilities is placed with the regional transmission organization, PJM Interconnection.  The owners of the transmission facilities are compensated through federally mandated charges under the PJM Open Access Transmission Tariff (“OATT”).  The customers that pay these charges are load serving entities such as utility companies and competitive retail service providers and individual customers in states that have provided for competitive choice such as Ohio.  Under the OATT, these individual customers may contract either directly or indirectly through a competitive retail electric service provider for transmission service.

In recent years, however, several PUCO rate orders have frustrated the customer’s ability to contract for transmission services.  While the OATT authorizes a customer to directly or indirectly contract with PJM for transmission service and the Ohio Commission’s rules provide that transmission rates are to be bypassable (meaning that the customer may contract for transmission services when it contracts for generation service), the PUCO has approved for each electric distribution utility nonbypassable transmission rates for certain PJM costs including Network Integrated Transmission Service (“NITS”).

Because the PUCO has frustrated contracting for transmission services by authorizing nonbypassable transmission charges, customers lose the opportunity to manage their transmission charges.  This opportunity arises because the customer’s cost for NITS under the OATT is based on the customer’s contribution to the zonal single coincident transmission annual peak while the electric distribution utilities have been authorized by the PUCO to bill customers for NITS and other transmission costs based on a customer’s monthly billing demand.  For a customer that can manage its contribution to the zonal single coincident annual transmission peak, there is an opportunity to reduce the customer’s transmission cost.

A simple example demonstrates the potential for savings.  In the example set out in the table, the customer’s contribution to the zonal single coincident annual transmission peak is five MW, and its average monthly demand is 30 MW.  The example assumes that the OATT provides for a zonal single coincident annual transmission peak-based charge of $5/kW, while the electric distribution company charges $3/kW for transmission services based on the customer’s monthly billing demand.  Due to the differences in billing math under the OATT and PUCO approved rates for transmission service, the customer faces increased transmission charges of $780,000 annually under the PUCO approved rates than what it would pay under the OATT rate.


Monthly Demand Based Rate Monthly Demand Monthly Transmission Charge
$3/kW 30 MW $90,000
Zonal Single Coincident Peak-Based Rate Customer Contribution to the Zonal Single Coincident Annual Peak Monthly Transmission Charge
$5/kW 5 MW $25,000
Monthly Net Difference   $65,000
Annual Net Difference   $780,000


Because there are opportunities for substantial savings, McNees Wallace and Nurick attorneys have supported efforts for customers to have the opportunity to elect to purchase transmission service based on their contributions to the zonal single coincident annual transmission peak rather than their monthly demand.

These efforts have resulted in two approved transmission pilot programs that permit customers to seek to reduce the transmission portion of their bills.  A third pilot is under PUCO review.  The enrollment in each pilot program is limited, but the PUCO has indicated that it will entertain applications from additional customers.

One pilot program is available to a group of customers of the FirstEnergy utilities, Ohio Edison Company, Cleveland Electric Illuminating Company, and Toledo Edison Company.  Under this pilot, a customer may elect to contract for transmission service through its competitive electric generation service provider.  The second pilot, developed under a settlement with the Ohio Power Company, provides for alternative tariff rates based on the customer’s contribution to the zonal single coincident annual transmission peak.  A third proposal that would be available for customers of Dayton Power and Light Company is currently under review by the PUCO.



As we transition from the dog days of summer and prepare for changes that are guaranteed to come this fall in our state and national political landscapes, we at McNees are considering what the upcoming elections and legislative sessions in Pennsylvania and Washington D.C. mean for our clients.  As discussed this summer, the Pennsylvania budget that became law on July 13 2016, provided relief for those who use state funding and its programs. The Pennsylvania General Assembly and Governor initially faced  a $1.3 billion shortfall in revenues when working on the FY 16-17 budget.  However, the final budget package was $1.2 billion less in spending than what Governor Wolf initially proposed and 5% higher than last year’s budget.  There are a number of new revenue sources for FY 16-17 including a $1 per pack tax increase on cigarettes with new taxes on e-cigarettes and smokeless tobacco products; expansion of the sales and use tax on digital downloads of videos, books, etc.; expansion of the income tax to include state lottery winnings, and a bank shares tax increase. While there was no across the board tax increases such as sales or income taxes or a tax on energy, it is expected and very likely that such tax increases will be necessary in the next budget cycle and is something we advise our large energy consumer clients to be mindful of as we approach this fall when elections and upcoming budget discussions will be front and center.

In addition to those relieved that a budget was passed somewhat timely in early July, there was also a sigh of relief for those who benefit from Senate Bill (SB) 1195 (Act 57 of 2016)  that was signed into law on June 23, 2016 and amends the Pennsylvania Greenhouse Gas Regulation Implementation Act by imposing requirements on Pennsylvania state government regarding its submission of a Clean Power Plan (CPP) to the EPA.  The CCP is intended to regulate states’ carbon emissions from existing electric power plants.

Act 57 reflects a compromise between the Pennsylvania General Assembly and Governor Wolf that allows the General Assembly the opportunity to review and approve the state’s proposed CPP before it is submitted to the EPA.  If either chamber of the General Assembly disapproves the draft CPP, the Department of Environmental Protection (DEP) must review and consider the reasons for disapproval and modify the draft CPP.  At that time, the DEP must resubmit a CPP to the General Assembly and open a public comment period for no less than 180 calendar days on the modified CPP during which time the department shall conduct at least four public hearings in geographically dispersed areas of the Commonwealth.  The Act also includes other provisions that address a default approval or a situation where neither chamber approves the draft or resubmitted modified CPP.  The amendment language further restricts the administration from submitting a CPP to the EPA until after the expiration of the stay issued by the United States Supreme Court on February 9, 2016.

While no one can truly predict how the U.S. Supreme Court will rule, Hillary Clinton’s campaign has boldly made its prediction. Recently during a panel discussion hosted during the Democratic National Convention in Philadelphia at the end of July 2016, Hillary Clinton’s campaign and energy adviser expressed the campaign’s expectation that the U.S. Supreme Court will uphold the CPP and the EPA’s authority to regulate greenhouse gases under the Clean Air Act.  While Donald Trump has not predicted the high court’s position, he has made clear that he is against the CPP and would work to repeal it regardless of the high court’s ruling.  Meanwhile, in Pennsylvania, the republican majority dominated General Assembly will be closely monitoring when the U.S. Supreme Court rules and monitor the state’s plan if and when it is submitted to the EPA.  Until then, the political landscape and issues being debated by the presidential candidates are indicators that this Fall will be quite interesting in many respects with the status and future of the CPP being just one of them.

At McNees, our energy attorneys and government relations professionals will be closely monitoring the politics that will affect this and many subjects of interest to our clients.  Please let us know if there is a specific issue or piece of legislation or subject you have interest in learning more about and we will help you.  Please contact Pam Polacek or Kathy Bruder at 232-8000 should you have any questions or want to discuss.

On June 10, 2016, the IRS released Notice 2016-36, which updates and expands the safe harbor provisions for payments and transfers of property to regulated public utilities occurring after June 20, 2016.  Although the utility must pay taxes on most payments or other contributions that a customer or project developer may make to upgrade the utility’s equipment for new services or generator interconnection, the IRS is exempting projects that it classifies as facilitating the transmission of electricity over the utility’s transmission system.  Specifically, the IRS considers contributions by Qualifying Facilities, wind generators, solar generators and energy storage to be such projects.  As of June 20, 2016, payments or transfers of those types of projects will be treated as a contribution to the capital of a corporation and not a taxable contribution in aid of construction (a “CIAC”). The Notice modifies and supersedes Notice 88-129, 1998 C.B. 541; Notice 90-60, 1990-2 C.B. 345; and Notice 2001-82, 2001-2 C.B. 619 (the “Prior Notices”).

By way of brief background, § 61(a) the Internal Revenue Code (the “Code”) provides that gross income means all income from whatever source derived, unless excluded by law. Section 118(a) of the Code provides that in the case of a corporation, gross income does not include any contribution to the capital of the taxpayer. Section 118(b) of the Code provides that for purposes of § 118(a), the term “contribution to the capital of a taxpayer” does not include any CIAC or any other contribution as a customer or potential customer.

The Prior Notices provided guidance with respect to the treatment of payments and transfers of property to regulated public utilities by qualifying small power producers and qualifying cogenerators (collectively, “Qualifying Facilities”). Specifically, the Prior Notices provided that a payment or transfer of property by a Qualifying Facility to a utility, with which it has a long-term power purchase contract or long-term interconnection agreement, would not constitute a taxable CIAC under either of the following safe harbor provisions: (i) the payment or transfer of property was made exclusively to promote the sale of electricity by the Qualifying Facility to the utility; or (ii) in the event the payment or transfer of property was not made exclusively to promote the sale of electricity by the Qualifying Facility to the utility, such as in the case of a “dual-use intertie,” then provided that the payment or transfer of property satisfied the “5% test.” The 5% test was satisfied if it was reasonably projected that during the ten taxable years of the utility beginning with the taxable year in which the transferred intertie was placed in service, no more than 5% of the projected total power flows over the intertie would flow to the Qualifying Facility.

The IRS issued Notice 2016-36 after recognizing that since the issuance of the Prior Notices, “electricity transmission and distribution systems have evolved and become interlinked so that close coordination of operations with the major U.S. power grids is needed to maintain the various interlinked components.” In order to appropriately adjust tax policy to reflect these industry changes, Notice 2016-36 modifies and supersedes the Prior Notices by (i) consolidating the safe harbor provisions of the Prior Notices, and (ii) providing new safe harbor provisions that remove the requirement that the Qualifying Facility have a long-term power purchase contract or long-term interconnection agreement with the utility. The IRS recognized that due to the substantial interlinking of the electricity distribution systems in the United States, a Qualifying Facility in one region and a utility in a different region that owns a transmission system that will be affected by power delivered by the Qualifying Facility may enter into an agreement in which the utility constructs upgrades to its transmission system, allowing it to handle increased capacity caused by the Qualifying Facility, and the Qualifying Facility may reimburse the utility for the costs of the upgrades. Although these entities may not have reason to enter into a power purchase contract or long-term interconnection agreement, the payment or transfer of property from the Qualifying Facility to the utility will promote reliability and economic efficiency throughout the grid and therefore may be warranted. Prior to the issuance of Notice 2016-36, however, such payment or transfer of property would have constituted a taxable CIAC under § 118(b) of the Code.

The IRS also took notice of the increased importance of renewable energy sources and their impact on the transmission and distribution of power throughout the United States. As a result, Notice 2016-36 also extends the provisions of the safe harbor to payments and transfers of property from solar and wind generators as well as energy storage facilities.

The updated safe harbor provisions are a welcome change and reflect new marketplace realities. If you have questions about Notice 2016-36 or the updated safe harbor provisions, please contact us.

By: Andrew S. Rusniak, Esq.

For many commercial and industrial companies, energy costs comprise a significant portion of their operating expenses.  Although many companies rely on their engineering, facilities management, and procurement departments to implement energy efficient strategies to reduce these costs, legal teams can also play an important role in ensuring that companies are making the most of every opportunity to reduce energy expenses.   For more information on how legal counsel can help companies create smart energy-management strategies, please click here for an in-depth report by Pamela Polacek, a Member of McNees Wallace and Nurick’s Energy and Environmental Group.

Each month, electric bills arrive like clockwork.  For large commercial and industrial businesses, especially those that are energy-intensive, these electric bills can represent a sizeable portion of a business’s monthly expenses.   Given the broad revenue collection ability of regulated utilities, businesses continue to see their electric bills increase to fund things beyond just the supply and delivery of electricity.  Compliance costs associated with things like energy efficiency and renewable energy mandates, economic development, payment assistance programs, and many more programs are often baked into the “price” of electricity that appears on a business’s electric bill.  Such is the case for businesses in Ohio and Pennsylvania.

Given the pressure on large energy-intensive businesses to not only manage the true cost of the supply and delivery of the electricity they consume but also to fund these additional programs through their electric bills, large energy-intensive businesses are constantly searching out tools to help control the magnitude of their bills.  One such tool, that goes by many names, is demand response (other names include interruptible capabilities, load shedding, and active load management).

Demand response represents the ability of a business to actively reduce the amount of electricity the business draws from the electric grid at specific times.  This typically occurs through the use of an on-site backup generator, shutting down or scaling back an energy-intensive business practice, or rescheduling an energy-intensive business practice to an off-peak time, typically the morning or evening.  Businesses with demand response capabilities can capitalize on those capabilities by avoiding certain costs and receiving compensation from both state and federal programs.

One significant challenge to the ability of businesses with demand response capabilities was recently resolved in favor of businesses. In February 2016, the United States Supreme Court, in F.E.R.C. v. Electric Power Supply Association (EPSA), upheld rules that provided compensation to businesses for committing their demand response capabilities to a regional grid operator.

Still, vital questions remain unresolved by the Supreme Court’s EPSA decision.  First, will states block businesses from participating in the federal programs? As things currently stand, the Federal Energy Regulatory Commission (FERC) has authorized states to block businesses in their states from participating in the federal programs.  Having lost their fight in the federal courts, electricity generators may turn to the states in an effort to block businesses from participating in the wholesale markets regulated by FERC.

Second, will FERC and the regional grid operators continue to rely on demand response resources?  While the Supreme Court has upheld FERC’s authority over demand response, PJM Interconnection (PJM), which is a regional transmission organization that serves 13 states, including Ohio, Pennsylvania and the District of Columbia, and other regional grid operators have taken and are taking actions to limit the scope of available federal demand response programs.

Third, how much compensation can demand response participants expect? Currently, demand response resources are generally paid the same amount as generators.  And we are talking big money:  PJM paid over $800 million to demand response resources in 2015 (these payments included all types of demand response in PJM, not just the specific demand response program at issue in EPSA).  As the ink was still drying on the Supreme Court’s decision in EPSA, FERC Commissioner Tony Clark encouraged the conversation to turn to whether the compensation that businesses receive for their demand response capabilities should be reduced.  So the question endures:  will customers continue to receive the same compensation as generators?

Getting help with energy costs

While the Supreme Court decision in EPSA is certainly good news for businesses, it is likely not the last word on the issue, and staying abreast of the varying state and federal electricity rates and programs applicable to businesses with demand response capabilities can be a daunting task.  McNees Wallace and Nurick’s Energy and Environmental Law Group frequently works with large energy consumers, state and federal regulators, and others in this dynamic area.

Matthew R. Pritchard practices in the Energy and Environmental Law Practice Group in the Columbus, Ohio office of McNees Wallace & Nurick LLC.  Joseph G. Bowser, a technical specialist in the Energy and Environmental Law Practice Group, assists clients of the firm with their participation in demand response programs. They can be reached at 614.469.8000 or mpritchard@mcneeslaw.com or jbowser@mcneeslaw.com

Earlier this year, the U.S. Supreme Court issued a decision in Federal Energy Regulatory Commission v. Electric Power Supply Association (“EPSA“) that significantly impacts members of the electricity industry.  In EPSA, the Court affirmed the Federal Energy Regulatory Commission’s authority to regulate demand response practices in wholesale power markets.  The Court also upheld the formula the Commission uses to set compensation for customers who curb their power consumption at the behest of system operators.

This decision holds many implications for members of the electricity industry, and will likely prompt an uptick in demand response participation in wholesale energy and capacity markets.  For more information about the implications of the EPSA decision, please click here  to watch a podcast by Robert Weishaar, Jr., Chair of McNees Wallace & Nurick’s Energy and Environmental Law Group.  Mr. Weishaar’s video provides a detailed overview of the case and discusses its short- and long-term implications for members of the power industry.

Since its adoption on September 6, 2015, the federal Clean Power Plan (“CPP”), the United States’ first comprehensive rule for lowering greenhouse gas emissions, has been a topic of simultaneous praise and criticism.  With respect to the impact of the CPP on future electricity costs, there are also significant differences of opinion.  Although the Environmental Protection Agency (“EPA”) acknowledges CPP compliance costs of $8.4 billion per year, the EPA contends that the CPP will encourage energy efficiency programs and switching to lower cost fuels that could eventually result in lower electricity costs for consumers.  By contrast, non-governmental organizations such as the National Economic Research Associates (“NERA”) estimate compliance costs at approximately $33.5 billion per year and predict an electricity cost increase of between 12 and 17%.  In light of such varying predictions related to the impact of the CPP on electricity costs, large consumers of electricity should, at a minimum, pay close attention to individual state implementation plan proposals to assess how these specific proposals may affect their electricity costs.

In addition to the questions associated with the CPP’s impact on future electricity costs, the future of the CPP is also subject to significant uncertainty.  On February 9, 2016, the United States Supreme Court issued a stay of the CPP preventing the EPA from enforcing the CPP until legal challenges are resolved by the federal courts.  As a result, the Supreme Court will not review the CPP until late 2017 or 2018.

The composition of the Supreme Court at that time will likely be the deciding factor regarding the CPP’s fate.  Specifically, since the death of Justice Antonin Scalia, the Supreme Court is considered to have four conservative Justices and four liberal Justices.  As a result, the upcoming Presidential election will almost assuredly determine whether or not the CPP will be upheld.  A President Hillary Clinton likely means a fifth liberal justice and the CPP surviving challenge at the Supreme Court.  A President Donald Trump likely means a fifth conservative justice and rejection of the CPP by the highest court.

Whether or not the CPP is upheld by the Supreme Court, however, the push by some for greenhouse gas reductions will continue.  The United States is now subject (as part of the Paris Agreement) to an international commitment to lower its greenhouse gas emissions by 26 to 28 percent from 2005 levels by 2025.  In addition, a number of states have adopted legislation and regulations to address climate change solutions or combat greenhouse gases directly.  For example, Pennsylvania’s Climate Change Act of 2008 requires Pennsylvania’s Department of Environmental Protection (“DEP”) to draft a Climate Change Action Plan that identifies greenhouse gas emissions baselines and recommends legislative changes to reduce greenhouse gas emissions in the Commonwealth.  Other states, such as California, have more aggressive and binding ambitions.

If you have any questions regarding the CPP or state proposals for reducing greenhouse gas emissions and the impact on electricity pricing, please do not hesitate to contact us.