PSC REF#:173020 Public Service Commission of Wisconsin RECEIVED: 09/26/12, 12:51:56 PM PUBLIC SERVICE COMMISSION OF WISCONSIN
Application of Madison Gas and Electric Company 3270-UR-118 for Authority to Change Electric and Natural Gas Rates
Volume 1
Prefiled Testimony Pages
September 18, 2012 D-MGE-Bollom-1-17, D-MGE Frassetto-1-4, D-MGE-Krueger-1-5, D-MGE-James-1-31, D-MGE-Johnson-1- 6, D-MGE-Minor-1-19, SD-MGE-Minor- 1-7, D-CUB-Neal-1p-20p, D-CUB Wallach-1-18, D-Clean Wis-Cook-1- 16, D-IBEW-Poklinkoski-1-6, D- UW System-Harrod-1-8, D-UW System Stephens-1-19, D-UW System-Weiss- 1-12, D-Airgas-Lyons-1-20, D-CNEG Fabrizius-1-10, D-PSC-Bauer-1-12, D-PSC-Hillebrand-1-8, D-PSC-Maly- 1-8, D-PSC-Singletary-1-20, D-PSC Vandervort-1-13, R-MGE-Bollom-1- 19, R-MGE-Keebler-1-8, R-MGE James-1-5, R-MGE-Johnson-1-2, R MGE-Minor-1-7, R-CUB-Wallach-1-11, R-Airgas-Lyons-1-14, R-Calpine Pena-1-4, R-PSC-Hillebrand-1-3, R PSC-Singletary-1-10, Incl. I N D E X
Prefiled Direct Testimony Pages
Gregory A. Bollom 1-17
Kenneth G. Frassetto 1-4
John D. Krueger 1-5
Steven S. James 1-31
Tamara J. Johnson 1-6
Timm A. Minor 1-19
Prefiled Supplemental Direct Testimony
Timm A. Minor 1-7
Prefiled Direct Testimony
Mary Neal 1p-20p
Jonathan Wallach 1-18
Daniel Tyson Steadman Cook 1-16
David Poklinkoski 1-6
John Harrod 1-8
Robert R. Stephens 1-19
Craig Weiss 1-12
Kenneth Lyons 1-20
Darcy A. Fabrizius 1-10
Robert C. Bauer 1-12
Randy Hillebrand 1-8
Gail M. Maly 1-8 I N D E X
Prefiled Direct Testimony Pages
Corey S. Singletary 1-20
Anne P. Vandervort 1-13
Prefiled Rebuttal Testimony
Gregory A. Bollom 1-19
Jeffrey M. Keebler 1-8
Steven S. James 1-5
Tamara J. Johnson 1-2
Timm A. Minor 1-7
Jonathan Wallach 1-11
Kenneth Lyons 1-14
Rick Pena 1-4
Randy Hillebrand 1-3
Corey S. J. Singletary 1-10 PSC REF#:l66575
'Ug. 1 BEFORE THE 1-' ::<1 1-'· t'il n 2 PUBLIC SERVICE COMMISSION OF WISCONSIN (1 t'iltll H (I) <: 11 t'il <: t:l 1-'· 3 Application ofMadison Gas and Electric .. n (I) 4 Company for Authority to Change Electric Docket 3270-UR-118 0 5 and Natural Gas Rates -.....o<1\(1 ~ ~
------~~-Ntil • 1-'· 0 6 DIRECT TESTIMONY OF GREGORY A. BOLLOM "'1:1 NO 7 ON BEHALF OF APPLICANT 1-'H! w~ --.J 1-'· til ~ g ::J tJl 8 Q. Please state your name and business address. 1-'· ::J 9 A. My name is Gregory A. Bollom. My business address is 133 South Blair Street, Post Office
10 Box 1231, Madison, Wisconsin 53701.
11 Q. By whom are you employed and in what capacity?
12 A. I am employed by Madison Gas and Electric Company (MOE) as Assistant Vice President -
13 Energy Planning.
14 Q. Please summarize your educational background and relevant work experience.
15 A. I have a B.A. degree in economics from St. Norbert College and a M.S. degree in economics
16 from the University of Wisconsin. I have held a variety of positions in forecasting, pricing and
17 planning during my 30 years with MOE. My current responsibilities include generation
18 planning and transmission policy; electric and natural gas sales and revenue forecasting; and
19 electric and natural gas pricing. I serve on the Edison Electric Institute Retail Energy Services
20 Executive Advisory Group; Economic Policy Advisory Group; and the Rates and Regulatory
21 Affairs Committee of which I am a past chairman. I have testified before the Public Service
22 Commission of Wisconsin (PSCW) many times on a variety of planning and pricing issues.
23 Q. What is the purpose of your direct testimony in this proceeding?
24 A. I am providing testimony to address two different aspects of MOE's case. I am providing the
25 Company's policy support for the increase in the fixed daily customer charges proposed in the
26 testimonies of Company witnesses Timm Minor and Steven James. The Company is
Direct-MGE-Bollom-1 1 proposing that an increased amount of the fixed costs of providing natural gas and electric
2 service to our customers currently recovered through variable energy charges be shifted and
3 recovered through increased daily fixed customer charges. And I am also presenting proposed
4 modifications to Rate Schedule Sp-3, University of Wisconsin Time-of-use Rate.
5 Q. Are you sponsoring any exhibits?
6 A. Yes, I am sponsoring two exhibits. Ex.-MOE-Bollom-1 consists ofthree schedules that
7 support my testimony on increasing fixed charges. Ex.-MOE-Bollom-2 provides the relevant
8 portions from the Sp-3 rate schedule that are being revised to incorporate the proposed new
9 pricing for kWh purchases by the UW for its electric chillers at the West Campus
10 Cogeneration Facility (WCCF). In my testimony, I also reference pages 15-16 of Schedule 1
11 ofEx.-MOE-James-2 sponsored by Mr. James.
12 Q. Were Ex.-MGE-Bollom-1 and Ex.-MGE-Bollom-2 prepared by you or under your
13 supervision?
14 A. Yes.
15 Q. What is the difference between fixed costs and variable costs?
16 A. Fixed costs describe the category of expenses that the Company incurs to provide service that
17 remain the same for a customer regardless of the amount of energy the customer consumes.
18 Variable costs describe those categories of expenses that are directly related to the amount of
19 energy the customer uses and that rise or fall as the customer uses more or less energy. MOE's
20 rates are designed to recover its fixed and variable costs through a combination of rate
21 elements that similarly incorporate fixed and variable structures.
22 Q. How do the fixed and variable elements ofMGE's rates match up with the fixed and
23 variable nature of the expenses it incurs?
24 A. Not particularly well. MOE's current rate structure is the result of cost allocation and rate
25 design patterns that are in some cases decades old. While different stakeholders may have
Direct-MOE-Bollom-2 different perspectives on the history, MOE's rates today reflect how the Commission has
2 balanced policy concerns about the accessibility, affordability, and social costs of natural gas
3 and electricity service over time. The cumulative result of those policy choices is a rate design
4 where some percentage of the Company's fixed costs are recovered through fixed rate
5 elements and the remaining percentage is recovered through variable rate elements. The
6 Company's variable costs are also recovered through the variable rate elements.
7 Q. Is there a drawback to the way the Company's rate structure has evolved?
8 A. Yes. It is always most economically efficient to recover the costs of service in a manner that
9 matches the way those costs are incurred. Customers will make better choices ifthe costs they
10 pay or the benefits they receive from increasing or decreasing their energy use match the
11 changes in the costs the Company incurs as a result of their change in behavior.
12 Q. Does the Company propose a shift in the manner in which its fixed costs are recovered
13 through rates?
14 A. Yes. The Company proposes that a greater percentage of its fixed costs be recovered through
15 fixed rates.
16 Q. Is the Company proposing to move to a complete straight fixed/variable rate design in
17 this current case?
18 A. No, we are not. We understand that because our current electric and natural gas rates recover a
19 significant portion of fixed costs through variable charges, moving too quickly to recover all
20 fixed costs through fixed charges could create large bill increases for some customers. MOE is
21 asking the PSCW for two types of findings in this case. First, we are asking the PSCW to
22 determine that it is appropriate and necessary for MOE to move to rate designs that recover
23 fixed costs through some type of fixed charges. Depending upon the bill impact across
24 different customer classes, it may take several rate cases to transition to rates that recover an
25 appropriate percentage of fixed costs through fixed rate components. And second, we are
Direct-MOE-Boll om-3 asking for specific approval ofthe initial incremental changes in fixed charges proposed in the
2 testimonies ofMr. James and Mr. Minor.
3 Q. Why is the Company proposing this shift in rate design?
4 A. There are several reasons. First, there is a general industry movement toward sending price
5 signals that more accurately match the cost to serve customers. Changes in regulatory
6 structures in other states, as well as the existence of regional energy markets make it
7 increasingly difficult to sustain MGE's current rate structures. Second, customer conservation
8 in recent years has highlighted the confusing nature ofthe current relationship between rates
9 and costs. And third, on the electric side of our business growing customer interest in
10 distributed generation has increased the need for MGE to get its rates and costs in better
11 alignment to prevent costs from being inappropriately shifted amongst different customers.
12 Q. Why do you believe changes outside Wisconsin require MGE to change its rate
13 structures?
14 A. Many ofMGE's business customers operate in regional, national and international markets.
15 States that have unbundled and restructured their electric utility sector, as well as utilities that
16 have moved aggressively into more advanced metering infrastructure, already have rate
17 structures that better align costs and revenue recovery. This provides a competitive advantage
18 for these states and utilities in attracting new and expanding business.
19 Q. What are the challenges associated with comparing MGE's rates to those in restructured
20 states?
21 A. Restructuring reduces many of the subsidies that have historically been present in electric
22 rates. Customers face tariffs that are distinctly separated between the delivery and supply
23 aspects of the business. In many cases there are separate delivery and supply companies. With
24 separate companies, there is no way to have the supply service rates recover costs for the
25 delivery business or vice versa. Energy supply companies do not have tariffs that include
Direct-MGE-Bollom-4 recovery of the distribution infrastructure costs, nor do distribution utilities include energy
2 supply costs in their distribution tariffs. There is no cross-subsidization between the
3 delivery/distribution and energy supply tariffs. With respect to energy supply, capacity related
4 costs are recovered through demand related charges for those customers with demand meters
5 and energy related costs (e.g. fuel and other variable costs) are recovered through variable
6 energy related charges.
7 Today, these are the rates MGE's current and potential customers are measuring MGE's
8 rates against in making business decisions. Industrial customers, and increasingly high-tech
9 commercial customers with high reliability and energy needs, look at the variable cost of
10 increasing production when choosing where to locate new facilities, expand production and
11 bring the associated jobs. Electricity can make up a significant portion of those variable
12 production costs. For the communities in MGE's service territory to effectively compete for
13 these businesses, MGE's rates for these customers have to be reasonably competitive.
14 Placing fixed cost recovery on charges that vary with changes in energy usage
15 creates problems for these competitive comparisons, especially across customer classes. Since
16 large customers use more energy and tend to have higher load factors, they end up paying a
17 greater share ofthe fixed costs. While there are many real cost differences that lead to some
18 differential between MGE's rates and those of other utilities, it is increasingly difficult to
19 explain away the rate design policies that artificially compound the differentials. Just as MGE
20 has been aggressively pursuing cost containment in recent years to combat the factors that
21 contribute to some of the rate differentials, it would be equally helpful for the Commission to
22 begin to rebalance its policy so that the mismatch between cost causation and cost recovery
23 can be reduced and the overhang of fixed cost recovery can begin to be excised from variable
24 energy charges.
Direct-MGE-Bollom-5 1 Q. How does the installation of more advanced metering infrastructure in other parts of the
2 country affect MGE's request?
3 A. New metering infrastructure has facilitated the increasing spread oftime-of-use pricing, both
4 dynamic and real-time, to a greater proportion of customers. This has been driven by a desire
5 to give customers a better understanding of how the actual cost of electricity varies by time of
6 year and time of day so that customers in tum can make more efficient decisions about how
7 much electricity to use and when to use it.
8 Q. Has the PSCW has been a part of this trend toward more efficient pricing?
9 A. Yes. MOE completed the installation of new meters during 2011 that enabled it by March
10 2012 to meet the PSCW's requirement in its 3270-UR-116 order (PSC REF# 125079) to
11 transfer all the Company's demand-metered C&I customers to time-of-use rates. MOE is also
12 seeking final approval in this case for additional changes to its TOU rates to meet the PSCW's
13 requirement to implement additional demand-response initiatives. These initiatives reinforce
14 the PSCW's commitment to drive smarter energy decisions by ensuring that customers get
15 price signals that more accurately reflect costs. MOE's request in this case to better align
16 recovery of fixed costs with fixed charge components in our residential and C&I rates - both
17 electricity and natural gas- is a logical extension of the PSCW's policy of sending more
18 accurate price signals.
19 Q. How does the current rate structure create confusion for MGE customers who conserve
20 energy as a way to better control their utility bills?
21 A. There is an inherent inconsistency in how MOE's rates are structured today. MOE's local
22 electricity and natural gas distribution service is a largely fixed-cost business. Yet historically,
23 different stakeholders have advocated, and the PSCW has adopted, rate designs that recover a
24 significant portion of these fixed costs of service through charges that vary with the quantity
25 of electricity and natural gas consumed. The argument has been that higher kWh and therm
Direct-MOE-Bollom-6 charges provide a better incentive for customers to conserve energy. While this may be the
2 case in the short term, it creates confusion for customers over time and can discourage
3 customers from taking actions to reduce their usage. Customers expect that as they reduce
4 their electricity and natural gas use their monthly bill will go down. What customers do not
5 expect, though, is that the rates they pay in the future will increase as a result of their
6 conservation. This is exactly what happens with MGE's current rate structure. The fixed costs
7 that are recovered through charges that vary with the level kWh and therm usage must be
8 reallocated into higher rates as customers reduce their energy usage. This is counterintuitive to
9 customers.
10 Q. Can you provide an example that illustrates your point?
11 A. Yes. Schedule 1 ofEx.-MGE-Bollom-1 shows a simple comparison ofthe difference between
12 how costs are incurred and how costs are recovered from a residential customer. Please note
13 that while the actual values I assume for the fixed and variable costs are representative of the
14 costs of service included in the testimonies of Mr. James and Mr. Minor, I am using them for
15 illustrative purposes only. I have also combined the variable rates to reflect only a single
16 variable charge to keep the calculation simple. I'm using the example only to highlight the
17 interaction between the fixed and variable components.
18 The left side of Schedule 1 ofEx.-MGE-Bollom-1 shows a simple electric example. I'm
19 assuming a typical residential customer using 6,320 kWh per year. The total annual cost of
20 $989.15 to serve this customer is made up of$480 offixed costs and $509.15 ofvariable
21 costs. Under MGE's current rates, this cost of service is recovered annually through fixed daily
22 charges totaling $104.35 and variable kWh charges of$884.80. These are shown in the
23 column labeled "Before". I also assume that this hypothetical customer replaces an old air
24 conditioner with a new, more efficient model that reduces his summer usage by 20%, or 464
Direct-MGE-Bollom-7 kWh per year. The change in the cost of service and annual bill are shown in the column
2 labeled "After".
3 Let's first look at the cost of service. The fixed costs to serve the customer do not
4 change. They remain $480 per year. But because the customer is now using fewer kWh, the
5 variable costs decline proportionately to $471.77. The new annual cost to serve this residential
6 customer in now $951.77. The annual electric bill also changes as a result of the customer's
7 conservation effort. Under current rates, the annual fixed daily charges remain $104.35. With
8 fewer kWh, the total annual variable charges now total only $819.84. The customer's total
9 annual bill savings from installing a more efficient air conditioner are $64.96. Yet the actual
10 reduction in the cost of service is only $37.38. Because ofthe mismatch between the how the
11 costs of service are allocated to and recovered from customers, MOE experiences a net under-
12 recovery of fixed costs of$27.58.
13 These fixed costs need to be reallocated and recovered in the form of higher rates in
14 MOE's next rate case. Assuming they are appropriately allocated to the same customer (i.e. the
15 cost causer), even if MOE held the line on expenses and managed its capital budgets to keep
16 the cost of service unchanged, MOE would have to seek a 3.0% rate increase for this customer
17 just to account for the lost fixed cost recovery resulting from inappropriate rate design.
18 Q. Does your point extend to gas customers as well?
19 A. Yes. The situation for a natural gas customer is similar, as shown on the right side of
20 Schedule 1 ofEx.-MOE-Bollom-1. Because the supply cost of natural gas is essentially a
21 pass-through trued up regularly through the purchased gas adjustment, my example is focused
22 on only the distribution portion of MOE's natural gas rates. In this case I am assuming a
23 typical residential customer using 700 therms per year. The total annual cost of$350.44 to
24 serve this customer is made up entirely of fixed costs. Under MOE's current rates, this cost of
· 25 service is recovered annually through fixed daily charges totaling $123.01 and variable therm
Direct-MOE-Bollom-8 1 charges of $227.43. These are shown in the column labeled "Before". I assume that this
2 hypothetical customer installs weatherization measures and sets its thermostat down in the
3 heating season to reduce its annual natural gas usage by 10%, or 70 therms per year. The
4 change in the cost of service and annual bill are shown in the column labeled "After".
5 The total costs to provide distribution service to this customer do not change because the
6 entire cost is fixed. But the annual natural gas bill does change as a result of the customer's
7 conservation effort. Under current rates, the annual fixed daily charges remain $123.01. With
8 fewer therms, the total annual variable charges now total only $204.69. The customer's total
9 annual bill savings from conservation are $22.74. Yet there is no actual reduction in the cost
10 of providing the distribution service to this customer.
11 Because ofthe mismatch between how the costs of service are allocated to and
12 recovered from customers, MGE experiences a net under-recovery of fixed costs of$22.74.
13 These fixed costs need to be recovered in the form of higher rates in MGE's next rate case.
14 Again assuming they are appropriately allocated to the same customer, even ifMGE held the
15 line on expenses and managed its capital budgets to keep the cost of service unchanged, MGE
16 would have to seek a 6.9% increase in its distribution rates for this customer just to recover the
17 lost fixed costs resulting from inappropriate rate design.
18 While my examples focus on a single customer, the challenge is multiplied many times
19 when many ofMGE's customers take action to conserve energy. When an economic recession
20 like the one experienced in recent years forces most customers to find ways to reduce their
21 energy usage, the level of unrecovered fixed costs that need to be reflected in annual rate
22 increase requests can be significant. For both the electric and natural gas services we provide,
23 the need to increase rates to make up for lost recovery of fixed costs puts MGE in the difficult
24 position of trying to explain to customers why rates must increase in response to customer
25 conservation - actions that public policy and general economic conditions strongly encourage.
Direct-MGE-Bollom-9 Q. How do customers typically respond?
2 A. Customers that I've talked with have expressed frustration at what appears at times to be a
3 "Whack-A-Mole" game. Customers reduce their usage to reduce their bills. MGE under
4 recovers its fixed costs and is forced to request a rate increase. The PSCW grants a rate
5 increase for the prudently incurred fixed costs. Customers' bills go back up, offsetting a
6 portion of the savings they expected when they took the conservation action in the first place.
7 It can appear to customers as a never-ending cycle and tends to discourage further
8 conservation over time.
9 Q. How would rate designs that better match cost causation address this challenge?
10 A. If rates are designed to recover costs in a manner that matches how costs are incurred, the
11 mixed signals are significantly reduced for customers. In Schedule 2 of Ex.-MGE-Bollom-1,
12 the example is updated so that the fixed and variable charges are set to equal the fixed and
13 variable costs. Using the electric example, the fixed charge per day is increased to recover the
14 full annual cost of$480 per year. The variable kWh charge is reduced to match the costs that
15 vary by kWh. Now when the customer reduces its usage by 464 kWh per year, the reduction
16 in the customer's bill matches the reduction in the Company's costs to serve the customer. The
17 revised natural gas example in Schedule 2 ofEx.-MGE-Bollom-1 shows a similar result.
18 There is no net under-recovery that needs to be reallocated and requested as a rate increase in
19 a subsequent rate case. While the customer receives a smaller initial bill savings when the
20 rates match the cost of service, there is also no subsequent rate increase offsetting a portion of
21 the savings. There is much less confusion for the customer because the level of savings over
22 time is more consistent with the customer's expectations.
Direct-MGE-Bollom-1 0 1 Q. How has increasing customer interest in distributed generation increased the need for
2 MGE to better align its rates and costs?
3 A. MGE currently has over 240 customers with installed or accepted applications for customer
4 owned and sited distributed generation projects. Savings these customers receive on their
5 utility bill from MGE are a big part of the economic calculation they evaluate when
6 considering whether to install their own on-site generation. When the cost of electricity from
7 distributed generation, solar or other fuel source is equal to or less than the customer's retail
8 electricity rate from MGE, it is generally in the customer's interest to consider installing its
9 own generation. However, the retail electricity rate pays for much more than just the energy
10 the customer's own generation displaces. As I discussed earlier, a significant portion ofMGE's
11 fixed costs of service are recovered from charges that vary with the level ofkWh usage.
12 Therefore, a significant share of the savings customers see in their electricity bills as a result
13 of installing solar power represent payments toward the fixed costs of service. Allowing these
14 customers to avoid paying the costs of the infrastructure necessary to take service from, and
15 often put energy onto, the distribution grid unfairly shifts costs to other customers. Over time,
16 as more distributed generation of all types is added to MGE's system, the level of costs
17 inappropriately borne by other customers will grow, increasing the utility bills for residential
18 and small business customers that either cannot or choose not to pursue their own on-site solar
19 generation.
20 Q. Why is it important to better align costs and rates now?
21 A. The current allocation of fixed costs to charges that vary with the level ofkWh usage is not
22 sustainable over the long term. It is fundamentally unfair to have customers subsidize the
23 fixed costs of service for those customers with the economic means to provide all or a portion
24. of their own electricity generation regardless of the fuel source. Further, customers making
25 economic evaluations of whether to own their own generation based on MGE's current rates
Direct-MGE-Bollom-11 could face financial challenges in the future as rates and costs are inevitably realigned over
2 time to more closely match cost causation. Customers that base their decision to purchase a
3 distributed generation system at today's rates could see the economic benefits diminish
4 significantly as market conditions and regulatory policy require pricing that more accurately
5 matches how costs are incurred. It is prudent to better align costs and rates now while the
6 number of customers with distributed generation remains relatively low. The misallocation of
7 cost recovery will only become more dramatic and difficult to correct with the passage of
8 time.
9 Q. Do you believe that most customers will find the fixed charge levels proposed by
10 Mr. James and Mr. Minor to be reasonable?
11 A. Yes. For comparison purposes, I will focus on the fixed daily charges for residential electric
12 customers. The level of these charges typically produces the most discussion and controversy
13 but is also the easiest to find comparable alternatives. The PSCW regulates the level of electric
14 rates for most of Wisconsin's residential consumers. But there are more than 20 Wisconsin
15 cooperatives outside the PSCW's jurisdiction that also provide electricity service to residential
16 customers. Customers served by coops are effectively owners of their own utility and often are
17 referred to as members, not customers. Coops are essentially self-regulated on the rates they
18 charge. If the members are not happy, the members can change the board representation that
19 governs their local coop and change the rates. The level of fixed charges included in the rates
20 of coops in Wisconsin provides a useful benchmark for comparison with the charges proposed
21 by Mr. James in his rate design. Based on information publicly available on many ofthe
22 coops' individual websites, we were able to identify the fixed charges for 15 ofthe coops
23 serving Wisconsin residents. The charges are summarized in Schedule 3 ofEx.-MGE
24 Bollom-1. In every case, the charges are above the level proposed by Mr. James. The levels
Direct-MGE-Bollom-12 1 proposed by MGE in this case are a reasonable first step toward a better alignment of costs
2 and rates.
3 Q. Turning now to the Sp-3 Rate Schedule, please describe the proposed pricing method.
4 A. The new pricing method delineated in Ex.-MGE-Bollom-2 establishes a two tiered pricing
5 mechanism for chiller load above and below a 17,000 kW threshold level which will be
6 established when new chillers are added at the West Campus Cogeneration Facility (WCCF)
7 by the University of Wisconsin (UW). The 17,000 kW level is not tied to any specific chiller
8 or chillers. When the UW does add new chiller load to WCCF, which is currently expected to
9 happen in 2014, the Sp-3 maximum on-peak 15 minute demand charges will apply to any
10 chiller load above 17,000 kW and that load will be integrated with the other UW load served
11 under Sp-3. The associated energy charges above the 17,000 kW threshold will also apply
12 once the new chiller load is in service. Until new chillers are added, the 17,000 threshold is
13 not applicable.
14 Applicable energy charges may include station service costs as defined in the O&M
15 agreement between the UW and MGE for the WCCF, Sp-3 energy charges contained in the
16 rate schedule, gas costs converted to a kWh price using an 8,500 Btu/kWh heat rate and a
17 Market Price, all of which are defined in the proposed revisions contained in Ex.-MGE
18 Bollom-2. The pricing depends on the kW load ofthe chillers and the season ofthe year.
19 Q. Please explain the genesis of this new pricing method.
20 A. The Sp-3 rate schedule has been an item of contention between the UW and MGE in the last
21 two rate case proceedings. Late last year MGE and the UW began to have productive
22 discussions about approaches to resolving differences regarding the operation of the WCCF
23 and certain other aspects of the relationship. Those discussions culminated in an agreement
24 between the parties that focused primarily on steam and chilled water service at WCCF. In
25 March 2012, MGE made two filings with the PSCW to implement certain aspects of the
Direct-MGE-Bollom-13 1 agreement reached between the UW and MOE (PSC REF #s 160534 and 160667). At this
2 time, the Commission has yet to act on those proposals. We will provide an update on the
3 status of those changes no later than the hearings in this proceeding. The changes proposed in
4 this rate case would implement the remaining aspects of that agreement.
5 Q. Please describe the goal of the new chiller energy pricing method.
6 A. In the discussions between the Company and the UW, the UW expressed a desire to have all
7 its electric chiller energy use at WCCF priced at a level that approximates the cost it would
8 incur ifthe energy came from cogeneration at WCCF. In addition, the UW wishes to preserve
9 the option of using Sp-3 energy rates.
10 The heat rate calculation contained in the proposed chiller pricing provision, defined as
11 "Option B" in the proposed tariff revisions, approximates the cost per kWh to the UW when
12 WCCF generators are running. In order to minimize the potential for arbitrage between this
13 heat-rate-derived price and the standard Sp-3 energy rates designated as "Option A", the UW
14 will be required to nominate by February 14 of each year which pricing option , A orB, it
15 wishes to use for each month of the following calendar year. Further, the Sp-3 energy rate is
16 not an option for the on-peak time periods in the heating season because the UW does have
17 the right to require WCCF to run by the use of steam nominations. IfUW was allowed to use
18 the Sp-3 energy rate during the winter it would be able to arbitrage at the expense of MOE's
19 other customers its energy prices between Station Service and the Sp-3 energy rate with steam
20 nominations. UW agrees with this limitation.
21 Q. How does the heat rate calculation prevent UW from receiving energy below cost?
22 A. The formula calculates a cost per kWh that generally will exceed the marginal cost of
23 electricity since it is based on a cost that mirrors gas-fired generation. Experience tells us that
24 in general, the LMP prices in the MISO market are below the typical cost of gas generation. If
25 the LMPs rise above the typical cost of gas generation, the WCCF generators will likely be
Direct-MGE-Bollom-14 1 operating in the market and the price the UW pays for chiller usage will be the Station Service
2 cost. The heat rate price has been carefully developed to minimize the times when the derived
3 rate is less than the marginal cost of electricity. Because the UW is required to make its
4 nominations almost a complete year in advance, the risk of the Option B heat rate alternative
5 price falling below the market cost of energy for any significant period is no greater than the
6 risk MGE's customers generally face that the average market LMP will fall below the forecast
7 average level of fuel costs included in all base rates.
8 Q. The proposal has pricing that is different for chiller load below 17,000 kW and for
9 chiller load above 17,000 kW, please explain the reason for the difference.
10 A. The 17,000 kW amount is the value the parties agreed to use to represent the load level ofthe
11 four existing UW chillers. The UW is planning to add two more chillers by 2014. The
12 proposed revisions to Sp-3 recognize that new chiller load at WCCF would be treated like
13 other UW Sp-3 load for purposes of demand charges. When the WCCF generators are
14 operating, energy to serve total chiller load above 17,000 kW would be priced at the higher of
15 Station Service costs or the Market Price. When the WCCF generators are not running but
16 available to run, the energy pricing would be the same for all chiller load, except that load
17 above 17,000 kW would be charged demand charges. None ofthe chiller load would be
18 included in the Customer Maximum 15-minute demand because the chiller load is served
19 through the WCCF connection to the transmission system and does not touch MGE's
20 distribution system.
21 Finally the energy price that is used when the WCCF units are not available has been
22 modified from a MISO LMP plus 10% basis to a Market Price as described in the Ex.-MGE
23 Bollom-2. The Market Price is very similar to the existing LMP plus 10% feature. Rather than
24 using the 10% adder as a proxy for the costs above LMP, the Market Price will now
25 incorporate all actual costs in addition to the LMP.
Direct-MGE-Bollom-15 I Q. Referencing pages 15-16 of Schedule 1 ofEx.-MGE-James-2, please describe the new
2 rate structure for implementing the pricing method you just described.
3 A. Pages I5-I6 of Schedule I of Ex.-MGE-James-2 show the breakout of charges for all
4 components ofthe proposed Sp-3 rate schedule. The top section on Page I5 contains the
5 billing components and rates for the basic service under Sp-3. These are followed by the
6 energy charges for the UW WCCF chiller service. The chiller energy service charges are
7 shown by month for both the heating and cooling seasons, consistent with the options
8 available to the UW. Near the bottom of page I6 is a summary of forecast LMP estimates
9 followed by a summary of other LMP related MISO charges. The Company is proposing that
IO the basic energy charges for Sp-3 service (shown near the top of page I5) be set to more
11 closely match the 20 I3 LMP estimates shown at the bottom of page I6.
I2 Q. Please explain how you used the MISO LMP information in developing the final
13 proposed Sp-3 rates.
I4 A. In Docket 3270-UR-II6, the Commission revised the Sp-3 rate design based on changes
I5 proposed by MGE (PSC REF# I25079). One of the major changes to the rate design lowered
I6 the energy charges contained in the rate schedule. Those lower energy charges were based on
I7 a four year average LMP analysis. However in this current case the Company is proposing to
I8 use LMP estimates for 20 I3 as the basis for establishing the Sp-3 energy charges.
I9 Q. Why change methods?
20 A. In 2009 the LMP values were quite volatile and market liquidity was not extremely high. We
2I proposed using the four year average to help mitigate the effects that one year of volatility
22 would have on the estimates. Since market liquidity has improved and LMP prices have
23 become less volatile, we believe using 2013 forecasted LMP estimates to develop the Sp-3
24 energy charges is more consistent with the ultimate rate design goals for this service and more
Direct-MGE-Bollom-I6 1 consistent with how fuel cost forecasts are used to establish other rates that apply to all other
2 customers.
3 Q. What was the final step in developing the rates proposed for Sp-3 service?
4 A. The demand charges were increased to offset any change in total revenue from the changes to
5 energy charges to ensure that the final proposed rates for Sp-3 service still recover the full
6 revenue requirement allocation to the Sp-3 class. While the demand charges have been
7 increased significantly, those increases are offset by substantial decreases in the energy
8 charges.
9 Q. Does this conclude your testimony?
10 A. Yes.
Direct-MGE-Bollom-17 PSC REF#:166578
g."" BEFORE THE 1-' ::0 1-'· £%30 2 PUBLIC SERVICE COMMISSION OF WISCONSIN (,) Mrtl H (!) <: '1 M < 3 Application of Madison Gas and Electric t! 1-'· .. 0 (!) 4 Company for Authority to Change Electric Docket 3270-UR-118 0 0)(,) 5 and Natural Gas Rates '-.0 :;: § '-.1-'· 1-' [Q N tQ • 1-'· 0 6 DIRECT TESTIMONY OF KENNETH G. FRASSETTO "' ::l NO 7 ON BEHALF OF APPLICANT ...... w;:s ..., 1-'· [Q ~ g ::l [Q 8 Q. Please state your name, title, and business address. 1-'· i:l 9 A. My name is Kenneth G. Frassetto. I am the Director ofTreasury Management and Shareholder
10 Services for Madison Gas and Electric Company (MGE), and my business address is
11 133 South Blair Street, Madison, Wisconsin 53703.
12 Q. What is your educational background and work experience?
13 A. I graduated from the University of Wisconsin-Whitewater in 1987 with a Bachelor of
14 Business Administration degree in finance and from the University of Wisconsin-Oshkosh in
15 1989 with a Bachelor of Business Administration degree in accounting. Since June 1989, I
16 have been employed by MGE in various positions. I have been in my current position as
17 Director ofTreasury Management and Shareholder Services since July 2004.
18 Q. What is the purpose of your testimony in this proceeding?
19 A. The purpose of my testimony is to present the capital structure for the test year ending
20 December 31, 2013. I also will present the rates of return on MOE's average net investment
21 ratebase that would be earned under present retail electric and gas rates. Finally, I will discuss
22 MOE's electric and gas revenue requirements for the test year. MOE's revenue requirement
23 calculation supports a 5.82% increase in retail electric rates and a 2.59% increase in retail gas
24 rates. In Ms. Tamara Johnson's testimony she will provide an overview of MOE's forecasted
25 electric and gas income statements and rate base for the test year. Ms. Johnson will provide
Direct-MGE-Frassetto-1 1 details as to the primary cost drivers for the proposed rate increases and discuss the steps taken
2 by the company to minimize the rate increases.
3 Q. Was Ex.-MGE-Frassetto-1 prepared by you or under your direct supervision?
4 A. Yes.
5 Q. Please describe what is presented in Ex.-MGE-Frassetto-1, Schedules 1 through 3.
6 A. These schedules detail MGE's capital structure, the overall rate of return requirements, and the
7 revenue requirements for the test year ending December 31, 2013.
8 Q. Please explain the data set forth in Ex.-MGE-Frassetto-1, Schedule 1.
9 A. This schedule develops the weighted cost of capital of 8.20% for the test year as can be seen
10 on line 4 of Column 5.
11 Q. How did you arrive at the costs in Ex.-MGE-Frassetto-1, Schedule 1, Column 4?
12 A. The 10.3% return on common stock equity (ROE) shown on line 1 of Column 4 is the level
13 that was authorized by the Commission in MGE's last full rate proceeding, Docket 3270-UR-
14 117 (PSC REF# 143559).
15 As shown on line 5, the pretax times interest coverage for the test year at a 10.30% ROE is
16 projected to be 5.98. MGE's 59.65% level of equity on a regulatory capital structure basis
17 equates to a 55% level of equity on a financial capital structure basis, which the Commission
18 determined to be an appropriate target level in the company's last full rate case. This is within
19 the Commission's long-term equity range on a financial capital structure basis of 55% to 60%,
20 authorized by the Commission in Docket 3270-UR-117 (PSC REF# 143559).
21 Line 2 of Column 4 shows the current long-term debt cost of5.58%, which is lower than
22 the percentage approved in Docket 3270-UR-117. This includes a new $30 million long-term
23 debt issuance forecasted for MGE in 2013. The cost of short-term debt is forecasted to be
24 0.40% for the 2013 test year, as shown on line 3 of Column 4.
Direct-MGE-Frassetto-2 1 Q. Are Off-Balance Sheet (OBS) obligations included in the calculation of MGE's financial
2 capital structure?
3 Yes. OBS obligations in the amount of$74.9 million are included in MGE's financial capital
4 structure. These OBS obligations reflect MGE's non-purchased power operating lease
5 obligations, excluding the leases related to MGE Power West Campus and MGE Power Elm
6 Road, current commitments related to its purchased power agreements (PPAs), and MGE's
7 various trade receivables. These are the OBS obligations the Commission included in MGE's
8 last full rate case order in Docket 3270-UR-117 (PSC REF# 143559). The calculation of
9 MGE's OBS obligations along with its various rating agency reports will be filed with MGE's
10 prefiled data request responses.
11 Q. What is shown on Ex.-MGE-Frassetto-1, Schedule 2?
12 A. This schedule shows the calculation ofthe percent return requirement on MGE's electric and
13 gas net investment rate base (NIRB) for the test year. The weighted cost of capital of 8.20%
14 divided by the ratio of rate base plus CWIP to total capital of98.74% provides an adjusted
15 return requirement applicable to NIRB of 8.30%, as shown in line 3. Several adjustments to
16 the return requirement are appropriate. First, lines 4 and 5 of Schedule 2 show an adjustment
17 to provide a current return on CWIP on 50% ofthe electric and gas CWIP balance as a
18 percentage of rate base. The second adjustment provides for a return on the carrying costs for
19 Elm Road at MGE's short-term debt rate, as shown on line 6. This was approved by the
20 Commission in Docket 3270-UR-116 (PSC REF# 125079). After these adjustments, the
21 percent return requirement on NIRB for the test year 2013 is 9.53% for electric and 8.53% for
22 gas, as shown on line 7.
23 Q. Please explain what is shown on Ex.-MGE-Frassetto-1, Schedule 3?
24 A. This schedule shows the computations for developing the revenue requirements for both the
25 electric and gas rate increases for the test year. I compared the estimated return earned on
Direct-MGE-Frassetto-3 1 MGE's electric and gas operating income for the test year based on the adjusted NIRB to the
2 rate of return required as calculated in Schedule 2. That difference represents the deficiency in
3 return on NIRB. The operating income deficiency is then grossed up for taxes to arrive at the
4 total revenue deficiency. The revenue increase necessary to realize the return requirement for
5 electric is $22,451,000, or 5.82%, as shown on lines 7 and 9, respectively. The revenue
6 requirement for gas results in an increase to gas revenue of $4,308,000, or 2.59%, as shown on
7 lines 16 and 18, respectively.
8 Q. Does that conclude your direct testimony?
9 A. Yes, it does.
Direct-MGE-Frassetto-4 PSC REF#:l66585
g.'11 1 BEFORE THE 1-' ~ 1-'· t<:l n 2 PUBLIC SERVICE COMMISSION OF WISCONSIN () 1:>;1 Ul H (1) 3 <: 11 1:>;1 < t:l 1-'· 4 Application of Madison Gas and Electric .. n (1) 5 Company for Authority to Change Electric Docket 3270-UR-118 0 6 and Natural Gas Rates -....o0\() :;:§ 7 ..... 1-'· 1-'tll 8 .N ....til 0 9 DIRECT TESTIMONY OF JOHN D. KRUEGER ID::J NO 10 ON BEHALF OF APPLICANT OOH! 11 12 13 Q. Please state your name and business address.
14 A. My name is John D. Krueger. My business address is 133 South Blair Street, Post Office Box
15 1231, Madison, Wisconsin 53701.
16 Q. By whom are you employed and in what capacity?
17 A. I am employed by Madison Gas and Electric Company (MOE) as Manager of Rates.
18 Q. Please summarize your educational background and relevant work experience.
19 A. I graduated from the University of Wisconsin-Milwaukee in 1983 with a Bachelor of
20 Business Administration degree with a major in Marketing. In 1985, I completed graduate
21 work at the University of Wisconsin-Madison, receiving a Master of Business
22 Administration degree with a major in Transportation Economics.
23 I was employed by the Public Service Commission of Wisconsin (PSCW) from
24 August 1986 to March 1995 as a gas rate analyst, where my responsibilities included
25 purchased gas adjustment and gas purchase plan review, processing informal complaint
26 investigations, cost-of-service analysis, rate design, testifying in numerous rate cases and
27 generic proceedings, and other PSCW rate and rule actions. Since 1995 I have been
28 employed in various positions at MOE, most recently as Manager of Rates, and have
29 performed and overseen such duties as cost allocation, rate and service design, and
30 intervention in regulatory proceedings relating to rates, rules and customer services.
Direct-MGE-Krueger-1 1 Q. What is the purpose of your direct testimony in this proceeding?
2 A. The purpose of my testimony is to present the proposed increase to the green pricing premium
3 in MOE's Residential and Business Renewable Energy tariffs (RWE and BWE) from the
4 current 2.50¢/kWh to 3.00¢/kWh.
5 Q. Why is the Company proposing an increase in this case?
6 A. The premium rate in the RWE and BWE tariffs (Green Power Tomorrow Program- OPT) is
7 designed to represent the incremental difference between the cost of the standard market
8 energy mix and the cost of renewable energy used to supply the programs. It is appropriate to
9 increase the rate as that cost differential grows. In our last full rate case, we indicated that if
10 costs for the standard market energy mix as represented by the Locational Marginal Price
11 (LMP) at MOE's load node remained at the low levels we were experiencing at the time, it
12 would be appropriate to continue to increase the premium in a future case. Relatively low
13 LMPs continue to represent a longer-term development and not a recession-related anomaly.
14 Q. Do you have any concerns with increasing the premium?
15 A. Yes, customers have told us that their participation in our green energy program is a way for
16 them to demonstrate their support for increasing the amount of renewable energy in MOE's
17 energy supply mix over the long-run. Voluntary green energy programs like MOE's OPT
18 program provide both a cost effective way to increase the amount of renewable energy in its
19 mix earlier than required by Wisconsin renewable portfolio standard (RPS) mandates and a
20 way to increase the overall amount of renewable energy in the long-run. Our OPT program is
21 supplied primarily from wind resources. The cost associated with electricity produced from
22 wind resources is generally stable and predictable. These include either capital cost recovery
23 associated with turbines that MOE owns, or very stable prices for energy purchased under
24 power purchase agreements (PPA) from third-party suppliers. While solar energy makes up
25 only a fraction of one percent of the energy in the program, the same is true of solar
Direct-MGE-Krueger-2 electricity. In both cases, the fuel is free. Consequently, participants in the program anticipate
2 price stability, and that price stability is important to maintain a significant level of long-term
3 participation in the program. Frequent or large changes in the premium create customer
4 confusion and hurt the credibility of the voluntary program.
5 Q. Why then are you proposing an increase in the premium?
6 A. Because the cost of other energy sources varies with the changes in fuel prices (e.g. coal,
7 natural gas), the market value of renewable energy can change over time as the incremental
8 difference between the stable costs of renewable energy varies with the more volatile costs of
9 the standard market energy mix. If the premium is not periodically adjusted to reflect the
10 change in the differential, participants could be inappropriately subsidized by non-participants.
11 Q. What is the current cost differential?
12 A. The current cost differential is approximately 5.26 cents/kWh. We used the same method of
13 calculating the cost differential in this rate case as was done in all previous cases. The cost
14 differential was determined based on renewable energy contract costs for 2011 under MOE's
15 PPAs and Pg-4 Solar Buy-back program and average LMP values weighted for wind and solar
16 production for calendar year 2011.
17 Q. Why is MGE only proposing to increase the premium to 3 cents/kWh instead of the full
18 5.26 cents/kWh differential?
19 A. Increasing the premium to 5.26 cents/kWh would result in an unacceptable rate impact for the
20 current program participants. We are proposing to only increase the premium by 0.5
21 cents/kWh as this time. Natural gas prices have continued at lower levels recently with
22 significantly warmer than normal weather this past year through most of the space heating
23 regions of the country. Normal or colder than normal weather could increase prices for natural
24 gas in future years. In addition, natural gas demand is increasing as a generation fuel relative
25 to coal. Further, natural gas could see an increase in demand as a transportation fuel as more
Direct-MGE-Krueger-3 medium and large size vehicle fleets move to compressed natural gas as a transportation fuel
2 as the spread between gasoline and diesel fuel prices and natural gas prices increase. The
3 continued increase in supply of domestic shale gas has put downward pressure on pricing, but
4 there continues to be uncertainty related to regulation of the fracking process, which could put
5 upward pressure on natural gas prices. Potential costs associated with carbon regulation also
6 could be an issue in the long-term. It would not be fair to program participants to raise the
7 premium for green energy significantly in this case only to decrease it again in the medium or
8 long-term. The proposed 20% increase in the rate is significant for a one-year change. MGE
9 proposes continuing gradual changes should the cost of the standard market energy mix
10 continue to remain low for several years.
11 Q. Will the proposed increase in the premium affect participation in the program?
12 A. Yes it will. When the premium is increased, some participants will drop out ofthe program or
13 reduce the level of their participation. Both our past customer research and the actual behavior
14 of current program participants suggests that the level of participation by any customer is price
15 sensitive. When the price was reduced from 2.68 cents/kWh to only one cent/kWh in 2008,
16 many participants simply increased the amount of renewable energy they purchased to keep
17 their monthly total green energy payments constant. In some cases, customers were able to
18 purchase the equivalent of 100% of their electricity under the GPT program and actually
19 reduce the total amount they were paying each month for green energy on their energy bills.
20 When the premium was increased in recent years, the opposite effect occurred. Customers
21 have the option of selecting a fixed-dollar amount for GPT now, and participation in that
22 option will automatically change the level of participation as prices change. Some customers
23 have a certain budget or amount they are willing to spend for their support of renewable
24 energy and they will adjust their actual kWh purchase based on the change in price, sometimes
25 automatically based on the participation option they choose.
Direct-MGE-Krueger-4 1 Q. Was this effect taken into account in the Company's 2013 sales forecast?
2 A. Yes, in part. Sales in the price block option were adjusted to be revenue neutral in the 2013
3 forecast in the rate design included in the testimony of Steve James. The level ofkWh sales in
4 the RWE and BWE programs associated with percentage purchases was unchanged.
5 Q. Does this conclude direct your testimony?
6 A. Yes.
Direct-MGE-Krueger-5 PSC REF#:166580
'tl 1 BEFORE THE ....& ::0 !-'· 1:<.10 2 PUBLIC SERVICE COMMISSION OF WISCONSIN () i:
8 Q. Please state your name and business address.
9 A. My name is Steven S. James. My business address is 133 South Blair Street, Post Office Box
10 1231, Madison, Wisconsin 53 701-1231.
11 Q. By whom are you employed and in what capacity?
12 A. I work for Madison Gas and Electric Company (MGE) as a Senior Rate Analyst III.
13 Q. Please summarize your educational background and work experience.
14 A. I graduated from the University of Wisconsin-Parkside with a Bachelor of Science degree in
15 Mathematics and Economics.
16 I was employed at MGE from August 1981 through November 1989. During this time,
17 my responsibilities included work in electric load research, sales forecast and tariff
18 implementation for the gas and electric utilities. From November 1989 through June 2001, I
19 was employed at Alliant Energy Company (WPL) as a pricing analyst. My job responsibilities
20 involved work in the rates areas of the gas, electric and water utilities. This included testifying
21 in multiple rate hearings in Wisconsin and Illinois. I was involved in preparing the purchased
22 gas adjustments, analyzing rate design issues, coordinating new and innovative pricing
23 options, reviewing competitive analysis positions, and dealing with other utility rate-related
24 issues.
Direct-MGE-James-1 In June 2001, I became employed in my current capacity at MOE, where my duties have
2 included gas forecasting, gas cost allocation, gas cost optimization modeling, electric fuel cost
3 reporting, electric rate analysis and design, and other electric and gas rate initiatives.
4 Q. How have you designed your testimony and exhibits?
5 A. I am splitting my testimony into two sections. The purpose of the first part of my testimony is
6 to present three electric embedded cost of service studies. Ex.-MGE-James-1 provides the
7 summary information from the cost of service studies that were prepared. The second section
8 of my testimony, and Ex.-MGE-James-2, present a proposed electric rate design, multiple
9 related electric rate issues, and the monthly fuel cost plan for monitoring fuel costs for the test
10 year ending December 31, 2013
11 Q. Reference is made throughout your testimony to various schedules contained in exhibits
12 that have been marked for identification as Ex.-MGE-James-1 and Ex.-MGE-James-2.
13 Were these exhibits prepared by you or under your direction?
14 A. Yes.
15 COST OF SERVICE STUDY
16 Q. Please describe what is presented in Ex.-MGE-James-1.
17 A. Ex.-MGE-James-1 is the summary Schedule for the three embedded cost studies I am
18 presenting in this case. This six-page exhibit shows, for each study, the development ofthe
19 earned rate of return under present rates for the total Company and for each rate class, and the
20 revenue requirement needed to produce the Company's requested rate of return on rate base of
21 9.53% as developed by Mr. Kenneth Frassetto.
22 Q. What is the purpose ofthe embedded cost of service studies which you performed?
23 A. The purpose of these studies is to separate Company revenues, expenses, and plant investment
24 among its various customer classes.
Direct-MGE-James-2 1 Q. Please discuss the general methodology used in the study.
2 A. In order to establish a methodology for separation of costs among customer classes, each item
3 of cost must be examined. A three step process is generally used to perform these cost
4 breakdowns. The steps are referred to as classification, functionalization, and allocation. In all
5 three steps, recognition is given to the way in which the costs are incurred by relating these
6 costs to the way the utility system is operated to provide service to its customers.
7 Q. Please explain the meaning of these three terms.
8 A. The first term, classification, refers to the identification of costs as being related to one of
9 three components: demand, energy, or customers. In order to classify a particular cost by
10 component, primary consideration is given to the question ofwhether the cost varies as a
11 result of changes in the number of customers, changes in demand imposed by the customers,
12 or changes in energy use.
13 In addition to classification, costs must be functionalized, that is, identified with the
14 operating functions ofthe system. Operating functions are defined to recognize the different
15 roles played by the various facilities in the utility system. In the Company's accounts, these
16 various roles are already recognized to some degree, particularly in the recording of plant
17 costs as production, transmission, or distribution related. However, this functional breakdown
18 is not always adequate for cost study purposes. Individual plant items are examined where
19 possible, and the associated investment costs are assigned to one or more operating functions
20 so that the costs may then be allocated among customer classes.
21 Q. Did you functionalize plant costs in the same manner as in previous rate cases?
22 A. Yes, I did.
23 Q. Please describe the allocation process you used in your study.
24 A. The process of allocation involves apportioning total costs to the individual customer class
25 through the use of various allocation factors. Allocation factors specify each class's value or
Direct-MGE-James-3 1 share of a total quantity. For example, a total quantity would be system energy (kWh
2 generation), which is used in the allocation of fuel inventory. Each class is assigned a portion
3 of fuel inventory based on its share oftotal system energy.
4 Once individual costs have been allocated to the various classes of service, it is possible
5 to total these costs as allocated and then arrive at a breakdown of utility rate base, income, and
6 expenses among classes of customers, much as if separate financial statements were derived
7 for subsidiaries of a single company. The results are stated in summary form to measure, on a
8 fully allocated basis, the adequacy of revenues for each class of customers. The measure of
9 adequacy is the rate of return on rate base, which is compared to the Company's overall rate of
10 return on rate base. The difference between the Company's overall return on rate base and
11 each class's individual return on rate base is then used to develop each class's portion of the
12 Company's total revenue deficiency which, in turn, is used as a guide in the designing of rates.
13 Q. What are the three cost studies you are submitting in this case?
14 A. The three studies I am submitting are the "Standard", "Time-of-Day" and "Location" studies.
15 Q. Would you elaborate on the basis for the allocation methodology you used in the
16 Standard study?
17 A. The method is a traditional cost of service study that has been used by the Company in
18 previous rate cases. It basically follows the methodology outlined in the National Association
19 of Regulatory Utility Commissioners' 1992 Electric Utility Cost Allocation Manual.
20 Production and transmission plant are allocated on the basis of each class's contribution to the
21 average of the 12 monthly system peak demands. Distribution Plant allocations have been
22 made based on demand and customer allocators. The demand used was the sum of the class's
23 peaks, or the non-coincident peak method. Customer allocations are based on the average
24 customers for the test year.
Direct-MGE-James-4 1 The average ofthe 12 monthly peaks method is used to allocate production and
2 transmission plant on the assumption that the demand requirements of the system are
3 determined by the coincident peak loads of the various customer classes as they occur
4 throughout the year.
5 On the other hand, non-coincident peak demands are used to allocate distribution
6 facilities. Due to the differences in consumption patterns between the various classes of
7 customers, non-coincident peak demands provide a reasonable allocation of localized
8 facilities. The non-coincident demand method is premised on the assumption that each
9 customer class would, if served independently, require facilities to meet the class-peak
10 demand, and therefore, each class should be allocated costs on the basis of each class-peak
11 demand irrespective of the relation of such demands to the time of the monthly system peaks.
12 Q. That explains the demand allocation process, but how was the customer portion of the
13 distribution system determined?
14 A. The minimum system method was used. Development of the minimum system is
15 accomplished by taking the average cost of the minimum size unit in a plant account (for
16 example, a 35-foot pole) and multiplying it by the total number of units to arrive at the
17 customer component. The balance in the account is considered to be the demand component.
18 Q. Would you please describe the allocation methodology you used to assign the other rate
19 base items in your studies?
20 A. Accumulated provision for depreciation, contributions in aid of construction, and plant
21 materials and supplies have been allocated to each class on the basis ofthe corresponding
22 plant function or primary plant account. Fuel inventory was allocated on system kWh
23 generation.
Direct-MGE-James-5 1 Q. How were revenues allocated?
2 A. The projected test year retail revenues have been directly assigned to each customer class.
3 Revenues from sales to other utilities and backup generation are credited to each customer
4 class on the basis of system demand and energy. Other operating revenues are allocated to
5 customer classes by examining each item individually and determining whether it is plant,
6 revenue, or labor related.
7 Q. Would you please describe how you classified and allocated operation and maintenance
8 (O&M) expenses?
9 A. O&M expenses were either determined to be energy, demand, or labor related, or they were
10 classified and allocated on the basis ofthe plant accounts for which the expenses were
11 assessed. For example, distribution line transformer expenses in Account 595 were allocated
12 on the corresponding plant Account 368, line transformers.
13 Q. Please describe the allocation of other expenses.
14 A. Depreciation expenses were also allocated by type of Production Plant and by primary plant
15 account for the other functional plant groups.
16 Taxes other than income taxes have been treated individually and allocated in a manner
17 consistent with the basis on which the respective taxes were assessed.
18 Q. Please describe how you have allocated federal income taxes and Wisconsin franchise
19 taxes.
20 A. Total taxes have not been allocated per se. Instead, the respective tax bases have been
21 developed, and taxes were calculated directly for each customer class.
22 The starting base for the tax calculation, operating income before taxes, represents
23 operating revenue less all operating expenses. Net additions to or deductions from the
24 respective tax bases are allocated individually. In this manner, taxable income for each
Direct-MGE-J ames-6 1 customer class is developed for each tax base and the appropriate tax rate applied. Final tax
2 amounts result after the allocation of any tax adjustments.
3 Q. How does the Time-Of-Day study differ from the Standard study?
4 A. There are two main differences between the Time-of-Day study and the Standard study. In the
5 Standard study, all Production Plant was allocated based on each customer class's contribution
6 to the system peak or CP demand. In the Time-of-Day study, the allocation of base load
7 Production Plant is split, with 60 percent based on demand and 40 percent based on energy.
8 The theory behind this is that base load plants have a dual role of meeting peak demands and
9 providing energy at the lowest possible cost. If demand were the only consideration, then
10 peaking plants, which have a lower installed cost per kW, could be built in place of large base
11 load units. However, cost of energy is also a factor in determining what type of unit is
12 installed. For example, base load plants are built because they have lower energy costs than
13 peaking units. Using a combined energy/demand allocator reflects the trade-off between
14 operating expense and initial plant cost made by MOE when it decided what plants should be ..
15 built. Peaker generation plant remains allocated 100% on CP demand.
16 In addition, the energy allocation in the Standard study was based on total generation
17 (total sales plus losses). This energy allocator, designated E10, was replaced with a new
18 allocator, E12, which reflects each class's on-peak energy use. In this way, classes using more
19 energy during the higher cost on-peak periods are assigned more of the costs associated with
20 those periods.
21 Q. Why did you split the allocation of Production Plant 60% demand and 40% energy?
22 A. This split has been used in previous MOE rate cases by Commission Staff and I saw no reason
23 to change it.
Direct-MOE-James-7 Q. How does the Location study differ from the Standard and Time-of-Day studies?
2 A. In the first two studies I used the minimum system approach to allocate customer distribution
3 costs. The Location study does not use the minimum system in allocating Distribution Plant.
4 Instead, the Location study allocates these costs based on non-coincident peak demand. This
5 study is included to provide a balance to the use of the minimum system approach. Some
6 analysts believe that the minimum system approach overstates the customer portion of costs
7 because it does not take into account customer density and location. Conversely, the Location
8 study understates the customer portion by eliminating all customer costs except for meters and
9 services.
I 0 Q. Why did you file three different studies in this case?
II A. Since there is no one universally accepted cost of service study, I have filed three studies
I2 containing different, but generally accepted methodologies. With the three studies, I hope to
I3 show a range of costs that the parties involved in this case can use in the design of rates.
I4 Q. Are all the studies equal in value?
I5 A. Cost of service studies are not meant to establish precise costs for customer classes. Cost study
I6 methodology is usually determined by the analyst performing the study. The analyst picks a
I7 methodology or methodologies he or she believes best represent cost causation among the
I8 various classes of customers. I have offered three studies in this case to provide the
I9 Commission with a range of costs produced by various accepted cost methodologies. In past
20 cases, the Commission has found it reasonable to rely on the results of more than one cost of
2I service study when allocating revenue responsibility. Depending on different factors the
22 Commission may consider as to how the rate increase in this case should be apportioned
23 among the customer classes, some studies may be deemed more appropriate than others.
Direct-MGE-James-8 1 ELECTRIC RATE DESIGN AND RATE ISSUES
2 Q. Please describe Schedule 1 of Ex.-MGE-James-2.
3 A. Schedule 1 shows the electric rate design and revenue allocation among the electric rate
4 classes. Schedule 1, page 1 of 41, provides summary information of the rate increases for each
5 rate class. The remaining pages of Schedule 1 show the detailed billing statistics and the
6 current and proposed rates for the rate classes.
7 Q. What is the purpose of Schedule 2 of Ex.-MGE-James-2?
8 A. Schedule 2 provides support for the 2012 calculation ofthe 2005 Wisconsin Act 141
9 contribution by rate class.
10 Q. Please describe what is shown in Schedule 3 ofEx.-MGE-James-2.
11 A. Schedule 3 shows generic bill comparisons for various rate classes. The rate classes included
12 in the bill comparison make up about 85% of the total electric revenues collected by MGE.
13 The proposed rate design for the time-of-use rate classes uses the base energy rate structure
14 that will be addressed later in this testimony.
15 Q. What is shown in Schedule 4 ofEx.-MGE-James-2?
16 A. Electric tariff sheets with proposed changes to the tariff language are shown in Schedule 4.
17 Also included in Schedule 4 are the tariff sheets that have been significantly modified due to
18 the Company's proposal to implement a base energy rate design structure. This base energy
19 rate design structure will be addressed later in this testimony.
20 Q. What is shown in Schedule 5 ofEx.-MGE-James-2?
21 A. Schedule 5 shows the calculation of the parallel generation rates using 2011 MISO LMP
22 information.
23 Q. What is shown in Schedule 6 and 7 of Ex.-MGE-James-2?
24 A. These schedules support changes to charges that are included on tariff sheet E-54.0,
25 Miscellaneous Service Charges. Schedule 6 is the calculation of the electric distribution costs
Direct-MGE-James-9 1 for energy only customers, demand billed customers and lighting customers. Schedule 7 is
2 support for revising the temporary service charges. These two issues will be discussed in more
3 detail later in this testimony.
4 Q. What is shown in Schedule 8 ofEx.-MGE-James-2?
5 A. Schedule 8 is support for the design of splitting the current TOD pricing options into
6 additional price periods.
7 Q. What is in Schedule 9 of Ex.-MGE-James-2?
8 A. A survey that was mailed to our customers in August, 2011 asking for their opinions on a
9 residential direct load control program as well as the general responses to the survey are
10 shown in Schedule 9.
11 Q. What is shown in Schedules 10 and 11 ofEx.-MGE-James-2?
12 A. Two additional demand response initiatives that MGE is proposing are implementing buyouts
13 for interruptible customers and adapting critical peak pricing rates for our Cg-2 and Cg-6
14 customers. Schedule 10 and 11 include support information for the design of the rate structure
15 for these rate classes.
16 Q. What is shown in Schedule 12 of Ex.-MGE-James-2?
17 A. Schedule 12 contains consumer impact and ability to pay information.
18 Q. What is shown in Schedule 13 ofEx.-MGE-James-2?
19 A. Schedule 13 contains the Company's proposed fuel cost plan for monitoring fuel costs during
20 the test year ending December 31,2013.
21 Q. Please describe the class revenue allocation reflected in the proposed rate design.
22 A. Page 1 of Schedule 1 ofEx.-MGE-James-2 summarizes the class revenue allocation. The
23 overall increase is 5.82%. The rate changes for most of the classes were designed to be in the
24 range of 4% to 8%. I used the cost of service studies presented with this testimony and other
25 relevant information as guidelines for increasing the individual class revenues
Direct-MGE-James-1 0 1 Q. In general terms, what type of rate changes have you made to the rate classes?
2 A. The proposed rate increases are distributed among the customer charges, electricity service
3 demand charges for demand-billed rates, and electricity service energy rates. Increasing these
4 billing components will ensure that most individuals in any specific rate class will receive bill
5 increases approximately equal to the overall rate increase for the respective rate class. The
6 electric bill comparisons in Schedule 3 ofEx.-MGE-James-2 show the bill impacts for various
7 sized customers for the rate classes that have a large number of customers.
8 Q. What changes are you proposing to the customer charges?
9 A. I am proposing increases to the customer charges for all rate classes. Current customer charges
10 do not recover the fixed costs that MGE incurs. These proposed increases will still only
11 recover a portion of the fixed costs through the customer charges, but a greater proportion than
12 in current rates. Mr. Gregory Bollom elaborates further on why the company proposed these
13 changes in his testimony.
14 Q. Will the increase in the customer charge cause small energy users to experience larger
15 percentage increases than the average or larger electric users in the class?
16 A. The small customers will receive larger percentage increases, but as Mr. Bollom states in more
17 detail, this increase is justified due to the costs that these customers cause the utility relative to
18 the revenue that we currently receive from these customers. The customer charge increases to
19 about $12.17 per month from about $8.70, or only about $3.47 per month out of an average
20 monthly bill of $89 per month.
21 Q. What fundamental change are you proposing to the rate structure for all of the
22 time-of-use rate classes?
23 A. Currently time-of-use energy charges are designed to recover the cost of service through
24 separate on-peak and an off-peak energy rates. I am proposing to eliminate this rate structure
25 and to create a base energy rate that will be charged for all energy used by time-of-use
Direct-MGE-James-11 1 customers, with adder rates for the on-peak time-of-use rate periods. While this will change
2 the appearance of the bills, the basic structure of time-of-use rate design is maintained. The
3 new tariff format for those rate schedules that are impacted by the implementation of base
4 energy rate are included in Ex.-MGE-James-2, Schedule 4. This redesign of the energy charge
5 will recover revenues from each customer comparable to what would be recovered under the
6 old time-of-use rate structure. The bill comparisons in Ex.-MGE-James-2, Schedule 3 show
7 that the new rate design does not distort the increases that individual customers will pay under
8 the new base energy rate design.
9 Q. Why are you proposing this modification to the electric rate structure?
10 A. The billing and accounting of Act 141 costs are complex for the current time-of-use rate
11 classes. Now that MGE is proposing to expand the time-of use structure to more than just the
12 standard on-peak/off-peak rate design, the billing and accounting becomes significantly more
13 onerous. Each Act 141 account requires distinct credit and debit accounts for each rate that is
14 used to collect the Act 141 charge. The demand based electric time-of-use rates have no single
15 rate component that can be used to collect the Act 141 charges and credits. That means that
16 MGE has to collect the Act 141 charges and credits across multiple rate components within
17 the class rate design. For instance, the Cg-2 rate currently collects the Act 141 charges and the
18 Large Energy Customer (LEC) credits separately on the on-peak and off-peak energy charges.
19 In this docket, we are proposing to add two additional time periods to the rate design. This
20 addition increases the complexity of billing, accounting and reporting ofthe Act 141 charges
21 and credits.
22 The bills for LEC customers show an Act 141 credit for both the on-peak and the
23 off-peak energy usage. Expanding to two more time-of-use periods would mean adding two
24 more Act 141 credit lines to the bill. With the proposed rate structure, the LEC credits can all
Direct-MGE-James-12 1 be shown on one line of the bill as opposed to the four lines that would be needed under our
2 current rate structure.
3 Q. Are you also proposing a similar change to the Residential Lifeline rate class?
4 A. Yes. In order to maintain continuity in the billing structure, we propose that the residential
5 lifeline rate design be structured such that there is a base energy charge for all energy used by
6 a customer. Any energy in excess of 300 kWh per month will be billed as an energy adder
7 measured by the difference between the lifeline base rate and the effective Rg-1 electric
8 service rate. The Act 141 billing and monitoring will be simplified since the Act 141 charge
9 can all be collected as part of the base energy rates. Like the proposed time-of-use rate
10 designs, this new residential lifeline rate design will change the appearance on the bill, but
11 does not distort the increases that individual customers will pay.
12 Q. Why are you proposing a larger percentage increase to the residential lifeline tariff than
13 to the standard residential rate?
14 A. We currently have only 15 customers on the electric residential lifeline rate. This lifeline rate
15 was closed to new customers effective July, 1985 in Docket 3270-UR-13. I am proposing to
16 eliminate the differential between the standard Rg-1 rate and the Rg-3 lifeline rate customer
17 charges that has developed over the years. When this rate was closed to new customers in
18 1985, the customer charge was equal to the Rg-1 customer charge. After 27 years, the
19 customer charge for lifeline customers is now about $3.90 a month less than the Rg-1
20 customer charge. Since there was no apparent intention to have a differential in the lifeline
21 customer charge at the time that the lifeline rate was closed, I am proposing to eliminate the
22 difference in the customer charge that currently exists.
23 In 1985, the summer energy rate for the first 300 kWh was $0.0271/kWh less than the
24 Rg-1 summer rate and the winter energy rate differential between the first 300 kWh and the
25 Rg-1 rate was $0.0231/kWh. Currently, the summer energy rate differential is $0.03845/kWh
Direct-MGE-James-13 and the winter differential is $0.03536/kWh. The intended lifeline benefit appears to have
2 been directed to the energy charge. I am proposing to increase the summer energy differential
3 to $0.04889/kWh and the winter differential to $0.04577/kWh in order to offset some of the
4 bill impact of the increased customer charge.
5 Q. Please provide the background for your rate design for the Sp-3, University of Wisconsin
6 (UW) Time-of-Use rate schedule.
7 A. For several years, MGE and the UW have been discussing alternative rate designs to serve the
8 university facilities, particularly the West Campus Cogeneration Facility (WCCF) that is
9 jointly owned by MGE and UW. Earlier this year, MGE and UW agreed on a modified Sp-3
10 rate design that would provide the UW rate options for determining the price of electricity that
11 would be supplied to power WCCF chillers at times when the WCCF is not operating.
12 Mr. Bollom's testimony (Direct-MGE-Bollom-13 to Direct-MGE-Bollom-17) provides further
13 details on additional proposed revisions to Sp-3 for 2013. Changes to the Sp-3 tariff that are
14 proposed to take effect immediately were filed with the Commission on March 1, 2012 as the
15 first step toward implementing this mutually-agreed upon rate design change. In the exhibits
16 related to my testimony, I am proposing an Sp-3 rate design based on the proposed rate
17 structure that was filed on March 1. If the Commission does not approve the filing that sets
18 forth the new rate structure, I intend to file a modified rate design in supplemental testimony.
19 Q. Did the March 1 filing include any proposed new rate formulas?
20 A. Yes. One ofthe proposed changes establishes a new formula applicable during the cooling
21 season for determining the price of electricity supplied to power the WCCF chillers at times
22 when WCCF is not operating. The formula incorporates the current cost of gas that would
23 otherwise be used for generation at the WCCF facility and a stated heat rate of 8,500
24 Btu/kWh. The charges on pages 15 and 16 of Schedule 1 ofEx.-MGE-James-2 for chiller
25 energy that utilize this new formula are estimates for determining revenues for the Sp-3 rate
Direct-MGE-James-14 1 class. The actual chiller rates for 2013 under Option B will be determined by the formula rate
2 described in paragraph 6.b. ofthe Special Terms and Provision section.
3 Q. Do you have any other changes to the rate design schedules?
4 A. Yes. I am proposing several tariff language changes. Most ofthese changes clarify the intent
5 and application ofthe existing tariff. The proposed tariff revisions are set forth in Schedule 4
6 of Ex.-MGE-James-2.
7 With the termination of the Cg-1 rate schedule, customers who previously had the option
8 of taking service on the Cg-1 or the Cg-4 rate Schedule are now required to take service on the
9 Cg-4 rate schedule. Since this is a mandatory rate, I propose deleting some of the conditions in
10 the Special Terms and Provisions section. These include an unnecessary reference to the Cg-3
11 rate Schedule and two paragraphs that refer to a waiting list to participate in the Cg-4 rate
12 schedule. These deleted portions of the Cg-4 tariff can be found in Ex.-MGE-James- 4,
13 Schedule 4.
14 For the Cg-2, C&I Lighting and Power Time-of-Use Rate, and the Cg-6, Commercial
15 and Industrial Lighting and Power: Large Annual High Load Factor Service, I am proposing
16 to include a section clarifying the use of a demand waiver. This demand waiver will allow
17 large customers to perform short duration tests of their electric system without the test
18 affecting their maximum monthly on-peak 15-minute demand charges. However, if a
19 customer maximum 15-minute demand occurs at the time ofthe test, the customer will be
20 charged the customer demand charge for the demand that was metered. These tests will only
21 be available for customers with prior approval by the Company. This provision will not permit
22 the customer to obtain a waiver on its demand charges for load that is a part of its normal
23 business requirements. The demand waiver terminology can be found in Ex.-MGE-James-2,
24 Schedule 4, pages 8 and 10.
Direct-MGE-James-15 The AVAILABILITY section ofthe Cg-6, Commercial and Industrial Lighting and
2 Power: Large Annual High Load Factor Service, (Sheet E-20.0) is being modified to clarify
3 that customer eligibility for the rate is determined by the customer's maximum I5-minute
4 demand.
5 I also am proposing to revise the buyout option ranges in paragraph 4 ofthe Conditions
6 of Delivery section ofthe C&I High Load Factor Direct Control Interruptible Service for
7 Transmission Voltage Rate (Cp-I). The current buyout option ranges are $0.06/kWh to
8 $0.12/kWh and $0.I2/kWh to $0.20/kWh. The new ranges will be $0.09/kWh to $0.I5/kWh
9 and $0.15/kWh to $0.20/kWh. The current summer on-peak rate exceeds $0.06/kWh, so this
I 0 buyout option is no longer applicable at the lower range level of the first buyout range.
II For Sp-4, Oscar Mayer Foods Corporation Time-of-Use Rate, I am proposing to remove
I2 the $0.06/kWh and $0.08/kWh buyout options included in paragraph 2 ofthe Supplemental
I3 Power section. These buyout options are being removed since the current summer on-peak
I4 rate exceeds $0.08/kWh. I am also proposing to modify the buyout rates to $0.IO/kWh,
I5 $0.15/kWh and $0.20/kWh.
I6 On Sheet E-40.0, Backup Generation Service Rider, I am proposing to reorganize the
I7 RATE section. Currently, the second paragraph of this section addresses both interruptible or
I8 supplemental service and firm demand levels. I am proposing that the firm demand levels be
I9 included in a separate paragraph since they are applicable to both paragraphs I and 2 ofthis
20 section.
21 I am proposing to modify the procedure for determining the interruptible standby and
22 interruptible maintenance demand charges in the Alternative Generation
23 Schedule (Schedule AGS). The firm standby and the energy charges are based on the Cg-2
24 rates. The current process for determining the interruptible standby and interruptible
25 maintenance demand components are based on the summer firm standby demand charges for
Direct-MGE-James-16 1 the AGS rate. The summer interruptible demand charge was calculated to be a third of the
2 firm standby demand charge while the winter interruptible standby and interruptible
3 maintenance charges were a sixth of the summer standby demand charge. There is no support
4 for determining the interruptible standby and interruptible maintenance demand charges in this
5 manner. It would be more appropriate to set the AGS interruptible rates based on the Cg-2
6 demand charges less the Direct Control Interruptible Service Rider credit. The modified rate
7 design for AGS using the Direct Control Interruptible Service Rider credit to determine the
8 interruptible demand charges is shown on page 35 of Schedule I ofEx.-MGE-James-2.
9 Q. Are there or have there ever been any customers on this rate?
10 A. No. Since no customers have ever received service under this rate, this modification in the rate
11 design will have no impact on existing customers.
12 Q. Are you proposing any changes to Outdoor Security Lighting (OL-1)?
13 A. Yes. First, I am proposing to change the name ofthe tariff from Outdoor Security Lighting to
14 Outdoor Overhead Lighting. This is a more appropriate name for the intended use of this
15 tariff. For this same reason, I am changing the name of section 2 of the Rate section from
16 security lighting to outdoor overhead lighting. I propose to close the HPS dusk-to-dawn yard
17 lighting options and to close the MH security lighting options. I am also proposing to add
18 several LED lighting options under the outdoor overhead lighting rate section.
19 Q. Why do you want to close the dusk to dawn yard lighting options?
20 A. More cities and villages in MOE's territory are implementing "dark sky" ordinances. Dark sky
21 implies preserving and protecting the nighttime environment. The dusk-to-dawn lighting
22 fixtures allow lighting to spread out to a wider pattern, which is inconsistent with increasingly
23 prevalent dark sky ordinances. Security lighting fixtures do not allow the light to spread as
24 much as the dusk to dawn lighting. Closing the dusk to dawn lighting options to new
Direct-MGE-James-17 1 customers enables the Company to provide only outdoor lighting that is acceptable to the
2 communities that we serve.
3 Q. What LED security lighting options are you proposing?
4 A. Unlike high pressure sodium (HPS) or metal halide (MH) lighting, LED lighting does not
5 come in standard wattage sizes. Instead LED is measured in number of individual LED lamps
6 on a fixture. The proposed LED rate class that I am proposing has separate rates for LED
7 fixtures with 30 or less lamps, 31 to 40 lamps, 41 to 60 lamps and 61 to 100 lamps.
8 Q. How do LED fixtures compare to HPS or MH fixtures?
9 A. The lumens for a 30 lamp LED are comparable to the lumens for a 70 Watt HPS or MH
10 fixture and a 40 lamp LED is comparable to a 150 Watt HPS or MH. The 60 lamp LED is
11 similar to a 250 Watt HPS or MH and a 100 lamp LED is comparable to a 400 Watt HPS or
12 MH. By adding these four new LED rate options, the customer can maintain the same quality
13 of lighting at a lower rate than is available for the comparable HPS or MH lamp options. In
14 order for customers to better understand the quantity of lighting that is provided by LED
15 lamps, I am proposing that the tariff reference the four new LED rate options by their
16 approximate wattage equivalence to that of a high pressure sodium or metal halide lamp.
17 Q. Why are you proposing to close the metal halide outdoor overhead lighting fixture
18 options?
19 A. LED lighting is more efficient than MH lighting, provides cleaner lighting, and is available at
20 a lower rate than a comparable MH fixture. In essence, MH lighting options are becoming
21 obsolete with the advent of LED lighting. If a customer is opposed to LED lighting, HPS
22 outdoor overhead lighting is still an option.
23 Q. Do you have any changes to the Gf-1 Miscellaneous Flat Rate Service?
Direct-MGE-James-18 1 Yes. For the Miscellaneous Flat Rate Service, Of-1, I am proposing to terminate the Category
2 1 rate option. Category 1 ofthe Of-1 rate is for public telephone booths. We have not had any
3 public telephone booths on this rate for at least five years.
4 Also in the Of-1 rate class I am proposing that the Category 2, CATV amplifiers, be
5 closed to new customers and that current CATV s on this rate be moved to a metered rate over
6 the next three years. At that time, Category 2 ofthe Miscellaneous Flat Rate Service would be
7 terminated. The Miscellaneous Flat Rate Service is intended for customers with small
8 predictable usage. MOE is finding that because ofrecent expanded use ofthe CATV
9 amplifiers for internet service and other enhancements to the original cable TV model, CATV
10 loads can be very different from one unit to the next and the usage can be substantial. Since
11 this load cannot be accurately estimated today, it is appropriate to require that this load be
12 placed on a metered service. We have about 575 CATVs currently being billed under
13 Category 2 of the Miscellaneous Flat Rate Service and MOE's intent is to install meters and
14 move the customers to a metered rate by January 1, 2016. Other utilities in the state meter the
15 service for the CATV amplifiers.
16 Q. Why are you proposing that the CATVs be converted to a metered rate over a three year
17 period?
18 A. The cost to the customer of retrofitting the CATV amplifiers so that MOE can install
19 metering equipment to monitor energy usage is expected to be $500 to $1,000 per metered
20 site. It makes sense to spread out this cost and labor time over three years so that the entire
21 rate impact is not felt in a single year.
22 Q. Are you proposing any changes to the Residential and Business Renewable Energy
23 Programs (RWE-1 and BWE-1)?
Direct-MOE-James-19 1 A. Yes. I am proposing to increase the incremental energy charge for the two Green Power
2 Tomorrow programs from $0.025/kWh to $0.030/kWh. Mr. John Krueger will address this
3 proposed change in his direct testimony.
4 Q. What changes are you proposing to the Parallel Generation (Pg-1) rates?
5 A. In the past, the parallel generation rates were designed using the avoided cost peaker method.
6 This method uses a marginal cost study to determine the avoided cost of purchasing power
7 from a qualified facility. As the MISO market has developed over the last six or seven years,
8 the avoided cost peaker method is no longer a true indicator of marginal cost since a utility's
9 marginal energy is generally obtained in the MISO market.
10 Q. How do you propose to determine parallel generation energy rates as shown in
11 Schedule Pg-1?
12 A. MOE proposes to develop parallel generation rates in a manner similar to Wisconsin Public
13 Service Corporation's method approved in 2011. The energy rates for each year would be
14 based on MOE's Day-Ahead load zone LMPs for the previous twelve months ending in
15 October. These LMPs would be the best available indicator of avoided costs since they reflect
16 MOE's most recent actual marginal energy costs. Ifthis new procedure for determining the
17 parallel generation rates is approved in this docket, the Company will file the LMP
18 information for the twelve months ended October, 2012 to be effective, without further PSCW
19 action, for the year 2013.
20 Q. Can you provide an estimate of what these rates might be?
21 A. Yes. The 2011 DA LMP information is shown in Ex.-MGE-James-2, Schedule 5. This
22 information shows the average MISO Day-Ahead LMPs. These numbers were then adjusted
23 for gross receipt tax and losses to derive what the parallel generation rates would be based on
24 2011 DA LMPs. This information is just an estimate ofwhat the parallel generation rates
Direct-MGE-James-20 would be based on 2011 DA LMPs. As stated earlier, actual parallel generation rates for 2013
2 will be based on LMPs for the twelve months ended October 2012.
3 Q. What change are you proposing to the Parallel Generation: Net Metering Pg-2 Rate
4 Schedule?
5 A. I am proposing to add language to clarify that with respect to any energy for which the
6 customer receives a net energy credit on its monthly bill, that customer retains any renewable
7 energy credits and benefits, emissions allowances, or other renewable energy, air emissions,
8 or environmental benefits for which the customer's generation project qualifies. MOE
9 currently treats net energy purchases by the Company in this way. The new language will
10 simply make this explicit in the rate schedule.
11 Q. What changes are you proposing for the Distribution Extension Embedded Cost
12 Allowances?
13 A. Ex.-MOE-James-2, Schedule 6, provides the Company's methodology for determining
14 Distribution Extension Embedded Cost Allowances. Support for the proposed changes to the
15 allowances is in the standard cost of service study, which has frequently been used as the basis
16 for Commission-approved Distribution Embedded Extension Allowances. MOE proposes that
17 the energy-only extension allowance be increased from $789 per customer to $886 per
18 customer, and that the lighting extension allowance of $43 per fixture be increased to $50 per
19 fixture based on the information provided in Schedule 6.
20 The current demand-only extension allowance is $102 per kW. The information in
21 Schedule 6 would support an increase in the demand-only extension allowance to $15 5 per
22 kW. Because this would be nearly a fifty percent increase over the current allowance, MOE
23 proposes that the demand extension allowance be increased by ten percent, to $112 per kW.
Direct-MOE-J ames-21 r 1 Q. Why is the projected demand-only extension allowance so much higher than the current
2 effective allowance, while the projected energy-only and lighting extension allowances
3 are more in line with the current allowances?
4 A. The energy-only allowance is based on the estimated number of customers classified as
5 energy-only for the test year. The growth in number of customers is reasonably consistent
6 from year to year, so the energy-only extension allowance remains fairly consistent, provided
7 that the level of embedded investments doesn't change dramatically. The same applies for the
8 lighting extension allowances. The growth in the number of lights is relatively steady, so the
9 lighting allowance also remains consistent as long as the level of embedded investments
10 doesn't change dramatically. In 2011, the embedded investments increased by eleven percent
11 over what they were two years ago when the extension allowances were last revised. This
12 eleven percent increase explains the relatively high increase that the energy-only and
13 streetlight allowances are receiving in this docket.
14 The estimated demand-only extension allowance is calculated by dividing the allocated
15 embedded investment by the non-coincident peak demand of the demand-only rate classes.
16 While customer growth has been steady for the last several years, non-coincident peak
17 demands have decreased due to customer conservation initiatives. Since embedded
18 investments continue to rise, with no corresponding increase in non-coincident peak demand,
19 the demand-only extension allowances have increased much faster than the other two
20 extension allowances.
21 Q. Are you proposing any other changes to the Miscellaneous Service Charges listed on
22 Sheet E-54.0?
23 A. Yes. I am proposing to increase the temporary service charge from $72 to $111. This charge
24 has not been updated in more than ten years. The support for updating the temporary service
25 charge is in Schedule 7 ofEx.-MGE-James-2. MGE reviewed its temporary service charge
Direct-MGE-James-22 orders in 2010 and 2011. As can be seen in Schedule 7, the actual costs to MOE for these
2 service charges were $106 per order in 201 0 and $116 per order in 2011. I am proposing to
3 increase the cost to $111 per order based on the average cost over the two year period. The
4 current charge of $72 per order is significantly below MOE's cost which implies that these
5 temporary services are being subsidized by other customers.
6 Q. Do you have any other changes to the electric service rules and regulation sheets?
7 A. One final change that is being proposed is the addition of language in the Electric Rules and
8 Regulations (Sheet E-65.5) making it explicit that MOE may have access to a customer's
9 premises for installing and upgrading equipment. This is not intended to represent a change
10 but simply to confirm the Company's right to install and upgrade metering equipment on the
11 customer's premises.
12 Q. Are you addressing any of the demand response initiatives that were referenced in the
13 3270-UR-116 Order?
14 A. Yes. There are five demand response initiatives that were referenced in the 3270-UR-116
15 Order (PSC REF# 125079). One ofthese initiatives was to transfer customers from the Cg-1
16 rate class to the Cg-4 rate class. This was completed in March of this year. The remaining four
17 initiatives are intended to: 1) split the current TOD pricing periods into additional pricing
18 periods, 2) bid a direct load control program into the MISO energy market as price-sensitive
19 load, 3) bid interruptible load into the MISO market as price sensitive load, and 4) develop a
20 critical peak pricing option for Cg-2 and Cg-6 customers.
21 Q. How are you proposing to split the current TOD pricing options into additional price
22 periods?
23 A. We are proposing to add additional TOD pricing periods. MOE's current on-peak TOD period
24 is from 10:00 AM to 9:00 PM, Monday through Friday excluding holidays. All other periods
25 are considered off-peak.
Direct-MOE-James-23 We propose to split the current on-peak periods into the following time periods, with no
2 changes to the holiday exclusion:
3 On-Peak Period 1 10:00 a.m. - 1:00 p.m., Monday - Friday
4 On-Peak Period 2 1:00 p.m. - 6:00 p.m., Monday- Friday
5 On-Peak Period 3 6:00 p.m. - 9:00 p.m., Monday- Friday
6 Off-Peak Period All other time
7 Q. How did you determine the hourly breaks for the three on-peak periods?
8 A. Ex.-MGE-James-2, Schedule 8, shows the average hourly Day-Ahead LMPs at the MGE load
9 zone by month for 2006 through 2011. This information shows the LMPs for the days with
10 on-peak hours, for days with only off-peak hours and for all days of the month. To better
11 identify the higher priced hours, I have highlighted the hours where the LMP price is more
12 than 150% ofthe average monthly price and where the LMP is in the range of 125% to 150%
13 of the average LMP price for the month. The summer months indicate a high cost period in the
14 mid-afternoon to early evening hours of on-peak days while the winter months showed some
15 tendency to higher prices in the evening hours.
16 Q. How will rates be designed under the new TOD periods?
17 A. Since MGE is a summer peaking utility, I am proposing that the winter TOD rates remain the
18 same for all three on-peak periods. The focus of the additional TOD periods is to create a new
19 pricing tier for the summer on-peak period 2. Since this is a new rate structure, I propose that
20 the variation in the summer rates for on-peak period 2 be only slightly greater than the rate for
21 on-peak period 1 and 3 to minimize rate shock. In future rate cases, the difference in the
22 on-peak period 2 rates can be gradually increased to further encourage customers to be energy
23 efficient during MGE high cost summer hours.
24 Q. Why are you not proposing higher cost rates for on-peak period three in the
25 non-summer months?
Direct-MGE-James-24 A. The average hourly Day Ahead LMPs shown in Schedule 8 indicate that on-peak period 3 has
2 the highest costs during the non-summer months. However, to reflect that in the rate design
3 would be confusing to customers. The rate principles identified by James C. Bonbright
1 4 highlighted simplicity and understandability as beneficial attributes of utility rate structure •
5 Changing from a high price period in on-peak period 2 in the summer to a high priced period
6 in on-peak period 3 in the non-summer months would be sending a confusing price signal to
7 our customers. As stated earlier, MGE is a summer peaking utility. I believe that our rates
8 should focus on providing a simplified rate structure that customers can understand that will
9 have the biggest influence during our peak months by sending a proper price signal to our
10 customers.
11 Q. Have you looked into the prospect of bidding a residential direct load control program
12 into the MISO energy market?
13 A. Yes. In August 2011, we surveyed (Ex.-MGE-James-2, Schedule 9 page 1 of 2) a random
14 sample of our residential customers about their interest in a residential direct load control
15 program. The response to the survey is summarized on page 2 ofEx.-MGE-James-2,
16 Schedule 9. This statistically valid sample indicated that customers were somewhat interested
17 in participating in a voluntary direct load control program.
18 The results of the survey indicate that about 91% of the surveyed customers would
19 consider participating in a direct load control program if they received a credit of $1.00 per
20 hour or more. With Day Ahead LMPs being no more than $100 to $150/MWh, any credit over
21 fifteen cents per hour would exceed the energy savings that MGE would experience from a
22 direct load control program. This does not include the non-energy related costs, such as
23 marketing costs, switching equipment, notification system and billing modifications and other
24 costs that would be needed to implement such a program. A credit of a dollar per hour or more
1 James C. Bonbright, Principles of Public Utility Rates, Columbia University Press, New York, New York, 1961, p. 291. Direct-MGE-James-25 would prohibitively exceed any value derived from bidding values into the energy market. Of
2 the remaining nine percent of survey respondents, seven percent said they would consider
3 participating in a DLC program with essentially no credit. Since less than two percent of the
4 surveyed customers responded with credits that could be reasonably considered (between
5 $0.25 and $0.75 per hour), there appears to be insufficient customer interest to justify
6 initiating such a program.
7 Q. What monthly credit could MGE provide to customers that would make this program
8 revenue neutral?
9 A. With LMPs at the levels that they have been over the last three years, any DLC credit would
10 not be cost effective. The annualized cost for just the air conditioning switch and installation is
11 $28 per year. Any administrative, communication or billing costs that would be required for
12 implementing and maintaining the program or any gift incentive to get customers to sign up
13 for the program would be additional costs not included in the $28 calculation. Also no
14 monthly credit for participating on the DLC program is included in the $28 annualized cost.
15 Ifwe assumed that Day Ahead LMPs reached a price of$200/MWh, we would have to
16 have over 400 direct load control hours in a year just to recover the incremental cost of the
17 program over the base residential energy rates. Since 2007, we have not had even one hour
18 where the day ahead LMPs exceeded $200/MWh.
19 The intent of the demand response initiative for direct load control is to provide
20 customers with a monthly or kWh credit for participating in a program and for MOE to use the
21 program during high cost periods in the summer. When compared to historical LMPs, this
22 program would not have been utilized in any of the last five years. With current market price
23 projections we see little or no opportunity for it to provide any value in the near future.
Direct-MGE-James-26 In conclusion, given the overwhelming mismatch between potential costs and benefits,
2 MGE believes it is inappropriate for the PSCW to mandate further development of a new
3 residential DLC program at this time.
4 Q. Is MGE proposing to design a program to bid interruptible load into the MISO market?
5 A. Yes, MGE is proposing to close the current interruptible tariffs, ls-I and Is-2, to all new
6 customers as of January 1, 2013. We will require all current Is-1 and Is-2 customers to
7 become firm customers or to sign up for the new proposed Is-3 or Is-4 tariffs that will be
· 8 effective on the customer's first meter read date after April 30, 2013.
9 Q. What are the Is-3 and Is-4 tariffs?
10 A. The Is-3 tariff is similar to the ls-1 tariff except the Company will call a buy-through when the
11 average Day Ahead LMP applicable for the MGE load zone for at least two consecutive hours
12 exceeds 130% of the sum ofthe Cg-4 on-peak period 2 rate and the Cg-4 base energy rate in
13 effect. If a customer uses interruptible energy during a buy-through period, the customer will
14 be charged the MISO Day Ahead LMP price for each hour ofbuy-through plus 10% for
15 ancillary services. Additional language in the Is-3 tariff restricts MGE to an annual maximum
16 of 300 hours of interruptible and buy-through hours in a year, with interruptions capped at no
17 more than 150 hours.
18 The Is-4 tariff is similar to the ls-2 tariff and also includes the buy-through provision.
19 Q. Will you allow current interruptible customers to cancel their interruptible contract due
20 to the buy-through provision?
21 A. Yes. Between January 1, 2013 and April}{; 2013, all current interruptible customers will be
22 required to sign a new contract for either the Is-3 or Is-4 tariff. Any customer that does not
23 sign a contract for one of the new interruptible tariffs will become a firm customer as of their
24 first meter read rate date after April30, 2013. As o/J!~[1, 2013, all customers will be
Direct-MGE-James-27 I removed from the ls-I and ls-2 tariffs. MGE proposes to terminate the ls-I and ls-2 tariffs at
2 that time.
3 Q. Why is the buy-through threshold price set at 130% of the sum of the Cg-4 on-peak
4 energy 2 rate and the Cg-4 base energy rate?
5 A. We are proposing 130% ofthe sum of the Cg-4 on-peak energy 2 rate and the Cg-4 base
6 energy rate as the threshold to establish a definitive level as to when a buy-through can be
7 called. Cg-4 has the highest rates during on-peak period 2 of all of our demand level on-peak
8 energy rates. The proposed formula ensures that buy-through periods are documentable and
9 that the buy-through price will exceed the current rates for all customers. We also want the
IO price high enough so that under normal circumstances we will not exceed the allotted
II interruption and buy-through hours.
I2 Q. Based on 130 percent of the sum of the Cg-4 on-peak period 2 rate and the Cg-4 base
13 energy rate, how many buy-through hours would MGE have called over the last five
I4 years?
I5 A. As is shown in Ex.-MGE-James-2, Schedule I 0, MGE would have called I5 hours of
I6 buy-throughs in 2007 and there would have been 6I hours ofbuy-through in 2008. From 2009
I7 through 20 II, the interruptible customers would not have experienced any buy-through
I8 periods.
I9 Q. Are you proposing any other changes to the Is-3 and Is-4 tariffs that will be replacing the
20 Is-1 and ls-2 tariffs?
2I A. Yes. The current ls-I and ls-2 tariffs allow customers to opt for the variable or fixed pricing
22 option. Under the variable pricing option, customers may have the rate adjusted periodically
23 as the Public Service Commission approves changes to the schedule. Under the fixed pricing
24 option, the customer receives the same credit for the full three year contract term, regardless
25 of other changes that may from time to time be approved by the PSCW. No customers have
Direct-MGE-J ames-28 ever participated on the fixed pricing option of the interruptible tariffs. Due to the lack of
2 interest, I propose that the fixed pricing option be eliminated from the Is-3 and Is-4 tariffs.
3 Q. Is MGE proposing a critical peak pricing option for Cg-2 and Cg-6 customers?
4 A. Yes. MGE is proposing critical peak pricing rate schedules (Cg-2A and Cg-6A) as optional
5 alternatives to the current Cg-2 and Cg-6 rate schedules. Commercial and industrial customers
6 can opt for the new critical peak pricing option (Cg-2A and Cg-6A) if they are served as firm
7 load.
8 Q. Please explain the intent of the critical peak pricing rate.
9 A. Critical peak pricing is intended to provide an incentive for customers to reduce their usage
10 during higher cost pricing hours. These customers are not required to interrupt their load
11 during a critical peak period, but can realize a financial benefit by reducing their usage when
12 notified by the Company of a critical peak period. This rate would be most useful for
13 customers that can adjust their loads during some hours, but cannot always interrupt their load
14 when notified to do so by the Company.
15 Q. Why can't interruptible customers participate on the critical peak pricing rate?
16 A. If interruptible customers could also be on the critical peak pricing rate, they would be getting
17 a double benefit for interrupting load when notified to do so. They would get the interruptible
18 credit as well as receive the reduced on-peak summer rates.
19 Q. Please explain how the critical peak pricing rates are designed.
20 A. All of the rates for the proposed Cg-2A and Cg-6A rates are equal to the proposed Cg-2 and
21 Cg-6 rates except that the on-peak period 2 summer rates are set equal to the rates in place for
22 the on-peak periods 1 and 3 summer rates. In addition, there is a critical peak pricing rate that
23 is in effect when the Company notifies the customer of a critical peak period. As I explained
24 earlier, a critical peak period will occur when the Day Ahead LMP applicable for the MGE
25 load zone exceeds the sum of the Cg-4 on-peak period 2 rate and the Cg-4 base energy rate for
Direct-MGE-J ames-29 1 two consecutive hours. The rate that the customer will pay during a critical peak period is set
2 at $0.2810 per kWh for Cg-2A and Cg-6A.
3 Q. Please explain what is shown in Schedule 11, pages 1 through 3 of Ex.-MGE-James-2.
4 A. Schedule 11, page 1, shows what the buyouts would have been for a critical peak pricing
5 program during the years 2007 through 2011. Over the five years, these customers would have
6 experienced a total of 76 critical peak hours, an average of 15 per year.
7 Schedule 11, Pages 2 and 3, shows the procedure used to determine the rate for the
8 critical peak prices for Cg-2A and Cg-6A. The top portions of each of these two pages contain
9 the proposed rates for the standard time-of-use rates and for the critical peak pricing rates.
10 Below these rates are the assumptions used to determine the critical peak prices. Most of these
11 assumptions are based on information from the Cg-2 and Cg-6 rate design sheets in
12 Schedule 1. I have assumed that there will be on average 15 hours of critical peak pricing
13 based on the information in Schedule 11, page 1.
14 Some ofthe information on pages 2 and 3 is necessarily based on assumptions. For
15 example, we have no way of knowing what the load factor will be for customers at the time of
16 a critical peak period. The relative load as well as the hours when the critical peak occurs
17 affect the determination of the critical peak pricing rate.
18 Q. How did you determine the level for the critical peak rate?
19 A. Using pages 2 and 3 of Schedule 11, I attempted to make the Cg-2A and Cg-6A bills revenue
20 neutral to the level of the Cg-2 and Cg-6 bills, assuming a customer does not alter its usage
21 during the Company's 15 critical peak hours. Ifthe Company calls less than 15 critical peak
22 hours or if the customer reduces its energy usage during critical peak periods, the customer
23 can save money on this rate. In each of the last three years, customers would have
24 automatically saved money on the critical peak period rate, since we have not had any critical
25 peak periods over that time.
Direct-MGE-James-30 1 Q. You state that the critical peak price for Cg-2A and Cg-6a is $0.281/kWh, yet on the
2 proposed tariff sheets the critical peak pricing rates are rate is $0.2242/kWh for Cg-2A
3 and $0.2260/kWh for Cg-6A. Please explain the discrepancy.
4 A. In the Cg-2A and Cg-6A tariffs, the critical peak pricing rate adders are exclusive of the base
5 energy rates. The total critical peak pricing rate is the sum of the critical peak pricing adder
6 and the base energy rate.
7 Q. You are proposing to minimize the difference between the on-peak period 2 rate and the
8 other on-peak period rates initially and then possibly expand this difference in future
9 rate cases. How will expanding this differential affect the critical peak period rate?
10 A. Increasing the differential with the on-peak period 2 rate in future cases will cause the critical
11 peak period rate to increase in order to maintain the current break-even level with the standard
12 Cg-2 and Cg-6 rates. If it is determined that the critical peak period rate is too high, the
13 Company may have to allow the summer on-peak period 2 rate to exceed the level of the
14 summer on-peak periods 1 and 3 rate level.
15 Q. What conditions are you proposing for customers for opting on or requesting to get off
16 of a critical peak pricing rate?
17 A. A customer that signs up for the critical pricing period rate will be required to be on the rate
18 for at least one year. Six months prior notice will be required for a customer to withdraw from
19 the critical peak pricing rate program. Once customers withdraw from the program, they will
20 not be allowed to sign up again for the rate for one year.
21 Q. Please describe Schedule 13 of Ex.-MGE-James-2?
22 A. This Schedule contains the Company's proposed fuel cost plan for monitoring fuel costs for
23 the January through December 2013 test year.
24 Q. Does this conclude your direct testimony?
25 A. Yes.
Direct-MGE-James-31 PSC REF#:166583
"'g. 1 BEFORE THE 1-' ::0 1-'· t'i!O 2 PUBLIC SERVICE COMMISSION OF WISCONSIN () t'i!Ul H (1) <: '1 1.>:1 < tJ 1-'· 3 Application of Madison Gas and Electric .. 0 (ll 4 Company for Authority to Change Electric Docket 3270-UR-118 0 0)() 5 and Natural Gas Rates -...o :;:~
------~~·tvro ' 1-'· 0 6 DIRECT TESTIMONY OF TAMARA J. JOHNSON \O:;l tvO 7 ON BEHALF OF APPLICANT U'1HI w~ 1-' 1-'• l1l ~g 1::1 ttl 8 Q. Please state your name and title. 1-'· ::J 9 A. My name is Tamara J. Johnson. I am the Senior Director- Financial Reporting and Budgets
10 for Madison Gas and Electric Company (MGE) and my business address is 133 South Blair
11 Street, Madison, Wisconsin.
12 Q. What is your educational background and work experience?
13 A. I graduated from the University of Wisconsin-Madison in 1986 with a bachelor ofbusiness
14 administration degree in accounting and information systems. Since June 1993, I have been
15 employed by MGE as an Internal Auditor, EDP Auditor, Director- Budgets and currently
16 Senior Director - Financial Reporting and Budgets. I have been in this position since July
17 2004. Prior to my employment with MGE, I was a Manager at Morton, Nehls and Tierney,
18 S.C., a public accounting firm located in Madison, Wisconsin. I am a Wisconsin certified
19 public accountant and a member ofthe Wisconsin Institute of Certified Public Accountants.
20 Q. What is the purpose of your testimony in this proceeding?
21 A. The purpose of my testimony is to present the electric and gas income statements including
22 the operation and maintenance expense estimates for the test year (the 12 months ended
23 December 31, 2013), and the electric and gas average net investment ratebase for the test year.
24 I will also explain the major factors contributing to the Company's proposed rate increases and
25 the steps taken to hold down those increases.
Direct-MGE-Johnson-1 1 Q. Was Ex.-MGE-Johnson-1 prepared by you or under your supervision?
2 A. Yes.
3 Q. Please describe what is presented in Ex.-MGE-Johnson-1, Schedules 1 and 2.
4 A. Both schedules contain the test year estimates and, for comparative purposes, the final figures
5 approved in Docket 3270-UR-117 (as adjusted by the limited re-opener Order dated
6 December 15, 2011, issued in the same docket (PSC REF# 157I13)) for operating revenues,
7 operation and maintenance (O&M) expenses, and other expenses to determine net operating
8 income. Schedule 1 relates to the electric utility and Schedule 2 relates to the gas utility.
9 Q. Please explain the information on these schedules.
IO A. For the electric utility, line 20 on Ex.-MGE-Johnson-I, Schedule I, in the UR-II8 column
II shows the amount of $26, I 08,000, which is the estimated net operating income for the test
I2 year under present rates. This amount is used to show MOE's projected rate of return on
13 rate base for the test year ending December 3I, 2013 without a rate increase. This projected
I4 rate of return is then used in Ex.-MGE-Frassetto-I, Schedule 3, line 3, presented by Company
I5 witness Kenneth G. Frassetto, to develop the revenue requirement for electric rates. Similarly,
I6 for the gas utility, line 18 on Ex.-MGE-Johnson-I, Schedule 2, in the UR-II8 column shows
I7 the amount of$9,057,000, which is the estimated net operating income for the test year under
I8 present rates. As with the electric utility, this amount is used to show MOE's estimated rate of
I9 return on rate base for the test year ending December 31, 2013. This projected rate of return is
20 then used in Ex.-MGE-Frassetto-I, Schedule 3, line I2, to develop the revenue requirement
2I for gas rates.
22 Q. Please describe the methodology used in developing the operation and maintenance
23 expense estimates shown on Schedule 1, lines 5 through 12, and Schedule 2, lines 4
24 through 10, ofEx.-MGE-Johnson-1.
Direct-MGE-Johnson-2 1 A. The Company has approximately 80 responsibility centers (RC). Each RC budgets for
2 expenditures based on various work activities it expects to perform. The RCs make estimates
3 of both labor and non-labor expenses. The labor and non-labor cost estimates are combined to
4 form the individual RC budgets. The Budget Department, with the aid of other Company
5 personnel where necessary, also budgets for items that are not covered by the budgets
6 prepared by individual RCs. Total expense estimates are accumulated and translated into
7 FERC accounts. These account estimates are compiled into an income statement that is
8 reviewed by the Budget Department.
9 Q. Please explain the data contained on Ex.-MGE-Johnson-1, Schedule 3.
10 A. Schedule 3 provides the basic data required for developing the average net investment
11 ratebase for the electric utility during the test year. Columns 1, 2, 4, 5, and 6 show the
12 component parts of the ratebase, resulting in the net amounts shown in Column 7. Column 8
13 shows the amounts of construction work in progress estimated for each month. All the
14 foregoing amounts are then totaled on line 14, and an average is developed on line 15 for each
15 column by dividing the total by 13. The average net investment ratebase for electric operations
16 for the test year is $414,813,000 as shown on line 15, Column 7. Also developed on this
17 Schedule is the percentage of construction work in progress (CWIP) to net investment
18 ratebase. The percentage for the test year is 29.36% as shown on line 18 of Column 8.
19 Q. Are there any large projects included in the 2013 construction work in progress balance
20 for the electric utility?
21 A. Yes. Approximately $99 million (13-month average) is included for the Columbia
22 environmental project approved in Docket 5-CE-138. Utilities would usually propose 100%
23 current return on CWIP for large construction projects. However, in an effort to lower the rate
24 impact, MOE is proposing that the cost of this construction project be treated similarly to
Direct-MGE-Johnson-3 1 other smaller utility construction projects, with 50% categorized as current return on CWIP
2 and 50% categorized as allowance for funds used during construction (AFUDC).
3 Q. Will you now turn to Ex.-MGE-Johnson-1, Schedule 4, and explain the information
4 contained on that page.
5 A. Schedule 4 pertains to the gas utility. It is set up in the same manner as Schedule 3 and has
6 been computed in the same way. It should be noted that the average gas net investment
7 ratebase for the test year is $136,452,000 and the percentage of construction work in progress
8 to average net investment ratebase is 5.47%.
9 Q. Please describe the factors contributing to the increase in electric rates.
10 A. Some ofthe contributing factors are:
11 1. Generation Costs. MGE is committed to providing a dependable, affordable and
12 environmentally responsible supply of energy to its customers. To that end, MGE is
13 involved in two major generation projects that are affecting 2013 rates.
14 a. Columbia. The two baseload units at Columbia require upgrades to comply with
15 current federal environmental standards. MGE will be investing $140 million in a
16 scrubber project that will provide our customers with cleaner energy.
17 b. Elm Road Generating Station (ERGS). ERGS Unit 1 became operational in February
18 2010 and ERGS Unit 2 became operational in January 2011. The ERGS project was
19 the largest single construction project ever undertaken in the State of Wisconsin. The
20 100 MW of energy that the ERGS units produce on behalf of MGE will assure our
21 customers of an adequate supply of energy while allowing MGE and its customers to
22 be better stewards of the environment. In previous rate cases, an estimated start date
23 for the lease payments was assumed for each ofthe units. The actual start dates for
24 ERGS Unit 1 and ERGS Unit 2 ended up later than the estimates and the excess lease
25 payments collected resulted in a one-time benefit and were returned to customers in
Direct-MGE-Johnson-4r the 2012 limited reopener. Also, for 2013 the Company has included increased O&M
2 expense as well as an increase in lease payments associated with the final construction
3 costs ofthe project.
4 2. Transmission-related costs. As noted earlier, the charges the Company will be assessed for
5 reliability purposes by A TC have also increased.
6 3. Fuel and Purchased Power. There is an increase in capacity costs related to power
7 purchase agreements.
8 Q. Please describe the primary factor contributing to the increase in gas rates.
9 A. The increase in natural gas rates is primarily due to increased ratebase associated with
10 infrastructure improvements which will enhance reliability of the gas distribution system.
11 Q. Please describe the cost control measures MGE has implemented to minimize the
12 necessary increases in electric and gas rates.
13 A. MGE took a number of steps to control costs and keep the requested increase as low as
14 possible. These include:
15 1. MGE made additional non-required cash contributions to its pension fund in order to
16 reduce pension expense for the 2013 test year.
17 2. MGE required all of its responsibility centers to scrutinize their budgets to ensure they
18 were at their lowest possible level while still providing safe and reliable energy to
19 customers and complying with all governmental requirements.
20 3. The Company has required increased employees' contributions to their medical insurance
21 premiums.
22 4. The Company revised its income tax methods of accounting for repairs based on the
23 Treasury regulations and case law. This aggressive tax change allows MGE to benefit
24 from tax savings (with a corresponding increase in deferred taxes). This change continues
25 to benefit customers both by creating cash flow and reducing ratebase.
Direct-MGE-J ohnson-5 1 5. The Company's CEO continues to review each open position with the goal of filling only
2 critical positions (those necessary for safety, reliability or compliance).
3 6. The Company accelerated the steps necessary to retire 90 MW at the Blount Generating
4 Station and to lower labor expenses associated with operating the plant.
5 Q. Ms. Johnson, are you aware of any items that will need to be updated during the rate
6 case proceeding?
7 A. Yes. The following items may need to be updated when additional information is available:
8 1. Electric fuel and purchased power costs. These will be updated before the Commission
9 makes its decision to reflect projected gas costs based on the most recent 12-month
10 NYMEX strip and the energy futures for 2013.
11 2. Pension and benefit costs. These will be updated, if necessary, during the audit or before
12 the hearings to reflect current market conditions.
13 3. Costs associated with ERGS, if applicable.
14 4. ATC network service fee (update estimate provided by A TC on October 1 of each year)
15 and MISO Schedule 26.
16 Q. Is the proposed amount to be included in rates for MGE's costs in this proceeding less
17 than four times the total amount assessed to the Company under Sections 196.85(1) and
18 (2) of the Wisconsin Statutes?
19 A. Yes.
20 Q. Does that conclude your direct testimony?
21 A. Yes.
Direct-MGE-Johnson-6 PSC REF#:166586
"'g. 1 BEFORE THE 1-' :>:1 1-'· l:xJO 2 PUBLIC SERVICE COMMISSION OF WISCONSIN (l l:xJtll H (!) <:: t1 l:xJ < Application ofMadison Gas and Electric t! 1-'· 3 .. 0 t1l 4 Company for Authority to Change Electric Docket 3270-UR-118 0 0'1(1 5 and Natural Gas Rates '-0 ~§ '- 1-'· I-' I'll "->I'll ' 1-'· 0 6 DIRECT TESTIMONY OF TIMM A. MINOR IJ>:;:! "->0 7 ON BEHALF OF APPLICANT OOH! ~::: 0 1-'· to ~g :;:! to 8 Q. Please state your name, business address, and current position. 1-'• :;:! 9 A. My name is Timm A. Minor. I am a Senior Gas Rate Analyst III at Madison Gas and Electric
10 Company (MOE), 133 South Blair Street, Madison, Wisconsin 53701.
11 Q. Please summarize your educational background and work experience.
12 A. I graduated from the University of Wisconsin-Madison in 1983 with a Bachelor of Science
13 Degree in Agricultural Economics.
14 I was employed by the Public Service Commission of Wisconsin (PSCW) from
15 December 1989 through October 1997 as a gas rate analyst, where my responsibilities
16 included purchased gas adjustment and gas purchase plan review, processing formal and
17 informal complaint investigations, cost-of-service analysis, rate design, testifying in numerous
18 rate cases and generic proceedings, and other PSCW rate and rule actions. I was involved in
19 the development of state-wide policy in areas such as transportation rate design and service
20 aspects, fixed gas cost allocation, balancing service design, and unauthorized use penalty
21 language. In October 1997, I assumed my current responsibilities at MOE, where my duties
22 include gas cost allocation, gas rate and service design, purchased gas adjustment analysis, gas
23 cost optimization modeling and intervention in regulatory proceedings.
Direct-MGE-Minor-1 1 Q. What is the purpose of your testimony in this proceeding?
2 A. The purpose of my testimony is two-fold. I will first present for Commission consideration a
3 fully embedded cost-of-service study based on projected 2013 test-year cost data. Secondly, I
4 will present a natural gas rate design proposal that is supported by my cost-of-service analysis.
5 Q. What exhibits are you sponsoring in this proceeding?
6 A. I am sponsoring Ex.-MGE-Minor-1 and Ex.-MGE-Minor-2.
7 Ex.-MGE-Minor-1 consists of five schedules:
8 Schedule 1: Margin Revenue Requirement Summary.
9 Schedule 2: Margin Expense Summary.
10 Schedule 3: Rate Base Summary.
11 Schedule 4: Summary of Allocation Factors.
12 Schedule 5: Customer Charge Summary.
13 Ex.-MGE-Minor-2 supports the natural gas rate design, and I will discuss it in more detail
14 later in my testimony.
15 Q. Please describe Schedule 1 ofEx.-MGE-Minor-1.
16 A. Schedule 1 shows the margin revenue requirement results ofthe cost of service study
17 performed using test-year information. The study is performed absent any gas costs or gas
18 revenues. Gas costs are allocated separately and addressed in the rate design portion of my
19 testimony. In general, a cost of service study serves as a means of approximating the
20 occurrence of actual costs that the Company experiences for each class of service. An
21 embedded cost study reviews the historical or projected future costs of providing utility
22 service which are forecast for a specific test-year. In this case, the costs are those anticipated
23 for the test- year beginning January 1, 2013.
24 One ofthe characteristics of utility service is that many ofthe costs are fixed in the
25 medium and long term. In addition, much of the plant that is utilized is used in common by a
Direct-MGE-Minor-2 number of service classes. With the high ratio of common or joint costs to direct costs
2 associated with the various services provided by a utility, it can be difficult to ascertain how
3 much a given service costs relative to other services that are provided. Costs can be classified
4 and allocated among services using various basic cost characteristics and principles that exist
5 in utility service. An embedded cost of service study accomplishes this through three steps
6 identified as Functionalization, Classification and Allocation of costs. Because plant (rate
7 base) and expense accounts separately go through the steps above, there are really two studies
8 within each cost of service study. The steps resulting in an allocation of rate base account
9 levels to the rate and service cost classes provide a means of allocating Depreciation Expenses
10 and Return on Rate Base among the classes. As will be illustrated in the Allocation step
11 description below, allocation of net plant accounts among classes can also provide a method
12 for allocating related operation and expense accounts.
13 Q. Please describe the Functionalization step of the cost of service study.
14 A. The starting point for gas utility embedded cost of service studies is the segregation of fixed
15 capital components (plant accounts) and operation and maintenance expenses by broad
16 functional groupings and sub-groupings. The functional groupings used in the state and
17 federal Uniform System of Accounts for Private Natural Gas Utilities categorize plant and
18 expense accounts into Production, Storage, Transmission and Distribution functions.
19 The Production Function for local distribution utilities (LDCs) typically includes the cost
20 of natural gas purchases, the largest operating expense item of a utility. For MGE, this
21 represents $100,941,000 during the projected test year, or approximately 63 percent ofthe
22 estimated operating expenses. Since this one expense account has numerous elements that
23 require separate cost of service treatment, the allocation of gas costs is done separately from
24 the margin cost of service study. Gas costs were, however, included in the Allocation Factors
25 called TOTAL-CUR-REV, which are used to allocate Gross Receipts taxes among the rate
Direct-MGE-Minor-3 1 classes. The expenses and revenues in the margin cost-of-service study discussed in my
2 testimony reflect the separation of the cost of gas from the margin costs. Since revenues and
3 costs are similarly adjusted in the study, the net income matches that found in the income
4 statement filed in the testimony of Company witness, Tamara Johnson, in Ex.-MGE-
5 Johnson-1.
6 The Storage Function is used by LDCs that own liquefied natural gas facilities or
7 underground storage facilities. MGE does not own any Storage plant in either of these
8 categories, so there is no rate base or expense recorded in this Functional group in the cost of
9 service study. The capital cost associated with natural gas supplies in storage facilities owned
10 by other entities (such as an upstream pipeline) is included in the Production Function.
11 The Transmission Function includes the return on plant and related expenses associated
12 with the transmission of gas from an area that serves as a wholesale source of gas to one or
13 more distribution areas. Most LDCs have relatively little plant or expenses that are classified
14 as Transmission. MGE currently does not account for any plant or expenses in the
15 Transmission Function.
16 The Distribution Function includes the plant and associated expenses incurred primarily
17 for distributing natural gas within a distribution area. This function includes most of the
18 operating plant of an LDC and is the second greatest operating expense after the cost of
19 purchased natural gas. For MGE, this includes the return and related expenses of distribution
20 mains, customer services, valves, regulators and measuring devices (meters) used in
21 distributing gas from MGE's receipt points (gate stations or town border stations ofthe
22 interstate pipeline companies delivering gas to MGE) to its retail customers.
23 Other expense groups are also included in the Distribution Function. Customer Service,
24 Customer Accounts and Administrative and General Costs can be functionalized among the
25 various cost groups according to the grouping of other costs or can be included in the
Direct-MGE-Minor-4 1 Distribution Function, since this is by far the highest margin cost function. In this cost of
2 service study, Administrative and General Costs were grouped into the three active Functions
3 according to the cost activity of the directly functionalized operating and maintenance expense
4 accounts. Customer Service and Customer Accounts expenses were functionalized entirely to
5 the Distribution Function to facilitate the Classification and Allocation steps of the study. The
6 functionalization ofmargin expenses is summarized in Schedule 2 ofEx.-MGE-Minor-1 and
7 the functionalization ofrate base is summarized in Schedule 3 ofEx.-MGE-Minor-1.
8 Q. Please describe the Classification step of the cost of service study.
9 A. Classification is the intermediate step between Functionalization and Allocation. There are a
10 few major classifications of embedded utility costs. These cost components aid in the
11 assignment of costs in the Allocation step of the study. The following are the major cost
12 classifications:
13 1. Customer Costs,
14 2. Capacity Costs, which include peak demand costs,
15 3. Commodity (or throughput-related) Costs.
16 Each functional cost is placed into these broad cost classification categories depending
17 on whether a particular cost varies with the number of customers, the volume of throughput,
18 the customer class coincident peak-demand (service class usage during the Company's peak
19 demand day or month) or non-coincident peak-demand (maximum service class usage during
20 the whole winter season- regardless of when the utility peak occurs). An analysis of the uses
21 of plant and expenses can be made to arrive at a reasonable cost allocation in the Allocation
22 step of the study.
23 Q. What are Customer Costs?
24 A. Customer costs are the costs directly related to serving a customer, regardless of sales volume,
25 such as meter reading, billing, and fixed charges for the minimum investment required to
Direct-MGE-Minor-5 1 serve a customer. For example, there is a customer component to service lateral costs because
2 each customer requires a service lateral in order to receive natural gas. Customer costs also
3 include a portion of items such as meters, regulators, distribution mains and the operating
4 expenses associated with customer billing, customer service and other costs that are a function
5 of the relative size of the customer group. These costs do not include costs related to a
6 customer's use or demand of gas, but are a cost caused by the mere existence of a customer.
7 Q. What are Capacity Costs?
8 A. Capacity costs are related to maximum system demand during a short period of time. These
9 costs are determined by the size of plant, especially distribution facilities, required to provide
10 the maximum demand of a customer class and of the system as a whole and are often also
11 called system demand costs. In the example of a service line, the size of the line depends on
12 the customer's maximum rate of usage, so a portion ofthe cost ofthat line should be classified
13 to the demand (capacity) component.
14 Q. What are Commodity Costs?
15 A. Commodity costs are those costs that are allocated on the basis of actual use of service. Such
16 costs have been traditionally defined in terms of quantities of gas sold, and include those items
17 which vary in direct proportion to the volume of gas purchased by an LDC. The largest
18 portion of commodity cost related to volumes of gas sold is the weighted average commodity
19 cost of purchased gas. Few non-gas (margin) costs vary in direct proportion to the volume of
20 gas purchased or distributed by an LDC. In my cost of service study, the biggest margin cost
21 classified to the commodity component is the return on Gas Stored Underground (Account
22 117). This is considered a sales related commodity cost and is consequently allocated to the
23 Margin Cost tied to All-Sales category. Because MGE distributes not only gas that it
24 purchases for gas sales supply service customers, but also distributes third party supplies for
25 customers that do not choose its gas sales service, it is appropriate to define system
Direct-MGE-Minor-6 commodity costs associated with distribution in terms of throughput, or volumes distributed
2 through the distribution system. The only expense which has a direct throughput-related
3 commodity classification is Distribution Load Dispatching, of which only half ofthe account
4 is classified on this basis; the other half is classified as Demand. This is one of many accounts
5 that are classified among two or three cost categories.
6 Q. Why are some plant and expense accounts classified to more than one cost component?
7 A. Some items of expense may not fall entirely into any one ofthe major cost components.
8 Others may be of such joint or common use that they are allocated on the basis of a group of
9 costs in the same functional area. An example of a plant account that is classified to more than
10 one major cost component is account 3 76, Distribution Mains. This major plant item is
11 divided between the customer and capacity (demand) cost components. A minimum amount
12 of distribution mains must be installed just to connect to the customer's service laterals (this is
13 the Customer component). As an LDC adds more customers in its service territory, it must
14 install additional footage of distribution mains. Therefore, the level of account 3 76 will vary
15 with the number of customers that are served. Distribution mains, however, are sized to meet
16 the highest anticipated demand of customers in a given location and the local distribution
17 system as a whole. With peak usage of natural gas mains exceeding their average use in areas
18 with a high percentage of space heating load, such as in MOE's service territory, there is an
19 argument for allocating much of this plant account on a peak demand basis.
20 In order to determine what level of the distribution mains asset should be classified to
21 the customer component to provide the minimum amount of service, a zero-intercept study is
22 performed to determine the amount of this account which varies on the basis of customers.
23 Q. Do you have any specific comments relating to the zero-intercept study?
24 A. Yes, in a recent full rate case filing, the Company worked jointly with Staffto develop a zero
25 intercept study using a simple average of both a least squares and robust regression analysis
Direct-MGE-Minor-7 1 resulting in a customer demand allocation ratio which the Commission subsequently found to
2 be reasonable. Given that the data used in the analysis does not change materially from year to
3 year, I am proposing to use the same zero-intercept results the Commission found to be a
4 reasonable proxy for mains allocation in this instant filing. Specifically, I am proposing to
5 classify 40 percent of account 3 7 6 on a customer basis and the remaining 60 percent on a
6 capacity (demand) basis. Service lines (account 380) were similarly classified, with 47 percent
7 classified to the customer component and the remainder classified to the capacity (demand)
8 Component.
9 Some accounts are classified (and subsequently allocated also) on the basis of other
10 accounts. For example, General Plant accounts 389 through 397 are classified on the basis of
11 all other plant accounts within the respective functional areas. Many of the operation and
12 maintenance expense accounts are allocated on the basis of the corresponding plant account
13 allocation. For example, expense account 887, Maintenance of Mains, is classified based on
14 the classification of Distribution Mains plant account (376).
15 Q. Please describe the Allocation step of the cost of service study.
16 A. Rate base (with its associated level of return) and expense account levels in each cost
17 component are allocated among the various rate classes (and in this case, cost classes) based
18 on allocation factors that relate each class cost responsibility to the cost classification for each
19 account. For example, an expense account that has been classified to the Customer component
20 may be allocated to each rate class based on the ratio of customers in that class to the total
21 number of natural gas customers served by the LDC. Costs associated with normal cycle
22 meter reading and billing are allocated on this basis. Residential customers account for 89
23 percent ofthe number ofMGE's customers so the Residential Distribution Service class is
24 allocated 89 percent of these costs.
Direct-MGE-Minor-8 1 Costs classified on a demand (capacity) basis may be allocated to rate classes on the
2 basis ofusage by class on a peak day or month. The portion of Distribution Mains (account
3 376) that was classified to the demand component was allocated based on the relative usage of
4 the firm distribution classes during a peak month. Since Residential Distribution Service
5 throughput represents 45 percent of the peak month's usage in this study, this class is allocated
6 45 percent of the costs allocated on a peak demand basis. Some rate base or expense accounts
7 that are classified on a demand basis are allocated based on the peak month's usage of each
8 class during the winter season as a whole, rather than on the peak month. In this study, this
9 allocator is called the non-coincident peak allocator. This can be used to allocate costs that
10 have a demand aspect that does not necessarily affect total system peak design. The portion of
11 service lateral rate base and related expense accounts that are classified as demand-related are
12 allocated on this basis.
13 Rate base and expense accounts that are classified on a commodity basis can be
14 allocated to the rate classes based on the volume of throughput that is estimated for each class.
15 Continuing with the Residential Distribution Service example, this class represents 35 percent
16 ofthe forecasted throughput in this case. Therefore, 35 percent of the costs allocated on a
17 throughput basis go to this class. The major allocators that were used in this study are included
18 in Schedule 4 ofEx.-MGE-Minor-1.
19 Q. What Allocation Classes were used in this cost of service study?
20 A. There were two types of classes used for the final allocation of rate base and expenses:
21 (1) Distribution Rate Classes and (2) Cost Classes related to the Gas Service Options. The
22 Distribution Rate Classes in the study match the rate classes discussed in the rate design
23 portion of my testimony. These include the Residential Distribution class (RD-1); the three
24 Firm Commercial and Industrial classes (GSD- 1 through 3); the Interruptible Generation
25 Distribution class (IGD-1); the West Campus Co-Generation Facility (WCCF-1); the Seasonal
Direct-MGE-Minor-9 1 Off-Peak Distribution class (SD-1) and the Compressed Natural Gas class (CNG-1). Costs
2 were allocated to these rate classes based on the classification and allocation assumptions
3 noted above for costs functionalized to the Distribution Function. Other cost classes were
4 added to the study to allocate margin costs associated with all Sales Service Options (FS-1,
5 IS-I and IS-2), additional margin costs that apply to firm sales (FS-1 ), margin costs associated
6 with Daily Balancing Service (DBS-1) and margin costs associated with telemetering. These
7 cost classes can be found along with the rate classes on page 2 of 2 of Schedule 1 of Ex.
8 MGE-Minor-1 along with the third and fourth pages of Schedules 2 and 3 ofEx.-MGE
9 Minor-1, the Margin Revenue Requirement, Margin Expense and Rate Base Summaries,
10 respectively.
11 Q. How are the margin costs associated with Sales Services identified and allocated in the
12 cost of service study?
13 A. Consistent with the Company's previously approved methodology, two rate base accounts in
14 the Production Function were directly identified and removed from the traditional distribution
15 margin to a cost class labeled Margin Costs Tied to All Sales (referring to the unbundled FS-1,
16 IS-I and IS-2 Gas Supply Services). The first ofthese is account 117- Gas Stored
17 Underground, which I described earlier in my testimony as an account classified to the
18 Commodity Component. This account was allocated specifically to the All Sales cost
19 category, using an Allocation Factor labeled SALES-COM. The return on this rate base
20 account is thus allocated only to customers using MGE's gas supply services. In addition, a
21 representative amount of Production-related Depreciation Expense was allocated into the All
22 Sales cost category, as is a representative level of Production Function operation and
23 maintenance expenses.
24 Another expense that is categorized in the Production Function, which was directly
25 allocated to the All Sales cost class, is Gas Purchasing Expense. This account primarily
Direct-MGE-Minor-1 Or consists of MOE's administrative cost ofthe gas supply area. With this allocation, only
2 customers using MOE's gas supply options will pay costs associated with this function. As
3 with the rate base allocation described above, this expense allocation increases the allocation
4 weighting towards the All Sales cost class of other Production expenses (including some
5 Administrative and General expenses) that use indirect allocators.
6 Q. How were Daily Balancing Service administrative costs allocated?
7 A. This service does not have any of its own functional accounts to which costs are directly
8 allocated. Instead, a portion of Customer Accounts expense was allocated to the Daily
9 Balancing Service Margin Costs class based on labor costs related to the administration of this
10 service according to recent experience. In addition, several other related administrative and
11 general expenses and a portion of plant related administrative and general were allocated to
12 the Daily Balancing Service Margin Cost.
13 Q. How were Telemetering costs allocated?
14 A. To break out the cost oftelemetering from the distribution margin, the rate base associated
15 with this expense had to be broken out of Account 397 (Communication Equipment) based on
16 the unit cost of installing telemetering equipment at customer locations. The associated rate
17 base was then allocated to the distribution classes using a customer allocation factor. The
18 operation and maintenance expenses related to telemetering were also identified and directly
19 allocated to the telemetering cost category. Overhead costs were picked up in the same
20 manner as with other classes resulting in a fully embedded cost allocation for this cost class.
21 Q. In addition to the cost class allocations described above, were other special allocators
22 used in the cost of service study?
23 A. Four direct cost assignments were used in the study: Collections Expense, Uncollectible
24 Expenses, Expenses related to Conservation Programs, and Automated Meter Reading (AMR)
25 related costs. Direct cost assignment is used when cost information by rate class or small
Direct-MGE-Minor-11 1 groups of classes is available for a plant or operation and maintenance expenses account for a
2 portion of an account or accounts. When class-specific cost information is available, the
3 allocation process is redundant and can be overridden so that costs can be assigned directly to
4 the appropriate classes.
5 Account 904, Uncollectible Accounts Expense is accounted for by rate class at MGE and
6 can therefore be assigned directly to each class according to its cost responsibility. In addition,
7 the portion of Customer Records and Collections Expense (account 903) related to collections
8 cost activity is also accounted for by rate class. This portion of the expense account is also
9 assigned directly to distribution rate classes according to their known cost responsibility.
10 Conservation Program expenses are accounted for as part of four Customer Services
11 expense accounts. As such, the portions of accounts 907 through 910 associated with
12 conservation program expenses are also directly assigned to distribution rate classes by sector
13 according to their known cost responsibility.
14 Q. Please explain Schedule S.ofEx.-MGE-Minor-1.
15 A. Schedule 5 ofEx.-MGE-Minor-1 is an independent cost study that utilizes the results of my
16 cost-of-service study for the purpose of illustrating the various fixed customer costs the
17 company realizes for each customer class. The study isolates all costs that are directly related
18 to serving a customer, regardless of sales volume, and allocates the costs based on customer
19 counts by service class. A daily customer charge is subsequently derived to recover a portion
20 of these fixed costs. It is generally recognized that an appropriately designed customer charge
21 will not only help to alleviate any intra-class subsidies that exist between space heating and
22 general use customers, but also more closely reflects the way a natural gas utility actually
23 incurs its service investment costs. I discuss my proposed changes to the daily customer
24 charge levels later in my testimony.
Direct-MGE-Minor-12 Q. What exhibits are you sponsoring in support of the rate design segment of your filing in
2 this proceeding?
3 A. I am sponsoring Ex.-MGE-Minor-2 which consists of six schedules as follows:
4 Schedule 1: Revenue Summary
5 Schedule 2: Rate Summary
6 Schedule 3: Ability to Pay Summary
7 Schedule 4: Bill Impact Summary
8 Schedule 5: Allocation of Act 141 Costs
9 Schedule 6: Revisions to gas tariff Sheet G-47.0
10 Q. Please explain Ex.-MGE-Minor-2, Schedules 1 through 6.
11 A. Schedule 1 is the Revenue Summary consisting of two pages and serves as a tie from my cost
12 of-service to my rate design. Page one of Schedule 1 illustrates current margin and
13 administrative charge revenues compared with the proposed revenues rebundled with gas
14 costs for the various distribution classes. Page two of Schedule 1 shows the COSS results
15 (Target Margin Allocation) for comparison with revenues at proposed rates. It also illustrates
16 the changes in revenue from Administrative Charges separately from the distribution classes
17 and shows the impact of proposed rates on the services. Factors such as customer impacts,
18 margin cross-over points between commercial classes, price signals, service unbundling goals
19 and. alternate fuel prices were all considered in the rate design.
20 Q. What changes are you proposing for the residential class?
21 A. As can be seen from the Target Margin Allocation column in Schedule I, the cost-of-service
22 results indicate that the residential rate class is under-recovering test-year-forecasted revenues
23 by approximately $6.9 million. Consequently, I am proposing per therm and customer charge
24 increases to move revenue recovery closer to cost of service for the class.
Direct-MGE-Minor-13 1 Q. Have you proposed any changes to the residential daily customer charge?
2 A. Yes, as I stated earlier in my testimony, Schedule 5 ofEx.-MGE-Minor-1 is an independent
3 cost study that utilizes the results of my cost-of-service study for the purpose of illustrating the
4 various fixed costs the company realizes for each customer class. The study isolates all costs
5 that are directly related to serving a customer, regardless of sales volume, and allocates the
6 costs based on customer counts by service class. The results of this study indicate that the
7 residential customer charge could be set as high as $0.85 per day or $25.95 per month. Given
8 that one ofthe primary rate design objectives is rate stability, I am proposing to increase the
9 residential customer charge in the direction ofCOSS by $0.063 per day from $0.3370 per day
10 to $0.4000 per day, which demonstrates a reasonable adjustment towards the cost of service
11 results. Company witness Gregory Bollom has offered testimony which addresses adjustments
12 to various customer charge levels from a Company-wide policy perspective as they relate to
13 the allocation of fixed and variable distribution costs.
14 Q. How do you propose to recover the remainder of the revenue from the residential class?
15 A. As noted above, there is cost justification to recover the entire suggested increase on a fixed
16 cost basis through the customer charge. However, in this case we are only proposing an
17 incremental increase towards cost of service to mitigate intra-class rate impacts. Because of
18 that, I am proposing to recover the remainder of the proposed revenue by increasing the
19 residential volumetric margin by $0.0087 per therm, from $0.2919 to $0.3006.
20 Q. How were the Commercial and Industrial Distribution (C&I) class rates designed?
21 A. The cost-of-service study results were, again, used as a general guide in designing rates for
22 these distribution classes. The study shows that both the GSD-1 and GSD-3 classes are under
23 recovering while the GSD-2 customer class is currently over-recovering. However, in order to
24 minimize the rate impact to the residential customer class, I have proposed a nominal increase
25 to the daily customer charges for all three C&I classes. Specifically, I am proposing to
Direct-MGE-Minor-14 1 increase the daily customer class charges by 5 percent for all three classes. In addition, I have
2 increased the distribution margin charges slightly in both the GSD-1 and GSD-2 classes to
3 maintain the approximate rate relationships while preserving the current cross-over-points
4 between the respective rate classes. This proposal generates approximately $355,553 toward
5 the revenue deficiency and helps to avoid excessive rate increases for other classes.
6 Q. How were Interruptible Generation Distribution Service (IGD-1) rates designed?
7 A. While this class remains interruptible for peak system distribution requirements, my COSS
8 attempts to recognize a portion of their load as peak demand resulting in an increase to the
9 IGD-1 cost responsibility. Since the current IGD-1 daily customer charge has remained
10 unchanged over the last seven years, (docket 3270-UR-112), I am proposing to increase the
11 daily customer charge from $102.00 per day to $117.30 per day, and I am also proposing to
12 increase the volumetric rate a nominal $0.001 per therm.
13 Q. What changes are you proposing for the Steam and Power Generation Distribution class
14 (SP-1)?
15 A. Since the COSS results are showing the SP-1 class is under-recovering by approximately
16 $270,000, I am proposing to increase the distribution margin by $0.003 per therm while
17 maintaining the current daily customer charge.
18 Q. What changes are you proposing to the Seasonal Distribution Service (SD-1) class?
19 A. This service class primarily consists of grain drying load as well as a couple of asphalt
20 companies. The operations of both ofthese industries are highly dependent on weather
21 conditions which can, and typically does, result in authorized and sometimes unauthorized
22 usage in the restricted months of December and April. In order to address this issue of
23 occasional peak month usage, I will be offering a revised SD-1 tariff in supplemental direct
24 testimony. The revised SD-1 tariff will reflect adjustments to the daily customer charge so that
25 SD-1 customers will be paying the customer charge year round regardless of whether or not
Direct-MGE-Minor-15r there is any consumption. The bill and revenue impacts will be minimal as the revised tariff
2 will simply spread the current customer charge revenues over the course of the entire test-year
3 instead of the current seven month time period resulting in a revenue neutral revision. In
4 addition, I will be proposing an on-peak distribution margin rate whereby all SD-1 customers
5 wifl automatically default to the on-peak margin rate during the months of December thru
6 April based on their respective billing cycles. I am proposing to set this on-peak SD-1 margin
7 rate at or above the current GSD-1 margin rate, which is currently proposed at $0.1326 per
8 therm. In the interim, I have adjusted the existing SD-1 tariffby increasing both the daily
9 fixed charge and the distribution margin in the SD-1 class. The fixed charge was increased
10 from its current $1.75 per day to $2.012 per day and the distribution margin was increased
11 from $.0787 per day to $.0827 per day. Both ofthese adjustments are consistent with my
12 COSS results.
13 Q. How were Compressed Natural Gas Service rates designed?
14 A. The Compressed Natural Gas Service is the only service that continues to remain bundled in
15 its rate design. This is because this service is sold at the nozzle and cannot be nominated from
16 day to day. While the current volumes in the CNG-1 class remain relatively small, the
17 Company anticipates demand for CNG to increase significantly due to the demand for
18 alternative motor fuels. As a result, the Company will be filing a new Natural Gas Vehicle
19 (NGV -1) service tariff outside ofthe rate case for implementation in 2012 as a new service.
20 In the interim, the COSS illustrates the current CNG-1 service is under-recovering by
21 approximately six percent. This revenue deficiency is not reflective of any direct allocation of
22 compressor and compressor-related costs. Consequently, I have proposed to increase the fully
23 bundled rate by $0.2848 per therm. This increase will also bring the distribution charge into
24 parity with CNG rates throughout the rapidly evolving CNG industry. I am also proposing that
25 customers currently subscribing to interruptible gas service under CNG-1 be moved to the
Direct-MGE-Minor-16 new CNG gas supply schedule (FS-3) which is currently under review by the Commission. In
2 addition, I am proposing to add a $0.15 per therm electric compression charge to acknowledge
3 the electric cost associated with the compression of natural gas. In reviewing other CNG
4 tariffs throughout the industry, I have found the electric compression charge to be a common
5 rate component which should be recognized as a cost of compressing natural gas.
6 Q. What changes have been proposed in the administrative charges for the various service
7 options?
8 A. I have proposed to increase the FS-I and the IS-I volumetric administrative charges a very
9 nominal $.000I to help achieve the Company's overall revenue requirement. All other
I 0 administrative charges remain unchanged.
II Q. Are you proposing any changes to the Company's daily telemetering charge for
I2 interruptible and daily balancing service (DBS-1) customers?
I3 A. Yes, the COSS indicates that the current telemetering charge is under-recovering by
I4 approximately 26 percent. In addition, the last time the Company's telemetering charge was
I5 increased was in 2008. Consequently, I am proposing to increase the charge from $I.50 per
I6 day to $1.75 per day. The proposed $.25 per day increase demonstrates appropriate movement
I7 towards COSS and is representative of an approximate 3 percent increase over the five-year
I8 period.
I9 Q. Please explain Schedule 2 of Ex.-MGE-Minor-2.
20 A. Current and proposed rates are detailed on the Schedule 2, Rate Summary. Current
2I Distribution Class Customer Charges, as well as the Administrative Charges for Telemetering
22 and Daily Balancing Service, are shown as daily charges in this filing, since that is how they
23 are billed.
24 Q. Please explain Schedule 3 of Ex.-MGE-Minor-2.
Direct-MGE-Minor-I7 1 A. Schedule 3 (Ability to Pay Summary) compares the changes in peak month bills of an average
2 residential space heating customer with other socioeconomic indicators from 1986 through the
3 present and projected forward through the test year. The comparative economic indicators
4 such as the Consumer Price Index, Local Manufacturing Wages and Social Security benefits
5 were used for comparison purposes.
6 Q. Please explain Schedule 4 of Ex.-MGE-Minor-2.
7 A. Schedule 4 consists of 8 pages and shows the bill impact of the proposed rate design for all
8 customer classes and service combinations using varying levels of consumption. For example,
9 a Madison area customer with average use of 720 therms per month will see a rate increase of
10 $2.45 per month.
11 Q. Please explain Schedule 5 of Ex.-MGE-Minor-2.
12 A. Schedule 5 illustrates how the allocation ofthe Company's Act 141 cost obligation was
13 accomplished. As can be seen from the schedule, I have used the same Commission approved
14 methodology that has been used in previous filings. Specifically, I allocate 40 percent ofthe
15 cost obligation to residential customers and the remaining 60 percent to commercial and
16 industrial customers based on throughput after adjusting for the volumetric and revenue
17 credits.
18 Q. Are there any other tariff related changes you are proposing at this time?
19 A. Yes, Schedule 6 ofEx.-MGE-Minor-2 illustrates some added language I am proposing for
20 tariff Sheet 47.0. The new language identifies the Company's redress when a customer refuses
21 to allow authorized Company personnel access to their premises at all reasonable times for
22 reasons including but not limited to reading meters, making repairs, installing and upgrading
23 equipment, making inspections, making investigations, removing Company property or for
24 any other purpose incident to providing safe and reliable service. Specifically, the proposed
25 added language states that any such refusal or failure to provide authorized Company
Direct-MGE-Minor-18 personnel access to Company equipment may result in disconnection of service. The proposed
2 language is consistent with the authorized language currently included in tariff sheet E-65 .5 of
3 the Company's electric utility.
4 Q. Does this conclude your direct testimony?
5 A. Yes it does.
Direct-MGE-Minor-19 PSC REF#:l67583
'0g. BEFORE THE :u::;: ~ 0 2 PUBLIC SERVICE COMMISSION OF WISCONSIN t'l[/) Hro <:li t'l t1 ....< 3 Application of Madison Gas and Electric •• 0 4 Company for Authority to Change Electric Docket 3270-UR-118 0 ([) "'n 5 and Natural Gas Rates 'o ~m ...... ,_. rn -~'-'rn.... I-' 0 6 SUPPLEMENTAL DIRECT TESTIMONY OF TIMM A. MINOR I-' t:l •• 0 7 ON BEHALF OF APPLICANT ~t-Il _.. ::;: l11 .... "" rn ~ g 8 Q. Please state your name, business address, and current position. ....rn t:l 9 A. My name is Timm A. Minor. I am a Senior Gas Rate Analyst III at Madison Gas and Electric
10 Company (MOE), 133 South Blair Street, Madison, Wisconsin 53701.
11 Q. Are you the same Timm A. Minor who previously filed direct testimony in this
12 proceeding?
13 A. Yes.
14 Q. What is the purpose of your supplemental testimony in this proceeding?
15 A. The purpose of my supplemental testimony is two-fold. I will first present for Commission
16 consideration a restructured Seasonal Distribution (SD-1) tariff. The SD-1 tariff primarily
17 consists of customers who use gas for grain drying as well as processing asphalt for
18 construction applications. The restructured SD-1 tariff is designed to better accommodate
19 customer requests for on-peak usage due to unpredictable weather conditions. Second, I will
20 discuss the operational characteristics of two of the Company's recently approved gas
21 distribution and supply tariffs. Both tariffs were introduced to meet the current and anticipated
22 future demands of nonresidential customers requiring compressed natural gas (CNG)
23 distribution and/or gas supply service for the purpose of using CNG as a motor fuel.
24 Q. Please describe the Company's revised SD-1 tariff.
25 A. As previously mentioned, customers taking service on the SD-1 tariff primarily consist of
26 seasonal grain dryers as well as construction companies involved in the application of asphalt.
Supplemental Direct-MGE-Minor-1 1 The service also can be of use to seasonal vegetable canning operations. The operations of
2 these industries are highly dependent on weather conditions. Currently, service under the SD-1
3 tariff is available to customers from May 1 to December 1. December and April are
4 considered restricted availability months. Before customers may use gas in December or
5 April, they must submit a written request and receive approval from the Company. Service is
6 not available to customers in January, February, or March, although rare exceptions have been
7 made upon request by a customer. A customer that receives service in December or April (or
8 on a rare occasion in January, February, or March) without first obtaining authorization from
9 the Company is subject to a $0.50 per therm penalty. It is difficult, however, for the Company
10 to determine if a customer has in fact received this unauthorized service. Most SD-1
11 customers subscribe to interruptible system supply service (IS-I) and are billed by cycle reads,
12 but the SD-1 customers do not have telemetering. Consequently, the Company has no way of
13 knowing with any level of certainty whether or not the SD-1 customer actually used gas in
14 December or April. For example, if an SD-1 customer has a November cycle read that
15 includes several days in December, the Company has to assume for penalty assessment
16 purposes that all ofthe consumption in the November cycle read was consumed in November,
17 even though a portion of it could have been used in December without the Company's prior
18 authorization. Thus, the Company cannot enforce the therm penalty.
19 The restructured SD-1 tariff (Schedule 1 of 3 of Ex.-MGE-Minor-3) is less restrictive in
20 that it expands the current availability to include all months. Use will be controlled through
21 incentive pricing rather than manual monitoring, customer communication, and the application
22 of penalties. All SD-1 use will be subject to a much higher on-peak distribution margin rate
23 from January 1 through March 31. In order to send the proper price signal to discourage any
24 on-peak usage by SD-1 customers, I am proposing to set the on-peak margin rate for SD-1
25 customers at $0.4000 per therm. The lower proposed rate of $0.0827 will apply from April 1
Supplemental Direct-MGE-Minor-2 through December 31. In addition to the proposed increase in the on-peak distribution margin
2 rate, I am also proposing to charge the SD-1 daily customer charge year-round regardless of
3 whether or not there is any consumption. Currently, SD-1 customers only pay a daily customer
4 charge in the months of May through November. However, if the SD-1 customer has any
5 authorized or unauthorized consumption from December through April, they are assessed the
6 SD-1 daily customer charge for the entire bill cycle. Assessing the SD-1 daily customer
7 charge has always been a very labor intensive, manual process because the Company's billing
8 department has to check each SD-1 account by billing cycle looking for any unauthorized use.
9 Once the usage is confirmed, the customer's daily customer charge is turned on and assessed
10 for the entire billing cycle. Billing must also monitor the usage and turn off the daily customer
11 charge once the consumption has ceased. This manual review process leaves open the
12 possibility of error and the process has not always been seamless or consistent. As a means of
13 addressing this issue, I am proposing to assess the SD-1 daily customer charge year-round
14 regardless of whether or not there is any consumption. The bill and revenue impacts will be
15 minimal as the proposed change will simply spread the current SD-1 daily customer charge
16 revenue recovery over the entire twelve month test-year instead of the current seven month
17 time frame, resulting in a revenue neutral adjustment. Specifically, I am proposing to decrease
18 the current SD-1 daily customer charge of$2.0125 to $1.18, which will generate
19 approximately the same daily customer charge revenues when compared with the current
20 method.
21 Q. Please describe the Company's recently approved distribution service designed for
22 natural gas vehicles (NGV) as well as an associated compressed natural gas (CNG) gas
23 supply tariff (FS-3).
24 A. On May 4, 2012, the Company submitted for approval two new service tariffs (PSC Ref
25 # 164239) to meet the current and anticipated future demands of nonresidential customers
Supplemental Direct-MGE-Minor-3 1 requiring CNG distribution and/or gas supply service for the purpose of using CNG as a motor
2 fuel. The Company offered the tariffs as a "pilot" project with the understanding that the final
3 determination as to the reasonableness of the rates and applicability of the utility service
4 would take place in the Company's pending rate case (Docket 3270-UR-118). On May 23,
5 2012, the Company received approval ofthe new services (PSC Ref# 165050) subject to a
6 formal review in our rate case.
7 The new NGV and FS-3 service tariffs (Schedules 2 and 3, respectively, ofEx.-MGE-
8 Minor-3) are intended to respond to customer demand, promote the adoption of
9 environmentally beneficial uses of natural gas, create new opportunities for either end-use
10 fleets or service providers, and provide a future net benefit to ratepayers and shareholders
11 alike. The proposed tariffs can work together and with other unbundled tariffs to provide CNG
12 service in a number of different ways. For example, service can be provided to an individual
13 customer who operates a fleet of natural gas vehicles (NGVs) through the combination of a
14 NGV distribution tariff and FS-3 gas supply service. In a situation where the customer wants
15 to own the compression facility (or have another party other than MGE own it), service can be
16 provided through a combination of one of MGE's standard commercial and industrial
17 distribution tariffs (GSD-1, GSD-2, or GSD-3) in conjunction with the FS-3 gas supply sales
18 service. This will provide flexibility to promote the use of CNG in a number of different ways
19 to the rapidly evolving CNG market.
20 Under the NGV distribution tariff, MGE will own and operate a dedicated gas
21 compressor and related equipment on the customer's site to provide gas at a pressure requested
22 by the customer and agreed to by MGE pursuant to a separate service agreement. Through this
23 tariff, MGE will own and maintain the entire CNG facilities up to the point where the CNG is
24 available for use by the fleet customer or resale by the third party as further described in the
25 service agreement. This allows MGE to provide natural gas service at a pressure necessary for
Supplemental Direct-MGE-Minor-4 NGV fueling from our distribution system. MGE developed the NGV distribution service
2 tariff in response to customer inquiries and anticipates an increase in such inquiries and related
3 · service requests in the future. MGE is currently in the process of finalizing an agreement with
4 a third party convenience store/gasoline service station and will provide service through the
5 combination ofthe proposed NGV distribution tariff and the FS-3 supply service (described
6 below). In this specific installation, MGE will use the compressor facility to deliver natural
7 gas at 3,600 PSI. The natural gas, once compressed, will be stored in multiple CNG-certified
8 storage tanks. The CNG will be delivered to the Company-owned and certified CNG
9 dispensing pump which is compatible with the convenience store's existing point of sale
10 transaction system. The dispensing pump will measure the flow of CNG by using a Micro
11 Motion mass flow meter. The meter in the dispenser will be used by MGE to bill the
12 convenience store for the gas it receives and will be used by the convenience store to collect
13 the total transaction costs of the gas which it sells to its customers. The metered gas amount
14 will be converted to gasoline gallon equivalence (GGE) in order for the convenience store to
15 sell the gas to its customers. The convenience store will be responsible for collection from
16 end-use customers and payment ofvarious state and federal road taxes and any other relevant
17 taxes or fees related to the dispensing and sale of CNG to the public. MGE will perform a
18 calculation to convert the metered gas amount to a billable therm equivalence and will apply
19 the charges in the NGV and FS-3 tariffs to bill the convenience store on a monthly basis. The
20 convenience store will pay the approved NGV customer charge and distribution rates to MGE.
21 The convenience store will be placed in the appropriate commercial and industrial small,
22 medium, or large NGV distribution class, with consumption thresholds designed to match the
23 Company's established GSD distribution service schedules, based on MGE's best estimate of
24 its annual throughput. In addition, it will pay an approved per-therm electric compression
25 charge to recover the cost of energy used for compression as well as a contracted per-therm
Supplemental Direct-MGE-Minor-5 1 electric compression facilities charge. The electric compression facilities charge will be based
2 on the estimated capital cost and O&M divided by a long-term estimate of sales and will be
,.., .J developed and mutually agreed to on a case-by-case basis. MGE is using a long term estimate
4 of sales as a way to balance the need to provide rate stability to the participating convenience
5 store with the potential short-term costs and long-term benefits to the other distribution
6 customers ofMGE.
7 Q. Have you addressed any concerns with the current pricing disparity between the
8 Company's existing fully bundled CNG-1 service tariff and the new NGV distribution
9 service tariff?
10 A. Yes, a temporary equalizing credit provision has been included in the NGV tariff and will be
11 in effect until the cost included in the Company's already established CNG-1 rate schedule can
12 be reviewed in our current rate case filing. Since the Company's existing CNG-1 rate is not
13 reflective of a proper cost allocation of all the hardware and various other components
14 necessary for the compression of natural gas, which has resulted in an artificially low or
15 subsidized rate, a temporary equalizing credit is being used to lower the existing NGV tariff
16 rate to the same level as the current rate reflected in the Company's CNG-1 service tariff. A
17 restructured CNG-1 rate 1 has been proposed in the Company's current rate case, and if
18 approved, the CNG-1 rate will more closely reflect the true cost of providing CNG service.
19 Upon approval ofthe proposed CNG-1 rate changes, the equalizing credit will be removed
20 from the NGV tariff.
21 Q. Please describe the FS-3 gas supply service tariff.
22 A. Under the FS-3 gas supply tariff, customers will receive firm gas supply service for annual gas
23 service supplied at a single point of delivery. This service will provide Company-owned
24 natural gas supply to a distribution service class customer who uses the gas supply exclusively
1 See Schedule I, page I of2, ofEx-MGE-Minor-I, PSC Ref# I66587. Supplemental Direct-MGE-Minor-6 for the purpose of compressed natural gas. This service will be available to all customers
2 taking distribution service under the Company's NGV rate schedule or under the GSD-1,
3 GSD-2, or GSD-3 rate schedules who use the supply exclusively for compressed natural gas.
4 Customers taking service on the FS-3 supply tariff will be eligible for a demand charge credit
5 based on the given month's effective annual and seasonal demand charges. The demand charge
6 credit is similar to the demand. charge credit currently authorized in We Energies' NGV tariff.
7 Volumes (therms) of natural gas delivered for use in NGVs will be metered separately, either
8 through a dedicated service meter or through a submeter dedicated to the measurement of gas
9 for use in NGVs. The demand charge credit will be calculated and applied to all therms of gas
10 delivered through the customer's dedicated meter. The credit will be equal to two-thirds
11 (66.7%) of the effective monthly demand charges. The credit will be calculated on both the
12 annual demand rate component and, when in effect, the seasonal demand rate component.
13 The Company has developed a combination of tariffs that authorize the Company to
14 provide CNG service to fleets and service resellers in a number of different ways that will
15 benefit ratepayers and support customers' needs while improving the environment when
16 customers switch from more traditional gasoline and diesel fuel products to CNG for their
17 vehicles. Our proposal keeps MGE focused on the delivery of high pressure gas to our
18 distribution customers and leaves the fueling of vehicles to other parties already in the market
19 for providing that service. For all of the reasons stated above, the Company remains confident
20 that the NGV distribution and FS-3 gas supply service tariffs will be well received by the
21 alternative motor fuels industry and will provide benefit to other ratepayers and shareholders
22 in the long term.
23 Q. Does this conclude your supplemental direct testimony?
24 A. Yes it does.
Supplemental Direct-MGE-Minor-7 PSC REF#:l70881
BEFORE THE PUBLIC SERVICE COMMISSION OF WISCONSIN
Application of Madison Gas and Electric Company For Authority to Change Electric and Natural Gas Rates Docket No. 3270-UR-118
DIRECT TESTIMONY OF MARY NEAL ON BEHALF OF THE CITIZENS UTILITY BOARD OF WISCONSIN August 27, 2012
I. Introduction. 2 Q. What is your name and business address? 3 A. My name is Mary Neal. I am employed by La Capra Associates, Inc ("La Capra"). My 4 business address is One Washington Mall, Boston, Massachusetts, 02108. 5 6 Q. On whose behalf are you testifying in this proceeding? 7 A. I am testifying on behalf of the Citizens Utility Board of Wisconsin ("CUB"). 8 9 Q. Please describe your education and employment background. 10 A. I received my B.S., Mechanical Engineering in 2005 from the University of California, 11 Davis, and my M.A., Energy and Environmental Analysis in 2010 from Boston 12 University. Currently, I am a Consultant at La Capra Associates. I have been with this 13 energy planning and regulatory economics firm for over three years. In my time at La 14 Capra Associates, I have reviewed several Wisconsin electric utility fuel cost plans. 15 Moreover, I have reviewed electric utility plans for the acquisition and building of new 16 resources, as well as capital upgrades to existing units for utilities in four states, including 17 Wisconsin, and in Nova Scotia. I have also provided extensive analysis of electric utility 18 cost allocation models and assisted in analyzing electric and gas rate design in various 19 regulatory proceedings. In addition, I have critiqued and helped develop electric utility 20 integrated resource plans. Prior to working for La Capra Associates I worked for Solar 21 Turbines, Inc. for three years, designing low-emissions combustion systems for industrial 22 gas turbine engines. My resume is provided in Ex.-CUB-Neal-1. Direct-CUB-Neal-1p 1 2 Q. Have you previously testified before the Public Service Commission of Wisconsin? 3 A. No. However, I have testified before the Nova Scotia Utility and Review Board. 4 5 Q. What is the purpose of your testimony in this proceeding? 6 A. La Capra has been retained by CUB to assist in reviewing Madison Gas and Electric 7 Company's ("MGE" or "the Company") filing in this case. Specifically, we were asked 8 to review the Company's 2013 Fuel Cost Plan. 9 10 Q. Please summarize your conclusions. 11 A. Based upon my review, I offer the following conclusions: 12 • In certain areas, MGE's fuel cost plan has improved from the previous fuel cost plan 13 proceeding. 14 • MGE's share of uneconomic dispatch costs was double counted in its fuel budget, 15 overstating fuel costs by $480,643. 16 • MGE inappropriately excludes certain MISO Make Whole Payment ("MWP") 17 revenues from its fuel cost forecast. This results in an overstatement of fuel costs by 18 19 • MGE's assumed equivalent forced outage rate ("EFOR") for the West Campus 20 Cogeneration Facility ("WCCF") should reflect historical outage data. 21 • MGE has inappropriately included the costs of the Calpine Power Purchase 22 Agreement ("PPA") in its forecast of fuel and capacity costs as MGE terminated this 23 agreement in 2012. Excluding the cost ofthe Calpine PPA from MGE's PPA capacity 24 costs, would lower MGE's total forecasted costs by Moreover, MGE 25 should attempt to sell any excess capacity to offset increased purchased capacity 26 costs. 27 • MGE should adjust its planned maintenance schedule and delay the 28 until a time when locational marginal prices ("LMPs") are lower. 29 • Recommendations by La Capra regarding the modeling of Elm Road Generating 30 Station ("Elm Road") discussed in Docket No. 05-UR-1 06 should carry over to 31 MGE's modeling of Elm Road in this proceeding.
Direct-CUB-Neal-2p 1 • As a result of the August 21st U.S. Court of Appeals vacatur of the Cross-State Air 2 Pollution Rule ("CSAPR"), in projected CSAPR emission allowance costs 3 should be removed from the test year budget. 4 5 II. Overview of the Application. 6 Q. Please provide a brief overview of the Company's Application in this proceeding.
7 A. On March 23, 2012 the Company submitted an Application to increase electric and 8 natural gas rates for the 2013 test year. According to the Direct Testimony of Mr. 9 Kenneth Frassetto, MGE is requesting a total increase in electric revenue requirement 10 of $22,451,000, or 5 .82%. 1 With respect to fuel costs, the request included a total 11 increase of 2 in total electric fuel and purchased power adjustments, 12 of monitored costs and of non-monitored 13 costs. 3 MGE requested that the Public Service Commission of Wisconsin ("the 14 Commission") also allow it to update its electric fuel cost forecast before the 15 Commission's final decision to reflect the most recent mid-month futures prices, as 16 has typically been done in the past.4 In addition to the fuel cost requests, the 17 Company also asked for adjustments related to Elm Road, environmental upgrades at 18 the Columbia Energy Center ("Columbia"), and transmission-related charges. The 19 issues surrounding Elm Road will be addressed in Docket No. 05-UR-1 06. 20 21 On July 9, 2012 MGE posted final results ofthe Commission Staff("Staff') audit ofthe 22 2013 Fuel Cost Plan. 5 The audit changes resulted in an in fuel costs of 23 24.
1 Direct-MOE-Frassetto-4, I. 5 (PSC REF#: 166578). 2 MOE Response to Data Submittal Requirement No. 7A (PSC REF# 162274) and MOE First Supplemental Response to 3-CUB/RFP-2 (PSC REF#: 169457). 3 MOE Response to Data Submittal Requirement No.7 A (PSC REF# 162274). 4 Direct-MOE-Johnson-6, II. 8-10 (PSC REF#: 166583). 5 MOE Fuel Audit Adjustments (PSC REF#: 168107). Direct-CUB-Neal-3p 1 Q. What issues have you reviewed on behalf of CUB? 2 A. I have reviewed whether the proposed changes in monitored and non-monitored fuel 3 costs are appropriate. 4 5 Q. What is your understanding of the methodology the Company used for projecting 6 fuel costs in this proceeding? 7 A. My understanding is that the methodology is somewhat similar to processes used by other 8 Wisconsin utilities. As part of a three-step process the Company has modeled the 9 dispatch of its own units, which results in estimating thermal plant fuel costs and 10 purchased power costs. 11 12 In step one, the Company estimated LMPs for the MOE zone. Monthly futures prices for 13 2013 were available for the Northern Illinois Hub ("NI Hub") in PJM from futures 14 markets. The Company employed regression analysis of historical data for the NI Hub 15 prices and MOE zone prices to establish a statistical relationship between these two 16 prices; The statistical relationship was applied to 2013 NI Hub prices to develop a 17 forecast of peak and off-peak MOE zone prices for 2013. These monthly prices were 18 converted to hourly prices based upon historical data. 6 19 20 In step two, the resulting hourly LMP curve is fed into the RTSim 7 dispatch model along 21 with the performance parameters for MOE's generation and MOE's projected hourly load 22 curve. This model estimates the output and fuel cost of each MOE resource for 2013 as 23 well as the cost and revenues for opportunity sales and purchases. 24 25 The final step in the process is to estimate LMPs for other MISO pricing zones where 26 MOE resources are located outside ofthe MOE zone. For example, MOE is a joint 27 owner of Elm Road. Because this resource is located outside ofthe MOE pricing zone, it 28 has its own LMP that is different from the LMP in the MOE zone due to the congestion 29 and loss components of the LMPs. When the LMP is higher in the MOE zone than the
6 MOE Response to FCP(ME-1) (PSC REF#: 162271). 7 MOE Response to FCP(DM-1) (PSC REF#: 162271). Direct-CUB-Neal-4p 1 zones in which MGE owns resources, there is a net cost to MGE, whereas when the LMP 2 is lower in the MGE zone, there is a net benefit. To estimate this congestion cost, the 3 Company relied on LMP data from the past twelve months. 8 4 5 The Company has also updated its forecast ofMISO charges to reflect the most recent 6 twelve months of historical values. 9 7 8 Q. What were the major drivers of the increased fuel costs reflected in the May filing? 9 A. According to testimony ofMGE witness Tamara Johnson, fuel cost increases are driven 10 in part from capacity costs related to power purchase agreements. 10 11 are other significant cost drivers 12 as shown in Figure 1 below. 13
8 MGE Response to 3-CUB/Inter-3 (PSC REF#: 169031). 9 MGE Response to FCP(IS0-3) (PSC REF#: 162271). 10 Direct-MGE-Johnson-5, II. 6-7 (PSC REF#: 166583). Direct-CUB-Neal-5p 1 Figure 111
2 3 Q. What changes were made to the fuel cost plan as part of the Staff Audit? 4 A. 5 6 7 8 9
11 Taken from data found in MGE's Response to Data Submittal Request No. 7A (PSC REF#: 162274) and MGE's First Supplemental Response to 3-CUB/RFP-2 (PSC REF#: 169457). 12Attachment to MGE Response to 6-CUB/Inter-2 (PSC REF#: 169507). Direct-CUB-Neal-6p Figure 2 13
-2013 Case C1
2 3 III. Fuel Cost Plan Improvements. 4 Q. Are there areas where the Company has improved its fuel cost projection methods 5 compared to the previous fuel cost plan proceeding?14 6 A. Yes. I have found that the Company's estimates ofMGE zonal LMPs and LMP 7 differentials for remote generation are generally improved. 8 9 Q. How has MGE improved its estimation of MGE zonal LMPs? IO A. The regression analysis MGE used to estimate the difference between NI Hub LMPs and II MGE zonal LMPs had been based on a time series stretching back forty-eight months.
13 MOE Fuel Audit Adjustments (PSC REF#: 168107). 14 This question refers to the 3270-UR-117 Reopener. Direct-CUB-Neal-7p 1 MGE now uses a regression based on the previous twelve months of data. This better 2 reflects current MISO market conditions and is in accordance with the Commission's 3 decision in the previous case. 15 4 5 Q. How has MGE improved its estimation ofLMP differentials for remote generation? 6 A. In the previous case, MGE estimated LMP differentials using a combination of actual 7 historical data and projections based on historical trends. 16 This method was not entirely 8 internally consistent and appeared to overstate these costs. MGE now relies on the 9 previous twelve months of actual data to forecast these costs, 17 which is more consistent 10 with the rest of its modeling and in accord with the Commission's decision in the 11 previous case. As of the time of the Staff Audit, 18 the forecast also included offsetting 12 revenues from new FTRs, 19 demonstrating MGE has taken some actions to control these 13 costs. 14 15 IV. Concerns with the Company's Estimates of Increased Fuel Costs. 16 Q. What aspects ofMGE's fuel cost plan appear to have overstated MGE's fuel costs? 17 A. I have found issues in the following areas: 18 • Double counting in the allocation of WCCF uneconomic dispatch charges; 19 • Make Whole Payment Revenues; 20 • WCCF equivalent forced outage rates; 21 • PPA Costs/Excess Capacity Costs; 22 • Planned outage schedule; and 23 • Elm Road generation. 24
15 Docket No. 3270-UR-117, Final Decision, pp. 12-13 (December 15, 2011) (PSC REF#: 157113). 16 /d. at pp. 13-15. 17 MOE Response to 3-CUB/Inter-3 (PSC REF#: 169031). 18 MOE Response to RJH-1-5 (PSC REF#: 166699). 19 MOE Response to 3-CUB/Inter-3 (PSC REF #: 169031 ). Direct-CUB-Neal-8p 1 Q. Please describe your concern with MGE's estimate of the allocation ofWCCF 2 uneconomic dispatch charges. 3 A. MOE's fuel budget includes line items for "West Campus Cogen-Gas" and "MOE share 4 of uneconomical dispatch." The costs ofthe MOE share of uneconomic dispatch, which 20 5 totals to $480,643 , is already included in the line item for "West Campus Cogen-Gas." 6 This means the uneconomic dispatch cost is double counted in the "Total West Campus 7 Cogen Gas" line item, which is the sum of all the WCCF fuel costs. 8 9 Q. Is MGE aware of this error? 10 A. Yes. CUB notified MOE ofthis problem, and MOE investigated its calculations of 11 uneconomic dispatch charges. In addition to the double counting problem, 12 13 14 15 Q. Please describe how MISO assigns Revenue Sufficiency Guarantee Make Whole 16 Payments ("RSG MWPs") to asset owners. 22 17 A. MISO credits asset owners with two types ofRSG MWP revenues: those associated with 18 the Day-Ahead ("DA'') market and those associated with the Real-Time ("RT") market. 19 20 In the DA market, MISO guarantees recovery of Start-Up, No-Load, Energy and 21 Operating Reserve Offers for resources that are committed by MISO and scheduled in the 22 energy and operating reserve market. MISO compares each generating asset's total 23 revenue from the energy and operating reserve markets to the asset's total offer amount 24 each operating day. If the offer amount exceeds the revenues, MISO issues aDA RSG 25 MWP equal to the difference. 26 27 Similarly, in the RT market, MISO also guarantees recovery of Start-Up, No-Load, 28 Energy and Operating Reserve Offers for generating assets that MISO commits during
20 Docket No. 3270-UR-117, Final Decision, p. 16 (January 12, 2011) (PSC REF#: 143578). 21 MGE Response to RJH-7 (PSC REF#: 170538). 22 The description ofMWP settlements derives from MISO's Market Settlements Calculation Guide (MS-OP-029- r15) and MISO's Market Settlements Business Practices Manual (BPM-005-r9). Direct-CUB-Neal-9p the Reliability Assessment Commitment ("RAC") process. In any given commitment 2 period, 23 if total production costs exceed total revenues, then MISO issues a R T RSG 3 MWP equal to the difference. 4 5 Q. Does MISO issue any other types of MWPs? 6 A. Yes. MISO issues RT Price Volatility MWPs. These payments are the sum ofDA 7 Margin Assurance Payments and Real-Time Offer RSG payments. DA margin assurance 8 payments are intended to compensate asset owners under certain market conditions if a 9 unit dispatches in RT below its DA schedule. This may be caused by price volatility or 10 manual redispatch. Sometimes assets ineligible for RT RSG MWPs are still eligible for 11 RT Offer RSG MWPs. RT Offer RSG MWPs are intended to guarantee recovery of 12 incremental energy and operating reserve costs for units that are committed in the DA 13 energy and operating reserve market or are RT must-run committed resources. 14 15 Q. What are some of the drivers of MWP revenues in the MISO market? 16 A. Asset owners receive MWPs for multiple reasons, including: 24 17 • MISO may keep a unit on-line after the LMP has dropped to less than the 18 unit's operating cost due to minimum run time limitations. 19 • Only the incremental energy offer component of each unit's three-part offer 20 into the MISO market impacts the calculation of LMPs. Therefore the LMP 21 established by a peaking unit on the margin will tend not to cover that unit's 22 total production costs. Moreover, if a peaking unit is committed by MISO to 23 run at its minimum load level (DA and/or RT Markets), the unit cannot set the 24 LMP because it is not a marginal unit. 25 • MISO may commit units through the RAC process to address reliability issues 26 that are not fully represented in the DA and RT markets. 27
23 The commitment period is limited to one operating day and must be separated from a different commitment r,eriod by at least one hour. 4 Derived from Docket No. 6630-FR-1 02, Wisconsin Electric Power Company ("WEPCO") response to MAR-1-31 (PSC REF#: 128208). Direct-CUB-Neal-1 Op Q. Has the Company included an estimate ofRSG MWPs in its fuel cost plan? 2 A. No. MGE states: 25 3 "MGE's fuel model only forecasts runs that result from MISO's security 4 constrained economic dispatch. The fuel model does not include forecasts 5 of runs that result from MISO dispatch for reliability reasons. Those runs 6 are typically uneconomic, and so operators are entitled to Make Whole 7 payments to offset their additional costs." 8 9 Q. Do you agree that it is inappropriate to include MISO MWPs in MGE's forecast of 10 fuel costs? 11 A. No. MGE argues that it does not include costs from units dispatched for reliability 12 reasons, but this is only one of the drivers ofMWP revenues. When MISO commits a 13 unit in the RAC process to ensure reliability, this may cause the unit's asset owner to 14 receive RT RSG MWPs. However, DA RSG MWPs and RT Price Volatility MWPs are 15 not associated with reliability. These revenues are issued due to constraints in MISO's 16 security-constrained economic dispatch, the costs ofwhich MGE models. Therefore, the 17 expected revenues should be included in its fuel cost plan. 18 19 Moreover, in its modeling, MGE estimates uneconomic dispatch charges26 for the WCCF 20 due to the need for steam production. Should such runs coincide with times when MISO 21 commits the WCCF for reliability, any RT RSG MWP revenues should offset the total 22 uneconomic dispatch charges. 27 23 24 25 currently this will not be a large amount of dollars.
25 MOE Response to 3-CUB{Inter-4 (PSC REF#: 169032). 26 MOE Response to TOB-7 (PSC REF#: 164477). 27 Currently MOE allocates uneconomic dispatch charges between UW and MOE ratepayers. The dollar amount that is allocated to ratepayers is fixed at about $480,000 (PSC REF#: 164477), a level previously approved by the Commission. Therefore, although offsetting MWP revenues would lower MOE's estimate of total uneconomic dispatch charges, it would not lower the total uneconomic dispatch charges estimated for MOE's ratepayers unless the total dropped below $480,000 or the allocation was altered. 28 MOE Supplemental Response to 3-CUB/Inter-5 (PSC REF#: 169483). 29 MOE Response to TOB-27 (PSC REF#: 166660). Direct-CUB-Neal-lip However, in the future should MISO regularly dispatch WCCF through the RAC process 2 during the winter, any resulting WCCF RT RSG MWPs should be credited in MGE's 3 fuel cost forecast. 4 5 Q. Do other utilities include forecasts of MWP revenues in their fuel cost plans? 6 A. Yes. WEPCO uses PROMOD and Northern States Power Company - Wisconsin 7 ("NSPW") uses PROSYM to estimate fuel costs. While the WEPCO PROMOD model 8 calculates LMPs internal to the model,30 NSPW's PROSYM model is like MGE's in that 9 it projects the generation and fuel costs from its generators with a set of projected LMPs 10 estimated external to the model. 31 Both utilities include estimates of all three types of 11 MWP revenues in their fuel cost plans based upon historical data. 32 12 13 Q. What do you recommend regarding MISO MWP revenues? 14 A. For its fuel cost plan, I recommend that: 15 • MGE include a forecast of 2013 DA RSG MWPs using the most recently 16 available twelve months ofhistorical data. From June 2011 to May 2012, 17 these revenues totaled 33 18 • MGE include a forecast of2013 RT Price Volatility MWPs using the most 19 recently available twelve months ofhistorical data. From June 2011 to May 20 2012, these revenues totaled 34 21 • MGE's total projected fuel costs for the 2013 test year should be reduced by 22 (the sum ofthe DA RSG MWPs and RT Price Volatility MWPs 23 identified above). 24 • MGE offset total WCCF uneconomical dispatch charges with WCCF RT RSG 25 MWPs received during time periods WCCF must run to produce steam. 26
30 Docket No. 05-UR-106, WEPCO's Responses to FCP (ME-l) and FCP (ME-3) (PSC REF#: 161404 and 160975). 31 Docket No. 4220-UR-118, NSPW's Responses to FCP (ME-l) and MAR-2, Question No.2 (PSC REF#: 165470 and 167179). 32 See, e.g., Docket No. 6630-FR-103, Direct Testimony of Mary L. Wolter, p. Dl.l5 (PSC REF#: 151508); Docket No. 6630-FR-103, Final Decision, p. 7 (PSC REF#: 157900); Docket No. 4220-UR-118, NSPW's Response to JKW-2, Question No. I (PSC REF#: 170626). 33 MGE Response to TOB-27 (PSC REF#: 166660). 34/d.
Direct-CUB-Neal-12p 1 Q. Please describe how MGE estimates the forced outage rate for the WCCF. 2 A. In response to discovery, 35 MOE states that the EFOR for the WCCF and its other units, 3 except for Columbia and Elm Road, have been used for many years, and that it could not 4 locate any documents to support these estimates. The EFOR for WCCF is 36 5 6 Q. Is MGE's assumed EFOR for WCCF in line with historical data? 7 A. No. MOE has provided data on planned outage and forced outage hours at WCCF from 8 the past five years. 37 This is summarized in Figure 3 below. This data indicates that 9 historically WCCF has operated with an EFOR than MOE has assumed in its 10 modeling. 11 Figure 3
WCCF Generator #1 WCCF Generator #2
WCCF Steam Turbine Generator '--.-MI--'--'iilllful!-..___,"11$ilik-l--lli'MMII-.._____ W-J
WCCF Generator #1 WCCF Generator #2
WCCF Steam Turbine Generator '-----L~~..___~~l~----L-~-~
WCCF Generator #1
WCCF Generator #2
WCCF Steam Turbine Generator L!!lli!I-'-Ll-•-L!!Ili!l-1--'--•~--w..~
12 13
35 MGE Response to 6-CUB/RFP-2 (PSC REF#: 169511). 36 MGE Response to 6-CUB/Inter-1 (PSC REF#: 169507). 37 MGE Response to FCP(DM-5) (PSC REF#: 162272). Direct-CUB-Neal-13p 1 Q. What do you recommend regarding the WCCF EFOR MGE uses to forecast fuel 2 costs? 3 A. I recommend MOE use an EFOR for WCCF based on the most recent five years of 4 outage history in the final model run in this proceeding. Based on the available data 5 summarized above, this number would be approximately . However, there are 6 certain caveats to this calculation. First, although MOE was asked to provide all 7 equivalent forced outage hours, the data above may not include all of the forced derate 8 outages, . Second, since this is a combined cycle facility, the 9 weighting of the outage factors for the different units should incorporate knowledge 10 about the typical cycle configuration, such as how frequently both combustion turbines 11 are operated. However, since MOE models the unit as this is difficult 12 to estimate from the model results, so figure is weighted by unit capacity.38 13 With these caveats, I recommend that MOE use a EFOR. 14 15 Q. Please describe why MGE's forecasted purchased capacity costs have increased over 16 the 2012 test year. 17 A. MOE's purchased capacity costs have increased for two reasons. 18 19 20 21 22 23 Q. How do capacity prices compare 24 A. 25 26 27
38 Capacity values are equal to the summer rating from the 2008 EIA-860 existing generator database. 39 MGE Response to 5-CUB/Inter-1 (PSC REF #:169325). 40 MGE Response to 3-CUB/Inter-2 (PSC REF#: 169048). Direct-CUB-Neal-14p 1 Q. Based on your review of the are there any provisions relevant to this 2 proceeding? 3 A. 4 5 6 7 8 9 Q. What is MGE's capacity surplus or deficiency in 2013? 10 A. 11 12 13 14 Q. Has MGE expressed any 15 A. MGE has stated that it 16 17 Q. Is there anything else that may impact MGE's capacity purchases in 2013? 18 A. On March 23, 2012 MGE filed a lawsuit against Riverside Energy Center, LLC ("REC"), 19 which administers the 75 MW PPA originally signed with Calpine in 2002. The 20 Complaint alleges that REC has violated the agreement and owes MGE $209,528 in 21 unpaid energy and ancillary service revenue from sales into the MISO markets. The 22 Complaint alleges that MGE properly terminated the PPA on March 23, 2012 by written 23 notice to REC. 44 24 25 Q. Do you have any recommendations related to MGE's capacity purchases? 26 A. Yes. First, MGE is in the process ofterminating a PPA with Calpine for 75 MW, yet the 27 cost ofthe PPA is still included in MGE's budget workpapers. Since the Company's 28 position is that the agreement has been terminated, this cost should be removed from the
41 MGE Response to 3-CUB/RFP-5 (PSC REF#: 169101). 42 MGE Response to Data Submittal Requirement No.7 A (PSC REF#: 162274). 43 MGE Response to 5-CUB/Inter-3 (PSC REF#: 169331). 44 Madison Gas and Electric Co. v. Riverside Energy Center, LLC, Dane County Case No. 12CV1236, Complaint, filed March 23, 2012. Direct-CUB-Neal-15p fuel cost for 2013. Excluding the cost ofthe Calpine PPA from PPA capacity costs, 2 would lower MOE's total forecasted costs by 3 Second, the Calpine PPA has a 4 5 6 additional capacity is needed during the term of the (for example, due to 7 the loss of the capacity under the Calpine PPA), I recommend that MOE pursue lower 8 priced purchased capacity through a competitive process rather than purchase additional 9 10 11 12 13 14 Q. What significant planned outages are included in MGE's test year forecast? 15 A. 16 17 18 19 20 21 22 Q. Has MGE provided any explanation for why any of these outages could not be 23 delayed until a time when LMPs are lower? 24 A. 25 26
45 MGE Response to 7-CUB/RFP-2, Attachment (PSC REF#: 170591) and MGE Response to 3-CUB/Inter-2 (PSC REF#: 169048). 46 MGE Response to 7-CUB/Inter-5 (PSC REF#: 170392). 47 /d.
Direct-CUB-Neal-16p 1 Q. What do you recommend regarding MGE's planned outage schedule? 2 A. I recommend that some of these outages be shifted slightly so that less generation is 3 scheduled out at one time. Specifically, I recommend that the planned month-long 4 be moved to October 2013, when LMPs are expected to be lower 5 6 7 Q. Please describe your concerns regarding Elm Road. 8 A. I have several concerns regarding the costs for Elm Road. As pertains to fuel costs, MOE 9 models Elm Road as must-run since that is historically how it has been offered into the 10 MISO market. 48 11 49 12 .• Since WEPCO is the primary owner 13 and operator of Elm Road, La Capra is examining fuel cost issues associated with Elm 14 Road, including issues related to its must-run status, in Docket No. 05-UR-1 06. All La 15 Capra recommended changes regarding Elm Road from that docket should be 16 incorporated into this proceeding. 17 18 v. CSAPR Compliance Costs.
19 Q. How much does MGE forecast it will spend on 802 emission allowance credits in the 20 2013 test year?
21 A. MOE is forecasting it will spend on S02 emission allowance credits in 22 2013. Of this total, about is projected for purchasing emission allowances to 23 comply with CSAPR. See column (a) of Figure 6 below, which shows MOE's estimated 50 24 costs of S02 emission allowance credits and emission credit amortization. 25
48 MGE Response to 7-CUB/Inter-2 (PSC REF#: 170394). 49 MGE Responses to 8-CUB.Inter-5 and 8-CUB/RFP-1(PSC REF#: 170717 and PSC REF#: 170729). 50 MGE Responses to 8-CUB/RFP-3 and 8-CUB/RFP-1 (PSC REF #: 170722 and PSC REF#: 170729). Direct-CUB-Neal-17p 1 Figure 6
2 S02 Emission Costs in Full Fuel Budget
Notes: All notes refer to spreadsheet provided in response to 8-CUB/RFP-3. (1) 2013 8 CUB lnter-RFP Responses.xlsx, tab 8CUBRFP3-S02 Credits 3 (2) 2013 8 CUB lnter-RFP Responses.xlsx, tab 8CUBRFP3-Acct 254.302 4 5 Q. What is the current status of CSAPR? 6 A. On August 21, 2012, the D.C. Circuit ofthe U.S. Court of Appeals struck down CSAPR, 7 remanding the rule back to the EPA for revision. 51 Until the EPA promulgates a new rule 8 to regulate emissions in upwind states that impact Clean Air Act compliance in 9 downwind states -likely in a matter of years- the 2005 Clean Air Interstate Rule 10 ("CAIR") is to remain in effect. Although appeals are theoretically possible, it is highly 11 unlikely in my opinion that CSAPR or any successor to CSAPR will be in effect in 2013. 12 13 Q. How does this court ruling impact projected emissions costs for MGE? 14 A. MGE should not have any CSAPR compliance obligation in the test year. As shown in 15 column (b) ofFigure 6 above, I recommend that the budgeted for CSAPR 16 emission allowances be removed from the test year fuel budget. The unexpected 17 extension of the CAIR program should not result in any additional emission costs beyond 18 the average inventory costs already included in the budget. MGE has noted 19 that it has not had to purchase any CAIRIAcid Rain allowances "for a number of 20 years,"52 and its inventory of allowances (even before receiving its 2013 allocation of 21 free allowances from the EPA) is the number of allowances needed in
51 EME Homer City Generation, L.P. v. Environmental Protection Agency, D.C. Circuit Court of Appeals Case No. 11-1302 (August 21, 2012). 52 MGE Response to 8-CUB/lnter-3 (PSC REF#: 170715). Direct-CUB-Neal-18p 1 2012. 53 I am not aware of any reason why the amortization credit would be
2 affected either. Therefore, I recommend that the S02 emissions allowance budget be 3 reduced to as shown in column (b) of Figure 6. 4 5 VI. Recommendations. 6 Q. Please summarize your recommendations. 7 A. I recommend that: 8 1) MGE include a forecast of2013 DA RSG MWPs in its fuel cost plan using 9 the most recently available twelve months of historical data; 10 2) MGE include a forecast of2013 RT Price Volatility MWPs in its fuel cost 11 plan using the most recently available twelve months of historical data; 12 3) MGE offset total WCCF uneconomic dispatch charges with WCCF RT RSG 13 MWPs received during time periods WCCF must run to produce steam; 14 4) For 2013, using the most recent data available from MGE, fuel costs should 15 be reduced by to account for these MWP revenues. 16 5) MGE use an EFOR for WCCF based on the most recent five years of outage 17 history, which is approximately according to the data MGE has 18 provided, and that MGE's fuel costs be adjusted accordingly; 19 6) The cost ofthe Calpine PPA be removed from the fuel cost plan for 2013, 20 reducing MGE's capacity costs by 21 7) MGE pursue lower-priced purchased capacity through a competitive process 22 rather than purchase additional capacity under the to the extent 23 required; 24 8) MGE develop a strategy to utilize MISO's capacity markets and any other 25 appropriate means 26 9) 27 when LMPs are expected to be lower 28 10) MGE adjust its modeling and cost projections to reflect all La Capra 29 recommended changes regarding Elm Road from Docket No. 05-UR-106;
53 MGE Response to Data Submittal Requirement No. 7A, spreadsheet -2013 FCP Responses, tab FF-13(1) (PSC REF#: 162272). Direct-CUB-Neal-19p 1 11) MGE' s forecast of CSAPR compliance costs for 2013 be reduced by 2 3 4 Q. Does this conclude your testimony? 5 A. At this time, yes, it does. Should additional information become available, I will 6 supplement this testimony as appropriate.
Direct-CUB-Neal-20p PSC REF#:l70884
BEFORE THE PUBLIC SERVICE COMMISSION OF WISCONSIN
Application of Madison Gas and Electric ) Company for Authority to Change ) Docket No. 3270-UR-118 Electric and Natural Gas Rates )
DIRECT TESTIMONY OF JONATHAN WALLACH ON BEHALF OF THE CITIZENS UTILITY BOARD OF WISCONSIN August 27, 2012
I. Introduction and Summary
2 Q: Please state your name, occupation, and business address.
3 A: My name is Jonathan F. Wallach. I am Vice President of Resource Insight, Inc.,
4 5 Water Street, Arlington, Massachusetts.
5 Q: Please summarize your professional experience.
6 A: I have worked as a consultant to the electric-power industry since 1981. From
7 1981 to 1986, I was a research associate at Energy Systems Research Group. In
8 1987 and 1988, I was an independent consultant. From 1989 to 1990, I was a
9 senior analyst at Komanoff Energy Associates. I have been in my current
10 position at Resource Insight since September of 1990.
11 Over the past thirty years, I have advised clients on a wide range of
12 economic, planning, and policy issues including: electric-utility restructuring;
13 wholesale-power market design and operations; transmission pricing and policy;
14 market valuation of generating assets and purchase contracts; power
15 procurement strategies; risk assessment and management; integrated resource
Direct-CUB-Wallach-1 planning; cost allocation and rate design; and energy-efficiency program design
2 and planning.
3 My resume is attached as Ex.-CUB-Wallach-1.
4 Q: Have you testified previously in utility regulatory proceedings?
5 A: Yes. I have sponsored expert testimony in more than 55 federal, provincial, or
6 state proceedings in the U.S. and Canada. In Wisconsin, I testified in Docket
7 Nos. 6630-CE-302, 3270-UR-117, 4220-UR-117, and 6680-FR-104. I include a
8 detailed list of my previous testimony in Ex.-CUB-Wallach-1.
9 Q: On whose behalf are you testifying?
10 A: I am testifying on behalf of the Citizens Utility Board of Wisconsin (CUB).
11 Q: What is the purpose of your testimony?
12 A: On March 23, 2012, Madison Gas and Electric Company (MGE or "the
13 Company") filed an application to increase electric rates by 5.8% in order to
14 recover an expected revenue deficiency of $22.4 million in the 2013 test year.
15 Based on the results of three embedded cost of service studies (COSS), the
16 Company proposes to increase average rates for the residential class by 6.2%. In
17 addition, MGE proposes a radical reformulation of its rate designs that would
18 recover the bulk of residential revenue requirements through the customer
19 charge. As a first step in a transition to this new rate structure, the Company
20 further proposes for 2013 rates to increase the residential customer charge from
21 $8.70/month to $12.17/month, or by about 40%.
22 This testimony addresses two aspects of the Company's filing: (1) the
23 methods used in the cost of service studies to allocate production and
24 distribution plant costs; and (2) the basis for the Company's proposal to
25 restructure residential rates. The first element is discussed in the pre-filed direct
26 testimony of Company witness Steven S. James. The proposal to restructure
Direct-CUB-Wallach-2 residential rates and to increase the residential customer charge is discussed in
2 the pre-filed direct testimony of Company witness Gregory A. Bollom.
3 Q: Please summarize your findings and recommendations.
4 A: The Company relied on the results of three cost of service studies to develop its
5 proposal for a 6.2% increase in residential rates. These three studies differ
6 primarily with respect to the methods used to allocate production and
7 distribution plant costs. Of the three studies, the "Location" COSS allocates
8 costs in a fashion that most reasonably reflects each class's responsibility for
9 such costs. In contrast, the "Standard" COSS appears to allocate more
IO production and distribution plant costs to the residential class than is
II appropriate, while the "Time-of-Day" COSS appears to overstate the appropriate
I2 residential allocation of distribution plant costs. The Commission should
13 therefore give little weight to the results of the Standard and Time-of-Day
I4 studies.
I5 With respect to residential rate design, MGE lacks a reasonable basis for its
I6 proposal to shift costs from the energy charge to the customer charge.
I7 Redesigning residential rates in the fashion proposed by the Company would
I8 inappropriately shift load-related costs to the customer charge, dramatically
I9 dampen pnce signals to consumers for reducing energy usage,
20 disproportionately and inequitably increase bills for the Company's smallest
2I residential customers, and exacerbate the subsidization of larger residential
22 customers' costs by these lower-usage customers. Consequently, the
23 Commission should reject both the Company's proposal to restructure
24 residential rates and its proposal to transition to restructured rates by increasing
25 the residential customer charge from $8.70/month to $12.17/month for 2013
26 rates.
Direct-CUB-Wallach-3 II. Cost Allocation
2 Q: Please describe the Company's requested rate increase.
3 A: The Company is requesting that electric rates be increased on average by 5.8%
4 in order to recover an expected revenue deficiency of $22.4 million in the 2013
5 test year. Of the total $22.4 million requested revenue increase, MGE proposes
6 to allocate $7.72 million to residential customers. I This amount represents a
7 6.2% increase over residential revenues under current rates.
8 Q: What is the basis for the proposed residential rate increase?
9 A: According to Mr. James, the proposed residential rate increase was derived
10 using as "guidelines" three cost of service studies. These three studies differ
11 with respect to the methods used to allocate production and distribution plant
12 costs, as well as with respect to the allocator for energy-related costs.
13 Specifically, the three studies differ as follows: 14 • The "Standard" COSS classifies all production plant costs as demand 15 related, and allocates such costs on the basis of each customer class's
16 contribution to the average of the twelve monthly system coincident peaks
17 ("12CP"). Distribution plant costs are classified as either demand-related 18 or customer-related based on a minimum-system analysis. Demand-related
19 costs are allocated based on class non-coincident peaks and customer 20 related costs are allocated based on number of customers. All energy 21 related costs are allocated based on each class's contribution to total
22 generation (i.e., sales plus losses).
23 • The "Time-of-Day" COSS classifies 60% of non-peaking production plant 24 costs as demand-related and the remaining 40% as energy-related.
1 Ex.-MGE-James-2, Schedule No. I, p. 1 (PSC REF #:166582).
Direct -CUB-Wallach-4 (Peaking plant costs are classified as 100% demand-related.) Demand
2 related production costs are allocated using the 12CP allocator and energy
3 related costs are allocated based on each class's contribution to on-peak
4 generation. Distribution costs are allocated in the same fashion as in the
5 Standard COSS. All energy-related costs are allocated using the on-peak
6 energy allocator.
7 • The "Location" COSS classifies and allocates production plant costs in the
8 same fashion as in the Time-of-Day COSS. All distribution plant costs,
9 other than for meters and services, are classified as demand-related and
10 allocated based on non-coincident peak. (All meter and services costs are
11 classified as customer-related.) All energy-related costs are allocated using
12 the on-peak energy allocator.
13 Q: Why did the Company perform these three cost of service studies?
14 A: According to Mr. James:
15 I have offered three studies in this case to provide the Commission with a 16 range of costs produced by various accepted cost methodologies. In past 17 cases, the Commission has found it reasonable to rely on the results of 18 more than one cost of service study when allocating revenue responsibility. 19 Depending on different factors the Commission may consider as to how the 20 rate increase in this case should be apportioned among the customer 21 classes, some studies may be deemed more appropriate than others. 2
22 Q: Are any of these studies more appropriate than the others?
23 A: Yes. Of the three studies, the Location COSS allocates costs in a fashion that
24 most reasonably reflects each class's responsibility for such costs. In contrast,
25 the Standard COSS appears to allocate more production and distribution plant
26 costs to the residential class than is appropriate, while the Time-of-Day COSS
2 Direct-MGE-James-8, II. 18-23 (PSC REF#: 166580).
Direct-CUB-Wallach-5 appears to overstate the appropriate residential allocation of distribution plant
2 costs.
3 Q: How does the Standard COSS over-allocate production plant costs to the
4 residential class?
5 A: The Standard COSS classifies all production plant costs as demand-related,
6 implying that, from a generation planning perspective, production capacity costs
7 are incurred solely for the purposes of meeting system reliability requirements.
8 This assumption is inconsistent with investment decision-making under typical
9 generation expansion planning practices, where plant investment choices are
1o driven by both reliability and energy requirements.
11 Specifically, investments in peaking plant are appropriately classified as
12 demand-related, since peaking units would be the least-cost option for meeting
13 an increase in peak demand and planning reserve requirements. On the other
14 hand, baseload or intermediate plant costs in excess ofpeaking plant costs (so-
15 called "capitalized energy" costs) should be classified as energy-related, since
16 these incremental costs are incurred to minimize the total cost of meeting an
17 increase in energy requirements.
18 Q: Does MGE recognize that the Standard COSS classification of production
19 plant costs is inconsistent with generation expansion planning?
20 A: Yes. According to Mr. James, the Time-of-Day and Location studies classify a
21 portion of production plant costs as energy-related in order to reflect "the trade-
22 off between operating expense and initial plant cost made by MGE when it
23 decided what plants should be built." 3
3 Direct-MGE-James-7, ll. 13-15 (PSC REF #:166580).
Direct-CUB-Wallach-6 Q: What is the basis for the 60°/o/40°/o demand/energy split of production plant
2 costs in the Time-of-Day and Location studies?
3 A: According to Mr. James, these studies simply adopt the split used by
4 Commission Staff in previous rate cases. 4
5 Q: Do you have any concerns about the 60°/o/40°/o split assumed by
6 Commission Staff?
7 A: I am concerned that this split-which Commission Staff has applied generically
8 across utilities -may not reasonably reflect the actual proportion of demand to
9 energy-related investments in the Company's production plant.
1o I am aware of two recent rate cases for other Wisconsin utilities where this
11 split was derived based on actual utility production plant cost data, and in both
12 cases the split implied a greater proportion of energy-related costs. In Docket
13 No. 05-UR-106, Wisconsin Electric Power Company calculated a 50%/50%
14 split between demand-related and energy-related costs. 5 And in Docket No.
15 4220-UR-117, I derived a 30%/70% demand/energy split for Northern States
16 Power Company's production plant costs. 6
17 Q: How do the Standard and Time-of-Day studies over-allocate distribution
18 plant costs to the residential class?
19 A: These studies classify distribution costs as customer-related or demand-related
20 based on a minimum-system analysis. Minimum-system methods are generally
21 unreliable and tend to misclassify demand-related costs as customer-related
4 Direct-MGE-James-7, ll. 22-23.
5 Docket No. 05-UR-106, Direct-WEPCO/WG-Rogers-16, ll. 10-16 (PSC REF#: 164646).
6 Docket No. 4220-UR-117, Direct Testimony of Jonathan Wallach, p. D2.33, II. 12-13 (PSC REF#: 154438).
Direct-CUB-Wallach-7 costs. As a result, cost allocations based on minimum-system classifications
2 overstate the appropriate allocation of distribution costs to residential customers.
3 Q: How does MGE apply the minimum-system approach in the Standard and
4 Time-of-Day studies?
5 A: The Company first classifies distribution plant costs (FERC Accounts 364
6 through 368) as either demand-related or customer-related based on a minimum-
7 size analysis. 7 The Company then allocates demand-related costs based on class
8 non-coincident peaks and customer-related costs based on number of
9 customers. 8
10 A minimum-size analysis attempts to estimate the cost to install the same
11 number of units (poles, conductor-feet, transformers) as are currently on the
12 system, assuming that each of those units are the smallest size currently used on
13 the distribution system. The cost of this minimum-size system is then deemed to
14 be customer-related, with the remaining cost classified as demand-related.
15 Q: Do minimum-size analyses generally produce reasonable classifications of
16 costs?
17 A: No. As James Bonbright, Albert Danielson, and David Kamerschen explain in
18 their Principles ofPublic Utility Rates, these analyses are fundamentally flawed
19 because minimum-system costs are neither properly classified as wholly
7 All distribution substation costs are considered to be demand-related, while all meter and service costs are considered to be customer-related.
8 Meter and service costs are allocated using a weighted customer allocator.
Direct-CUB-Wallach-8 customer-related nor demand-related. 9 Instead, Bon bright, Danielson, and
2 Kamerschen argue that such costs are inherently "unallocable":
3 But if the hypothetical cost of a minimum-sized distribution system is 4 properly excluded from the demand-related costs ... , while it is also denied 5 a place among the customer costs ... , to which cost function does it then 6 belong? The only defensible answer, in our opinion, is that it belongs to 7 none of them. Instead, it should be recognized as a strictly unallocable 8 portion of total costs .... But fully-distributed cost analysts dare not avail 9 themselves of this solution, since they are prisoners of their own 10 assumption that "the sum of the parts is equal to the whole." They are 11 therefore under impelling pressure to fudge their cost apportionments by 12 using the category of customer costs as a dumping ground for costs that 13 they cannot plausibly impute to any of their other cost categories. 10
14 Residential customers are especially burdened when a high percentage of
15 these unallocable costs are inappropriately dumped into the customer-cost bin.
16 In addition, in a 1981 article, George Sterzinger identified a specific flaw
17 in the minimum-size approach that could result in over-allocation of costs to the
18 residential class. 11 The problem arises because the minimum-size method
19 typically defines the minimum system to include equipment that would carry a
20 large portion of the average customer's load. For example, assume that the
21 minimum-size line transformer is large enough to cover the average load of
22 residential customers. In this case, only those costs incurred for the minimum-
23 size transformers are appropriately attributable to, and appropriately allocated
24 to, the residential class. However, the minimum-size method would not only
9 In other words, these costs are not driven primarily by either changes in the number of customers or by changes in customer demand, but instead may depend on such factors as customer density or terrain.
10 Bonbright, James C., Albert L. Danielsen, and David R. Kamerschen, Principles ofPublic Utility Rates, Arlington, VA: Public Utilities Reports, 1988., p. 492.
11 George J. Sterzinger, "The Customer Charge and Problems of Double Allocation of Costs", Public Utilities Fortnightly, July 2, 1981.
Direct-CUB-Wallach-9 allocate these mm1mum-s1ze transformer costs to the residential class as
2 customer-related costs, but would also inappropriately allocate a portion of the
3 remaining costs for larger-sized transformers to residential customers as
4 demand-related costs, even though the costs for these larger transformers were
5 not incurred to serve residential load.
6 Q: Is there a reasonable alternative to the minimum-size method for classifying
7 distribution plant costs?
8 A: Yes. A reasonable and reasonably straightforward alternative approach would be
9 to classify meters and services as customer-related and all other distribution
1o plant costs as demand-related. This is in fact the approach used in the Location
11 COSS.
12 III. Rate Design
13 Q: What is the Company's proposal with respect to residential rate design?
14 A: According to Mr. Bollom, the Company proposes a radical redesign of 15 residential rates that would recover all allegedly "fixed" costs through the 16 customer charge. The Company further proposes to transition to this "straight
17 fixed/variable" rate design over several years, and as a first step in this transition
18 to increase the residential customer charge from $8.70 per month to $12.17 per 19 month, or by about 40%, for 2013 rates.
20 Q: By what amount would MGE have to increase the residential customer 21 charge in order to recover all of the costs the Company considers to be
22 "fixed"?
23 A: According to the Company's response to Interrogatory No. 2-CUB/Inter-1 (PSC 24 REF#: 168381), the customer charge would have to increase to $73.32 per
Direct-CUB-Wallach-1 0 month, or by more than eight times the current level, in order to recover all costs
2 allocated to the residential class under the Company's COSS that MGE
3 considers to be "fixed."
4 Q: What would be the effect on the average residential energy rate, if recovery
5 of all allegedly "fixed" costs were shifted from the energy charge to the
6 customer charge?
7 A: If the customer charge for the Rg-1 rate class were increased to $73.32 per
8 month, the average energy rate (for distribution and electricity service
9 combined) would have to be reduced dramatically from about 14¢/kWh to about
10 4¢/kWh. 12 In this case, the energy rate for distribution service would be zero,
11 since all distribution costs would be considered to be "fixed" under the
12 Company's proposal.
13 Q: What are the "fixed" costs that MGE proposes to recover through the
14 residential customer charge?
15 A: Based on data provided in the Company's response to Request for Production
16 No. 2-CUB/RFP-5 (PSC REF#: 163894), MGE apparently considers all costs
17 that are classified as customer-related in the COSS to be fixed and thus
18 recoverable through the residential customer charge. In addition, MGE includes
19 all costs (whether generation, transmission, or distribution) classified as
20 demand-related in the category of "fixed costs" to be recovered through the
21 residential customer charge. Thus, from the Company's perspective, the only
22 non-fixed costs are those that are classified in the COSS as energy-related.
23 According to the Company's response to Interrogatory No. 2-CUB/Inter-1
24 (PSC REF#: 168381), customer-related costs would contribute $26.75, or about
12 This calculation is based on the allocation results from the Time-of-Day COSS.
Direct-CUB-Wallach-11 36%, to the total residential customer charge of $73.32 under the Company's
2 proposal. Demand-related costs would contribute the remaining $46.57, or about
3 64%. 13
4 Q: Would it be reasonable to recover all costs classified in the COSS as
5 customer-related through the residential customer charge?
6 A: No. The derivation of the customer-related portion of the proposed customer
7 charge is based on the results of the Time-of-Day COSS. As discussed above,
8 the Time-of-Day (as well as the Standard) COSS misclassifies demand-related
9 distribution costs as customer-related by relying on the minimum-system
10 method. As a result, the Time-'of-Day COSS overstates the total amount of
11 distribution costs appropriately allocated to the residential class, and overstates
12 the portion of the allocated amount that is appropriately classified as customer-
13 related.
14 In addition, while it may be reasonable to classify certain costs as
15 customer-related for the purposes of allocating such costs among customer
16 classes in the COSS, it is not appropriate to recover all such costs allocated to
17 the residential class through a fixed customer charge. For example, a number of
18 customer-classified distribution costs - such as services or uncollectible
19 accounts and collection expense - are likely to vary with the size of the
20 customer (in revenues, sales, or demand). If such costs were recovered through a
21 fixed customer charge, then the smallest residential customers (with the least-
22 expensive distribution equipment) would be required to pay the average of
23 customer costs attributable to all sizes of residential customers. In other words,
13 According to the Company's response to Request for Production No. 2-CUB/RFP-5 (PSC REF#: 163894), the customer-related and demand-related portions of the $73.32 total amount were determined based on the results ofthe Time-of-Day COSS.
Direct-CUB-Wallach-12 if all customers were to pay the same customer charge regardless of size, then
2 small customers would subsidize larger customers' distribution costs.
3 Q: What is the basis for the Company's proposal to recover all demand-related
4 costs through the residential customer charge?
5 A: The Company has not provided any rationale for recovering demand-related
6 distribution costs through the customer charge.
7 With respect to demand-related generation and transmission costs, the
8 Company offers the following explanation in response to Interrogatory No.2-
9 CUB/Inter-3 (PSC REF#: 168383):
10 Demand-related costs associated with generation and transmission are 11 typically associated with the size of a customer's maximum load and do not 12 vary with the amount of energy used. For residential and small commercial 13 customers with only energy meters, these costs should be treated as fixed 14 and recovered through some type of fixed charge.
15 In other words, MGE acknowledges that demand-related generation and
16 transmission costs are not fixed, but in fact vary with customer load. However,
17 the Company asserts that these costs vary solely with "maximum load" and
18 therefore presumably should be recovered through a demand charge. Given that
19 residential meters do not support the levy of a demand charge, the Company
20 believes that demand-related charges should instead be recovered through the
21 customer charge.
22 Q: Would it be appropriate to recover demand-related distribution costs
23 through the residential customer charge?
24 A: No. Such costs may appear "fixed" when considered in the short-term context of
25 utility cost recovery, since the revenue requirements associated with debt service
Direct-CUB-Wallach-13 and maintenance for a given set of lines and transformers in any year is unlikely
2 to vary much with load or sales in that year.I4
3 However, from the longer-term perspective of cost causation and price
4 signals, distribution investments are variable with respect to customer demand.
5 Increased loading of existing lines, conduit, transformers, substations, and other
6 distribution equipment reduces the lives of that equipment and requires the
7 installation of more and larger equipment. Higher loads may even require more
8 poles and towers, to carry additional primary circuits, and higher poles and
9 towers, to allow for higher distribution voltages. In general, energy charges
10 better reflect the causation of these costs than fixed customer charges, and hence
11 provide the better price signal.
12 Q: Has MGE offered a valid basis for recovering demand-related generation
13 and transmission costs through the customer charge?
14 A: No. As the Company acknowledges, these demand-related costs vary with
15 customer load, and thus are more reasonably recovered through a volumetric
16 rather than a fixed charge in order to provide appropriate price signals to
17 customers. Shifting recovery of such demand-related costs to the customer
18 charge would seriously distort price signals, since consumers would no longer
19 benefit from actions that reduce maximum demand and thus reduce demand-
20 related costs. Likewise, consumers would no longer be penalized for increases
21 in their peak demands. In other words, the Company's proposal would
22 misleadingly and inefficiently signal to consumers that there is no economic
23 gain or loss associated with changes in peak demand.
14 Higher loads, especially in the summer, are likely to result in failure of more transformers and underground lines, so current costs may vary with current load to some extent. However, this is probably a small effect, compared to total distribution costs.
Direct-CUB-Wallach-14 In contrast, recovering demand-related costs through energy charges would
2 appropriately signal to consumers the benefit or harm from any changes to peak
3 demand that accompany changes in energy usage. For changes in energy usage
4 that have the same load shape - i.e., has the same load factor- as that for the
5 residential class, the price signal through an energy charge would be identical to
6 that provided through a demand charge. 15
7 Q: Why is MGE proposing to radically redesign residential rates at this time?
8 A: Mr. Bollom offers the following reasons for restructuring residential rates:
9 • Current rate designs reduce the competitiveness of the Company's
10 commercial and industrial rates against those in states that have undergone
11 restructuring and instituted market pricing of generation.
12 • Current rate designs confuse customers who invest in energy-efficiency
13 measures, since bill savings in one year may be offset in part by rate
14 increases in following years.
15 • The proposed restructuring "is a logical extension of the PSCW's policy of
16 sending more accurate price signals" through advanced metering.
17 • Current rate designs inappropriately and inequitably shift "fixed" costs
18 from customers who install distributed generation to other customers.
19 Q: Are these concerns regarding the current residential rate design valid?
20 A: No. For the most part, such concerns are unwarranted, since as discussed above
21 ' the current rate design reasonably reflects cost causation and provides
15 For changes in energy usage that are "peakier" than residential average usage, an energy charge would understate the impact on demand-related costs. In the extreme, the price signal would be negated for measures that shift usage off of or on to the system peak hour without any change in overall energy usage.
Direct -CUB-Wallach-15 appropriate price signals regarding changes in customers' peak demands and
2 energy usage.l6
3 In addition, the concern about customer confusion is misguided. If
4 customers are confused about the relationship between bill savings and rate
5 increases from energy efficiency, the Company's response should be to better
6 inform customers about the economic benefits from reducing usage through
7 energy efficiency, the fact that cost-effective efficiency investments reduce bills
8 even when accounting for short-term rate increases, and about the fact that
9 efficiency investments reduce utility costs and thus rates over the long term.
10 Q: Other than the conceptual arguments supporting the proposed rate
11 restructuring, has MGE offered any justification for its specific proposal to
12 increase the residential customer charge for 2013 rates to $12.17 per
13 month?
14 A: Mr. Bollom believes that the proposed customer charge for 2013 will appear
15 reasonable to MGE customers because members of Wisconsin's electric
16 cooperatives apparently are satisfied with higher customer charges (or at least
17 not so dissatisfied that they chose to unseat board members.) By Mr. Bollom's
18 thinking, if cooperative members find their current customer charges acceptable,
19 then the Company's customers should also find a higher customer charge to be
20 reasonable.
21 If the Company's residential customers were to base their judgments of the
22 proposed customer charge on comparisons with other utilities' customer charges,
16 The concern about the competitiveness of commercial and industrial rates is also irrelevant to the issue of the reasonableness of current residential rate designs. The competitiveness of the Company's non-residential rates depends not on how costs allocated to the residential class are recovered from residential customers, but on the extent to which non-residential generation rates exceed competitive market prices.
Direct-CUB-Wallach-16 presumably they would be more inclined to look at customer charges paid by
2 customers at Wisconsin's other investor-owned utilities. If so, as indicated in the
3 following table, they would find that the customer charge proposed by MGE
4 would be 1.4 to two times the customer charges paid by residential customers of
5 the four other investor-owned utilities.
6 Table 1
7 Monthly Customer MGE Charge17 Multiple MGE (Proposed) $12.17 MGE (Current) $8.70 1.4 Northern States Power $8.00 1.5 Wisconsin Electric Power $7.60 1.6 Wisconsin Power and Light $7.67 1.6 Wisconsin Public Service (Current) $5.70 2.1 Wisconsin Public Service (pre-RSM)18 $8.40 1.4
8
9 Q: What do you recommend with regard to the Company's proposal to
10 redesign residential rates and increase the residential customer charge?
11 A: The Company requests that the Commission "determine that it is appropriate
12 and necessary for MGE to move to rate designs that recover fixed costs through
13 some type of fixed charges." 19 This request should be denied. The Company's
14 proposal would unreasonably shift to the customer charge costs that are more
17 MGE Response to 2-CUB/RFP-3, page 31 of80 (PSC REF#: 169088) and individual utility tariffs.
18 Per Docket No. 6690-UR-121, Direct-WPSC-Ferguson-1 0 (PSC REF#: 164605), Wisconsin Public Service Corporation's current customer charge was reduced upon implementation of its pilot revenue stabilization mechanism (RSM), which is to terminate at the end of this year.
19 Direct-MGE-Bollom-3, II. 21 ~23 (PSC REF#: 166575).
Direct-CUB-Wallach-17 appropriately recovered through energy charges. Such a shift would distort price
2 signals and inequitably burden smaller customers.
3 Lacking a reasonable basis for shifting costs into the customer charge, the
4 Company's specific proposal for increasing the 2013 customer charge to $12.17
5 per month should also be rejected. Any increase to residential revenues allowed
6 by the Commission should be recovered solely through the energy charge.
7 Q: Does this complete your direct testimony?
8 A: Yes.
Direct-CUB-Wallach-18 PSC REF#:170872
BEFORE THE PUBLIC SERVICE COMMISSION OF WISCONSIN
Application of Madison Gas and Electric for Authority to Change Electric and Docket No. 3270-UR-118 Natural Gas Rates
DIRECT TESTIMONY OF DANIEL TYSON STEADMAN COOK FOR CLEAN WISCONSIN August 27, 2012
1 Q. Please state your name and business address.
2 A. My name is Daniel Tyson Steadman Cook. My business address is 634 W. Main Street,
3 Suite 300, Madison, Wisconsin, 53703.
4 Q. By whom are you employed and in what capacity?
5 A. I am employed by Clean Wisconsin, as Staff Scientist.
6 Q. On whose behalf are you testifying?
7 A. I am testifying on behalf of Clean Wisconsin.
8 Q. Please describe your educational background.
9 A. I received a Bachelor's Degree in Physics from Kalamazoo College, in Kalamazoo,
10 Michigan, and a Master of Science degree in Civil and Environmental Engineering from the
11 Atmosphere/ Energy Group at Leland Stanford Jr. University, in Stanford, California. I also
12 studied Environmental Health Science at the graduate level at the University Of Michigan
13 School Of Public Health in Ann Arbor, Michigan.
14 Q. Please describe your work experience.
Direct - Clean Wisconsin - Cook - 1 1 A. As a Staff Scientist at Clean Wisconsin, I am responsible for providing technical support
2 and scientific expertise to the energy, air and water programs at Clean Wisconsin. Prior to
3 joining Clean Wisconsin, I worked as a consultant on energy efficiency, emerging energy
4 efficient technologies, and renewable power for Energy Solutions of Oakland, California. As part
5 of this work with Energy Solutions I was the corporate lead on light emitting diode (LED)
6 lighting. During that time, I led numerous studies and published a total of nine reports on the
7 implementation, use, and economics of LED lights, especially in outdoor settings. This included
8 eight project reports for the Pacific Gas and Electric Company.
9 Q. Are you sponsoring any exhibits with your testimony?
10 A. Yes, I am sponsoring the following exhibits:
11 Ex.-Ciean Wisconsin-Cook-1: MGE's response to 2-CW-RFP-1, filed in this docket as
12 PSC REF# 166664
13 Ex.-Clean Wisconsin-Cook-2: Marketplace Analysis for Outdoor Area/Roadway LED
14 Lights to Replace 150 Watt HPS Lights (August 2012)
15 Ex.-Clean Wisconsin-Cook-3: Marketplace Analysis for All Outdoor Area/Roadway
16 LED Lights (August 2012)
17 Ex.-Clean Wisconsin-Cook-4: MGE Response to Clean Wisconsin Interrogatory No. 3-
18 CW-INT -1, filed in this docket as PSC REF#: 166667
19 Ex.-Clean Wisconsin-Cook-S: MGE Response to Clean Wisconsin Interrogatory No. 3-
20 CW-INT-2, filed on ERF as PSC REF#: 170050
21 Ex.-Clean Wisconsin-Cook-6: Updated Calculations for MGE's Proposed OL-1 LED
22 Rate Structure, Based on Revised Values
23 Ex.-Clean Wisconsin-Cook-?: Proposed Formulae for Appropriate Rate Structures for
Direct - Clean Wisconsin - Cook - 2 1 Unmetered LED Outdoor Lighting (OL-1, SL-1, SL-2, SL-3), Including Example
2 Calculations
3 Q. What is the purpose of your testimony in this proceeding?
4 A. My testimony will discuss technical and practical aspects of LED lighting technology and
5 evaluate Madison Gas and Electric's (MGE) proposed rate structure for LED outdoor lighting.
6 Q. Please provide a brief overview of MGE's proposed rate structure for outdoor LED
7 lighting.
8 A. As discussed in Direct-MGE-James and shown in Ex.-MGE-James-2, MGE is proposing
9 monthly rates for light emitting diodes (LEOs) in four categories of the "OL-1" rate schedule for
10 MGE-owned and -maintained outdoor security lighting facilities: "70 watt equivalent LED
11 lamps," "150 watt equivalent LED lamps," "250 watt equivalent LED lamps," and "400 watt
12 equivalent LED lamps." The rates in each of these categories are set using the results of
13 calculations which are in turn based on assumptions for fixture wattage, operating hours,
14 installation and maintenance cost, and a fixed distribution charge.
15 Q. Is this proposed rate structure appropriate for LED outdoor lighting?
16 A. No. This proposed rate structure is based on a number of erroneous assumptions
17 regarding LED lighting. These assumptions fail to account for the differences between LED
18 lighting and traditional high intensity discharge (HID) based lighting. The proposed rate
19 structure therefore limits customers' options for utilizing the unique features of LED lighting to
20 optimize efficiency.
21 Q. How would MGE's proposed rate structure impact the ability of their customers to
22 use LED lighting?
Direct - Clean Wisconsin - Cook - 3 1 A. MGE's proposed rate structure is based around the concept of defining a limited number
2 of rates based on easily categorized options from which consumers are billed. This concept is
3 appropriate for traditional lighting rate structures, because those lights are indeed limited to a
4 few standardized sizes. For example, the American National Standards Institute (ANSI) provides
5 standards for high-pressure sodium (HPS) ballasts and lamps of 35, 50, 70, 100, 150, 200, 400,
6 600, or 700 watts. In Direct-MGE-James-28, MGE attempts to similarly characterize LED lights
7 by claiming equivalencies between LEDs and HID lights, based on assumptions of light output
8 such as" ... a 40 lamp LED is comparable to a 150 Watt HPS or MH [Metal Halide]."
9 However, LED lighting options are not directly analogous to traditional lighting
10 technologies. The light output and performance of LED luminaires is not directly tied to the
11 number of individual LED lamps in the fixture, as suggested by Mr. James, nor is the energy
12 usage or cost of the luminaire, as assumed by MGE's proposed rate structure shown in Ex.-Clean
13 Wisconsin- Cook- 1. Ex.-Clean Wisconsin- Cook- 2 demonstrates the wide range in electrical
14 demand for currently available LED products that may be used to replace a 150 watt HPS
15 luminaire based on light output.
16 As noted in Direct-MGE-James-18, "[u]nlike high pressure sodium (HPS) or metal halide
17 (MH) lighting, LED lighting does not come in standard wattage sizes." Contrary to Mr. James'
18 assertion of equivalencies however, the wide range of options in LED lights -including a
19 spectrum of different light outputs, power usages, efficiencies, lifespans, colors, light qualities,
20 and light distributions - don't necessarily correspond to traditional lighting categories. As a
21 result, setting rates for LEDs using assumptions of "equivalent" lights to the traditional HID
22 sizes is inappropriate. Depending on the design, LED fixtures that provide comparable lighting
23 performance to a 150 Watt HPS fixture, for example, can vary greatly in electrical usage, total
Direct - Clean Wisconsin - Cook - 4 1 light output, and upfront and lifecycle costs. Mr. James' suggestion at Direct-MGE-James-18
2 that the proposed LED rate classes cover a range of LED lights (e.g. "LED fixtures with 30 or
3 less lamps, 31 to 40 lamps, 41 to 60 lamps and 61 to 100 lamps") is insufficient because it does
4 not provide a sufficient number of options to properly account for the range of options in LED
5 lights. Instead, the proposed rates each represent only one specific and fixed set of values
6 corresponding to a single hypothetical LED light.
7 Additionally, it is important to note that the pace of advancement of LED technology is
8 such that, even within the next year, the performance and available options for LED lights may
9 change significantly. These factors significantly affect both the energy cost and non-energy cost
10 of LED lights, thus impacting the appropriate rates for their use. Since LED lights cannot be
11 categorized in the same manner as traditional outdoor lights, MGE's proposed rate structure
12 limits their customer's ability to effectively utilize LED lighting.
13 For a visualization demonstrating the full range of options currently available for outdoor
14 area and roadway LED lights, see Ex.-Clean Wisconsin-Cook-3.
15 Q. How does the energy usage of traditional outdoor lighting technologies compare to
16 LEDs?
17 A. Traditional outdoor lights are generally based on high intensity discharge (HID)
18 technology. These lights, including high-pressure sodium (HPS), low-pressure sodium (LPS),
19 mercury vapor (MV), and metal halide (MH) lights, rely on a translucent bulb filled with gas and
20 metal salts. This bulb is penetrated by electrodes, between which an electrical arc is formed,
21 creating a plasma from the metal salts that gives off light. High-performing HPS lamps can
22 produce as much as 150 lumens of light per watt. In order to both start and maintain the electrical
23 arc in a HID bulb however, an external ballast is also needed. Additionally, since HID bulbs
Direct - Clean Wisconsin - Cook - 5 1 produce light in all directions, reflectors and lenses are often needed to produce the lighting
2 distribution required. When ballast and other losses are considered, HID luminaires typically
3 produce between 60 and 80 lumens per watt. This has historically made them the most efficient
4 technology for outdoor lighting. However, whereas HID lighting technologies are relatively
5 mature at this point, LED technology has been advancing at a rapid pace.
6 LED technology is in some ways much more straight-forward than HID technology; they
7 create light simply by running electrical current through properly prepared semiconducting
8 material. The individual LEDs (commonly referred to as "lamps" or "packages" to distinguish
9 from the complete light, or "luminaire") thus emit colors that are then either mixed or altered
10 through the use of a phosphor to create white light. These individual white LED lamps have the
11 potential to provide the same amount or more light output with less energy than HIDs. For
12 example, Cree Inc. (a major LED manufacturer) has reported LED packages in research and
13 development producing 254 lumens per watt. Like HID lights however, a number of other
14 components go into creating a complete LED luminaire. A typical LED luminaire includes
15 multiple LED lamps, one or more lenses, a driver (to transform the available alternative current
16 electricity into the necessary direct current), a heatsink, and a housing. The resulting complete
17 luminaires are still more efficient than HID luminaires however, with current commercially-
18 available outdoor lighting products producing almost 100 lumens per watt.
19 Q. Please provide an example of the rate of advancement in LED technology, and
20 describe how it impacts appropriate rate structures for LED lights.
21 A. In 2005, CREE lighting reported the highest efficiency LED in research and
22 development, producing 65 lumens per watt. In November of 2008, they reported a package
23 achieving 161 lumens per watt, and the mark of 254 lumens per watt was announced in April of
Direct - Clean Wisconsin - Cook - 6 1 2012. This pace of this advancement is such that the marketplace for outdoor LED lights
2 contains a wide range of performance levels at any given time (see Ex.-Clean Wisconsin-Cook-
3 3), with new products becoming available on a regular basis. As a result, any number of LED
4 lights could be ·chosen to meet situational needs, with varying performance levels and costs.
5 Inflexible rate structures are therefore inappropriate for LEOs because the electrical and non-
6 energy costs of their installation and use can vary greatly, both due to differences between
7 specific products considered at a given time, and due to changes in the LED marketplace over
8 time. Instead, unmetered LEOs should be billed based on calculations that consider the cost and
9 energy use parameters specific to a given customer.
10 Q. Are there other potential advantages of LED lighting as compared to traditional
11 outdoor lighting technologies?
12 A. Yes. LED lights have the ability to maintain or improve visibility and other aspects of
13 lighting performance with less total light output than traditional sources. For example, unlike
14 HID lamps, LEOs are inherently directional (shine in a particular direction), allowing more
15 precise control over lighting distribution and less wasted light. The quality of the light itself
16 produced by LEOs can also be significantly superior to traditional lighting technologies,
17 including in color rendering, color temperature, and color spectra. In addition, there can be
18 improved visibility under LED lights even as total illuminance levels measured in a conventional
19 (photopic) fashion are decreased - again allowing for decreased energy usage as less bright
20 LEOs are required compared to other technologies. This is because traditional measurements for
21 specifying outdoor lights do not treat LEOs the same as some other technologies. Traditional
22 lighting measurements are based on how our eyes work in bright conditions, which are different
23 than the nighttime conditions when outdoor lights are actually used. LEOs can perform much
Direct - Clean Wisconsin - Cook - 7 1 better than traditional outdoor lights because the light they produce is more easily perceived in
2 dark conditions (it has a higher "scotopic/photopic ratio").
3 Q. How should LED lighting rate structures account for these differences in lighting
4 characteristics between traditional outdoor lighting technologies and LEDs?
5 A. Like other aspects of LED light performance, these color, distribution, and
6 scotopic/photopic characteristics can vary significantly between specific products. As a result,
7 the specification of LED lights is most appropriately done on a site-specific basis to match
8 lighting needs. The structure that MGE has proposed, based on traditional outdoor lighting
9 technologies, creates a very limited set of rates for LED lights, artificially setting assumptions
10 and performing calculations based on categories that do not exist. This would result in
11 preventing MGE's customers from being properly billed for and using LED lights that best meet
12 their needs.
13 Q. Are there other technical differences between LEDs and conventional outdoor
14 lighting technologies that are relevant to this case?
15 A. Yes, there is one other critical factor that affects how LED lights should be billed: as
16 opposed to HID lights, which are simply either on or off, LED lights can be dimmed either
17 continuously or step-wise through a range of power levels. This allows users of LED lights to
18 instantaneously match changing lighting needs, thereby saving energy when less light output is
19 needed. For example, LED lights can be managed to utilize lower power settings during dusk
20 and dawn (when ambient light supplements the light produced by outdoor lights), or during times
21 when traffic is lighter (reducing required lighting levels). This can be done on a scheduled basis,
22 or through the use of technologies such as photocells, motion sensors, or networked controls.
Direct - Clean Wisconsin - Cook - 8 1 This increased level of management has been successfully demonstrated in a number of
2 situations, with corresponding energy savings as well as security, perception, and lighting
3 benefits. For example, in a West Sacramento parking lot demonstration, installed LED lights
4 were connected to motion sensors. This allowed the lights to be at a lower power setting (using
5 approximately 1/3 of the full power setting) nearly half of the time, for an average power usage
6 of roughly 70% of the full rated power of the LEOs, with employees indicating that the parking
7 lot both looked brighter and felt safer than under the previous metal halide lights.
8 Proper rate structures that enable the use of varying power levels are necessary to enable
9 these energy saving and management benefits of LED lighting.
10 Q. Please describe any significant potential impact to ratepayers from not adequately
11 accounting for the differences between LED lights and traditional outdoor lighting
12 technologies.
13 A. As discussed both here and in the testimony of Mr. James, LED lights can provide a
14 number of advantages to consumers over traditional lighting technologies. These include reduced
15 energy and maintenance costs, better lighting quality and control, and improved durability and
16 longevity. As a result, there is a significant consumer demand for LED lighting. Without LED
17 rate structures however, consumers are not able to install LED lights in unmetered locations such
18 as along streets and roadways, or in parks. Because of these, Clean Wisconsin strongly supports
19 the addition of LEOs to MGE' s OL-1 rate schedule.
20 However, if the differences between LEOs and traditional lights discussed here are not
21 taken into account, customers will be improperly billed and remain unable to realize the benefits
22 of LED lights. In particular, by setting as fixed erroneous assumptions regarding energy usage,
23 the rate structure that MGE has proposed will unfairly transfer any savings beyond those
Direct - Clean Wisconsin - Cook - 9 1 assumed from customers to the utility. Additionally, the rate structure proposed by MOE does
2 not allow customers to choose the LED lights appropriate for their needs, and thereby restricts
3 customers' ability to benefit from the use of LED lights. This is especially important since MOE
4 is proposing to remove metal halide lights from OL-1, thereby leaving LED lights as the only
5 remaining option for customers desiring efficient, high color temperature, and high color
6 rendering lights.
7 If MOE's proposed rates for LED lights are adopted, and thereafter set precedent for
8 other utilities, they will severely limit customer choice throughout the state, as well as restricting
9 the potential to realize energy and financial savings from this technology.
10 Q. Please provide a brief overview of the potential for LED lighting technology in
11 outdoor applications.
12 A. While LED lighting technology has been used commercially since the late 1960's, it was
13 originally limited to a range of niche applications. Since the 1960's however, LED development
14 has followed a trend commonly known as "Haitz's law" in which every 10 years the cost of
15 LEDs has decreased by approximately a factor of 10, and the amount of light from a single LED
16 package has increased by a factor of 20 (although recently, white LEOs have exceeded this rate).
17 As a result, with the recent advent of low-cost, high-efficiency white LEOs, the technology has
18 quickly reached the point where it can effectively be used for general lighting purposes.
19 Due to its advantages over conventional technologies, consumer demand for LED
20 lighting is such that its market share is rapidly increasing. This is especially true in outdoor
21 applications, which are particularly suited to LED lighting. Indeed, it is estimated that by 2025,
22 LEOs will comprise over 80% of outdoor lighting sales, resulting in sector-wide energy savings
23 of 40%.
Direct - Clean Wisconsin - Cook - 10 1 Q. Do you agree with MGE's cost assumptions for calculating LED rates?
2 A. No. The assumed values used in the calculation of rates are incorrect. In particular, the
3 following values are of concern: monthly kWh per lamp, including LED fixture watts and
4 operating hours; LED fixture costs; LED manhours to install; and OH#6 Duplex requirement and
5 manhours to install. MGE assumes, and would set as fixed through their proposed rates, that
6 LED replacement lights for HPS lights would use a set amount of electricity based on the power
7 of the light replaced. (Ex.-Clean Wisconsin-Cook~ I) As previously discussed, the light output of
8 different LED lights is not necessarily tied to electrical usage. Additionally, LED lights have the
9 ability to vary power consumption during use, a factor that must be considered to allow
10 customers to fully realize the potential benefits of LED lighting. Similarly, by fixing assumed
11 operating hours, MGE's proposed LED rates do not allow customers to schedule lighting to fit
12 their needs.
13 Q. Do you have any other concerns about MGE's cost estimates?
14 A. Yes. MGE also assumes that the cost of LED fixtures will stay constant for the duration
15 of the proposed rates, at values of $507, $575, $767, and $991, for LEDs to replace 70-, 150-,
16 250-, and 400-watt HPS lights respectively. (Ex.-Clean Wisconsin-Cook- I) However, in late
17 2008, LED replacements for 100-watt HPS lights cost as little as $310-400 on a bulk-rate basis.
18 And as previously noted, LED costs have been decreasing rapidly as the technology advances,
19 and new outdoor streetlights are projected to sell for less than $200. If this cost ($200) is
20 assumed to only be valid for a repiacement LED in MGE's the 70 watt HPS category, it is a
21 reduction of $307- or over 60%- from MGE's assumptions. Applying this 60% cost correction
22 to the rate calculations that MGE performed would reduce the rates for monthly non-energy costs
Direct - Clean Wisconsin - Cook - 11 1 by $2.50, $2.83, $3.77, and $4.88, for the LEDs to replace 70-, 150-, 250-, and 400-watt HPS
2 lights respectively.
3 MGE' s assumption of 2.5 manhours (Ex.-Clean Wisconsin-Cook -1) to install an LED
4 streetlight is also questionable, as my research has shown that even inexperienced workers can
5 install new LED streetlights in 1.5 manhours including travel time. It is reasonable to assume
6 that this time will be further reduced as technical familiarity with LED lights grows.
7 Conservatively assuming the 1.5 manhours required to remain constant however, the estimated
8 per-fixture installation cost should still be reduced by $84.36, and the corresponding rate for
9 monthly non-energy costs by $0.69.
10 MGE also has proposed to set as fixed an assumption in their proposed LED light rates of
11 135 feet of overhead duplex line installed (requiring 4 manhours) for each light installed. (Ex.-
12 Clean Wisconsin-Cook-1) However, the majority of LED streetlights going forward will be
13 installed on a retrofit basis, taking the place of existing fixtures, meaning that no additional line
14 will be required. Additionally, it is unclear whether MGE has "double-counted" some costs of
15 installation, such as travel time when overhead line is installed in conjunction with the
16 installation of LED fixtures, as well as the "time to install the bracket and fixture." (Ex.-Clean
17 Wisconsin-Cook-4.) Even an overly conservative assumption of 50% new installations, at the
18 full rate quoted by MGE, would reduce the estimated per-fixture installation cost by $190.74,
19 and the corresponding rate for monthly non-energy costs by $1.55. Alternately, and more
20 appropriately, customers could be billed a separate rate amount if and only if significant
21 additional installation costs are needed.
22 Finally, the "Proposed Calculated Monthly Rate" values provided by MGE were
23 increased by various factors ranging from 2.40% to 11.42% to arrive at MGE's final "Proposed
Direct - Clean Wisconsin - Cook - 12 1 Rate" values (See Table 1 and Ex.-Clean Wisconsin-Cook-S). There is no justification for this
2 increase, since the Proposed Calculated Monthly Rates already account for all costs to MGE,
3 including MGE's proposed increased distribution and electrical rates, as well as a carrying
4 charge based on MGE's approved cost of capital.
5 Table 1: Calculated monthly rates vs. proposed rates
MGE "Proposed MGE "Proposed Increase- "Proposed Calculated Calculated Monthly Rate" Rate" Rate" to "Proposed Rate" $0.32 30 Lamp LED $13.48 $13.80 (2.40%) $0.59 40 Lamp LED $15.01 $15.60 (3.94%) $1.68 60 Lamp LED $17.62 $19.30 (9.53%) $2.46 100 Lamp LED $21.54 $24.00 (11.42%) 6 While noting that MGE's rate proposed rate structure is not appropriate for LEDs, as
7 previously discussed, Ex.-Clean Wisconsin-Cook-6 demonstrates the effect of using these
8 revised but still conservative assumptions to correct MGE's calculations.
9 As previously discussed, LED rates should instead be calculated based on fixture
10 wattages, operating schedules (both hours and power levels), and actual installed costs, but these
11 values should correspond to the circumstances specific to each customer.
12 Q. How should rate structures be set to properly bill for unmetered LED outdoor
13 lighting?
14 A. Since there is so much variability in LED lights, it is not appropriate to categorize them
15 into a limited number of sizes comparable to HID lights, and thereafter to set fixed rate options
16 based on pre-calculated values. Instead, flexibility must be maintained to allow for the use of a
17 wide range of different LEDs for each application. The best way to do this is to simply provide
18 an open-ended rate, based on a "monthly rate per fixture calculation" as in Schedule SL-1:
Direct - Clean Wisconsin - Cook - 13 Fixture Wattage x Burning Hours) Electricity Service)! Distribution Monthly Non- x 12 (( 1,000 Charge per kWh + Servtce . Charge + Energy Charge
1 Since these lights are unmetered, the rates would be calculated based on fixture wattages,
2 operating schedules (for both hours and power levels), and actual installed costs. Critically, these
3 values must correspond to the circumstances specific to each customer. This is as opposed to a
4 fixed, category-based rate as proposed.
5 Q. Have other utilities successfully adopted rate structures similar to the one you
6 propose?
7 A. A calculated rate approach has been adopted for utilities including the Public Service
8 Electric and Gas Company of New Jersey, the Consolidated Edison Company of New York, and
9 Detroit Edison of Michigan.
10 Other utilities have adopted rates structures in which rates are pre-calculated as for
11 traditional lighting technologies, but in which a much larger number categories are calculated for
12 LEDs, to make them more sufficient to account for the unique characteristics of LEDs. For
13 instance, the Pacific Gas and Electric Company (PG&E) of California provides rates for LEDs
14 with electrical demands ranging from 0 to 400 watts, broken into 5-watt incremental ranges. For
15 example, a 167-watt LED light would be charged at the "165.01-170.00" rate, based on the total
16 consumption of the lamp and driver (if external), using the calculation:
17 Energy use= (high wattage in range-2.5 watts) x (4,100 hours/12 months/1000)
18 While this rate schedule also provides for adjustments based on differing schedules, it
19 does not allow for the usage of LED lights at varying power levels, and thereby removes one
20 significant benefit of LED lighting. It should be noted however, that PG&E does have a pilot
21 program to provide unmetered service for network-controlled dimmable streetlight systems.
Direct - Clean Wisconsin - Cook - 14 1 Other utilities that have taken a similar approach to PG&E also include Southern California
2 Electric, and San Diego Gas and Electric.
3 Q. Are there any other changes that would be necessary to allow MGE's ratepayers to
4 successfully utilize LED outdoor lighting?
5 A. Yes. The use of outdoor LED lights should not be limited to the "Security Flood
6 Lighting" category, but also be added to the category of "Dusk-To-Dawn Yard Lighting" in rate
7 schedule OL-1, as well as added to rate schedules SL-1 (MGE-owned and -maintained
8 streetlights), SL-2 (customer-owned and -maintained streetlights), and SL-3 (customer-owned
9 and MOE-maintained streetlights). There is no technical limitation for the use of LED outdoor
10 lights as streetlights, or distinction between their uses as outdoor security lights, that would
11 warrant their exclusion from these rate schedules.
12 For use in all of these rate schedules, LED lights may be billed the same distribution
13 charges as other lamps. Monthly facility charges (for SL-1) should reflect to the actual cost of
14 installed equipment, and monthly maintenance charges (for SL-1 and SL-3), should reflect the
15 maintenance charges calculated by MGE for rate OL-1 ($1.21 on an annual basis).
16 Q. Please provide an overview of the appropriate rate structures for unmetered LED
17 lights, and an example of each.
18 A. For each rate schedule, unmetered LEDs should be billed a distribution charge, and a
19 monthly electrical charge based on fixture wattages, operating schedules including both hours
20 and power levels, and an electrical service charge per kWh. Monthly non-energy charges should
21 include actual installed costs specific to each customer when fixtures are owned by MGE (OL-1
22 and SL-1) and maintenance costs when fixtures are maintained by MGE (OL-1, SL-1, and SL-3).
23 For specific calculation equations and examples, please see Ex.-Clean Wisconsin-Cook-7.
Direct - Clean Wisconsin - Cook - 15 1 Q. Does this conclude your testimony?
2 A. Yes.
Direct - Clean Wisconsin - Cook - 16 PS F#:l70847
'tlg. 1 BEFORE THE 1-' :>:1 .... to:! 0 2 PtJBLIC SERVICE COMMISSIOI\ OF WISCONSIN 0 to:! til 3 H (!) ~ li to:! <: 4 Application of Madison Gas and Electric Company for 3270-CR-118 tl .... •• 0 5 Authority to Change Electric and Natural Gas Rates ro 0 OO(l 6 "-0 7 ,::;~ .... 1--' Ill N Ill 8 TESTIMONY OF DAVID POKLINKOSKI ' .... 0 9 ON BELHALF OF THE INTERNATIONAL BROTHERHOOD OF ELECTRICAL "'::1 N 0 10 WORKERS LOCAL 2304 f-'l"h 11 12 13 Q. Please state your name and title.
14 A. My name is David Poklinkoski. I am the President and Business Manager of the
15 International Brotherhood of Electrical \Vorkers (IBEW) Local2304. I also work at
16 \:1adison Gas and Electric Company (MGE) in the Materials Management department as
17 a Storekeeper.
18 Q. What is your educational background and experience?
19 A. I attended the University of Wisconsin-Madison from 1973 to 1978. I was elected to be
20 the President and Business Manager of IBEW Local 2304 in the fall of 1985 and have
21 served in this capacity to this day. I served as an IBEW Local 2304 Steward from 1980
22 to 1985. I have been employed by MGE since 1978 in various operational and
23 maintenance capacities. I have previously testified before the Commission in MGE rate
24 cases and on utility restructuring issues on behalf of IBE\V Local 2304. As the elected
25 Secretary of the Utility Workers Coalition (t:WC) since its inception in 1992. I have also
26 assisted in drafting comments on behalf of the UWC in various Commission dockets
27 regarding gas and electric industry structure and service needs. including the Strategic
28 Energy Assessment (SEA). During the existence of the IBt: w·s International
Direct-IBEW-Poklinkoski-1 1 Restructuring Committee ( 1995-2005). I served as a representative from the IBEW Sixth
2 District (a region that comprises much of the Midwest).
3 Q. What is the purpose of your testimony in this proceeding'?
4 A The purpose of my testimony is to address the question: \vhat. if any. comprehensive
5 work force plan is reasonable and. thereby. what impact does this hm eon the applicant" s
6 revenue requirement for electric and natural gas sen ice? The need f{)r such work t(m.:c
7 planning has been addressed and established in previous \1GE rate cases as well as in the
8 ··,)'traleRic l:'nergy Assessment 2012. Final Report... Consequently. this testimony will
9 not belabor those points previously made. We \vilL however. look at some specific
10 elements of work force planning at MGF and their impact on the revenue requirement.
11 Q. Has the lBEW engaged in any re\·iew or discussion of work force planning with
12 the applicant'!
13 A. The parties met August 24. 2011 in a Joint Labor/\-1anagement Committee meeting to
14 address a number of important issues and among them was a review of the staffing and
15 work i(Jrce needs ofMGE. F:x.-IBEW-Poklinkoski-1 is part of a document that we
16 prepared for that meding and the raw data for that document was provided to the IBEW
17 by MGE. The breakdown of the numbers on this document was undisputed and they
18 sene as a demonstration of the work force necessary to get the work done at MGE to
19 provide the level of service our customers have come to expect from our gas and electric
20 utility.
21 Q. Does the IBEW have more current specific staffing numbers, for example; numbers
22 for work in 2012 or for projected work in 2013?
Direct-IBEW-Poklinkoski-2 1 A. :\o. we do not. Ilowever. it is our understanding that there will be little change in the
2 overall staffing numbers in the IBEW/MGF work force for 2012 or 2013. There hav~:
3 been e!Torts and discussions aimed at ··taking our work in-house'' which is prudent for a
4 number of reasons that are raised in the ··Talking Points" in our exhibit. This is a good
5 thing. There is concern. hm\evcr. that there are structural limits to success in this effort
6 given that this added \\ork docs not correspond to any apparent additional starting of
7 IBEWIMGE employees. As you can sec by the numbers in the exhibit. there is a
8 significant k\cl of IBEW/MGE work performed by \cndors and contractors and this is a
9 work load that cannot be absorbed \vith current IBE\\' lMGE stat!ing levels. It should
10 also be noted that this is a particular staffing structure and lew! of work that \\as
11 occurring in some of the worst economic conditions faced by our nation since the 193()' s.
12 Those general economic conditions are unlikely to change much from 2011 through
13 2013.
14 Q. In your exhibit you have identified a category entitled "Short year round". Could
15 you please explain the significance of that?
16 :\. Since the early to mid-1980's MGE. along with much of the investor-owned utility
17 industry. began to move from a what was referred to as a .. fire department'" slatTing mode
18 to one where they tried to find a lower permanent staffing level and then proceeded to
19 contract t(lr the work that represented the .. peaks .. of the \vork load. This was a so-called
20 .. peaks and valleys .. staffing model. This was a significant change in the industry. The
21 industry. individually and collectively. under-shot that lovver level and found statling cut
22 not just to the .. bone .. but actually into the .. marro\\ ... This process and tendency was
23 also mediated by the drive to deregulate the utilities in the 1990's and well into the
Direct-IBEW-Poklinkoski-3 1 200()" s. \:1GE. too. \vent down this road but conected this problematic course: others
2 have not. Once proper staffing levels arc lost. corrections to the sustaining or u
3 prudent level of a skilled labor force do not happen overnight. Hm:vever. if a
4 company was prudently staning for peaks and valleys. then where there arc contractors
5 on the propcrt) on a year-round basis. that work \vould better serve our community and
6 our customers by being done .. in-house··. This document has identified those numbers.
7 Q. Has the Commission previously addressed the issue of an incumbent utility's work
8 force in relation to the use of outside contractors'?
9 A. Yes. In Docket 3270-UR-115 the Commission. in its Final Decision found that. .. \1GE"s
10 management should also evaluate whether any cost savings resulting from replacing
11 outside contractors with permanent employees could offset any increased comprehcnsi\e
12 workplace planning costs:· Whether the Commission· s direction was a factor or not.
13 MGE made a concerted eH 14 \,1ost of those young men. many of whom were hired from our community. han: 15 successfully progressed to .. Journeyman"' status today. 16 Q. Do you see additional opportunities to do a similar project with line technicians and 17 other areas of work at MGE? 18 i\. Y cs. The record evidenced in our exhibit clearly dcmonstrates the need to build on this 19 successful approach to efllciently serving our customers. We understand that large 20 infusions ( 12~,;) to 20%) of potentially untrained workers into our relatively small labor 21 hwce can he difficult even from a safety standpoint: however. any prudent comprchensiv..: 22 work fon.:..: plan would take steps in the direction of replacing year-round outside 23 contractors. Instead of hiring and training an outside contractor labor force. \1Gl· should Direct-IBEW-Poklinkoski-4 1 imcst in IBEW/\·1GE utility \\Orkcrs who are in our community and committed to 2 serving our community. IBEW/MGE workers are the ones with the obligation to serve: 3 not the outside contractors. 4 Q. Other than from an efficiency and service standpoint, are thue other reasons to 5 develop the utilit:y's in-house work force'? 6 .\. The gas and dectric utility industry is lacing a skilled labor shortage and the outside 7 contractors \\ ho serve the utility industry are in th.:- sam.:- boat. For example. thl.:'r.:- is a 8 huge demand for journeyman line technicians and the outside contractor crews that were 9 available yesterday will not be available tomorrow. There arc major distribution and 10 transmission projects either underv..ay or soon to be launched that make these skilled 11 workers unavailable in the quantity or quality that MGE has once enjoyed. 12 Q. Does MGE have to increase its revenue requirement for electric and natural gas 13 service to accommodate comprehensive work force planning in this I>ocket'? 14 A. ~o. It would not be reasonable to raise the re\enue requirement because of the 15 efficiencies and other cost savings related to taking the work in-house. What is required 16 is a work f(lrce plan that shifts from th~: investing in and the hiring of a contractor labor 17 force to one that imests in and hires a work f{)rcc at the utility. In the process all of the 18 advantages that are outlined in our exhibit can be realized. Further. the Commission and 19 MGE can provide not just good sustainable jobs but also careers in serving our 20 communit\ at a time \:vhen our economy is struggling for some positive direction. It is 21 a rare opportunity that we can increase good jobs without realizing imprudent costs. 22 Therefore. the Commission need not raise the revenue n:yuin:rnent by raising the Direct-IBEW-Poklinkoski-5 1 IBEW 1\1GL staffing le\ ds as it r~placcs th~: ear-round outsid~ contractors who ar~ 2 p~rforming essential IBEW!MGE work. 3 Q. What, if anything, should the Commission do on the work force planning issue if 4 there is no need to raise the reHnue requirement'? 5 :\. The Commission should do no kss than \\hat it had done in 3270-L'R-115. !he 6 Commission should. at least. provide firm encouragement to r·v1GE to continue to make 7 progress on this work f(Jrce planning issue and prudently replace identifiable y~ar-round 8 outside contractors with pennancnt cmploy~es of the utility. 9 Q. Docs this conclude your testimony'? 10 A. Yes. 11 Respectfully submitted on this 27th day of August. 2012 12 By: 13 14 15 David A. Poklinkoski 16 President and Business Manager 17 lBEW Local 2304 18 1602 South Park Stred. Room 10 l 19 Madison. WI 53715 20 21 Email: ihew2304 £/att.nct 22 Otticc: 608-256-8896 23 Cdl: 608-770-8896 24 Fax: 608-256-8496 Direct-IBEW-Poklinkoski-6 PSC REF#:l70892 BEFORE THE PUBLIC SERVICE COMMISSION OF WISCONSIN Application of Madison Gas and Electric Docket 3270-UR-118 Company for Authority to Change Electric and Natural Gas Rates DIRECT TESTIMONY OF JOHN HARROD ON BEHALF OF THE BOARD OF REGENTS OF THE UNIVERSITY OF WISCONSIN SYSTEM Q. Please state your name and business address. 2 A. John P. Harrod, Jr., 1217 University Avenue, Madison, Wisconsin 53706-1589. 3 Q. By whom are you employed and in what capacity? 4 A. University of Wisconsin-Madison. Director of Physical Plant- Facilities Planning and 5 Management. I have been employed in this position for 21 years. 6 Q. Please state your educational background and work experience. 7 A. Bachelor of Science- Landscape Architecture, from Iowa State University. Over 42 8 years of facility management experience in the higher education arena. 9 Q. What is the purpose of your direct testimony in this proceeding? 10 A. The purpose of my testimony is to provide background information regarding UW's 11 energy needs, its relationship with Madison Gas and Electric Company ("MGE") 12 regarding West Campus Cogeneration Facility ("WCCF"), and UW's future energy 13 plans. DIRECT-UW SYSTEM-HARROD-I 1. Overview of UW District Energy System 2 Q. Please describe UW's district energy system. 3 A. The UW Campus district energy system provides steam, chilled water, cogenerated 4 electricity and compressed air. The district energy system is composed of three major 5 facilities (1) Charter Street Heating Plant ("CSHP"), (2) Walnut Street Heating Plant 6 ("WSHP"), and (3) WCCF. The system is operated as an integrated district energy 7 system with multiple boilers, chillers, and compressors, and one steam turbine generator 8 ("STG") to serve the UW load for each of those energy needs. 9 The CSHP delivers heating (steam at 175 psi and 13 psig) and cooling to the 10 campus and also generates about 9 megawatts ("MW") of electricity via a back pressure 11 steam turbine generator. The CSHP is in the midst of a $188.3 million construction 12 project. This project will remove the existing coal-fired boilers and replace with four 13 gas/oil fired boilers, each rated at 225,000 pounds per hour (lb/hr). The project will also 14 provide a new water treatment system and mechanical, electrical and control system 15 replacement and upgrades. The CSHP will be completed in the fall of2013. 16 WSHP is located adjacent to WCCF on the west side of the Campus producing 17 steam at 175 psi from three gas/oil-fired boilers. No electricity is produced at WSHP. 18 The WSHP steam output is utilized for steam turbine-driven chillers, and is 19 interconnected into the UW Campus steam system for space heating and process 20 purposes. In addition, a new electric-driven chiller was installed in the fall of 2010 at 21 WSHP. The chillers produce chilled water for distribution throughout the UW Campus 22 for building air conditioning. 23 WCCF is jointly owned by an MGE affiliate, MGE Power (56%) and UW (44%) 24 and consists of (1) a combined cycle cogeneration system that produces approximately DIRECT-UW SYSTEM-HARROD-2 150 MW of electricity for MGE customers and 400,000 PPH of steam output for Campus 2 distribution, and (2) a four-unit electric-driven chiller system (approximately 17 MW) 3 that produces chilled water, also for Campus distribution. The combined cycle 4 cogeneration system consists oftwo approximately 60 MW STG gas-fired combustion 5 turbines with the hot exhaust gas fed into heat recovery steam boilers that in turn feed 6 steam into an approximate 45 MW STG. 7 Under the Joint Ownership Agreement, MGE has the right to WCCF electricity 8 and UW has the right to WCCF steam and chilled water output. UW can call on WCCF 9 for firm steam production during winter months from October 16 through April 14 and 10 interruptible steam service for non-winter months when WCCF is dispatched by the 11 Midwest Independent System Operator ("MISO") to produce power. UW is not required 12 to take the steam produced by WCCF during MISO-dispatched operations but usually 13 does due to discounted steam price. 14 The four UW-owned chillers co-located at the WCCF are rated 5,000 tons per 15 hour. These chillers use Station Service electricity and are not charged Sp-3 demand 16 charges. As a co-owner of the facility that includes electric facilities, UW was entitled to 17 electric output to serve these chillers without paying MGE for capacity charges. Among 18 the considerations for UW's approximate $90 million investment in WCCF, MGE and 19 UW agreed that the facility chillers would be supplied by Station Service which was 20 defined to be the production cost of electricity. 21 A summary-level description of the UW Campus district energy system is 22 included as Ex.-UW System-Harrod-1. The information presented in this Exhibit was 23 updated from UW's most recently issued "Utilities Master Plan Report". DIRECT-UW SYSTEM-HARROD-3 Q. What is happening at CSHP? 2 A. UW is in the process of rebuilding the CSHP plant to extend its life another 50 years. 3 The CSHP Rebuild Project will replace three existing coal-fired boilers with four new 4 natural gas I oil-fired boilers. Two boilers were installed in late 2011 and two boilers are 5 being installed in 2012; all feeding into the existing 600 psig common header. The CSHP 6 Rebuild Project is planned to be complete in 2013. At that time the UW will still rely 7 heavily on MGE to serve UW electricity loads during peak and intermediate load periods. 8 Q. What else is UW undertaking to manage Campus energy needs? 9 A. The CSHP Rebuild Project is part of an ongoing set of activities to reduce energy 10 demand, cut costs, improve boiler efficiency, and improve the environmental impact of 11 the UW Campus, while continuing to provide a reliable source of heating and cooling for 12 campus facilities. Those activities include "We Conserve"-a campus-wide initiative to 13 reduce energy consumption and enhance the environmental footprint. 14 Other major UW goals are to capture cogeneration efficiency benefits from both 15 electricity and steam production, improve Campus system reliability, and replace aging 16 equipment for a 50-year remaining life. 17 Q. Can you discuss the general reliability of the Charter Street electric generation 18 capability? 19 A. The CSHP Rebuild Project is going a long way to improve not only the reliability of the 20 steam and chilled water operations but also improve electric generation reliability. When 21 complete, the five boilers (four new and one existing natural gas fired) will be equipped 22 with a state-of-the-art digital control system capable of precise load control and quick 23 reaction to potential upset conditions. High pressure steam (600 psig) from these boilers DIRECT-UW SYSTEM-HARROD-4 drives the steam turbine coupled to the electric generator. Early in 2012 the high pressure 2 steam piping to the steam turbine was modified to eliminate a restriction that limited the 3 maximum electrical output of the generator. In the fall of 2012 the digital control system 4 will be expanded to control and monitor the steam turbine generator package. As stated 5 above, one of the major goals is to improve Campus system reliability, and the electric 6 generation reliability is no exception. 7 Q. Do variations in CSHP electric generation output mean that it has not been reliable? 8 A. A casual observer might think that the CSHP STG was not reliable because the metered 9 output of the STG varied significantly by season, month, week, day and hour. However, 10 this is due in part to the UW Campus steam system economic dispatch. While the CSHP 11 STG has relatively high availability, it is not always dispatched because the 600 psi steam 12 supply to its inlet is not enough to produce full output of 8.0 MW. 13 As discussed previously, UW Campus 175 psi steam system is an interconnected 14 system of steam pipes to provide highly reliable looped feeds to Campus buildings. UW 15 is required by State statute to economically dispatch its energy production resources to 16 meet its load. Wis. Stat. § 16.92(2). UW steam system has two ends: East at CSHP and 17 west at WCCF and WSHP. Each end of the system needs to maintain constant pressure 18 into the 175 psi distribution system for reliability and pressure stability. During light 19 load periods or periods when the WCCF generation is running and WCCF is producing 20 steam, the CSHP STG is fully available but operating at low loads due to low CSHP 21 boiler output. DIRECT-UW SYSTEM-HARROD-S Q. What impact will the elimination of coal utilization have on the utilization of the 2 CSHP STG in the fall of2013? 3 A. As part of the CSHP Rebuild Project, two new 225,000 PPH gas/oil boilers were installed 4 at CSHP in the fall of2011. With these new boilers in service, the existing coal-fired 5 boilers have been retired and all coal use at CSHP has ended. At this point in time, the 6 UW Campus steam production is 100% fueled by natural gas/fuel oil. This change will 7 not, on its own, create a large change in STG utilization. Assuming continuation of the 8 current Sp3 rate design, which is not recommended by UW, the STG annual capacity 9 factor may drop somewhat, but will still be well above 50%. 10 2. WCCF 11 Q. Were you involved in discussions with MGE that resulted in the construction and 12 operation of the WCCF? 13 A. Together with other UW officials and consultants, I was personally involved in 14 discussions that resulted in the agreements between UW and MGE regarding the WCCF. 15 Q. At that time did UW and MGE enter an Agreement regarding the cost of electricity 16 to operate chillers at WCCF? 17 A. UW and MGE agreed that the cost for electricity to operate chillers at WCCF should not 18 include capacity charges, but be based on the production cost to generate electricity at the 19 facility. The parties signed a Back Up Service and Station Service 20 Agreement on October 1, 2003, which was approved by the Commission in the Final 21 Decision in docket 5-CE-121. A copy ofthe Back Up Service and Station Service 22 Agreement is marked as Ex.-UW System-Harrod-2 and the Final Decision is marked as 23 Ex.-UW System-Harrod-3. The parties subsequently entered a February 15, 2006 DIRECT-UW SYSTEM-HARROD-6 Memorandum of Understanding (MOU) that sets out terms regarding the price of 2 electricity to operate WCCF chillers when the generators are not producing electricity. A 3 copy ofthe MOU is marked as Ex.-UW System-Harrod-4. 4 Before February 16,2012, when WCCF was producing electricity, UW was 5 allocated WCCF fuel and O&M cost for chiller operations; when WCCF was not 6 operating, but available to operate, UW was charged the Sp-3 energy rate; and, when 7 WCCF was not available to operate, UW was charged the MISO Locational Marginal 8 Price ("LMP") plus 10%. LMP is the marginal (i.e., highest) wholesale energy price for 9 the MGE delivery points from the ATC transmission system. During most of the summer 10 air conditioning season when MISO dispatches the WCCF generators, the WCCF electric 11 chillers are the least expensive source of chilled water and operate constantly. 12 While UW has paid the SP-3 energy rate, the WCCF chiller load has never been 13 included in the determination of the customer maximum or the maximum on-peak 15- 14 minute demand under the Sp-3 tariff. Furthermore, UW is billed separately for WCCF 15 chiller electricity which is separately metered by MGE. 16 Q. What has UW done to improve WCCF operations? 17 A. Since WCCF began operation, UW and MGE have amended the O&M Agreement to 18 address procedures at WCCF. On February 16,2012, UW and MGE again amended these 19 procedures in the following respects: 20 • UW agreed to assume financial responsibility for uneconomic dispatch. 21 • UW agreed that WCCF Station Service for chillers be capped at 17 MW. DIRECT-UW SYSTEM-HARROD-7 • UW agreed that electric service for WCCF chiller load beyond 17 MW be 2 provided upon the terms and conditions of the Sp-3 Tariff including the 3 payment of Sp-3' demand charges. 4 • UW agreed to a formula rate for WCCF chiller load up to 17 MW (1) when 5 WCCF is able to operate, but MGE does not operate, and (2) when WCCF not 6 able to operate. 7 Under the terms of the February 16,2012, amendment to the O&M Agreement, 8 UW has the right to elect a proxy rate based on the cost of fuel and a heat rate factor in 9 lieu of the Sp-3 energy rate. A copy of this agreement is marked as Exhibit Ex.-UW 10 System-Harrod-5. The Public Service Commission approved the amendment and entered 11 an Order to this effect on May 2, 2012 (PSC REF# 164707). 12 Q. Does this complete your testimony? 13 A. Yes. 8372250_1 DIRECT-UW SYSTEM-HARROD-8 PSC REF#:l70912 BEFORE THE PUBLIC SERVICE COMMISSION OF WISCONSIN Application of Madison Gas and Electric Docket 3270-UR-II8 Company for Authority to Change Electric and Natural Gas Rates DIRECT TESTIMONY OF ROBERT R. STEPHENS ON BEHALF OF THE BOARD OF REGENTS OF THE UNIVERSITY OF WISCONSIN SYSTEM Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 2 A. Robert R. Stephens. My business address is I6690 Swingley Ridge Road, Suite I40, 3 Chesterfield, MO 630I7. 4 Q. WHAT IS YOUR OCCUPATION? 5 A. I am a consultant in the field of public utility regulation and principal ofBrubaker & 6 Associates, Inc., energy, economic and regulatory consultants. 7 Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND 8 EXPERIENCE. 9 A. This information is included in exhibit Ex.-UW System-Stephens- I to my testimony. 10 Q. ON WHOSE BEHALF ARE YOU APPEARING IN THIS PROCEEDING? II A. I am appearing on behalf of the Board of Regents of the University of Wisconsin I2 System ("UW" or "University"). The University is a large customer of Madison Gas I3 and Electric Company ("MGE" or "Company") taking service under MGE's DIRECT-UW SYSTEM-STEPHENS-I Rate Schedule Sp-3, University of Wisconsin Time-of-Use Rate. As suggested by the 2 name, this rate is used exclusively by UW. 3 Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY? 4 A. I have been retained by the University to address and offer opinion on certain rate 5 design issues. Specifically, I will address MGE's proposed Sp-3 demand charges; its 6 proposed generation credit (and lack of standby rate) for the University's Charter 7 Street Heating Plant ("CSHP"); and the potential for restructuring Sp-3 energy charges 8 to be market-based. 9 Q. PLEASE SUMMARIZE YOUR CONCLUSIONS AND 10 RECOMMENDATIONS. 11 A. These can be summarized as follows: 12 1. MGE's proposed demand charges for the Sp-3 rate are too high. They are 13 set on a "residual" basis to collect the remainder of the allocated revenue to 14 the Sp-3 class that is not collected through other charges. However, 15 because MGE proposes to collect too much revenue from the Sp-3 class, 16 the resulting demand charges are unreasonably high. In addition, the 17 historic level of revenues collected from the Sp-3 class does not adequately 18 credit UW for its capital investment in the West Campus Cogeneration 19 Facility. The final demand charges should be reduced from the Company's 20 proposal in the amount sufficient to reduce the overall class revenue 21 allocation by approximately $1.8 million, in order to eliminate 22 cross-subsidies within current rates, which would be exacerbated under the 23 Company's proposed rates. 24 2. MGE's rate treatment of UW's Charter Street Heating Plant through a 25 modest generation credit is inequitable and inadequate. It does not 26 recognize the full value of capacity and represents a small fraction of the 27 demand charge that MGE would impose on the University. Instead of a 28 rate structure that includes a modest generation credit, a more fair and 29 equitable approach would be to charge the University on a net demand 30 basis (University load only) and to pay a reservation charge for MGE 31 generation that provides standby service to the Charter Street Heating Plant 32 along with a daily standby demand charge for the specific times when the 33 University calls on MGE's supply to back-up its own generating facility. DIRECT-UW SYSTEM-STEPHENS-2 1 In the alternative of modifying the Sp-3 rate in the way I have proposed, 2 MGE should be directed to develop a more traditional standby rate for the 3 University's use, such as those that are offered by other Wisconsin utilities. 4 As a second alternative, should the existing rate structure be retained, the 5 generation credit should be increased dramatically to better reflect the 6 current marginal cost of capacity. 7 3. The University desires to pay energy rates that are reflective of cost and 8 cost is best represented by the current wholesale market. MGE should be 9 directed to work with the University to seek agreement on a more 10 appropriate energy charge that would be the actual hourly wholesale 11 market values (adjusted as necessary) rather than the forecasted average 12 values in MGE's proposed Sp-3 rate. IfMGE and UW are able to reach 13 agreement on an approach for Sp-3 energy charges, MGE should present 14 such proposal to the Commission for consideration by no later than July 1, 15 2013. 16 1. Proposed Sp-3 Demand Charges 17 Q. HAVE YOU REVIEWED HOW MGE HAS DESIGNED THE PROPOSED SP-3 18 RATES IN THIS PROCEEDING? 19 A. Yes, I have. This design is described primarily in the Direct Testimony of MGE 20 witness Gregory A. Boll om, at pages D 1. 73 through D 1. 77. This topic is also 21 addressed in the Direct Testimony of UW witness Craig Weiss. 22 Q. WHICH ASPECT OF THE SP-3 RATE DESIGN DO YOU WISH TO 23 ADDRESS IN THIS SECTION OF YOUR TESTIMONY? 24 A. I wish to address the summer and winter on-peak demand charges. 1 As Mr. Bollom 25 describes at page D 1. 77 of his direct testimony, the demand charges are set in the final 26 step of developing the proposed rates for Sp-3 service by increasing them to offset any 27 change in total revenue from the changes in energy charges, to ensure that the final 28 proposed rates for Sp-3 service still recover MGE's proposed full revenue requirement 1The Distribution Service Demand Charge is proposed to remain unchanged and is not directly an issue. DIRECT-UW SYSTEM-STEPHENS-3 allocation to the Sp-3 class. The changes in energy charges to which he refers are a 2 significant reduction in energy charges from present rates, and are based on the 3 Company's estimates of Locational Marginal Prices ("LMP") for 2013. The present 4 and proposed rates under Sp-3 are shown in MGE Exhibit 1.4, Schedule 1, at page 15 5 of 41 and are summarized as follows. TABLE 1 Primary Charges Under Rate Sp-3 Present Proposed Increase I Rate Component Rate Rate (Decrease} Customer Charge $700 $980 40.0% ($/day) Distribution Service 0.0829 0.0829 0.0% Demand ($/kW-day) Winter On-Peak Demand ($/kW-day) 0.57802 1.03 78.2% Summer On-Peak Demand ($/kW-day) 0.68714 1.13 64.4% Generation Credit ($kW-day) (0.12329) (0.12329) 0.0% Winter On-Peak 0.05925 0.033 (44.3%) Energy ($/kWh) Summer On-Peak 0.0724 0.036 (50.3%) Energy ($/kWh) Off-Peak Energy 0.03948 0.023 (41.7%) ($/kWh) 6 As can be seen in Table 1 above, some charges do not change while other 7 charges vary dramatically, going up by as much as 78.2% or going down by as much 8 as 50.3%. The net effect of all of the proposed changes, as applied to the Sp-3 billing DIRECT-UW SYSTEM-STEPHENS-4 units assumed by MGE,2 is shown on page 16 ofMGE Exhibit 1.4, Schedule 1. As 2 shown, the Sp-3 total proposed revenues to be collected is increased by $1.4 million or 3 4.01% over present revenues, which includes revenues from UW payments for the 4 West Campus Cogeneration Facility ("WCCF") chiller usage when WCCF generation 5 was available but not dispatched by the Midwest Independent Transmission System 6 Operator ("MISO"). 7 Q. DOES THE UNIVERSITY HAVE A SPECIFIC OBJECTION TO THE USE OF 8 LOWER ENERGY CHARGES WHICH ARE BASED ON LMP ESTIMATES 9 FOR 2013? 10 A. My understanding is that UW does not object to this concept. Furthermore, there is 11 sound rate design basis for such a change. 12 As explained by Company witness Bollom, some percentage of the Company's 13 fixed costs, e.g. capacity cost, are recovered through fixed rate elements and the 14 remaining percentage is recovered through variable rate elements, such as energy 15 (page D 1.63). In other words, the present energy charges include some collection of 16 capacity costs. This concept is acknowledged by UW witnesses Weiss and John 17 Harrod. 18 I will address energy charges further in a later section of this testimony. 21 understand that UW witness Weiss addresses the reasonableness ofMGE's assumptions on Sp-3 billing units. DIRECT -UW SYSTEM-STEPHENS-5 Q. WHY IS IT APPROPRIATE TO HAVE REDUCED ENERGY CHARGES 2 THAT MORE CLOSELY MATCH THE COST OF ENERGY IN THE 3 MARKET? 4 A. As Mr. Bollom acknowledges at page 01.63 ofhis direct testimony, it is always most 5 economically efficient to recover the cost of service in a manner that matches the way 6 those costs are incurred. He goes on to explain at page 01.64 the reasons justifying 7 the shift in rate design toward lower energy charges, citing the general industry 8 movement towards sending price signals that more accurately match the cost to serve 9 customers, the confusing nature of the current relationship between rates and costs 10 present in MGE's current rates, the need for better alignment in costs and rates in light 11 of growing customer interest in distributed generation and finally, a competitive 12 advantage in states and utilities with rate structures that better align costs and revenue 13 recovery in attracting new and expanding business. 14 Q. WHAT IS YOUR CONCERN WITH THE PROPOSED CHANGE IN ON 15 PEAK DEMAND CHARGES (SUMMER AND WINTER)? 16 A. Because of the way they are set, along with the functioning of the tariff, the proposed 17 demand charges are too high and would result in too much revenue being collected 18 from the University. Over-collection from the University implies cross-subsidization. 19 Q. HOW ARE THE PROPOSED DEMAND CHARGES SET? 20 A. As mentioned above and explained by Mr. Bollom at page 01.77, the demand charges 21 were increased to offset any change in total revenue due to changes to (i.e., lowering) 22 energy charges, in order to ensure that the final proposed rates for Sp-3 service will 23 still recover the full revenue requirement allocation to the Sp-3 class. In other words, OIRECT-UW SYSTEM-STEPHENS-6 these demand charges are set on a "residual" basis to collect the remainder of the 2 allocated revenue to the Sp-3 class. Residual rate elements are sometimes analogized 3 as a "sponge" used to "soak-up" the allocated revenue requirement not collected 4 through other charges. Under MGE's approach, because of the zero-sum nature of 5 rate design, the higher the energy rates, the lower the demand charges and vice versa. 6 Q. IF THE DEMAND CHARGES ARE MERELY USED TO ENSURE 7 RECOVERY OF THE ALLOCATED REVENUE REQUIREMENT TO THE 8 SP-3 CLASS, WHY DO YOU STATE THAT THEY ARE TOO HIGH? 9 A. There are two primary reasons why they are too high. First is the fact that MGE 10 proposes to collect too much revenue from the Sp-3 class and second is because of the 11 functioning of the tariff, particularly in light of the application of demand charges for 12 load other than the chiller load at the WCCF. 13 Q. WHY DO YOU SAY THAT THE ALLOCATED REVENUES TO THE SP-3 14 CLASS ARE TOO HIGH? 15 A. This is demonstrated very plainly by the results of the Company's cost of service 16 studies in this case. More specifically, MGE's cost of service studies are presented by 17 its witness Steven S. James and the results are shown on his exhibit, 18 Ex.-MGE-James-1. Mr. James examined cost of service under three different sets of 19 assumptions, which he has labeled "Standard," "Time-of-Use" and "Location."3 20 Under each of the three measures of cost of service employed by Mr. James, he finds 21 that the Sp-3 class is already paying in excess of its cost of service. On a percentage 22 basis, these excesses range from 0.27% to 1.22%. Most of the other rate classes are 3Mr. James describes these three cost study types at pages Dl.l4 through Dl.l8 ofhis testimony. DIRECT-UW SYSTEM-STEPHENS-? paying revenues that are less than their cost of service, as demonstrated on pages 4 and 2 6 of Mr. James' exhibit. On an embedded cost basis, these classes are being 3 subsidized by the classes which are paying revenues above cost, such as Sp-3. 4 Utilizing his "Standard" cost of service approach, which I believe to be the 5 most reasonable of the three, it shows that under current rates, the Sp-3 class is paying 6 about $434,000 per year too much, which equates to 1.22%. Therefore, if cost of 7 service principles were followed, exclusively based on this cost study, the Sp-3 class 8 would deserve a rate reduction. Yet as indicated previously, MGE proposes a 4% 9 increase. If the Sp-3 rates are already $434,000 above cost of service and MGE 10 proposes to raise them $1.404 million more (as shown on Exhibit 1.4, Schedule 1, 11 page 16), this means that the University is being asked to pay over $1.8 million above 12 its cost of service. 13 So despite Mr. Bollom's claim that rates should be aligned with costs, he 14 clearly does not fully advocate this with respect to the Sp-3 class and instead proposes 15 that the significant subsidy that they already pay be increased. This should not be 16 adopted by the Commission. As mentioned previously, since the demand charges are 17 used to recover the allocated revenue requirement, they should be modified downward 18 by the approximate $1.8 million per year, or something reasonably close thereto, to 19 bring the University's charges closer to cost of service. 20 Q. WHAT WAS THE SECOND REASON WHY THE DEMAND CHARGES ARE 21 TOO HIGH? 22 A. This reason is a little more complex. As discussed earlier, the present energy rates 23 contain an element of capacity costs in the energy charges. Therefore, the demand DIRECT-UW SYSTEM-STEPHENS-8 charges in present rates are lower than they would be if they reflected the full capacity 2 costs and the energy rates are higher than they would be if they reflected no capacity 3 costs. 4 As Mr. Bollom describes and University witness Harrod acknowledges, 5 17,000 kW of demand, representing the chiller load at the WCCF, is not subject to a 6 demand charge. Only demand in excess of 17,000 kW is subject to such charge. 7 Thus, in acknowledgment of its initial investment in the WCCP, the University is 8 relieved of this portion of capacity costs. However, it historically has not been 9 relieved of the full value of this capacity, since the demand charges which it did not 10 pay were suppressed and did not reflect the full value of the capacity (since some of 11 that capacity was being recovered through energy charges for which the University 12 was not relieved). Therefore, the historic level of revenue collected from the 13 University was artificially inflated due to the inclusion of capacity costs within the 14 energy charges. 4 15 Now, with better-aligned energy charges as proposed by MGE, the target 16 revenues to be collected through demand charges (on a residual basis) are too high due 17 to this historical undervaluing of the University's share of capacity investment. 18 Q. WHAT IS YOUR RECOMMENDATION TO THE COMMISSION? 19 A. While I do not oppose the restructuring of energy and demand charges in concept, the 20 specific demand charges should be reduced from the Company's proposal in the 21 amounts sufficient to reduce the overall class revenue allocation by approximately 4As described by UW witness Harrod, UW and MGE agreed on February 16, 2012 to an alternative approach to pricing energy for WCCF chiller load up to 17 MW when WCCF is available to operate, but is not dispatched by MISO. DIRECT-UW SYSTEM-STEPHENS-9 $1.8 million, in order to eliminate cross subsidies within present rates, which are 2 exacerbated under the Company's proposed rates. If this figure (actually 3 $1.838 million), were applied equally to the winter and summer on-peak demand 4 units, the reduction to the demand charges would be reduced by approximately 5 $0.253 per kW-day.5 6 2. Generation Credit/Standby Rate for the CSHP 7 Q. WHICH ASPECT OF THE SP-3 TARIFF DESIGN DO YOU WISH TO 8 ADDRESS IN THIS SECTION OF YOUR TESTIMONY? 9 A. I wish to address MOE's generation credit applicable to, and the general treatment of, 10 the University's CSHP. 11 Q. WHAT IS THE CSHP? 12 A. This is described in the Direct Testimony of UW witness Harrod. 13 Q. HAVE YOU REVIEWED THE GENERATION CREDIT MGE APPLIES TO 14 THE UNIVERSITY'S CSHP UNDER MGE'S SP-3 TARIFF? 15 A. Yes, I have. Currently, MOE charges the University for demand for its total load on a 16 gross basis, including both the campus load and the output of the CSHP. As shown in 17 Table 1, MOE applies a generation credit in the amount of$0.12329 per kW-day (or 18 approximately $3.70 on a per kW-month basis) to the generation capacity provided by 19 the University's CSHP. 5Calculated as $1,838,000 divided by 457,741 kW plus 267,594 kW- the winter and summer on-peak demand billing units shown on Exhibit 1.4, Schedule 1, page 15. DIRECT -UW SYSTEM-STEPHENS-I 0 Q. WHAT IS YOUR UNDERSTANDING AS TO WHY MGE IMPLEMENTED A 2 GENERATION CREDIT FOR THE UNIVERSITY? 3 A. University witness Craig Weiss describes the implementation of the generation credit 4 in his direct testimony at pages 04-6. It is my understanding that a generation credit 5 was put into place as a result of the decision in Docket No. 3270-UR-II6. As 6 explained by Mr. Weiss in his direct testimony, MGE indicated the generation credit 7 was designed to mirror MGE's interruptible credit and takes the place of a standby 8 rate. 9 Q. HAS THE UNIVERSITY OPPOSED THE MGE GENERATION CREDIT IO APPLIED TO THE UNIVERSITY'S CSHP UNDER MGE'S SP-3 TARIFF? II A. Yes. UW has opposed the generation credit since the University believes it is I2 unsupported by any cost that MGE has incurred and is an inappropriate way to charge I3 for standby service for the University's CSHP.6 This issue is addressed more fully by I4 UW witness Weiss. I5 Q. DO YOU HAVE A SPECIFIC OBJECTION TO THE GENERATION I6 CREDIT? I7 A. Yes. I believe that the current generation credit applied to the University's CSHP I8 generation capacity is inequitable and inadequate. 6Docket No. 3270-UR-117, Initial and Reply Briefs of the Board of Regents of the University of Wisconsin System. DIRECT-UW SYSTEM-STEPHENS-II Q. PLEASE EXPLAIN WHY THE CURRENT GENERATION CREDIT IS 2 INEQUITABLE? 3 A. The current generation credit paid by MGE to the University for the CSHP capacity is 4 very low as compared to the Sp-3 demand charge paid by the University on a gross 5 basis for its total load (the University load plus load displaced by the University's 6 CSHP generation capacity.) Thus, MGE proposes to charge the University 7 $1.13 per kW-day (summer) for load served by its CSHP, and then credits the 8 University only $0.12329 per k W -day, or about 11% of the value, for the generation 9 output. 10 Q. HOW DOES THE GENERATION CREDIT COMPARE TO THE LONG 11 TERM A VOIDED COST OF CAP A CITY? 12 A. The current generation credit paid by MGE to the University for the CSHP generation 13 capacity is also very low as compared to the cost of a combustion turbine used as a 14 proxy for the long-term avoided cost of capacity. In determining the appropriate value 15 for long-term capacity, it is appropriate to consider the annualized cost of a generating 16 unit that otherwise would be built for capacity purposes. At this time, it is widely 17 accepted that simple cycle natural gas-fired combustion turbines are the appropriate 18 standard for measuring the long-term capacity values. At today's prices, the marginal 19 capacity cost of a combustion turbine is quite significant. 20 Q. CAN YOU PROVIDE AN ESTIMATE OF THE CURRENT MARGINAL 21 CAPACITY COST ASSOCIATED WITH A COMBUSTION TURBINE? 22 A. Yes. For this purpose, I will rely on the direct testimony provided by Wisconsin 23 Public Service Corporation witness Durga Karin Docket No. 6690-UR-121, currently DIRECT-UW SYSTEM-STEPHENS-12 before the Commission who, based on long-range 2012 costs, has estimated the real 2 levelized cost of a combustion turbine at $176.10 per kW-year, in 2012 dollars. 7 3 While I am not testifying as to the accuracy of Mr. Kar's figure, I am using it to show 4 the relative magnitude of the value of avoided capacity. After adjusting Mr. Kar's 5 figure for reserve margin, losses and coincidence factor, it would yield an annual value 6 of over $167 per kW-year. If this were to form the basis of a generation credit on 7 equal monthly levels, it would be nearly $14 per kW-month or approximately 8 $0.46 per kW-day. Thus, customer capacity is of very significant value by enabling 9 the utility to avoid constructing new generating capacity. 10 Q. HOW DOES THE CURRENT MARGINAL CAPACITY COST COMPARE TO 11 MGE'S GENERATION CREDIT PAID TO THE UNIVERSITY FOR THE 12 CSHP? 13 A. The marginal capacity cost of $0.46 per kW-day is nearly four times the MGE 14 generation credit of$0.12329 per kW-day. 15 Q. IS THERE CURRENTLY A SHORT-TERM MARKET FOR CAPACITY IN 16 THE WHOLESALE MARKET? 17 A. Yes. The current market price for short-term generating capacity is lower than the 18 current avoided cost for a new generation facility. This is because of the current levels 19 of generation reserve margins in the MISO footprint. However, note that new 20 generation capacity cannot be built overnight and the current market price for capacity 21 is a temporary situation. Experiences show that short-term market prices for capacity 22 do not reflect the expected long-term cost for generation capacity. Typically, 7Source: Ex.-WPSC-KAR-1, Page 2 of3 Docket No. 6690-UR-121, (PSC REF #164610). DIRECT-UW SYSTEM-STEPHENS-13 short-term market prices for capacity significantly understate the long-term value of 2 capacity when excess capacity exists and dramatically overstate the long-term value of 3 capacity when capacity margins are tight. In addition, there remains considerable 4 uncertainty regarding the future of the large, relatively old coal-fired generation fleet 5 located in the MISO footprint, due to various environmental rules. Should these rules 6 result in a rapid reduction in generation planning reserve margin within the MISO 7 footprint, it could cause the market price of electric capacity to rise rapidly. 8 Finally, as long-term wholesale forward markets for electricity mature, the 9 market price for electric capacity should trend toward the avoided cost of new 10 generation facilities. However, even in a mature market, depending on the 11 circumstances present in the year in question, the current annual market price for 12 capacity may be substantially lower or substantially higher than the avoided cost for a 13 new generation facility. 14 Consequently, a more stable, dependable measure of the value of capacity is 15 the avoided cost of the peaking unit, as discussed above, than the short-term capacity 16 prices in the wholesale market. In addition, use of a more stable measure of capacity 17 that does not fluctuate widely from year-to-year affords customers a greater 18 opportunity to invest in resources necessary to enable them to operate as a demand 19 response resource or as distributed generation. 20 Q. WOULD IT BE APPROPRIATE TO INCREASE THE VALUE OF THE 21 GENERATION CREDIT? 22 A. Yes, but only if the current rate structure is retained, despite my primary 23 recommendation discussed below. The current generation credit appears to be priced DIRECT -UW SYSTEM-STEPHENS-14 based on short-term avoided cost of capacity. The University's CSHP generation is a 2 long-term resource available to MGE and should reflect the long-term avoided cost of 3 capacity. 4 Q. IS THERE A MORE FAIR AND EQUITABLE APPROACH TO CHARGE 5 THE UNIVERSITY FOR STANDBY SERVICE APPLICABLE TO THE 6 UNIVERSITY'S CSHP GENERATION CAPACITY? 7 A. Yes. A more fair and equitable approach would be to charge the University on a net 8 demand basis (University load only- no CSHP capacity) and pay a reservation charge 9 for MGE generation that provides standby service to the CSHP. If MGE believes that 10 the current generation credit is a proxy for the value of capacity, then the Reservation 11 charge could reflect the value of the current generation credit paid by MGE to the 12 University. The reservation charge should reflect the costs incurred by MGE to 13 acquire capacity for providing standby service to the University. These costs are 14 better reflective of the short-term value of capacity. For days in which CSHP is not 15 operable and UW utilizes standby service, the on-peak demand charges should be 16 applied on a daily basis rather than a maximum for the month basis, as the rate applies 17 to campus load. In this way, UW would pay demand charges more commensurate 18 with its need for standby service. In addition, for periods of planned maintenance of 19 CSHP, when UW has given reasonable notice to MGE (e.g. 30 days), it is appropriate 20 to reduce somewhat the daily demand charges. DIRECT-OW SYSTEM-STEPHENS-15 Q. DO YOU HAVE PROPOSED CHANGES TO THE SP-3 TARIFF THAT 2 WOULD IMPLEMENT YOUR PRIMARY RECOMMENDATION? 3 A. Yes. The modified tariff language is attached as Ex.-UW System-Stephens-2.8 This 4 exhibit shows my version of tariff modifications that would implement the concepts 5 described in my prior answer.9 However, as it is MGE's tariff, I recognize that the 6 Company may have preferred alternative language to accomplish these principles and 7 I would be open to considering same. 8 Q. SHOULD THE COMMISSION NOT ADOPT YOUR PRIMARY 9 RECOMMENDATION, DO YOU HAVE A SECONDARY ONE? 10 A. Yes. The Commission could direct a more traditional standby rate be used. The 11 Commission could look to other utilities' standby rates for guidance. I have included 12 in Ex.-UW System-Stephens-3, examples of other standby rates in use by Wisconsin 13 utilities. Though I am not recommending any of these other tariffs specifically, they 14 contain useful information and demonstrate the existence of valid standby rates in 15 Wisconsin. 16 Q. WHAT IS YOUR RECOMMENDATION TO THE COMMISSION? 17 A. I recommend that the University be billed on a net demand basis, pay a reservation 18 charge for standby generation that reflects the current generation credit paid by MGE 19 to the University and pay for standby service used on a daily basis at the applicable 8My suggested changes are highlighted in yellow. 90ne additional change that I address in the proposed tarifflanguage is to eliminate the tariffs punitive $25 per kW per instance charge for not running CSHP when requested by MGE. (Paragraph 2 under Special Terms and Provisions.) This charge is extremely high, appears to be without cost basis and seeks to solve a problem which has not been shown to exist. DIRECT-UW SYSTEM-STEPHENS-16 on-peak demand rate, as described above and illustrated in my 2 Ex.-UW System-Stephens-2. 3 Q. DO YOU HAVE ANY ADDITIONAL RECOMMENDATIONS TO THE 4 COMMISSION? 5 A. Yes. In the event the Commission does not adopt my primary recommendation for net 6 metering and a reservation charge, or my secondary recommendation of directing a 7 standby rate be established, then the Commission could, in the alternative, increase the 8 value of the generation credit paid by MGE to the University. As noted previously in 9 my testimony, the current marginal cost of capacity is nearly four times the value of 10 the generation credit paid by MGE to the University. 11 3. Restructuring Sp-3 Energy Charges to Market-Based 12 Q. EARLIER YOU DESCRIBED HOW MGE IS RESTRUCTURING THE SP-3 13 TARIFF TO MAKE THE ENERGY CHARGES MORE REFLECTIVE OF 14 CURRENT MARKET PRICES AND THAT THE UNIVERSITY DOES NOT 15 OBJECT GENERALLY TO THIS APPROACH. WHAT IS YOUR 16 UNDERSTANDING OF THE UNIVERSITY'S RATIONALE FOR THIS 17 POSITION? 18 A. I understand that the University desires to pay energy rates that are reflective of cost, 19 and cost is best represented by the current wholesale market. As I described 20 previously and showed in Table 1, the proposed energy charges are intended to be an 21 estimation ofMISO LMP values for 2013. 10 As such, while they are an improvement 10MGE inexplicably adds 0.5 cents per kWh to the expected MISO LMP values in developing its proposed Sp-3 energy charges. DIRECT-UW SYSTEM-STEPHENS-17 over the current energy charges, they are not optimal measures of market prices since 2 1) they are only forecasts not actual values and 2) they do not vary on an hourly basis. 3 Should MGE and the University be able to agree to it, a more appropriate energy 4 charge would be the actual hourly MISO LMP values (adjusted as necessary), rather 5 than forecasted average values. UW is open to considering this approach and 6 exploring it further with MGE. 7 Q. SHOULD THE ENERGY CHARGES UNDER SP-3 BECOME ACTUAL 8 MARKET-BASED CHARGES, WHAT WOULD BE THE IMPLICATIONS 9 FOR MGE AND ITS OTHER CUSTOMERS? 10 A. MGE and its other customers should either be neutral to this change or benefit from it. 11 They would be neutral if the tariff is designed in such a way to ensure that no revenue 12 or cost is shifted between classes as a result of the variation in energy prices. MGE 13 and other customers will be benefited by the fact that UW would be taking on a 14 significant amount of price risk that currently resides with MGE, and ultimately its 15 customer base as a whole. 16 Q. PLEASE EXPLAIN FURTHER, THE PRICE RISK TO WHICH YOU ARE 17 REFERRING. 18 A. The fixed energy rates in both current and proposed rates are just that, fixed. Should 19 the cost of providing the power vary significantly from the assumptions used in 20 determining the fixed rates, this can yield significant income variations for MGE and, . 21 ultimately, it's other customers. By absorbing this price risk, the University would 22 effectively shield MGE from the potential over or under recovery, at least as relates to DIRECT-UW SYSTEM-STEPHENS-18 serving UW. Reduction in risk is of value and, therefore, MGE and other customers 2 would benefit. 3 Q. WHAT IS YOUR RECOMMENDATION IN THIS REGARD? 4 A. I recommend that the Commission direct MGE to meet with the University within 90 5 days of its order in this case to discuss the potential for restructuring the Sp-3 energy 6 charges to be a direct measure of actual MISO LMPs (as delineated by the parties) 7 and, if agreement is reached, to present such proposal to the Commission for 8 consideration. Such a filing should be targeted for no later than July 1, 2013. 9 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 10 A. Yes, it does. 8369681 I DIRECT-UW SYSTEM-STEPHENS-19 PSC REF#:l70898 BEFORE THE PUBLIC SERVICE COMMISSION OF WISCONSIN Application ofMadison Gas and Electric Company for Authority to Change Electric Docket 3270-UR-118 and Natural Gas Rates DIRECT TESTIMONY OF CRAIG WEISS ON BEHALF OF THE BOARD OF REGENTS OF THE UNIVERSITY OF WISCONSIN SYSTEM Q. Please state your name and business address. 2 A. My name is Craig A. Weiss. My business address is 4729 Dale Curtin Drive, McFarland, 3 Wisconsin 53558-0541. 4 Q. By whom are you employed and in what capacity? 5 A. I am principal of Innovative Business Engineering, LLC ("IBE"). IBE is a contractor to 6 the Board of Regents of the University of Wisconsin System; the parent organization for 7 the University of Wisconsin- Madison ("UW"). I am testifying in support of UW on 8 electric rate matters impacting the current and future energy costs of UW. 9 Q. Please state your educational background, certifications and work experience. 10 A. I graduated from the University of Wisconsin with a Bachelors of Science degree in 11 applied mathematics and Engineering Physics and a Master of Science in Mechanical 12 Engineering. I am a registered Professional Engineer in Wisconsin and have worked in DIRECT-UW SYSTEM-WEISS-I the electric generation industry and power plant dispatch and management for over 30 2 years. Attached as Ex.-UW System-Weiss-1 is my resume. 3 Q. Did you prepare your testimony? 4 A. I prepared my testimony with the assistance of UW personnel who manage UW power 5 facilities. 6 Q. What is the purpose of your direct testimony in this proceeding? 7 A. The purpose ofthis testimony is to present (1) UW's position regarding Sp-3 Tariff 8 revisions since 2009; (2) an analysis of MGE's proposal for the Sp-3 Tariff and the 9 economic effects on UW; and (3) UW's proposals for the Sp-3 Tariff. 10 Q. Please describe your work at WCCF for UW. 11 A. I have provided consulting services to UW relating to the dispatch of electric, steam and 12 chilled water since 2005 in advance of the West Campus Cogeneration Facility (WCCF) 13 commercial operation. My responsibilities have included reviewing MGE bills to ensure 14 compliance with SP-3 tariff terms of service. I have participated in numerous meetings 15 with UW and MGE representatives regarding the full range of issues under the SP-3 tariff 16 including the discussions that resulted in the most recent amendment to the WCCF O&M 17 Agreement. I have worked with UW personnel who manage UW power facilities to 18 optimize and coordinate the operation of UW-owned electric, steam and chilled water 19 production facilities with MGE-owned and/or operated electric, steam and chilled 20 resources. I have reviewed the UW's agreements for the operation and maintenance of 21 the WCCF and provide energy balance schematics and part load performance energy 22 tables for each chiller, boiler, and generator at the Charter Street Heating Plant (CSHP), DIRECT-UW SYSTEM-WEISS-2 Walnut Street Heating Plant (WSHP), and WCCF. I have provided modeling to identify 2 the lowest cost supply options considering available sources and optimizing the variable 3 O&M, energy and fuel costs for the set of chillers, steam and electrical supply options 4 available to satisfy given daily and monthly load ranges. I also model and analyze the 5 value of alternate electric rates for WCCF chillers. I provide advice regarding fuel 6 procurement and selection of alternative electric rates to reduce costs with improved 7 reliability. 8 Q. What have you done to prepare your testimony for this proceeding? 9 A. Based on my work with UW, I am familiar with the Sp-3 Tariff as it has changed over 10 time and have reviewed the related proceedings before the Public Service Commission of 11 Wisconsin (PSC or Commission). In particular, I have reviewed dockets 3270-UR-116, 12 3270-UR-117 and 3270-UR-117 (Reopener). I have also reviewed MOE's testimony and 13 exhibits pertaining to UW and the Sp-3 Tariff in this proceeding. 14 1. SP 3 tariff revisions since 2009. 15 Q. Please describe the Sp-3 tariff and its billing determinates that were in place before 16 2010. 17 A. Before January 2010 the Sp-3 tariff recovered MGE capacity costs needed to serve UW 18 load through a traditional kW demand charge that did not include a charge for electricity 19 provided by UW generation. In January 2010 MGE increased the demand charge rate per 20 kW by 119% and included electricity supplied by UW generation. I have obtained a 21 copy ofExhibit 10 introduced by MGE in 3270-UR-116 (REF# 116472) and marked it 22 as Ex.-UW System-Weiss-2 for this proceeding. This exhibit is a red-lined copy of the DIRECT -UW SYSTEM-WEISS-3 Sp-3 tariff in effect in 2009 that shows the changes to the Sp-3 Tariff proposed by MGE 2 in 3270-UR-116 and adopted by the Commission in the Final Decision in that proceeding 3 (REF# 125079) which is marked as Ex.-UW System-Weiss-3 for this proceeding. UW 4 did not intervene as a party in that proceeding, but submitted written comments objecting 5 to the proposed changes (REF# 120354), a copy of which is also included as Ex.-UW 6 System-Weiss-4 in this proceeding. 7 Q. What changes proposed by MGE did UW oppose? 8 A. MGE proposed changes that were adopted in the Final Decision, but UW had opposed 9 the following: ( 1) Increasing the customer charge from $230.14 to $2,260 per day; 10 (2) increasing the summer Maximum on-peak 15-minute demand charge from $0.29250 11 to $0.6300 per kW per day and the winter Maximum on-peak demand charge from 12 $0.24000 to $0.53000 per kW per day; (3) including UW CSHP generation output 13 contribution in the calculation ofkW demand charges; (4) providing for a "generation 14 credit" for UW generation based on the highest 15 minute kW recorded in the preceding 15 year, (5) prescribing significant penalties in the event UW's CSHP generation facilities 16 did not operate as nominated; and (6) providing MGE control with the right to order 17 UW's CSHP facilities be dispatched upon an hour's notification. 18 Q. Why did UW oppose these MGE-proposed changes? 19 A. Generally speaking, UW opposed these changes as they were not based on the cost to 20 serve UW and were designed to discourage UW from going forward with the expansion 21 of generation at CSHP by decreasing energy kWh charges and increasing kW demand 22 charges and the fixed customer charge. DIRECT -UW SYSTEM- WEISS-4 In testimony in that proceeding MGE stated that MGE made these proposals in 2 response to UW's plan to rebuild and expand CSHP to 22-35 MW of cogeneration 3 capacity. (Ex.-UW System-Weiss-5, Docket 3270-UR-116, Vanderbloemen, Rl.38, lines 4 21-25, Rl.39, lines 1-2; Docket 3270-UR-116; REF# 121502.)1 In particular, MGE 5 stated that it decreased the energy charge and increased Sp-3 customer and demand 6 charges to the same extent energy charges were decreased "to maintain the same revenue 7 requirement in the SP-3 rate category." (Ex.-UW System-Weiss-6, Docket 3270-UR- 8 117, Vanderbloemen, Dl.82, lines 8-14; REF# 135381)2 In fact, MGE's new Sp-3 rate 9 was not "revenue neutral" but increased Sp-3 revenues by $859,452 which MGE's 10 witness stated was "used to reduce the revenue requirement for other rate payers." (Ex.- 11 UW System-Weiss-7, Docket 3270-UR-116, Vanderbloemen Direct Testimony, Tr. 100- 12 101 (REF# 116471),3 Ex.-UW System-Weiss-8, Exhibit 11 (REF# 116473).) 13 Q. Why did UW also oppose the use of a "generation credit", increasing kW demand 14 charges to include UW generation, including terms providing MGE control over 15 CSHP and imposing penalties for failure to generate? 16 A. Prior to January 2010, MGE provided and billed electricity service to UW-Madison 17 Campus on a "net-of-generation" basis. MGE did not meter CSHP generation output 18 until 2010. UW generation output was "behind the meter" and not separately taken into 19 account by MGE in the Sp-3 tariff, billing, or demand forecasting. MGE's Sp-3 demand 1 Ex.-UW System-Weiss-5 contains Vanderbloemen's rebuttal testimony, pages Rl.38 -Rl.40, referenced from 3270-116. Further references to Vanderbloemen rebuttal testimony from this docket will be: Ex.-UW System Weiss-5. 2 Ex.-UW System-Weiss-6 contains Vanderbloemen's direct testimony,, page 01.89, referenced from 3270-UR- 117. Further references to Vanderbloemen direct testimony from this docket will be: Ex.-UW System-Weiss-6. 3 Ex.-UW System-Weiss-7 contains Vanderbloemen direct testimony, pages 100-101, referenced from 3270-UR- 116. Further references to testimony from this docket will be: Ex.-UW System-Weiss-7. DIRECT -UW SYSTEM- WEISS-5 meters measured both net demand (kW) and energy (kWh) used by UW's central 2 Madison campus for billing purposes. MGE did not keep track of CSHP output nor did it 3 need to under the previous net-of-generation Sp-3 rate design, in place for decades. 4 Before January 2010, MGE did not charge to back up UW's approximately 8 5 MWs of generation at CSHP. (Ex.-UW System-Weiss-9, Docket 3270-UR-117, 6 Vanderbloemen, Tr. 56, 74(REF # 139439))4 Neither did MGE incur any capacity cost to 7 back up CSHP. (Id. at 75.) MGE did not maintain or plan from a reserve margin 8 perspective to back-up UW self-generation not otherwise netted out of total UW load. 9 (Id.) MGE reported generation capacity to MISO, FERC and the PSCW without 10 including UW's 8 MW at CSHP. (Id.) 11 From time to time when planned or unplanned outages occurred at CSHP, UW's 12 metered usage increased and MGE was compensated for this usage based on normal 13 demand and energy rates in the Sp-3 tariff. (Id. at 74.) UW scheduled outages during 14 non-peak months and not in the summer when demand and Sp-3 energy charges are 15 highest. MGE has always been paid for power supplied to UW and has never incurred 16 additional capacity costs to back up UW CSHP generation. (Id. at 75.) 17 In 3270-UR-116, MGE explained that the 2010 Sp-3 tariff added "a generation 18 credit concept into the rate structure." (Ex.-UW System-Weiss-5,Vanderbloemen Rl.39, 19 line 2, REF# 121502.) MGE indicated the Generation Credit was designed to mirror 20 MGE's interruptible credit and takes the place of"standby" rate. (Ex.-UW System- 21 Weiss-5, Vanderbloemen Rl.40, Tr. 63, lines 12-18.) UW has opposed this arrangement 4 Ex.-UW System-Weiss-9 contains excerpts from the September 29,2010, Hearing Tr. Vol. 2, pp. 56, 74 and 75, from 3270-UR-117. (REF # 139439) Further references to this transcript· from this docket will be: Ex.-UW System-Weiss-9. DIRECT-UW SYSTEM-WEISS-6 as it was unsupported by any cost that MGE has incurred and was an unreasonable way to 2 provide service to back up CSHP generation. 3 Q. What did UW do regarding the 2010 SP3 tariff? 4 A. The Final Decision in 3270-UR-116 directed MGE to work with UW and Commission 5 staff to try to resolve issues related to Sp-3 tariff structure. There were discussions and 6 various proposals were exchanged, but no resolution was reached before MGE filed an 7 application to increase rates in 2010 for test year 2011 which was 3270-UR-117. In that 8 proceeding, UW and MGE submitted testimony and exhibits regarding a range of issues 9 including Sp-3 Tariff design. However, the Commission did not resolve issues related to 10 Sp-3 Tariff design and again directed Commission staff to provide the Commission with 11 a proposal for the tariff. I have marked as Ex.-UW System-Weiss-1 0 the Final Decision 12 in 3270-UR-117. (REF# 143578) 13 Q. Does UW plan to expand CSHP generation? 14 A. No. On July 22, 2011, the Department of Administration announced that plans to expand 15 CSHP electric generation had been dropped. 16 Q. Did the Commission staff present a proposal for the Sp-3? 17 A. After consulting UW and MGE, Commission staff prepared a proposal and invited 18 comments from interested parties. I have marked as Ex.-UW System-Weiss-11 a copy of 19 the proposal and staff memorandum. (REF # 151549). The proposal was not presented 20 to the Commission for consideration at an open meeting. As a consequence, the Sp-3 21 Tariff continues to include terms which UW has contended are unfair and unreasonable. DIRECT -UW SYSTEM- WEISS-7 Q. Did UW make an effort to resolve issues with MGE since the Final Decision in 3270- 2 UR-117? 3 A. UW attempted to introduce these issues in the limited reopener which occurred in 2011 in 4 3270-UR-117 (reopener); however, the scope of that proceeding was limited and these 5 issues were not considered. I have marked as Ex.-UW System-Weiss-12 a copy of the 6 Final Decision in that proceeding. (REF# 157113). 7 Q. After the Final Decision in 3270-UR-117 (reopener), did UW continue to engage 8 MGE regarding disputed issues? 9 A. After the Final Decision, UW and MGE were able to resolve several major issues related 10 to uneconomic dispatch at WCCF, installation of new chiller load at WCCF and related 11 matters. These discussions lead to the amendment of the WCCF O&M Agreement that 12 was approved by the Commission on May 2, 2012. (REF# 164123) A copy ofthis 13 agreement is marked as Ex.-UW System-Harrod-5. However, these discussions did not 14 address Sp-3 rate design issues. 15 2. MGE's Sp-3 Rate Proposal. 16 Q. Mr. Weiss, what analysis did you undertake to determine the likely economic effects 17 on UW if MGE-proposed Sp-3 rates were adopted by the Commission? 18 A. I have reviewed MGE's Sp-3 Rate Proposal as shown in James Exhibit 1.4, Schedule 1, 19 pages 15 and 16, and have identified the following concerns: ( 1) MGE understates 20 projected sales for Test Year 2013; and (2) Sp-3 demand charges are increased by almost 21 $500,000 to recover a decline in revenue due to projected decrease in Sp-3 energy sales 22 to WCCF chillers. DIRECT-UW SYSTEM-WEISS-8 Q. Have you had occasion to analyze MGE-proposed rate revisions to Sp-3 for test year 2 2013? 3 A. I reviewed Mr. Bollom's and Mr. James' testimony and exhibits regarding proposed 4 revisions to Sp-3 and rates. I understand that MGE projected UW sales based on actual 5 sales during 2010 and 2011. Using this data to project sales for 2013 will likely 6 understate kWh sales because UW has increased its need for electricity as a result of the 7 completion of several large construction projects such as Union South and Discovery 8 Center and the installation of a new chiller at WSHP replacing steam chiller loads. 9 Q. Do you have other documentation to support your opinion that the projection used 10 for Sp-3 sales should be increased? 11 A. I also obtained data regarding UW actual usage of MGE electricity supplied to the 12 campus for the fiscal year that ended June 2012, which is shown in exhibit Ex.-UW 13 System-Weiss-13. This exhibit shows MGE supplied UW 416,240,455 kWh for fiscal 14 year that ended June 2012 compared to 379,476,607 kWh in Mr. James' exhibit. As 15 shown, UW's actual2012 usage exceeds MGE's proposed test year figures in all 16 categories of distribution service demand, winter on-peak demand and summer on-peak 17 demand. Applying MGE's proposed demand rates to UW's actual demand in the fiscal 18 year ended June 2012 results in recovery of revenue for demand charges of $26,457,012. 19 This will mean additional demand revenue of$923,503 to MGE over MGE's projection 20 in James Ex. 1.4, Schedule 1, pages 15 and 16. 21 The actual MGE Sp-3 energy purchases will be dependent on the amount of 22 CSHP generation that is influenced by WCCF dispatch, natural gas prices, electric 23 chillers replacing base load steam chillers because of low Sp-3 rates, among other factors. DIRECT-UW SYSTEM- WEISS-9 Q. In addition to MGE's understatement of projected Sp-3 sales, did you identify other 2 concerns regarding MGE's Sp-3 proposal? 3 A. As explained by Mr. Bollom, MGE recognizes less revenue for Sp-3 energy sales to 4 WCCF chillers and recovers this lost revenue by increasing Sp-3 demand charges in 5 order to achieve Sp-3's revenue requirement. (Bollom, 01.77 (REF# 162761).) MGE 6 apparently is projecting a decline in Sp-3 WCCF chiller revenues for electricity for 7 WCCF chillers when WCCF was available, but not running. 8 The projected decrease in revenue from energy sales to operate WCCF chillers at 9 the Sp-3 energy rate should not be recovered by increasing Sp-3 campus demand charges. 10 If the Commission determines that UW's Sp-3 revenue requirement proposed by MGE is 11 correct, then the billing determinates for Sp-3 campus service should be adjusted 12 accordingly. However, WCCF chiller energy revenues should not be considered as a 13 source of revenue to meet University campus Sp-3 revenue allocations. Under the 14 agreements that govern WCCF operations, UW is not obligated to pay demand (kW) 15 charges for its 17 MW WCCF chiller load. The Sp-3 Tariff provides that "[t]he chiller 16 load will be separately metered for purposes of determining the charges under these 17 special terms and provisions." (James Ex. 1.4, Schedule 4, p. 21.) 18 Q. Is UW objecting to pay its fair share of MGE demand/capacity costs? 19 A. UW does not object to paying its fair share ofMGE demand/capacity costs, but it does 20 object to MGE's proposal to recover lost energy revenue from Sp-3 energy sales to 21 WCCF chillers by increasing campus demand charges. In this proceeding UW is not 22 disputing MGE's calculation of the Sp-3 revenue requirement other than as pointed out in 23 the testimony of Mr. Stephens that the Sp-3 revenue requirement is more than warranted DIRECT-UW SYSTEM-WEISS-10 by cost of service principles. UW submits that MGE revenues derived from WCCF 2 chiller operations should be separate and distinct from campus Sp-3 revenue 3 requirements. Instead of projecting a revenue loss due to projected reduction in UW's 4 payment for energy for WCCF chiller operations that use the Sp-3 rate as a proxy for 5 Station Service, MGE should formulate Sp-3 billing rates based on University campus 6 usage independent of 17 MW of WCCF chiller load. 7 Q. MGE shows that the Sp-3 proposed rate increase to be 4.01% on James Ex. 1.4, 8 Schedule 1, page 1. Do you agree with this calculation? 9 A. MGE's proposed rate increase for the Sp-3 Tariff includes revenue from Sp-3 WCCF 10 energy to operate WCCF chillers. With WCCF energy included, the revenue increase is II calculated by Mr. James to be 4.01%. However, ifWCCF chiller energy is excluded, the 12 proposed campus Sp-3 revenue increase is 5.6%. 13 3. UW's Proposal for Sp-3 Tariff. 14 Q. Why is establishing a just and reasonable Sp-3 rate design and appropriately 15 allocating fixed and variable costs important to the University? 16 A. As Mr. Harrod testified, the University devotes considerable resources to management 17 and planning for campus energy needs. The University will continue to emphasize and 18 pursue energy efficiency programs and demand management strategies to address these 19 needs. These projects often require significant investments. Long range planning 20 requires certainty regarding fixed and variable cost structure the University faces for 21 energy. DIRECT-UW SYSTEM-WEISS-11 Q. What changes does UW propose for the Sp-3 rate design? 2 A. Based on the principles explained by Mr. Stephens, UW has three specific proposals: 3 (1) provide for standby service to back up CSHP generation; (2) eliminate the generation 4 credit, penalty and must-run provision in the Sp-3 terms and conditions; (3) eliminate 5 including UW generation in the determination of Sp-3 demand charges; and ( 4) 6 incorporate terms that make clear that MGE energy sales for the existing 17 MW WCCF 7 chiller load do not recover unrelated MGE demand/capacity costs. These proposals are 8 included in modifications to the SP-3 Tariff as proposed by MGE as set out in Ex.-UW 9 System-Stephens-2. 10 Q. Does UW anticipate further discussion with MGE regarding Sp-3 rate design? 11 A. About two weeks ago UW power plant managers met with MGE and discussed market 12 based pricing options. UW proposes that the Commission order MGE to work with UW 13 to arrive at a reasonable and non-discriminatory Sp-3 rate design that provides such 14 options to UW. In particular, UW proposes that the Commission direct MGE to meet 15 with UW within 90 days of its order to discuss restructuring Sp-3 energy charges. If an 16 agreement is reached, MGE should present the proposal to the Commission by July 1, 17 2013. 18 Q. Does this conclude your testimony? 19 A. Yes. 8372014_1 DIRECT-OW SYSTEM-WEISS-12 PSC REF#:l70887 BEFORE THE PUBLIC SERVICE COMMISSION OF WISCONSIN Application of Madison Gas and Electric Company for Authority to Change Electric Docket No. 3270-UR-118 and Natural Gas Rates DIRECT TESTIMONY OF KENNETH LYONS ON BEHALF OF AIRGAS MERCHANT GASES Q: Please state your name, title and business address. 2 A: My name is Kenneth Lyons. I hold the position of Energy Manager at Airgas Merchant 3 Gases ("Airgas"). My office address is 6990A Snowdrift Road, Allentown, Pennsylvania 4 18106. Airgas operates 15 production plants including the Airgas Wisconsin facility in 5 Madison which is a customer of Madison Gas and Electric Company ("MGE"). 6 Q: Please describe your educational and business experience. 7 A: I graduated from Brigham Young University with a major in Accounting and a minor in 8 Economics. I spent a number of years at Price Waterhouse & Co. and was a Senior 9 Accountant when I left to join one of my clients-Bethlehem Steel Corp. While at 10 Bethlehem Steel, I joined the Energy Management Group as Program Manager-Energy. 11 I oversaw and managed the energy issues at Bethlehem Steel and subsequently lead that 12 same effort at MG Industries and Lehigh Cement before joining Airgas in 2007. In these 13 roles, I worked to effectively measure and manage all aspects of energy cost, including 14 production, sourcing, efficiency, and regulatory policy. Direct Testimony-Airgas-Lyons-1 Q: Have you testified before today in regulatory proceedings? 2 A: Yes. I testified on behalf of Airgas in the MGE Base Rate Cases with the Public Service 3 Commission of Wisconsin Docket Numbers 3270-UR-116, 3270-UR-117 and 3270-UR- 4 117 Reopener. I also testified in Dominion Virginia Power's 2011 fuel proceeding. 5 Q: Can you summarize the Airgas business? 6 A: Airgas is one of the largest producers of atmospheric gases in North America. These 7 gases include oxygen, nitrogen, and argon, which are used in many industries. Our plants 8 clean, compress, refrigerate, and refine air into its individual basic components (i.e., 9 oxygen, nitrogen, and argon). Once separated, Airgas delivers these critical products to 10 industrial, paper, medical, food processing, chemical, construction, and other industries, 11 which in turn use the gases in their own products and services. 12 Over 90 percent of Airgas's electric load is used to power several large motors 13 which drive compressors, which operate 24 hours per day, 365 days per year. Electricity 14 is Airgas's most significant cost. As a consequence, electricity costs determine a 15 facility's competitiveness both internally (among all Airgas-owned facilities) and 16 externally (with respect to Airgas's business competitors). Increases in the cost of 17 electricity necessarily increases production costs, which impacts not only our ability to 18 remain competitive, but also the ability of our customers to remain viable. 19 Q: Please describe your current role with Airgas. 20 A: I work to ensure that our facilities operate in an economic and engineering efficient 21 manner. A primary focus is to keep energy costs for all of our facilities competitive 22 within the industry and to advocate for fair, just, and reasonable energy costs. Failure to Direct Testimony-Airgas-Lyons-2 achieve these goals can have both near- and long-term impacts on our facilities' ability to 2 remain competitive. 3 Q: What is the purpose of your testimony in this proceeding? 4 A: My purpose is two-fold. First, I discuss COSS methodologies generally and explain why, 5 for MGE, production plant (capacity) should be allocated using the utility's single annual 6 system coincident peak (commonly referred to as a 1CP allocation) instead of 12CP, 7 which is the method MGE now uses. 1 The fact is, fully 25 percent ofMGE's capacity is 8 used less than 4 percent of the year. Energy is my business, and I was very surprised to 9 discover that so much capacity sits idle for most of the year. Certainly the average 10 customer-whether residential, commercial, or industrial-has no idea (much less 11 interest) in knowing that utilities build power plants that are used for just a few hours. 12 believe that, for MGE at least, the 12CP method for allocating fixed production costs 13 works against energy conservation because it hides from customers the very high price 14 we pay for MGE to build generation that is used so seldom. 15 I understand that the Commission has long sought ways in which to reduce 16 overall utility costs by providing customers with reasonable price signals. My proposal 17 to use 1CP to allocate fixed production costs, when combined with appropriate revenue 18 allocation and rate design, will provide customers with meaningful price signals that will 1 While the nomenclature is similar, MGE's tariff"Cp-1" should not be confused with the term "1CP", which is unrelated. 1CP refers to the annual coincident system peak-that is, the coincident peak in the single month with the highest system demand. 12CP refers to the average coincident peak for all 12 months. 4CP refers to the average coincident peak in the 4 months with the highest system demands. Direct Testimony-Airgas-Lyons-3 help them understand how their energy use, particularly during very short periods of 2 limited peak use, can effect how MGE incurs costs. 3 Second, I address a reasonable revenue allocation for the Cp-1 rate, which is the 4 MGE tariffurider which Airgas takes service. For several reasons I recommend that the 5 Cp-1 rate be reduced in 2013. MGE's filing shows that the revenues it is receiving under 6 the Cp-1 rate already are greater than MGE's cost to serve the class. Indeed, all three of 7 the cost of service studies ("COSS") that MGE filed in this case clearly show that the 8 Cp-1 rate should receive a rate decrease. Results from my own COSS, which I also 9 discuss, provide additional support for a decrease to Cp-1 rates. While I believe strongly 10 that my COSS proposal, discussed at length here, is one that the Commission should 11 adopt, it is very important that the Commission recognize that even should it not fully 12 agree with me as to the validity ofthe 1CP methodology, the COSS evidence presented 13 by MGE itself fully supports a reduction to the Cp-1 rates. 14 COST OF SERVICE 15 Q: What is the purpose of cost of service studies and revenue allocation? 16 A: COSS are used to identify, as closely as possible, the actual cost a utility incurs to serve 17 specific customers (the customer class). COSS should be used by the Commission-as 18 the starting point for allocating the utility's revenue requirement and designing rates-in 19 a manner that ensures that every customer's decision to use (or not use) electric power is 20 tied to the cost of that use. Commission staff has shared this belief in prior cases stating 21 "[t]he cost to provide electricity should be assigned to customers in a manner that reflects Direct Testimony-Airgas-Lyons-4 the way these cost are incurred by a utility." (Peterson Testimony, 3270-UR-117 (PSC 2 Ref#138164). 3 In a sense, customers should validate both MGE's planning assumptions and 4 investment decisions with their willingness to pay MGE's cost to provide the services 5 they choose. If the rates charged a customer are less than the actual costs to serve that 6 customer, the customer is encouraged to use electricity that may have a value lower than 7 what it cost to provide that service. This is particularly true for discretionary use. Failure 8 to establish rates that serve to check uneconomic use will drive overall system costs 9 higher and raise rates for everyone. Rates that are less than cost also conflict with efforts 10 to increase energy efficiency and reduce the environmental impacts of electric 11 production. On the other hand, rates set above actual cost to serve here will discourage 12 operational efficiency as efficient manufacturing facilities become non-competitive when 13 faced with even less-efficient competitors in jurisdictions which do have accurate price 14 signals for electricity. 15 Unjustifiably shifting costs from one customer class to another has undesirable 16 and unintended consequences. For industries like the one in which Airgas operates, 17 where electricity is such a significant cost component of operations and production, an 18 unjustified increase in energy cost for one class, simply to mitigate the rate impacts 19 caused by another class, can result in the loss of jobs for those employed by companies 20 required to subsidize other classes. Over the last several years, Airgas has had to shift 21 production from Wisconsin to our-of-state facilities to respond to competitive pressures 22 that have included production cost directly related to electricity prices. Direct Testimony-Airgas-Lyons-5 Well thought out COSS are useful tools to clarify for all parties what is causing a 2 utility cost to be incurred, helping understand the system design and cost outcome of 3 those causes and then to determine if the behavioral signals customers are providing the 4 utility to build or not build capacity are effective. With this perspective the rate making 5 process can achieve a fair, efficient and sustainable rate structure for a regulated utility to 6 serve its customers at the lowest possible long-term cost. 7 Q: Do you believe that all COSS methodologies provide meaningful information? 8 A: No, I do not. I recognize that there are several methodologies that most agree have some 9 degree of reasonableness. But I am not aware of anyone who believes that a single COSS 10 methodology applies to all utilities, in all cases. That is, COSS are not one size fits all. 11 The analyst using a particular COSS must have an understanding of the utility system at 12 issue and be able to determine, from that system, what methodology most accurately 13 measures how a customer class causes the utility to incur a particular cost. This requires 14 more than the application of a mathematical formula. It requires one to understand, 15 among other things, system load characteristics and how to identify the most appropriate 16 methodology that reflect actual cost causation for that system. COSS are very instructive 17 and useful to achieve a well thought-out process to drive down overall system cost and 18 improve system efficiency. 19 Q: Have you reviewed the testimony of MGE witness Steve James? 20 A: Yes I have. 21 Q: Do you agree with the approach Mr. James followed for cost allocation? Direct Testimony-Airgas-Lyons-6 A: For some of the costs, but not all. In particular, I disagree with the manner in which he 2 allocates fixed production costs. 3 Mr. James followed a three step process to allocate cost to customer classes, and 4 began by determining whether utility costs are caused by (1) changes in the number of 5 customers (for example, meter costs); (2) changes in the demand imposed by customers 6 (for example, requirements to build capacity); and (3) changes in energy use by 7 customers. I agree with Mr. James that, in general, this is a meaningful approach to 8 classifying cost. However, I do not agree with Mr. James's approach to functionalizing 9 and allocating fixed production costs. MGE's system capacity needs are driven by 10 MGE's forecast of coincident customer class peak use. As a consequence, I believe that 11 these costs should be allocated according to the known and demonstrable impact classes 12 have on MGE's need to plan for and invest for the system peak. While Mr. James offers 13 three different COSS methodologies, he has not explained what MGE system 14 characteristics support one or more of these methodologies. 15 As I suggested earlier in my testimony and will show in greater detail, the 1CP 16 method appears to be the most reasonable methodology for allocating fixed production 17 plant given MGE system characteristics. I do not understand why Mr. James uses 12 CP 18 (the average of MGE's 12 monthly system peaks) to allocate fixed production plant and 19 transmission costs (which the Commission describes in the most recent Strategic Energy 20 Assessment as enormous costs that have significant impacts on customer rates), but does 21 use a single peak for each customer class (NCP) to allocate the majority ofMGE's 22 distribution costs. While his use of 12CP for allocating fixed production costs may be 23 consistent with prior practice, he has not offered any evidence as to why, out of the Direct Testimony-Airgas-Lyons-7 available accepted COSS methodologies, the three he uses best represent the impact each 2 customer class has on MOE's costs. 3 Q: How does Mr. James allocate fixed production cost? 4 A: Mr. James provides several different approaches to allocation. MOE's standard COSS 5 allocates capital investment in production resources based on the average use by a 6 customer class at the time of each of MOE's 12 monthly peaks. MOE's TOU and 7 Location COSS allocate 60% of production capital investment based on the average uses 8 by each customer class at the time of each of MOE's 12 monthly peaks and 40% of 9 production capital investment based each class's on-peak energy use. 10 Q: Do you agree that these allocation methodologies best reflect how the individual 11 customer classes have caused MGE to incur cost? 12 A: No, I do not, because the allocation methodology (using 12CP) fails to account for 13 MOE's primary cost drivers. The Commission in its most recent Final Strategic Energy 14 Assessment, Energy 2016 (PSC Ref.# 145368) (the "SEA") recognized that generation 15 costs are extraordinary, and do not vary with use. MOE must have generation to meet 16 customer use at the period of greatest need (the system peak) and, as can be seen in 17 Figure 1 below, that need currently is for a very short period of time. MOE plans for this 18 peak and knows that it will peak for a brief period of time. We cannot believe that MOE 19 looks to a non-peak month like March to determine whether it needs to build additional 20 capacity, when its peak in June (652 m Ws) is already more than 200m Ws greater than its 21 peak in March (418 mWs). Direct Testimony-Airgas-Lyons-8 Q: Which allocation methodology do you support as most appropriate for the MGE 2 system? 3 A: The 1CP allocation best correlates MGE's costs with the customer classes causing those 4 costs. And 1CP provides the best starting point for improved pricing signals and 5 customer decision feedback, which will improve MGE system efficiency and reduce 6 overall costs to all customers. 7 Q: Why are you focusing your testimony on the allocation of fixed production costs? 8 A: Because it appears that fixed production costs are the primary driver of costs for MGE, 9 and the manner in which they currently are allocated is most clearly not consistent with 10 cost causation. There are many costs drivers, of course. But given the extraordinarily 11 large capital requirements for capacity, and the long-term costs of capacity, whether used 12 or not, I focus on the allocation ofMGE's committed capacity. 13 The Commission recognized the significance of capital investments in its most 14 recent SEA. The Commission expressly recognized that"[e ]lectric utilities are capital 15 intensive-power plants and transmission lines are very expensive to build. About 75 16 percent of a customer's electric bill is fixed-and covers infrastructure investment costs 17 that do not vary with usage, like the cost of power plants and transmission lines." (PSC 18 Ref#145368, at 41-42). Thus, reduced usage leads to increased rates to pay for the same 19 fixed costs, now spread over fewer units. The Commission explained its view that "[i]n 20 the long run, if new power plants can be delayed because conservation has reduced the 21 need for the plants, future bills can be reduced because of the enormous expense of the 22 plants." (SEA, at 42). Direct Testimony-Airgas-Lyons-9 The blunt truth, implicit in the SEA, is this: no matter what steps we take to 2 reduce our average energy consumption throughout the year, new power plants will still 3 need to be built for those very few hours every year that customers choose to close their 4 windows to the outdoor heat and turn on their air to a comfortable temperature. If 5 production plant drives energy costs, as the Commission states in the SEA, then 6 controlling these fixed costs, that arise from customer choices, requires that customers 7 pay for their real contribution to the power plants that they want only a few hours a year. 8 The 12CP methodology is inadequate to meet this task. 9 Q: Can you describe MGE's investment to meet its peak demand? 10 A: Yes. MGE clearly has an obligation to provide its customers reliable service. It must 11 have sufficient generation (or access to generation) to meet the electricity needs of its 12 customers consistent with its agreement to provide firm service to those customers. It 13 must plan a system that has capacity available for all of its firm customers' energy needs, 14 at all times. This means that MGE must have sufficient resources to meet the firm energy 15 demands of all of its customers and, as a practical matter, do so when demand on the 16 system is at its highest-typically that very hot day in the summer when, in addition to 17 the "typical" energy use MGE would see from its industrial, commercial and residential 18 customers, its customers use air conditioning. What we know is that MGE has acquired 19 sufficient capacity to meet the system peak. But by allocating the cost of that capacity to 20 its customer classes using the 12CP methodology, MGE allocation is not reasonable 21 because it does not assign appropriate costs to those customers who are driving the need 22 for that generation that is needed for only a few hours every year. Direct Testimony-Airgas-Lyons-1 0 1 Figure 1 below shows that a significant portion ofMGE's capacity is used only 2 for brief periods of time each year: *********MGE Load Distribution- Actual Hourly Load in 2011 ******** Capacity Annual Percent Of Utilization Load Hours Time Capacity Year2011 mW Utilized Needed Hourly Use At 100% Of Annual Peak 777.9 1 0.01% Hourly Use At 95% Of Annual Peak 739.0 12 0.14% Hourly Use At 90% Of Annual Peak 700.1 28 0.32% Hourly Use At 85% Of Annual Peak 661.2 71 0.81% Hourly Use At 75% Of Annual Peak 583.4 309 3.53% Hourly Use At 50% Of Annual Peak 388.9 4,743 54.14% 3 Hourly Use At 25% Of Annual Peak 194.5 8,760 100.00% 4 MGE's peak load in 2011 was about 779 mWs. It had to have sufficient capacity 5 to meet that load, but only for that one single hour. And there were only 12 hours in 6 2011 in which MGE needed 739 mWs of available generation to meet its customers' 7 energy needs. Indeed, 15 percent of MGE' s capacity was used less than 1 percent of the 8 year, and fully 25 percent of its capacity needs were used less than 4 percent of the year. 9 I am in no way criticizing MGE's need to have sufficient resources available to 10 meet its customers needs, whenever those needs arise. However, we should all 11 understand the extraordinary cost of meeting such isolated needs. In approving the Elm 12 Road Generating Station nearly a decade ago, the Commission noted construction costs 13 of$1,400 I kW or greater. (PSC REF #86450, at 26.) This is $1,400,000 per mW. At 14 this cost, MGE's need to meet the additional customer load that appears just 12 hours 15 every year-38.9 mWs in 2011 (the difference between its 777.9 mW peak and the 739 16 mWs that is needed in the highest 12 hours)-has a capital cost of nearly $55 million. 17 An investment of $55 million to meet load in only 12 hours? And the capacity needed 18 only 4 percent ofthe time-194 mWs-comes at a cost of$250 million. Direct Testimony-Airgas-Lyons-11 I recognize that this cost estimate is very high. Newer technology, and the 2 construction of peaking units instead of base load, would show the actual costs to meet 3 MOE's peak load to be lower than this. But the point I mean to illustrate is that MGE has 4 significantly underutilized generation resources (and it is a utilization rate that is even 5 worse when we include MOE's required reserves-that safety net of capacity above 6 MOE's forecasted peak). If the Commission means to reduce overall system costs, than 7 it can do so by properly allocating capacity costs to those who cause MGE to acquire 8 capacity for such very limited periods of time. 9 The evidence is pretty clear. We are spending enormous amounts to serve very IO short term needs. Unfortunately, the manner in which these costs are allocated in COSS, II and in the rates that are designed to recover MOE's costs, fail to tell any customer how I2 their decisions to use energy impact the system costs, much less their own costs. I3 Given the significance ofMGE's fixed cost, logic requires that a more direct I4 correlation between the actions causing enormous investments and the cost responsibility I5 for the investments made. No other approach will ensure that those receiving benefits I6 from deployment of significant capital validate that the cost is worth the benefit. While I7 an individual customer's decision to use or not use power in each of the 8,760 hours of I8 the year will have an impact on a utility's cost, it is the behavior that impacts the utility's I9 need to spend these enormous amounts on generation capacity to meet the single system 20 peak need that is driving this cost the Commission correctly describes as enormous. 2I In summary, capacity investments are the most significant driver of cost. 22 However, the impact of a customer's use decisions on impacting these costs are masked 23 by multiple COSS allocations being provided to the Commission without providing the Direct Testimony-Airgas-Lyons-I2 Commission any analysis and documentation at to which one of the many options (all of 2 which may be appropriate in some circumstance) best achieves the allocations that 3 represents how customer classes have caused the incurrence of cost by MGE in this case. 4 This process, and the divergence from what are actual costs causations, are preventing 5 customers from making informed decisions about their use. This impacts not only 6 individual class rates, but even more importantly it feeds into the system planning that 7 supports a never ending cycle of lost opportunity to improve system design efficiency. 8 This lack of understanding and failure to communicate to customers the true cost of their 9 loads has a great impact on raising the overall system cost and destroying useful price IO signals that would otherwise improve system efficiency and greater conservation of II energy. I2 Q: Other than offering general statement of methodologies, as others often have, can I3 you provide specific evidence based on the record in this case that supports your I4 conclusion that a 1 CP method would be more appropriate than 12CP? I5 A: Yes, I can. A clear picture is available by examining the load patterns for the five largest I6 MGE customer classes, which account for about 90 percent ofMGE's annual revenues. 17 These rate classes are (Rg-I, Rg-3 and Rw-1), Cg-2, Cg-4, Sp-3, and Cg-5. In my I8 Exhibit I, schedules I through 5, for each respective class I contrast MGE's annual I9 system peak in June with that class's monthly peaks (the blue line), its average peak over 20 twelve months (12CP) (the red line), and its average in the four highest months (4CP) 2I (the green line). These charts show well how the 1CP method for allocating capacity 22 costs differs from the 12 CP and 4CP methods. Direct Testimony-Airgas-Lyons-13 Exhibit Airgas-Lyons-1, Schedule 1, reflects the class use for the residential 2 classes. As is true for all, MGE's system peak is in June, and it builds sufficient capacity 3 to meet that June peak. At the June system peak, the Rg-1 class load-its contribution to 4 the system peak-is 169.4 mWs (represented by the large blue dot). The 1CP 5 methodology that I propose would allocate to the Rg-1 class its portion ofMGE's 6 capacity costs at that time. At the system peak, MGE has planned for and built sufficient 7 capacity to ensure that the 169.4 m W load is met. The 12CP methodology, though, cares 8 little for this actual contribution to the system peak. Instead, it creates the fiction that 9 MGE builds capacity for each individual month, and then considers how the residential 10 class contributes to that individual monthly peak. The result, represented by the red line, 11 is the class average monthly contribution to the average monthly system peak. Thus, 12 despite the fact that residential class's contribution to the system peak is actually 169.4 13 mWs, the 12CP methodology instead allocates to the class only 137 mWs. 14 Exhibit Airgas-Lyons-1, Schedule 2 is a similar chart, now reflecting the Cg-2 15 class use. In June, at the system peak, the Cg-2 load is 180 m W. There is no question 16 that in June, when MGE has its system peak, it must have sufficient capacity to meet the 17 Cg-2 load of 180 m W. The use of 12CP to allocate capacity costs, though, frees the Cg-2 18 customers from paying for much of that capacity. Indeed, under that methodology they 19 are allocated as if their contribution is only about 142 mWs. The class is under allocated 20 capacity costs even if we were to use the 4CP methodology. 21 Exhibit Airgas-Lyons-1, Schedule 3, shows a similar inequity with respect to Cg- 22 4. Its contribution to the system peak is 130 mW, although use ofthe 12CP method 23 allocates to the class as if its contribution to the peak were only 103 m W. Direct Testimony-Airgas-Lyons-14 Exhibit Airgas-Lyons-1, Schedule 4, shows that the Sp-3 class is harmed by the 2 use of the 12CP method. At the system peak, the Sp-3 class has, relative to the rest of the 3 year, less usage than at other times. Its use at the system peak-that is again, what it 4 contributes to the total capacity needs ofthe MGE system-is 51 mWs. But because its 5 average contribution to the system peak, in each ofthe 12 months, is 55 mWs, the 12CP 6 methodology assigns to Sp-3 class more than its true contribution to MGE's total system 7 needs. 8 Ex.Airgas-Lyons-1, Schedule 5 reflects the most out-of-sync relationship between 9 actual contribution to MGE's peak and the 12CP allocation methodology. Under the 10 12CP methodology, the Cg-5 customers' allocation of capacity costs is based on 25 11 m W s. But at that MGE system peak in June, the Cg-5 customer class is responsible for 12 twice that demand. That is, MGE must plan for a Cg-5 need of 50 m W of capacity in 13 June. It must be able to serve that 50 m W load. But because MGE uses the 12CP 14 methodology in its cost allocation, the Cg-5 customers are "responsible" under the 15 methodology as if they only contributed 25 m W to the system. 16 The Cg-5 class use pattern is additional evidence that the 12CP methodology is 17 not appropriate for MGE. It is an example of why better price signals need to be 18 provided to customers so that the customers better understand the cost implication of 19 their behavior and can signal that MGE should continue to invest for that behavior. Or 20 that they understand the cost implications of their behavior and wish to signal MGE that 21 they are changing their behavior. The 1CP will best show customers how their usage 22 drives the need for MGE to plan for and invest in power plants. Direct Testimony-Airgas-Lyons-15 Ifrates are designed such that load that only shows up at the system peak, in fact 2 is a primary driver of the system peak, is not required to bear the significant fixed cost 3 burden of that isolated use (as is now the case), the load will be discouraged from looking 4 at efficiency improvement, load management opportunities, cost effective distributed 5 generation, and other positive energy changes that may more effectively meet its needs 6 (and system needs). 7 Q: Has the Cp-1 class caused MGE to incur capacity cost? 8 A: No, the Cp-1 class has not caused MGE to incur capacity cost. In planning to meet peak 9 generation needs, MGE forecasts its gross system load and then nets out MISO Load 10 Modifying Resources- Demand Response which are callable by the MISO to meet system 11 reliability needs. This is one of the structures available for utilities to reduce capacity 12 investments by participating in MISO's cooperative operation structure designed to 13 minimize invested capital. The Cp-1 load is operated as a MISO Load Modifying 14 Resource - Demand Response and reduced the MISO obligated capacity requirements of 15 MGE. There has been no need, nor would it be prudent for MGE, to build capacity for 16 the Cp-1 class load. In addition to limiting MGE capacity needs, MGE has rights beyond 17 the required MISO curtailment call which are utilized for non-capacity MGE system 18 benefits. 19 Q: Under your proposed allocation, will the Cp-1 class get the benefit of low cost 20 generation without paying for capacity? 21 A: No. The Cp-1 class does not get that benefit today, and it will not get that benefit under 22 the revenue design based on my proposed COSS. Every hour of every day, MGE has Direct Testimony-Airgas-Lyons-16 available at prevailing market prices, energy supply from the MISO market. The hourly 2 rate in this transparent market in 2011 ranged from ($0.1299) to $0.4494 per kWh. While 3 MGE can decide to self-generate or purchase from the market, prudent decision making 4 would direct that the least cost option be selected. Least cost meaning selecting the lower 5 of the variable fuel and other cost that can be avoided or purchase price. This is the same 6 decision that any prudent business operator is making today for their product. Ex.Airgas 7 Lyons-3 reflects a comparison of the variable fuel and purchased power cost allocated to 8 the Cp-1 class as compared to the available transparent MISO energy cost for MGE for 9 both 2011 and for the test year forecast. 10 Consider that in 2011 in each hour MGE made a choice to buy the power to serve 11 the Cp-1 load from MISO at a transparent rate anyone with a computer can verify, or to 12 produce electric energy from their own equipment at their cost. Any decision to produce 13 energy for Cp-1 from the MGE generation would be driven by a conclusion that the MGE 14 generation was at a lower cost, or that there were other system benefits not related to the 15 Cp-1 load that offset the higher cost. The same would hold true for the test year 16 assumptions. What is shown on Ex.Airgas-Lyons-3 is that the allocated fuel costs in the 17 test year are $777,946 higher than the most easily found available power to serve the Cp- 18 1 load. The facts clearly demonstrate that for this case, not only is the Cp-1 class not 19 receiving a benefit from the MOE-owned generation in energy cost, but to the contrary 20 the Cp-1 class is making a significant contribution to offset generation capacity cost it did 21 not cause by absorbing these excess fuel allocations. Direct Testimony-Airgas-Lyons-17 Q: Have you reduced the fuel cost allocation in your COSS to reflect the Cp-1 class test 2 year energy cost shown on your exhibit? 3 A: No, I have not. My proposed COSS does reflect the significant contribution the Cp-1 4 class makes to MGE's fixed cost in the test year. 5 Q: Have you prepared your own COSS? 6 A: Yes, I have. Ex.Airgas-Lyons-2 summarizes my COSS results, based on the cost and 7 load data reported by MGE in this case. I prepared both Standard and Time-of-Use 8 COSS, and for each I allocated capacity using the 12 CP method Mr. James used, the 9 1CP methodology, and a third approach (4CP) that allocates generation capacity based on 10 class use at MGE system peaks in the 4 months with the highest monthly peaks. For the 11 reasons discussed above, the Commission should primarily rely on the 1CP methodology. 12 As shown in Ex.Airgas-Lyons-2, whether a 1CP, 4CP or 12CP method is used, the Cp-1 13 class should receive a rate decrease, as under the standard COSS the results were, 14 respectively, -10.47%,-9.32%, and -5.69%. 15 REVENUE ALLOCATION 16 Q: Do you agree with Mr. James' revenue allocation? 17 A: No, I do not. First, Mr. James' proposed revenue allocation was made with respect to 18 COSS results that no longer are true. With an overall increase of 5.82%, Mr. James 19 proposed an increase to the Cp-1 Rate Class of 4.28% ($219,000). This was, apparently, 20 based on his own results that showed a decrease of 5.69% under the standard COSS, and 21 increases of around 5% under the Time of Use and Location COSS (with respect to Cp-1 Direct Testimony-Airgas-Lyons-18 Class, the Time of Use and Location COSS are nearly identical, as the Cp-1 class has 2 almost no distribution facilities owned by MGE). At the time of his revenue allocation 3 testimony, he provided no support for giving greater weight to the non-standard COSS 4 than the standard COSS. Indeed, even if one concluded that the COSS were equally 5 credible, the results of these COSS would still support a decrease for the Cp-1class. 6 In early August, though, Mr. James filed a corrected COSS, which results show a 7 decrease for the Cp-1 class under all ofMGE's COSS. See Ex.-MGE-James-1r, page 6 8 of 6. That is, the results of all COSS of record show that the Cp-1 class should receive a 9 decrease in rates. With these results, Mr. James' proposal to increase the Cp-1 rate class 10 by more than 4% (and Airgas' electric rates by nearly $220,000) is completely without 11 support. 12 Moreover, as shown in my Ex.-Airgas-Lyons-2, my own COSS results show that 13 the Cp-1 rate class, under the preferred 1CP allocation methodology, shows a more than 14 double-digit decrease. The overwhelming evidence provided by MGE itself, coupled 15 with the COSS results I have submitted here, support a sizeable rate decrease for the Cp-1 16 class. Of course, at the same time I recognize that when allocating revenue responsibility 17 the Commission must take into consideration other factors, including bill impacts. And I 18 know that the Commission cannot well increase some customers rates substantially, while 19 reducing other customers' rates substantially. In light of the objective results of this case 20 and the subjective need to soften what could be large increases to some customer classes, 21 I propose a very modest decrease to the Cp-1 class and moderate the increases to several, 22 but not all, other classes. Direct Testimony-Airgas-Lyons-19 Q: Have you prepared a revenue allocation? 2 A: Yes, I have. Ex.Airgas-Lyons-4 provides my proposed revenue allocation to all classes at 3 the overall system increase of 5.82 percent. I propose a 1 percent decrease to the Cp-1 4 class. This is consistent with the results of Mr. James' COSS (all ofwhich show a 5 decrease), and is considerably less of a decrease than is supported by the I CP 6 methodology (showing a decrease of greater than 10 percent). Consistent with 7 Commission's past practice, I limit increases to other customer classes so that none are 8 more than 1.5 percentage points above the system average increase of 5.82 percent. 9 Should the Commission's audit result in a substantial change to MGE's overall revenue 10 requirement, I may update my COSS and proposed revenue allocation to reflect Staff's 11 audit. I anticipate that if the Staff audit results in a smaller revenue increase than the 12 more than $22 million that MGE is seeking, my proposed revenue allocation to all 13 customer classes will be reduced. 14 Q: . Does this complete your direct testimony? 15 A. Yes, it does. 8370805 4 Direct Testimony-Airgas-Lyons-20 PSC REF#:l70 63 1 BEFORE THE 2 PUBLIC SERVICE COMMISION OF WISCONSIN 3 Application of Madison Gas and Electric 4 Company for Authority to Change Electric 5 and Natural Gas Rates Docket No. 3270-UR-118 6 7 8 DIRECT TESTIMONY OF DARCY A. F ABRIZIUS ON 9 BEHALF OF CONSTELLATION NEWENERGY- GAS DIVISION, LLC 10 11 12 Q. Please state your name, business address, and current position. 13 A. My name is Darcy A. Fabrizius. I am a Regulatory Affairs Manager at Constellation 14 NewEnergy - Gas Division, LLC ("CNEG"). My office is located at N21 W23340 15 Ridgeview Parkway, Waukesha, WI 53188. 16 Q. Please summarize your educational background and work experience. 17 A. I graduated from Gustavus Adolphus College, St. Peter, MN in June 1979 with a 18 Bachelor of Arts Degree. I received a Masters of Business Administration degree in 19 December 1981 from the University of Minnesota. My background includes ten years of 20 marketing experience with a telecommunications utility. I have been in my current 21 position since February of 1997. 22 Q. Please describe CNEG's business? 23 A. CNEG is a full-service natural gas marketer that supplies natural gas and related 24 transportation services to more than 16,000 commercial and industrial customers, 25 municipalities, local distribution companies and cogeneration facilities, including 26 customers in the service territory of Madison Gas and Electric Company ("MGE", or the 27 "Company"). CNEG' retail natural gas market includes 30 U.S. states and two Canadian Direct- CNEG- Fabbrizius- 1 1 provinces. In addition to our office in Wisconsin, CNEG is headquartered in Louisville, 2 Kentucky and has regional offices in Michigan, Ohio, Illinois, California, Oklahoma, 3 Maryland, New York, Pennsylvania, Missouri, Arkansas, Kansas, Minnesota, Iowa and 4 Nebraska. CNEG is a wholly owned indirect subsidiary of Exelon Corporation 5 ("Exelon"). Headquartered in Chicago, Exelon is the largest U.S. competitive power 6 generator. Exelon utilities deliver electricity and natural gas to customers in Illinois, 7 Pennsylvania and Maryland. Exelon subsidiaries also provide competitive wholesale and 8 retail electricity and gas supply, energy management and consulting services nationwide. 9 CNEG and its predecessor, Kaztex Energy Management, have been serving 10 transportation customers in Wisconsin for over twenty years. 11 Q. What is the purpose of your testimony in this proceeding? 12 A. The purpose of this testimony is to address the supplemental direct testimony of Mr. 13 Timm Minor wherein he discusses the Company's Schedule NGV: Distribution Service 14 for Natural Gas Vehicles and Schedule FS-3: Firm Gas Sales Service for Natural Gas 15 Vehicles (PSC Ref# 167583 & 167584). 16 Q. According to Mr. Minor, these tariffs will enable MGE "to promote the use of CNG 17 in a number of different ways to the rapidly evolving CNG market." (Supplemental 18 Direct-MGE-Minor-4) Do you concur that the CNG market is rapidly evolving? 19 A. Most emphatically yes. On a weekly basis, and sometimes even daily, there is an 20 announcement, press release or news story about some new development, study, 21 initiative, or legislation that relates to alternative fuels and the use of CNG to fuel 22 vehicles. Earlier this month, at the initial request of Secretary Chu of the Department of 23 Energy, the National Petroleum Council released its multi-year study Advancing Direct- CNEG- Fabbrizius- 2 1 Technology for America's Transportation Future. According to this report, if the 2 expansion of recoverable shale reserves "evidenced in recent years continues to result in 3 sustainable long term and stable price advantages relative to petroleum fuels, there are 4 economic incentives for increased use of natural as in the transportation section." 1 5 Coupled with the opportunity to reduce greenhouse gas emissions and U.S. dependence 6 upon foreign oil, natural gas vehicles ("NGV") may be at the launch of significant 7 upward momentum in use. 8 Closer to home, on April 11, 2012 Governor Walker announced a series of at least four 9 public roundtables throughout Wisconsin on natural gas as a transportation fuel and to 10 identify opportunities to expand the use of compressed natural gas ("CNG") vehicles. 11 Two well-attended sessions have already taken place. NGV initiatives are likewise 12 taking place across the county. On May 31st, the Pennsylvania Public Utilities 13 Commission hosted a forum to examine alternative fuel vehicles ("AFV"), specifically 14 including technologies which utilize natural gas and more recently the Governors of 15 Oklahoma and Colorado announced a 22 state request for proposal for 1,800 CNG 16 vehicles. It is evident to me that the CNG market is rapidly evolving. My concerns lies 17 not with the timeliness of a tariff targeted to NGV use, but with the manner in which 18 MGE has chosen to structure their tariff. 19 Q. Please comment on MGE's Schedules NGV and FS-3. 20 A. MGE designed these two schedules to function in conjunction with each other; they are 21 "intended to respond to customer demand, promote the adoption of environmentally 22 beneficial uses of natural gas, create new opportunities for either end-use fleets or service 1 National Petroleum Council, "Advancing Technology for America's Transportation Future" Draft (August 1, 2012), Natural Gas Analysis, NG-1. Direct- CNEG- Fabbrizius- 3 1 providers, and provide a future net benefit to ratepayers and shareholders alike." 2 (Supplemental Direct-MGE-Minor-4) However, no sales projections or quantification of 3 customer demand are provided by MGE. MGE offered no evidence to either support or 4 quantify the net benefits to either ratepayers or shareholders. Furthermore, in its 5 provision of Schedule NGV, MGE proposes, through a regulated natural gas distribution 6 utility, to offer services that are competitively available in the marketplace. MGE further 7 bundles these two schedules so that a customer electing Schedule NGV is required to 8 purchase its gas supply from the utility in order to obtain the services offered in Schedule 9 NGV? 10 Q. What are the services which MGE may provide to customers via Schedule NGV? 11 A. Based on Schedule NGV (PSC Ref# 167584), a customer may receive: 12 • Distribution service on a firm basis from MGE; 13 • Compression service via facilities owned by MGE; 14 • Planning, designing, procuring, installing, constructing and engineering of the 15 compression facilities by MGE; and 16 • Maintenance of compression facilities by MGE. 17 Q. Why does the manner in which MGE has structured Schedules NGV and FS-3 18 concern you? 19 A. While MGE's intention to promote environmentally beneficial uses of natural gas and 20 create new market opportunities is laudable, there are several issues that arise with these 21 Schedules. Certain of the services offered in Schedule NGV extend beyond traditional 22 monopoly services of utilities. Rather, these are services which can be obtained from any 2 According to Schedule NGV, Sheet G- 41, "Customers taking service under this rate schedule must receive their full gas supply service requirements under the Company's FS-3 rate schedule (PSC Ref# 167584). Direct- CNEG- Fabbrizius- 4 1 number of competitors in the marketplace. When regulated utilities provide services 2 which directly compete with non-utility businesses, market distortions and an unfair 3 competitive environment may result. 4 In a 2012 report prepared by TIAX for America's Natural Gas Alliance, the researchers 5 discuss four main categories of companies that have the most involvement in CNG 6 infrastructure development: 1) compressor manufactures/suppliers/packagers, 2) 7 engineering companies, 3) construction companies, and; 4) CNG retailers. This report 8 describes the first category as either manufacturers of compressors who then assemble 9 them with other components into complete fueling systems or companies which purchase 10 compressors from a manufacturer and then assemble them with other required 11 components, and then distribute CNG fueling systems. For many of these companies, 12 compression manufacturing is a segment of a larger industrial gas compression business. 13 These companies are usually privately held and provide fueling equipment through a 14 construction company.3 This suggests there are competitive businesses from which to 15 secure compression services as contemplated by MGE in Schedule NGV. While the firm 16 distribution service offered in Schedule NGV remains a traditional monopoly service to 17 be provided by a regulated utility, other services in this Schedule are not. 18 Q. Do regulated utilities provide CNG fueling stations, including both compression and 19 dispensing services, in certain jurisdictions? 20 A. Yes, in some states LDCs operate CNG fueling stations; some states even allow rate base 21 cost recovery. However, in other jurisdictions, such as California, LDCs are explicitly 22 prohibited from including CNG infrastructure costs in their rate base unless the station 3 America's Natural Gas Alliance, U.S. and Canadian Natural Gas Vehicle Market Analysis: Compressed Natural Gas Infrastructure Final Report, prepared by TIAX, page 30. Direct- CNEG- Fabbrizius- 5 1 primarily serves their own fleet. 4 Certainly though, whenever non-core, competitively- 2 available services are provided through a regulated utility, certain issues thereby arise 3 such as what is appropriate cost recovery, whether all costs are fully allocated, if it is 4 proper that certain costs are recovered from captive rate base, if it's fitting to use the 5 same cost of capital as that used for core services, whether any cross subsidization exists, 6 etc. MGE's filing begs examination of these matters on behalf of Wisconsin rate payers. 7 Q. Are there considerations beyond cost recovery? 8 A. Yes. While CNG vehicles have existed for many years, current natural gas economics, 9 technological advances, environmental and domestic energy policy considerations are 10 injecting new life into this market. From 2003 to 2010, the International Energy Agency 5 11 estimated that globally NGV markets compounded annual growth rate was 23.2%. 12 While today NGVAmerica ranks the U.S. 1ih in the world with less than I% of the total 13 NGVs, North America is now expected to experience some of the fastest growth due to 14 its abundant, low-cost, domestically produced natural gas. 15 With unprecedented growth expected, Wisconsin must decide what the appropriate role 16 of natural gas utilities is in the future in NGV markets. This matters as increasingly there 17 are private firms who are investing private capital in CNG fueling infrastructure. Earlier 18 this year, Kwik Trip opened a CNG fueling pump in La Crosse and announced the 19 addition of several other sites in Wisconsin. This month, Express Convenience Centers 20 plans to open a CNG fueling pump in Marinette and also plans for more locations 21 throughout the state. The Commission needs to ask whether utility participation will lead 4 Ibid, page 38. 5 National Petroleum Council, "Advancing Technology for America's Transportation Future" Draft (August 1, 2012), Natural Gas Analysis, NG-10. Direct- CNEG- Fabbrizius- 6 1 to unfair competition and market confusion, and discourage private capital investment in 2 this market. Regulators should consider what they can do to create a level playing field 3 while best protecting rate payers. And it should be evaluated as to whether this market is 4 better served if utilities provide non-core NGV -related services through affiliates, rather 5 than directly as utility service. 6 Q. Are Commissions elsewhere grappling with these questions? 7 A. Yes. A utility compression services tariff is currently being contested in California. Due 8 in part to its stringent air emissions requirements, California is the state with the highest 9 development ofNGV and CNG fueling infrastructure. According to the U.S. Department 10 of Energy's Alternative Fuels Data Center, California has 141 public CNG stations 11 compared to 20 in Wisconsin and, as of 8/21112, 511 in the entire US. Last November, 12 Southern California Gas Company filed application 11-11-011 requesting authority to 13 offer "a new tariff service to meet the current and future needs of non-residential 14 customers requiring natural gas compression above the standard line pressure for 15 customer end-use applications." Two companies filed protests arguing the utility tariff is 16 anti-competitive. Before making a utility compression service permanent in Wisconsin, 17 the long-term ramifications of such a determination on the market should be considered 18 by the Commission. 19 Q. Thus far you raise several issues for consideration, but take no definitive positions 20 on those issues. Do you have any explicit positions in regards to MGE's Schedule 21 NGV and FS-3? 22 A. Yes, there is one aspect ofMGE's proposal to which I am strongly opposed as it is most 23 certainly anti-competitive. For decades in Wisconsin, non-residential gas consumers Direct- CNEG- Fabbrizius- 7 1 have had the opportunity to participate in competitive markets by purchasing their gas 2 supply from non-utility sources. In 1995, the Wisconsin Commission confirmed its gas 3 industry policy in Docket No. 05-GI-1 08 (Phase 1): 4 Competitive markets are preferred to regulation. Regulatory actions 5 should not frustrate or impede appropriate movement to the most 6 competitive model. . . .One of the benefits of competition should be 7 increase customer choice. (Public Service Commission of Wisconsin, 8 Findings of Fact, Conclusions of Law and Phase I Order, Docket 05-GI- 9 108 (Phase 1), November 30, 1995, page 4.) 10 11 MGE's Schedules NGV and FS-3 disregard this as, in order to obtain the services in 12 Schedule NGV, a customer must obtain its gas supply exclusively from the utility. A 13 customer has no choice; there is no opportunity to obtain its gas from a competitive 14 supplier. While We Energies NGV Service is also a bundled service restricted to sales 15 customers, We Energies tariff does not extend beyond utility distribution service to offer . . 16 compress10n services. 17 Q. Mr. Minor suggests the demand charge credit in the MGE tariff is similar to that 18 currently authorized in We Energies' NGV tariff. (Supplemental Direct-MGE- 19 Minor-7) Do you concur? 20 A. No. Based on my understanding, the credit in Wisconsin Electric- Gas Operations 21 Schedule x-131 and Wisconsin Gas LLC Schedule x-131 is two-thirds of the effective 22 peak day demand, but does not provide any credit of annual demand. As I understand the 23 MGE tariff, the MGE credit is based on both the annual demand rate and, when in effect, 24 seasonal demand. (Supplemental Direct-MGE-Minor-7) 25 Q. Do other utilities that offer special NGV tariffs offer both sales and transportation 26 service options for the natural gas commodity? Direct- CNEG- Fabbrizius- 8 1 A. Yes. In Illinois, Peoples Gas Light and Coke Company offers CNG Service. While the 2 customer must provide the compression, commodity can be obtained either via sales or 3 transportation service. Southern California Gas Company's exiting tariff for natural gas 4 service for motor vehicles, Schedule No. G-NGV, allows the customer to select 5 transportation service while requiring the customer to provide compression. Thus, it is 6 feasible for a utility to structure a NGV service to allow customers the option to purchase 7 the gas commodity via either sales or transportation service. 8 Q. Based on your testimony, are you suggesting that special natural gas tariffs should 9 not be approved by Commissions? 10 A. No. I do not object to special NGV rates by utilities for the distribution of natural gas 11 dedicated to vehicle fueling. As CNG fueling load is relatively stable and not seasonally 12 driven, it may be reasonable to remove storage or peak natural gas pipeline capacity 13 related costs from the development of rates in order to offer a special distribution rate 14 class for customers. It may be appropriate for a Commission to authorize a dedicated rate 15 based on the cost of delivery of natural gas when it is used exclusively for the fueling of 16 vehicles. What I object to is a tariff which limits customer choice of commodity to gas 17 only obtained from the utility. 18 Q. Please summarize your recommendations. 19 A. I recommend the following: 20 • The Commission rejects any bundled tariff approach which provides special NGV 21 services which require the customer to purchase its gas commodity from the utility; 22 • Any special NGV tariff allows customer choice for its commodity purchase; Direct- CNEG- Fabbrizius- 9 1 • The affects on long-term market development and the nurturing of properly 2 functioning competitive markets are evaluated before permitting a utility to offer 3 NGV -related services that extend beyond traditional utility distribution service; and, 4 • If after throughout evaluation the Commission determines it will permit a regulated 5 utility to provide non-core services to the NGV marketplace, it require the utility to 6 provide such services through an affiliate subject to appropriate standards of conduct 7 between utilities and their affiliates. 8 Q. Does this conclude your testimony? 9 A. Yes. Direct- CNEG- Fabbrizius- 10 PSC REF#:170850 Public Service Commission of Wisconsin Direct Testimony of Robert C. Bauer Gas and Energy Division Madison Gas and Electric Company Docket 3270-UR-118 August 27, 2012 Q. Please state your name, business address, and occupation. 2 A. My name is Robert C. Bauer. My business address is Public Service Commission of 3 Wisconsin (Commission), 610 N. Whitney Way, P.O. Box 7854, Madison, Wisconsin 4 53707-7854. I am employed as a Utility Rate Analyst in the Gas and Energy Division. 5 Q. Would you please state your educational background and summarize your duties with the 6 Commission? 7 A. I am a 1977 graduate of the University of Wisconsin Oshkosh with a Bachelor of 8 Business Administration degree with a major in accounting. I have been employed with 9 the Commission since May 1977, first as an Auditor, then as a Public Utility Rate 10 Analyst from February 1982. 11 Q. What is the purpose of your testimony? 12 A. The purpose of my testimony is to discuss Madison Gas and Electric Company's (MGE) 13 proposal to provide compressed natural gas service on a pilot basis, discuss a new supply 14 service rate for gas sales for natural gas vehicles (NGVs), and to discuss MGE's current 15 rate for gas sales directly to NGVs. 16 MGE proposes to promote natural gas vehicle service in three different ways: 17 1. Compressed distribution service: MGE proposes to provide compressed natural gas 18 distribution service to customers who do not own or maintain their own compression 19 facilities through a combination of its proposed distribution service for NGVs (Schedule NGV) and a gas supply service, Firm Gas Sales Service for NGVs 2 (Schedule FS-3). Natural gas distribution service would be provided to customers 3 after compression of the natural gas. Customers would pay for general distribution 4 service at the same level as the General Service Distribution (GSD) class they qualify 5 for and, in addition, pay compression costs through a fee for the compression energy 6 and a customized contract fee for the compression facilities. The customers would 7 also pay for gas used under Schedule FS-3, which provides for a credit that is not 8 available to subscribers of the standard firm gas sales service. Customers taking 9 service on the above two services could resell the gas to end-use customers. 10 2. Firm gas sales service for NGV: MGE proposes to provide service to customers who 11 own and operate their own compression facilities through the combination of its 12 existing commercial and industrial distribution service tariffs (GSD-1, GSD-2 and 13 GSD-3) and its proposed Schedule FS-3. As stated above, Schedule FS-3 is a firm 14 gas sales service tariff that provides for a credit that is not available to subscribers of 15 the standard firm gas sales service. 16 3. MGE retail NGV service: In addition to the two new services described above, MGE 17 proposes continuing to offer end-use service through its CNG-1 tariff at a higher rate 18 comparable to the combined rates under NGV/FS-3. 19 DISTRIBUTION SERVICE FOR NATURAL GAS VEHICLES 20 Q. Please describe MGE's proposed compressed natural gas service (CNG). 21 A. MGE has filed a tariff, Distribution Service for NGVs, which provides availability to: 22 " ... any nonresidential customer requiring compressed natural gas 23 (CNG) whose use is intended for motor fuel for natural gas vehicles. 24 Other acceptable uses of CNG provided herein will be subject to all 25 terms of this rate schedule including applicability of road-use taxes." 2 Q. MGE's distribution main pressure is 60 pounds per square inch. The current tariffs 2 provide for greater pressures upon the written request of the customer, subject to a 3 number of conditions. 1 Do you believe these provisions consider requests for pressures 4 requiring utility compression? 5 A No. In a situation where higher pressure service is requested (such as in service to power 6 generation facilities), it is typically limited to areas where higher pressure gas is already 7 available at the customer's premises or may be made available in accordance with the 8 rules governing gas service extensions. In other words, if the prevailing pressure at the 9 distribution system or nearby interstate pipeline is less than the customer's needs, then 10 most often the customer is responsible for gas compression. With regard to compressed 11 natural gas service, I believe the provisions that provide for greater pressures would not 12 apply and MGE would deliver gas to a customer under ordinary pressures. This means it 13 would be a customer's responsibility to compress the gas for NGVs. 14 The customer would choose either a slow-fill or fast-fill process. In a slow-fill 15 process, a compressor pumps compressed natural gas directly into the vehicle tank 16 without intermediate storage. In a fast-fill process, a compressor pumps compressed 17 natural gas into a storage tank before it is filled into the vehicle tank. It may take several 18 hours to slow-fill a vehicle; however, many fleet operations choose slow-fill when it can 19 easily be performed during non-working hours at off-peak electric rates. 20 Q. Does MGE plan to provide a slow-fill or fast-fill compression facility? 21 A. MGE plans to provide fast-fill compression facilities to customers that can provide 22 refueling to any NGV customer on a retail basis. A typical customer would be a retail 23 provider of other fuels, including gasoline and diesel fuel. 1 Madison Gas and Electric Gas Tariffs, Gas Rules and Regulations: Meter Installations, Sheet G-47.2. 3 Q. Did Commission staff reduce MGE's test-year plant investment for costs associated with 2 a natural gas fast-fill compression facility? 3 A. Yes, staff reduced MGE's test-year plant investment by $800,000. This is the estimated 4 cost of a fast-fill compression facility that MGE plans to place into service at a customer 5 site. 6 Q. What factors could be considered when the Commission decides whether the cost of such 7 a facility should be included in MGE's gas net investment rate base? 8 A. Ultimately, the decision depends on whether CNG service should be a utility-provided 9 service. NGV market growth is strong world-wide. Some states are actively developing 10 NGV markets by converting state fleets2 to natural gas, providing grants for retail NGV 11 supply facilities, developing NGV transportation corridors to facilitate intrastate 12 transportation and, allowing utility rate recovery for CNG facilities. 13 There is renewed interest in the NGV market given the possibility that natural gas 14 prices will remain cheaper than either gasoline or diesel prices in the future. Truck fleets 15 began converting to diesel in 1972 when diesel was cheaper than gasoline. With natural 16 gas $1.50 cheaper per a diesel-equivalent gallon, today's fleets have already started 17 converting to natural gas. However, many fleets are hesitant to convert given the lack of 18 a compressed natural gas distribution infrastructure. 19 In 2007, California Energy Commission prepared an alternative fuels plan that 20 stated: "Private sector investment, including investor-owned and municipal utilities, 21 should be encouraged to become major new investors in the development and 2 Governors of Colorado, Wyoming, Pennsylvania, Oklahoma, Virginia, Ohio, Maine and West Virginia plan to convert state fleets to NGVs. Kathryn Clay, Ph.D., Executive Director of the Drive Natural Gas Initiative. 4 commercialization of electric drive and natural gas vehicles."3 The state of California 2 also set goals for the conversion of vehicles to clean alternative fuels. In its filing of a 3 Compression Services Tariff in late 2011, Southern California Gas Company (SoCalGas) 4 testified that since the state of California's conversion plan adoption, "market growth of 5 natural gas vehicle fuel is not keeping pace either with the conservative or moderate 6 forecasts as presented in the state plan .... Actual growth has been only about a third of 7 the rate required to meet the moderate forecast and about 30% below that rate required to 8 meet the conservative forecast."4 SoCalGas also testified that utility service including the 9 compression of natural gas for NGV customers would support the NGV market and help 10 the state achieve its planned growth targets. 11 Environmental and economic factors, such as NGV greenhouse gas emissions are 12 29 percent lower than comparable gasoline light-duty vehicles, and the fact that domestic 13 natural gas production would increase jobs in the United States and decrease our 14 dependence on foreign oil, have also led to a renewed interest in natural gas vehicle 15 market. 16 MGE's proposed tariffs are similar, in part, to SoCalGas's tariff that provides for 17 the installation, operation and ownership of compression facilities on customer premises 18 to support CNG needs. 19 The Public Service Commission of Utah has made a regulatory commitment to 20 NGV by finding that: (1) the NGV program is in the public interest, (2) the gas utility is 21 the logical leader/expert, (3) CNG infrastructure belongs in rate base, and (4) subsidized 22 can rates jump-start the market. 3California Energy Commission- State Alternative Fuels Plan, dated December 2007, page 8. 4 Chapter I Policy Support Prepared Direct Testimony of Jeffrey G. Reed in the Matter of Application of Southern California Gas Company (U904G) to establish a Compression Services tariff. 5 The Commission could adopt a position that would allow utilities to foster the 2 NGV market while the market matures. In this case, the Commission would consider 3 NGV to be in the public interest with a need for utility participation given the utilities' 4 natural gas experience and ability to finance distribution facilities to jump-start the NGV 5 market in Wisconsin. With this approach, the ratepayers' interest could be served both 6 from an economic and environmental perspective. Many believe that, over time, NGV 7 performance and investment will increase while NGV costs decrease. If the market 8 develops and sales increase, the additional revenue would provide a net benefit to all 9 other ratepayers. 10 The Commission could also consider provisions that would limit the money spent, 11 the number of compressing stations (i.e., 10 units @ $800,000/unit), or the duration of 12 such activities (i.e., three years). When MGE first filed its proposal with the 13 Commission, it stated that the service should be viewed as a pilot program.5 The tariffs, 14 as proposed, were filed with this Commission. In accepting the tariffs for filing the 15 Commission stated: "Approval is not a final determination as to the reasonableness of the 16 rates, applicability of utility service or the scope of the 'pilot' offering. The proposed 17 service, the need for a tariff, and the reasonableness of the rates on a formal basis will be 18 further examined in docket 3270-UR-118, Application ofMadison Gas and Electric 19 Company for Authority to Change Electric and Natural Gas Rates with a final 20 determination made by the Commission in that docket."6 21 MGE witness Timm Minor did not discuss how to limit this program on a pilot 22 basis in his supplemental testimony (PSC REF#:167583). In my discussions with MGE, 5 Per MGE letter dated May 4, 2012 (PSC REF#: 164239). 6 Per letter dated May 23, 2012, from Robert Norcross, Administrator, Gas and Energy Division (PSC REF#: 165050). 6 it agreed to develop limits in this docket so that utility-owned compression can be 2 evaluated on a pilot basis without exposing the utility or its customers to undue risk. For 3 example, the pilot could establish limits with respect to the program's duration, number 4 of customers, proximity of other dispensing locations and overall capital expenditure. 5 When considering MGE's request, the Commission could adopt a position that 6 utilities should simply react to the demand for NGV and not foster the NGV market. 7 Presently, most fleets (i.e., transit and refuse vehicles) have their own "private" stations 8 where the utility meter is placed before the customers' compressors. 9 Integrys, a holding company that owns Wisconsin Public Service Corporation, has 10 also chosen to participate in the CNG market. It is doing so through an affiliate 11 company, Integrys Transportation Fuels. Integrys Transportation Fuels invests in the 12 CNG infrastructure suited to its customers' needs. It owns two companies: Trillium 13 CNG, the second largest provider of CNG in the U.S., and Pinnacle CNG, a manufacturer 14 of CNG refueling equipment. 15 Q. If the proposed Distribution Service for Natural Gas Vehicles, Schedule NGV tariff, is 16 approved, would MGE recover its cost of providing such service from the appropriate 17 customers? 18 A. No. The test-year sales estimate at the proposed rate levels would not recover MGE's 19 cost of providing compressed distribution service. The rate recovery is based on a " ... 20 long-term estimate of sales as a way to balance the need to provide rate stability to the 21 participating convenience store with the potential short-term cost and long-term benefits 22 to the other distribution customers ofMG&E."7 I believe it is reasonable to state that the 23 cost will likely be subsidized until the long-term sales estimates are achieved. To reduce 7 Supplement Direct Testimony of Timm A. Minor of Behalf of Applicant, page 6, lines 2-6. 7 such a subsidy, the compression facilities charge could be increased to limit some of the 2 short-term costs. However, this option would transfer more of the financial risk to the 3 retail NGV service provider and discourage customers from subscribing to this service. 4 SUPPLY SERVICE FOR NATURAL GAS VEHICLES 5 Q. Have you reviewed MOE's proposed Firm Gas Sales Service for Natural Gas Vehicles, 6 Schedule FS-3? 7 A. Yes, I have. It is a natural gas supply service for customers using gas supply exclusively 8 for the purpose of compressed natural gas. Mr. Minor states that it is different from 9 MOE's Firm Gas Sales Service, Schedule FS-1, because it will include a demand charge 10 credit on the given month's effective annual and seasonal demand charges. Mr. Minor 11 also states that it is similar to the tariffs of Wisconsin Electric - Gas Operations and 12 Wisconsin Gas Company. Wisconsin Electric- Gas Operations and Wisconsin Gas LLC 13 (the Companies), however, have a Demand Charge Credit on file with this Commission 14 that is limited to seasonal peak demand charges and no credits are made for annual peak 15 demand charges. MOE's Demand Charge Credit includes both seasonal peak demand 16 and annual peak demand charges. 17 MOE's proposed Firm Gas Sales Service for NGVs could be modified to more 18 closely resemble the Companies' tariffs. In the alternative, the Demand Charge Credit 19 could be eliminated and then regular firm service rates would apply. Eliminating the 20 demand charge credit would have NGV customers contribute toward MOE's interstate 21 pipeline costs in the same manner as firm sales service customers. Eliminating the 22 demand credit would basically eliminate this tariff. Presently, CNG prices for NGVs are 23 $1.50 less than regular gasoline prices. There may be little reason to discount the cost of 8 natural gas when the economics are already in its favor, although it is fair to say that it 2 can impact the customer's payback period and ultimately the decision of some customers 3 with other more favorable investment opportunities. 4 RETAIL SERVICE FOR NATURAL GAS VEHICLES 5 Q. Mr. Minor states in his direct testimony, page 16, line 15, that MGE's current CNG-1 6 tariff sets forth rates for CNG service that MGE provides at the nozzle. Is this similar to 7 the same service that other third-parties could be providing? 8 A. In my opinion, the CNG service at the nozzle is the same service regardless of the service 9 provider. As such, I do not consider MGE's service to be a utility service any more than 10 I consider the service of a third-party provider (i.e., Kwik Trip) a utility service. MGE's 11 current CNG-1 tariff that allows it to provide end-use, retail CNG service to NGV is not 12 consistent with the Commission's Final Decision in 05-UR-102, dated January 26,2006, 13 where the Commission denied Wisconsin Electric-Gas Operations and Wisconsin Gas 14 LLC's request for a Natural Gas Refueling Service tariff that would have established a 15 retail refueling service rate equal to the companies' monthly cost of natural gas. In this 16 Final Decision, the Commission stated that it would be inappropriate to file a tariff for 17 service that is not under the jurisdiction of this Commission. In an earlier decision in 18 Petition of Wisconsin Gas Company for a Declaratory Ruling as to Whether Sellers of 19 Compressed Natural Gas are Public Utilities Under Section 196.01 (1), Wisconsin 20 Statutes, docket 6650-DR-3 dated October 9, 1984, the Commission ruled that the sale of 21 CNG through a hose to a motor vehicle does not constitute utility service under Wis. Stat. 22 § 196.01(1). 9 If MGE continued this service in the unregulated market, the possibility of 2 improper cross-subsidization between the regulated and non-regulated activities exists. 3 At this time, cross-subsidization would be insignificant. If a natural gas refueling service 4 becomes a substantial business, though, the Commission will need to keep track of 5 cross-subsidies just as it does with other unregulated activities. 6 Q. In other words, MOE's Compressed Natural Gas Distribution Service, Schedule CNG-1, 7 should be removed from its filed tariffs? 8 A. Yes. A competitive market already exists for this service. 9 Q. Would you summarize the issues and alternatives? 10 A. There are basically three issues. The issues and alternatives are shown below: 11 Issue One: Should MGE offer a compressed natural gas distribution service to 12 customers who are providing retail service to NGVs? 13 Alternative One: Approve MOE's request to file tariffs for compressed natural 14 gas distribution service and include the cost of facilities providing the service as utility 15 plant in service. This alternative fosters the NGV market that could prove beneficial to 16 other ratepayers in the long run. 17 Alternative Two: Deny MOE's request to file tariffs for compressed natural gas 18 distribution service and exclude the cost of facilities providing the service from utility 19 plant in service. Denying MOE's request to provide compressed natural gas distribution 20 service would eliminate the financial risk to other ratepayers and provide opportunities 21 for others to participate in the market place. 22 Alternative Three: Subject to modification, approve MOE's request to file 23 tariffs for compressed natural gas distribution service and include the cost of facilities 10 1 providing the service in utility plant in service. This alternative could foster the NOV 2 market while limiting the financial risk to other ratepayers. 3 Issue Two: Should MOE offer a firm natural gas supply service that includes a 4 discount from the standard firm natural gas supply service to customers filling NOVs? 5 Alternative One: Approve MOE's request to file tariffs for a firm natural gas 6 supply service for NOVs. A discounted firm natural gas supply service for NOVs would 7 improve the economic advantage of natural gas as a fuel over gasoline and diesel. 8 Alternative Two: Deny MOE's request to file tariffs for firm natural gas supply 9 service for NOVs. Denying MOE's request to discount firm natural gas supply would 10 eliminate the price differential for the same service provided to other ratepayers. 11 Alternative Three: Subject to modification, approve MOE's request to file 12 tariffs for firm natural gas supply service to NOVs. Reducing the discount for firm 13 natural gas supply service to NOVs would improve the economic advantage of natural 14 gas as a fuel while reducing the price differential for the same service provided to other 15 ratepayers. 16 Issue Three: Should MOE continue to offer compressed natural gas retail service 17 to NOVs pursuant to its CN0-1 tariff that is on file with this Commission? 18 Alternative One: Allow MOE to continue its compressed natural gas retail 19 service to NOVs pursuant to its CN0-1 tariffthat is on file with this Commission. 20 Allowing MOE to provide compressed natural gas retail service to NOVs at tariffed rates 21 would ensure that charges for the cost of natural gas to NOV s would be at the price 22 charged other ratepayers. 11 Alternative Two: Remove MGE' s tariffed utility service, Schedule CNG-1, that 2 provides compressed natural gas retail service to NGVs as a regulated utility service. 3 Removing MOE's tariffed rates for service to NGV would not prohibit MGE from 4 providing such service from facilities built to serve its own fleet; however, such service 5 could be priced at "market" prices. 6 Q. Does this conclude your testimony? 7 A. Yes, it does. RCB:cmk:DL:00583614 12 PSC F#:l70851 Public Service Commission of Wisconsin Direct Testimony of Randy Hillebrand Gas and Energy Division Madison Gas and Electric Company Docket 3270-UR-118 August 27, 2012 Q. Please state your name, occupation, and business address. 2 A. My name is Randy Hillebrand. I am employed as an auditor in the Gas and Energy 3 Division of the Public Service Commission of Wisconsin (Commission). My business 4 address is 610 North Whitney Way, Madison, Wisconsin. 5 Q. Please state your educational background and experience. 6 A. I graduated from the University of Wisconsin-Platteville in 1979 receiving a Bachelor of 7 Science degree with a major in Accounting. I am a licensed Certified Public Accountant 8 in the state of Wisconsin. I have been employed by the Commission as an auditor for 9 over 30 years. I have previously presented exhibits and testimony for electric, natural 10 gas, telephone, and water utility cases on numerous occasions. 11 Q. What is the purpose of your testimony and the exhibit you are filing in this proceeding? 12 A. My testimony and exhibit (Ex.-PSC-Hillebrand-1) support Commission staff's level of 13 fuel and non-network transmission costs estimated for the 2013 test year. As part of its 14 March 29, 2012, filing in this docket, Madison Gas and Electric Company (MGE) 15 submitted an estimate of $109,258,994 for monitored fuel costs and $132,574,035 for 16 total fuel and non-network transmission costs to be collected in revenue requirement for 17 the 2013 test year. 18 Q. Have you reviewed MGE's work papers, books, records, and other data supporting the 19 requested level of2013 fuel expense? A. Yes, Tim O'Brien of Commission staff and I have reviewed this data and when I refer to 2 "Commission staff" in my testimony I am referring to the two of us. 3 Q. As a result of such review, was the exhibit you are sponsoring prepared by you or under 4 your direction? 5 A. Yes it was. 6 Q. Please explain Schedule I of your exhibit. 7 A. Schedule I shows how MGE's March 29, 20I2, filed forecast of annual fuel cost for 8 20I3 is adjusted to arrive at the Commission staffs forecast of20I3 fuel costs. 9 Column (C) is the company's filed estimate of megawatt-hour (MWh) production by IO generation source and Column (F) shows the company's associated cost by source. II Column (E) is Commission staffs estimate of20I3 generation by source and I2 Column (H) is Commission staffs estimate of the associated cost by source. Column (D) I3 and Column (G) show Commission staffs adjustments by source for MWh generated and I4 associated fuel costs, respectively. Column (I) and Column (J) show the comparable cost I5 per MWh ofthe company's and Commission staffs 20I3 fuel forecasts to use for I6 monitoring fuel costs during the test year period. I7 Q. Please explain Schedule 2 of your exhibit. I8 A. Schedule 2 lists the adjustments Commission staff made to MGE's March 29, 20I2, filed I9 20 I3 test-year monitored and non-monitored electric fuel costs. Explanations of all 20 Commission staffs adjustments are based on changes to MGE' s filed estimate of fuel 2I costs. 22 Adjustment I is the summary of the various changes that were made to MGE's 23 filed fuel forecast as a result of incorporating Commission staffs electric sales forecast. 2 Test-year fuel costs were increased by an estimated $765,729 reflecting Commission 2 staff's forecasted sales increase of26,606 MWh. 3 Adjustment 2 is the result of using a different methodology to forecast wind 4 generation. MGE's filed wind generation forecast reflects the actual output of each wind 5 source during 2011. Commission staffs wind generation forecast is based on the average 6 historical monthly capacity factors experienced at each wind farm for the last three to 7 four years. However, in the case ofMGE's long-time ownership of its Lincoln Red River 8 location, the monthly production statistics from the last eight years were used. As a 9 result, Commission staff decreased MGE' s 2013 wind forecast by about 17,517 MWh. 10 Since the majority of the wind generation reduction was to purchases and the energy 11 prices in the associated purchased power agreements (PPA's) are higher than the 12 forecasted prices from other energy sources, this adjustment reduced test-year fuel costs 13 by $604,993. 14 MGE has an ownership interest in the Columbia Generating Station (Columbia) 15 and the Elm Road Generating Station (ERGS). The operating partners of each ofthese 16 coal plants are Wisconsin Power and Light Company and Wisconsin Electric Power 17 Company (WEPCO), respectively. Both of the operating partners are having their 2013 18 electric fuel costs reviewed in dockets 6680-FR-105 and 05-UR-106, respectively. 19 Adjustment 3 incorporates the findings of Commission staffs review in those dockets, 20 resulting in a $4,048,690 reduction in MGE's filed test year fuel with a $1,438,811 21 decrease from Columbia and $2,609,879 from ERGS. 22 Adjustment 4 is a change to MGE's filed test-year MISO market administrative 23 costs reflecting an updated forecast of the MISO rate as well as a correction of the 3 calculation of the 2013 charges to include all applicable forecasted energy subject to 2 MISO billing. This adjustment increases test-year fuel costs by $336,877. 3 Commission staff adjusted MGE's filed financial transmission rights (FTR) and 4 auction revenue rights (ARR) forecasted revenues to reflect the recent auction results for 5 the 2012-2013 ARRIFTR season based on current revenues received for these ARR's and 6 FTR's, and the current auction clearing prices for FTR's. This update results in a 7 $181,030 decrease in test-year fuel costs as shown in Adjustment 5. 8 Adjustment 6 reflects an updated forecast of all other billings from MISO 9 reflecting changes that have occurred since December 2011. Commission staffs forecast 10 reflects MISO billings through May 2012, which results in a $163,648 decrease in 11 test-year fuel costs. 12 The seventh adjustment reflects the use ofthe May 15,2012, New York 13 Mercantile Exchange (NYMEX) futures for Henry Hub natural gas, Basis Swaps for 14 applicable supply sources, and PJM NiHub RT LMP's (Peak and Off Peak). The effect 15 of using the updated prices rather than the January 17, 2012, NYMEX futures reflected in 16 MGE's filing is to increase fuel costs by approximately $4,688,568. 17 Adjustment 8 reflects a $1,358 reduction to forecasted West Campus 18 Cogeneration Facility (WCCF) emission control chemical costs, resulting from staffs 19 other fuel cost adjustments. 20 Adjustment 9 reflects the effect of updating the differential, or basis differences, 21 between the NiHub LMP's and LMP's at the MGE node, to reflect data for the twelve 22 months ending May 31, 2012, a reduction to test-year fuel costs of $1,018,515. 4 As the fuel cost component ofLMP's is the same throughout the MISO service 2 territory, and marginal loss component differences are relatively insignificant, 3 geographical differences in LMP's are largely due to differences in the congestion charge 4 component. Differences between the average congestion charges in two areas are largely 5 due to the relative capacity and reliability of the transmission lines serving those areas. 6 As staff will be updating Network Transmission Service (NTS) charges to reflect the 7 American Transmission Company's updated forecast of transmission service 8 construction, provided to our utilities around October 1st of each year, to be consistent, I 9 intend to again update the basis differences to reflect data for the twelve months ending 10 August 31, 2012. This assumes there will be no major anomalies, (such as forced outages 11 of major transmission lines and/or power plants causing LMP's in MGE's node to spike), 12 within the next few days. The probability of such an event occurring in the next few days 13 is, of course remote, but if it were to occur it could render the updated data 14 unrepresentative. In that event staff would simply use data for the twelve months ending 15 July 31, 2012. 16 Adjustment 10 reflects a decrease to forecasted Cross State Air Pollution Rules 17 (CSAPR) S02 emission allowance prices at the time of staff's audit, which results in a 18 reduction to test-year fuel costs of $990,535. Commission staff estimated that MGE 19 would purchase 3,000 allowances, at an average cost of $250 per allowance, for a total 20 cost of$750,000. Subsequent to the completion of the audit, Commission staff learned 21 that MGE had purchased 2,000 allowances at a total cost of $4 70,000, a difference of 22 $280,000. In light of the vacating of CSAPR by the District of Columbia Circuit Court of 23 Appeals, as described below, it is likely, but by no means certain, that these 2013 vintage 5 allowances are now of no value. As MGE's purchase ofthese allowances was consistent 2 with its CSAPR compliance plan, Commission staff proposes that the $470,000 spent by 3 MGE on CSAPR allowances be amortized over the 2013-2014 biennium, with the 4 provision that should MGE recover any value from the sale of these allowances, that 5 amount would be returned to ratepayers in a subsequent rate proceeding. 6 Adjustment 11 increases fuel costs by $748,470 to reflect the updating oftest-year 7 capacity charges under the WEPCO PP A. 8 The net effect of all of these adjustments is to reduce estimated test-year electric 9 fuel costs by $466,409 from $132,474,035 to $132,107,626 and monitored fuel costs by 10 $1,597,069, from $109,258,994 to $107,661,925. 11 Q. Do you have any corrections to your forecasted 2013 test-year fuel costs as shown in 12 your exhibit? 13 A. Yes, I do. Subsequent to the completion of the audit, Commission staff became aware of 14 two errors made by the utility in reflecting staffs proposed adjustments in its dispatch 15 model. The first correction would be to correctly reflect 2013 capacity costs rather than 16 the 2012 capacity costs currently reflected for the WEPCO purchased power agreement. 17 Correction of this error would increase test-year fuel costs by $1,051,488. The second 18 correction would be to correct for the overstatement of WCCF uneconomic dispatch costs 19 in the amount of$1,071,047. Correction of this error would reduce test-year fuel costs by 20 $1,071,04 7. Correction of both errors would result in a decrease to test-year fuel costs of 21 $19,559. 22 Q. Please describe the new fuel rules and the reconciliation process. 6 A. Schedule 1 of my exhibit shows Commission staff's forecast of MOE's 2013 fuel costs to 2 be recovered in electric rates and subject to deferral accounting1 and reconciliation2 under 3 the Commission's new fuel rules. In this proceeding, the Commission will review 4 MOE's 2013 fuel cost plan as required under Wis. Admin. Code§ PSC 116.03. The 5 deferred account balances that are a result of the under- or over-recovery of fuel costs 6 during a plan year will reflect the exclusion of any costs within a tolerance level. As 7 specified in Wis. Admin. Code § PSC 116.06, the fuel cost tolerance level is set at plus or 8 minus two percent unless the Commission sets a different percentage when approving a 9 fuel cost plan. 10 It should be noted that prior to the utility's collection of any deferred fuel costs 11 from ratepayers, a hearing is required as part of the Commission's review of the plan 12 year's actual fuel costs, in order to determine if those fuel costs were accurately reported 13 and prudently incurred.3 14 Q. What is the status ofCSAPR? 15 A. On August 21, 2012, the District of Columbia Circuit Court of Appeals vacated and 16 remanded the Clean Air Transport Rule back to the Environmental Protection Agency 17 (EPA). Given that the court found that there were "fundamental flaws" in the Rule as 18 promulgated by the EPA, it is extremely unlikely that CASPR will be in effect for any 1 Wisconsin Admin. Code§ PSC 116.04 requires a utility to apply deferral accounting to all of its actual cost for items in an approved fuel cost plan and to all amounts collected or credited under Wis. Admin. Code§§ PSC 116.07 and 116.08. 2 Wisconsin Admin. Code § PSC 116.07 requires a utility to file, no later than 90 days after the end of a plan year, an application for the reconciliation of actual cost for items in an approved fuel cost plan to the amount of fuel costs already collected from customers. 3 Under Wis. Admin. Code§ PSC 116.07, if after hearing the Commission finds that the utility demonstrated that the deferred account balance debit was accurate and included only prudently-expended fixed costs, collection in rates will be authorized. 7 1 portion of the 2013 test year. In its absence, electric utility air emissions will be 2 governed by the Clean Air Interstate Rule (CAIR). 3 Q. Please describe the fuel cost components to be updated prior to the Commission decision 4 in this docket. 5 A. Commission staff proposes that MOE file a delayed exhibit, as close as possible to the 6 time of the Commission decision in this docket, that updates natural gas prices and 7 natural gas hedging activity, spot coal prices, rail delivery costs, and any new purchased 8 power contracts entered into. This exhibit will illustrate the effect on test-year fuel costs 9 of updating for NYMEX natural gas futures prices and electric fuel cost hedges, 2013 10 NiHub On-Peak and Off-Peak LMP's futures prices, and any applicable coal, rail, and 11 purchased power cost updates. 12 In addition, the delayed exhibit should include the 2013 monthly detail of the 13 natural gas prices as filed by MOE, and as updated and the 2013 NiHub (On-Peak and 14 Off-Peak) monthly energy prices as filed by MOE, and as updated, and adjusted for basis 15 differences to arrive at LMP's at the MOE node, and the detail of any applicable coal, 16 rail, or purchased power cost updates. 17 To be consistent with past Commission practice with the intent to minimize price 18 volatility, the date selected for the updated NYMEX natural gas futures and NiHub 19 LMP's should be as close to the middle of the month as possible. 20 Q. Does this conclude your direct testimony? 21 A. Yes, it does. RJH:cmk:DL:00587137 8 PSC REF#:l70852 Public Service Commission of Wisconsin Direct Testimony of Gail M. Maly Gas and Energy Division Madison Gas and Electric Company Docket 3270-UR-I I 8 August 27, 2012 Q. Please state your name, business address, and occupation. A. My name is Gail Ma1y. I am employed by the Public Service Commission of Wisconsin (Commission), 610 N. Whitney Way, Madison, Wisconsin, as a Public Utility Auditor in the Gas and Energy Division. Q. Please describe your educational background and experience. A. I have a Bachelor of Science Degree with majors in Accounting and Management from Upper Iowa University. I have been employed by the Commission since 1988. I have presented testimony and exhibits in numerous formal proceedings involving electric, natural gas, and water utilities, as well as generic proceedings. Prior to my tenure at the Commission, I worked in the private sector, preparing financial statements, payroll, and taxes. Q. Please explain the purpose of this proceeding. A. Madison Gas and Electric Company (MGE) filed an application with the Commission on March 23, 2012, requesting authority to change its electric and natural gas rates. MGE requested a $22,451,000 (5.82 percent) increase for electric operations, and a $4,308,000 (2.59 percent) increase for gas operations, to be effective January 1, 2013. A Prehearing Conference was held on May 21, 2012, to determine the issues that will be addressed in this docket and to establish a schedule for the hearing. Q What is the purpose of your testimony? Direct-PSC-Maly-1 A. The purpose of my testimony is to provide the Commission, MGE, and all parties in this proceeding with a proposed electric and natural gas income statement, net investment rate base, and revenue requirement for the test year ending December 31, 2013, to be used for final rates in this docket. Q. Have you reviewed the working papers and other records supporting MGE's request to change electric and natural gas rates in the proceeding? A. Yes. Q. As a result of this examination, did you prepare the document marked for identification as Ex.-PSC-Maly-1? A. Yes. Q. Please summarize Commission staff's estimated revenue deficiencies for MGE's electric and natural gas operations. A. Commission staff estimates that MGE needs a $13,122,000 (3.36 percent) increase for electric operations and a $1,956,000 (1.16 percent) increase for natural gas operations. The electric and natural gas revenue deficiencies are based on a 10.30 percent rate of return on common equity, which is the level authorized in MGE's last rate case, docket 3270-UR-117 (PSC REF#: 143559). Q. Please describe the primary factors contributing to the electric rate increase. A. The primary factors for the electric increase are: • Construction work in progress includes $99 million for upgrades to the Columbia power plant, which are required to meet federal environmental standards. The treatment for construction costs proposed by MGE provides a current return on 50 percent of costs, and allowance for funds used during construction (AFUDC) for 50 percent. This proposal appears reasonable. Direct-PSC-Maly-2 • Costs associated with the Elm Road Generating Station (ERGS) also contribute to the increase. Commission staff's financial statements include all costs associated with MGE's 8.33 percent ownership in ERGS. However, there were material cost overruns associated with the project. The nature of these overruns is an issue in the Wisconsin Electric Power Company (WEPCO) rate case, docket 5-UR-106. Whatever the Commission decides in the WEPCO case, with respect to the appropriate recovery of the ERGS cost overruns, would also apply to MGE. • Electric rates in 2012 include an ERGS credit that will not be available in 2013. • Fuel and purchased power have also increased for the test year. Q. If the Commission discusses the MGE case prior to the WEPCO case, and subsequently determines ERGS adjustments are appropriate, how could those adjustments be applied to MGE? A. Any adjustments applicable to MGE could be deferred until the company's next rate case. Q. Please describe the primary factors contributing to the natural gas rate increase. A. The increase for natural gas is driven by an increase in plant, mainly distribution plant, as well as increased operation and maintenance costs for distribution. Q. Please explain Schedules 1 and 2 of Ex.-PSC-Maly-1. A. Schedules 1 and 2 represent the estimated electric and natural gas operating income statements and average net investment rate bases for MGE for the test year ending December 31, 2013. Column (a) sets forth MGE's estimate of operations for the test year as pre:filed with the Commission. Column (b) identifies, by number, the Commission staff adjustments shown in column (c). Column (d) shows Commission staff estimates of operating income and average net investment rate base for the test year ending December 31,2013. Q. Please explain Schedule 3 of Ex.-PSC-Maly-1. Direct-PSC-Maly-3 A. Schedule 3 provides details concerning the Commission staff adjustments shown on Schedules 1 and 2. The majority of the adjustments are self-explanatory and do not require further comment. I will, however, provide additional comments for some of the adjustments. Adjustment No. 1 increases sales of electricity by approximately $5.4 million. This adjustment consists ofthe following items: • Commercial sales were decreased by $338,000 primarily to reflect Commission staff's estimate of a lower use per customer in the Cg-4a rate class. • Residential, Commercial, and Industrial sales were increased by $2,881,000 to reflect Commission staff's estimate of the conversion of sales of electricity from a billed basis to a calendar basis, consistent with the method used by MGE for gas sales. • Commercial sales were increased by $611,000 to reflect Commission staff estimates of the proportion of kilowatt hour (kWh) energy usage in the Cg-4a and Cg-4b rate classes that is used during on-peak periods as opposed to off-peak. • Commercial and Industrial sales were increased by $2,163,000 to reflect Commission staff's estimate ofKW demand in the Cg-4a, Cg-4b, Cg-2, and Cg-6 rate classes. • Commercial and Industrial sales were increased by $50,000 to reflect Commission staff estimates of primary voltage discounts in the Cg-6 rate class and generation credits in the Sp-3 rate class. Q. Please continue. A. Adjustments 7D, 9A, 19C, and 21A reflect Commission staff's payroll adjustment. Commission staff decreased payroll by $929,000, primarily due to a lower rate of increase for non-union wages (Commission staff used inflation rates of2.3 percent and 1.9 percent for 2012 and 2013, respectively; MGE used 3 percent for both years), an Direct-PSC-Maly-4 increased vacancy rate, adjustments to overtime and part-time costs, and disallowance of bonuses. Adjustment 16 increases sales of gas by $365,000. This adjustment consists of the following items: • Residential sales were increased by $260,000 based on Commission staffs estimate of a higher use per customer. • Sales of gas used for generation of electricity were increased by $15,000 to reflect the fuel auditor's estimate. • Sales were increased by $9,000 based on Commission staffs correction of a customer in rate code 0831 that was omitted from MOE's estimate. • System sales were increased $81,000 to reflect an update in cost of gas based on the May 15, 2012, NYMEX strip. Expenses were adjusted by an identical amount in Adjustment 18. Q. Please continue. A. Adjustment 17 increases gas other operating revenues by $46,000 to reflect Commission staffs estimate of test year transportation revenues. Adjustments 22, 24, 27, 28, and 29 reflect Commission staffs disallowance, as non-utility property, of new compressed natural gas facilities in rate base. Commission staff witness Robert Bauer addresses this issue in his testimony. Q. Please explain Schedule 4 ofEx.-PSC-Maly-1. A. Schedule 4 presents Commission staffs calculation of the regulatory weighted cost of capital at a 10.30 percent return on common stock equity, which is the level approved in the company's last rate case, docket 3270-UR-117 (PSC REF#: 143559). Q. Please explain Schedule 5 of Ex.-PSC-Maly-1. Direct-PSC-Maly-5 A. Schedule 5 shows the calculation of the ratio of average net investment rate base plus construction work in progress (CWIP) to capital applicable primarily to utility operations plus deferred investment tax credit (ratio) for the test year. The Commission staff estimate of the test year ratio is 98.76 percent, which is slightly higher than the company-filed level of 98.7 4 percent. The Commission staff estimate is the result of adjusting certain working capital accounts to levels more consistent with historical balances. Commission staffs ratio also incorporates changes to utility rate base resulting from Commission staffs audit. Q. Please explain Schedule 6 of Ex.-PSC-Maly-1. A. Schedule 6 shows Commission staffs calculation of the required return on average net investment rate base at a 10.30 percent return on common stock equity. Consistent with prior MGE rate case proceedings, Commission staff has included an adjustment to the return requirement to provide a current return on 50 percent of CWIP. Commission staff also included an adjustment to the return requirement for the ERGS regulatory asset earning at Commission staffs short-term debt rate of 0.30 percent. Q. Please explain Schedule 7 of Ex.-PSC-Maly-1. A. Schedule 7 shows the development of the electric and natural gas revenue deficiencies at 10.30 percent return on common stock equity for the test year. The electric revenue deficiency is $13,122,000 and the natural gas revenue deficiency is $1,956,000. Q. Are you sponsoring any other exhibits? A. Yes. Ex.-PSC-Maly-2 was prepared by Commission financial staff. Q. Please describe what is included in Ex.-PSC-Maly-2. Direct-PSC-Maly-6 A. Ex.-PSC-Maly-2 shows interest rates and inflation rates which are typically provided to the Commission in rate cases. It also shows the forecasted short- and long-term debt rates used in this case. Q. What are the forecasts for short- and long-term debt rates? A. Page 1 of Schedule 6 shows various interest rates from the Blue Chip Financial Forecast. This Commission's practice has been to use the Blue Chip Financial Forecast's commercial paper rate forecasts (which reflect A-1/P-1 rated commercial paper rates) for determining the test year commercial paper rate. Based on the June 2012 Blue Chip Financial Forecast, a reasonable estimate for A-1/P-1 rated commercial paper for the test year is 0.30 percent. This compares with the 0.40 percent used by MGE. Page 2 of Schedule 6 shows Commission staffs calculation of the cost of the new long-term debt to be issued in 2013. The estimate is based on current yield of Wisconsin utilities' long-term debt and a forecast of expected changes in current bond yields. For the test year, Commission staff forecasted a new long-term debt cost of 4.70 percent. This compares to 5.75 percent used by MGE. Q. Will this information be updated? A. Yes. Updated market information will be provided through a delayed exhibit filed approximately six days before the Commission discussion of the record to assist the Commission in making a final determination of test year short- and long-term debt costs. Q. Should the standard financial findings of fact from the January 12,2011, Final Decision in docket 3270-UR-117 (PSC REF#: 143559) be reaffirmed in this docket? A. While Commission staff is not making adjustments to the return on equity or capital structure in this case, the Commission may wish to incorporate the standard financial Direct-PSC-Maly-7 findings and the related order points in its Order in this docket. Findings 28 and 29 from the January 12, 2011, Final Decision deal with the target equity level and range. Findings 32 and 34 relate to reporting requirements to be filed with the next rate proceeding, and Finding 33 sets a dividend restriction. Due to the capital needs of the company, the amount of dividends in this case is $0. (A dividend payment is still allowed as long as the capital structure remains balanced.) These findings are typical, and would ensure that the Commission's findings would continue to apply, even in a case where financial issues are not contested. Q. Does that conclude your direct testimony? A. Yes, it does. GMM:jlt:DL:00586373 Direct-PSC-Maly-8 PSC REF#:l71243 '0 g_ .... :0 .... Public Service Commission of Wisconsin trl 0 () trl!Jl Direct Testimony of Corey S. Singletary Hill < I-! trl Gas and Energy Division t:! ....< •• (1 (]) 0 OJ() Madison Gas and Electric Company '-0 Docket 3270-UR-118 ~@ '- P· f-'!tl !0(J1 ' .... August 27, 2012 0 ro::J wo !01-t, 1 Q. Please state your name, business address, and occupation. U1::;: !--" l-1· m :v (1 ::;:: 0 2 A. My name is Corey S.J. Singletary and my business address is the Public Service ::J m P· ::l 3 Commission of Wisconsin (Commission), 610 N. Whitney Way, P.O. Box 7854, 4 Madison, Wisconsin 53707-7854. I am employed by the Commission as an Energy 5 Policy Advisor in the Gas and Energy Division. 6 Q. Please state your educational background and experience. 7 A. I hold a Bachelor of Science degree in Biology and a Bachelor of Arts degree in 8 International Studies from the University of Wisconsin- Milwaukee. I also hold a 9 Master's Degree in International Public Affairs and a Graduate Certificate in Energy 10 Analysis and Policy from the University of Wisconsin- Madison. I have worked with 11 the Commission since May of2010, as an energy policy advisor. My work focusses on 12 electric utility rate design and cost of service and a number of policy issues such as smart 13 grid technology, smart grid enabled rates, rate-based energy efficiency and conservation 14 incentives, distributed generation, and energy efficiency evaluation. 15 Q. Have you previously testified in proceedings before the Commission? 16 A. Yes, I have previously presented exhibits in testimony in municipal and investor owned 17 electric utility proceedings before the Commission. 18 Q. What is the purpose of your testimony? Direct-PSC-Singletary-1 1 A. My testimony will address three areas. First, I will present the results of Commission 2 staffs embedded electric cost-of-service studies (COSS) and a proposed revenue 3 allocation for Madison Gas and Electric Company's (MGE) 2013 test year. Second, I 4 will present staffs proposed electric rate design. Lastly, I will cover MGE's Customer 5 Service Conservation budget. 6 Q. Are you sponsoring any exhibits in conjunction with this testimony? 7 A. Yes. I am sponsoring one exhibit, Ex.-PSC-Singletary-1, which consists of five 8 schedules: 9 Schedule 1: Summary of the three COSS I am presenting. 10 Schedule 2: Electric rate design and revenue allocation among the electric rate 11 classes. 12 Schedule 3: Generic bill comparisons for various rate classes. 13 Schedule 4: Calculation of2005 Wisconsin Act 141 electric rates. 14 Schedule 5: Budget overview of Customer Service Conservation activities filed by 15 MGE. 16 Q. Was this exhibit prepared by you or under your direction? 17 A. Yes. 18 Electric Cost of Service Study 19 Q. Briefly describe what is shown in Schedule 1 of your exhibit. 20 A. Page 1 of Schedule 1 presents a summary of the three COSS I performed using staffs 21 revenue requirement, as well as an initial revenue allocation "target" based on these study 22 results. Direct-PSC-Singletary-2 1 Pages 2 through 4 show the development of the revenue requirement and 2 proposed increase for each customer class under the three staff COSS specifications. 3 Page 5 shows a comparison of staff's COSS results against the COSS used by 4 MGE, all under staff's revenue requirement. 5 Pages 6 through 8 show the development of the revenue requirement and 6 proposed increase for each customer class under MGE's COSS specifications and staff 7 revenue requirement. 8 Pages 9 through 11 show development of the revenue requirement and proposed 9 increase for each customer class under MGE's COSS specifications, modified to allocate 10 account 507 in a manner consistent with production plant, and staff revenue requirement. 11 I will discuss this modification below. 12 Q. Please describe the general approach you took in performing the COSS you are 13 presenting. 14 A. In preparing Commission staff's COSS, I used a copy ofMGE's COSS spreadsheet 15 model as provided by the company. In general I found the approach used by MGE 16 witness Steven James in presenting "Standard," Time-of-Use (TOU), and Location 17 studies to be reasonable, and as such focused on modifying the three COSS models so as 18 to reflect Commission staff's test-year sales forecast and revenue requirement. The 19 method used by Mr. James can be found on pages 4 through 8 of his direct testimony. 20 Commission staff's sales forecast and revenue requirement is addressed in Gail Maly's 21 direct testimony. 22 Q. Did you make any other modifications to the three COSS models? Direct-PSC-Singletary-3 1 A. Yes. I also made modifications to the allocators used to assign costs associated with 2 production plant, power generation expense, and power generation labor so as to be 3 consistent with the way in which commission staff has historically treated interruptible 4 capacity. 5 Q. In what ways does Commission staff approach interruptible capacity differently from 6 MGE? 7 A. MGE handles interruptible load by developing a coincident peak allocator with 8 interruptible capacity subtracted out. This allocator, labeled D12 in MGE's COSS 9 model, is used to allocate a variety of costs including Production Plant, Other Power 10 Generation operation and maintenance (O&M) expense, and capacity related Purchased 11 Power expense. MGE also uses the D12 allocator for the Steam Power Generation 12 Operation expense account 507-Rents as the value charged to this account largely 13 represents MGE's share of Columbia and Elm Road generation costs. As such, account 14 507 is effectively equivalent to Production Plant accounts and as such is allocated in a 15 manner consistent with Production Plant. 16 By netting out interruptible capacity from the D12 allocator, customers with 17 interruptible capacity are given a lower allocation of utility costs in order to "credit" 18 interruptible customers for the value their interruptible load provides to the utility as a 19 whole. 20 Q. Is all ofMGE's interruptible capacity handled the same way under the company's COSS 21 models? 22 A. No. The D 12 allocator only reflects coincident peak demand net of Cp-1 interruptible 23 capacity. Cg-4, Cg-2, and Cg-6 interruptible capacity is not recognized in the Direct-PSC-Singletary-4 1 development ofthe D12 allocator. Consequently, only the one customer taking service 2 under the Cp-1 class, Airgas Merchant Gas, receives any benefit for interruptibility in 3 MOE's COSS model design. 4 Q. Have you used a different approach in recognizing interruptible capacity? 5 A. Yes. The approach preferred by Commission staff is to develop the COSS to reflect the 6 test-year average and then explicitly apply an interruptible credit to all customer classes 7 with interruptible load based on the value per kW of interruptibility and the interruptible 8 capacity of each customer class. The interruptible credit is offset by an allocation of an 9 interruptible "expense" applied to each customer class based on coincident peak demand 10 net of interruptible capacity. This is consistent with the approach used by Commission 11 staff in past MOE cases. 12 A. Why is this approach used? 13 Q. MOE's revenue requirement represents the forecasted cost of providing electric service to 14 all of the utility's customers during the test year. The values that are used to develop the 15 revenue requirement generally represent average utility costs during the test year 16 average plant balance, average O&M expense, etc. In turn, the revenue allocation 17 informed by the COSS results is used to set average cost retail rates. As such, staff starts 18 with a COSS model that represents the utility's test-year average. Put another way, staff 19 designs the COSS model so as to reasonably represent the utility's costs, and the way in 20 which those costs are incurred, most ofthe time- say 95% of the time for the sake of 21 example. Staff then recognizes that in that other 5% of the time, such as in the case of 22 interruptible load, cost causation may deviate from the average and an adjustment is 23 applied to recognize those deviations. Direct-PSC-Singletary-5 1 Q. What effect does the difference between the way MGE and Commission staff treats 2 interruptibility have on the COSS results? 3 A. Due to the fact that the Cp-1 class is considered entirely interruptible (i.e., the D12 and 4 DE12 allocators reflect a coincident peak demand of zero for Cp-1), coupled with the fact 5 that the D12 and DE12 allocators are used to allocate some of the largest cost drivers for 6 the utility, the result is a dramatic understatement of the cost to serve the Cp-1 class 7 under MOE's COSS. 8 Q. What changes to MOE's COSS design have you made so as to reflect Commission staffs 9 approach to interruptible capacity? 10 A. In the "Standard" model, I made the following changes: I Allocators Accounts MGE Staff Production Plant (31 0-316, 340-346) D12 D10 Production O&M- Rents (507) Production O&M and Labor: D12 D12s Other Power Generation (547-554,555) Purchased Power- Capacity (555) 11 The D 10 allocator reflects the average coincident peak demand for all classes without 12 interruptibility subtracted out, while the D 12s is a new allocator that reflects coincident 13 peak demand net of interruptible capacity for all classes. D12s was developed by 14 subtracting the total Cp-1 load and the interruptible capacity in k W enrolled under 15 MOE's Is-1 and Is-2 Interruptible Service Riders, consistent with staffs test-year sales 16 forcast, from the D 10 coincident peak demand. 17 Q. Why did you use the D 12s allocator for Other Power Generation O&M expenses instead 18 of the D 10 allocator? Direct-PSC-Singletary-6 1 A. Through discussions with the company it was determined that the O&M expenses 2 included in the Other Power Generation O&M accounts are primarily for peaker units 3 and are based solely off of historical costs and do not in any way reflect interruptible 4 capacity. As such, it is appropriate to reflect interruptible capacity in the allocation of 5 these costs. Similarly, the D12s allocator was used to allocate the capacity component of 6 purchased power expenses. This is consistent with the approach used by Commission 7 staff in the last MGE rate case in Docket number 3270-UR-117, with the exception that 8 the D12s allocator recognizes all interruptible capacity, not just that of the Cp-1 class. 9 Q. Did you make similar changes to MGE's TOU and Location studies? 10 A. Yes. As described on page 7 of Mr. James' direct testimony, the TOU and Location 11 studies allocate 60% of Production Plant based on coincident peak demand while 40% is 12 allocated based on on-peak energy. The DE12 demand/energy allocator used by 13 Mr. James in MGE's TOU study reflects class coincident peak demands less all of Cp-1 14 coincident peak demand, similar to the D12 allocator used in the "Standard" model. In 15 preparing a TOU study, I replaced the DE12 allocator in MGE's TOU study with a new 16 DE 12s allocator that reflects total class coincident peak demand consistent with the D 10 17 allocator. I also applied the DE12s allocator to account 507-Rents so as to allocate 18 Columbia and Elm Road costs consistent with production plant. Commission staffs 19 TOU and Location studies are otherwise consistent with those prepared by Mr. James. 20 Q. How have you calculated the interruptible credit? 21 A. Total Cp-1 coincident peak load and the interruptible capacity in kW enrolled under 22 MGE's Is-1 and Is-2 Interruptible Service Riders were multiplied by a capacity credit rate 23 to determine the dollar credit to be applied to each class with interruptible capacity. For Direct-PSC-Singletary-7 1 Cp-4, Cp-2, and Cp-6 interruptible capacity, the interruptible credit is equal to the 2 applicable Is-1 or Is-2 interruptible credit rate. For the Cp-1 class an interruptible credit 3 of$4.00 per kW is used. 4 An offsetting interruptible "expense" is allocated back to all customer classes 5 based on the D 12s allocator. The net interruptible credit or expense can be found on 6 pages 2 through 4 of Schedule 1 of my exhibit. 7 Q. Do you have any other comments regarding MGE's treatment of interruptible capacity in 8 its COSS? 9 A. Yes, I believe that there is an inconsistency in MGE's filed TOU and Location studies 10 with respect to the allocator used for Production O&M Account 507-Rents. In MGE's 11 "Standard" study, account 507 is allocated in a manner consistent with Production Plant. 12 In the TOU and Location studies filed by Mr. James, account 507 is allocated based on 13 the D12 allocator rather than the DE12 allocator used for Production Plant accounts. 14 Q. Have you considered what effect allocating account 507 consistent with the allocation of 15 Production Plant would have on the results ofMGE's TOU and Location Studies? 16 A. Yes. On page 5 of Schedule 1 of my exhibit I have provided a comparison of the average 17 COSS results under staff's COSS specifications, MGE's COSS specifications as filed, 18 and MGE's COSS modified so as bring account 507 into consistency with Production 19 Plant allocation. As you can see, allocating account 507 using the same allocator as 20 production plant dramatically changes the results ofMGE's model, with respect to the 21 Cp-1 class. I nstead of a decrease, the COSS results would suggest an increase for the 22 Cp-1 class. The Results for other classes are fairly comparable across the different study Direct-PSC-Singletary-8 1 designs with respect to general trends. More detailed results, broken out by study type, 2 can be found on pages 9 through 11 of Schedule 1 of my exhibit. 3 Q. Please describe how you developed the Staff Proposed Revenue Allocation Target shown 4 on page 1 of Schedule 1 of your exhibit. 5 A. Grouping the rate classes in the manner show on page 1 of Schedule 1, I first took the 6 results of each of the three COSS I performed and limited the increases so as to be within 7 plus or minus 1.25 percent of the utility average. I then calculated a weighted average of 8 the three studies, producing a revenue allocation for each of the usage groups. The 9 allocation for each of the smaller groups or classes (residential & small C/I, Cg-2, etc.) 10 was then determined by considering how each of these groups compared to the larger 11 group average and the utility average. For example, the COSS results suggest that when 12 compared against the Large Use group as a whole, the Cg-2 should get a slightly higher 13 than average increase, whereas the Cg-6 should get a slightly lower than average 14 mcrease. The resulting allocation targets were used in the design ofthe staff proposed 15 rates. 16 Rate Design 17 Q. Please describe what is shown in Schedules 2 and 3 of your exhibit. 18 A. Page one of Schedule 2 provides a summary of the rate increases for each rate class. The 19 remaining pages of Schedule 2 show the detailed billing statistics and the current and 20 proposed rates each rate class. 21 Schedule 3 provides bill comparisons for the various rate classes, consistent with 22 the bill comparisons filed by Mr. James so as to be easily comparable. 23 Q. In general terms, what type of rate changes have you made to the rate classes? Direct-PSC-Singletary-9 1 A. The proposed rate increases are distributed among the customer charges, electricity 2 service demand charges for demand-billed rates, and electricity service energy rates. 3 Increasing these billing components will ensure that most individuals in any specific rate 4 class will receive bill increases approximately equal to the overall rate increase for the 5 respective rate class. The electric bill comparisons in Schedule 3 of my exhibit show the 6 bill impacts for various sized customers for the rate classes that have a large number of 7 customers. 8 Q. Were any additional adjustments performed to the revenue allocation as a result of your 9 proposed rate design? 10 A. Yes. The COSS results and allocation targets do not reflect incremental revenues from 11 proposed changes to test-year rates. As I will touch on later in my testimony, the rate for 12 MGE's residential and business voluntary green pricing program have been raised under 13 the proposed rate design. Similarly, interdepartmental revenues have increases under 14 proposed rates. These incremental revenues were not part of Commission staff's 15 test-year sales and revenue forecast under present rates. These incremental revenues 16 were allocated to the various customer classes consistent with the method used in the 17 COSS performed. 18 Q. MGE has proposed to increase the customer charges for all customer classes, have you 19 made a similar adjustment to the customer charges in your proposed rates? 20 A. No. I have held the customer charges equal to those under present rates for the 21 residential and small C/I classes (Cg-5 and Cg-3). I have increased the customer charges 22 for the larger classes such that the larger use customers received larger increases to the Direct-PSC-Singletary-1 0 1 customer charge as the customer charge constitutes a smaller proportion of those 2 customers' bills. 3 Q. In the direct testimony of MGE witness Greg Boll om it is argued that increasing the 4 customer charges would encourage energy conservation. Do you agree with this 5 position? 6 A. In his direct testimony, Mr. Bollom correctly points out that part ofMGE's fixed costs 7 are recovered through energy rates. As a result, all else held constant, if customers 8 reduce their energy usage the company will under-recover fixed costs, which in turn 9 necessitates a rate adjustment. This produces the effect where a conserving customer will 10 see their energy bill decrease due to initial conservation efforts and then see their bill rise 11 slightly when rates are adjusted to reflect the lost revenues. Mr. Bollom indicates that 12 this is frustrating to some customers and may discourage further conservation over time. 13 He argues that increasing customer charges would better align the level of customers' 14 saving with their expectations over time. 15 I do not doubt that these fluctuations in electricity rates are frustrating to some 16 MGE customers, indeed I have heard the same complaint from some customers. 17 However, with respect to energy conservation, the issue Mr. Bollom has highlighted 18 needs to be weighed against the opposing issue, which is providing a sufficient price 19 signal so as to encourage conservation in the first place. Increasing the customer charge 20 would lower the variable energy charges. This would reduce the level of savings that 21 customers would receive for a given reduction in energy usage. Using the examples 22 provided by Mr. Bollom in Ex.-MGE-Bollom-1, under current rates, if a customer 23 reduces their usage by a certain percentage, they receive roughly the same level of bill Direct-PSC-Singletary-11 1 savmgs. In the case of electric, for every 1.1 percent reduction in usage a customer will 2 see approximately 1 percent reduction in their bill. In the case of gas the ratio is 3 approximately 1.5 to 1 exclusive of cost of gas itself. If customer charges were to be 4 adjusted according to the company's ultimate goal of straight fixed/variable charges, an 5 electric customer would have to reduce their usage 1.9 percent to achieve 1 percent in bill 6 savings in the example. In the case of gas the customer would only save based on the 7 cost of gas. While these calculations are only illustrative in nature given the example 8 scenarios they are based upon, I believe they convey my point regarding price incentives 9 relative to energy savings. 10 Setting rates in the manner in which they are now - recovering a portion of fixed 11 costs through variable charges - is a product of policy decisions made over time by this 12 Commission to trade some of the pure economic efficiency argued for by Mr. Bollom in 13 favor of public policy objectives such as energy conservation. In light of this, in 14 considering whether to increase the customer charges, I believe the key question is 15 whether the Commission believes that the frustration caused by the "whack-a-mole" 16 aspect of the current fixed vs. variable charge rate design disincentivizes conservation 17 and energy efficiency efforts to such a degree as to overwhelm the incentives provided by 18 proportionally higher bill savings per unit energy saved. The other consideration is the 19 proportionally greater impact that higher customer charges will have on low usage 20 customers. In particular, those low usage customer who may be on a low or fixed 21 mcome. Direct-PSC-Singletary-12 1 Q. Mr. Bollom cites increased interest in customer-owned distributed generation (DG) as 2 another reason why he believes the current fixed/variable charge rate design is 3 unsustainable. Do you agree with his position? 4 A. Yes and no. It is true that there is a degree of cross-subsidization from non-DG owning 5 customers to DG customers taking service under the company's net metering tariff. 6 However, similar to my comments regarding incentives for energy efficiency and 7 conservation, the choice to authorize and maintain net metering service, and any 8 cross-subsidization that may come along with it, is a public policy choice based on the 9 theory that there are societal benefits that come from DG. As such, the decision to adjust 10 the current rate design with respect to fixed/variable charges must consider these policy 11 goals. Furthermore, while the growth in customer owned DG does present challenges 12 with respect to cross subsidization of distribution costs under the current fixed/variable 13 cost rate design, I have not seen any analysis presented by any utility in Wisconsin that 14 would lead me to believe that DG presents a clear and present danger to the sustainability 15 ofMGE so as to support raising customer charges for all customers. Finally, ifDG 16 penetration rates were to rise to a level so as to provide cause for concern, I believe that 17 the tariffs and rate design for DG service should also be evaluated for opportunities to 18 more appropriately align rates with costs, in addition to general customer charges. 19 Q. Mr. Bollom states that MGE is seeking a decision by the Commission "that it is 20 appropriate and necessary for MGE to move to rate designs that recover fixed costs 21 through some type of fixed charges." Could you please comment on this request? 22 A. In light of the conflicting public policy and efficiency drivers I have noted, should the 23 Commission wish to decide on a long term goal for fixed charges for MGE, a reasonable Direct-PSC-Singletary-13 1 compromise may be to decide up on an appropriate metric or set of metrics for evaluating 2 whether customer charges should be adjusted. MGE could work with Commission staff 3 to develop these metrics before the filing ofMGE's next full rate case. As an example, a 4 goal could be to adjust customer charges so as to recover a certain percentage of fixed 5 costs, not to exceed a percentage of the average customer's bill. 6 Q. Why are you proposing a larger percentage increase to the residential lifeline tariff than 7 to the standard residential rate? 8 A. As noted by Mr. James, the residential lifeline rate (Rg-3) was closed to new customers 9 in 1985 and currently only has 15 customers taking service under the rate. In MGE's last 10 full rate case, the Commission expressed a desire to see the Rg-3 rate brought closer to 11 the general Rg-1 rate and ultimately to transition those customers to the Rg-1 tariff. In 12 keeping with this objective I have increased both the customer charge and the energy 13 charge for the first 300kW for Rg-3. 14 Q. MGE is proposing a fundamental change to the rate design for TOU rate classes. Could 15 you please comment on this proposal? 16 A. As discussed on pages 11 through 13 of Mr. James's direct testimony, MGE is proposing 17 to transition their TOU rates to one where there is a flat, base energy rate for all hours, 18 with kWh usage during on peak periods subject to an adder. 19 While I do not have strong feelings as to whether or not this proposal is "good" or 20 "bad," I feel it worth noting that the switch to the base+adder rate design could prove to 21 be confusing to customers. Furthermore, as this has been presented as a solution to an 22 accounting and customer bill design "problem," I feel that the Commission should 23 consider whether this is the best solution to that problem. Ultimately, the final TOU rate Direct-PSC-Singletary-14 design effect can be achieved whether or not the Commission approves this proposed 2 change. 3 Q. Has MGE taken any action in this case to carry out the Demand Response Plan it filed on 4 September 1, 2010, in Docket 3270-UR-116? 5 A. Yes. Coming into this case, three items from the company's demand response plan had 6 yet to be implemented. This demand response plan was a condition of this Commission's 7 approval of advanced metering implementation funded through a grant from the U.S. 8 Department of Energy. These three items were: 9 1. Splitting the current TOU pricing periods into additional pricing periods. 10 2. Proposing new rate schedules allow the utility to bid its direct load control 11 program and interruptible loads into the MISO market as price sensitive load. 12 3. Developing a Critical Peak Pricing Option for Cg-2 and Cg-6 customers with 13 firm energy use. 14 As discussed on pages 23 through 31 of Mr. James's direct testimony, the 15 company has addressed all outstanding components of its demand response plan, and has 16 proposed implementation of all components, except for the direct load control program, 17 which the company determined to be uneconomic based on customer research it 18 conducted. I have reviewed the company's implementation of the remaining demand 19 response plan items and found them to be acceptable. My proposed rate design reflects 20 the company's proposal. 21 Q. Has MGE proposed any changes to its buyback rate tariffs? 22 A. Yes. As discussed on pages 20 to 21r of Mr. James's direct testimony, MGE is proposing 23 to modify its Pg-1 parallel generation tariff and its Pg-2 net metering tariff. Direct-PSC-Singletary-15 Q. Do you have any comments regarding these proposed changes? 2 A. Yes. With respect to the proposed change to the Pg-1 tariff, I believe this largely 3 consistent with changes to the parallel generation tariffs of Wisconsin Public Service 4 Corporation (WPSC) and Northern States Power Company (NSPW) recently approved by 5 this Commission. However, consistent with the WPSC and NSPW parallel generation 6 tariffs, MGE should add to the final tariff language indicating that, should the Midwest 7 Independent Transmission System Operator (MISO) implement a capacity market, a 8 capacity credit shall be implemented reflecting the MISO capacity market methodology. 9 Additionally, similar to what has been proposed for its Pg-2 service, language should be 10 added to the Pg-1 tariff to clarify that, with respect to any energy that the company 11 purchases from the customer, that customer retains any renewable energy credits and 12 benefits, emissions allowances, or other renewable energy, air emissions, or 13 environmental benefits for which the customer's generation project qualifies. 14 The proposed change to the Pg-2 tariff is acceptable and is consistent with net 15 metering tariffs recently approved for WPSC and NSPW. 16 Q. Could you please comment on MGE's proposed change to the Green Power Tomorrow 17 premium rate? 18 A. As noted on pages i9 and 20 of Mr. James's direct testimony, the company is proposing 19 to raise the rate for the voluntary green pricing tariffs RWE-1 and BWE-1 from $0.025 20 per kWh to $0.030 per kWh. This increase is appropriate given the continued mismatch 21 between the green pricing rate, and the desire expressed by the Commission in previous 22 cases to have the green pricing premium reflect the full incremental cost of renewable 23 energy supplied under the program. Direct-PSC-Singletary-16 1 I would however like to note that the calculation method used by the company, 2 and supplied in a data request response under PSC ERF#170582 and PSC ERF#170583, 3 is different from that supplied in previous cases as it includes a delivery premium not 4 included in previous calculations. Commission staff has not considered at this time 5 whether the inclusion of the delivery premium is appropriate in calculating the green 6 pricing premium. However, using a calculation method consistent with that used in 7 docket 3270-UR-117, I have estimated the full green pricing premium to be $0.0413 per 8 kWh. As a result, I believe the proposed rate of$0.030 per kWh is still appropriate. 9 Customer Service Conservation 10 Q. Do you have any comments regarding MGE's filed Customer Service Conservation 11 budgets and Conservation Escrow Budget? 12 A. Yes. In the order dated July 13, 2012, in Docket 05-BU-102, the Commission made a 13 number of decisions that affect Customer Service Conservation (CSC) spending and the 14 Conservation Escrow. In particular, the Commission eliminated the minimum spending 15 requirement for esc activities, and established a definition of esc as "those activities 16 and services that a utility provides its customers to: (1) help them understand and control 17 their energy use and bills; (2) create customer awareness of energy efficiency and its 18 value; (3) provide information and assistance related to energy efficiency topics; or (4) 19 encourage and assist customers to take advantage of other services provided by Focus on 20 Energy and federal and state energy programs. Fifty-one percent of an activity or service 21 must be dedicated to energy efficiency in order to meet the definition of CSC." 22 The Commission also directed Commission staff to work with utilities to: Direct-PSC-Singletary-17 1. ensure the overall design of CSC activities and services is consistent with the 2 Commission-approved CSC definition and CSC activities and services 3 guidelines; 4 2. ensure only appropriate CSC expenditures are allowed escrow treatment; 5 load-management expenditures shall not be allowed escrow treatment; 6 3. determine annual spending on esc activities and services; 7 4. develop appropriate metrics for assessing the effectiveness of esc 8 expenditures in conjunction with program development; and, 9 5. to the extent practicable, make uniform the esc filings of the utilities to 10 facilitate the staff audit process and a reasonable comparison of CSC activities 11 between the utilities. 12 In evaluating MGE's filed CSC budget against the Commission's decisions in 13 05-BU-102, I have chosen to consider the CSC budget in terms of two principal 14 questions. First, what CSC activities are appropriate for treatment through the 15 Conservation Escrow? Second, which CSC activities are consistent/inconsistent with the 16 Commission's definition of CSC? Related to the second point, the expenditure levels for 17 esc activities should be reviewed for reasonableness. 18 With respect to Conservation Escrow treatment, the spending levels for MGE's 19 various esc activities have been fairly consistent over the last 4 years as shown on page 20 1 of Schedule 5 of my exhibit. In particular, the largest spending area, Internal Labor and 21 Fringe, has varied by 1 percent or less when compared against the average over time. 22 Overall, the high degree of consistency in MGE's CSC expenditure levels overall would 23 suggest that all ofMGE's currently budgeted CSC activities should be disallowed Direct-PSC-Singletary-18 1 treatment through the Conservation Escrow. If the Commission chooses to allow for 2 escrow treatment of some CSC expenses, I would recommend that escrow treatment be 3 limited to Internal Overheads, Sponsorships or Other Financial Support to Community 4 Organizations, and expenses that fall under the "Other Customer Service Conservation 5 Expenditures" category listed by MGE. All three of these spending categories have at 6 times deviated from the historical average by 30 percent or more which suggests that they 7 are more appropriate candidates for escrow treatment. 8 With respect to whether MGE's CSC activities are consistent with the definition 9 of esc, an expenditure area that should be considered in particular is the $280,229 10 budgeted for a Public Benefits & Low-Income Weatherization program not classified as 11 CSC by MGE, but included in the company's Conservation Escrow budget. It is unclear 12 whether this program meets the definition of esc, a condition of escrow treatment 13 established in Order Point 4.b. ofthe July 13, 2012, Order in Docket 05-BU-102. 14 In order to aid the Commission in evaluating MGE's CSC budget, I have prepared 15 a summary analysis, found on page 2 of Schedule 5 of my exhibit, of the expenditures for 16 which MGE is seeking Escrow treatment. Detailed descriptions ofMGE's CSC activities 17 and expenditures, including a breakout of internal labor and fringe expenses, can be 18 found in the three data request responses referenced on page3 of Schedule 5 of my 19 exhibit. 20 Consistent with Order Point 4.d. of the July 13, 2012 order, I have calculated 21 MGE's total budgeted Conservation activities, inclusive ofMGE's Public Benefits & 22 Low-Income Weatherization program, on a per customer basis and as a percent of 23 reveneue requirement. These values are presented as metrics that could be used to Direct-PSC-Singletary-19 1 evaluate utility esc expenditures, both independently, and in comparison with other 2 utilities, and can be found at the bottom of page 2, Schedule 5 of my exhibit. 3 Q. Does this conclude your direct testimony? 4 A. Yes. CSS:cmk:DL:00586891 Direct-PSC-Singletary-20 PSC REF#:l70854 Public Service Commission of Wisconsin Direct Testimony of Anne P. Vandervort Gas and Energy Division Madison Gas and Electric Company Docket 3270-UR-118 August 27, 2012 Q. Please state your name, business address, and occupation. 2 A. My name is Anne P. Vandervort. I am employed as a Principal Rate Analyst in the Gas 3 and Energy Division of the Public Service Commission of Wisconsin (Commission), 4 6IO North Whitney Way, P.O. Box 7854, Madison, Wisconsin 53707-7854. 5 Q. Please describe your professional experience. 6 A. I graduated from the University of Wisconsin-Madison with a Bachelor of Arts Degree in 7 Social Work. I returned to the university and completed additional courses in accounting, 8 mathematics, and statistics. 9 I have been an analyst at the Commission since August 1991. My responsibilities IO have included preparing cost-of-service studies (COSS), as well as analyzing and II developing proposals regarding utility rates, services, and tariffs. I have testified before I2 the Commission in numerous natural gas rate proceedings. 13 Q. What is the purpose of your testimony? 14 A. I am presenting the results of two COSS and proposing a natural gas rate design. I am I5 also commenting on proposals made by MGE witness Timm A. Minor regarding natural 16 gas rates and services. Commission staff witness Robert C. Bauer provides comments on I7 Mr. Minor's testimony regarding NGV, Distribution Service for Natural Gas Vehicles I8 and FS-3, Firm Gas Sales Service for Natural Gas Vehicles. I9 Q. What exhibit did you prepare? Direct-PSC-Vandervort-! A. I prepared Ex.-PSC-Vandervort-1, which consists of six schedules: 2 Schedule 1: Cost-of-Service Study Results 3 Schedule 2: Major Cost-of-Service Study Allocators 4 Schedule 3: Rate Design 5 Schedule 4: Summary of Present and Proposed Customer Class Revenue 6 Schedule 5: Summary of Present and Proposed Rates 7 Schedule 6: Act 141 Rate Factor Calculation 8 NATURAL GAS COST-OF-SERVICE STUDIES 9 Q. Please describe the COSS that you utilize in this proceeding. 10 A. The two embedded COSS use allocators to spread test-year natural gas distribution costs 11 among the customer classes to determine the cost responsibility of each class. My COSS 12 utilize the same computer model used by Mr. Minor to prepare his COSS for this 13 proceeding. A description of how the model processes data to produce its results is 14 included in pages 2 through 12 of Mr. Minor's direct testimony. 15 My COSS differ from MGE's COSSin that I enter Commission staff's sales 16 forecast, present revenue, proposed revenue and Uniform System of Accounts balances 17 into the model. Additionally, I calculate my COSS allocators using Commission staff's 18 audited numbers. I also allocate some expenses differently as described below: 19 • Uncollectibles are divided into low-income uncollectibles and other 20 uncollectibles. Low-income uncollectibles are allocated to all customer 21 classes based on class revenue, while other uncollectibles are allocated to the 22 classes as each class incurred them. Direct-PSC-Vandervort-2 • Collection expenses are divided into those related to low-income collection 2 activities and other collection activities. The low-income portion is allocated 3 to all customer classes based on class revenue, while the remaining portion is 4 allocated to the classes as each class incurred them. 5 • Conservation expense related to Focus on Energy programs is separated from 6 other conservation program expenses. I apportion 40 percent of Focus on 7 Energy expense to the residential class and 60 percent to the commercial 8 classes, which splits the cost in the same ratio as the statewide funds are 9 budgeted for these customer sectors. The commercial portion is allocated to 10 the commercial and industrial classes based on throughput. 11 Q. What is the difference between the two COSS that you prepared? 12 A, In COSS A, MGE's investment in distribution mains is divided into a customer 13 component and a demand component based on the results of a zero-intercept study. The 14 40 percent customer component is allocated to the customer classes based on customer 15 number, and the 60 percent demand component is allocated to the classes based on 16 coincident peak demand. The allocations of intangible and general plant, as well as 17 administrative and general expenses, follow the allocation of accounts related to the 18 particular plant or expense accounts. 19 In COSS B, distribution mains plant is divided into a commodity (throughput) 20 component and a demand component based on the zero intercept study. The 40 percent 21 commodity component is allocated to the customer classes based on throughput, while 22 the 60 percent demand component is allocated to the classes based on coincident peak Direct-PSC-Vandervort-3 demand. A portion of intangible and general plant, as well as administrative and general 2 expenses, is allocated to the classes based on throughput. 3 Q. Why do you perform two COSS? 4 A. COSS A and COSS B reflect different viewpoints of cost causation. Advocates of COSS 5 A contend that distribution mains costs are incurred to serve each individual customer, as 6 well as to meet system demand. Advocates of COSS B contend that distribution mains 7 are not generally dedicated to individual customers. Instead, mains are installed to ensure 8 system reliability and are sized to meet demand. Together, COSS A and COSS B 9 provide the bookends of a range of reasonableness for rate design. IO Q. What schedule contains your COSS results? II A. The results are shown in Schedule I ofEx.-PSC-Vandervort-1. 12 Q. What is shown in schedule 2 of your exhibit? 13 A. Schedule 2 contains a summary of the major allocators used in the COSS. 14 Q. Please describe the COSS results. 15 A. The COSS results indicate that the residential class should receive a smaller percentage 16 revenue increase than the commercial and industrial classes. Additionally, the results 17 show that the FS-I, firm gas supply administrative charge and IS-I, interruptible gas I8 supply administrative charge should be decreased. I9 NATURAL GAS RATE DESIGN 20 Q. Please describe the rate design process. 21 A. The rate design process attempts to balance multiple objectives. The results of costs 22 studies are often used as a guide in designing rates; however many other important Direct-PSC-Vandervort-4 factors are considered. Mr. James C. Bonbright1 lists the following ten characteristics of 2 a good rate design: 3 I. yields the total revenue requirement effectively; 4 2. produces stable and predictable revenues; 5 3. results in no unexpected changes in the rates themselves; 6 4. promotes static efficiency, which in turn discourages wasteful use and 7 promotes justified use; 8 5. reflects all present and future private and social costs and benefits caused by 9 using the service; 10 6. apportions the costs of service fairly among ratepayers; 11 7. avoids undue discrimination in rate relationships (no subsidies); 12 8. promotes dynamic efficiency by encouraging innovation and economic 13 responses to changing demand and supply patterns; 14 9. creates simplicity, certainty, convenience of payment, economy in 15 collection, understandability, public acceptability, and feasibility of 16 application; and 17 10. eliminates controversy about interpretation. 18 Q. Is it possible to satisfy all these objectives in your rate design? 19 A. These principles are goals to strive for rather than a rigid prescription for proper rate 20 design. Many rate designs could generally satisfy the Bonbright principles, because the 21 principles provide general objectives to consider when setting rates. I consider 22 Bonbright's principles, as well as other factors, when determining my rate design. 23 Q. What schedule contains your rate design? 24 A. Schedule 3 of Ex.-PSC-Vandervort-} provides a detailed look at the present and proposed 25 rates and revenues of each customer class. Schedule 4 summarizes the proposed changes 1 James C. Bonbright, Albert L. Danielsen, and David R. Kamerschen, Principles of Public Utility Rates, Public Utility Reports, 1988. Direct-PSC-Vandervort-5 in revenue for each customer class. Schedule 5 contains a summary of present and 2 proposed rates. 3 Q. What is the amount of the natural gas revenue deficiency that you design rates to 4 recover? 5 A. The revenue deficiency is $1,955,554, as identified by Commission staff auditor Gail 6 Maly. The revenue deficiency is 2.88 percent of present distribution service revenues, or 7 1.16 percent of present revenues including the cost of natural gas. 8 Customer Charges 9 Q. Do you increase the residential customer charge? 10 A. No. MGE proposes to increase the residential customer charge from $0.33 70 per day 11 ($1 0.25 per month) to $0.4000 per day ($12.17 per month), an 18.7 percent increase. 12 However, MOE's residential customer charge is currently set at the highest level 13 approved by the Commission for natural gas residential customer charges. Conservation 14 and energy efficiency incentives are important considerations when contemplating an 15 increase in the residential customer charge. Increasing the fixed portion of the bill 16 reduces savings that residential customers can experience due to using less gas, which 17 can reduce a customer's incentive to conserve energy and install energy efficiency 18 measures. 19 Q. Do you increase the GSD-1 Small Commercial class customer charge? 20 A. No. MGE proposes to increase this charge from $0.6600 per day ($20.08 per month) to 21 $0.6930 per day ($21.08 per month). The small commercial class contains customers 22 with usage less than 25,000 therms annually. The average customer in this class uses 23 3,345 therms annually, with many customers in this class using less than that amount. Direct-PSC-Vandervort-6 1 Increasing the fixed portion of small commercial customer bills would have a detrimental 2 effect on conservation and energy efficiency incentives. Additionally, MGE's current 3 small commercial customer charge is comparable to or higher than the customer charges 4 of other utilities' small commercial customer classes with similar usage parameters. 5 Q. Do you change the customer charges of the other customer classes? 6 A. I incorporate the following customer charge increases proposed by MGE into my rate 7 design: Present Customer Proposed Customer Customer Class Charge Charge $3.5020 daily $3.6771 daily GSD-2, Medium Commercial $106.52 monthly $111.85 monthly $20.0610 daily $21.0116 daily GSD-3, Large Commercial $610.19 monthly $639.10 monthly $102.00 daily $117.30 daily IGD-1, Interruptible Generation $3,102.50 monthly $3,567.88 monthly 8 These increases are supported by the COSS results. Additionally, increasing these 9 customer charges will not significantly affect conservation and energy efficiency 10 incentives because the customer charges will continue to be a relatively small portion of 11 bills. 12 IS-1 and FS-1 Administrative Charges 13 Q. What changes do you make in the IS-I and FS-1 administrative charges? 14 A. I decrease the IS-1 administrative charge from $0.0295 to $0.0265 per therm and the 15 FS-1 administrative charge from $0.0330 to $0.0300 per therm because the COSS results 16 indicate that the present charges are substantially over-collecting costs. The IS-I 17 administrative charge is paid by all system sales customers that use interruptible gas, 18 while the FS-1 administrative charge is paid by all system sales customers that use firm 19 gas. These charges collect costs related to gas supply purchasing personnel, gross Direct-PSC-Vandervort-7 receipts tax on gas sales revenue and the return on stored gas. The FS-1 charge also 2 collects cost related to MGE's peaking plant. The current charges were set in January of 3 2008. In recent years, the return on stored gas and gross receipts tax on gas sales 4 revenues have decreased considerably due to natural gas price decreases. 5 Telemetering Charge 6 A. Do you change the Telemetering Charge? 7 Q. No. MGE proposes to increase this charge from $1.50 to $1.75 per day. However, it has 8 recently come to light that the telemetering equipment that is currently being installed is 9 much less expensive than the telemetering equipment that was previously installed. Most 10 of the telemetering equipment in place at this point is the older technology. However, as 11 the newer technology is installed, the cost oftelemetering equipment will decrease. For 12 this reason, I propose to maintain the telemetering charge at this time. 13 In the next rate case, it would be appropriate to require that MGE provide more 14 precise information regarding the overall cost of telemetering. This report should include 15 up-to-date information about the telemetering equipment that is currently in service, 16 including the number of each type of equipment, the cost of each type of equipment, and 17 the cost of maintaining this equipment. 18 2005 Wisconsin Act 141 (Act 141) Rate Factors 19 Q. How do you calculate the Act 141 rate factors? 20 A. The Act 141 rate factors are calculated on Schedule 6 ofEx.-PSC-Vandervort-1, using 21 the methodology that was approved by the Commission in previous MGE rate cases. The 22 residential factor is $0.0111 per therm and the commercial factor is $0.0172 per therm. 23 Direct-PSC-Vandervort-8 Class Revenue Increases 2 Q. Please describe the distribution revenue increases that you propose for each class. 3 A. Residential revenue is increased by 2.7 percent. Small commercial, medium commercial, 4 and large commercial class revenue is increased by 3.4, 1.7, and 4.8 percent, respectively. 5 IGD-1, Interruptible Generation class revenue is increased by 3.8 percent, while SP-1, 6 Steam and Power Generation class revenue is increased by 3.4 percent. These class· 7 revenue increases are the result of increases in the distribution charges for all classes, as 8 well as the increases in the customer charges discussed above. 9 The COSS results are an important factor in determining the amount of revenue I I 0 recover from each customer class. Another significant factor in determining my rate 11 design for the small commercial, medium commercial, and large commercial classes is 12 maintaining a smooth transition in bills at the crossover points between these classes. It 13 is important that bills do not increase or decrease substantially as customers move from 14 one commercial class to another due to changes in usage. 15 Revenue increases for the CNG-1 Natural Gas Distribution class and the SO-l 16 Seasonal Off-Peak Distribution classes are discussed separately below. 17 CNG-1, COMPRESSED NATURAL GAS DISTRIBUTION SERVICE 18 Q. Please describe CNG-1 service. 19 A. The CNG-1 tariff contains distribution rates for usage at MGE's compressed natural gas 20 (CNG) fueling station. MGE's CNG facility is located on utility property, and has been 21 owned and operated by MGE for many years. It is utilized mostly to fuel MGE's small 22 fleet of CNG vehicles, although it is also utilized occasionally by third parties that fuel up 23 in Madison on their way to other destinations. Direct-PSC-Vandervort-9 Q. What rates do you propose for the CNG-1 class? 2 A. I support MGE's proposal to increase the distribution charge from $0.2202 to $0.5050 3 per therm, and to add a $0.1500 per therm electric compression charge. The COSS 4 results indicate that an increase in revenue is appropriate for the CNG-1 class. 5 Additionally, these rate increases put CNG-1 prices on a more equal footing with CNG 6 market prices, which is important at this time when the CNG industry is showing signs of 7 expansion. 8 SD-1, SEASONAL OFF-PEAK DISTRIBUTION SERVICE 9 Q. Please describe MGE's current Seasonal Off-Peak Distribution Service (SD-1). 10 A SD-1 is currently available to customers that can use their gas between May and 11 November of each year. MGE has the ability to extend this period to include all or parts 12 of April or December, if requested by a customer. Customers currently served under this 13 tariff include agricultural crop dryers and asphalt companies. 14 Q. Do you agree with MGE's proposal to bill the SD-1 daily customer charge in all twelve 15 months of the year? 16 A. Yes. Currently, the SD-1 customer charge is billed May through November of each year, 17 as well as in any other month that usage occurs. Billing for the customer charge between 18 May through November is an automatic process, however, manual processing is required 19 for any customer charges that do not occur during these months. If the customer charge 20 is billed in all twelve months, this manual processing would be eliminated, along with 21 any errors that could result from it. 22 The current daily customer charge of$1.75 is generally charged during seven 23 months of each year. In my rate design, I include a $1.03 daily customer charge billed Direct-PSC-Vandervort- I 0 during twelve months of each year, which results in collecting about the same amount of 2 customer charge revenue from the SD-1 class as the current charge. 3 Q. How is usage billed under the current tariff? 4 A. The current tarifflimits customer usage to the months of May through November. The 5 distribution charge for usage during these months is $0.0787 per therm. If usage occurs 6 during the months of December through April, a $0.50 per therm penalty is added to the 7 distribution charge, unless the customer has received authorization from MGE to use gas 8 during this period. 9 Q. How does MGE propose to bill for usage under the revised tariff? 10 A. Under MGE's proposal, the distribution charge for usage during the months of April 11 through December would be $0.0827 per therm, while the distribution charge for usage 12 during January through March would be much higher at $0.4000 per therm. Customers 13 would not need to ask permission to burn gas in any month of the year. However, the 14 much higher distribution rate during January, February, and March should deter 15 customers from using much gas during these months. 16 Charging a higher distribution rate to discourage usage during certain months, 17 rather than adding a penalty for each therm used, has the advantage of reducing the 18 possibility of billing errors. Adding a penalty requires manual processing, while charging 19 a higher distribution rate during these months would be done automatically. 20 Q. What distribution rate do you propose for the SO-l class? 21 A. I increase the distribution charge from $0.0787 to $0.0837 per therm. This results in a 22 3.0 percent increase in revenue from this class. 23 Q. Do you have any concerns about SO-l customer billing? Direct-PSC-Vandervort-11 1 A. I do have one serious concern that relates to customer billing. SD-1 customer usage is 2 not currently being measured on a daily basis. When a customer has a meter reading date 3 that does not fall on the last day of the month, it is impossible to determine how much of 4 the usage in the any billing period occurred in the previous month and how much 5 occurred in the current month. This is an important distinction in those situations when a 6 higher distribution charge or a per-therm penalty should be charged in one of these 7 months. Currently, MGE gives the customer the benefit of the doubt and charges the 8 lower rate for all usage in these circumstances. However, this situation needs to be 9 remedied. 10 MGE has indicated that it plans to install equipment that would provide daily 11 usage readings sometime in 2012 or early 2013. Because daily usage information is 12 critical to billing under the SD-1 tariff, it would be appropriate to require that MGE 13 install this equipment as soon as reasonably practicable and no later than April 1, 2013. 14 Q. Would you suggest any changes to the language included in MGE's proposed SD-1 tariff 15 sheets? 16 A. I believe the availability provision should be enhanced to more clearly define which 17 customers are eligible to take service under this rate schedule. I suggest the following 18 language for the first paragraph of this provision: 19 Service under this rate schedule is available to commercial and industrial 20 customers that use the vast majority of their natural gas requirements during the 21 period of April 1 through December 31. The per-therm distribution rate for 22 service during this period is significantly lower than during the period January 1 Direct-PSC-Vandervort-12 through March 31. The customer charge applies in all twelve billing periods in a 2 calendar year. 3 Additionally, the metering provision should be changed to read: Service furnished 4 hereunder will be separately metered. Meter reading will occur on a monthly basis 5 according to the customer's billing cycle. 6 CHANGE IN SERVICE RULES 7 Q. MGE proposes adding new language to its service rules that states that the Company may 8 disconnect a customer's service if a customer refuses to allow authorized utility personnel 9 access to their premises at all reasonable times for purposes related to providing safe and 10 reliable service. Do you agree that this language can be added to MGE's gas service 11 rules? 12 A. Yes, this new service rule provision is in line with current natural gas administrative rule 13 provisions that allow for disconnection of service when customers do not provide 14 reasonable access to utility equipment on their premises. Additionally, this proposed 15 language mirrors a provision that is currently contained in the Company's electric service 16 rules. 17 Q. Does this complete your direct testimony? 18 A. Yes it does. APV:cmk:DL:00586899 Direct-PSC-Vandervort-13 PSC REF#:l71782 BEFORE THE 2 PUBLIC SERVICE COMMISSION OF WISCONSIN 3 Application of Madison Gas and Electric 4 Company for Authority to Change Electric Docket 3270-UR-118 5 and Natural Gas Rates 6 REBUTTAL TESTIMONY OF GREGORY A. BOLLOM 7 ON BEHALF OF APPLICANT 8 Q. Please state your name and business address. 9 A. My name is Gregory A. Bollom. My business address is 133 South Blair Street, Post Office I 0 Box 1231, Madison, Wisconsin 53 701. 11 Q. Are you the same Gregory A. Bollom who previously filed direct testimony in this 12 proceeding? 13 A. Yes, I am. 14 Q. What is the purpose of your rebuttal testimony? 15 A. The purpose of my testimony is to respond to various issues raised in the direct testimonies of 16 Mr. Craig Weiss and Mr. Robert Stephens on behalf of the University of Wisconsin (UW), 17 Mr. Jonathon Wallach on behalf of the Citizens Utility Board (CUB), and Mr. Corey 18 Singletary, Ms. Anne Vandervort, and Ms. Gail Maly ofthe Public Service Commission of 19 Wisconsin (PSCW). 20 Q. In his direct testimony, Mr. Weiss states that in an amendment to the O&M agreement 21 between MGE and the UW approved by the PSCW on May 2, 2012, the parties did not 22 address Sp-3 rate issues. Is this correct? 23 A. No, it is not. As indicated in my direct testimony and exhibits in this case, there were a 24 number of significant changes to the Sp-3 rate that the parties agreed to. In fact, all of the 25 changes to the rate design included in Ex-MGE-James-2 and described in my direct testimony Rebuttal-MGE-Bollom-1 1 directly reflect the May 2, 2012, agreement between the UW and MGE. The amendment 2 resolved most of the outstanding issues between the parties. That said, there are areas where 3 the parties essentially agreed to disagree and understood that their unresolved issues could be 4 addressed in subsequent proceedings before the PSCW. The single biggest issue is that of 5 allocation ofMGE's revenue requirement to the UW. The changes made to the Sp-3 rate in the 6 recent past have come between open rate cases before the PSCW. Consequently, while MGE . 7 and the UW could agree to changes in the structure and design ofthe Sp-3 rate without 8 adversely affecting other parties, the total revenue requirement allocated to the UW could not 9 be changed without potentially imposing increased costs on other customers or exposing MGE 10 to under recovery of prudently incurred costs. 11 Q. Mr. Weiss expresses concern that the sales forecast used by MGE will likely understate 12 sales to the UW for the test year. Do you agree? 13 A. No, I do not. MGE's forecast of 2013 sales to the UW is based on an analysis of historic 14 electric usage across the geographically contiguous campus served on the Sp ....3 rate, which I 15 will refer to as the total campus load. There are three sources of electricity used to supply the 16 total campus load~nergy the UW purchases from MGE under the Sp-3 rate, energy the UW 17 receives on a station service basis to serve electric chillers generated and provided directly 18 from the West Campus Cogeneration Facility (WCCF), and energy the UW self-generates at 19 the Charter St. Heating Plant (CSHP). Energy purchased under the Sp-3 rate is further 20 segregated into traditional campus loads and energy supplied to the WCCF chillers in lieu of 21 station service when the facility is available, but not operating. The energy used to directly 22 supply the electric chillers when WCCF is operating is treated as station service and the UW 23 pays for this energy on a cost-sharing basis under the O&M agreement for WCCF. In 24 preparing the forecast of test year sales to the UW, MGE considers all three sources of 25 electricity to ensure that our projection for electric use is reasonable across the total campus Rebuttal-MGE-Bollom-2 1 load. MGE's forecast of total campus electricity use for 2013 reflects a 2.5% increase over the 2 calendar year 2011 level. Our forecast reflects an increase of more than 120% in the level of 3 CSHP generation between the 2011 actual and the forecast 2013 level. This translates into a 4 net decrease in traditional electricity sales to serve campus loads under Sp-3 of approximately 5 4% between the 2011 actual and 2013 forecast levels. In addition, we forecast an increase of 6 more than 30% in the level of electricity directly supplied to the WCCF chillers through 7 station service. This directly translates to a decrease of more than 20% in the level of 8 electricity supplied to the WCCF chillers under the Sp-3 rate. 9 Q. Does Mr. Weiss's Ex-UW System-Weiss-13 accurately reflect sales for 2013? 10 A. No it does not. There appear to be several errors in his data. First, the exhibit incorrectly 11 represents the customer maximum demand, labeled in the exhibit as "Distribution Demand 12 12 Mo Peak." As defined in the Determination of Demand portion of the Sp-3 tariff, the 13 "customer maximum IS-minute demand will be the greatest rate at which electrical energy 14 from the Company has been used during any period of 15 consecutive minutes in the current 15 or preceding 11 billing months plus, at the same time, the amount of generation by customer 16 owned generators at its Charter Street facility". Ex-UW System-Weiss-13 uses the 71,992 kW 17 demand value for June 2012 as the billed demand for the entire period from July 2011 through 18 June 2012. But since a level of demand experienced in June 2012 is not relevant to the 19 determination of demand for any prior months, the 71 ,3 55 k W demand value for July 2011 is 20 the appropriate value for the period of July 2011 through May 2012. The total in Mr. Weiss's 21 exhibit is therefore overstated. Mr. Weiss also appears to have made several errors in his 22 comparisons of total electricity sales data. The data included and labeled as "Total FY2012 23 Campus kwh w/CSHP Gen and No WCCF" in Ex-UW System-Weiss-13 are not directly 24 comparable to the sales estimates reflected on pages 15-16 of Mr. James Exhibit-MGE 25 James-2. First, Mr. Weiss is including kWh associated with generation at CSHP in his total Rebuttal-MGE-Bollom-3 even though no electricity produced at CSHP is billed at Sp-3 rates. He is also excluding the 2 chillers at WCCF, even though electricity used by the chillers when WCCF is available and 3 not operating is billed under the Sp-3 tariff. Further, he has chosen an incorrect 379,376,607 4 kWh subtotal of electricity sales from page 15 of Mr. James exhibit instead of the actual 5 complete 403,590,106 kWh total shown on page 16 of Mr. James exhibit. Not only is the 6 comparison in Mr. Weiss's testimony not an apples to apples comparison, I'm not sure it's even 7 apples to any fruit. The two numbers in Mr. Weiss's testimony are simply not comparable. 8 Q. Do you believe the forecast level of sales to the UW used by MGE for the 2013 test year is 9 reasonable? 10 A. Yes. It is worth noting that in the PSCW Staffs audit ofMGE's test year sales forecast, they 11 made only minor reductions to the Company's forecast level of sales, which MGE did not 12 oppose. The level of sales included in the cost of service and rate design proposals of PSCW 13 staff witness Mr. Corey Singletary reasonably reflects a test year level of total campus load 14 taking into account the significant changes to the UW's use of its CSHP generation and the 15 revised provisions to Sp-3 tariff and O&M agreement. 16 Q. Mr. Weiss also raises some concerns that the Sp-3 rate as proposed in Mr. James' exhibit 17 may be inappropriately recovering lost revenue associated with Sp-3 energy sales to the 18 WCCF chillers through increased demand charges in the Sp-3 rate. Are the rates 19 proposed by Mr. James appropriate? 20 A. Yes they are. Revenue requirement allocation and rate design, while mathematically related, 21 are two different processes. Revenue requirement allocation is based on the range of cost of 22 service (COS) studies developed in each rate case, as well as other guidelines that can vary 23 from case to case. Mr. James has provided three different studies in this case. He proposed an 24 allocation of revenue requirement guided by the directional changes suggested by the COS 25 studies and limiting the increases to any class of customer to generally plus or minus an Rebuttal-MGE-Bollom-4 1 additional2% from the utility average. Mr. Singletary ofthe PSCW staff performed similar 2 COS studies and proposed a revenue requirement allocation that generally limited increases to 3 any customer class to a more narrow range of plus or minus an additional 1.25% from the 4 utility average. Once revenue requirement is allocated to each customer class, the rates must 5 be designed to recover the allocated amounts from the various rate components. In the case of 6 the Sp-3 rate, the parties in the past have agreed and the PSCW has approved that the energy 7 rates should be set to generally reflect the wholesale market value of energy to encourage 8 efficient decisions regarding the use of the different facilities available to the UW. When the 9 Sp-3 energy rates were last approved by the PSCW, they were based on historical four-year 10 average MISO LMP values. In the current case, MGE is proposing that they be set based on 11 estimated 2013 test year LMP estimates. And the UW is asking the PSCW in the future to 12 consider setting the energy rates to reflect real-time LMP values. Regardless of which LMP 13 method is chosen to be appropriate in this case, an estimate of the energy revenue that the 14 rates will produce is needed to determine the remainder of the Sp-3 rate design. Essentially the 15 projected energy revenue based on the LMP rates approved by the PSCW is subtracted from 16 the total allocated revenue requirement, and the remainder of the allocated revenue 17 requirement must be recovered from the other rate components of the Sp-3 tariff. Mr. Weiss is 18 correct that MGE is projecting a decline in Sp-3 chiller revenue for electricity supplied to the 19 WCCF chillers when WCCF is available, but not running. As I indicated earlier in my 20 testimony, a greater portion of the energy needed by the chillers will be coming from station 21 service and less from Sp-3 sales. In addition, using projected 2013 LMP values instead of 22 historical four-year average values results in lower energy rates. With lower energy revenue, 23 the remaining allocated revenue requirement must be recovered from the other components of 24 the Sp-3 tariff. As I stated in my direct testimony and as is highlighted by Mr. Weiss, MGE 25 chose to increase the demand charges in the Sp-3 rate. There is nothing sinister or Rebuttal-MGE-Bollom-5 inappropriate about this. MGE could have just as easily proposed to increase the customer 2 charge. Regardless of which rate components are changed, the allocated revenue requirement 3 not recovered through LMP-based energy rates must be recovered from the UW. 4 Q. If the PSCW decides to use a different, lower revenue requirement allocation for the 5 UW, could the demand charges proposed by MGE be lowered? 6 A. Yes, lowering the proposed demand charges would be a viable alternative if the allocated 7 revenue requirement is lowered, as the UW advocates. The salient point is that as long as the 8 energy rates in the Sp-3 tariff are set on some type of LMP-basis, then the remaining allocated 9 revenue requirement must be recovered from other charges. That is the very nature of the 10 ratemaking process. 11 Q. Mr. Robert Stephens is proposing a number of potential changes to the generation credit 12 components of the Sp-3 rate. Do you agree with his proposed changes? 13 A. No I do not. There are two specific changes that he proposes that are troubling. The first is to 14 reduce the application of the generation credit (or standby charge as he redefines it) to only 15 those days in which the UW actually uses that level of service from MGE. The second is his 16 proposal to effectively eliminate the penalty provision for non-performance of the UW 17 generator. Both proposals should be rejected by the PSCW. · 18 Q. Why is it inappropriate to only charge for standby service for the days the UW actually 19 uses the service? 20 A. Generation capacity reserved to serve the UW's full load needs to be in place whenever and 21 for however long the UW might need it. MGE cannot obtain capacity for a few days here or 22 there. It needs to be there 365 days a year to be able to reliably provide the backup service the 23 UW expects. One of the changes included in the proposed Sp-3 rate allows the UW to 24 nominate a CSHP generation level for each month of the year, and MGE will have some 25 ability to change the level of capacity month to month to accommodate the UW's nominations. Rebuttal-MGE-Bollom-6 But, that capacity will be acquired well in advance of the operating month in anticipation of 2 the UW's needs. Mr. Stephens' proposed approach of reducing the application of the 3 generation credit to only those days in which the UW actually uses that level of service 4 (determined after the fact) is incongruous with the reality of needing to have capacity 5 available in anticipation of potential use. Furthermore, costs for that capacity will, at a 6 minimum, be incurred on a monthly basis, not on a daily basis. While the demand charges are 7 stated in the Sp-3 rate as $/kW/day, the demand cost upon which they are based is a monthly 8 demand as defined in the Determination of Demand portion of the Sp-3 tariff. These demand 9 charges are used to recover the total allocated monthly costs for generation and transmission 10 capacity. The daily aspect of the demand charges is for billing and administrative ease; it II essentially eliminates the need to pro-rate demand charges when the number of days in the 12 monthly billing cycle is different each month. To fully recover the total cost incurred by MGE 13 to have the nominated level of generation capacity available for the month, the UW must pay 14 the daily charge each and every day ofthe month regardless ofthe how often the standby 15 capacity may be called upon. If the UW were allowed to only pay for one or a few days of the 16 generation capacity MGE has reserved on the UW's behalf, the UW would effectively be 17 shifting a significant portion ofMGE's cost of maintaining that capacity to other customers. If 18 MGE had many customers with customer-owned generation, and MGE could take into 19 account the probability that any one of those customers needing standby would be off at any 20 one time, it may be appropriate to consider a standby service similar to those Mr. Stephens 21 included as examples in Exhibit-OW System-Stephens-3. But MGE has only one customer 22 with such a need, far fewer than required to possibly make such an approach feasible and 23 prudent. Consequently, the full cost of maintaining the backup capacity must reasonably be 24 allocated to that one customer, in this case the UW. Therefore it would be inappropriate to Rebuttal-MGE-Bollom-7 1 allow the UW to only pay for a few days of the service based on the daily demand charge for 2 only those days its generator was not actually available. 3 Q. Why is it inappropriate to eliminate the penalty provision for failing to perform when 4 called upon my MGE? 5 A. Eliminating the $25 per kW penalty for instances beyond a first failure has the same effect as 6 allowing the UW to only pay for the number of days it uses capacity. If the only penalty for 7 non-performance is payment of the daily demand charge for the full metered load, there is no 8 incentive for the UW to properly maintain its generation and no incentive for the UW to take 9 seriously the annual nomination process. The UW could effectively nominate zero and then 10 only pay for the days it chooses not to run its generation. MGE would still need to plan to 11 serve the full UW load assuming no CSHP generation existed, but the rates would effectively 12 shift a significant portion of the cost of maintaining that capacity for the UW to MGE's other 13 customers. That's why the PSCW should reject this proposed change to the Sp-3 tariff. 14 Q. Both Mr. Weiss and Mr. Stephens suggest MGE should be ordered by the PSCW to meet 15 with the UW within 90 days of its order to discuss the potential for restructuring the Sp- 16 3 energy rates to incorporate a direct measure of actual MISO LMPs, and if agreement 17 is reached to present a proposal to the PSCW no later than July 1, 2013? Is this a 18 reasonable request? 19 A. The UW only recently approached MGE with the idea of restructuring the Sp-3 energy rates to 20 incorporate a direct measure of actual LMPs. MGE indicated to the UW this was a discussion 21 we were open to. MGE and the UW meet regularly through a variety of both structured 22 committees and less formal groups. We are willing to continue to discuss changes to the Sp-3 23 rate, but find the 90-day requirement to be unnecessary. We are also concerned about 24 specifying a July 1, 2013, date that likely bears little relationship to a subsequent full rate case 25 filing schedule. If the past is any guide to the future, proposed changes to the Sp-3 tariff to Rebuttal-MGE-Bollom-8 which both parties can agree can often affect the revenue requirement allocation to other MGE 2 customers or could set a policy precedent such that consideration in a full rate case proceeding 3 with public hearings is necessary. Consequently, MGE is willing to commit to continued 4 discussions with the UW to ensure that the proper economic incentives and cost allocations 5 are in place for both parties, but we find the 90-day requirement unnecessary. Any changes to 6 the Sp-3 tariff should be fully vetted through a complete rate case and should not be required 7 to be submitted by an arbitrary date as part of a separate, stand-alone process. MGE would 8 suggest the PSCW may wish to avoid setting the precedent of authorizing an individual 9 customer to negotiate a preferred rate outside of the normal rate case process. 10 Q. Mr. Jonathon Wallach testifying on behalf of CUB, focused only on MGE's request to 11 change residential electric rates. He indicates that MGE's proposal to increase customer 12 charges would result in a "radical redesign of residential rates." (Direct-CUB-Wallach- 13 10) Do you agree? 14 A. No I do not. While the relative level of charges within MGE's Rg-1 tariff will change, there 15 will still be a daily fixed charge and a variable per kWh charge. I do agree with Mr. Wallach 16 that the level of the per kWh charge would be dramatically reduced if all the non-variable 17 energy costs were recovered through a fixed charge. For illustrative purposes, I think it is 18 worth noting that even if the per kWh charge were reduced from 14 cents to 4 cents, which is 19 more than MGE's proposal, the variable energy rate would still be almost 60% higher than the 20 estimated average LMP cost of a little over 2.5 cents for the 2013 test year. 21 Q. Mr. Wallach challenges the Company's assertion that demand-related costs are fixed for 22 residential customers. He states that the Company has failed to provide any rationale for 23 why it believes demand-related distribution costs are fixed. How do you respond? 24 A. Demand-related costs for distribution can vary with the size of the customer. However, the 25 variation is relative. The residential class is generally the most homogeneous class of Rebuttal-MGE-Bollom-9 customers on MGE's system. While there are always exceptions to any generalization, the 2 distribution services used to supply MGE's residential customers-the infrastructure necessary 3 to physically deliver energy and meter its usage-is similar across the class. Unlike 4 commercial or industrial customers where demands can vary from as little as a few kilowatts 5 to tens of megawatts, the peak demand for MGE's residential customers generally doesn't vary 6 by plus or minus a couple kW from the 5 kW non-coincident class average. Consequently, the 7 demand-related distribution cost for most residential customers is basically the same and does 8 not vary with the level of monthly energy use. That's why residential customers are generally 9 only metered with simply energy-only meters. With so little variation in demand, the higher 10 cost of demand meters is not justified. And that's also the reason why MGE believes it is 11 appropriate to consider demand-related costs of distribution to be generally fixed costs that are 12 more appropriately recovered through fixed charges than through variable kWh charges. 13 Q. Mr. Wallach raises similar concerns with demand-related generation and transmission 14 costs and states that MGE in fact acknowledges these costs vary with customer load. If 15 MGE agrees these costs vary with customer load.., why is it appropriate to consider them 16 fixed costs for residential customers? 17 A. For the same reason I cited for demand-related distribution costs, I believe it is appropriate to 18 consider demand-related generation and transmission costs as fixed for residential customers. 19 Relative to the entire population of utility customers, residential customers are very similar 20 from an electric service perspective. Again unlike C&I customers with coincident peak loads 21 that can vary from a few kW to many tens of megawatts, each residential customer's 22 contribution to MGE's coincident peak demands varies little from the class coincident peak 23 average of approximately 2.6 kW. Consequently, MGE treats them for planning purposes as 24 the same. The minor cost differences do not justify the cost of separately demand metering 25 each residential customer, and MGE believes it is appropriate to treat these costs that do not Rebuttal-MGE-Bollom-1 0 1 vary with the level of monthly kWh usage as fixed costs that should be recovered through 2 some type of fixed charge. 3 Q. Mr. Corey Singletary of the PSCW staff also addresses the Company's proposal to 4 increase customer charges in its rate design in this case. Beginning at Direct-PSC 5 Singletary-11, Mr. Singletary suggests that the current recovery of some portion of fixed 6 costs through variable charges is a product of policy decisions to trade off some pure 7 economic efficiency in order to encourage conservation. Do you agree with his 8 characterization that the key question is "whether the Commission believes that the 9 frustration caused by the 'whack-a-mole' aspect of the current fixed vs. variable charge 10 rate design disincentivizes conservation and energy efficiency efforts to such a degree as 11 to overwhelm the incentives provided by proportionally higher bill savings per unit 12 energy saved"? 13 A. I do agree that the key question, at least with respect to this limited issue, is a policy decision. 14 I agree that, all else being equal, higher prices send a stronger signal to discourage 15 consumption than do lower prices. But customer perception of the signal is important to put 16 into context. For better or worse, most customers don't spend a lot oftime engaging with their 17 utility service. MGE provides a lot of information to customers on the costs of energy and 18 benefits of conservation. We provide information in monthly bills, we run media advertising 19 campaigns, and we have information on our website. But most residential customers still can't 20 tell you how many kWh of electricity or therms of gas they use in a month. Most know what 21 their monthly bill is, but very few take the time to really engage in their energy use. If the 22 weather is cold in the winter or warm in the summer, they expect their bill to be higher. If the 23 weather is the opposite, customers generally expect to see a lower bill. Similarly, if they make 24 home improvements or install a new furnace or air conditioner, they expect their bill to go 25 down. But very few have a good idea by exactly how much. Rebuttal-MGE-Bollom-11 Mr. Singletary's rate design retains the lower current customer charge and has a total 2 energy rate in the summer of $0.15492 perkWh. Using the staff-recommended revenue 3 requirement allocation in Mr. Singletary's rate design, if the customer charge were increased 4 to the level requested by MOE, the total energy rate in the summer would decrease to 5 $0.14845 per kWh. Increasing the customer charge to the level proposed by MOE would 6 result in only a $0.0064 7 per kWh difference in the energy rate for a residential customer. If a 7 customer reduces its AC usage by 100 kWh a month by increasing its thermostat setting, all 8 else-including the current customer charge-being equal, the customer would see an extra 9 savings of only 65 cents on its monthly bill. This is a conservation signal, but it may be easy 10 to overestimate the extent to which it actually affects our customers' decision-making. Indeed, 11 with even the slightest variation in weather, the savings will not be discernible to the customer 12 at all. But the sum of many small reductions across the population of customers often results 13 in MOE requesting an increase in rates to offset the lost recovery of fixed costs. And as 14 Mr. Singletary concedes, when customers do conserve (or see reduced usage because their 15 business is off during a recession) and they see their utility ask for a rate increase to offset the 16 reductions in sales, it is difficult to understand. 17 Q. Mr. Singletary also states that consideration should be given to the proportionally 18 greater impact a higher customer charge will have on low usage customers, in particular 19 those customers that may be on a low or fixed income. Have you looked at this issue? 20 A. Yes and I agree that a higher fixed customer charge will have a proportionally larger impact 21 on lower usage customers. MOE has proposed to phase in higher customer charges over a 22 several year period to mitigate the impact on these very customers. Further, it is not entirely 23 appropriate to assume that lower usage customers are necessarily correlated with lower 24 income customers. MOE had close to 5,000 customers that received service at one address for 25 the full calendar year 2011 and also received some form of energy assistance payment during Rebuttal-MOE-Bollom-12 the year. Using that group to represent lower income residential customers, MOE compared 2 the average monthly usage for these customers with average customers generally. While lower 3 income customers do tend to use slightly less, the two groups are fairly similar. The median 4 monthly usage for customers receiving energy assistance was 512 kWh vs. 538 kWh for 5 residential customers generally. Increasing the customer charge will not disproportionately 6 disadvantage lower income customers to a significant extent. 7 Q. Mr. Singletary agrees that there is some cross-subsidization under MGE's current rate 8 structure from non-distributed generation (DG) customers to DG customers taking 9 service under MGE's net metering tariff. But he goes on to suggest that while the growth 10 in customer-owned DG does present challenges with respect to cross subsidization under 11 current rates, he hasn't seen any analysis to suggest a "clear and present danger" to the 12 sustainability of MGE so as to support raising customer charges for all customers. 13 (Direct-PSWC-Singletary-13) Do you agree with Mr. Singletary? 14 A. No. Although Mr. Singletary appears to concede there may be more appropriate ways to align 15 rates and costs, he does not currently see a significant problem and he believes the mismatch 16 between rates and costs can wait to be addressed. From MOE's perspective, the time to 17 address the mismatch is now before it becomes a significant problem. To paraphrase 18 Mr. Singletary, the current lack of a "clear and present danger" makes this the appropriate time 19 to address the issue. 20 Q. What are some of the reasons to address the current mismatch between rates and costs 21 now? 22 A. First, most customers with DO likely made the decision to own their own generation based on 23 a tradeoff between the costs to own and operate the DO and the savings they earn on their 24 utility bills. Under MOE's current rate structure, net metering allows customers to receive an 25 energy credit equal to the full variable retail rate per kWh. As Mr. Singletary has conceded, Rebuttai-MOE-Bollom-13 the current variable kWh rate includes some fixed cost recovery. Since those fixed costs do 2 not disappear when a customer installs DG, those fixed costs to serve the DG customer are 3 essentially shifted to other customers. If over time the rates are brought more into alignment 4 with costs, the variable energy rates will go down and as a result so will the economic value of 5 net metered generation. If the PSCW begins to address the mismatch now by phasing in higher 6 customer charges as proposed by MGE, the impact of the realignment will be mitigated for 7 those customers currently operating DG under net metering. Second, the current number of 8 DG customers remains relatively low. The subsidy from non-DG customers to DG customers 9 can be gradually reduced and the number of DG customers that will be affected by the 10 inevitable realignment of rates and costs also will be minimized. The PSCW's options for 11 addressing realignment in the future become more challenging as the number ofDG 12 customers and the total associated cross-subsidy continue to grow. 13 Q. Does MGE believe that net metering provides a valuable service to customers? 14 A. Yes. Net metering provides a relatively easy to understand way for customers to interconnect 15 their own DG to MGE's system. But net metering only works properly if costs and rates are 16 aligned, and the current mismatch puts MGE in a difficult situation. Under Act 141 that grew 17 out of a bipartisan effort to address a variety of energy-related issues in Wisconsin, there were 18 some significant changes to the rules related to Wisconsin's renewable portfolio standard 19 (RPS). To balance the increased cost of renewable energy with the environmental and energy 20 diversity benefits renewable energy provides, Act 141 made changes to 196.3 78( 4m), Wis. 21 Stat., that prohibited the PSCW from imposing additional renewable energy requirements on a 22 utility if that utility is in compliance with the RPS. IfMGE's rates and costs are not realigned, 23 then net metering as it currently operates effectively imposes upon MGE a requirement that it 24 acquire more renewable energy than it needs. MGE is currently in compliance with its RPS 25 requirements. Requiring MGE to pay a premium for renewable energy-all of MGE's net Rebuttal-MGE-Bollom-14 metered customers have either wind turbines or PV as their DO-effectively imposes upon 2 MGE a requirement to acquire more renewable energy. Unless the PSCW indicates in this 3 case that it is appropriate to begin phasing out the subsidy embedded in MGE's current rate 4 structure, then MGE will be forced to consider seeking other changes to its net metering tariff. 5 Q. Mr. James in his direct testimony proposed adding language to the Pg-2 net metering 6 tariff a provision that clearly states the customer retains ownership of the renewable 7 attributes. This suggests that MGE is not purchasing renewable energy. Why do you 8 conclude that net metering requires the MGE to purchase renewable energy? 9 A. Mr. James' rate design also incorporates the changes to the customer charges I describe in my 10 direct testimony. MGE's proposals in this case need to be reviewed as a total package. Since 11 we are proposing to begin realigning rates to better match costs, it would be inappropriate for 12 MGE to claim the renewable attributes without paying for them. However, if the PSCW 13 continues its past policy of recovering significant fixed costs through variable energy charges, 14 MGE would have to reconsider ownership of the renewable attributes. It would be 15 inappropriate for non-DG customers to both pay a significant premium for net metered 16 renewable energy and not get any benefit for that premium. 17 Q. Is your proposal consistent with federal law applicable to buy-back rates? 18 A. Yes. Increasing customer charges while reducing energy charges would bring MGE's net 19 metering tariff closer to the federal approach to this issue. 20 I am not a lawyer, and I was surprised to learn that residential customers who have solar 21 panels installed on their homes and sell the power they generate back to MGE are technically 22 considered "public utilities" under the Federal Power Act. The Federal Energy Regulatory 23 Commission ("FERC") sensibly declines to assert its jurisdiction over these customers as a 24 general matter. However, if a customer becomes a net seller-that is, if the customer sells 25 more self-generated power to MGE than it uses for its own purposes-then FERC will assert Rebuttal-MGE-Bollom-15 jurisdiction and the customer will be considered a "Qualifying Facility" within the meaning of 2 the Public Utility Regulatory Policies Act ("PURPA"). 3 Under PURPA, the rates MGE pays to purchase energy from a net seller customer 4 cannot exceed MGE's avoided costs. "Avoided costs" is another way of saying variable costs. 5 In other words, once an MGE customer with solar panels becomes a net seller, the rates that 6 MGE pays the customer cannot be designed to recover any portion of MGE's fixed costs. 7 Consequently, using the rates proposed by Mr. James in Ex-MGE-James-2, MGE will 8 purchase residential customer-generated electricity under the net metering tariff at a rate of 9 15.129 cents per kWh (summer), but ifthe customer becomes a net seller, the rate MGE can 10 pay for self-generated electricity drops to 4.285 cents per kWh on-peak and 2.803 cents per 11 kWh off-peak. In light of this, contractors will work with customers to design solar panel 12 arrays that allow the customer to generate nearly all its energy needs, but no more than it 13 needs in order to avoid "net seller" classification. 14 From our perspective, the federally authorized PURP A approach to buy-back rates is 15 economically sound because it provides a price signal that is more accurately matched to the 16 benefits that flow from customer investment in distributed generation. In addition, from a 17 practical perspective, it makes sense for the PSCW to authorize rates that reduce the level of 18 fixed costs recovered through the energy charge so as to begin to mitigate the reverse rate 19 shock that a distributed generation customer would experience if it became a net seller. 20 Q. Are there any other alternatives to address net metering if the PSCW decides to retain 21 significant recovery of fixed costs through variable kWh charges? 22 A. Yes, the Company could seek to close or cap net metering in a subsequent rate case as another 23 utility has proposed in its current case. This would eliminate the risk that MGE would be 24 required to purchase renewable energy in excess of its RPS requirements. As I noted earlier 25 though, MGE finds net metering to be a useful and simple way for customers to understand Rebuttal-MGE-Bollom-16 1 how to interconnect DO to MOE's system. MOE believes it would be preferable for the PSCW 2 to approve MOE's request to begin better aligning costs and rates than to force MOE to seek 3 other less desirable alternatives to net metering. 4 Q. In response to the request in your direct testimony that the PSCW issue a finding "that it 5 is appropriate and necessary for MGE to move to rate designs that recover fixed costs 6 through some type of fixed charges", Mr. Singletary suggests an alternative should the 7 PSCW wish to decide on a long-term goal is for MGE to work with PSCW staff to 8 develop metrics for evaluating whether customer charges should be adjusted. How do 9 you respond to his suggested alternative? 10 A. MOE is always willing to work with PSCW staff to help all parties and the Commission better 11 understand issues. But we believe there is more than enough information presented in this case 12 for the PSCW to make a determination that rates and costs should be more closely aligned. 13 Mr. Singletary's and Ms. Vandervort's proposal to hold most customer charges constant should 14 be rejected. The level of customer charges proposed by MOE witnesses Mr. James and 15 Mr. Minor are a reasonable first step and should be authorized as part of the approved rate 16 design in this case. MOE will be happy to work with PSCW staff to develop an appropriate set 17 of subsequent progressions in customer charges if the PSCW finds that useful. 18 Q. Do you agree with all of the PSCW staff electric sales adjustments as represented in 19 Ms. Gail Maly's direct testimony and if not, what items do you take issue with? 20 A. No, I do not agree with all of the electric sales adjustments as detailed on Direct-PSC-Maly-4 21 of Ms. Maly's direct testimony. In particular, I take issue with the Cg-4a/4b on-peak/off-peak 22 sales adjustment that was made in this case. As part of the electric sales audit, PSCW staff 23 increased MOE's filed estimates of the proportions of kWh energy usage in the Cg-4a and Cg- 24 4b rate classes that are used during on-peak periods to levels that actually exceed the levels 25 that existed prior to the increase in ori-peak rates. This is inconsistent with both Commission Rebuttal-MOE-Bollom-17 staff testimony in a prior docket supporting the shift to mandatory time-of-day (TOD) rates 2 and the raison d'etre for time-differentiated rates. 3 Q. Please describe the recent history for customers in these rate classes. 4 A. Prior to the 3270-UR-116 case, MGE offered two demand and energy rate options for 5 customers with a maximum demand between 20 and 200 kW. The Cg-1 rate was a demand 6 and energy rate in which the energy and demand charges were not time differentiated. The 7 Cg-4 rate was a TOD rate offered as an option for these customers. In the 3270-UR-116 case, 8 the Commission staff proposed that the Commission close the Cg-1 rate and require customers 9 to take service under the Cg-4 TOD rate. As justification for this change, PSCW staff witness 10 Feit in his direct testimony (PSC REF#:120420, pages D9.101-D9.102) stated, "The objective 11 of passive demand response programs is to provide customers with 'better' price signals than a 12 standard rate structure. Increasing electric prices during periods when costs are relatively 13 higher result in lower usage during higher cost periods and thus lower overall costs." 14 The Commission found this reasonable and ordered MGE to work with staff to 15 implement this provision. MGE closed the Cg-1 rate class to new customers in January 2010 16 and transferred all customers to Cg-4 by April2012. Consistent with the PSCW's intent in 17 requiring the shift to mandatory TOD rates, in creating the UR-118 test year sales forecast, 18 MGE assumed that customers would react to increasing on-peak electric rates and begin 19 shifting some of their energy use to the lower priced off-peak periods. MGE's projected 2013 20 Cg-4 on-peak energy percentages were lower than our actual 2009 load research on-peak 21 percentages. 2009 data is of interest because it was the last full year of load research data 22 before the Cg-1 class was closed to existing customers and new customers began to be placed 23 in the Cg-4 class on a mandatory basis. During the UR-118 electric sales audit, MGE provided 24 staff with the 2009 Cg-1 and Cg-4 load research data as justification for MGE's Cg-4 on-peak 25 and off-peak energy percentage forecasts. Despite this information, PSCW staff adjusted the Rebuttal-MGE-Bollom-18 1 test year on-peak percentages to a level higher than the 2009 actual level. Detailed below is a 2 table with the applicable on-peak billing statistics. 2009 Actual PSCW 2013 Staff MGE 2013 Forecast Rate Class On-Peak Audited On-Peak On-Peak Percentage Percentage Percentag_e Cg-la/4a 39.6% 39.2% 39.9% Cg-lb/4b 38.4% 36.8% 39.2% 3 Q. Do you agree with the implication of PSCW staff's sales audit adjustment, namely that 4 customers when moved to a time-of-day price structure will begin using more energy 5 during the higher priced period? 6 A. No. While it is uncertain to what extent customers will be able to shift load to the lower priced 7 off-peak period, we do not believe that customers as a group will use more energy during the 8 higher priced on-peak period. We believe this is especially true for the larger Cg-4b 9 customers. These customers have maximum demands between 76 and 200 kW. Because of 10 their size, they are more likely to have electric processes that will allow them to shift load to 11 off-peak periods in response to the significant economic incentive and subsequently lower 12 their on-peak percentages. Consequently, the PSCW should reject staff's adjustment to the on- 13 peak percentages for the Cg-4a and Cg-4b rate classes. 14 Q. Does this conclude your rebuttal testimony? 15 A. Yes it does. Rebuttal-MGE-Bollom-19 PSC REF#:l71786 BEFORE THE 2 PUBLIC SERVICE COMMISSION OF WISCONSIN 3 Application of Madison Gas and Electric 4 Company for Authority to Change Electric Docket 3270-UR-118 5 and Natural Gas Rates 6 REBUTTAL TESTIMONY OF JEFFREY M. KEEBLER 7 ON BEHALF OF APPLICANT 8 Q. Please state your name, title, employer, and business address. 9 A. My name is Jeffrey M. Keebler. I am the Assistant Vice President - Energy Supply and 10 Customer Service for Madison Gas and Electric Company, 133 South Blair Street, Madison 11 Wisconsin 53703. 12 Q. Please state your educational background and work experience. 13 A. I graduated from UW-La Crosse with a BS in Finance and Economics and from UW- 14 Whitewater with an MBA. I have been employed by MGE since 1995 in various roles, 15 primarily in the energy procurement areas. My current role includes oversight of our Energy 16 Supply and Trading, Energy Market Operations, NERC Compliance and Generation 17 Operations, as well as our Customer Services departments. I have testified before the Public 18 Service Commission of Wisconsin multiple times on energy supply and fuel cost matters. 19 Q. What is the purpose ofyour rebuttal testimony? 20 A. I will address issues related to MGE's fuel costs, in particular those areas discussed by Staff 21 Witness Hillebrand and CUB witness Neal. 22 Q. CUB witness Neal recommends the inclusion of Make Whole Payments (MWP) in 23 MGE's fuel cost forecast. Do you agree that MWP should be included? 24 A. No. Ms. Neal's contention is a repeat of one that CUB's witness made in our last rate case. I 25 will repeat some of the same points I provided last time that explain why CUB is wrong. MGE Rebuttai-MGE-Keebler-1 1 determines its fuel cost projections based on a computer model that predicts how MISO will 2 dispatch MGE's generation units based on a forecast of LMPs. MGE's model does not include 3 forecasts of runs that result from MISO dispatch for reliability reasons. These runs are 4 typically uneconomic-if they were not, they would be initiated by MISO in the normal 5 course of its economic dispatch. MISO typically provides MWPs to the operators of the units 6 that it dispatches for reliability reasons in order to bring their revenues up to the level of their 7 expenses. It is true that MGE's forecast does not include MWPs as revenues, but the forecast 8 also does not include the additional costs that the MWPs are intended to offset. All in all, it's a 9 wash. As Ms. Neal observes, MWPs are sometimes provided under circumstances other than I 0 reliability dispatches, but as I explain below, they are appropriately disregarded in MGE's II model. I2 In our last rate case, the re-opener in 3270-UR-II7, the Commission's final decision I3 discussed CUB's MWP contention and concluded that "in the absence of a showing of a 14 material flaw, MGE's modeling assumption is reasonable. It is therefore reasonable that the 15 test-year electric fuel cost forecasts do not reflect a forecast of MISO RSG make-whole 16 payments." (Final Decision in Docket 3270-UR-117 [PSC REF# 157113], page 16.) 17 Q. Has CUB's witness demonstrated a material flaw in MGE's modeling assumptions in this I8 proceeding? 19 A. No. 20 Q. Please explain. 2I A. Ms. Neal discusses three separate types ofMWP. The first MWP is called the DA RSG MWP. 22 It is provided when MISO dispatches a generator in the day-ahead (DA) market, but the LMP 23 ends up not covering the full offer cost. In this case, the MWP is provided to the market 24 participant so that the generator's revenue matches its offer. As an example, assume a 25 generator's full run is expected to cost $10,000, including start-up, no-load, and energy and Rebuttal-MGE-Keebler-2 ancillary production costs. Also assume the total expected revenue resulting from the energy 2 and ancillary sales to the market is expected to be $9,500. The revenue is less than the cost, 3 resulting in the need for a MWP of $500 to make the run feasible. 4 Since the run is not economic on its own, MGE's model would not dispatch the unit. 5 Therefore neither the cost of $10,000 nor the revenue of $10,000 ($9,500 from the market and 6 $500 from the MWP) are included. If the MWP were to be included in MGE's fuel cost 7 estimates, then the market revenue and the offsetting costs would also need to be included. 8 Q. What is the second type of MWP that Ms. Neal discusses? 9 The second type ofMWP is called the RT RSG MWP. It is provided to generators that are 10 dispatched, typically for reliability reasons, after the DA market clears. 11 This MWP is similar to the DA RSG MWP except that the unit is receiving RT market 12 prices and therefore the MWP is calculated based on the R T market. Assume a similar 13 scenario as above. The cost for a run is $10,000 and the DA market revenue is $9,500. In this 14 scenario, the unit is not dispatched by MISO in the DA market. Now MISO dispatches the unit 15 in the RAC process for reliability reasons and real-time revenues equal $8,000. Costs remain 16 at $10,000, however market revenue is only $8,000. The difference of $2,000 will be paid as a 17 RT RSG MWP to the generator. 18 This is not an economic run. MGE's model would not dispatch the unit, therefore neither 19 the cost of $10,000, nor the revenue of $10,000 ($8,000 from the RT market and $2,000 from 20 the MWP) is included. If the MWP were to be included in MGE's fuel cost estimate, then the 21 cost and the market revenue would also need to be accounted for, since the cost just matches 22 the market revenue plus MWP, there would be no impact on MGE's fuel cost estimate. 23 Q. What is the third type of MWP that Ms. Neal discusses? 24 The third type ofMWP is called the RT Price Volatility MWP. This payment is made to 25 generators to keep them whole when they follow dispatch instructions from MISO, but are Rebuttal-MGE-Keebler-3 disadvantaged financially due to the dispatch. This MWP is a little more complex, but the 2 same outcome holds-the MWP is paid to keep the generator whole. It does not create 3 incremental revenue . 4 Q. Please explain. 5 In the DA market, the LMP is simply an hourly price, and while units are "dispatched" by 6 MISO in the DA market, there is no actual "day ahead" operation of the units. The actual 7 operation occurs in real time, as MISO sends set point instructions to the units. The RT LMP 8 is the average of 12 five-minute pricing periods for each hour. Certain circumstances can 9 cause a generator to lose money compared to its DA commitment when it follows MISO's RT 10 dispatch instructions. For example, five-minute market prices may vary within an hour in a 11 way that affects the RT MWh generation of the unit, causing actual production to deviate from 12 the DA MWh commitment. Generally, if the RT prices stay above the cost of the unit, there is 13 no change in its dispatch. However, if certain five-minute period prices are above the cost of 14 the unit and others are below the cost of the unit in the same hour, MISO will modify the 15 dispatch. Since the unit is already operating there is no impact of the start-up and no load 16 costs. 17 The following is a simplified example of this process: 18 Assume the following: 100 MW unit, Offer cost of$30, DA LMP of$35, unit is 19 dispatched for economic reasons, start-up and no load costs are covered, unit dispatched in 20 accordance with unit constraints. 21 In this scenario, the LMP exceeds the cost of the unit, so it will be dispatched. The 22 expected cost is $3,000 and the expected revenue is $3,500. In RT, prices start the hour at $40, 23 but then drop for several five-minute periods to $25, before rebounding again to finish the 24 hour at $50, with an average price of $38. In the periods where the five-minute price is $30 or 25 above, MISO will dispatch the unit at 100 MWh. However as the five-minute prices drop, Rebuttal-MGE-Keebler-4 MISO will lower the dispatch of the unit, since the offer cost of the unit is greater than the 2 market price. When the market price increases above the offer cost, MISO will again dispatch 3 the unit at 100 MW. Since the unit was dispatched at a lower level for several periods, the 4 actual generation for the hour will be below 100 MWh. Assume it is 90 MWh in this case. The 5 unit owner agreed to sell 100 MWh in the DA market at a market price of$35. However, due 6 to following MISO dispatch, the unit only produced 90 MWh. The unit is required to buy back 7 the difference between its DA commitment (I 00 MWh) and its actual production (90 MWh) at 8 the RT LMP, which for the hour is actual higher than the DA LMP. As shown in the following 9 chart, the net impact of this lower production is the unit lost $80 by following MISO dispatch. 10 MISO provides the RT PV MWP to cover this loss. DA Clearing RT Settlement Net Position Generation 100 DA Generation 100 DA Net Revenue $500 LMP $35 RT Generation 90 Bu~ Back Cost -$380 Revenue $3,500 Difference -10 Production Savings $300 Net Market Result $420 Generation 100 Bu:l::: Back at RT Price $38 Offer Cost $30 Buy Back Cost -$380 RTPVMWP $80 Total Cost $3,000 Total Net Revenue $500 Offer Cost $30 Net Revenue $500 Production Savings $300 Model Revenue $500 Difference $0 Net Cost vs DA $80 II Q. Why is it inappropriate to include the MWP in the forecast? 12 A. In the model, MGE would assume a dispatch in the market of I 00 MW at its forecast price. In 13 the example this would be 100 MW at $35 per MWh or $3,500 of market revenue. In addition 14 the model would assume a cost of 100 MWh multiplied by the offer cost of$30 per MWh, for 15 a total cost of $3,000. The net revenue from the market for this generator is $500. As shown in 16 the chart, the RT PV MWP provides revenue to make the unit whole to its DA clearing, which 17 is exactly what MGE forecasts. If the RT PV MWP were to be included, MGE would have to 18 also include the expected buy-back cost and reduced fuel costs. Since these will net to zero, it 19 is not worth going through the workto incorporate these items. Rebuttal-MGE-Keebler-5 Q. CUB witness Neal recommends that MGE utilize a lower EFOR for WCCF. Please 2 comment. 3 A. CUB's calculations are incorrect. The NERC definition ofEFOR uses "service hours" as the 4 denominator. CUB appears to have used calendar hours in its denominator, which would 5 significantly reduce the EFOR. Since CUB's calculations are not correct, it has not 6 demonstrated that MGE's EFOR estimate should be adjusted downward. 7 In addition, the EFOR has little consequence for WCCF costs in this case. WCCF is run 8 for economic purposes as well as "must run" during uneconomic periods for steam production. 9 IfMGE utilized a lower EFOR for WCCF in its fuel cost model, the plant would be forecast to 10 run more frequently, but this would not result in any increased net revenues for the company if 11 uneconomic dispatch costs would be incurred during the additional operating hours. Only 12 those additional operating hours that would occur at times when the plant could be dispatched 13 economically would result in additional revenues for the company. The additional revenues 14 that would be forecast utilizing a lower EFOR for WCCF are unlikely to be significant. 15 Q. CUB Witness Neal discusses MGE's capacity plans. Can you briefly comment on the 16 state of the MISO capacity market? 17 A. The MISO short-term capacity market is very weak at this point in time. Generally, the market 18 has excess capacity and therefore the prices in the market are low. MGE actively monitors 19 both the bilateral market as well as the monthly capacity auction for opportunities. MGE does 20 not have plans to sell excess capacity due to the current low market prices, but will react to 21 opportunities that become available. 22 Q. CUB Witness Neal believes that the planned outages should be moved to October 2013. 23 Do you agree with this? 24 A. No. Outage planning requires coordination between various entities, including MISO, ATC, 25 joint plant partners, and vendors. MGE has completed its planning process and determined the Rebuttal-MGE-Keebler-6 dates of these outages on the basis of a number of considerations. MGE files its outage 2 schedule with MISO, which then reviews the proposal and determines whether or not the 3 outages can proceed as scheduled. Once a schedule is approved, changes in the dates of 4 planned outages can become difficult to arrange. CUB Witness Neal prefers that we should 5 move outages to October, when she expects LMPs to be lower. Projected LMP levels are one 6 of the factors we took into account, and in fact MGE would not save money by shifting the 7 outages to October based on projected LMPs as of May 15 (the last date prices were updated). 8 Q. Please comment on CUB witness Neal's concerns regarding Elm Road. 9 A. Ms. Neal is wrong when she asserts that offering Elm Road as economic in the MISO market 10 in all months except July and August in 2013 would result in significant fuel cost savings for ll MGE. In Docket 05-UR-1 06 in response to 9-CUB/Inter-4, WEPCO performed a fuel cost run 12 for 2013 changing Elm Road from a must-run unit to an economic unit. Several unit 13 conditions needed to be adjusted as well, such as minimum run time and minimum down time 14 to reflect an actual economic offering scenario. The results of this run were a projected 15 savings of approximately $193,000 on a plant basis. Assuming MGE's ownership percentage, 16 a comparable number for MGE's share is about $16,000. While this number will change for 17 each fuel run and MGE could forecast a slight cost or a slight savings, the outcome of 18 changing the dispatch from must-run to economic is likely to be immaterial. MGE should not 19 be required to adjust its model. 20 Q. Staff Witness Hillebrand's testimony contains various adjustments to the fuel costs. In 21 Adjustment 10, he proposes a method for handling the costs associated with Cross State 22 Air Pollution Rule (CASPR). Do you agree with his method? 23 A. Yes. MGE agrees with Mr. Hillebrand's recommended approach of amortizing over calendar 24 20 13 and 2014 costs incurred prior to the Court action on August 21, 2012, striking down 25 CSAPR. No additional costs will be forecast for inclusion in rates associated with CSAPR. Rebuttal-MGE-Keebler-7 Q. CUB witness Neal recommends removing all costs associated with CSAPR compliance 2 from fuel costs. Do you agree with this recommendation? 3 A. No, I don't as it fails to recognize that MOE has already incurred $470,000 of costs in 4 anticipation of complying with CSAPR. 5 Q. Why did MGE incur costs associated with CSAPR? 6 A. Consistent with MOE's CSAPR compliance plan, MOE purchased 2013 S02 allowances. 7 MOE had very few alternatives for compliance with then-anticipated CSAPR requirements, 8 since the majority of our S02 emissions come from Columbia, which is a base load plant for 9 MOE. Without purchasing allowances, MOE's only other option would be to reduce the 10 dispatch of Columbia. This option would be extremely expensive and was the subject of much 11 discussion in MOE's last rate case. In that case, decreasing the dispatch of Columbia was 12 projected to cost annually in the neighborhood of$14.5 million dollars. While that number 13 changes with the fuel runs, it would not have dropped significantly if the projections were 14 updated. 15 MOE believes that proper planning is required for its fuel expenses. There is always 16 some level of uncertainty with respect to specific costs, fuel volumes, and other factors that 17 need to be taken into account in our planning. With this uncertainty, it is prudent to develop 18 plans which allow MOE to be flexible. In preparing for CSAPR, MOE reviewed available 19 alternatives and concluded that the best option was to purchase some allowances in the event 20 the rule went forward. MOE looked at both futures and options and concluded that purchasing 21 some, but not all of our estimated allowance requirements, was the best path. Waiting to 22 purchase all the allowances that would potentially be required left too much risk for 23 customers. 24 Q. Does this conclude your testimony? 25 A. Yes. Rebuttal-MOE-Keebler-8 PSC REF#:l71783 BEFORE THE 2 PUBLIC SERVICE COMMISSION OF WISCONSIN 3 Application of Madison Gas and Electric 4 Company for Authority to Change Electric Docket 3270-UR-118 5 and Natural Gas Rates 6 REBUTTAL TESTIMONY OF STEVENS. JAMES 7 ON BEHALF OF APPLICANT 8 Q. Are you the same Steven S. James who previously filed direct testimony in this 9 proceeding? 10 A. Yes, I am. 11 Q. What is the purpose of your rebuttal testimony? 12 A. The purpose of my testimony is to address issues raised in the direct testimonies of Mr. Corey 13 Singletary of the PSCW and Mr. Daniel Tyson Steadman Cook of Clean Wisconsin. I am also 14 submitting Exhibit-MGE-James-3, which is the customer notice ofthe proposed rate increase. 15 Q. What do you wish to address pertaining to Mr. Singletary's direct testimony? 16 A. On Direct-PSC-Singletary-16, lines 1 through 13, Mr. Singletary proposes that MGE should 17 add to the Pg-1 tariff language indicating that, should the Midwest Independent Transmission 18 System Operator (MISO) implement a capacity market, a capacity credit will be implemented 19 reflecting the MISO capacity market methodology. In addition, Mr. Singletary proposed that 20 language be added to the tariff to clarify that the energy credits under the Pg-1 tariff are the 21 property of the customer. 22 MGE, in general, agrees with these proposals and proposes to add two new sections to 23 the Pg-1 tariff that will incorporate Mr. Singletary's suggested additions. Rebuttal-MGE-James-1 Q. What new tariff language is MGE proposing to add to the Pg-1 tariff to address 2 Mr. Singletary's concerns? 3 A. MGE proposes to add the following two sections to the Pg-1 tariff: 4 Capacity Payment 5 Should the Midwest Independent Transmission System Operator (MISO) implement a 6 capacity market, a capacity credit shall be implemented reflecting the MISO capacity 7 market pricing method. 8 Energy Credits 9 All renewable energy credits and benefits, emissions allowances, or other renewable 10 energy, air emissions, or environmental benefits for which the customer's generation 11 project qualifies under any existing or future applicable law relating to the project will 12 remain the property of the customer for any energy for which the customer receives a net 13 energy credit on its monthly bill based on the rates as shown under the Rate section of 14 this tariff. However, if the customer negotiates rates that differ from those in the Rate 15 section, the ownership of the energy credits may also be negotiated. 16 The only variation to Mr. Singletary's proposal that MGE has included is that the 17 ownership of the energy credit may be a negotiable condition if the customer on the Pg-1 tariff 18 negotiates with MGE for rates other than those specified in the Pg-1 rate schedule. 19 Q. Do you have any comments on the direct testimony of Mr. Daniel Tyson Steadman 20 Cook? 21 A. Yes. In this docket, MGE is proposing to implement optional LED lighting rates under the 22 OL-1, Outdoor Overhead Lighting tariff. Mr. Cook expresses concerns with the filed rate 23 design and with the general process that MGE is proposing for implementing LED outdoor 24 lighting. Rebuttal-MGE-James-2 Q. What is MGE's intent in proposing optional LED outdoor lighting rates? 2 A. The LED outdoor lighting option that MGE is proposing is intended for those customers who 3 are interested in having LED outdoor lighting, but are looking to avoid the direct up-front 4 costs and administrative burden of owning and installing their own LED fixtures. 5 Q. Do you know of any other investor-owned utility in Wisconsin that has LED outdoor 6 lighting rate options? 7 A. No. The lighting rate options that MGE is proposing are the first such rates in Wisconsin for 8 investor-owned utilities. Mr. Cook, at Direct-Clean Wisconsin-Cook-S, lines 7 through 9, 9 accurately states that "[i]t is important to note that the pace of advancement of LED 10 technology is such that, even within the next year, the performance and available options for 11 LED lights may change significantly." I agree. That's why only a few basic optional LED 12 lighting rates were proposed, at a rate that is lower than the alternative types of outdoor rate 13 options, for customers who are interested in company-owned LED outdoor lighting. 14 Q. Does MGE prefer that customers who want outdoor lighting sign up for the OL-1 rate? 15 A. No. Beginning on the bottom of Direct-Clean Wisconsin-Cook-4, Mr. Cook states, 16 "Depending on the design, LED fixtures that provide comparable lighting performance to a 17 150 Watt HPS fixture, for example, can vary greatly in electrical usage, total light output and 18 upfront and life cycle cost." For these reasons, MGE's preference would be to have the LED 19 lighting billed under one of our current metered rates. Under a metered rate, the customer can 20 alter its usage to utilize the unique features of LED lighting to optimize its efficiency, and the 21 customer can also install the type of LED fixture( s) that best meets its needs. 22 Q. Does MGE currently have any LED lighting installed in its service territory that is on a 23 metered rate? 24 A. Yes. Currently, several communities have installed multiple LED lighting fixtures and are 25 taking service from MGE under a metered rate. Under a metered rate, the customers control Rebuttal-MGE-James-3 1 the type of LED fixtures they want and how they can best use the fixtures to achieve the 2 lighting requirements that they desire. 3 At Direct-Clean Wisconsin-Cook-9, lines 16 through 18, Mr. Cook states, "Without 4 LED rate structures however, consumers are not able to install LED lights in unmetered 5 locations such as along streets and roadways, or in parks." This statement is incorrect. 6 Customers have already installed metered LED fixtures in these locations. 7 Q. Why does unmetered LED lighting have to be company owned? 8 A. lfthe LED fixtures are unmetered, the only way MGE can accurately predict usage ofthe 9 LED fixture in order to identify the most appropriate rate for the fixture is if the fixtures are 10 company-owned. Usage of customer owned LED lighting can vary significantly for a 11 particular fixture since the customer has the ability to "dim" the LED lights. The volatility of 12 the usage for a customer-owned LED fixture makes its usage unpredictable. 13 Q. Has MGE had concerns with other loads that were not metered but had unpredictable 14 usage? 15 A. Yes. Wherever possible, MGE prefers that all loads be metered. For example, the Gf-1, 16 Category 2 rate option is currently available for CATV amplifiers, but MGE is proposing to 17 phase out this option because it has found the load from CATV amplifiers can vary 18 significantly from one CATV amplifier to the next. 19 Q. At Direct-Clean Wisconsin-Cook-tO, lines 7 through 9, Mr. Cook states that adoption of 20 MGE's rate design "could severely limit customer choice throughout the state, as well as 21 restricting the potential to realize energy and financial savings" from the LED 22 technology. Do you agree with Mr. Cook? 23 A. No. As stated earlier, MGE intended to design the optional outdoor LED rate so that 24 customers who want a simpler outdoor lighting alternative will have an LED option. As Rebuttal-MGE-James-4 already demonstrated by the actions of several MGE customers, standard metered service for 2 LED lighting is available and already provides the range of flexibility Mr. Cook is seeking. 3 Q. Would MGE be open to Mr. Cook's proposed "monthly rate per fixture calculation"? 4 A. No. MGE offers the OL-1 tariff as a customer service. While the number of customers who 5 participate may be low, there are customers looking for simple outdoor lighting alternatives. 6 As such, it is important to keep the administrative burden low. An unmetered formula rate 7 specific to each individual customer installation would be difficult to administer and could 8 lead to billing errors as a customer changes how it utilizes its lighting over time. Mr. Cook 9 correctly points out there is much variability in LED lighting. That is why MGE has proposed 10 only a few standardized design alternatives to respond to the few customers that request the 11 service. MGE encourages the PSCW to approve this simple tariff proposal for LED 12 alternatives. However, if the PSCW agrees with Mr. Cook that the proposed rate option is a 13 hindrance to LED technology, MGE would prefer to withdraw its proposal for this optional 14 service. 15 Q. Did MGE provide customer notices of the proposed rate increase to all customers 16 pursuant to Wis. Admin. Code § PSC 2.10? 17 A. Yes. 18 Q. How was the customer notice in Ex-MGE-James-3 distributed to MGE customers? 19 A. It was distributed as a bill insert included in all customers' bills over one complete billing 20 cycle. This bill insert was included with all bills mailed to customers from August 6 through 21 September 6, 2012. Customers who received electronic bills were provided a link within their 22 electronic bills to access the customer notice. 23 Q. Does this conclude your rebuttal testimony? 24 A. Yes. Rebuttal-MGE-James-5 PSC REF#:l71785 1 BEFORE THE 2 PUBLIC SERVICE COMMISSION OF WISCONSIN 3 Application of Madison Gas and Electric 4 Company for Authority to Change Electric Docket 3270-UR-118 5 and Natural Gas Rates 6 REBUTTAL TESTIMONY OF TAMARA J. JOHNSON 7 ON BEHALF OF APPLICANT 8 Q. Please state your name. 9 A. My name is Tamara J. Johnson. 10 Q. Are you the same Tamara J. Johnson who previously filed direct testimony in this 11 docket? 12 A. Yes. 13 Q. What is the purpose of your rebuttal testimony in this proceeding? 14 A. The purpose of my rebuttal testimony is to discuss the following items: 15 1. Comment on Public Service Commission of Wisconsin (PSCW) staff witness Corey S. 16 Singletary's comments on the Customer Service Conservation (CSC) spending and the 17 Conservation Escrow. 18 2. Comment on Citizens Utility Board of Wisconsin (CUB) witness Mary Neal's proposed 19 adjustment to the Calpine Purchase Power Agreement (PPA). 20 Q. Does MGE have any comments on Mr. Singletary's comments of how to account for 21 CSC spending in the Conservation Escrow? 22 A. Yes. MGE is comfortable with Mr. Singletary's suggestion that certain MGE CSC activities no 23 longer need to be treated through the Conservation Escrow but instead can be treated in the 24 rate case as regular customer service expenditures. In fact, MGE would be comfortable having 25 all of its CSC activities treated as regular customer service expenditures in the rate case. As Rebuttal-MGE-Johnson-1 Mr. Singletary points out, MOE's CSC budgets remain relatively consistent from year to year. 2 For this reason, from MOE's perspective, escrow accounting treatment is no longer necessary 3 unless the PSCW sees a particular need for it. 4 Q. Please comment on CUB witness Mary Neal's testimony in regard to the proposed 5 adjustment for the Calpine PPA. 6 A. On April26, 2012, MOE filed a letter with the PSCW (PSC REF#l63739) which requested to 7 "defer amounts equal to the capacity payment MOE would be making under the terms of the 8 Riverside (Calpine) PPA if it were still in effect." This would then create a liability to MOE's 9 customers for a future credit assuming MOE has the right to terminate the PPA once the 10 litigation process is complete. The PSCW approved the request on June 14, 2012 (PSC 11 REF#l66600), and any savings in capacity costs that ultimately result from the termination of 12 the contract will flow through to MOE's customers in a future proceeding. 13 Q. Does that conclude your rebuttal testimony? 14 A. Yes. Rebuttal-MOE-Johnson-2 PSC REF#:l71787 1 BEFORE THE 2 PUBLIC SERVICE COMMISSION OF WISCONSIN 3 Application of Madison Gas and Electric 4 Company for Authority to Change Electric Docket 3270-UR-118 5 and Natural Gas Rates 6 REBUTTAL TESTIMONY OF TIMM A. MINOR 7 ON BEHALF OF APPLICANT 8 Q. Please state your name for the record. 9 A. My name is Timm A. Minor. 10 Q. Have you previously filed testimony in this proceeding? 11 A. Yes, I have filed both direct and supplemental direct testimony. 12 Q. What is the purpose of your rebuttal testimony? 13 A. The purpose of my rebuttal testimony is to respond to portions of the direct testimonies of 14 Mr. Robert Bauer and Ms. Anne Vandervort ofthe Public Service Commission of Wisconsin 15 (Commission), and to respond to portions of the direct testimony of Ms. Darcy Fabrizius of 16 Constellation New Energy. 17 Q. On pages 10 and 11 of his direct testimony, Mr. Bauer identifies three issues and 18 alternatives for each issue. Does the Company wish to comment on the issues and 19 alternatives proposed by Mr. Bauer? 20 A. Yes. I will address the Company's comments on each issue separately. 21 Q. What comments does the Company have on the first issue identified by Mr. Bauer? 22 A. The first issue asks whether MGE should offer a compressed natural gas distribution service to 23 customers who are providing retail service to natural gas vehicles (NGVs). 24 The Company supports Alternatives One and Three as proposed by Mr. Bauer, which 25 both suggest approval of MGE's NGV distribution tariff. As discussed in Mr. Bauer's Rebuttal-MGE-Minor-1 testimony and implied in his Alternative Three, MGE is willing to work with staff to establish 2 reasonable boundaries or limits to the Company's proposed pilot tariff. Indeed, even after 3 MGE received interim approval to provide both NGV distribution service and FS-3 gas supply 4 service in Mr. Robert Norcross's letter dated May 23, 2012 (PSC REF# 165050), the Company 5 has proceeded with the understanding that the scope of the pilot offering would be further 6 examined in this docket. The Company is willing to revise the NGV tariff to help ensure that 7 the scope of the pilot does not exceed its original intent. The intent of the pilot program is to 8 stimulate and help foster growth in a CNG market that has been relatively slow to develop in 9 our region. 10 Q. Does the Company have any other comments on the first issue identified by Mr. Bauer? 11 A. Yes. A second and very important issue related to the approval ofthe NGV tariff is Staff's 12 recommendation to disallow the test-year plant investment pertaining to the compression 13 facility (and related appurtenances) that the Company plans to place into service at a customer 14 site. 15 As an initial matter, I note that the Company first identified $800,000 as the amount of 16 the test-year plant investment. However, since filing its application in this docket, the 17 Company has received a $200,000 grant from the Wisconsin State Energy Office for the 18 project. Thus, the amount of the test-year plant investment is now $600,000. 19 Mr. Bauer's recommendation raises two questions. The first is whether the expenses 20 related to compression equipment that MGE incurs are properly included in rate base. If the 21 answer to the first question is yes, then the second question becomes how should MGE 22 recover those expenses in rates. 23 MGE's NGV tariff is based on the premise that the distribution and compression of 24 natural gas for use as a motor fuel is properly considered a utility service. The utility's 25 investment in the facilities required to provide this service is appropriately included in rate Rebuttal-MGE-Minor-2 base because the investment covers the expense of distributing and compressing the gas just 2 up to the point where title to the gas passes to the customer and it is dispensed into end-use 3 customers' vehicles. The service is intended to help foster the growth of the market for CNG 4 as a motor fuel, which ultimately will benefit the Company's other gas customers by growing 5 the base of sales over which the Company's fixed costs may be spread. 6 Turning to the second question about the rate structure of the NGV service tariff, the 7 Company has attempted to strike a balance between ratepayer risk and market pricing, while 8 attempting to minimize cross-subsidization with other rate classes. Nevertheless, we 9 acknowledge that the contracted compressor facilities charge might under-recover costs from 10 the initial NGV customer in the short run. However, the Company believes that the short-run 11 costs may be necessary to set the stage for the long-run net benefits that ratepayers will realize 12 as the CNG market develops and the corresponding gas sales increase. It is a challenge to set 13 rates for compression and compression facilities charges prior to the development of the levels 14 of demand that those charges anticipate, but the Company remains confident that as the CNG 15 market develops, pricing and revenues will be better aligned. Because this is a pilot project, 16 the Company will closely monitor NGV sales and propose appropriate adjustments in future 17 rate case filings. 18 Q. What comments does the Company have on the second issue identified by Mr. Bauer? 19 A. The second issue asks whether MGE should offer a firm natural gas supply service that 20 includes a discount from the standard firm natural gas supply service to customers filling 21 NGVs. The Company supports Alternative One proposed by Mr. Bauer, which calls for 22 approving the Company's FS-3 gas supply tariff without changes. On page 8 of his testimony, 23 Mr. Bauer suggests that because CNG prices for NGVs are already at least $1.50 less per 24 gasoline gallon equivalence (GGE), there may be little reason to further discount the cost of 25 the gas used for compression as offered in the Company's FS-3 tariff. However, Mr. Bauer Rebuttai-MGE-Minor-3 does not take into account that there are also significant costs incurred when converting from a 2 gasoline-driven vehicle to a vehicle that runs on CNG. Moreover, vehicles dedicated to the use 3 of CNG can have a purchase price up to 30 percent more than their gasoline-driven 4 counterparts. The Company believes that reasonable incentives like those included in the FS-3 5 supply tariff should be used to encourage the use ofNGVs. Finally, it is worth noting that the 6 Commission has already approved discounted gas supply used for compression for motor use 7 in the We Energies and Wisconsin Gas Company's NGV tariffs. (I discuss the concept of the 8 peak-day credit and its proposed level in my response to Ms. Fabrizius' testimony). 9 Q. What comments does the Company have on the third issue identified by Mr. Bauer? 10 A. The third issue is whether MGE should continue to offer compressed natural gas retail service 11 to NGVs pursuant to the Company's CNG-1 tariff already on file with the Commission. The 12 Company supports Alternative One proposed by Mr. Bauer, which allows for the continued 13 operation of the CNG-1 service tariff as it was originally designed, but with the higher rates 14 more closely aligned with costs that are included in the Company's proposed rate design for 15 CNG-1. If approved, the price of CNG-1 service will increase significantly, thereby 16 eliminating any cost disparities between CNG-1 and NGV service and addressing any concern 17 over unfair competition. The Company intends to retain the CN G-1 tariff at the proposed 18 higher cost-based rate so that the public will not have an incentive to use the Company's 19 facility instead of a third-party operation. Further, the Company's facility will also be used as a 20 back-up for emergencies or when the other public facilities are down for scheduled 21 maintenance. There are also a number of CNG customers who must receive CNG service 22 pressure at 3,000 psi, which is the current dispensing pressure at the Company's facility. These 23 customers cannot receive CNG service at the higher 3,600 psi level that the pending public 24 access facility will offer. Finally, the Company plans to use the existing facility to provide 25 CNG service to its own fleet of seven dedicated CNG vehicles. Rebuttal-MGE-Minor-4 Q. What are your comments related to Ms. Vandervort's direct testimony and 2 corresponding rate design? 3 A. While Ms. Vandervort's proposed rate design reflects many sound rate design principles and 4 achieves her target revenues, her rate design falls short in terms of increasing the customer 5 charges for the residential (RD-1) and small commercial and industrial (GSD-1) customer 6 classes. The Company maintains that the benefits of increased customer charges far outweigh 7 the arguments offered for keeping customer charges low for these smaller sales classes. 8 Company witness Gregory Bollom addresses in detail the Company's position on increased 9 customer charges in his initial and rebuttal testimonies. 10 Q. Does the Company have comments on Ms. Fabrizius' direct testimony? 11 A. Yes. The Company's comments regarding Ms. Fabrizius' direct testimony fall into two 12 categories. First, MGE wishes to clarify certain statements made by Ms. Fabrizius. Second, 13 the Company wishes to respond to the summary of recommendations made by Ms. Fabrizius. 14 Q. What statements made by Fabrizius do you wish to clarify? 15 A. On pages 4 and 5 of her testimony, Ms. Fabrizius initially states that NGV services do not fall 16 within the scope oftraditional services offered by utilities. Yet, on page 5 ofhertestimony, 17 Ms. Fabrizius acknowledges that some states allow rate base cost recovery for NGV services. 18 These states include North Carolina, Georgia, Utah, Oklahoma, New Jersey, Indiana, 19 Pennsylvania, and New York. Indeed, not only do other state utility commissions allow utility 20 participation in the development of the CNG market, some encourage such participation as a 21 means of facilitating or fostering CNG market development. 22 Ms. Fabrizius also testifies that some states, such as California, explicitly prohibit 23 including CNG infrastructure costs in rate base unless the facility primarily serves the utility's 24 own fleet. There are no explicit prohibitions on the inclusion of CNG infrastructure costs in 25 public utility rate base in California's laws or regulations. Indeed, as Ms. Fabrizius notes on Rebuttal-MGE-Minor-5 page 7 of her testimony, utility compression service is currently being considered in Southern 2 California Gas Company's rate case in California. This proceeding is not yet completed. 3 Q. Does the Company have comments on Ms. Fabrizius' concern with the Company's 4 proposed FS-3 demand credits? 5 A. Yes. Ms. Fabrizius asserts that the Company's FS-3 demand credit includes a credit to both its 6 annual and seasonal demand rate components, while We Energies and Wisconsin Gas 7 Company only provide credit on the seasonal demand component. The credits provided by 8 MGE, We Energies and Wisconsin Gas Company are similar. MGE has a rate design that 9 recovers its peak demand cost obligation using two separate rate components: an annual 10 demand rate component, which is applied to firm sales customers throughout the entire year, 11 and a seasonal demand rate component, which is only applied in the Company's defined 12 heating season (November through March). We Energies and Wisconsin Gas Company have 13 similar rate designs but have elected to recover their seasonal demand rate component over a 14 six-month period (November through April). In addition, each rate component can be 15 comprised of different pipeline costs obligations, depending on each utility's Commission 16 approved cost recovery practice. A comparison between what would have been MGE's 17 average annual and seasonal demand credits and the actual demand credits for We Energies 18 and Wisconsin Gas Company during calendar years 2009 through 2011 reveals that the 19 differences in the average credit amounts are minimal. It is not the Company's intention to 20 offer a credit larger than the credit approved for We Energies and Wisconsin Gas Company. 21 Rather, MGE proposes to provide a similar credit, but calculated on the basis of the annual 22 and seasonal rate components in its credit mechanism. 23 Q. Does the Company have any comments related to Ms. Fabrizius' summary of 24 recommendations? Rebuttai-MGE-Minor-6 A. Yes. On page 9 of her testimony, Ms. Fabrizius opposes the Company restricting NGV 2 subscribers to FS-3 gas supply. The Company is open to expanding the gas supply options 3 available to customers subscribing to the Company's proposed NGV tariff to include DBS-1 or 4 third-party gas supply. Assuming the NGV distribution pilot tariff is approved in this docket 5 and the Commission directs the addition of DBS-1 as a gas supply option for NGV customers, 6 it can be included as part of the Company's compliance filing in this docket. 7 Q. Does the Company have any comments concerning Ms. Fabrizius' recommendation that 8 MGE provide NGV distribution service only through a company affiliate? 9 A. Yes. For the reasons I have previously described, the Company believes that NGV as 10 proposed can be included within utility operations and that this is a reasonable way to 11 encourage the growth of the NGV market. As the market develops, the Company believes that 12 a number of options can be explored for continued development of compressed natural gas 13 servtce. 14 Q. Does this conclude your rebuttal testimony? 15 A. Yes, it does. Rebuttal-MGE-Minor-7 PSC REF#:l71792 BEFORE THE PUBLIC SERVICE COMMISSION OF WISCONSIN Application of Madison Gas and Electric ) Company for Authority to Change ) Docket No. 3270-UR-118 Electric and Natural Gas Rates ) REBUTTAL TESTIMONY OF JONATHAN WALLACH ON BEHALF OF THE CITIZENS UTILITY BOARD OF WISCONSIN September 10, 2012 I. Introduction and Summary 2 Q: Please state your name, occupation, and business address. 3 A: My name is Jonathan F. Wallach. I am Vice President of Resource Insight, Inc., 4 5 Water Street, Arlington, Massachusetts. 5 Q: Are you the same Jonathan Wallach that filed direct testimony in this 6 proceeding? 7 A: Yes. 8 Q: On whose behalf are you testifying? 9 A: I am testifying on behalf of CUB. 10 Q: What is the purpose of your rebuttal testimony? 11 A: This rebuttal testimony addresses the following issues raised in direct testimony 12 filed in this proceeding: Rebuttal-CUB-Wallach- I • Adjustments to the Company's production cost allocators with respect 2 to the treatment of interruptible load, as proposed by Commission staff 3 member Corey S. Singletary. 4 • Allocation of demand-related production plant costs on the basis of each 5 customer class's contribution to system peak (1CP), as proposed by 6 Kenneth Lyons on behalf of Airgas Merchant Gases (Airgas). 7 • Redesign of the UW Sp-3 rate, as proposed by Robert R. Stephens on 8 behalf of the University of Wisconsin (UW). 9 Q: Please summarize your findings and conclusions. 10 A: Commission staff's primary proposal to allocate demand-related production 11 costs to Cp-1 interruptible load and to explicitly credit Airgas for the value of 12 that interruptible load is reasonable. However, Commission staff's secondary 13 proposal to not allocate certain demand-related production costs to Cg-2, -4, and 14 -6 interruptible load would inappropriately double-credit those classes for the 15 value of their interruptible load. Commission staff's "Location" COSS, as 16 modified to eliminate the inappropriate treatment of Cg interruptible load, 17 would therefore be a reasonable basis for establishing residential rates. 18 Considering that the Location COSS likely over-allocates demand-related 19 production costs to the residential class, the results of that study would appear to 20 support a residential rate increase of no more than 3.9%. 21 Airgas lacks a reasonable basis for its proposal to allocate demand-related 22 production plant costs using a 1CP allocator. Airgas is incorrect when it asserts 23 that investments in reserve capacity are driven solely by coincident peak load. In 24 fact, peak demands in other months are likely to contribute to annual loss of 25 load probability and thus the need for additional reserve capacity. The Company 26 should therefore continue to allocate demand-related production plant costs on Rebuttal-CUB-Wallach-2 the basis of each customer class's contribution to the average of the twelve 2 monthly peaks (12CP). 3 The University of Wisconsin's proposed redesign ofthe Sp-3 rate appears 4 to be a rehash of its proposal in Docket No. 3270-UR-117. As with the prior 5 proposal, the University's proposal for nominating and pricing standby demand 6 would allow UW to lean on the Company's system for standby capacity without 7 paying the full cost for that capacity. It would not be reasonable for other 8 ratepayers to have to compensate MGE for the revenue losses associated with 9 the University paying less than the full cost of standby capacity. Given these 10 recurring problems, MGE and UW should continue to pursue a negotiated 11 resolution of this issue. Until then, the current Sp-3 rate design should not be 12 modified. 13 II. Staff Adjustments to Production Plant Cost Allocators 14 Q: Please describe the 2013 test year rate increase and residential revenue 15 allocation proposed by Commission staff. 16 A: Commission staff proposes that electric rates be increased on average by 3.4% 17 in order to recover an expected revenue deficiency of $13.1 million in the 2013 18 test year. Of the total $13.1 million proposed revenue increase, Commission 19 staff proposes to allocate $5.3 million to residential customers. 1 This amount 20 represents a 4.2% increase over residential revenues under current rates. 21 Q: What is the basis for the proposed residential rate increase? 22 A: According to Mr. Singletary, the proposed residential rate increase was derived 23 based on modified versions of the Company's three cost of service studies 1 Ex.-PSC-Singletary-1, Schedule No.2, p. 1 (PSC REF#: 170858). Rebuttal-CUB-Wallach-3 ("Standard" COSS, "Time-of-Day" COSS, and "Location" COSS). Specifically, 2 Commission staff ran these three studies using staff's forecast of sales and 3 revenue requirements for the 2013 test year and with modified demand 4 allocators for: (1) production plant costs; (2) production O&M and labor costs 5 for other power generation; and (3) purchased power capacity costs. 2 6 Q: Why does Commission staff recommend modifications to these three 7 demand allocators? 8 A: According to Mr. Singletary, Commission staff is recommending these 9 modifications in order to address an inconsistency in the valuation of 10 interruptible load for different rate classes. For the Cg-2, -4, and -6 rate classes, 11 the value of interruptible load is determined explicitly through the provision of 12 Interruptible Service (IS) rider credits for such interruptible load. In contrast, 13 the value of Cp-1 interruptible load is determined implicitly through application 14 of the Company's production cost allocators. Specifically, the Company's 15 allocators do not allocate any demand-related costs to Cp-1 interruptible load. 3 16 As a result, Cp-1 interruptible load is implicitly valued at the amount of 17 demand-related production costs that would have been allocated to an equivalent 18 level of firm load. 19 In order to rectify this inconsistency, Commission staff recommends the 20 following modifications: 2 Commission staff also modified the allocators applied to Account 507 (Rents) costs in the Time-of-Day and Location studies to correct for the fact that these production plant-related costs were not being allocated consistently with the allocation of production plant costs. 3 In contrast, the Company does allocate energy-related production costs to Cp-1 interruptible load. Rebuttal-CUB-Wallach-4 • Allocate demand-related production plant costs to the Cp-1 class on the 2 basis ofthe class's 12CP interruptible load. 3 • Impute a credit of $4/kW-month to the Cp-1 class for the Cp-1 4 interruptible load. 5 • Exclude Cg-2, -4, and -6 interruptible load from the determination of the 6 demand allocators for production O&M and labor costs for other power 7 generation and for purchased power capacity costs. 4 8 • Allocate all interruptible credit costs, whether explicit IS rider costs or 9 imputed Cp-1 credit costs, on the basis of 12CP load net of interruptible 10 load. 11 Q: Is Commission staff's proposal reasonable? 12 A: Commission staff's primary proposal to explicitly determine the value of Cp-1 13 interruptible load is reasonable. As with the IS rider credits, it would be 14 appropriate and consistent with good regulatory practice to explicitly determine 15 the value of the planning reserves avoided by Cp-1 interruptible load, and to 16 subject that determination to regulatory review. Accordingly, for the purposes of 17 allocating the revenue deficiency in this proceeding, it would be reasonable to 18 allocate demand-related production costs to the Cp-1 class and to impute an 19 explicit credit for Cp-1 interruptible load. 20 However, it would not be appropriate to exclude Cg-2, -4, and -6 21 interruptible load from the determination of the demand allocator for production 22 O&M and labor costs for other power generation or the demand allocator for 23 purchased power capacity costs. Commission staff's proposal in this regard 24 would inappropriately double-credit the Cg-2, -4, and -6 classes for the value of 4 In other words, such demand-related costs would be allocated to the Cg-2, -4, and -6 classes solely on the basis of their firm loads, rather than on firm plus interruptible loads. Rebuttal-CUB-Wallach-5 their interruptible load, implicitly by not allocating these demand-related costs 2 to interruptible load and then explicitly through IS rider credits which reflect the 3 value of avoiding such demand-related costs. 4 It would also not be appropriate to allocate imputed Cp-1 credit costs to 5 other customer classes on the basis of each class's 12CP load net of interruptible 6 load (rather than on gross 12CP). Commission staff's proposal would 7 inappropriately double-credit the Cg-2, -4, and -6 rate classes for the value of 8 their interruptible load, directly through the provision of IS rider credits 9 attributable to those classes' interruptible load and then indirectly by not 1o allocating any of the costs of imputed Cp-1 credits to those classes' interruptible 11 load. 12 Q: Would it be reasonable to set residential rates on the basis of the 13 Commission staff cost of service studies? 14 A: Commission staff's Location COSS, as modified to eliminate the double- IS crediting of Cg interruptible load, would be a reasonable basis for establishing 16 residential rates. As I discussed in my direct testimony, ofthe three studies, the 17 Location COSS allocates costs in a fashion that most reasonably reflects each 18 class's responsibility for such costs. In contrast, the Standard COSS appears to 19 allocate more production and distribution plant costs to the residential class than 20 is appropriate, while the Time-of-Day COSS appears to overstate the 21 appropriate residential allocation of distribution plant costs. 22 Relying on the COSS spreadsheet model provided in Commission staff's 23 response to Interrogatory No. 0 1-Airgas-0 1, I have modified the Location COS S 24 to eliminate the Commission staff adjustments that give rise to the double- 25 crediting of Cg interruptible load. This modified Location COSS allocates $6.4 26 million of the total $13.1 million revenue deficiency to the General Services Rebuttal-CUB-Wallach-6 classes. This amount represents a 4.1% increase over General Services revenues 2 under current rates. 3 Q: Do you have any concerns about the Location COSS? 4 A: As I discussed in my direct testimony, I am concerned that the generic 60%/40% 5 demand/energy split used to classify production plant costs may overstate the 6 actual proportion of demand to energy-related investments in the Company's 7 production plant. If so, the Location COSS over-allocates production plant costs 8 to the General Services classes. 9 For example, in Docket No. 05-UR-106, I derived a 43%/57% 10 demand/energy split for Wisconsin Electric Power Company's production plant 11 costs. 5 And in Docket No. 4220-UR-117, I derived a 30%/70% demand/energy 12 split for Northern States Power Company's production plant costs. 6 Using a 13 40%/60% demand/energy split for MGE would reduce the General Services rate 14 increase from 4.1% to 3.8%. 15 Q: What do you conclude from these results? 16 A: Considering that the Location COSS likely over-allocates demand-related 17 production costs to the residential class, the results ofthe corrected Commission 18 staff's Location study would appear to support a residential rate increase of no 19 more than 3.9%. 5 Docket No. 05-UR-106, Direct-CUB-Wallach-7, ll. 13-15 (PSC REF#: 171702). 6 Docket No. 4220-UR-117, Direct Testimony of Jonathan Wallach, p. D2.33, ll. 12-13 (PSC REF#: 154438). Rebuttal-CUB-Wallach-7 III. The lCP Demand Allocator 2 Q: What does Mr. Lyons recommend with regard to the allocation of demand- 3 related production plant costs? 4 A: Mr. Lyons recommends that demand-related production plant costs be allocated 5 using a 1CP allocator, rather than the 12CP allocator that MGE has traditionally 6 used. 7 Q: Why does Mr. Lyons argue for using the 1 CP allocator? 8 A: Mr. Lyons appears to believe that the Company's investments in reserve 9 capacity are driven solely by system coincident peak, and therefore that such 10 investments should be allocated on the basis of each customer class's 11 contribution to that single peak. According to Mr. Lyons: 12 MGE must have generation to meet customer use at the period of greatest 13 need (the system peak) and ... that need currently is for a very short period 14 of time. MGE plans for this peak and knows that it will peak for a brief 15 period of time. We cannot believe that MGE looks to a non-peak month 16 like March to determine whether it needs to build additional capacity, when 17 its peak in June (652 mWs) is already more than 200 mWs greater than its 18 peak in March (418 mWs).7 19 What we know is that MGE has acquired sufficient capacity to meet the 20 system peak. But by allocating the cost of that capacity to its customer 21 classes using the 12CP methodology, M GE[' s] allocation is not reasonable 22 because it does not assign appropriate costs to those customers who are 23 driving the need for that generation that is needed for only a few hours 24 every year. 8 25 Q: Are investments in reserve capacity driven solely by coincident peak 26 demand, as alleged by Mr. Lyons? 7 Direct-Airgas-Lyons-8, ll. 15-21 (PSC REF#: 170887). 8 Direct-Airgas-Lyons-! 0, ll. 18-22. Rebuttal-CUB-Wallach-8 A: No. Although planning reserve requirements are typically stated in terms of a 2 margin over system coincident peak, such requirements are determined by the 3 margin of available capacity over demand throughout the year. Specifically, 4 utilities typically plan to maintain sufficient capacity in reserve so that the 5 annual loss of load probability (LOLP) does not exceed one day in ten years. 6 Peak demands throughout the year may contribute to annual LOLP and thus 7 system reserve requirements. For example, the scheduling of plant maintenance 8 during low-demand shoulder months may reduce capacity margins during peak 9 periods in those shoulder months and thus increase annual LOLP and reserve 10 requirements. If so, peak demands in these shoulder months would also 11 contribute to the need for investments in reserve capacity. 12 Q: Does the fact that MGE dispatches reserve capacity infrequently indicate 13 that the need for such capacity is driven solely by system peak? 14 A: No. We would expect such capacity to be dispatched infrequently, if at all, since 15 it is by definition excess capacity, i.e., capacity in excess of expected coincident 16 peak demand. Its purpose is not to serve expected demand, but to be held in 17 reserve in the event that demand is higher than expected or available capacity is 18 less than expected. 19 Q: Should the Commission adoptAirgas' proposal to rely on the lCP allocator 20 for allocating demand-related production plant costs? 21 A: No. Airgas lacks a reasonable basis for its proposal to allocate demand-related 22 production plant costs using a 1CP allocator. The Company should therefore 23 continue to allocate demand-related production plant costs on the basis of each 24 customer class's contribution to the average of the twelve monthly peaks. Rebuttal-CUB-Wallach-9 IV. Sp-3 Rate Design 2 Q: Please describe the University of Wisconsin's proposal for reformulating 3 Rate Schedule Sp-3. 4 A: According to Mr. Stephens, the University proposes to restructure the current 5 generation credit applied to Charter Street Heating Plant (CSHP) generation into 6 a charge for standby service to back up CSHP capacity. 7 Under the current tariff, the Company assesses the Sp-3 demand charge for 8 electricity service on a gross dell?-and (i.e., metered demand plus CSHP 9 generation) basis. The Company then applies a generation credit based on 10 nominated CSHP generation. 11 Under the tariff proposed by the University, the Company would instead 12 assess the Sp-3 demand charge for electricity service on a net demand basis (i.e., 13 metered load) and, in addition, assess a standby charge based on CSHP 14 generation. 15 Q: Has the University proposed this reformulation in prior rate cases? 16 A: Yes. The University offered a similar redesign in Docket No. 3270-UR-117. 17 Q: Would the University's proposal fully compensate MGE for the cost of 18 standby capacity required to back up CSHP generation? 19 A: No. The University proposes to pay standby demand charges not for the full 20 amount of capacity that must stand ready to back up CSHP, but only for the 21 amount of standby capacity that is actually required in each hour to cover the 22 shortfall in hourly output from CSHP. In essence, the University apparently 23 proposes to pay for capacity-reservation service as if it were replacement-energy 24 service, paying only for that portion of the capacity standing in reserve to back 25 up CSHP that it actually relies on to firm up CSHP generation. Rebuttal-CUB-Wallach-1 0 Q: How might residential ratepayers be affected by the University's proposal 2 for standby service? 3 A: The Company would incur a revenue shortfall to the extent that the University 4 avoids paying the full cost of standby capacity. Residential ratepayers would be 5 adversely affected to the extent that they are required to compensate MGE for 6 these revenue losses. 7 Q: What do you recommend with regard to the University's proposed redesign 8 of the Sp-3 rate structure? 9 A: Given the potential adverse impact on other customer classes, the Commission 10 should reject the University's proposal at this time. Instead, the Commission 11 should direct MGE and UW to continue discussions on this issue and to provide 12 regular reports to the Commission regarding the course of those discussions. 13 Q: Does this conclude your rebuttal testimony? 14 A: Yes. Rebuttal-CUB-Wallach-11 PSC REF#:l71795 BEFORE THE PUBLIC SERVICE COMMISSION OF WISCONSIN Application of Madison Gas and Electric Company for Authority to Change Electric Docket No. 3270-UR-118 and Natural Gas Rates REBUTTAL TESTIMONY OF KENNETH LYONS ON BEHALF OF AIRGAS MERCHANT GASES Q: Please state your name. 2 A: My name is Kenneth Lyons. 3 Q: Have you previously presented testimony in the above-captioned proceeding? 4 A: Yes, I presented Direct Testimony on behalf of Airgas Merchant Gases ("Airgas"). 5 Q: What is the purpose of your Rebuttal Testimony? 6 A: I address the Direct Testimony of Commission Staff witness Mr. Corey Singletary with 7 respect to his COSS methodology, his mistaken allocation of production plant costs to 8 Cp-1 customers, and the deviation he makes from his own COSS when he allocates the 9 revenue requirement to certain customer classes. On this last point, Mr. Singletary's 10 allocation of revenue requirement to the Cg-5 and Cg-3 customer classes, in particular, 11 reflect the results of my proposed 1CP COSS methodology, and not his own COSS 12 methodologies. I also address Citizen Utility Board witness Mr. Jonathan Wallach's 13 testimony with respect to the Time-of-Use and Location studies, both of which I disagree 14 with. Rebuttal-Airgas-Lyons-1 1 Q: Have you reviewed the COSS prepared by Mr. Singletary? 2 A: Yes I have. Mr. Singletary's COSS differ from the ones that I prepared in a number of 3 ways, but the two most significant differences, which I disagree with and discuss here, 4 are these: first, the way in which he chose to determine customer class responsibility for 5 MGE's need to build capacity to meet its peak load obligation; and, second, the way in 6 which he chose to allocate capacity cost to load that did not cause MGE to incur capacity 7 cost. 8 Q: In what way do you disagree with Mr. Singletary's allocation of capacity costs to 9 customer classes? 10 A: Given the Commission's acknowledgement in the most recent Strategic Energy 11 Assessment that ratepayers' future bills can be greatly reduced if the extraordinary costs 12 of electric power plants can be avoided or delayed, I would have expected that at least 13 one of Mr. Singletary's COSS would have provided a focused view on this most 14 significant cost driver of capacity, and that he would have offered rate design proposals 15 that would work to avoid investments in capacity that are used for only a few hours every 16 year. The meaningful question that all parties should be focusing on is what processes 17 are in place to minimize the exposure to capacity that is rarely or never used. As I 18 explained in my Direct Testimony, the 12CP approach to allocating production plant for 19 the MGE System does not offer a reasonable view of whose demand has driven MGE's 20 need for capacity, and it certainly fails to minimize all customers' exposure to costly 21 production plant. The 1CP approach I recommended to the Commission in my Direct 22 Testimony provides a much more reasonable method by which to assign costs according Rebuttal-Airgas-Lyons-2 to customer groups' respective responsibilities for MGE's need to have capacity to serve 2 their needs. 3 Q: Have you been able to determine how Mr. Singletary's COSS results would change 4 if he had allocated capacity using the lCP methodology? 5 A: Yes. In response to the 01-Airgas-01 data request, Mr. Singletary provided an excel 6 version of his COSS model. (PSC Ref. #171434). I was able to easily adjust his 7 production plant allocators to reflect a 1CP methodology, replacing his 12CP 8 methodology. My Ex.-Airgas-Lyons-5 compares the results of Mr. Singletary's 9 Standard, TOU and Location COSS using 12CP (which are the results he filed) with 10 these same COSS using 1CP. In all other respects, the COSS compared on this exhibit 11 are identical. I also provide in my Ex.-Airgas-Lyons-6 the relationship between each 12 customer class's annual 12-month average peak (the 12CP method) and each customer 13 class's annual peak (the 1CP method). 14 The results shown on Ex.-Airgas-Lyons-5 may surprise some people. First, the 15 allocation to the residential class is less using 1CP than it is using12CP. While this may 16 be the opposite of what many people would instinctively believe, the evidence is clear 17 that MGE's residential class customers actually have a less peaky load than some other 18 MGE classes. Should 12CP be used in place of 1CP, residential customers will be 19 allocated more than their share and they then will be called upon to subsidize certain 20 other customer classes. 21 Second, the results show (as did my own COSS results) that the Cg-5 and Cg-3 22 customer classes are the greatest beneficiaries of the 12CP methodology, as they are 23 allocated substantially less production plant costs than that to which they so clearly Rebuttal-Airgas-Lyons-3 contribute. These two customer classes contribute the peakiest load to the MGE system, 2 and the generation that they cause MGE to build to serve their needs at MGE's system 3 peak is that very production plant that then sits idle for so much of the year. As shown on 4 my Ex.-Airgas-Lyons-6, the Cg-5 class's annual peak is 203 percent greater than its 5 average monthly peak; the Cg-3 class's annual peak is 197 percent greater than its 6 average monthly peak. Because the 12CP methodology that Mr. Singletary employs uses 7 the average monthly peak, these two rate classes are allocated in his COSS only one-half 8 of their actual contribution to MGE's production plant. 9 The differences in results for the remainder of the classes are important, but not so 10 dramatic as they are for Cg-5 and Cg-3. Importantly, these results show with this one 11 change to reflect a customer classes' responsibility to the system peak, the Cp-1 class 12 should receive a decrease in rates in 2013. Mr. Singletary's COSS results, with this one 13 change only (and still including the other differences between his COSS, Mr. James' 14 COSS, and my own COSS), results in a rate decrease under Standard (-3.70%), and well 15 below average increases under TOU (1.05%) and Location (1.22%) for the Cp-1 class. 16 Thus, if the Commission was to accept all of the changes Mr. Singletary made to his 17 COSS, but agreed that the production plant should be allocated to account for the class 18 contribution to the system peak, relying only the results of Mr. Singletary's COSS, it 19 could reasonably authorize a rate decrease for the Cp-1 class. Of course, the results of 20 Mr. James' COSS and my own COSS present even stronger evidence that a rate decrease 21 for Cp-1 is appropriate. Rebuttal-Airgas-Lyons-4 1 Q: Does Mr. Singletary allocate any utility costs based on a single month value as you 2 suggest he should for production plant? 3 A: Yes he does. As does Mr. James of MGE, Mr. Singletary allocates a significant portion 4 of distribution plant and distribution operation and maintenance expense ("O&M") using 5 the customer class's annual peak. His use of the class annual peak for these costs 6 suggests to me that he believes it reasonable that these costs should not be based on the 7 customer group's average peak use throughout the year. It does not seem reasonable that 8 he accepts the single peak for these certain distribution costs, but then (despite submitting 9 two of his three COSS with the exact same allocation of production) makes no effort to 10 even provide the Commission with results that show the allocation of production plant 11 (which costs the Commission recognizes as enormous) under a similar single month 12 method. 13 Q: Is there a benefit to using lCP to allocate production plant beyond simply 14 identifying customer class responsibility? 15 A. Yes, certainly. Using the appropriate methodology serves at least two purposes. It first 16 identifies customer class responsibility. But equally as important is the opportunity that it 17 presents to provide appropriate price signals to all customer classes. If production plant 18 costs are allocated according to the results of the 1CP methodology, customers who give 19 any consideration to their cost of electricity will see how their usage affects their bills. In 20 this case in particular it will tell certain customers who contribute significantly to the 21 system peak that their current behavior is expensive to serve and that they could, if they 22 wished, modify their usage patterns to reduce their costs and improve system efficiency. 23 On the other hand, the 12CP methodology calmly speaks to these same customers and Rebuttal-Airgas-Lyons-5 1 suggests that they can increase demand at peak hours and not pay their respective share 2 for that additional, very temporary, load. If the Commission is interested in reducing 3 long-term utility costs, the Commission staff should, at a minimum, provide information 4 (in the form of COSS) that would support an allocation that can result in long-term 5 savings. With respect to production plant costs, the 1CP offers just that type of 6 information. 7 I believe it very unlikely that investment in production plant can be delayed by 8 shifting cost way from those customer classes that have very peaky loads to those who 9 have flat loads. This is because those with the peaky loads currently do not know the 10 extraordinary cost they cause the system overall. It is unlikely that hiding this 11 information from peak-use customers, as is the case under a 12CP methodology, will 12 show them that investment in conservation and efficiency-particularly at peak periods- 13 is economically good for them. Some might think it strange that the current system 14 collects money from all customers to give to selected customers to become more 15 efficient, while at the same time it is taking money from more efficient users so that less 16 efficient users can be subsidized to continue the less efficient behaviors. 17 Q: You noted that you had two disagreements with Mr. Singletary's COSS 18 methodology. Can you describe the second disagreement? 19 A: Yes. What I described above relates to a single change to his COSS-that dealing with 20 the allocation of production plant. Corrected to reflect the 1CP methodology, the results 21 support a decrease to the Cp-1 class and the results for all customer classes appear on 22 Ex.-Airgas-Lyons-5. But I also disagree with the manner in which Mr. Singletary 23 allocates capacity costs to the Cp-1 class. Rebuttal-Airgas-Lyons-6 Mr. Singletary has chosen to fully allocate capacity costs to loads for which MGE 2 was not required to build capacity and for which it in fact did not build capacity. He then 3 uses a credit to offset only a portion of the costs that he assigned the class. The premise 4 of his position is this: even though MGE has no obligation to build capacity to meet the 5 Cp-1 class load, the COSS should assume that there was just such an obligation. Then, 6 after fully assigning these costs, he creates a credit that he argues is equal to the value the 7 Cp-1 class offers the MGE system as an interruptible credit. 8 The problem with the first step-the allocation of capacity costs to the Cp-1 9 class-is this: Mr. Singletary assumes (incorrectly) that MGE has built capacity for 10 MGE, when MGE in fact has not. This assumption is misplaced for several reasons. 11 First, there is no evidence that MGE purchased capacity for Cp-1 customers. Second, the 12 Cp-1 tariff expressly provides that to qualify for the tariff the customer must sign an 13 initial 15-year contract to remain interruptible and, after the initial 15-year term, give 14 MGE at least 5 years notice before it can move to firm service. The purpose of these 15 restrictions on Cp-1 customers was to provide MGE (and all of its customers) certainty 16 that it would not need to build capacity for the Cp-1 customers load for at least 15 years. 17 And then, following the 15 years, the customer must give MGE five years in which to 18 provide capacity if the customer wished to return to firm service. Third, MGE has 19 confirmed that MGE has utilized the Cp-1 load as a MISO Load Modifying Resource 20 Demand Response. (MGE Response to 02-Airgas-07; PSC Ref.#: 170057). MGE is 21 allowed to, and in fact has, removed the Cp-1 load from its MISO capacity obligations. 22 If Mr. Singletary had believed that MGE had an obligation to build capacity to serve Cp- 23 1 load-and that it did so-he should be questioning why MGE would act so imprudently Rebuttal-Airgas-Lyons-7 as to incur costs without any corresponding need. Of course, we know that on this point 2 MGE has been prudent because it has not, in fact, acquired capacity to serve the Cp-1 3 load. In short, MGE has no current obligation to provide Cp-1 customers with capacity. 4 It has not built capacity to serve those customers. Mr. Singletary's allocation process 5 ignores these facts and nevertheless allocates non-existent costs to the Cp-1 class. 6 Q: Please continue. 7 The inclusion of non-existent capacity in the COSS also creates a fiction with respect to 8 the allocation of costs to other customers. By assuming that the Cp-1 class is firm load, 9 the COSS includes a total load that is larger than true. Indeed, if MGE had acquired 10 additional capacity to serve the Cp-1 load as firm, the remaining customer would have 11 been allocated the same capacity as I allocated to them in my COSS and the capacity 12 acquired to serve a firm Cp-1 load would be allocated to Cp-1 (if the allocation was done 13 properly). So in essence, his process of pretending the load is firm and then crediting the 14 load a portion of the pretend number is a shell game to transfer cost from customers who 15 caused MGE to build capacity to customers that did not cause those costs. 16 Q: Do you have other concerns with Mr. Singletary's approach? 17 A. Yes. Even assuming that his first step-allocating capacity costs to Cp-1 despite the 18 overwhelming evidence that no such costs have been incurred-was reasonable, his 19 second step is wrong because it fails to fairly value the benefit that the Cp-1 class would 20 have to MGE system under his first assumption. In this second step-the creation of an 21 offsetting interruptible credit- Mr. Singletary chose $4.00 per kW. (Direct-PSC 22 Singletary-8) (PSC Ref. #171243). Although he did not explain in his Direct Testimony Rebuttal-Airgas-Lyons-8 why he believed that $4.00 per kW was appropriate, his response to Airgas discovery 2 (PSC Ref.#: 171433) reveals that he simply adopted the $4.00 per kW credit that the 3 Commission authorized for customers under MGE's Is-2 rider, which I provide in my 4 Ex.-Airgas-Lyons-7, Schedule 1. 5 Q: Do you agree with Mr. Singletary's adoption of the Is-2 credit in his calculation? 6 A. No. Again, I don't agree with his first assumption that the Cp-1 customers caused MGE 7 to incur capacity costs. But even if that was the case, the Is-2 credit that he adopts is not 8 appropriate because the terms for service under Is-2 differ substantially from the terms 9 for service under the Cp-1 tariff. The Cp-1 customers offer the MGE system 10 substantially more value than do the ls-2 customers. A copy of the ls-2 tariff and the Cp- 11 1 tariff can be found in my Ex.-Airgas-Lyons-7, Schedules 2 and 3, respectively. 12 Q: In what ways does the Cp-1 tariff customer provide greater value to MGE than the 13 Is-2 customer? 14 A. First, the Cp-1 tariff requires the customer to have a minimum interruptible demand in 15 excess of 10,000 kW (in contrast to the Is-2 customer minimum demand of only 75 kW). 16 The very large block of power that this load provides MGE to meet emergencies is much 17 more meaningful, and of unquestionably greater value, than is a load of only 75 kW. 18 Second, the Cp-1 tariff requires that the customer's load be utilized 90% of the 19 time. The Is-2 tariff has no such requirement. This requirement of the Cp-1 customer 20 provides substantial benefits to the MGE system in that it uses system resources during 21 system low load hours (i.e., it gives efficiency to the system), maintains a very high 22 consistency in energy sales during both high and low price hours, and is available for 23 interruption when needed. That is, this high load factor (which Is-2 customers need not Rebuttal-Airgas-L yons-9 maintain) provides MGE a high degree of assurance that when it does need to shed load 2 for an emergency, there will be a lot of load to shed. And from a system operator's 3 standpoint, the high load factor provides assurance that at system minimum operating 4 levels, there will be a consistent load (the Cp-1 customer) to help balance the system and 5 deal with the low load operating complications. 6 Third, and most importantly, the Cp-1 tariff requires a much lengthier contract 7 period than does the Is-2 tariff, giving MGE much greater certainty that it will not need to 8 build capacity to meet the Cp-1 customer's load. The Cp-1 tariff customer must commit 9 to an initial 15-year term with no opt-out and, subsequently, provide MGE with five-year 10 advance notice to convert to firm power. The Is-2 tariff, in comparison, offers the 11 customer significantly more flexibility in taking firm power (and, as a consequence, 12 provides MGE with less certainty, over a shorter period of time, as to its generation 13 needs). For instance, the Is-2 customer can elect to take service under the contract on a 14 trial basis for up to one year (compare with the Cp-1 customer that must, initially, agree 15 to a 15-year term). The Is-2 customer, after the one-year trial, is then agreeing only to a 16 3-year term (compare with the Cp-1 customer that has an initial 15-year term, and then 5- 17 year terms). The Is-2 customer can reduce its level of interruptible load on an annual 18 basis, by up to 30 percent every three years. The Is-2 customer can completely avoid 19 interruptions for limited periods of time with Short-Term Interruptible Replacement 20 service. The Is-2 customer is charged a reduced penalty the first time it fails to curtail its 21 load (the Cp-1 customer has no free pass). The Is-2 customer is charged $25 per kW for 22 unauthorized use of electricity (the Cp-1 customer is charged $35 per kW). Rebuttal-Airgas-Lyons-1 0 In short, the value that those on the Is-2 rate bring to the MGE system cannot 2 fairly be compared with the much more significant value that Cp-1 brings to the MGE 3 system. The Commission should not accept Mr. Singletary's approach as it relates to his 4 allocation of production plant to the Cp-1 class because neither of the two steps he takes 5 has a factual basis. 6 Q: Do you have any comments on the direct testimony of CUB witness Jonathan 7 Wallach? 8 A: Yes I do. At Direct-CUB-Wallach-6lines 13-17, Mr. Wallach gives the false impression 9 that certain customers (such as the Cp-1 class of customers) are receiving a benefit from 10 owned generation because the owned generation is being used to reduce energy costs at II some times during the year. I disagree with the suggestion that to the extent there is such 12 a benefit, that it is one realized by the Cp-1 class. As shown on Ex.-Airgas-Lyons-3, the 13 highest cost that MGE could reasonably incur to serve the Cp-1 load in the test year 14 ($2,538,505) is $777,946 lower than the fuel and purchased power cost that is allocated 15 to the Cp-1 class. 16 I also disagree that either Time of Use or Location Studies are reasonable, 17 particularly in the way in which production plant is allocated in the COSS. If the 18 Commission should accept as reasonable either the TOU or Location study-which work 19 to assign production plant on the basis of both demand and energy-then it is particularly 20 appropriate to allocate the demand portion on 1CP as I have suggested in my testimony. 21 As noted above, Mr. Singletary's COSS, with the single change of 12CP to 1CP, results 22 in an increase of around I percent for the Cp-1 class. The 4CP methodology also Rebuttal-Airgas-Lyons-11 supports an increase for the Cp-1 customer that is less than the system average. Ex. 2 Airgas-Lyons-5, page 3 of 3. 3 Q: Do you agree with Mr. Singletary's revenue allocation? 4 A: Only in part. I do agree with his effort to limit increases to any one class so that no class 5 receives an increase greater than 1.25 percentage points above the system average. 6 However, I disagree with his starting point in allocating the revenue requirement because 7 that starting point is based on his use ofthe 12CP method. And, as I've discussed, this 8 method for allocating production plant hides the impact certain customer groups have on 9 MGE's need to build capacity. But even assuming that his COSS results were correct, 10 his allocation raises significant questions. 11 A particularly revealing allocation involves the Cg-5 class. As my COSS using a 12 I CP allocation showed (and as presented on my Ex.-Airgas-Lyons-2), the Cg-5 13 customers should receive an increase of 5.3 percent. In each of Mr. Singletary's COSS 14 (as shown on EX.-PSC-Singletary-1 Schedule 1 page 3 of 11 ), results would suggest that 15 the Cg-5 customer group is due a significant decrease-an average of a 12.84% decrease 16 according to Mr. Singletary's results. However, in applying his COSS results to his 17 revenue allocation, Mr. Singletary groups this Cg-5 customers with residential customers. 18 Yet the residential customers have significantly different load patterns and the COSS 19 results are markedly different. Instead of a decrease, the residential classes under Mr. 20 Singletary's COSS support an increase of 8.79%. By joining these disparate groups of 21 customers, Mr. Singletary reduces the responsibility ofthe residential class and 22 substantially increases the responsibility of the Cg-5 customers. That is, despite COSS 23 results showing that a decrease of 12.84% is due these customers, he recommends an Rebuttal-Airgas-Lyons-12 increase of 4.45%, which is 31% more than the system average increase. Additionally 2 his COSS evidence for the rate he grouped with Cg-5 for revenue allocation reflected an 3 increase of2.75 times the system average, but he recommends a lower increase of 4.21 %. 4 It is important that the Commission not misunderstand the point that I am making 5 here. I agree with Mr. Singletary that the Cg-5 customers should get an increase in their 6 rates. However, I reach this conclusion by looking to my COSS results, which show that 7 the Cg-5 customers are significantly more responsible for production plant costs than 8 appears through the results of the 12CP study that Mr. Singletary supports. It is not 9 readily apparent how Mr. Singletary justifies the significant deviation for this one 10 customer group. Perhaps-and it would be a point with which I agree-he understood 11 the load pattern shown in Ex.-Airgas-Lyons-1, Schedule 5, for the Cg-5 class and made a 12 modification to selectively reflect a 1CP allocation for this customer. Perhaps there are 13 other reasons for this, which he did not share. But whatever the reasons that caused him 14 to judgmentally disregard his own COSS evidence, it appears that his conclusion, 15 however arrived at, supports the 1CP methodology relating to cost causation based on 16 single peak use for this most extreme example of a user of peak only load. It is 17 unreasonable that he provides no evidence on a 1CP allocation, but makes selective 18 adjustments to achieve allocations more reflective of 1CP allocation for only limited 19 customers. The Commission should accept my revenue allocation as adjusted for Staff 20 adjustments as it more accurately reflects the cost causation Mr. Singletary attempts to 21 achieve selectively. This allocation is shown on Ex-Airgas-Lyons-8. Rebuttal-Airgas-Lyons-13 Q: Why are the time of use and location results so close for Cp-1? 2 A: As required by MGE and the Commission, the Cp-1 class is required to self provide all 3 facilities below 69,000 kw. MGE provides only a single meter of distribution facilities. 4 Since the TOU and Location are essentially the same for all cost except distribution, the 5 results for the TOU and Location for Cp-1 are essentially the same calculation. For that 6 reason, Mr. Singletary's use of the average of the results of Standard, TOU and Location 7 for the Cp-1 class is not really an average, but the average of two values weighting one 8 value as twice the weight of the other. What make this significant is his average is not an 9 average. It is the value calculated by taking one value for production allocated on the 10 Standard basis and two values for production allocated on the 60% demand and 40% 11 energy basis. In simple terms, this is like a tennis match with single player matched 12 against a doubles team. If the single player is far superior, in tennis we could understand 13 why matching two players against the one could make a fairer match. If Mr. Singletary's 14 purpose was to attempt to offset the greater accuracy of the Standard method, he should 15 just state that, not create an averaging to reflect two players on the 60/40 team. 16 Q: Does this complete your rebuttal testimony? 17 A. Yes, it does. 8419809_5 Rebuttai-Airgas-Lyons-14 PSC REF#:171789 "'g. :<:!::: BEFORE THE ~ Cl t"..m PUBLIC SERVICE COMMISSION OF WISCONSIN HIll <: '1 txJ < t:i ...... Cl 0 ill Application ofMadison Gas and Electric Company 'o"'n for Authority to Change Electric and Natural Gas Docket No. 3270-UR-118 6~ ..... Rates ---I-' til -Ntll...... o 1-' i:l .. 0 REBUTTAL TESTIMONY OF RICK PENA OF ~ ...... :li! CALPINE CORPORATION w ..... N(IJ ~g i:l (IJ..... i:l 1 Q. Please state your name, title, and business address. 2 A. My name is Jesus Ricardo "Rick" Pena, Jr., and I am the Director of Strategic Origination 3 for the North Region of Calpine Corporation ("Calpine"). My business address is 4 717 Texas Avenue, Suite 1000, Houston, Texas 77002. My telephone number is 5 (713) 830-8814. 6 Q. What are your job responsibilities? 7 A. I am responsible for the financial optimization of Calpine owned generation, which 8 includes responsibility for relationship management and business development. As a part 9 of my day-to-day duties, I have knowledge ofthe Power Purchase Agreement between 10 Madison Gas and Electric ("MGE") and Riverside Energy Center, LLC (" Riverside"). 11 Q. Please give a brief description of your background and experience. 12 A. I joined Calpine in June 2007. Prior to joining Calpine Corporation, I was a Manager of 13 Mergers and Acquisitions for Direct Energy, primarily focusing on North American 14 power and gas asset acquisitions. I graduated with a Bachelor of Business 15 Administration from Texas A&M University. Rebuttal-Calpine-Pena-l 1 Q. What is the purpose ofyour rebuttal testimony? 2 A. The purpose of my rebuttal testimony, consistent with Calpine's role in this proceeding as 3 described in the Order on Request to Intervene (PSC Ref#: 169841 ), is to respond to the 4 direct testimony of Mary Neal on behalf of the Citizens Utility Board of Wisconsin (PSC 5 Ref#: 170881 (Neal Direct pp. 2, and 15- 16)). In particular, my testimony rebuts Ms. 6 Neal's characterization of the Power Purchase Agreement ("PPA") between Madison Gas 7 and Electric Company ("MGE") and an affiliate of Calpine entered into on March 5, 8 2001. 9 Q. How was the PPA characterized in those portions of Ms. Neal's testimony? 10 A. In her testimony, Ms. Neal states that MGE has "terminated" the PPA, that MGE "alleges 11 that [it] properly terminated the PPA," and that "MGE is in the process ofterminating a 12 PPA with Calpine for 75MW .... " Based upon these characterizations, Ms. Neal 13 concludes that the cost of the PPA should not be included within MOE's PPA capacity 14 costs in this proceeding. 15 Q. How are these characterizations inaccurate? 16 A. It is not accurate to state MGE has terminated or is in the process of terminating the PPA. 17 Whether MGE has or is able to terminate the PPA currently is the subject of a pending 18 arbitration proceeding and was raised by MGE in a related court action in the Dane 19 County (Wisconsin) Circuit Court. In those proceedings, Calpine asserts that MGE did 20 not terminate the PPA and that any purported termination ofthe PPA by MGE is 21 wrongful. Rebuttal-Calpine-Pena-2 1 Q. Please describe the procedural status of the dispute between Calpine and MGE 2 regarding the PPA. 3 A. On March 23, 2012, MOE commenced a lawsuit against a Riverside Energy Center, 4 LLC, a Calpine affiliate, in Dane County, Wisconsin, seeking, among other things, a 5 declaration that it had terminated the PPA effective on that same date. Calpine moved to 6 dismiss the complaint and initiated an arbitration proceeding--as required by specific 7 terms of the PPA--to resolve issues relating to, among other things, MOE's purported 8 termination ofthe PPA. On August 10, 2012, the court convened a hearing on a Motion 9 for Temporary Injunction that MOE filed to try to enjoin the arbitration proceeding. At 10 the conclusion of that hearing, the court denied MOE's Motion for Temporary Injunction, 11 found that the disputed issue concerning MOE's purported termination ofthe PPA should 12 be determined in the pending arbitration proceeding, and stayed the court action pending 13 the resolution of the arbitration proceeding. The court's ruling was memorialized in an 14 order entered by the court on August 14, 2012, a true and correct copy of which is 15 provided as Ex.-Calpine-Pena-1. 16 Q. As a result of the proceedings in the Dane County action, did the court resolve 17 whether MGE terminated or is able to terminate the PPA? 18 A. No. The court determined that those issues should be resolved in the arbitration 19 proceeding. 20 Q. What is the status of that arbitration proceeding? 21 A. In the arbitration proceeding, the arbitrator will determine a number of issues including 22 whether, as MOE contends, MOE terminated the PPA or whether, as Calpine asserts, 23 MOE did not terminate the PPA. Calpine and MOE currently are participating in Rebuttal-Calpine-Pena-3 discovery in the arbitration proceeding. A hearing in the arbitration proceeding is 2 scheduled to take place on November I4-I6, 20I2. The arbitrator has committed to 3 issuing a final decision in the arbitration proceeding by December I4, 20I2. A true and 4 correct copy of the scheduling order issued by the arbitrator in the arbitration proceeding 5 is provided as Ex.-Calpine-Pena-2. 6 Q. How does the status of the arbitration proceeding affect the accuracy of Ms. Neal's 7 characterization of the status of the PPA? 8 A. Because the issue of the termination of the PPA has not been determined, it is inaccurate 9 to state-- as Ms. Neal does-- that MOE terminated the PPA. Such a statement could be IO made only after the arbitrator issues his final decision and only if that final decision is II favorable to MOE with respect to that issue. 12 Q. Does your rebuttal of Ms. Neal's characterizations of the status of the PPA affect the 13 conclusions drawn by Ms. Neal? I4 A. Yes. Because it has not been determined that MOE terminated the PPA, and given I5 Calpine's position that MOE did not terminate the PPA, there is no basis to exclude the I6 costs ofthe PPA from MOE's PPA capacity costs in the rate case. Consequently, there is I7 no basis to treat the PPA in the present proceeding any differently than how it was treated I8 in MOE's prior rate case proceedings. I9 Q. Does this conclude your prefiled rebuttal testimony? 20 A. Yes, it does. Rebuttal-Calpine-Pena-4 PSC REF#:l71800 Public Service Commission of Wisconsin Rebuttal Testimony of Randy Hillebrand Gas and Energy Division Madison Gas and Electric Company Docket 3270-UR-118 September 10, 2012 1 Q. Please state your name, occupation, and business address. 2 A. My name is Randy Hillebrand. I am employed as an auditor in the Gas and Energy 3 Division ofthe Public Service Commission of Wisconsin (Commission). My business 4 address is 610 North Whitney Way, Madison, Wisconsin. 5 Q. Are you the same Randy Hillebrand who previously filed direct testimony in this 6 proceeding? 7 A. Yes I am. 8 Q. What is the purpose of your rebuttal testimony? 9 A. The purpose of my rebuttal testimony is to respond to the direct testimony of Citizens 10 Utility Board (CUB) witness Mary Neal and to clarify my own direct testimony. 11 Q. Do you have any comments with respect to Ms. Neal's direct testimony? 12 A. Yes I do. On pages nine through twelve of her direct testimony, Ms. Neal expresses her 13 concern that Midwest Independent System Operator, Inc. (MISO) Make Whole Payments 14 (MWP) revenue have not been reflected in Madison Gas and Electric's (MGE) 2013 15 test-year fuel costs. I believe that there is no need to reflect additional revenues for Make 16 Whole Payments. This is because MWP's are associated with the additional costs of the 17 uneconomic dispatch of certain power plants by MISO. In forecasting the dispatch of 18 MGE's plants for purposes of developing a future test year's fuel costs, neither MGE nor 19 Commission staff forecast any uneconomic dispatch of plants, with the exception of the PSC-Rebuttal-Hillebrand-1 West Campus Cogeneration Facility, where the Univert ~~sbY4n is responsible 2 for the cost of any uneconomic dispatch costs in excess of $4 5 g,QQO for its benefit. 3 Because no unreimbursed uneconomic dispatch costs, other than the above-mentioned 4 amount, are included in 2013 test-year forecasted fuel costs, there is no need to include 5 any Make Whole Payment revenue. 6 On pages seventeen and eighteen of Ms. Neal's direct testimony she recommends 7 removing all Cross-state Air Pollution Rule (CSAPR) compliance costs from fuel costs. 8 Prior to CSAPR being vacated MGE had purchased 2,000 allowances at a cost of 9 $470,000. As this allowance purchase made was consistent with its CSAPR compliance 10 plan, and the cost per allowance purchased appears reasonable, Commission staff has 11 proposed allowing MGE to recover these costs by amortizing the $470,000 over the 12 2013-2014 biennium, with the provision that should MGE recover any value from the 13 sale of these allowances, that amount would be returned to ratepayers in a subsequent rate 14 proceeding. 15 Q. Do you have any clarifications or corrections to your direct testimony? 16 A. Yes I do. On page 4, line 20, through page 5, line 15, of my direct testimony I discuss 17 the rationale for my proposed adjustment 9, which reflects a decrease in the locational 18 marginal pricing (LMP) differentials between the MGE node and LMPs at the nodes 19 where MGE purchases wind and other generation. The portion of this discussion 20 regarding basis differences between NiHub LMPs and LMPs at the MGE node is actually 21 applicable only to adjustment 7, which reflects the effects of updated NYMEX natural 22 gas futures and NiHub LMPs, as well as the updated LMP basis differences between the 23 NiHub and the MGE node. The balance of the discussion, which pertains to the causes of PSC-Rebuttal-Hillebrand-2 the differences in LMPs in different geographical areas, is applicable to both adjustments 2 8 and 9. 3 Q. Does this conclude your rebuttal testimony? 4 A. Yes, it does. RJH:cmk DL00588651 PSC-Rebuttal-Hillebrand-3 PSC REF#:l71801 Public Service Commission of Wisconsin Rebuttal Testimony of Corey S.J. Singletary Gas and Energy Division Madison Gas and Electric Company Docket 3270-UR-118 Q. Please state your name. 2 A. My name is Corey S.J. Singletary. 3 Q. Have you previously submitted direct testimony in this proceeding? 4 A. Yes. 5 Q. What is the purpose of your rebuttal testimony? 6 A. The purpose of my rebuttal testimony is to address the direct testimony submitted by 7 Airgas witness Ken Lyons and by Citizens Utility Board witness Jonathan Wallach with 8 respect to Cost of Service Studies (COSS) and by Clean Wisconsin witness Tyson Cook 9 with respect to rate design for LED lighting. Additionally, I would like to offer a 10 correction to my direct testimony and an updated staff rate design. 11 Q. Are you sponsoring any exhibits in conjunction with this rebuttal testimony? 12 A. Yes. I am sponsoring exhibit Ex.-PSC-Singletary-2. 13 Q. What correction would you like to make to your direct testimony? 14 A. On pages 4 and 7 of my direct testimony I make reference to the 507 account and state 15 that the expense under this account represents MGE's share of Columbia and Elm Road 16 costs. This is incorrect. The expenses under account 507 represent MGE's share of the West 17 Campus Cogeneration Facility and Elm Road costs. 18 Q. Why are you offering an updated staff rate design? PSC-Rebuttal-Singletary-1 A. After filing my direct testimony and exhibit Ex.-PSC-Singletary-1, errors were identified 2 in some of the rates and billing units. The following corrections were made. 3 1. The Cg-3 3-phase customer charge was meant to be held at the current rate. It was 4 mistakenly left at the rate proposed by MGE. The staff proposed Cg-3 3-phase 5 customer charge was modified so as to remain equal to the current 3-phase charge. 6 2. The Cg-2A customer charge and monthly maximum on-peak demand charges are 7 meant to be consistent with the customer charges and monthly maximum on-peak 8 demand charges, and have been updated accordingly. 9 3. The base energy kilowatt-hours (kWh) quantity was incorrect; it did not reflect the 10 proper total number ofkWhs. I updated the base energy kWh billing units so that the 11 total kWhs are equal under present and proposed rates. 12 An updated rate design reflecting these changes can be found in Schedule 1 of 13 Ex.-PSC-Singletary-2 and bill impact comparisons can be found in Schedule 2 of 14 Ex.-PSC-Singletary-2. An effort was made to keep class revenue allocations the same as 15 in my initially-prepared rate design. However, some small changes in final allocation 16 have resulted due to the nature of the corrections. 17 Q. Mr. Lyons has argued that a 1CP method should be used, instead of the 12CP method 18 used by the company and yourself, to allocate production plant. Do you agree with this 19 position? 20 A. No. The 1CP method makes the assumption that all ofMGE's capacity costs are incurred 21 to serve peak loads during the single highest month of the year, and provide no benefits 22 to customers at any other points throughout the year. MGE has built generation and 23 purchased capacity to meeting reliability standards. While these reliability standards are PSC-Rebuttal-Singletary-2 1 based on analyses that show that the majority of reliability risk exists during peak 2 summer months, it is important to recognize that all of the utility's generation plant, 3 including peaking resources, provides reliability during other times of the year. If this 4 were not true, the Midwest Independent Transmission System Operator, Inc. (MISO) 5 would allow MGE and other generation owners to schedule maintenance projects on their 6 generating facilities during non-peak months without restrictions. In fact, there are strict 7 rules that require utilities to ensure that these plants are available to operate during the 8 entire year, with maintenance scheduling also subject to strict rules. 9 Utilities also ensure that their generation facilities are available during the 10 non-summer months because they provide economic benefits to the utility and its 11 ratepayers as a hedge against the risk of purchasing energy at a high cost. The 1CP 12 method assumes this cost-hedge has no value during a non-peak month. 13 For these reasons, Commission staff does not support the use of the I CP method 14 for the allocation of production plant. As Mr. Lyons also makes note of a 4CP approach 15 in his direct testimony, I would note that staff also does not support the use of 4CP for the 16 same reasons. 17 Q. Would the use of the 1CP method affect the allocation of any costs other than production 18 plant? 19 A. Yes. Nearly $73 million in other utility production and transmission operation and 20 maintenance expense (O&M) are allocated based on coincident peak demand and would 21 be affected by a switch to a 1CP method. I would note that of the $73 million, the Cp-1 22 class is already excluded from the allocation of approximately $25 million due to the way 23 in which interruptible capacity is treated with respect to the allocation of these expenses. PSC-Rebuttal-Singletary-3 If one considers the revenue requirement for the Cp-1 class under M GE' s 2 "Standard" model, expenses allocated on the basis of coincident peak demand make up 3 over 21 percent of the Cp-1 revenue requirement. 4 Q. With respect to the approximately $25 million in expenses you m:rt are not allocated to 5 the Cp-1 class due to the treatment of interruptible capacity, have you used the same 6 allocation method in your studies to allocate these expenses? 7 A. Yes. 8 Q. Is your allocation consistent with past Commission staff practice to allocate those 9 production O&M expense based on total coincident peak demand, not demand net of 10 interruptible capacity? 11 A. Somewhat. As is reflected in my direct testimony, the approach I used represents a 12 compromise between the approach historically employed by staff, and that used by MGE. 13 Under this "compromise," steam production O&M expense is allocated using a demand 14 allocator reflecting total coincident peak demand. For "Other Power Generation" and 15 "Other Power Supply," production O&M expense is allocated using a 16 net-of-interruptibility coincident peak demand allocator. 17 That being said, a reasonable argument can be made that netting out interruptible 18 demand when allocating these production O&M expenses, when coupled with staffs 19 interruptible credit method, improperly double credits interruptible load. Considering 20 that, one could reasonably allocate all production O&M costs based on total coincident 21 demand (where demand allocation is specified), not demand net of interruptibility. 22 Q. How would allocating production O&M based on total coincident peak load change 23 affect the results of the studies performed? PSC-Rebuttal-Singletary-4 A. In the case ofMGE's studies, it would allocate a large amount of these production O&M 2 expenses to the CP-1 class that are currently bourne by other classes, remembering that 3 under the current, net-of-interruptibility method, that Cp-1 is allocated none of these 4 expenses. This would in turn significantly, but not necessarily inappropriately, magnify 5 the rate increase suggested by the COSS results. 6 Similarly, under the studies I performed, Cp-1 would receive a share of these 7 costs and a greater suggested increase. Due to the way in which I recognized all 8 interruptible capacity in developing staffs net-of-interruptibility demand allocator, Cg-4, 9 Cg-2, and Cg-6 would also see a larger increase under staffs COSS results if a total 10 coincident peak allocation was used for production O&M. The impact to these three 11 classes would be proportional to the relative amounts of interruptible capacity present in 12 each class, with the Cg-6 seeing the greatest impact. 13 Q. Do you have any other concerns regarding the cost allocation and COSS approach 14 proposed by Mr. Lyons? 15 A. Yes. As I noted in my direct testimony, the coincident peak allocators used by Mr. James 16 to allocate production plant are developed by subtracting out the entire Cp-1 class 17 coincident peak load. This is due to the way in which Mr. James has treated Cp-1 18 interruptible capacity in his COSS. The consequence is that the Cp-1 class is allocated no 19 production plant costs. The results of Mr. Lyons' COSS results in Ex.-Airgas-Lyons-2, 20 indicate that Mr. Lyons has used the same method with respect to coincident peak 21 demand allocators for production plant. PSC-Rebuttai-Singletary-5 Q. Mr. Lyons testified it would not be the case that under his proposed allocation the Cp-1 2 class will get the benefit of low cost generation without paying for capacity. Do you 3 agree with his statement? 4 A. No. As I have just noted, under the "Standard" COSS approach prepared by Mr. Lyons, 5 the Cp-1 class is allocated no production plant costs and, if revenue allocation were set 6 strictly based on this these costs of service results as he suggests, Cp-1 would not pay for 7 any ofMGE's production plant. I would also note that this would occur whether a 12CP 8 or 1CP approach is used. 9 Q. Why is this result of Mr. Lyons' preferred COSS method problematic? 10 A. Cp-1 is a high load-factor customer class, with a requirement of a minimum annual load 11 factor of 90 percent. The load under this class is instantaneously interruptible at the sole 12 discretion ofMGE. In previous rate cases, Mr. Lyons has argued that the interruptible 13 nature of the Cp-1 class warrants the production plant allocation method he prefers. 14 However, the result, that the Cp-1 class contributes nothing to production plant under the 15 "Standard" COSS, is difficult to reconcile with the facts about the Cp-1 class's usage 16 characteristics. 17 Looking at the monthly demand information used in MGE's COSS, one can see 18 that Cp-1 load is extremely consistent, with relatively little variation from month to 19 month and even between coincident peak demand and non-coincident peak demand, 20 precisely what one would expect from a high load factor class. This demand data can be 21 found in Schedule 3 ofEx.-PSC-Singletary-2. This shows that the Cp-1 class receives 22 the benefit ofMGE's generation in meeting its demand for most, if not all 8760, hours 23 each year. PSC-Rebuttal-Singletary-6 Since 1999, MGE has called only one interruption for reliability reasons, for 6 ~( 2 hours on August 1, .z.eH, when the company was required to interrupt load. The Cp-1 3 class is also subject to economic interruptions. During economic interruption events, 4 Cp-1 customers have a buyout option in lieu of interrupting or reducing their load. 5 Schedule 4 of Ex.-PSC-Singletary-2 shows that, from 2004 to the present, MGE has 6 called 225 buyout events for Cp-1 totaling I ,316 hours. When the average demand for 7 Cp-1 during those buyout events is compared against the class average peak demands in 8 Schedule 3 of Ex.-PSC-Singletary-2, we can come to the reasonable conclusion that Cp-1 9 has consistently opted to largely, if not entirely, buy-through economic interruptions 10 rather than curtail load. 11 From this, it can be seen that Cp-1 behaves as if it were a high load-factor, 12 firm-load customer, and as such receives the benefit of consistent, reliable, low cost 13 energy from the generation resources owned or obtained by MGE. In light of this, 14 Mr. Lyons' implicit position, that the Cp-1 class should contribute nothing to production 15 plant in return for an interruptible resource whose benefits one might argue are 16 theoretical at best, is difficult to accept. 17 Q. Are you suggesting that Cp-1 interruptible capacity not be recognized in preparing a 18 COSS for MGE? 19 A. Not at this time. In fact, as I noted in my direct testimony I treat interruptible capacity in 20 a very explicit manner, using values for interruptible capacity authorized by this 21 Commission, which MGE has not made any proposal to modify. The approach I use, in 22 addition to being more equitable through the recognition of all interruptible capacity, can PSC-Rebuttal-Singletary-7 easily be modified to reflect whatever value the Commission determines to be reasonable, 2 and can be updated over time to reflect the ever-changing value of capacity. 3 Q. Do you agree with Mr. Lyons' statements regarding revenue allocation as they relate to 4 MGE's and his COSS results? 5 A. No. Mr. Lyons' statements regarding the appropriate revenue allocation for the Cp-1 6 class are predicated on the assumption that the three COSS models -"Standard," 7 time-of-use (TOU), and Location, all suggest decreases or lower than average increases 8 for the Cp-1 class. This assumption is false for several reasons. 9 First, as noted in my direct testimony, MGE's filed TOU and Location studies 10 include an inconsistency in the treatment of expense account 507. In the last MGE rate 11 case, some degree of consensus was reached between MGE, Airgas, and Commission 12 staff witness Dr. James Petersen that the 507 account should be allocated in a manner 13 consistent with the allocation of production plant. Conversations with MGE staff 14 regarding the company's COSS model confirmed that this is the approach MGE intended 15 to use in preparing its studies. 16 As a consequence of this inconsistency, the company's TOU and Location studies 17 incorrectly and dramatically understate the allocation of account 507 expenses to the 18 Cp-1 class. lfthis inconsistency is rectified, the results ofMGE's TOU and Location 19 studies no longer suggest a decrease for Cp-1, but rather, more closely align with the 20 results of Commission staffs TOU and Location studies in suggesting a significantly 21 larger than average increase. This is without making any changes to MGE's allocation of 22 Production Plant. A comparison of COSS results under MGE's original allocation PSC-Rebuttal-Singletary-8 against results using the corrected account 507 allocator can be done by referring to the 2 COSS summaries on pages 6 through 11 of Schedule 1 of exhibit Ex.-PSC-Singletary-1. 3 Second, once the error in the allocation of account 507 is addressed, the results 4 from MGE' s "Standard" study, and by extension the 12CP "Standard" study performed 5 by Mr. Lyons, stand in stark contrast to the other 5 model scenarios (MGE TOU, MGE 6 Location, Staff "Standard," Staff TOU, Staff Location), and as such may be ignored as an 7 outlier. All model results, except for Mr. Lyons' COSS method, suggest significantly 8 higher than average increases for Cp-l. Even if one did not fully accept the arguments 9 against excluding Cp-1 from the allocation of production plant under the "Standard" 10 model, it would be difficult to credibly suggest that the results ofMGE's "Standard" 11 model should carry equal or greater weight than the results of all the other models that 12 consistently produce a dramatically different result. 13 Q. Please comment on Mr. Wallach's statements regarding the allocation of distribution 14 plant. 15 A. Mr. Wallach is correct in stating in his direct testimony that the minimum system method 16 used by MGE to allocate distribution system costs in its "Standard" and TOU models has 17 some shortcomings. In fact, Mr. James addresses this in his direct testimony, noting that 18 "some analysts believe that the minimum system approach overstates the customer 19 portion of costs because it does not take into account customer density and location. 20 Conversely, the Location study understates the customer portion by eliminating all 21 customer costs except for meters and services." (Direct-MGE-James-8, lines 5-9.) 22 As noted in Mr. James' direct testimony and by other witnesses in this proceeding 23 testifying on COSS, there is no single universally-accepted cost of service study. This PSC-Rebuttai-Singletary-9 Commission has found it reasonable to consider the results of multiple studies when 2 allocating revenue responsibility. Highlighting issues such as those raised by 3 Mr. Wallach is appropriate in rate case proceedings, not to rule out studies for the 4 slightest perceived imperfection, but rather to highlight the shortcomings of various 5 model approaches in order that the Commission can consider them when evaluating the 6 results of cost of service studies. 7 Q. Do you have any comments regarding Mr. Cook's LED lighting proposal? 8 A. Only that I have reviewed Mr. Cook's testimony and share his concerns surrounding the 9 difficulty present in trying to develop rates for LED lights which do not fall into discreet 10 categories as easily as HID lighting. That being said, one of the principles of good rate 11 design as enumerated by James Bonbright is that it should create "simplicity, certainty, 12 convenience of payment, economy in collection, understandability, public acceptability, 13 and feasibility of application." The final rate design should not seem like "rocket 14 science," either to the customer or the utility's billing department- or at the very least not 15 to both. My hope is that Clean Wisconsin and MGE will be able to work together to 16 develop a workable LED lighting design without letting the perfect become the enemy of 17 the good. I would also note that the LED lighting rate design can be review and revised 18 in subsequent rate cases if experience with authorized rates suggest that they require 19 modification to reflect changes in LED technology. 20 Q. Does this conclude your rebuttal testimony? 21 A. Yes. CSS:cmk:DL:00588336 PSC-Rebuttal-Singletary-1 0