Governor Wolf has signed into law Act No. 40 under HB 118.  This Act, in addition to a number of other matters, adds language to modify the state’s Alternative Energy Portfolio Standards (AEPS).   For your convenience, the actual language from the Bill is included at the end of this post.

The AEPS became effective on Feb. 28, 2005.  It requires that a specific percentage of electricity sold to Pennsylvania retail customers by Electric Distribution Companies (EDC) and Electric Generation Suppliers (EGS) should be obtained from alternative energy resources.  The percentage amounts of electricity covered by the purchase of Tier I, Tier II and Solar Renewable Energy Certificates (SRECs) gradually increases each year through 2021.  By 2021, AEPs mandates that 18% of all electricity will come from alternative energy resources.

The Pennsylvania market for SRECs has been primarily oversupplied for several years.  This is in large part because PA was one of only two states that allowed sites outside of its geographical footprint to provide SRECs to satisfy the PA AEPS requirements. Currently there are a number of solar/photovoltaic sites in other states registered to provide SRECs to PA AEPS.  Below is a chart complied from the publicly available qualified facilities data on the PA PUC’s website:   (http://www.pennaeps.com/reports/)

 

 

You can see in the chart, at the present time, PA has only approximately 19% of the total nameplate capacity of facilities qualified to provide SRECs into the market coming from within its borders.   Despite this, Pennsylvania was the state of origin for 74.1% of the SRECs retired under the AEPS statute in the 2015 Reporting Year.

One of the expectations of restricting geographical eligibility to allow only those sites within the Commonwealth to provide SRECs to satisfy PA’s AEPS is that we will see an increase in the value of PA SRECs.  For reference, the current market price is approximately $5.00/2017 SREC and the alternative compliance payment (ACP) for 2016 was approximately $124/SREC.  In the 2015 Reporting Year, the weighted average credit price was $78.62/2015 SREC.  The ACP is calculated as 200% of the average SREC price paid over the compliance year which runs June to May.  The price impact of the restriction may take a few years to materialize because existing contracts with facilities outside of Pennsylvania are grandfathered.

The second expectation is that some of the in-state PA solar projects that may have previously been shelved due to financial decisions may now become viable.

If you need assistance with these projects, or any other renewable or on-site generation issues, McNees has a team of energy managers, engineers, accountants and attorneys to help you.  Please feel free to contact Amy York (ayork@mcneeslaw.com) or any of our attorneys in the Energy and Environmental Group for more information.

As promised, the actual language from the Bill:

This new language, effective as of the date of the Act, or October 30, 2017, added to AEPS requirements that solar systems satisfy one of the following:

(I) DIRECTLY DELIVER THE ELECTRICITY IT GENERATES TO A RETAIL CUSTOMER OF AN ELECTRIC DISTRIBUTION COMPANY OR TO THE DISTRIBUTION SYSTEM OPERATED BY AN ELECTRIC DISTRIBUTION COMPANY OPERATING WITHIN THIS COMMONWEALTH AND CURRENTLY OBLIGATED TO MEET THE COMPLIANCE REQUIREMENTS CONTAINED UNDER THE “ALTERNATIVE ENERGY PORTFOLIO STANDARDS ACT.”

(II) BE DIRECTLY CONNECTED TO THE ELECTRIC SYSTEM OF AN ELECTRIC COOPERATIVE OR MUNICIPAL ELECTRIC SYSTEM OPERATING WITHIN THIS COMMONWEALTH.

(III) CONNECT DIRECTLY TO THE ELECTRIC TRANSMISSION SYSTEM AT A LOCATION THAT IS WITHIN THE SERVICE TERRITORY OF AN ELECTRIC DISTRIBUTION COMPANY OPERATING WITHIN THIS COMMONWEALTH.

As to what will become of the facilities currently registered outside of the state to provide SRECs, the law says this:

NOTHING UNDER THIS SECTION OR SECTION 4 OF THE “ALTERNATIVE ENERGY PORTFOLIO STANDARDS ACT” SHALL AFFECT ANY OF THE FOLLOWING:

(I) A CERTIFICATION ORIGINATING WITHIN THE GEOGRAPHICAL BOUNDARIES OF THIS COMMONWEALTH GRANTED PRIOR TO THE EFFECTIVE DATE OF THIS SECTION OF A SOLAR PHOTOVOLTAIC ENERGY GENERATOR AS A QUALIFYING ALTERNATIVE ENERGY SOURCE ELIGIBLE TO MEET THE SOLAR PHOTOVOLTAIC SHARE OF THIS COMMONWEALTH’S ALTERNATIVE ENERGY PORTFOLIO COMPLIANCE REQUIREMENTS UNDER THE “ALTERNATIVE ENERGY PORTFOLIO STANDARDS ACT.”

(II) CERTIFICATION OF A SOLAR PHOTOVOLTAIC SYSTEM WITH A BINDING WRITTEN CONTRACT FOR THE SALE AND PURCHASE OF ALTERNATIVE ENERGY CREDITS DERIVED FROM SOLAR PHOTOVOLTAIC ENERGY SOURCES ENTERED INTO PRIOR TO THE EFFECTIVE DATE OF THIS SECTION.

Over the past few weeks, the Pennsylvania House of Representatives and Senate have passed most of the bills that make up the revenue package to fund the previously-passed appropriations in the budget.  Significantly, the proposals endorsed in July by the Senate and the Governor to increase the utility Gross Receipts Tax (“GRT”) on electricity, and to expand the GRT to natural gas service, are not included in the Tax Code portion of the final revenue package.  The final funding package also excludes the Marcellus Shale severance tax and the suggested application of sales tax to commercial storage services (which were very broadly defined).

We will provide more information regarding the entire budget and revenue package at a later date.  In the interim, if you have any questions, please feel free to contact Pam Polacek (717-237-5368) or Kathleen Duffy Bruder (717-237-5318).

After December 7, 2017, new Pennsylvania land development projects that disturb in total over an acre of land will require an individual National Pollutant Discharge Elimination System (“NPDES’) permit.  Although the Pennsylvania Department of Environmental Protection (“PaDEP”) missed the window to timely reauthorize General Permit PAG-02, it has administratively extended existing issued permits which have not expired and do not expire in the interim, until December 7, 2018.  PaDEP has also stated that it intends to reissue a final PAG-02 well before December 8, 2018, most likely by the spring of 2018.

Furthermore, by administratively extending the existing PAG-02, PaDEP enables any previously issued PAG-02 permit that will expire or require amendment after December 7, 2017, to be renewed or amended by Conservation Districts, provided the coverage area is not expanded and the renewal/amendment is applied for on or before December 7, 2017.  We caution, however, that only timely application for renewal will extend your existing PAG-02 beyond its expiration.

After December 7, 2017 (until PaDEP finalizes the PAG-02 reissue), all new or amended acre-plus construction activity stormwater permits must be individual NPDES permits. While individual permits are typically reviewed and issued by PaDEP, not Conservation Districts, PaDEP has indicated that if your project would have qualified for the PAG-02, you may submit the same information and fees and follow the same instructions for an individual permit application as you would have for a PAG-02 NOI (Form 3150-PM-BWEW0035), by checking the box for the “Individual” Permit Type. Similarly, if your NOI is pending and will not be issued by December 7, 2017, you should submit Form 3150-PM-BWEW0035, with the box for the “Individual” Permit Type checked.  Conservation Districts will conduct the entire review, with consultation with PaDEP as necessary, and will issue the individual permit.

However, if you do not anticipate beginning construction prior to the date PaDEP finalizes the PAG-02 reissue, you may submit your PAG-02 to your Conservation District and request that a review be conducted, but final action will be delayed until PaDEP completes the reissue.

Application for an individual permit would typically be published for comment (not simply the issuance). The permit itself may contain additional terms and conditions, and the full review would be performed by PaDEP. However, during this interim period, PaDEP has indicated that for new projects that would normally qualify for PAG-02 coverage, conservation districts will conduct the entire review (with consultation with PaDEP as necessary) and issue the permit. It further provides that the applicant may submit the same information and fees for an individual permit application as it would for a PAG-02 Notice of Intent, but make sure to check the box for “Individual” for Permit Type and follow the applicable instructions as if the applicant was submitting a PAG-02 NOI. Typically individual permits are reserved for projects in special protection waters and projects within an impaired watershed.

PaDEP has established a webpage for updated information on this “Construction Stormwater” Issue.  It may be accessed here.

If you have questions about construction stormwater permits in general or your project in particular, please contact either Scott A. Gould (717.237. 5304, sgould@mcneeslaw.com) or Steve Matzura (717.237.5276, smatzura@mcneeslaw.com).

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).

On May 18, 2017, House Bill 1405 was introduced into the Pennsylvania General Assembly.  The proposed legislation, which would restrict a municipality’s ability to utilize revenue generated by a municipal electric system, would significantly impact 35 municipalities in PA that purchase wholesale power on behalf of residents and distribute the power through municipal-owned electric distribution system.

Apparently, in response to complaints of high electric service costs from Ellwood City residents, HB 1405 was introduced to prohibit Ellwood City from using revenues from its purchased power and electric retail distribution services for any purpose other than paying the expenses for such services.  However, as currently drafted, HB 1405 would apply not just to Ellwood City, but to all 35 boroughs in the Commonwealth that purchase and distribute power for their local communities.  This bill would dramatically upset the status quo, as the Borough Code currently does not prevent boroughs from using electric service revenues to fund a variety of other operating expenses such as police, fire, and public works services.

In addition to banning the use of electric revenues to fund other municipal services or projects, HB 1405 would allow residents to challenge a borough’s electric rates in the local court of common pleas, restrict boroughs from adjusting electric rates more than quarterly, set rules for delinquent customer payment agreements, and prohibit termination of electric service for low-income customers during winter months.

Following its introduction to the House, HB 1405 was referred to the Committee on Local Government.  Various groups have announced support for the bill, including AARP, the Service Employees International Union, and the Pennsylvania Chapter of Americans for Prosperity (a tax reduction and deregulation advocacy group).  Opponents of the bill include the Pennsylvania State Association of Boroughs and the Pennsylvania Municipal League.

Of potential concern to many municipalities, HB 1405 would change the administration of borough-owned electric systems across the state based on complaints from customers in a single municipality.  Without expressing an opinion on the issues in Ellwood City, we note that many municipalities offer electric service to residents at competitive rates while also using electric revenues to fund general expenses that would otherwise require tax hikes for residents.

If you are interested in learning more about the status of HB 1405 and its impact on your municipal electric operations, please contact Adeolu Bakare at abakare@mcneeslaw.com or Kathy Bruder at Kbruder@mcneeslaw.com.

On July 8, 2017, The Pennsylvania Bulletin published a notice that the Pennsylvania Public Utility Commission (“PUC” or “Commission”) is seeking comments from stakeholders regarding electric distribution companies’ (“EDCs”) tariff provisions concerning the resale/redistribution of electric power to third parties.  Specifically, the PUC seeks comments regarding how those provisions would impact the operation and viability of electric vehicle (“EV”) charging stations.

Background on EVs in Pennsylvania

Over the past couple of years, the Commonwealth has witnessed an uptick in the number of registered EVs (rising from 1,653 vehicles in 2013 to around 3,600 EVs in 2016).  Although EVs continue to become more pervasive across the State, only 623 EV charging stations remain available to the public for recharging EV batteries.  As a result, the PUC believes all parties should take steps to foster increased investment in EV charging infrastructure across the State.  Accordingly, the PUC seeks comments from affected parties, particularly EDCs, on tariff provisions that account for EV charging stations.

Current Regulatory Framework Impacting EV Infrastructure

EV charging station owners purchase electricity from EDCs and resell that power to EV drivers with the goal of earning a profit from that sale.  The PUC believes that the current regulatory framework may restrict the ability of EV charging stations to earn a profit, which in turn would serve as a barrier to entry to this market.  Specifically, the PUC is concerned with Section 1313 of the Public Utility Code, 66 Pa. C.S. § 1313 (relating to price upon resale of public utility services), and EDCs’ tariff restrictions on resale/redistribution of purchased power.

Section 1313 indicates that an entity cannot resell power “to any residential customer” in an amount that exceeds what the EDC would bill its own residential customers for the same quantity of service under the EDC’s existing tariff.  On its face, this provision wouldn’t appear to impact an EV charging station owner because it resells power to an EV driver, not a residential customer. However, when viewed in connection with resale/redistribution provisions of EDCs’ tariffs, the PUC avers that Section 1313 may actually serve as a barrier to entry in this market by restricting EV charging stations’ ability to profit from sales of electricity to EV drivers.  EDCs’ tariffs vary widely and not all those tariffs address resales of power by a third-party EV charging station operators to EV drivers.  Further, some tariffs broadly permit the resale of power as long as it is compliant with 66 Pa. C.S. § 1313.

PUC Request for Stakeholder Comment on Potential EV Tariff Provisions

Because EVs continue to become more pervasive in Pennsylvania, the PUC believes all parties should take steps to foster increased investment in EV charging infrastructure.  As a result, the PUC seeks comments from affected parties, particularly EDCs, on the following topics:

  • What restrictions, if any, each EDC’s existing tariff places on the resale/redistribution of electric power by third-party EV charging.
  • The advantages and disadvantages of specific tariff provisions permitting unrestricted resale/redistribution of electric power when done for the purpose of third-party EV charging.
  • Whether it is appropriate to encourage EDCs across the state to move toward a tariff design which includes provisions permitting the resale/redistribution of electric power for third-party EV charging.
  • What other resale/redistribution tariff provision designs may aid in establishing clear rules for third-party EV charging stations.
  • What other regulatory options may aid in establishing clear resale/redistribution rules for third-party EV charging stations.

Comments on this issue are due to the Commission on August 22, 2017.  If you have any questions on this matter, please do not hesitate to contact any member of McNees’s Energy & Environmental Group or McNees’s Transportation, Distribution, and Logistics Group.

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.

 

 

The Susquehanna River Basin Commission (“SRBC”) approved a final rulemaking at its business meeting on June 16, 2017, that will regulate “grandfathered” water withdrawals and consumptive uses as we explained in our analysis of the proposal last Fall.  This new regulation will be effective January 2018.  While the SRBC revised the proposed rule in response to public comments, the thrust of the rule will remain the same:  grandfathered withdrawals and uses will be required to register with the SRBC and to be metered.  The registration requirements for grandfathered withdrawals and uses will result in closer agency scrutiny.  They could cause loss of grandfathered status, triggering full SRBC review and approval for failure to timely register or increases in quantities withdrawn or used.

Entities with grandfathered sources and uses should carefully analyze this final rulemaking and contact McNees for additional information.

The new regulation is important for currently regulated and future projects.  There are changes to general application provisions and procedures that will be effective sooner than the grandfathering provisions (upon the rulemaking’s publication in the Federal Register) and could more broadly impact projects.

Other aspects of the proposed rulemaking last Fall, which would have imposed mitigation requirements for consumptive uses beyond the typical payment of a consumptive use mitigation fee, were abandoned in the final rule.  The SRBC removed proposed provisions relating to mitigation plans from the final regulation, including provisions on “water critical areas.”  The SRBC also put its draft Consumptive Use Mitigation Policy on hold, indicating that it will further consider the public comments on these issues and go back to the drawing board in the future.

We will know more about the final rulemaking when the SRBC posts the text and a comment/response document on its website in the coming weeks.  Until the grandfathering rule becomes effective in January 2018, the SRBC will be working on the forms and additional guidance for registration.  Once the grandfathering rule is effective, registrations can be made for six months without any application fee.

McNees contacts who can provide assistance include:

 

Capacity prices cleared PJM Interconnection LLC’s (“PJM”) most recent auction for the “rest of RTO” region of PJM at $76.53 per megawatt-day (“MW-day”) for the PJM delivery year beginning June 1, 2020.  The “rest of RTO” region represents all of the unconstrained zones of PJM and makes up the majority of the PJM footprint.  This is the second consecutive auction where capacity prices have declined in the unconstrained PJM zones, while at the same time PJM was implementing more stringent capacity rules under the “capacity performance product.”  The clearing price for the 2018/19 and 2019/20 delivery years was $164.77/MW-day and $100/MW-day, respectively.

For the first time, the Duke Energy Ohio and Kentucky zone (“DEOK”) was constrained with capacity clearing at $130/MW-day.  The Mid-Atlantic Area Council (“MAAC”), Eastern MACC (“EMAAC”), and COMED Load Delivery Areas (“LDAs”) were also constrained with capacity clearing at $86.04, $187.87, and $188.12/MW-day in those LDAs, respectively.  The higher price in the EMAAC LDA was driven in part by 2,300 MW of generation retirements.  The MAAC LDA includes Potomac Electric Power Company, Baltimore Gas and Electric Company, Metropolitan Edison Company, Pennsylvania Electric Company and PPL Electric Utilities.  The EMAAC LDA is a subzone of MAAC and is comprised of Atlantic Electric Company, Delmarva Power and Light Company, Jersey Central Power and Light Company, PECO Energy, Public Service Electric and Gas Company, Rockland Electric Company.

In addition to decreased capacity prices, PJM cleared a record high reserve margin of 23.3%, representing a 6.7% increase over PJM’s target reserve margin of 16.6%.

Overall the supply and demand balance in PJM remained largely unchanged from the prior auction, with a 2,196.7 MW reduction of cleared capacity (165,109.2 MW vs. 167,305.9 MW) offset by a 2,800 MW decrease in PJM’s reliability requirement driven by lower forecasted peak demand (153,915 MW vs. 157,188 MW).  Notable changes for supply side resources clearing the auction included year-over-year increases in new generation (2,389.3 MW), capacity imports (121.3 MW), and energy efficiency (195.1 MW), and uprates to existing generation (434.5 MW).  Notable year-over-year decreases included a reduction of cleared demand responses (2,527.6 MW), wind (81.3 MW), and solar capacity resources (209.7 MW).

PJM will conduct up to three additional incremental capacity auctions for the delivery year beginning June 1, 2020.  However, in the past the incremental capacity auctions have had little impact on the overall capacity price.

On May 17, 2017, the Pennsylvania Environmental Quality Board (“EQB”) greenlighted a proposal that would substantially increase fees for public water suppliers regulated by the Department of Environmental Protection (“PADEP”).  In addition to seeking the fee hike, the proposal would amend other regulations under the Pennsylvania Safe Drinking Water Act (“SDWA”), with some changes being even more stringent than federal standards.  The proposal now will be published in the Pennsylvania Bulletin followed by a public comment period of at least 30 days.

Stakeholders should carefully review the proposal and consider submitting comments, including all community water systems, noncommunity water systems, and bottled, vended, retail, and bulk water suppliers.  Those affected may include municipalities with water supply systems and businesses that supply water to the public or their own employees.

Fee Increase

The SDWA allows the EQB to establish fees for permit applications and certain services, as long as those fees bear a reasonable relationship to the actual cost of providing a service.  The proposal would amend the SDWA regulations by removing the current fee provisions and adding a new subchapter relating specifically to fees for each public water system.  PADEP has explained that the purpose of the fees is to increase the agency workforce tasked with inspecting public water systems, which would occur over the next few years.  When coupled with other costs of maintaining a reliable supply of water through permitting and technical requirements, such as those imposed by the Susquehanna River Basin Commission (“SRBC”), the financial impact on suppliers may be significant.

The proposed annual fees are generally broken down by type of water system and population served.  For community water systems, the proposed fees range from $250 to $40,000 depending on the population served.  The high end for noncommunity systems and vended, retail, and bulk water suppliers is $1,000, while the fee for bottled water systems is $2,500.  Public water suppliers will also be subject to additional fees for permit and technical reviews.  For example, application fees for construction or modifications would increase from the general $750 charge currently, to upwards of $10,000 under the proposal, again depending on system type and population served.

Other Amendments

Several other amendments have been proposed to keep pace with federal standards and, in some instances, go beyond federal standards.  Some of the regulatory proposals that are more stringent than federal requirements include:

  • Amended turbidity and filtration requirements to prevent turbidity spikes and pathogens.
  • System resiliency requirements for back-up power to ensure a continuous supply of water is delivered.
  • Clarifications to monitoring requirements for back-up sources and comprehensive monitoring plan requirements to ensure that all permitted sources are subject to routine compliance monitoring.
  • Requirements for responding to significant deficiencies through a protocol for notification and corrective action.

Public water suppliers should determine whether these and other provisions may apply to their systems and, if so, consider the potential impact.  McNees contacts that can provide assistance include: