Recommended Decision Addresses Retail Natural Gas Market Changes, Improvements (Capacity Assignment, Storage Access, Balancing, More)
August 22, 2019 Email This Story Copyright 2010-19 EnergyChoiceMatters.com
Reporting by Paul Ring • firstname.lastname@example.org
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A Pennsylvania ALJ would adopt without modification a settlement among various parties in UGI Utilities - Gas Division's (the "Company") rate case that addresses various natural gas market issues
The rate case was used as a vehicle to implement, as developed in a collaborative, a uniform transportation program at UGI, as opposed to unique processes in its legacy distinct service areas.
The settlement provides that, except as specifically modified by the settlement and its terms noted below, the UGI's proposed Choice and Non-Choice transportation program rules would be approved and will become effective November 1, 2019, in the case of the Choice transportation program, and November 1, 2020, in the case of the Non-Choice transportation program
Settling parties include UGI, the OCA, the PUC's I&E Staff, OSBA, Direct Energy, and the Natural Gas Supplier Parties (NGS) and the Retail Energy Supply Association
Retail suppliers noted that the settlement provides non-choice (transportation) customers with the opportunity for more accurate metering which allows customers to lower costs by having exact delivery targets, includes less onerous cash out provisions, and an expanded ability to rely on No Notice Service (NNS) above the 4.5% threshold, albeit on an interruptible basis. Supplier operations will be benefited by consolidated delivery rules and tariffs and the opportunity, however remote, of having virtual access to storage
Terms of the settlement include:
Delivered Supply Service. Effective November 1, 2020, the Company will make necessary tariff changes in its compliance filing in this case to allow deliveries of delivered supply service available to a Natural Gas Supplier ("NGS") under the choice program to be used to meet its non-choice delivery requirements to the extent the delivered supply capacity is not needed to serve a NGS’s choice load. Such deliveries will be subject to delivery region deliverability requirements.
Non-Choice Daily Balancing. Effective November 1, 2020, the applicable daily balancing tolerance shall be four and one-half (4.5) percent.
Access to Storage. The Company commits to analyze the capability to provide a virtual storage proposal ("VSP") to NGSs who provide "choice" natural gas supply service on the UGI Gas distribution system that will allow suppliers to manage injections and withdrawals of supply through nominations made to the Company. The VSP analysis shall include a review of allowable mechanisms pursuant to FERC policy and rules in order to identify potential legal barriers and solutions, if any, and provide a strawman proposal to the extent the Company identifies a workable VSP construct. Such proposal may include, but may not be limited to, the identification of all associated costs related to specific asset utilization, administrative costs and IT architecture costs. The VSP analysis shall be completed no later than March 1, 2020. The Company will thereafter hold a collaborative meeting for stakeholder input, and pending the outcome of that collaborative, may thereafter make a VSP filing with the Commission; with such filing, if made, being no later than October 1, 2020. If UGI Gas determines not to make a filing, all parties expressly preserve their rights regarding future litigation of this issue.
Eligible Customer Delivery List. The Company agrees to modify its Eligible Customer List to provide associated customer delivery region designations. UGI Gas will continue to provide certain information concerning choice customers in accordance with the Commission’s customer information disclosure regulations at 52 Pa. Code §62.78. For non-choice customers, the Company will post a listing of account numbers and their respective delivery region designations on its website. Such posting will be made on a password protected website accessible only by authorized Company personnel and licensed NGSs qualified to do business on the UGI Gas system.
Acceptable Substitute Delivery Points. The Company’s proposal is accepted with the following qualifications. First, the Company will delay implementation of the interconnections with the Sunbury Pipeline and Mt. Bethel Pipeline as Acceptable Substitute Delivery Points for non-choice transportation customer deliveries until November 1, 2023, provided that those points may be used for purchased gas cost obligations and choice related peaking and delivered services. Second, UGI Gas shall provide written notice on its Gas Management Website of any proposed interconnection points within thirty (30) days of the execution of an Interconnection Agreement with the Company where the interconnecting entity elects to have the Interconnection Point included as an Acceptable Substitute Delivery Point. Such notice will include a posting of the interconnecting entity’s name and contact information with the express goal of allowing NGSs sufficient opportunity to consider adjustments to their supply plans.
Capacity Assignment. As reflected in Rule 22A.6 of the compliance tariff, effective November 1, 2020, the weighted average cost of demand ("WACOD") charges to customers, or their NGS, served under Rates DS and LFD, and who utilize assigned PGC capacity, shall be modified as follows:
(a) The WACOD charges for Rate DS shall include the associated demand charges for Peaking Services on a 100% percent basis, and the revised WACOD will be assessed to all Rate DS transportation customers;
(b) The WACOD charges for Rate LFD shall include the associated demand charges of Peaking Services on a 50% percent basis, and the revised WACOD will be assessed to all Rate LFD customers electing assigned capacity;
(c) The resulting WACOD charges under (i) and (ii) shall be reduced by the Economic Benefit of Peaking Service commodity supply defined in Rule 22A.6 (EBPS Credit), which shall be included as a monthly deduction (credit) to the WACOD calculation for Rate DS and Rate LFD customers on an actual experienced basis, subject to review and reconciliation through the 2021 PGC filing;
(d) Modifications set forth in subparagraphs (i) – (iii) shall be implemented without further change on a pilot basis, and will become permanent unless changed by order of the Commission pursuant to a proposed change by the Company or any other party, which proposal may become effective only for periods after December 1, 2021;
(e) The Company shall be held harmless in the application of the changes to the WACOD mechanism in this paragraph; and
(f) The Company shall post on its password protected gas management website the calculation of the associated demand charges and the EBPS Credit on a monthly basis.
The Company’s capacity assignment proposals for Rate XD are accepted as filed
Non-Choice Excess Imbalances
Cash-out Price. The Company’s currently effective cash-out pricing methodology (Sections 20.2c and 20.4 in the UGI South Rate District and UGI North Rate District Gas Service Tariffs No. 6 and 9, respectively, and Sections 16.3c and 16.5 in UGI Central Rate District Gas Service Tariff No. 4) shall remain unchanged up through and including October 31, 2020 ("Transition Period"). Effective on and after November 1, 2020 ("Post-Transition Period"), the Company’s proposed delivery region cash-out pricing methodology shall become effective. The Company will include in the compliance tariff rules applicable to each of the Transition Period and the Post-Transition Period.
Monthly Cash-out Volume. The Company will include in the compliance tariff rules applicable to each of the Transition Period and the Post-Transition Period. For the Transition Period the Company’s monthly cash-out rules, as proposed by the Company, will be unchanged. For the Post-Transition Period, the Company will specify a cash-out methodology that cashes out, for both long and short positions, only the increment that is greater than 5% (rather than cash out the entire balance) once the 10% threshold is exceeded, but shall otherwise be as proposed by Company.
Supply Nomination Process
Supply Nomination Process – The deadline for Delivered Supply under the choice program shall remain 8:45 am. The Company shall provide the Daily Delivery Requirement target no later than 8:15 am. The deadline for Bundled Supply under the choice program shall be extended from 9:00 am to 2:00 pm.
DUNS numbers – Effective November 1, 2019, the Company will institute a common DUNS number for the purpose of making customer and delivery nominations under the choice transportation program. Effective November 1, 2020, the Company will institute a common DUNS number for the purpose of making customer and delivery nominations under the non-choice transportation program.
Rate NNS. The Company will adjust the storage trip cost in the calculation of Rate NNS charges to $0.3483 per Mcf. The Company shall clarify in its tariff that Rate NNS service elections in excess of four and one-half (4.5) percent are interruptible. The resulting Rate NNS charges will be as follows:
NNS Unit Cost $/mcf: 0.0244
NNS Unit of Demand $/mcf per month: 0.4880
Rate MBS. The following changes to the Rate MBS shall be made: 1) OCA’s proposed inclusion of storage demand charges on a 100 percent load factor basis in the development of the rate shall be adopted; and 2) the Company will update the average monthly imbalance utilized in the development of Rate MBS charges annually with the actual average monthly imbalance for the 12 month period ending September to determine the new Rate MBS charges effective December 1 each year. The Company shall include the new Rate MBS charges as part of its annual PGC compliance filing. The resulting initial Rate MBS charges would be as follows ((with avg storage use = 1.54%, as-filed))
MBS – DS $/mcf: 0.0190
MBS – LFD $/mcf: 0.0110
MBS – XD Firm $/mcf: 0.0113
Merger of Southeast and Southwest Regions. The Company agrees to merge these regions. The updated delivery split requirements will be as follows:
Revised Delivery Regions and Requirements (Merged SW and SE regions)
Region: Delivery Requirement
North: 100% Tennessee
Central: 100% Transco
South: • 30%-45% Columbia MA 21, 23, 25, 29
• 55%-70% Texas Eastern (Up to 8% of Texas Eastern supplies may be delivered to meters West of Dauphin and York)
West: 100% Columbia – Market Area 36
Daily Metering Expansion. The Company’s proposal is accepted, as discussed in the Direct Testimony of Shaun Hart, UGI Statement No. 9, and the Company will exercise best efforts to transfer the remaining non-choice transportation accounts to calendar month billing and balancing pools by no later than November 1, 2020.
Producer List. UGI Gas shall release to suppliers a full list of producers directly connected to the UGI Gas system. Such posting will be made on a password protected website accessible only by authorized Company personnel and licensed NGSs.