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HomeMy WebLinkAboutMinutes_GTEU_01.26.2022Minutes of the Meeting for the Georgetown Electric Utility Board Thursday, January 26th at 4:00 PM at the Hewlett Room at Georgetown Public Library, 402 W. 8th St. Georgetown, TX 78626 Board Members Present: Robert Case - Chairman, Rick Woodruff- Vice-Chairman, Sam Jones- Secretary, Ben Butler, Mike Triggs Board Members Absent: None Staff Present: Daniel Bethapudi, Leigh Wallace, Elaine Wilson, Leticia Zavala, Kress Carson. David Morgan, Laurie Brewer, Mike Weisner, Daniel Potter, Issac Van Eenoo and Jennifer Flor Public Attendees: None Regular Session (This Regular Session may, at any time, be recessed to convene an Executive Session for any purpose authorized by the Open Meetings Act, Texas Government Code 551.) A. Call to Order -- Robert Case, Board Chairman • Meeting called to order at 4:00 pm by Case. B. Roll Call of Board Members -- Robert Case, Board Chairman. • All members present C. Introduction of Visitors -- Robert Case, Board Chairman D. Public Wishing to Address the Board • None present Legislative Session E. Review and Approval of Minutes- Kress Carson, Board Liaison • November 17th Meeting- Motion to approve by Jones; seconded by Butler • Minutes approved as read 5-0 • January 20th Meeting- Motion to approve- motion by Jones; seconded by Butler • Minutes approved as read 5-0 Regular Session (cont.) F. General Managers Monthly Report- Daniel Bethapudi- General Manager of Electric Utility • Customer Service and Billing- Leticia Zavala-Customer Care Director o 30,819 Available Services o 29,897 Electric customers/accounts, 107 estimated “bad meter reads” o Overall Average a December 2021 bills nearly $30 cheaper than September 2020 ▪ Billing numbers lower than last year due to a combination of higher monthly temperatures and reduced PCA o Electric Revenue Breakdown and Receivables presented- roughly 17% of yearly budgeted amount collected o Roughly $93,000 collected in outstanding bills since the collection agency commenced collections in May to collect the bad debt • Finance and Budgeting Report- Leigh Wallace- Finance Director o 4th Quarter Background ▪ Due to COVID-19 pandemic timing, year over year comparisons of 2020 to 2021 show large variances in revenues and expenses. This was expected going into 2021 ▪ City has applied for FEMA reimbursement for the impacts of Winter Storm Uri o Electric Fund Revenue ▪ FY 2021 revenue budget was $141.3 Million ▪ 56% of budgeted revenues is from charges for service ▪ 39% if the budget was bond proceeds ▪ Electric Sales Charges down 6% compared to last year due to rate adjustments and mild summer weather o Electric Fund Expenses ▪ Expenses came in under budget for FY2021 ▪ Case asks what the largest driver for coming under budget • Wallace answers that capital projects throughout the City had a lot unspent funds that were rolled forward into the next fiscal year ▪ The beginning fund balance was $28 Million and the ending balance was $40.6 Million ▪ This fully funds reserves necessary including the rate stabilization fund, 90 Day Contingency fund, and Operating Reserves Fund o Net Purchased Power ▪ 72% of the Electric Fund expenses ▪ Purchase power was up 63% due to Winter Storm Uri and other congestion issues ▪ With removing the winter storm Uri expenses, purchased power budget comes in just under budget projections o Case asks if you write off uncollectible bill revenue at 60 or 90 days ▪ Zavala answers that it is reported to the collection agency at 90 days ▪ Wallace then adds at 180 days the debt is then written off balance remains uncollectible o Grants Update- Winter Storm Uri 2021- Elaine Wilson- Assistant Finance Director ▪ Electric submitted $510,229.75 to FEMA for Emergency Reimbursement due to expenses incurred from Winter Storm Uri. ▪ Originally denied reimbursement due to much of the work being considered “Maintenance Expenses” which according to FEMA are not eligible as “Emergency Expenses” ▪ The work in question includes “Cut and Toss” activities in which branches are cut off of power lines, which were creating most of the outages during this event, that were weighed down by snow and ice. ▪ The City is in the process of appealing FEMA’s ruling o Recap of Winter Storm Uri Energy Expense ▪ $48 million in purchased power expenses ▪ City debt financed the cost over a 10 year period and is to be repaid by the PCA revenue ▪ In order to meet bond covenant requirements the City was then faced with the option by engaging in a Springing Reserve or booking a regulatory asset. ▪ After consultation, the City chose to opt to create a Regulatory Asset on the GAAP financial statement for $48 million and amortize over 20 years ▪ Butler asks why it is scheduled for 20 years. • Wilson answers that it provides additional relief on expenses and rates and not to put a larger burden on the rates to recover the expense. ▪ There is a complete Cost of Service Study that accounts for the entire debt service and accounts for the debt coverage ration required by City debt covenants. ▪ Case asks if rate increases will make an impact on a study that could affect the debt coverage. • Bethapudi answers that those kind of impacts are meant to be allocated and adjusted in the model accordingly. ▪ Triggs asks when the first interest payment for the issued Winter Storm debt is. • Wallace answers the first principal payment was made in 2021 and the first interest payment will occur in 2022. ▪ Wilson adds when annual financial reports are published, the 48 million will be reflected in the balance sheet rather than the income statement. This is what the rating agencies will look at when determining the City’s debt coverage ratio. ▪ Bethapudi adds that City uses cash-based reporting and GAAP based reporting. The GAAP based reporting is what used by the rating agencies to determine financial ratio calculations. • Electric Operations Report- Kress Carson- Electric Utility Analyst o Electric Reliability (SAIFI)- .547 (Good Metric) o Electric Outage Duration (CAIDI)-85.17(Good Metric) o Training- 100% (Good metric) o Safety, 100% attendance o Service Order Completion, 100% o Preventative Maintenance, 100% o Corrective Maintenance, 100% o Top 5 Outages Report ▪ Outages include mostly blown fuses and an outage due to high winds. ▪ Another outage included and underground boring incident in which the bore accidentally struck the Primary line, but was fixed promptly within two hours. o Woodruff asks what the City’s plan was to keep critical infrastructure powered throughout major events such as Winter Storm Uri. ▪ Bethapudi answers that the PUC has set broad guidelines to identify who is a critical customer. Without more clear guidance, the City uses the best existing practice in which any customer with critical needs keep uninterrupted power. Internally, the City has identified what is a critical facilities and maintains its power throughout an outage event. This includes critical facilities such as water facilities and hospitals. o Woodruff adds that his main concern is that if there was a resolution to the situation in which the customers who were on the same circuit as critical facilities were with power longer than those who were not on those circuits. From his perspective, it seems that many customers experienced less outage times than others. ▪ Bethapudi answers that it was City’s strategy was to spread the load shed as much as possible to include as many circuits into the load shed plan in which City facilities are kept with power while rotating outages between customers to ensure that most were able to not be without power for extended period of time. o Butler then asks if critical facilities are required to possess some form of backup generation. ▪ Bethapudi answers that there are some requirements for backup generation on water facilities from the PUC. ▪ David Morgan adds that there is an ongoing resiliency study for the Water Utilities and that City Council recently approved backup generation for one the wastewater treatment plants. ▪ He adds that there are areas with backup generation that are required by the State to retain such generation in addition to maintenance of the generation. ▪ Bethapudi adds at this point the City is still awaiting clear guidance from the PUC to undertake backup generation and load shedding solutions. In the meantime the City is preparing for all possible options and updates in technology. G. Review of Net Energy Metering Policy and Distributed Energy Resource Installation and Interconnection Policy- Daniel Bethapudi; General Manager of Electric Utility and Letica Zavala; Customer Care Director • Bethapudi introduces Scott Burnham of NewGen Strategies; the consulting firm that aided in developing the New Metering Policy • Background- Net Energy Metering ▪ The City’s Net Metering Program has been issued by the City for the last 12 years. ▪ This is not required by the PUC, but has become a standard for Utilities throughout the state to offer. o In the recent update, NewGen identified multiple issues with the previous Net Energy Metering program which included: ▪ The Renewable Energy Credit exceeded the avoided energy costs. This results in a cost shifting from NEM to Non-NEM customers in approximately $118,000 per year. ▪ There is not a floor on the credit. This reduces the fixed cost recovers, allows for a potential Utility bill of zero dollars which includes electric, water, wastewater, and garbage. Lastly, it allows for a potential bypass of the Base Rate Charge and Power Cost Adjustment that allows for the City to recover certain costs to operate the utilities. ▪ Lastly there was poor compliance with system requirements in which the 10kW limit was not enforced. o The recommended changed included: ▪ Reduce the Renewable Energy Credit to a market-based energy credit. This reduced the credit from $0.09580 to 0.04976 for 2020 . This helped reduce the cost shift between NEM and Non-NEM classes, aligned with the original intent of avoided costs set by Council in 2006, and is an overall acceptable practice in the industry. ▪ Establish a floor in which the Renewable Energy Credit cannot exceed the volumetric charge. This would prevent revenue losses for other funds such as Water, Wastewater, and Garbage. This also improves the utility cost recovery and eliminates any potential bypass of the base rate charge and power cost adjustment. ▪ Include a grandfather provision to allow existing NEM customers to transition to the market-based credit. Customers would then be given a period of 2 years until their rates were to adjust the new rate calculation set by City Council ▪ The Received Credit for all new NEM customers will then have their credit rates based on a new calculation methodology in which uses historical ERCOT Settlement Point Prices at South Load Zone as a proxy for the market value of energy. ▪ Enforce size compliance and allow PV systems no larger than 10kW ▪ Simplify the Ordinance language to help make customers make an informed decision. o This was passed on 09/22/2020. • Background: DER Interconnection Policy o The purpose of the DER Interconnection Policy was to ensure the safe interconnection of a customer-owned distributed energy resource (DER) installation and parallel operation with the electric distribution system. The policy was also intended to cover all costs associated with the application review and inspection process in addition to identifying the installation requirements, processing guidelines, and associated fees. o With the new fees in place the customer has to pay be a minimum of $700 dollars in fees to ensure installation and interconnection. o Bethapudi identifies two issues that do not allow for a larger DER system than 10kW. One is an engineering and safety point of view of which the system stability, linemen, and customer safety is at question. The other is for cost recovery reasons. o Woodruff asks how the use of battery storage with use of solar generation affects for system stability. ▪ Bethapudi answers that is an apparent issue, but the largest problem is for providing a way for customers of different classes and installations to be charged in a equal and equitable way. • Recent Net Energy Metering Changes o Upon the annual review NEM policy by the Utility staff and NewGen Strategies and Solutions and the City’s wholesale market consultant, Crescent Power, it became evident that Settlement Point Prices included multiple adders. o The adders are intended to incent demand response and additional resource commitment in the short-term in grid emergencies and controlled outages such as during Winter Storm Uri and investment in new resources in the long term o Based on the consultant’s review, it was determined that Lo cational Marginal Prices (LMPs) generated by ERCOT, and not the Settlement Point Prices (SPPs) more accurately represent the market cost of energy and represent the true avoided cost of purchased power by the City. o Additionally, it was also determined to eliminate periods in which ERCOT and/or the PUC declare emergencies and/or controlled outages from the calculation methodology as those periods skew the market cost of energy (or avoided cost of purchased power by the City). o February 10, 2021 through February 19, 2021 were not included in the Received Energy Credit calculation in accordance to the emergency declared timeline of Winter Storm Uri. o The resulting draft calculation of the Renewable Energy-Received Credit is proposed to be approximately $0.0538/kWh, and will come into effect February 1st, 2022. The grandfathered customers will continue to see their old rates until September 2022. o Case asks what happens in an event which there are two generation plants that are shut down for unscheduled maintenance. ▪ Bethapudi answers that ERCOT would most likely declare some kind of an emergency. Although the situation may not require load shed. He further then explains the various levels of emergency declarations of ERCOT. • Scott Burnham- NewGen Strategies and Solutions presents for the Net Energy Metering Discussion. o Burnham identifies the main issues for NEM and how they are addressed: ▪ Utility rates should primarily reflect the cost of providing service ▪ All utilities incorporate public policy goals in their rates and structures that can create subsidization of other customer classes ▪ Utilities are addressing NEM rate reform across the country. This includes changes in methodologies and recovery mechanisms. ▪ Cost shifting due to rapid penetration of residential solar and distributed storage is becoming a larger issue. ▪ Subsidy exists between PV and non-PV customers due to current rate design • Energy costs include fixed cost recovery • For every kWh consumed by customer, a kWh is not sold by Georgetown o One solution is to implement demand charge for all customers in a non-discriminatory fashion. o This would require significant investment in billing/metering systems • Recently adopted DER interconnection policy and rate design change which addresses cost shifting issues with the legacy NEM program ▪ Time differentiated market prices in the Weighted Avg. Market Price • Not uncommon for use among utilities • Higher contribution for ERCOT market prices observed in peak solar hours • Usage will change by customer and season • Lack of hourly generation data from PV customers • Recent change reduced the impact of market disruption events like Winter Storm Uri ▪ Avoided transmission cost included in excess generation rate • Utilized average (total $/total kWh to simplify approach) • Approximately $0.013/kWh • Standard element in avoided cost calculation ▪ Transmission costs determined by contribution to ERCOT system peak • Would require hourly solar production of all PV systems • Would need to be updated for new PV units installed during the year ▪ PV systems can introduce volatility into distribution system • Voltage disruptions • Harmonic issues • Loss of VAR and other electrical engineering issues • Can require additional investments ▪ Georgetown should investigate system costs for larger PV systems ▪ Smaller PV systems do not need elaborate system studies or upgrades ▪ Woodruff asks what the effect of storage would be to the Utility with the expected changes to the NEM policy in the future. Could the City possibly take more advantage in the event the customer provides more energy to the Georgetown distribution grid at more hours of the day. • Burnham suggest that there can be incentives for customers and the City to cooperatively utilize power when demand is most necessary. In the future the industry will more likely see more responsive price signals to encourage technology and customer behavior in which utilities and customers can benefit. ▪ Butler describes a situation in which a PV and backup battery customer utilizes a home structure in which they never put much demand on the system until on a cold winter day, when the solar and backup battery runs out of power. This results in a large spike in energy demand due to the sudden energy they are using, thus creating a strain on the distribution system and creating an overall higher demand in the future if other customers start trending to do this also. Butler then follows that at some point in the future there is a question that needs to be addressed that maybe a solar customer needs to be paying different rates upon signing up as PV customer than a regular customer rather than the Utility changing the rate structure for the entire customer base. Ultimately, this can create a risk of subsidizing Georgetown electric customers. o Bethapudi answers that the concept of a demand charge has been around for commercial customers, but never has been needed for residential customers. However, the industry is aware that at some point there will need to be solutions for residentials customer as described in the situation. He adds that demand rates can be very complex, so the challenge is making the rate to where it easy to understand for the common customer. These are solutions that the Utility is currently looking forward to implementing in the future. • Jones adds that there is still a much-needed change in technology and cost in addition to customer behavior to make these systems truly available in the way the discussion was presented. At the moment, one rate set now would likely not address any future issues, but definitely needs to be addressed in the future as the systems become more widely adopted. o Bethapudi claims that the Utility is monitoring the changes in the industry from both an engineering and financial point of view to address them proactively as possible H. Review of Energy Risk Management Policy- Daniel Bethapudi; General Manager of Electric Utility • In December 2020 the City of Georgetown requested that ACES, the City’s Energy Risk Management Support Services Consultant, to perform a high level policy review of the Energy Risk Management Policy and recommen d enhancements to keep the policy in line with industry best practices. • The ACES Recommended the following policies in February of 2021, and Bethapudi provided updates from each recommendation: o Modify and enhance the governance, roles, and responsibiliti es • This was addressed in the recent policy update o Clarify and enhance hedging guidelines • New hedging policy is in process of being developed o More clearly define authorized trading activity • New Trading Authority Policy in process of development o Develop a credit policy • New Credit Policy in development o Continue with credit exposure monitoring activity • New consultation agreement executed with ACES (Energy Resource Management Support Services Provider) to continue credit monitoring o Incorporate ongoing stochastic portfolio modeling • New consultation agreement executed with ACES to provide ongoing stochastic portfolio modeling services • Governance Responsibility Updates o ACES recommended that the Electric Board serves as the Risk Oversight Committee as a part of the enhanced risk governance structure • The responsibility of the ROC will be to oversee the energy risk management activities of Georgetown, establish the scope and frequency for management reporting to the City Council, and periodically review compliance with Georgetown policies and procedures. • This also includes discussing, mitigating and monitoring, Georgetown’s major energy exposures • Case asks if there will be posting requirements to such meeting required by the ROC/ Electric Board. ▪ Morgan answers that the City is currently looking into current laws and practices with the City Attorney’s Office to see how this can be allowed and performed and just how the meetings will take place while also adhering with the Energy Risk Management Policy and ACES recommendations o The Internal Risk Management Committee will consist of the City Manager, the Assistant City Manager, the General Manager of Electric Utility, and a senior Utility Analyst. o The Finance Director will perform the Independent Risk Management o Function and will be responsible for establishing the supporting policies: • Trading Authority Policy • Trading Sanctions Policy, • Hedging Policy • Credit Policy o The projected next steps are as follows: • Approval of Electric Board and City Council of ▪ Trading Authority Policy ▪ Trading Sanctions Policy, ▪ Hedging Policy ▪ Credit Policy • Approval projected to take place on February 17t h (Electric Board) and February 22 (City Council) respectively • Legal review of Electric Board processes within the scope of the Energy Risk Management Policy • ACES and Board review for processes and procedures over the next few months. Board moves into Executive Session at 6:26 PM Executive Session In compliance with the Open Meetings Act, Chapter 551, Government Code, Vernon's Texas Codes, Annotated, the items listed below will be discussed in closed session and are subject to action in the regular session. I. Section 551.086: Competitive Matters • Purchased Power Update Board moves back into Regular Session at 6:36 PM. Adjournment MOTION by Butler, second by Jones to adjourn the Board Meeting APPROVED 5-0 Electric Board Meeting Adjourned at 6:36 PM.