FinalOrder

              STATE OF ILLINOIS
ILLINOIS COMMERCE COMMISSION
North Shore Gas Company :
:
Proposed general increase in natural gas : 11-0280
rates. :
:
The Peoples Gas Light and Coke Company : 11-0281
:
Proposed general increase in natural gas : Consol.
rates. :
ORDER
January 10, 201211-0280/11-0281 (cons.)
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Table of Contents
I. INTRODUCTION.................................................................................................. 1
A. PROCEDURAL HISTORY ...................................................................................... 1
II. TEST YEAR ......................................................................................................... 5
III. REVENUE REQUIREMENT................................................................................. 5
A. NORTH SHORE .................................................................................................. 6
1. Utilities .................................................................................................... 6
2. Staff......................................................................................................... 6
3. North Shore’s Response ......................................................................... 6
4. Commission Analysis and Conclusion .................................................... 7
B. PEOPLES GAS................................................................................................... 7
1. Utilities .................................................................................................... 7
2. Staff......................................................................................................... 7
3. Peoples Gas Response .......................................................................... 7
4. Commission Analysis and Conclusion .................................................... 8
IV. RATE BASE......................................................................................................... 8
A. OVERVIEW ........................................................................................................ 8
B. UNCONTESTED ISSUES....................................................................................... 9
1. Natural Gas Prices – Working Capital Allowance – Gas in Storage........ 9
2. Plant........................................................................................................ 9
3. Accumulated Depreciation Expense on Forecasted Additions and Utility Plant in Service – 2010 Actual ................................................................ 9
4. Accumulated Deferred Income Taxes ..................................................... 9
C. CONTESTED ISSUES......................................................................................... 10
1. Plant (all subjects relate to NS and PGL unless otherwise noted) ........ 10
2. Materials and Supplies – Computation of Associated Accounts Payable .............................................................................................................. 18
3. Gas in Storage – Computation of Associated Accounts Payable.......... 19
4. Cash Working Capital ........................................................................... 21
5. Retirement Benefits, Net ....................................................................... 28
6. Accumulated Deferred Income Taxes – ................................................ 34
D. ACCUMULATED DEPRECIATION (UNCONTESTED EXCEPT FOR DERIVATIVE ADJUSTMENTS FROM CONTESTED ADJUSTMENTS) ............................................. 43
1. Utilities .................................................................................................. 43
2. Staff....................................................................................................... 43
3. Commission Analysis and Conclusion .................................................. 43
E. APPROVED RATE BASE .................................................................................... 43
V. OPERATING EXPENSES ......................................................................................................... 44
A. OVERVIEW ...................................................................................................... 44
B. UNCONTESTED ISSUES..................................................................................... 4411-0280/11-0281 (cons.)
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1.
Physical Gas Losses............................................................................. 44
2. Distribution O&M................................................................................... 45
3. Distribution O&M – Adjustment to Reflect Costs that Should Have Been Capitalized Instead of Expensed........................................................... 45
4. Distribution O&M – Inflation................................................................... 45
5. Distribution O&M - Building Lease (PGL).............................................. 45
6. Customer Service and Information........................................................ 45
7. Administrative & General ...................................................................... 46
8. Depreciation Expense on Utility Plant in Service – 2010 Actual............ 47
9. Current Income Taxes........................................................................... 47
10. Invested Capital Tax (derivative adjustments)....................................... 48
11. Interest Synchronization (derivative adjustments)................................. 48
12. Updated Inflation Rate .......................................................................... 48
13. Rate 4 Revenues (NS) .......................................................................... 48
C. CONTESTED ISSUES......................................................................................... 48
1. Incentive Compensation........................................................................ 48
2. Non-union Base Wages ........................................................................ 59
3. Headcounts........................................................................................... 61
4. Self-Constructed Property..................................................................... 63
5. Uncollectibles Expenses – Use of Net Write-Off Method ...................... 65
6. Administrative & General ...................................................................... 66
7. Depreciation.......................................................................................... 93
8. Revenues.............................................................................................. 94
D. TAXES OTHER THAN INCOME TAXES (PAYROLL AND INVESTED CAPITAL TAXES) (UNCONTESTED EXCEPT FOR DERIVATIVE ADJUSTMENTS FROM CONTESTED ADJUSTMENTS) ............................................................................................. 100
E. INCOME TAXES (INCLUDING INTEREST SYNCHRONIZATION) (UNCONTESTED EXCEPT FOR DERIVATIVE ADJUSTMENTS FROM CONTESTED ADJUSTMENTS)................... 100
F. GROSS REVENUE CONVERSION FACTOR ......................................................... 101
1. Uncollectible Rate ............................................................................... 101
2. Derivative Adjustments from Contested Adjustments ......................... 101
G. TOTAL OPERATING EXPENSES........................................................................ 101
VI. RATE OF RETURN .................................................................................................................... 102
A. OVERVIEW .................................................................................................... 102
B. CAPITAL STRUCTURE ..................................................................................... 103
1. Utilities ................................................................................................ 103
2. Staff..................................................................................................... 103
3. Companies’ Response ........................................................................ 107
4. Commission Analysis and Conclusion ................................................ 108
C. COST OF LONG TERM DEBT............................................................................ 109
1. Utilities ................................................................................................ 109
2. Staff..................................................................................................... 109
3. Commission Analysis and Conclusion ................................................ 110
D. COST OF SHORT-TERM DEBT ......................................................................... 110
1. Utilities ................................................................................................ 110
2. Staff..................................................................................................... 11011-0280/11-0281 (cons.)
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3.
Commission Analysis and Conclusion ................................................ 111
E. COST OF COMMON EQUITY............................................................................. 112
1. Utilities ................................................................................................ 112
2. AG....................................................................................................... 115
3. GCI...................................................................................................... 116
4. Staff..................................................................................................... 125
5. Utilities’ Response............................................................................... 132
6. Commission Analysis and Conclusion ................................................ 135
F. WEIGHTED AVERAGE COST OF CAPITAL .......................................................... 141
1. North Shore......................................................................................... 141
2. Peoples Gas........................................................................................ 141
VII. WEATHER NORMALIZATION .............................................................................................. 141
VIII. RIDERS .......................................................................................................................................... 141
A. RIDERS UEA AND UEA-GC ........................................................................... 141
1. Utilities ................................................................................................ 141
2. Staff..................................................................................................... 142
3. Utilities Response ............................................................................... 143
4. Commission Analysis and Conclusion ................................................ 143
B. RIDER VBA................................................................................................... 143
1. Utilities ................................................................................................ 143
2. Staff..................................................................................................... 144
3. AG....................................................................................................... 146
4. Utilities Response ............................................................................... 161
5. Commission Analysis and Conclusion ................................................ 163
C. RIDER ICR.................................................................................................... 164
1. Commission Analysis and Conclusion ................................................ 164
IX. COST OF SERVICE STUDY ................................................................................................. 165
A. EMBEDDED COST OF SERVICE STUDY ............................................................. 165
B. CONTESTED ISSUES....................................................................................... 165
1. Classification of Uncollectible Accounts Expenses Account No. 904.. 165
2. Classification of A&G Related to O&M................................................ 166
3. Classification of Fixed Costs ............................................................... 167
X. RATE DESIGN ................................................................................................. 168
A. OVERVIEW .................................................................................................... 168
B. GENERAL RATE DESIGN................................................................................. 168
1. Allocation of Rate Increase ................................................................. 168
2. Uniform Numbering of Service Classifications .................................... 168
C. SERVICE CLASSIFICATION RATE DESIGN.......................................................... 169
1. Uncontested Issues............................................................................. 169
2. Contested Issues – North Shore and Peoples Gas............................. 173
D. TARIFFS – OTHER NON-TRANSPORTATION TARIFF ISSUES................................ 189
1. Uncontested Issues - North Shore and Peoples Gas.......................... 189
E. BILL IMPACTS ................................................................................................ 19011-0280/11-0281 (cons.)
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Utilities ................................................................................................ 190
2. Staff..................................................................................................... 191
3. AG....................................................................................................... 191
4. Commission Analysis and Conclusion ................................................ 191
XI. TRANSPORTATION ISSUES .............................................................................................. 192
A. OVERVIEW .................................................................................................... 192
1. Utilities ................................................................................................ 192
2. IIEC/CNEG.......................................................................................... 193
3. IGS...................................................................................................... 195
B. UNCONTESTED ISSUES................................................................................... 196
1. Allowable Bank (AB) Calculation......................................................... 196
2. Rider CFY ........................................................................................... 196
3. Rider AGG (except Aggregation Charge)............................................ 197
4. Rider SBO........................................................................................... 197
C. ADMINISTRATIVE CHARGES ............................................................................ 197
1. Utilities ................................................................................................ 197
2. Staff..................................................................................................... 199
3. IGS...................................................................................................... 199
4. Commission Analysis and Conclusion ................................................ 200
D. LARGE VOLUME TRANSPORTATION PROGRAM.................................................. 200
1. Administrative Charges ....................................................................... 200
2. Transportation Storage – Issues ......................................................... 202
3. Associated Rider Modifications ........................................................... 221
E. SMALL VOLUME TRANSPORTATION PROGRAM (CHOICES FOR YOUSM OR “CFY”) .................................................................................................................... 231
1. Aggregation Charge ............................................................................ 231
2. Purchase of Receivables (withdrawn) ................................................. 234
XII. FINDINGS AND ORDERING PARAGRAPHS .............................................................. 235STATE OF ILLINOIS
ILLINOIS COMMERCE COMMISSION
North Shore Gas Company :
:
Proposed general increase in natural gas : 11-0280
rates. :
:
The Peoples Gas Light and Coke Company : 11-0281
:
Proposed general increase in natural gas : Consol.
rates. :
I. Introduction
ORDER
A. Procedural History
On February 15, 2011, North Shore Gas Company (“North Shore” or “NS”) filed with the Illinois Commerce Commission (“Commission”), pursuant to Section 9-201 of the Public Utilities Act (the “Act”) (220 ILCS 5/9-201), the following revised tariff sheets: ILL. C.C. No. 17, Title Sheet and ILL. C. C. No. 17, Sheet Nos. 1-4, 6, 8-10, 17-28, 32 39, 44-48, 57-97, 100, 102-104, 107, 111, 112, 114, 123-125, 134-149, 157, 161, 170-186. This tariff filing embodied a proposed general increase in gas service rates, and revisions of other terms and conditions of service. The tariff filing was accompanied by direct testimony, other exhibits, and other materials required under Parts 285 and 286 of Title 83 of the Illinois Administrative Code (the “Code”), 83 Ill. Admin. Code Parts 285 and 286.
On February 15, 2011, The Peoples Gas Light and Coke Company (“Peoples Gas” or “PGL” or “Peoples”) filed with the Commission, pursuant to Section 9-201 of the Act, the following revised tariff sheets: ILL. CC. No. 28, Title Sheet and ILL. C. C. No. 28, Sheet Nos. 1-5, 7-9, 16, 18-29, 32-39, 44-48, 58-85, 93-104, 106, 108-110, 113, 117, 118, 120, 130, 139-141, 150-163, 168, 172, 181-197. This tariff filing embodied a proposed general increase in gas service rates and revisions of other terms and conditions of service. The tariff filing was accompanied by direct testimony, other exhibits, and other materials required under Parts 285 and 286 of the Code.
Notices of the proposed tariff changes reflected in these rate filings were posted in North Shore’s and Peoples Gas’ (the “Utilities” or “Companies”) business offices and published in secular newspapers of general circulation in the Utilities’ respective service areas, as evidenced by publishers’ certificates, in accordance with the requirements of Section 9-201(a) of the Act and the provisions of 83 Ill. Admin. Code Part 255.
The Commission issued a Suspension Order for North Shore’s tariff filing on March 23, 2011, which suspended the tariffs to and including July 14, 2011, and further initiated Docket 11-0280. On July 7, 2011, the Commission issued a Resuspension Order that suspended these tariffs to, and including, January 14, 2012.11-0280/11-0281 (cons.)
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The Commission issued a Suspension Order for Peoples Gas’ tariff filing on March 23, 2011, which suspended the tariffs to and including July 14, 2011, and initiated Docket 11-0281. On July 7, 2011, the Commission issued a Resuspension Order that suspended these tariffs to, and including, January 14, 2012.
On April 5, 2011, the Utilities each filed motions for protective orders in each Docket, pursuant to 83 Ill. Admin. Code §200.600. On the same date, the Utilities also filed motions to remove the confidential and proprietary designations from JamesSchott’s direct testimony relating to year-end return on common equity, the Utilities’ most recent actuarial report, and Part 285.315(c) Attachment B.
On April 11, 2011, the Administrative Law Judges (“ALJs”) held a n initial status hearing and, on the oral motion of Commission Staff (“Staff”), consolidated these cases and also orally approved a case schedule and data request response time schedule.
On April 12, 2011, the Utilities filed a motion for entry of case management plan and schedule, pursuant to Section 10-101.1 of the Act and 83 Ill. Admin. Code §§ 200.190, 200.370, and 200.500.
On April 13, 2011, the ALJs issued a notice of schedule.
Petitions to Intervene were filed or appearances were entered on behalf of the Attorney General of the State of Illinois (the “Attorney General” or “AG”); the Citizens Utility Board (“CUB”); the City of Chicago (the “City”) (collectively, CUB and the City are “CUB/City”) (collectively, the AG, CUB, and the City are “AG/CUB/City or also “GCI” for “Governmental and Consumer Intervenors”); Constellation NewEnergy-Gas Division, LLC (“CNE”); Ford Motor Company and Merchandise Mart proceeding as the Illinois Industrial Energy Consumers (“IIEC”); Integrys Energy Services-Natural Gas LLC (“IES”); Interstate Gas Supply of Illinois, Inc. (“IGS”); and Vanguard Energy Services, LLC. All petitions were granted by the ALJs.
The evidentiary hearing was held August 29, 2011 through September 2, 2011, and September 6, 2011, at the offices of the Commission in Chicago, Illinois. At the evidentiary hearings, the Utilities, Staff, and the Intervenors entered appearances and presented testimony. The following witnesses testified on behalf of the Utilities: James F. Schott, Vice President-External Affairs, Integrys Energy Group, Inc., North Shore and Peoples Gas (NS Ex. 1.0, PGL Ex. 1.0, NS-PGL 17.0, NS-PGL Ex 34.0); Lisa J. Gast, Manager, Financial Planning and Analysis, Integrys Business Support, LLC (NS Ex. 2.0, PGL Ex. 2.0, NS-PGL Ex. 18.0, NS-PGL Ex. 35.0); Paul R. Moul, Managing Consultant, P. Moul & Associates (NS Ex. 3.0 REV, PGL Ex. 3.0 REV, NS-PGL Ex 19.0 REV, NS-PGL Ex. 36.0); Steven M. Fetter President, Regulation UnFettered (NS-PGL Ex. 20.0, NS-PGL Ex. 37.0); Kevin R. Kuse, Senior Load Forecaster, Integrys Business Support, LLC (NS Ex. 4.0 REV, PGL Ex. 4.0 REV, NS-PGL Ex. 32.0, NS-PGL Ex. 48.0); Christine M. Gregor, Director, Operations Accounting, North Shore and Peoples Gas (NS Ex. 5.0, PGL Ex. 5.0, NS-PGL Ex. 21.0 Corr., NS-PGL Ex. 38.0); Sharon Moy, Rate Case Consultant, Regulatory Affairs, Integrys Business Support, LLC (NS Ex. 6.0, PGL Ex. 6.0, NS-PGL Ex. 22.0 2 Corr., NS-PGL Ex. 39.0 Corr.); John Hengtgen, Consultant, Stafflogix Corporation (NS Ex. 7.0, PGL Ex. 7.0, NS-PGL Ex. 23.0 Corr., NS-PGL Ex. 40.0 Corr.); Edward Doerk, Vice President, Gas Standardization, The Peoples Gas Light and Coke Company and North Shore Gas Company (NS Ex. 8.0, PGL Ex. 8.0 11-0280/11-0281 (cons.)
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(except for the portion adopted by witness Phillip M. Hayes), NS-PGL Ex. 24.0 (same), NS-PGL Ex. 41.0); Noreen E. Cleary, Assistant Vice President, Total Compensation, Integrys Energy Group, Inc. (NS Ex. 9.0, PGL Ex. 9.0, NS-PGL Ex. 25.0, NS-PGL Ex. 43.0); John P. Stabile, Tax Director, Integrys Business Support, LLC NS Ex. 10.0, PGL Ex. 10.0, NS-PGL Ex. 26.0, NS-PGL Ex. 44.0); Christine Phillips, Manager, Benefits Accounting, Integrys Business Support, LLC (NS Ex. 11.0, PGL Ex. 11.0, NS PGL Ex. 27.0); Valerie H. Grace, Manager, Gas Regulatory Services, Integrys Business Support. LLC (NS Ex. 12.0, PGL Ex. 12.0 REV, NS-PGL Ex. 28.0, NS-PGL Ex. 45.0), Joylyn C. Hoffman-Malueg, Rate Case Consultant, Regulatory Affairs, Integrys Business Support, LLC (NS Ex. 13.0, PGL Ex. 13.0, NS-PGL Ex. 29.0); Thomas Connery, Supervisor, Gas Supply Trading, Integrys Business Support, LLC (NS Ex. 14.0, PGL Ex. 14.0, NS-PGL Ex. 30.0, NS-PGL Ex. 46.0); John McKendry, Senior Leader, Gas Transportation Services, Integrys Business Support, LLC (NS Ex. 15.0, PGL Ex. 15.0, NS-PGL Ex. 31.0, NS-PGL Ex. 47.0); Thomas L. Puracchio, Manager, Gas Storage, Integrys Business Support, LLC (PGL Ex. 16.0, NS-PGL Ex. 33.0 REV), Phillip M. Hayes, Director, Project Management, Integrys Business Support, LLC (PGL Ex. 8.0 (portion), NS-PGL Ex. 24.0 (portion), NS-PGL Ex. 42.0).
The following witnesses testified on behalf of Staff: Daniel Kahle, Accountant, Accounting Department Financial Analysis Division, Illinois Commerce Commission (Ex. 1.0, Ex. 10.0); Mike Ostrander, Accountant, Accounting Department, Financial Analysis Division, Illinois Commerce Commission (Ex. 2.0, Ex. 11.0 Corr., Ex. 20.0); Theresa Ebrey, Accountant, Accounting Department, Financial Analysis Division, Illinois Commerce Commission (Ex. 3.0, Ex. 12.0 Corr.), Sheena Kight-Garlisch, Senior Financial Analyst, Finance Department, Illinois Commerce Commission (Ex. 4.0, Ex. 13.0 Corr.); Michael McNally, Senior Financial Analyst, Finance Department, Financial Analysis Division, Illinois Commerce Commission (Ex. 5.0 Corr., Ex. 14.0 Corr.), David Brightwell, Economic Analyst, Policy Program, Energy Division, Illinois Commerce Commission (Ex. 6.0, Ex. 15.0); Cheri L. Harden, Rates Department, Financial Analysis Division, Illinois Commerce Commission (Ex. 7.0, Ex. 16.0), Brett Seagle, Engineering Department, Energy Division, Illinois Commerce Commission (Ex. 8.0, Ex. 17.0), David Sackett, Economic Analyst, Policy Program, Energy Division, Illinois Commerce Commission (Ex. 9.0, Ex. 18.0); David Rearden, Policy Program, Energy Division, Illinois Commerce Commission (Ex. 19.0).
GCI’s witnesses were: Lafeyette Morgan, Consultant, Exeter Associates, Inc. (GCI Ex. 1.0 Corr., GCI Ex. 6.0); David J. Effron, Consultant (GCI Ex. 2.0 Corr., GCI Ex. 7.0); Scott Rubin, Consultant (GCI Ex. 3.0, GCI Ex. 8.0); David E. Dismukes, Consulting Economist, Acadian Consulting Group (GCI Ex. 4.0, GCI Ex. 9.0); Christopher C. Thomas, Director of Policy, Citizens Utility Board (GCI Ex. 5.0, GCI Ex. 10.0).
Interstate Gas Supply of Illinois’ witness was: Vincent A. Parisi, General Counsel, Interstate Gas Supply of Illinois, Inc. (IGS Ex. 1.0, IGS Ex. 2.0).
Illinois Industrial Energy Consumers and Constellation NewEnergy’s witness was: Michael P. Gorman, Managing Principal, Brubaker & Associates, Inc. (IIEC-CNE Ex. 1.0, IIEC-CNE Ex. 2.0).11-0280/11-0281 (cons.)
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Constellation NewEnergy-Gas Division’s witness was: Jason R. Kawczynski, Associate of Volume Management, Constellation NewEnergy-Gas Division, LLC (CNE Ex. 1.0, CNE Ex. 2.0).
The above references to testimony are intended to include the attachments thereto, whether given separate exhibit numbers or not.
All parties were given the opportunity to cross-examine witnesses. On October 24, 2011, the ALJs marked the record “Heard and Taken”.
During the course of the proceeding, Staff proposed various adjustments and changes to the Companies’ February 15, 2011 request. The Companies accepted certain of Staff’s modifications and Staff withdrew others. A summary of Staff’s final recommendations to the Commission in this proceeding for North Shore and Peoples Gas were attached to Staff’s Initial Brief as Appendix A and Appendix B. Also, attached as part of Appendix A and Appendix B were Staff’s revised Revenue Requirements.
A status hearing was held April 11, 2011, where the ALJs granted Staff’s motion to consolidate these Dockets.
Rulings on Motions
On April 11, 2011, the ALJs granted Utilities’ motion to remove the confidential and confidential and proprietary designations from the direct testimony of Utility witness Schott, the actuarial report submitted pursuant to Part 285.305(g), and Attachment B to Part 285.315(c).
On May 5, 2011, the ALJs issued an Order for Case Management Plan and Schedule in these dockets. On the same date, after considering all of the parties’ arguments, the ALJs entered a Protective Order for these dockets.
On August 25, 2011, the ALJs denied the Utilities’ motion to strike portions of Staff Exhibit 14.0 and Schedules 14.1 through 14.4.
On August 29, 2011, the ALJs granted Staff’s motion for leave to file supplemental rebuttal testimony of Staff witness Ostrander. On the same date, the ALJs denied the Utilities’ renewed motion to strike portions of Staff Exhibit 14.0 and Schedules 14.1 through 14.4.
On October 4, 2011, the ALJs denied the Utilities’ Verified Motion to Preserve the Confidential Designations of Certain Documents (Revised).
On September 22, 2011, the Utilities, Staff, the AG, City-CUB, IES, IGS, and IIEC CNE each filed Initial Briefs (“Init. Br.”). On September 27, 2011, per direction of the ALJs, the Utilities submitted a draft Proposed Order and Staff and intervenors submitted draft position statements. On October 6, 2011, the Utilities, Staff and intervenors each filed Reply Briefs (“Rep. Br.”). On November, 3, 2011, the ALJs issued their Proposed Order.
Post-Hearing Briefs
On November 17, 2011, Briefs on Exceptions (“BOE”) were filed by the Utilities, Staff, the AG, City-CUB, IGS, and IIEC CNE. On November 30, 2011, Reply Briefs on Exceptions (“RBOE”) were filed by the Utilities, Staff, the AG, City-CUB, IGS, and IIEC CNE. On November 17, 2011 the Utilities requested Oral Argument pursuant to Section 11-0280/11-0281 (cons.)
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9–201 of the Act and 83 Ill. Adm. Code Section 200.190. Oral Argument was heard on December 13, 2011.
This Order considers all of the positions and arguments set out in the exceptions briefs and reply briefs on exceptions listed above.
II. Test Year
The Utilities proposed forecasted calendar year 2012, the twelve months ending December 31, 2012, as their test year. NS Ex. 6.0 at 4-5; PGL Ex. 6.0 at 4-5. The 2012 test year data were based on the Utilities’ forecasted 2012 revenues, expenses, and rate bases, subject to appropriate adjustments. NS Ex. 6.0 at 4-5; 6; NS Ex. 5.0 at 4-5; PGL Ex. 6.0 at 4; 6; PGL Ex. 5.0 at 4-5. The proposed test year is uncontested. The Commission approves the test year as reasonable.
III. Revenue Requirement
Under long established federal and Illinois constitutional law, and Illinois ratemaking law, a utility’s rates must be set so as to allow it the opportunity to obtain full recovery of its prudent and reasonable costs of service, including its costs of capital. The legal standards governing a utility’s right to a fair and reasonable rate of return, in particular, are well established and familiar. A public utility has a constitutional right to a return that is “reasonably sufficient to assure confidence in the financial soundness of the utility and [is] adequate, under efficient and economical management, to maintain and support its credit and enable it to raise the money necessary for the proper discharge of its public duties.” Bluefield, 262 U.S. at 693. The authorized return on equity “should be commensurate with returns on investments in other enterprises having corresponding risks. That return, moreover, should be sufficient to assure confidence in the financial integrity of the enterprise, so as to maintain its credit and to attract capital.” Hope, 320 U.S. at 603. The Commission “fully embraces the principles set forth” in the Bluefield and Hope cases. In re Consumers Ill. Water Co., ICC Docket No. 03 0403 (Order April 13, 2004), p. 41. Allowing a utility the opportunity to recover fully its costs of service, including its costs of capital, is in the long-term interests of customers, because this is necessary in order for the utility to be able to provide adequate, safe, and reliable service over time at the least long term cost. PGL Ex. 1.0 at 3; NS Ex. 1.0 at 3.
The Commission, in a rate case, is required to set just and reasonable rates. 220 ILCS 5/9 201(c). The rates must be just and reasonable to the utility and its stockholders as well as customers. Bus. and Prof. People for the Pub. Interest v. Illinois Commerce Comm’n, 146 Ill. 2d 175, 208, 585 N.E.2d 1032, 1045 (1991) (“BPI II”).
The formula for determining a utility’s costs of service -- its revenue requirement is well established and uncontested. RR = OE + (ROR x RB). A utility’s revenue requirement (“RR”) equals: (1) its operating expenses (“OE”) plus (2) a reasonable rate of return (“ROR”) on its rate base (“RB”). ComEd, 322 Ill. App. 3d at 849, 751 N.E.2d at 199.11-0280/11-0281 (cons.)
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A. North Shore
1. Utilities
North Shore’s asserts that its existing rates fall short of allowing it to recover fully its costs of service. North Shore’s direct case supported a base rate revenue requirement of $83,313,000, which meant that its cost recovery shortfall (its revenue deficiency) under existing rates in the 2012 test year would be $8,594,000. NS Ex. 6.0 at 6; NS Ex. 6.1 at Sched. C-1, line 5.
Consistent with the revenue requirement formula discussed above, North Shore’s base rate revenue requirement is the sum of (1) its base rate operating expenses plus (2) its operating income requirement. NS Ex. 6.1 at Sched. C 1, lines 5, 33, 34. The operating income requirement number is the product of multiplying the utility’s rate base by its cost of capital. NS Ex. 6.1 at Sched. A-2, lines 1-7, and Sched. C 1, line 33. The revenue requirement figure does not include the Cost of Gas recovered under Rider 2 or any costs recovered under Riders 11, EEP, UEA, VBA, or FCA. NS Ex. 6.0 at 2.
The drivers of the cost under-recovery were discussed in direct and rebuttal testimony. NS Ex. 1.0 at 9-11; NS-PGL Ex. 17.0 at 11-12; NS Ex. 5.0 at 11-13. The evidence supporting North Shore’s rate base, operating expenses, and rate of return is discussed in Sections IV, V, and VI, infra, respectively.
2. Staff
Staff recommends a revenue requirement of $77,255,000 as reflected on page 1 of Appendix A to Staff’s Initial Brief. Staff recommends an increase to base rates of $394,000 (0.52%) and an increase of $134,000 (8.61%) to other revenues for a total increase of $528,000 (0.69%). Staff’s overall recommended increase is $7,819,000 less than the $8,347,000 increase requested by the Company in surrebuttal.
3. North Shore’s Response
North Shore’s rebuttal testimony supported a revised base rate revenue requirement of $83,579,000, with a reduced cost recovery shortfall under current rates of $8,409,000. The revisions reflected that North Shore, in its rebuttal, agreed with or accepted in order to narrow the issues, in whole or in part, a number of Staff’s and GCI’s proposed adjustments, and updated certain items, including, among others, a reduced proposed ROR reflecting a reduced proposed ROE.
Finally, North Shore’s surrebuttal testimony supported a revised base rate revenue requirement of $83,384,000, with a further reduced cost recovery shortfall under current rates of $8,214,000 (the figures including rider and other revenues other than PGA and coal tar revenues are $85,074,000 and $8,347,000, respectively). The additional reductions reflected that North Shore, in its surrebuttal, again agreed with or accepted, in whole or in part, certain Staff proposed adjustments and updated certain items, among them a reduced proposed ROR reflecting a reduced proposed ROE. 11-0280/11-0281 (cons.)
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4. Commission Analysis and Conclusion
The Commission approves a revenue requirement of $ 78,659,000, representing a 2.52% increase totaling $1,932,000 for North Shore.
B. Peoples Gas
1. Utilities
Peoples Gas’ alleges that its existing rates fall far short of allowing it to recover its costs of service. Peoples Gas’ direct case supported a base rate revenue requirement of $613,779,000, which meant that its cost recovery shortfall under existing rates as of the 2012 test year would be $123,652,000. PGL Ex. 6.0 at 6; PGL Ex. 6.1 at Sched. C-1, line 5.
Consistent with the revenue requirement formula discussed above, Peoples Gas’ base rate revenue requirement is the sum of (1) its base rate operating expenses plus (2) its operating income requirement. PGL Ex. 6.1 at Sched. C 1, lines 5, 33, 34. The operating income requirement number is simply the product of multiplying the utility’s rate base by its cost of capital. PGL Ex. 6.1 at Sched. A-2, lines 1-7, and Sched. C 1, line 33. The revenue requirement figure does not include the Cost of Gas recovered under Rider 2 or any costs recovered under Riders 11, EEP, UEA, VBA, or Rider ICR. PGL Ex. 6.0 at 2.
The drivers of the cost under recovery were discussed in direct and rebuttal testimony. PGL Ex. 1.0 at 9-12; NS-PGL Ex. 17.0 at 10-11; PGL Ex. 5.0 at 11 14. The evidence supporting Peoples Gas’ rate base, operating expenses, and rate of return is discussed in Sections IV, V, and VI, infra, respectively.
2. Staff
Staff recommends a revenue requirement of $555,180,000 as reflected on page 1 of Appendix B to Staff’s Initial Brief. Staff recommends an increase to base rates of $46,113,000 (9.41%) and an increase of $1,688,000 (9.78%) to other revenues for a total increase of $47,801,000 (9.42 %). Staff’s overall recommended increase is $64,809,000 less than the $112,610,000 increase requested by the Company in surrebuttal.
3. Peoples Gas Response
Peoples Gas’ rebuttal testimony supported a lower base rate revenue requirement of $601,734,000, meaning its test year cost recovery shortfall under current rates would be decreased to $111,607,000. NS PGL Ex. Ex.22.1P 2 Corr. at Sched. C-1, line 5. The decreases reflected that Peoples Gas, in its rebuttal, agreed with or accepted in order to narrow the issues, in whole or in part, a number of Staff’s and GCI’s proposed adjustments, and updated certain items, including , among others, a reduced proposed ROR reflecting a reduced proposed ROE. NS-PGL Ex. 22.0 2 Corr. at 2, 4-5; NS PGL Ex. 22.2P Corr. at Sched. C-2; NS PGL Ex. 18.1P.
Finally, Peoples Gas’ surrebuttal testimony supported a further reduced base rate revenue requirement of $601,055,000, meaning its test year cost recovery shortfall under current rates would be decreased to $110,928,000 (the figures including rider and other revenues other than PGA and coal tar revenues are $619,989,000 and 11-0280/11-0281 (cons.)
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$112,610,000, respectively). The additional reductions reflected that Peoples Gas, in its surrebuttal, again agreed with or accepted, in whole or in part, certain Staff proposed adjustments and updated certain items. NS PGL Ex. 39.0 Corr. at 2, 3, 4; NS-PGL Ex. 39.2P Corr. at Sched. C 2.
4. Commission Analysis and Conclusion
The Commission approves a revenue requirement of $565,192,000 representing a 11.39% increase totaling $57,813,000for Peoples Gas.
IV. Rate Base
A. Overview
1. North Shore
In its direct case, North Shore proposed a rate base of $186,897,000, including $422,385,000 of Gross Utility Plant, less $180,540,000 of Accumulated Provision for Depreciation and Amortization (commonly referred to as the “Depreciation Reserve”), and various other additions and subtractions. NS Ex. 7.0 at 4; NS Ex. 7.1 at Sched. B 1.
In its rebuttal case, North Shore proposed a rate base of $192,783,000, reflecting adjustments proposed by Staff and intervenors that the utility agreed with or accepted in whole or in part and certain updates. NS-PGL Ex. 23.0 Corr. at 23-24; NS-PGL Ex. 23.1N Corr. (Sched. B-1); NS-PGL Ex. 23.2N Corr. (Sched. B-2).
In its surrrebuttal case, North Shore proposed a rate base of $192,562,000, reflecting adjustments proposed by Staff and intervenors that the utility agreed with or accepted in whole or in part and certain updates. NS-PGL Ex. 40.0 Corr. at 15; NS PGL Ex. 40.1N (Sched. B-1); NS PGL Ex. 40.2N (Sched. B-2).
2. Peoples Gas
In its direct case, Peoples Gas proposed a rate base of $1,415,543,000, including $2,844,667,000 of Gross Utility Plant, less $1,182,971,000 for the Depreciation Reserve, and various other additions and subtractions. Dir., PGL Ex. 7.0 at 4; PGL Ex. 7.1 at Sched. B 1.
In its rebuttal case, Peoples Gas proposed a rate base of $1,452,914,000, reflecting adjustments proposed by Staff and intervenors that the utility accepted in whole or in part and certain updates. NS-PGL 23.0 Corr. at 23-24; NS-PGL Ex. 23.1P Corr. (Sched. B-1); NS-PGL Ex. 23.2P Corr. (Sched. B-2).
In its surrebuttal case, Peoples Gas proposed a rate base of $1,472,853,000, reflecting adjustments proposed by Staff and intervenors that the utility accepted in whole or in part, and certain updates. NS PGL, 40.0 Corr. at 14-15; NS-PGL Ex. 40.1P Corr. (Sched. B-1); NS PGL Ex. 40.2P Corr. (Sched. B-2).11-0280/11-0281 (cons.)
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B. Uncontested Issues
1. Natural Gas Prices – Working Capital Allowance – Gas in Storage
The Utilities, Staff, and GCI agree to the Utilities’ proposed reductions to the Gas in Storage valuations in rate base in order to reflect an updated gas price. NS-PGL Ex. 23.0 Corr. at 7-8; Staff Ex. 17.0 at 9-10; GCI Ex. 6.0 at 2-3. Therefore, the Commission approves the Utilities’ proposed reductions to the Gas in Storage valuations in rate base in order to reflect an updated gas price.
2. Plant
a) Specific Plant Investments – Warehouse at Manlove Field
The Utilities and Staff agreed upon the inclusion of the costs of the following projects in rate base: (1) the costs associated with the Pigging and Well-Head Separator Project #1, (2) the costs associated with the Pigging and Well-Head Separator Project #2, (3) the costs associated with the construction of a new warehouse at Manlove Field, and, (4) the costs associated with the Pipeline Heaters Replacement Project. Staff Ex. 17.0 at 5, 11, 12, 13. These are not contested. Therefore, the Commission approves the inclusion of the costs of these projects in rate base.
b) Pigging Well-Head Separator Project #1
See Section IV.B.2.a, supra.
c) Pigging Well-Head Separator Project #2
See Section IV.B.2.a, supra.
d) Pipeline Heaters Replacement Project
See Section IV.B.2.a, supra.
3. Accumulated Depreciation Expense on Forecasted Additions and Utility Plant in Service – 2010 Actual
The Utilities and Staff have agreed upon the adjusted depreciation reserve amounts for actual 2010 plant-in-service for both Utilities. NS PGL Exs. 23.4N and 23.4P; Staff Ex. 10.0 at 6. This is not contested. Therefore, the Commission approves the adjusted depreciation reserve amounts for actual 2010 plant-in-service for both Utilities.
4. Accumulated Deferred Income Taxes
a) Bonus Depreciation, Illinois State Income Taxes and Tax Accounting Method Changes
Regarding Accumulated Deferred Income Taxes (“ADIT”), the Utilities and Staff have agreed to adjustments which account for the new State income tax rate and tax accounting method changes, as they relate to bonus depreciation, for both Utilities. NS PGL Exs. 23.4N and 23.4P; Staff Ex. 10.0 at 6. This is uncontested. Therefore, the Commission approves these adjustments for both Utilities.11-0280/11-0281 (cons.)
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b) Use of Average Rate Assumption Method Relating to Health Care Reform Legislation
In his direct testimony, Utilities witness Stabile testified that the Utilities propose to remeasure deferred tax balances caused by the enactment of the Health Care Reform Legislation using the average rate assumption method. NS Ex. 10.0 at 2 6; PGL Ex. 10.0 at 2-6. This proposal is uncontested. Therefore, the Commission approves the Utilities’ proposed methodology to remeasure deferred tax balances caused by the enactment of the Health Care Reform Legislation.
c) Net Operating Loss – Tax Normalization
The Utilities proposed to calculate their Net Operating Loss (“NOL”) at present rates to offset deferred tax liabilities and avoid a normalization violation. A further calculation is needed to reflect NOL normalization based on revenue changes in the final Order. NS-PGL Ex. 23.0 at 6; NS-PGL Ex. 26.0 at 26; NS-PGL Ex. 40.0 at 13-15. This is uncontested. Therefore, the Commission approves the Utilities’ proposal.
C. Contested Issues
1. Plant (all subjects relate to NS and PGL unless otherwise noted)
a) Forecasted Test Year Capital Additions
(1) Utility Plant in Service
(a) Utilities
North Shore and Peoples Gas presented evidence supporting their Utility Plant in Service in rate base, as referenced in Section IV.A.1, supra. The Utilities do not object to Staff’s adjustment to reduce the Utilities’ forecasted additions to plant-in-service for the years ending December 31, 2011, and December 31, 2012, as corrected by Utilities witness Hengtgen’s surrebuttal testimony. Staff Ex. 1.0 at 15-16; NS-PGL Ex. 40.0 Corr. at 3-4. They maintain that GCI’s proposed adjustment to 2011 and 2012 Accelerated Main Replacement Program (“AMRP”) additions is without merit, as discussed in Section IV.C.1.a.ii, infra.
(b) Staff
Staff maintains that the Companies updated their forecasted plant additions in their rebuttal testimony. Staff used the Companies’ updated figures in computing its proposed adjustment in rebuttal testimony, and does not see the necessity for a separate adjustment.
(c) AG
The AG argues that under Section 9-211 of the Public Utilities Act, only utility plant that is used and useful shall be incorporated into customer rates. 220 ILCS 5/9-211. The burden of proof is on the Companies to demonstrate that forecasted levels of plant in service are supported by actual circumstances, and that plant additions sought to be included in rate base will actually be made. 11-0280/11-0281 (cons.)
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The AG maintains that the gross utility plant included in rate base is the forecasted average plant balance in 2012, the test year in this case. The Companies began with the actual balances of plant as of June 30, 2010 and then adjusted those balances for forecasted additions to and retirements from plant for the last six months of 2010 and calendar years 2011 and 2012. On Rebuttal, as explained by NS-PGL witness Doerk, PGL and North Shore increased the forecasted capital expenses in 2011 and 2012 from the amounts in the original rate case filing.
Referring to PGL Schedule B-5, the AG argues that it can be seen that the PGL forecasted additions to distribution plant in service in 2011 and 2012 are substantially greater than the additions in 2009 or 2010. That is, the actual additions to distribution plant in service were $56.8 million and $54.5 million in 2009 and 2010, respectively (response to PGL AG 1.02), while in 2011 the forecasted additions to PGL distribution plant are $144.9 million, and in 2012 the forecasted additions to PGL distribution plant are $155.8 million. As explained in PGL Exhibit 8.0, pages 9-13, the main reason for the expected increase in distribution plant additions is PGL’s AMRP. The capital spending on AMRP is projected to be $124.3 million in 2011 and $140.4 million in 2012 (response to PGL AG 1.02). GCI Ex. 2.0 at 4.
The AG argues that based on PGL’s response to AG data request 4.19, the actual spending on the accelerated main replacement program in 2011 through May was $12.1 million. In the original response to Staff Data Request PGL DGK 3.05, PGL attributed the difference between budgeted and actual plant additions through April 2011 to a delay in the commencement of the accelerated cast iron replacement program from January to March. However, in the May update of the response to Staff Data Request PGL DGK 3.05, the actual plant additions continued to run substantially below the forecasted level of additions, even after the commencement of the program. The plant additions related to the accelerated main replacement program are running below forecast in 2011 both because the program began in March rather than January and because once the program began the actual plant additions were less than forecasted. GCI Ex. 2.0 at 5.
The AG points out that after reviewing updated plant investment information supplied by the Company, GCI witness David Effron testified that information in the response to PGL AG 6.01 shows that the cumulative actual spending on the AMRP in 2011 through the end of June was $24.7 million. The response to PGL AG 6.02 shows that the cumulative amount of budgeted spending on the AMRP in 2011 through the end of June is $62.0 million. Thus, through the end of June 2011, PGL had spent $37.3 million less than the amount reflected in its 2011 budget. GCI Ex. 7.0 at 2.
According to the AG, based on this plant investment experience to date, PGL’s test year level of plant in service should be modified. GCI witness Effron proposes the following adjustments: First, at a minimum, the test year rate base should be adjusted to recognize the actual under-spending experienced on accelerated main replacements through the end of June 2011 for PGL. This adjustment reduces the 2011 AMRP plant included in the test year rate base by $37,324,000. Mr. Effron stated that this is a relatively conservative quantification of the appropriate adjustment to 2011 AMRP plant additions because it implicitly assumes that the actual plant additions for the second half 11-0280/11-0281 (cons.)
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of the year will be on budget, even though that has clearly not been the case in the first six months of the year. Id. at 3.
Given the Company’s performance in 2011, Mr. Effron testified that it would also be reasonable to reflect the same reduction to the forecasted additions for 2012. In this regard, reduction of the 2012 forecast by $37,324,000 would be a conservative adjustment. This proposed adjustment does not extrapolate the Company’s actual under-spending over the six month period in 2011 to the full year. It simply recognizes the amount under spent in 2011. Further, this proposed adjustment also recognizes a level of AMRP plant additions in 2012 that is $16.1 million higher than the adjusted level of plant additions in 2011. The AG states, accordingly, a reduction of $37,324,000 to the forecasted 2012 AMRP plant additions should be reflected, as shown on GCI Ex. 7.2, Schedule DJE-1.1.
The effect of these adjustments to the forecasted 2011 and 2012 AMRP capital expenditures can be seen on GCI Ex. 7.2, Schedule DJE-1.1, and result in a reduction of $55,985,000 to PGL test year plant in service. The 2012 test year depreciation expense is reduced by $1,931,000 and the average balance of accumulated depreciation in 2012 is lower by $1,610,000. The net reduction to the 2012 test year rate base is $54,376,000. GCI Ex. 7.0 at 3-4.
Other adjustments to plant in service separate and apart from the AMRP plant adjustments are also appropriate, in light of the most recent Utilities data available. That data shows that both companies’ updates to forecasted level of test year plant are significantly overstated. As noted above, as explained in the Rebuttal phase of the docket by Utilities witness Doerk, PGL and North Shore increased the forecasted capital expenses in 2011 and 2012 from the amounts in the original rate case filing. NS-PGL Ex. 24.0 at 7. Specifically, Mr. Doerk testified that PGL would increase capital expenditures by $10.3 million in 2011 and $56.8 million in 2012. NS-PGL Ex. 24.0 at 7. For North Shore, the increase in capital expenditures is $5.0 million for 2011 and $13.2 million for 2012. Id.
Budget Update
The AG pointed out that these updates were not supported by the Companies’ own data and are inappropriate. For example, in 2011 through June, North Shore’s actual plant additions were $1.4 million, or 25%, below the original budget (response to Staff Data Request NS DGK 3.5, June Update, Confidential), and Peoples Gas’s actual plant additions were $32.9 million, or 41%, below the original budget (response to Staff Data Request PGL DGK 3.5, June Update, Confidential). GCI Ex. 7.0 at 8. It would make little sense to adjust the rate bases for increases to the forecasted level of plant additions when the Companies aren’t even keeping up with the original forecasts of plant additions. The effect of eliminating the increases to the original forecasts of plant additions is to reduce the North Shore rate base by $11,443,000 (NS Schedule DJE-1) and the Peoples Gas rate base by $38,355,000 (PGL Schedule DJE-1). Id.
For his part, Staff witness Kahle took issue with the Effron-proposed adjustments, asserting that his includes “all of the Companies’ budgeted capital expenditures rather than a single project as does Mr. Effron.” The AG pointed out that this criticism was rendered moot by Mr. Effron’s rebuttal analysis, which relied on total 11-0280/11-0281 (cons.)
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plant in service budgeted and actual numbers. As shown on AG Cross Ex. 11, Mr. Effron relied on the Company’s own update to its total plant in service numbers. The response, the Companies’ update to DGK 3.05, shows that through June of 2011, the PGL additions to plant in service were $32.9 million under budget. Tr. at 256. Mr. Kahle confirmed that those numbers reflected this under-budgeted amount. Tr. at 257. AG Cross Ex. 12, which was North Shore’s update to the same discovery question, showed that North Shore’s level of plant in service as of June, 2011 were $1.4 million under budget, an amount again confirmed by Mr. Kahle. Tr. at 257. Staff’s suggestion, thus, that Mr. Effron’s plant in service adjustment related to a single project is simply wrong.
In sum, the GCI adjustments, eliminating the increases to the original forecasts of plant additions that reduce the North Shore rate base by $11,443,000 (NS Schedule DJE-1) and the Peoples Gas rate base by $38,355,000 (PGL Schedule DJE-1) should be adopted. Id.
(d) Commission Analysis and Conclusion
The Commission finds that North Shore and Peoples Gas presented sufficient evidence supporting their Utility Plant in Service in rate base. They did not object to Staff’s adjustment in which they updated their forecasted plant additions in their rebuttal testimony and Staff did not see the need for a further, separate adjustment. Staff’s proposed adjustment is superior to GCI witness Effron’s proposed adjustment inasmuch as Staff considers the Companies’ total expenditures to planned expenditure over a three-year period as opposed to GCI’s single year analysis. Further, Staff reviewed proposed projects as demonstrated by the direct and rebuttal testimony of Staff witness Seagle. The Commission finds that the Utility Plant in Service as adjusted by Staff is approved.
(2) Capital Additions Related to Accelerated Main Replacement – AMRP (PGL)
(a) Utilities
Peoples Gas argues that GCI witness Effron’s adjustment should be rejected as it is based on a flawed premise that Peoples Gas will not complete the work scheduled for 2011, and thus, this under-spending will carry over into the test year. In surrebuttal testimony, Peoples Gas witness Hayes explained that Peoples Gas initially treated the 2011 AMRP expenditures of $124.3 million as if they would be expended evenly over the course of 2011 and budgeted accordingly. However, these expenditures instead reflected a bell shape curve, with fewer costs being incurred in the early and late months of the year and the peak expenditures being in the middle months, which represent the peak construction months. NS-PGL Ex. 42.0 at 4. The record demonstrates that for 2011, the first year of the 20 year AMRP, Peoples Gas has experienced the normal transition or “learning curve” with the ramp up of activities such as design, permitting, staffing of key positions, construction contract bidding, etc., that have slightly delayed the expenditures so far this year. Id. at 4-5. By the end of May 2011, there has been a ramp-up of the AMRP expenditures which are expected to climb dramatically for the remainder of 2011 and 2012. NS PGL Ex. 24.0 at 6. 11-0280/11-0281 (cons.)
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Peoples Gas maintains that even though fewer costs were expended in the early months of 2011, it fully intends to achieve the forecasted 2011 expenditures for AMRP as is demonstrated by: (1) Peoples Gas has contracted with four installation contractors to install over 180 miles of new mains and over 16,000 services in 2011; and (2) Peoples Gas crews are ramping up to complete over 24,000 meter sets in 2011. Additionally, Peoples Gas states that it has a contingency plan in place should circumstances prevent it from completing this work, which includes the installation of approximately 4 miles of high pressure piping inclusive of the tie-in to the natural gas transmission line along with the necessary valves and regulators. Id. at 5.
Furthermore, Peoples Gas argues that GCI’s argument that any under spending in 2011 will affect 2012 spending is purely speculation and without merit. 2012, the second year of the AMRP, will benefit from the lessons learned from 2011 and Peoples Gas expects a much earlier start for the 2012 construction year. Id. at 5.
Finally, Peoples Gas states that if the Commission determines to approve the GCI adjustment—which Peoples Gas submits it should not—Peoples Gas would have to limit its capital expenditures to what the Commission allows for the 2011-2012 period. Peoples Gas still plans to spend the revised 2011-2012 total amount on AMRP that is reflected (subject to the average rate base method) in its surrebuttal. NS-PGL Ex. 42.0 (entire). However, Peoples Gas cannot do so if that means being denied millions of dollars of recovery of the costs of the AMRP for this period, and instead, in that event, Peoples Gas would have to limit the 2011- 2012 expenditures to what the Commission allows, resulting in delay and higher costs. NS-PGL Ex. 17.0 at 14-15. Based on GCI’s original proposed reduction of $129 million of AMRP costs (gross amount) in 2012 (GCI Ex. 2.0 Corr. at 6), Peoples Gas would lose approximately $11 million per year until the implementation of rates after its next rate case. NS-PGL Ex. 17.0 at 14. The disallowance of these costs from rate base would delay customer benefits, such as safety and reliability, as described by Mr. Hayes. PGL Ex. 8.0 at 12-13.
(b) Staff
Staff notes that GCI witness Effron proposed an adjustment to rate base for the rate of accelerated main replacement being slower than forecasted. Staff did not find fault with Mr. Effron’s proposal, but finds its own analysis to be more appropriate. Staff’s analysis included all of the Companies’ budgeted capital expenditures rather than a single project as Mr. Effron’s does. Staff Ex. 10.0, p. 15. While not individually identified, the accelerated main replacement project would be included in Staff’s overall analysis.
Although Staff would support Mr. Effron’s proposed adjustment, the Companies have accepted Staff’s adjustment. NS-PGL Ex. 40.0 CORR., pp. 3 – 4. Accepting both Staff’s and Mr. Effron’s adjustments could result in double counting. If the Commission were to accept Mr. Effron’s proposed adjustment, all or a portion of Staff’s adjustment to forecasted plant additions should be removed from People Gas’ revenue requirement.
(c) AG
See Section IV.C.1.a.i., supra.11-0280/11-0281 (cons.)
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(d) CUB-City
CUB-City recommended an adjustment to reflect the Utilities’ forecasted plant additions related to the AMRP. GCI Ex. 2.0 at 6. GCI witness Effron stated that actual spending through at least the end of June 2011 was significantly lower than originally budgeted. GCI Ex. 7.0 at 3. Initially, the Company claimed this was due to a delay in the commencement of the AMRP from January to March. GCI Ex. 2.0 at 5. However, Mr. Effron found that the Company’s May and June updates reflected that actual spending continued to lag significantly behind budgeted amounts. Id. at 5; GCI Ex. 7.0 at 2. CUB-City averred that, given the Company’s performance in 2011, it is also reasonable to reflect a similar reduction to the forecasted additions for 2012. Id. at 3. Mr. Effron testified that these are conservative adjustments, based only on the Company’s under-spending for the first six months of 2011, assuming that the actual plant additions for the second half of each year will be on budget even though that has not been the case previously. Id. at 3.
CUB-City acknowledged PGL’s claims that their under-spending is actually attributable to an erroneous, flat-line budget which did not reflect the bell-curve of the Company’s actual anticipated spending. NS-PGL Ex. 42.0 at 4. CUB-City pointed out that the Company never provided any correction to this “erroneous” budget. Sep. 2, 2011 tr. at 791. CUB-City responded to Mr. Hayes’s testimony regarding the bell shape curve about which supposedly reflects peak expenditures in the middle months of the year, which are peak construction months. CUB-City found that testimony, as well as statements that the Company suffered from a “learning curve” early in 2011, unpersuasive, as May and June updates continued to lag so far behind budget.
CUB-City argued that the Company has encountered obstacles in gaining City approval for AMRP work. CUB-City noted that on cross-examination, Mr. Hayes admitted that although Peoples asserts that it has tried to coordinate its AMRP work with the City of Chicago (Sep. 2, 2011 tr. at 793), the City has expressed concerns about its ability to process the numerous permit requests that Peoples Gas must submit to do work in the City’s rights of way. Id. at 794-795. CUB-City also noted Mr. Hayes’s admission that there are problems with work that Peoples Gas proposes to do on streets that the City has recently resurfaced. Id. at 795. Mr. Hayes testified that the City has informed Peoples Gas that it should avoid doing work in streets that “have been recently repaved, resurfaced, or rebuilt.” Id. Such streets are subject to a five-year moratorium. Id. at 795-796. CUB-City pointed to Mr. Hayes’s statement that there is overlap between some of the AMRP work that Peoples Gas plans to do and streets that are subject to the City’s moratorium on work being conducted in streets that have recently undergone improvements. Id. at 796.
CUB-City argued that the Company has failed to make investments consistent with its budgeted amounts, and it is not likely that it will do so now. Nor has the Company updated its budget. In addition, CUB-City noted, the Company has encountered several obstacles in its efforts to secure the requisite permits to do the work it claims it will do in Chicago during 2011 and 2012. For these reasons, CUB-City urge the Commission to find that spending will continue below forecasted levels and to adjust the Company’s plant accordingly. If it happens that the Company does spend more than the Commission allows on AMRP, CUB-City state the revenue requirement 11-0280/11-0281 (cons.)
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effect of the incremental plant can be recovered through PGL Rider ICR. GCI Ex. 2.0 at 6:120-23. Given the uncertainty of the level of future expenditures on the AMRP at this time, CUB-City recommend that the Commission should reduce the Company’s forecast of future plant additions by $37,324,000, with any increment to be recovered through the rider. Id. at 6:130-33.
(e) Commission Analysis and Conclusion
The Commission finds that Staff’s analysis, which included all of the Companies’ budgeted capital expenditures rather than a single project, is more appropriate than Mr. Effron’s proposed adjustment. The Companies have, in fact, accepted Staff’s adjustment. Staff notes that it did not find fault with Mr. Effron’s proposal, but realizes that accepting both Staff’s and Mr. Effron’s adjustments could result in double counting. A calculation of the overlap between Staff’s and Mr. Effron’s adjustments was also not offered. The Commission finds Staff’s adjustment, which included a comparison of total expenditures to planned expenditures over a three year period, more satisfactory.
b) Capitalized Incentive Compensation
(1) Utilities
See Section V.C.1., infra.
(2) Staff
See also Section V.C.1., infra.
c) Non-Union Wages
(1) Utilities
See Section V.C.2., infra.
(2) Staff
See also Section V.C.2., infra.
d) Original Cost Determination as to Plant Balances as of December 31, 2009
(1) Utilities
The Utilities argue that the Commission should approve the $411,643,000 original cost of plant for North Shore at December 31, 2009 and the $2,667,949,000 original cost of plant for Peoples Gas at December 31, 2009, as reflected on each utility’s Schedule B-5, Page 1 of 2, as the original costs of plant. NS Ex. 7.0 at 15-16; PGL Ex. 7.0 at 17-18; NS-PGL Ex. 23.0 Corr. at 24-25; NS-PGL 40.0 Corr. at 12.
According to the Utilities, Staff’s proposed adjustment to the original cost finding is inappropriate because incentive compensation is a contested issue in this proceeding and an issue on appeal for both the 2007 and 2009 Utilities rate cases. If the Utilities were to prevail on appeal, the Commission would have inappropriately reduced their original cost of plant. NS PGL Ex. 23.0 Corr. at 24-25.11-0280/11-0281 (cons.)
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The Utilities maintain that if, however, the Commission decides to accept Staff’s adjustments to the original cost determination, then the Commission’s final Order should specify that if a decision in the Appellate Court or another court or a Commission decision on remand or in any other proceeding results in the plant in question being approved, then the original cost amounts should be restored to their full amounts of $2,667,949,000 original cost of plant for Peoples Gas and $411,643,000 original cost of plant for North Shore.
In the Utilities’ Reply Brief they note that the Appellate Court in Madigan v. Illinois Commerce Comm’n., Case Nos. 1-10-0654, 1-10-0655, 1-10-0936, 1-10-1790, 1-10-1846, and 1-10-1852 (slip op. of September 30, 2011, (“Madigan”) has recently denied the Utilities’ appeal in regards to the issue of concern here and that in the interests of narrowing the issues, the Utilities are willing to accept Staff’s reduced figures, if the Commission’s Order further provides that this is without prejudice to the Utilities’ seeking approval of higher figures in the event of a decision by the Supreme Court of Illinois or the Appellate Court that reverses in whole or in part the past capitalized incentive compensation disallowances. Absent such a proviso, the Utilities, in the alternative, recommend that their figures be approved.
(2) Staff
Staff argues that the Commission should approve $411,521,000 and $2,667,300,000 as the original cost determination of plant-in-service for North Shore and Peoples Gas, respectively, as of December 31, 2009. The original costs recommended by Staff are less than the Companies’ proposed original costs because Staff does not include costs previously disallowed by the Commission. The Commission has disallowed capitalized incentive costs in Docket Nos. 07-241/0242 and 09-0166/0167 (“Peoples 2007” and “Peoples 2009”). The Companies argue that the disallowed costs should be included in original costs because the disallowed costs are contested issues on appeal for both the 2007 and 2009 rate cases. However, this would have the Commission contradict its own findings. Under the PUA the pendency of an appeal does not of itself stay or suspend a decision of the Commission. 220 ILCS 5/10-204. Therefore, the Commission should adjust original costs in accordance with its orders in those previous dockets. Staff Ex. 1.0 and 10.0, pp. 19 – 20.
Staff notes on page 6 of its Reply Brief that it has come to its attention that its proposed reductions to original costs (Staff Ex. 1.0 and 10.0, pp. 19 – 20) include adjustments from Peoples 2009 which applied to those proceedings 2010 test year. Staff states that since the original costs in the instant proceeding are as of December 31, 2009, it would not be appropriate at this time to make a reduction to the December 31, 2009 balance for adjustments that pertain to a subsequent period. As a result, for North Shore, the Company’s proposed original cost of $411,643,000 (NS Ex. 7.0, p. 2) should be reduced by $27,000. For Peoples Gas, the Company’s proposed original cost of $2,667,949,000 (PGL Ex. 7.0, p 2) should be reduced by $166,000.
(3) Commission Analysis and Conclusion
The Commission finds without prejudice that the Utilities have accepted Staff’s reduced figures. 11-0280/11-0281 (cons.)
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2. Materials and Supplies – Computation of Associated Accounts Payable
a) Utilities
The Utilities’ direct case included in rate base Materials and Supplies offset by the related Accounts Payable. NS. Ex. 7.0 at 7; PGL Ex. 7.0 at 7.
The Utilities did not contest GCI witness Morgan’s methodology to compute accounts payable associated with Materials and Supplies, which is a two-year composite percentage of the monthly debits to materials and supplies accounts that is applied to the test year, as corrected by Utilities witness Hengtgen. NS-PGL Ex. 23.0 Corr. at 11-12; GCI Ex. 6.0 at 2. The Utilities argue that Staff’s methodology for computing improperly uses a lead time in days from the Cash Working Capital (“CWC”) lead-lag study to calculate what Staff refers to as “reasonable level of costs that would be included in Accounts Payable.” Staff Ex. 3.0 at 27.
The Utilities maintain that the CWC lead-lag study is prepared to determine the level of cash working capital a utility requires to finance its day to day operations. The CWC requirement is included in a utility’s rate base. NS Ex. 7.0 at 16-17; PGL Ex. 7.0 at 18-19. The CWC requirement does not affect any other rate base component. A lead-lag study measures the amount of time in days that on average it takes a utility to pay for its other operation and maintenance expenses, such as Material and Supplies. Thus, according to the Utilities, the lead-lag study only applies to expenses and not the portion of the purchases that are included in material and supplies and already are a component of rate base. However, the accounts payable offset is intended to measure the amount of materials and supplies, a rate base item, at month end for which payment has not yet been made.
The Utilities assert that as a result, Staff’s calculation computes an amount of accounts payable by utilizing a time period in days. They maintain that the two are not related and a time period is not an appropriate measure to reflect an amount of accounts payable at month end. NS-PGL Ex. 23.0 Corr. at 12.
b) Staff
Staff argues that the Commission should accept its adjustment to reflect a more reasonable amount for the accounts payable for materials and supplies inventory. Staff maintains that its adjustment is more reasonable because it is based on actual purchases and takes into account the results of the Companies’ lead/lag studies. Staff Ex. 3.0, Corrected, p. 27.
The Companies in their rebuttal testimony accepted an adjustment proposed by GCI witness Morgan, albeit with minor calculation corrections. NS-PGL Ex. 23.0, p. 11. Staff believes that while GCI witness Morgan’s adjustment is an improvement over the Companies’ proposal, Staff’s adjustment more accurately reflects the accounts payable balance for material and supplies inventory.
According to Staff, Mr. Morgan’s proposal uses the amount of purchases each month as a proxy for accounts payable balances which he then averages over 13 months; this proposal assumes that payment is made in 30 days. However his assumption regarding 30 days for repayment is flawed. The evidence indicates that 11-0280/11-0281 (cons.)
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payment is made in 42.44 days and 46.62 days for NS and PGL, respectively (Staff Ex. 12.0 Corrected, p. 19) not 30 days. Staff’s adjustment is based on the 42.44 days and 46.62 days supported by the record and should be approved. If the Commission does not accept Staff’s proposed adjustment, then it should consider Mr. Morgan’s adjustment as an alternative, since it is an improvement over the Companies’ proposal.
c) Commission Analysis and Conclusion
The Utilities in their rebuttal testimony accepted GCI witness Mr. Morgan’s adjustment with minor calculation corrections. Staff states that although Mr. Morgan’s adjustment is an improvement over the Utilities’ proposal, Staff’s adjustment more accurately reflects the accounts payable balance for material and supplies inventory. The Commission finds Mr. Morgan’s methodology more appropriately uses a two year composite percentage of the monthly debits or increases to compute accounts payable associated with Materials and Supplies as opposed to Staff’s use of a lead time in days from the CWC lead-lag study is reasonable and should be approved.
3. Gas in Storage – Computation of Associated Accounts Payable
a) Utilities
The Utilities maintain that Gas in Storage is an asset in rate base which the Utilities have offset with related accounts payable based on Commission treatment established in their last two rate cases. NS Ex. 7.0 at 7; PGL Ex. 7.0 at 7. Consistent with the methodology that was approved by the Commission in the Utilities’ 2009 rate case, the Utilities state that they calculated the associated accounts payable offset amount associated as the net increase in the monthly Gas in Storage balance. NS Ex. 7.0 at 12; PGL Ex. 7.0 at 14.
According to the Utilities, Staff’s computation of associated accounts payable is flawed because it does not reflect that the Utilities’ use the Last-In First-Out (“LIFO”) method to account for Gas in Storage Inventory. The LIFO accounting method means that as the Utilities purchase gas to serve customers, the last gas in (purchased) is the first gas out (to customers). Thus, based on the LIFO method, the Utilities do not reflect current year gas purchases in inventory until the beginning of the year volume of gas is restored or replenished back into inventory. In other words, as demand for gas exceeds purchases and gas in inventory is withdrawn, gas is restored to previous LIFO layers before current year purchases are reflected in Gas in Storage Inventory. The Utilities argue that for both Peoples Gas and North Shore, this does not occur in the test year until August. From August to November, an amount for current year purchases is reflected in the end of the month inventory balance. NS-PGL Ex. 23.0 Corr. at 9; NS-PGL Exs. 23.6N and 23.6P. That is consistent with the Utilities’ methodology, whereby the average in the increase in test year monthly balances of Gas in Storage is used as the accounts payable offset. The Utilities maintain that its methodology is conservative in that it begins in April 2012 for both Utilities (NS Ex. 7.1 at p. 2; PGL Ex. 7.1 at p. 2) even though the gas purchases are not projected to be recorded to Gas in Storage until August 2012. 11-0280/11-0281 (cons.)
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However, according to the Utilities, Staff’s methodology calculates accounts payable amounts for all months of the test year except January, 2012. NS-PGL Exs. 23.6N and 23.6P show that for the months January through July and December, the dollar value of gas that comprises the ending balance of Gas in Storage is related to inventory purchased years ago – not the test year. To assign an amount of outstanding accounts payable related to gas that was purchased in years prior to the test year is improper. NS-PGL Ex. 23.0 Corr. at 9.
They argue further that Staff’s reliance on the Ameren Illinois methodology used in its current rate cases, ICC Docket Nos. 11-0279/0281 (cons.), is misplaced because Ameren Illinois uses a different accounting method for Gas in Storage. NS-PGL Ex. 23.0 Corr. at 9-10; NS-PGL Ex. 23.15. Instructive is the methodology used in ICC Docket No. 08 0383, Northern Illinois Gas Company’s (“Nicor”) last rate case. Nicor, which uses the LIFO accounting method for Gas in Storage, proposed a similar methodology as the Utilities have proposed in this proceeding and it was uncontested in Nicor’s rate case. NS-PGL Ex. 23.0 Corr. at 10.; Northern Illinois Gas Co., ICC Docket No. 08-0363 (Order Mar. 25, 2009), p. 16. Noteworthy is that GCI witness Mr. Morgan proposed a similar adjustment as Staff’s regarding associated accounts payable for Gas in Storage. GCI 1.0 Corr. at 10-11. However, upon learning that the Utilities account for Gas in Storage using the LIFO method, Mr. Morgan withdrew his adjustment, stating “Given the Companies’ accounting method, my adjustment would be inappropriate.” GCI Ex. 6.0 at 2; NS-PGL Ex. 23.13.
Finally, the Utilities argue that Staff’s calculation here is also flawed because it is based on the lead-lag study. The lead-lag study is prepared to determine the level of Cash Working Capital a utility requires to finance its day to day operations. The CWC requirement is included in a utility’s rate base. NS Ex. 7.0 at 16-17; PGL Ex. 7.0 at 18-19. The CWC requirement simply does not affect any other rate base component. A lead-lag study measures the amount of time in days that on average it takes a utility to pay for its gas costs expenses. The Utilities conclude that thus the lead-lag study only applies to expenses and not the portion of the purchases that are included in inventory and already are a component of rate base. However, the accounts payable offset is intended to measure the amount of Gas in Storage Inventory, a rate base item, at month end for which payment has not yet been made. As a result, the Utilities argue that Staff’s calculation computes an amount of accounts payable by utilizing a time period in days. The two are not related and a time period is not an appropriate measure to reflect an amount of accounts payable at month end. NS PGL Ex. 23.0 Corr. at 11.
b) Staff
Staff argues that the Commission should accept its adjustment to reflect a more reasonable amount for accounts payable for gas in storage inventory. Staff believes that its method of estimating the level of accounts payable associated with Gas in Storage is more accurate than the Companies’ method because it reflects the actual purchases and payments for gas placed into storage by the Companies. The Companies’ estimates presented on Schedule B-1.1 for each utility reflects amounts for accounts payable only in months in which the inventory balance increases; for those months of declining balances, no amount is included for accounts payable. Company Schedule F-8 clearly shows that injections are made every month of the year, thus 11-0280/11-0281 (cons.)
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accounts payable associated with gas in storage are created every month, not just in those months where the inventory balance reflects a net increase. Staff Ex. 3.0 Corrected, p. 28 and Schedules 3.5N and 3.5P.
The Companies argue that Staff’s adjustment is incorrect because it does not consider that the Companies account for gas in storage by the LIFO method of accounting for inventory. NS-PGL Ex. 23.0, p. 8. In response, Staff indicated that the method of accounting for inventory does not impact the balance recorded as accounts payable. Staff Ex. 12.0 Corrected, pp. 22-23. Staff also provided an explanation of the LIFO method of accounting for inventory and the mechanics of the LIFO Liquidation Credit which results from that accounting method based on the Companies’ discovery responses. Id., pp. 21-22. The Companies did not take issue with Staff’s characterization of that accounting. Due to the Companies’ argument regarding the LIFO method of accounting for inventory, Staff considered using the 12-month average of the LIFO Liquidation Credit as a proxy for the accounts payable, since those amounts are the liabilities recorded on the books of the Utilities that are a direct result of the LIFO method of inventory valuation. However, Staff’s proposals for accounts payable which are based on the actual gas purchases and the delay in payment for those purchases are more accurate representations of the accounts payable associated with gas in storage inventory. Id., p. 23.
Staff argues that the Companies are the only party to take issue with its adjustment in testimony. GCI witness Morgan initially proposed an adjustment to accounts payable associated with gas in storage inventory similar to his proposal for the accounts payable associated with Materials and supplies inventory. Mr. Morgan withdrew his adjustment in rebuttal testimony. GCI Ex. 6.0, p. 2.
c) Commission Analysis and Conclusion
The Commission accepts the Utilities’ methodology for calculating accounts payable associated with Gas in Storage inventory. We find that the Utilities’ use of the LIFO accounting method for Gas in Storage is instructive. Nicor, which also uses the LIFO accounting method for Gas in Storage, proposed a similar methodology that went uncontested in its 2008 rate case. Further, in these dockets GCI witness Morgan who proposed a similar adjustment as Staff’s regarding associated accounts payable for Gas in Storage withdrew his adjustment as inappropriate based upon the Utilities’ use of the LIFO method. The Commission accepts the Utilities’ methodology.
4. Cash Working Capital
Cash working capital is the amount of funds required to finance the day-to-day operations of a utility. The CWC requirement is included in each of the Utilities’ rate bases for ratemaking purposes. NS Ex. 7.0 at 16-17; PGL Ex. 7.0 at 19. To determine the cash working capital requirement, a lead lag study analyzes the differences between the revenue lags and the expense leads of a utility. Three broad categories of leads and lags are considered: (1) lag times associated with the collection of revenues owed to the utility; (2) lag and lead times associated with the collection and payment of what are commonly called “pass-through” taxes and “energy assistance charges” and (3) lead times associated with the payments for goods and services received by the utility. NS Ex. 7.0 at 17; PGL Ex. 7.0 at 20. The Utilities note that they performed a lead-lag 11-0280/11-0281 (cons.)
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study closely conforming to the methodology adopted by the Commission in the 2007 and 2009 rate cases. NS Ex. 7.0 at 18; PGL Ex. 7.0 at 21.
a) Pass-Through Taxes
(1) Utilities
According to the Utilities, the only contested aspect of its lead-lag cash working capital study relates to pass-through taxes and energy assistance charges. The Utilities add pass through taxes and energy assistance charges to customer bills and then are required to remit the funds to various local and state governmental agencies. These taxes and charges are not recorded as revenue or expense on the income statement, but their collection and payment cause a timing difference in the cash flow that needs to be accounted for. NS Ex. 7.0 at 21; PGL Ex. 7.0 at 24. In approving the Utilities’ expense leads and revenue lags in the 2009 rate case, the Commission acknowledged and found that: “If shareholders make a payment because the money has not yet been received from ratepayers, then this amount is appropriately contained in the calculation of cash working capital.” Peoples 2009, p. 24.
In a lead-lag study, the revenue lag measures the number of days from the date service was rendered by the Utilities until the date payment was received from customers and such funds become available to the Utilities. NS Ex. 7.0 at 19; PGL Ex. 7.0 at 22. Pass-through taxes and energy assistance charges are included on the monthly bills and payments are received for these amounts at the same time as all other cash from its customers, therefore the lag for the collection of pass-through taxes and energy assistance charges is identical to the revenue lag. NS Ex. 7.0 at 22; PGL Ex. 7.0 at 25.
Lags for Pass-Through Taxes and Energy Assistance Charges
The Utilities argue that Staff’s proposal to reduce the revenue lag to zero for pass-through taxes and energy assistance charges must be rejected. The Utilities note that the Commission specifically rejected Staff’s argument in the Utilities’ 2009 rate case, stating:
The Utilities have appropriately used a methodology that matches what the Commission approved in the Utilities’ last rate cases. The evidence shows that the Utilities addressed the actual lags and leads for pass-through taxes in their study. Staff‘s proposal, however, would in effect find that the Utilities are holding customers’ money for 50.3 days (Peoples Gas) and 74.82 days (North Shore). Tr. at 750. The evidence does not support this. It appears that Staff's approach improperly ignores the time between when customers are billed for pass through taxes and when the pass through taxes are remitted to the Utilities.
Peoples 2009, p. 24 (emphasis added). 11-0280/11-0281 (cons.)
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Further, Staff agrees that the terms upon which the Utilities remit taxes and charges have not changed since the 2009 rate cases. Kahle Tr. 8/30/11 at 271-272. Staff’s methodology must be rejected again as it is not supported by the record.
The Utilities argue that Staff’s argument that because cash received from customers for pass-through taxes is not a payment for utility service, there should be no revenue lag should be rejected for several reasons. First, Staff is incorrect. Utilities witness Hengtgen explained in his rebuttal testimony the types of pass-through taxes and energy assistance charges and that these taxes and charges were taxes or charges imposed by law on either the Utilities or the customers and were either collected through a separate charge prescribed by law or described within the statute as a charge for utility service. NS-PGL Ex. 23.0 Corr. at 17-18; 305 ILCS 20/13(e) (“The Energy Assistance Charges assessed by electric and gas public utilities shall be considered a charge for public utility service.”).
Second, assuming that Staff is correct that there should be no lag because the cash collected for the pass-through taxes and energy assistance charges is not recorded as revenue, and they are not, then there should also be no expense lead because the taxes are not recorded as expense either. Staff’s position is flawed as consistent thinking would require that because they are not recorded as expense, they cannot have an expense lead either. The Utilities, in their direct testimony (NS Ex. 7.0 at 20; PGL Ex. 7.0 at 24), and again in rebuttal (NS-PGL Ex. 23.0 at 19-20), have stated that the pass-through taxes are not recorded as revenue or expense but they do create timing issues in the collection and payment of the taxes. That is because the Utilities bill customers for the pass-through taxes in their normal billing process, and the customers do not pay the bills immediately to the Utilities when they receive their bills. Thus, the Utilities appropriately calculated the lead times based on the timing of cash flows in and cash flows out. NS-PGL Ex. 23.0 at 20. In the 2009 rate case Order, the Commission acknowledged that “If shareholders make a payment because the money has not yet been received from ratepayers, then this amount is appropriately contained in the calculation of cash working capital.” Peoples 2009, p. 24. Staff does not disagree. Kahle Tr. 8/30/11 at 269-270. However, Staff continues to eliminate the cash flow in part of the timing difference but does not correct or adjust downward the lead (cash flow out). Staff’s proposal would indicate that the Utilities collect and hold most of the pass through taxes and energy assistance charges for an extremely long period of time before remitting them to the appropriate taxing jurisdiction, which is simply not accurate. Furthermore, under Staff’s proposal, the Utilities would not be in compliance with the appropriate statutes and ordinances governing the payment of the pass through taxes and energy assistance charges. NS-PGL Ex. 23.0 Corr. at 20.
Third, Staff argues that the Commission’s decisions on this issue have “evolved” based on its Orders in the following rate cases: Nicor 2008; Ameren Illinois, ICC Docket Nos. 09-0306/0307/0311 (cons.) (Order April 29, 2010) (“Ameren 2009”); and Commonwealth Edison Co., ICC Docket No. 10-0467 (Order May 24, 2010) (“ComEd 2010”). However, the Commission in the Utilities’ 2009 rate cases Order found that:
This is a factual question that rests on when a utility must make certain payments, such as taxes, and when it receives the cash from ratepayers to the make the payments. 11-0280/11-0281 (cons.)
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Whether the payments are based on estimate or actual cash receipts does not matter. If shareholders make a payment because the money has not yet been received from ratepayers, then this amount is appropriately contained in the calculation of cash working capital. Lead lag studies are the method by which this is determined. It is to be expected that each utility‘s lead-lag study will show different results and, thus, the decision in Nicor 2008 is not controlling.
Peoples 2009, p. 24 (emphasis added).
Thus, because it is a factual question as to when a utility must make certain payments, such as taxes, and when it receives cash from customers to make payments, the decisions in Nicor 2008, Ameren 2009, and ComEd 2010 are not controlling here. It is true that the companies in Nicor 2008, Ameren 2009, and ComEd 2010 are utilities, a gas utility, a combination gas and electric utility, and an electric utility, respectively. However, electric utilities have some different types of taxes imposed on them or their customers, which have different requirements than the taxes being at issue in this proceeding. Further, each of these utilities operates in different parts of the State indicating that there are different municipal utility taxes imposed on them or their customers. Finally, not all utilities remit these types of taxes on the same basis. For example, unlike other utilities, Peoples Gas and North Shore remit these taxes based on estimated collections based on an agreement that Peoples Gas has with the City of Chicago. NS-PGL Ex. 40.0 Corr. at 10-11. Despite asserting that the Utilities “process pass-through taxes in the same manner” as the utilities in Nicor 2008, Ameren 2009, and ComEd 2010 (Staff Ex. 10.0 Corr. at 10), Staff acknowledged he did not compare the local laws or municipal agreements to which Nicor, Ameren or ComEd on the one hand and the Utilities on the other hand are subject. Kahle Tr. 8/30/11 at 274.
An expense lead represents the time between when a good is received or a service is provided and when the Utilities pay for that good or service. NS Ex. 7.0 at 24; PGL Ex. 7.0 at 27.
Leads for Pass-Through Taxes and Energy Assistance Charges
Although Staff witness Kahle initially agreed with the Utilities’ calculation of expense leads for pass-through taxes and energy assistance charges, in rebuttal testimony, he revised the expense leads for three items, including Energy Assistance Charges, Gross Receipts/Municipal Utility and City of Chicago Gas Use Taxes, because Utilities witness Hengtgen “offered a revised number of lead days that [the Utilities] collect these pass through taxes before remitting.” Tr. 8/30/11 at 265; Staff Ex. 10.0 Corr. at 7-8. To support his calculations, Mr. Kahle relies on lines 442-451 on page 21 of Mr. Hengtgen’s rebuttal testimony (NS-PGL Ex. 23.0 Corr.). Tr. 8/30/11 at 266. However, nowhere in Mr. Hengtgen’s direct, rebuttal, or surrebuttal testimonies does he offer a revised number of lead days that the Utilities collect these pass-through taxes and energy assistance charges before remitting. In fact, the testimony upon which Kahle relies is actually a criticism of Staff’s methodology for calculating revenue lag days for pass through taxes. Mr. Kahle acknowledged on cross examination that he “interpreted [Mr. Hengtgen’s testimony] as being an altered calculation of the expense 11-0280/11-0281 (cons.)
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lead days” and that Mr. Hengtgen did not revise lead days for these taxes. Id. at 266 267.
(2) Staff
Staff argues that the Commission should find that pass-through taxes have a revenue lag of zero days. Staff witness Kahle testified that revenue lag is, generally, the time lag between the Companies’ cash outlays for the provision of service to the collection of cash from customers. Staff Ex. 1.0, p. 8.
Mr. Kahle further explained that Cash Working Capital is the amount of funds required from investors to finance the day-to-day operations of the Companies. Pass-through taxes are taxes that are added on to ratepayers’ bills and collected by the Companies on behalf of a taxing body. While pass-through taxes are collected through the Companies’ billing systems, they are not charges for utility service. Staff Ex. 1.0, p. 7.
Staff maintains that since pass-through taxes are not related to the provision of utility services, (i.e. not revenue), there is no lag between a delivery of utility service and the receipt of cash from customers. Accordingly, pass-through taxes cannot have a revenue lag. Staff notes that the Commission has determined that pass-through taxes should have a revenue lag of zero in three recent rate cases: Commonwealth Edison Company Docket No. 10-0467; Ameren Illinois Utilities Docket Nos. 09-0309, 09-0307, and 09-0311 (Cons.); and Nicor Gas Docket No. 08-0363. In those cases the Commission stated the following:
In our view, and after our analysis, we agree with Staff‘s position. We find it is proper to give the pass-through taxes zero revenue lag time in the CWC calculation. The fundamental idea lies in the theory that pass-through taxes are collected from the ratepayers and merely turned over by the Company to the taxing authority. Nicor seems to ignore the basic premise upon which CWC is based, as previously stated in the 2007 Peoples Gas Rate Case above. Since every dollar for pass-through taxes is collected from the ratepayers, the inflows and outflows earmarked for these taxes should be perfectly balanced. Thus the need for CWC should not arise with respect to pass-through tax transactions.
ICC Docket No. 08-0363, Order, March 25, 2009, at 11,
As an initial matter, the Commission accepts Staff's argument that the utility has no "investment" associated with pass-through taxes. Since every dollar for pass-through taxes is collected from the ratepayers, the inflows and outflows earmarked for these taxes should be perfectly balanced. Thus the need for CWC should not arise with respect to pass-through tax transactions. This conclusion is 11-0280/11-0281 (cons.)
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consistent with prior Commission decisions. Nicor Docket No. 08-0363 at 11-12.
Staff distinguishes pass-through taxes from other cash flows in that unlike other revenue, pass-through taxes are not directly associated with the provision of utility service. The Commission believes that Staff makes a legitimate point here. The Company would have us believe there is an additional and measurable cost to pass-through taxes but fails to illustrate how a tax that is completely ratepayer-funded could generate any costs or expense. This is simply not the case. The Commission finds that Staff's proposed adjustment to the CWC requirement must be accepted. [emphasis added]
ICC Docket Nos. 09-0306 et al. (Cons.), Order, April 29, 2010, at 54,
The Commission agrees with Staff’s interpretation as to the EAC/REC and GRT/MUT tax issues. For the EAC/REC tax, the utility shall remit all moneys received as payment to the Illinois Department of Revenue by the 20th day of the month following the month of collection. Under the GRT/MUT tax, this ordinance requires ComEd to file a monthly tax return to accompany the remittance of such taxes, due by the last day of the month following the month during which such tax is collected. Both the statute and ordinance requires ComEd to remit these pass-through taxes after they have been collected from customers. ComEd stated in its briefs that the Company correctly pays these taxes in the month following activity that occurs in a prior “tax liability” month. The Commission concludes that the CWC calculation for GRT/MUT pass-through taxes should reflect zero revenue lag days and 44.21 expense lead days and zero revenue lag days and 35.21 expense lead days for EAC/REC pass-through taxes as supported by Staff.
ICC Docket No. 10-0467, Order, May 24, 2011, at 47.
Staff notes that the Companies’ own witness confirmed that pass-through taxes are not revenues. The Companies’ witness Hengtgen states: “The revenue lag measures the number of days from the date service was rendered by Peoples Gas until the date payment was received from customers and such funds become available to Peoples Gas.” PGL Ex. 7.0, p. 22. Mr. Hengtgen made an identical statement regarding North Shore Gas. NS Ex. 7.0, p. 19. Staff argues that by the Companies’ definition, pass-through taxes remitted by ratepayers could not have a revenue lag since pass-through taxes do not represent payment for utility services. Staff maintains that in accordance with the Companies’ testimony, the Companies do not include pass-through taxes as revenue in their revenue requirements. Stated differently, the 11-0280/11-0281 (cons.)
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Companies propose to apply a revenue lag to something they themselves do not include as revenue.
Staff surmises that Cash Working Capital is included in rate base to allow investors to recover the cost of financing operating expenses until operating revenue is collected. The collection of pass-through taxes is not the recovery of a cost of providing service; therefore, pass-through taxes are not included in the revenue requirement. Staff holds that because ratepayers provide the financing for pass-through taxes, the Commission should not allow a revenue lag for pass-through taxes which would allow investors to earn a return on ratepayer provided funds.
Staff maintains that the Commission should accept the Cash Working Capital levels recommended by it on page 11 of Appendices A and B to Staff’s Initial Brief.
(3) Commission Analysis and Conclusion
The Commission acknowledges that it approved the Utilities’ expense leads and revenue lags in their 2009 rate case. The Utilities have used a methodology that matches what the Commission approved in their last rate case, and the Commission recognizes that the terms upon which the Utilities remit taxes and charges have not changed since the 2009 rate case.
However, the Commission finds that this is a factual question that rests on when a utility must make certain payments, such as taxes, and when it receives the cash from ratepayers to make the payments. Whether the payments are based on estimated or actual cash receipts is not determinative. If the Companies make a payment but the money has not yet been received from ratepayers, then this amount is appropriately considered in the calculation of cash working capital. Likewise, if the money is collected and held prior to payment, then that fact must also be considered in the calculation of cash working capital. Lead lag studies are the method by which this determination is made.
In the present case, the Commission finds that Staff’s approach properly considers the time between when customers are billed for pass through taxes, the receipt of payment by the Utilities, and the length of time the payment is held by the Utilities until the pass through taxes are remitted to the taxing authorities. Staff’s analysis finds that the utilities are, for the most part, holding customers’ money for pass-through taxes which are later remitted to taxing authorities. The Commission notes that this same type of analysis was proposed by Staff and adopted by the Commission in the three cited prior rate cases, and the Commission sees no reason to deviate from that analysis here.
Accordingly, Staff’s cash working capital methodology for pass-through taxes is adopted. Based on the analysis in the record, the Commission agrees with Staff’s position to give pass-through taxes zero revenue lag time in the cash working capital calculation.
b) Prepayments (Uncontested)
GCI witness Morgan and Staff witness Kahle each proposed a change to the collection lag with respect to prepayments. GCI Ex. 1.0 Corr. at 7-8; Staff Ex. 1.0 at 9-11-0280/11-0281 (cons.)
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10. In rebuttal testimony, Utilities witness Hengtgen agreed that an adjustment to the collection lag was appropriate and accepted Staff’s adjustment. Mr. Morgan accepted the adjustment in rebuttal testimony. GCI Ex. 6.0 at 3. The Commission approves the adjustment to the collection lag with respect to prepayments as proposed by Staff and accepted by the Utilities.
c) All Other (Uncontested)
The Utilities, Staff, and GCI agree that the final amount of the Utilities’ CWC requirements should be determined based on the revenue and expense levels ultimately approved by the Commission in this proceeding. NS-PGL Ex. 23.0 Corr. at 15; Staff Ex. 10.0 Corr. at 8; GCI Ex. 6.0 at 3. Therefore, the Commission determines the final amount of the Utilities’ CWC requirements based on the revenue and expense levels approved by the Commission elsewhere in this Order.
5. Retirement Benefits, Net
a) Pension Asset
(1) Utilities
The Utilities state that it is undisputed that “Retirement Benefits, Net” for each utility is the sum of its pension asset (its prepaid pension expense) less its “OPEB” (other post employment benefits) (also sometimes referred to as “post retirement welfare”) liability. NS Ex. 7.1 at Sched. B-1.2; PGL Ex. 7.1 at Sched. B 1.2; NS Ex. 11.0 at 12; PGL Ex. 11.0 at 12; GCI Ex. 2.0 at 8.
The Utilities request Commission approval of “Retirement Benefits, Net” of $2,804,000 for North Shore and $68,887,000 for Peoples Gas (updated figures as of rebuttal and surrebuttal). NS-PGL Ex. 40.1N, line 7; NS-PGL Ex. 40.1P, line 7. In other words, the Utilities should be allowed to recover the carrying costs of their prepaid pension expense. That is what including their Retirement Benefits, Net, in rate base, would do, while at the same subtracting their OPEB liabilities. The Utilities submit that that would be the correct ruling given the evidence in the record and the applicable law.
In the alternative, North Shore requests that the Commission (1) approve inclusion in North Shore’s rate base of its recent pension contributions from internally generated sources, $4,001,111 and $11,139,238 in 2009 and 2010, respectively, NS Ex. 11.0 at 7, less its OPEB liability; or (2) allow North Shore to recover as an income item the annual customer benefit (in terms of reduced pension expense in the utility’s revenue requirement) of those two pension contributions, i.e., $1,260,000 per year, id., while still including the OPEB liability in rate base.
Finally, further in the alternative, the Utilities request that the Commission remove from rate base each utility’s pension asset and its OPEB liability, i.e., its Retirement Benefits, Net, to be fair and consistent.
The Utilities argue that the reason the Commission in the 2007 and 2009 rate cases excluded from rate base Peoples Gas’ pension asset and excluded the alternative of the Utilities’ pension contributions, and the reason Staff and GCI in the instant cases propose the exclusion in rate base of the Utilities’ pension assets and North Shore’s pension contributions, is the theory that the pension assets and 11-0280/11-0281 (cons.)
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contributions were not funded by investors but instead by customers because the source of funds was funds from net cash from operating activities (in particular, the collection of customers’ utility bills). Peoples 2007, p. 36; Peoples 2009, pp. 35-37; Staff Ex. 3.0 at 3–7; Staff Ex. 12.0 at 3–4; GCI Ex. 2.0 at 8–10; GCI Ex. 7.0 at 8–9.
The Utilities maintain that the evidence in the instant cases, including new facts elicited by Staff at the evidentiary hearing, does not permit a finding that the pension assets and contributions were not funded by investors. In the 2007 and 2009 rate cases (and some other cases), and in Ms. Ebrey’s reasoning, the fact that a utility makes pension contributions and creates a pension asset using funds from net cash from operating activities has been taken to mean that none of those funds constitute capital of the utility. However, Utilities witness Phillips pointed out in her rebuttal testimony that “net cash from operating activities includes the portion of what customers pay on their bills for return of and on rate base as approved during the ratemaking process.” NS PGL Ex. 27.0 at 9. The Utilities surmise that in other words, part of what customers pay is the return of and on past capital investments of the utilities (“return of” being depreciation and amortization expense, and “return on” being the rate of return on rate base reflected as net income in the revenue requirement). The fact that the utility collects return of and on its capital investments does not mean that those collected funds then are not capital of the utility. The Utilities contend that neither the facts nor logic supports that inference, which was refuted by Ms. Phillips. Moreover, the cross-examination of Utilities witness Ms. Gast by Staff showed another reason that inference is incorrect, i.e., the portion of funds derived from collecting customers’ utility bills that ends up as net income is retained earnings and thus is a part of equity. Gast Tr. 8/31/11 at 399-400. According to the Utilities, these facts preclude any finding that the use of a portion of net cash from operating activities to make pension contributions and create a pension asset is not an expenditure of capital. These facts were not addressed in the 2007 and 2009 rate cases.
The Utilities state that Ms. Ebrey’s rebuttal did attempt to respond to Ms. Phillips’ rebuttal, but, in essence, all that Ms. Ebrey did was claim that Ms. Phillips had not shown a change in facts since the 2007 and 2009 rate cases and state that the additional information that Ms. Phillips had supplied did not contradict North Shore’s prior data request response about the source of funds for its 2009 and 2010 pension contributions. Staff Ex. 12.0 at 3–4. The Utilities maintain that neither point refutes or even undercuts what Ms. Phillips said. Moreover, Ms. Phillips’ point about a portion of funds collected from customers being return of and on capital investments of the utility may not be a change in circumstances, but it is a new fact that was not in evidence and thus was not addressed by the Commission’s Orders in the prior cases.
The Utilities note that Mr. Effron agreed that, by definition, customers’ payments of their utility bills cannot be direct contributions to a utility’s pension trust. Tr. 8/30/11 at 205.
The Companies assert that further proof that it is erroneous to infer that use of funds from operations cannot be a use of capital is found in the facts that the pension assets are part of the Utilities’ balance sheets and, with respect to defined benefit plans, which is what is involved here, that the utilities own the assets, with the employees 11-0280/11-0281 (cons.)
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being the beneficiaries of the trust. NS-PGL Ex. 27.0 at 9. These two facts were raised in the past cases, but they remain uncontested.
The Utilities argue that exclusion of the pension assets from rate base would be contrary to law. The premise that customers, by paying utility bills, somehow should be treated as if they had paid for the utility’s assets, also is wrong as a matter of law. Utility customers pay for service, not for the property used to render it. Board of Public Utility Commissioners, et al. v. New York Tel. Co., 271 U.S. 23 (1926).
Moreover, the Utilities continue, the Supreme Court of Illinois previously has rejected a claim that a utility’s rate base should be reduced on the theory that part of it was the product of customer supplied funds. In Citizens Utilities Co. of Illinois v. Illinois Commerce Comm’n, 124 Ill. 2d 195, 529 N.E.2d 510 (1988), the Commission in a rate case had made a $4,253,953 reduction in plant in a utility’s rate base and reduced its depreciation expenses by $403,432, a total of $4,657,385, where the utility’s existing rates had incorporated a level of income taxes that resulted in collecting through rates $4,657,385 more for income taxes that the utility actually had paid. Citizens Utilities, 124 Ill. 2d at 201-202, 529 N.E.2d at 513. The Commission, on appeal, sought to justify the reductions on the basis that the funds that paid for the plant were not investor supplied but rather were customer supplied, by virtue of the income tax over recovery. Citizens Utilities, 124 Ill. 2d at 203, 204 205, 529 N.E.2d at 513, 514 515. The Supreme Court reversed, finding that the Commission’s reductions constituted improper retroactive ratemaking. Citizens Utilities, 124 Ill. 2d at 203, 206 207, 210 211, 529 N.E.2d at 515 516, 517 (citing, inter alia, Mandel Brothers, Inc. v. Chicago Tunnel Terminal Co., 2 Ill. 2d 205, 117 N.E.2d 774 (1954)). The Supreme Court stated in part:
The Commission would derive from those cases the rule that a public utility's investors are not entitled to earn a return on sums that may be characterized as capital contributions by customers. We would note, however, that there was no contention made in either of the cited cases concerning retroactive ratemaking. The amounts at issue here were recovered by Citizens in past ratemaking orders as part of its income tax expense, and the validity of those orders cannot now be questioned.
Citizens Utilities, 124 Ill. 2d at 212, 529 N.E.2d at 518.
The Utilities maintain that although the circumstances are not identical, here, too, the Staff and GCI positions are based on the premise that customers’ payments of bills under past rates mean that customers supplied the funds used to pay for the asset and, therefore, the utility should earn no return on the asset. That is inconsistent with Citizens Utilities.
The Utilities argue that the decision in Commonwealth Edison Co. v. Illinois Commerce Comm’n, 398 Ill. App. 3d 510, 924 N.E.2d 1065 (2d Dist. 2009) (“ComEd 2009”), does not support denying the Utilities recovery of the carrying costs of their prepaid pension expense. In the rate case Order on Rehearing underlying the relevant portion of that Second District decision, the Commission had excluded Commonwealth Edison Company’s (“ComEd”) pension asset from rate base but allowed ComEd to 11-0280/11-0281 (cons.)
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recover a return at its cost of long term debt on an $803 million contribution to the pension plan that was made in 2005 using funds supplied by ComEd’s ultimate parent company. ComEd 2009, 398 Ill. App. 3d at 519 520, 924 N.E.2d at 1079. ComEd appealed, arguing that it should be allowed a return based on its overall cost of capital, not its cost of long term debt, but the Second District affirmed, accepting the Commission’s argument that ComEd has failed to carry its burden of proving that recovery of the $803 million contribution at ComEd’s full cost of capital was reasonable or that there was not a less expensive alternative to funding the contribution than that full cost of capital. ComEd 2009, 398 Ill. App. 3d at 521 522, 924 N.E.2d at 1080. Thus, the question on appeal in ComEd 2009 did not revolve around whether the funds used to contribute to the pension plan were investor-supplied, but around whether financing the contribution at the utility’s full cost of capital, rather than its cost of long-term debt, was proven to be reasonable. The fact that the ComEd pension contribution was funded by its ultimate parent company does not warrant excluding the Utilities’ pension assets from rate base. The Utilities argue that the facts of the instant cases do not permit the conclusion that the funding of the pension contributions and pension assets are customer supplied.
The Utilities maintain that although the facts and law support inclusion of the Utilities’ pension assets in rate base (i.e., recovery of carrying costs on their prepaid pension expense), in the alternative, as to North Shore, the utility should be allowed to include its 2009 and 2010 pension contributions in rate base or, alternatively, to recover the annual customer benefit of the contributions.
In addition to the facts referenced above, the Utilities argue that, with respect to North Shore’s 2009 and 2010 pension contributions, the level of pension expense in the approved revenue requirement set in the 2009 rate cases was about $2.9 million per year, much less than the $4,001,111 and $11,139,238 that North Shore contributed in 2009 and 2010, respectively. NS-PGL Ex. 27.0 at 10.
The theory that customers somehow were funding the 2009 and 2010 North Shore pension contributions is fallacious for another reason according to the Utilities. Neither of the Utilities has recovered its approved rate of return on common equity since 2003. NS Ex. 1.0 at 4; PGL Ex. 1.0 at 4. Thus, customers were not paying the utility’s total costs of service, and it is not logical or fair to infer that they nonetheless were funding these pension contributions.
Finally, the Utilities assert that in ComEd’s 2010 rate case, the Commission approved ComEd’s recovery of costs relating to its 2009 pension contribution, which was shown to be funded using internally generated funds, although the recovery was set at the level of annual customer benefit, while the recovery of ComEd’s 2005 pension contribution was continued based on a debt rate of return but reduced on an amortization theory. ComEd 2010 at 50 51, 98.
Accordingly, the Utilities state that North Shore should recover the carrying costs of its 2009 and 2010 pension contributions by including them in rate base or, alternatively, should recover as an income item the annual customer benefit (in terms of reduced pension expense in the utility’s revenue requirement) of those two pension 11-0280/11-0281 (cons.)
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contributions, i.e., $1,260,000 per year. In either scenario, the OPEB liability still would be included in rate base.
The Utilities argue, in the alternative, if North Shore and Peoples Gas are not allowed to recover the carrying costs of their prepaid pension expense, or, in North Shore’s case, even to earn a recovery as its 2009 and 2010 pension contributions, then their OPEB liabilities should not be included in rate base, either. The pension assets / contributions and OPEB liabilities are similar in nature and should be treated on a consistent basis. NS PGL Ex. 27.0 at 2, 12. The Commission did not so rule in the 2007 and 2009 rate cases, but there is no valid factual or legal reason for disparate treatment of these items.
(2) Staff
Staff argues that the Commission should accept its adjustment to remove the Pension Asset and associated ADIT from rate base. Staff updated the amount of the adjustment in rebuttal testimony to reflect the updated actuarial study as it was included in the Companies’ rebuttal positions. The pension asset was created with funds provided by ratepayers, thus shareholders should not reap benefits from its inclusion in rate base. Staff Ex. 3.0, p. 3 Not only is such a conclusion supported by the evidence in the record in this case, it is also consistent with the Commission’s conclusions about the pension asset in the 2007 and 2009 PGL rate cases. In both cases, the Commission denied the inclusion in rate base of the pension asset. Staff Ex. 3.0 Corrected, pp. 4-5. Staff recognizes that the Commission is not bound by prior decisions:
Initially we note that the decisions of the Commission are not res judicata. The concept of public regulation includes of necessity the philosophy that the Commission shall have power to deal freely with each situation as it comes before it, regardless of how it may have dealt with a similar or same situation in a previous proceeding. Thus like other administrative agencies, the Commission is free to change its standards so long as such changes are not arbitrary and capricious.
City of Chicago v. Illinois Commerce Commission, 133 Ill.App.3d 435, 440 (1st Dist. 1985) (citations omitted), and that the Commission must decide this case on the evidence in the record (220 ILCS 5/10-103, 10-201(e)(iv)(A)). However, on appeal, Commission decisions are entitled to less deference when the Commission drastically departs from past practice. Business and Professional People for the Public Interest v. Illinois Commerce Comm’n, 136 Ill.2d 192, 228 (1989) (“BPI 1”. Staff maintains that in this case the Companies did not provide any testimony explaining why the Commission should decide this issue differently for PGL. Staff Ex. 12.0 Corrected, p. 4. The Companies explained that the newly created pension asset for NS was funded from normal operating revenues collected from utility ratepayers. Staff Ex. 3.0 Corrected, pp. 3-4. While Company witness Phillips opines that customers did not supply the funds for the NS pension contribution, no evidence was provided to contradict the evidence provided in response to Staff data request TEE 9.02. The response to that data request indicates that the pension contribution results from “internally generated sources” (i.e. net cash from operations). Staff Ex. 3.0 Corrected Attachment B. Company witness Phillips also opines that due to pending appeals on this issue in the two prior PGL rate 11-0280/11-0281 (cons.)
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cases, the inclusion of the pension asset in the instant rate case is warranted; but she provides no new rationale or facts to support why the inclusion is “warranted”. Id., p. 5. No Company witness provided surrebuttal testimony on this issue.
Staff notes that GCI witness Effron agrees with Staff’s position on this issue and likewise recommends removal of the pension asset from rate base for both utilities. GCI Ex. 2.0, p. 10.
(3) AG
The AG asserts that GCI witness Effron made appropriate adjustments to rate base to account for net retirement benefits, and updated those adjustments in his rebuttal testimony to reflect the updates presented in the rebuttal testimonies of NS/PGL witnesses Hentgen and Phillips. GCI Ex. 2.0 at 8-10; GCI Ex. 7.0 at 8-9. Mr. Effron’s adjustments reflect the Commission’s findings in ICC dockets 07-0241/07-0242 and 09-0166 and 09-0167 on the appropriate treatment to account for North Shore and Peoples’ retirement benefits as part of rate base. The AG maintains that those decisions both concluded that the accrued OPEB liability should be reflected in rate base but that the pension balances should not be recognized in the determination of rate base. Staff witness Ebrey agreed with Effron’s approach, and removed the Utilities respective net pension assets from rate base, but kept the OPEB liabilities in rate base.
The AG asserts that elimination of the Companies’ net pension asset from rate base, based on the Companies’ updates to their respective pension assets (NS PGL Ex. 23.9N, p. 1 and NS/PGL Ex. 23.9P, p. 1) results in a reduction to rate base of $3,941,000 for North Shore (GCI Ex. 7.1, Schedule DJE-1, “Rate Base Adjustments”) and $118,420,000 for Peoples (GCI Ex. 7.1, Schedule DJE-1 “Rate Base Adjustments”). The AG concludes that Mr. Effron’s adjustments are consistent with the Commission’s policy on this issue and the Commission should adopt them.
(4) Commission Analysis and Conclusion
The Commission agrees with both Staff and GCI concerning the adjustments to rate base made to account for net retirement benefits. Staff witness Ebrey agreed with GCI witness Effron’s approach which removed the Utilities’ respective net pension assets from rate base, but kept the OPEB liabilities in rate base. Staff and GCI’s adjustments are supported by the evidence and remain consistent with the Commission’s conclusions about the pension asset in the 2007 and 2009 PGL rate cases. Those decisions both concluded that the accrued OPEB liability should be reflected in rate base but that the pension balances should not be recognized in the determination of rate base. 11-0280/11-0281 (cons.)
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6. Accumulated Deferred Income Taxes –
a) 50/50 Sharing Related to Tax Accounting Method Changes
(1) Utilities
The Utilities state that they elected two tax accounting method changes: (1) a change in method of accounting related to the determination of unit of property used for repairs and retirements (“Repairs Change”); and (2) a non automatic change to the capitalization of certain indirect and overhead costs (“Overhead Change”). Both of these tax accounting method changes are not final and are still subject to final rulings by the Internal Revenue Service (“IRS”). The Utilities maintain that because approval of these tax accounting method changes is far from certain and in the near term carries significantly greater risk than normal issues, they propose that the benefits associated with the change be shared 50/50 with their customers. NS Ex. 7.0 at 14-15; PGL Ex. 7.0 at 16-17; NS-PGL Ex. 23.0 Corr. at 12-14.
The Utilities claim that to not recognize that a substantial risk exists with North Shore’s and Peoples Gas’ Repairs Change and Overhead Change would send a chilling effect to utilities in the future in making such elections before guidance from the Treasury Department and IRS is final. They note that Mr. Hengtgen explained, when a utility takes a tax deduction and reflects the impact of the deduction in its financial statements, the benefits of that deduction will inevitably be conveyed to customers through reduced rates. However, to the extent an election is subject to a final determination after audit or other Treasury action or law change that reverses a utility’s position, it usually results in a utility returning the benefit without the ability to recover equivalent amounts from customers. NS Ex. 7.0 at 14-15; PGL Ex. 7.0 at 17. The Utilities maintain that, having made these elections, they simply would like to share, 50/50, the risks as well as the benefits with the customers. The Utilities note that Staff agrees that the Utilities’ sharing proposal is appropriate.
According to the Utilities GCI witness Morgan errs in claiming that sharing the benefit related to the Repairs Change is unnecessary because there is no significant IRS audit risk. GCI Ex. 1.0 Corr. at 13–14. The Repairs Change relates to the determination of unit of property used for repairs and retirements. NS Ex. 10.0 at 6-7; PGL Ex. 7.0 at 6-7. Utilities witness Stabile testifies, the change in tax accounting method is based on Internal Revenue Code (“IRC”) Section 263 which provides: “No deduction shall be allowed for…Any amount paid out for new buildings or permanent improvements or betterments made to increase the value of any property or estate.” Id. at 7. The Proposed Treasury Regulations issued under this section in 2006 and then again in 2008 provide more detail and generally attempt to define a “unit of property.” NS-PGL Ex. 26.0 at 5. The Utilities maintain that neither the 2006 proposed regulations nor the 2008 re-proposed regulations can be relied upon. Even if they could be relied upon, neither the 2006 nor the 2008 proposed regulations included a definition of a unit of property for network assets. Mr. Stabile explains, because of the complexity of the issue, the Treasury Department and the IRS have encouraged individual industries to work separately within the confines of the Industry Issue Resolution (“IIR”) program.
Repairs Change11-0280/11-0281 (cons.)
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The natural gas industry, through the American Gas Association and Interstate Natural Gas Association of America, has only in May 2011 initiated the IIR process for the industry. The Utilities note that even if the IIR process is successful, no individual company’s method will necessarily be the same as the IIR result or the final Treasury regulations issued under IRC Section 263, which would render IIR guidance null and void. The Utilities argue that until final regulations are issued or the IIR process is completed, the Utilities’ tax accounting change methodology could vary significantly from the IIR resolution or ultimately the Treasury Department’s final regulation; thus, there is significant risk. NS-PGL Ex. 26.0 at 7-8. Even though more utilities have opted to make this election, it in no way lessens this risk – either a utility’s methodology will comply with the IRS final regulations 100% or 0% or someplace in the middle.
The Utilities find that even if the unit of property is reasonable and a company has applied that unit of property correctly, the IRS can still challenge a lot of judgment and factual information, such as whether amounts incurred that materially increase the value or substantially prolong the useful life of any unit of property, adapt the property for a new use, or as part of a plan of rehabilitation, modernization, or improvement to any unit of property have been improperly expensed as a repair. The audit risks in a post-change environment are going to be extremely significant until the IIR is concluded and final regulations issued. Id. at 9.
The Utilities contend that the Commission has addressed the risk associated with the Repairs Change. In ComEd’s 2010 rate case, ICC Docket No. 10-0467, Illinois Attorney General and Citizens Utility Board witness Effron made an accounting reserve and refunds proposal reflecting the Repairs Change in ADIT, even though ComEd had not yet made an election. ComEd 2010 at 114. In its final Order, the Commission stated, with respect to ComEd’s decision not to elect to make the Repairs Change:
The Commission cannot conclude that ComEd’s cautious behavior with the IRS, without more, is an act of imprudence. The Commission also cannot conclude that only ComEd’s shareholder will benefit when and if ComEd elects to use this new tax procedure. As Staff points out, when the IRS issues guidelines on this new procedure, and when ComEd avails itself of this procedure, (providing it proves to be beneficial) ratepayers will benefit in the future. Additionally, ComEd used a historic test year. As Staff points out, any change regarding the IRS will not occur during the test year. The Commission therefore declines to adjust ComEd’s rate base in the manner that Mr. Effron recommends.
ComEd 2010 at 114. The Utilities argue that if the Commission recognized that there were risks to ComEd, and that the issue had not developed to a more certain level, it is clear that the Utilities likewise have risk with the method changes. The Utilities assert that the 50/50 sharing of the benefit associated with the Repairs Change is appropriate and Mr. Morgan’s arguments are without merit.
The Utilities suggest that GCI witness Effron errs in proposing to reflect 100% of the benefit associated with the Overhead Change in ADIT because he claims that the associated risk is not significant. GCI Ex. 2.0 at 11–13. Utilities witness Stabile
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explained, the Overhead Change has its genesis in the Simplified Service Cost Method (“SSCM”) contained in the Treasury Regulations relating to IRC Section 263A, Uniform Capitalization Rules. In 2001, utilities began to elect the SSCM, which at the time could be made automatically. However, by 2003 as the number of utilities making the election increased, the IRS removed this election from the list of elections that could be made automatically and ultimately changed the applicable regulations disallowing the use of SSCM for any property with a life of more than three years. The implementation of the revised regulations disallowing use of the SSCM by utilities was abnormally harsh in that it required an immediate change in accounting in the middle of a tax year with no estimated payment relief. NS-PGL 26.0 at 10-12.
Further, the Utilities explain, the IRS has designated this election a Tier 1 issue. The Large Business and International (“LB&I”) Division of the IRS adopted a compliance issue tiering strategy in 2006 to ensure that high-risk compliance issues are properly addressed and treated consistently across the division for all LB&I taxpayers that are involved in the issue. Thus, it provides a consistent framework for identifying, prioritizing and addressing significant compliance risks in a nationally coordinated manner. There are three tiers in the strategy, Tier I, Tier II and Tier III. Tier I is defined as follows:
“Tier I - High Strategic Importance. Tier I issues are of high strategic importance to LB&I and have significant impact on one or more Industries. Tier I issues could include areas involving a large number of taxpayers, significant dollar risk, substantial compliance risk or high visibility, where there are established legal positions and/or LB&I