Blog Archive

Friday, August 24, 2018

August 28, 2018 EPB Meeting

AUGUST 28, 2018, 6:00 PM








A. CPD CHARGE STATUS                            



TO:                       Members of Glasgow Electric Plant Board                 
FROM:                  William J. Ray, PE                 
DATE:                  8/24/2018    
SUBJECT:            Board Meeting Information                                          

August has been a relatively calm month, but for the frustration with making peak predictions – a very new science that is far from easy. Still, we are looking good for August relative to peak predictions, at least that is the case as this narrative is written.

The biggest difficulty this month has been the harsh reality of the beginning of the exodus of so many key members of the EPB team. We’ve said goodbye to Bill Anderson and Eric Bruton through retirements, and Timmy Matthews due to an unexpected illness this month. The coming months will result in many more departures. We are lucky to have talented new folks to step into these roles, and those team members will bring exciting levels of innovation to our mission, but seeing our old friends depart still results in a great deal of melancholy. This is just another problem we must deal with, and we are working hard to come up with new people ahead of the departures, and we will continue that work.    

The big agenda item this month continues to be our retail rates, and how we need to change them to reflect our real costs, the cost of the upcoming TVA wholesale rate change, and other changes we face. As is the case lately, the meeting might be a bit long.

September 1 FCA
As we continue the third year of our retail rate re-designs, September 1 will bring us a sizable drop in overall power cost due to a decrease in the FCA. The FCA calculation always trails actual TVA fuel expenditures by a couple of months, so September will see us getting a decrease, due to the temperatures being right on predictions, and due to the ample cheap hydro power available from the above-average rainfall this summer. The September 2018 FCA is going to decrease, to 1.668 cents per kWh. As usual, I am attaching the narrative on the FCA from the TVA portal. On September 1, the energy component of our retail rates will be adjusted to reflect this decrease to the wholesale cost of energy.
CMTS Upgrade
The Cable Modem Termination System (CMTS) is the engine for our whole internet access via cable modem business. This is the financial cornerstone to the EPB balance sheet these days, as it produces more net income than even the electric power business. It is the successful and growing internet access business that allows us to provide the lowest cost cable television products in the United States. I say all of this to underscore the importance of this business and the need to keep its quality second to none.

We have traditionally found ways to increase the speed of our internet access products each Christmas, and we believe that tradition should continue. Increasing the speed of the cable modems, often requires upgrades to the CMTS to facilitate higher speed offerings. We last issued debt to finance a major CMTS replacement/upgrade in 2015. At that time, we purchased a complete new CMTS and put most of our customers on the new core device, while using the newly freed up older generation CMTS for a the remainder of the customers. This approach is a classic redundancy philosophy, similar to the way we operate the electric grid. Using redundant devices assures that a major equipment failure would not bring the whole network to its knees, since the other CMTS would, presumably, survive. That process allowed us to successfully upgrade internet speeds in three more annual reconfigurations.

We are now facing the end of life for the older generation CMTS and it seems the best move at present would be to purchase new cards and capacity for the new CMTS. Once upgraded we can move all internet customers to it, and we will be in a position to upgrade the speeds of our internet products by around Christmas.

Now, that move violates our redundancy philosophy, so we need to increase the support contract we purchase to cover disasters with the CMTS, to recognize the new risk we will face by using only one CMTS. This will be far less expensive than purchasing another CMTS. When we bought the new one we operate now, the cost was $350,000. We have a proposal, through NCTC using the vendor Motorola/Arris has assigned to all Kentucky internet providers, for new hardware, software, and licenses that will accomplish our goals for the next few upgrades. The cost of this solution is just over $41,000. A copy of the materials list and pricing is attached.

At the meeting I will ask you to authorize me to issue a purchase order to Advanced Media Technologies, finding that they are the sole source for the components needed to plug into our existing Motorola/Arris CMTS, that their proposed price is the best and only price we can get in Kentucky from the vendor assigned by the manufacturer to sell these components in Kentucky. With the order placed, we can begin our planning and marketing approaches for a Christmas 2018 speed enhancement to our internet products.

Rate Design Discussion for FY 2019

I will not go over all of the rate design slides, unless you want me to do so, but we will spend some time discussing the variables that are being solved relative to the equation for our needed retail rate change for later this year. The elements of the rate change we will recommend to you later in the year include:

·         Increased fixed costs due to three-year lapse since last design of retail rates.
·         CERS increased cost, which will not be as large as we feared thanks to the Kentucky Legislature overriding Gov. Bevin’s veto of a bill which allows the CERS agencies to limit their annual contribution increases to a much smaller amount.
·         TVA wholesale rate change, as we have already discussed. The main issue here is how we account for the wholesale changes in our retail rates.
·         Implementation of gradualism, in our process of removing delivery charge markup to kWh and moving the remaining fixed cost revenue collection to the Customer Charge, as we initially envisioned. There are also considerations about the optional fixed rates we created in 2016 that need to be addressed.
·         Additional personnel cost, as we have discussed, to recognize the cost of hiring and training new personnel to replace numerous upcoming retirements.
·         Capital projects, and the Board’s vision of how aggressively EPB needs to move in upgrading the resiliency of the EPB grid.

This month we’ll continue the performance analysis of our present rates, and we’ll discuss the path from where we are, over time, to reach the desired outcome of being totally non-volumetric, with respect to the collection of our fixed cost revenue, on our electric rate architecture.   

As we discussed last month, TVA is establishing a new rate mechanism. In short, they will start collecting some of their revenue through a fixed charge (they are calling it the Grid Access Charge), but there is a problem with that. They are not actually charging us a new fixed charge! Rather, they are adding a new ½ cent volumetric charge to our kWh purchases. Though this move results in a net zero effect on our overall wholesale bill, it will look like a small increase to our wholesale cost of kWh, which we pass along to our customers.

Further, we will need to adjust the delivery adder to our kWh charge as it relates to the ratio of fixed cost recovery vs. volumetric cost recovery, for the ratios you have already asked me to report on. Each alteration to the customer charge, will have a mathematical relationship to that delivery adder, and vice versa. When you settle on the ratio you want to implement next, we will perform the mathematics to report on how those two numbers will change.  

At this meeting I will continue the process of reviewing the mathematics relative to these issues, and how we might proceed with recovering the damage done to our intended non-volumetric retail rates, when we agreed to lower our Customer Charge by $5 per month and create two new fixed charge tariffs. As we all know, this move was popular with our critics, but the result has been the decay of our rate design, moving us back in time. Since we made the changes in 2017, we have been moving away from the non-volumetric rate architecture which the board found essential for the future health of Glasgow. We will spend considerable time going over the percentage of fixed cost collection which was planned in 2015, and how it has been altered since then. We will have projected impacts of implementing the 60/40 and 70/30 ratios you asked me to examine. You will be asked to give us guidance on how to proceed from that information.   

TVA has informed us that the crush of LPCs who will also be making changes to their retail rates, has eclipsed their capability to approve them for October 1 implementation, so our change will likely need to fall toward the end of the year. We’ll just have to see how the design and approval process goes for the next few months. After this year, we will need to conduct this review annually in July and August, such that we get into a pattern of any potential retail rate adjustments each October, in line with the TVA wholesale adjustments.

I look forward to discussing this at the meeting.

Ethics/Fraud Policy
We’ve kicked this proposed policy around a bit at the last couple of meetings. I’m placing it on the agenda again for your consideration. If you want our auditor to not criticize us this year for not having a fraud policy, we need to adopt this, or something similar, before they complete the audit.

Safety Report. I will review our latest Workers Comp modifications at the meeting. We were really doing well and our W/C cost was decreasing each year, but the last fiscal year included a couple of expensive accidents that will cost us. I’ll have more detail at the meeting.

CPD Charge Reserve Fund Status. Last year, when we agreed to limit peak prediction days to four per month, while stipulating that customers will only pay for their demand which is coincident with the highest system peak hour during one of our predicted hours, we were forced to establish a kW demand markup over the TVA wholesale cost, to accumulate funds to use when TVA bills us for a peak which is higher than one we are billing our customers. We knew we would make some mistakes and miss some peak hours, and that has come to pass.

For most of the last year, the projected cost of mistakes, and the actual cost of mistakes, have aligned well, but we got a bit behind by missing the June, and July peak hours by a considerable margin. From October 2017 through July 2018, we have collected $85,888 to fund that account. Missed peak predictions have cost us $74,643 during that period, so we have a positive fund balance of about $11,244 at the end of July. June and July cost us a lot of what we had accumulated, but as it stands now, assuming we have a win in August, it looks like our guess at what misses would cost us in a year was very accurate. Hooray for mathematics! I will keep you posted regularly as this fund moves toward a full year of experience.

EPB Team Staffing Master Plan. I want to review the situation with retirements/resignations and our long-term staffing plan with you. We talked about this some last month, and I thought you might want to hear what progress we have made since then. I’ll have an updated chart at the meeting.

EPB Version 4.0. Inspired by the process of PEER certification, I’ve challenged the team to make steady progress toward the 4th iteration of Glasgow EPB. The first version of our utility encompassed the totally analog format that existed from 1962 until 1988, when we became an electric power and cable television utility. Version 2 (electric/cable television) lasted until 1996 when we added internet to our offerings and began to transform the broadband network to support a wide variety of services as well as all electric power telemetry. We entered Version 3 when we implemented cost-based electric rates that are designed to make the local grid sustainable.

Looking forward to Version 4.0, we will be using everything we learned and implemented since 1962 to transform the resiliency and reliability of our services. We can now support truly rare and advanced technology that will begin to make our grid smart and self-healing. We are ready to begin the process of installing technology that will recognize fault conditions on our grid, and isolate those faults to a small area, while redirecting power to the un-faulted line sections so as to maintain service to more customers, during and after grid damaging events. This new version of EPB will not arrive quickly. Rather, it is a direction that might well take the next decade to fully implement, but I am excited about sharing these new concepts and potential direction with you at the meeting.

Please let me know if you have any questions before the meeting.