PROPOSED RULEMAKING
PENNSYLVANIA PUBLIC
UTILITY COMMISSION
[52 PA. CODE CH. 62]
Proposed Rulemaking: Natural Gas Distribution Company Business Practices; 52 Pa. Code § 62.225.
[53 Pa.B. 6860]
[Saturday, November 4, 2023]Public Meeting held
October 19, 2023Commissioners Present: Stephen M. DeFrank, Chairperson; Kimberly Barrow, Vice Chairperson; Ralph V. Yanora; Kathryn L. Zerfuss; John F. Coleman, Jr.
Proposed Rulemaking: Natural Gas Distribution Company Business Practices; 52 Pa. Code § 62.225; L-2017-2619223
Order Withdrawing Rulemaking By the Commission:
The Pennsylvania Public Utility Commission (Commission) proposed at the above-referenced Docket an Advance Notice of Proposed Rulemaking to solicit comments on amending our regulations at 52 Pa. Code § 62.225. The proposed regulatory changes addressed the release, assignment, and transfer of capacity among Natural Gas Distribution Companies (NGDCs) and Natural Gas Suppliers (NGSs). The proposed changes resulted from the Commission's Natural Gas Retail Markets Investigation (RMI) and were intended to improve the competitive market by revising how capacity is assigned and addressing the related issues of penalties and imbalance trading. Based on the comments received, the Commission finds that due to the diversity of the NGDCs' systems and operations the viability and benefits of implementing the proposed changes is questionable at this time, accordingly, the Commission, by this order, is withdrawing this proposal and closing this Docket.
Background
The history of proceedings that led to the initiation of this ANOPR proceeding is thoroughly recounted in the Commission's Advance Notice of Proposed Rulemaking Order adopted by the Commission at the Public Meeting held on August 31, 2017, and will not be repeated here. Through that ANOPR Order, the Commission released for comment several proposals regarding (1) uniform capacity costs for all customers; (2) capacity assignment from all assets; (3) imbalance trading; and (4) penalty structures during non-peak times. At the August 31, 2017, Public Meeting, Chairman Gladys Brown Dutrieuille issued a statement in support of the ANOPR process to thoroughly deliberate the proposals.
The ANOPR Order was published in the Pennsylvania Bulletin on September 16, 2017, at 47 Pa.B. 5786, with comments on the proposals due within 45 days of publication. The Commission received comments from the following: Columbia Gas of Pennsylvania, Inc. (Columbia); Direct Energy Services, LLC, Direct Energy Business Marketing, LLC, and Direct Energy Business, LLC (collectively, Direct Energy); the Energy Association of Pennsylvania (EAP); Columbia Industrial Intervenors, the Philadelphia Area Industrial Energy Users Group, the Philadelphia Industrial and Commercial Gas Users Group, and the UGI Industrial Intervenors (collectively, Industrials); Mirabito Natural Gas, LLC (MNG); the National Energy Marketers Association (NEMA); National Fuel Gas Distribution Corp. (NFG); the Office of Consumer Advocate (OCA); PECO Energy Company (PECO); Peoples Gas Company LLC (Peoples); the Pennsylvania Energy Marketers Coalition (PEMC); Philadelphia Gas Works (PGW); the Retail Energy Supply Association and Shipley Energy (collectively, RESA); UGI Distribution Companies (UGI); Valley Energy, Inc. (Valley); and WGL Energy Services, Inc. (WGL).
On February 27, 2018, the Commission issued a Secretarial Letter announcing a Technical Conference to be held on March 29, 2018, where participants were given an opportunity to discuss the technical issues related to the proposed regulatory changes at this Docket and at Docket L-2016-2577413. The Technical Conference was held as scheduled.
Discussion
The Commission thanks the various stakeholders for their helpful participation and comments throughout this proceeding. We will briefly review the proposals and comments provided below.
I. Uniform Capacity Costs for All Customers
Capacity is generally released to NGSs to serve customers participating in the retail competitive natural gas market. This release can occur in different ways, but the cost of the capacity release is generally based upon the system average cost of capacity. In most service territories, an NGDC's capacity released for shopping customers are in turn paid for by the NGS providing the service.
A. Proposed Regulation
In the ANOPR, we proposed that applying Peoples' capacity payment mechanism statewide creates immediate and potentially lasting benefits for competition, including non-shopping customers. To accomplish this standardization the Commission proposed the following change to its regulations:
§ 62.225. Release, assignment or transfer of capacity.(a) An NGDC holding contracts for firm storage or transportation capacity, including gas supply contracts with Commonwealth producers, or a city natural gas distribution operation, may release, assign, or transfer the capacity or Commonwealth supply, in whole or in part, associated with those contracts to licensed NGSs or large commercial or industrial customers on its system.* * * * * (3) A release, assignment or transfer [must be based upon the applicable contract rate for] of capacity or Pennsylvania supply [and] shall be subject to applicable contractual arrangements and tariffs. Capacity or Pennsylvania supply costs shall be charged to all customers as a non-bypassable charge based on the average contract rate for those services.B. Comments
Columbia does not support this proposal for several reasons. First, through its 1307(f) process, Columbia already accomplishes what Peoples' standardized approach achieves regarding uniform capacity costs. Second, while Columbia could release capacity at zero cost, doing so would bring greater risk to Columbia's system as NGSs would have the ability to ''game the system'' by choosing to serve customers seasonally, thereby creating recovery issues for sales customers. Third, releasing capacity at zero cost and direct billing Choice customers would shift certain storage-related commodity costs, appropriately charged to Choice customers today under Columbia's average day program, to sales customers. Fourth, Columbia releases capacity to Choice NGSs on a recallable basis, however Columbia is not required to take the capacity back from the NGS if that capacity need decreases. Finally, Columbia is not aware of any supplier/marketer requesting that Columbia's program mimic Peoples' system. Consequently, Columbia does not support the codification of Peoples' capacity mechanism into existing Commission regulations. Columbia Comments at 7, 8.
If implemented properly, NFG does not object to this proposal but questions whether it would really result in an NGS offering innovative or lower priced services. To be sure, at least in some cases the NGS commodity price would be nominally lower because the capacity cost would be unbundled from the total cost. The same would be true for NGDC default supply service so comparatively there would be no difference; the change would be that the comparison would take place at a nominally lower rate. NFG believes the ANOPR's presumed efficacy of the Uniform Capacity Cost Proposal would benefit from a study comparing NGS rates to NGDC default rates that would include re-bundled rates in Peoples Natural Gas Company LLC territory. NFG Comments at 4.
PECO does not believe that maintaining capacity associated with critical assets for reliability purposes presents NGSs with a market disadvantage. PECO asserts that its virtual storage program eliminates the need to release capacity from critical assets. PECO releases the amount of capacity needed for each supplier to meet the suppliers' requirements, accordingly, NGDCs should not be required to provide virtual access to critical assets. PECO also expressed concern that virtual access could negatively impact reliability, noting that use of its LNG and Propane facilities must be weighed against existing demand and potential future demand requirements or PECO may not be able to meet its supplier of last resort requirements. PECO Comments at 4—7.
Peoples believes that this method has helped the development of the Customer Choice market in its service territory and can recommend this method. Peoples is concerned, however, that a regulation-prescribed method for assigning and recovering the cost of released capacity may be too restrictive and could limit potential responses to changes in the interstate capacity market. Peoples suggests that the Commission consider means other than a regulation for moving the natural gas Customer Choice marketplace toward consistent practices. The goal would be to encourage the adoption of consistent practices without locking the industry into a single methodology that could not be modified until a future rulemaking permits a change. Peoples Comments at 4.
PGW states that under the Commission's proposal, the suppliers would no longer have to pay for the capacity. Rather, all customers would pay for the capacity. Suppliers would still receive the capacity, and when a supplier re-releases capacity, the NGS would then be able to keep any payments generated from that—rather than it being returned to PGW's customers. Second, this change shifts the risk of collecting costs onto paying customers. PGW is also concerned about the feasibility of incorporating myriad interstate pipeline contracts for a multitude of different services into its billing system. Such wholesale changes could require significant modifications to PGW's billing systems and retail systems. Changes of this nature and breadth will necessarily be a costly endeavor. PGW believes that a one-size fits-all approach may not be the most effective method for handling capacity release. PGW states that the proposal does not work for PGW because it does not sit in or near production areas, and therefore, has much higher capacity costs. PGW respectfully recommends that the Commission continue to provide NGDCs with the flexibility necessary to release capacity in the best interests of its ratepayers and the NGSs that serve each NGDC's territory. PGW Comments at 3, 4.
UGI posits that to the extent the Commission wishes to proceed with the ANOPR's proposal to recover the costs of gas supply assets released, transferred, or sold to Choice Suppliers from customers, UGI believes that the Commission should require that sharing mechanism credits resulting from assets paid for and used by PGC customers alone should be credited to those customers alone. UGI believes that the regulations should not mandate a particular Choice program design but should instead provide the Commission with the flexibility to permit variations to deal with unanticipated conditions. While UGI believes the proposal could be workable, with language changes, UGI believes the potential benefits may be overstated and need to be weighed against the cost of implementation. UGI comments at 8—12.
Valley states that the proposed modifications will be difficult for it to implement and asserts that some of the changes may be inconsistent with the Public Utility Code. Accordingly, Valley requests that the Commission decline to implement the proposed changes or exclude small gas utilities from the requirements. Valley Comments at 4—8.
EAP emphasizes that what works well for Peoples may not be directly comparable or workable for other NGDCs. EAP also states that implementing this change by other utilities may result in significant cost shifts inconsistent with the utilities' obligation to procure least-cost fuel relative to the statutory SOLR role. EAP Comments at 10.
At this time, the OCA does not object to the adoption of this approach if it can be fairly implemented in other systems. The OCA notes that a careful review of each NGDCs Price to Compare may be necessary to facilitate this change. OCA Comments at 2.
Direct Energy supports the Commission's proposal and agrees that applying Peoples' capacity payment mechanism statewide creates immediate and potentially lasting benefits for competition, including non-shopping customers. Direct Energy notes, however, that the rule should apply to Choice customers and any non-choice customer for whom capacity is assigned by the utility, whether as a mandatory requirement or because of the customer requesting that capacity be assigned. Direct Energy agrees that a socialization of upstream assigned capacity costs has the potential of making the market more competitive, because recovering the capacity costs through a distribution charge will reduce the NGS' financial risks. Direct Energy Comments at 2, 3.
The Industrials submit that the Commission's proposal to establish uniform capacity costs for all customers is unjust and unreasonable. The Industrials state that such a proposal would be problematic for several reasons, including the failure to: (1) recognize the unique differences among customer classes; (2) consider the distinctive capacity requirements on the various NGDCs' systems; (3) identify the provision in Section 2204(d)(3) of the Public Utility Code requiring that the release, assignment, or transfer of capacity shall be at the applicable contract rate for such capacity; and (4) distinguish the fact that the cited Peoples Tariff provision does not apply to Large C&I transportation customers. Assuming, arguendo, that the PUC seeks to implement a non-bypassable charge for capacity costs, the Industrials respectfully submit that Large C&I transportation customers be carved out of any application of this charge. Industrial Comments at 2, 3.
MNG states that any rulemaking that socializes costs creates market price distortions (i.e., there is no benefit for efficient use) and removes one of the primary tools upon which suppliers can differentiate and compete. Further, socialization of such valuable assets for the purpose of reducing barriers to entry would be a net loss in competitiveness. Regarding risk of payment, suppliers must be held to credit, reliability, and default standards as would any other unregulated entity. MNG states that burdening customers with assets that are not useful in supplying their geographic location distorts market economics. MNG notes that market distortions occur where any socialization economically benefits some customers and negatively impacts others. Such distortion encourages expansion and contraction of gas service that is contrary to actual market costs and in the long run is not economically sustainable. MNG Comments at 2.
While NEMA appreciates the stated purpose of the proposal, the proposal does not address whether the uniform capacity charge mechanism will include a change in the underlying capacity release program. If the uniform capacity charge mechanism is not accompanied by a commensurate change in which assets are released to suppliers and which assets are retained by the utilities so that suppliers receive an allocation more closely approximating a true slice-of-the-pie than they currently receive, it is not clear that the suppliers will indeed be better off. NEMA is also concerned that capacity costs are properly allocated and unbundled from utility delivery rates and included in the charge. NEMA is further concerned that it may become more challenging to compete with the utility monopoly, not less so, under this proposal. NEMA Comments at 3, 4.
PEMC supports this proposal, particularly the proposed regulatory language that ''Capacity or Pennsylvania supply costs shall be charged to all customers as a non-bypassable charge based on the average contract rate for those services.'' PEMC believes this is an equitable approach, which will ensure system reliability to the benefit of all customers without placing the cost burden on a single group of customers. PEMC asserts that the proposal would minimize the risk of exposure for payment of capacity both from an NGDC and NGS perspective and provides for a level playing field in terms of risk of liability for non-payment of capacity. PEMC states that the proposal could reduce the financial barriers to entry into the market by reducing the upfront capital required to begin serving customers. PEMC Comments at 3.
RESA supports the Commission's proposal for a uniform capacity as a means of leveling the playing field. RESA asserts that access to capacity assets, both pipeline and storage, on a level playing field is critical in making the market competitive. RESA posits that it is axiomatic that if suppliers and the default supplier are to receive an equal slice of capacity for each customer, as Peoples provides today, the payment for that slice should be the same for each. RESA states that charging customers directly for capacity assets allows suppliers to avoid the risk of recovery of capacity payments and eliminate the complex systems that some NGDCs employ that charge suppliers and then credit customers against an otherwise identical capacity charge. RESA cautions, however, that the fundamental premise of charging all customers the same amount for capacity, is providing suppliers with a bundle of usable capacity assets that fairly represents the physical basis of the system average cost, otherwise the system average cost basis for the charge would not be appropriate. RESA supports the notion of assigning a representative slice of system capacity assets to suppliers and supports the notion that such slice should follow the customer. RESA notes that NGDCs should not be permitted to provide a functionally inferior bundle of capacity assets, or a slice that includes virtual access to an asset which may have a vastly diminished value compared to the actual asset, and then still charge the system average cost for capacity. RESA Comments at 2, 3.
WGL supports the proposed modifications and agrees with the benefits that they would provide to the market, suppliers, utilities, and customers. WGL states that the changes would potentially reduce the risk for suppliers and simultaneously enable them to enhance their services. WGL notes that by eliminating the need for suppliers to pay for capacity upfront and then be at risk to recover the payments just to break even, suppliers would have a greater opportunity to focus on providing more competitive and innovative products and possibly lower price offerings. WGL cautions that if NGDCs place a new line item on the utility bill it could confuse customers. WGL Comments at 3—5.
C. Disposition
We agree with the commenters that state that a one-size-fits-all approach to capacity assignments is not appropriate for all NGDC systems and operations due to the capacity assets available and the varying costs of those capacity assets for each NGDC. We also agree with the commenters who raise concerns about the cost shift associated with the proposal and the cost-effectiveness of implementing the proposal in several of the service territories. While the proposal may reduce the upfront costs to enter the market in some NGDC service territories, it has not been shown in these comments that such cost reductions would in fact be conveyed to customers. For these reasons we will not proceed with this rulemaking proposal and will withdraw the rulemaking and close this docket.
II. Capacity Assignment from All Assets
The Commission recognized that physical access to certain facilities may raise reliability and/or operational problems for NGDCs and their customers. Therefore, virtual access to the asset may be the best option to provide NGSs with the ability to utilize and benefit from the asset but still provides overall control to the NGDC for reliability assurance.
A. Proposed Regulation
In the ANOPR we proposed the following additions to the regulation at 52 Pa Code § 62.225(a)(2):
§ 62.225. Release, assignment or transfer of capacity.(a) An NGDC holding contracts for firm storage or transportation capacity, including gas supply contracts with Commonwealth producers, or a city natural gas distribution operation, may release, assign or transfer the capacity or Commonwealth supply, in whole or in part, associated with those contracts to licensed NGSs or large commercial or industrial customers on its system.* * * * * (2) A release of an NGDC's pipeline and storage capacity assets must follow the customers for which the NGDC has procured the capacity, subject only to the NGDC's valid system reliability and Federal Energy Regulatory Commission constraints. When release must be restricted due to reliability or other constraints, an NGDC shall develop a mechanism that provides proxy or virtual access to the assets.B. Comments
Columbia does not support this approach for a few reasons. First, Columbia's complex distribution system makes management of a ''virtual access'' approach extremely difficult due to its wide-spread geographic location, disaggregated markets, numerous market areas, numerous points of delivery and because of several pipelines feeding into its system. Second, the ''virtual access'' approach will create greater operational risk and reliability issues for Columbia's system. Third, given the issues identified above, Columbia would need to implement new systems and modify numerous existing systems just to attempt a ''virtual access'' approach with no identified benefits to justify these significant costs. Columbia Comments at 11.
While the NFG understands the ANOPR's intent for providing NGSs with broader, albeit indirect, access to restricted assets, the approach of a generic change to the applicable regulation ignores the unique operating circumstances applicable to and asset portfolios present in each NGDC's territory. Requiring NGDCs to develop a mechanism that provides proxy or virtual access to restricted assets appears counter to reliability because rather than permitting NGDCs to create different programs that meet each NGDC's unique reliability concerns, the ANOPR appears to advocate for only one solution—proxy or virtual access. The Virtual Access Mechanism language removes any balancing of the circumstances present; in effect it improperly presumes that restricted access provides a competitive advantage to the NGDC that must be remedied. NFG does not object to employment of virtual access mechanisms as an option but believes a better approach would be to address this concern on an NGDC by NGDC basis. NFG Comments at 6, 7.
Peoples believes providing virtual access to retained capacity can be done, again subject to conditions that may be specific to the capacity or to the NGDC's operations. In short, the implementation of the concept may have to be company specific and/or be flexible in the definition of proxy or virtual access to the assets. Peoples Comments at 5.
PGW submits that capacity assignment of restricted assets is best managed on an individual NGDC basis to account for distinct service territory and system design characteristics. As such, PGW proposes that no changes are necessary to the Commission's regulations on this issue. PGW Comments at 6.
UGI states that in the area it operates, it is not reasonable or prudent to assume that substitute gas supplies could be procured at reasonable cost during peak conditions if certain key gas supply assets unexpectedly become unavailable. While the ANOPR appropriately recognizes the existence of reliability assets, UGI asserts that it mistakenly assumes that these assets can be released if there are appropriate contractual restrictions on their use or imposed through operational flow orders (OFO). UGI states that a contractual restriction only gives the utility the right to sue for damages or specific performance, neither of which provide the required gas deliveries on short notice to meet SOLR obligations, potentially affecting reliability. Regarding OFO restrictions, UGI states that such restrictions only enable the utility to issue penalties or deny future service for any violations, noting that such penalties may be of no concern to an insolvent supplier or a supplier leaving the market. UGI states that its Commission-approved bundled city gate sales obligations constitutes the provision of virtual access to its core market gas supply assets that are appropriate for its systems. UGI Comments at 12—14.
Valley has substantial concerns with the proposed use of GCR assets by NGSs. Because Valley is served by a single interstate pipeline, Valley is prudent in arranging for sufficient interstate pipeline capacity to serve its GCR customers. Valley also contracts for storage services near its service territory to ensure operational reliability. Valley uses the pipeline capacity year-round to fill the storage, and then calls upon its gas in storage to meet peak demands during the winter and to balance its system. Even virtual access by NGSs to the assets could impair operational reliability practices in the territory. Valley Comments at 8, 9.
EAP asserts that the proposal is not feasible on all NGDC systems based on the capacity constraints and other unique characteristics that differentiate the eastern Pennsylvania market from the western Pennsylvania market. EAP states that the proposed contractual restrictions only provide legal recourse after the NGDC has already replaced the required gas delivery necessary to fulfill its SOLR obligations, should the initial assets become unavailable due to virtual release. EAP Comments at 10.
The OCA submits that more information is needed from the NGDCs regarding the proposed regulation change. NGSs and NGDCs would need to properly identify assets to which NGSs do not currently have reasonable access, or where current mechanisms are not adequate. The OCA further submits that virtual or proxy capacity access has not been a major issue in recent Purchased Gas Cost proceedings, so it is not clear to the OCA what benefit is sought to be achieved. The OCA further recommends that the Commission develop protocols for specific resources to ensure reliability. OCA Comments at 3.
Direct Energy agrees that capacity should be assigned, as near as possible on a slice of system basis. Direct Energy recognizes that some assets may not be assignable and accordingly supports the Commission's proposal to create virtual access to various supply assets. Direct Energy notes, however, that virtual access must be structured to insure that access is established on a non-discriminatory basis. Direct Energy asserts that it is important that if the asset creates cost advantages that reduce the cost of gas for the NGDC, then those same cost advantages should be shared with the suppliers. Direct Energy Comments at 4.
NEMA suggests that increased detail and transparency is needed associated with what is or will be deemed a reliability asset by the utility. Utilities should not be permitted to unduly restrict supplier access to assets. NEMA recommends that more information about how virtual pooling will work under the proposal be provided to stakeholders. NEMA Comments at 5.
PEMC supports the proposal for capacity assignment from all assets, subject only to the NGDC's system reliability needs and Federal Energy Regulatory Commission regulations. PEMC states that the NGDC must develop a mechanism that provides a proxy or virtual access to the facilities assets in question to provide suppliers with the ability to utilize and benefit from these assets while allowing the NGDC to maintain overall control for reliability. PEMC states that communication between the suppliers and the NGDC is paramount, and the use of a particular physical asset may be denied based on pre-established rules. PEMC Comments at 4.
RESA suggest that the Section 2204(d)(3) of the Public Utility Code, 66 Pa.C.S. § 2204(d)(3), requires more than the ANOPR acknowledges regarding the level and type of assets that must be released. RESA asserts that this section of the Public Utility Code requires that if an NGDC releases capacity at all, it must indeed release the assets that the company would otherwise have used to serve the customer or group of customers. RESA notes that while the virtual storage does address some of the downside risk, it also eliminates the potential for any upside with any profit gained by selectively releasing the capacity is shared between the asset manager and the utility. RESA asserts that virtual storage does not provide the same optionality as actual storage, even when considering the costs to the supplier of meeting the requirements of the storage operator for filling and withdrawing from that storage. RESA states that if the NGDC were providing a virtual asset that is less valuable than the actual asset, then fairness would dictate that if the NGDC makes any profit on the asset that it will not, or cannot assign, the supplier a share in that profit. RESA does not take issue with the use of an asset manager, but if the primary reason for the non-assignment of a fair slice of assets is the asset manager's need for profit, this would be discriminatory. RESA also contends that assigned capacity must also be usable by the supplier to serve the customers whom it follows—that is, it must reasonably represent the same bundle of assets that the NGDC would use to serve the same customers. RESA Comments at 2—5.
WGL does not support a rule that would change the current programs that utilities have in place to deal with critical assets. WGL believes that such a rule would result in additional, unnecessary burdens for suppliers without commensurate benefits. WGL recommends that the Commission make it standard that all capacity releases be executed monthly, rather than yearly. WGL Comments at 6, 7.
C. Disposition
Again, we agree with the commenters that the one-size-fits-all approach for proxy or virtual access to assets can create greater operational risks for some NGDCs and may not be feasible for some NGDCs. In addition, the proposal would require some NGDCs to implement new systems and modify numerous existing systems just to attempt a ''virtual access'' approach with no identified benefits to justify these significant costs. The benefits of the proposal may be suspect in that virtual storage does not provide the same optionality as actual storage, even when considering the costs to the supplier of meeting the requirements of the storage operator for filling and withdrawing from that storage. Commenters noted that the proposal would result in additional, unnecessary burdens for suppliers without commensurate benefits. Commenters also stated that more information about how virtual pooling would work under the proposal needs to be fleshed out prior to implementation. Commenters also noted that virtual or proxy capacity access has not been a major issue in recent Purchased Gas Cost proceedings, where the benefits of such a program can be determined on a case-by-case basis. For these reasons we will not proceed with this rulemaking proposal and will withdraw the rulemaking and close this docket.
III. Imbalance Trading
Penalties help ensure safe and reliable service in the natural gas market. While system reliability may be the primary mission of the NGDC, it is also a major focus of most market participants. In addition, it requires a cooperative approach between all market participants to ensure reliability. Improving upon this cooperative approach, therefore, should help to improve reliability in the natural gas market.
A. Proposed Regulation
In the ANOPR the Commission proposed that imbalance trading between market participants (both Choice and Transportation customers) should be a market feature. To implement this daily imbalance trading, the Commission proposed the following additions to the regulation at 52 Pa. Code § 62.225:
(5) An NGDC shall provide the opportunity for imbalance trading on the day the imbalance occurred. Capacity may be traded between market participants provided that either:(i) The trade improves the position of both parties.(ii) The trade improves the position of one party and is agreed to by the second party but does not negatively impact the second party's imbalance.B. Comments
Columbia does not support this recommendation for several reasons. First, Columbia's system is not built for trading between CHOICE and Transportation and therefore it cannot accommodate such trading. Second, permitting NGSs to trade imbalances across transportation programs could result in NGSs ''gaming the system.'' Third, for Columbia to implement and monitor such a program modification would require that the Company undertake expensive and time-consuming programming costs. Lastly, no party has requested this change and no clear reason as to the basis for such a change has been shared. Columbia Comments at 13.
NFG states that the use of the term ''Capacity'' in the proposed regulatory text is inconsistent with applicable FERC regulations, potentially exposing NGDCs to substantial penalties; capacity cannot be traded outside of FERC's capacity release mechanism. NFG believes this is simply an improper choice of language and proposes replacing the term Capacity with ''Gas Imbalances'' in the proposed Section 62.225. NFG, however, is concerned that the Daily Imbalance Trading Proposal is designed to address a problem that does not exist on its system and even if it did, due to illiquidity, is inferior to trading opportunities on the interstate pipeline system. NFG Comments at 13—16.
Peoples asserts that the allowance of imbalance trading would introduce a reliability risk that does not currently exist. Today, NGSs can trade gas supplies prior to the gas delivery day to satisfy their delivery target amounts. If, instead of acting proactively to manage deliveries, an NGS assumes that it can trade for gas at the end of or after the gas delivery day, and there turns out to be no other NGS in an opposite position with whom to trade imbalances, then the NGDC is left to manage that imbalance. Peoples Comments at 7.
PGW is opposed to daily imbalance trading for its interruptible transportation suppliers but may be amenable to interruptible transportation suppliers trading imbalances at the end of the month. Trading at the end of the month would help ensure better reliability than daily imbalance trading. However, before PGW could support such a proposal, it would need more developed information. PGW agrees that significant technology and system upgrades would be necessary to accommodate daily imbalance trading, as PGW's current system is not able to communicate with suppliers in real-time. Such upgrades would necessarily be costly. PGW does not support trading between interruptible and firm transportation supplier pools. Such a mechanism would be problematic because it could permit NGSs to manipulate the pools to create arbitrage opportunities that profit the NGSs at the expense of ratepayers. PGW Comments at 7.
UGI notes that it does not have smart meters that would permit the collection of real time daily imbalance information for its SOLR customers. UGI must ensure that appropriate deliveries are made to fulfill its SOLR obligations. UGI does provide a balancing service to handle any variations between the specified daily delivery amount and actual use. UGI Comments at 16, 17.
Valley has not implemented an EDI system and EDI will be needed to enable real-time information exchange regarding account usage, deliveries and over or under delivery status. Based on the experiences of Valley's sister-affiliates (Citizens' Electric Company and Wellsboro Electric Company), the costs to implement EDI will be $500,000 to $1 million. In a small territory like Valley's the cost equates to approximately $75 to $150 per customer. Valley suggests that implementing EDI to facilitate imbalance trading may not be cost-effective. Valley Comments at 9, 10.
EAP does not believe this proposal is workable or valuable to the marketplace and does not benefit customers. EAP states that most NGDCs don't have smart meters and cannot collect real-time, daily information from low volume market customers. The costs for implementing smart meters would be in addition to the IT costs necessary to update the NGDCs' electronic bulletin boards to enable such daily trades. EAP Comments at 11.
The OCA submits that it is not clear that there will be material benefits by creating daily imbalance trading. As a result, the OCA is concerned with the additional costs that will be incurred by developing the needed trading platform. The OCA states that it is unclear if there would be supplies available to trade imbalances on any day because all Choice suppliers should be delivering the requested amount. It may be that NGSs would find useful daily imbalance trading for only their larger, Transportation Program customers where the NGDC does not specify the daily amount to be delivered. The OCA submits that NGSs should be required to demonstrate a significant need for daily trading for Choice Program customers if those costs are to be incurred. Similarly, with respect to daily trading of capacity, there should be a demonstration of a significant need prior to the building of a daily trading platform. OCA Comments at 4, 5.
Direct Energy strongly supports the imbalance trading concept and notes that such trading is already permitted on some of the NGDC systems. Direct Energy also supports imbalance trading between Choice and Transportation programs, noting that artificial restrictions about imbalances trading between the two pools appears to be without operational justification. Trading between pools allows a supplier to offset a positive balance against a negative imbalance, causing no net impact on the system. Direct Energy Comments at 5.
NEMA supports the imbalance trading proposal on the basis that it is a source of flexibility for suppliers that provides suppliers with a means to minimize the costs to deliver natural gas to consumers. Moreover, by implementing a standardized approach as is proposed, it provides suppliers with a more definitive basis upon which to do business across utilities, thereby providing greater certainty of the costs of participating in the market. NEMA also agrees that communication of real-time information is critical for daily imbalance trading. NEMA Comments at 6.
PEMC supports the proposal for the trading of daily imbalances with the understanding that there may be system upgrades required to afford access to more real-time information. PEMC states that the proposal provides the ability for suppliers and the NGDCs to manage their portfolios in a more cost-efficient manner by minimizing imbalance penalties. PEMC Comments at 4.
RESA has long championed more uniform and market rational penalties. RESA asserts that the ability to trade imbalances among suppliers in near real time will allow suppliers to balance the market without resort to penalties, when one supplier might be long and the other short on a particular day. RESA acknowledges that daily read meters and IT systems capable of collecting and processing the information is needed, but there is not yet universal deployment of such systems. RESA wishes to be realistic and acknowledges that daily imbalance trading may be more than a few years out, due to the needed first step of upgrading metering capability on a statewide basis and all that such a task involves, even if consideration is given initially only to commercial customers. RESA Comments at 8.
WGL supports the Commission proposal if the rules do not cause a supplier or utility to go outside of the imbalance tolerance threshold, which has been ongoing in the marketplace without a rule in effect. WGL proposes a change to clarify that trades should be allowed between parties if they do not cause either party to go outside the utility's tolerance threshold. WGL Comments at 9.
C. Disposition
Commenters agree that significant and costly upgrades to NGDC systems are needed to accommodate daily imbalance trading. Commenters have also noted that no party has requested this change and no clear reason as to the basis for such a change has been shared with some commenters noting that the Daily Imbalance Trading Proposal is designed to address a problem that does not exist and may be inferior to trading opportunities on the interstate pipeline system. No commenter has demonstrated that the benefits of daily imbalance trading on every NGDC system would provide benefits in excess of the significant costs to upgrade NGDC systems needed to facilitate such a program. Accordingly, we will not proceed with this rulemaking proposal and will withdraw the rulemaking and close this docket.
IV. Penalty Structure During Non-peak Times
Penalties are a necessary market feature to help maintain system integrity and reliability. In Pennsylvania and within each NGDC, there is a difference in penalty structure during system peak demand periods and off-peak demand periods. Generally, system peak demand periods occur during the winter months (November through March) or when an operational flow order is issued. Penalties are appropriately higher during system peak demand periods because the harm to system reliability could be substantial. During the Retail Market Investigation stakeholder discussions, concerns were raised about the fairness of penalties during off-peak periods and corresponding questions about whether the penalties were sufficient to prevent inappropriate market behavior.
A. Proposed Regulation
In the ANOPR the Commission proposed a standardized penalty mechanism to reduce barriers to participation in the retail natural gas market. To implement this proposed standard, the Commission proposed the following additions to the regulation at 52 Pa. Code § 62.225:
(6) Penalties during system off-peak periods must correspond to market conditions.(i) An NGDC shall use the system average cost of gas as the reference point for market based penalties. If an NGDC takes service from a local hub, it may use the local hub as a reference point for market based penalties.(ii) The lowest penalty must be set at the market price.B. Comments
Columbia opposes this proposal for several reasons, not the least of which is because NGDC systems do not function like EDC systems. First, Columbia notes that it does not operate its system in a vacuum. Rather, Columbia communicates and works regularly with NGSs to resolve issues like that of penalties. Columbia transformed its operational order penalty structure from a flat rate to a market-based rate as part of the settlement agreement in Docket No. R-2016-2529660. Second, an off-peak price structure would not work for Columbia as the Company is subject to operational orders during both peak and off-peak periods. Third, because Columbia has a very wide-spread geographic footprint served directly by six different pipelines it sees a very wide range of prices on the pipelines delivering to its system and has very little flexibility to maneuver receipts from pipeline to pipeline. Lastly, Columbia maintains that a standardized penalty structure works for EDCs but is not a realistic model for NGDCs due to system constraints and the vastly different array of resources the NGDCs must manage. Columbia Comments at 19, 20.
NFG states that while the text of the ANOPR appears to take reliability into consideration, the proposed regulatory addition doesn't capture the reliability discussion in the ANOPR. This is not to say that market pricing cannot be factored into penalties but if done improperly, market- oriented penalty pricing creates a gaming opportunity that would benefit NGSs that fail to meet their delivery obligations to shopping customers at the expense of non-shopping customers. NFG Comments at 17.
PECO supports using penalty structures that are market-based and that prevent opportunities for arbitrage, however, PECO states that a one-size-fits-all approach will not work for all NGDCs. PECO states that if the penalty is not properly aligned with the specific Choice program, system balancing problems could result. PECO Comments at 8—10.
Peoples' current practice is consistent with this proposal. It provides a market-based cash out value but carries a high enough market premium/discount to encourage NGS attention to delivery obligations and protect retail customers from serving as a free balancing service for Choice suppliers. Peoples Comments at 8, 9.
PGW's daily imbalance penalty structure is designed to protect the reliability of its system by providing appropriate penalties. PGW believes that each NGDC should be provided maximum flexibility to design penalty mechanisms that best fit its unique distribution system needs. PGW would, therefore, recommend that no changes be made to the current regulations. PGW Comments at 10, 11.
UGI states that if system reliability rules are reasonable and clearly communicated, and penalties are appropriately set to deter risky behaviors, suppliers should be able comply with the reliability rules and avoid penalties. UGI believes that if suppliers can avoid penalties, such penalties should not be considered a barrier to increased participation in the market. UGI further asserts that reliability penalty assessments have not been significant, and thus cannot be considered a significant barrier to the market. UGI Comments at 20.
EAP believes that the current system-specific penalty structure is working to appropriately deter bad actors and avoid compromises to utility reliability. EAP notes that the effects of arbitrage might also be felt by other system customers, jeopardizing wider system supplies. EAP Comments at 12.
The OCA submits that the UGI standard for delivery shortfalls for off-peak periods provides adequate protection for NGDCs. However, it only appears to address shortfalls, not over deliveries. The OCA submits that the proposed regulation appears to be misstated in requiring that the lowest penalty must be set at the market price rather than the difference between published and local market prices. OCA Comments at 6.
Direct Energy supports the Commission's proposal, noting that market-based mechanisms are fairer and more dynamic, and will serve as an effective deterrent to behavior that may threaten operational integrity. Direct Energy, however, does not support a need for a minimum penalty structure. Direct Energy Comments at 6.
The Industrials submit that penalties must consider the actor involved, the impact on the system, and degree of the injury, which is not currently the case. The Industrials recommend that NGDCs not charge penalties, but rather, simply charge the market rates for the imbalance when: (1) an NGS has an imbalance in an opposite direction of the overall system imbalance, resulting in the imbalance aiding the NGDC; (2) the imbalance is caused by the NGDC; or (3) the overall system remains in balance despite various NGS imbalances that negate themselves. The Industrials assert that implementing these changes would still assure that all market players are working towards a balanced system while not unreasonably penalizing a market participant for an error that caused no harm. The Industrials also propose that the Commission adopt a more flexible mechanism, like PGW's and PECO's, that allows suppliers to make-up gas in the summer to alleviate supplier imbalances. Industrials Comments at 7, 8.
NEMA agrees that penalties should be market-based. Additionally, NEMA states that penalties should be focused on deterring actual problems and not be unnecessarily punitive. NEMA notes that off-peak penalties should properly be designed so the punishment fits the crime and that the use of a multiplier in computing a penalty should be limited to a reasonable percentage, reflective of the off-peak period. NEMA Comments at 7.
PEMC supports the proposed penalty structure during non-peak times with the understanding that all NGDCs would establish penalties for system off-peak periods based upon its local gas costs. PEMC states that a straight multiplier could be used to generate the penalty during system off peak periods. At the same time, PEMC believes it is imperative to maintain the discretion of the NGDC to waive penalties, as appropriate, especially if the supplier does not flow the correct amount of gas due to inaccurate information from the NGDC or if an imbalance benefits the NGDC system daily balancing position. PEMC Comments at 5.
RESA agrees that penalties provide a meaningful tool to enforce delivery requirements. RESA states that to the extent penalties are based on actual market prices, however, with a rational multiplier, they will continue to provide an incentive to comply, while not exposing suppliers to extreme risk for non-compliance which can often be the result of mistakes, as opposed to intent to do so. RESA agrees that the Commission's vision that such requirements and the consequences for non-compliance be uniform across all NGDCs is a good way to avoid continual litigation of penalties. RESA also agrees that having a rational and uniform penalty structure on a statewide basis will eliminate barriers to entry and allow suppliers to better understand the risks of providing service. RESA further agrees at a market price multiplied by 115% would be a reasonable maximum penalty for non-delivery on a non-peak day. So long as the market price is determined by indices that are relevant to the service territory, RESA asserts that this should produce the appropriate incentives for compliance. RESA Comments at 9, 10.
WGL notes that utilities can now impose summer penalties on suppliers and that the penalties can be unreasonable. WGL submits that suppliers should have greater flexibility during the summer and proposes additional language. WGL Comments at 10, 11.
C. Disposition
While most commenters agree that a market-based penalty structure provides appropriate incentives to maintain system reliability during peak and off-peak periods, most commenters note that such a penalty structure may not work in every service territory due to each NGDCs unique configuration and operation. Accordingly, we agree with the commenters that state that a one-size-fits-all approach will not work for all NGDCs and that each NGDC should be provided maximum flexibility to design penalty mechanisms that best fit its unique distribution system needs. Accordingly, we will not proceed with this rulemaking proposal and will withdraw the rulemaking and close this docket.
Conclusion
As the changes to the Commission's regulations proposed in this proceeding may not work in every service territory due to each NGDC's unique configuration and operational characteristics, the resulting significant costs to implementing the changes and there not being demonstrated benefits in excess of those costs and operational risks, the Commission is withdrawing the proposed regulatory changes. The Commission appreciates the time and effort all stakeholders provided in this proceeding to inform the Commission and the regulated community more fully on natural gas distribution company business practices and potential opportunities to improve those practices; Therefore,
It Is Ordered That:
1. The instant rulemaking at Proposed Rulemaking: Natural Gas Distribution Company Business Practices; 52 Pa. Code § 62.225, Docket No. L-2017-2619223 be marked closed.
2. A copy of this Order be served on all jurisdictional natural gas distribution companies, the Office of Consumer Advocate, the Office of Small Business Advocate, the Commission's Bureau of Investigation and Enforcement and the parties that filed comments in this proceeding.
3. The Law Bureau shall deposit this Order with the Legislative Reference Bureau to be published in the Pennsylvania Bulletin.
4. The Office of Competitive Market Oversight shall electronically send a copy of this Order to all persons on the contact list for the Committee Handling Activities for Retail Growth in Electricity.
5. A copy of this Order shall be posted on the Commission's website at the Office of Competitive Market Oversight web page and on the web page for the Retail Markets Investigation—Natural Gas.
6. This Docket be marked closed.
ROSEMARY CHIAVETTA,
SecretaryORDER ADOPTED: October 19, 2023
ORDER ENTERED: October 19, 2023
[Pa.B. Doc. No. 23-1509. Filed for public inspection November 3, 2023, 9:00 a.m.]
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