psc ref#:88448
TRANSCRIPT
BEFORE THE
PUBLIC SERVICE COMMISSION OF WISCONSIN
Joint Application of Wisconsin Electric Power Company and Wisconsin 5-UR-103 Gas LLC, both d/b/a We Energies, for Wisconsin Electric Power Company to Increase Its Electric, Natural Gas, and Steam Rates and for Wisconsin Gas LLC to Increase Its Natural Gas Rates
FINAL DECISION
This is the Final Decision concerning the application of Wisconsin Electric Power
Company (WEPCO) for authority to increase Wisconsin retail electric, natural gas, and steam
rates and Wisconsin Gas LLC (WG) for authority to increase natural gas rates in 2008.
Final overall rate changes are authorized consisting of a $389,065,000 annual rate
increase for WEPCO Wisconsin retail electric operations coupled with estimated credits of
$315.912.000 in 2008 for the sale of the Point Beach Nuclear Power Plant (Point Beach), (a
3.24 percent effective increase), a $3,973.000 annual rate increase for WEPCO natural gas
operations, (a 0.60 percent increase). a $1,94.7.000 annual rate increase for WEPCO Downtown
Milwaukee steam (DMS) operations. (a 10.16 percent increase). a $1,693.000 annual rate
increase for WEPCO Wauwatosa steam (WS) operations, (a 12.42 percent increase) and a
$20,132,000 annual rate increase for WG natural gas operations, (a 2.21 percent increase), for
the test year ending December 3 1.2008. based on a 10.75 percent return on common equity.
Credits for the Point Beach sale will be reduced to $240,726.000 in 2009, providing an effective
increase in 2009 of 3.22 percent.
PSC REF#:88448Public Service Commission of Wisconsin
RECEIVED: 01/17/08, 1:24:31 PM
Docket 5-UR- 103
Introduction
In this Final Decision, any reference to WG and the four utility operations under
WEPCO, collectively, will use the general name "We Energies" and any reference to the
holding company, Wisconsin Energy Corporation, will use the acronym "WEC."
On May 7, 2007, We Energies requested an $11.8 million (1.8 percent) increase for
WE-GO (Wisconsin Electric-Gas Operations) operations, a $36.1 million (4.2 percent) increase
for WG operations, a $3.1 million (16.2 percent) increase for DMS operations, and a $2.2 million
(16.0 percent) increase for WS operations. On May 21,2007, WEPCO filed financial data for
the 2008 test year indicating that its electric operations needed a $648.6 million (28.7 percent)
increase on a Wisconsin jurisdictional basis. In order to mitigate the impact on customers of the
requested electric operations increase, WEPCO proposed to use net proceeds from the sale of
Point Beach, the subject of docket 6630-EI-113, to provide bill credits in 2008 and 2009 and to
offset recovery of certain regulatory assets. The use of the proceeds from the Point Beach sale,
as proposed in its filing, resulted in a net requested electric increase of $170.3 million
(7.5 percent) in 2008 and an effective increase of $183.5 million (7.5 percent) in 2009. The
company's proposed rates are based on an 11.2 percent return on common equity.
On July 30,2007, a prehearing conference was held to determine the issues to be
addressed in this docket and to establish a schedule for the hearing. Hearings were held on
October 3 1, November 1, and 6, 2007, in Madison, Brookfield, and Kenosha.
The Commission considered this matter at its open meeting of December 20,2007.
The parties, for purposes of review under Wis. Stat. $9 227.47 and 227.53, are listed in
Appendix A. Others who appeared are listed in the Commission's files.
Docket 5-UR- 103
Findings of Fact
1. Presently authorized rates for WEPCO's Wisconsin retail electric utility
operations will produce operating revenues of $2,349,290,000 for the test year ending
December 31, 2008, which results in an adjusted net operating loss of $5,918,000 and an annual
revenue deficiency of $3 89,065,000.
2. Presently authorized rates for WEPCO's natural gas utility operations will
produce operating revenues of $66 1,386,000 for the test year ending December 3 1,2008, which
results in an adjusted net operating income of $33,793,000 and an annual revenue deficiency of
$3,973,000.
3. Presently authorized rates for WEPCO's DMS utility operations will produce
operating revenues of $19,061,000 for the test year ending December 31,2008, which results in
an adjusted net operating income of $1,775,000 and an annual revenue deficiency of
$1,947,000.
4. Presently authorized rates for WEPCO's WS utility operations will produce
operating revenues of $13,626,000 for the test year ending December 3 1,2008, which results in
an adjusted net operating income of $463,000 and an annual revenue deficiency of $1,693,000.
5. Presently authorized electric, natural gas, and steam rates of WEPCO are
unreasonable because they produce inadequate electric, natural gas, and steam revenues.
6. Presently authorized rates for WG's natural gas utility operations will produce
operating revenues of $910,278,000 for the test year ending December 31, 2008, which results
in an adjusted net operating income of $43,221,000 and an annual revenue deficiency of
$20,132,000.
Docket 5-UR-103
7. Presently authorized natural gas rates of WG are unreasonable because they
produce inadequate natural gas revenues.
8. For the WEPCO Wisconsin retail electric utility, the estimated rate of return on
average net investment rate base of $3,018,467,000 at current rates subject to the Commission's
jurisdiction for the test year is negative 0.20 percent, which is inadequate.
9. For the WEPCO natural gas utility, the estimated rate of return on average net
investment rate base of $395,447,000 at current rates subject to the Commission's jurisdiction
for the test year is 8.55 percent, which is inadequate.
10. For the WEPCO DMS utility operations, the estimated rate of return on average
net investment rate base of $32,420,000 at current rates subject to the Commission's jurisdiction
for the test year is 5.48 percent, which is inadequate.
11. For the WEPCO WS utility operations, the estimated rate of return on average net
investment rate base of $15,742,000 at current rates subject to the Commission's jurisdiction for
the test year is 2.94 percent, which is inadequate.
12. For the WG natural gas utility, the estimated rate of return on average net
investment rate base of $506,799,000 at current rates subject to the Commission's jurisdiction
for the test year is 8.53 percent, which is inadequate.
13. A reasonable increase in operating revenue for the test year to produce a
9.26 percent return on WEPCO's average net investment rate base for Wisconsin retail electric
operations is $389,065,000.
Docket 5-UR- 103
14. A reasonable increase in operating revenue for the test year to produce a
9.15 percent return on WEPCO's average net investment rate base for natural gas operations is
$3,973,000.
15. A reasonable increase in operating revenue for the test year to produce a
9.09 percent return on WEPCO's average net investment rate base for DMS operations is
$1,947,000.
16. A reasonable increase in operating revenue for the test year to produce a
9.41 percent return on WEPCO's average net investment rate base for WS operations is
$1,693,000.
17. A reasonable increase in operating revenue for the test year to produce a
10.91 percent return on WG's average net investment rate base for natural gas operations is
$20,132,000.
18. WEPCO's and WG's filed operating income statements and net investment rate
bases for the test year, as adjusted for Commission decisions, are reasonable.
19. It is reasonable for WEPCO to use escrow accounting for the monies from the
sale of Point Beach.
20. It is reasonable to allow recovery of 100 percent of the sale of Point Beach
transaction costs provided that such costs, upon audit, are found to be reasonable and not of the
type normally excluded for ratemaking purposes.
21. It is reasonable to authorize WEPCO to transfer to WEC Nuclear an amount
sufficient to fully compensate WEC Nuclear for that diminution in value.
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22. It is reasonable to use a historical jurisdictional allocator for the refund of the
Point Beach decommissioning trust fund based on a historical decommissioning fund balance
and, therefore, 85.2 percent of decommissioning trust fund monies shall be allocated to the
Wisconsin retail jurisdiction.
23. It is reasonable to allocate the net pre-tax gain on the sale of Point Beach to
jurisdictions based on 12 CP demand and, therefore, 86.1 percent of the net pre-tax gain shall be
allocated to the Wisconsin retail jurisdiction.
24. It is reasonable to not allow WEPCO to withhold proceeds from the sale of Point
Beach for any contingencies.
25. Of the amounts to be returned to ratepayers from the sale of the Point Beach, it is
reasonable to require that amounts related to the book gain on the sale and the tax gain realized
on the non-qualified trust fund, plus interest thereon, be satisfied by bill credits only.
26. A reasonable investment interest rate for the segregated external trust fund for the
proceeds from the sale of Point Beach, as authorized in the Interim Decision in this proceeding,
is 5.28 percent for the test year.
27. It is reasonable to allow WEPCO to recover Point Beach relicensing costs in rates.
28. A 2008 total company test year fuel cost of $1,104,217,000 is reasonable.
29. A 2008 total company test year fuel rules monitoring level of fuel costs of
$976,904,000 is reasonable.
30. It is reasonable to calculate the total estimated cost of electric generation from
natural gas using the NYMEX price futures from December 13, 2007, as the estimated cost.
Docket 5-UR-103
3 1. It is reasonable to use the results of the PROMOD economic dispatch model as
the basis for the estimated 2008 fuel cost.
32. It is reasonable to include certain Midwest Independent Transmission System
Operator (MISO) Day 2 costs and credits not included in the fuel cost estimates generated by
the PROMOD economic dispatch model.
33. It is reasonable to include the recovery of the deferred MIS0 Day 2 costs as of
December 31, 2006, including interest, amortized over six years. WEPCO is required to show
an overall increase in cost as a result of MIS0 Day 2 to be granted rate recovery for these costs
in 2007 in its next rate case.
34. It is reasonable to continue monitoring fuel costs using the following ranges: plus
or minus 8 percent monthly; cumulative ranges of plus or minus 8 percent for the first month,
plus or minus 5 percent for the second month, and plus or minus 2 percent for the remaining
months of the year; and plus or minus 2 percent for the annual range.
35. It is reasonable to include $3.8 million of net Ancillary Service revenues based on
a June 1,2008, start of the MIS0 Ancillary Service Market (ASM).
36. It is reasonable to include the revenue requirement changes resulting from the
Point Beach scheduled outage move and the Edison Sault Electric Company (ESE) change from
an opportunity sale to a fully allocated sale.
37. It is reasonable to exclude WEPCO's request for the recovery additional costs
estimated for 2008 associated with the purchase of renewable green tags, the updated MIS0
load forecast, reduced rail deliveries to Pleasant Prairie and Oak Creek power plants, hedge
transaction costs for its fuel oil hedging program, and reduced hydro generation.
Docket 5-UR- 103
38. It is reasonable not to update coal transportation costs based on the most recent
NYMEX heating oil futures prices.
39. It is reasonable to allocate the estimated test year cost of the Point Beach
Purchased Power Agreement (PPA) based on demand and energy in the jurisdictional
cos t-of-service study (COSS).
40. It is reasonable to include costs associated with the Elm Road open cycle water
intake structure in the Power the Future (PTF) escrow. Escrowed costs may be the subject of a
prudence review if the intake system is not ultimately approved.
41. It is reasonable to use the end-of month construction work in progress (CWIP)
balances in the calculation of carrying costs on PTF construction.
42. It is reasonable to reduce the PTF escrow balance by $5.1 million and eliminate
the related test year amortization of $1,023,000 for the difference between actual escrowed
PTF-related gross receipts tax and that which was included in previous rate proceedings.
43. It is reasonable to authorize recovery of payments to the village of Caledonia
resulting from the construction of the Elm Road Generating Station (ERGS) related to police
and fire service costs in the amount of $600,000 per year for two years and the 4 Mile Road
grade separation in the amount of $600,000 per year, up to a total funding of $8 million'
provided that the village of Caledonia obtains the concurrence of the Office of the
Commissioner of Railroads (OCR) as to the need and proper cost allocation between the
railroad and Caledonia for grade separation. WEPCO may only recover costs relative to the 4
' The $8 million represents the present value of annual payments of $600,000 over a 20-year period. The total and annual amounts are subject to funding from other sources.
Docket 5-UR-103
Mile Road grade separation that are not allocated to the railroad and are not funded by other
sources in the future.
44. It is reasonable to require WEPCO to notify the Commission of the final decision
from the OCR regarding the 4 Mile Road separation project.
45. It is reasonable to include WEPCO's forecasted distribution expense in revenue
requirement.
46. It is reasonable to allocate shared officer time based on an average of Commission
staffs and the applicants' proposed allocation percentages.
47. It is reasonable for the applicants to work with Commission staff to develop a
mechanism that moves away from requiring executives to fill out timesheets.
48. It is reasonable to disallow recovery of WEC board of director costs.
49. It is reasonable to allow recovery of economic development expenses.
50. It is not reasonable to allow recovery of updated forecasts of the test year PSCW
remainder assessment.
51. It is reasonable that the carrying costs of gas in storage be recovered through
margin rates versus the purchased gas adjustment clause (PGA) mechanism.
52. It is reasonable to reflect a cash balance of zero for WEPCO and WG in the Ratio
of Net Investment Rate Base Plus CWIP to Capital Applicable Primarily to Utility Service Plus
Accumulated Deferred Investment Tax Credit.
53. It is reasonable to discontinue the escrow accounting treatment as of
December 31,2007, for American Transmission Company (ATC) transmission expense and to
Docket 5-UR-103
increase test year transmission expense to levelize this 2008 and 2009 expense based on the
October 4, 2007, updated ATC budgets.
54. It is reasonable for WEPCO to defer any refunds from ATC associated with its
network service fees until such refunds can be returned to ratepayers.
55. For future rate case applications, it is reasonable to direct WEPCO and WG to file
a complete forecast of its balance sheet, by month, for all months from the actual starting point
through the test year.
56. It is not reasonable to adjust the 2008 revenue deficiencies to levelize any
increase in gross receipts tax in 2009.
57. It is reasonable to continue to use the ratio of average net investment rate base
plus CWIP to capital applicable primarily to utility operations plus deferred investment tax
credits when determining the return on net investment rate base in this proceeding.
58. It is reasonable to allow a current return on 50 percent of CWIP for electric and
natural gas operations when determining the return on net investment rate base in this
proceeding, unless otherwise noted.
59. It is reasonable to continue treating carrying costs on Elm Road Units 1 and 2
CWIP as a current expense through the PTF escrow.
60. It is reasonable to continue recovery of Elm Road Unit 1 lease expenses through
the PTF escrow in 2008.
61. It is reasonable to allow deferred accounting for $2,595,000 of costs related to
environmental trust financing from docket 6630-ET-100 until it can be considered in another
Docket 5-UR- 103
environmental trust financing order at which time the company will need to justify whether
these costs have in fact facilitated that future financing.
62. It is reasonable to reduce test year income tax expense for the estimated 2008
production tax deduction and to begin amortizing the estimated 2007 year-end balance over four
years. It is also reasonable to address the appropriate amount of production tax benefit and
associated carrying costs for 2005 through 2009 in the company's next rate proceeding.
63. It is reasonable to disallow WEPCO recovery of the $22.1 million deferral of
costs relating to the Spring 2005 Point Beach Unit 2 extended outage.
64. It is not appropriate to disallow amortizations of deferred balances in this
proceeding based on setting a boundary on the return on equity which is below the allowed
return.
65. It is reasonable to offset $84,933,000 of net proceeds from the sale of Point Beach
to offset the same amount of regulatory assets related to escrowed bad debts, deferred coal
conservation costs, and deferred Pleasant Prairie forced outage costs.
66. It is appropriate to amortize the regulatory asset balances in this proceeding over
six years.
67. It is appropriate for all authorized amortizations to begin as of the effective date
of this order.
68. It is appropriate to accrue carrying costs on deferred balances at the weighted cost
of capital, except it is appropriate to continue accruing carrying costs on the PTF escrow, MIS0
deferral, and the coal conservation deferral at WEPCO's authorized short-term debt rate.
Docket 5-UR- 103
69. The appropriate conservation escrow budgets are $33,954,000 for WEPCO
electric, $9,152,000 for WEPCO natural gas, and $12,664,000 for WG. The test year expenses
reflect 2008 and 2009 levelized expenditures.
70. It is appropriate that the same standards be used in approving and judging all
energy efficiency programs in the state, including We Energies' voluntary utility programs.
71. We Energies should work with Commission staff in the development of its
voluntary utility programs and information in support of the programs. We Energies should
also work with Commission staff and the Focus on Energy program administrator to ensure
adequate coordination of We Energies' programs and Focus on Energy programs.
72. We Energies should work with Commission staff to develop measures of success
for its 2008 customer service conservation activities.
73. It is reasonable to discontinue escrow accounting treatment as of December 3 1,
2007, for NOx reduction compliance related costs.
74. It is reasonable to reflect in revenue requirement the Commission staff
adjustments not contested by any party.
75. A long-term range of 48.5 percent to 53.5 percent for WEPCO' s common equity
ratio, on a financial basis, is reasonable and provides adequate financial flexibility.
76. A long-term range of 4.5.0 percent to 50.0 percent for WG's common equity ratio,
on a financial basis, is reasonable and provides adequate financial flexibility.
77. An appropriate target level for WEPCO's test year average common equity
measured on a financial basis is 5 1.0 percent.
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78. An appropriate target level for WG's test year average common equity measured
on a financial basis is 47.5 percent.
79. It is reasonable that an adjustment be made to the financial capital structure for
the goodwill and other push-down accounting adjustments associated with the purchase of WG
by WEC.
80. It is reasonable that the financial capital structure to be used in Commission
proceedings should not include any debt equivalent associated with the PFT leases.
81. A reasonable estimate of the debt-equivalent of WEPCO's capital leases and
off-balance sheet obligations to be imputed into the financial capital structure for the test year is
$463,155,000.
82. A reasonable financial capital structure for WEPCO for the test year consists of
51.00 percent common equity, 0.62 percent preferred stock, 37.76 percent long-term debt,
1.16 percent short-term debt, and 9.46 percent debt-equivalents of off-balance sheet obligations.
83. A reasonable financial capital structure for WG for the test year consists of
47.50 percent common equity, 41.98 percent long-term debt, and 10.52 percent short-term debt.
84. It is reasonable to revise WEPCO's and WG's dividend restrictions based on the
financial capital structure determinations in this proceeding.
85. It is reasonable to require WEPCO and WG to submit ten-year financial forecasts
in their next rate proceedings.
86. It is reasonable to require WEPCO to submit in its next rate proceeding detailed
information regarding all off-balance sheet obligations for which the financial markets will
calculate a debt equivalent.
Docket 5-UR- 103
87. It is reasonable that WEPCO and WG shall obtain and file proof of credit rating
agency treatment of all capital items along with all credit agency reports and releases related to
the companies in their next rate case application.
88. It is reasonable to continue the practice of removing non-utility investments that
are not related to the provision of utility service from WEPCO's and WG's average common
stock equity to arrive at utility common stock equity for purposes of determining the regulatory
capital structure and test year revenue requirement.
89. It is reasonable to treat the common equity investment in ATC as a non-utility
investment, financed by common equity of shareholders of WEPCO.
90. A reasonable utility capital stmcture for ratemaking for WEPCO for the test year
consists of 54.36 percent common equity, 0.72 percent preferred stock, 43.58 percent long-term
debt, and 1.34 percent short-term debt.
91. A reasonable utility capital structure for ratemaking for WG for the test year
consists of 46.64 percent common equity, 42.67 percent long-term debt, and 10.69 percent
short-term debt.
92. A reasonable interest rate for WEPCO's and WG's short-term borrowing through
commercial paper is 4.28 percent for the test year.
93. A reasonable interest rate for WEPCO's proposed 30-year debentures totaling
$500 million is 6.01 percent.
94. A reasonable interest rate for WEPCO's variable rate long-term debt is
2.78 percent for the test year.
Docket 5-UR- 103
95. A reasonable average embedded cost for WEPCO's long-term debt is 5.49 percent
for the test year.
96. A reasonable average embedded cost for WG's long-term debt is 5.74 percent for
the test year.
97. A reasonable average cost for WEPCO's preferred stock is 3.95 percent for the
test year.
98. A reasonable return on utility common stock equity for WEPCO and WG is
10.75 percent.
99. A reasonable weighted average composite cost of capital is 8.33 percent for
WEPCO.
100. A reasonable weighted average composite cost of capital is 7.92 percent for WG.
101. It is reasonable to rely on the results of one or more COSS along with other
factors, such as bill impacts, when allocating revenue responsibility.
102. It is reasonable to direct the applicant, Commission staff, and any interested
parties to work to develop a retail allocation that reflects how Point Beach costs were allocated
prior to the sale for use in the next filing by the applicant.
103. It is reasonable to approve rates for electric service for the test year to achieve
customer class changes in revenue as shown in Appendix B.
104. It is reasonable to allow WEPCO to track any deficiency in revenue resulting
from 2005 Wisconsin Act 141 (141) related refunds to qualifying customers with escrow
accounting and trued up in a future rate case.
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105. It is appropriate to direct WEPCO to continue its collaborative work with the
Citizens' Utility Board (CUB) to investigate innovative residential and Small Use rate options
such as new Time-of-Use (TOU) rates.
106. It is reasonable to direct WEPCO to provide an accounting of Point Beach refunds
made by tariff class along with a forecast of tariff class energy use for the third year of the
three-year refund period prior to the utility's next biennial rate application.
107. The standard buyback rates proposed by WEPCO are reasonable.
108. The standby rates for the CP-4 service schedule proposed by WEPCO are
reasonable.
109. It is reasonable for WEPCO to discontinue charging for disconnections of electric
service.
110. It is reasonable for WEPCO to discontinue charging a Timing Adjustment Factor
in its contributions in aid of construction associated with electric extensions.
11 1. It is reasonable to approve Standby Rates as shown in Appendix B.
112. It is reasonable to approve rates for steam service for the test year to achieve
customer class changes in revenue as shown in Appendix B.
113. It is reasonable to authorize rates for natural gas service for WG and WEGO as
shown in Appendix D.
114. It is reasonable to authorize general service rates that result in a greater
percentage increase in the fixed distribution service charge than in volumetric distribution
service charges for residential customers and the smallest-volume commercial service rate class.
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115. It is reasonable to authorize metered demand gas service charges for the
companies' three largest-volume service rate classes.
116. It is reasonable to authorize natural gas service rates that reduce billing
differences at the service rate class breakpoints in 2009.
117. It is reasonable to eliminate WG's meter aggregation billing practices.
118. It is reasonable to revise WG's current classification of average peak-day demand
gas costs and average annual demand gas costs, and to waive the service switching rules for 90
days to permit interruptible sales customers to move to transportation service upon meeting all
other tariff requirements.
119. It is reasonable to revise the default credit for Distribution Capacity with or
without Gas Supply Interruption Crediting Service to 15 percent of the volumetric basic
distribution charges excluding metered demand service charges.
120. Current service availability standards are reasonable and it is not necessary to
revise the tariffs to allow the companies to directly assign customers to larger volume service
rate classes.
121. It is reasonable for the companies to offer a meter pulse signal device service for
customers requesting real-time usage information.
Conclusions of Law
The Commission concludes it has jurisdiction under Wis. Stat. 55 1.12, 196.02, 196.025,
196.03, 196.19, 196.20, 196.21, 196.37, 196.374, 196.395, and 196.40 and Wis. Admin. Code
chs. PSC 113, 116, 134, and 137 to issue an order authorizing WEPCO and WG to place in effect
the rates and rules for electric, natural gas, and steam utility service set forth in Appendices B,
Docket 5-UR-103
and D, and the fuel cost treatment set forth in Appendix F, subject to the conditions specified in
this order.
Opinion
Applicants and Business
WEPCO and WG are public utilities, as defined in Wis. Stat. 5 196.01(5). WEPCO
conducts its operations primarily in three operating segments: an electric utility segment, a
natural gas utility segment, and a steam utility segment. WEPCO serves approximately
1,102,200 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately
452,600 natural gas customers in Wisconsin, and about 460 steam customers in metropolitan
Milwaukee, Wisconsin. WG is a natural gas distribution public utility which serves
approximately 588,800 natural gas customers in Wisconsin. WG also serves approximately
2,500 water customers in Milwaukee's northern suburbs. WEPCO and WG are operating
subsidiaries of WEC, a holding company based in Milwaukee, Wisconsin.
WEPCO has two physically separate steam utility systems which are known as the DMS
and WS. DMS provides steam service in downtown Milwaukee and the near south side of
Milwaukee. WS owns and operates the Milwaukee County Power Plant which produces steam
energy that is distributed to customers located on the Milwaukee County Grounds in Wauwatosa,
Wisconsin.
Docket 5-UR- 103
ELECTRIC UTILITY REVENUE REQUIREMENT
Electric Fuel Costs
PROMOD Economic Dispatch Model
WEPCO used the PROMOD model for forecasting fuel costs in its filed test year
estimates. The model is a security-constrained production cost model and has the ability to
represent power flows to calculate Locational Marginal Prices (LMP). WEPCO believes
PROMOD provides a representative projection of unit utilization by MISO.
CUB made numerous comments concerning the validity of the PROMOD model for
purposes of estimating monitored fuel costs. CUB stated that the company did not meet its
burden of proof that the PROMOD model makes reasonable estimates of fuel costs. CUB cited
the lack of appropriate testing of the model-including "backcasting," which is taking the model
and appropriate assumptions and attempting to match fuel costs to a historical time period. CUB
proposed that no incremental fuel costs from the company's filed rate case over the authorized
monitored fuel costs from the 2006 test year should be allowed unless or until the company could
make a demonstration that the model is working properly.
WEPCO stated that the increase in monitored fuel costs for 2008 over 2006 approved fuel
costs can be explained substantially by the increase in the delivered cost of coal of
$109.3 million and the increase in fuel costs due to the limit on generation at Pleasant Prairie of
$6.7 million, and is not due to any shortcomings of the model. Commission staff stated that the
company has used PROMOD in a reasonable fashion.
For this proceeding, the PROMOD model provides reasonable results and is appropriate
to use for estimating monitored fuel costs.
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MIS0 Day 2 Costs and Credits
WEPCO's fuel cost estimate included a net credit of $24.2 million of MIS0 Day 2
charges and credits not forecasted through the PROMOD model. This estimated net credit is
based on the actual amounts charged and credited to WEPCO in 2006. CUB disagreed with
WEPCO that the Revenue Neutrality Uplift (RNU) charge is incremental to the PROMOD
model. CUB proposed that the test year forecast of $5.5 million for RMJ charges should be
excluded from test year fuel costs.
The RNU charge collects costs or refunds revenues that are not collected or returned to
market participants in any other MIS0 Day 2 charges or credits. It is generally the last
mechanism to collect costs or return revenues to market participants in order to make the MIS0
Day 2 market revenue neutral. The largest component of the RNU charge is the Revenue
Inadequacy Uplift that is primarily caused by congestion costs and inaccuracies in how losses are
charged. CUB witness Ms. Smith testified the model is likely to reflect some costs related to
congestion, but it appears the amounts related to losses would not be reflected in the model.
CUB states that the PROMOD model estimates the cost of running units as they are
dispatched by MIS0 which includes start-up, no-load, spinning reserves and all other production
costs. CUB argues that just because MIS0 has identified a category of "charges" to make sure
no costs fall through the cracks does not mean that the costs are not reflected in the PROMOD
model.
WEPCO states that the testimony of WEPCO witnesses Mr. Schumacher and
Dr. Sustman indicates the RNU charges cannot be modeled in PROMOD or any other market
simulator. Therefore, it is appropriate to include the RNU charge as a component of monitored
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fuel costs outside of the fuel cost generated through the PROMOD model. WEPCO testified that
the recent (June 8,2007) changes in how MIS0 calculates RNU charges provides additional
evidence that RNU costs are not captured anywhere in WEPCO's 2008 fuel costs forecasted
through the PROMOD model.
The Commission finds that the RNU charges are incremental to the fuel costs forecasted
through the PROMOD model and that it is appropriate to include an additional $5.5 million of
monitored fuel costs in the test year for these charges.
Deferred MIS0 Day 2 Costs for 2005,2006, and 2007
The Commission, in its August 26,2007, Final Decision in docket 05-EI-139, approved
the deferral of certain MIS0 Day 2 costs, but required a utility requesting deferral to show in its
next rate proceeding that these costs are incremental to the fuel costs included in rates prior to
allowing recovery from ratepayers (Order Point 10). Mr. Schumacher, in rebuttal testimony,
presented data to show that these costs are incremental to fuel costs collected by WEPCO in
approved rates.
Mr. Schumacher provided data to support inclusion of the deferred amounts for calendar
years 2005, 2006, and 2007. For 2005, he testified that $24.4 million of deferred MIS0 costs
(before interest) are incremental. In support of this conclusion, Mr. Schumacher relied on three
premises. First, the fuel cost collected from ratepayers in 2005 was $35.6 million short of the
fuel costs included in 2005 rates (net of deferred amounts). WEPCO states that because it
undercollected fuel costs in 2005, it will not be "double dipping" to recover the deferred costs.
Second, the February 28,2007, "Independent Assessment of Midwest IS0 Operational
Benefits" report to MIS0 prepared by ICF International showed for the period June through
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December 2005 that there was a negative benefit for the MIS0 market for the overall market
participants. This study excluded April and May 2005 and did not include the costs-to-achieve
which could significantly increase the net cost to market participants.
Finally, WEPCO states there are MIS0 start-up costs specifically incurred by WEPCO
for 2005 by comparing the amount of combustion turbine (CT) generation, the number of CT
start-ups and the number of hours of CT operations for 2005 with 2003,2004,2006 and
year-to-date 2007 CT start-ups and hours of operation. This comparison shows a significantly
higher level of CT generation, start-ups and hours of operation in 2005 compared to the other
years. Mr. Schumacher testified, "Everything else being equal, one would expect that such an
enormous increase in the operation of gas-fired CT units, especially during a period when gas
prices were as high as they were in 2005, would increase costs, not decrease costs."
For 2005 Mr. Schumacher testified that even though WEPCO originally overcollected
fuel costs by $37.4 million in 2006, it should be allowed to collect the $3.9 million of deferred
costs for 2006 because it refunded all fuel-related collections in excess of actual fuel costs.
WEPCO stated, "Allowing recovery of that deferred amount in this proceeding will result in
Wisconsin Electric just being made whole for its 2006 fuel costs plus MIS0 costs."
Mr. Schumacher supported collection of the 2007 year-to-date deferred cost of $0.9 million
through August 2007 based on underrecovery of fuel costs through that period in the amount of
$40.8 million, indicating that allowing recovery of the deferred amount will not result in double
dipping.
CUB stated that the company did not demonstrate that all of the deferred MIS0 Day 2
costs (Day-Ahead RSG and Real-Time RNU) should be collected from ratepayers because the
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evidence does not indicate that MIS0 Day 2 operations had increased costs after the MIS0
start-up year of 2005. CUB proposed that the Commission disallow rate recovery of $4 million
of deferred MIS0 costs.
The company has demonstrated that it incurred incremental fuel costs in 2005 as a result
of the start-up of the MIS0 Day 2 market for the high level of CT generation incurred by the
company in 2005. It is appropriate to allow WEPCO to recover the 2005 deferred MIS0 Day 2
costs of $24.4 million.
It is appropriate to allow recovery of 2006 deferred MIS0 Day 2 costs of $3.9 million
because WEPCO returned to ratepayers the overrecovery of fuel costs collected in 2006.
The only support shown for the recovery of amounts deferred for 2007 is that WEPCO
has not filed for a 2007 fuel reopening and as of August 2007 has underrecovered fuel costs by
$40.8 million. The amount deferred for MIS0 Day 2 costs of $0.9 million as of August 2007
may materially change because of MIS0 resettlements through the end of the year. It is
appropriate to defer 2007 MIS0 Day 2 costs as approved in docket 05-EI-139. WEPCO is
required to show in its next rate case an overall increase in costs as a result of NIISO Day 2 to be
granted rate recovery for deferred 2007 MIS0 costs.
Chairperson Ebert dissents and would have permitted collection of the 2007 deferred
MIS0 Day 2 costs.
Ancillary Service Revenue
MIS0 is currently planning to start its ASM June 1, 2008. Commission staff proposed
that the test year fuel costs be reduced by $3.8 million to reflect WEPCO's share of the
anticipated benefits resulting from the MIS0 ASM. WEPCO believes it is not appropriate to
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include this benefit in 2008 because it is possible that the start of the ASM may be delayed.
WEPCO also believes that the proposed benefit estimated by MIS0 may not be achieved quickly
due to start-up costs that may be similar to the costs experienced during the start-up of the MIS0
Day 2 market.
It is appropriate to include the benefits of the MIS0 ASM starting June 1, 2008. MIS0 is
still planning to start the ASM June 1,2008, and its experience from the MIS0 Day 2 start-up
should permit it to efficiently implement the ASM.
WEPCO Additional Requested Increases
In rebuttal testimony, WEPCO requested the following increases in revenue requirement
associated with fuel costs and sales for resale:
Update PROMOD for a New MIS0 Load Forecast
Reduced Rail Deliveries to Pleasant Prairie and Oak Creek Units
Point Beach Planned Outage Schedule Move
Hedge Transaction Costs for Fuel Oil Hedging Program
Hydro Generation Reduction
Purchase of Renewable Energy Green Tags
ESE Sale from Opportunity to Fully Allocated Sale (Plus Correction)
Total Additional Request in Revenue Requirement
$ 4.34 million
$ 8.7 million
$ 6.5 million
$ 1.2 million
$ 2.5 million
$0.42 million
$3.0 million
$ 26.66 million
The request to collect new items by a utility late in a rate proceeding requires a utility
show that the cost could not have been estimated earlier and that the cost has a great likelihood
of occurring. In past rate proceedings, the Commission has not included requested changes by
utilities that occur late in the rate case process because it does not allow intervenors or
Commission staff time to do an in-depth review of the proposed changes. Also, updating the
request for rate changes does not allow intervenors or Commission staff an opportunity to find
other changes that may occur that offset the increases requested by the utility. The filing of
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updated requests for increases by the utility requires the intervenors and Commission staff to
review a moving target.
Commission staff reviewed and supported inclusion of the Point Beach planned outage
move, the purchase of Renewable Energy Green Tags, and the classification change of the ESE
sale from an opportunity to a fully allocated sale in test year revenue requirement. These items
result from contracts with outside firms in the case of the Point Beach Planned Outage Move and
the Renewable Energy Contracts. The treatment of the new ESE contract as a fully allocated
sale rather than an opportunity contract is appropriate for this base rate proceeding.
Mr. Schumacher presented testimony to support the inclusion of a new MIS0 load
forecast, reduced rail deliveries to the Pleasant Prairie and Oak Creek Units, and hedge
transaction costs for WEPCO's fuel oil hedging program in test year revenue requirement.
Mr. Schumacher presented testimony on reasons why these items could not be requested earlier
and his opinion of the likelihood of the item occurring. Commission staff had not reviewed any
independent analysis of these requested amounts to comment on the likelihood of occurrence
other than the support supplied by Mr. Schumacher in sur-surrebuttal testimony.
It is appropriate to include in this test year the revenue requirement only the costs
associated with the Point Beach planned outage move, and the classification change of the ESE
Sale from an opportunity to a fully allocated sale because Commission staff has reviewed these
changes.
Fuel and Ash Handling
Commission staff reduced the company's filed fuel and ash handling costs by $1,150,000
for three items. The first item is a reduction to the Deswarte Property Remediation cost estimate
Docket 5-UR- 103
for 2008 of $615,000 to include two-thirds of WEPCO's filed cost for 2008 to reflect
Commission staff's expected timing of expenditures and the reduced cost for remediation. The
second item is to allow one-half of the forecasted cost of various small remediation projects to
reflect that only some of these projects will likely be incurred in 2008 resulting in a reduction of
$235,000. The third item is a $300,000 reduction to reflect net ash utilization costs based on the
inflated average of actual 2006 and updated 2007 ash utilization costs. WEPCO disagreed with
the first and third items of Commission staff adjustment.
Mr. Schumacher presented rebuttal testimony based on "Remedial Design Report,
Former Drueker Fly Ash Landfill" approved by the Wisconsin Department of Natural Resources
(DNR) on June 25,2007. The Drueker Fly Ash Landfill remediation is also known as the
Deswarte Property Remediation. This agreement committed the company to complete the entire
project by the end of 2008.
Mr. Schumacher testified that the cost associated with gypsum utilization expenses will
be $240,000 higher than the company's filed forecast for 2008. Also, greater air quality
emission controls are increasing the quality assurance testing required for fly ash. Because of
these two changes, WEPCO believes the $300,000 reduction proposed by Commission staff for
net ash utilization costs should be restored.
The Commission determines that it is appropriate to include $615,000 of Fuel and Ash
Handling associated with the Deswarte Property Remediation and to exclude $300,000
associated with net ash utilization costs.
Docket 5-UR-103
Updated Coal Transportation Costs
In rebuttal testimony, WEPCO requested that the Commission update fuel costs for
higher coal transportation costs for diesel fuel surcharges based on NYMEX futures prices for
heating oil. The utility provided further information in sur-surrebuttal testimony. Based on the
NYMEX heating futures prices as of October 30, 2007, WEPCO indicated this would result in an
estimated $14.9 million increase in the delivered cost of coal. The revenue requirement change
would be less than the $14.9 million requested for delivered coal cost after the higher cost is run
through the fuel inventory model. Due to the timing of the request, Commission staff was only
able to conduct a limited review of the utility's calculations and assumptions.
Based on the timing of this request, it is appropriate to not update coal cost for the change
in diesel fuel in this rate proceeding.
Point Beach PPA Jurisdictional Allocation
The Commission, in docket 6630-EI-113, approved the sale of Point Beach by WEPCO
to FPL Energy Point Beach, LLC, a subsidiary of FPL Group Capital, Inc. (FPL). Included in
the sale agreement is a PPA between WEPCO and FPL for the electric energy produced by Point
Beach. The price for the Point Beach power in the PPA is collected based completely on energy
usage. The PPA does not have a fixed capacity charge.
Because the cost of the Point Beach PPA is based solely on energy charges, WEPCO
allocated the cost of the Point Beach PPA by the jurisdictional energy allocator in calculating the
Wisconsin retail revenue requirement.
WPPI presented testimony stating that the Commission approved the Point Beach sale
and the PPA to result in similar costs from the PPA as if the Point Beach power plant was
Docket 5-UR- 103
continued to be owned by WEPCO. WPPI stated that by allocating the cost of the PPA on
energy in the jurisdictional COSS, WEPCO is changing the level of cost collected from different
WEPCO customer^.^ WPPI proposed that the cost of the Point Beach PPA be allocated both on
demand and energy similar to what the total cost of Point Beach would have been if still owned
by WEPCO. WPPI proposed an allocation of 65 percent on demand and 35 percent on energy as
the representative allocation of the total' cost to own and generate power at Point Beach.
It is appropriate to allocate the cost of the Point Beach PPA based on demand and energy
allocators to represent a similar allocation of the total cost of Point Beach power as if the plant
was continued to be owned by WEPCO. For this proceeding, it is appropriate to allocate the cost
of the Point Beach PPA based on 65 percent on demand and 35 percent on energy.
Monitoring'of electric fuel costs
Monitored fuel costs include only the cost of fuel itself and purchased power energy.
Any purchased capacity costs that are required to meet reserve requirements are excluded from
monitoring and may only be adjusted in a base rate case. Firm transmission costs associated
with these capacity purchases are also excluded. For this proceeding, the transmission charges
associated with access to economy energy are excluded from monitored fuel costs. Fuel and ash
handling, and sulfur dioxide (SO2) allowance costs are excluded as well. Based on information
in the record, a reasonable test year monitored fuel cost is $976,904,000. The test year fuel cost
divided by the test year estimate of net native energy requirements of 32,75 1,893 MWh results in
an average net fuel cost of $0.02983 per kWh. Appendix F shows the monthly fuel costs to be
used for monitoring purposes.
WPPI has entered into a settlement agreement with WEPCO to abide by the Wisconsin Commission's determination of the appropriate jurisdictional allocation of the cost of the Point Beach PPA.
Docket 5-UR- 103
Monitoring Ranges
Under Wis. Admin. Code 5 PSC 116.04, the Commission establishes monthly and annual
ranges for monitoring the test year fuel forecasts. The following variance ranges are reasonable
for monitoring WEPCO's fuel costs: (1) for the annual range, plus or minus 2 percent; (2) for
the monthly range, plus or minus 8 percent; and (3) for the cumulative range, plus or minus
8 percent for the first month of the year, plus or minus 5 percent for the second month, and plus
or minus 2 percent for the remaining months of the year. The method of applying those ranges,
established in prior Commission decisions for WEPCO, shall continue to be used and applied,
using the data in Appendix F for monitoring fuel costs.
Elm Road Open Cycle Cooling Water Intake Structure
The Certificate of Public Convenience (CPCN) for the ERGS was approved in docket
05-CE-130 by order dated November 10,2003, which authorized construction of two coal-fired
generation units with projected in-service dates of May 2009 and May 2010. The order in that
docket was contingent upon the Wisconsin Department of Natural Resources (DNR) issuing
required permits, which it did in 2005, based upon its understanding of the statutes at that time.
The DNR's decision was affirmed by the Administrative Law Judge (ALJ) of the Division of
Hearings and Appeals in a decision issued July 10, 2006, and in an earlier order on summary
judgment issued October 31,2005. The decision was subsequently appealed by Clean
Wisconsin, Inc. (Clean Wisconsin) to the Dane County Circuit Court. While that appeal was
pending, the United States Court of Appeals for the Second Circuit issued its decision in
Riverkeeper v. EPA, 475 F.3d 83 (2d Cir. 2007) (Riverkeeper IT). In that case, the Second
Circuit remanded the decision regarding the Phase I1 ("existing facility") rule to Environmental
Docket 5-UR-103
Protection Agency (EPA). As a result of the Riverkeeper II decision, EPA suspended the entire
Phase I1 rule, and re-instated the case-by-case best professional judgment standard for Best
Technology available determinations at existing facilities. Since the exclusion relied on by the
DNR and ALJ had been found to suffer from a procedural flaw, the Dane County Circuit Court
remanded the administrative appeal to the ALJ to re-evaluate the status of the facility in light of
Riverkeeper II.
On November 29,2007, the ALJ issued an order finding that the "new facilities" Phase I
rules applied and directed DNR to reissue or modify the Wisconsin Pollutant Discharge
Elimination System (WPDES) permit with conditions requiring the cooling water intake
structure to reflect the best technology available in conformance with standards applicable to
"new facilities." However, the ALJ denied Clean Wisconsin's request that the WPDES permit
be vacated and construction stopped noting that it was not apparent that the cooling water intake
structure " . . . whose construction is very nearly complete, could not be operated in compliance
with applicable CWIS performance standards."
Clean Wisconsin objected to the recovery of the intake-related costs at this time because
the system is currently the subject of litigation and a pending administrative proceeding before
the DNR. Clean Wisconsin contends that WEPCO's decision to take the risk and construct the
intake, notwithstanding the legal challenges, was imprudent and unreasonable. Clean Wisconsin
recommends that the Commission deny WEPCO the recovery of any part of the intake-related
costs.
In general, many of the Commission's decisions contain disputed issues which ultimately
become the subject of judicial review. The ERGS CPCN issued by the Commission approved a
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timeline that placed one unit in service in 2009 and the other unit in service in 2010. If the
company had decided not to construct ERGS based on the possibility that there could be legal
challenges, it would have put the company in a position of being imprudent for not being
consistent with the Commission's order. Further, it is not realistic to expect utilities to wait until
each and every appeal of a decision is exhausted since doing so would seriously threaten the
state's ability to protect ratepayers and provide reliable energy. There will be an opportunity for
a prudence review of the ongoing escrowed amounts related to the PTF construction of ERGS in
a future proceeding should the intake system ultimately not be approved.
Power the Future Escrow
The PTF facility leases that were approved by the Commission in dockets 5-AE-109 and
5-AE-118 provide that WEPCO pay its affiliate a return on capital with respect to outstanding
construction costs. A review of the related escrow amounts revealed that the calculations of
carrying costs on PTF-related CWIP use the end-of-month balances for both the Port
Washington and Elm Road Generating facilities. Commission staff proposed that the average
monthly balances be used in the calculation of carrying costs because the facility leases do not
specifically indicate that the end-of-month CWIP balances are to be used in the calculation of
carrying costs and it has been Commission practice to calculate carrying costs on average
monthly CWIP balances.
WEPCO contended that the approved leases specifically define how the calculations are
to be made. The Commission concurs that it is appropriate to continue using the end-of-month
CWIP balances in the calculation of carrying costs on PTF construction as currently reflected in
the PTF escrow account.
Docket 5-UR- 103
Chairperson Ebert dissents and would use average month CWIP balances going forward.
Review of the PTF-related escrow amounts also reveals that WEPCO had included gross
receipts taxes on PTF-related increases in the PTF escrow. Because it has not been Commission
practice to escrow gross receipts taxes, it is appropriate to reduce the PTF escrow balance by
$5.1 million and eliminate the related test year amortization of $1,023,000 for the difference
between actual escrowed PTF-related gross receipts tax and that which was included in previous
rate proceedings.
Village of Caledonia
In 2003, the Commission issued a CPCN for construction of ERGS. In docket 5-UR-102,
Caledonia requested to recover its "health and safety" related costs from WEPCO resulting from
the construction of ERGS for incremental police, fire, and ambulance protection; traffic and road
costs; 4 Mile Road grade separation; and payments for noise and diesel fume problems. Under
Wis. Stat. 9 196.20(7), mitigation payments that a utility makes to a municipality cannot be
recovered through rates, but payments for health and safety impacts are not considered
mitigation payments.
In docket 5-UR-102, the Commission concluded that in determining what costs would be
subject to rate recovery, it would only consider reasonable costs that can be directly linked to the
construction or operation of a power plant, exceed shared revenue support, and are legitimate
health and safety concerns. The Commission recognized in its CPCN order approving ERGS
that Caledonia will experience a variety of environmental and socioeconomic effects because of
construction. In that proceeding, the Commission approved part of Caledonia's request for the
emergency services in the amount of $600,000 per year for two years with reexamination of the
Docket 5-UR- 103
proper level of payment for Caledonia police, fire, and ambulance service, if any, at the end of
two years, based upon its actual cost for these services brought about by the continued
construction of the plant. The Commission did not find there to be sufficient evidence in the
record to support payments for Caledonia's request for payment for road maintenance and noise
and diesel fumes. In this proceeding, Caledonia has demonstrated that the need for continuation
of the police and fire service costs is the consequence of ERGS. The Commission therefore
finds it reasonable to approve emergency services in the amount of $600,000 per year for the
biennial period 2008 and 2009.
In docket 5-UR-102, the Commission also determined that the 4 Mile Road grade
separation project was a health and safety concern. The Commission indicated that before it
would grant recovery, Caledonia must demonstrate to the Commission's satisfaction that: (1) the
Wisconsin Department of Transportation funds will not assist in the grade separation, (2) the
OCR concurs as to the essential need and proper cost allocation between the railroad and the
town for grade separation, and (3) Caledonia demonstrates that is has pursued and exhausted all
other sources of governmental funding. Provided that Caledonia made this demonstration, the
Commission found it reasonable to fund up to $8 million for the project at $600,000 per year for
20 years. In this proceeding, the record demonstrates that Caledonia has satisfied the criteria in
items (1) and (3) above. Caledonia is in the process of obtaining approval from the OCR and
therefore the Commission finds it reasonable to fund up to $8 million for the project at $600,000
per year for 20 years,3 provided that final approval from the OCR is obtained. It is reasonable to
require WEPCO to notify the Commission of the final decision from the OCR regarding the
The $8 million represents the present value of annual payments of $600,000 over a 20-year period. The total and annual amounts are subject to funding from other sources.
Docket 5-UR- 103
4 Mile Road separation project. It is also reasonable for WEPCO to recover costs associated
with the 4 Mile Road Grade separation that are not funded by other sources, if any, in the future.
Electric Distribution Expense
WEPCO has proposed to significantly increase its electric distribution expense in the test
year compared to recent historical trends. Commission staff proposed a reduction of $8.9 million
after considering recent increasing electric distribution expense trends and a change in
accounting for expenses. WEPCO has identified three distribution-related initiatives that result
in an increase of approximately $9 million above and beyond the usual customary work which it
plans to undertake in 2008. WEPCO has indicated that it can do all of the work it believes is
necessary by using outside contractors for the additional projects. The record in this proceeding
demonstrates that WEPCO has a reasonable plan to ensure the undertaking of additional
distribution projects in the test year will not be done and, therefore, it is not appropriate to reduce
the company's forecasted test year distribution expenses.
Chairperson Ebert dissents. Chairperson Ebert is concerned about the significant one-
year increase and would approve $4.5 million of the distribution expense at issue in the revenue
requirement.
Shared Officer Compensation
In the last rate case proceeding, docket 5-UR-102, Commission staff reallocated shared
holding company officer time between affiliates based on an analysis of the positions those
officers may hold. Based on the record in that proceeding, the Commission determined that
(1) the allocation of shared officer salaries could result in ratepayers supporting a
higher-than-reasonable portion of executive compensation; (2) the proper allocation was
Docket 5-UR- 103
somewhere between that proposed by the applicants and by Commission staff; and (3) it was
reasonable to cut the proposed adjustment in half. The Commission directed Commission staff
to work with the applicants to arrive at a new allocation method that takes into consideration
Commission staff's concern that the applicant's method of allocating shared officer time was not
adequate.
Several meetings have taken place between company personnel and Commission staff.
Consistent with its recent holding company audit, in docket 9402-GF- 101, Commission staff
maintains that the company has not followed the master affiliated interest agreement as approved
by the Commission in docket 5-AU-105 and, therefore, decreased allocated test year executive
compensation payroll and related expense for WEPCO by approximately $1.8 million and for
WG by about $260,000, consistent with the methodology that it used in 5-UR-102. Based on the
record in this proceeding, it is again appropriate to split the proposed adjustment in half. The
Commission directed staff to work with the applicants to develop a mechanism that moves away
from requiring executives to fill out timesheets.
Commissioner Azar dissents. Because of WEPCO's lack of record keeping, she believes
it is appropriate to allocate the shared officer time and related cost based on Commission staff's
proposed allocation percentages in this proceeding. To properly allocate their time,
Commissioner Azar would also require utility executives in holding company systems to
complete accurate timesheets.
Board of Director Costs
In the test year, approximately $1.6 million of costs related to the WEC Board of
Directors were allocated to WEPCO and $360,000 of such costs were allocated to WG.
Docket 5-UR- 103
Commission staff excluded these costs, asserting that (1) they are duplicative and should remain
at the holding company level and (2) the adjustment was consistent with previous Commission
decisions.
The applicants argue that the record does not support Commission staff's claim that the
costs are duplications. In addition, the applicants maintain that both allocations were made
pursuant to the Commission approved Master Affiliated Interest Agreement.
The "Cost Allocation Methodologies" section in Attachment A- 1, List of Audit
Recommendations, of the 2003 Audit Report on Wisconsin Energy Corporation included the
following recommendation.
6. WEC should discontinue its practice of including any costs associated with its Board of Directors in its allocation of holding company system costs. It is appropriate to allocate these costs to all other entities within the WEC holding company system that do not have their own Boards of Directors, but such allocation should not include any entities which have their own Board of Directors, such as WEC's utilities.
In addition, that costs are allocated to the utility from the holding company as provided in
an affiliated interest agreement does not mean that the Commission has determined they should
be recovered in rates. Condition No. 9 of the affiliated interest order in docket 05-AU-105 states
that, "Approval of this agreement is not a determination by the Commission that the charges are
just and reasonable."
Article VIII of the Commission-approved Master Affiliated Interest Agreement states, in
part:
Wisconsin Energy (a non-utility affiliate) will experience, as the holding company, costs and expenses in performing certain activities which, in the absence of the holding company, would have been performed by the utility affiliates and other non-utility affiliates. Such costs and expenses shall be referred to as "holding company system costs."
Docket 5-UR- 103
Since WEPCO and WG have their own boards, the allocation of WEC Board of Director
costs are not holding company system costs and are duplicative. Because such costs duplicate
WEPCO Board of Director costs, it is appropriate to exclude these WEC Board of Director costs
from each utility's revenue requirement.
Economic Development Costs
In the last rate proceeding, docket 05-UR-102, the Commission authorized recovery of
economic development costs associated with customer assistance and business/load retention
activities and directed WEPCO and WG to provide a detailed explanation of economic
development activities in the next rate proceeding, including how these efforts assist in economic
development, and to quantify the direct and substantial benefits realized. In this proceeding, the
companies requested recovery for economic development costs of approximately $177,000 for
WEPCO and $20,000 for WG. The record in this proceeding provides justification of direct and
substantial benefits and, therefore, it is reasonable to include the economic development costs
associated with customer assistance and load retention in revenue requirement.
Commissioner Azar dissents because she believes that the record of this proceeding does
not provide sufficient evidence that the costs are related to load retention.
PSCW Remainder Assessment
In rebuttal testimony, the company proposed that Commission staffs estimate of the
PSCW Remainder Assessment be updated to reflect the 2008 remainder assessment as provided
in the notice that the company received on September 26,2007, because that is the bill they
actually received. That bill reflects an advance assessment for fiscal year 2008 which will be
trued up to actual remainder assessment costs next year. Recent historical data shows that the
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actual assessment factors have been decreasing annually through fiscal year 2006, which was the
most recent data available during Commission staff's audit. Commission staff used the 2006
actual factor in its calculations of the remainder assessment and did not adjust it further to reflect
the decreasing trend. Subsequent to Commission staff's audit, the fiscal year 2007 actual factor
and the fiscal year 2008 advance factor have been calculated and are reflected in the invoices that
WEPCO and WG received on September 26,2007. The actual fiscal year 2007 factor is higher
than the fiscal year 2006 factor, which in turn affects the calculation of the fiscal year 2008
advance assessment. The advance assessment factors are typically 10 percent higher than the
previous year's actual advance assessment and, therefore, the fiscal year 2008 advance is higher
than Commission staffs forecasted amounts for test year 2008. However, the fiscal year 2007
remainder assessment has been affected by one-time adjustments that will not occur in 2008.
Therefore, the record in this proceeding shows that the data used by Commission staff in its
estimate of the 2008 PSCW remainder assessment is reasonable and should not be adjusted.
Transmission Costs
WEPCO filed its case assuming the ATC transmission escrow continues though the
biennial period. However, recent rate case decisions in dockets 6680-UR-114, 3270-UR-114,
and 6690-UR-118 eliminated escrow treatment for ATC and MIS0 Day 1 costs. To be
consistent with its treatment of other Wisconsin investor-owned utilities, the Commission finds
that it is reasonable to eliminate the transmission escrow in this proceeding after December 3 1,
2007. Any costs included in the transmission escrow prior to December 31, 2007, that are
related to MIS0 Schedules 16 and 17 should be excluded in the true-up of final escrowed costs
Docket 5-UR- 103
through 2007 in the next rate proceeding because they were included in base rates per the order
in docket 5-UR-102, dated January 26,2006.
According to the most recent update provided by ATC to its customers on October 4,
2007, total company ATC-related transmission expense is estimated at $215.2 million for 2008,
and $232.9 million for 2009. Adjusting for the updated 2008 ATC transmission expenses and
levelizing the updated ATC estimates for 2008 and 2009 ATC transmission expenses results in
additional expense of $9.3 million on a Wisconsin retail basis.
Due to the significant change in the updated ATC transmission estimates for 2008 and
2009 and the fact that the Commission has allowed other utilities to address increases in external
transmission expenses in "re-opener" cases or through other mechanisms, the Commission finds
it reasonable to levelize the estimated 2008 and 2009 ATC transmission expenses based on the
October 4,2007, updated ATC budgets for 2008 and 2009. It is reasonable for WEPCO to defer
any refunds from ATC associated with its network service fees until such refunds can be
returned to ratepayers.
Gross Receipts Tax
In its filing, WEPCO proposed an adjustment to electric revenue requirement in the
amount of $2.8 million to levelize gross receipts tax that would occur in 2009 as a result of the
rate increase in 2008. The company subsequently proposed that an increase in 2009 gross
receipts tax expense of $10 million or more as a result of the 2008 rate increase would constitute
a known and significant change that should be included in the test year on a 2008-2009 levelized
basis or as part of a step increase effective January 1,2009.
Docket 5-UR- 103
Consistent with current Commission practice, and considering that 2009 gross receipts
tax expense will not increase by $10 million as a result of the 2008 rate increase, the
Commission finds it appropriate to deny an adjustment to normalize the 2008 and 2009 gross
receipts tax expense estimates.
Sale of Point Beach
On September 25,2007, the Commission issued its Final Decision in docket 6630-EI-113
approving the transfer of ownership and operational control of Point Beach to FPL Energy Point
Beach, LLC. The current estimate of the net proceeds from the transaction total $882 million, or
approximately $761 million on a Wisconsin retail basis. Based on the $761 million and the
estimated average investment interest rate of 5.28 percent as discussed later in this Final
Decision, the estimated interest earned on the net proceeds to be returned to Wisconsin retail
customers is $42 million, for a total amount of funds to be returned to Wisconsin retail customers
of $803 million. Of this amount, as discussed previously in this Final Decision, $85 million shall
be used to offset regulatory assets, and $315.9 million in 2008 and $240.7 million in 2009 shall
be returned in the form of billing credits. WEPCO shall use escrow accounting for the monies
from the sale of Point Beach that have not yet been refunded to WEPCO's customers.
Transaction costs
WEPCO is seeking recovery of transaction costs related to the sale of Point Beach,
currently estimated to be $58.6 million. Transaction costs fall into three categories: costs to
complete the transaction, curtailment/settlement costs, and costs related to the termination of the
Nuclear Management Company (NMC). Transaction costs such as governmental,
Docket 5-UR- 103
curtailment/settlement costs, and costs related to the termination of NMC, were necessary for the
sale to be finalized.
Because the entire gain on the sale of Point Beach is being returned to customers,
shareholders receive no gain from the transaction and, thus, there is nothing against which to
apply any of the costs. The sharing of transaction costs between customers and shareholders as
was done in the sale of the Kewaunee Nuclear Power Plant (KNPP) is inappropriate because
there was a loss in the KNPP sale and there is a large gain in the Point Beach sale. Given that
the gain was not proposed to be shared between shareholders and customers, full recovery of the
transaction and transition costs is reasonable. Regarding NMC-related costs, these are the
termination payment and recovery of investment in the NMC that needed to occur in order to
complete the transaction. One of those costs is the diminution in the value of the equity interest
that WEPCO's affiliate WEC Nuclear held in NMC. The transaction could not have closed
without contractually obligated exit fees and the loss of the investment by an affiliate of
WEPCO. Therefore, recovery of 100 percent of the sale of Point Beach transaction costs is
reasonable provided that such costs, upon audit, are found to be reasonable and not of the type
normally excluded for ratemaking purposes. In addition, WEPCO is authorized to transfer to
WEC Nuclear an amount sufficient to fully compensate WEC Nuclear for that diminution in
value.
Jurisdictional Allocators
WEPCO proposed allocating the refund of decommissioning trust fund monies to the
jurisdictions using a forward-looking jurisdictional allocation factor based on generation-level
energy. Commission staff testified that the refund of the non-qualified decommissioning trust
Docket 5-UR- 103
fund monies represents a refund of money previously collected from ratepayers of all of the
company's jurisdictions. The use of a historical jurisdictional demand allocator would allow for
the money to be refunded to the jurisdictions in the same proportion as it was collected.
Therefore, it is reasonable to use a historical jurisdictional allocator for the refund of the
decommissioning trust fund based on a historical decommissioning fund balance and
85.2 percent of decommissioning trust fund monies should be allocated to the Wisconsin retail
jurisdiction.
Indemnity claims and a jurisdictional allocation reserve contingency funds
WEPCO proposed to withhold proceeds from the sale of Point Beach for two
contingencies - indemnity claims and a jurisdictional allocation reserve. The first contingency is
approximately $30 million and it relates to indemnification matters identified in the Point Beach
Asset Sale Agreement (ASA). The second contingency of $40 million relates to the
jurisdictional allocation of the net proceeds.
Regarding the $40 million jurisdictional allocation reserve, the Wisconsin Industrial
Energy Group (WIEG) suggests that it is essential that the Commission retain jurisdiction. If the
company's other jurisdictions claim more of the proceeds than the company proposes, for
whatever reason, the Commission is not bound to "make-up" the difference simply because there
is a difference. The Commission should not require that Wisconsin retail ratepayers essentially
backstop the allocations approved in the other jurisdictions.
Regarding the $30 million contingency, the ASA contains certain normal and customary
indemnification provisions that would require WEPCO to pay the buyer if certain events took
place subsequent to the sale of Point Beach. While this contingency is based on contractual
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provisions in the ASA, the ASA is unclear as to which time period the contingency will apply.
In addition, CUB maintains that the company has not provided an analysis that justifies this
amount; therefore, it should be disallowed.
The proceeds from the sale of Point Beach are being returned to customers over a
three-year period. As a result, sufficient funds will be available to fund the two proposed
contingency funds and WEPCO's proposal is unnecessary. If in the future WEPCO seeks
recovery of indemnity claims or excess refunds due to jurisdictional allocation decisions by the
three jurisdictions, Wisconsin retail, Michigan retail, and the Federal Energy Regulatory
Commission, WEPCO can make this request in a future proceeding and demonstrate the need for
recovery.
Segregated external trust fund
In the Interim Decision in this proceeding, WEPCO was authorized to use a segregated
external trust fund for the proceeds from the sale of Point Beach. A reasonable estimate of
WEPCO's average investment interest rate to be used for this external trust fund for the test year
is 5.28 percent. In the Interim Decision, the Commission found that:
1. It is reasonable to establish an unequivocal regulatory obligation of the Company to refund all of the net proceeds and accrued interest of the segregated fund to customers in accordance with a plan approved by the Commission.
2. A plan for distributing the net proceeds will ultimately be approved by the Commission in the rate case order in this docket.
3. The net proceeds from the sale shall be segregated from internal funds of the utility, i.e., that there be no co-mingling of such funds with other utility funds.
4. The fully segregated fund shall remain under the oversight of the Commission until the entirety of the fund is fully distributed to customers.
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As discussed in the Interim Decision, a taxpayer may be able to exclude from gross
income gains on the sale of assets if the funds the taxpayer receives are beyond its dominion and
control and are subject to an unequivocal regulatory obligation to pay the gain to its customers.
Thus, the taxpayer may not have the unrestricted use, dominion and control over the funds, and
may not receive any economic benefit from the funds.
Using the proceeds from the gain on the sale of Point Beach to offset regulatory assets
may be considered an economic benefit to WEPCO in that WEPCO is allowed to keep some of
the proceeds for its own use. Therefore, the amounts to be returned to ratepayers that relate to
the book gain on the sale of Point Beach and the tax gain realized on the non-qualified trust fund,
plus interest thereon, shall be satisfied by bill credits only. This treatment confirms the
understanding set forth in the Interim Decision that all proceeds from the sale of Point Beach
must be returned to WEPCO's ratepayers.
Point Beach relicensing costs
In docket 6630-EI-113, the book value of Point Beach as of August 3 1,2007, included
$18.4 million associated with relicensing the Point Beach units. In its December 22, 1995, order
in docket 05-EP-7, Order Point 4.3, and in Appendix D of the Commission's January 20, 1999,
order in docket 05-EP-8, the Commission adopted six relicensing principles. The first
relicensing principle states that, "There shall be no relicensing costs included in rates until the
Commission approves relicensing." Despite the first principle, WEPCO proceeded with
relicensing the Point Beach units without specific Commission approval and, therefore, at its
own risk.
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In this current rate case, WEPCO is proposing to reduce the needed rate increase by the
net proceeds from the sale. By including the relicensing capital costs in the net book value of the
plant sold, the amount paid by WEPCO's customers will be higher and WEPCO will be
recovering these relicensing capital cost in rates.
In docket 6630-El-1 13, Commission staff testified that when comparing the sale of Point
Beach to the sale of other nuclear power plants, with license renewal complete, or nearly
complete, the value of Point Beach, to a prospective buyer, has been or was increased.
Therefore, the sales price covers the relicensing capital costs, and relicensing costs should be
recovered in rates because there is a net benefit to customers since the relicensing costs increased
the value of Point Beach to prospective buyers.
Carrying Costs on Elm Road CWIP
WIEG argues that the question for the Commission is not whether WEPCO must pay
WE Power for the carrying costs on CWIP that is being billed to WEPCO as part of the Facility
Lease, but instead, whether WEPCO should recover that payment currently from ratepayers or
whether it should defer the costs and amortize them over the lives of the Facility Leases.
WIEG provides two reasons for the Commission to conclude that WEPCO should
capitalize these carrying costs on CWIP and recover them over the life of the asset. First, these
carrying costs are a cost with future value and are not current or period costs. Second, such a
practice involves an intergenerational transfer of cost responsibility to ratepayers that currently
receive no benefit from those facilities.
WIEG recommends that instead of allowing WEPCO to recover these costs in current
rates, the Commission should direct WEPCO to defer the costs and amortize them to expense
Docket 5-UR- 103
over the 30-year lives of the Facility Leases. This way, according to WIEG, costs of
construction will be paid for by the generations of ratepayers that are served by these assets. A
witness for Lowe's and Wal-Mart agreed with WEG.
WEPCO argues that WIEG ignored the Commission's decisions in the Power the Future
proceedings where it determined that, as provided in the facility leases, WEPCO should pay the
carrying costs on CWlP during the construction period. In addition, WEPCO maintained that
WIEG's and Lowe'stWal-Mart's argument ignores Wisconsin's leased generation statute, Wis.
Stat. 3 196.52(9). What WIEG characterized as a return on Elm Road CWlP is the "Monthly
Return on Capital Amount" which WEPCO is obligated to pay to WE Power under the terms of
the Commission-approved Elm Road facility leases. Wisconsin Statute 3 196.52(a)(b)(ll)
provides that a public utility that has entered into a leased generation contract that has been
approved by the Commission must be permitted to recover in rates the payments it makes under
the leased generation contract.
Consistent with the Commission's decision in the Power the Future proceedings and
Wisconsin's leased generation statute, Wis. Stat.§ 196.52 (9), WEPCO may continue treating
carrying costs on Elm Road Units 1 and 2 CWIP as a current expense through the PTF escrow.
Recovery of Elm Road Lease Costs
WEPCO's requested revenue requirement includes the annual average of its projected
Elm Road 1 lease and other costs that will be paid to WE Power in 2008 and 2009, subject to
escrow accounting. Because WEPCO assumes that Elm Road 1 will be commercially available
first in May 2009, the company's revenue proposal results in one-half of its projected costs for
2009 being included in its revenue requirement for each of the years 2008 and 2009. WIEG
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argues that WEPCO's proposal results in the premature recovery of 2009 costs during 2008, and
the under-recovery of 2009 costs in 2009. WIEG further argues that there is no compelling
reason to provide WEPCO with this premature recovery and, therefore, the Commission should
reject it in favor of a second-step rate increase in 2009.
The Commission finds that levelizing the costs over two years is an appropriate
methodology. It is therefore appropriate to continue recovery of the Elm Road Lease and other
expenses through the PTF escrow in 2008.
Environmental Trust Financing Deferral
In its filing, WEPCO included a deferred asset balance in the amount of $2,595,000 for
environmental trust financing (ETF) and test year amortization expense of $5 19,000.
Commission staff eliminated this deferred asset balance and amortization expense because it did
not find evidence that the deferral was authorized or any support for why recovery of such costs
should occur. The costs that the company deferred pertain to third party costs incurred in the
environmental trust financing request from docket 6630-ET-100 that was ultimately withdrawn.
The company subsequently agreed to the removal of the amortization expense, but requested that
the deferred asset balance remain for possible recovery at a later date because it believes that the
information gained from third parties during its first ETF application can and should be applied
to a future asset securitization under 2003 Wisconsin Act 152.
Since the Commission has strongly encouraged companies to explore the use of
environmental trust financing, the Commission finds it is reasonable to allow WEPCO to defer
$2,595,000 of ETF costs incurred during the proceeding in docket 6630-ET-100 until potential
Docket 5-UR- 103
future financing at which time the Commission can determine whether the costs have in fact
facilitated that future financing.
Production Tax Deduction
In its December 20,2004, order in docket 05-GF-143, the Commission directed WEPCO
and other affected utilities to defer the revenue requirement impacts, including carrying costs
calculated at the authorized pre-tax weighted average cost of capital, resulting from the Jobs
Creation Act until future rate proceedings. After Commission staff's audit was completed in this
proceeding, it was discovered that the amortization of the deferred tax benefit associated with the
domestic production deduction under Section 199 of the Internal Revenue Code, which was
enacted as part of the American Jobs Creation Act of 2004, had not been included in the
calculation of the revenue deficiency for WEPCO's electric operations. Commission staff
indicated that its review of the estimates and calculations provided by the company would not be
complete in time for the hearing in this proceeding. In addition, a number of issues had arisen
pertaining to the deductions that need to be more fully reviewed.
For the purpose of this proceeding, Commission staff described three alternative
approaches to dealing with the deferred deduction. WEPCO requested that the Commission
implement the alternative that would include $9.7 million of production tax benefit as a
reduction to income tax expense ($16.1 million total company reduction in revenue requirement)
to reflect an estimate for 2008 of the production tax benefit and to amortize over four years
Wisconsin Electric's estimated deferred tax benefit balance as of December 31,2007. WEPCO
agrees with Commission staff that the company's next rate proceeding should address the
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appropriate amount of production tax benefit and associated carrying costs for 2005 through
2009.
The Commission finds that implementation of the second alternative as requested by
WEPCO is reasonable because this alternative addresses both the estimated balance as of
December 3 1,2007, and the estimated future production tax deductions. It is also reasonable to
address the appropriate amount of production tax benefit and associated carrying costs for 2005
through 2009 in the company's next rate proceeding to accommodate a full review of this
deduction.
Point Beach Extended Outage
On April 1,2005, Point Beach Unit 2 entered its scheduled refueling outage. In addition
to refueling the reactor, the reactor vessel head (RVH) was also scheduled to be replaced. On
April 6,2005, Nuclear Regulatory Commission (NRC) inspectors identified that the NMC had
not considered the results of a 1982 RVH drop analysis for the original head, during preparations
for the replacement of the Unit 2 RVH. The 1982 RVH drop analysis had been performed in
response to a request from the NRC. A review by the NRC inspectors revealed that WEPCO
(plant owner and also plant operator until the operations function was turned over to NMC) had
not incorporated this analysis into the FSAR in 1983, as required by 10 CFR 50.71 (e) and as a
result, may not have taken all of the appropriate contingencies and precautions when moving the
original Unit 1 and Unit 2 heads during refueling outages since the analysis was completed in
1982. The NRC determined that WEPCO and NMC had numerous opportunities since 1983 to
incorporate this analysis into the final safety analysis report (FSAR) but failed to identify and
capitalize on these opportunities until the problem was identified and brought to its attention in
Docket 5-UR- 103
2005 by the NRC. The NRC required that the RVH drop analysis issue be addressed prior to the
installation of the new RVH. Addressing the RVH drop analysis issue to NRC's satisfaction
resulted in the outage being extended by 41 days.
By letter dated May 27, 2005 (docket 6630-GF-118), WEPCO was allowed deferral
accounting for the costs associated with the Spring 2005 Point Beach Unit 2 extended outage.
The May 27,2005, letter stated that the authorization was for accounting purposes only and did
not bind the Commission to any specific treatment for this item in any future proceeding
involving rates or other matters before the Commission. The amount of deferral for which
WEPCO requests recovery is $22.1 million for the Wisconsin jurisdiction.
WEPCO argues that the Commission should authorize recovery of costs related to the
extension of the Point Beach refueling outage because the outage was a result of NRC reversing
a 20-year-old position when, without warning, it required nuclear plant operators to perform
RVH drop analyses. Prior to this decision, the NRC had consistently and regularly informed
operators that they were not required to perform such analyses. This decision was first
implemented at Point Beach, catching the NMC, which operated the plant at the time, unaware in
the midst of a refueling outage at Point Beach Unit 2. The end result of the NRC's requirement
was that the refueling outage was extended and WEPCO was forced to purchase replacement
power during the extension. WEPCO states that it acted prudently in relying on the NRC's long-
held position that RVH drop analyses were not necessary.
CUB argues the Commission should disallow any recovery of WEPCO's costs associated
with the extension of the Point Beach outage in Spring 2005. CUB states the Commission
should reject WEPCO's request for rate recovery of the deferral because the unplanned extension
Docket 5-UR- 103
was due to events within WEPCO's control. CUB argues that in the years leading up to the
outage, third parties like Westinghouse and the NRC presented WEPCO with key opportunities
to address the underlying problem that caused the outage, but WEPCO ignored them. CUB
states that WEPCO's argument that the extension of the outage was caused by the NRC
reversing "its twenty-year old position when, without warning, it required nuclear plant operators
to perform RVH drop analyses," should be rejected for several reasons: (1) NRC did not
"reverse" any position relevant to the cause of the extension of the outage; (2) the outage
extension was actually caused by WEPCO's failure to update its FSAR; and (3) it was
unreasonable for WEPCO to assume that NRC was going to let stand, as the last official word
from the company, an RVH drop analysis that concluded that "severe damage" could result,
especially when WEPCO would be replacing the original RVH with a vessel head package more
than 13 tons heavier than originally analyzed.
The Commission is not persuaded by WEPCO's argument and, based on a standard of
prudence, determines that it is reasonable to disallow WEPCO recovery of the $22.1 million
deferral of the costs relating to the Spring 2005 Point Beach Unit 2 extended outage.
Commissioner Meyer dissents. Commissioner Meyer would allow WEPCO recovery of
half of the costs associated with the Spring 2005 Point Beach Unit 2 extended outage.
Deferral Issues
Both WEPCO and WG have proposed amortizing regulatory assets (increases rates) over
five years and regulatory liabilities (decreases rates) over two years. One exception to this
general approach is the proposed one-year amortization of the regulatory assets for bad debt
expense, the Point Beach outage extension, coal conservation, and the Pleasant Prairie forced
Docket 5-UR-103
outage. This one-year amortization would be financed by the one-time application of a portion
of the Point Beach sale proceeds. In addition, WEPCO proposes to accrue carrying costs on all
deferral and escrow account balances at its pre-tax overall cost of capital.
CUB maintains that the Commission should disallow a portion of the company's
deferrals because doing so would not cause WEPCO serious financial harm. As a result, CUB
maintains that almost $50 million of deferrals from 2003 through 2005 should be written off.
CUB believes that a reasonable threshold of "serious financial harm" would occur if a utility's
return on equity was more than 200 basis points lower than its allowed rate of return in a
particular year. WEPCO disagrees with CUB'S proposal to disallow a portion of the company's
deferrals because two hundred basis points equals approximately $50 million of net income and
represents almost 20 percent of WEPCO's earnings. WEPCO is concerned that removing
20 percent of investors' expected return would drive down the company's stock price and its
market value, would damage coverage ratios and would result in increased financing costs.
WEPCO also maintains that CUB misinterprets the Commission's decision in docket
6690-UR- 117 in which the Commission disallowed a portion of deferral recovery which was
based on Wisconsin Public Service Corporation (WPSC) earning in excess of its authorized
return. WEPCO maintains that disallowing deferred costs where, even without recovering those
costs, the utility will earn in excess of its authorized return is significantly different from
disallowing deferred costs as proposed by CUB. In addition, WEPCO maintains that its two
largest deferrals are for PTF and transmission costs that use escrow accounting and should not be
subject to any earnings test.
Docket 5-UR- 103
The record in this proceeding does not support disallowing amortization of deferred
balances based on setting a boundary on the return on equity below the allowed return.
WIEG supports a six-year amortization period for all of WEPCO's regulatory assets to
accommodate the biennial timeframe of rate proceedings. Given the magnitude of WEPCO's
request, WIEG believes it most appropriate to amortize these costs over a six-year period as
compared to a shorter period, in order to minimize the effect on WEPCO's revenue
requirements. WIEG indicates that it is particularly concerned about the one-year amortization
that WEPCO proposes to pay-down with Point Beach sale proceeds. WIEG sees no compelling
reason for a one-time amortization of these costs, and it does not believe that WEPCO has
provided any compelling reason. WIEG maintains that the availability of Point Beach sale
proceeds should not drive the length of an amortization period as WEPCO is seeking to do.
Regarding WIEG's suggestion to use six-year amortization periods, WEPCO believes all of its
proposed amortizations of regulatory assets and liabilities are reasonable and it urges the
Commission to approve them. WEPCO points out that in the Commission's Final Decision in its
last rate proceeding, the Commission expressed concern regarding the build-up and size of
WEPCO's regulatory assets. In that Final Decision the Commission indicated that it was
concerned about the deferrals and escrow balances that are on WEPCO's books right now. The
Commission stated its belief that these balances are similar to an outstanding loan ratepayers are
going to have to pay in the future.
Consistent with the Commission's concern stated in the previous rate proceeding in
docket 5-UR-102 regarding the build-up and size of WEPCO's regulatory assets, it is reasonable
to offset $85 million of regulatory assets related to escrowed bad debts, deferred coal
Docket 5-UR- 103
conservation costs, and deferred Pleasant Prairie forced outage costs with proceeds from the sale
of Point Beach. It is also reasonable to amortize the remaining regulatory asset balances over six
years consistent with WIEG's proposal to accommodate the biennial rate case timeframe and
minimize overall revenue requirement. It is reasonable for all authorized amortizations to begin
as of the effective date of this order.
Commission staff adjusted the cost of capital to provide a return, calculated at the
utility's short-tern debt rate on three regulatory assets. They are the PTF escrow, the MIS0
deferral, and the coal conservation deferral. Commission staff made these adjustments consistent
with previous Commission authorizations. The Commission has authorized WEPCO to earn a
return calculated at the company's authorized short-term debt rate on its PTF escrow in several
dockets, most recently in WEPCO's last rate proceeding.4 Similarly, the Commission authorized
WEPCO to earn a return calculated at the company's authorized short-term debt rate on its
MIS0 deferral in its August 30,2007, Final Decision in docket 5-EI-139 on pages 22 and 23.
Finally, the Commission authorized WEPCO to earn a return at the company's authorized
short-term debt rate on its coal conservation deferral in the August 29,2005, letter from the
Administrator of the Commission's Gas and Energy Division to WEPCO in docket
6630-GF-120. Commission staff testified to a number of instances in recent utility rate cases
where deferral balances continued to earn carrying costs at the short-tern debt rate in rate cases
rather than being included in working capital and earning a return based on the pre-tax cost of
capital. WEPCO indicated that unamortized deferral balances are a part of the company's
4 The Commission's January, 26, 2006, Final Decision in docket 5-UR-102, pages 19-21.
Docket 5-UR- 103
working capital and thus should earn a return at the weighted cost of capital. WIEG indicated its
support for a return on all regulatory assets calculated at the short term debt rate.
The Commission finds it reasonable to continue to accrue carrying costs on deferred
balances at the weighted cost of capital, except for the accrual of carrying costs on the PTF
escrow, MIS0 deferral, and coal conservation deferral that have been authorized at WEPCO's
short-term debt rate in previous proceedings.5
Commissioner Azar dissents. She would authorize accrued carrying costs at the weighted
cost of capital.
A list of all deferral and escrow accounts is shown in Appendix G.
Discontinuance of Escrow Accounting for Nitrogen Oxide (NO,) Reduction Compliance Costs
The NO, escrow account as filed by the company includes no escrowed activity
forecasted in the test year. Consistent with decisions in dockets 6680-UR-112 and
6690-UR-115, the Commission finds it appropriate to discontinue authorization of escrow
accounting for NO, reduction compliance-related costs as of the start of the 2008 test year. The
remaining December 31, 2007, estimated balance of $33,000,000 is to be amortized over six
years.
Cash Balances
During its audit, Commission staff asked the company to provide specific reasons why
either WEPCO or WG would need to maintain a cash balance. The company did not provide
specific reasons in response to such data requests. At the hearing in this proceeding, the
Costs associated with the Point Beach Outage Extension have been disallowed in this proceeding and, therefore, the carrying costs related to such costs are moot.
Docket 5-UR- 103
company witness provided more specific information about why the companies need to maintain
a cash balance. Since this information was not provided until the hearing, Commission staff did
not have an opportunity to further examine the reasons given. It is reasonable, therefore, to
forecast the average cash balance during the test year as zero for both companies.
Need for a Complete Forecast of the Balance Sheet
During the audit, the company was not able to provide a complete forecast of its balance
sheet for the bridge year (2007) or the test year for either WEPCO or WG in response to data
requests. Since the Ratio of Rate Base to Capital provides a return on working capital, it would
be reasonable to expect the company to provide a complete forecast of its balance sheet,
including working capital accounts, in its rate filings. Therefore, in future rate filings, the
Commission finds it reasonable to direct WEPCO and WG to file a complete forecast of its
balance sheet on a monthly basis for the entire forecast period, consisting of all months from the
actual starting point through the test year.
Summary of Operating Income Statements at Present Rates
In addition to the findings regarding the specific items discussed in this Final Decision,
all other uncontested Commission staff adjustments to WEPCO's filed electric, natural gas, and
steam operating income statements and WG's natural gas operating income statements are
appropriate. Accordingly, the estimated WEPCO electric, natural gas, and steam operating
income statements and WG natural gas operating income statements at present rates for the 2008
test year, which the Commission finds reasonable for the purpose of determining the revenue
requirements in this proceeding, are as follows:
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Operating Revenues: Sales Revenues Other Operating Revenues Total Operating Revenues Operating Expenses: Fuel Purchased Gas Expense Other Production Expenses Steam Generation Generation Transfer Gas Supply and Storage Expenses Transmission Expenses Distribution Expenses Customer Accounts Expenses Customer Service Expenses Administrative & General Expenses Total Operation & Maintenance Expenses Depreciation/Amortization Expense Regulatory Amortizations-Tax Items Taxes Other Than Income Taxes Income Taxes Deferred Tax Expense Investment Tax Credits Total Operating Expenses Net Operating Income
WEPCO Downtown WG
Natural Milwaukee Wauwatosa Natural Electric Gas Steam Steam Gas (oooa) (000's) (ooo's) (000's) (000's)
$2,259,086 $659,179 $1 9,158 $13,626 $903,935 90.204 2.207 -97 0 6.343
Net Investment Rate Base
Carrying Costs on Gas in Storage Inventory
The companies' estimated carrying costs on gas storage inventories for the 2008 test year
are $4,343,000 for WG and $6,989,000 for WE-GO. The companies proposed to recover the
carrying cost of gas-in-storage through the PGA mechanism, which would guarantee that the
companies would earn the authorized return on their associated investment in stored natural gas.
The companies' position is that with today's volatility in the natural gas market, it is
unreasonable to hold the utility and its shareholders responsible for changes in the carrying costs
57
Docket 5-UR- 103
on the gas inventory when the PGA mechanism could be used to accommodate fluctuations in
natural gas costs and inventory levels.
The companies' proposal is not consistent with the Commission's generic order regarding
the PGA mechanism, docket 05-GI-106 (November 8, 1996); the Commission's decision in
docket 6690-UR-111, in which the Commission denied a similar request by WPSC; the
Commission's decision in docket 5-UR-102, in which the Commission last denied the
companies' request; or with past and present rate treatment for all other Wisconsin natural gas I.
utilities. In docket 05-GI-106, the Commission found that "most LDCs [local distribution
companies] can no longer claim to be mere 'price takers' but rather must be viewed as players
whose expertise, judgment, and dedication are able to significantly affect the delivered price they
pay for gas supplies."6 Therefore, it is reasonable to recover the carrying cost of gas in storage
through margin rates given the forward-looking rate setting of margin rates versus guaranteeing
the return through the PGA mechanism.
The companies also requested that a final order reflect actual storage injection costs to
date and updated NYMEX gas price forecasts for the test year injections and that the carrying
costs be calculated using the final authorized cost of capital for each utility if the Commission
rejects their request to recover carrying costs on storage gas through the purchased gas
adjustment clause. The companies' proposal is not consistent with the Commission's March 23,
2003, decision in docket 6690-UR-114, in which WPSC requested that it be allowed to update
gas prices, the cost of natural gas-fired electric generation, uncollectible accounts expense,
Wisconsin remainder assessment, and gross receipts tax so that the updated information could be
-
Order issued in docket 05-GI-106, page 6.
Docket 5-UR- 103
reflected in the test year. Order Point 8, in that order states that "For revenue requirement
purposes, WPSC shall file changes in the cost of natural gas-fired electric generation as a result
of the updated NYMEX strip, without additional adjustments." The Commission decision in this
docket is consistent with its decision in docket 6690-UR-114.
Summary of Average Net Investment Rate Bases
In addition to the findings regarding the specific items discussed in this final decision, all
other uncontested Commission staff adjustments to WEPCO' s filed electric, natural gas, and
steam and WG's natural gas average net investment rate bases are appropriate. Accordingly, the
estimated WEPCO electric, natural gas, and steam and WG natural gas average net investment
rate bases for the 2008 test year, which the Commission finds reasonable for the purpose of
determining the revenue requirements in this proceeding, are as follows:
WEPCO
Utility Plant in Service Less: Accumulated Reserve for Depreciation Net Utility Plant Add: Natural Gas in Storage Fuel Inventory Materials and Supplies Less: Accumulated Deferred Income Taxes Customer Advances - Net Average Net Investment Rate Base
Downtown WG Natural Milwaukee Wauwatosa Natural
Electric Gas Steam Steam Gas (000's) (000's) (000's) (000's) (000's)
$5,893,663 $863,307 $66,498 $28,120 $1,213,545
Demand-Side Management
Conservation Budget
Under Act 141, a Wisconsin electric utility may administer three types of energy
efficiency programs: (1) programs directed to large commercial, industrial, institutional, or
Docket 5-UR- 103
agricultural customers in its service territory that will reduce dollar-for-dollar its contribution of
1.2 percent of annual operating revenues that would otherwise fund statewide energy efficiency
(Focus on Energy) programs; (2) statutorily defined "ordered programs" that also reduce dollar-
for-dollar the utility's contribution to Focus on Energy programs; and (3) voluntary energy
efficiency programs that may serve any customer sector, but does not reduce the utility's
contribution to Focus on Energy programs. In docket 05-CE-130, the Commission required
WEPCO to implement energy efficiency programs to capture 55 MW of demand reduction by
the end of 2008. Additionally, in dockets 6630-GF-121 and 6650-GF-103, the Commission
approved voluntary natural gas energy efficiency programs, through 2007, for WEPCO and WG.
In order to continue these programs through 2009, We Energies requested authority in this
proceeding to spend $12.6 million for voluntary electric energy efficiency programs in 2009 and
to spend $6.1 million in 2008 and $6.3 million in 2009 for voluntary natural gas energy
efficiency programs.
Wisconsin Administrative Code ch. PSC 137 specifies the process and requirements for
approval of the various types of energy efficiency and renewable resource programs in the state.
Wisconsin Administrative Code 5 PSC 137.08 specifically addresses the process and
requirements for Commission approval of voluntary utility programs, such as those for which
We Energies is requesting funds. We Energies has not satisfied the requirements for approval of
its voluntary utility programs. For instance, We Energies did not provide annual and multi-year
performance targets, portfolio and program level cost-effectiveness analyses, administrative and
program delivery budgets for the first year of program operation, proposed reporting schedules, a
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description of how We Energies will coordinate its programs with Focus on Energy programs,
and evaluation, measurement, and verification plans.
Although We Energies has not satisfied the requirements for approval of its requested
voluntary programs, the Commission finds it appropriate to include We Energies' funding
requests in determining the appropriate 2008 conservation escrow budgets. Including the
funding request in the 2008 conservation escrow budget ensures timely recovery of appropriate
expenditures, should the Commission approve We Energies' voluntary energy efficiency
programs. The appropriate 2008 conservation escrow budgets are $33,954,000 for WEPCO
electric, $9,152,000 for WEPCO natural gas, and $12,664,000 for WG. The test year expenses
reflect 2008 and 2009 levelized expenditures.
The level of escrowed conservation expense included in the test year revenue
requirements for WEPCO is $39,528,000 for electric utility operations and $10,692,000 for
natural gas utility operations. The $39,528,000 for electric operations consists of 2008 and 2009
levelized expenditures of $39,683,000 and a ($155,000) annual amortization of the estimated
December 31,2007, underspent balance. The $10,692,000 for natural gas operations consists of
2008 and 2009 levelized expenditures of $9,358,000 and a $1,334,000,000 annual amortization
of the estimated December 3 1,2007, overspent balance. WEPCO's electric load management
expenditures previously recorded in the conservation escrow and forecasted at $1,136,000 in
2008 have been transferred to a non-escrow expense in the test year.
The level of escrowed conservation expense included in the test year revenue
requirements for WG is $15,660,000 and consists of 2008 and 2009 levelized expenditures of
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$12,948,000 and a $2,712,000 annual amortization of the estimated December 3 1, 2007,
overspent balance.
It is appropriate to address Commission approval of We Energies' proposed voluntary
electric and natural gas programs outside of this rate proceeding. It is important that the same
standards be used in approving and judging all energy efficiency programs in the state,
regardless of the entity delivering the programs. To that end, We Energies should continue to
work with Commission staff in its development of voluntary utility programs and information in
support of the programs. It is also important that any voluntary programs be coordinated with
the Focus on Energy Programs. We Energies should work with the Focus on Energy program
administrator and Commission staff to ensure adequate coordination.
Measures of Success for the Test Year
In docket 05-BU-100, the Commission determined energy savings goals are not
appropriate for all customer service conservation activities, but that some measure of success is
needed to ensure the customer service conservation funds spent by utilities provide a useful
service to ratepayers. The Commission also deemed it appropriate for Commission staff to work
with each utility to develop appropriate measures of success for customer service conservation
activities. We Energies did not propose measures of success for its 2008 customer service
conservation activities. It is appropriate for We Energies to work with Commission staff to
develop measures of success for 2008.
Pro Forma Rate of Return
The adjusted net operating income at present rates for the test year ending December 3 1,
2008, results in a rate of return on average net investment rate base of (0.20) percent for WEPCO
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electric operations, 8.55 percent for WEPCO natural gas utility operations, 5.48 percent for
WEPCO Downtown Milwaukee steam utility operations, and 2.94 percent for WEPCO
Wauwatosa steam utility operations. The adjusted net operating income at present rates for the
test year ending December 3 1,2008, results in a rate of return on average net investment rate
base of 8.53 percent for WGC natural gas utility operations.
FINANCIAL
Financial Capital Structure and Dividend Restriction
The long-term range for WEPCO's common equity ratio, on a financial basis, found
reasonable in WEPCO's last rate case, was 48.5 to 53.5 percent common equity. This range is
consistent with guidelines for maintaining an "A" credit rating for companies with WEPCO's
business risk profile ranking of 4. No party in this proceeding objected to the continuance of the
current range. The Commission agrees that the current long-term range of 48.5 to 53.5 percent
for WEPCO's common equity ratio, on a financial basis, continues to be reasonable and provides
adequate financial flexibility at this time. The exact level of the common equity ratio within that
range should not be static, but rather should dynamically reflect the circumstances facing
WEPCO at a given time.
The applicant proposed that the Commission find the long-term range of 48.5 to
53.5 percent reasonable for WG. The Commission reviewed several long-term equity range
options, including the 45.0 to 50.0 percent range found reasonable in docket 6650-GR-111. One
range option was based on the total debt to total capitalization guidelines for Standard and Poor's
(S&P) "A" credit rated utilities with WG's business risk profile rank of 2. While the applicant
argues that the higher range option is needed to support its credit ratings, Commission staff
presented testimony that WG requires less equity than WEPCO due to WG's lower business risk
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compared to WEPCO. The Commission remains committed to healthy utilities. A long-term
range of 45.00 to 50.00 percent for WG's common equity ratio, on a financial basis, is
reasonable and provides adequate financial flexibility at this time.
One contested issue related to where, within the long-term equity range, WEPCO's
average test year financial equity should be forecasted. WIEG proposed that the average test
year equity be near the lower level of the range, while the applicant proposed that it be at the
middle of the range. An appropriate target level for WEPCO's test year average common equity
measured on a financial basis is 51.0 percent. This target level is consistent with the 48.50 to
53.50 percent range established by the Commission and historic Commission practice.
Furthermore, an appropriate target level for WG's test year average common equity measured on
a financial basis is 47.5 percent, which is consistent with the 45.00 to 50.00 percent range
established by the Commission.
Commission staff's removal of $178,314,000 of Goodwill and other push down
accounting entries associated with the acquisition of WG by WEC from WG's financial capital
structure was uncontested in this docket.
Commission staff proposed that in their next rate proceedings WEPCO and WG be
required to obtain and provide proof of credit rating agency treatment of all capital items along
with all credit agency reports and releases related to the companies. The Commission is not
persuaded that WEPCO and WG do not need or receive such information. It is reasonable that
WEPCO and WG obtain and file in their next rate case applications proof of credit rating agency
treatment of all capital items along with all credit agency reports and releases related to the
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companies. WEPCO and WG should work with Commission staff to provide the requested
information.
Consistent with the Commission's practice, WEPCO and Commission staff included in
the financial capital structure off-balance sheet obligations, including debt-equivalent associated
with leases and purchased power agreements. Adjustments for these off-balance sheet
obligations are made by S&P and other financial analysts when calculating various financial
ratios, including the total debt to capital ratio. WEPCO's filing used a 100 percent factor
adjustment for calculating the debt equivalents of capital leases; a 40 percent factor adjustment
for calculating the debt equivalents of the non-Point Beach purchased power agreements and
purchased power operating leases; and a 25 percent factor for calculating the debt equivalents of
the Point Beach purchased power agreement. Commission staff added non-purchased power
operating leases using a 100 percent factor adjustment. Uncontested are the cash flows
associated with the off-balance sheet obligations, the average interest costs used as the discount
factors, and the risk factoring described above except, in rebuttal testimony, WEPCO requested
that the risk factor applied to the Point Beach purchased power agreement be revised to
40 percent from 25 percent. The 25 percent risk factor is consistent with testimony regarding
expectation of S&P treatment of the obligation and should be used. Historically, the
Commission has imputed debt equivalence for WEPCO's nuclear fuel trust. However, with the
sale of Point Beach, the trust no longer exists. Lastly, the Commission affirms that no
off-balance sheet obligation relating to the PTF leases is to be imputed into the financial capital
structure. Consequently, a reasonable estimate of the total debt-equivalent of WEPCO's
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off-balance sheet obligations to be imputed into the financial capital structure for the test year is
$463,155,000.
In recent rate orders, the Commission has required other major Wisconsin utilities to
provide in their next rate proceeding additional detailed information so that the parties can more
accurately determine off-balance sheet debt equivalents and relative impacts on the utilities'
financial capital structures. Specifically, the Commission directed the utilities to thoroughly
evaluate and provide proof, from S&P and other major credit rating agencies, of what debt
equivalent factors will be used in the credit rating process. It is reasonable that WEPCO also
submit in its next rate case application detailed information regarding all off-balance sheet
obligations for which the financial markets will calculate a debt equivalent. The information
shall include, at minimum, the minimum annual lease and purchased power agreement
obligations; the method of calculation along with the calculated amount of the debt equivalent;
and supporting documentation, including all reports, correspondence and any other justification
that clearly establish S&P's and other major credit rating agencies' determination of the
off-balance sheet debt equivalent, to the extent available, and publicly-available documentation
if S&P and other major credit rating agencies' documentation is not available.
Incorporating the above off-balance sheet debt equivalents and other Commission
determinations, WEPCO's financial capital structure for the test year consists of 5 1 .OO percent
common equity, 0.62 percent preferred stock, 37.76 percent long-term debt, 1.16 percent
short-term debt, and 9.46 percent debt-equivalents of off-balance sheet obligations. In addition,
incorporating the Commission's determinations, WG's financial capital structure for the test year
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consists of 47.50 percent common equity, 41.98 percent long-term debt, and 10.52 percent
short-term debt.
Assessing the reasonableness of WEPCO's and WG's capital structures depends upon
three important principles. First, capital structure decisions must be based on WEPCO's and
WG's needs, not on the needs of the non-utility operations of the holding company. Second, the
capital structure should provide adequate flexibility to WEPCO, WG, and the Commission to
allow proper utility investment now and in the future. Third, the dividend policy of WEPCO and
WG should be similar to typical electric and natural gas dividend practices as long as WEPCO
and WG are below the estimated test year common equity ratio, on a financial basis.
Generally, under Wis. Stat. 5 196.795, the utility's capital needs must take precedence
over non-utility needs if ratepayers are to be protected. The identification of utility needs goes
beyond foreseeable needs. WEPCO and WG must have flexibility to finance both foreseen and
unforeseen capital requirements.
In previous dockets, the Commission recognized the need to protect ratepayers and to
ensure that utility needs are placed before non-utility needs in capital structure and dividend
policy choices. Consequently, WEPCO may not pay dividends in excess of the amount
forecasted in this case if such dividends cause the average annual common equity ratio, on a
financial basis, to fall below the test year authorized level of 51 .OO percent. WG may not pay
dividends above those estimates deemed reasonable in this proceeding without prior Commission
approval, if after the payment of such dividends the actual average common equity ratio, on a
financial basis, would be below the test year authorized level of 47.50 percent.
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The determination of whether the payment of dividends, over and above a typical or
normal dividend is appropriate, can only be made at the end of the test year. Therefore, the
applicant should wait until the end of the test year to pay additional dividends to the parent.
Such dividends shall only be paid if their payment will not cause the common equity ratio, on a
financial basis, to fall below the test year authorized level.
Ten-Year Financial Forecast
WEPCO's and WG's ten-year financial forecasts are useful to the Commission and
should be submitted in future rate cases. The ten-year forecast can be combined with other
business risk information to assess capital structure needs and rate of return requirements.
Regulatory Capital Structure and Cost of Capital
In docket 6630-UR- 1 11, the Commission reaffirmed its practice of deducting WEPCO's
investment in non-utility items from its financial common equity to arrive at the common equity
amount for its regulatory capital structure. Consequently, Commission staff removed
$20,463,000 and $1 1,924,000 of non-utility investments from WEPCO's and WG's common
equity. The adjustment was uncontested.
In addition, Commission staff deducted WEPCO's investment in common equity of
ATC, net of deferred income taxes associated with transmission assets transferred to ATC, from
WEPCO's financial common equity to arrive at the common equity amount for its regulatory
capital structure. This method results in WEPCO's net investment in ATC being excluded from
retail rates at 'WEPCO's return on equity rate. The deferred income taxes on the books of
WEPCO for transmission assets transferred to ATC are included in the calculation of
transmission rates charged by ATC and subject to FERC approval.
Docket 5-UR- 103
As a result, WEPCO's common equity investment in ATC is treated as non-utility
investment financed by common equity of the shareholders of WEPCO. This equity investment
earns common equity return from ATC. The shareholders of WEPCO will receive any gain or
be responsible for any loss if WEPCO should sell its investment in ATC. This method will result
in the retail ratepayers paying a similar return on transmission investments as they did prior to
the transfer of transmission assets to ATC. The Commission finds this treatment reasonable.
This determination is also consistent with the Commission's determination for docket
6690-UR-113 for WPSC, docket 6680-UR-111 for Wisconsin Power and Light Company, and
docket 3270-UR-111 for Madison Gas and Electric Company.
A reasonable utility rate-making capital structure for the purpose of establishing just and
reasonable rates for WEPCO for the test year consists of 54.36 percent common equity,
0.72 percent preferred stock, 43.58 percent long-term debt, and 1.34 percent short-term debt.
Similarly, a reasonable utility rate-making capital structure for the purpose of establishing just
and reasonable rates for WG for the test year consists of 46.64 percent common equity,
42.67 percent long-term debt, and 10.69 percent short-term debt. These values are calculated
from the Commission staff's capital structure, by adjusting for the decisions in this proceeding.
Short-Term Debt
WEPCO's and WG's test year capital structures contain approximately $56,917,000 and
$77,651,000, respectively, of short-term debt. The interest rate associated with the short-term
indebtedness is the commercial paper rate. A reasonable estimate of the average cost of
short-term commercial paper for the test year is 4.28 percent. This forecast is based on the
average of test year commercial paper rate estimates provided by the Blue Chip Financial
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Forecasts newsletter. This is a reasonable and objective method of determining short-term debt
costs.
Long-Term Debt
WEPCO's test year long-term debt includes an issuance of 30-year debt aggregating
$500,000,000 principal amount. A reasonable estimate for the cost of the indebtedness is
6.01 percent. WEPCO's long-term debt also includes $164,350,000 of variable rate notes.
These tax-exempt notes have an interest rate of approximately 65 percent of the commercial
paper rate. Based on a commercial paper rate of 4.28 percent, a reasonable estimate of the
average cost of the demand notes for WEPCO for the test year is 2.78 percent. The resulting
embedded cost of long-term debt for WEPCO of 5.49 percent is reasonable for the test year. A
reasonable embedded cost of long-term debt for WG for the test year is 5.74 percent.
Preferred Stock
The average cost of WEPCO's preferred stock of 3.95 percent is reasonable for the test
year.
Return on Equity
A principal factor used to determine the appropriate return on equity is the investors'
required return. Authorized returns less than the investors' required return would fail to
compensate capital providers for the risks they face when providing funds to the utility. Such
sub-par returns would make it difficult for a utility to raise capital on an ongoing basis. On the
other hand, authorized returns that exceed the investors' required return could be unfair to utility
consumers who ultimately pay for those returns.
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In reaching its determination as to the appropriate return on equity, the Commission must
balance the needs of investors with the needs of consumers, with due consideration to economic
and financial conditions along with public policy considerations. If the appropriate return on
equity could be measured precisely, setting the authorized return on equity would be
straightforward. Because that return cannot be measured precisely, determining the appropriate
return on equity is typically one of the most contested issues in a rate proceeding. In this
proceeding the applicant proposes its authorized return be set at 11.20 percent. Its financial
witness' best point estimate was 11.0 percent for WEPCO and 11.5 percent for WG. The
applicant's financial witness applied an After-Tax Weighted-Average Cost of Capital
methodology in developing the applicant's recommended return. WIEG recommends that the
return on equity be set at 9.7 percent. Commission staff suggests that the appropriate return on
equity be set somewhere in the range from 10.00 to 11.00 percent. The Commission is not
persuaded that the After-Tax Weighted-Average Cost of Capital methodology should be used in
setting an authorized return for a regulated utility.
Given the above-mentioned considerations, balance is struck most reasonably in this
proceeding by authorizing a return on equity equal to 10.75 percent. A 10.75 percent return
should allow the applicant to attract capital at reasonable terms without burdening consumers
with excessive financing costs.
Chairperson Ebert dissents and would authorize a 10.8 percent return on equity.
Using a 10.75 percent return on equity, WEPCO's average utility capitalization ratios,
annual cost rates, and the composite cost of capital rate considered reasonable and just for setting
rates for the test year are as follows:
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Amount Annual Weighted (000's) Percent Cost Rate Cost
Utility Common Equity $ 2,306,690 54.36% 10.75% 5.85%
Preferred Stock 30,450 0.72% 3.95% 0.03%
Long-Term Debt 1,849,350 43.58% 5.49% 2.39%
Short-Term Debt 56.917 1.34% 4.28% 0.06%
Total Utility Capital $4.243.407 100.00% 8.33%
The weighted cost of capital of 8.33 percent is reasonable for WEPCO for the test year.
It generates an economic cost of capital of 12.22 percent and a pre-tax interest coverage ratio of
4.99 times, on the regulatory capital structure.
Similarly, WG's average utility capitalization ratios, annual cost rates, and the composite
cost of capital rate considered reasonable and just for setting rates for the test year are as follows:
Amount Annual Weighted (000's) Percent Cost Rate Cost
Utility Common Equity $338,822 46.64% 10.75% 5.01%
Long-Term Debt 3 10,000 42.67% 5.74% 2.45%
Short-Term Debt 77-65 1 10.69% 4.28% 0.46%
Total Utility Capital $726.473 100.00% 7.92%
The weighted cost of capital of 7.92 percent is reasonable for WG for the test year. It
generates an economic cost of capital of 11.27 percent and a pre-tax interest coverage ratio of
3.87 times, on the regulatory capital structure.
Rate of Return on Rate Base
The ratio of net investment rate base plus CWIP to capital applicable to utility operations
plus deferred investment tax credits (ratio) is used in Wisconsin to translate the composite cost of
capital into a rate of return that can be applied to the average net investment rate base. The ratio
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is also used to compute the overall return requirement in dollars. The estimate of WEPCO's
ratio for the test year is 91.60 percent. The estimate of WG's ratio for the test year is 73.35
percent. These estimates reflect all appropriate Commission adjustments and are reasonable and
just for use in translating the composite cost of capital into a return requirement applicable to the
average net investment rate base.
A witness for WIEG recommended rejecting the use of the ratio for a number of reasons
including: (1) there is no evidence that there are any amounts missing from rate base that would
require the Commission to use the ratio; and (2) the company's proposed gross-up essentially
would provide it a return on regulatory assets upon which it already earns a rate of return
specified by the Commission.
The difference between net investment rate base plus CWIP and capital applicable
primarily to utility operations plus deferred investment tax credits is working capital. This
working capital includes regulatory assets. The items that make up working capital are the
amounts missing that require the use of the ratio. In addition, the ratio does not allow the
company to recover the return on working capital twice. A company accrues carrying costs on a
deferral or regulatory asset from the time it first receives authorization from the Commission
until a rate case. At the time of a rate case when the recovery of the deferral is considered, a
return on the deferral is only given through the use of the ratio.
Not only does the ratio allow the Commission to provide a return on working capital, it
also prevents the company from earning a return on capital applicable primarily to non-utility
operations. Therefore, the test year estimates of the ratio reflect all appropriate Commission
Docket 5-UR- 103
adjustments and are reasonable and just for use in translating the composite cost of capital into a
return requirement applicable to the average utility net investment rate base.
To allow a test year current return on the average CWIP balance, an adjustment must be
added to the return on net investment rate base. Since the late 1990s, the Commission has
allowed utilities to earn current returns on some portion of CWIP. For example, in the
Commission's order in docket 6630-UR-111, dated August 30,2000, the Commission found that
it was reasonable to allow a current return on 50 percent of CWIP for that test year.
In this case, a witness for WIEG recommended that the Commission accrue an allowance
for funds used during construction (AFUDC) on all CWIP and not allow WEPCO to earn a
current return on any CWIP. This witness maintained that there is no demonstration that
WEPCO is in financial need or distress. He considers distress to be the only valid reason to
deviate from requiring a utility to capitalize carrying costs incurred during the construction of
assets and to recover those costs over the lives of those assets.
In considering whether to authorize a current return on any portion of CWIP, the
Commission's standard practice has been to consider a company's test year financing, cash flow
requirements, and forecasted amount of construction activity. Providing a current return on
CWIP today helps to smooth rates over time. A current return on CWIP mitigates rate increases
tomorrow and beyond since on-going rate base will be lower. This Commission has not required
a finding of financial distress before allowing a company to earn a current return on CWIP.
Given both WEPCO's and WG's financing and cash flow requirements in the test year
and the forecasted amount of construction activity, the Commission finds it reasonable to allow a
current return on 50 percent of CWIP for the test year.
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Accordingly, the Commission finds that the rates of return on average electric, natural
gas, and steam net investment rate bases, which are reasonable for the purpose of determining
just and reasonable rates in this proceeding, are as follows:
Weighted Cost of Capital
Ratio of Average Net Investment Rate Base Plus CWIP to Capital Applicable Primarily to Utility Operations Plus Deferred hvestment Tax Credit
Adjusted Cost of Capital to Derive Percent Return Requirement Applicable to Average Net Investment Rate Base
Adjustment to Return Requirement to Provide Current Return on CWIP
Adjustment to Return Requirement to Provide Current Return on PTF Escrow, MIS0 Deferral, and Coal Conservation at short term debt of 4.28 percent
Required Rate of Return on Average Net Investment Rate Base
Downtown WG Natural Milwaukee Wauwatosa Natural
Electric Gas Steam Steam Gas 8.33% 8.33% 8.33% 8.33% 7.92%
Revenue Requirement
On the basis of the findings in this order, a $389,065,000 increase in WEPCO electric
utility operations before implementation of credits due to the sale of Point Beach, a $3,973,000
increase in WEPCO natural gas utility revenues, a $1,947,000 increase in WEPCO Downtown
Milwaukee steam utility revenues, a $1,693,000 increase in WEPCO Wauwatosa steam utility
revenues, and a $20,132,000 increase in WGC natural gas utility revenues, are reasonable for the
purpose of determining reasonable and just rates in this proceeding and are computed as follows:
Docket 5-UR- 103
WEPCO
Pro Forma Return on Average Net Investment Rate Base at Present Rates Required Return on Average Net Investment Rate Base
Earnings Deficiency as a Percent of Average Net Investment Rate Base
Average Net Investment Rate Base (000's)
Amount of Earnings Deficiency on Average Net Investment Rate Base (000' s) Revenue Deficiency to Provide for Earnings Deficiency Plus Federal and State Income Taxes (000's)
PBPP Sale Proceeds Applied to Regulatory Assets (000's)
Revenue Deficiency before Implementation of PBPP credits (000's)
Downtown WG Natural Milwaukee Wauwatosa Natural
Electric Gas Steam Steam Gas
Steam Issues
WEPCO presented information supporting increases in steam revenues for the Downtown
Milwaukee and Wauwatosa service areas of 17.0 percent and 16.0 percent, respectively. After
adjustments for other Commission decisions affecting steam costs, it is appropriate to authorize
revenue increases of 10.2 percent and 12.5 percent, respectively, for the Downtown Milwaukee
and Wauwatosa service areas. The steam rates and revenues shown in Appendix B reflect this
information and are reasonable.
Docket 5-UR- 103
Electric Cost of Service
Witnesses for WEPCO, intervenors, and Commission staff testified regarding COSS
issues. Issues presented included the type of demand allocator and mix of demand and energy
allocators to use for assigning production costs, the correct allocation method for purchased
power costs from Point Beach, the methodology to be used for determining Point Beach refunds,
the allocation of Act 141 refund costs, and the appropriate method to use to allocate distribution
costs. The information provided in these discussions was used by the Commission in making its
decisions and assigning revenue responsibility. It is for this reason that it is appropriate for the
Commission to continue to rely on the results of a variety of COSS information, along with other
factors, such as bill impacts, when allocating revenue responsibility.
As previously discussed, the jurisdictional allocation of Point Beach purchased power
costs was an issue in this case. It is an issue on the retail level as well. WEPCO had proposed to
allocate these costs primarily on the basis of energy allocators while intervenors provided
information supporting allocating these costs using both demand and energy allocators. In order
to best reflect historical treatment of the costs of power from Point Beach, as well as the
allocation of the net gain on the sale of Point Beach, an allocation based on 65 percent customer
demand and 35 percent energy use is appropriate for the retail level. Because of the profound
impact that Point Beach purchased power costs may have in subsequent WEPCO dockets, the
Commission directs the applicant, Commission staff, and any interested parties to work to
develop a retail allocation that reflects how Point Beach costs were allocated prior to the sale for
use in the applicant's next rate filing.
Docket 5-UR- 103
Electric Revenue Allocation and Rate Design
The results of WEPCO's and Commission staff's COSS in this case support a lower than
average increase for residential customers. However, WIEG presented COSS information that
indicated a higher than average increase for residential customers. Additional information
presented indicates that other factors, such as the proper allocation of purchased power costs, Act
141 costs, and continuity of rate design, should be considered when determining allocation of
revenue responsibility. Taking these factors into account, the Commission determines that near
average increases in revenue responsibility for all classes are warranted. This includes increases
in Small Use class customer charges and proportionally greater increases in off-peak energy
charges to better reflect the costs to serve customers. All of the individual electric rate class
impacts are affected by consideration of factors such as established rate relationships, customer
bill impacts for both high and low energy use customers of all classes, and the relationship of
tariff charges to cost. In making this decision, the Commission continues to rely on the results of
a range of electric COSS along with the other information as guides in determining revenue
allocation and setting rates. The electric rates shown in Appendix B are reasonable.
Innovative Rate Options for Residential Customers
In this case, WEPCO proposed two additional TOU options for its Small Use customers.
The Commission finds these options reasonable with adjustments to off-peak energy charges and
on-peakloff-peak charge differentials as shown in Appendix B.
CUB proposed to continue its collaborative work with WEPCO to investigate innovative
rate options such as new TOU rates, and other rate options that promote energy conservation for
residential and Small Use customers. The Commission accepts this proposal, and directs
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WEPCO to work with CUB and include Commission staff in the collaborative meetings to
investigate these alternative rate structures.
Act 141 Costs in Base Rates
The Act 141 costs that are included in WEPCO's electric rates for the 2008 test year total
$25,513,000. Act 141 defines a "large energy customer" as a customer of an energy utility that
owns or operates a facility in the energy utility's service area that has an energy demand of at
least 1,000 kilowatts per month or of at least 10,000 decatherms per month and that, in a month,
is billed at least $60,000 for electric service, natural gas service, or both, for all of the facilities of
the customer within the energy utility's service territory. Act 141 specifies that these customers
should pay only the specific conservation costs associated with public benefits that they paid in
2005. To implement this requirement, the Commission must determine how much Act 141 costs
are included in the base rates for the rate classes that serve the large energy customers. WEPCO
has large energy customers that receive service under all its electric rate tariffs except for its
residential tariffs. The non-residential rates that serve a mixture of large energy customers and
non-large customers must be treated differently because Act 141 costs are built into those base
rates. The Act 141 costs built into base rates for the non-residential rates classes amount to
$0.00088 per kWh. Based on the Act 141 limits, the large energy customers will pay the specific
conservation costs associated with public benefits that they paid in 2005, less the authorized
$0.00088 per kWh Act 141 costs included in base rates. The amount the large energy customers
paid in 2005 was approximately $0.00034 per kWh. Therefore, the Act 141 refund to qualifying
large customers of $0.00054 per kWh for electric rates, as shown in Appendix B, is reasonable.
Docket 5-UR- 103
WEPCO requests that any deficiency in revenue resulting from Act 141-related refunds
to qualifying customers be tracked with escrow accounting and trued up in a future rate case.
This approach is reasonable.
Point Beach Sale Refunds
The sale of Point Beach resulted in the need to refund customers both the Point Beach
decommissioning fund and the net gain on the sale of the plant. The Commission finds it
reasonable to allocate the decommissioning fund on the basis of energy use and to allocate the
net gain on sale on the basis of 65 percent on customer demand and 35 percent on energy use
because these allocations reflect the historical treatment of the costs by the Commission.
WEPCO initially proposed that Point Beach refunds to customers be treated as a credit
based on energy use by customers over a two-year period. WIEG asked that the refunds be used
to offset the revenue increases in this case. Commission staff provided information indicating
that a three-year refund period may reduce the impact on price signals that the refunds have if an
energy credit is used for the refund mechanism. The Commission is concerned that the impact of
the refund is minimized and that the net increase in customer bills after the refund is as uniform
as possible over the refund period. The Commission directs WEPCO to use a credit based on
energy usage by customer over a three-year period to address these concerns. The Point Beach
refunds shown in Appendix B are based on this approach and are reasonable.
The amount of Point Beach sale refunds occurring over the three-year period will vary
from the test year forecast because it is unlikely that actual energy use will match test year
forecasts. It is for this reason that the Commission previously authorized a true-up of the refund
at the end of the refund period. Customer impact will be reduced if WEPCO provides an
Docket 5-UR- 103
accounting of the refunds made by tariff class along with a forecast of tariff class energy use for
the third year of the three-year refund period. This information allows an adjustment in the
refund in the third year if one is necessary. It is reasonable to direct WEPCO to provide an
accounting of refunds made by tariff class along with a forecast of tariff class energy use for the
third year of the three-year refund period prior to the utility's next biennial rate application.
CP-PN Change - Emergency Interruption Option
WEPCO's Cp-2M and the Cp-FN interruptible rate schedules are available to large
commercial and industrial customers that take service at primary voltage. Under the Cp-2M
schedule, a customer's entire load must be subject to interruption. Under the Cp-FN schedule,
customers may take firm service for a portion of their load and interruptible service for the
remaining portion. The firm service is billed at the same rates as the Cp-1 firm schedule and the
interruptible portion is billed at the rates that apply under the Cp-2M schedule.
WEPCO proposes that customers that take service under the Cp-FN interruptible rate
schedule be offered an option under which they would be subject to interruption only for
capacity reasons. Under this option, customers would only receive the interruptible credit
applied against the firm demand charge. They would not receive the discounts from the firm
on-peak and off-peak energy charges.
WIEG supports the WEPCO proposal, but recommends that the option also be extended
to the Cp-2M rate schedule.
The Commission understands that changes to WEPCO's interruptible rate schedules may
be desirable. However, the Commission must ensure that any changes are consistent with the
Midwest IS0 market. Therefore, the Commission will refrain from authorizing the proposed
Docket 5-UR- 103
changes to the Cp-FN or Cp-2M rate schedules until a comprehensive review of interruptible
rates that takes into account the MIS0 Day 2 market can be completed.
Biogas Rates
RENEW Wisconsin (RENEW) sponsored several witnesses who testified about the
technology and economics of manure-based biogas generation. These witnesses also provided
calculations of the buyback rates they suggested were necessary to support the development of
manure-based systems. WEPCO opposed the implementation of a buyback rate based solely on
the costs of the biogas generator because such a calculation ignores other revenue streams that
these installations provide for the owner. WEPCO pledged to file a new biogas buyback rate
with the Commission before the end of 2007.~ The Commission finds that WEPCO's proposal is
reasonable.
Generic proceedinlg on buyback rates
RENEW witness Michael Vickerman testified that RENEW is concerned that the
piecemeal develop~nent of buyback rates for renewable resources has not been productive.
RENEW urges the Commission to open a generic proceeding to develop standardized buyback
rates for renewable resources. WEPCO believes that each utility's buyback rates should be set
on an individual basis and that a generic proceeding is unnecessary. The Commission will not
open a generic investigation at this time, but will continue to examine its options to evaluate the
issues related to renewable resources.
7 WEPCO did file a new buyback rate before the end of 2007
82
Docket 5-UR- 103
Electric Tariff Language Changes
WEPCO proposes numerous changes to its electric rate, service rule, and extension rule
tariffs. The majority of these are minor tariff language changes that were unopposed. However,
Commission staff testified in opposition to some of the proposed changes.
WEPCO requests an increase in the current charges for reconnection and disconnection
of electric service. WEPCO also requests different reconnection and disconnection charges
applicable to pole-top reconnections and disconnections. Commission staff opposes charging
customers for the disconnection of their electric service. Traditionally, Wisconsin utilities have
imposed charges for reconnecting electric service, but not for disconnecting electric service.
WEPCO's charge for disconnection of electric service was introduced in 2006. Currently no
other electric utility in Wisconsin is authorized to charge for disconnection of electric service.
Cost analyses introduced to justify reconnection charges have not included costs associated with
disconnections. The Commission determines that WEPCO should discontinue charging for
disconnections of electric service. The changes proposed by WEPCO to the electric
reconnection charges are reasonable.
WEPCO proposes new tariff language for customer-requested terminations of service
during the winter moratorium. Under this proposal, whenever WEPCO receives a
customer-requested termination and the owner has verified that the premise is empty, WEPCO
will visit the premise and knock on the door or ring the doorbell to make an attempt to find out if
anybody is inside. If not, WEPCO will assume the premise is unoccupied and disconnect
service. Under WEPCO's interpretation, its proposed change is consistent with the intent of
Wis. Admin. Code $8 PSC 113.0304(3) and 134.0624(3). Commission staff's long-time
Docket 5-UR- 103
interpretation of these Wisconsin Administrative Code sections has been that a utility must
physically inspect inside a premise to verify the premise is not occupied before disconnection of
service can occur during the winter moratorium. The Commission considers this a customer
safety issue and, therefore, denies WEPCO's proposed tariff language changes for
customer-requested terminations of service during the winter moratorium.
In WEPCO's last rate case, docket 05-UR-102, the Commission authorized an electric
tariff change for WEPCO, which allowed "carrying costs on prepaid income taxes," also referred
to as a Timing Adjustment Factor, to be included in the calculation of contributions in aid of
construction for electric extensions. This issue was not fully vetted in that case. As a result, in
that proceeding, Commission staff addressed whether WEPCO should be allowed to continue
imposing this charge. WEPCO's only description of the Timing Adjustment Factor in the last
case was to mention in testimony the proposal for "numerous minor changes to the rules and
regulations" that were included in an exhibit. However, the impact of the Timing Adjustment
Factor was a 3 1 percent increase applied to the net capital cost of extensions. WEPCO provided
no analysis of the impact of the Timing Adjustment Factor on individual customers or the utility
revenue requirements.
The cost that is at issue here, carrying cost on prepaid income taxes, is simply a time
value of money consequence of an IRS tax interpretation. Commission staff raised the question
of whether a significant change to the electric extension rules, such as a 3 1 percent adder, should
be addressed in a generic proceeding rather than in a rate case for a single utility. Currently no
other electric utility in Wisconsin charges for carrying cost on prepaid income taxes for electric
extensions. The Commission determines that WEPCO shall discontinue including the Timing
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Adjustment Factor in its calculation of contributions in aid of construction for electric
extensions.
The other numerous minor tariff changes WEPCO proposes for its electric rate, service
rule, and extension rule tariffs were unopposed. WEPCO is authorized to implement these
changes to its electric rate, service rule and extension rule tariffs that are not addressed above, as
proposed in Exhibits 118 and 119.
NATURAL GAS RATES
Revenue Recovery Adequacy of Service Class Rates
Overall, the rates authorized for WE-GO in Appendix D of this Final Decision will
provide a 9.15 percent rate of return on the average gas net investment rate base. This represents
an increase of 2.37 percent in margin rates and a 0.60 percent in total natural gas sales revenues.
The rates authorized in Appendix D of this order for WG will provide a 10.91 percent rate of
return on the average gas net investment rate base. This represents an increase of 8.11 percent in
margin rates and a 2.21 percent in total natural gas sales revenues. Margin rates exclude natural
gas costs from the increase calculations.
Authorized rates as set forth in Appendix D are based on the cost of supplying natural gas
service to the various service rate classes and other rate setting goals. A summary of the revenue
rate impacts on a service rate class is shown in Appendix C.
As shown in Appendix C, the natural gas COSS results in a relatively wide range of
increase in the charges to the various service rate classes. To provide for historical continuity in
the companies' rates, the Commission finds it reasonable to authorize service rates that move in
the direction of the natural gas COSS results, with intent to make further adjustments in that
direction in subsequent rate proceedings. In moving toward the cost of service in authorized
Docket 5-UR- 103
rates, the Commission tempers the rate increase to the service rate classes that, according to the
cost analysis, should receive the largest percentage increases. The resulting revenue difference is
recovered through the rates of the remaining service rate classes. The percentage rate increase to
any individual customer will not necessarily equal the overall percentage increase to the
associated service rate class, but will depend on the specific usage level of the customer.
Appendix E shows some typical natural gas bills for residential service, comparing existing rates
with new rates including the cost of natural gas.
Fixed General Service Rates Monthly Charges for Residential Customers and the Smallest Volume Commercial Service Rate Class
Authorized general service rates provide a greater percentage increase to residential
customers and the smallest volume commercial service rate class than for larger-volume users
within the same service class. This is the result of the higher authorized percentage increases in
the fixed daily distribution service charge over the volumetric distribution service charges. For
example, the overall 2.48 percent increase in the WE-GO residential margin revenues
(7.68 percent increase for WG) consists of a 12.00 percent increase in the fixed daily distribution
service revenues (12.00 percent increase for WG) and a 2.57 percent decrease in volumetric
distribution service revenues (5.70 percent increase for WG). Small-volume customers will
experience the highest percentage increase in rates because their bills are comprised of
proportionately more of the fixed daily distribution service charge than the volume charges when
compared to larger volume users. The authorized fixed charges for residential customers and the
smallest volume commercial customers are designed to recover customer costs including meter
reading, billing, and collecting expenses, and the depreciation and return associated with meters
and service laterals. The applicants incur these costs regardless of the volume of gas used by
Docket 5-UR- 103
their customers, so it is more appropriate to recover such costs through fixed service charges than
through volumetric charges. Some typical gas bills for WE-GO and WG residential customers
were computed, using Schedule Rg-1, to compare existing rates with authorized rates. The
comparisons are set forth in Appendix E.
Metered Demand Service Rates
The companies, WE-GO and WG, and Commission staff proposed a new charge, the
Metered Demand Service Charge, for the companies' three largest volume service rate classes,
G-6 through G-8. Metered Demand Charges are designed to generate revenues based on
maximum daily demands for the purpose of recovering costs associated with the investment and
operation of facilities to meet demands in excess of average loads. Typically, these costs have
been recovered from monthly volumetric usage rates. The authorized Metered Demand Service
Rates would be a charge applied to the customer's peak day usage in the most recent rolling
12-month period and are set forth in Appendix D. In the initial year, the historical 12-month
period will be phased in so that demand is not based on usage before the effective date of the
authorized rates.
Late in March 2007, the companies presented informational material directly .to affected
customers and to industry associations involved in energy issues. The informational material,
the notice of the companies' rate application and the building of the 12-month history has
allowed the customers opportunities to evaluate the impacts, express their concerns and react to
the rate implementation.
The companies understand that an industrial customer's short-term plant maintenance and
testing are an operational necessity that may result in a new peak day use for the customer. The
Docket 5-UR- 103
Commission finds that a peak day waiver is reasonable in special situations provided that waiver
terms and conditions set forth the appropriate notice requirements. The waiver conditions, in
part, will require the customer to request the waiver seven days in advance of the peak and a
company response within three days of receipt of such a request. The companies shall review
the notification requirements after six months and voluntarily shorten the notification
requirements if appropriate.
Breakpoint Analysis
Breakpoint analysis is the rate design minimization of billing differences where a
customer switches or crosses over from one service rate class to another service rate class so that
the customer is economically indifferent as to service rate class assignment. Reducing the
differences at the breakpoints is a rate design objective. However, this objective was weighed
with other objectives including cost of service recovery, rate migration, new service rate
classifications, and rate similarities for WE-GO and WG. It is appropriate to authorize a second
set of rates effective for service January 1, 2009, that reduces the differences at the breakpoints
and improves cost recovery in an overall revenue neutral manner. The authorized rates, effective
for service on January 1, 2009, are set forth in Appendix D.
Meter Aggregation
Retail meter aggregation is the summing of gas consumption from any number of retail
gas meters into a single volume before billing a customer. Furthermore, a number of
transportation customers have benefited from meter aggregation by being charged a single
transportation administrative fee versus a separate transportation administrative fee for each
meter. WG stopped the practice of combining metered usage for customers with multiple meters
Docket 5-UR- 103
in the 1990s while grandfathering all existing combined billing practices. Eliminating the
aggregated accounts will result in additional revenues of nearly $752,000 per year. This is based
on the billing of the full facilities charge for each additional meter, higher commodity rates for
service rate reclassifications and separate transportation administrative fees. Treating each
metered service as a separate account is reasonable because the applicable service charges will
recover the investment and operating costs associated with each meter and service lateral. Given
the transportation customer rate impacts, particularly among small volume transportation
customers, a customer may be better served with system sales service. Because small volume
customers may no longer realize net gas cost savings from transportation service and many, if
not all, may find it advantageous to return to system sales service, it is reasonable to waive the
WG service switching notice requirements for small volume customers for 90 days from the date
the order becomes effective. For customers in service rate classes TF-4 and above, WG shall
waive the service switching notice requirements for customers wherever adequate supply (both
capacity and commodity) exists.
WG Classification of Peak-Day Demand Gas Costs and Annual Demand Gas Costs
WG has four base cost of gas components: average peak-day demand gas costs, average
annual demand gas costs, commodity gas costs and surcharge costs. These base cost of gas rates
are updated to reflect the test year estimates in order to minimize adjustments and are done so in
a fairly routine manner. The individual costs for the capacity purchases and services are identified
and allocated to peak-day demand gas costs and annual demand gas costs. Each utility adopted its
current methodology some 20 years ago. The methodologies vary and WG allocates more costs to
peak day demand gas costs than WE-GO does. In order to align the assignment of capacity costs of
the two natural gas utilities, WG shall adopt the WE-GO reservation cost allocation method because
Docket 5-UR- 103
it is the more appropriate allocation method. The change in the methodology will result in higher
average annual demand gas costs and lower average peak day demand gas costs for WG customers.
This reclassification of natural gas costs will have a larger impact on interruptible system sales
customers than on firm system sales customers. Because interruptible system sales service
customers may find it advantageous to switch to transportation service, it is reasonable to waive
WG's eight-month notice requirement for service switching for 90 days to permit interruptible
sales customers to move to transportation service upon meeting all other tariff requirements.
Distribution Capacity With or Without Gas Supply Interruption Crediting Service
The Distribution Capacity with or without Gas Supply Interruption Crediting Service
allows the companies to contract with customers for interruptible service in distribution system
sections that do not meet firm service criteria. The Distribution Capacity with or without Gas
Supply Service sets forth the terms that are negotiable under the contract. The "negotiable"
terms have default values, but may be specifically negotiated and set forth in the contract. In
light of Metered Demand Service Charges, it is reasonable to increase the credit from 10 percent
to 15 percent of the volumetric distribution rate, excluding metered demand service charges.
Pulse Signal Devices
Large customers and natural gas marketers have requested real-time usage information.
The companies can offer this service and can assure continued compatibility with metering
information. It is reasonable to offer this as a tariffed service that sets forth an initial installation
fee and a daily service charge.
Effective Date
This Final Decision shall be effective the date of mailing. The authorized rates and rules
shall also be effective on the same date, provided that the rates are filed with the Commission
Docket 5-UR- 103
and placed in all offices and pay stations of the utility by that date. If the authorized rates and
rules are not placed in all offices and pay stations by the effective date of the Final Decision, the
rates shall become effective on the date that the rates are placed in all offices and pay stations.
The applicants shall inform the Commission, in writing, of the date that the authorized rates and
rules are to take effect.
Order
1. This Final Decision shall be effective the date of mailing. The authorized rates
and rules shall also be effective on the same date, provided that the rates are filed with the
Commission and placed in all offices and pay stations of the utility by that date. If the
authorized rates and rules are not placed in all offices and pay stations by the effective date of the
Final Decision, the rates shall become effective on the date that the rates are placed in all offices
and pay stations. The applicants shall inform the Commission, in writing, of the date that the
authorized rates and rules are to take effect.
2. WEPCO is authorized to substitute for its existing rates and rules for retail
electric, steam, and natural gas service, the rate and rule changes contained in Appendices B and
C. These changes shall be in effect until the issuance of an order by the Commission
establishing new rates and rules.
3. WG is authorized to substitute for its existing rates and rules for natural gas
service, the rate and rule changes contained in Appendix D. These changes shall be in effect
until the issuance of an order by the Commission establishing new rates and rules.
4. The applicants shall prepare bill inserts that appropriately identify the rates
authorized in this Final Decision. The applicants shall distribute the inserts to customers no later
Docket 5-UR- 103
than the first billing containing these rates and shall file copies of these inserts with the
Commission before distributing the inserts to customers.
5. The fuel costs in Appendix F shall be used for monthly monitoring of WEPCO's
fuel costs, pursuant to Wis. Admin. Code ch. PSC 116.
6. WEPCO shall use the following ranges to monitor fuel costs: plus or minus 8
percent monthly; cumulative ranges of plus or minus 8 percent for the first month, plus or minus
5 percent for the second month, and plus or minus 2 percent for the remaining months of the
year; and plus or minus 2 percent for the annual range.
7. In order to recover 2007 deferred MIS0 Day 2 costs, WEPCO must demonstrate
in the next full rate case an overall increase in costs as a result of MIS0 Day 2.
8. WEPCO shall pay the village of Caledonia $600,000 per year for two years for
police, fire, and ambulance protection resulting from the construction of the ERGS.
9. WEPCO shall pay the village of Caledonia $600,000 for the 4 Mile Road grade
separation for a period of 20 years, up to a total funding of $8 million8 provided that the village
of Caledonia obtains the concurrence of the OCR as to the need and proper cost allocation
between the railroad and Caledonia for grade separation. WEPCO shall only recover costs
relative to the 4 Mile Road grade separation that are not allocated to the railroad and are not
funded by other sources in the future.
10. WEPCO shall notify the Commission of the final decision from the OCR
regarding the 4 Mile Road separation project.
8 The $8 million represents the present value of annual payments of $600,000 over a 20-year period. The total and annual amounts are subject to funding from other sources.
Docket 5-UR-103
11. The applicants shall work with Commission staff to develop a mechanism that
moves away from requiring executives to fill out timesheets.
12. In future rate case applications, WEPCO and WG shall include a complete
forecast of its balance sheet, by month, for all months from the actual starting point through the
test year.
13. WEPCO shall discontinue escrow accounting treatment on December 3 1,2007,
for ATC transmission expenses that were formerly being escrowed.
14. WEPCO shall defer any refunds from ATC associated with it network service fees
until such refunds can be returned to ratepayers.
15. WEPCO shall discontinue escrow accounting treatment on December 31,2007,
for NOx reduction compliance-related costs.
16. WEPCO shall use escrow accounting for the monies from the sale of Point Beach.
17. WEPCO shall use a historical jurisdictional allocator for the refund of the Point
Beach decommissioning trust fund based on a historical decommissioning fund balance
(85.2 percent to the Wisconsin retail jurisdiction) and 12 CP demand for the refund of the net
pre-tax gain on the sale of Point Beach (86.1 percent to the Wisconsin retail jurisdiction).
18. WEPCO shall not withhold proceeds from the sale of Point Beach for any
contingencies.
19. Of the amounts to be returned to ratepayers, the amounts that relate to the book
gain on the sale of Point Beach and the tax gain realized on the non-qualified trust fund, plus
interest thereon, shall be satisfied by bill credits only.
Docket 5-UR- 103
20. WEPCO and WG shall record AFUDC at authorized rates on 50 percent of retail
CWIP, unless otherwise noted.
21. All authorized amortizations shall begin as of the effective date of this Final
Decision.
22. We Energies shall work with Commission staff in the development of its
voluntary utility programs and information in support of the programs. We Energies' voluntary
utility programs will be approved and judged using the same standards as those used for the
Focus on Energy statewide energy efficiency programs.
23. We Energies shall work with Commission staff and the Focus on Energy program
administrator to ensure adequate coordination of We Energies' voluntary utility energy
efficiency programs with the Focus on Energy programs.
24. We Energies shall work with Commission staff to develop measures of success
for its 2008 customer service conservation activities.
25. WEPCO shall maintain a long-term range of 48.5 percent to 53.5 percent for its
common equity ratio, on a financial basis.
26. WG shall maintain a long-term range of 45.0 percent to 50.0 percent for its
common equity ratio, on a financial basis.
27. WEPCO and WG shall submit ten-year financial forecasts in their next rate
proceedings.
28. WEPCO may not pay dividends in excess of the amount forecasted in this
proceeding if such dividends cause the average annual common equity ratio, on a financial basis,
to fall below the test year authorized level of 51.00 percent. WEPCO may not pay a special
Docket 5-UR- 103
dividend in excess of the forecasted dividends at the end of the year unless the additional
payment does not reduce the average annual common equity ratio, on a financial basis, below the
forecasted level of 5 1 .OO percent.
29. WG may not pay additional dividends above those estimates deemed reasonable
in this proceeding without prior Commission approval, if after the payment of such dividends the
actual average common equity ratio, on a financial basis, would be below the test year authorized
level of 47.50 percent.
30. WEPCO shall submit in its next rate case application detailed information
regarding all off-balance sheet obligations for which the financial markets will calculate a debt
equivalent. The information shall include, at minimum, the minimum annual lease and
purchased power agreement obligations; the method of calculation along with the calculated
amount of the debt equivalent; and supporting documentation, including all reports,
correspondence and any other justification that clearly establish S&P's and other major credit
rating agencies' determination of the off-balance sheet debt equivalent, to the extent available,
and publicly-available documentation if S&P and other credit rating agencies' documentation is
not available.
3 1. WEPCO and WG shall obtain and file proof of credit rating agency treatment of
all capital items along with all credit agency reports and releases related to the companies in their
next rate case application. The applicants shall work with Commission staff to provide the
requested information.
32. WEPCO shall continue its collaborative work with CUB to investigate innovative
rate options, such as new TOD rates, for residential and Small Use customers.
Docket 5-UR- 103
33. WEPCO shall work with Commission staff and any interested parties to develop a
method that reflects how Point Beach costs were allocated to retail customer classes prior to the
sale of that power plant for WEPCO's use in its next rate filing.
34. WEPCO shall provide an accounting of refunds made by tariff class along with a
forecast of tariff class energy use for the third year of the three-year refund period prior to the
utility's next biennial rate application.
35. WEPCO shall discontinue charging for disconnections of electric service.
36. WEPCO shall discontinue charging a Timing Adjustment Factor in its
contributions in aid of construction associated with electric extensions.
37. WG and WE-GO shall file tariffs consistent with this Final Decision.
38. WG and WE-GO shall file an Ovemn Waiver Provision for Metered Demand
Service Charges for all G-6 through G-8 service rate classes consistent with this Final Decision.
The companies shall review the notification requirements set forth in the Overrun Waiver
Provision after six months and voluntarily shorten the notification requirements if appropriate.
39. WG and WE-GO shall place into effect a second set of rates effective for service
January 1, 2009, that reduces the differences at the service rate class breakpoints and improves
cost recovery in an overall revenue-neutral manner.
40. WG shall discontinue its retail meter aggregation billing practices. WG shall
notify TF- 1 through TF-3 transportation customers that received retail meter aggregation service
of a 90-day opportunity to switch to system sales service while the company waives the notice
requirements for service switching. WG shall also notify TF-4 through TF-8 transportation
customers that received meter aggregation service of a willingness to consider requests to switch
Docket 5-UR- 103
to system sales service made within 90 days wherever adequate supply (both capacity and
commodity) exists.
41. WG shall adopt WE-GO'S classification of average peak-day demand gas costs
and average annual demand gas costs. WG shall notify all interruptible supply service customers
of a 90-day opportunity to switch to transportation service while the company waives the notice
requirements for service switching.
42. WG and WE-GO shall revise the default credit for Distribution Capacity with or
without Gas Supply Interruption Crediting Service to 15 percent of the volumetric basic
distribution charges excluding metered demand service charges.
43. The companies shall offer a real time gas usage data service.
44. Jurisdiction is retained.
Dated at Madison, Wisconsin, u
By the Commission:
Sandra J. Paske Secretary to the Commission
See attached Notice of Appeal Rights
Docket 5-UR- 103
Notice of Appeal Rights
Notice is hereby given that a person aggrieved by the foregoing decision has the right to file a petition for judicial review as provided in Wis. Stat. 3 227.53. The petition must be filed within 30 days after the date of mailing of this decision. That date is shown on the first page. If there is no date on the first page, the date of mailing is shown immediately above the signature line. The Public Service Commission of Wisconsin must be named as respondent in the petition for judicial review.
Notice is further given that, if the foregoing decision is an order following a proceeding which is a contested case as defined in Wis. Stat. 5 227.01(3), a person aggrieved by the order has the further right to file one petition for rehearing as provided in Wis. Stat. 3 227.49. The petition must be filed within 20 days of the date of mailing of this decision.
If this decision is an order after rehearing, a person aggrieved who wishes to appeal must seek judicial review rather than rehearing. A second petition for rehearing is not an option.
This general notice is for the purpose of ensuring compliance with Wis. Stat. 3 227.48(2), and does not constitute a conclusion or admission that any particular party or person is necessarily aggrieved or that any particular decision or order is final or judicially reviewable.
Revised 9/28/98
Docket 5-UR- 103
APPENDIX A (CONTESTED)
In order to comply with Wis. Stat. 3 227.47, the following parties who appeared before the agency are considered parties for purposes of review under Wis. Stat. 3 227.53.
Public Service Commission of Wisconsin (Not a party but must be served) 610 N. Whitney Way P.O. Box 7854 Madison, WI 53707-7854
WE ENERGIES Larry J. Martin Brian D. Winters Quarles & Brady LLP 41 1 East Wisconsin Avenue, Suite 2040 Milwaukee, WI 53202
VILLAGE OF CALEDONIA Frank Jablonski Progressive Law Group 354 West Main Street Madison, WI 53703
CITIZENS UTILITY BOARD Curt F. Pawlisch Kira E. Loehr Cullen Weston Pines & Bach LLP 122 West Washington Avenue, Suite 900 Madison. WI 53703
CLEAN WISCONSIN Katie Nekola 122 State Street, Suite 200 Madison, WI 53703
E4 INC. Kathryn Sachs 637 Walton Drive, Suite 1 Plymouth, WI 53073
CITY OF OAK CREEK William J. Mulligan Davis & Kuelthau, S.C. 11 1 East Kilbourn Avenue, Suite 1400 Milwaukee, WI 53202-6613
Docket 5-UR- 103
RENEW WISCONSIN Michael Vickerman 222 South Hamilton Street Madison, WI 53703
WAL-MART STORES EAST, LP, and LOWE'S HOME CENTERS, INC.
Alan Jenkins Jenkins at Law, LLC 1933 Pine Bluff Marietta, GA 30062
WEST ALLIS - WEST MILWAUKEE SCHOOL DISTRICT Michael Mangan 9333 West Lincoln Avenue West Allis, WI 53227
WISCONSIN END-USER GAS AND ELECTRIC ASSOCIATION Darcy Fabrizius PO Box 2226 Waukesha, WI 53 187-2226
WISCONSIN INDUSTRIAL ENERGY GROUP Steven A. Heinzen Godfrey & Kahn, S.C. 1 East Main Street, Suite 500 Madison. WI 53703
WISCONSIN PAPER COUNCIL Earl J. Gustafson PO Box 718 Neenah, WI 54957-07 18
WISCONSIN PUBLIC POWER INC. Paul G. Kent Anderson & Kent, S.C. 1 North Pinckney Street, Suite 200 Madison, WI 53703
WISCONSIN UTILITY INVESTORS, INC. Robert H. Seitz Roger W. Cole 10 East Doty Street, Suite 500 Madison, WI 53703-3397
SCHEDULE 1: AUTHORIZED STEAM REVENUE AND RATE DESIGN
Table 1: Current and Authorized Steam Revenues Rate Schedule Current Revenue Authorized Revenue $ Increase % Increase Y' Agl Downtown Milwaukee Steam $ 18,820,189 $ 20,728,307 $ 1,908,118 lo.l% a
$ 338,287 $ 377,177 $ 38,889 11.5% CI Ag4 Downtown Milwaukee Steam S
Agl Wauwatosa Steam $ 13,625,897 $ 15,318,897 $ 1,693,000 12.4%
Table 2: Current and Authorized Steam Rates Rate Schedule Current Rates Authorized Rates Agl Downtown Milwaukee Steam
Facilities Charge per Customer Day $ 0.660 per Day $ 0.660 per Day Production Energy Charge $ 2.94109 perMLbs $ 4.08175 per MLbs Distribution Energy Charge $ 5.70794 per MLbs $ 5.72571 per MLbs
Ag4 Downtown Milwaukee Steam Facilities Charge per Customer Day $ 3.500 per Day $ 3.500 per Day
Production Energy Charge $ 2.21364 perMLbs $ 3.36423 per MLbs Distribution Energy Charge $ 5.70794 per MLbs $ 5.72571 per MLbs
Agl Wauwatosa Steam Facilities Charge per Customer Day $ 0.500 per Day $ 0.500 per Day
Production Energy Charge $ 13.45905 per MLbs $ 15.34954 per MLbs Distribution Energy Charge $ 4.82547 per MLbs $ 5.27090 per MLbs
Fuel Costs included in Base Production Rates Downtown Milwaukee $ 2.26144 $ per million BTU $ 2.97137 $ per million BTU Wauwatosa $ 2.62942 $ per million BTU $ 3.13319 $ per million BTU
Table 3: Embedded Credits for Service Extensions Rate Schedule Current Credit Authorized Credit Downtown Milwaukee $ 15.00 $ per MLBS $ 13.00 $perMLBS Wauwatosa $ 1 1 .OO $ per MLB S $ 10.00 $ per MLBS
Docket 5-UR-103 Appendix B Page 2 of 11
SCHEDULE 2: AUTHORIZED ELECTRIC REVENLTE AND RATE DESIGN
Table 1: Current and Authorized Class Electric Revenue Changes
% Change % Change Authorized Rates Percent PB Refund PB Refund
Customer Class Current Rates W10 Refund Change in 2008 in 2009
SMALL $1,094,245,604 $1,282,661.923 17.22% 4.76% 4.52% MEDIUM LARGE STR. LGT & OTHER 26,058,360 30,545,922 17.22% 7.24% 3.53%
TOTAL WISCONSIN 2,259,086,492 2,648,151,559 17.22% 3.24% 3.22%
Table 2: Current and Authorized Tariff Rate Revenue Changes
% Change % Change Authorized Rates Percent PB Refund PB Refund
Tariff Rate Current Rates W10 Refund Change in 2008 in 2009
$3619591716 $43131 51370 17.2% 2.7% 5.4% Total Residential & Farm $886,422,901 $1,040,527,903 17.4% 5.0% 4.5%
cG6 $9,717,743 $1 1;269;431 16.0% 1.7% 5.3% Total Small General Secondary $207,822,703 $242,134,019 16.5% 3.7% 4.7%
Total Small Customer Class $1,094,245.604 $1,282,661,923 17.22% 4.8% 4.5%
Cg2 (Medium Customer Class) $1 26,548,093 $148,335,581 17.22% 3.6% 5.0%
cg3 $452,550,600 $524,758,483 15.96% 2.4% 1.3% C ~ ~ A $1,596,220 $1,858,294 16.42% 2.4% 1.4% Cg3C $3,264,397 $3,858,731 18.21% 3.5% 1.4% Total Large General Secondary $457,411,217 $530,475,508 15.97% 2.4% 1.3%
Total General Secondary $791,782,012 $920,945,108 16.31% 2.9% 2.8%
Cpl Low $1 9,530,543 $22,801,577 16.75% 0.6% 1.6% Cpl Medium $428,543.249 $503,107,875 17.40% 0.4% 1.7% Cpl High $4,144,892 $5,005,225 20.76% 1 .O% 1.9% Cp2M Medium $17,328,152 $21,743,630 25.48% 3.3% 2.1% Cp3 Medium $32,659,802 $38,781,298 18.74% 1.2% 1.7% Cp3 High $1 1,947,203 $14,719,025 23.20% 1 .O% 2.2% Cp3A Low $91 9,207 $1,081,849 1 7.69% 1.7% 1.6% Cp3A Medium $16,929,784 $20,041,625 18.38% 0.5% 1.8% CpFN Medium $2,593,236 $3.1 76.476 22.49% 2.0% 2.0% CpFN High $20,227,151 $25,674,043 3.3% 2.3% 26.93% Total General Primary $554,823,218 $656,132.625 18.26% 0.7% 1.7%
Total Large Customer Class $1,012,234,435 $1,186,608.133 17.23% 1.4% 1.5%
GI1 St1 Cg6 All Ms 1 Ms2 Ms3 Ms4 Mg 1 $4,272 $4,640 8.6% 8.6% 0.0% Total Street Lighting & Other 3 17.2% 7.2% 3.5%
Total Wisconsin Retail $2,259,086,492 $2,648,151,559 3.24% 3.22% 17.22%
Docket 5-UR- 103 Appendix B Page 3 of 11
SCHEDULE 2: AUTH. ELECTRIC REVENUE AND RATE DESIGN (Cont.)
Table 3: Current and Authorized Rates Rate Schedule
Rgl -- Residential Service Facilities Charge - Single Phase
Facilities Charge - Three Phase
Extra Meter Charge
Energy Charge - Base
Rg2 -- Residential Service TOU Facilities Charge - Single Phase
Facil~ties Charge - Three Phase
Extra Meter Charge
On-Peak Energy Charge - Base Option A
On-Peak Energy Charge - Base Option B
Off-Peak Energy Charge - Base Option A
Off-Peak Energy Charge - Base Option B
Rg3 -- Residential Service Experimental TOU Facilities Charge - Single Phase
Facilities Charge - Three Phase
Extra Meter Charge
On-Peak Energy Charge - Base Summer
On-Peak Energy Charge - Base Non Summer
Mid-Peak Energy Charge - Base Summer
Mid-Peak Energy Charge - Base Non Summer
Off-Peak Energy Charge - Base Summer
Off-Peak Energy Charge - Base Non Summer
Fgl -- Farm Service Facilities Charge - Single Phase
Facilities Charge - Three Phase
Extra Meter Charge
Energy Charge - Base
Cgl -- General Secondary Service Facilities Charge - Single Phase
Facilities Charge - Three Phase
Extra Meter Charge
Energy Charge - Base Cg2 -- General Secondary Service - Demand
Facilities Charge
Extra Meter Charge
Energy Charge - Base
Regular On-Peak Demand Charge - Base
Low Hours of Use Adjustment per HOU less than 100
Current Rate Authorized Rate
$0.25000 per Day
$0.50000 per Day
$0.04665 per Day
$0.1 1763 per kwh
$0.25000 per Day
$0.50000 per Day
$0.04665 per Day
$0.21589 per kwh
$0.16542 per kwh
$0.05326 per kwh
$0.07519 per kwh
$0.25000 per Day
$0.50000 per Day
$0.04665 per Day
$0.24956 per kwh
$0.17662 per kwh
$0.21589 per kwh
$0.15896 per kwh
$0.05326 per kwh
$0.05326 per kwh
$0.25000 per Day
$0.50000 per Day
$0.04665 per Day
$0.1 1763 per kwh
$0.25000 per Day $0.50000 per Day
$0.04665 per Day $0.1 1763 per kwh
$1.52877 per Day
$0.13151 perDay
$0.095 1 1 per kwh
$5.60200 per kW
$0.03361 per kW
Docket 5-UR-103 Appendix B Page 4 of 11
SCHEDULE 2: AUTH. ELECTRIC REVENUE AND RATE DESIGN (Cont.)
Table 3: Current and Authorized Rates Rate Schedule
Cg3 -- General Secondary Service - DemandROU Facilities Charge Extra Meter Charge On-Peak Energy Charge - Base
Off-Peak Energy Charge - Base
Regular On-Peak Demand Charge - Base
Low Hours of Use Adjustment per HOU less than 100
Customer Demand Charge Cg3a -- Gen. Sec. - Energy Coop. Curtailable
Facilities Charge
Extra Meter Charge On-Peak Energy Charge - Base Off-Peak Energy Charge - Base
Regular On-Peak Demand Charge - Base Low Hours of Use Adjustment (per HOU less than 100)
Customer Demand Charge
Curtailable Credit
Cg3c -- Gen. Sec. -Experimental Curtailable Facilities Charge
Extra Meter Charge On-Peak Energy Charge - Base
Off-Peak Energy Charge - Base Regular On-Peak Demand Charge - Base Low Hours of Use Adjustment per HOU less than 100
Customer Demand Charge Curtailable Credit (per On-Peak HOU)
Cg6 -- General Secondary Service - TOU Facilities Charge - Single Phase Facilities Charge - Three Phase Extra Meter Charge
On-Peak Energy Charge - Base Option A On-Peak Energy Charge - Base Option B Off-Peak Energy Charge - Base Option A
Off-Peak Energy Charge - Base Option B ERERl & ERER3 Renewable Rider
Energy for Tomorrow - 25%
Energy for Tomorrow - 50%
Energy for Tomorrow - 100%
ERER2 Renewable Rider
Energy for Tomorrow - < 70,000 kWh per month
Energy for Tomorrow - >= 70,000 kWh per month
Current Rate Authorized Rate -
$1.52877 $1.52877 per Day
$0.13151 $0.13151 per Day
$0.06750 $0.07342 per kWh
$0.03894 $0.05366 per kWh
$10.81600 $11.20500 per kW
$0.06490 $0.06723 per kW
$1.3 1000 $1.75700 per kW
$3.41918 per Day
$0.13 151 per Day
$0.07342 per kWh
$0.05366 per kWh
$1 1.20500 per kW
$0.06723 per kW
$1.75700 per kW
$2.00000 per kW
$3.41918 per Day
$0.13151 perDay
$0.07342 per kWh
$0.05366 per kWh $1 1.20500 per kW
$0.06723 per kW
$1.75700 per kW $0.02080 per kW
$0.26 175 $0.25000 per Day $0.52350 $0.50000 per Day $0.041 10 $0.04665 per Day
$0.20017 $0.21 589 per kWh NA $0.16542 per kWh
$0.03826 $0.05326 per kWh
NA $0.07519 per kWh
$0.00343 $0.00343 per kWh
$0.00685 $0.00685 per kWh
$0.01370 $0.01370 per kWh
$0.01370 $0.01370 per kWh
$0.01000 $0.01000 per kWh
Docket 5-UR-103 Appendix B Page 5 of 11
SCHEDULE 2: AUTH. ELECTRIC REVENUE AND RATE DESIGN (Cont.)
Table 3: Current and Authorized Rates
ERER4 Renewable Rider Energy for Tomorrow - 25%
Energy for Tomorrow - 50%
Energy for Tomorrow - 100%
Cpl -- General Primary Service - TOU Facilities Charge
On-Peak Energy Charge - Base (Low Voltage)
On-Peak Energy Charge - Base (Medium Voltage)
On-Peak Energy Charge - Base (High Voltage)
Off-Peak Energy Charge - Base (Low Voltage)
Off-Peak Energy Charge - Base (Medium Voltage)
Off-Peak Energy Charge - Base (High Voltage)
On-Peak Demand Charge - Base (Low Voltage)
On-Peak Demand Charge - Base (Meduim Voltage)
On-Peak Demand Charge - Base (High Voltage)
Customer Demand Charge (Low Voltage)
Customer Demand Charge (Medium Voltage)
Customer Demand Charge (High Voltage)
CplR -- Gen. Pri. - Experimental Real-Time Pricing Facilities Charge
Access On-Peak Demand Charge (Low Voltage)
Access On-Peak Demand Charge (Medium Voltage)
Access On-Peak Demand Charge (High Voltage)
Access Customer Demand Charge (Low Voltage)
Access Customer Demand Charge (Medium Voltage)
Access Customer Demand Charge (High Voltage)
Cp2M -- General Primary Service - Interruptible Facilities Charge
On-Peak Energy Charge - Base (Medium Voltage) On-Peak Energy Charge - Base (High Voltage)
Off-Peak Energy Charge - Base (Medium Voltage)
Off-Peak Energy Charge - Base (High Voltage)
On-Peak Demand Charge - Base (Medium Voltage) On-Peak Demand Charge - Base (High Voltage)
Customer Demand Charge (Medium Voltage)
Customer Demand Charge (High Voltage)
Current Rate Authorized Rate
$0.00250 per kwh
$0.00500 per kwh
$0.0 1000 per kwh
$17.26027 per Day
$0.06754 per kwh
$0.06649 per kwh
$0.06560 per kwh
$0.04733 per kwh
$0.04659 per kwh
$0.045 14 per kwh
$10.90800 per kW
$10.73800 per kW $10.59500 per kW
$1.02300 per kW
$1.00700 per kW
$0.00000 per kW
$23.01370 per Day
$10.90800 per kW
$10.73800 per kW
$10.59500 per kW
$1.02300 per kW
$1.00700 per kW
$0.00000 per kW
$26.30137 per Day
$0.063 17 per kwh $0.063 17 per kwh
$0.04426 per kwh
$0.04426 per kwh
$5.37800 per kW
$5.37800 per kW $1.00700 per kW
$0.00000 per kW
Docket 5-UR- 103 Appendix B Page 6 of 1 1
SCHEDULE 2: AUTH. ELECTRIC REVENUE AND RATE DESIGN (Cont.) I Table 3: Current and Authorized Rates
Rate Schedule
Cp3 -- Gen. Pri. Service - Curtailable
Facilities Charge
On-Peak Energy Charge - Base (Low Voltage)
On-Peak Energy Charge - Base (Medium Voltage)
On-Peak Energy Charge - Base (High Voltage)
I Off-Peak Energy Charge - Base (Low Voltage)
I Off-Peak Energy Charge - Base (Medium Voltage)
Off-Peak Energy Charge - Base (Bgh Voltage)
On-Peak Demand Charge - Base (Low Voltage)
On-Peak Demand Charge - Base (Medium Voltage)
On-Peak Demand Charge - Base (High Voltage)
Customer Demand Charge (Low Voltage)
Customer Demand Charge (Medium Voltage)
Customer Demand Charge (High Voltage)
Curtailable Credit (Low Voltage) per On Peak HOU
Curtailable Credit (Medium Voltage) per On Peak HOU
Curtailable Credit (High Voltage) per On Peak HOU
Cp3A -- Gen. Pri. - Energy Coop. Curtailable
Facilities Charge
On-Peak Energy Charge - Base (Low Voltage)
On-Peak Energy Charge - Base (Medium Voltage)
On-Peak Energy Charge - Base (High Voltage)
Off-Peak Energy Charge - Base (Low Voltage)
Off-Peak Energy Charge - Base (Medium Voltage)
Off-Peak Energy Charge - Base (High Voltage) On-Peak Demand Charge - Base (Low Voltage)
On-Peak Demand Charge - Base (Medium Voltage)
On-Peak Demand Charge - Base (High Voltage)
Customer Demand Charge (Low Voltage) Customer Demand Charge (Medium Voltage)
Customer Demand Charge (High Voltage) Curtailable Credit (Low Voltage)
Curtailable Credit (Medium Voltage)
Curtailable Credit (High Voltage)
Current Rate Authorized Rate 7
$17.26027 per Day
$0.06754 per kwh
$0.06649 per kwh
$0.06560 per kwh
$0.04733 per kwh
$0.04659 per kwh
$0.045 14 per kwh
$10.90800 per kW
$10.73800 per kW
$10.59500 per kW
$1.02300 per kW
$1.00700 per kW
$0.00000 per kW
$0.02028 per kW
$0.02000 per kW
$0.01970 per kW
$17.26027 per Day
$0.06754 per kwh
$0.06649 per kwh
$0.06560 per kwh
$0.04733 per kwh
$0.04659 per kwh
$0.04514 per kwh
$10.90800 per kW
$10.73800 per kW
$10.59500 per kW
$1.02300 per kW $1.00700 per kW
$0.00000 per kW $2.00000 per kW
$2.00000 per kW
$2.00000 per kW
Docket 5-UR- 103 Appendix B Page 7 of 11
SCHEDULE 2: AUTH. ELECTRIC REVENLTl3 AND RATE DESIGN (Cont.)
Table 3: Current and Authorized Rates Rate Schedule
Cp4 -- Gen. Pri. Service - Optional Standby Facilities Charge
Extra Meter Charge
On-Peak Energy Charge - Base (Low Voltage)
On-Peak Energy Charge - Base (Medium Voltage)
On-Peak Energy Charge - Base (High Voltage)
Off-Peak Energy Charge - Base (Low Voltage)
Off-Peak Energy Charge - Base (Medium Voltage)
Off-Peak Energy Charge - Base (High Voltage)
On-Peak Demand Charge - Base (Low Voltage)
On-Peak Demand Charge - Base (Medium Voltage)
On-Peak Demand Charge - Base (High Voltage)
Customer Demand Charge (Low Voltage)
Customer Demand Charge (Medium Voltage)
Customer Demand Charge (High Voltage)
Reserved Demand Charge (Low Voltage)
Reserved Demand Charge (Medium Voltage)
Reserved Demand Charge (High Voltage)
Standby Energy Charge (Low Voltage)
Standby Energy Charge (Medium Voltage)
Standby Energy Charge (High Voltage)
CpFN -- Gen Pri. Combined Firm & Non Firm Facilities Charge
On-Peak Firm Energy Charge - Base (Medium Voltage)
On-Peak Firm Energy Charge - Base (High Voltage)
On-Peak Non Firm Energy Charge - Base (Medium Voltage)
On-Peak Non Firm Energy Charge - Base (High Voltage)
Off-Peak Firm Energy Charge - Base (Medium Voltage)
Off-Peak Firm Energy Charge - Base (High Voltage) Off-Peak Non Firm Energy Charge - Base (Medium Voltage)
Off-Peak Non Firm Energy Charge - Base (High Voltage)
On-Peak Firm Demand Charge - Base (Medium Voltage)
On-Peak Firm Demand Charge - Base (High Voltage) On-Peak Non Firm Demand Charge - Base (Medium Voltage)
On-Peak Non Firm Demand Charge - Base (High Voltage)
Customer Demand Charge (Medium Voltage)
Customer Demand Charge (High Voltage)
Current Rate Authorized Rate
$17.26027 $17.26027 per Day
$6.57534 $6.57534 per Day
$0.06213 $0.06754 per kwh
$0.06127 $0.06649 per kwh
$0.06031 $0.06560 per kWh
$0.03354 $0.04733 per kWh
$0.03305 $0.04659 per kwh
$0.03120 $0.04514 per kWh
$10.52100 $10.90800 per kW
$10.38000 $10.73800 per kW
$10.21600 $10.59500 perkW
$0.77000 $1.02300 per kW
$0.76000 $1.00700 per kW
$0.00000 $0.00000 per kW
$1.78100 $1.95714 per kW
$1.77600 $1.92666 per kW
$1.00000 $0.90760 per kW OOPC + 10% OOPC + 10% per kWh
OOPC + 10% OOPC + 10% per kwh OOPC + 10% OOPC + 10% per kWh
$26.30137 per Day
$0.06649 per kWh
$0.06560 per kWh
$0.06317 per kwh
$0.06232 per kwh
$0.04659 per kwh
$0.045 14 per kwh $0.04426 per kwh
$0.04288 per kwh
$10.73800 per kW
$10.59500 per kW
$5.37800 per kW $5.23500 per kW
$1.00700 per kW
$0.00000 per kW
Docket 5-UR-103 Appendix B Page 8 of 11
SCHEDULE 2: AUTH. ELECTRIC REVENUE AND RATE DESIGN (Cont.)
Table 3: Current and Authorized Rates Rate Schedule
CGSl Customer-Owned Generation Facilities Charge - Non Demand Metered
Facilities Charge - Demand Metered
On-Peak Purchase Price Secondary Voltage
On-Peak Purchase Price Primary < 69 kV
On-Peak Purchase Price Primary >= 69 kV
Off-Peak Purchase Price Secondary Voltage
Off-Peak Purchase Price Primary < 69 kV
Off-Peak Purchase Price Primary >= 69 kV
CGS3 Customer-Owned Generation Facilities Charge
Capacity Payment Secondary Voltage
Capacity Payment Primary < 69 kV
Capacity Payment Primary >= 69 kV
Dispatched Energy Flowing Into System Secondary
Dispatched Energy Flowing Into System Pri <69 kV
Dispatched Energy Flowing Into System Pri >= 69 kV
Dispatched Displaced Energy Secondary
Dispatched Displaced Energy Primary < 69 kV
Dispatched Displaced Energy Primary >= 69 kV
Purchased Non-Dispatched Energy Secondary
Purchased Non-Dispatched Energy Primary < 69 kV
Purchased Non-Dispatched Energy Primary >= 69 kV
St1 -- Optional TOU Street Lighting Service Facilities Charge - Single Phase
Facilities Charge - Three Phase
Extra Meter Charge
On-Peak Energy Charge Off-Peak Energy Charge
Current Rate Authorized Rate -
$0.04 110 per Day
$0.1 1507 per. Day
$0.07 150 per kwh
$0.07450 per kwh
$0.07330 per kwh
$0.04009 per kwh
$0.04176 per kwh
$0.04109 per kwh
$4.93 15 1 per Day
$4.92000 per kW
$5.12500 per kW
$5.04200 per kW
$0.11711 per kwh
$0.12199 per kwh
$0.12002 per kwh
$0.02543 per kwh
$0.0303 1 per kwh
$0.02834 per kwh
$0.04009 per kwh
$0.04176 per kwh
$0.04109 per kwh
$0.26175 $0.26175 per Day
$0.52350 $0.52350 per Day
$0.041 10 $0.041 10 per Day $0.20016 $0.21492 per kwh
$0.03588 $0.05082 per kwh
Docket 5-UR-103 Appendix B Page 9 of 11
SCHEDULE 2: AUTH. ELECTRIC REVENUE AND RATE DESIGN (Cont.)
Table 3: Current and Authorized Rates Rate Schedule
GI1 - Area Lighting Standard High Pressure Sodium
50 Watt
70 Watt
100 Watt
150 Watt
200 Watt
250 Watt
400 Watt
Flood High Presure Sodium
70 Watt
100 Watt
150 Watt
200 Watt
250 Watt
400 Watt
Flood Metal Halide
175 Watt
250 Watt
400 Watt
1000 Watt Standard Metal Halide
175 Watt
250 Watt
400 Watt
Poles
Spans All - Alley Lighting
50 Watt 70 Watt 100 Watt
Msl - Highway Lighting Facilities - 75 Watts or Less
Facilities - Greater than 75 Watts Energy Charge - Base
Current Rate Authorized Rate -
$8.06 $10.49 per Month
$8.92 $1 1.50 per Month $10.28 $13.15 per Month
$11.71 $15.01 per Month
$13.85 $17.49 per Month
$15.40 $19.59 per Month
$20.45 $25.36 per Month
$11.84 $13.68 per Month
$13.10 $15.24 per Month
$14.77 $17.06 per Month
$17.48 $18.90 per Month
$19.05 $21.07 per Month
$23.97 $26.53 per Month
$25.62 per Month
$25.97 per Month
$29.98 per Month
$56.13 per Month
$23.97 per Month
$24.77 per Month
$28.79 per Month
$2.57 per Month $2.15 per Month
$3.99 per Month $4.90 per Month
$6.45 per Month
$3.03 per Month
$4.86 per Month $0.1 1763 per kwh
Docket 5-UR- 103 Appendix B Page 10 of 11
SCHEDULE 2: AUTH. ELECTRIC REVENUE AND RATE DESIGN (Cont.)
Table 3: Current and Authorized Rates Rate Schedule Current Rate Authorized Rate
Ms2 - Street Lighting Energy Charge - Base $0.08989 $0.10587 per kwh
Ms3 - Street Lighting =gh Pressure Sodium Lamps
50 Watt $8.53 $10.49 per Month 70 Watt $9.37 $1 1.50 per Month 100 Watt $10.90 $13.15 perMonth
150 Watt $12.43 $15.01 per Month 200 Watt $15.04 $17.49 per Month
250 Watt $16.94 $19.59 per Month 400 Watt $22.07 $25.36 per Month
Metal Halide Lamps 175 Watt $17.83 $23.97 per Month
250 Watt $18.96 $24.77 per Month 400 Watt $22.79 $28.79 per Month
Ms4 - Street Lighting Facilities Charge - Option A
Facilities Charge - Option B
Non-Standard Lamps 50 Watt HPS 70 Watt HPS
100 Watt HPS
150 Watt HPS 175 Watt MH
200 Watt HPS 250 Watt HPS 400 Watt HPS 1000 Watt HPS
Mgl - Municipal Defense Sirens Facilities Charge Energy Charge - Base
1.9% per Month
0.5% per Month
$1.9 1 per Month $2.82 per Month
$4.36 per Month
$6.19 per Month $7.01 per Month $8.19 per Month
$10.18 perMonth $15.74 per Month $36.66 per Month
$2.90 per Month
$0.11763 per kwh
SCHEDULE 3: AUTHORIZED ELECTRIC CREDITS
Table 1: Point Beach Proceeds Refund Credits Small, Medium and Streetlighting & Other Customer Classes Rgl,Rg2,Rg3,Fg1,Cgl,Cg2,G11,Stl,All,Msl,Ms2,Ms3,Ms4,Mgl Refund Credit
Energy Credit - PBNP Proceeds Refund (2008 Value) ($0.01348) per kWh Energy Credit - PBNP Proceeds Refund (2009 Value) ($0.00836) per kWh
Large Customer Classes Cg3, Cg3A, Cg3C, Cpl, Cp2m, Cp3, Cp3A, Cp4, CpFN Refund Credit
Energy Credit - PBNP Proceeds Refund (2008 Value) ($0.01 127) per kWh Energy Credit - PBNP Proceeds Refund (2009 Value) ($0.01015) per kWh
Table 2: Act 141 Costs and Unit Refunds for Qualifying Customers Residential Classes Act 141 Costs in Rates
Rgl, Rg2, Rg3, Fgl $0.00125 per kWh Unit Refund To Non-Qualifying Customers $0.00000 per kWh
Non-Residential Classes Act 141 Costs in Rates Cgl, Cg2, Cg3, Cg3A, Cg3C, Cpl, Cp2m, Cp3, Cp3A, Cp4, CpFN $0.00088 per kWh
Unit Refund To Non-Qualifying Customers $0.00000 per kWh Unit Refund to Oualifving Large Customers ($0.00054) ~ e r kWh
Table 3: Embedded Credits for Line Extensions Customer Tariff Rate Class Current Credit Authorized Credit
Rgl, Rg2, Rg3 & Fgl Single Phase Rg 1, Rg2, Rg3 & Fgl Three Phase Cg 1 & Cg6 Single Phase Cg 1 & Cg6 Three Phase Cg2, Cg3, Cg3A & Cg3C General Primary Standard Street Lighting
$661 $752 per Customer $1,984 $2,256 per Customer $1,008 $919 per Customer $2,016 $1,838 per Customer
$168 $126 perkW $83 $107 perkW $53 $41 per Lamp
Docket 5-UR- 103
WISCONSIN ELECTRIC POWER COMPANY
Appendix B Schedule 4
Page 1 of 34
Volume 19 - Electric Rates Revision 15 Sheet 19 Effective In All Areas Served In Wisconsin Amendment No. xxx
COST OF FUEL ADJUSTMENT
A cost of fuel adjustment is applicable to the rate schedules indicated below. The cost of fuel adjustmentR is $0.00 per kwh.
RATE SCHEDULE Rg 1 Rg 2 Rg 3 Fg 1 c g 1 c g 2 c g 3 Cg 3a Cg 3c c g 6 CP 1
Cp 1 R2 Cp FN CP 2M CP 3
Cp 3A CP 4 Ms 1 Ms 2 Ms 3 Ms 4 GI 1 Al I St 1 TE 1
Mg 1 (metered only) CGS 2 (only when a net purchaser from Company) CGS 4 (only when a net purchaser from Company)
(Continued to Sheet No. 20)
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103
WISCONSIN ELECTRIC POWER COMPANY
Appendix B Schedule 4
Page 2 of 34
Volume 19 - Electric Rates Revision 5 Sheet 20.1 Effective In All Areas Served In Wisconsin Amendment No. xxx
RESERVEDFORFUTUREUSE
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103 Appendix B Schedule 4
Page 3 of 34 WISCONSIN ELECTRIC POWER COMPANY
Volume 19 - Electric Rates Revision 0 Sheet 20.2 Effective In All Areas Served In Wisconsin Amendment No. xxx
POINT BEACH SALE CREDIT
The rate schedules indicated below shall receive a Point Beach sale credit of $0.01348 per kwh.
RATE SCHEDULE Rg 1 Rg 2 Rg 3 Fg 1 c g 1 c g 2 c g 6 Ms 1 Ms 2 Ms 3 Ms 4 GI 1 Al I St 1 Mg 1 TE 1
The rate schedules indicated below shall receive a Point Beach sale credit of $0.01 127 per kwh.
RATE SCHEDULE Cg 3 Cg 3a Cg 3c CP 1
Cp 1 R2 Cp l R CP 2M CP 3
Cp 3A CP 4
Cp FN
Any customer served under rate schedule CGS2 or CGS4 will receive the Point Beach Sale Credit which applies to the applicable rate schedule when the customer is a net purchaser of energy from the Company.
(Continued to Sheet No. 21)
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103
WISCONSIN ELECTRIC POWER COMPANY
Appendix B Schedule 4
Page 4 of 34
Volume 19 - Electric Rates Revision 5 Sheet 23 Amendment No. xxx
Effective In All Areas Served In Wisconsin Rate Schedule Rq 2
RESIDENTIAL SERVICE -- TIME-OF-USE
AVAILABLE
To residential customers contracting for electric service for domestic purposes for a period of one year or more. Either this rate or the Rg3 rate, as chosen by the customer, is mandatory as prescribed in Docket No. 6630-UR-101, for residential customers or successor customers at the same premises whose annual consumption exceeds 60,000 kwh. (a) Available on a voluntary basis for residential and farm customers; a voluntary customer may be removed from the rate upon their request, however the customer will not be allowed back on this rate for 12 months. Both mandatory and voluntary customers are required to remain on the selected on-peak period (b) for at least one year.
(a) Those mandatory customers whose annual consumption drops below 45,000 kwh will be allowed, upon request, to take service under, the Regular Residential, Rg 1 rate.
RATE
Facilities Charae, including one meter Single Phase $.25000 per day Three Phase $.50000 per day
Enerav Charae, per kwh Customers may select one of either OPTION A energy rates or OPTION B energy rates as follows:
OPTION A On-Peak Energy (b) $0.21 589 Off-Peak Energy (c) $0.05326
OPTION B On-Peak Ener~lv (b) $0.1 6542
- < . , Off-Peak Energy (c) $0.0751 9
(b) Residential on-peak energy usage is the energy in kilowatt hours delivered during the on-peak period selected by the customer. The four on-peak periods available are:
prevailing time, Monday through Friday, excluding those days designated as legal holidays for New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day and Christmas Day.
(Continued to Sheet No. 24)
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR-103
WISCONSIN ELECTRIC POWER COMPANY
Appendix B Schedule 4
Page 5 of 34
Volume 19 - Electric Rates Revision 0 Sheet 24.1 Amendment No. xxx
Effective In All Areas Served In Wisconsin Rate Schedule Rg 3 N
RESIDENTIAL SERVICE - EXPERIMENTAL 3-TIER TIME-OF-USE
AVAILABLE
To residential customers contracting for electric service for domestic purposes for a period of one year or more. Either this rate or the Rg2 rate, as chosen by the customer, is mandatory as prescribed in Docket No. 6630-UR-101, for residential customers or successor customers at the same premises whose annual consumption exceeds 60,000 kwh. (a) Available on a voluntary basis for residential and farm customers; a voluntary customer may be removed from the rate upon their request, however the customer will not be allowed back on this rate for 12 months. Both mandatory and voluntary customers are required to remain on the selected on-peak period (b) for at least one year. This experimental rate will be available for 3 years from the effective date of this tariff.
(a) Those mandatory customers whose annual consumption drops below 45,000 kwh will be allowed, upon request, to take service under the Regular Residential, Rg 1 rate.
RATE
Facilities Charae, including one meter Single Phase $.25000 per day Three Phase $.50000 per day
Enerav Charae, per kwh Summer Enerav Charaes a ~ ~ l v from June 1"'- Se~tember 30th On-Peak Energy (b) $0.24956 Mid-Peak Energy (b) $0.21 589 Off-Peak Energy (c) $0.05326
IVon-summer Enerav Charaes a ~ ~ l v from October 1 "' - Mav 31 st On-Peak Energy (b) $0.1 7662 Mid-Peak Energy (b) $0.1 5896 Off-Peak Energy (c) $0.05326
(b) Residential on-peak energy usage and mid-peak energy usage are the energy in kilowatt hours delivered during the on-peak and mid-peak periods, respectively. The on-peak period is 2p.m.- 6p.m. and the mid-peak periods are 8a.m.- 2p.m. and 6p.m.- 8p.m. Both the on- peak and mid-peak periods apply at the prevailing time, Monday through Friday, excluding those days designated as legal holidays for New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day and Christmas Day.
(Continued to Sheet No. 24.2)
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103
WISCONSIN ELECTRIC POWER COMPANY
Appendix B Schedule 4
Page 6 of 34
Volume 19 - Electric Rates Revision 0 Sheet 24.2 Amendment No. xxx
Effective In All Areas Served In Wisconsin Rate Schedule Rg 3 N
RESIDENTIAL SERVICE - EXPERIMENTAL 3-TIER TIME-OF-USE
(Continued from Sheet No. 24.1)
(c) Residential off-peak energy usage is the energy in kilowatt-hours delivered during all hours other than on-peak or mid-peak hours.
Point Beach Sale Credit
See Sheet No. 20.2
Adjustment for Cost of Fuel
See sheet Nos. 19 and 20.
Transmission Adiustment
See Sheet No. 20.1.
Meter Charae
The monthly meter charge for each meter in excess of one shall be $.04665 per day.
Minimum Charae
The monthly minimum charge for a single or multi-unit dwelling shall be the facilities charge, plus the meter charge.
Late Pavment Charae
A one percent (1%) per month late payment charge will be applied to outstanding charges past due.
CONDITIONS OF DELIVERY
See Sheet Nos. 25 through 29.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103
WISCONSIN ELECTRIC POWER COMPANY
Appendix B Schedule 4
Page 7 of 34
Volume 19 - Electric Rates Revision 2 Sheet 37 Amendment No. xxx
Effective In All Areas Served In Wisconsin Rate Schedule Cg 2
GENERAL SECONDARY SERVICE -- DEMAND
AVAILABILITY
This rate is mandatory for customers contracting for secondary electric service for one year or more for R general commercial, industrial or governmental purposes, and whose energy consumption is equal to or greater than 10,000 kwh a month for any 3 months out of a 12 month period.
Customers who meet the availability criteria of the Cg 2 rate, who were previously served under rate schedule Cg 3, who qualify to be removed from the Cg 3 rate, will be mandated to the Cg 2 rate immediately.
(a) A customer whose latest 12 months total consumption drops below 100,000 kilowatt hours and who has not had more than one month's usage in excess of 10,000 kilowatt hours will be removed from the Cg2 rate and will be required to take service under the regular general secondary rate available in the area for which they qualify, and will remain on that rate so long as that customer's consumption does not exceed 10,000 kilowatt hours per month for any 3 out of 12 months.
(b) Generally a new customer or existing customer will not be billed on this rate until after there have been 3 months' usage during a 12 month period in excess 10,000 kilowatt. The customer must remain on this rate classification for 12 months before becoming eligible to request a transfer to a different general secondaryrate as outlined in above.
(Continued to Sheet No. 38)
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103
WISCONSIN ELECTRIC POWER COMPANY
Appendix B Schedule 4
Page 8 of 34
Volume 19 - Electric Rates Revision 2 Sheet 40 Amendment No. xxx
Effective In All Areas Served In Wisconsin Rate Schedule Cg 3
GENERAL SECONDARY SERVICE - DEMAND/TIME-OF-USE
AVAILABILITY
This is a mandatory rate for customers contracting for secondary electric service for one year or more R for general commercial, industrial or governmental purposes, and whose energy consumption is equal to or greater than 30,000 kwh a month for any 3 months out of 12 month period. Also available, on a voluntary basis for a period of one year or more, to a limited number of secondary customers who utilize renewable energy systems (wood excepted), energy storage systems requiring electric energy as the supplemental or sole source, or those who generate electricity in excess of their own needs. (a)(b)
(a) A customer whose latest 12 months total consumption drops below 300,000 kilowatt hours and who has not had more than one month's usage in excess of 30,000 kilowatt hours will be removed from the Cg3 rate and will be required to take service under the general secondary rate available in the area for which they qualify, and will remain on that rate so long as that customer's consumption does not exceed 30,000 kilowatt hours per month for any 3 out of 12 months.
(b) Generally a new customer or existing customer will not be billed on this rate until after there have been 3 months' usage in excess of 30,000 kilowatt hours during a 12 month period. The customer must remain on this rate classification for 12 months before becoming eligible to request a transfer to a different general secondary rate as outlined in (a) above.
RATE
Facilities Charae, including one meter $1 52877 per day
(Continued to Sheet No. 41)
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103
WISCONSIN ELECTRIC POWER COMPANY
Appendix B Schedule 4
Page 9 of 34
Volume 19 - Electric Rates Revision 6 Sheet 60 Amendment No. xxx
Effective In All Areas Served In Wisconsin Rate Schedule Cg 6
GENERAL SECONDARY SERVICE -- TIME-OF-USE
AVAILABILITY
Available, on a voluntary basis, for a period of one year or more, to customers contracting for secondary electric service for general commercial, industrial or governmental purposes.
This rate will be available on an optional basis to customers formerly served on the incandescent street lighting, Ms 2, rate regardless of energy consumption level.
RATE
Facilities Charae, including one meter Single-phase $.25000 per day R Three-phase $.50000 per day R
Enerav Charae. per kwh, Customers may select one of either OPTION A energy rates or R
OPTION B energy rates as follows: OPTION A:
On-peak energy (a) Off-peak energy (b)
OPTION B: On-peak energy (a) Off-peak energy (b)
(a) Small secondary on-peak energy usage is the energy in kilowatt-hours delivered between 9:00 a.m. and 9:00 p.m., prevailivg time, Monday through Friday, excludivg those days designated as legal holidays for New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day and Christmas Day.
(b) Small Secondary off-peak energy usage is the energy in kilowatt hours delivered during all hours other than on-peak hours.
Point Beach Sale Credit
See Sheet No. 20.2 N
Adiustment for Cost of Fuel
See Sheet Nos. 19 and 20.
Transmission Adiustment
See Sheet No. 20.1.
(Continued to Sheet No. 61)
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103
WISCONSIN ELECTRIC POWER COMPANY
Appendix B Schedule 4
Page 10 of 34
Volume 19 - Electric Rates Revision 4 Sheet 81.1 Amendment No. xxx
Effective In All Areas Served In Wisconsin Rate Schedule Cp FN
GENERAL PRIMARY SERVICE - COMBINED FIRM and NON-FIRM SERVICE
AVAILABILITY
For customers contracting for three-phase 60 hertz power service at approximately 13,200 volts or higher R for a period of at least three years with a monthly 15 minute integrated demand of at least 1,000 kilowatts of interruptible load. Customers are required to remain on the selected on-peak period for at least one year. The Company reserves the right to restrict participation under this tariff to a program maximum of 150 MW contracted interruptible load. Any customer denied service under this tariff has a right to appeal this denial to the Public Service Commission of Wisconsin. The Company further reserves the right to add a curtailable option to this tariff, subject to PSCW approval.
Customers participating in this rate schedule shall enter into a contract which specifies a firm service level above which all additional load, a minimum of 1,000 kilowatts, is interruptible by the Company and is treated and billed as such per the RATE and CONDl1-IONS OF DELIVERY sections of this tariff.
RATE
Facilities Charue $26.301 37 per day
Demand Charues For Service at Primarv Voltaaes
Equal to or Greater than 13,200 volts Equal to or
and Less than Greater than 138,000 volts 138,000 volts
All Billed on-peak firm demand per kW $1 0:73800 $1 0.59500
All Billed on-peak non-firm demand per kW $5.37800 $5.23500 (minimum of 1,000 kW beyond firm load)
All customer maximum demand per kW $1.00700 $0.00000
Billed on-peak firm demand and customer maximum demand are as determined on Sheet No. 81.3- 81.6
(Continued to Sheet No. 81.2)
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103 Appendix B Schedule 4
Page 11 of 34 WISCONSIN ELECTRIC POWER COMPANY Volume 19 - Electric Rates Revision 1 Sheet 81.4
Amendment No. xxx Effective In All Areas Served In Wisconsin Rate Schedule Cp FN
GENERAL PRIMARY SERVICE - COMBINED FIRM and NON-FIRM SERVICE
(Continued from Sheet No. 81.3)
DETERMINATION OF DEMAND (continued) (c) Contract firm service level shall be the firm service level as determined by a contract
(service agreement) entered into by the Company and subscribers to this rate. The customer may re-nominate a contract firm service level once during a calendar year subject to approval by the Company. The contract firm service level may be increased by no more than 20% on an annual basis and no more than 30% during any period equivalent to the original term of the contract. At the sole discretion of the Company, other customer requests to waive this cancellation fee may be considered and granted, but only under extraordinary circumstances such as a systemic and sustained change in Customer production levels.
Note that the firm service level nominated can be zero such that all consumption will be R billed as non-firm.
(d) Measured on-peak firm demand shall be determined by the following criteria:
If the customer contracts for a firm service level of 0 kW, the measured on-peak firm demand shall be 0 kW. However, if the contract firm service level is greater than zero, the measured on-peak firm demand shall be that portion of measured on-peak demand that does not exceed the contract firm service level.
(e) Measured on-peak non-firm demand shall be equal to the measured on-peak demand minus the measured on-peak firm demand.
(f) Measured off-peak demand shall be the maximum demand within the billing period which is established during off-peak hours for the billing period. Off-peak hours are those hours not designated as on-peak hours.
(g) Measured off-peak firm demand shall be determined by the following criteria:
If the customer contracts for a firm service level of 0 kW, the measured off-peak firm demand shall be 0 kW. However, if the contract firm service level is greater than zero, the measured off-peak firm demand shall be that portion of measured off-peak demand that does not exceed the contract firm service level.
(h) Measured off-peak non-firm demand shall be equal to the measured off-peak demand minus the measured off-peak firm demand.
(i) Customer maximum demand shall be the maximum measured demand, not adjusted for power factor, which occurs during either the on or off-peak period, in the current or preceding 11 billing periods.
(Continued to Sheet No. 81.5)
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103 Appendix B Schedule 4
Page 12 of 34 WISCONSIN ELECTRIC POWER COMPANY Volume 19 - Electric Rates Revision 1 Sheet 81.7
Amendment No. xxx Effective In All Areas Served In Wisconsin Rate Schedule Cp FN
GENERAL PRIMARY SERVICE - COMBINED FIRM and NON-FIRM SERVICE
(Continued from Sheet No. 81.6)
CONDITIONS OF DEI-IVERY
(2) Service under this rate is primarily for customers who use it in manufacturing and industrial operations. Any customer receiving service under this rate who requires lighting regulation shall furnish, install, operate and maintain the necessary regulating equipment at his expense.
(3) The customer shall, at his expense, install all apparatus and materials necessary for the proper utilization of the power furnished by the Company. All such apparatus shall conform to the Company's rules and regulations pertaining to primary substation installation and shall at all times be kept suitable for operation by the power furnished.
(4) If the customer's off-peak demand exceeds the on-peak demand to the extent that the installation of additional facilities is required, then the customer shall pay for such additional facilities. R
(5) Unless specified to the contrary in writing by six months prior to written notice to customer, provided the on-peak period does not exceed twelve hours per day, on-peak hours shall be either from 8:00 a.m. to 8:00 p.m. or from 10:OO a.m. to 10:OO p.m., as selected by the customer, preva~ling time, Monday through Friday, excluding those days designated as legal holidays for New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day and Christmas Day.
(6) The Company will furnish auxiliary service under this rate to a customer who operates his power plant. For such service the customer's net yearly bill shall be not less than $15.00 per kilovolt- ampere or equivalent kilovolt-ampere output rating of all customer's power plant equipment that supplies load which can be transferred from the customer's to the Company's system or the k~lovolt-ampere rating of the customer's substation capacity able to serve such loads, whichever R is the smaller. The customer's power plant equipment is defined as including steam, combustion or hydraulic equipment used to operate electric generators, air compressors, refrigeration equipment, pumps and other similar equipment. At the end of each calendar year, if the net amounts, excluding the adjustment for cost of fuel, billed by the Company for service under the customer's contract have not equaled the net minimum yearly bill for auxiliary service as provided hereunder, then the difference shall be billed by the Company and paid by the customer with the regular bill for service for the twelfth month of the calendar year. The first year's billing under a new contract shall be prorated to the December reading date.
(Continued to Sheet No. 81.8)
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103 Appendix B Schedule 4
Page 13 of 34 WISCONSIN ELECTRIC POWER COMPANY Volume 19 - Electric Rates Revision 1 Sheet 81.8
Amendment No. xxx Effective In All Areas Served In Wisconsin Rate Schedule Cp FN
GENERAL PRIMARY SERVICE - COMBINED FIRM and NON-FIRM SERVICE
(Continued from Sheet No. 81.7)
(7) Customers who wish to operate electric generation equipment in parallel with the Company's system shall abide by the conditions of purchase for rate schedules CGS1, CGS2 and CGS3.
(8) Should the customer, because of fire, strike, demonstrations, casualties, civil or military authority, insurrection or riot, the actions of the elements, or any other like causes beyond his control, be prevented from utilizing the power service contracted for, the Company will waive the monthly minimum demand charge for such period; provided, however, that the period of time of such suspension of use of power shall be added to the period of the contract; and further, provided that the customer notifies the Company in writing within six days of his inability to use said power service, specifying reasons therefore.
(9) The Company shall use reasonable diligence in furnishing an uninterrupted and regular supply of power, but it shall not be liable for any damages sustained by customer because of interruptions, deficiencies, or imperfections in electric service provided under this rate.
(10) Service under this rate shall be furnished only in accordance with the Electric Service Rules and Regulation of the Company.
(1 1) Except as provided by contract entered into pursuant to paragraph 6 of these conditions, the Company shall not be required to provide service as standby for other types of energy or fuel. Customers with their own generating equipment shall be required to separately meter such equipment or demonstrate the separation of non-firm loads from the generation output.
(12) Energy furnished under this rate shall not be resold, except as provided in the Electric Service Rules and Regulations of the Company.
(13) For customers owning and operating generating systems greater than 75 MW gross output, the Company, under contract agreement for billing and metering, may net the kwh consumed by the customer's generatirlg facility from those kwh produced by the customer's same generating facility for those periods when the customer's generating facility is producing energy. There will be no net billing of the demand component or a reduction in the facilities charge. If additional metering is required for this net energy billing, the customer must pay for such metering.
(Continued to Sheet No. 81.9)
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103 Appendix B Schedule 4
Page 14 of 34 WISCONSIN ELECTRIC POWER COMPANY Volume 19 - Electric Rates Revision 1 Sheet 81.9
Amendment No. xxx Effective In All Areas Served In Wisconsin Rate Schedule Cp FN
GENERAL PRIMARY SERVICE -COMBINED FIRM and NON-FIRM SERVICE
(Continued from Sheet No. 81.8)
CONDITIONS OF DELIVERY
(14) A customer may make a one-time election to take service under this rate schedule for a trial period of twelve consecutive months, provided the customer has not been previously served under another of the Company's non-firm rates. The customer must execute a contract which specifies that the customer will notify the Company at least 30 days before the trial period ends of whether the customer will continue the interruptible service under this rate schedule for a minimum of three more years. The interruptible service contract will contain a provision which, absent notice, will automatically extend the contract for one year from each anniversary date.
(15) If the customer terminates the contract schedule described in (12) prior to the date of termination R as set forth in said contract, the customer will pay to the Company a cancellation charge equal to the demand charge differential between the customer's non-firm demand charge and the firm on- peak demand charge from this rate schedule multiplied by the sum of the billed demands associated with the customer's interruptible load as shown on the customer's bills for the most recent 12 month period. The cancellation charge will not apply if the customer executes a contract to take service, effective the day following termination of the existing non-firm contract, under the Company's Contract Service Tariff for a period of at least 3 years, or, another of the Company's non-firm rate schedules which has a 3 year rolling contract term, provided the on- peak firm demand is the same or less.
(16) For the purposes of determining the customer's eligibility for the non-firm portion of this rate, the customer's non-firm interruptible load will be the difference between the customer's maximum measured on-peak demand during the last consecutive 12-month period and the customer's proposed contracted firm service level. Service under this rate may be refused if the Company believes the load to be interrupted will not provide adequate load reduction when the Company desires interruption. The Company will notify the customer of the Company's refusal to provide service under this rate and the Company will inform the customer of the customer's right to ask for a commission review of the Company's refusal of service.
(1 7) If the customer's non-firm interruptible load is less than 1000 kW for any 3-months out of a 12 consecutive month period, the Company may suspend service under the non-firm interruptible portion of this rate and serve the customer under the firm portion of this rate for their entire load.
(18) The customer shall, at their expense, install all apparatus and materials necessary for the measurement of the non-firm load. The customer's circuits are to be arranged so that none of the interruptible load can be transferred to service furnished under any other rate.
(Continued to Sheet No. 81 .lo)
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103
WISCONSIN ELECTRIC POWER COMPANY
Appendix B Schedule 4
Page 15 of 34
Volume 19 - Electric Rates Revision 6 Sheet 87 Amendment No. xxx
Effective In All Areas Served In Wisconsin Rate Schedule Cp 2M
GENERAL PRIMARY SERVICE -- INTERRUPTIBLE
AVAILABILITY
For customers contracting for three-phase 60 hertz power service after January 1, 1995, at approximately 13,200 volts or higher for a period of at least three years with a monthly 15 minute integrated demand of at least 1,000 kilowatts of interruptible load. Customers are required to remain on the selected on-peak period for at least one year. The Company reserves the right to restrict participation under this tariff to a maximum of 150 MW contracted interruptible demand.
RATE Facilities Charae
$26.301 37 per day
Demand Charaes
Equal to or Less than Greater than 138,000 volts 138,000 volts
Billed on-peak demand, per kW per month $5.37800 $5.37800 Customer maximum demand, per kW per month. $1.00700 $0.00000
Billed on-peak demand will be theon-peak demand as determined on sheet Nos. 67 and 68 or 80% of the highest measured off-peak demand adjusted for power factor as described on Sheet Nos. 67 and 68, whichever is greater, subject to a minimum billed on-peak demand on 700 kW. Customer maximum demand will be as determined on Sheet No. 67.
Enerav Charaes
All on-peak energy per kwh (a): All off-peak energy per kwh (b):
Equal to or Less than Greater than 138,000 volts 138,000 volts
(a) General Primary on-peak energy usage is the energy in kilowatt hours delivered during the on-peak period selected by the customer. The two on-peak periods available are:
(Continued to Sheet No. 88)
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103 Appendix B Schedule 4
Page 16 of 34 WISCONSIN ELECTRIC POWER COMPANY
Volume 19 - Electric Rates Revision 2 Sheet 153 Amendment No. xxx
Effective In All Areas Served In Wisconsin Rate Schedule Ms 3
STANDARD SODIUM AND METAL HALIDE STREET LIGHTING SERVICE
CONDITIONS OF DELIVERY
(1) The Company will furnish, install, own and operate a standard high pressure sodium or metal halide lighting unit, and will supply all electric energy and normal maintenance for the operation of the unit. The standard street lighting unit shall consist of a cobra head fixture on an arm mounted on an existing Company-owned wood pole, with a control device wired for operation. This rate requires use of existing Company-owned wood poles and available overhead 120-volt service. Where additional primary and/or secondary facilities are required, the Customer shall pay the full cost of installation less the appropriate embedded credit.
(2) When necessary, the Customer shall grant or obtain permissions, easements, ordinance satisfaction, and/or permits to the Company to install/remove lighting facilities on public or private property without expense to the Company. The Customer is responsible for marking all privately owned underground facilities. If such facilities are not marked correctly and are subsequently damaged, the Customer is responsible for damages. All installations shall be in accordance with the construction standards of the Company and any other codes the Company determines to be applicable.
(3) Lamps will automatically be switched on approximately 30 minutes after sunset and off 30 minutes before sunrise, providing dusk-to-dawn operation of approximately 4200 hours per year. Non-standard, part-night, temporary or seasonal service is not available under this rate.
(4) The Company will initiate a first response to replace inoperative lamps and otherwise maintain luminaires during regular daytime work hours within 72 hours after notification by the customer. Conditions may require repeat visits to complete repairs. No credit will be allowed for periods during which lamps are out of service.
(5) In the event of abnormal or excessive maintenance due to frequent vandalism or other causes not related to the quality of material or workmanship, the Customer shall reimburse the Company for all associated costs.
(6) The Company will, at customer's expense, modify, replace, transfer, relocate or temporarily remove and reinstall any properly operating poles or fixtures contracted for under this rate as requested in writing by the customer or as required by a governing body.
(7) The lighting agreement shall continue in force until terminated upon 30 days' prior written notice given by either of the parties to the other. The Company may remove any and/or all lighting facilities upon termination.
(Continued to Sheet No. 154)
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103 Appendix B Schedule 4
Page 17 of 34 WISCONSIN ELECTRIC POWER COMPANY
Volume 19 - Electric Rates Revision 2 Sheet 154 Amendment No. xxx
Effective In All Areas Served In Wisconsin Rate Schedule Ms 3
STANDARD SODIUM AND METAL HALIDE STREET LIGHTING SERVICE
(Continued from Sheet No. 153)
CONDITIOIVS OF DELIVERY
(8) If the customer or a governing body requests the permanent removal of any Company- R owned street lighting facilities within 60 months of installation, the customer shall pay the lesser of the estimated labor charges for installation and removal of the equipment, or the remaining balance of monthly fees to satisfy the 60 month period. Permanent removal of pole mounted street lighting facilities more than 60 months after installation shall be at no cost to the customer.
(9) Subject to Company approval, the Company will allow municipal customers to make temporary attachments of Christmas lighting andlor decorations on Company-owned light poles. The customer must execute an annual agreement for such attachments, and must meet all conditions thereof. Estimated energy consumptions will be billed under the current CG1 Energy rate. Time and material charges for installation, removal or associated maintenance may also apply.
(10) Electric service will not be furnished hereunder for breakdown or standby purposes where another source of power is available to the customer. Energy furnished under this rate shall not be used for purposes other than those specified hereunder and shall not be resold.
(1 1) Customer shall indemnify and hold harmless the Company, from and against any and N all liability for injuries or damages to persons or property arising or resulting from (a) any interruption or modification of service requested or caused by the Customer; or (b) any lighting, requested by Customer or third party, which does not conform to the Illuminating Engineering Society (IES) Recommended Practices.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103
WISCONSIN ELECTRIC POWER COMPANY
Appendix B Schedule 4
Page 18 of 34
Volume 19 - Electric Rates Revision 2 Sheet 158 Amendment No. xxx
Effective In All Areas Served In Wisconsin Rate Schedule Ms 4
NON-STANDARD STREET AND AREA LIGHTING SERVICE
(Continued from Sheet No. 157)
CONDITIONS OF DEI-IVERY
(8) If a customer served under Option A terminates service or requests the removal of any Company-owned non-standard lighting facilities, it shall reimburse the Company for the unamortized balance of the estimated installed cost of facilities plus removal costs, less estimated net salvage, of the facilities removed because of such termination or request for removal.
(9) If a customer served under Option B terminates service or requests the removal of any Company-owned non-standard lighting facilities, it shall reimburse the Company for the removal costs less estimated net salvage, if greater than zero, of the facilities removed because of such termination or request for removal.
(10) Customer shall indemnify and hold harmless the Company, from and against any and R all liability for injuries or damages to persons or property arising or resulting from (a) any interruption or modification of service requested or caused by the Customer; or (b) any lighting, requested by Customer or third party, which does not conform to the Illuminating Engineering Society (IES) Recommended Practices.
(1 1) Subject to Company approval, the Company will allow municipal Customers to make attachments of temporary Christmas lighting andlor decorations on Company-owned light poles. The Customer must execute an annual agreement for such attachments and must meet all conditions thereof. Estimated energy consumption will be billed under the current CG1 energy rate. Time and material charges for installation removal or associated maintenance may also apply.
(12) Electric service will not be furnished hereunder for breakdown for standby purposes R where another source of power is available to the customer. Energy furnished under this rate shall not be used for purposes other than those specified hereunder and shall not be resold.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103 Appendix B Schedule 4
Page 19 of 34 WISCONSIN ELECTRIC POWER COMPANY Volume 19 - Electric Rates Revision 2 Sheet 161
Amendment No. xxx Effective In All Areas Served In Wisconsin Rate Schedule GI 1
STANDARD AREA LIGHTING SERVICE
(Continued from Sheet No. 160)
CONDITIONS OF DELIVERY
(7) The Company will, at the customer's expense, modify, replace, relocate or change the position of any Properly operating fixtures or poles contracted for under this rate as requested in writing by customer. The Company will, at the Company's expense, modify, replace, relocate or change the position of a fixture or pole contracted for under this rate at the end of the contract term and upon receipt of a new 60 month contract for the new installation.
(8) The initial term of the contract for lights under this rate is 60 months commencing on the date service is connected. After expiration of the initial term, the contract shall continue in force until terminated upon thirty (30) days prior written notice given by either of the parties to the other. ,
(9) If customer terminates service or requests removal of any Company-owned area lighting facilities before expiration of a 60-month period after installation, customer shall pay the lesser of the estimated labor charges for installation and removal of the equipment, or the remaining balance of monthly fees to satisfy the 60 month period. If customer vacates the premises within 60 months after installation, and the transfer of monthly lighting charges to a successor customer is pending, the Company may elect to terminate service at no additional cost to the customer.
(10) Customer shall indemnify and hold harmless the Company, from and against any and all liability for injuries or damages to persons or property arising or resulting from (a) any interruption or modification of service requested or caused by the Customer; or (b) any lighting, requested by Customer or third party, which does not conform to the Illuminating Engineering Society (IES) Recommended Practices.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103 Appendix B Schedule 4
Page 20 of 34 WISCONSIN ELECTRIC POWER COMPANY
Volume 17 - Electric Rules and Regulations Effective In All Areas Served In Wisconsin
Revision 2 Sheet 10 Amendment No. xxx
101. GENERAL INFORMATION, (continued)
( f ) When applying for new service, or a change to an existing service, customers should provide information concerning the date service is required, the type of structure, nature of the electrical load, and the size and voltage of service desired. For service to new buildings, a site layout showing property lines, obstructions and building location should also be provided.
(g) In case of underground service, municipalities ordinarily do not issue permits to open-cut streets or alleys in winter months when there is frost on the ground, and requests for underground service should be made with this in mind. The Company's winter construction rates are in effect during the winter months when there is frost on the ground and underground costs are adjusted to reflect conditions affecting construction accordingly.
(h) Continuity of service is extremely important to hospitals, pumping stations, public meeting places, etc., where safety to life and property is involved, also to some industries whose manufacturing processes, dependent upon continuous service, cannot be stopped without serious economic losses. The customer is invited to consult the Company to assist with the electrical plans so that the customer may receive maximum benefits from the Company's service and that continuity of service may be safeguarded for all customers.
(i) Under no circumstances will a customer be permitted to configure their system to allow the transfer of loads between services that are subject to different rate schedules.
(j) The Company will attempt to set all the meters at a multi-meter installation during one site visit. N If an installation is ready for meters to be set, and the customer requests that the Company not
set all the meters, the customer will be charged a trip charge for each subsequent trip to set a meter. Billing for service will begin at the time the meter is installed.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103
WISCONSIN ELECTRIC POWER COMPANY
Volume 17 - Electric Rules and Regulations Effective In All Areas Served In Wisconsin
Appendix B Schedule 4
Page 21 of 34
Revision 2 Sheet 16 Amendment No. xxx
102.5 Resale of Enerav, (continued)
(b) A customer who owned and operated facilities for the furnishing of electric service to his or her tenants or lessees and was engaged in resale prior to November 29,1962, in Rate Area One, or August 15, 1963, in Rate Area Two, may continue such resale, but only at that location.
(c) The provisions of this rule do not apply to resale of electricity by the Milwaukee Board of Harbor Commissioners at locations where the Board is authorized to fix fees by Section 30.38(9), Wisconsin Statutes, and where on IVovember 29, 1962, the public-owned and operated harbor facilities included electric distribution facilities serving said locations.
(d) A customer who is allowed to resell under these rules must currently be purchasing electric energy R under the general primary rate. Permission to resell is granted by the Company through a written agreement that is not transferable or assignable. If the resale is to a number of buildings owned by a customer such buildings must be on contiguous properties, including those directly across public thoroughfares. Where such resale is permitted, the lease agreements which the customer has with his tenants shall contain a provision that the tenants agree to accept electric service from the customer.
(e) A customer who is permitted to submeter and resell electricity in accordance with these rules shall charge rates which are not higher than the currently filed rates of the Company for comparable service to the ultimate user. The rates shall be applied on the basis of single meter service or as such service would be metered by the Company. In case a customer is a party to an existing contract entered into before January 29, 1963, which provides for resale of electricity and imposes a charge which is not based on submetering, said charge may be continued in effect for the balance of the term of said contract.
(f) Distribution facilities used for resale shall be subject to the following requirements:
(1) They shall be provided by the customer and maintained so that their operation will not interfere with service to other customers of the Company.
(2) They shall not be extended to serve additional locations without written consent of the Company, and such consent shall be given only where the rendering of service directly by the Company would be impractical.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103
WISCONSIN ELECTRIC POWER COMPANY
Volume 17 - Electric Rules and Regulations Effective In All Areas Served In Wisconsin
Appendix B Schedule 4
Page 22 of 34
Revision 2 Sheet 17 Amendment No. xxx
102.5 Resale of Enerav, (continued)
(3) Submeters, where used, shall be provided by the customer,and their accuracy shall be maintained within the limits prescribed by the Public Service Commission of Wisconsin.
(4) If the practice of resale at any location is discontinued, the Company will not again furnish service for that purpose at that location except in accordance with these rules.
(g) The practice of rent inclusion shall not be established in premises where the ultimate users are being served directly by the Company.
(h) Failure to observe any of the provisions of this section shall subject a customer to disconnection of service after reasonable notice of not less than ten days.
(i) The preceding paragraphs (a) through (g) are not applicable after March 1, 1980. Individual metering is required for each residential or commercial unit except:
(1) where commercial unit space requirements are subject to alteration with change in tenants as evidenced by temporary versus permanent unit spaces;
(2) for electricity used in central heating, ventilating and air conditioning systems; or
(3) for electric back-up service to storage heating and cooling systems or when alternative renewable energy resources are utilized in connection with central heating, ventilating and air conditioning systems.
(j) Any existing building which undergoes alterations involving a change in type of occupancy or substantial remodeling shall have installed a separate electric meter for each separate tenant space.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103 Appendix B Schedule 4
Page 23 of 34 WISCONSIN ELECTRIC POWER COMPANY
Revision 2 Sheet 19 Volume 17 - Electric Rules and Regulations Amendment No. xxx Effective In All Areas Served In Wisconsin
103.1 General, (continued)
(g) (continued) brackets or insulators for supporting service drops on buildings. If for any reason a customer's service entrance must be extended to enable the Company to connect its service facilities, the customer shall make the necessary extension at his own expense, except as provided in Section 103.2(b).
(h) All areas in which lines, cables, drops, laterals, or equipment are to be placed shall be staked and rough-graded by the customer or property owner to within four inches of final grade or the customer may pay the Company to clear and grade such property. Any restoration of lawn and/or landscaping shall be the responsibility of the property owner, land developer or subdivider. Grade changes of more than four inches in the vicinity of the Company's distribution system and service facilities shall not be made without written approval of the Company.
0) The Company shall have the right to install, maintain and inspect its facilities and shall at any reasonable time have access to the customer's premises for such purposes.
(j) Not more than one service drop or service lateral for either standard retail service or retail power service will be installed to the same building or utilization point except:
(1) where more than one point of delivery is necessary because of voltage regulation, governmental requirements, or regulatory orders;
(2) for installations where, in the opinion of the Company, more than one service drop or lateral is necessary to meet the load requirements:
(3) for row houses and other multiple occupancy buildings in compliance with the Wisconsin State Electrical Code; or
(4) where additional services may be required for billing under different rate schedules.
(k) The Company will coincidize meters for billing (i.e., account of diversity) under a single rate N schedule where the service was set up with an additional service drop(s) or service lateral(s), due to a constraint on the Company's existing system or if it was economically preferable for the Company to serve the customer with an additional service drop or service lateral. An extra meter charge will be assessed for each meter in excess of one.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103 Appendix B Schedule 4
Page 24 of 34 WISCONSIN ELECTRIC POWER COMPANY
Volume 17 - Electric Rules and Regulations Effective In All Areas Served In Wisconsin
Revision 1 Sheet 27 Amendment No. xxx
104.6 Sealina of Equipment
(a) All meters and associated equipment must be of a type and so arranged to permit effective sealing by the Company. Such seals shall not be broken or tampered with except in cases of emergency. The Company shall be promptly notified when seals are broken.
(b) All cabinets and troughs containing conductors carrying unmetered energy shall provide for sealing by the Company.
104.7 Groundina of Services
Services shall be grounded in accordance with the Wisconsin State Electrical Code or local ordinances, where more restrictive.
104.8 Construction and Eauipment Details
Installation of metering equipment, service entrance facilities, and service switch equipment shall be made in accordance with the Wisconsin State Electrical Code, local ordinances and the Company's standards of construction. The applicable standards of construction are contained in the Company's Electric Service & Metering Manual and its addendum for Primary Rate Substations.
104.9 Customer Reauested Meter Tests N When a customer requests more than one meter test within the allowable timeframe defined by the Wisconsin Administrative Code, and where the meter is found to be accurate, the customer will be billed for the meter test at actual cost.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103 Appendix B Schedule 4
Page 25 of 34 WISCONSIN ELECTRIC POWER COMPANY
Volume 17 - Electric Rules and Regulations Effective In All Areas Served In Wisconsin
Revision 2 Sheet 43 Amendment No. xxx
200. EXTENSION OF SERVICE
201. EXTENSION OF NEW ELECTRIC SERVICE
201.1 General
(a) Company-owned fac~lities installed on the customer's premises shall be over the most direct and practical route convenient to the Company. Service entrance conductors shall be located so as to be most readily accessible to the Company's lines. If the customer elects a service entrance location other than that most convenient to the Company, the customer shall pay the cost of excess facilities required to serve the customer's preferred service entrance location. For any portion of an extension which in the Company's judgment would be hazardous or where the operation of the customer or others may introduce a hazard, the customer shall pay all costs of removing such hazards or the cost of rerouting the Company's extension to avoid hazards.
(b) The estimated cost of distribution system facilities will include the cost of extension of primary and secondary mains; reconstructing of existirlg main feeders including changirlg from single-phase to three-phase or construction of new feeders made necessary solely by addition of such customers; the cost of tree trimming or right of way clearing; securing easement; moving conflicting facilities; and all other costs incident to furnishing service. This definition applies to the D overhead and underground distribution system.
(c ) The Company will design the distribution facilities to provide safe, reliable, environmentally acceptable service at the lowest reasonable cost following accepted engineering and planning practices. If it is found to be advantageous for the Company to install facilities in excess of facilities normally installed, the added costs of these facilities will not be used in determining the extension costs for purposes of that customer's contribution.
(d) The customer shall provide or shall be responsible for the cost of all right-of-way easements and permits necessary for the Company to install, maintain, or replace distribution facilities. The customer shall either clear and grade such property or pay the Company to clear and grade such property prior to construction.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103
WISCONSIN ELECTRIC POWER COMPANY
Volume 17 - Electric Rules and Regulations Effective In All Areas Served In Wisconsin
Appendix B Schedule 4
Page 26 of 34
Revision 2 Sheet 45 Amendment No. xxx 691
201.1 General, continued
(I) The Company shall, upon request, provide the customer at no charge, one estimate of the customer cost within a 12-month period. Should the Company be asked by the customer to estimate multiple scenarios or re-estimate the customer cost (due to installation changes, t im i~g changes, etc) within 12 months of providing the first estimate, the Company shall prepare new estimates and bill the customer for the cost to prepare such estimates. The bill for the estimate is due within 30 days of being billed.
201.2 Installation Charaes
(a) Customers and developers for whom an extension of the Company's distribution system as defined in Section 103.1 (a) is required, will be required to pay an installation charge in advance of construction as specified by these rules.
(b) lnstallation charges for single-phase secondary voltage service, including service to residential and farm customers, will be the estimated cost of distribution facilities to be installed, excluding transformers, less the average depreciated embedded cost of distribution facilities of $752, R determined by dividing the original cost less accrued depreciation of distribution facilities and Contributions in Aid of Construction, excluding Account 368 - Line Transformers, allocated to this group of customers by the number of customers in the group.
(c ) lnstallation charges for three-phase secondary voltage service, including service to three phase residential customers and farm customers served under the Company's Fg 1, Cg 1 or Cg 6 rate schedules will be the estimated cost of distribution facilities to be installed, excluding transformer; less the average estimated depreciated embedded cost of distribution facilities of $2,256, determined by dividing the original cost less accrued depreciation of distribution facilities R and Contributions in Aid of Construction, excluding Account 368 - Line Transformers, allocated to this group of customers by the number of customers in the group.
(d) Installation charges for single-phase secondary voltage service to general secondary customers billed on the energy tariff (no demand component) will be the estimated cost of distribution facilities to be installed, excluding transformers, less an estimated amount of $91 9 representing R the average depreciated embedded cost of distribution facilities, excluding Account 368 - Line Transformers, allocated to this customer group.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR-103 Appendix B Schedule 4
Page 27 of 34 WISCONSIN ELECTRIC POWER COMPANY
Revision 2 Sheet 46 Volume 17 - Electric Rules and Regulations Amendment No. xxx Effective In All Areas Served In Wisconsin
201.2 Installation Charaes, (continued)
(e) Installation charges for three-phase secondary service to general secondary customers billed on the energy tariff (no demand component) will be the estimated cost of the distribution facilities to be installed, excluding transformers, less the calculated depreciated embedded cost of $1,838 for distribution facilities. The depreciated embedded cost is determined by subtracting the total depreciated embedded cost allocated to single-phase General Secondary accounts from the total depreciated embedded cost less Contributions in Aid of Construction, excluding Account 368 - Line Transformers, allocated to the entire regular general secondary rate classification. This difference is then divided by the average number of three-phase general secondary customers served.
(f) Residential developers and subdividers of single- and two family subdivisions shall pay, in advance of construction, the total estimated cost of the distribution facilities required, excluding transformers. The developer or subdivider may receive a refund as structures are built and customers are connected to the extended distribution system. The refund, if any, shall equal the amount by which the average embedded cost applicable at the time the extension was installed or the current embedded cost, whichever is greater, exceeds the estimated cost of any additional distribution facilities required for the new customer. If the estimated cost of the additional distribution facilities exceeds the average embedded cost, no refund is due the developer or subdivider and the new customer will be required to pay an installation charge, as provided in Section 201.2. If the installation date of the original extension is on or after July 1, 1982, then, the developer or subdivider shall receive refunds, if any, for five years from that installation date. In no case shall the developer or subdivider receive funds in excess of the original charge.
(g) Installation charges for multi-family residential housing units will be the cost of distribution facilities to be installed, excluding transformers, less the average embedded cost as determined in Section 201.2(b), per each living unit in the multi-family building.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103
WISCONSIN ELECTRIC POWER COMPANY
Appendix B Schedule 4
Page 28 of 34
Volume 17 - Electric Rules and Regulations Effective In All Areas Served In Wisconsin
Revision 2 Sheet 47 Amendment No. xxx
201.2 Installation Charaes, (continued)
(h) Installation charges for general secondary customers billed on a demand and energy tariff will be the estimated cost of distribution facilities to be installed, excluding transformers, less the average depreciated embedded cost of $126 per kilowatt for distribution facilities, determined by dividing R the original cost less accrued depreciation of distribution facilities and Contributions in Aid of Construction, excluding Account 368 - Line Transformers, allocated to this group of customers by the estimated average billed demand of these customers, to produce an average depreciated embedded cost per kilowatt of demand. The customer will then nominate a minimum contractual demand on which the embedded cost credit will be based, and will contract with the Company for such minimum demand for a period of 1 year. If requested by the customer, the Company may R allow the Customer to be served under a non-demand General Secondary Service Rate for a start-up period not to exceed twelve months and ending with the month in which the minimum contract demand is reached. When the start-up period has ended, the twelve month period for which the minimum contract demand shall be billed will begin.
(0 Installation charges for general primary customers will be the estimated cost of distribution facilities to be installed less the average depreciated embedded cost of $107 per kilowatt for distribution facilities, determined by dividing the original cost less accrued depreciation of the distribution facilities and Contributions in Aid of Construction, excluding Account 368 - Line Transformers, allocated to this group of customers by the estimated average monthly billed demand of these customers, to produce an average embedded cost per k~lowatt of demand. The customer will then nominate a minimum contractual demand on which his embedded cost credit will be based, and will contract with the Company for such minimum demand for a period of 1 ear. If requested by the customer, the Company may allow the Customer to be served under a R demand General Secondary Service Rate for a start-up period not to exceed twelve months and ending with the month in which the minimum contract demand is reached. When the start-up period has ended, the twelve month period for which the minimum contract demand shall be billed will begin.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103 Appendix B Schedule 4
Page 29 of 34 WISCONSIN ELECTRIC POWER COMPANY
Revision 2 Sheet 48 Volume 17 - Electric Rules and Regulations Amendment No. xxx Effective In All Areas Served In Wisconsin
201.2 Installation Charaes, (continued)
( j ) Installation charges for governmental units contracting for street lighting service from Company-owned facilities, other than nonstandard street lighting, will be the estimated cost of the distribution system to be installed, excluding transformers, less the average depreciated embedded cost of $41 per lighting unit for such systems, determined by dividing the original cost R less the accrued depreciation of the distribution facilities and Contributions in Aid of Construction,
excluding Account 368 - Line Transformers, allocated to this type of service by the number of street lighting fixtures to produce an average embedded cost per fixture.
(k) Installation charges for governmental units contracting for primary voltage service for customer-owned street lighting installations will be the estimated cost of the distribution system to be installed less the average depreciated embedded cost of $107 per kilowatt for distribution R facilities, determined by dividing the original cost less accrued depreciation of the distribution facilities and Contributions in Aid of Construction, excluding Account 368 - Line Transformers, allocated to primary voltage customers by the estimated average monthly billed demand of general primary customers, to produce an average embedded cost per kilowatt of demand. The allowance for embedded cost credit will be based on the total wattage of the lamps to be connected.
(I) The cost of installing distribution facilities for nonstandard street lighting service will be recovered as shown on Rate Schedule Ms 4 in the Company's tariffs on file with the Public Service Commission of Wisconsin.
Issued: - Effective: - PSCW Authorization: -
Docket 5-LTR- 103 Appendix B Schedule 4
Page 30 of 34 WISCONSIN ELECTRIC POWER COMPANY
Revision 1 Sheet 49 Volume 17 - Electric Rules and Regulations Amendment No. xxx Effective In All Areas Served In Wisconsin
201.2 Installation Charaes, continued
(m) Should additional customers be connected to an existing extension of the distribution system outside of a single- or two-family subdivision, which extension has required an installation charge from the original customer for whom the extension was first made, that original customer may receive a refund. The original customer will receive a refund only if that customer is continuing to receive service at that location at the time the additional customers are connected; refunds will be made to subsequent customers. The refund, if any, shall equal the amount by which the average embedded cost applicable at the time the extension was installed or the current embedded cost, whichever is greater, exceeds the estimated cost of any additional distribution facilities required for the new customer. If the estimated cost of the additional distribution facilities exceeds the average embedded cost, no refund is due the original or subsequent customer, and the new customer will be required to pay an installation charge, as provided in Section 201.2. If the installation date of the original extension is on or after July 1, 1982, then, the original or subsequent customer shall receive refunds, if any, for 5 years from that installation date. In no case shall the original or subsequent customer receive refunds in excess of the original installation charge.
(n) The Company shall require a contract between the Company and a retail customer before the Company extends or modifies its transmission facilities to serve the retail customer. The contract shall describe the facilities to be constructed, list the cost of construction, apportion the responsibility for the construction costs between the Company and the customer, and include the supporting analysis for the construction an the cost apportionment. The contract shall be submitted to the Public Service Commission of Wisconsin for approval. The contract is approved if the Public Service Commission does not respond to the Company within 20 working days from the receipt of the contract.
(0) Seasonal customers shall receive one-half the average embedded cost of a year-round customer for the same customer classification.
(p) Service facilities, as defined in Section 103.1 (b) and transformers shall be provided without charge, except as may be appropriate in cases described in Section 201.2(q), 201.2(r) and Section 102.4, Special Service.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103
Volume 17 - Electric Rules and Regulations Effective In All Areas Served In Wisconsin
Appendix B Schedule 4
Page 3 1 of 34
Revision 2 Sheet 52 Amendment No. xxx
202. CHANGES TO EXIS-TIIVG FACILITIES (continued)
(h) If relocation of Company distribution facilities or service facilities is requested under provisions of Section 103.2(a), the customer shall pay, in advance of construction, the cost of making the desired relocation, in addition to any charges for necessary changes and additions to remaining facilities, as described in Section 202(a). The customer 's contribution shall be refundable as additional customers attach to the relocated facilities as provided in Sections 201.2(f) and 201.2(m).
(i) Customer initiated work, including but not limited to, construction, remodeling, relocation or removal of their facilities that causes temporary alterations, adjustment or relocations of Company facilities will be done by the Company and the cost charged to the customer after completion of the job at the client job rate.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103 Appendix B Schedule 4
Page 32 of 34 WISCONSIN ELECTRIC POWER COMPANY
Revision 2 Sheet 63 Volume 17 - Electric Rules and Regulations Amendment No. xxx Effective In All Areas Served In Wisconsin
RESPONSIBILITY FOR USE OF SERVICE
(a) When a customer notifies the Company with the intent to discontinue service, the Company shall obtain a final meter reading for this account. If a successor customer is to be placed on service consistent with the off-service date, or if the landlord wants service between tenants and has informed the Company, the final meter reading for the former customer is also the on-reading for the successor customer or landlord.
(b) If there is no successor customer for a residence, apartment or multi-unit dwelling and the landlord has not informed the utility of the intent to receive service between tenants, service may be disconnected. No disconnection fee will be charged.
(c ) If there is no successor customer for a non-residential type unit and the landlord has not informed the utility of the intent to receive service between tenants, service may be disconnected. No disconnection fee will be charged.
(d) If the premises remains vacant and the meter reader, on the next reading date, or automated meter reading device determines that service has been used on the meter, an attempt will be made by the Company to determine responsibility for service used. The procedure will be as follows:
(1) At the time the meter reader or automated meter reading device determines that service R is being used on the idle meter, the meter reader or billing support personnel will attempt to determine who is responsible for the service.
(2) If it is an apartment or multi-unit dwelling and the landlord has previously notified the Company of the intent to be responsible for service between tenants, the landlord will be placed on service and billed for usage between tenants.
(3) In instances in which the Company is unable to determine responsibility for service, a letter will be sent to the occupant at the account address. If this is an apartment building and the name of the landlord is known to the utility, the letter will be so addressed. This letter will indicate that service has been used on an idle meter and that we are attempting to determine responsibility for service used, and that we request that the occupant of the premises, or (in the case of an apartment house) landlord apply for service within ten days of the date of the letter. If no application for service is received by the Company within this ten-day period, the letter will state that the service will be disconnected for lack of proper service application, in accordance with the disconnection rules.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103 Appendix B Schedule 4
Page .33 of 34 WISCONSIN ELECTRIC POWER COMPANY
Volume 17 - Electric Rules and Regulations Effective In All Areas Served In Wisconsin
Revision 2 Sheet 73 Amendment No. xxx
406.3 Disconnection and Reconnection Fees for Electric Service Onlv
Next Day Reconnection During Regular Hours is $31 per meter Same Day Reconnection During Regular Hours are $ 5 4 per meter Reconnection After Regular Hours is $124 per meter
Reconnection at pole during regular hours is $62 or actual cost, if greater. Reconnection at pole after regular hours is $1 17 or actual cost, if greater.
Company initiated reconnections will be charged at the next day reconnection rate regardless of when the actual reconnection occurs. If a customer requests a same day reconnection, and the workload allows the Company to honor such request, the Company will perform the same day reconnection. The Company will review the charges with the customer prior to scheduling the same day reconnection. If the Company informs the customer at the time of their request that the same day reconnection will occur during regular hours, the customer will be charged the same day reconnection rate, regardless of whether the reconnection actually occurs during or after regular hours. If the Company informs the customer at the time of their request that the same day reconnection will occur after regular hours, the customer will be charged the after regular hours rate if the reconnection actually occurs after hours or the customer will be charged the same day rate if the reconnection occurs during regular hours. Same day reconnections for customers with medical emergencies will be at the same day reconnection rate. Same day reconnections are done at the sole discretion of the Company as capacity allows.
(a) Regular hours are defined as Monday - Friday, 8:00 am to 5:00 pm, not including those days, designated as company holidays or legal holidays for New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day and Christmas Day.
(b) Where one or more meters have been disconnected for nonpayment of arrears, service shall be restored only upon satisfactory arrangement for payment of arrears. The customer will be billed the applicable reconnection fee.
(c) When the Company is requested by a Public Safety Agency to perform a disconnection, or when performed by the Company due to fire or explosion, a reconnection fee will be billed when the company is requested by the customer to subsequently perform the reconnection.
(d) When the Company is requested by a third party (e.g. realtor, lending institution, court of appropriate jurisdiction) to perform a disconnect, a new customer requesting the company to perform a reconnection of the same premise which was disconnected at the request of a third party shall not be billed a reconnection charge.
(e) For a customer requested disconnection for reasons not addressed above (examples include but are not limited to maintenance, remodeling, seasonal shutoff, code violations) a reconnection fee will be billed when the customer requests reconnection.
Issued: - Effective: - PSCW Authorization: -
Docket 5-UR- 103
WISCONSIN ELECTRIC POWER COMPANY
Volume 17 - Electric Rules and Regulations Effective In All Areas Served In Wisconsin
Appendix B Schedule 4
Page 34 of 34
Revision 1 Sheet 73.1 Amendment IVo. xxx
(f) When there has been unauthorized energy consumption on an inactive meter and the N Company has been unable to determine responsibility for the usage, the Company will send a letter to the premise and to the owner or owner's agent, if known, requesting that the occupant apply for service. If the Company receives no response to its letter, it may disconnect the service. After such disconnection, if the Company determines that there was an occupant who used this service, but did not apply for it, the Company will bill the applicable reconnection fee and an estimate or actual amount at a later date for the service used prior to the time of application.
(g) When a meter on a rental dwelling unit has been disconnected between customers and the N meter was not disconnected due to non-payment (NPSO), and the owner or owner's agent of the rental dwelling unit has previously received a letter informing them of the opportunity to set up an all-year owner agreement with We Energies for their rental property(s), in these instances, if the owner or owner's agent requests service in their name or for their benefit, then the owner or owner's agent will be charged the applicable reconnection fee. If a New Residential Customer makes proper application for service at the rental dwelling unit, then no reconnection fee shall be charged.
Issued: - Effective: - PSCW Authorization: -
Wisconsin Electric - Gas Operations Margin Revenue Summary
2008
Residential ardRely-A-Bill Residential (Rg- 1 )
Suhrotal
Clisses and Other Cost Categories 1 Volumes
Commercial & 1ndustrial.g-1 (0 to 3999) Firm Comm. hd. (Fg- I ) Agricultural Sewoml Use I&- I ) Natunl Gas Vehicles 1 (NGV-I)
Suhtutal g-l
Commercial &Industrial, g-2 (4,UUO tu 39999) Firm Cumm. hd, (Fg-2) Agricultural Seaoral Use (Ag-2) Natural Gas Veh~cles 2 (NGV-2) Tramport Commercial 2 (Tf-2)
Subtotal g-2
Margin Revenue ~4
Current Rues
Commercial & Indu~trial, g-3 (4UBOO to 99999) Firm Comm. Ind. (Fg-3) Agricultural Seil\onl Use (Ag-3) Nalural Gas Vehicles 3 (NGV-3) Inter. Comm. Ind. (Ig-3) Trmyorr Cclmmercial 3 ( n - 3 )
Subtotal g-3
Commercial &Industrial g-4 (1UO8OO 10499999) Firm Comm. Ind. (Fg-4) 19.330.968 Agricuitural Seaorwl Use (Ag-4) Inter. Comm. Ind. (Ig-4) Trampa Commercial 4 (Tf-4)
Subtotal g-4
Commercial & Industrial g-5 (SOUDUO lo 999999) Firm Comm. Ind. (Fg-5) Agricultural Sewonl Use (Ag-5) I Inter. Comm. hd. ( k 5 ) T r m p n Commercial5 ('IT-5)
Subtotal g-5 35.C42.563
Mar in Cost of Service C O 2 A I COSSB
--
Dutside A-B
3utsi'le A-B
Margin Revenue at Authoriled
Rates
Change horn Percent Revenue at Margin
Current Rates Change
Authorizd Relative to " A
in B to A
Difference Between COSS "A" and Authoriud 6) I ( % I
Ditierenee Between COSS "B" and Authoriud
($1 I ( % I
1 Margin Revenue at
Distribution Cllsses and Other Cost Caleguries Volumes Current Rales I
Commercial &Industrial g-6 (I,OU0,000 tu 79Y99YY) Firm Cumm. Ind. (Fg-6) Il~rer. Comm. Ind. (lg-6) Tmspurt Culnmercial 6 (Tf-6)
Subtotal g-6
Commercial & 1ndustrial.g-7 (8,OOO,OOO lu9999,999) Suhtotal g-7
Cl>mmercial & Industrial, g-8 (LO,OOOPOO+) Firm Cumm. Ind. (Fg-8) Inter. Comm. Ind. (lg-8) Tmapurr Commercial 8 (Tf-8)
Subtotal g-8
Total 730,645,513 $ 165,107,562 I
Wisconsin Electric - Gas Operations Margin Revenue Summary
2008
Margin Revenue Change from Percent Margin Cost of Service at Authoriled Revenue at Margin
COSSA 1 COSSB Rates Current Rates Change and Authorized and Authorized Relative to "A"
i n B t o A
Total Gas Rate Margin Revenue 817.098.009 167,558,496 Authorim<l Rare Rerenue Change Re\enue Excess (Shortfall) a Aurhorkd Pates Cost of Gas 49 1 62 1.466 Thtal Gas Rate Rewnue $ 659.179.962
Plus Orher Relenue Total Gw Rerenue $ 66 1.386.962
Ipower ene era tors
I I I I I I
86,452,496 $ 2,450,934 $ 2,526.083 $ 75.149 3.07'1.
Wisconsin Gas Company Margin Revenue Summary
2008
r 1 I Mnroin I I Marein Revenue I Chaneefrom Percent s l
Residential w d Rely-A-Bill ksi&aiml (RE- I)
i I
Distribution Classes and Other Cost Calegories
Commercial & Industri;~l,g-1(O lo 3,999) Firm Conlrn. Inl. (Fg- I ) Agricdtural Seirvonal Use (&-I I Natwal @as Vehicles 1 (NGV-I) Ormcnwl Lighling (OL) Transpar1 Commercial (Ti- I)
Suhtotal g-I
Commercial & Industrial, g-2 (4,000 lo 39,999) FirrnComrn. Inl. (Fg-2) 141,353,031 $ 29,108,117 $ Agricuhtual Seasonal Usc (Ag-2) 1,198523 $ 225261 $ 260,584 $ Natural G;rr Vcl~iclcs 2 (NGV-2) 26,190 $ 5519 $ 6,328 $ Transport Commercial 2 (m-2) 5,261,770 $ 1,018,367 $ 1,089,181 $
Suh~olal g-2 147,839,514 $ 30,357265 $ 33,928.9IO $ 39,621,872 $ 34,918.259 $ 4.560.995 15.02% $ 989.349
-- ,, Revenue el
Commrrcid & Industrial,g-3 (40,000 to 99,9991 Firm Comrn Inl. (Fg-3) 40,236,505 E 6,607,865 Agriculltual Staronal Use (Ag-3) 78,608 $ Nawal G u Vchicles 3 (NGV-3)
1 415:, 1 $ 66.904 1 1 1 7'831'604 1 $
107,836 $ 18292 21,338 $ Inter. Comm Id. (16.3) 536,985 $ 84,852 101,933 8: Transport Commercial 3 (Tf-3) 13,989 619 $ 2,223,069 2,370,355 $
Suhlord 6-3 55.286.539 $ 9.000983 $ 8,806,958 $ 11.957.677 $ 10,403,839 $
I
Cc~mmercial &Industrial g-4 (100,000 lo 499,999) Firm Comm. Inl. (Fg-4) 23.531.981 $ 3,123,518 $ 3.684996 $ Agrlculrucal Semonal Use (Ag-4) 489,482 $ 61,084 $ 71,529 $ Inler. G m r n Inti. (Ig-4) 3.403.813 $ 429,429 $ 502,381 $ Tramport Commercial 4 (Ti-4) 1 77.331.940 $ 8,581,435 $ 8,773,848 $
Subtocal g-4 / 104,747,216 $ 12,195,466 $ 11,699208 $ 18,222,021 $ 13,032,753 $
/ Volumes Margin Cost ufService
I I I I I I I Current Rates
at Authoried COSSA I COSS B
Revenue al Margin Rates
and Authori md Current Rates Change
w d Aulhorirrd Relalive to ($) I (9%) I ($1 I (%) "A" in B to A
Wisconsin Gas Company Margin Revenue Summary
2008
Dislributinn Classes and Olher Cosl Calegories Volumes
Cummercial &lnduslrial p-5 (SOU,OUU lo 999,999) Firm Comm. I n r l (Fg-5) ; 1.379.057 &ricultural Seasolvl Use (Ag-5) Inter. Comm. Lnd. (Ig-5) 1 2,353.9 17 Transp,rr Commerciill 5 (Ti-5) 1 45,079,861
Subrural g J ; 48.812.835
Commercial &Industrial g-6 (l,UOOPUO lo 7,999999) ; Flrm Comm. Ind. (Fg-6) Inter. Comm. Inrl. (Ig-6) ! 10,550,556 Trmsp,rr Commercial 6 (Tf-6) 1 175,366,875
Subtotal g-6 1 185,917,431
Commercial &Industrial, g 7 (8,000,000 to 9999,YYY) Firm Comm. Ind. (Fg-7) Inter. Comm. Ind. (lg-7) Transpun Commeruial7 (Ti-7)
Subtotal g-7
Commercial & Industrial, g-8 (IO,MlO,O00+) RrmComm Ind (Fg-8) Inter Comm Ind (Ie-81 T r m p r t Commercial (Tf-8)
Subtotal g-8
Power Generators Special Contracts
DISCOUNTS Told Gav Raie Margin Revenue ; 1,222,419,700 Authnried Wte Rexnue Change Re\enue Excess (Shortfdll) at Authorired Rates Coat of Gas Total C z b t e Revenue
Plua Other Rexnue Total G z Rewnue
Margin Revenue a1
Currenl Rilles
$ 143,678 $ $ 238,194 $ 3,922229 $ 4,304,102
5 5 764,071 $ 10.475.085 5 11.239.156
$
5 $ $
$ $ $ 548,740 $ 548,740
$ 240,264,311
$ 4.239.109 5 3,752,538
248,255,958 $ 268,387,958 -- 5 (20,132,000 5 655,680,843 5 903,936,801 5 6,342,832 5 910,279.633
I Marein Revenue Chanee from Percent I MRerence Between COSS "A" I Difference Between COSS "B" I Authorized Revenue ai Margin and Authorized and Authorized Relalive lo
CurrentRaies Change ($) I (%I ($) I (9%) " A " i n B t o 4
Wisconsin Electric - Gas Operations Margin Revenue Summary
2009
DistrihutionClases and Orher Cost Categories
Commercial & Iniustrial, g-l ((1 to 3.999) RrmComm. Ind. (Fg-l ) Agricultural Semonal Use (Ag-l ) Natural Gas Vehicles 1 (NGV- I )
Subtotal g- l
Commercial & Wusrrial. g-2 (4.000 to 39,999) Firm Comm. Ind. (Fg-2) Agricultunll Seasonal Use (Ag-2) Natural Gas Vehicles 2 (NGV-2) Transport Commercial 2 ('IF-2)
Subtotal g-2
Cumrnemiul& Indu,trinl. g-3 (40,000 to 99,999) Firm Comm. W. iFg-3) Agricultural Seasonal Use (Ag-3) Narurd Gas Vchiolcs 3 (NGV-3) I~uer. Comm. h l . (19-3) Trmspr t Commercial 3 i n - 3 )
Subtoral g 3
Cc>mmercld& Industrial g-4 (100.000 to 499,999) Firm Cnmm. Ind. (Fg-4) Agricultural Seasowl Uae (Ag-4) Inter. Comm. W . ( Ig -4 Triuaport Commercial4 i n - 4 )
Subtotal g-4
Volumes
337.094.89C -- 337.094,89C
35,632.74 1 190,284
2,500 35,825.525
113.838.526 1.173.376
72.795 585.253 --
115,669,950
32,494,767 479,433
3,352,265 36.326.445
19,330,968
4,183,139 32.1 75,648 55.689.755
Msrgln Revznue ~t
Current RK
112.41 1.152
$ 10,270,280 $ 50,815 $ 1,003 $ 10,322,097
$ 21,567,705 $ 210,349 $ 12,748 6 I l0.08l $ 21,900,883
$ 4,992,402 $ 65,585 $
$ $ 448,263 $ 5,506.250
$ 2,454,193 $ $ 45 1,303 $ 3,036.h22 $ 5,942,118
Commercial &lnrlustrial g-5 (500,000 to 999,999) Firm Comm. Ind. (Fg-5) Agricultuml Seaso~lal Use (Ag-5) Inter. Comm W. (19-5) Transpm Cammerciill5 (TL-5)
1 1 l33,!83 33,714,223 $ 2,770.993
Subtotal g-5 35,042.563 $ 2,904,075
1 MnreinCust of Service at Authorized COSS A I COSSB Rates
Change from Pewent Difference Berwen COSS "A" Difference Berueen COSS Rexnue at Margin anJ Autho,rizrd ' W a d Authorixd
Current Rates Ckmge (s) I (91) i$) I (%)
Authorized Relatiue to "A'
inBto A
95.345
Outside A-B
--
Outside A-B
Outside A-B
Outaale A-B
Wisconsin Electric - Gas Operations Margin Revenue Summary
2009
k~tllorired Relaliw lo 'W
in B lu A
66.87%
0.00%
94.851,
Total Gas f i l e Mugill Rewnue $ 171,534,962 $ 3.976.466 2.37% /\lllhorrzed Rate Rclcnue Char19 $ 171,531,496 Rewnue Excess (Shutifall) a Al~lhurizcd Ralcs $ (3,973,000) $ 3,466 $ 3,466 0.00% Cost of Gas $ 491,621,466 $ 491.621.466 $ 0.00% lblal G a M e Relenae $ 659,179.962 $ 663,156,428 $ 3,976,466 0.60%
Plus Other Rexnue $ 2,207,000 $ 0.00% Total G a Rewnue $ 665,363,428 $ 3,976,466 0.609;
Difference BctwenCOSS 'BB"mrd Aulhoriced ($1 I (9)
$ (3.684,055) (42.98)%
$ 0 0.00%
Co~n~nercial & Imluslrial. g-8 (10.000,000+) FumConlm. hd. (Fg-8) - $ - $ Inter. Conlm. hxl. (lg-8) - $ $ $ . - T r m p n Comtncrcial 8 (TI-8) 31.310,916 $ 1,279,892 $ 1,300,067 $ 20,175 1.58%
Subtotal g-8 31.310.916 $ 1,279,892 $ 1,192,293 % 3,283,747 $ 1300,067 $ (60.41)s
Told j 730.645.513 $ 165,107,562 $ 166,841,563 $ 166,841,562 $ 169,008,879 $ 3,901,317 2.36%
I j
Power Gearmlors 1 86,452,496 $ 2.450.934 $ 2,526,083 $ 75,149 3.07% . ,
Chal~g tilion) Percent Rewlule al Magi!,
Current Rates Change
$ $ $ 46.59 1 0.961 $ 46,591 0.969,
$ 0 0.001
Marao Revenue a1 kllhurizcd
Rates
$ - $ - $ 4.887.685 $ 4.887.685
$ 0
Dislrihuliou Classes iuvl Othcr Carl Cale~oriea
Commercid & Lrlustrid &6 ( 1.000.000 to 7,999,999) Firm Camn, hd. (Fg-6) hler. Comm. (lul. (116) h a p t i Commercid 6 (Ti-6)
Sublotal g-6
Commercial & hxlus1rial.g-7 (8,000,000 lu Y.YYY.YY9) SuMuld g-7
Differelre Betwen COSS "A" a d Aulhorized
($) I (5%)
$ 1,824,853 59.58%
0 0.00% $
Volumes
- -
83,685.469 83,685.469
-
Magill Rewnue at
Currca Ryes
$
$ $ 4.841.094 $ 4,841,094
$ -
Mwgin Corl o l Ser\ice
COSS A
$ 3,062,832
$ -
COSS B
$ 8,571,740
$ -
Wisconsin Gas Company Margin Revenue Summary
2009
Distribution Classes and Other Cost Categories I Residential a d Rely-A-Bill
Residential (Rg-I) Rely-A-Bill (M-I)
Subtotal
Commercial & Industrial. g- l (0 to 3,999) Firm Comm. Ind. IF%- I ) Agricultural Sevrunal Use (&-I) Natural Gas Vehicles I (NGV-I) Ommental Lighting (OLJ Transport Commercial (Tf- I )
Subtotal g-1
Commercial & !adustrial, g-2 (4,000 to 39,999) FirmComm. Ind. (Fg-2) &icultural Seasonal Use (&-2) Natural G a Vehicles 2 (NGV-2) Trmpon Commercial 2 (Ti-2)
Subtotal g-2
Commercial & Indurtriol, g-3 (40,000 to 99.999) FirmComm. Incl. (Fg-3) &iculrural Seasonal Use (&-3) Natural Car Vehicles 3 (NGV-3) Inter. Comm. Ind. (Ig-3) Trmpon Commercial 3 (V-3)
Subtotal g-3
Commercial & h<lustriol g 4 (100,000 to 499,999) RrmCumm. Ind. (Fg-4) Agricultural Seasonal Use (Ag-4) Inter. Comm. Ind. (1%-4) Transport Commerciul4 (Ti-4)
Subtotal g-4
Margin Rexnue at hthorized
Rates
$ 170,134,127 $ $ 170,134,127
$ 16.324.549 $ 25.477 $ 1 67 $ 9,882 $ 7,289 5 16,367,364
5 33,420,813 5 259,386 $ 6,302 $ 1,083,919 5 34.770.420
$ 7,791,368 5 78,193 $ 21.230 $ 101,396 $ 2,356.366 $ 10,348,552
$ 3,661.4H $ 71,039 5 498,977 $ 8,696,526 $ 12,928,006
Authori/~d Relatiw to "A"
l" B to A
89.2 19
Outride A6
85.224
5 1.074
8l.l64
Difference Betwen COSS 'W orrl Authorized (5) 1 1%)
Change from Percent Rexnue at Margin
Current Rates Change
Difference Betwen COSS "A" a d nlthorized
($) 1 (%)
Wisconsin Gas Company Margin Revenue Summary
2009
Co~nmcrcial & Lduarid g 5 (500.000 to 999.999) Flr~nComm. Ld. (Fg-5) Agicultural Seuo~wl Use (Ag-5) filter. Comm. hd . ( k 5 ) Trolaport Commercial 5 (m-5)
Suhluld g-5
Cummercid & hdustrid g-6 (1,000,000 to 7,999999) Firnl Cumm. Ld. (Fg-6) Inter. Cumm. Itd. (1g-6) i 10,550.55f Tralspart Cornmercid 6 (7116) j 175,366,875
Suhtotd g-6 i 185,917,431
Cornmercid & I l~d~s l r id , g-7 (8,000,000 lo 9,999999) Firm Cotnm hxl. (Fg-7) Inter. Cornm. lid. (Ig-7) Trueporl C~rmmcrcid 7 (TT-7)
Subtold g-7
Comnmerci;d& Lalustrid. gU (lO.UUU,UU0+) Firm Comm Ld. (Fs-8) fi~tcr. Cornm. Lrl. (Ig-8) Trm~sport Cr>mmercial (TI-8) ! 12,507,304
Suhtord g-8 2 12,807,304
I DISCOUNTS Tow G s Rsle Margill Rewlllle 1.222,419,70C Aull~orizcJ Rale Relel,up Cholg~ Reveuue Excess (Shorlfall) ;ll AuIhori~ed Rates Cost of G a Totul Gas h l e Reucllue
Plus Other Rewnue Told Gas k w ~ u c
Maren Magin Rewnue Chmge from Perceut Differelre Belxeen COSS 'W DDifferemce Bclwea COSS Revenue at Marqiu Coal of Servicc at k ~ t h o r i z d Re\e~llle ;n Margin aid Authori,ed 'Wsrxl Aulhorired
Curre111 Rles COSS A I COSS B Rates Currea Rles Chelfie ($) I ( 6 ) 6) I (4h)
Docket 5-UR- 103 Appendix D Page 1 of 12
Wisconsin Electric - Gas Operations Authorized Natural Gas Service Rates
2008
Present Authorized Rates Rates
Residential Daily Basic Distribution Charge (Rg- 1, Rt-1) Transportation Administrative Charge (Rt- 1) Volumetric Charges: Distribution Service Charge (Rg- 1, Rt- 1) Daily Balancing Charge (Rg- 1, Rt- 1) Competitive Supply Charge (Rg- 1) PeakDay Backup Charge (Rg-1)
Commercial (0 to 3,999) Daily Basic Distribution Charge (Fg-1, Ag- 1, NGV- 1, Tf-1) Transportation Administrative Charge (Tf- 1 ) Volumetric Charges: Distribution Service Charge (Fg- 1, Ag- 1, NGV- 1, Tf- 1) Daily Balancing Charge (Fg- 1, Ag- 1, NGV- 1, n - 1 ) Competitive Supply Charge (Fg- I , NGV- 1, Ag- 1) Peak Day Backup Charge (Fg- 1, NGV- 1, Ag- 1)
Commercial (4,000 to 39,999) Daily Basic Distribution Charge (Fg-2, Ag-2, NGV-2, Tf-2) Transportation Administrative Charge (Tf-2) Vol~unetric Charges: Distribution Service Charge (Fg-2, Ag-2, NGV-2, Tf-2) Daily Balancing Charge (Fg-2, Ag-2, NGV-2, Tf-2) Competitive Supply Charge (Fg-2, Ag-2, NGV-2) Peak Day Backup Charge (Fg-2, Ag-2, NGV-2)
Commercial (40,000 to 99,999) Daily Basic Distributioncharge (Fg-3, Ag-3, NGV-3, Tf-3) Transportation Administrative Charge (Tf-3) Volumetric Charges: Distribution Service Charge (Fg-3, Ag-3, NGV-3, Tf-3) Daily Balancing Charge (Fg-3, Ag-3, NGV-3, Tf-3) Competitive Supply Charge (Fg-3, Ag-3, NGV-3) Peak Day Backup Charge (Fg-3, Ag-3, NGV-3)
Commercial (100,000 to 499,999) Daily Basic Distributioncharge (Fg-4,Ag-4, Ig-4, Tf-4) Transportation Administrative Charge ( ~ f - 4 ) Volumetric Charges: Distribution Service Charge (Fg-4, Ag-4, Ig-4, n - 4 ) Daily Balancing Charge (Fg-4, Ag-4, Ig-4, Tf-4) Competitive Supply Charge (Fg-4, Ag-4, Ig-4) Peak Day Backup Charge (Fg-4, Ag-4)
Docket 5-UR- 103 Appendix D Page 2 of 12
Wisconsin Electric - Gas Operations Authorized Natural Gas Service Rates
2008
Present Authorized Rates Rates
Commercial (500,000 to 999,999) Daily Basic Distribution Charge (Fg-5, Ag-5, Ig-5, Tf-5) $ 35.00 $ 35.00 Transportation Administrative Charge (Tf-5) $ 2.75 $ 2.75 Volumetric Charges : Distribution Service Charge (Fg-5, Ag-5, Ig-5, Tf-5) $ 0.0597 $ 0.0613 Daily Balancing Charge (Fg-5,Ag-5, Ig-5, Tf-5) $ 0.0020 $ 0.0020 Competitive Supply Charge (Fg-5, Ag-5, Ig-5) $ 0.0192 $ 0.0242 Peak Day Backup Charge (Fg-5, Ag-5) $ 0.0057 $ 0.0025
Commercial (1,000,000 to 7,999,999) Daily Basic Distribution Charge (Fg-6, Ig-6, Tf-6) Transportation Administrative Charge (Tf-6) Volumetric Charges: Distribution Service Charge (Fg-6, Ig-6, Tf-6) Demand Charge (Fg-6, Ig-6, Tf-6) Daily Balancing Charge (Fg-6, Ig-6, Tf-6) Competitive Supply Charge (Fg-6, Ig-6) Peak Day Backup Charge (Fg-6)
Commercial (8,000,000 to 9,999,999) Daily Basic Distribution Charge (Fg-7, Ig-7, Tf-7) Transportation Administrative Charge (Tf-7) Volumetric Charges: Distribution Service Charge (Fg-7, Ig-7, Tf-7) Demand Charge (Fg-7, Ig-7, Tf-7) Daily Balancing Charge (Fg-7, Ig-7, Tf-7) Competitive Supply Charge (Fg-7, Ig-7) Peak Day Backup Charge (Fg-7)
Commercial (10,000,000+) Daily Basic Distribution Charge (Fg-8, Ig-8, Tf-8) Transportation Administratiw Charge (Tf-8) Volumetric Charges: Distribution Service Charge (Fg-8, Ig-8, Tf-8) Demand Charge (Fg-8, Ig-8, Tf-8) Daily Balancing Charge (Fg-8, Ig-8, Tf-8) Competi tive Supply Charge (Fg-8, Ig-8) Peak Day Backup Charge (Fg-8)
Docket 5-UR- 103 Appendix D Page 3 of 12
Wisconsin Electric - Gas Operations Authorized Natural Gas Service Rates
2008
Present Authorized Rates Rates
Electric Generation Special Contract Service Fixed Daily Charges:
Pt-2
Pt-5
Pt-6
Pt-7
Pt-8 Volumetric Charges: Pt-2 Pt-5 Pt-6 Pt-7 Pt-8
Base Gas Cost Rates: Axrage Peak Day Demand Costs - Volumetric Average Peak Day Demand Costs - Contracted Axrage Annual Contract Demand Costs Average Annual Demand Costs Average Commodity Costs Average Surcharge Costs LDC Reserxd Gas Supply Service
Daily Cashout Charges: Competitive Supply Peak Day Backup
Act 141 Volumetric DistributionFactors 11 Residential Commercial G-1 (0 to 3,999) Commercial G-2 (4,000 to 39,999) Commercial G-3 (40,000 to 99,999) Commercial G-4 (100,000 to 499,999) Commercial G-5 (500,000 to 999,999) Commercial G-6 (1,000,000 to 7,999,999) Commercial G-7 (8,000,000 to 9,999,999) Commercial G-8 (1 O,OOO,OOO+)
11 Act 141 volumetric distribution factors are included in the abow volumetric Distribution Service Charges.
Docket 5-UR- 103 Appendix D Page 4 of 12
Wisconsin Gas Company Authorized Natural Gas Rates
2008
Present Authorized Rates Rates
Residential Daily Basic Distribution Charge (Rg- 1, Rt- 1 ) $ 0.25 $ 0.28 Transportation Administrative Charge (Rt- 1 ) $ 2.00 $ 2.00 Volumetric Charges: Distribution Service Charge (Rg- 1, Rt- 1) $ 0.2113 $ 0.2155 Daily Balancing Charge (Rg- 1, Rt- 1 ) $ 0.0020 $ 0.0012 Competitive Supply Charge (Rg- 1 ) $ 0.0340 $ 0.0445 Peak Day Backup Charge (Rg- 1 ) $ 0.0002 $ 0.0004
Commercial (0 to 3,999) Daily Basic Distribution Charge (Fg- 1, Ag- 1, NGV- 1, Tf- 1 ) $ 0.25 $ 0.28 Transportation Administrative Charge (Tf- 1) $ 2.00 $ 2.00 Volumetric Charges: Distribution Service Charge (Fg- 1, Ag- 1, NGV- 1, Tf- 1) $ 0.1990 $ 0.2155 Daily Balancing Charge (Fg- 1, Ag- 1, NGV- 1 , IT- 1 ) $ 0.0020 $ 0.0012 Competitive Supply Charge (Fg- 1, NGV- 1, Ag- 1 ) $ 0.0330 $ 0.0445 Peak Day Backup Charge (Fg- 1, NGV- 1, Ag- 1 ) $ 0.0002 $ 0.0004
Commercial (4,000 to 39,999) Daily Basic Distribution Charge (Fg-2, Ag-2, NGV-2, Tf-2) $ 0.80 $ 0.85 Transportation Administrative Charge (Tf-2) $ 2.00 $ 2 .OO Volumetric Charges: Distribution Service Charge (Fg-2, Ag-2, NGV-2, Tf-2) $ 0.1531 $ 0.1606 Daily Balancing Charge (Fg-2, Ag-2, NGV-2, Tf-2) $ 0.0020 $ 0.0012 Competitive Supply Charge (Fg-2, Ag-2, NGV-2) $ 0.0220 $ 0.0439 Peak Day Backup Charge (Fg-2, Ag-2, NGV-2) $ 0.0001 $ 0.0003
Commercial (40,000 to 99,999) Daily Basic Distribution Charge (Fg-3, Ag-3, NGV-3, IT-3) $ 5.75 $ 5.80 Transportation Administrative Charge (Tf-3) $ 2.00 $ 2.00 Volumetric Charges: Distribution Service Charge (Fg-3, Ag-3, NGV-3, Tf-3) $ 0.1080 $ 0.1162 Daily Balancing Charge (Fg-3, Ag-3, NGV-3, Tf-3) $ 0.0020 $ 0.0012 Competitix Supply Charge (Fg-3, Ag-3, NGV-3) $ 0.0205 $ 0.0408 Peak Day Backup Charge (Fg-3, Ag-3, NGV-3) $ 0.0001 $ 0.0003
Docket 5-UR- 103 Appendix D Page 5 of 12
Wisconsin Gas Company Authorized Natural Gas Rates
2008
Present Authorized Rates Rates
Commercial (100,000 to 499,999) Daily Basic Distribution Charge (Fg-4, Ag-4, Ig-4, Tf-4) Transportation Administrative Charge (Tf-4) Volumetric Charges: Distribution Service Charge (Fg-4, Ag-4, Ig-4, Tf-4) Daily Balancing Charge (Fg-4,Ag-4, Ig-4, Tf-4) Competitive Supply Charge (Fg-4, Ag-4, Ig-4) Peak Day Backup Charge (Fg-4, Ag-4)
Commercial (500,000 to 999,999) Daily Basic Distribution Charge (Fg-5, Ag-5, Ig-5,Tf-5) Transportation Administrative Charge (Tf-5) Volumetric Charges: Distribution Service Charge (Fg-5, Ag-5, Ig-5, Tf-5) Daily Balancing Charge (Fg-5, Ag-5, Ig-5, Tf-5) Competitive Supply Charge (Fg-5, Ag-5, Ig-5) Peak Day Backup Charge (Fg-5, Ag-5)
Commercial (1,000,000 to 7,999,999) Daily Basic Distribution Charge (Fg-6, Ig-6, Tf-6) Transportation Administrative Charge (Tf-6) Volumetric Charges: Distribution Service Charge (Fg-6, Ig-6, Tf-6) Demand Charge (Fg-6, Ig-6, Tf-6) Daily Balancing Charge (Fg-6, Ig-6, Tf-6) Competitive Supply Charge (Fg-6, Ig-6) Peak Day Backup Charge (Fg-6)
Commercial (8,000,000 to 9,999,999) Daily Basic Distribution Charge (Fg-7, Ig-7, Tf-7) Transportation Administrative Charge (Tf-7) Volumetric Charges: Distribution Service Charge (Fg-7, Ig-7, Tf-7) Demand Charge (Fg-7, Ig-7, Tf-7) Daily Balancing Charge (Fg-7, Ig-7, Tf-7) Competitive Supply Charge (Fg-7, Ig-7) Peak Day Backup Charge (Fg-7)
Docket 5-UR- 103 Appendix D Page 6 of 12
Wisconsin Gas Company Authorized Natural Gas Rates
2008
Present Authorized Rates Rates
Commercial ( 10,000,000+) Daily Basic Distribution Charge (Fg-8, Ig-8, Tf-8) Transportation Administrative Charge (Tf-8) Volumetric Charges: Distribution Service Charge (Fg-8, Ig-8, Tf-8) Demand Charge (Fg-8, Ig-8, Tf-8) Daily Balancing Charge (Fg-8, Ig-8, Tf-8) Competitive Supply Charge (Fg-8, Ig-8) Peak Day Backup Charge (Fg-8)
Ornamental Lighting - 0 to 3 CF/Hr Monthly Charge
Base Gas Cost Rates: Average Peak Day Demand Costs - Volumetric Average Peak Day Demand Costs - Contracted Average Annual Contract Demand Costs Average Annual Demand Costs Average Commodity Costs Average Surcharge Costs
Daily Cashout Charges: Competitive Supply Peak Day Backup
Act 14 1 Volumetric Distribution Factors 11 Residential Commercial G- 1 (0 to 3,999) Commercial G-2 (4,000 to 39,999) Commercial G-3 (40,000 to 99,999) Commercial G-4 ( 100,000 to 499,999) Commercial G-5 (500,000 to 999,999) Commercial G-6 (1,000,000 to 7,999,999) Commercial G-7 (8,000,000 to 9,999,999) Commercial G-8 (1 O,OOO,OOO+)
11 Act 141 volumetric distribution factors are included in the above volumetric Distribution Service Charges.
Docket 5-UR- 103 Appendix D Page 7 of 12
Wisconsin Electric - Gas Operations Authorized Natural Gas Rates
2009
Present Authorized Rates Rates
Residential Daily Basic Distribution Charge (Rg- 1, Rt- 1) Transportation Administrative Charge (Rt- 1) Volumetric Charges: Distribution Service Charge (Rg- 1, Rt- I ) Daily Balancing Charge (Rg- 1, Rt- 1) Competitive Supply Charge (Rg- 1) PeakDay Backup Charge (Rg-1)
Commercial (0 to 3,999) Daily Basic Distribution Charge (Fg- I , Ag- 1, NGV- 1, Tf- 1) Transportation Administrative Charge (Tf- 1) Volumetric Charges: Distribution Service Charge (Fg-1, Ag- 1, NGV- 1, Tf- 1) Daily Balancing Charge (Fg-1 , Ag- 1, NGV- 1, Tf- 1) Competitive Supply Charge (Fg- 1 , NGV- 1, Ag- 1) Peak Day Backup Charge (Fg- 1, NGV- 1, Ag- 1)
Commercial (4,000 to 39,999) Daily Basic Distribution Charge (Fg-2, Ag-2, NGV-2, Tf-2) Transportation Administrative Charge (Tf-2) Vol~unetric Charges: Distribution Service Charge (Fg-2, Ag-2, NGV-2, Tf-2) Daily Balancing Charge (Fg-2, Ag-2, NGV-2, E-2) Competitive Supply Charge (Fg-2, Ag-2, NGV-2) Peak Day Backup Charge (Fg-2, Ag-2, NGV-2)
Commercial (40,000 to 99,999) Daily Basic Distribution Charge (Fg-3, Ag-3, NGV-3, Tf-3) Transportation Administrative Charge (Tf-3) Volumetric Charges: Distribution Service Charge (Fg-3, Ag-3, NGV-3, Tf-3) Daily Balancing Charge (Fg-3, Ag-3, NGV-3, Tf-3) Competitive Si~pply Charge (Fg-3, Ag-3, NGV-3) Peak Day Backup Charge (Fg-3, Ag-3, NGV-3)
Commercial (100,000 to 499,999) Daily Basic Distribution Charge (Fg-4, Ag-4, Ig-4, Tf-4) Transportation Administrative Charge (Tf-4) Volumetric Charges: Distribution Service Charge (Fg-4, Ag-4, Ig-4,Tf-4) Daily Balancing Charge (Fg-4, Ag-4, Ig-4, Tf-4) Competitive Supply Charge (Fg-4, Ag-4, Ig-4) Peak Day Backup Charge (Fg-4, Ag-4)
. Docket 5-UR-103 Appendix D Page 8 of 12
Wisconsin Electric - Gas Operations Authorized Natural Gas Rates
2009
Present Authorized Rates Rates
Commercial (500,000 to 999,999) Daily Basic Distribution Charge (Fg-5, Ag-5, Ig-5, Tf-5) Transportation Administrative Charge (Tf-5) Volumetric Charges: Distribution Service Charge (Fg-5,Ag-5, Ig-5, Tf-5) Daily Balancing Charge (Fg-5, Ag-5, Ig-5, Tf-5) Competitive Supply Charge (Fg-5, Ag-5, Ig-5) Peak Day Backup Charge (Fg-5, Ag-5)
Commercial (1,000,000 to 7,999,999) Daily Basic Distribution Charge (Fg-6, Ig-6, Tf-6) Transportation Administrative Charge (Tf-6) Volumetric Charges: Distribution Service Charge (Fg-6, Ig-6, Tf-6) Demand Charge (Fg-6, Ig-6, Tf-6) Daily Balancing Charge (Fg-6, Ig-6, Tf-6) Competitive Supply Charge (Fg-6, Ig-6) Peak Day Backup Charge (Fg-6)
Commercial (8,000,000 to 9,999,999) Daily Basic Distribution Charge (Fg-7, Ig-7, Tf-7) Additional Meter Charge Tramportation Administrative Charge (Tf-7) Volumetric Charges: Distribution Service Charge (Fg-7, Ig-7, Tf-7) Demand Charge (Fg-7, Ig-7, Tf-7) '
Daily Balancing Charge (Fg-7, Ig-7, Tf-7) Competitive Supply Charge (Fg-7, Ig-7) Peak Day Backup Charge (Fg-7)
Commercial (1 0,000,000+) Daily Basic Distribution Charge (Fg-8, Ig-8, Tf-8) Additional Meter Charge Transportation Administrative Charge (Tf-8) Volumetric Charges: Distribution Service Charge (Fg-8, Ig-8, Tf-8) Demand Charge (Fg-8, Ig- 8, Tf-8) Daily Balancing Charge (Fg-8, Ig-8, Tf-8) Competitive Supply Charge (Fg-8, Ig-8) Peak Day Backup Charge (Fg-8)
Docket 5-UR- 103 Appendix D Page 9 of 12
Wisconsin Electric - Gas Operations Authorized Natural Gas Rates
2009
Present Authorized Rates Rates
Electric Generation Special Contract Service Fixed Daily Charges:
Pt-2
Pt-5
Pt-6
Pt-7
Pt-8 Volumetric Charges: Pt-2 Pt-5 Pt-6 Pt-7 Pt-8
Base Gas Cost Rates: Average Peak Day Demand Costs - Volumetric Average Peak Day Demand Costs - Contracted Average Annual Contract Demand Costs Average Annual Demand Costs Average Commodity Costs Average Surcharge Costs LDC Reserved Gas Supply Service
Daily Cashout Charges: Competitive Supply Peak Day Backup
Act 141 Volumetric Distribution Factors 11 Residential Commercial G- 1 (0 to 3,999) Commercial G-2 (4,000 to 39,999) Commercial G-3 (40,000 to 99,999) Commercial G-4 (1 00,000 to 499,999) Commercial G-5 (500,000 to 999,999) Commercial G-6 ( 1,000,000 to 7,999,999) Commercial G-7 (8,000,000 to 9,999,999) Commercial G-8 (I O,OOO,OOO+)
11 Act 14 1 volumetric distribution factors are included in the above volumetric Distribution Service Charges.
Docket 5-UR- 103 Appendix D Page 10 of 12
Wisconsin Gas Company Authorized Natural Gas Rates
2009
Present Authorized Rates Rates
Residential Daily Basic Distribution Charge (Rg- 1, Rt-1) $ 0.25 $ 0.28 Transportation Administrative Charge (Rt- I ) $ 2.00 $ 2.00 Volumetric Charges: Distribution Service Charge (Rg- 1, Rt- 1) $ 0.2113 $ 0.2155 Daily Balancing Charge (Rg- 1, Rt- 1) $ 0.0020 $ 0.0012 Competitive Supply Charge (Rg- 1) $ 0.0340 $ 0.0445 Peak Day Backup Charge (Rg- 1) $ 0.0002 $ 0.0004
Commercial (0 to 3,999) Daily Basic Distribution Charge (Fg- 1, Ag- 1, NGV- 1, Tf- 1) $ 0.25 $ 0.28 Transportation Administrative Charge (Tf- 1) $ 2.00 $ 2.00 Volumetric Charges: Distribution Service Charge (Fg- 1, Ag- 1, NGV- 1, Tf- 1) $ 0.1990 $ 0.2155 Daily Balancing Charge (Fg- 1, Ag- 1, NGV- 1, Tf- 1) $ 0.0020 $ 0.0012 Competitive Supply Charge (Fg- 1, NGV- 1, Ag- 1 ) $ 0.0330 $ 0.0445 Peak Day Backup Charge (Fg- 1, NGV- 1, Ag- 1 ) $ 0.0002 $ 0.0004
Commercial (4,000 to 39,999) Daily Basic Distribution Charge (Fg-2, Ag-2, NGV-2, Tf-2) $ 0.80 $ 0.85 Transportation Administrative Charge (Tf-2) $ 2.00 $ 2.00 Volumetric Charges : Distribution Service Charge (Fg-2, Ag-2, NGV-2, Tf-2) $ 0.1531 $ 0.1596 Daily Balancing Charge (Fg-2, Ag-2, NGV-2, Tf-2) $ 0.0020 $ 0.0012 Competitive Supply Charge (Fg-2, Ag-2, NGV-2) $ 0.0220 $ 0.0439 Peak Day Backup Charge (Fg-2, Ag-2, NGV-2) $ 0.0001 $ 0.0003
Commercial (40,000 to 99,999) Daily Basic Distribution Charge (Fg-3, Ag-3, NGV-3, Tf-3) $ 5.75 $ 5.80 Transportation Administrative Charge (Tf-3) $ 2.00 $ 2.00 Volumetric Charges: Distribution Service Charge (Fg-3, Ag-3, NGV-3, Tf-3) $ 0.1080 $ 0.1152 Daily Balancing Charge (Fg-3, Ag-3, NGV-3, Tf-3) $ 0.0020 $ 0.0012 Competitive Supply Charge (Fg-3, Ag-3, NGV-3) $ 0.0205 $ 0.0408 Peak Day Backup Charge (Fg-3, Ag-3, NGV-3) $ 0.0001 $ 0.0003
Docket 5-UR- 103 Appendix D Page 1 1 of 12
Wisconsin Gas Company Authorized Natural Gas Rates
2009
Present Authorized Rates Rates
Commercial (1 00,000 to 499,999) Daily Basic Distribution Charge (Fg-4, Ag-4, Ig-4, Tf-4) Transportation Administratix Charge (Tf-4) Volumetric Charges: Distribution Service Charge (Fg-4, Ag-4, Ig-4, Tf-4) Daily Balancing Charge (Fg-4, Ag-4, Ig-4, Tf-4) Competitix Supply Charge (Fg-4, Ag-4, Ig-4) Peak Day Backup Charge (Fg-4, Ag-4)
Commercial (500,000 to 999,999) Daily Basic Distribution Charge (Fg-5, Ag-5, Ig-5, Tf-5) Transportation Administratix Charge (Tf-5) Volumetric Charges: Distribution Service Charge (Fg-5, Ag-5, Ig-5, Tf-5) Daily Balancing Charge (Fg-5, Ag-5, Ig-5, Tf-5) Competitive Supply Charge (Fg-5, Ag-5, Ig-5) Peak Day Backup Charge (Fg-5, Ag-5)
Commercial (1,000,000 to 7,999,999) Daily Basic Distribution Charge (Fg-6, Ig-6, Tf-6) Transportation Administrative Charge (Tf-6) Volumetric Charges: Distribution Service Charge (Fg-6, Ig-6, Tf-6) Demand Charge (Fg-6, Ig-6, Tf-6) Daily Balancing Charge (Fg-6, Ig-6, Tf-6) Competitive Supply Charge (Fg-6, Ig-6) Peak Day Backup Charge (Fg-6)
Commercial (8,000,000 to 9,999,999) Daily Basic Distribution Charge (Fg-7, Ig-7, Tf-7) Transportation Administrative Charge (Tf-7) Volumetric Charges: Distribution Service Charge (Fg-7, Ig-7, Tf-7) Demand Charge (Fg-7, Ig-7, Tf-7) Daily Balancing Charge (Fg-7, Ig-7, Tf-7) Competitix Supply Charge (Fg-7, Ig-7) Peak Day Backup Charge (Fg-7)
Docket 5-UR- 103 Appendix D page 12 of 12
Wisconsin Gas Company Authorized Natural Gas Rates
2009
Present Authorized Rates Rates
Commercial (1 0,000,000+) Daily Basic Distribution Charge (Fg-8, Ig-8, Tf-8) Transportation Administrative Charge (Tf-8) Volumetric Charges: Distribution Service Charge (Fg-8, Ig-8, Tf-8) Demand Charge (Fg-8, Ig-8, Tf-8) Daily Balancing Charge (Fg-8, Ig-8, Tf-8) Competitive Supply Charge (Fg-8, Ig-8) Peak Day Backup Charge (Fg-8)
Ornamental Lighting - 0 to 3 CFIHr Monthly Charge
Base Gas Cost Rates: Average Peak Day Demand Costs - Volumetric Average Peak Day Demand Costs - Contracted Average Annual Contract Demand Costs Average Annual Demand Costs Average Commodity Costs Average Surcharge Costs
Daily Cashout Charges: Competitive Supply Peak Day Backup
Act 141 Volumetric Distribution Factors 11 Residential Commercial G- 1 (0 to 3,999) Commercial G-2 (4,000 to 39,999) Commercial G-3 (40,000 to 99,999) Commercial G-4 (1 00,000 to 499,999) Commercial G-5 (500,000 to 999,999) Commercial G-6 (1,000,000 to 7,999,999) Commercial G-7 (8,000,000 to 9,999,999) Commercial G-8 ( lO,OOO,OOO+)
11 Act 14 1 volumetric distribution factors are included in the above volumetric Distribution Service, Charges.
WE-GO Residential Monthly Bill Impact Analysis 2008
Gas Costs Summer Winter Film Sales Serbice 0.81 14 0.9263
Current Present Admin & Total
Monthly IJse Customer Distribut'~~ Monthly Therms Charge Charges Cost
Rg-I: Residential Firm Sales Service During Summer Months 5 $ 7.60 $ I .W) $ 8.69
15 $ 7.60 $ 3.27 $ 10.87 24 ayg. 5 7.60 $ 5 . 2 3 % 12.84 35 $ 7.60 $ 7.63 $ 15.23 50 $ 7.60 $ 10.90 $ 18.50 75 $ 7.60 $ 16.35 $ 23.95
I00 $ 7.60 $ 2 1 . 8 0 $ 29.40 108 $ 7.60 $ 23.54 $ 31.15 150 $ 7.60 $ 32.70 $ 40.30 200 $ 7.60 $ 43.60 $ 51.20 300 $ 7.60 $ 65.40 $ 73.00
Autlioriled A~~tl~orized Authorigd Monthly Monthly Admin. & Admin & Total Bill Percent Customer Distribut'n Monthly Total lncreare Lncrease Charges Charges Cost Gm Costs Costs (Decrease) (Decrease) Gas Costs Total Costs
Rg-I: Residential FirrnSalcsService During Winter Months 5 $ 7.60 $ 1.09 $
15 $ 7.60 $ 3.27 $
24 $ 7.60 $ 5.23 $
35 $ 7.60 $ 7 . 6 3 $ 50 $ 7.60 $ 1 0 . 9 0 $ 75 $ 7.60 $ ,16.35 $
100 $ 7.60 $ 2 1 . 8 0 $ 108 a%. $ 7.60 $ 23.54 $
150 $ 7.60 $ 32.70 $
200 $ 7.60 $ 43.60 $
300 $ 7.60 $ 6 5 . 4 0 $
Avg. Annual Residential Billing 7 92 $ 91.25 $ 172.66 $ 263.91
WGC Residential Monthly Bill Impact Analysis 2008
Gas Costs Firm Service Preaent Allocalion
Author i~d Autboriled Author i~d Monthly Monthly Admin.4 Admin& Total Bill Percent Customer Distribut'n Monthly Total Increase Increase Charges Charges Cost Gas Costs Costs (Decrease) (Deerease)
Current Present A h i n . & Total
Monthly Use Customer Distribut'n Monthly lherms Charge Charges Cost Gas Costs Total Cosls
Rg-I: Residential Firm Sales Service During Summer Month 5 $ 7.60 $ 1.24 $
15 $ 7.60 $ 3.71 $ 24 a s . $ 7.60 $ 5.94 $ 35 $ 7.60 $ 8.66 $ 50 S 7.60 $ 12.38 $ 75 6 7.60 $ 18.56 $
100 $ 7.60 $ 24.75 $ 108 $ 7.60 $ 26.73 $ 150 $ 7.60 $ 37.13 $ 200 $ 7.60 $ 49.50 $
300 $ 7.60 $ 74.25 $
Rg-I: Residential Firmsales Service During Winter Month 5 $ 7.60 $ 1.24 $
15 $ 7.60 $ 3.71 $ 24 $ 7.60 $ 5.94 $ 35 $ 7.60 $ , 8.66 $ 50 $ 7.60 $ 12.38 $ 75 $ 7.60 $ 18.56 $
100 $ 7.60 $ 24.75 $ I11 avg. $ 7.60 $ 27.47 $ I50 $ 7.60 $ 37.13 $ 200 $ 7.60 $ 49.50 $ 300 $ 7.60 $ 74.25 $
Avg. Annual Residential Billing 810 $ 91.25 $ 200.48 $ 291.73 $ 754.18 $ 1,045.90
Docket 5-UR- 103 Appendix F
Wisconsin Electric Power Company Monitoring for Fuel Costs
05-UR-103
Fuel Cost Cumulative Fuel Net k W h per Net kWh Cost Costs Produced Produced per k W h
January $ 72,591,000 2,756,38 1,000 $ 0.02634 $ 0.02634
February 6932 1,000 2,494,7 17,000 0.02799 0.027 12
March 80,407,000 2,665,5 14,000 0.03017 0.028 15
April 68,848,000 2,475,779,000 0.02781 0.02807
June 89,44 1,000 2,879,458,000 0.03 106 0.02892
July 1 14,409,000 3,129,158,000 0.03656 0.03018
August 108,245,000 3,095,210,000 0.03497 0.03085
September 84,550,000 2,703,877,000 0.03 127 0.03090
October 66,825,000 2,650,653,000 0.02521 0.03035
November 64,460,000 2,523,929,000 0.02554 0.02994
December 78,383,000 2,744,366,000 0.02856 0.02983
Total $ 976,904,000 32,75 1,893,000 $ 0.02983 $ 0.02983
Docket 5-UR- 103 Appendix G
Deferred and Escrow Account Amortizations-Wisconsin Jurisdiction
NIRB - Used in calculation of working capital at pre-tax weighted average cost of capital. WACC - Canying cost based upon pre-tax weighted average cost of capital. STDR - Canying cost based upon short-term debt rate. N/A - Not included in working capital or no canying costs were authorized. Amort. Period Yrs. -Where no amortization period listed, item awaiting disposition in future case * - One-time amortization of 12/31/07 balance.
BEFORE THE
PUBLIC SERVICE COMMISSION OF WISCONSIN
Joint Application of Wisconsin Electric Power Company and Wisconsin Gas LLC, both d/b/a We Energies, for Wisconsin Electric Power Company to Increase Its Electric, Natural Gas, and Steam Rates and for Wisconsin Gas LLC to Increase Its Natural Gas Rates
COMMISIONER AZAR'S PARTIAL DISSENT FROM AND CONCURRENCE WITH THE FINAL DECISION
In this docket, members of the public testified about the hardship that would be created
by increasing utility prices. Fortunately, the Commission was able to minimize the increase in
rates. Nonetheless, as we move toward addressing costs incurred for the current construction
cycle, carbon cap and trade, and other environmental controls, we will be continually challenged
with higher and higher costs for electricity.
The public noted, because of hard economic times, they have been forced to tighten their
belts and asked what utilities are doing. In future rate cases, it would be helpful to have
testimony on the actions utilities are taking to improve efficiency and reduce costs without
threatening the safety and reliability of service. Moderating attorneys' hourly rates is an example
of how utilities can tighten their budgets.
I suspect the hourly rates that Wisconsin utilities pay for local attorneys is generally in the
range of $300-$500/hour (sometimes more, sometimes less). Moreover, utility attorneys have
much discretion in how many hours to spend on a case. Usually, the primary consideration is not
cost, but winning the case.
To provide some context regarding hourly rates, when awarding intervenor
compensation, the Commission currently caps attorney fees at $175/hour. Plus, we cap the
Docket 5-UR-103
number of hours spent on any single case. The ratepayers are paying for two sets of attorneys:
(1) those representing ratepayers and (2) those representing utilities. Ironically, ratepayers are
compensating their opponents' attorneys more than twice as much as they are paying their own
attorneys. I find this to be unjust and warranting correction.
For larger clients, the hourly rates of local attorneys may be negotiated down.
Indeed, the Commission could help the utilities with ths endeavor. We could increase the
utilities' leverage in their negotiations by setting a cap on attorneys' hourly rates. If utilities
wanted to pay more than a Commission-set cap, then the shareholders would have to pay for
those extra fees.
Carrying Costs of Deferrals
As noted on page 55, when deferred costs for regulatory assets are amortized, I would
grant the weighted cost of capital as the rate to calculate carrying costs. Once the Commission
determines that deferred costs are recoverable in rates, then those deferred costs are
indistinguishable from costs relating to ordinary regulatory assets and should be treated the same
vis-a-vis carrying costs.
The dispute raised in this docket arose from a few recent decisions. Specifically, the
dispute arose because the Commission, in some but not all cases, awarded carrying costs when
granting deferrals. In these few cases, the carrying costs were set at the short-term cost of debt.
I understand, historically, utilities were not awarded carrying costs at all when granted a
deferral because deferrals are considered unusual and just receiving an approval for a deferral
was considered sufficient compensation. If and when the deferred costs were approved for rates,
the deferred costs were considered as any other regulatory-asset cost and received the weighted
Docket 5-UR- 103
cost of capital. Hence, the dispute in this case arose because the Commission in a few situations
awarded lower-than-normal carrying costs at the time of granting deferrals.
I believe it is preferable for the Commission to set a uniform policy on whether carrying
costs will be awarded during the period from the granting of a deferral to when the deferred costs
are amortized in a rate case. In response to the next request for deferral, I will advocate a return
to the historic policy, which I believe is more reflective of the unique nature of deferrals.
Dated at Madison, Wisconsin, this 17th day of January, 2008.
By Commissioner Lauren L. Azar: ,,*./,,-
Lauren Azar Commissioner
K:\Azar\Dissents or concurring opinions\5-UR-103 - WEPCO Dissent&Concurrance.doc