On June 21, 2018, PJM Member GreenHat Energy, LLC, defaulted on a $1.7 million weekly invoice for an FTR position payable to PJM.  PJM does not absorb the cost of market defaults; rather, PJM Members cover the cost of market defaults through a “default allocation assessment” charged to all PJM Members.  The value of the weekly invoice that was the basis of GreenHat’s original default translates to a default allocation assessment to PJM Members totaling approximately $1.2 million.  However, this weekly invoice unfortunately represents just the tip of the iceberg with respect to the impact of the GreenHat default on PJM Members and the PJM market.  Below is more information to help understand the far-reaching ramifications of this significant event.

GreenHat was a participant in PJM markets for Financial Transmission Rights or “FTRs.”  GreenHat started acquiring so-called “long-term FTRs” in 2015 and held FTR positions in its portfolio through 2021 before its PJM Membership was terminated due to the default.  The value of GreenHat’s portfolio has declined since the FTRs were acquired.  Existing PJM Tariff rules call for PJM to liquidate the entire position at the next available auction in the event of a default.  Approaching the liquidation this way for the GreenHat default could result in significant risk premiums and ultimately raise the default allocation costs for all PJM Members.  With this concern, PJM filed a request with FERC on July 26 for a waiver of the tariff obligation and to allow for liquidation of the FTR positions for one-month forward in each of the FTR auctions conducted from July to October 2018 to allow time for consideration of alternate approaches to handle the GreenHat default.

PJM has quantified the actual net losses on the FTR portfolio for the months of June and July 2018 and the costs to liquidate the August 2018 positions utilizing the approach set forth in the waiver request to be $42.5 million.  Because GreenHat held positions into the future, PJM is unable to determine the full value of the final default allocation because the price of the future market is unclear.  As such, given the remaining GreenHat positions, the actual amount of the default could far exceed $42.5 million.

At the August 23rd PJM Markets and Reliability Committee and Members Committee, PJM Members undertook two actions.

First, upon the motion of Exelon and Old Dominion Electric Cooperative, PJM Members approved PJM requesting FERC approval to allow PJM to suspend liquidating GreenHat’s August 24 through November 30 positions in favor of allowing these positions to “go to settlement.”  Those market participants speaking in favor of this approach indicated it would allow PJM Members, if interested, to hedge the costs associated with the GreenHat FTR positions.  This approach is also a reaction to information that the August 2018 FTR auction resulted in liquidation prices that were as much as six times higher than the actual portfolio losses for the first half of August.

Second, PJM Members voted to continue stakeholder deliberations of alternatives to PJM Tariff’s current liquidation process for FTR positions held by a member that defaults, which could also potentially apply to the GreenHat default.

Customers purchasing power or selling generation directly or indirectly in the PJM wholesale market will be impacted by the GreenHat default, treatment of the GreenHat FTR positions, and default allocation assessment.  It’s important to keep in mind that a PJM Member default is handled through both a membership and a market activity allocation.  The membership portion (10%) of allocation is capped at $10,000 annually.  The activity allocation (90%) is based on a pro rata share of market activity in the prior three months from the event of default.  From a retail customer perspective, PJM charges a default allocation assessment to PJM Members, including those that serve as retail customers’ suppliers (known as Load-Serving Entities at PJM).

If a customer purchases energy under a fixed-priced or other structured energy contract, the customer’s supplier may seek to pass along the costs incurred due to this default allocation.  As such, the customer’s contract language should be closely reviewed to determine whether such costs can be collected from the retail customer.  Also, those market participants, including customers, with access to FTRs may want to consider the benefits of pursuing strategies to minimize their own default allocation assessment.

McNees is available to assist in reviewing energy supply contracts to assess risks of being charged a portion of the GreenHat default and help understand the impact of the GreenHat default on your company.   Please contact Susan Bruce, sbruce@mcneeslaw.com or Amy York, ayork@mcneeslaw.com for more information or with any questions.

Capacity prices cleared PJM Interconnection LLC’s (PJM) most recent auction for the “rest of RTO” region at $140.00 per megawatt-day (MW-day) for the PJM delivery year June 1, 2021 through May 31, 2022.  The rest of RTO region represents all of the unconstrained zones of PJM and makes up the majority of the PJM footprint.  The clearing price of this auction is roughly double the result for the rest of RTO region for the prior delivery year which cleared at $76.53/MW-day.

Five local delivery areas were constrained and cleared at prices higher than the rest of RTO region:  ATSI $171.33/MW-day, BGE $200.30/MW-day, COMED $195.55/MW-day, EMAAC $165.73/MW-day, PSEG $204.29/MW-day.

The auction cleared a total of 163,627 MWs, representing a 21.5% reserve margin over PJM’s projected peak demand for the 2021/22 delivery year.  The prior auction cleared 165,109 MWs, representing a 23.3% reserve margin.

Notably, the amount of nuclear capacity that cleared in the auction was 7,473 MWs less than the prior auction.  FirstEnergy Solutions (FES) announced that it failed to clear 3,865 MW of nuclear capacity: Davis-Besse (875 MW), Perry (1,212 MW), and Beaver Valley Units 1 & 2 (1,778 MW).  Exelon announced that it failed to clear roughly 3,500 MW of nuclear capacity in the Dresden, Three Mile Island, and Byron plants, with Three Mile failing to clear for the second consecutive auction.  Exelon also announced that it cleared its Quad Cities nuclear plant in Illinois in the auction, a plant that had failed to clear in the prior auction.

There was also a significant increase from the prior auction in non-traditional capacity resources.  Demand response increased 42% (7,820 MW to 11,126 MW), energy efficiency increased 66% (1,710 MW to 2,832 MW), wind increased 60% (888 MW to 1,417 MW), solar increased 456% (125 MW to 570 MW), and seasonal capacity increased 80% (397 MW to 715 MW).

PJM will conduct up to 3 additional incremental capacity auctions for the delivery year beginning June 1, 2021.  However, in the past the incremental capacity auctions have had little impact on the overall capacity price.

On April 5, 2018, the Pennsylvania Public Utility Commission (“PUC” or “Commission”) issued a Final Policy Statement Order on Combined Heat and Power (“CHP”).  The Commission seeks to promote and advance the development of CHP systems and facilities in Pennsylvania.  The Commission will require electric distribution companies (“EDCs”) and natural gas distribution companies (“NGDCs”) to file biennially a report that documents the utility’s strategies, programs, and other initiatives in support of CHP.  Importantly, the Final Policy Statement does not require or encourage the public release of CHP project-specific cost or usage data.

Background

In the Final Policy Statement, the PUC affirmed that CHP is an efficient means of generating electric power and thermal energy from a single fuel source, providing cost-effective energy services to commercial and industrial entities like hotels, universities, hospitals, manufacturing, and other businesses.  CHP also provides enhanced reliability for the end-user, improves manufacturing competitiveness, and reduces greenhouse gas emissions.  Other PUC-stated benefits include increased diversification of resources for generating electricity, expansion of natural gas and associated economic development, and increased security due to multiple points of power generation.

In the Final Order, the Commission established a biennial reporting requirement to reduce barriers to the development of CHP in the Commonwealth, such as 1) perceived difficulty in justifying capital investment in CHP; 2) costs of purchasing backup power during planned plant maintenance and unplanned downtime; and 3) lack uniform standards, fees, and procedures for the interconnection of distributed generation technologies.

Funding and Financial Incentives for CHP

The Commission emphasized that mechanisms to promote CHP projects should only apply to cost-effective projects and not uneconomical projects.  Because not all mechanisms for promoting CHP are administered under the Act 129 Energy Efficiency and Conservation program, the Commission expressed openness to other mechanisms but declined to establish new utility-based incentives to encourage CHP.

Creation of PUC CHP Working Group

The Commission ordered its Bureau of Technical Utility Services to initiate a CHP Working Group within 90 days of issuance of the Final Policy Statement Order. The temporary working group will discuss CHP reporting, processes, and related topics.

Definition of CHP in the Policy Statement: 52 Pa. Code § 69.3201

The PUC revised the definition of CHP by incorporating the Department of Energy’s definition, which defines CHP as the concurrent production of electricity or mechanical power and useful thermal energy (heating and/or cooling) from a single source of energy.  CHP is a type of distributed generation located at or near the point of consumption (unlike central station generation).  CHP consists of “a suite of technologies that can use a variety of fuels to generate electricity or power at the point of use, allowing the heat that would normally be lost in the power generation process to be recovered to provide needed heating and/or cooling.”[1]

The Utility Biennial Reports: 52 Pa. Code § 69.3202

In the Final Policy Statement, the Commission determined that CHP project-specific data “will not be reported or released to the public.”[2]  The Commission also emphasized that the reports will “only require the reporting include known information” as utilities will not need to generate or acquire information not known to the utilities.[3]  Further, individual customer information will be kept confidential and proprietary.[4]

All jurisdictional EDCs and NGDCs will report on proposed CHP strategies, programs, and initiatives rather than focus on historic efforts.  The report for both EDCs and NGDCs must include:

  • The utility’s detailed plans to encourage CHP development;
  • Identification of CHP systems interconnected with the utility;
    1. The location, nameplate capacity (MW), and basic operation of each system
    2. Payments made to the utility associated with the CHP interconnection
    3. Estimated projected annual energy and costs savings over life of CHP system
    4. Reliability benefits of CHP system
  • Identification of CHP systems scheduled for interconnection;
  • A discussion of challenges for CHP development;
  • A description of efforts made by the utility to obtain information for the report; and
  • The utility’s CHP system development communication strategy

In addition to the above requirements, EDCs must also report:

  • Interconnection terms and conditions (e.g., efforts to streamline procedures and contracts, dispute resolution, efforts to help larger CHP systems meet applicable interconnection standards, and recent changes to terms and conditions);
  • Monthly usage information regarding electric generation delivered to all customers with CHP;
  • The customer accounts with CHP systems; and
  • Tariffed rates for those customer accounts (including the rate design methodology for each customer, demand, and energy rate element).

NGDCs must also report:

  • Any separate rates for customer accounts with CHP systems;
  • Monthly usage information regarding natural gas delivered to all customers with CHP; and
  • NGDC capital costs incurred and not recovered from CHP customers as well as estimated incremental annual revenues associated with the CHP system interconnection.

PUC Staff Biennial Reports: 52 Pa. Code § 69.3203

The Final Policy Statement requires the Commission’s Bureau of Technical Utility Services to provide a biennial report to the Commission that summarizes and analyzes the EDC/NGDC reports, identifies government agency programs for financial incentives for CHP, and provides recommendations for further developing CHP in Pennsylvania.

Questions on CHP and the PUC Final Policy Statement

If any energy end users and customers are interested in CHP or have any questions or concerns regarding the Commission’s Final Policy Statement on Combined Heat and Power, please feel free to contact us at your convenience.

[1] Final Policy Statement on Combined Heat and Power at p. 12-13, Annex A.

[2] Id. at p. 16, Annex A.

[3] Id. at p at p. 16-17.

[4] Id. at p. 19.

Across much of the United States, the number of municipalities imposing stormwater management fees upon property owners has increased dramatically in recent years.  The rising prevalence of stormwater management fees has predictably led to local and state court challenges by businesses, as non-residential property owners are typically more severely impacted by stormwater management fees in comparison to residential property owners.  Affected businesses have questioned whether parcel-based stormwater fees constitute legitimate fees for services rendered or are simply revenue-generating taxes in disguise.

State courts have issued conflicting rulings on this question.  In the heartland, the Supreme Court of Missouri issued a 2013 decision striking down stormwater management fees and requiring municipalities to fund stormwater management programs through tax revenues.  In the northeast, the Supreme Court of Maine conversely issued a 2012 decision affirming a stormwater management fee program as a fee for services rendered.

It now appears that Pennsylvania jurisdictions will have an opportunity to weigh-in on this critical debate.  In January 2018, the Chester Business Association filed injunctions seeking to block imposition of a stormwater management fee proposed by the Stormwater Authority of Chester.  Similarly, an attorney and property owner in the city of New Castle filed a complaint with the Lawrence County Court of Common Pleas requesting that the court void stormwater management fees to be collected by the New Castle Sanitation Authority.

While the outcome of these cases remains uncertain, any decisions in these jurisdictions may not be dispositive as to rulings in other Pennsylvania jurisdictions, as stormwater management fees are complex and can be developed based on a variety of different models.  For both municipalities and businesses impacted by stormwater management fees, effective stakeholder engagement can ensure that legitimate stormwater management fees serve their intended purpose and avoid overly burdening property owners.  Attorneys at McNees can assist with review, analysis, and if necessary, litigation of stormwater management fees.

On January 25, 2018, the U.S. Environmental Protection Agency (“USEPA”) issued guidance withdrawing the “once in always in” policy for the classification of major sources of hazardous air pollutants (“HAPs”) under section 112 of the Clean Air Act.  Under the new guidance, sources of HAPs previously classified as major sources may be reclassified as area sources when the facility limits its potential to emit below major source thresholds.

The guidance supersedes the “once in always in” policy that had been in place since May 1995, shortly after promulgation of the HAPs MACT rule.  Its rescission should provide incentive for HAPs reduction at facilities that are major sources by virtue of HAPs emissions.

The policy memorandum finds that the 1995 policy memorandum is contrary to the plain language of the Clean Air Act, which the current EPA interprets to not contain a time limit on when a facility emits or has the potential to emit HAPs in excess of regulatory thresholds.

USEPA intends to publish the memorandum in the Federal Register for comment but has commenced implementing it.  The EPA page addressing the policy can be found here: https://www.epa.gov/stationary-sources-air-pollution/reclassification-major-sources-area-sources-under-section-112-clean

In our November 6, 2017 post, Amy York alerted readers to the impact of Act 40 (an omnibus spending bill passed by the Pennsylvania Legislature on October 30, 2017) on the state’s Alternative Energy Portfolio Standards (AEPS).  AEPS requires Electric Distribution Companies (EDC) and Electric Generation Suppliers (EGS) to procure a portion of the electricity they sell from alternative energy resources, including solar.

Traditionally, EDCs and EGSs have been able to meet this requirement by purchasing solar energy sourced anywhere in the regional transmission grid.  Act 40 limits the solar AEPS requirements to solar generation physically located in Pennsylvania.  As indicated in our November 6 blog post, this could eventually eliminate over 80% of currently-qualified solar generation and increase the price of solar renewable energy credits (SRECs) in Pennsylvania.

With the ink of Act 40 already dry, it now falls to the Pennsylvania Public Utility Commission to determine how to implement the Act – especially its “grandfathering” provisions.  A broad interpretation could permanently allow out-of-state solar generators that are already certified to sell SRECs in Pennsylvania to continue to do so.  It could provide a temporary grandfathered status to out-of-state solar generators that were not certified before October 30, 2017, but nonetheless had a contract to provide SRECs in Pennsylvania.  Finally, it could allow for “banked” out-of-state SRECs to still count toward Pennsylvania requirements.

In contrast, the Commission could take a narrow interpretation of the Act.  In that case, all grandfathering would be temporary—only for the duration of existing contracts.  An out-of-state solar generator without both Pennsylvania certification and an executed contract before October 30, 2017, would likely receive no grandfathering status.  It is unclear whether “banked” SRECs from non-grandfathered facilities would continue to count toward Pennsylvania requirements.

On December 21, 2017, the Public Utility Commission (PUC) issued a Tentative Implementation Order to provide its tentative interpretation of the new AEPS rules and to ask for comments.  The Commission’s proposed interpretation is broad, allowing permanent grandfathering status for currently-certified out-of-state solar generators.  However, Commission Chairman Gladys M. Brown and Vice Chairman Andrew G. Place issued a joint statement proposing a narrow interpretation of the Act and seeking comments.

The Commission will accept comments on these issues until February 5, 2018.  Sometime after that date, we expect that the Commission will issue a new Order providing its definitive interpretation.

To learn more about how the Commission’s decision will impact the Pennsylvania SREC market and Pennsylvania electricity prices, please reach out to us and follow this blog.  If your organization is interested in submitting comments to the Commission on this issue, we may be able to help.  Please do not hesitate to contact us.

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.

On November 8, 2017, Aqua Pennsylvania (“Aqua”) filed a Complaint in the Pennsylvania Court of Common Pleas of Bucks County against the Bucks County Water and Sewer Authority (“BCWSA” or “Authority”), docketed at Case #2017-07215.  Joining Aqua as co-Plaintiff is J. Kevan Busik, a customer and ratepayer of BCWSA.

The Aqua Complaint alleges BCWSA (and ostensibly, all PA Municipal Authorities) has a significant competitive advantage for acquisition of water/sewer systems and seeks redress.  Specifically, the Complaint cites unfair competitive advantage of BCWSA (and other PA Municipal Authorities) in light of its exemption from property taxation, ability to raise capital via the issuance of tax-free bonds, and freedom from the substantial expense associated with regulation.  In addition, it notes that because no regulatory body has oversight of BCWSA to limit its rate setting capability, BCWSA is able to amass funds to give it a competitive advantage.

On an ironic note, the Complaint indicates that neither co-Plaintiff Busik, nor any other current customer of BCWSA, would benefit from acquisition of any other water/wastewater system.

The Complaint cites four separate Counts:

  • Count I seeks Declaratory Judgment requesting a Court Order in favor of the Plaintiffs declaring that, pursuant to the Municipal Authorities Act’s (“MAA”) Noncompetition Clause, BCWSA is prohibited from competing with Aqua (or any other privately owned public utility) that serves the same substantial purpose by bidding on acquiring any water or wastewater provider.
  • Count II seeks Permanent Injunctive Relief that enjoins BCWSA from bidding upon and being competitive with Aqua in the acquisition of any water and/or wastewater provider.
  • Count III seeks Declaratory Judgment declaring BWCSA’s expenditure of revenue generated by its service area to purchase and acquire any water or wastewater provider to be prohibited under the terms of the MAA.
  • Count IV requests Declaratory Judgment declaring BCWSA’s rates unreasonable and invalid under the MAA because of BCWSA’s use of funds to acquire water and wastewater systems rather than solely for providing for payment of expenses, construction, improvement, repair, maintenance, and operation of Authority facilities and properties.

Aqua is a public utility providing water and wastewater services to various Pennsylvania residents and is regulated by the Pennsylvania Public Utility Commission (“PUC”).  BCWSA originally provided water/sewer service to residential, commercial, and industrial customers solely in portions of Bucks County, and only recently expanded its services beyond Bucks County.

Aqua notes that in purchasing and acquiring water/sewer systems from Pennsylvania municipalities, it is specifically bound by provisions of Act 12 of 2016, which sets forth procedural requirements for determining fair market valuation of acquired water and wastewater systems for ratemaking purposes.  BCWSA, in contrast, is not regulated by the PUC for provisions of service, setting of customer rates, or acquisition of new water or wastewater systems.  BCWSA also does not fall under the oversight of any other legislative or regulatory body that can limit rate setting, nor is it constrained by any Act 12 requirements.  BCWSA’s authority and powers are instead set forth, governed, and controlled by the provisions of the MAA.

Aqua’s Complaint further notes that pursuant to MAA, BCWSA is exempt from paying taxes or assessments upon property acquired or used by BCWSA for purposes of performing essential government services.  Similarly, BCWSA is authorized to issue tax-exempt bonds to finance its acquisitions and improvements of municipal water and wastewater systems, and the income from these bonds, including any profits made on the sale of these bonds, are exempt from taxation.  BCWSA’s operating income comes directly from the service revenues it receives from its water and sewer customers.

The Complaint identifies two local prospective sales of water/sewer systems in which both Aqua and BCWSA appear to be enormously interested (Cheltenham Township Sewer System and Exeter Township (Berks County) Wastewater System).  The Complaint also cites, for background purposes, BCWSA’s recent acquisition of the Springfield Sewer System.  BCWSA overcame two competitors – privately owned public utilities – and paid $16,500,100.  Aqua alleges the actual value of the Springfield System was approximately $9 million.

This Complaint will surely receive attention from all Pennsylvania public utilities and Municipal Authorities that have been looking to expand, by acquisition or combination, their water and sewer service territories.

 

Municipalities throughout Pennsylvania are in the process of implementing local stormwater ordinances and fees that will likely impact land development.  Recent changes to federal and state laws have forced municipalities to seek new funding sources, regulate businesses that have large areas of solid pavement and roofing (“impervious” areas), and limit stormwater impacts that occur from land development.  Businesses and developers should remain on the lookout for changes to local laws that will regulate stormwater, limit traditional land development, create quasi-governmental stormwater agencies (known as authorities), and impose stormwater fees.  Stakeholders should take advantage of opportunities to participate to limit any adverse impacts from these local government initiatives on their operations.  This article focuses specifically on Pennsylvania, but similar changes may be happening in municipalities throughout the country that are grappling with stormwater issues.

Businesses and land development within the borders of a regulated municipal separate storm sewer system (a system that has separate pipes to convey stormwater, known as an “MS4”) may be affected the most by local stormwater regulation, whether or not operations involve discharges into storm sewer pipes.  Municipalities regulated as MS4s have independent legal obligations related to stormwater management.  These obligations are implemented through their MS4 permits with the Pennsylvania Department of Environmental Protection (“DEP”).   An MS4’s compliance depends on land uses and practices of businesses within its borders.  One potential component of an MS4’s compliance is regulation of businesses and land development through ordinances.  For example, DEP requires minimum standards for stormwater controls in local ordinances and, to that end, has issued a model stormwater ordinance that MS4s are expected to implement, in some form, by September 30, 2022.  The permitting requirements are even more severe if the MS4 is within the Chesapeake Bay watershed or within an identified “impaired” watershed.

A list of the hundreds of regulated MS4s, by county, and their regulatory status is available on DEP’s website.  Businesses and developers within these listed municipalities, in particular, should be attentive to changes at the local level and take advantage of their opportunities to shape local laws to accommodate their current and future operations.  Below are some key points to consider.

Stormwater Authorities and Fees
Municipalities may now create stormwater authorities, which are separate local entities that have defined responsibilities such as stormwater planning, management, and implementation.  By law, stormwater authorities may generally impose “reasonable and uniform” rates.  A key point of contention at the local level will undoubtedly be whether rates imposed are “reasonable and uniform” based on the characteristics of the properties that are subject to the fees.

Fee structures vary widely from municipality to municipality.  The most simple is flat per-parcel fee. Another simple approach is the equivalent hydraulic area (EHA) approach, which features separate per-square footage rates for impervious area surfaces (parking lots and other paved surfaces) and pervious area surfaces (lawns, gardens, green rooftops).  Additionally, many municipalities may impose separate fees for non-residential and residential parcels, with residential properties typically charged a flat-fee, while non-residential properties pay more targeted fees designed to reflect each parcel’s total impervious area, such as a per-EHA rate. Typically, non-residential properties are subject to a broader range of fees based on higher variance in impervious surface areas among commercial and industrial parcels.  For example, a used car lot would likely pay more in stormwater fees than a hotel because used car lots cover a large swath of impervious pavement, while hotels would generally have a relatively smaller footprint of impervious area.

No matter how the municipality or authority structures its fees, the revenue generated from the fees may be used by MS4s to implement “best management practices” (“BMPs”) that control and reduce the discharge of stormwater, including sediment contributions (or “loadings”) to surface waters (sediment, or soil particles, is considered a pollutant).  BMPs can range from something as simple as more-frequent street cleaning, to something as burdensome as construction of retention basins and infiltration techniques.

Fee structures can (and should) include credit programs that reduce or eliminate fees for property owners who manage stormwater, such as by implementing their own BMPs.  A properly structured credit program will allow property owners to reduce the billed stormwater fees commensurate with reductions in stormwater runoff from the property due to implementation of BMPs.  Businesses should ensure that credit programs are considered and look for opportunities to implement BMPs that can result in credits and long-term cost savings.  Legal representation may be helpful to assist with proactive review of proposed stormwater programs in order to encourage development of fair and flexible stormwater fee structures.

Businesses and Development in the Chesapeake Bay Watershed
Businesses within the Chesapeake Bay watershed may be most affected by local regulation as MS4s attempt to meet more-stringent permit requirements in this region.  The Chesapeake Bay is considered “impaired” for sediment, nitrogen, and phosphorous.  Therefore, federal and state regulation have focused on these three pollutants and, in urban or developed areas, particularly sediment.  DEP permitting now requires MS4s in the Chesapeake Bay watershed to reduce sediment loadings to surface waters over the next several years and demonstrate those reductions (this is a new requirement for MS4 programs in Pennsylvania).  In turn, this means businesses and land development within the Chesapeake Bay watershed will be in the crosshairs for more local regulation through BMPs and fees.  Under DEP’s program, the amount of stormwater (or “volume”) is equivalent to “sediment” because higher volume results in stream scouring and stream bank erosion.  Businesses and developers may be forced to implement BMPs to reduce volumes discharged from properties where stormwater management was approved years or even decades ago.

Businesses and Development in Other “Impaired” Watersheds
Even beyond the Chesapeake Bay watershed, businesses and development within other, smaller watersheds throughout Pennsylvania that are considered “impaired” may be subject to additional local scrutiny for stormwater management.  MS4s are subject to additional permitting requirements similar to those for the Chesapeake Bay if they are located within certain smaller watersheds that are “impaired” for specific pollutants, including not only sediment, nitrogen, and phosphorous, but also pathogens, metals or acidity from abandoned mine drainage, and certain priority pollutants like polychlorinated biphenyls (“PCBs”) and pesticides.  In turn, this means the potential for more local regulation in MS4 municipalities that face these issues beyond the Chesapeake Bay watershed.

Opportunities to Participate and Cooperate
When municipalities propose ordinances, fees, BMPs, and other measures to regulate stormwater, stakeholders should take advantage of opportunities to be in the conversation.  Early participation in the development of fee structures, in particular, can ensure that assessments are fair, reasonable, and uniform and include credit programs for implementing desired controls, preventing the need for litigation later (which has been common for stormwater fees throughout the country).  This includes having you, legal counsel, or other representatives attend public meetings, file written comments, and organize businesses in similar situations to oppose any inequitable treatment.

In addition, MS4 municipalities may look to private landowners and businesses to help them implement BMPs on private property.  This can involve questions related to funding, design and construction, and long-term operation and maintenance (“O&M”) agreements to ensure ongoing effectiveness of BMPs.  It may also involve restrictions on property, such as through deed covenants or use restrictions.  The opportunity to work collaboratively with a municipality on such projects can be beneficial for stakeholders and help frame the outcome, resulting in a win-win if done properly.  These opportunities may also expand beyond the borders of a municipality and involve cooperation with regional and county-wide initiatives (e.g., in York County).

Conclusion
Businesses and developers must remain vigilant in tracking proposed local regulation of stormwater. Early participation by stakeholders or their representatives can reduce the regulatory burdens, present a positive community image, and result in savings in the long run.

Please look for this article in the upcoming January/February 2018 issue of Metropolitan Corporate Counsel!

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.