On November 7, 2018, the Pennsylvania Public Utility Commission’s (“PUC” or “Commission”) Damage Prevention Committee (“DPC”) held its inaugural meeting in Harrisburg, Pennsylvania.  The DPC is a creation of Act 50 of 2017, which enhances Pennsylvania’s Underground Utility Line Protection Law (i.e., the “One Call Law”) to prevent accidental strikes.

Comprised of excavators, utilities, municipalities, and regulators, the DPC operates collectively to review incidents, identify what went wrong, and issue corrective actions (including penalties).  These review sessions are not legal proceedings and are essentially a measure to analyze mistakes and determine what actions will make accidental strikes less likely to occur.  The process for each review is as follows:

  1. The PUC’s investigator requests information from the project owner, facility owner, and excavator regarding the incident.
  2. The PUC’s investigator prepares a report and recommendation for the DPC.
  3. If the incident will be discussed at the meeting, the project owner, facility owner, and excavator receive written notice of the option to participate in the meeting.
  4. The PUC’s investigator provides the DPC with an overview of the incident and provides photos of the damage.
  5. The DPC asks each of the parties involved in the incident to explain what happened and what actions they took. The DPC prefers to hear directly from the parties, rather than from their lawyers.
  6. The DPC decides whether to issue penalties on any of the parties.

The DPC’s initial meeting revealed several key takeaways for utilities, excavators, and other entities:

  1. It’s important for any party served with a notice to appear before the DPC in relation to an incident to consider attending the DPC meeting to present that party’s side of the story and answer questions. Several DPC members noted their disappointment with parties that failed to attend.
  2. If any pipeline hit results in the release of flammable, toxic, or corrosive gas or liquid which endangers life, health, or property, then the excavator must immediately call 911 and notify the facility owner.
  3. The DPC considers whether the parties involved in the incident employed prudent excavation practices.
  4. It’s important that each party take clear photographs of the site where the strike occurred. With the availability of digital cameras, it may be advisable for excavators to take videos of the One Call Markings prior to beginning the project.
  5. It’s critical that each party record in writing any conversations with the other parties about the incident.

The next DPC meeting is December 11, 2018.  If you have any questions about the DPC or other Commission proceedings, please do not hesitate to contact Pam Polacek (ppolacek@mcneeslaw.com) or Aly Hylander (ahylander@mcneeslaw.com).

 

 

 

 

On November 29, 2018, the Pennsylvania General Assembly’s Nuclear Energy Caucus (“NEC”) released the “Bicameral Nuclear Energy Caucus Report” (“Report”) that details the NEC’s findings on nuclear energy issues during the 2017-2018 Legislative Session.  The Report finds that Pennsylvania’s five nuclear plants provide numerous benefits, including supporting jobs, providing zero-emissions energy, moderating electricity prices, and ensuring grid resilience and reliability.[1]  As a result, to avoid adverse “employment, economic, and environmental impacts associated with the premature closures” of Pennsylvania’s nuclear facilities, the Report suggests that Pennsylvania has four options to determine the future of its nuclear industry:[2]

  1. Do nothing and leave Pennsylvania’s clean energy resources, including its nuclear plants, on a trajectory to early retirement – effectively allowing PJM to dictate the mix of resources serving Pennsylvania.
  2. Modify AEPS (or establish a ZEC program) to put nuclear generation on equal footing with other zero-emission electric generation resources in Pennsylvania.
  3. Modify AEPS (or establish a ZEC program) with a “safety valve” mechanism that (depending on the outcome of the FERC proceeding) would allow Pennsylvania to adopt a new capacity construct proposed by FERC that is designed to accommodate state programs to support preferred generation resources.
  4. Establish a Pennsylvania carbon pricing program.

Despite the detail in the report, several questions remain unanswered and issues remain unaddressed:

  1. The Report does not specify the amount of subsidies that nuclear generators should receive. Any policy decision must include an analysis of the costs to consumers and the potential impact on employment and investment in Pennsylvania.
  2. The Report discusses testimony from a portion of the stakeholders (e.g., the nuclear industry, environmental advocates, and organized labor coalitions), but groups that serve as “watchdogs” to ensure that consumers’ costs and interests are considered by the legislature (e.g., the Pennsylvania Energy Consumer Alliance, the Pennsylvania Manufacturers Association, AARP, etc.) were not invited to testify before the NEC. By doing so, the NEC omitted a key stakeholder group that has a different perspective about the potential costs and pitfalls of “saving” the nuclear industry.
  3. The Report relies on a Brattle Group study to support the assertion that nuclear generators moderate electricity prices, thus providing $788 million in reductions to the energy costs of Pennsylvania’s consumers. However, that study assumes that there is no replacement of the retiring nuclear capacity with new generation.  Within the last three years, sufficient natural gas generation has been constructed (or is under construction) to match the entire Pennsylvania nuclear fleet, including those facilities that are not retiring (Susquehanna, Peach Bottom, and Limerick).  In December 2018 alone, Tenaska is scheduled to begin operation of a 925 MW plant in Westmoreland County.
  4. The Report summarily dismisses the fact that consumers paid $10 billion for stranded cost to the generation owners, without recognizing that those subsidies were calculated over the expected lifetime of the project. Once those payments were made, ratepayers were not expected to bear the financial risk that the plants could close.  Providing additional ratepayer subsidies is reneging on the bargain.
  5. Nuclear plants are not “prematurely” retiring – they are retiring because they cannot compete in the market. This is a natural effect of competitive market forces.  Non-competitive fuel sources (e.g., coal, inefficient gas, etc.) should retire from the market while stronger resources prevail.  Any attempt to interfere with these natural market sources will interfere with price signals and thus impact current and future investment in replacement generation.
  6. The Report makes errant assumptions (e.g., assuming that all Pennsylvania nuclear generators will retire) and misstates PJM’s conclusion in its fuel security study, which is still ongoing.

 

We are continuing to review the Report and will provide further updates.  In the interim, if you have any questions, please do not hesitate to contact David Kleppinger (dkleppinger@mcneeslaw.com), Pam Polacek (ppolacek@mcneeslaw.com), Kathy Pape (kpape@mcneeslaw.com), Kathy Bruder (kbruder@mcneeslaw.com), or Aly Hylander (ahylander@mcneeslaw.com).

[1] https://nuclearenergy.pasenategop.com/pennsylvanias-bipartisan-nuclear-energy-caucus-releases-report-detailing-impacts-of-losing-the-states-nuclear-industry-and-provides-options-for-taking-action-in-2019/

[2] Report, p. 30.

Recently, the Pennsylvania Department of Environmental Protection (“DEP”) issued a notice that the final draft of the Finding Pennsylvania’s Solar Future plan (“Solar Plan”) will be released this fall.  After receiving comments from businesses, utilities, nonprofits, academia, and citizens, the DEP will hold another stakeholder meeting on November 15, 2018, to discuss the final Solar Plan and present the draft strategy support guide.

By way of background, the Solar Plan began in 2017 as a statewide planning project led by the DEP’s Energy Programs Office (“EPO”).[1]  The goal of the Solar Plan is to equip Pennsylvania to produce more solar energy.  Specifically, the Solar Plan set a target that 10 percent of retail electric sales will come from in-state solar energy sources by 2030.  The DEP indicates that this 10 percent target is achievable but challenges the “business-as-usual” model and promotes development of a variety of strategies that could be pursued.  Essentially, to meet this 10 percent goal, approximately 11 gigawatts of solar energy must be installed in the State.[2]

In developing the Solar Plan, drafters considered five main strategies:[3]

  • Increasing the Alternative Energy Portfolio Standard (“AEPS”) requirements for solar to 4-8 percent by 2030;
  • Providing customers access to capital, including provision of loan guarantees;
  • Adopting carbon pricing;
  • Creating uniform policies for siting and land use; and
  • Considering tax exemptions that encourage solar deployment and assist solar projects in finding project sponsors with tax equity.

In addition to those core five approaches, the Solar Plan’s authors considered other strategies involving decentralized projects (i.e., solar panels on residences) and grid-scale solar projects.[4]

Stakeholder responses to the draft Solar Plan were varied, with some in support of the Plan and others critical.  Some commenters indicated that the Solar Plan impeded the goals of the Electricity Generation Customer Choice and Competition Act (“Competition Act”) because the Solar Plan proposed to reinstate centralized generation planning beyond what has already occurred with the existing AEPS statue.  In addition, concerns were raised about the costs of implementing strategies proposed in the Solar Plan and how those would be recovered.  While the planning phases for the Solar Plan were funded by a combination of a grant from the Department of Energy (“DOE”) and time and resource investments from DEP and other associated partners, it is unclear what the costs of implementing the Solar Plan’s programs would be or how (and from whom) those costs would be recovered.  Those questions may be answered at the November 15 stakeholder meeting with the release of the final Solar Plan.  In the meantime, if you have any questions regarding the information discussed above, please contact Pamela Polacek (ppolacek@mcneeslaw.com) or Aly Hylander at (ahylander@mcneeslaw.com).

[1] https://www.dep.pa.gov/Business/Energy/OfficeofPollutionPrevention/SolarFuture/Pages/Finding-Pennsylvania%E2%80%99s-Solar-Future.aspx

[2] Id.

[3] Id.

[4] Id.

On October 11, 2018, the Commonwealth Court of Pennsylvania (“Court”) vacated the Pennsylvania Public Utility Commission (“PUC”) Order approving the acquisition of the wastewater system assets of New Garden Township and New Garden Sewer Authority (collectively “New Garden”) by Aqua Pennsylvania Wastewater, Inc. (“Aqua”).[1]  Aqua’s Application sought PUC approval of the acquisition, a Certificate of Public Convenience to furnish wastewater service to customers in and around the service territory of New Garden, and, approval of a rate base predicated on the acquisition price, rate commitments and transaction costs.[2]

The Court remanded the case to the PUC to ensure all affected ratepayers (i.e., New Garden customers, as well as all Aqua customers) receive proper notice of the proposed acquisition, and to adduce additional evidence as to the full impact on rates for all Aqua customers of the Acquisition, and the other rate restrictions set forth in the Asset Purchase Agreement (“APA”).[3]  (i.e., the APA contains a two-year “rate freeze” in which New Garden customers would experience no rate increase, as well as a limitation that New Garden customers would have a ten-year cap limiting rate increases to no more than a compounded 4% per year, in addition to an Aqua commitment to fund $2.5M of capital improvements in the New Garden service territory).[4]

By way of background, in 2016, Pennsylvania Governor Tom Wolf signed Act 12 of 2016 (Act 12) into law, establishing a methodology for valuing water and wastewater systems owned by Municipal Authorities or Municipal Corporations to be acquired by a Public Utility.  Act 12 is codified in Chapter 13 of the Public Utility Code, 66 Pa. C. S. § 1329 et al.[5]  As the Court noted in the instant case, “[i]n sum, Section 1329 allows a utility to cover the full costs of its investment in purchasing the new system from ratepayers.”[6]

This law furthers the 2006 Pennsylvania Public Utility Commission Policy Statement (set forth at 52 Pa. Code §69.721) regarding water and wastewater system acquisitions where:

“…The Commission believes that further consolidation of water and wastewater systems within this Commonwealth may, with appropriate management, result in greater environmental and economic benefits to customers. The regionalization of water and wastewater systems through mergers and acquisitions will allow the water industry to institute better management practices and achieve greater economies of scale….”[7]

Under the terms of the APA intended to satisfy the requirements of Act 12, Aqua would pay New Garden $29.5M for the assets, which is almost 3x the systems’ fully depreciated original cost of $10.9M.[8]  Yet, the average of two Fair Market Value (“FMV”) appraisals required by Section 1329 was $32.1M.[9]  As Section 1329 requires use of the lesser of the purchase price or the average of the FMV appraisals, Aqua relied on the $29.5 million valuation.[10]

In hearings before a PUC Administrative Law Judge (“ALJ”), Aqua entered substantial evidence that acquisition will have no adverse effects on service provided to existing customers.  The Court noted “Aqua, however, provided no evidence regarding the effect on rates by increases on the rate base or the rate impact of the rate freeze provision or Compound Annual Growth Rate (“CAGR”) limitation to New Garden on existing ratepayers.”[11]

In addition, the Office of the Consumer Advocate (“OCA”) and the PUC’s Bureau of Investigation and Enforcement (“I&E”) both filed protests at this Docket and vigorously challenged Aqua’s Application and claims as to the rate impact on all Aqua customers.[12]  OCA challenged the $29.5M prospective rate base impact on all Aqua customers, as well as the additional embedded impact of a two-year rate freeze and ten-year rate cap for New Garden customers.[13]  In short, OCA argued the cost of acquiring New Garden to all Aqua customers would far exceed any net benefit gleaned from addition of New Garden customers.[14]

The ALJ, while finding the $29.5M APA was reasonable, nonetheless denied the request for a Certificate of Public Convenience (“Certificate”) on the basis that Aqua failed to show “… that all affected parties, including its existing customers, will realize any affirmative public benefits…” and Aqua’s existing ratepayers will have “to bear a disproportionate share of revenue requirements in future base rate cases….”[15]

The PUC later reversed the ALJ’s Recommended Decision and approved the $29.5M ratemaking rate base and directed that a Certificate be issued to Aqua to provide service in New Garden’s former service territory.[16]  The PUC disagreed with the ALJ and found Aqua proved the acquisition would affirmatively benefit the public, and that consolidation of Pennsylvania’s water and wastewater industry would advance significant economic and environmental benefits to all citizens and end users.[17]  However, the PUC did attach conditions for approval, including the filing of a Cost of Service Study in Aqua’s next rate case that separates costs, capital and operating expenses of providing wastewater service to New Garden customers as a stand-alone rate group.[18]  The PUC perceived this cost data, provided at a future time, would adduce an overall rate impact on all Aqua customers.[19]

The Commonwealth Court, while agreeing with PUC acceptance of “aspirational” statements as evidence of acquisition public benefits, disputed the PUC plan of reliance on a prospective Cost of Service Study to assess rate impact on all customers.[20]  Specifically, Section 1102 of the Code requires a balancing test to weigh all factors, including impact on rates, to determine if a public benefits exists as a result of this transaction.[21] The Court held this PUC determination must be made in the instant Application, and not in a prospective rate case.[22]  Accordingly, the Court directed the PUC to make a full determination and disposition of all issues, most especially rate impact issues at this Docket.[23]

As such, the Court remanded this matter to the PUC for, after actual notice to all affected ratepayers, a full explication of rate impact on all Aqua customers, as well as a more detailed explanation of all corresponding affirmative net benefits.[24]

It will be interesting to observe how participation of other interested parties impacts the analysis required under the law.  In any event, the proceedings before the PUC should provide additional guidance as to what evidence will be appropriate in terms of acquisition impact on existing customers.

[1] McCloskey v. Pa. PUC, 2018 Pa. Commw. LEXIS 559 (Cmwlth, Oct. 11, 2018) (“Court Order”).

[2] Application of Aqua Pennsylvania Wastewater, Inc. pursuant to Sections 1102 and 1329 of the Public Utility Code for Approval of its Acquisition of the Wastewater System Assets of New Garden Township and the New Garden Sewer Authority, Docket No. A-2016-2580061 (Dec. 15, 2016).

[3] Court Order at *27-*33.

[4] Opinion and Order, Application of Aqua Pennsylvania Wastewater, Inc. pursuant to Sections 1102 and 1329 of the Public Utility Code for Approval of its Acquisition of the Wastewater System Assets of New Garden Township and the New Garden Sewer Authority at 16-17, 27-28, Docket No. A-2016-2580061 (June 29, 2017) (“PUC Order”).

[5] 66 Pa.C.S. § 1329.

[6] Court Order at *3.

[7] 52 Pa. Code § 69.721.

[8] Court Order at *5.

[9] Id. at n.7.

[10] 66 Pa.C.S. § 13296(c)(2).

[11] Court Order at *8.

[12] Id. at *6.

[13] Id. at *6-*10.

[14] Id. at *9-*10.

[15] Application of Aqua Pennsylvania Wastewater, Inc. pursuant to Sections 1102 and 1329 of the Public Utility Code for Approval of its Acquisition of the Wastewater System Assets of New Garden Township and the New Garden Sewer Authority, Docket No. A-2016-2580061, Recommended Decision at 43-44 (Apr. 21, 2017).

[16] PUC Order at 72-73.

[17] Id. at 67-68.

[18] Id. at 73-74.

[19] Court Order at *14-*15.

[20] Id. at *23-*27.

[21] Id. at *27.

[22] Id.

[23] Id.

[24] Id. at *25-*33.

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.