Blog Archive

Thursday, September 20, 2018

September 25, 2018, EPB Board Meeting





TENTATIVE AGENDA
GLASGOW ELECTRIC PLANT BOARD 
SEPTEMBER 25, 2018, 6:00 PM

1. MINUTES OF PREVIOUS MEETING


2. ANALYTICS REPORT FOR MONTH OF AUGUST  

3. REPORT ON OCTOBER 2018 FCA


4. CONSIDER CONSENT TO ALLOW INSPECTION OF OLD CITY DUMP PROPERTY


5. CONSIDER NEW DEFAULT RETAIL RATES FROM TVA FOR OCTOBER 1


6. REPORT ON RATE DESIGN AND CONSIDER TARIFFS TO PROPOSE TO TVA


7. NEW / OLD BUSINESS / REPORTS
A. CPD CHARGE STATUS                            

B.  EPB TEAM MASTER PLAN CHANGES
8. ADJOURN



TO:                       Members of Glasgow Electric Plant Board                 
                                                                                               
FROM:                  William J. Ray, PE                 
                                                                                               
DATE:                  9/20/2018    
                                                                                                                  
SUBJECT:            Board Meeting Information                                          


                                     
Preamble
September has been another calm month for the EPB team. The weather has been quite normal and non-violent. As this is written, we’ve only had to issue a peak demand prediction on two days, and those predictions were accurate, so we are looking good for September relative to peak predictions. We hope this will continue through the balance of the month.

The task of making decisions about reorganizing the team in the face of numerous retirements continues. So far, the folks we have given new responsibilities as a result of these changes, are doing a great job and making big improvements. I am optimistic that this result will continue, but that is not to say that we are not missing the team members who have left. We’ve got several more departures coming in the next few months, so this project will continue through 2019.    

The big agenda item this month continues to be our retail rates, and how we need to change them to reflect our real costs. Our agreement with the Advisory Council last year dictates an annual review of our rate effectiveness, and that task is ongoing. The matter reaches peak complexity this month as we will discuss the upcoming TVA wholesale rate change, and how we need to accommodate that along with the other changes we face. As has been the case lately, the meeting might be a bit long.


October 1 FCA
As we move toward the completion of the third year of our retail rate re-designs, October 1 will bring us an increase in overall power cost due to an increase in the FCA. The FCA calculation always trails actual TVA fuel expenditures by a couple of months, so October will see us getting an increase, due to the temperatures being higher than predictions, and due to the greater than anticipated power purchases from neighbors during August. The October 2018 FCA is going to increase, to 1.836 cents per kWh. As usual, I am attaching the narrative on the FCA from the TVA portal. On October 1, the energy component of our retail rates will be adjusted to reflect this increase to the wholesale cost of energy.
        
Old City Dump Property
A decade ago, when we were looking for a site for our second TVA delivery point, we thought the site of the old city dump would be perfect. The City agreed and transferred the property to us.  We then engaged an engineering firm to do an analysis of the site. The analysis uncovered environmental issues that were far worse than we anticipated, so we built East Glasgow Primary Substation nearby, on a piece of property we acquired from a private owner.

Though we ultimately didn’t use the property, we still wound up owning it, and all of the issues attendant thereto. We really haven’t done anything with, or even really thought about the property for many years, until we got a call about it a couple of weeks ago. It seems that the Commonwealth has engaged an engineering firm to study old trash dump properties like this because there are monies available to clean up some of these sites. The engineering firm is tasked with considering the many properties and making recommendations to the Commonwealth regarding which sites might best make use of the available funds. We certainly want to cooperate with this effort, because if we can get the site remediated with grant funds, we might well find a use for the site in the future.

Attached to this narrative is a copy of an agreement which would simply grant access to the site for the engineering firm to study it. We have already given them copies of the site environmental analysis we had done a decade ago, and, in the interest of time, I have already executed the access agreement. At the meeting I will ask you to ratify my previous execution of the agreement.

Default TVA Approved Retail Rates for October 1
As if this whole retail rate matter were not complex enough, and since TVA’s wholesale rate change for October 1 does not align with our time line for recommending a change to our retail rates, we need to implement TVA stipulated retail rates to accommodate only the TVA wholesale change, this month. The changes to our tariffs are very minor, only enough to cover the TVA 1.5% increase and a couple of other procedural changes, but you need to officially approve them, so we can get the billing system ready for October 1.

I am sorry this is so complex, but TVA is in charge of this, and they will also be in charge of considering the combined retail rates that we are likely to propose after your consideration of them later in the meeting. This extra step is really just the result of TVA’s implementation of their wholesale rate changes a couple of months before they can address our proposed local changes to retail rates. I am attaching the tariff sheets proposed for October 1 to this narrative. I don’t want to clog up the meeting PowerPoint presentation with another set of tariffs for you to review.

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 time discussing the variables that are being solved relative to the equation for our needed retail rate change for later this year. I also look forward to hashing out the issues relative to volumetric rates and the remaining volumetric components of our retail rate offerings. We decided in 2015 that EPB must move completely away from volumetric rates, due to steadily declining sales and the inherent unfairness in the way volumetric rates fail to accurately charge all customers in direct proportion to the costs generated by all customers. We’ve suffered some setbacks in the goal of becoming totally non-volumetric, but the risk of continuing to have a volumetric component to our rates is still there. At the meeting, if you choose to examine them, we will have updated examples of how our present rates, which include a volumetric element, can fail to properly collect revenue to cover fixed costs appropriately for the varying levels of energy consumption within each rate class.

Remember, TVA has informed us that the crush of LPCs who will also be making changes to their retail rates, has eclipsed their capability to consider 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 after this month’s meeting. 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 complex matter with you at the meeting.


           
Reports

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. We also narrowly missed August’s peak as well. From October 2017 through August 2018, we have collected $96,599 to fund that account. Missed peak predictions have cost us $76,777 during that period, so we have a positive fund balance of about $19,821 at the end of August. June and July cost us a lot of what we had accumulated, but the very narrow miss in August, combined with high demand for the month, puts us in good position to end the year very close to where we had projected. 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. One very interesting development is a set of recommendations from Reed Public Relations, a firm we have engaged to advise us on brand management and marketing initiatives, as a part of my consideration of how to replace the departing Shelia Hogue, who has been the lynch-pin of our administrative and marketing work for the last several years. I’ll have an updated chart at the meeting and we can discuss this.

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

Wednesday, September 19, 2018

Coincident Peak Notice

E.P.B. Electric Customers on the Variable Price Rate- We predict the POSSIBILITY for September's peak electric demand to occur on Thursday, September 20th between 12pm & 6pm. This is only a prediction based upon our best guess as to what the combination of all customers in Glasgow will demand from T.V.A. A peak demand hour can occur during any of the maximum of 24 hours of each month during one of our predicted peaks. This is our forecast which is provided as a convenience for E.P.B. customers who wish to receive forecasts. If you want to move to a fixed energy rate without coincident peak demand charges, please contact us at 270-651-8341.
Tuesday, September 18, 2018

Coincident Peak Notice

E.P.B. Electric Customers on the Variable Price Rate- We predict the POSSIBILITY for September's peak electric demand to occur on Wednesday, September 19th between 12pm & 6pm. This is only a prediction based upon our best guess as to what the combination of all customers in Glasgow will demand from T.V.A. A peak demand hour can occur during any of the maximum of 24 hours of each month during one of our predicted peaks. This is our forecast which is provided as a convenience for E.P.B. customers who wish to receive forecasts. If you want to move to a fixed energy rate without coincident peak demand charges, please contact us at 270-651-8341.
Monday, September 3, 2018

Coincident Peak Notice

E.P.B. Electric Customers on the Variable Price Rate- We predict the POSSIBILITY for September's peak electric demand to occur on Tuesday, September 4th between 12pm & 6pm. This is only a prediction based upon our best guess as to what the combination of all customers in Glasgow will demand from T.V.A. A peak demand hour can occur during any of the maximum of 24 hours of each month during one of our predicted peaks. This is our forecast which is provided as a convenience for E.P.B. customers who wish to receive forecasts. If you want to move to a fixed energy rate without coincident peak demand charges, please contact us at 270-651-8341.
Monday, August 27, 2018

Coincident Peak Notice

E.P.B. Electric Customers on the Variable Price Rate- We predict the POSSIBILITY for August's peak electric demand to occur on Tuesday, August 28th between 12pm & 6pm. This is only a prediction based upon our best guess as to what the combination of all customers in Glasgow will demand from T.V.A. A peak demand hour can occur during any of the maximum of 24 hours of each month during one of our predicted peaks. This is our forecast which is provided as a convenience for E.P.B. customers who wish to receive forecasts. If you want to move to a fixed energy rate without coincident peak demand charges, please contact us at 270-651-8341.
Sunday, August 26, 2018

Coincident Peak Notice

E.P.B. Electric Customers on the Variable Price Rate- We predict the POSSIBILITY for August's peak electric demand to occur on Monday, August 27th between 12pm & 6pm. This is only a prediction based upon our best guess as to what the combination of all customers in Glasgow will demand from T.V.A. A peak demand hour can occur during any of the maximum of 24 hours of each month during one of our predicted peaks. This is our forecast which is provided as a convenience for E.P.B. customers who wish to receive forecasts. If you want to move to a fixed energy rate without coincident peak demand charges, please contact us at 270-651-8341.
Friday, August 24, 2018

August 28, 2018 EPB Meeting



TENTATIVE AGENDA
GLASGOW ELECTRIC PLANT BOARD 
AUGUST 28, 2018, 6:00 PM



1. MINUTES OF PREVIOUS MEETING


2. ANALYTICS REPORT FOR MONTH OF JULY  


3. REPORT ON SEPTEMBER 2018 FCA


4. CONSIDER CMTS UPGRADE


5. REPORT ON RATE DESIGN FUNDAMENTALS AND UPCOMING RATE CHANGE       PROCESS


6. CONSIDER ETHICS/FRAUD POLICY

7. NEW / OLD BUSINESS / REPORTS

A. CPD CHARGE STATUS                            

B.  EPB TEAM MASTER PLAN CHANGES


8. ADJOURN



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


                                     
Preamble
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.

           
Reports
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.
  
Conclusion

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

Monday, August 6, 2018

Coincident Peak Notice

E.P.B. Electric Customers on the Variable Price Rate- We predict the POSSIBILITY for August's peak electric demand to occur on Tuesday, August 7th between 12pm & 6pm. This is only a prediction based upon our best guess as to what the combination of all customers in Glasgow will demand from T.V.A. A peak demand hour can occur during any of the maximum of 24 hours of each month during one of our predicted peaks. This is our forecast which is provided as a convenience for E.P.B. customers who wish to receive forecasts. If you want to move to a fixed energy rate without coincident peak demand charges, please contact us at 270-651-8341.
Sunday, August 5, 2018

Coincident Peak Notice


E.P.B. Electric Customers on the Variable Price Rate- We predict the POSSIBILITY for August's peak electric demand to occur on Monday, August 6th between 12pm & 6pm. This is only a prediction based upon our best guess as to what the combination of all customers in Glasgow will demand from T.V.A. A peak demand hour can occur during any of the maximum of 24 hours of each month during one of our predicted peaks. This is our forecast which is provided as a convenience for E.P.B. customers who wish to receive forecasts. If you want to move to a fixed energy rate without coincident peak demand charges, please contact us at 270-651-8341.
Friday, July 20, 2018

July 24, 2018 EPB Board Meeting



TENTATIVE AGENDA
GLASGOW ELECTRIC PLANT BOARD 
JULY 24, 2018 - 6:00 PM



1. MINUTES OF PREVIOUS MEETING


2. ANALYTICS REPORT FOR MONTH OF JUNE  


3. REPORT ON AUGUST 2018 FCA


4. CONSIDER PARKING LOT OVERLAY BID


5. REPORT ON RATE DESIGN FUNDAMENTALS AND UPCOMING RATE CHANGE PROCESS


6. CONSIDER BIDS ON TRANSMISSION LINE HARDWARE


7. CONSIDER RULES AND REGULATIONS CHANGE


8. NEW / OLD BUSINESS / REPORTS

A. CPD CHARGE STATUS                            

B.  EPB TEAM MASTER PLAN CHANGES

C. DRAFT ETHICS/FRAUD POLICY


9. ADJOURN



MEMORANDUM
                                                                                                                  
                                                                                               
                                                                                     
TO:                       Members of Glasgow Electric Plant Board                 
                                                                                               
FROM:                  William J. Ray, PE                 
                                                                                               
DATE:                  7/20/2018    
                                                                                                                  
SUBJECT:            Board Meeting Information                                          


                                     
Preamble
July has been another relatively calm month, but for the frustration with making peak predictions, given very unpredictable weather. The hot, then cool, weather, personnel retirement/transition issues, and difficult issues relative to rate transition have all been frustrations this month. We’ve been hammering away at our plans for the electric retail rate change that will be necessary for the fall, including the implementation of the TVA rate change, while also working hard to find personnel to fill the positions opening due to the many retirements we are facing. As I’ve said before, you will see rate matters on the agenda each month for the remainder of the year.   

We’ve gotten you the additional information you requested relative to the policies of our peers relative to deposits and/or security to guard against bad debt, and that information will be presented. These matters are always of importance to us as a business. The meeting might be a bit long, so try to grab a snack before you arrive. Now, let’s move on to this month’s agenda!



August 1 FCA
As we continue the third year of our new retail rate designs, August 1 will bring us another very small increase in overall power cost due to an increase in the FCA. The FCA calculation always trails actual TVA fuel expenditures by a couple of months, so August will see us getting a small increase, due to the record June heat and the increased fuel expenditures to meet that demand. The August 2018 FCA is going to increase very slightly, to 1.893 cents per kWh, and that increase, when blended with our other wholesale costs, will bring about a roughly .1% increase in overall energy costs to us and our customers. As usual, I am attaching the narrative on the FCA from the TVA portal. On August 1, the energy component of our retail rates will be adjusted to reflect this increase to the wholesale cost of energy.
        
Asphalt Parking Lot Overlay
The core of the EPB buildings, which make up our campus today, were constructed in 1967. The parking lot and driveways have been altered a little over the years, but it too was born in 1967. We have tried to repair cracks and maintain a good seal on the parking lots and driveways, but 51 years have taken their toll on the asphalt. I asked my team to develop specifications for an overall refurbishment of the pavement on our campus. They did the research and came up with a good plan to apply a 1.5” – 2” sand aggregate top course for the parking lot and driveways, that will result in a leveled and stabilized surface that, hopefully, will last for another 50 years.

Using that specification, we opened bids on July 6. Of course, we got the same result that nearly everyone gets when they want asphalt work done – we got only one bid, and that was from Scotty’s Contracting and Stone, LLC. The cost is significant -- $71,335. We also asked for a bid to construct a concrete pad under our recycling dumpster, where the weight of the dumpster and the truck that services it, has caused significant sinking of the pavement. The additional cost of this pad is $3,310.

At the meeting I will recommend that we make this investment from our capital projects budget. The pavement on our campus has served us well for over 50 years, and we believe it is now time to refurbish it.

Rate Design Fundamentals and the TVA Wholesale Changes

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 will be discussing the increased fixed costs we are experiencing since we designed our variable rates in 2015, and how you want to approach correcting our retail rates to properly collect the revenue to cover those costs. While it would be pretty simple to just adjust the customer charge to reflect updated costs, there are other complicating factors.  

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. I will explain that in detail at the meeting.

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, in response to pressure from the Advisory Committee and some members of the Glasgow City Council. The details will come in my presentation at the meeting, but suffice to say that our collection of fixed costs through a fixed charge, with kWh costs being reduced to the wholesale cost, has been set back by our concessions in 2016 and 2017. 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. You will be asked to give us guidance on if you want to return to pursuit of the non-volumetric rate environment, and, if so, how many years you want to take to achieve our goal.  

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 retail rate adjustments each October, in line with the TVA wholesale adjustments.

I look forward to discussing this at the meeting.

Rules and Regulations Change Relative to Deposits/Security
As discussed last month, we’ve had an unusual amount of problems of late relative to securing proper deposits (or other security) relative to new commercial accounts. Some of the problems come from customers who just do not think they represent a risk to EPB and should not be asked to provide security. Other questions might be resolved  by clarifying language relative to the distinctions between residential deposits and the security necessary to protect EPB customers from larger losses associated with commercial accounts. It is the latter that we feel you should consider addressing.

We discussed this last month, but you didn’t take any action. Instead, you asked me to research the deposit/security policies of our peers, so that you could weigh that information along with our recommended changes to our Rules and Regulations. That information is included with this narrative for your consideration. You will note that, nearly universally, our peers use the word “may” relative to all discussions of what deposit, or security, will be required. I’m not sure that helps you very much.

Working with TVA’s regulatory staff, we drafted the following suggested changes to our Rules relative to deposits (underscored words are to be inserted, while stricken through words are to be deleted:




2. SERVICE DEPOSIT -
A deposit, or suitable security guarantee, approximately equal to twice the estimated average monthly bill, shall be required of any Customer before service is supplied. Deposits are based on several factors and may vary with the class of customer being served and the financial risk to EPB attendant thereto. However, the amount of the deposit for Residential Customers only, may be reduced based upon the results of a credit check on the customer/customers wishing to establish an account.

For Residential Customers – Deposit requirement will be based on such factors as credit rating, credit history, and/or old balances owed to EPB from previous accounts left unpaid by Customer or resident. Customers applying for residential services will be subject to an online credit check when applying for service, providing one of three results:
- Excellent credit will require no deposit.
- Average credit will require a deposit equal to a one-month average electric bill.
- Poor credit or no available credit history will require a deposit equal to a two-month average electric bill.

For Commercial and Industrial Customers – Deposit requirement will be based on such factors as demand and energy load projections, previous business history and/or billing history for similar businesses. Deposit amounts shall be determined by EPB so as to provide security equal to the EPB’s estimate of two-month cost of electric service to a business based upon any and all data available to EPB for its use in establishing the risk to EPB, and its customers, resulting from non-payment of amounts billed to the account.

2. SERVICE DEPOSIT –
A deposit or suitable guarantee approximately equal to twice the average monthly bill may be required of any Customer before service is supplied, depending on credit rating, credit history, and other factors, including old balances owed to EPB from previous accounts left unpaid by Customer or resident. An online credit check will be performed when applying for service, providing one of three results:
-  Excellent credit will require no deposit.
-  Average credit will require a deposit equal to one-month average electric bill.
-  Poor credit or no available credit history will require a deposit equal to a two-month average electric bill.

EPB may, at its option, return deposit to a the Residential Customer after one year or at any time EPB deems appropriate, otherwise, Residential deposits will be held until account is terminated. Deposits shall earn annual non-compounded interest at a rate, adjusted annually, to equal the published rate on the first business Monday each year on One Year U.S. Treasury Obligations. Interest will continue to accrue and is prorated if Customer leaves after anniversary date. Interest will be credited annually to the account on December 31. However, upon demand by the Customer, interest which has accrued through the anniversary date of deposit will be paid at any time during the following year. Deposits may be returned based on excellent payment history of twelve (12) months; otherwise, entire deposit will be held as security. The Customer’s deposit balance, including earned interest, is subject to review by the Customer and the EPB.
Commercial Customer Deposits will be held until account is terminated. Interest will accrue until that time. The EPB may require any Customer to increase their deposit if the Customer becomes delinquent, if their credit report indicates greater risk to EPB, or if inflation or increased use of service has caused the deposit to be less than adequate to provide proper security for EPB. Alternatively, should actual energy usage reveal that a Commercial Customer’s Deposit is greater than needed to provide EPB the two-month’s bill security level required, Customer may request, and EPB may grant, a reduction in the required deposit and a corresponding alteration of the power contract between EPB and said Commercial Customer, including a refund of the amount held in excess of that which is determined to be necessary.
We can discuss this fully at the meeting, but this general direction will be my recommendation (and that recommendation has already been tentatively approved by TVA). Please pay particular attention to the highlighted word in the first sentence. Deciding whether you want “shall” there or, alternatively “may” will determine whether you want my team to have any flexibility on this matter or not.

System Reliability Upgrade Bids
Work continues in our efforts to upgrade critical poles with steel and iron replacements. This month we conducted a bid opening for various materials needed to continue making progress on these projects. The list of items is long, and no single bidder submitted a combined low bid, so we are going to recommend that the material bids be split up among the bidders who were lowest and best on each item. I will have more information on this for your review at the meeting.
           
Reports
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 for. 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 really behind by missing the June, and likely, the July peak hours by a considerable margin. From October 2017 through June 2018, we have collected $75,758 to fund that account. Missed peak predictions have cost us $48,886 during that period, so we have a positive fund balance of about $26,871 at the end of June. However, July, as it stands today, will consume all of that credit. Next month’s information will be critical, but it is likely that, when we consider rate adjustments in August and September, a recommendation to increase the kW markup will be a part of those discussions. I will keep you posted regularly as this fund moves toward a full year of experience.

Draft Ethics and Fraud Policy. At the last meeting I provided you with a draft version of an Ethics and Fraud Policy that our auditors have been urging us to adopt for the last few years. I hope you had a chance to review it and give me feedback. I would like to place this, or an updated version of it, on the agenda for August so we can have this done before the audit is completed.

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.
  
Conclusion

Well, that ought to be more than enough to set your head to spinning for this month. Let me know if you have any questions before the meeting.