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New York Utilities To Continue Current Supply Hedging Levels, Discuss Specifics In Rate Case

Propose Change In How Customer UCAP Calculated

May 22, 2019

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Copyright 2010-19
Reporting by Paul Ring •

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In a newly filed rate case, NYSEG and Rochester Gas & Electric (the "Companies") stated that they would continue the current 70% hedging level for residential electric customers

For electricity, NYSEG and RG&E take additional energy and capacity hedges for non-time-of-use residential (NYSEG Service Class ('SC')-1 and RG&E SC-4 Residential Service) and small commercial/industrial variable rate customers (i.e., mass market or Default Supply Option) to achieve certain energy and capacity hedge levels. NYSEG’s and RG&E’s current target is approximately 70% for these customers.

The Companies no longer procure additional energy and capacity hedges for the voluntary residential time-of-use customers (NYSEG SC-8 and SC-12, and RG&E SC-4), as provided in the Commission’s June 15, 2016 Order Establishing Rate Plan in Cases 15-E-0283 et al. ('2016 Rate Order').

In testimony, the companies said that they will continue to maintain the current 70% hedging level for residential electric customers

"The 70% level strikes a reasonable balance between mitigating market price volatility and allowing customers to experience some exposure to market prices. The Companies periodically review the hedge percentage through consultation with Staff. Lastly, as noted in the Electric Supply Planning and Management Chapter (Chapter 17, Recommendation 2) of the Management Audit Report, it was recommended that the Companies '[c]ontinue the 70% hedging target and periodically evaluate its appropriateness,'" a panel of Company witnesses said

"The additional physical or financial hedges that the Companies take to achieve an approximately 70% hedge level for residential, Company-supplied customers would be allocated equally by load share between residential and small commercial/industrial customers. Small commercial/industrial customers are hedged at a slightly lower level because these customers do not receive the benefit of NYPA hydropower. Thus, the only difference between residential and small commercial/industrial customers’ hedge levels would be the residential customers’ allocated share of NYPA hydropower," the Companies said

Discussing the electricity hedging strategy further, the panel said, "No entity, including NYSEG and RG&E, can accurately predict electricity supply market prices. A structured program that layers in hedges over time will smooth out the impact of price volatility. Hedging too far into the future would expose the Companies’ customers to the risk of customer migration. For example, if a large number of customers unexpectedly migrates to an energy service company ('ESCO'), the remaining customers would bear the cost of all these hedges."

The panel explained that the Companies take on long-term electricity hedges on a 24-month rolling basis. NYSEG and RG&E hedge approximately 1/8 of their open position each quarter (subject to standard market products) such that, coupled with the Companies’ remaining resources, the desired hedge percentages are achieved prior to the start of the period for which the hedges are applicable.

The panel further testified that, "Financial energy hedges generally trade in 25 MW blocks. In addition, certain months trade together: winter (January and February); spring (March and April); summer (July and August); and fourth quarter (October – December). May, June and September trade individually. Rather than pay a premium for a non-standard product, NYSEG and RG&E generally use standard trading blocks to hedge commodity purchases taken on behalf of variable price residential customers."

The Companies' UCAP hedging practices are generally the same as used for electric energy, with the exception that UCAP hedges are taken on a calendar year basis so that hedges are taken quarterly for two years in advance of the calendar year being hedged. For example, any UCAP hedges executed in June of 2019 may be for Calendar Year 2020 and/or Calendar Year 2021.

The Companies also explained in testimony the use of fixed price resources, company-owned generation, and contractual purchases. For all of the Test Year, only 5.7% of NYSEG’s residential delivery load and 3.5% of its non-residential delivery load were hedged by these resources. For all of the Test Year, about 1.8% of RG&E’s residential and 0.5% of its non-residential delivery load were hedged by fixed price resources, RG&E-owned generation and contractual purchases. The difference between the residential and non-residential percentages is the Companies’ NYPA hydro allocation, which solely benefits residential customers.

NYSEG’s and RG&E’s contractual purchases of NYPA hydropower are presently scheduled to terminate at the end of 2020. Prior to the end of the existing contract term, and assuming that NYPA is willing to continue a contractual relationship, NYSEG and RG&E will evaluate whether to enter into an extension and/or new agreement with NYPA.

Change In Customer UCAP Calculation

The Companies propose to make changes to the way they determine individual UCAP requirements

Specifically, for customers who participate in demand response ('DR') programs administered by the NYISO and/or the Companies, the Companies propose to add any customer DR load reductions back into those individual customer Installed Capacity ('ICAP') responsibility determinations, should those load reductions be included in the NYISO peak load determination.

To determine what load needs to be added to the individual customer UCAP requirements, the Companies said that, for DR events called by the NYISO or the Companies, NYSEG and RG&E will add back into those individual DR customer UCAP requirements the amount of load reductions as reported by or to the NYISO.

"The Companies propose this change to ensure an equitable distribution of UCAP charges among all customers. If this change is not made, non-DR participant customers would incur a disproportionate share of UCAP charges," the Companies said

Electric Cost Incentive Mechanisms

The Companies proposed two Electric Cost Incentive Mechanisms such that the benefits of certain electric supply procurement activities are shared between shareholders and ratepayers

The first Electric Cost Incentive Mechanism, which is associated only with NYSEG, is a mechanism designed to share all optimization revenues associated with grandfathered transmission entitlements up to 471 MW from the Homer City Generating Station, located in PJM Interconnection, LLC, into the NYISO between customers and shareholders. NYSEG proposes to share 80% / 20% between its customers and shareholders the cost savings associated with the optimization activities associated with NYSEG’s grandfathered transmission entitlements of up to 471 MW from the Homer City Generating Station, located in PJM, into the NYISO. Under standard operating procedures and subject to Homer City generation availability, NYSEG evaluates market conditions and may schedule energy up to 471 MW per hour in the PJM and NYISO day-ahead and/or real-time markets. For the Test Year, this optimization resulted in over $4.6 million savings, $3.4 million savings from day-ahead market transactions and about $1.2 million savings from real-time market transactions.

The second Electric Cost Incentive Mechanism, associated with NYSEG and RG&E, is designed to share in the savings associated with the procurement of environmental attributes that are procured in support of the purchase obligations associated with the Clean Energy Standard. The Companies propose a sharing mechanism associated with the procurement activities of REC Certificates. Given the increased annual LSE obligations as set forth in the CES Order and subsequent implementation orders and the likelihood of limited availability of Tier 1 RECs from NYSERDA, utilizing the rules established for the banking of RECs, and in combination with procurement of RECs from third-parties, the Companies propose an 80% / 20% sharing between customers and shareholders of savings in procurement costs for NYSEG and RG&E through a two-step process. The first step is to identify the number of RECs that would be subject to ACP-related costs if RECs through NYSERDA auctions and/or generation related to the Value of Distributed Energy Resources (VDER) were not available to meet the mandated, Compliance Year obligations. The second step is to calculate the overall savings by applying the ACP value for that specific Compliance Year to the remaining number of RECs needed to meet a specific Compliance Year obligation and deducting the procurement costs associated with third-party arrangements, any banked RECs from previous compliance periods, and, if necessary, any ACP for any remaining REC obligations.

Case 19-E-0378 et al.

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