Monday, August 27, 2018
Coincident Peak Notice
10:54 AM | 
Posted by
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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.
- 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.
- 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.
Wednesday, July 18, 2018
Coincident Peak Notice
E.P.B. Electric Customers on the Variable Price Rate- We predict the POSSIBILITY for July's peak electric demand to occur on Thursday, July 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
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