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					ALBERTA ENERGY AND UTILITIES BOARD
Calgary, Alberta


ATCO PIPELINES SOUTH                                                  Errata to Decision 2001-97
2001/2002 GENERAL RATE APPLICATION                                      Application No. 2000365
PHASES I and II                                                                  File No. 1306-3


The Alberta Energy and Utilities Board (Board) issued Decision 2001-97 (The Decision) on
December 12, 2001. The Decision dealt with the 2001/2002 General Rate Application filed by
ATCO Pipelines South on December 14, 2000.

By letter dated December 17, 2001, Campbell Ryder Consulting Group Ltd (Campbell Ryder)
drew the Board’s attention to two minor typographical errors in the body of the Decision and
another error in the Order section of the Decision. The Board agrees that the data referred to by
Campbell Ryder are incorrectly reflected in Decision 2001-97. Details of the errors and required
corrections are set out in the following paragraphs of this Amending Order:

Decision 2001-97 (Page 136, Section 8.2.4)
The Decision includes a chart, which includes the following information:

   •   Forecast peak demand for 2001 of 1,758 TJ/day, including 16 TJ/day for Gas Alberta

The corrected information is:

   •   Forecast peak demand for 2001 of 1,757.8 TJ/day, including 15.8 TJ/day for Gas Alberta

Decision 2001-97 (Page 148, Section 8.2.8)
The Decision states:

   •   “The FGA agreed with ATCO that it was reasonable that a company would spend 50%
       of its Utility marketing effort on an entity that has 4% of Utility connections and 1.6% of
       Utility demand.”

The corrected sentence is:

   •   “The FGA agreed with ATCO that it was unreasonable that a company would spend
       50% of its Utility marketing effort on an entity that has 4% of Utility connections and
       1.6% of Utility demand.”
                                                                                  (Bolding added)




                                                   Errata to EUB Decision 2001-97 (January 15, 2002) • 1
2001/2002 General Rate Application – Phase I and II                            ATCO Pipelines South


Decision 2001-97 (Page 154, Section 10)
ORDER NO. 6 states:

    •   The rates, tolls and charges for Gas Alberta Inc., attached as Schedule “A” to this
        Decision are effective for all consumption on and after January 1, 2002.

ORDER NO. 7 has been added, acknowledging the effect of Gas Alberta’s new rate for 2001:

    •   ATCO Pipelines South shall propose a method for refund of over collections from Gas
        Alberta Inc. to the extent that revenues collected from Gas Alberta Inc. for consumption
        in 2001 exceed the revenues from Gas Alberta Inc. as determined based on the rates, tolls
        and charges attached as Schedule “A” and Appendix 1 to this Decision.


DATED in Calgary, Alberta on January 15, 2002.

ALBERTA ENERGY AND UTILITIES BOARD


<original signed by>

B. F. Bietz, Ph.D.
Presiding Member


<original signed by>

Gordon Miller
Member


<original signed by>

Carolyn Dahl Rees
Acting Member




2 • Errata to EUB Decision 2001-97 (January 15, 2002)
         DECISION 2001-97


      ATCO PIPELINES SOUTH

2001/2002 GENERAL RATE APPLICATION
            PHASES I AND II




                     EUB DECISION 2001-97 (December 12, 2001)
2001/2002 GENERAL RATE APPLICATION – PHASES I AND II                                                        ATCO Pipelines South


                                     ATCO PIPELINES SOUTH
                             2001/2002 GENERAL RATE APPLICATION
                                         PHASES I AND II

CONTENTS


1     INTRODUCTION............................................................................................................. 1
      1.1       Background ............................................................................................................. 1

2     PROCEDURAL AND OTHER GENERAL MATTERS.............................................. 3
      2.1       Matters of Process................................................................................................... 3
      2.2       Regulatory Status of ATCO Pipelines .................................................................... 4
      2.3       Completeness and Accuracy of Financial Data ...................................................... 4
      2.4       Other Matters .......................................................................................................... 6

3     RATE BASE ...................................................................................................................... 7
      3.1       Plant in Service ....................................................................................................... 7
      3.2       Capital Expenditure Forecasts ................................................................................ 8
      3.3       Support for Capital Projects.................................................................................. 18
      3.4       UFG Meters .......................................................................................................... 20
      3.5       Summary of Board Adjustments and Approved Capital Additions...................... 25

4     NECESSARY WORKING CAPITAL.......................................................................... 26
      4.1       Cash Expenses ...................................................................................................... 26
                4 .1 Operating and Maintenance Expense Lag ................................................ 26
                 .1
                4 .2 Income Tax Expense Lag.......................................................................... 26
                 .1
                4 .3 Taxes Other than Income .......................................................................... 27
                 .1
                4 .4 Financial Items.......................................................................................... 27
                 .1
                4 .5 Other Adjustments .................................................................................... 27
                 .1

5     FAIR RETURN ON RATE BASE ................................................................................ 30
      5.1       Treatment of ATCO Gas South (AGS) and ATCO Pipelines South (APS) as
                Separate or Merged Entities.................................................................................. 30
      5.2       Appropriate Return on Equity for AGS and APS................................................. 31
      5.3       Appropriate Capital Structure for AGS and APS ................................................. 38
      5.4       Preferred Share Cost ............................................................................................. 44
      5.5       Debt Cost .............................................................................................................. 45

6     UTILITY REVENUE REQUIREMENT ..................................................................... 47
      6.1       Operating & Maintenance Expense ...................................................................... 47
                6 .1 General...................................................................................................... 47
                 .1
                6 .2 Transmission ............................................................................................. 47
                 .1
                6 .3 Administration & General Expenses ........................................................ 48
                 .1


                                                                        EUB DECISION 2001-97 (December 12, 2001) • i
2001/2002 GENERAL RATE APPLICATION – PHASES I AND II                                                            ATCO Pipelines South


                     6 .4 Restructuring............................................................................................. 57
                      .1
                     6 .5 IT Spending............................................................................................... 60
                      .1
                     6 .6 Reserve for Injuries................................................................................... 65
                      .1
                     6 .7 Hearing Costs............................................................................................ 67
                      .1
                     6 .8 EUB Operating Cost Assessment ............................................................. 69
                      .1
                     6 .9 Net Cost Recoveries.................................................................................. 69
                      .1
                     6 .10 Non-Utility Expenses.............................................................................. 69
                      .1
          6.2        Taxes Other than Income ...................................................................................... 69
          6.3        Depreciation.......................................................................................................... 69
          6.4        Income Tax ........................................................................................................... 73
          6.5        Unaccounted-for Gas (UFG)................................................................................. 77
                     6 .1 Canadian Information ............................................................................... 82
                      .5
                     6 .2 United States (U.S.) Information .............................................................. 86
                      .5
                     6 .3 Allocation of UFG to Customer Groups................................................... 91
                      .5

7         UTILITY REVENUES................................................................................................... 97
          7.1        Transportation Revenue ........................................................................................ 97
                     7 .1 NOVA Chemicals Joffre......................................................................... 103
                      .1
                     7 .2 Agrium Carseland ................................................................................... 104
                      .1
                     7 .3 Other Industrial Markets ......................................................................... 104
                      .1
                     7 .4 Producers................................................................................................. 105
                      .1
                     7 .5 PanCanadian Carseland Contract............................................................ 105
                      .1

8         COST OF SERVICE STUDY...................................................................................... 114
          8.1        Background ......................................................................................................... 114
                     8 .1 COS Study Methodology........................................................................ 116
                      .1
          8.2        Specific Issues Arising........................................................................................ 119
                     8 .1 Distance of Haul ..................................................................................... 119
                      .2
                     8 .2 Direct Assignment .................................................................................. 121
                      .2
                     8 .3 Allocation Issues..................................................................................... 127
                      .2
                     8 .4 AGS Peak Demand ................................................................................. 133
                      .2
                     8 .5 Rolled In Principle (GURDI).................................................................. 136
                      .2
                     8 .6 Splitting the Utilities Group.................................................................... 141
                      .2
                     8 .7 Gas Alberta Settlement ........................................................................... 142
                      .2
                     8 .8 Calgary’s COS Study.............................................................................. 144
                      .2
          8.3        Rate Design......................................................................................................... 149

9         SUMMARY OF DIRECTIONS .................................................................................. 152

10        ORDER .......................................................................................................................... 153

SCHEDULE “A”....................................................................................................................... 157

APPENDIX 1............................................................................................................................. 159




ii • EUB DECISION 2001-97 (December 12, 2001)
ALBERTA ENERGY AND UTILITIES BOARD
Calgary, Alberta

ATCO PIPELINES SOUTH                                                                     Decision 2001-97
2001/2002 GENERAL RATE APPLICATION                                                Application No. 2000365
PHASES I AND II                                                                            File No. 1306-3


1       INTRODUCTION

1.1     Background
By letter dated December 14, 2000, ATCO Pipelines filed a 2001/2002 General Rate Application
(GRA) for ATCO Pipelines South (ATCO, the Company or APS), a division of ATCO Gas &
Pipelines Ltd. (AGPL).1 In the Application, ATCO forecast that the revenue requirement for the
test years would exceed revenue at existing rates by $1.1 million in 2001 and $1.8 million in
2002.

In correspondence dated April 2, 2001, ATCO requested that all affiliate, pension and post
employment transactions arising in the context of the GRA be deferred and heard as part of the
ATCO affiliate Transactions and Pension proceedings scheduled to be heard in the Fall of 2001.
By letter dated May 17, 2001, the Board, in the absence of objections from interested parties,
accepted ATCO’s proposal for deferral of the affiliate, pension and post employment benefit
transactions.

Notice of Hearing for the GRA was mailed to all interested parties on January 11, 2001, and
published on January 18, 2001.

The public hearing was convened in Calgary on July 3, 2001 before Board members
Dr. B. F. Bietz (Chair), Mr. G. J. Miller, and Ms. C. Dahl Rees. The hearing was completed on
July 18, 2001. Registered interveners and the Company were required to file written argument
and reply on August 10, 2001 and August 31, 2001 respectively.

The Board considers that the record for this proceeding and for the related proceeding ATCO
Gas South 2001/2002 GRA, Phase I, closed on September 14, 2001.

Those who appeared at the hearing and the abbreviations used in this report are listed in the
following table.

        1
           In the Application, ATCO Pipelines referred to the restructuring of Canadian Western Natural Gas
Company Limited and Northwestern Utilities Limited, noting that effective January 1, 2001, Northwestern Utilities
Limited would be amalgamated into ATCO Gas and Pipelines Ltd (formerly Canadian Western Natural Gas
Company Limited). ATCO Pipelines stated that on an ongoing basis, two divisions of ATCO Gas and Pipelines Ltd.
(ATCO Gas and ATCO Pipelines) would continue the operations of the distribution system and the transmission
system respectively. In the hearing, ATCO Pipelines confirmed that these changes had taken place, and that this
structure would continue at the present time with the operating and accounting functions being segregated into
ATCO Gas North and ATCO Gas South, and ATCO Pipelines North and ATCO Pipelines South, in accordance with
Decision U99102, dated November 1, 1999.

                                                               EUB Decision 2001-97 (December 12, 2001) • 1
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South




THOSE WHO APPEARED AT THE HEARING
Principals and Representatives
(Abbreviations used in Report)                              Witnesses

ATCO Pipelines South (ATCO or the Company)
      L. E. Smith                                           J. D. Graham
      A. C. Wooley                                          D. E. Gibbons
      N. M. Gretener                                        D. Belsheim
                                                            A. J. Dixon
                                                            W. Wright
                                                            G. J. Lidgett
                                                            K. C. McShane
                                                            M. Chwalowski
The City of Calgary (Calgary)
       R. B. Brander                                        H. W. Johnson
       P. L. Quinton-Campbell                               J. Stephens
                                                            L. E. Kennedy
                                                            H. J. Vander Veen
                                                            L. Booth
                                                            M. Berkowitz
Alberta Irrigation Projects Association (AIPA)
        J. H. Unryn

Consumers Coalition of Alberta (CCA)
      J. A. Wachowich

Municipal Intervenors (MI)
       C. R. McCreary

Public Institutional Consumers of Alberta (PICA)            R. T. Liddle
        N. J. McKenzie                                      R. Retnanandan
        R. T. Liddle

Federation of Alberta Gas Co-ops Ltd and Gas Alberta Ltd.
(FGA)
        L. J. Burgess                                       K. Dannacker
                                                            D. Symon
Mirant Americas Energy Marketing Canada Limited
(Mirant)
        E. Decter                                           S. Boucher-Chen

Industrial Gas Consumers Association of Alberta
(IGCAA)
        B. J. Roth                                          N. MacMurchy

PanCanadian Petroleum (PanCanadian)
      D. G. Davies



2 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                   ATCO Pipelines South


Canadian Association of Petroleum Producers (CAPP)
       G. Giesbrecht

Alberta Energy and Utilities Board staff
        J. Hocking, Board Counsel
        E. J. Gallagher
        R. Armstrong
        D. Popowich
        M. McJannet


2       PROCEDURAL AND OTHER GENERAL MATTERS

2.1     Matters of Process
In the Application, ATCO Pipelines indicated that meetings had been held throughout the year
2000 with Industrial and Producer customers to negotiate a revised settlement of rates for
Industrial/Producer (I/P) customers for 2001/2002. The negotiations were undertaken to activate
a re-opener in the existing settlement agreement, approved by the Board in Decision 2000-162
dated June 13, 2000. The existing agreement was re-opened to identify changes to rates, tolls and
charges, required to maintain competitiveness with the tolls and tariffs of NOVA Gas
Transmission (NGTL) approved by the Board on February 4, 2000. On November 19, 2000,
ATCO Pipelines filed an application for approval of the revised settlement, successfully
negotiated with I/P customers. The Board approved the revised settlement in Decision 2001-533
dated June 11, 2001.

By letter dated March 8, 2001, the Board expressed the view that, given the potential impact of
the I/P settlement on core customers, a comprehensive examination of relevant cost allocation
issues in the GRA would be necessary. The Board considered that a comprehensive examination
of cost allocation issues could only be achieved with the filing of a Cost of Service Study (COS
Study) by ATCO in advance of the hearing. Accordingly, the Board directed ATCO to file a
COS Study and related information by March 19, 2001, to allow for examination of both Phase I
and Phase II components of the rate proceeding during the hearing. To provide interveners with
the opportunity to seek additional information and clarification of issues arising from the COS
Study, the Board revised the schedule for the proceedings, to incorporate additional dates
required to facilitate an interrogatory process with respect to the COS Study. In accordance with
the direction of the Board, ATCO filed a COS Study on March 19, 2001.

By letter dated June 21, 2001, ATCO advised the Board that the Company had reached a
settlement agreement with Gas Alberta Inc. on a number of matters relating to the gas
transportation service provided by ATCO to Gas Alberta in 2001 and 2002. ATCO indicated that
the settlement included agreement on the transportation rate, the sale of gas meters by ATCO to
Gas Alberta, and the assumption of responsibility by Gas Alberta for the operation and
maintenance of these gas meters and associated regulating stations. On June 22, 2001, the Board

        2
          Decision 2000-16 ATCO Gas and Pipelines Limited, 1998 GRA – Phase II
        3
          Decision 2001-53 ATCO Pipelines, Approval of Rates, Tolls, Charges and Transportation Service
Regulations; Approval of Amendments to North and South Transmission Transportation Agreements

                                                              EUB Decision 2001-97 (December 12, 2001) • 3
2001/2002 General Rate Application – Phases I and II                          ATCO Pipelines South


agreed with ATCO’s proposal to incorporate the settlement with Gas Alberta into the GRA
deliberations. The Board therefore, invited interested parties to deal with questions or concerns
with respect to the settlement through cross-examination of ATCO or Gas Alberta witnesses
during the course of the GRA hearing.

2.2     Regulatory Status of ATCO Pipelines
There was considerable discussion in this Proceeding with respect to matters relating to the
regulatory status of ATCO, the impact of restructuring of the ATCO Group and related
accounting, and the quality and extent of evidence provided by ATCO in support of the
Application. The positions of the parties with respect to these matters are summarized in the
following paragraphs of this Section of the Decision.

Position of ATCO
ATCO submitted that if Calgary believed that a regulatory filing by ATCO was invalid
relative to the Gas Utilities Act, this point should have been raised immediately upon
receipt of the Application, not at the end of a lengthy and expensive General Rate Case
proceeding.

Position of Calgary
Calgary submitted that, for the test periods, 2001 and 2002, AGPL is the legal entity, the legally
regulated utility, and that ATCO Gas South (AGS), ATCO Gas North (AGN), APS and ATCO
Pipelines North (APN) are trade names or, at best, best business units.

Views of the Board
The Board notes the comments of ATCO and Calgary regarding the regulatory status of APS.
The Board considers that it was appropriate for AGS and APS to file their GRAs separately in
these proceedings.

In Section 2.3, the Board deals with the filing of annual reports by the business units of AGPL.

2.3     Completeness and Accuracy of Financial Data
Position of ATCO
ATCO referred to Calgary’s statement that there is a “…need for a complete regulatory filing of
AGPL in order to determine whether the whole was equal to the sum of the two parts, i.e. APS
and AGS as filed in the two separate applications.”

ATCO pointed out that, in 1999 and 2000, AGPL (formerly Canadian Western Natural Gas
Company Limited (CWNG)) was the “regulated entity”, and that the data referred to above as
“the whole” for 1999 has been filed in AGS GRA filing, and the 2000 data will be available
when 2000 actual regulatory results are filed with the Board. ATCO indicated that, with the
exception of necessary working capital, the data referred to above as “the two parts” for 1999
and 2000 is available in the respective 2001/2002 GRA filings of ATCO Gas and ATCO
Pipelines. ATCO submitted that the unavailability of 1999 and 2000 necessary working capital


4 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                ATCO Pipelines South


should provide no impediment to Calgary’s ability to assess the reasonableness of ATCO
Pipelines’ test year forecasts.

ATCO noted Calgary’s statement that “The primary concern addressed in Calgary’s evidence is
that historical data for at least one, if not two, base periods is useful in comparing and
determining the reasonableness of the forecasts for 2001 and 2002.” ATCO’s position was that
Calgary’s request for one or two base periods of data has been met.

ATCO rejected Calgary’s assertion that ATCO Pipelines record keeping is not in compliance
with Order U99130,4 dated December 21, 1999.

While ATCO maintains a single general ledger, wherever practical North/South distinctions are
identified by separate North/South accounts. ATCO provided examples to illustrate the point,
and indicated that where it is considered impractical to maintain a North/South distinction,
allocation methods have been developed. ATCO pointed out that the most significant of these
types of accounts are the Operating & Maintenance (O&M) accounts. ATCO submitted that
application of its policy provides the separate accounts required by Order U99130, that, in
ATCO’s view there is no other practical approach to comply with the Board’s direction, and that
financial statements prepared on this basis are completely valid.

Finally, ATCO noted that no other interveners appeared confused, or expressed concerns about
their ability to understand ATCO’s Application, nor did any of them question its validity.

ATCO referred to Calgary’s argument that the AGPL board of directors fails to recognize
the business units. Calgary contends that there is one entity which assigns and allocates
costs to a set of books, actual or forecast, and the only definitive method of examining the
legitimacy of the costs is to review that process; a process which AGPL will not divulge.
ATCO submitted that the Company does have a separate board of directors, which in
ATCO’s view, can review its accounts in any manner they choose and there is nothing in
any legislation that imposes duties on the board of directors to examine accounts in a
particular fashion.

Position of Calgary
Calgary’s submission on this issue was comprehensive and detailed. The main concerns are
summarized below. Calgary submitted that:

    •   the Board must consider the actions of ATCO, and the ATCO group, in creating a
        circumstance in which Interveners and the Board have been forced to deal with this GRA
        in a disjointed and incomplete fashion;
    •   from the date of the filing in this proceeding Calgary has tried to understand the financial
        maze created by AGPL commencing with the restructuring in late 1998;



        4
          Order U99130 Canadian Western Natural Gas Company Limited and Northwestern Utilities Limited,
Transactions re Organization of Companies

                                                            EUB Decision 2001-97 (December 12, 2001) • 5
2001/2002 General Rate Application – Phases I and II                             ATCO Pipelines South


      •   the financial data cannot be properly examined and the reasonableness of such financial
          data cannot be tested, without access to the whole picture, that is, all four sets of
          books/accounts;
      •   it is only through a series of allocations and other techniques that the four sets of
          books/accounts for each of AGS, AGN, APS, and APN were developed;
      •   the allocation factors vary from year to year and in some cases are less than or greater
          than 100%;
      •   for the test periods, 2001 and 2002, AGPL is the legal entity, and the legally regulated
          utility, and that AGS, AGN, APS and APN are trade names or, at best, best business
          units, the result of assignments and allocations of dollars, recorded to look like
          accounting records, which are not subject to examination in their totality;
      •   there is no practical methodology available for either the Board or interveners to
          determine the relationship of the parts to the whole or the whole to the parts.

Views of the Board
The Board agrees with intervener observations with respect to the complexity of this
Application, recognizing in particular that this is the first time applications have been filed for
two separate business units of ATCO Gas and Pipelines Ltd. The Board also agrees with
concerns expressed that, without an extensive interrogatory process and cross-examination, it
would have been extremely difficult to properly evaluate the test year forecasts. The Board is
satisfied that the additional information provided as a result of requests by the Board and
interveners has provided a reasonable basis to evaluate the Application.

However, the Board notes that the latest annual report of finances and operations, filed as
required by the Board for the year 2000 was for ATCO Gas and Pipelines Ltd. The Board
expects that for the year 2001 and subsequently, ATCO will file a separate annual report for each
of ATCO Gas South, ATCO Pipelines South, ATCO Gas North and ATCO Pipelines North.

2.4       Other Matters
A number of submissions were entered into evidence challenging ATCO’s position with respect
to:
    • the quantification of benefits to customers resulting from restructuring, and the treatment
      of pension gains and other costs arising from restructuring;
    • the concept of prospectivity and adjustments for actual events arising subsequent to the
      filing of the Application;
    • capitalization and inclusion of short term debt and no cost capital;
    • the treatment of affiliate-related and pension-related transactions.

Views of the Board
The Board notes the comments and concerns raised by interveners and the responses by ATCO
with respect to issues regarding the benefits of restructuring, and the concept of adjusting
forecasts to recognize post-Application transactions and events. The Board considers that there is
no need to reproduce the positions of the parties with respect to these matters in this section of
the Decision, since the issues are addressed more fully in other sections of the Decision. While


6 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                          ATCO Pipelines South


the same comment applies to the issue of affiliate and pension-related transactions, the Board
considers it worthwhile to highlight at the beginning of the Decision, how affiliate and pension-
related transactions in the Application will be dealt with in this Decision.

On April 2, 2001, ATCO requested Board approval to transfer affiliate, pension and post
employment benefit transactions from the GRA to the ATCO Affiliate and Pension proceedings
respectively. In the case of affiliate-related transactions, ATCO requested that all revenues and
expenditures relating to transactions with non-regulated affiliates be dealt with in the Affiliate
proceeding. Due to the complexities associated with isolating the revenue requirement impact of
capital related affiliate transactions, ATCO proposed that capital costs associated with affiliate
transactions continue to be reviewed in the GRA. On May 17, 2001, the Board accepted ATCO’s
proposal. Accordingly, the quantum and propriety of forecast revenues from services to
affiliates, forecast expenditures relating to services provided by affiliates, and forecast
expenditures relating to pension and post-employment benefits are not addressed in this
Decision. The forecast amounts will be treated as “placeholders” in the revenue requirement for
the test years, and adjusted by ATCO on refiling, after the Board Decisions are issued in the
Affiliate and Pension proceedings.


3       RATE BASE

3.1     Plant in Service
Position of ATCO
ATCO assigned forecast capital additions for the test years to three main categories, namely,
growth, improvements, and replacements. Total forecast capital expenditures were $15.72
million (2001) and $11.69 million (2002).

ATCO indicated that growth-related expenditures are required for new or upgraded plant or
equipment necessary to extend service to new customers, to generate additional revenues from
existing customers, or to protect revenues from existing customers. ATCO indicated that the bulk
of the forecast expenditures in this category are required for new transmission facilities to
provide service to new producer and industrial customers, and for installation of systems
expansions to accommodate growth in deliveries to ATCO Gas. The total forecast for
transmission growth was $1.98 million (2001) and $1.85 million (2002), representing
approximately 45% (2001) and 70% (2002) of growth-related expenditures.

The improvement category includes expenditures incurred to improve current system operability
and efficiency, to address changes to codes and regulations, and to improve compliance with new
industry standards and increase productivity. ATCO indicated that the bulk of the forecast
expenditures in this category are required for installation of new unaccounted for gas (UFG)
meter stations, designed to determine the correct allocation of unaccounted for gas between the
ATCO Gas distribution system and the ATCO Pipelines transmission system. The forecast for
the UFG meter stations was $4.87 million (2001) and $4.63 million (2002), representing
approximately 78% (2001) and 72% (2002) of improvement-related expenditures.



                                                       EUB Decision 2001-97 (December 12, 2001) • 7
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


ATCO’s expenditures in the replacement category are designed for replacement of equipment,
no longer suitable for service or which cannot be repaired, or to lower or relocate facilities for
safety and security. ATCO indicated that these expenditures generally do not result in increased
capacity, but ensure safety and reliability of service. ATCO indicated that the bulk of the forecast
expenditures in this category are required for replacement of facilities on the transmission
pipeline system, including pipeline integrity investigations, replacement of cathodic protection
equipment, replacement of obsolete equipment at meter stations and pipeline lowering and
relocates. The total forecast for these categories was $2.58 million (2001) and $2.39 million
(2002), representing approximately 50% of the total replacement expenditure forecast in 2001,
and 93% in 2002. The balance of the 2001 test year forecasts represents expenditures for the
Crowsnest Lake Replacement project ($1 million) and Supervisory Control and Data Acquisition
(SCADA) Replacement ($1.1 million). ATCO indicated that the SCADA system is an integral
component in overall maintenance of reliable pipeline service, which allows control centre
operators to ensure adequate pressures on the system for provision of natural gas service, while
maximizing system flows to ensure the most effective pipeline network utilization.

In the Application the balance of forecast expenditures in the three categories (Growth [G],
Replacement [R], and Improvement [I]) was set out as follows:

                                                        2001           2002
                                                       ($000)         ($000)
       East and South Mainline Expansion (G)             182
       Strathmore Branch Loop (G)                        360
       Bragg Creek extension (G)                         300
       Dewinton Branch Loop (G)                          262
       Chestermere North Branch Loop (G)                 820
       Valley Ridge Branch Loop (G)                      500
       Rockyview Branch Looping (G)                                     800
       Transmission Improvements (I)                    789           1,155
       Land & Structures (I)                             35             107
       Moveable Equipment (I)                            53              57
       Information Systems (I)                          500             500
       Land & Structures (R)                             72
       Moveable Equipment (R)                           240             193


3.2     Capital Expenditure Forecasts
Position of ATCO
ATCO submitted that the capital expenditure forecasts for the test years are conservative and
should be approved by the Board. ATCO pointed out that forecasts of capital expenditure for
2000 included in the Application, were based on actual expenditures to July and estimates for the
remaining months of the year. ATCO noted however, that problems encountered with
landowners during the second half of that year adversely impacted the Company’s ability to
complete some of those projects before the end of the year. Although the projects in question
will now be completed in 2001, ATCO submitted that, in keeping with the concept of



8 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                               ATCO Pipelines South


prospective ratemaking, the Company has not requested an increase in 2001 forecast
expenditures.

ATCO noted that the total expenditure of this nature amounted to $2.25 million, and submitted
that on an overall basis, the forecast for 2001 is low, relative to the expenditure the Company
will experience. ATCO also referred to its comments in testimony during the hearing, regarding
the potential to connect the Calpine and AES power plants to the system in 2002, noting that
there is no expenditure included in the 2002 forecast for these projects.

Referring to the MI proposal for a reduction of the 2000 forecast Property, Plant and Equipment
closing balance by $1.989 million to reflect actual amounts, ATCO pointed out that the Board
has been very clear with respect to the use of actual information that becomes available
subsequent to filing an application. ATCO referred to the Board’s rejection of this approach
outlined in Decision 2000-95 dated March 2, 2000, noting that the MI proposal would undermine
the Board’s stated position on prospective ratemaking. Furthermore, ATCO reiterated the point
that specific circumstances impacted the ability to complete all the work proposed for 2000,
stating that the work is being completed in 2001, but in keeping with the prospective ratemaking
concept, the Company is not requesting an increase in forecast expenditures.

In addition, ATCO pointed out that the MI’s proposal to selectively reduce the asset balance
without considering other areas of plant in service such as Work in Progress, Accumulated
Depreciation and Contributions is, in essence, cherry picking. ATCO indicated that,
notwithstanding the Board’s position on prospective ratemaking, the MI’s proposal is
inappropriate. By way of illustration, ATCO provided a table compiled from evidence contained
in information responses and the Application, demonstrating that the asset expenditure forecasts
are within 0.3% of actual expenditure, and are appropriate.

With reference to the MI’s request for a 10% reduction of the test year forecasts based on a
historical analysis of eight years, ATCO noted that the MI included information for only three
years (1998, 1999 and 2000), of which the year 1999 has no bearing, as there was no discussion
on 1999 data. While the two remaining years show an over-expenditure of 0.7% (1998) and
under-expenditure of 18.3% (2000), ATCO noted that the MI have selectively neglected to back
out the costs for projects where specific circumstances resulted in the projects amounting to
$1.45 million being delayed until 2001. Taking these projects into account, ATCO indicated that
the variation for 2000 reduces to 4.95%, resulting in a weighted average variance for 1998 and
2000 of 3%, which is well within reasonable forecasting accuracy. Accordingly, ATCO
submitted that the MI request for a blanket reduction of 10% should be denied.

With respect to the issue of delay of specific projects, ATCO submitted that there will also be
additional projects (Valley Ridge, Calpine and AES) for which increases have not been sought.
ATCO referred to its rebuttal evidence, where the Company took issue with Calgary’s evidence
with respect to the size of certain facilities and pointed out that the Valley Ridge project was
anticipated to cost more than forecast due to land issues.


        5
           Decision 2000-9 ATCO Gas and Pipelines Ltd. (CWNG, 1997 Return on Common Equity and Capital
Structure, 1998 GRA – Phase I

                                                           EUB Decision 2001-97 (December 12, 2001) • 9
2001/2002 General Rate Application – Phases I and II                          ATCO Pipelines South


ATCO expressed concern with Calgary’s apparent incorrect use of data provided in Information
Responses dealing with system looping to serve growth in Strathmore and Chestermere. ATCO
pointed out that, in the Responses, the Company provided the maximum delivery capacity at the
Maximum Allowable Operating Pressure, while at the same time indicating that the normal
minimum pressure, which is lower than that for which the information was requested, is the
pressure at which the designs are based in order to ensure that adequate flow capacity exists at
minimum conditions to meet downstream requirements. Accordingly, ATCO also submitted that
Calgary had misinterpreted the load information, pointing out that Calgary’s forecast load
calculations were flawed and should not be considered.

ATCO pointed out that the forecast with respect to the Valley Ridge project was based on a
capacity for a 3km, 88 mm pipeline. However, ATCO stated that a pipeline double the length
and capacity of the original is now being proposed due to landowner issues in the area. ATCO
noted that the pipeline is now anticipated to cost $1.3 million, which is $800,000 more than the
amount included in the 2001 forecast. However, in accordance with the principles of prospective
ratemaking, ATCO has not requested an increase in the forecast.

ATCO also pointed out that the decision to defer approximately $400,000 of general
improvements on the looping projects from 2000 to 2001 was made to ensure that all
expenditures were completed prudently (vault replacements, odorization equipment
standardization and compressor greenhouse gas improvements). ATCO note that the work is now
being completed in 2001, and in the interests of prospective ratemaking, has not been included in
the 2001 forecast.

Referring to the MI’s concern that AGS customers are essentially backstopping risks taken by
the Company during the 10-year exclusive transportation agreement between APS and AGS,
ATCO noted that the risk noted by the MI is that the current investment policy for I/P customers
ensures that customer specific facilities are covered during the initial contract term but no
mainline costs are covered unless that customer continues to flow past the initial term. ATCO
noted that the MI suggests that the Company should move towards a primary and secondary
contract term to ensure that transportation customers cover all their costs.

ATCO pointed out that, as the 10-year agreement terminates six years after the test years of this
GRA, the term is not sufficient to remove the risk of stranded assets for AGS customers after
2008. ATCO considered that it could be argued that I/P customers will be backstopping AGS
customer risk long term. ATCO submitted that, in any case, the I/P Settlement approved in
Decision 2001-53 remains effective until December 31, 2002, after which time, changes to the
investment policy could be entertained.

ATCO submitted that Calgary’s submission that forecast rate base additions cannot be approved
until the affiliate hearing is complete is unfounded, and referred to the AGS charges to the
Company of cost plus 30% for any work completed. ATCO noted that some of this work is
directly charged to capital projects, typically involving welding, heavy trucking, land
administration and printing of work order documents. ATCO submitted that the only question at
issue for the Affiliate proceeding may be the appropriateness of the rate charged by AGS (i.e.
cost + 30%), noting that minor changes to this rate would be immaterial to the ATCO


10 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


Application. ATCO stated that the only issue to be dealt with is the reasonableness of the
Company’s forecasts, and the requirement to complete the identified projects. ATCO submitted
that, as indicated previously, the test year forecasts are conservative, given the increased
expenditures now currently known, and that the City’s request should be denied.

ATCO noted that PICA considered that there is no longer any competitive need for ATCO to
build new, regulated lateral services, taking this position based upon the fact that ATCO’s
principal competitor, NGTL no longer builds regulated laterals. However, ATCO’s investment
policy requires a new Industrial or Producer customer to contract for a sufficient term so that
their revenue over the term of their contract covers the cost of facilities built to provide them
with service. ATCO stated therefore that, as core customers are not at risk of paying for
industrial or producer laterals and the producers are supportive of ATCO Pipelines policy to
build laterals, there is no reason for ATCO to discontinue such service.

ATCO noted that PICA suggests changing the current ATCO Pipelines investment policy with
respect to new Industrial or Producer customers. ATCO pointed out that this long-standing
investment policy is one factor that helps ATCO attract new industrial and producer customers in
the ever increasingly competitive gas business.

In this regard, ATCO noted PICA’s comment that:

        In general, PICA accepts the principle all customers of APS are better off if
        existing industrial or producer customers continue to contribute some revenue to
        APS than if they leave the system and no longer contribute any revenues.

ATCO submitted that there is a balance here, i.e. the risk of foregoing increased I/P revenues
with an uncompetitive investment policy versus the risk of stranded assets should I/P customers
leave the system after their original contract term with the current investment policy. ATCO
submitted that PICA is only concerned with the latter risk when both need to be considered
simultaneously.

ATCO provided details of its approved investment policy for industrial and producer customers,
paraphrased as follows:

        Customer Specific Facilities – APS will invest a maximum of the present value of
        revenue received from the contract demand over the term for which the customer
        signs.

        Mainline Facilities – APS will invest in these facilities without customer
        contribution subject to the “don’t be silly test” described by witness Belsheim
        (Tr. p.716, line 23).

ATCO also provided details of its investment policy for AGS within the Transportation Service
Agreement between AGS and APS, an excerpt of which is noted below:




                                                       EUB Decision 2001-97 (December 12, 2001) • 11
2001/2002 General Rate Application – Phases I and II                             ATCO Pipelines South


        Where ATCO Gas’ request to maintain service to existing customers or to provide
        service to new customers requires improvements to the existing APS facilities,
        APS will make these improvements without contribution from ATCO Gas except
        in unique circumstances [e.g. uneconomic extension of facilities].

ATCO noted that PICA had concerns with the investment policy for I/P customers.
Firstly, PICA was concerned that the investment policy for customer specific facilities
will only cover costs of that specific facility and will not see the customer contributing
towards mainline facilities used if they decontract after the initial contract term. ATCO
pointed out I/P shippers extend service past the initial term and that the investment policy
must encourage I/Ps to sign up with the Company in the first place. ATCO noted that
PICA agreed that a punitive investment policy would reduce I/P volumes, which in the
long run are good for everyone. ATCO submitted that the approved investment policy for
I/P customer specific facilities is appropriate.

ATCO noted that PICA expressed concern with the investment test applicable for new mainline
facilities required for I/P customer volumes, taking the position that a comprehensive formal test
should be established to avoid danger of discriminatory treatment. ATCO pointed out that the
current investment policy for mainline facilities is virtually the same for ATCO Gas and I/P
customers. All parties are treated equally.

Positions of the Interveners
CCA
The CCA expressed concern that ATCO has attempted to bolster its capital expenditure forecasts
by referring to projects which may come on stream in 2002, and submitted that capital
expenditures should be formally included in the forecast, rather than simply alluded to during the
hearing process.

Acknowledging ATCO’s position on projects deferred from 2000 and 2001, the CCA noted that
it is equally likely that projects forecast for 2002 will be deferred into 2003, and pointed out that
these deferrals result from simple over-forecasting or changes in economic or other conditions.
The CCA submitted that, since it is in the interest of utilities to over-forecast capital additions to
increase rates of return, the AEUB represents the only check to prevent this.

Calgary
Calgary expressed concern with forecast capital additions on the Strathmore, Chestermere and
Valley Ridge projects, which are part of the expansion of ATCO’s pipeline system undertaken in
response to directions by its affiliate, ATCO Gas South.

With respect to the Strathmore project, Calgary noted that the planned construction is designed
to serve a load of 32,700 GJ/d, which, even with high forecast growth rates, will be
approximately three times the forecast winter 2004/2005 demand of 11,000 GJ/d. Calgary
calculated that, based on a 4% compound growth rate, it will require 32 years from the forecast
2000/2001 forecast demand to fill the capacity of the proposed expansion. Calgary submitted


12 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                             ATCO Pipelines South


that, without detailed substantiation, it is difficult to conclude on the reasonableness of this
proposed expansion.

Calgary expressed similar concerns about the Chestermere and Valley Ridge projects, submitting
that the proposed expansions respectively provide four times and almost three times the capacity
required 20 years from now.

With respect to ATCO’s attempt to justify and explain its forecasting accuracy, Calgary agreed
with the MI’s position regarding capital forecasting. In addition, Calgary submitted that it is
fallacy for ATCO (and AGS) to attempt to defer review of its forecasts through the simple
assertion that the forecast is the “best information at the time of filing”. In Calgary’s view,
determining what is the “best information” is the responsibility of the Board, not the Applicant,
and in making that determination, the Board (and interveners) are entitled to all relevant data.
Calgary considered that such data could include information in existence before filing of the
Application (such as earlier forecasts), and information that came into existence after filing of
the Application, and stated that the filing of an application should in no way restrict the
information available to the Board.

Calgary submitted that, with respect to the affiliate costs capitalized, since ATCO has not
quantified such amounts, the rate base additions as requested cannot be approved until the
Affiliate hearing is complete, and such amounts have been quantified and adjusted.

MI
The MI expressed the view that CWNG, the predecessor of ATCO has a long history of over-
forecasting capital expenditures in test years, and cited comments of interveners from the
1997/98 CWNG GRA to support this view. To illustrate the extent to which this trend has
continued, the MI provided a table demonstrating that the forecast expenditures reflected in the
Application for 1999 and 2000 were in excess of actual expenditures subsequently filed for those
years by 33% and 18.3% respectively.

The MI considered that this forecasting bias translates into an inflated rate base, and related
return, taxes and depreciation, and suggested that ATCO had not met its burden of proof.
Accordingly, the MI submitted that, based on the experience in recent test years, capital
additions should conservatively be reduced by 10% in each test year. The MI pointed out that, as
detailed on the table referred to above, actual expenditure for 2000 was $1.99 million less than
forecast. The MI submitted therefore, that the opening balance of Property, Plant and Equipment
for 2001 should be reduced by that amount.

The MI noted that expenditures of $1.05 million on the Strathmore Branch Loop, the Bragg
Creek Extension and the Dewinton Branch Loop, earmarked for 2000, were largely deferred to
2001 due to land acquisition problems, with the result that the expenditure will be shifted to
2001. The MI considered this an example of updated information that ATCO should have been
aware of when the Application was filed. On the other hand, the MI noted ATCO’s comment that
the 2002 forecast expenditure for Rockyview Branch Looping project will be deferred until after
2002. The MI referred to a similar scenario with respect to expenditures on general transmission


                                                         EUB Decision 2001-97 (December 12, 2001) • 13
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


improvements, where an amount of only $293,000 was expended out of a total of $714,000
forecast for 2000.

Referring to the 2001 forecast of $1 million on the Crowsnest Lake Replacement, ATCO had
considered that there is a reasonable probability that the project may be cancelled, since the
largest customer shut down operations during the winter and the Company did not proceed with
the replacement. The MI submitted that, while the Company is trying to ascertain whether or not
the customer plans to stay in full production, it would be highly imprudent to incur an
expenditure of $1 million to replace this transmission line without extending the duration of the
firm service delivery contract to cover the additional costs of serving this customer. The MI
submitted that a significant customer contribution may be the only way to provide real assurance
that core customers will not bear this stranded cost, given the circumstances of the 10-year
agreement with ATCO Gas, and related residual ratemaking practices.

The MI submitted that, based on actual expenditures and a historical record of over-forecasting,
capital expenditure should be reduced by $1.99 million in 2000, and by 10% in each of 2001 and
2002. The MI provided a table supporting the 10% reduction for the test years, and
acknowledged that these reductions were proposed recognizing that expenditures of $922,000 for
the Strathmore and Dewinton Branch Loops and the Bragg Creek Extension had been deferred
from 2000 to 2001.

Despite ATCO’s characterization of the internal approval process for capital expenditures as a
very rigorous process undertaken for all additions and improvements, the MI considered the
1999 and 2000 forecasts proved extremely ambitious, even after taking into consideration the
deferrals of the Strathmore, Bragg Creek and Dewinton looping projects totaling some
$1 million. The MI concluded that the process is intended to ensure that shareholders are
protected.

The MI noted ATCO’s justification of 2000 under-expenditures by suggesting that these projects
will be completed in 2001, and that the Company has not requested an increase in the 2001
forecast, in the interest of prospective ratemaking. The MI submitted nevertheless, that based on
the best information available at the time of the hearing, the 2000 closing balance of property,
plant and equipment should be reduced by $1.99 million to reflect actual expenditures in 2000.

The MI argued that the looping projects, completed in 2001, should only be reflected in the 2001
closing balance, and not in both the opening and closing balances.6 The MI submitted however,
that, in addition to deferring these projects, there should also be a 10% reduction in forecast
expenditures to reflect the long-term, persistent and disturbing trend of over-forecasting which
dates back to at least 1989.

In conclusion, the MI submitted that, after giving effect to the deferral of projects to 2001, there
should be a further 10% reduction to the forecast expenditures based on the historical over-
forecasting trend, known cancellations, changes in scope and significant uncertainty surrounding
certain projects.

        6
            Argument p. 8

14 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South




The MI noted that ATCO expanded the east and south mains in 1999 and 2000 to enable delivery
of additional volumes of producer firm service to TransCanada Transmission (TCT), at a total
cost of $6.1 million, including costs of meter stations, installation of compressors and purchase
of the Monarch compressors from TCT. While ATCO was required to sign a contract with TCT
for a one-year primary term plus a three-year secondary term, the MI noted that ATCO only
required a one-year term for the majority (85%-90%) of the large volumes from its transmission
customers.

The MI indicated that these arrangements were of particular concern, given the residual pricing
methods used to determine the transmission charges for ATCO Gas South. Referring to
comments made by a witness for the Company, that AGS will “provide support [to APS] during
the early years” the MI considered that this indicated that AGS will essentially backstop the risks
taken by APS during the term of 10-year exclusive agreement between AGS and APS. The MI
submitted that ATCO should be required to obtain commitments from new transportation
customers that are at least equivalent to the standards of ATCO’s main competitor, or
alternatively, ensure that the industrials and producers collectively are charged tariffs that
recover their transmission costs.

PICA
PICA considered that the 10-year exclusive transportation agreement between APS and AGS
eliminates APS’s risk with respect to core customers, and indicated that as long as monopoly
protection is offered to ATCO through its exclusive contract with AGS, it results in significant
reduction or elimination of APS’s risk with respect to that portion of its transmission business.

PICA acknowledged that there is an unbundling proceeding underway and that there will be a
proceeding regarding the sale of ATCO Gas’ retail function yet to come.

PICA anticipated participating in all those proceedings and advancing these same views in each.

PICA submitted that ATCO’s I/P tariffs are designed to cover primarily the system costs (i.e.
costs shared by all customers). PICA considered that, if ATCO invests in customer specific
facilities to a level equivalent to the revenue during the contract period, contract revenue would
only pay for ATCO’s investment in customer facilities and there would be no payment towards
system costs during the contract period. In other words, PICA considered that I/P customers
would receive a free ride on either system costs or customer facilities costs during the contract
period, meaning that core customer rates would have to rise to cover the amount not recovered
from I/P customers.

PICA submitted that every I/P customer must pay at least its long run marginal cost of service,
including the customer and system components, to avoid a burden on core customers, and
expressed concern, like the MI, that ATCO’s investment policy does not recognize and mitigate
cost recovery risks associated with certain higher risk I/P customers. PICA expressed concern
with the degree of customer specificity implicit in what may be classified as system costs when
new customer or load additions take place. For example, although system facilities are
depreciated over 40 years, some facilities may be stranded if there is sufficient uncertainty with

                                                       EUB Decision 2001-97 (December 12, 2001) • 15
2001/2002 General Rate Application – Phases I and II                                      ATCO Pipelines South


respect to the revenue stream, and these facilities may not necessarily be required to serve other
customers.

PICA considered that there is no mechanism in place for recognizing different risk profiles of
revenue streams associated with different I/P customers, and recommended that system facility
additions or upgrades be classified as system facilities and paid for by all customers only if there
will be a reasonable match between annual costs of the facilities and corresponding recoveries.
PICA expressed the view that, if the level of projected revenues associated with system additions
or upgrades would result in higher costs to current or future core customers, contributions should
be required to offset those costs.

Views of the Board
The Board notes the MI’s submission that capital expenditure forecasts have exceeded actual
expenditures for 1999 and 2000 by 33% and 18% respectively. The Board also notes ATCO’s
position that the variance for 2000 is distorted given that the forecast for that year included
expenditures of $1.45 million on projects that did not proceed. The Board acknowledges
ATCO’s submission that, when this amount is eliminated from the forecast, the variance for
2000 is only 4.95%, but does not agree with ATCO’s comment that the 1999 variance should be
ignored since there was no discussion on 1999 data during the proceeding. In the Board’s view,
the variances for both years are relevant, and even after adjusting for the expenditure deferred
from the year 2000, the average under-expenditure for 1999 and 2000 is approximately 19%.

The Board agrees, therefore, with the MI and other interveners, that historical experience
indicates a trend towards over-forecasting, which, when projected to the test years, translates into
an inflated rate base and related return. However, the Board is not persuaded that a reduction in
the 10% range as proposed by the MI is justified. The Board considers that a smaller reduction
would be more appropriate, and that recognition should be given to ATCO’s submission that the
projects deferred from one year are likely to be undertaken in a later year, although not included
in the forecast for that year.

Accordingly, the Board directs ATCO to reduce the forecasts for capital additions by 3% in 2001
and 5% in 2002.

The Board also agrees with the MI’s observation that, since year 2000 actual expenditure was
$1.99 million less than forecast, the opening balance of Property, Plant and Equipment for the
2001 test year should be reduced by that amount. In reaching this conclusion, the Board
considered the findings in Decisions U970657 dated October 31, 1997, and E890918 dated
December 15, 1989, where the forecasts of TransAlta Utilities Corporation (TransAlta) and
ATCO Electric Ltd. (AE) were found to be deficient to the extent that actual information that
became available during the course of the proceedings was not used. In those Decisions, the

        7
           Decision U97065 Alberta Power Limited, Edmonton Power Inc., TransAlta Utilities Corporation and
Grid Company of Alberta, 1996 Electric Tariff Application
         8
           Decision E89091 TransAlta Utilities Corporation, In the Matter of a Filing by TransAlta Utilities
Corporation, Pursuant to a Direction of the Public Utilities Board in Order C88027 dated November 14, 1988, for an
Order or Orders Fixing New Rates, Charges or Schedules Thereof for Electric Light, Power or Energy Furnished by
TransAlta Utilities Corporation to and for the Public in Alberta During the years 1988, 1989 and 1990

16 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


Board concluded that the use of forecast data distorted the opening balances for the test period,
when actual results were available.

Accordingly, the Board directs ATCO to reduce the 2001 test year opening balance of Property,
Plant and Equipment by $1.99 million to recognize actual expenditure in the year 2000.

The Board notes the MI’s concern that there is a reasonable probability that the Crowsnest Lake
Replacement project may be cancelled, and that, under the circumstances, a significant customer
contribution may be the only way to provide real assurance that core customers will not bear this
stranded cost. The Board also notes the MI’s reference to arrangements to enable delivery of
additional volumes to TCT, whereby ATCO had to enter into a contract with TCT for an initial
one year term plus an additional three year term, but only required a one year term commitment
from transmission customers. The Board notes the MI’s concern that, given the residual pricing
arrangement with ATCO Gas South, ATCO Gas South customers will be required to backstop
any related risks during the term of the 10-year agreement between ATCO Pipelines South and
ATCO Gas South.

The Board also notes PICA’s related comments with respect to ATCO’s investment policy for
I/P customers, which does not envisage the customer contributing towards the costs of mainline
facilities used if that customer decontracts after the initial contract term. The Board notes that
PICA proposed establishment of a comprehensive formal investment test for mainline facilities
serving I/P volumes, to avoid discriminatory treatment of core customers.

However, the Board acknowledges ATCO’s position on the issue of the Company’s investment
policy for customer specific facilities and for mainline facilities. Specifically, ATCO points out
that for customer specific facilities, the Company will invest a maximum of the present value of
revenue received from the contract demand over the term for which the customer contracts. The
Company will invest in mainline facilities without customer contribution, subject to the “don’t be
silly rule” stated by Mr. Belsheim for the Company. This rule envisages that, if there are
insufficient reserves from an area, the Company will not install intensive mainline just because
the customer requests it. The Board also notes ATCO’s submission that the investment policy
extends to service requested by ATCO Gas South, and notes that ATCO pointed out that where
AGS’s request to maintain service or provide service to new customers requires improvements to
existing facilities, the Company will make those improvements without contribution from AGS
except in unique circumstances, such as uneconomic extension of facilities.

The Board agrees with ATCO that a punitive investment policy would discourage customers
extending service past the initial term, and would reduce I/P volumes, which in the long run are
of benefit to all customers. The Board agrees that the risk of stranded assets, should I/P
customers leave the system, has to be weighed against the risk of foregoing increased I/P
volumes with an uncompetitive investment policy. The Board also agrees with ATCO that the
current investment policy for mainline facilities is virtually the same for ATCO Gas South
volumes and I/P customers.

In conclusion, the Board does not see the need to amend or revise ATCO’s existing investment
policy with respect to either customer specific or mainline facilities, and does not accept PICA’s


                                                       EUB Decision 2001-97 (December 12, 2001) • 17
2001/2002 General Rate Application – Phases I and II                          ATCO Pipelines South


proposals in this regard, or the MI’s recommendation for a customer contribution with respect to
the Crowsnest Lake Replacement.

The Board notes Calgary’s submission that Rate Base additions cannot be approved until the
Affiliate hearing is complete and all relevant amounts are quantified and adjusted. However, the
Board agrees with ATCO that the only question at issue for the Affiliate proceeding may be the
mark-up rates charged to the Company by ATCO Gas South and included in costs charged to
capital projects. The Board agrees that any adjustments to the mark-up arising from the Affiliate
proceeding would likely not be material.

3.3     Support for Capital Projects
Position of ATCO
ATCO strongly disagreed with the CCA’s general claims that insufficient detail has been
provided with respect to capital projects, and that the Company has not addressed Board
Direction #16 from Decision 2000-9, which required the Applicant to provide sufficient
information for all major capital projects to enable the Board and interveners to assess the need
for the projects. ATCO pointed out that detailed information on all major projects was provided
in the Application and in response to information requests. ATCO stated that the Board’s
direction was specific to major projects in excess of $500,000 in value. ATCO provided
examples of the type of information provided, including the comment that in many cases, there is
no realistic alternative, particularly where service would be lost due to insufficient capacity.

ATCO noted that the CCA also attempted to imply that the Company must complete projects as
requested by AGS, and selectively referenced one page of the transcript in isolation, choosing to
ignore relevant references making it clear that ATCO questions AGS on requirements and
facilities. ATCO pointed out that this equates to the “don’t be silly rule” mentioned frequently in
testimony. ATCO also took issue with the CCA’s statement that IGCAA members do not have
the ability to request capital projects. ATCO indicated that IGCAA does not request capital
improvements on behalf of its members, but it is those members who request service on the
ATCO system, resulting in the requirement for improvements to existing facilities. ATCO
submitted that the attempt by the CCA to cloud the issue of project justification should be
ignored and that the request for a 50% reduction in capital expenditures should be rejected.

Positions of the Interveners
CCA
The CCA referred to the direction of the Board in Decision 2000-9 that, for major capital
projects, the Company needs to provide sufficient information to help the Board and interveners
assess the need for the projects, and noted the acknowledgement of ATCO during the hearing,
that the Company is obligated to Board directions from previous CWNG Decisions. While
acknowledging that the Company provided limited demand, energy and supply information for
some projects in information responses, the CCA considered that the information fails to
demonstrate project need as there is no comparison of demand and energy needs against demand
and energy supply. Furthermore, the CCA submitted that no information essential for the review
of project requirement has been provided, such as forecasts of increased customers, effects of
reduced consumption, changes in demand, or breakdown of proposed costs. The CCA concluded

18 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


that options considered by ATCO were provided in a manner which provides very little detail
about those options and their economics. In short, the CCA considered that need for the projects
was not proven by ATCO.

In the CCA’s view, it is insufficient for ATCO to suggest that a project needs to go ahead to
address a requirement by ATCO Gas South. The CCA considered that the courtesy ATCO
extends to AGS is not extended to other customers, noting that the witness for IGCAA stated that
IGCAA members do not have the ability to request capital projects. On the basis of the lack of
information to justify expenditure on capital projects, the CCA submitted that the revenue
requirement for capital additions be reduced by 50 per cent.

The CCA supported each of Calgary’s recommendations resulting from the review of
information services and customer accounting functions.

Calgary
In Calgary’s view, ATCO, in common with AGS, has not complied with the directions in
Decision 2000-9 with respect to capital expenditures. Calgary considered that there were two
problems with ATCO’s assertion that the project justification, large or small, is written on the
work order. Calgary argued that, in the first instance, the Board expected the Company to
provide additional information “in sufficient detail, in all future filings”, and secondly, the
Company’s assertion is simply not true, since the work orders in question do not provide the
detail required in Decision 2000-9. Calgary submitted that the Board needs to once again remind
ATCO of the expectations articulated in Decision 2000-9, and consider any application in future
GRA filings to be incomplete if such information is not provided.

Calgary pointed out ATCO’s contradictory position on the philosophy of “prospective
ratemaking” which, on the one hand is used to limit the information available, and on the other
hand seeks to enter into evidence, late breaking and unsubstantiated information regarding the
possibility that Calpine and AES power plants could increase capital expenditure over forecast.
Calgary pointed out that, in Decision 2000-9, the Board considered and rejected CWNG’s
assertion that the Board only approves a capital forecast in general, and submitted that, if ATCO
wishes the Board to consider possible capital costs with respect to the Calpine and AES facilities,
the Company should bring evidence forward that the facilities will be used and useful. Calgary
considered that, without any such evidence, the Board should reject the Company’s speculative
submissions.

Views of the Board
The Board acknowledges the concerns of interveners with respect to the Company’s compliance
with the direction in Decision 2000-9, that for major capital projects, ATCO should provide
sufficient information to enable the Board and interveners to assess the need for the projects.
However, the Board notes that ATCO did provide a description of the projects and related
information in the Application, in response to Information Requests and in Undertakings
throughout the proceeding.




                                                       EUB Decision 2001-97 (December 12, 2001) • 19
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


While the Board considers that ATCO could have provided more detail with respect to projects
the Board does not consider that failure to comply justifies the type of general reduction in
capital expenditure forecasts suggested by the interveners, particularly since, in this Section of
the Decision, the Board has already directed ATCO to reduce capital additions by 3% (2001) and
5% (2002).

In future rate applications, the Board will require more detailed information from ATCO for all
major capital projects, in accordance with the Board’s direction in Decision 2000-9, as follows:

      •   a detailed justification including demand, energy and supply information;
      •   a breakdown of the project cost;
      •   the options considered and their economics; and
      •   the need for the project.

3.4       UFG Meters
Position of ATCO
ATCO stressed the importance of the installation of UFG meters as the definitive method of
establishing fair and reasonable UFG levels for ATCO Gas and ATCO Pipelines, pointing out
that the equipment will measure delivered volumes from ATCO Pipelines and receipt volumes
for ATCO Gas. ATCO stated that the meters will allow both businesses to identify areas for
improvement to reduce UFG on their respective systems.

ATCO noted that, while both PICA and the IGCAA agree that the proposed UFG meters are
required, they consider that cost accountability is an issue. ATCO pointed out that the issue of
cost accountability is dealt with in the context of the overall discussion on UFG. UFG costs are
addressed in Section 6.5 and Section 8 of this Decision.

ATCO considered that the statements of the CCA with respect to the proposed installation of
UFG meters are contradictory. Specifically, ATCO referred to the CCA’s comment that the
Company provided no cost benefit analysis for the proposal, while on the other hand suggesting
that ATCO’s cost benefit analysis is flawed due to the Company’s assumptions about gas prices
during the test years. ATCO stated that the Company did indeed prepare a cost benefit analysis,
incorporating gas price forecasts based on price levels prevailing at the time the forecast was
prepared, and considered that the CCA’s observation about forecast prices was easy to make in
hindsight.

Referring to the CCA’s comment that the meters are not required, ATCO acknowledged that the
meters are not yet in use, and agreed that an allocation method is required on an interim basis.
ATCO stated however, that the long-term solution is installation of meters, which will provide
absolute and definitive UFG levels for the Company and AGS.

With respect to the statements of Calgary and AIPA that the request to install additional meters
should be denied, ATCO stated that, since the statements were made without any foundation
whatsoever, the Board should disregard them.



20 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                             ATCO Pipelines South


ATCO noted that the MI appeared to question only the installation of meters at farm tap
locations (2002 expenditure) and not the gate station meters in 2001. The MI’s concern appeared
to be the need for the Company to justify why the retail farm tap meter readings are inadequate.
ATCO indicated that it proposed meters at only the largest flow taps, representing approximately
32% of the total, which will provide data that could result in an impact to UFG levels. ATCO
considered that it has been prudent in selecting only those locations that could significantly
impact UFG levels. ATCO submitted that the Board should deny the MI’s request not to proceed
with the farm tap installations in 2002.

ATCO referred to the questions raised by some interveners about the ongoing O&M expenses for
the meters to be installed and indicated that the assumptions used by the interveners are flawed,
as all assumptions appear to be based on the incorrect conclusion that ATCO owns the entire
regulating facility, which is not the case. ATCO pointed out that the Company owns only the
meter, while AGS owns the regulating facility, and submitted that the only incremental O&M
expense will be for meter inspections, commencing in 2003.

ATCO referred to cross-examination by Mr. Roth, where Mr. Johnson stated that:

        … I guess we are even more confused with the metering issue now when we read
        the Memorandum of Association [sic] with the FGA’s or Gas Alberta where
        ATCO Pipe seems to be prepared to allow them to use their meters for purposes
        of determining volumes, but they are not prepared to use their associate ATCO
        Gas’s meters for purposes of determining volumes.9

ATCO considered that it is evident from this statement that Mr. Johnson does not realize that
APS delivers volumes to 77 locations for Gas Alberta, who in turn delivers volumes through its
system to end-use customers. It is the metering at the 77 interconnect locations between ATCO
and Gas Alberta that is used as the delivery volume, not the downstream/distribution metered
volume. ATCO stated that the meters, to which Mr. Johnson refers on AGS, consist of
approximately 400,000 meters in the distribution system. ATCO indicated that the installation of
the proposed 667 meters would be comparable to the 77 Gas Alberta meters, which are clearly
identified in the Gas Alberta Memorandum of Understanding (MOU).

ATCO considered that each intervenor developed differing arguments on allocating the costs of
meter installations. The IGCAA believes that the core should bear the costs. The MI believes the
costs should be shared amongst all customers. PICA submits that those customers given the
benefit should bear the costs.

ATCO submitted that, notwithstanding the argument of these Interveners, all customers will
derive a benefit from the installation of the meters. In this regard, ATCO stated:

        •     First, the installation of the meters will allow each of APS and AGS to review their
              respective systems to identify areas of improvement to reduce UFG levels in their
              respective systems. Without the metering, this would not be possible.

        9
            Tr., pp. 1544-1545

                                                         EUB Decision 2001-97 (December 12, 2001) • 21
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


        •   Secondly, metering will eliminate the cross-subsidization that currently exists under
            the blended UFG rate. Each customer class will contribute equitably.
        •   Lastly, with the appropriate UFG rates, the potential for industrial bypass will be
            mitigated.

Given that all customers will benefit to some degree, ATCO recommended that the meter
installation be allocated as outlined by it.

Positions of the Interveners
CCA
With respect to the forecast expenditure on UFG meters, the CCA expressed concern that,
despite intervener requests, ATCO provided no cost benefit analysis but instead merely indicated
that the metering will provide identification of the unique UFG quantities for the distribution and
transmission systems.

The CCA noted that ATCO indicated that an appropriate UFG rate is required to ensure the
ongoing competitiveness of the pipeline system, and noted ATCO’s concern that, without
establishing an appropriate UFG rate, the Company’s largest industrial customer might be lost.

The CCA also noted ATCO’s comment that the installation of meter stations will allow better
analysis to improve the level of UFG, providing an example assuming a 10% reduction of
forecast UFG level for 2001 and a $7.50/GJ gas price would result in savings of $1.57 million in
annual savings for the distribution and pipeline division.

The CCA however, disagreed with ATCO’s estimate of revenue requirement for the UFG meters
for the test years, indicating that these forecasts under-represent the future revenue requirement
amounts because of the mid-year convention for plant additions. The CCA also expressed
concern that overheads and cost allocations that are based on total plant are not included in the
analysis.

The CCA considered that the cost benefit analysis provided by ATCO is flawed in its assumption
of benefits, as gas prices are not forecast to be in the $7.50 range for either of the test years, and
submitted that there may be no benefits to the metering. The CCA expressed concern that the
costs to core customers are high if they are allocated or assigned 100% of the meters, and
considered that the benefits of the metering, if any will be unlikely to accrue to core customers.

The CCA considered that the UFG meters are not used or required for use, and that the issue can
be handled by an allocation process.

PICA
PICA considered that, while the installation of the new UFG meters represents the largest
individual expenditure in each test year, it is not at all clear how this new equipment will be of
any benefit to customers served from the ATCO Gas system. PICA reluctantly agreed that, given
the division of the utility into separate transmission and distribution businesses, there should be
no argument about the need for the expenditure, but questioned the responsibility for the costs. In

22 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


this regard, PICA submitted that cost responsibility should rest with the customers who are
requesting, and stand to benefit from, the investment, namely industrial and producer customers
of ATCO.

PICA noted IGCAA’s position that recovering the costs of the interconnect metering between
APS and AGS as general assets would be discriminatory to industrial customers served directly
from APS who already pay for the costs of the retail meters required for measurement of
consumption at their individual plants.10 According to PICA, this position ignores the fact all
customers of AGS already fully pay for the costs of their retail meters through the rates they pay
for retail service. PICA submitted that actually IGCAA’s proposal would be discriminatory since
it would require AGS customers to pay for two sets of meters. PICA submitted a better case
could be made for the costs of the interconnect metering to be borne by IGCAA customers, given
they are the ones requesting the interim change in the method of calculating UFG and ultimately
expecting to benefit from the reduction in UFG resulting from the installation of such additional
metering.

Calgary
Referring to the forecast expenditure of approximately $9.6 million on metering equipment to
more accurately measure UFG, Calgary submitted that, before ATCO fully commits to this
expensive endeavour, the Company should meet with customers to determine if an agreement
can be reached with respect to the appropriate levels of UFG based on industry and ATCO data.

As Calgary understands it, some of the proposed meters are meter interconnects between APS
and AGS, while the balance are meters at line and farm taps for which AGS already has meters
in place. Calgary submitted that, remarkably, APS wants to install its own meters in these
locations, presumably to provide metering independently of AGS, while its Memorandum of
Agreement with the FGA allows them to do their own metering and provide the data to APS.11

Calgary pointed out that IGCAA noted the problems with the ATCO evidence with respect to the
calibration of AGS’ meters, yet went on to use the raw numbers of AGS meters to suggest that
most UFG should be allocated to AGS. Calgary agreed with IGCAA that the contribution to
UFG of the AGS meter calibration is somewhat uncertain. In Calgary’s view, even if new
meters, and serviced or replaced meters, are deliberately under-calibrated, that only encompasses
a very small proportion of the hundreds of thousands of meters that AGS has in service and
would not explain a significant portion of UFG. Calgary noted that the ATCO evidence is that
once the meters are in service they “may” speed up and tend toward zero (or neutral).12 Meters,
as measurement devices, are regulated under the Electric and Gas Inspection Act and the Electric
and Gas Inspection Regulation. Calgary saw no evidence that the guidelines under those
statutory provisions provide for a metering “bias” and believed that meter accuracy, as a whole,
would be required to fit into a range around zero (neutral). Consequently, most meters should be
ranging around zero, and the contribution of any negatively “biased” sample should be
negligible.

        10
           IGCAA Argument, paragraph. 28-30
        11
           Volume 7, p. 1544
        12
            Tr. Volume 6, pp.1236–1238

                                                       EUB Decision 2001-97 (December 12, 2001) • 23
2001/2002 General Rate Application – Phases I and II                          ATCO Pipelines South




MI
Acknowledging ATCO’s statement that the definitive method of establishing fair and reasonable
UFG levels for AGS is the installation of custody meters, the MI considered that there appeared
to be a total disregard for the costs involved in achieving this goal. In the MI’s view, ATCO
appears too eager to accommodate the I/P customers, which is inappropriate given IGCAA’s
position that AGS customers should bear the cost associated with interconnect metering. The MI
expressed concern that AGS customers were not party to the final I/P negotiations, agreed with
other AGS customers that this expenditure has not been justified, and strongly opposed any
suggestion that the capital and operating costs be allocated to AGS customers.

The MI noted that IGCAA was the only party supporting ATCO’s UFG proposal, and that
IGCAA went further, by recommending a more favourable solution to IGCAA, using a ratio of
3:1 for distribution vs. transmission allocation of UFG.

The MI submitted that it would be totally unfair to allocate all costs to AGS customers when this
measure is being taken to appease the industrial customers.

AIPA
AIPA referred to ATCO’s proposal for a significant upgrade to metering at the interface between
APS and AGS, as a result of the restructuring of the distribution and pipeline components. AIPA
noted that this proposal would extend to installing meters on mains that provide connections to
services metered individually, such as farm services.

AIPA submitted that such additional custody transfer measurement at costs of $4.87 million for
2001 and $4.63 million for 2002 is extravagant, and only serves to increase rate base and rates to
all customers while providing minimal benefits, if any, to customers who will in effect be double
metered. AIPA pointed out that customers will be metered once at the end use site, and again at
the feeder by ATCO, and considered that the Company has not provided the justification for this
expenditure.

IGCAA
IGCAA believed that, given the wide variation on UFG reported in the evidence filed by ATCO
Pipelines, the only fair solution to all parties is to install metering to properly measure the
volume of gas moving to ATCO Gas. IGCAA believed that the cost of these meters should be
fully allocated to ATCO Gas through ATCO Pipelines rate structure.

IGCAA considered that the MI completely missed the fact that, as far as measurement is
concerned, loss to UFG is directly proportional to the number of customers or meters involved.
IGCAA pointed out that AGS is the largest single customer of APS, taking well over half of the
deliveries off the APS system, which are made through over 400,000 meters. On the other hand,
IGCAA noted that APS only uses 160 meters to service all of its other customers, including
producers at receipt locations. IGCCA noted that this evidence regarding relative responsibility
for UFG attributable to measurement was unchallenged by everyone, including the MI, and


24 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                   ATCO Pipelines South


submitted that regardless of the differences in calibration referred to by the MI, the vast majority
of UFG attributable to measurement is caused by ATCO Gas.

Views of the Board
The Board notes the observations of interveners with respect to the need for installation of UFG
meters. Specifically, the CCA considered that the meters are not used or required for use and that
the distribution of UFG could be handled by an allocation process. The CCA, the MI and AIPA
considered that ATCO had not justified the need for this expenditure, and Calgary questioned
why meters already on customers’ premises would not be used to determine UFG volumes. In
the Board’s view, these objections are not convincing.

The Board does believe that the UFG meters will allow both the Company and ATCO Gas South
to identify areas where reductions in UFG can be made on the respective systems. The Board is
prepared to accept ATCO’s assurance that the long-term solution appears to be the installation of
meters, which will provide absolute and definitive levels of UFG on both systems. The Board
notes that PICA and IGCAA also supported the need for this expenditure.

Accordingly, the Board accepts ATCO’s forecast of expenditure on installation of UFG meters in
the test years.

With respect to intervener positions on the allocation of the capital costs of UFG meters, the
Board notes that there were conflicting views. Specifically, IGCAA believed that responsibility
for the costs should rest with the core customers, while PICA considered that the I/P customers
should be responsible. The MI on the other hand considered that the costs should be shared
amongst all customers.

As stated above, the Board accepts ATCO’s position that all customers will derive benefit from
installation of the meters. However, while the Board agrees that the costs should be allocated
among customer classes, the appropriateness of that allocation is addressed in Section 8 of this
Decision dealing with ATCO’s COS Study.

3.5      Summary of Board Adjustments and Approved Capital Additions
The following table sets out the Board adjustments described in this Section of the Decision
made to the capital additions forecast by ATCO for the test years. As indicated in the table, the
Board will approve capital additions of $15.247 million for 2001 and $11.276 million for 2002.

                                                                             2001         2002
      Forecasts as applied for                                              $15.719      $11.869
      Less: Reductions in forecasts for:
           Over-forecasting and absence of adequate support for forecast      $0.472      $0.593
           additions
      Approved Capital Additions                                            $15.247      $11.276




                                                               EUB Decision 2001-97 (December 12, 2001) • 25
2001/2002 General Rate Application – Phases I and II                         ATCO Pipelines South


4       NECESSARY WORKING CAPITAL

Position of ATCO
ATCO requested $3,365,000 and $2,828,000 for Necessary Working Capital (NWC) for the
years 2001 and 2002 respectively.

In support of its request for NWC, ATCO filed a lead-lag study completed in 2000 using the
methods used in previous applications by CWNG. The lead-lag study calculated revenue and
expense lags by applying payment and receipt patterns expected to exist in 2002, based on the
methodology in the lead-lag study approved in Decision 2000-9.

A single average revenue lag was determined by reviewing the time lag by revenue source
between the time of service and receipt of payment for the service. These revenue lags were
calculated as the lag period between the meter reading or service month-end dates and the
payment receipt dates weighted by the amount of revenue for each source resulting in a weighted
lag of 15.49 days. An amount of 15.21 days was added this lag to account for the lag between the
point of service and meter reading or service month-end. This resulted in a total revenue lag of
30.70 days.

Expense lags were calculated for each expense category. The net lead/lag for each expense
category was the difference between the average revenue lag and the appropriate expense
payment lag. The net lag for each expense category was stated as a percentage of 365 days to
calculate the NWC component for cash and financial items.

4.1     Cash Expenses
4 .1 Operating and Maintenance Expense Lag
 .1
O&M expense lag included an analysis of monthly salaries, bi-weekly wages, and payroll
deductions, affiliate payments, insurance and other operating and maintenance expenses. For
payroll related expense lag, the pay date was used in calculating the lag. The lag for affiliate
services was calculated as the sum of the mid-point of the average month plus the average delay
from the end of the month to the settlement date on the fourth working day of the following
month when affiliate charges are reconciled. The lag for property and liability insurance and
general insurance was calculated as the difference between the mid-point of the insurance
coverage and the payment of premiums. The lag associated with other operating and
maintenance expenses was calculated as the difference between the receipt of goods or services
and the payment clearance date.

ATCO rejected Calgary’s argument that the terms and conditions of payment for affiliates,
especially ATCO Gas, should be consistent with the terms and payment for arms-length parties.
ATCO Gas argued that third parties have a credit cost built into their prices whereas ATCO
affiliates do not.

4 .2 Income Tax Expense Lag
 .1
Income tax installments are paid on the last day of each month, and therefore, the payment lag
associated with income tax was considered to be 15.21 days. The final payment for income tax is

26 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


made on the last day of February of the following year, therefore, a reduction from NWC was
calculated for the payment lag.

4 .3 Taxes Other than Income
 .1
Property taxes are paid at various times of the year. ATCO calculated the property tax lag as the
time lag between the mid-point of the annual service period (July 1) and the payment clearance
date. Franchise taxes are paid according to the requirements of the franchise agreements. The
franchise tax lag was calculated as the time lag between the mid-point of the service period and
payment clearance dates.

4 .4 Financial Items
 .1
Debt Interest
ATCO determined that debt interest lag to be 91.25 days, the arithmetic mid-point of semi-
annual interest payments.

Preferred Dividends
ATCO determined the dividend payments relating to preferred shares were determined at a lag of
45.63 days, the arithmetic mid-point of quarterly dividend payments.

Common Return
ATCO assigned the payment lag for common return (retained earnings and common dividends)
at zero lag days.

Depreciation Expense
ATCO assigned the payment lag for depreciation return a zero expense lag.

4 .5 Other Adjustments
 .1
Materials and Supplies
The NWC requirement for materials and supplies was determined by calculating the O&M
percentage allocation and then applying the allocation (39.54%) against mid-year materials and
supplies inventory.

Deferred Pension
The NWC requirement for Deferred Pension was the mid-year value of $2,094,000.

Deferred Post Retirement Benefits
ATCO reduced the NWC by $156,000 in 2001 and $275,000 in 2002 to reflect the mid-year
balance in the Deferred Post Retirement Benefits account.

Deferred Supplemental Pension
ATCO reduced the NWC requirement by $187,000 for 2001 and $314,000 for 2002 to reflect the
mid-year balance in the Deferred Supplemental Pension account.

                                                       EUB Decision 2001-97 (December 12, 2001) • 27
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South




Reserve for Injuries and Damages
ATCO reduced the NWC by $300,000 in each of 2001 and 2002 to account for the balance in the
Reserve for Injuries and Damages.

Computer Reserve Deficiency Account
ATCO increased the NWC capital to recognize the mid-year effect of the unamortized costs
related to the disposition of computer equipment sold to ATCO I-Tek.

Deferred Pension Owing by Customers
NWC requirement of $90,000 for 2001 was added to reflect the mid-year balance of Pension and
Post Retirement Adjustments of previous years.

Deferred Income Tax
ATCO reduced the NWC by $522,000 in 2001 and increased it by $125,000 in 2002 to recognize
the mid-year balances in the Deferred Income Tax account.

Deferred Restructuring Costs
ATCO increased the NWC by $206,000 in 2001 and $72,000 in 2002 to recognize the mid-year
effect of the unamortized deferred restructuring costs.

Hearing Cost Reserve
NWC was increased by $486,000 in 2001 to recognize the mid-year effect of unamortized
deferred hearing costs.

Positions of the Interveners
Calgary argued that in its view, the treatment of affiliates is not consistent with the treatment of
arms-length parties. Calgary submitted that there is no reason ATCO Gas South should be
paying ATCO Pipelines South in less than 6 days when other customers have over 20 days to
pay. In Calgary’s view, the terms and conditions of payment for affiliates should be consistent
with the terms for arms-length parties.

Views of the Board
Cash Expenses
The Board notes that ATCO’s lead/lag study incorporates a revenue lag with respect to
transactions with AGS, which the Company indicates is necessary due to the fact that both
entities have separate bank accounts through which divisional transactions are cleared. The
Board is not persuaded that there is justification for the Company to earn a return in relation to
transactions with ATCO Gas South. Accordingly, the Board directs ATCO to recalculate its
lead/lag study with application of a zero lag to transactions with ATCO Gas South.




28 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


The Board notes the different treatment between payments to affiliates and other payments in the
lead/lag study. Specifically, ATCO’s proposed expense lag for affiliate payments (excluding I-
Tek) is 20.96 days, as opposed to 34.16 days for other O&M expenses. The Board also notes that
the expense lag for payments for I-Tek services is 53.21 days. The Board considers that, for the
purposes of calculating the NWC requirement, there is no reason why the lag days for payments
to affiliates should be any less than the lag relating to payments for arms length transactions.
Accordingly, the Board directs ATCO to recalculate the NWC balance using an expense lag of
34.16 days for payments for affiliate services (excluding I-Tek).

The Board notes that ATCO applies a zero expense lag to the common dividend component of
common equity return. The Board continues to hold the view that assigning a zero expense lag to
the common dividend component of common equity return fails to take into account the payment
schedule that generally exists for the portion of equity return that may be paid out in dividends
on a periodic basis throughout the year. As indicated in Decision U97065 with respect to AE
(previously Alberta Power Limited), the Board considers it reasonable to make the assumption
that the dividend component of common equity should be treated, for working capital purposes,
in the same manner as preferred equity.

In Decision 2000-9, the Board directed ATCO to apply a zero expense lag to the retained
earnings component of common equity return and an expense lag for the common dividend
component based on the methodology used to calculate the preferred dividend lag. The Board
therefore, directs ATCO to make the appropriate adjustment to the lead/lag study to comply with
this requirement.

Other Items
The Board notes that the treatment of Deferred Pension and Benefits was not challenged by any
of the interveners. While the Board considers ATCO’s treatment of these items to be reasonable,
the Board recognizes that the issue of deferred pensions and post employment benefits will be
considered in the Pension proceeding. Accordingly, the Board will not address the quantum of
the forecasts included in NWC for deferred pension, supplemental pension and post employment
benefits pending the outcome of the Pension proceeding.

While satisfied with the treatment of the unamortized portion of the computer reserve deficiency
account in NWC, the Board recognizes that issue with respect to the accounting for the loss on
sale of computer equipment to I-Tek is being considered in the Affiliate proceeding.
Accordingly, the Board will not address the quantum of the forecasts included in NWC for the
unamortized computer reserve deficiency account pending the outcome of the Affiliate
proceeding.




                                                       EUB Decision 2001-97 (December 12, 2001) • 29
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


5       FAIR RETURN ON RATE BASE

5.1     Treatment of ATCO Gas South (AGS) and ATCO Pipelines South (APS) as
        Separate or Merged Entities
Background
ATCO applied for separate treatment of AGS’ and APS’ rate of return and capital structure. In
the most recent GRA for ATCO, the 1998 CWNG GRA, the two divisions were treated as one
entity, CWNG. The capital structure and rate of return for CWNG was established based on risks
facing that integrated entity.

Position of ATCO
ATCO stated that it was appropriate to consider the capital structures and allowed rate of return
on equity separately for AGS and APS. The principle put forward by ATCO was that the entities
should be considered on a stand-alone basis. However, ATCO also stated that no premium had
been added to its requested return above what was required for the two divisions to contribute to
the overall maintenance of the CU Inc. credit rating.

ATCO stated that it met its financing requirements with a combination of internally and
externally generated funds. Long-term external financing was obtained through CU Inc. Upon
completion of a debenture, preferred share, or common share issue by CU Inc. in the capital
markets, ATCO received its required portion of the proceeds by issuing a similar financing
instrument to CU Inc. Based on this financing process, ATCO received the funds necessary to
meet the funding requirements of its capital expenditure programs and to balance its capital
structure. In its Application, ATCO stated that using CU Inc. as a long-term financing vehicle for
its three utility subsidiaries optimized the size of public financing, and reduced the cost of market
access.

ATCO noted that both the Canadian Bond Rating Service (CBRS) and Dominion Bond Rating
Service (DBRS) had downgraded the debt ratings of CU Inc. CBRS had downgraded CU Inc.
debt from AA to AA-, in response to increased industry risk. DBRS had downgraded CU Inc.
debt from AA(low) to A(high). DBRS specifically referenced changes in the Alberta regulatory
climate that have arisen in connection with deregulation, and stated that “gas utility…operations
continue to be subject to an unfavourable regulatory environment.”13

Positions of the Interveners
Calgary
Calgary submitted in evidence that reshuffling the assets of CWNG into AGS and APS should
have no impact on either the appropriate overall capital structure or allowed rate of return. It
stated that, however, the business risk of AGS may not be the same as APS, so that the allowed
equity range should differ between the two. It stated that the critical issue was not to “over-
compensate” for business risk differences by unintentionally adjusting both the allowed return
and the common equity ratio.

        13
             AGS Application, S:3.1, p. 4

30 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South




Views of the Board
The Board agrees with Calgary that it is not appropriate to change the assessment of the relative
risk facing ATCO merely on the basis that it has restructured its business into two divisions. The
Board is of the view that the most important issue with respect to these divisions is whether or
not the business risks facing the still legally integrated entity have changed relative to previous
GRA applications.

However, having reviewed the risks of the company as a whole, the Board also agrees with
Calgary that it is appropriate to allocate the allowed return on equity between the divisions on the
basis of their relative risk. This is consistent with the past practice of the Board in other cases
involving the notional separation of previously integrated utility functions into separate
divisions. The Board is of the view that a similar approach would be appropriate in this case.

5.2     Appropriate Return on Equity for AGS and APS
Position of ATCO
For AGS, based on common equity financing rate base of 37.4% in 2001 and 39.4% in 2002,
ATCO requested a return on common equity of 11.5% for both 2001 and 2002.

For APS, based on common equity financing rate base of 45.4% in 2001 and 50.1% in 2002,
ATCO requested a return on common equity of 12.0% for both 2001 and 2002.

ATCO presented estimates of fair rate of return on common equity for 2001 and 2002 based on
an application of equity risk premium tests, discounted cash flow tests, and comparable earnings
tests. In support of its requests, evidence was filed by Ms. K. McShane, Senior Vice President of
Foster Associates Inc., who recommended a fair rate of return on common giving primary weight
to the equity risk premium and discounted cash flow tests, but also with significant weight to the
comparable earnings test.

Since AGPL is not a publicly traded company, Ms. McShane stated that its cost of equity could
not be estimated directly from capital markets, and since it does not have its own debt rating,
there was no independent market assessment of its business and financial risk. Therefore, the
determination of a fair return was made by reference to proxies that do have market data.
Ms. McShane used market data available for a sample of publicly traded utilities including data
from U.S. utilities in her evaluations.

Ms. McShane stated that the standards that set the parameters of fair return on equity necessary
to induce investment in public utility assets must provide the opportunity to attract capital on
reasonable terms; maintain its financial integrity; and earn a return on the value of its property
commensurate with that of comparable risk enterprises. She noted that during the past decade in
Canada, the comparable earnings test has effectively been replaced by the cost of attracting
capital test. Factors noted to contribute to this change were the sharp decline in inflation in 1992,
industrial restructuring, and severe recession in the early 1990’s which resulted in a significant
decline in earnings. Ms. McShane stated that these lowered earnings were unrepresentative of
future earnings, and unreliable indicators of investor expectations for future returns. On this

                                                        EUB Decision 2001-97 (December 12, 2001) • 31
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


basis, Ms. McShane stated that the results of the comparable earnings test were of limited
reliability. She stated that the same factors had a similar effect on the discounted cash flow test.

Ms. McShane stated that with the shift in reliance onto the equity risk premium test, the
approved returns of utilities in Canada were tied almost exclusively to interest rates, which had
declined between 1992 and 1999. Approved returns can be broken into the real cost of capital,
compensation for inflation and equity risk premium components. The effective risk premium
declined by close to 2% since the risk premium test become the sole methodology relied upon in
the mid-90’s. She noted that with declining inflation and interest rates, and a strong economy,
earnings of competitive firms have rebounded from the early 1990’s to a point where in
unregulated industries, the gap between the comparable earnings test and approved returns has
widened considerably. She stated the opportunity cost (the return foregone) by investing in utility
assets rather than the next best alternative has also widened. Ms. McShane stated that the
comparable earnings standard provides a measure of such an opportunity cost and should be
given weight. The equity risk premium test estimates a return expected or required on the market
value of the investment. Ms. McShane stated that, for utilities, replacement cost is higher than
book value, thus the market value of utility shares should be higher than book value.

The comparable earnings test recognizes return as applied to an original cost rate base.
Ms. McShane recommended that weight be given to both the cost of attracting capital (through
the application of both the equity risk premium and discounted cash flow tests) and the
comparable earnings standard.

Equity Risk Premium Test
Ms. McShane stated that the equity risk premium test is a measure of the market-related cost of
attracting capital. She noted that an equity investment in a utility is more risky than a bond
investment and requires a higher return. As utility assets are long-lived and are committed to
public use over the life of the asset, long-term Government of Canada bond yield becomes the
basis for applying the risk premium test. Ms. McShane stated that the risk premium required by
investors tends to widen and narrow with factors such as inflation, productivity, profitability and
investors’ willingness to take risks. In addition, she stated that it was a prospective concept that
reflects investors' requirements to compensate for risk on a future basis.

The starting point of applying the risk premium test is to project the expected nominal long
Canada yield, which serves as a proxy for the “risk free rate.” Ms. McShane used a forecast of
long Canada yield at 6.25%. Her estimation of required market risk premium resulted from
analyzing U.S. and Canadian data from 1947 to 1999, which showed that risk premiums varied
in the range of 6.3% to 6.9% (adjusted for exchange rates and impact of annual data based on a
weighted average of 70% and 30% Canadian and U.S. stock and bond returns respectively). On a
forward looking basis, Ms. McShane’s analysis of the expected market returns over the past 10
years in relation to bond yields (weighted at 70% - 30% for Canadian and U. S forward-looking
premiums respectively) resulted in a risk premium in the range of 8.25% - 8.75%. Her estimate
of the current market risk premium based upon historic premiums was 6.5%. She noted that this
premium needed to be adjusted to reflect the risk of utilities relative to the market risk premium.
Using several models and regression analyses, Ms. McShane recommended 65% of market risk


32 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


premium as the “bare bones” utility risk premium above long Canada bonds. Her adjusted equity
risk premium for typical Canadian electric/gas utilities was approximately 4.25%.

Ms. McShane conducted a review of the historic risk premiums for the Canadian and U.S
utilities for the period of 1947–1999, giving primary weight to the Canadian data. She found that,
using arithmetic averages, a compound risk premium was achieved in the range of 4.0% - 5.8%.

Ms. McShane also conducted an analysis of investor growth expectations for a sample of U.S.
gas distributors for the period from 1993 to 2000 with similar investment risk to typical
Canadian gas/electric utilities. She stated that this indicated an average risk premium of 4.8%.

The results of the three approaches studied by Ms McShane indicated an equity risk premium for
a typical Canadian utility of 4.25% - 4.5%, above a long Canada yield of 6.25%. Her estimate of
the resulting cost of equity was in the range of 10.5% - 10.75%, before any adjustment for
financial flexibility.

Discounted Cash Flow Test
The discounted cash flow (DCF) test proposes that the price of a common stock is the present
value of the future expected cash flows discounted at a rate reflecting risk of the cash flows.

Ms. McShane applied the DCF test to a sample of eight LDC’s. She found the average and
median expectations of long-term earnings growth were both 5.8%. The average and median
adjusted dividend yields were 5.2% for both. She stated that adding the adjusted dividend yield
to the expected growth rate results in an estimated required return on common equity of 11.0%
unadjusted for financial flexibility for AGS. Applying the discounted cash flow test to APS led
Ms. McShane to recommend a 11.0-11.5% return, without adjustment for financing flexibility.

Comparable Earnings Test
The comparable earnings test measures a fair return based on the concept that invested capital
should earn a return commensurate with alternative ventures of comparable risk.

The application of the comparable earnings test requires the selection of industrials of reasonably
comparable risk to regulated firms, selection of an appropriate time period over which returns are
to be measured to estimate prospective returns and the determination of relative risk of the
industrials as compared to regulated firms.

Ms. McShane selected 17 companies from 95 Canadian industrial firms that met certain selection
criteria. The earnings for the selected low risk industrials were evaluated over the most recent
business cycle from 1991 to 1999. She found that the average annual returns for the selected
sample of low risk industrials were 12.8%.

Ms. McShane noted that the business risks of industrials were typically higher than of regulated
firms. She stated that the purpose of the analysis of relative risk of selected industrials was to
determine to what extent the differences in risk should result in a risk adjustment to the industrial
returns. She stated that statistical measures of risk for six major publicly traded Canadian


                                                        EUB Decision 2001-97 (December 12, 2001) • 33
2001/2002 General Rate Application – Phases I and II                                          ATCO Pipelines South


gas/electric utilities suggested that these utilities are in about the same risk class as the typical
low risk industrial sample, and that the data indicated that the gas/electric utilities have
experienced greater book and market return stability than the low risk industrials. She argued
that, therefore, a quantification of the risk differences on the return requirements was
appropriate. This adjustment was made using the Capital Asset Pricing Model (CAPM), using an
adjusted beta,14 giving 2/3 weight to the raw beta and 1/3 weight to the market beta, applied to
the comparable earnings test for Canadian industrials. Ms. McShane stated that this would
indicate an appropriate return of 12.5% - 12.75%.

Ms. McShane considered the returns of U.S. industrials as a relevant input factor to the
comparable earnings test due to the relatively low number of low risk consumer-oriented
industrials in Canada, and the contrast of returns for low risk U.S. industrials as compared to low
risk Canadian industrials for the most recent business cycle. Adjusting for corporate tax
differences and differential risk with Canadian utilities, Ms. McShane determined that the
applicable return was in the range of 12.5% - 13.0%

Ms. McShane gave primary weight to the Canadian results. Based upon the comparable earnings
test and before adjustment for financial flexibility, she stated that the fair return would be in the
range of 12.5% – 12.75%.

Financial Flexibility
Ms. McShane stated that to avoid equity dilution, the “bare bones” cost of equity derived from
the risk premium test should be adjusted upward to maintain financial flexibility and integrity.
She stated that the adjustment should include an amount for administrative expenses related to
equity issues; an amount for market pressure to avoid the tendency for the price of the stock to
fall as an additional supply of stock is issued; and an additional margin to cover unforeseen
events such as a sharp rise in interest rates. She stated that financing costs for high-grade
Canadian firms are in the range of 4% - 5% corresponding to an after tax rate of approximately
2.5%. The allowance for market pressure was evaluated in the range of 4% - 5%. Her sum of
financing costs and market pressure costs was 7%. Adding a minimal increment for unforeseen
events results in a flotation cost allowance of approximately 10%. Ms. McShane stated that the
flotation cost adjustment was approximately 45–50 basis points for a 7% floatation cost, and was
approximately 65–70 basis points for a 10% flotation cost.

ATCO rejected Drs. Booth and Berkowitz recommended rate of return on equity as being
inadequate to reflect a sufficient premium over the cost of long-term debt. It stated that the tests
applied by Calgary relied on the past, and did not take in to account investors’ current
expectations.




         14
            In the CAPM model “beta” is the measure of the variance of a given stock or portfolio relative to that of
the overall market. It is defined as the covariance of the stock or portfolio with the overall market, divided by the
variance of the market. A beta equal to 1 implies that the stock in question has the same variance (is as volatile) as
the market as a whole. A beta equal to 0.5 implies that the stock in question is 50% as volatile as the market. The
theory behind the CAPM model is that stocks with a smaller beta require less return to attract investors.

34 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


Positions the of Interveners
Calgary
In support of its position on rate of return on equity, Calgary submitted evidence from its
witnesses Dr. Booth and Dr. Berkowitz.

Drs. Booth and Berkowitz stated that the foundations for fair rate of return on equity were:

    1) A regulated utility should be allowed to earn a fair return on the actual capital invested in
       the enterprise that should be equivalent to what the stockholders could get if they took
       their book value and invested it elsewhere.
    2) The rate of return should be sufficient to attract new capital without impairing the
       existing investments.
    3) The rate of return should be sufficient to maintain its financial integrity at a level that
       attracts capital at reasonable terms.

Drs. Booth and Berkowitz calculated the fair rate of return in relation to the market risk or beta
and the risk free rate compared to long Canada bond yields. They forecast the long Canada bond
yield rate at 5.75% over the next two years. Drs. Booth and Berkowitz studied two risk premium
models. The CAPM estimate based upon the historic average market risk premium, adjusted for
the changing risk profile of long Canada bond showed a fair return on equity in the range of
8.00% - 8.16%. A newer, multi-factor model showed a fair rate of return on equity in the range
of 7.68% - 8.13%. Drs. Booth and Berkowitz recommended a “bare bones” rate of return of
8.00% based on the results of their tests.

Adjusted for flotation costs, Drs. Booth and Berkowitz recommended a fair rate of return on
equity at 8.25% for both 2001 and 2002, on a 35% common equity capitalization ratio for AGS
and 34% for APS. This rate of return was judged as sufficient to maintain the financial integrity
of a gas LDC and would be broadly consistent with the NEB awards for class 1 pipelines.

In their evidence, Drs. Booth and Berkowitz criticized Ms. McShane’s use of the comparable
earnings test due to the accounting practices and relative risk of the sample firms studied, the
time period of the study, the screening method to select the sample of firms studied, and an
inability of the comparable earnings test to measure opportunity cost. Calgary disagreed with
ATCO’s method of arriving at market risk premium using the arithmetic rate of return versus the
geometric rate of return method, and the weighting of U. S. data used in arriving at the
recommendation. Furthermore, Calgary disagreed with the adjustment of 50 basis points to the
risk premium for financial flexibility.

In rebuttal evidence, Calgary evaluated the difference between the recommendations of AGS and
Calgary. In its view, the difference was attributable to several adjustments used by AGS’
witness, all tending to increase the rate of return requested by AGS.

Calgary criticized Ms. McShane’s comparable earnings test stating that the sample used did not
eliminate those firms that exhibit market power, thus violating the premise that regulation is a
surrogate for competition. Calgary submitted that the comparable earnings test did not provide an


                                                       EUB Decision 2001-97 (December 12, 2001) • 35
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


insight into what earnings investors require in the future, and results in an upward bias of the risk
premium, and therefore should be given no weight by the Board. Furthermore, Calgary submitted
that the Board should reject Ms. McShane’s result of the DCF model on the grounds that it relied
heavily on U.S. data and was biased upward as a result of reliance on IBES analysts’ forecasts,
which could be optimistic.

Calgary submitted that Ms. McShane’s Market Risk Premium test was biased upward due to her
selection of data from the Canadian Institute of Actuaries and her disregard of the data from the
Task Force on Retirement Income and the Canadian Stocks, Bonds and Inflation. Similarly,
Calgary criticized Ms. McShane’s selection of the Blume report and her disregard of the study by
Gombola and Kahl, which Calgary suggested resulted in an upward bias to the recommended
rate of return on equity.

Calgary submitted that Ms. McShane’s addition of 50 basis points for financial flexibility was
unwarranted since no evidence was provided that CU Inc. experienced any market pressure when
raising common equity on behalf of AGS. Calgary agreed with the result of using Canadian data
to measure market risk premium as presented in the evidence of Ms. McShane. Calgary was
critical of the weight given by Ms. McShane to U.S. data and recommended that the Board reject
the reliance on U.S. data and base AGS’ allowed return on Canadian data.

AIPA
AIPA considered that AGS overstated the risk free rate in comparison to the average of the
10-year Canada Consensus forecast of 5.6%. AIPA submitted that a risk free rate of 5.7% would
be appropriate for the test years of 2001 and 2002.

CCA
The CCA supported Calgary’s recommendation of 8.25% return on equity for ATCO.

FGA
The FGA did not support the use of data from U.S. markets to evaluate investor’s perceptions
about raising capital in Canada. As a consequence, FGA recommended that the Board should
consider 50 points as an adjustment to the risk premium for financial flexibility.

MI
The MI were critical of AGS’ request for 11.5% and 12.0% return on equity for AGS and APS,
respectively. The MI agreed with Calgary regarding the equity risk premium and the adjustment
for financial flexibility and supported Calgary in recommending a fair return on equity of 8.25%
for 2001 and 2002.

Views of the Board
As noted in the previous section, the Board is of the view that it is appropriate to consider the
rate of return on common equity for AGS and APS as a combined entity, then look to the relative
risks of AGS and APS in establishing their respective allowed capitalization ratios.



36 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


The Board has reviewed the evidence of Ms. McShane for ATCO, and Drs. Booth and Berkowitz
for Calgary. The Board is concerned that the nature of the expert evidence provided is of little
probative value to the Board in establishing this important determinant of the utility’s revenue
requirement.

In particular the Board notes the effect that the application of professional judgement has on the
outcome of the equity risk premium test, a test which has been noted to be the mainstay of this
Board and other Canadian regulatory boards over recent periods, and is also the one test
undertaken by both parties. Ms. McShane provides an estimate of adjusted beta for the CAPM of
.65 as appropriate for ATCO, resulting in an equity risk premium of 425 basis points. Drs. Booth
and Berkowitz criticize Ms. McShane’s conclusions regarding this adjustment and note:

        The beta estimate used by Ms. McShane in this hearing is too high. To raise her
        estimated beta of .45 to a level of .65, she applies Blume’s (1975) finding that in
        the long run, U.S. equities in general tend to regress toward the market. … If we
        now repeat Blume’s analysis using the 1994-98 and 1989-93 periods…these
        results suggest an overall regression tendency towards an overall beta of .582
        [using data from 16 Canadian utilities].15

This beta estimate of 0.582 is further averaged with other data on current market utility betas to
arrive at an adjusted beta of .50. This is compared to another direct estimate of beta in the range
of 52-56%.16 In the final analysis, the value for beta used by Drs. Booth and Berkowitz is .50,
associated with a return on equity of 8.00%, adjusted for the changing risk profile of long
Canada bonds (an adjustment of 50 basis points).

Although the Board is of the view that Calgary’s criticism of Ms. McShane’s beta adjustment has
merit, it finds that the further adjustments made by Calgary present their own difficulties. It is
evident that the range of professional judgement that can be applied to this one aspect of one of
the tests can account for a substantial difference in the estimated required return. This one
difference accounts for nearly 100 basis points on return on equity, or approximately $1.5
million per year, between Ms. McShane’s beta estimate of .65 and Drs. Booth and Berkowitz’
estimate of .50. The Board has examined the other evidence brought forward by parties on the
issue of rate of return and has found that parties’ views are similarly far apart in every instance.

The Board notes Calgary’s submission that the adjustments made by Ms. McShane increase the
requests for rate of return for ATCO. However, the Board also notes that on the same page in
evidence where Calgary makes a recommendation of 250 basis points being adequate for a risk
premium for ATCO, it notes that comparable recent awards in other Canadian utility
jurisdictions have ranged from 300-387.5 basis points.17 The Board view is that the application of
professional judgement to rate of return evidence must not just be a “one way street”. The Board
is of the view that the requests by ATCO for between 525 and 550 basis points above their long
Canada bond forecast and the Calgary recommendation for 250 basis points above their long
Canada bond forecast are both outside of what the Board would consider to be reasonable.

        15
           Calgary Evidence, Appendix B. pp.11-12
        16
           Calgary Evidence, pp.51-52
        17
           Calgary Evidence, p.68

                                                       EUB Decision 2001-97 (December 12, 2001) • 37
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


Further, these estimates are far enough apart that the underlying evidence is of little value to the
Board in establishing an accurate and well justified estimate of the utility rate of return required
to maintain the financial integrity of the utility in the eyes of investors and the market.
Subsequently, the Board must rely on an examination of past awards to CWNG to determine if
there is a requirement for adjustments to those awards. The Board is also of the view that
alternative methods of determining appropriate utility return may need to be examined for use in
future rate cases.

In Decision 2000-9, the Board awarded a risk premium of 375 basis points above the forecast
long Canada rate for 1998. This was inclusive of an amount for financing flexibility. The Board
notes that this premium is near the upper end of the range of current awards noted by Calgary.
The Board has no reason to believe that investors or the market would see a need for ATCO to
receive a risk premium that would be above these other awards, based on either the business or
regulatory climate in Alberta. Therefore, lacking evidence that would suggest a measured
adjustment up or down, the Board is satisfied that this previous risk premium award is reasonable
and may be used for AGS and APS for 2001 and 2002.

The Board notes that the estimates provided for long Canada bond rates are relatively close
together, Calgary has forecast 5.75% and ATCO has forecast 6.25%. The Board notes that both
estimates have involved the use of judgement by the expert witnesses to account for various
recent financial trends. The Board finds that it is reasonable to average these estimates, to
establish a forecast long Canada bond rate of 6.0% for the test period.

The Board therefore determines that a rate of return on common equity of 9.75% is reasonable
for both AGS and APS for the period of 2001/2002.

5.3      Appropriate Capital Structure for AGS and APS
Position of ATCO
ATCO applied for approval of its forecast capital structure for 2001 and 2002 in comparison to
the capital structure approved in Decision 2000-9. The proposed capital structure consolidated by
the Board (exclusive of no-cost capital) is as follows:

                                  Forecast 2001          Forecast 2002          Decision 2000-9
      Debt                            53.8%                 51.1%                  45 - 50%
      Preferred Equity                 6.5%                  6.5%                  12 - 17%
      No Cost Capital                  0.5%                  0.4%
      Common Equity                   39.2%                 42.0%                  32 - 37%

Ms. McShane testified that with a capital structure with a common equity ratio of 40% and a
preferred share component in the 5–10% range, AGS would contribute its fair share to the
creditworthiness of CU Inc. She testified that a capital structure with a common equity ratio of
50% and a preferred share component of approximately 5% would be appropriate for APS.




38 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                               ATCO Pipelines South


AGS requested approval for a target 40% common equity component financing rate base;
however, AGS claimed it was unable to achieve a mid-year ratio of 40% due to the effect of
Decision 2000-45,18 dated July 4, 2000, on retained earnings in 2000.

In its application, ATCO proposed a significantly lower preferred equity ratio than approved in
Decision 2000-9. The changes in ATCO’ capital structure reflected the changes in tax laws and
accounting treatment of preferred shares. It stated that there was no market for true preferred
shares and an unpredictable market of equity-like preferred shares, therefore, it was prudent and
cost effective to maintain a capital structure with a lower preferred ratio and higher common
equity and debt ratios.

In support of its requested capital structure, ATCO submitted evidence from Ms. McShane.
Ms. McShane provided evidence on capital structure for 2001 and 2002 for AGS and APS.

Ms. McShane stated that the major elements of business risk for AGS were:

    •   Market risks related to the concentration of its load among a few cyclical industries, the
        relatively small number of residential heating customers whose usage is subject to
        variations in temperature and conservation;
    •   The Alberta utilities face higher forecasting risks than the typical Canadian LDC due to
        lack of deferral mechanisms for weather and usage variations, fewer deferral accounts for
        unusual expenses;
    •   Generally longer intervals between rate cases;
    •   The introduction of full retail competition and the unbundling of various services being
        competitively supplied;
    •   Anticipation of significant changes in the market place raises the prospect that
        municipalities will not renew franchise agreements;
    •   Exposure of gas utilities to competition resulting from the restructuring of the gas
        industry.

Ms. McShane stated that the major business risks for APS were:

    •   Competitive pressure from other, larger pipeline companies, particularly NGTL.
    •   No direct access to ex-Alberta markets.
    •   A highly concentrated industrial sector, where the ten largest customers account for 85%
        of industrial throughput.
    •   Declining deliverability from the western sedimentary basin.

Financial risk relates to the use of leverage in terms of capital structure and coverage ratios.
Ms. McShane noted that ATCO common equity ratios are slightly higher than the average ratio
of its peers. The debt rating of CU Inc. by CBRS was AA-. CBRS states a range of 45–55% debt
ratio for AA ratings. Ms. McShane stated that ATCO endeavors to maintain a capital ratio
consistent with ratings maintained by CU Inc.

        18
            Decision 2000-45 ATCO Gas and Pipelines Ltd. (CWNG), 1997 Return on Common Equity and Capital
Structure, 1998 GRA – Second Refiling

                                                          EUB Decision 2001-97 (December 12, 2001) • 39
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South




Ms. McShane noted that AGS’ proposed capital structure, marginal tax rate of 43.5% and return
on equity of 11.5% indicated a pre-tax coverage ratio of 2.8 times for 2001 and 3.2 times for
2002. She noted that the 2002 coverage would be toward the lower end of the CBRS range of
3.0 - 4.0 times for AA rating, but at the upper end of the 2.0–3.2 times range for A rating. She
also noted that the average for all rated gas/electric distributors was 2.5 times. With respect to
APS, Ms. McShane stated that near term interest coverage ratios should be in the range of 3.5
time, rising to 4 times as embedded debt costs fall.

ATCO stated that AGS was requesting virtually the same common equity ratio which had been
proposed for CWNG in 1998, but with a significantly lower preferred stock ratio and a higher
debt ratio. With the elimination of the Public Utilities Income Tax Transfer Act (PUITTA), it
argued that preferred shares have become less cost efficient and are being replaced with debt and
common equity. It stated that, effectively, the 18.0 % decline in the preferred component has
been replaced 80% with debt and 20% with common equity.

Ms. McShane stated that it was necessary to consider all three components of capital structure to
determine if a particular structure was compatible with the business risk and retain the objective
of maintaining financial integrity of the utility. In the comparison of a proposed capital structure
with capital structures in effect prior to the elimination of PUITTA, she stated that it was
important to consider that preferred shares had been used in place of common equity in prior
capitalization ratios.

Ms. McShane stated that the following factors should be taken into account when determining
whether the proposed capital structures are reasonable in comparison to capital structures
maintained before the elimination of PUITTA, as follows:

    •   An expectation to contribute fairly to the creditworthiness of the parent company that
        issues capital on behalf of the regulated subsidiaries.
    •   The remaining preferred shares are a hybrid security with elements of both debt and
        equity, not a direct substitute for debt.
    •   The relative costs of the three main components of capitalization and unreliability of the
        preferred market.
    •   The findings of the Board with respect to reasonable capital structures for other utilities.

Ms. McShane agreed that business risk was the key determinant of capital structure.
Ms. McShane concluded that ATCO’ proposed 2001 and 2002 capital structure was compatible
with its business risk representing an average business risk relative to its peers and would
provide an ability to maintain a degree of financial integrity consistent with CU Inc. However,
with the unfavorable market for preferred shares, Ms. McShane stated it was prudent and cost
effective for ATCO to maintain a capital structure with a lower preferred ratio and higher
common equity and debt ratios.

Ms. McShane noted that in a 1996 Decision, the Board permitted TransAlta to increase its
regulated common equity ratio from 35.5% to 40.0%. Ms. McShane stated that since AGS had a
relatively similar level of business risk and a lower preferred stock ratio than TransAlta, there is

40 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                             ATCO Pipelines South


no reason that ATCO’s common equity ratio would be lower than that approved for TransAlta in
1996. Furthermore, she noted that ATCO’s forecast coverage ratios were almost identical to
those determined reasonable for TransAlta in 1996.

ATCO noted that its request to transfer debt from APS to APN arose from the need to increase
the common equity of APS in response to increased competitive risks. ATCO submitted that
APS customers would not be treated unfairly by transferring debt that was secured post 1995. It
stated that fairness would dictate that debt should be transferred at a rate similar to that in place
at the time of the transfer.

In argument, ATCO rejected Drs. Booth and Berkowitz statement that AGS had “very, very low
risk” and concluded that Drs. Booth and Berkowitz were not sufficiently familiar with risks
faced by natural gas utilities in Alberta. ATCO agreed with Drs. Booth and Berkowitz
acknowledgement during cross-examination that the relative difference in business risk between
gas distribution and electric transmission companies was 5%.

ATCO noted several instances wherein Drs. Booth and Berkowitz were unable to discuss or
identify key business risks facing the company. ATCO also noted that its submission was
virtually identical to a submission made by TransCanada Pipelines Ltd. before the National
Energy Board. In reply argument (APS), ATCO stated that interveners had understated the actual
risks facing the company.

Positions of the Interveners
Calgary
In support of its position on capital structure, Calgary submitted evidence from its witnesses
Dr. Booth and Dr. Berkowitz.

Drs. Booth and Berkowitz agreed that it was appropriate to set capital structure to address the
overall risk facing the Company. The sources of risk faced by investors in utilities are business,
financial, investment, and regulatory risk.

Calgary stated that ATCO’s business risks were affected by:

    •   The company’s large residential sales component greatly reduces its exposure to changes
        in the business cycle.
    •   The ability of the company to recover almost all of its costs through fixed demand
        charges.
    •   Limited competition from alternate energy sources.
    •   Volatility of gas costs resulting from price and volume changes is shielded through the
        effects of the Deferred Gas Account (DGA) process.
    •   The ability to raise capital through CU Inc.

On the basis of their analysis, Drs. Booth and Berkowitz concluded that the overall business risk
of ATCO remains relatively low and stable and similar to high grade low risk LDC’s.



                                                         EUB Decision 2001-97 (December 12, 2001) • 41
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


Drs. Booth and Berkowitz stated that regulated utilities have the lowest business risk of any
sector and therefore should have the highest debt ratios. The reasons for this assertion were
stated as:

    •   A full cost-of-service regulated utility has no variation in its operating income.
    •   In the unanticipated events can be recovered through rate relief from the regulator.
    •   The tax advantages of debt are offset by the low risk of bankruptcy.
    •   The asset base consists largely of tangible assets that provide security to lenders.

In comparison to a typical competitive firm, Drs. Booth and Berkowitz evaluated that the
regulated utility was about 50% as risky when compared to overall market risk.

In argument, Calgary submitted that AGS should be compared with high quality companies in
their peer group such as Consumers, Union, and B.C. Gas.

Drs. Booth and Berkowitz reviewed the common equity ratios for seven natural gas LDC’s in
Canada. On the basis of their analysis, Drs. Booth and Berkowitz recommended a common
equity ratio of 35% for AGS.

Since the elimination of PUITTA, preferred share financing is no longer tax efficient and was
recommended by Drs. Booth and Berkowitz to be eliminated as a source of financing. One
exception could be in times when regulated utilities have problems meeting interest coverage
tests, and retaining their access to reasonable debt financing. In such a time, a five-year preferred
issue would circumvent a temporary financing problem.

Calgary observed that in its Annual Information form, CU Inc. stated its operations were subject
to the normal risks faced by regulated companies, and that in its list of other than normal
business risks, there were no material gas and pipeline risks other than those mentioned in the
broad definition of regulated operations.

In argument, Calgary stated that the critical issue for assessing business risk of AGS was that
95% of AGS’ throughput and 98% of AGS’ revenues came from the residential and commercial
sector. It further assessed that rate unbundling and/or GCRR methodology would likely have a
negligible impact on AGS. Drs. Booth and Berkowitz evaluated AGS as a high quality local gas
distribution company, having extremely low business risk. They noted that Ms. McShane had
classified AGS in the same low risk group as Union, Enbridge, Consumers and B.C. Gas.
Drs. Booth and Berkowitz argued that the capital structure for AGS should be related to those
companies, which have a common equity ratio of 33 – 35%.

Calgary also noted that the risk facing APS was greatly affected by the low risk of AGS, in that
60% of its revenue was derived from AGS. It noted that there was relatively little risk of major
bypass to serve Calgary, and that the Industrial/Producer Settlements and Gas Alberta
Memorandum of Understanding would see any shortfall in revenues being passed on to AGS.

Calgary argued that CU Inc. and CUL do not have enough common equity to support AGPL’s
common equity ratio and therefore, AGS would be engaging in “double leverage”. In reply

42 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


argument, Calgary referred to Exhibit 127, wherein a calculation was provided supporting its
proposition that there was a lack of common equity underpinning the AGS requested common
ratio. To determine the existence of common equity for which a return is requested in the
regulated entity, Calgary requested the Board to direct AGPL, in future proceedings, to provide
pro forma financial statements showing the allocation of its capitalization between each of its
four regulated business units and to provide pro forma financial statements showing the
allocation of the capital structure of CU Inc. between that portion financing AGPL and that
portion financing other regulated entities as well as the portion financing unregulated entities.
Calgary submitted that this information was required to determine whether there was any cross-
subsidization between regulated entities or between regulated and unregulated entities as a result
of capital structures that may be inappropriate for the relative risks involved.

AIPA
AIPA expressed concern that the proposed transfer of debt from APS to APN would increase the
weighted cost of APS debt capital above 8.5%.

CCA
The CCA stated that it was not appropriate for the Board to determine a range for capital
structure and then use the maximum end of the range, as had been done in Decision 2000-9. The
CCA supported the use of a deemed capital structure for ATCO.

The CCA stated that it considered that there had been an improvement in the business risks
facing ATCO since its previous GRA, as displayed in the significant increase in producer
revenues.

MI
The MI were critical of AGS’ request of 40% common equity ratio. It was MI’s position that the
risk to AGS had not increased since the last GRA, and had been reduced through certain
elements of reorganization such as removal of the pipeline function and pending sale of the retail
business unit. MI supported Calgary’s recommended common equity ratio of 35%. The MI did
not agree that business risks had increased for APS, and supported the evidence of Calgary.

The MI were also critical of APS’ proposal to transfer debt issues to APN and recommended that
any debt transfer occur at APS’ embedded cost of debt.

Views of the Board
The Board has examined the overall risk of ATCO compared with the business and regulatory
conditions prevalent at the time of 1998 CWNG GRA. The Board is of the view that there is a
slight increase in the business risk facing ATCO since that time. The Board notes two factors
that particularly affect APS, in turn affecting the Board’s assessment of business risk for ATCO.
These are:




                                                       EUB Decision 2001-97 (December 12, 2001) • 43
2001/2002 General Rate Application – Phases I and II                               ATCO Pipelines South


      •   Decision 2000-6,19 dated February 4, 2000, had the effect of lowering prices for NOVA
          transmission in the APS service territory, increasing competitive pressure on the
          Company.
      •   Recent swings in gas prices, both up and down, have provided a new basis for the
          assessment of the risk facing APS. High gas prices have the effect of increasing costs to
          APS for compressor gas. Low gas prices have the effect of reducing producer volumes on
          the APS system.

The Board is of the view that there have been no significant changes in the business risks facing
AGS. In particular, the Board has examined the effect of Decision 2001-7520 (Unbundling
Decision), dated October 30, 2001, to determine the effects of gas rate unbundling on the utility.
The Board notes that those areas that were speculated to have an effect on the risks facing the
company have either not been affected by the Unbundling Decision or have been specifically
addressed by the inclusion of deferral accounts to collect any potential stranded costs.

On the basis of the slight increase in risk seen to be faced by ATCO, the Board is of the view that
the overall common equity ratio may be reasonably increased from 37% on an integrated basis to
39% on an integrated basis. The Board is satisfied with ATCO’s forecast levels of preferred
share equity. The overall level of deemed long-term debt will be determined as the remaining
portion of the capital structure, after accounting for common and preferred equity, and no cost
capital.

Addressing the share of the overall equity deemed appropriate for the integrated entity that
should be allocated to AGS and APS, the Board is of the view that it is appropriate for APS to
have a higher common equity ratio. As noted above, the Board is of the view that the noted
increases in business risk have affected APS. The Board has determined that a common equity
ratio of 37% should be maintained for AGS, particularly in light of the appropriate reduction in
preferred equity. APS will be allowed to have 45.5% common equity in its capital structure.

5.4       Preferred Share Cost
Position of ATCO
APS forecast a mid-year cost rate on preferred Shares of 5.59% for 2001 and 6.23% for 2002.
This represented the embedded cost of APS’ preferred shares based on a mid-year balance of
$8.92 million for 2001 and $8.943 million for 2002.

There were no preferred share issues or retirements forecast in 2001 or 2002. As per the
conditions of share issue, the dividend rate for the Series U and V non-retractable preferred
shares will be re-negotiated. The forecast negotiated rate for each of these series was 7.0%.




          19
          Decision 2000-6 NOVA Gas Transmission Ltd., 1999 Products and Pricing
          20
          Decision 2001-75 Methodology for Managing Gas Supply Portfolios and Determining Gas Cost
Recovery Rates (Methodology) Proceeding and Gas Rate Unbundling (Unbundling) Proceeding, Part A: GCRR
Methodology and Gas Rate Unbundling

44 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


Positions of the Interveners
Calgary argued that no information was presented justifying the reasonableness of the requested
rate for the preferred Series U and V. On the argument that ATCO Ltd. was issuing preferred
shares of a lower quality and lower rate than forecast by AGS, Calgary recommended a rate of
5.75%.

Views of the Board
The Board is of the view that ATCO’s forecast preferred equity cost should be reasonably
accurate. This is based on there being no forecast issues and redemptions. The forecast rate for
renegotiations of the Series U and V shares appears to be reasonable.

5.5     Debt Cost
Position of ATCO
APS forecast a mid-year cost rate on long-term debt of 8.49 % for 2001 and 8.34% for 2002.
This represented the embedded cost of APS’ long-term debt based on forecast mid-year balances
of $62.136 million for 2001. This would be a reduction from 2000, accomplished by the
redemption of a 9.85% issue for $3.287 million and the 10.25% issue for $1.174 million, as well
as transferring debt to ATCO Pipelines North ($2.834 million of the 6.97% issue and $2.833
million of the 7.05% issue). APS long-term debt requirements for 2002 were forecast to be
$64.748 million.

The was no long term debt financing forecast for 2001; however, a 9.85% debenture and a
10.25% debenture are forecast to be redeemed prior to their stated maturity date. The 2002 long
term financing requirements were forecast to be met with a $35 million debenture issue at a
coupon rate of 7.05%. In addition, a $26.8 million 5.42% debenture and a $19.1 million 12.00%
debenture were forecast to be redeemed prior to maturity date.

Positions of the Interveners
Calgary
Calgary was critical of ATCO’s request to include a debenture issue for 30 years at a nominal
cost rate of 7.05% given the track record of ATCO in forecasting the type and yields of bonds.
Calgary argued that ATCO has not provided information that justifies the reasonableness of the
forecast cost.

MI
The MI observed that ATCO has not issued any long-term debt within the past 10 years. The MI
suggested that ATCO should obtain 10-year financing rather than 30 years and that the coupon
rate should be 6.43% to 6.63% versus the 7.05% forecast by ATCO in the application.

Views of the Board
The Board notes that if ATCO were to alter its proposed debt issue, as suggested by the MI, this
change would arise in a GRA well before the end of the debt issue. The Board is comfortable


                                                       EUB Decision 2001-97 (December 12, 2001) • 45
2001/2002 General Rate Application – Phases I and II                               ATCO Pipelines South


that this provides a reasonable incentive for ATCO to try to be accurate in its forecast debt
issues.

For the purposes of this Decision, the Board is concerned with the long-term debt cost rate
appropriate for the deemed capital structures of AGS and APS. The Board accepts that ATCO
has an incentive to reasonably forecast debt costs, and therefore accepts its forecast debt cost
rates. The overall debt level deemed to be appropriate for ATCO is noted below.

                 Approved Capital Structure and Cost Rates for AGS and APS

         2001                        AGS                                    APS

                                                  Return                                 Return
                      Ratios    Cost Rate       Components   Ratios    Cost Rate       Components

   Debt               55.90%       8.31%           4.64%      48.06%     8.49%            4.08%
   Preferred           6.50%       5.52%           0.36%       6.44%     5.94%            0.38%
   No-Cost             0.60%                       0.00%       0.00%                      0.00%
   Equity             37.00%       9.75%           3.61%      45.50%     9.75%            4.44%
   Total             100.00%                       8.61%     100.00%                      8.90%

          2002
   Debt               55.90%       8.16%           4.56%      48.30%     8.34%            4.03%
   Preferred           6.60%       6.15%           0.41%       6.20%     6.23%            0.39%
   No-Cost             0.50%                       0.00%       0.00%                      0.00%
   Equity             37.00%       9.75%           3.61%      45.50%     9.75%            4.44%
   Total             100.00%                       8.58%     100.00%                      8.85%




46 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                              ATCO Pipelines South


                     Approved Capital Structure and Cost Rates for AGPL

                         2001                           AGPL
                                                                     Return
                                         Ratios        Cost Rate   Components
                         Debt            54.11%         8.34%           4.51%
                         Preferred        6.49%         5.61%           0.36%
                         No-Cost          0.46%         0.00%           0.00%
                         Equity          38.94%         9.75%           3.80%
                         Total          100.00%                         8.68%

                            2002
                         Debt            54.05%         8.20%           4.43%
                         Preferred        6.50%         6.16%           0.40%
                         No-Cost          0.38%         0.00%           0.00%
                         Equity          39.08%         9.75%           3.81%
                         Total          100.00%                         8.64%



6       UTILITY REVENUE REQUIREMENT

6.1     Operating & Maintenance Expense
6 .1 General
 .1
ATCO forecast that O&M expenses would increase to $12,161,000 in 2001, and moderate
slightly to $11,058,000 in 2002. Both years increased from the operation and maintenance
expense of $9,390,000 in 2000. The forecasts are based on an inflation factor of 4% for labour
and 3% for supplies.

ATCO’s O&M expenses can be broken down into transmission, and administration and general
expenses.

6 .2 Transmission
 .1
The Transmission function of O&M expenses was forecast at $5,198,000 in 2001, and
$5,362,000 in 2000. Transmission expenses include labour and supply expenses for compressors,
transmission lines, stations, measurement and billing systems, and the control and
communication systems; the costs for transportations by others, facilities, and leases; business
development and customer services functions, and engineering. Transmission expenses are
detailed below.




                                                          EUB Decision 2001-97 (December 12, 2001) • 47
2001/2002 General Rate Application – Phases I and II                         ATCO Pipelines South


                                               1999       2000           2001           2002
            O&M Expense ($000)
                                              Actual     Actual        Forecast       Forecast
   Transmission                                 4668       4355           5198           5362
   Component Analysis
   Labour                                       2628       2693           2953           3043
   Supplies                                     1109       1007           1560           1613
   Subtotal                                     3737       3700           4513           4656
   Affiliate Services                            931        655            685            706
   Total                                        4668       4355           5198           5362
   Affiliate Services
   ATCO Gas Corporate Services                     0         38             38             39
   ATCO Gas Engineering                          127        137            130            133
   ATCO Gas Operations                           798        471            509            525
   ATCO Gas Customer Services                      6          9              8              9
   Total ATCO Gas                                931        655            685            706
   Total Affiliate Services                      931        655            685            706

Transmission labour costs were predicted to rise by $260,000 in 2001. This was due to higher
customer service costs arising from standby wages for gas coordination staff, higher operations
costs arising from the transfer of functions for compressors, and station facilities previously
performed by ATCO Gas, along with higher business development costs due to staff hiring.

Transmission supplies expenses have been forecast to increase by $553,000 in 2001, and an
additional $53,000 in 2002. This is in contrast to the decline in transmission costs in 2000.
ATCO attributes the cost increase in 2001 to higher transportation costs by others resulting from
a TransCanada cost of service/minimum annual volume charge, and functions previously
performed by ATCO Gas for ATCO Pipelines regarding compressor and station facilities.

Affiliate Services expenses related to the transmission function of O&M declined by
approximately 30% in 2000, as ATCO began to perform functions previously performed by
ATCO Gas. The major changes in costs for affiliate services are due to termination of contracts
for services now being performed in-house by the Company

6 .3 Administration & General Expenses
 .1
Administration and General expenses were forecast at $6,963,000 in 2001 and $5,696,000 in
2002. Administration and General expenses include the supplies and labour costs for the
financial, human resources, corporate communications, regulatory and information systems, and
general functions of ATCO; the costs of auditing services, legal services, consulting services,
corporate memberships, insurance and fringe benefits, and regulation costs. A detailed
description assigning costs to specific components is set out below.




48 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                   ATCO Pipelines South


         Operation & Maintenance Expenses          1999           2000        2001         2002
         ($000)                                   Actual         Actual     Forecast     Forecast
         Administration & General                   4854           5170         6963         5696
         Component Analysis
         Labour                                          69         639         736           764
         Supplies                                      1708        2077        2292          2178
         Subtotal                                      2402        2716        3028          2942
         Affiliate Services                            2365        2395        2371          2421
         Regulatory Accounts                            251         154        1840           604
         Net Cost Recoveries-ATCO Gas                   (63)        (95)       (141)         (143)
         Subtotal                                      4955        5170        7098          5824
         Less Non-Utility                               101         135         135           128
         Total                                         4854        5035        6963          5696



                                                   1999           2000        2001         2002
         Affiliate Services Analysis ($000)
                                                  Actual         Actual     Forecast     Forecast
         ATCO Gas Financial Services               387            353          467          473
         ATCO Gas Corporate Services               176            115          118          122
         ATCO Gas Customer Services                (52)
         Total ATCO Gas                             511           444           585          595
         Total ATCO I-Tek                          911            771           954         983
         Total ATCO Group (OOC/C0)                 943           1180          832          843
         Total Affiliate Services                 2365            239         2371         2421


                                                   1999           2000        2001         2002
         Regulatory Account Analysis ($000)
                                                  Actual         Actual     Forecast     Forecast
         Reserve For Injuries & Damages             90            (47)          25           25
         Hearing Costs                                 74         372         1739          500
         EUB Operating Cost Assessment                 87        (171)          76           79
         Total                                     251            154         1840          604

ATCO indicated that the major factors leading to increases in the Component analysis of O&M
are:

    •   $97,000 increase in administration in 2001 as a result of labour accrual reversal in 2000
    •   An increase of $369,000 in 2000, largely attributable to an increase in customer related
        promotions and severance costs; while the $215,000 increase in 2002 was a result of
        higher expenses for pension and post retirement benefits. These costs reflected regulatory
        adjustments to pension expenses and post retirement benefits in 2000 and a higher
        applied expense rate, arising from decision 2000-9.
    •   The Regulatory Account is forecast to increase by $1,686,000 in 2001, reflecting costs
        associated with the 1998 and 1999 CWNG GRA, and costs for the 2001/2002 ATCO
        Pipelines GRA.


                                                               EUB Decision 2001-97 (December 12, 2001) • 49
2001/2002 General Rate Application – Phases I and II                          ATCO Pipelines South


Affiliate services expenditures consist of the cost of supplies, and overhead services, and labour
for services provided by ATCO affiliates, namely ATCO I-Tek, ATCO Gas, and the ATCO
Group for the administrative and general function.

As with the transmission function, ATCO terminated some services provided by affiliates in
2001. All services provided by ATCO Gas Financial services terminated as of April 1, 2001,
except for matters related to corporate financial and regulatory reporting, and taxation. ATCO
expects to use internal resources on matters related to human resource management, benefits
administration, training and safety services, ending ATCO Gas Corporate Services contract in
January 1, 2001.

Interveners had a variety of concerns with regards to general O&M matters, subdivided into
Inflation, Restructuring, and Information Technology (IT)/Information Systems (IS) spending. IT
spending will largely be addressed in the affiliate hearing, but related intervener argument is
provided below.

Position of ATCO
ATCO observed that the MI argued that O&M costs should increase by no more than 6%, plus
3% inflation. ATCO submitted that the MI did not consider the additional costs from regulatory
proceedings, post retirement benefit provisions, the new minimum annual volume charges levied
by TransCanada or the new standby pay to provide weekend gas control service, all detailed in
section 4.2 of the Application.

ATCO noted that the CCA suggested that O&M costs be held to 2000 levels, but offered no
evidence to support that recommendation.

ATCO furthermore, strongly disagreed with Calgary’s recommendation for a lower inflation
percentage and a 1% productivity factor, based on the Canadian CPI increase for 2000. As noted
in response CAL-ATCO 183(c), the Alberta 2000 inflation forecast increase was 3.2%. ATCO
investigated several sources of information including Alberta specific data to arrive at their
forecast rate. ATCO argued that, if anything, the forecast inflation rate is low, compared to 2001
inflation rates experienced by Calgary and Edmonton to date.

ATCO submitted that there was no basis for the Board to select a Canadian inflation factor for a
business operating exclusively in Alberta, and that Calgary’s recommended inflation rates should
therefore be rejected.

ATCO objected to Calgary and the CCA’s argument for a productivity adjustment for inflation.
ATCO argued that the requested rate increases of 2.75% in 2001 and 2.4% in 2002, which
included inflation and incremental growth from 1999-2002, already included large productivity
gain to customers. ATCO submitted that the Board should reject the productivity adjustments
suggested by Calgary and the CCA, which would duplicate productivity improvements already
factored in.




50 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


Positions of the Interveners
MI
The MI noted that ATCO’s system demand was forecast to increase 13% from 1999 to 2002,
while total O&M costs were forecast to increase 16% during that period.21 However, the MI
pointed out that industrials and producers were proposed to increase only 5% from 1999 to
2002.22 The MI argued that the transmission labour and supply costs of total O&M expenses may
be a function of increases in demand, while administration and general costs are more a function
of the number of industrial and producer customers, an increase of only two customers, from 142
customers in 1999 to 144 in 2002.23

The MI suggested that O&M increases since 1999 were not justified by growth and inflation,
noting that ATCO’s forecast for 2000 O&M costs was $9.55 million versus the actual O&M
costs of $9.39 million. The MI submitted that 2000 actual transmission function costs should
increase by a maximum of 6% growth in throughput from 2000 to 2002 plus a maximum of 3%
for inflation, net of productivity. The MI advocated that the Board recognize the throughput
increase on the transmission function, but decline any increase in administration and general
costs based on limited growth and inflationary pressure.

CCA
The CCA argued that the increased O&M costs were significantly greater than both inflation and
growth. The CCA submitted that the 27% increase from the 2000 estimate to the 2001 forecast,
and 9% decrease from the 2001 forecast to the 2002 forecast were above both inflationary
pressure and growth forecasts. The CCA pointed out that the 2002 forecast was a 16% increase
from ATCO’s 2000 estimate.

The CCA noted that ATCO indicated that the inflation factors used in its 2001 and 2002
forecasts were 4% for labour and 3% for supplies for both transmission expenses and
administration and general expenses. The CCA argued that ATCO’s’ inflation rate forecast must
be weighed against their responses in CAL-APS-72 (a), (b), (d) to determine their validity. The
CCA noted that ATCO indicated that it inadvertently omitted to state that the inflation rate used
for its occupational labour was 3%. The 4% labour inflation referenced in the evidence was used
for supervisory labour. The CCA referred to part (b) of this response, where ATCO indicated
that its inflation forecasts represent management judgement of cost increases for the test periods
based on their general business knowledge and expected conditions in the service area, void of
any inflation analysis documentation (part d).

The CCA argued that inflation rates should be linked to productivity improvement factors, which
creates an incentive to utilities to ensure customers’ rates are as low as possible.

In addition, the CCA expressed concern regarding escalating O&M costs, as shown in the
following table:

        21
           Table 4.2-1 of the Application
        22
           BR-25(a)
        23
           BR-APS.25

                                                       EUB Decision 2001-97 (December 12, 2001) • 51
2001/2002 General Rate Application – Phases I and II                                  ATCO Pipelines South


                               Operations and Maintenance Expenditures
                                                ($000)
                                            1999         2000        2001              2002
                                           Actual      Estimate    Forecast          Forecast
        Transmission                           4,668       4,756          5,198         5,362
        Administration & General               4,955       4,921          7,098         5,824
        O&M - Corp.                            9,623       9,677         12,296        11,186
        Less: Non-Utility O&M                    101         127            135           128
        O&M - Utility                          9,522       9,550         12,161        11,058

(Page 2, Section 4.2, APS Filing)

Actual O&M expenditures for 2000 were updated as follows:

                                                                     ($000)
                               Transmission                           4,355
                               Administration & General               5,170
                               O&M – Corp.                            9,525
                               Less: Non-Utility O&M                   135
                               O&M – Utility                          9,390

The CCA cited Decision 2000-9 where the Board directed CWNG to reduce the company’s
operation and maintenance forecast for 1998 by 2.5% after certain specified deductions.24 The
2.5% reduction was based upon historical experience and a review of specific components of the
operations and maintenance forecast. The CCA pointed out that the AEUB found that it was
appropriate for the Board to anticipate further management efficiency gains in addition to those
filed in the 1998 application. The CCA also noted that the Board also expressed concern that it
was inappropriate to allow a company to determine its own budget in a setting where it may keep
any portion of the budget not spent.25

The CCA considered that the level of operations and maintenance forecast increases were
excessive and should be held to 2000 estimated levels.

Calgary
Calgary submitted that ATCO used inflation factors of 4% for labour and 3% for supplies for
2001 and 2002, based upon a non-quantitative internal management forecast; whereas, the March
Consensus Forecast26 was a CPI increase of 2.4% in 2001 and 2.2% in 2002, while industrial
product prices are forecasted to increase by 2.0% and 2.5% respectively



        24
            Decision 2000-9, p.163
        25
            Decision 2000-9, p. 98
         26
            FGA-ATCOP- 10 p. 3 of 4, the December Consensus Forecast for 2001 was 2.4% for CPI and 2.3% for
Industrial Product Prices

52 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                  ATCO Pipelines South


Calgary referred to the following table showing the total O&M expense27 and the portion
allocated to Affiliates.


                                                   1999         2000        2000        2001         2002
                     ($000)                       Actual       Actual     Forecast    Forecast     Forecast
 O&M - Corporate                                    9,623        9,525       9,677      12,296       11,186
 Less: Non-Utility O&M                                101          135         127         135          128
 O&M – Utility                                      9,522        9,390       9,550      12,161       11,058
 Affiliate costs                                    3,296        3,050       3,082       3,056        3,127
 O&M (net of Affiliates)                            6,226        6,340       6,468       9,005        7,931
 Compound % increase over 2000 actual                                                     29.5           8.5
 Compound % increase over 2000 actual
 (net of Affiliates)                                                                      42.0         11.9

Calgary argued that the percentage increase does not reflect benefits from either productivity or
restructuring, and are higher than any forecast of inflation for the test periods. Calgary referred to
the following table showing specific components of O&M Costs and their increased cost
forecasts.

                 Transmission                      1999         2000        2000         2001        2002
                    ($000)                        Actual       Actual     Forecast     Forecast    Forecast
Labour                                            2,628        2,693       2,693        2,953       3,043
Suppliesa                                         1,109        1,007       1,281        1,560       1,613
Total                                             3,737        3,700       3,974        4,513       4,656
Compound % increase over 2000 actual                                                      22.0        12.2

Application at 4.2.2 Page 3 of 12 for Transmission expenses and BR-APS.12.
Note: (a) excludes affiliates costs

Calgary noted that, on a compounded basis, the 2002 labor cost forecast escalated by more than
6% per year from 2000 as proposed by ATCO, not the 4% set forth in their evidence. Supplies
expense, excluding the costs passed on from Affiliates, are increasing by 12.5% per year from
forecast 2000 to forecast 2002 above APS’s stated 3%.

Calgary produced the following table, based upon the Application, which showed similar
increases were forecast for labour and supplies as for Administrative and General Expenses,
excluding affiliate charges and regulatory costs:




        27
             Exhibit 4, APS Application, Table 4.2-1 and BR-APS.12

                                                              EUB Decision 2001-97 (December 12, 2001) • 53
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South




      Administrative and General              1999      2000      2000       2001          2002
                ($000)                       Actual    Actual   Forecast   Forecast      Forecast
Labour                                        694        639      640        736            764
Suppliesa                                    1,708     2,077     1,893      2,292         2,178
Total                                        2,402     2,716     2,300      3,028         2,942
Compound % increase over 2000 actual                    12.9b                 11.6           4.1

Note: (a) excludes affiliates costs
      (b) increase over 1999 actual

Calgary noted that, while the above showed only a 4.1% compounded increase in 2002 over
2000, 2000 was almost 13% higher than 1999 (7.0% compounded over three years).

Calgary stated that an inflationary increase of 2.7% of the 2000 actuals should be used for 2001,
and an inflationary increase to 2002 of 2.5% over 2001, less a productivity gain of 1% for each
year. Calgary espoused that total O&M be should be reduced by $2.6 million for 2001, and $1.4
million for 2002 before consideration of affiliate charges.28

Calgary submitted that the consensus inflation rates, less a productivity factor, should be used for
purposes of determining the applicable O&M expense for APS, and that the adjustments outlined
in Calgary’s evidence should apply.

Views of the Board
The Board notes the significant discussion with respect to the escalation in expenditures forecast
for the test years compared to 2000. As indicated in other Sections of this Decision, the forecast
expenditures for the Affiliate and Pension-related expenditures will be held as “placeholders” in
the test year revenue requirements and the quantum and propriety of the amount will be
addressed in the Affiliate and Pension Proceedings.

The Board notes ATCO’s submission that O&M expenditures increased in 2001 due to a transfer
of services from ATCO Gas to ATCO Pipelines South, specifically related to the operating costs
of compressor and station facilities, which effected both the transmission and general
administration components of ATCO’s forecasts. The Board also recognizes that transportation
by others increased in 2001 due to a TransCanada cost of service/minimum annual volume
charge increase. The Board notes that ATCO attributes $279,000 of the increase to these factors.

The Board also notes ATCO’s statement that the 2001 forecast for transmission labor expenses
increased due to higher customer service costs from standby wages for gas coordination staff,
and higher business development costs. The Board notes that significant increases in forecast
supplies and labor expenditures for the general and administration component of O&M in 2001,
are largely a result of the termination of various affiliate service contracts, which are now being
performed in-house, regulatory account expenses largely associated with hearing costs, and


        28
             Exhibit 76, p.4 of 14 line 3.

54 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                             ATCO Pipelines South


increases in pension and post retirement benefits. The Board notes however, that ATCO
expenses declined in 2002, as the regulatory account component of supplies moderated.

Nevertheless, the Board acknowledges the concerns expressed by interveners with respect to
increases in O&M expenditure forecasts resulting from factors affecting those expenditure
categories that are not Affiliate related. In particular, the Board notes that there was a significant
degree of concern expressed that ATCO had forecast increases in the test years that were
significantly in excess of inflation. In this regard, the Board considers that there is merit in the
argument of Calgary that ATCO’s proposed inflation factors are based on a non-quantitative
internal management forecast, which is considerably out of line with the Federal Government
Consensus Forecast. On the other hand, the Board also recognizes that ATCO is primarily an
Alberta based business, and as such, considers it appropriate to recognize an Alberta inflationary
factor. The Board notes that observations about escalating O&M costs presented by the CCA,
focused on a recommendation that expenses should be held to year 2000 levels, and that the MI
recommended reductions in escalation factors for Transmission and Administration and General
expenses.

The Board recognizes that, while the interveners approach the issue from varying perspectives,
the consistent theme is that the forecast escalation in O&M expense in the test years is higher
than would be expected with the application of a recognized inflation factor.

The Board agrees with the MI’s proposal that ATCO should be allowed an inflation rate of 3%
for supplies and labor for both 2001 and 2002 test years, plus a 6% growth rate in 2001 to reflect
the increases in system demand. The Board considers it reasonable to expect increased
compressor and station facilities costs due to the transfer of functions previously performed by
ATCO Gas, and the increased costs from the transportation by others could, as indicated by
ATCO, result in an increase of $279,000 in 2001 costs compared to 2000. Therefore, the Board
is prepared to accept an increase of $279,000 in the 2001 forecast. The Board is also prepared to
accept a 3% increase for inflation in 2002 separate from the increase of 6% for growth and a 3%
increase for inflation for other supplies and labour expenditures in both 2001 and 2002 test years.
The Board also accepts an additional increase of 3% for inflation in 2002.

The Board acknowledges the MI’s position that industrial and producer customers only increased
from 142 to 144 between 1999 and 2002, and agrees that, since customer growth is a key cost
driver of general and administration expenditure increases, no growth factor should be allowed in
this expenditure category. The Board believes however, that inflation must be factored into these
expenses. The Board therefore approves a 3% inflation rate for both supplies and labor
expenditures for both test years (2001and 2002) in the general and administration category, with
no factor for growth. The Board adjustments to labor and supplies expenses are calculated less
regulatory account costs, net costs recoveries associated with ATCO Gas transactions, and
affiliate expenses, cost drivers that are being addressed in either the affiliate hearing or are one-
time anomalies.

The Board notes that the MI’s 3% inflation factor falls within a justifiable range of the Alberta
inflation rate, and the Canadian Consensus CPI forecast argued by the City of Calgary. However,
while recognizing that productivity gains suggested by Calgary, the MI and the CCA should be


                                                         EUB Decision 2001-97 (December 12, 2001) • 55
2001/2002 General Rate Application – Phases I and II                                         ATCO Pipelines South


relevant, the Board does not see the need for further adjustments to ATCO’s operation and
maintenance forecast expenses

The Board notes that the forecast for hearing costs (regulatory account) in each test year
represents the other main factor contributing to the increase in expenditures from sources which
are not Affiliate related. The Board agrees with ATCO’s proposal to treat the amount of $1.739
million included in the 2001 forecast as a one-time expenditure item, and that the forecast
hearing costs for the 2002 test year should be increased to $500,000 based on an anticipated
forecast of regulatory activity in the future. The Board agrees that the balance should be
allocated to the deferred hearing account.

To determine the extent of increases in forecast expenditures for categories that are neither
affiliate or pension related nor one-time payments, the Board has prepared the following table,
which includes ATCO’s requested operation and maintenance expenditures, adjustment based on
views of the Board, and their overall impact.

                             ATCO O&M ($000), based on comparison with year 2000 actual
       Category                                                                     2000    2001     2002
       2000 Base Year for comparison                                               Actual Forecast Forecast
  1    Transmission                                                                   4355    5,198   5,362
  2    Admin.& General                                                                5170    7,098   5,824
  3    O&M- Corp.                                                                     9525 12,296 11,186
  4    Less: Non-Utility O&M                                                           135      135     128
  5    O&M- Utility                                                                   9390 12,161 11,058



                                       Board Adjustment of Transmission Component
  6    Transmission Total                                                                  4355   5198    5362
       Transmission Adjustment-3% inflation for both test years - 2001, & 2002, with 6%
       growth adjustment for 2001 - based on 2000 comparison.                              4355   4747    4889
  7
                                      Plus $279,000 cost recognition for Transmission              279     289
                                   Supplies related to compressors & station facilities,
                                   TBO costs; plus a 3% increase for inflation in 2002,
  8                                          Based on original application submission
  9 Board Adjusted Transmission Total (Line 7 + Line 8)                                           5026    5178
  10 Impact of Board Adjustment on Transmission (Line 9-Line 6)                                   -172    -184




56 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                            ATCO Pipelines South


                                   Board Adjustment of General & Administration Component
       APS Administration & General                                                            2000    2001     2002
  11   Total Administration & General                                                          5170    7098     5824
  12   Less: Reductions for one-time costs & extraordinary costs
  13                                                                               Non Utility  135     135      128
  14                                                                    Regulatory Account      154    1840      604
  15   Affiliate Services-I-Tek & ATCO Group (OOC/CO), dealt with in affiliate proceeding      1951    1786     1826
  16   Total Reductions (Sum of Lines 13:Lines16)                                              2240    3761     2558
  17   Subtotal Administration & General, Net of Reductions (Line 11-Line 16)                  2930    3337     3266
  18   Board Adjustment: 3% for inflation, with no adjustment for growth                       2930    3018     3108
  19                                                Add Back Total Reductions (Line 16)        2240    3761     2558
  20   Board Adjusted of Administration & General Total (Line 18 + Line 19)                    5170    6779     5666
  21   Board Adjustment Impact on General and Administration (Line 20-Line11)                     0    -319     -158

  22   Board Adjusted of Administration & General Total (Line 20)                             5170     6779     5666
  23   Board Adjusted Transmission Total (Line 9)                                             4355     5026     5178
  24   Total Board Adjusted O & M Expenses - Corp. (Line 22+Line 23)                          9525    11805    10844
  25   O & M Corporate applied for by APS in Application (Line 3)                             9390    12,296   11,186
  26   Total Impact of Board Adjustment on O & M (Line 24-Line25)                                0      -491     -341



The table illustrates that the allowed increases for transmission labor and supplies expenses are
3% for inflation in 2001 and 2002 test years, plus a 6% increase in 2001 due to system demand
growth. The Board further approves a lump sum increase of $279,000 as a separate adjustment
to transmission expenses in 2001, with a 3% inflation rate increase in 2002. The table also
demonstrates that for administration and general expenses, the Board recognizes a 3% inflation
rate for 2001 and 2002 test years.

Accordingly, as indicated by the calculations in the table above, the Board directs ATCO to
reduce O&M forecasts by $491,000 in 2001, and $341,000 in 2002.

6 .4 Restructuring
 .1
Position of ATCO
Since the last CWNG general rate hearing, the pipeline industry has seen considerable change,
and greater competition. As indicated by ATCO, in testimony, the separation of the transmission
function was a direct reflection of the new realities of the pipeline industry. As a result, ATCO
saw throughputs and revenues increase, which benefited all pipeline customers.

Restructuring minimized requested rate increases to 2.75% for 2001 and 2.4% for 2002 , after the
impact of inflation from 1999-2002 and the increased maintenance and carrying costs for the
incremental facilities required to manage increased throughputs. ATCO pointed out that, while
Calgary confused the issue by focusing on detailed level account-by-account comparisons, the
Company proactively responded to the changing pipeline industry through restructuring, to the
benefit of all customers.


                                                                   EUB Decision 2001-97 (December 12, 2001) • 57
2001/2002 General Rate Application – Phases I and II                         ATCO Pipelines South


ATCO stated that both Calgary and the MI claimed that there was no benefit to restructuring.
ATCO countered this conclusion as unsupportable, as producer revenues were forecast to grow
36% from 1999 to 2002 while costs increased by only 16%. ATCO considered that the MI’s
claim that cost increases outstripped revenue growth simply ignored the impact of plant shut-in
and fuel switching due to higher gas costs and load retention rate reductions due to competitive
bypass alternatives on industrial revenues. ATCO submitted that restructuring allowed them to
request only a 2.75% rate increase for 2001 and a 2.4% rate increase for 2002, pointing out that
these rate increases included the impact of the incremental facilities required by system
throughput increases as well as inflation. Unlike Calgary and the MI claim of no system by-pass,
ATCO indicated that the Company undertook restructuring as a means to mitigate stranded cost
risks.

ATCO stated that customers benefited from restructuring which enabled the Company to keep
requested rate increases below the rate of inflation, while system throughput increased. ATCO
argued that restructuring costs should be allowed as requested.

Positions of the Interveners
MI
The MI submitted that ATCO included $143,000 of restructuring costs in 2001 and 2002, which
represented the proposed amortization over four years beginning in 1999 of the company’s share
of the CWNG/NUL restructuring cost that commenced January 1, 1999.29The MI agreed with
Calgary’s evidence in both the Gas and Pipeline proceedings, that restructuring costs in 2001 and
2002 revenue requirements should not be approved until there is tangible evidence of benefits to
customers. The MI submitted that if the Board approves restructuring costs in the 2001 and 2002
revenue requirements, these costs should be uniformly amortized over four years, from
January 1, 1999 to December 31, 2002.

The MI noted that ATCO expressed the view that the benefits of restructuring should be
measured against the minimal requested rate increases of 2.75% in 2001 and 2.4% in 2002, after
inflation and increased throughput.30The MI submitted that restructuring should be gauged
against the 1.4% rate reduction of January 1, 1999 plus the 14% rate reduction north customers
received effective January 1, 2001 pursuant to the Re-opener under the 1998-2002 PBR
Settlement. Since 1998, the North has received a 15.4% total cost reduction, attributable to both
the transmission and distribution functions. On the other hand, the MI pointed out, that ATCO’s
core customers received rate reductions of only 8% to 11% effective September 2000. MI argued
that there appears to be an inequity in reductions between AGN and APS, possibly as a result of
the AGN settlement with their customers.

Calgary
Calgary was opposed to the inclusion of any restructuring costs in ATCO’s 2001/2002 revenue
requirements.31 Calgary’s indicated that its opposition was based on a number of factors, but
primarily the inappropriateness of using pension gain to reduce restructuring costs, the lack of
        29
           CAL-69(c) (i)
        30
           APS Argument, p.3
        31
           Exhibit 4, Section 4.4, p.7 and Section 2.5, p.2

58 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                    ATCO Pipelines South


benefit to customers from the restructuring, and the failure of ATCO to comply with Decision
U99102,32 dated November 1, 1999. Calgary stated that use of the pension gain was discussed in
Calgary’s evidence in the ATCO Gas South proceeding33.

Calgary submitted that the 1998 estimated actual O&M expense for transmission operations
could be calculated as $6.365 million.34 The 1999 actual was $9.522 million35 or about 47%
higher than 1998. Calgary argued that a 50% increase was not indicative of restructuring
benefits. Furthermore, Calgary pointed out that the forecasts for 2001 and 2002 showed that the
increase in 1999 was no aberration since the 2002 forecast was 74% higher than the 1998
amount, a compounded increase of almost 15% per year. Calgary submitted that ATCO has
failed to display economies of scale.

Calgary recommended that for 2001 and 2002 the consensus forecast for CPI be used less a
productivity factor of 1% for ATCO’s’ O&M forecasts, pointing out that, if there were any gains
achieved from the restructuring even Calgary’s recommended increase would have been
excessive.

Calgary noted ATCO’s argument 36 that the success of restructuring was shown by a minimal
2.75% rate increase requested for 2001 and 2.40% for 2002. Calgary noted that while the
percentage increase between 2001 and 2002 may be 2.40%, the increase between 2000 and 2001
was significantly higher than the 2.75% asserted by ATCO. Based on BR-APS.12, the actual
ATCO revenues for 2000 were $34.3 million. Calgary argued that the requested revenue
requirement of $41.1 million for 2001 was an almost 20% increase. In addition, Calgary
submitted that the ATCO rate design data that resulted in an increase from $1.82/GJ/month for
AGS to the proposed rate of $1.93/GJ/month of contract demand for transmission service was an
increase of over 6%. Calgary submitted that this increase was greater than the alleged 2.75%.

Views of the Board
The Board notes that Calgary and the MI took issue with ATCO’s position with respect to the
benefits of restructuring, on the basis that the significant escalation in costs from 1998 to the test
years is not indicative of any significant restructuring benefits. Calgary and MI argued that
restructuring costs should not be included in 2001 and 2002 revenue requirements until there is
tangible evidence of benefits to customers. On the other hand, the Board acknowledges ATCO’s
submission that the percentage increases in forecast producer revenues from 1999 far exceed the
relative increase in O&M costs during the same period. The Board considers that precise
quantification of the savings from restructuring is not fundamental to addressing the issue of
whether or not the costs of restructuring should or should not be included in test year forecasts.



        32
            Decision U99102 Canadian Utilities Limited, Northwestern Utilities Limited and Canadian Western
Natural Gas Company Limited, Application for renewal of the reorganization of NUL and CWNG
         33
            AGS Exhibit 45, Evidence of The City of Calgary, pp .3-5
         34
            AGS Exhibit 45 Table 1 - $66.401(for CWNG) less BR-ATCO Gas.37 – $59.036 (for AGS net of
transmission)
         35
            Exhibit 4, APS Application, Section 4.2, p. 2 of 12
         36
            APS Argument, p. 3

                                                             EUB Decision 2001-97 (December 12, 2001) • 59
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


The Board believes that the Company should be permitted to restructure and reposition in
response to changes in its business environment. The costs of restructuring are a normal cost of
conducting business and as such, should be considered an appropriate item for inclusion in
regulated rates without the need for additional justification. The Board is prepared to accept
ATCO’s representations that customers benefited from restructuring while noting the problems
with attempting to quantify benefits to ratepayers associated with restructuring activities. The
Board is not persuaded that compelling evidence has been presented to support any reduction in
restructuring costs included in the test year forecasts. Therefore, the Board allows ATCO’s
restructuring costs as requested.

6 .5 IT Spending
 .1
Position of ATCO
ATCO submitted that its IT spending was prudent, and that Calgary’s evidence does not provide
a reasonable basis for reducing the revenue requirement.

ATCO cited Dr. Chwalowski’s observation that the Company had a highly responsive approach
to its customer needs with respect to IT capacity, particularly in the area of e-commerce, where
customers view their bills, make nomination requests and obtain hourly balance information via
the internet. In addition, ATCO applied to include in rates, the costs of construction of an e-mail
notification system, which offers customers the ability to view their bills on-line. ATCO noted
that the Gartner Report, offered into evidence by Calgary, suggested that IT spending to revenue
ratio of a company advanced in e-commerce will be higher than companies that have not
invested in e-commerce.

ATCO noted Calgary’s assertion that the Company spent too much on IS/IT, based on
comparing IT spending to revenue ratio with the average ratios of “petroleum industry”
companies in the Gartner Report. ATCO submitted that the Gartner Report failed to provide a
rational basis for limiting the Company’s IT spending.

ATCO argued that Calgary failed to produce evidence in either this application or the AGS
proceeding that supported the methodology used in the Gartner Report. ATCO pointed out that
Calgary’s witness was not aware of the size of the survey sample, the survey selection criteria,
the total number of petroleum companies surveyed (or the number of such companies in the
U.S.), whether the averages were calculated on a simple, weighted or other basis, or what
systems/services were included in the survey. In addition, crucial background facts about the
data were unknown, including how many of the ratios provided by the individual companies fall
within 20% of the survey average.

ATCO challenged the validity of a comparison between ATCO and petroleum industry
companies in the Gartner Report. As noted by Dr. Chwalowski, none of the petroleum industry
companies were classified as “natural gas pipelines”, they bore little resemblance to regional
natural gas pipelines, and had revenues roughly 130 to 140 times larger than ATCO and enjoyed
economies of scope and scale relative to the Company. A comparison between ATCO and gas
utility companies may also be invalid on similar grounds.



60 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


ATCO noted that Calgary’s witness intended to use the Gartner Report simply “as an indicator”
but recommended that the Board make a decision to limit ATCO’s IT spending to a ratio
consistent with that of the petroleum industry companies in the report. In his testimony in the
AGS GRA, the witness acknowledged that the Board should take into consideration the Gartner
Report’s statement that:

        “Each enterprise should assess its own situation carefully and should not
        arbitrarily change to conform to the survey results, which do not represent norms
        or best practices. By itself, IT spending as a percentage of revenue does not
        provide valid comparative information that should be used to allocate IT or
        business resources. IT spending statistics alone do not measure IT effectiveness
        and are not a gauge of successful business and IT fusion.37

ATCO suggested, based on the evidence in the proceeding that Calgary’s witness mechanically
applied an incorrectly derived standard in arriving at his recommendations, with the result that
his recommendations should be rejected.

ATCO submitted that Calgary’s argument on IS spending compared the total IS spending of one
company with the statistical average spent by several other companies. This methodology failed
to evaluate whether ATCO acted prudently, as the benchmark may not necessarily provide a best
practice standard for industry.

ATCO argued that its IS spending should be analyzed against the nature and the function of the
item, versus the underlying cost to determine budget prudence. Meanwhile, ATCO pointed out
that Calgary suggested that functionality is irrelevant to the analysis of IS expenditures because
“to perform their basic functions, all pipeline companies would have the same portfolio of
applications.” ATCO submitted that all companies have the same portfolio of applications to
perform basic functions does not, however, speak to the full scope of the applications used by a
company or to the functionality of those applications. As noted by Dr. Chwalowski, the
functionality of the applications used by a company is crucial for the assessment of IS spending:

        It is also not clear how advanced in E-commerce the cited Petroleum companies
        were; as the Gartner report clearly states, more forward-looking companies would
        have higher IT spending. APS would be expected to have a higher IT to revenues
        ratio as it has proactively responded to the marketplace needs for speed,
        information and customer information processing… .38

        The single most significant problem with the Intervener’s submission is that there
        is a failure to provide and analyze the ATCO Pipeline IT capabilities and services.
        The discussion of the IT to revenue ratio without providing the analysis of
        services is very misleading and quite useless. We not only have a concern about
        the use of that ratio, but without the discussion of capabilities, it is not
        meaningful.


        37
             Gartner Report p. 13; Tr. pp. 1721-1722
        38
             Chwalowski, p. 4

                                                       EUB Decision 2001-97 (December 12, 2001) • 61
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


          The intervenor does not have the basis to be critical about the IT expenditures as
          he conducted no examination of the evolution of the IT systems and capabilities
          within APS. As we stated earlier, ATCO Pipelines has been responsive in
          deployment of IT capabilities in response to marketplace pressures; system
          deployment and e-commerce capability deployment explain higher IT expenses.39

ATCO argued that when the IS decisions made by the Company are scrutinized individually,
taking into account functionality, those decisions can be seen to be consistent with just and
reasonable rates.

ATCO submitted that Calgary based much of its argument on IS spending on the Company’s
relationship with ATCO I-Tek. For example, Calgary submitted that the use of this non-tender
process, together with “insourcing” to affiliates increased the costs of IS. ATCO noted that the
relationship between ATCO and ATCO I-Tek will be dealt with in the Affiliate proceeding, and
that the Board therefore, should not address or make any determinations of those issues in this
proceeding.

Positions of the Interveners
Calgary
Calgary suggested that during cross-examination, ATCO’s IS forecast budget was found to be
different than industry expectations because of the following factors:

      •        ATCO Pipelines (AP) IS O&M was allocated 40% to ATCO and 60% to APN40
      •        AP IS depreciation was allocated 50% to ATCO and 50% to AGN41
      •        AP 2000 revenues were about $161 million, with about $40 million from ATCO and
               $121 million or 75% from APN42
      •        AP 2000 assets were about $456 million, with about $143 million in ATCO and $313
               million or 69% in APN43
      •        AP 2000 customers consisted of about 190 producers and industrials, with 39 in ATCO
               and 151 or 79% in APN44

Calgary proposed that forecast IS budgets allocation between ATCO and AGN should follow the
same percentage as revenue split (25% APS and 75% APN) as the allocation method.

Calgary submitted that the Board should accept the conclusions of its witness that:

          •     IS costs of ATCO are outside the bounds of reasonableness, resulting in a
                20% increase in 1999 over 1998, due in large measure to the insourcing with


          39
             Chwalowski, pp. 6-7
          40
             Volume 2, p. 304
          41
             Volume 2, p.303
          42
             Volume 2, pp.304-305 and p.371
          43
             CAL-AGS.116
          44
             Volume 2, p.323 and p.396

62 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                  ATCO Pipelines South


             I-Tek and the fact that the IS budget in 2002 is forecast to be approximately
             30% higher than the 1999 IS budget.45
        •    The 2001 and 2002 IS budgets as a percentage of revenue are more than
             double both the Gas Utilities and Petroleum Industry (Pipeline Comparable)
             averages found in the Gartner survey.46

Calgary referred to ATCO’s argument that the Gartner survey was invalid because it used a very
small sample of only 13 Petroleum companies, and lacked analysis of underlying IT
developments.47 However, Calgary noted that, in cross-examination, Dr. Chwalowski agreed that
it was very likely that to perform their basic functions, all pipeline companies would have the
same portfolio of applications.48

Calgary submitted that ATCO provided no information that would allow the Board to compare
ATCO IS expenditures with others in the industry, whereas Gartner, as the leading worldwide IS
Research company, regularly provided these indicators for nearly all industries.49

Calgary stated that, during cross-examination of the first ATCO panel, it came to light that the
distribution of O&M and IS capital favored AGN more significantly than originally thought.50
Calgary recommended that the Board must direct this be corrected so that IS costs are
proportional to the amount that a customer pays for service, i.e., the revenue split between APS
and APN.

Calgary submitted that the Board should:

        •    Allow ATCO to recover annual IS spending in 2001 and 2002 in an amount
             no more than 1.0% to 1.5%51 of ATCO revenue or approximately $0.4 million
             to $0.6 million.
        •    Indicate the reasons for reducing the level of ATCO IS cost recovery include
             the allocation of costs should be based on the split in revenues between ATCO
             and APN and the jump in costs of approximately 20% when I-Tek started
             providing services to AGS and ATCO in 1999 was inappropriate and should
             be renegotiated. Reducing just these two areas of excessive ATCO IS cost will
             bring IS spending as a percentage of Company revenue to about 1.7%.
        •    Require ATCO to provide annual information filings for Information Services,
             showing all direct and indirect costs in similar detail to that provided in a class
             cost of service study.

Calgary pointed out that ATCO applied to include in rates IT/IS capital of $500,000 for each of
2001 and 2002. Calgary also pointed out that ATCO testified that for all capital projects, large or

        45
           Exhibit 69, SCL 2001 Report - Chart 8 and Schedule 3, line 204
        46
            Exhibit 69, SCL 2001 Report – Chart 10
        47
            Exhibit 99, APS Rebuttal, Rebuttal Evidence of Dr. Chwalowski, pp. 3-4
        48
           Tr., p. 946
        49
           Exhibit 69, SCL 2001 Report, p.12 of 32
        50
           Tr., pp. 277-278
        51
           Exhibit 69, SCL Report, p.5 of 32 – 1.2% plus or minus 20%

                                                              EUB Decision 2001-97 (December 12, 2001) • 63
2001/2002 General Rate Application – Phases I and II                                ATCO Pipelines South


small, there is a work order created that shows the requirement, the options, the cost-benefit
analysis and why the option was chosen.52 Calgary noted that ATCO did not provide these work
orders when they were requested by Calgary.53

Calgary referred to ATCO’s application to include in rates the expenses associated with the
construction of an e-mail notification system which would allow customers to see their bills on-
line54. Given the absence of an ATCO work order, Calgary concluded that the e-mail notification
system was an unnecessary use of technology by an affiliate organization (I-Tek) that ATCO
used as a learning vehicle55 at the expense of customers and not, as Dr. Chwalowski attempted to
assert, a highly responsive approach to its customers needs particularly in the area of e-
commerce.56.

Calgary noted that ATCO IT/IS spending (IS O&M plus IS depreciation/amortization) was
forecast to be $1.5 million or 3.6 % of revenue in 2001 and $1.6 million or 3.8 % of revenue in
200257. Calgary indicated that these amounts do not include58 the SCADA spending (SCADA
O&M plus SCADA depreciation/amortization) forecast to be an additional $1.0 million in 2001
and $0.2 million in 2002.59 Calgary stated that the O&M costs were split 40% to ATCO and 60%
to APN,60, capital costs were split 50% to ATCO and 50% to APN,61 and revenue was split 25%
to ATCO and 75% to APN.62 Calgary stated that it appeared that the IT/IS O&M and capital
splits had more to do with the fact that APN was under a negotiated settlement than with the
competitive challenges of the gas transmission marketplace in Alberta.

Calgary disagreed with ATCO’s assertion that its IT spending is prudent63, submitting that the e-
mail notification system was an example of an unjustified application. Calgary submitted that the
split of IT/IS spending between ATCO and APN increased the Company’s risk to expect
competitive challenges and this split does not ensure all consumers enjoy the benefits of a
competitive marketplace.

Calgary argued that neither ATCO nor Dr. Chwalowski64 provided comparative information to
show the Board that the ATCO level of IS spending was reasonable.

Calgary expressed the view that ATCO IT/IS spending be within 20% of the Gartner Petroleum
Industry (Pipeline Industry comparable) average, which will force ATCO to improve IS
strategies, to evaluate options more critically, to plan application upgrades or changes more

        52
           Tr., pp.269-270
        53
           CAL-APS.64 (b)
        54
           APS Argument, p. 15
        55
           AGS 2001/2002 GRA, Exhibit 85, Work Management System Feasibility Report, p. 27
        56
           Tr., p. 948, line 15 to p. 949
        57
           Stephens 2001 Report, Schedule 3, line 204 and Schedule 5, line 196
        58
           Tr., p. 292, lines 19 to 24 and p. 293, lines 1 to 6
        59
           CAL-APS.102 and CAL-APS.103
        60
           Tr., p. 304
        61
           Tr., p.303
        62
           Tr., p.304-305 and p.371
        63
           APS Argument, p.15
        64
           Tr., p.947, lines 11 to 12

64 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


effectively, and to select outsourcing suppliers that are more cost effective. Calgary argued that
by IT/IS costs should be allocated based on the revenue split between ATCO and APN and
renegotiated I-Tek rates to competitive levels.

Views of the Board
The Board notes ATCO’s argument that its IT spending was prudent, and should be measured
against the nature and the function of item, versus the underlying cost, in order to determine
budget prudence. The Board recognizes ATCO’s perspective that a direct link between IT
spending to revenue is difficult to quantify. On the other hand, the Board notes Calgary’s
argument that IT spending must be gauged against the prudency of the costs and the necessity of
the functions, along with a reasonable correlation to revenues consistent with industry averages,
as argued in the Gartner Report. The Board also notes Calgary’s concern with regards to the
allocation of IT costs between ATCO Pipelines North and ATCO Pipelines South, and their
submission that IT budgets should follow a percentage split similar to revenue split (i.e. 25%
APS and 75% APN), versus the current 40% to APS and 60% to APN split.

The Board recognizes the concerns of Calgary and other Interveners related to IT spending,
allocation of these costs, and their impact on ATCO’s GRA. As these matters are related to
affiliate costs, they are being addressed separately in the Affiliate proceeding.

6 .6 Reserve for Injuries
 .1
ATCO’s forecast for injuries and damages reserve complies with the expense level mandated
under Decision 2000-9 for CWNG. CWNG’s reserve for injuries and damages target is
$300,000, allocated equally between ATCO Gas and Pipelines. ATCO argues that the $300,000
level fails to allow them the opportunity to recover costs for major incidents, nor a means by
which to refund customers when recoveries are below the required reserve level. ATCO requests
that the Board revisit its Decision 2000-9 to address the above stated concerns.

Position of ATCO
ATCO requested that the Board reassess its position in Decision 2000-9 to address concerns that
the Board approved expense failed to allow ATCO to recover costs of significant incidents above
the $300,000 threshold, along with an ability to refund over recoveries to customers. ATCO was
at odds with the CCA on this issue and submitted that the Injuries and Damages reserve remains
at a maximum of $300,000.

ATCO noted that the CCA was “concerned that the division of CWNG into AGS and APS that
there will be an increase of total funding for the reserve for injuries and damages. While the
CCA considers that the requirements for both AGS and APS should be limited in total to
$600,000.” ATCO noted that the reserve was, in fact, limited to $600,000.

Positions of the Interveners
CCA
The CCA pointed out that the application from CWNG for the test year 1998 provided the
following table with respect to the Reserve for Injuries and Damages.

                                                       EUB Decision 2001-97 (December 12, 2001) • 65
2001/2002 General Rate Application – Phases I and II                                     ATCO Pipelines South




                                         Injuries and Damages Reserve
                                                     ($000)
                                  1992         1993        1994       1995       1996       1997         1998
                                 Actual       Actual      Actual     Actual     Actual     Actual       Actual

   Opening Balance               (385)            (380)    (587)      (650)      (502)      (260)           (329)
   Expenses                      (150)            (372)    (261)      (261)      (261)      (261)           (546)
   Payments                       155              165      198        409        503        192             275
   Closing Balance               (380)            (587)    (650)      (502)      (260)      (329)           (600)

The CCA noted that, on page 10 of section 4.2 of its filing, ATCO provided the following table
concerning its reserve for injuries and damages.

                                         Injuries and Damages Reserve
                                                     ($000)
                                          1999              2000                2001             2002
                                         Actual           Estimate            Forecast         Forecast

     Opening Balance                       (64)              (369)              (300)               (300)
     Expenses                             (111)               (22)               (25)                (25)
     Payments                                6                 22                 25                  25
     Adjustments                              -                69                  -                   -
     Closing Balance                        369               300                300                 300

The CCA noted that ATCO stated the following:

        ATCO Pipelines requests that the Board reassess its position in Decision 2000-9.
        By mandating that the reserve be maintained at a level of $300,000, there is no
        opportunity for ATCO Pipelines to recover the costs of significant incidents nor is
        there an ability to refund over recoveries to customers.65

The CCA noted that ATCO indicated that total claims paid out in 1999 were $6,000, related to
the Banff Line Looping Project damage claims, split equally between adjustor and legal fees.

The CCA submitted that a maximum total reserve of $600,000 be maintained for both AGS and
APS, citing Decision 2000-9 to support this position, and reaffirming that a reserve for injuries
and damages of $600,000 was appropriate (Page 89).

Views of the Board
The Board recognizes CCA concerns that the total funding for the reserve for injuries and
damages remain at the $600,000 level, with an equal allocation of $300,000 to AGS and APS.
The Board also notes that ATCO indicated in the Application that total claims paid out in 1999
        65
             Section 4.2, p.10

66 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


were $6,000.00, related to the Banff Line Looping Project. The Board believes that based on
actual and forecast expenses associated with injuries and damages reserve since 1992, the reserve
can be reduced to $175,000, consistent with adjustment of ATCO Gas South in the ATCO Gas
South proceeding. Accordingly, the Board directs ATCO to reduce the reserve for injuries and
damages to $175,000 for each test year.

However, to provide the Board with information to evaluate the ongoing appropriateness of the
reserve balance, the Board directs ATCO, at the next GRA, to provide a more detailed
accounting of the reserve for injuries and damages, including details of amounts required for
major and minor damages, claims history, and the extent to which the reduction in reserve is
offset by increases in insurance premiums.

6 .7 Hearing Costs
 .1
Position of ATCO
ATCO stated that it was allocated 25.17% of CWNG’s hearing costs, based on fixed assets. The
costs associated with the merger of NUL and CWNG were assigned to each merger participant,
and then allocated to ATCO Gas and ATCO Pipelines on a fixed asset basis at December 31,
1998.

ATCO indicated that hearing costs are forecast to increase in 2001 and 2002, based on the
following:

    2001 Forecast
       • Recovery of its share of costs from 1998 CWNG GRA ($957,000)
       • 1999 CWNG GRA ($228,0000)
       • Share of Merger hearing costs ($54,000)
       • 50% of hearing cost for ATCO Pipelines 2001/2002 GRA ($500,000)

    2002 Forecast
       • Estimated hearing cost outstanding for 2001/2002 GRA ($500,000)

ATCO also indicated that hearing costs were adjusted for 1998 and 1999, consistent with Board
Direction in Decision 2000-9, and provided a continuity table in the Application.

ATCO stated that the CCA incorrectly characterized the 2001 forecast recovery of prior years
hearing costs as going to base rates. ATCO pointed out that the 2002 base rates included an
annual provision increase of $500,000 void of one-time costs on existing rates that would carry
through to 2003. ATCO stated that this is consistent with the CCA’s argument and therefore no
adjustment was required.

Positions of the Interveners
CCA
The CCA referred to the following table filed in the previous CWNG application with respect to
reserve for deferred hearing costs.


                                                       EUB Decision 2001-97 (December 12, 2001) • 67
2001/2002 General Rate Application – Phases I and II                               ATCO Pipelines South




                                   Hearing Costs Deferral Account
                                               ($000)
                          1992        1993       1994          1995       1996       1997           1998
                         Actual      Actual     Actual        Actual     Actual     Actual         Actual
Opening Balances           (289)       (245)      (419)         (677)      (147)       158             (57)
Expense                    (296)       (296)      (296)         (296)      (296)      (296)          (1450)
Payments                    340         122         38           826        601         81             907
Closing Balance            (245)       (419)      (677)         (147)       158        (57)           (600)


The CCA noted that in its filing, ATCO provided the following table concerning its deferred
hearing cost reserve account.

                                       Deferred Hearing Costs
                                               ($000)
                                     1999                2000             2001            2002
                                    Actual             Estimate         Forecast        Forecast
    Opening Balance                    46                 313              971               0
    Expense                           (15)               (176)          (1,739)           (500)
    Payments                          282               1,027              768             500
    Adjustment                          0                (203)               0               0
    Closing Balance                   313                 971                0               0

The CCA referred to Decision 2000-9 which indicated that the Board prefers a level amount of
hearing cost expenses.

The CCA agreed with the AEUB that it was preferable to level the revenue requirement effects
of hearing costs. The CCA recommended that a maximum of 50% of the CWNG hearing cost
payments and 100% of the forecast ATCO actual, estimated and forecast payments over the last
ten years be used to set a hearing cost expense amount.

Views of the Board
The Board recognizes that increased regulatory activity and subsequent hearing costs should
preclude the use of historical actual expenditures as a forecasting base as suggested by CCA.
Consistent with Board Decision 2000-6, the Board believes a level hearing expense is preferable,
with a deferral account on any amounts above the hearing expense provision. The Board agrees
with ATCO’s proposal to treat the amount of $1.739 million included in the 2001 forecast as a
one-time expenditure item, and considers that the forecast for 2002 test year should be increased
to an annual hearing cost provision to $500,000 with the balance collected in the deferred
hearing account.




68 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


6 .8 EUB Operating Cost Assessment
 .1
As in the case of hearing costs, CWNG’s EUB operating cost assessment was allocated to ATCO
Pipelines on a fixed cost basis (25.17%) at December 31, 1998. The Company proposed that in
the future that EUB operating costs be accounted as a prepaid asset similar to ATCO Pipelines
North (previously Northwestern Utilities Ltd.), versus the current accounting treatment as a
deferred item.

ATCO indicated that an adjustment was made in Decision 2000-9 for CWNG for an over-
recovery of these expenses in 1998 and 1999 of $191,000, and provided a continuity table for the
EUB operating cost assessment in the Application.

6 .9 Net Cost Recoveries
 .1
Net cost recoveries refer to the recovery of fringe benefits, rent and equipment costs, and
overhead costs for services that ATCO provides to ATCO Gas. ATCO Gas receives services
from the Company’s engineering, operation, customer and pipelines system customer and
pipeline system control services. The contracts for land, natural gas vehicle compressor, and
production facilities services are to be terminated in 2001, and are not included in forecasts.

6 .10 Non-Utility Expenses
 .1
Non-utility items such as rent and corporate donations have been removed from ATCO’s
operation and maintenance expense, consistent with past CWNG decisions.

Views of the Board
The Board notes that none of the interveners took issue with the Company’s forecasts for EUB
assessment, net cost recoveries or non-utility expenses, and accepts the forecasts for these
expenditure categories as filed.

6.2     Taxes Other than Income
Taxes, other than Income taxes, are forecast for 2001 and 2002 at $2,480,000 and $2,677,000
respectively. Municipal franchise taxes are forecast at $280,000 in 2001 and $251,000 in 2002.
Property taxes are forecasted at $2,200,000 and $2,426,000 for 2001 and 2002 respectively. A
detailed calculation of property taxes can be found in the Application.

Views of the Board
The Board notes that none of the interveners took issue with the Company’s forecasts for taxes
other than income, and accepts the forecasts for this expenditure as filed.

6.3     Depreciation
ATCO forecast net depreciation expense and amortization of contributions and other deferred
expenses at $6,886,000 for 2001 and $7,146,000 for 2002.




                                                       EUB Decision 2001-97 (December 12, 2001) • 69
2001/2002 General Rate Application – Phases I and II                                ATCO Pipelines South


Position of ATCO
ATCO indicated that the fixed assets are depreciated or amortized using one of three methods of
calculation:
    1. Straight Line Method (Equal Life Group Procedure)
    2. Contract Life
    3. Straight Line Fixed Rate

For study assets where the Straight Line Method was applicable, ATCO developed depreciation
rates based on the parameters approved in Decision 2000-9 for CWNG that were applied to
vintage survivors as of December 31, 1999 and added a new asset category, Account 496,
SCADA computer equipment to this group.

Facilities depreciated over Contract Life included:

    1. Leasehold improvements amortized over the remaining life of the lease, and
    2. Dedicated facilities constructed at the request of the customers depreciated over the life
       of the underlying contract. In this application, ATCO proposed that new dedicated
       facilities constructed in 2001 or later, be depreciated over a period of twice the contract
       term. This change would bring a consistent practise between the North and South I/P
       customers.

Assets depreciated using the straight line fixed rate method consist of office furniture and office
equipment; tools and work equipment; stores, shop and garage equipment; database mapping;
and major software costs.

Amortization of other items included expenses related to Computer Reserve deficiency resulting
form the retirement of computer assets sold to ATCO I-Tek and deferred Merger Costs resulting
from the restructuring of CWNG.

The 1998 and 1999 depreciation expense for assets where the straight line ELG method was
applied was calculated by applying the rates and reserve amortization adjustments approved in
Decision E93004,66 dated February 8, 1993. Based on Decision 2000-9, depreciation rates and
reserve amortization adjustments for these assets were revised and applied retroactively to the
fixed asset account balances existing in 1998 and 1999. The lower depreciation expense resulting
from the revised rates in each of 1998 and 1999 was recorded in 2000.

In rebuttal, ATCO commented on Calgary’s criticism that a full depreciation study was required
to support its application rather than using a Technical Update from data that was eight years old.
ATCO submitted that changed circumstances should be used to trigger the need for a full
depreciation study rather than an arbitrary 3–5 year period.




        66
             Decision E93004 Canadian Western Natural Gas Company Limited, 1992/1993 GRA Phase I

70 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


Positions of the Interveners
Calgary
Calgary provided evidence from its expert witness Mr. L. E. Kennedy on certain aspects of the
Depreciation Expense requested by ATCO.

Calgary noted that ATCO’s current depreciation recommendations were based on parameters
approved in Decision 2000-9 and that the last full depreciation study was based on data to
December 31, 1994. The original study was competed in 1996, reviewed and updated in 1998
and updated again in 2000 for the current application. Calgary noted that this results in using
depreciation rates for 2002 based upon parameters developed from data that was eight years old.
Mr. Kennedy recommended that a compete review of depreciation parameters should be made
approximately every three to five years. In the circumstances of this application, Calgary stated
that ATCO has far exceeded the reasonable range for which a technical update can be relied
upon to produce accurate results for depreciation rates.

Regarding computer equipment, Calgary submitted that it was inappropriate for ATCO to
suggest that depreciation rates filed and defended in 1999 for its computer equipment, and
subsequently sold to ATCO I-Tek, were now insufficient to fully recover the CWNG investment.
Calgary observed that the proposed loss on sale results from market valuations that incorporate
four-year service lives rather than five or six-year service lives as approved in 1999. Calgary
pointed out that Mr. Kennedy stated that there was no new information or change in technology
that has resulted in a sudden change in future usefulness of the computer equipment. Therefore,
Calgary proposed that the valuation of the computer equipment transferred to ATCO I-Tek be
calculated at the previously approved survivor curves and the depreciation expense amount be
adjusted to reflect the sale at net book value.

Calgary criticized ATCO’s proposal to depreciate facilities related to specific contracts over the
remaining life method for contracts entered into prior to 2001 verses depreciating facilities
related to specific contracts entered into after 2001 for twice the contract period. Calgary
suggested that since 27 of 37 contracts listed were extended past their original contract date,
establishing a significant probability of contract renewals, for consistency, all 10 contracts that
have a remaining undepreciated balance as at December 31, 2000 should be amortized over a
period of twice the original contract life.

In addition, Calgary requested that the investment associated with Contract #30, should be
considered part of the mass property accounts for which ATCO develops depreciation rates using
the Equal Life Group procedure.

Calgary recommended that the Board require ATCO to file a full depreciation study with its next
GRA.

Views of the Board
The Board notes Calgary’s concerns with respect to the calculation of the loss on the sale of
computer equipment to I-Tek. However, the Board recognizes that issues with respect to the
accounting for the loss on sale of computer equipment to I-Tek will be considered in the Affiliate

                                                       EUB Decision 2001-97 (December 12, 2001) • 71
2001/2002 General Rate Application – Phases I and II                          ATCO Pipelines South


proceeding. Accordingly, while the Board is satisfied with ATCO’s amortization of the loss on
sale of the computer equipment to I-Tek, the Board will not address the quantum of the amount
amortized pending the outcome of the Affiliate proceeding.

With respect to the issue of depreciation of contract facilities, the Board in Decision 2000-9,
stated that its primary concern is that an adequate amount is being collected from customers, and
indicated that the matching of revenues to expenses is a secondary concern. The Board’s primary
concern is satisfied by the Company’s assurances that its investment policy ensures that the
present value of a customer’s demand equals or exceeds the capital cost of the asset.

However, the Board considers that ATCO’s proposal to depreciate dedicated contract facilities,
constructed in 2001 onwards over a period equal to twice the contract term recognizes that the
majority of contracts extend beyond the term of the initial contract. The Board believes that this
addresses concerns expressed by Calgary and other interveners in this regard in this and previous
proceedings.

The Board acknowledges ATCO’s submission that the proposed change will result in a
consistent practice between North and South I/P customers. The Board however is not persuaded
that the change should apply to the entire un-depreciated balance related to contract facilities as
at December 31, 2000.

The Board is also satisfied that the practice of amortization of leasehold improvements over the
original contract life term should continue.

The Board notes Calgary’s submission that the investment associated with Contract #30 should
be considered part of the mass property accounts for which ATCO develops depreciation rates
using the Equal Life Group method, as opposed to ATCO’s use of the Contact Life method for
this item. The Board notes that the total investment in this pipeline is $1.26 million at
December 31, 2001, and notes that ATCO has never provided information regarding this pipeline
that would demonstrate that its service life is dependent on the expiration of a specific contract.
Accordingly, in the absence of information to support the use of the Contract Life method, the
Board agrees with Calgary’s recommendation for depreciation of this asset using the Equal Life
Group method.

Accordingly, the Board directs ATCO to revise its depreciation calculations for the test years to
reflect use of the Equal Life Group method for Contract #30.

The Board notes Calgary’s concern that depreciation rates for the test years are based on
parameters developed from a depreciation study that is up to eight years old, which, in Calgary’s
view, exceeds a reasonable range for reliance on a technical update. The Board agrees that a
complete review of depreciation parameters should be carried out more frequently. Accordingly,
while satisfied with the results of a technical update for the purpose of these proceedings, the
Board directs ATCO to file a full depreciation study for the next GRA.




72 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                     ATCO Pipelines South


6.4      Income Tax
Position of ATCO
ATCO forecast income tax expense of $5.9 million (2001) and $6.7 million (2002), calculated
using the flow through method as approved for Provincial Income Taxes in Decision C91023 and
as approved for Federal Income Taxes in the Board’s letter dated May 13, 1996. The tax rates
used were:

                     Federal Income Tax                               28%
                     Provincial Income Tax                         15.59%
                     Total                                         43.50%

ATCO noted that Calgary, in its written evidence recommended that the Board establish
guidelines for the ongoing use of income tax normalization. ATCO pointed out that use of
deferred income taxes was derived from three sources:

      1. Board Decisions (e.g. Deferred Pension and Reserve for Injuries and Damages, Decision
         2000-9, page 124),
      2. the application of prior Board Decisions to new circumstances and
      3. the application of management judgement to new circumstances.

ATCO did not believe that the development and maintenance of guidelines by the Board would
provide benefits in excess of the associated costs, noting that the current practice was based on
Board Decisions and any new items can be properly dealt with based on the specific
circumstances relating to the new items.

With respect to the tax deductions available from issues raised in the Rainbow Pipe Line
Company Ltd. (Rainbow Pipelines) and Canderel Ltd. (Canderel) cases, ATCO pointed out that
these tax deductions have been reflected in the determination of taxation expense.

Regarding the 1998 and 1999 amounts referenced by Calgary with respect to the deductions
allowable pursuant to the Rainbow Pipeline decision, ATCO noted that these are non-test year
amounts, the treatment for which was addressed by the Board in Decision E9510667 dated
November 1, 1995 and confirmed in Order U9603368 dated April 12, 1996. The relevant excerpts
follow:

         The Board considers that any additional producer transportation revenues should
         not be selected in isolation for offset in the GCRR, since there are potentially
         other costs and revenues which have arisen since the last GRA in 1993 which
         would also have to be considered.69



         67
              Decision E95106 Canadian Western Natural Gas Company Limited, 1995/96 Winter and 1996 Summer
GCRR
         68
              Order 96033 Canadian Western Natural Gas Company Limited, Sale of Assets
         69
              Decision E95106, p. 28

                                                              EUB Decision 2001-97 (December 12, 2001) • 73
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


        Respecting concerns raised by Calgary about cost savings and the inherent effect
        on CWNG’s revenue requirement for 1996, the Board considers that regulatory
        principles generally preclude the deferral of particular cost savings arising from
        isolated transactions occurring outside of a test year. The Board notes CWNG’s
        reference to Decision E95106 concerning CWNG’s 1995/1996 Gas Cost
        Recovery Rates. In that decision, the Board considered that certain transportation
        revenues should not be selected in isolation for offset in calculating the gas cost
        recovery rate, because of the potential of other similar or related costs or revenues
        which would not have received the same treatment. The Board considers that the
        same principle of non-isolation should also apply to the sales of the P&NG
        assets.70

ATCO also noted Calgary’s statement that:

        Other utilities (e.g. Enbridge Consumers Gas and AltaGas) have specifically
        documented how the savings arising out of these decisions have been passed on to
        customers.

In ATCO’s view, this represents new, unsupported evidence.

ATCO submitted that the reference to the financial statements of The Consumers Gas Company
Limited does not provide evidence of Enbridge Consumers Gas’ and AltaGas “specifically
documented” regulatory treatment, nor does it provide the context (test year vs. non-test year).
ATCO submitted that the new evidence submitted by Calgary in argument should be rejected.

Noting intervener concerns with respect to the taxation rates used in determining income tax
expense, ATCO pointed out that, at the time of filing the Application, neither the Federal nor the
Provincial Tax Rate changes were substantively enacted in accordance with CICA Handbook
Section 3465, and at the time of the response to BR-APS-21, only the Federal rate changes were
substantively enacted. ATCO noted that Calgary and the CCA both recommend adjustments to
ATCO’s Application to give effect not only to Federal Rate changes but also to Provincial Rate
changes whether or not they have been substantively enacted.

ATCO submitted that an adjustment to tax rates would be inconsistent with prospective rate
making and it would be patently unfair to the Company if the tax rate adjustment was processed
while certain other cost increases and revenue adjustments were not processed.

ATCO noted Calgary’s suggestion that savings associated with possible 2003 income tax rate
changes be placed in a deferral account. In ATCO’s view, the principle of non-isolation, noted
by the Board in the excerpts from Decision E95106 and Order U96033, applies not only to
deferral of non-test year amounts but also to the proposed deferral of future amounts. ATCO
submitted that Calgary’s suggestion to defer future income tax rate changes be rejected by the
Board.



        70
             Order U96033, p. 5

74 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


Positions of the Interveners
Calgary
Calgary expressed concern with respect to the computation of income taxes on two counts. First,
Calgary referred to the change in assessing practice relating to the Rainbow Pipeline case and the
notification provided to The Consumers Gas Company Limited, referred to in their financial
statements, whereby Canada Customs and Revenue Agency allows gas utilities to write off
greater amounts that were previously capitalized for tax purposes. In ATCO’s case, Calgary
noted that, while the only amount that would seem to relate to this is the indirect overheads, no
indication was provided to ascertain whether that is in fact the case.

Calgary noted that ATCO has indicated that with respect to AGPL, the change in assessing
practice arising out of the Rainbow Pipelines/Canderel decisions resulted in tax savings of $1.9
million in 1998 and $2.1 million in 1999.71 Calgary considered that these saving obviously went
to the shareholders in those non-test years, and pointed out that other utilities (e.g. Enbridge
Consumers Gas and AltaGas) have specifically documented how the savings arising out of these
decisions have been passed on to customers. Calgary remained concerned with ATCO’s failure
to provide specific documentation of how these decisions have benefited customers in the test
years.

The second matter noted by Calgary relates to the increased use of deferred income taxes.
Calgary noted that ATCO seems to be slowly inching away from flow through tax accounting
and appears to be moving towards full normalization. Calgary however, recognized that the
deferred income taxes in the test years were drawdowns of prior years deferrals, but given the
number of items for which deferred taxes have been recorded, considered that some guidelines
were required for the ongoing use of normalization.

Calgary considered that ATCO’s treatment of tax rates in the Application borders on disdain for
the interests of its customers, particularly for those customers served through AGS, who under
ATCO’s approach to costing bear all the residual costs. Calgary pointed out that changes in
income tax rates have been proposed by both the Alberta and Federal Governments, and given
the sizable majorities and recent mandates of both governments, it is virtually inconceivable that
these changes to income tax rates will not come to fruition. Calgary noted however, that ATCO
has used the existing rates in its Application.

Calgary submitted that the Board should direct that ATCO use the federal income tax rates
approved72 and the provincial income tax rate approved for April 2001 to March 31, 2002,73 as
well as the forecast reduction for April 2002 to March 2003. Further, to the extent that ATCO
does not have an Application for a change in rates in 2003, Calgary submitted that the Board
should direct that any savings associated with the changing income tax rates should be placed in
a deferral account for the benefit of customers. Calgary considered it ludicrous to suggest that a
change in income tax rates was an “efficiency” achieved by ATCO.


        71
             Tr., p. 1468
        72
             BR.APS.21
        73
             Tr., p.1058

                                                       EUB Decision 2001-97 (December 12, 2001) • 75
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


CCA
The CCA referred to Tr. p. 1058 and p. 1059, where the witness for ATCO agreed that, regarding
the provincial income tax rate, reductions have been made effective April 1, 2001, and enacted
through legislation. The corporate income tax rate was 13.5% for 2001, and has been proposed to
go to 11.5% on April 1, 2002, although there has been no enacting legislation.

The CCA considered that forecast income tax expense should be updated for both enacted and
introduced or announced federal and provincial income rates.

The CCA noted that Calgary stated that it was concerned about changes in income tax
assessment practices. Specifically, Calgary was concerned about the Rainbow Pipeline case as
demonstrated in the notes to the financial statements of The Consumers Gas Company Limited.
The CCA noted that this case law allows gas utilities to write-off amounts that were previously
capitalized for income tax purposes.

The CCA considered that the benefits of lower income tax expense from the quicker write-offs
of previously capitalized expenses should flow to customers because of the Rainbow Pipeline
case. By reducing write-offs of capital expenses a utility would cause higher income tax expense
in future years.

The CCA submitted that ATCO should be directed in it’s refiling, to provide complete details of
the potential range of effects of the Rainbow Pipeline income tax case.

Views of the Board
The Board notes Calgary’s concern with the increasing use of deferred taxes, and its proposal for
development of guidelines for ongoing use of deferred accounts. In this regard, the Board
acknowledges ATCO’s submission that the deferrals are established pursuant to prior Board
Decisions, particularly Decision 2000-9, and considers that the nature of the deferrals in the
Application is consistent with the criteria established by the Board in Decision 2000-9. The
Board therefore agrees with ATCO that the development of guidelines would not provide any
additional benefits.

The Board notes Calgary’s observation that the change in assessing practice arising out of the
Rainbow Pipeline decision, which relied on the Canderel decision, resulted in tax savings of $1.9
million (1998) and $2.1 million (1999) to shareholders of AGPL. While acknowledging
Calgary’s concern that other utilities have documented how customers have benefited from the
savings arising from those decisions, the Board considers that ATCO’s method of accounting for
these savings is consistent with past practice in this jurisdiction. Specifically, as noted by ATCO,
in Decision E95106 and Order U96033, the Board confirmed that regulatory principles generally
preclude the deferral of cost savings arising from isolated transactions occurring outside of a test
year.

The Board notes that Section 3465 of the CICA Handbook specifies that income tax assets and
liabilities be measured using the income tax laws and rates that are expected to apply when the
asset is realized or liability settled. Section 3465 states that it would be appropriate to use a


76 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


substantively enacted rate that the Government is able and committed to enacting in the
foreseeable future. The Board notes that Clause 112 of the March 2001 Income Tax Act,
indicates that the rates in effect for 2001 will be reduced by 1% from previously prevailing rates,
and by 2% for 2002.

The Board agrees with Calgary’s submission that, in determining income tax expense and
liabilities for the test years, ATCO should use the federal income tax rates as set out in the 2001
Income Tax Act, and the provincial income tax rates announced by the Alberta Government
applicable for periods from April 2001 to March 2003. Accordingly, the Board directs ATCO to
recalculate income tax expense and liabilities for the test years using those rates announced or
substantively enacted by the federal and provincial governments for those years.

6.5     Unaccounted-for Gas (UFG)
UFG is defined as the difference between the quantity of natural gas receipted onto a pipeline
and the quantity of natural gas delivered off the pipeline excluding compressor fuel used during
the transmission process.

Position of ATCO
ATCO submitted evidence in its Application with respect to establishing unique and appropriate
UFG rates for APS and AGS. As noted in the evidence, a “blended” or combined UFG rate
currently exists for both APS and AGS, as custody transfer metering does not exist between the
transmission facilities owned by APS and the distribution facilities owned by AGS. Accurate
metering is in place at all other locations where APS either receipts or delivers volumes on or off
its system.

To accurately measure UFG, APS requires the installation of custody transfer meters at
approximately 667 interconnections with AGS, at both the receipt and delivery points.

ATCO indicated that, since meters are not in place at the delivery points to AGS, UFG
determination by accurate measurement is not possible at this time. ATCO proposed a
methodology to calculate UFG on an interim basis by prorating the blended UFG for AGS and
APS into components for each. From the data collected and recommendations provided from two
consultants, ATCO determined that a 2.3:1 ratio between the distribution UFG and transmission
UFG was a representative average ratio that was applicable to splitting the ATCO blended UFG.
Since the blended UFG rate approved by the Board was 1.391% for AGS and APS combined, the
UFG for APS was calculated at 0.42%. The compressor fuel component of 0.17% would only be
applicable to the ATCO transmission system and would be added to the 0.42% UFG. ATCO
proposed to utilize this preceding procedure for 2001 and 2002 and until the custody transfer
metering installations were completed.

ATCO undertook this endeavour to ensure that fair and reasonable UFG rates are applied to each
respective system rather than maintaining the blended UFG approach. ATCO pointed out that it
has been the Industrial and Producer customers who have been subsidizing the Core customers,
and expressed the view that the installation of the meters and interim allocation methodology
will correct this cross-subsidization.


                                                       EUB Decision 2001-97 (December 12, 2001) • 77
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South




ATCO indicated that, as noted in the response to BR.ATCO Pipelines.7, the installation of the
meters will also allow AGS and APS to focus within their systems to try and ascertain ways to
decrease UFG overall. ATCO pointed out that, without the meters this would not be possible,
and that without the meters and a correct allocation of UFG on an interim basis, ATCO will
continue to have an artificially imposed business risk due to a UFG rate that is clearly neither fair
nor appropriate. ATCO indicated that its primary competitor has neither a delivery toll nor a
UFG charge for deliveries in Alberta, and that, without appropriate and reasonable UFG rates for
the Industrial group, bypass is a very realistic option.

ATCO noted that some Interveners have attempted to portray what is a very simple issue as
complex. In ATCO’s view this was done to cloud the underlying fact that the current blended
UFG rate is a benefit to core consumers, as they are being cross subsidized by Industrial and
Producer customers. ATCO noted that both the MI and Calgary claim that the burden of proof
has not been met, and stated that this claim is no surprise to the Company, as neither Calgary
nor the MI would continue to enjoy the benefit of cross-subsidization should a change occur.

To establish unique and appropriate UFG rates, ATCO applied for approval to:

      1.    Install accurate measurement between the APS and AGS systems so that an
            appropriate UFG rate for each respective system could be determined, and
      2.    Establish an interim allocation of the existing blended UFG rate between APS and
            AGS while the meters are being installed and metering history is established,
            approximately 3 years. Meter installation is to occur in 2001 and 2002.

ATCO indicated that the allocation method was based upon a ratio of fugitive emissions between
ATCO Pipelines and ATCO Gas, and a ratio of the UFG experiences of all distribution and
transmission companies in the United States (at an aggregate level). ATCO utilized the lowest of
the ratios, being 2.3:1, to ensure that a fair approach was used. The 2.3:1 ratio is the level of
distribution UFG (ATCO Gas) to transmission (ATCO Pipelines). As outlined in the response to
CCA.ATCO Pipelines.21(h), ATCO indicated that a UFG level of 1.52% was established for
ATCO Gas and .42% for ATCO Pipelines, based on the current blended UFG rate (Rider “D”) of
1.391% as approved by the Board.

Positions of the Interveners
IGCAA
IGCAA submitted that the issue is of direct concern to it because it directly affects the plant gate
cost of members connected to the ATCO system, and in the current era of high plant gate prices
the proper allocation of costs could mean the difference between some plants operating in
Alberta or plants shutting down.

IGCAA indicated that its members compete in world markets, and cited the example of the
ammonia producing industry, of which several plants are connected to ATCO’s system. IGCAA
noted that in early January 2001 about 50% of North American capacity was shut in, including
two plants in Alberta. Since then many of these plants have come back on line to meet the


78 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


expected demands of the spring fertilizer market. Once the spring season is complete it is likely a
number of plants will again be shut-in. This appears to be very likely given unfavorable climatic
conditions that may restrict the volume of fertilizer sold this spring.

IGCAA considered that ATCO Pipelines North has the same issue, in that UFG is improperly
allocated on that system as well.

IGCAA has agreed to a settlement with ATCO Pipelines that calls for the UFG issue to be dealt
with in the current ATCO Pipelines South GRA. It also calls for the issue to be dealt with by
ATCO Pipelines North “in a similar manner as soon as is practical after the South has been
addressed.” Given the settlement agreement with the North Core group, IGCAA believed that
implementation of the methodology approved by the Board should be applied to the North upon
expiry of the current North Core agreement. However given the time that is required to install the
necessary metering, IGCAA asked the Board to direct ATCO to undertake a program to install
the necessary metering in ATCO Pipelines North so that upon expiry of the North Core
settlement a proper allocation of UFG costs could be determined.

IGCAA indicated that, in the face of high gas costs, the least economic plants would be the ones
forced to shut in, and with high gas costs, UFG becomes a substantial cost of transportation.
IGCAA submitted that, to ensure that Alberta industrial gas consumers remain competitive, it
was essential that UFG costs are fairly allocated to them. IGCAA noted ATCO’s position that
proper allocation of UFG is essential to its competitive position, and considered ATCO
prejudiced in its ability to compete with other gas transmission companies if it is forced to assess
UFG against its customers which is actually caused by the distribution system operated by
ATCO Gas.

IGCAA submitted that the Board must act now to ensure that during these periods of high and
volatile gas prices, both ATCO and its industrial customers are able to compete. In IGCAA’s
view, the need to address the UFG issue was a matter of both equity and efficiency. Equity
requires that customers who actually cause the UFG should pay for it. Efficiency requires the
identification of the sources or causes of UFG to obtain information necessary to reduce the
amount, as well as to provide motivation to those responsible to deal with it.

IGCAA took issue with PICA’s submission that the Board should not do anything on an interim
basis, as there was no particular urgency associated with UFG, submitting that this was
completely inconsistent with PICA’s position that UFG was one of the most significant issues in
the hearing, representing a considerable cost in transportation tolls paid by industrial customers.

IGCAA submitted that, in the period prior to installation and operation of the meters, the Board
needs to approve an interim allocation methodology in order to ensure equity between APS and
AGS customers, and to ensure that ATCO’s industrial customers remain competitive with
respect to the cost of gas supplied to them. IGCAA submitted that the Board should not leave the
UFG issue to be dealt with through negotiated rates from now until 2004.




                                                       EUB Decision 2001-97 (December 12, 2001) • 79
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


AIPA
AIPA submitted that it would be preferable and less confusing if UFG was applied to receipt
volumes rather than delivery volumes, which would result in all customers, including producers,
being responsible for their appropriate share.

MI
The MI noted that, following the February 1999 I/P Settlement, UFG was only collected on
deliveries off the system, which effectively resulted in no UFG charges being incurred on
producer gas delivered on-system. The MI noted that, as a consequence of the re-opener to the
Settlement, UFG represents the bulk, if not all of the tolls for I/P customers, thereby leading to
bypass. The MI also noted that, given the dramatic increase in gas prices, UFG was discussed
extensively by the negotiating parties, who did not include core customers, without an
appropriate resolution for the issue. Referring to Clause 11(b) in the Settlement, the MI noted
that the Settlement could be re-opened if a regulatory decision for the ATCO Pipelines UFG
does not result in a significant change to the UFG rate charged to ATCO Pipelines’ customers.

The MI expressed concern with ATCO’s proposal, based on an analysis of US data, which
appears to be another attempt to shift a large cost component to core customers in order to enable
ATCO to be more competitive on I/P rates. Specifically, the MI submitted that since physical
losses comprise only 8–10% of UFG, the primary cause is measurement related including, not
only metering inaccuracies, but also temperature, pressure and heating value errors, indicating
that there is no reason why UFG should not be charged to all customers, including producers at
receipt points.

Calgary
Calgary noted that ATCO has requested the treatment of UFG be changed so that:

     •   producers do not contribute any volume for UFG on deliveries; and
     •   the combined AG and AP ratio be allocated on the basis of 2.3:1 between AGS and APS,
         which for 2001 would be 0.42% for AP and 1.52% for AG.74

Calgary submitted that the onus was on the Applicant, in this case ATCO, to justify the
reasonableness and the need for the change in UFG proposed. Calgary submitted that ATCO has
done neither. The single “study” on which ATCO relied for the 2.3:1 ratio appeared flawed to
Calgary. Calgary argued that cross-examination by both PICA and Calgary75 showed that the
study results76 were flawed. They were, in fact, not a study at all, but rather a compilation
undertaken with no consideration of the nature of the data reviewed.

Calgary indicated that other LDCs with a combination of distribution, and what ATCO calls
transmission, have lower UFG ratios than the combined entity of APS/AGS. There are factors


         74
            Exhibit 4, APS Application, Section 6.1, p. 9 of 9
         75
            Tr., pp. 767 - 778, and 910 - 927
         76
            CAL-APS.94 and 96.

80 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


other than metering between APS and AGS that can account for UFG. The principle difference
between APS/AGS and other LDCs is the number of receipt points with producers.

Calgary noted ATCO’s assertion that Mr. Johnson is incorrect when he indicated that producers
do not pay UFG. Calgary noted that the tariffs filed in section 8.0 of the Application indicate that
Rider “D”, which collects the UFG, is not applicable to firm service charges payable by
producers at each point of receipt. Calgary indicated that this was the point Mr. Johnson was
making. Calgary pointed out that, to the extent that producers are also contracting for delivery
service, they might pay UFG. Further, Calgary stated that if one accepts Mr. Wolnik’s causes for
UFG at page 6 of his report, then 71% to 100% of the causes of UFG are related to accounting,
measurement, and leakage. Calgary noted that these three factors would of course be applicable
to receipts from producers. Calgary submitted therefore, that producer receipts will cause UFG,
and it is inappropriate that UFG caused by one class of customer be collected from all other
customers.

Calgary noted that IGCAA only raised two issues in this proceeding, UFG and the need for a
standard contract between AG and AP. Calgary also noted that IGCAA adopts the ATCO
“evidence,” but did not review the ATCO “studies” to determine their validity.77

Views of the Board
The Board acknowledges ATCO’s submission that its main competitor does not levy a UFG
charge for deliveries in Alberta, and that without the establishment of an appropriate and
reasonable UFG charge for deliveries to the Company’s industrial customers, bypass is a very
real possibility. The Board agrees that this risk requires that ATCO take steps to ensure that the
UFG component of tolls for transmission delivery service is reasonable. The Board is prepared to
accept the Company’s position that application of the prevailing blended rate should only
continue if all classes of customers using the system can be regarded as being equally
responsible for causing UFG on the system. Based on the submissions of all parties, the Board
considers that this is clearly not the case.

Accordingly, the Board agrees with ATCO that, until the proposed UFG metering is installed,
there is need for an interim allocation of UFG based on the relative responsibility applicable to
transmission and distribution customer classes. First of all, the Board considers it appropriate
that ATCO proposes to charge UFG on delivery volumes only, on the basis that there is no
physical loss at the point of measurement into the transmission system. UFG occurs during the
time that gas volumes travel down the pipeline system until they are delivered off the system.
The Board considers it reasonable that the customers to whom volumes are delivered should be
responsible for bearing the cost of any volume losses as the gas flows downstream, since their
requirement for the gas generated the inflow to the system. Accordingly, the Board does not
agree with the submissions of Calgary, AIPA and the MI regarding application of UFG to receipt
volumes.

With regard to the relative responsibilities of the distribution and transportation customers for
UFG costs, the Board notes the submission of IGCAA that UFG is caused by the distribution

        77
             Tr., pp. 1251 and 1252

                                                       EUB Decision 2001-97 (December 12, 2001) • 81
2001/2002 General Rate Application – Phases I and II                        ATCO Pipelines South


system operated by AGS. However the Board believes that IGCAA failed to make a sufficiently
substantive case to support that view. In the Board’s view, the general consensus appears to
support ATCO’s position that distribution and transmission share the responsibility for UFG on
the system. In the Board’s view, no compelling evidence has been presented to refute ATCO’s
arguments in this regard. Accordingly, the Board is satisfied that ATCO acted responsibly in
undertaking a study to identify the appropriate allocation of responsibility for UFG between
transmission and distribution customers. In the ensuing paragraphs of this section of the
Decision, the Board will address the appropriateness of the study undertaken by ATCO to
determine responsibility for UFG.

The Board notes the submission of IGCAA that ATCO Pipelines should be directed to undertake
a program to install metering in the North. As this proceeding deals only with ATCO Pipelines
South and its customers, it would be inappropriate for the Board to include such a direction in
this Decision.

6 .1 Canadian Information
 .5
Position of ATCO
ATCO stated that, as indicated in the Company’s evidence, three Canadian pipeline companies
and four distribution companies were contacted regarding their UFG experience, but that none
were prepared to provide details on their total UFG experience. ATCO stated that, as noted in the
executive summary of Mr. Wolnik’s report, these companies represented approximately 65% of
the transmission pipeline network and 70% of the distribution system network in Canada,
respectively. Without these major companies being willing to provide details on their UFG
experience, ATCO stated that it determined that attempting to go further with Canadian
information was not feasible. ATCO pointed out that in cross-examination Mr. Wolnik reviewed
the information requested from the Canadian companies and identified that Canadian companies
are not required to file such information, unlike comparable companies in the United States.

With regard to the information from TransCanada Pipelines (TCPL) regarding some historical
information on UFG introduced by PICA in cross examination, ATCO noted that the information
provided was dated up to 1998. ATCO took the position that if the data was available, which,
based upon Mr. Wolnik’s research, it was not, having UFG experience from only one Canadian
transmission company would still not be useful in establishing any reasonable or fair allocation
methodology. ATCO refuted the comments of PICA regarding the availability of Canadian data
on UFG, indicating that the major distribution/transmission companies contacted were not
prepared to provide details on their total UFG experience.

ATCO also noted that the MI have requested:

        ….that the AltaGas UFG rate should be given strong consideration in determining
        an appropriate UFG rate for sales customers




82 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


ATCO found this request to be unacceptable as:

    •   at no time did the MI submit evidence to suggest the validity of the AltaGas rate, nor was
        it tested in cross-examination; and
    •   AltaGas is a single organization and the UFG experience of one single company does not
        represent that of another.

ATCO stated that it did not specifically respond to any comments made by Calgary with respect
to the Union report, as it was clear from the Board's decision during the proceedings that while
the existence of the report was not disputed, the UFG analysis was not to be admitted. ATCO
referred to the following statement by the Board:

        In other words, the Board is not prepared to accept evidence through the back
        door that the parties are unprepared to put in through the front door.

        With regards to the specific document Calgary wished to put to the ATCO
        witnesses, that is the Union UFG analysis, the Board notes that this report was in
        Mr. Johnson's possession prior to the start of this hearing. Clearly, the City should
        have, if the City believe the report is relevant to the decisions this Board must
        make, sought leave to file this report before this hearing commenced or at the
        very least, … at the start of the hearing.78

ATCO submitted that the Board should disregard any statement from Calgary that contains
information that flows from the Union report.

ATCO also requested that the Board sanction Calgary’s conduct in whatever way it deems
appropriate, and submitted that the matter be dealt with in costs.

Positions of the Interveners
IGCAA
IGCAA considered that the MI had raised a substantive point when submitting that ATCO
should have considered the AltaGas experience when submitting its Application. In IGCAA’s
view, this provided an Alberta benchmark for the UFG experience of a distribution utility.
IGCAA submitted that the AltaGas data represents the fairest and most accurate picture of UFG
pending installation of interconnect metering.

PICA
PICA noted that IGCAA had suggested that the only relevant Canadian experience concerning
UFG is AltaGas. On the other hand, they also indicated that the experience of other Canadian
companies, such as TransCanada, is unlikely to be relevant, even though the negative UFG
experienced by TransCanada would be beneficial to IGCAA. PICA submitted that IGCAA had
missed PICA’s point that TransCanada’s UFG experience was public information and refuted the
position advanced by ATCO that such data was not available from Canadian Pipelines. Further,
        78
             Tr. p.576

                                                        EUB Decision 2001-97 (December 12, 2001) • 83
2001/2002 General Rate Application – Phases I and II                         ATCO Pipelines South


PICA submitted that the TransCanada data clearly demonstrates that UFG calculations are not
always positive, reinforcing the point there is no reason to assume that the ATCO UFG
experience, when actually measured after the installation of the new metering, will correspond to
any particular average drawn from any source of data. Finally, PICA stated that, since the
TransCanada mainline UFG experience is derived from the difference between gas metered into
the mainline from the TransCanada Alberta Division (previously NGTL), TransCanada mainline
data has an additional degree of relevance since NGTL is the same company metering much of
the gas into ATCO. PICA noted that this point was also acknowledged by ATCO’s witnesses
during the hearing and was in no way refuted by IGCAA in its argument.

PICA noted that ATCO had suggested that the TransCanada data introduced by Mr. Liddle was
the only Canadian data available and had further suggested it would be unreasonable to use data
from only one Canadian transmission company. PICA submitted however that ATCO’s policy
witness had agreed that all Canadian utility companies experience UFG and have to recover their
costs of UFG through rates approved by their regulator. Given the public nature of such
regulatory rate approval proceedings, PICA submitted that UFG information must be available
from the public record for other Canadian utility companies. PICA considered that the onus is on
the proponent, in this case ATCO, to provide the necessary evidence to support a proposed
change or new investment. PICA submitted that, in this instance, ATCO had failed to make any,
or at the very least adequate or reasonable efforts to secure what must be available and relevant
information for consideration by the Board and ATCO customers. PICA considered that this
failure to provide relevant data casts considerable doubt as to the validity of ATCO’s assertions
and the use of alternative data in relation to the UFG of other utilities.

Furthermore, PICA pointed out that the hearing record is also clear that UFG information exists
for Union Gas and AltaGas, and therefore, ATCO’s contention that data is only available for one
Canadian company is both misleading and incorrect.

MI
The MI noted that AltaGas is currently using a UFG rate of 0.88%, a value which had not been
reviewed by ATCO prior to the hearing. When asked why AltaGas would have a rate of 0.88%
compared to the Company’s 1.56%, the MI noted that ATCO made the observation that the
AltaGas average included a rate as high as 1.31%. The MI pointed out that ATCO had also used
a 3-year average to determine the current rate rather than the highest amount, and submitted that
the AltaGas UFG rate should be given strong consideration in determining an appropriate rate for
sales customers.

The MI noted that IGCAA was the only party supporting ATCO’s UFG proposal, and that
IGCAA went even further, by recommending using a ratio of 3:1, a more favorable solution to
IGCCA. The MI submitted however, that IGCAA’s underlying support for its position contained
some significant errors. Specifically, the MI noted that IGCAA’s position suggests that the only
relevant Canadian UFG experience is provided by AltaGas, and that the experience of other
companies, such as TCPL is unlikely to be relevant, even though the negative UFG experience of
TCPL would be beneficial to IGCAA’s case. The MI referred to PICA’s argument in this regard,
indicating that the TCPL data was readily available, relevant and demonstrated that UFG
calculations are not always positive.

84 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South




The MI submitted that ATCO has failed to provide the necessary evidence, readily available
from Canadian sources to support the change or investment proposed. The MI submitted that the
record clearly indicates that information exists for Union Gas and AltaGas, contrary to ATCO’s
assertion that data is only available for one Canadian Company.

Calgary
Calgary considered ATCO’s claim that there was no data available for Canadian pipelines and
Canadian LDCs79 to be surprising. Calgary stated that ATCO’s own counsel, through his
knowledge of other proceedings, proved the unreliability of his own client’s evidence.80

Calgary stated that it had reviewed other evidence and submitted that there is Canadian data
available, although the data may not be tabulated in a manner such that it can be accepted and
applied carte blanche. Calgary considered that data from any external source would require
examination and analysis before being used, and felt that it appears as though ATCO quickly
commissioned a study to achieve a pre-conceived notion and, as a result, ended up missing
relevant data.

Views of the Board
The Board agrees with the statements of Calgary and the MI that it would have been preferable
for ATCO Pipelines to have completed a more comprehensive UFG study, incorporating relevant
Canadian data. At the same time, the Board acknowledges the Company’s representations that
several Canadian companies contacted in this regard, representing approximately 65%-70% of
transmission and distribution companies, were not prepared to release details with respect to their
UFG experience. Therefore, although more data would have been useful, the Board is not
prepared to find ATCO at fault for the paucity of information presented at the hearing. The
Board also acknowledges ATCO’s reservations regarding the use of information from
TransCanada Pipelines. In the Board’s view, the Company has a responsibility to exercise
prudence in terms of the extent of effort and related cost that should be invested in the data
gathering process.

The Board does not agree with intervener submissions regarding the use of AltaGas data,
particularly since the data in question were not available for cross-examination.

With respect to Calgary’s submissions regarding consideration of available data from Union Gas,
the Board’s ruling, as already expressed during the proceedings, is that the Union Gas UFG
analysis is not to be admitted as evidence, on the basis that Calgary should have made the
documentation available to the Board and other parties at the earliest possible opportunity, to
allow for review and consideration by witnesses in advance of cross-examination.




        79
             CAL-APS.94 (b) and Tr., pp. 740-762
        80
             Exhibit 130

                                                       EUB Decision 2001-97 (December 12, 2001) • 85
2001/2002 General Rate Application – Phases I and II                             ATCO Pipelines South


6 .2 United States (U.S.) Information
 .5
Position of ATCO
ATCO pointed out that, once Canadian data was found to be not readily available, Mr. Wolnik
recommended that the overall UFG experience in the United States be used. ATCO indicated
that the U.S. data, overall or aggregate, is available, as natural gas pipeline operators are required
by FERC to file annual reports of natural gas sold and transported. As well, natural gas
consumption data is available from the U.S. Energy Information Administration (EIA). ATCO
stated that this data was available for 1992 through 1998, for approximately 1400 distribution
companies and 60 transmission companies.

ATCO pointed out that using this data and Lost and Unaccounted For information provided by
the Gas Research Institute (GRI), overall representations for distribution and transmission UFG
levels could be ascertained, as noted in Mr. Wolnik’s report and Section 6 of the Application.

ATCO noted that Mr. Liddle, in his cross-examination, referred to specific information for the
states of California, Washington and New York, in attempting to identify potential anomalies in
reporting for these states for 1995, 1996 and 1997. ATCO stated that what Mr. Liddle did not
indicate is that the averaging of “all” U.S. data went from 1992 to 1998 for the purposes of
establishing an average overall U.S. UFG rate. The case of using many years of data for all of the
U.S. would have the effect of normalizing any small or isolated anomalies. Mr. Wolnik indicated
at Tr. p. 771, that he did not try to manipulate the data.

ATCO also noted that PICA’s argument relating to the status of California, Washington and New
York, now also included Louisiana even though nowhere in the transcripts nor within the Exhibit
138 referenced by PICA, was there any reference to that State.

ATCO pointed out that, in the context of determining end-use consumption, the transmission
pipeline is a carrier of gas volumes, which represent the gas supplied to distribution utilities and
end-use customers. The throughput of the transmission pipeline is, for the most part, a pass
through of gas volumes to the distribution system and end users minus the losses (UFG) and
pipeline operations gas use. ATCO stated that, clearly, the entire distribution industry is, in fact,
the total value transported through the transmission pipeline network.

ATCO indicated that, specific to Mr. Vander Veen’s example relative to the 1998 pipeline
system deliveries, in fact, the total consumption in the U.S. was 21.26 TCF,81 which included all
consumption. This consumption included not only gas delivered by transmission lines to LDCs,
co-ops, municipalities and electric power generators, but also gas used in leasehold production
facilitates, gas plant operations and compressor fuel for pipeline operations.

ATCO indicated that the 19.47 TCF (1998) quoted as 19 TCF by Mr. Vander Veen, referred to
the transmission throughput volume of gas delivered for consumption by residential, commercial
industrial, vehicle fleet and electrical utility customers of LDCs, co-ops and municipalities. It
excludes consumption volumes upstream of the distribution system receipt points.


        81
             CAL-ATCO Pipelines.94, Table 3

86 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                       ATCO Pipelines South


ATCO noted that the difference between these two values is 1.79 TCF (not the 3 TCF as quoted
by Mr. Vander Veen) and this volume relates specifically to volumes consumed upstream of the
distribution system.

ATCO indicated therefore, that for the purpose of calculating UFG as a percentage of
transmission throughput or consumption attributable to gas delivered to distribution system
customers, the use of 19.47 TCF is appropriate.

Similarly, for the purpose of arriving at a representative average of the total gas supply system
UFG, the 21.26 TCF (1998) is the appropriate base. ATCO submitted that including these
volumes in total consumption results in a reasonable estimate of total UFG and represents a fair
and reasonable approach.

ATCO went on to refer to Mr. Vander Veen’s statement that the 15 transmission companies
sampled to verify Mr. Wolnik’s work have more throughput than the overall 60 combined within
all U.S. data. ATCO pointed out that this is due to the exclusion of “interstate transfers” between
transmission pipelines. Specifically, if one pipeline delivers to another, it represents the same
throughput for consumption purposes, and, on an aggregate basis, it must not be double counted.
ATCO noted that, when looking at a specific company, such as each of the 15, the throughput for
each must be used solely to determine the UFG level for that specific company.

Referring to matters raised by Calgary, the MI and PICA regarding the discussions on the use of
U.S. data, ATCO indicated that its position was very clear:

        Once Canadian data was found to be not readily available, Mr. Wolnik
        recommended that the overall UFG experience in the United States be used.82

Positions of the Interveners
IGCAA
IGCAA submitted that the methodology put forward by ATCO appears to be somewhat
arbitrary, based on selected United States pipeline systems for which it is impossible to judge the
comparability with the ATCO Pipeline system. IGCAA questioned the fact that Table 6.1-5 in
ATCO’s evidence shows that the average UFG for 15 U.S. transmission companies similar to
ATCO Pipelines is 0.25%, yet ATCO uses a UFG figure of 0.42% for its transmission system
based on an additional 45 U.S. transmission companies. IGCAA requested the Board to order
ATCO to use 0.25% for the 2001 UFG for ATCO Pipeline’s transmission system.

Referring to intervener opposition to ATCO’s use of data from U.S. pipelines to derive the
allocation, IGCAA considered that the reason for the necessity of this data was overlooked, and
stated that data from combined transmission and distribution companies, such as Union Gas,
would provide no direction for the required allocation. IGCAA considered that, to derive an
appropriate allocation, it is necessary to obtain data for these functions separately. As for the
suggestion by interveners that ATCO should have looked at the TCPL system, IGCAA submitted

        82
             Tr. p. 743, lines 9-21 and Exhibit, Section 6, p. 6

                                                                   EUB Decision 2001-97 (December 12, 2001) • 87
2001/2002 General Rate Application – Phases I and II                          ATCO Pipelines South


that, although it would be beneficial to IGCAA members to use this data, it is unlikely that
TCPL’s experience would be reflective of UFG on the ATCO Pipelines system.

IGCAA noted that ATCO’s approach to the interim allocation, based on data available for U.S.
distribution and transmission systems, resulted in allocation of 1.63% for distribution systems
and 0.7% for transmission systems, and a 2.3:1 ratio which ATCO applied to its forecast UFG
rate. IGCAA expressed the following concerns with this approach:

    •   No attention was paid to whether the US transmission and distribution companies
        were similar to ATCO Pipelines or ATCO Gas. The average of 2.33% for the
        blended rate derived from the data suggests that these systems bear little, if any
        resemblance to either ATCO system, in that ATCO’s blended rate over the past
        eight years has averaged approximately 1%;
    •   Mr. Wolnik’s evidence was that the 0.7% for transmission pipelines was overly
        conservative because of reduction in UFG experience by transmission pipelines in
        recent years, submitting that average transmission pipeline UFG was closer to
        0.54%; and
    •   Of the 60 US transmission companies used to calculate the average of 0.7%, 15 of
        these pipelines, with a UFG rate of only 0.25% were identified as similar to, or
        representative of ATCO Pipelines.
IGCAA submitted that a more accurate allocation could be obtained by using 0.25% as a
representative number, a percentage that should be applied to ATCO’s historical blended rate of
1% or 2,000TJ per year. IGCAA submitted that, applying the 0.25% to the average annual loss of
2,000TJ results in 500TJ being attributable to ATCO Pipelines, leaving the remaining 1500TJ as
the responsibility of ATCO Gas, which results in a ratio of 3:1 rather than 2.3:1. IGCAA
submitted that this approach makes sense because it only relies upon US data to the extent that it
has been determined to be representative of the ATCO experience.

IGCAA noted that it’s recommended 3-1 ratio is consistent with the AltaGas experience, which,
with an average UFG rate of 0.88% is greater than the average 0.75% recommended by the
Association, suggesting that IGCAA’s recommended rate is conservative and results in
allocating less blended UFG to ATCO Gas than required.

IGCAA noted that ATCO used data from the 15 transmission companies only to directionally
confirm Mr. Wolnik’s work, and not to ascertain a definitive UFG level. IGCAA submitted that
this was a mischaracterization of the approach used by IGCAA. IGCAA specifically, did not
recommend use of the 0.25% for the 15 transmission companies as a fixed percentage that would
be applicable to ATCO, but used exactly the same approach as ATCO, the only difference being
that IGCAA only relied on U.S. data found to be comparable or representative of the ATCO
Pipelines system. IGCAA submitted that rather than simply using the data from the 15
transmission companies to get directional comfort, this better data should have been used to
calculate the ratio directly using ATCO’s own blended UFG experience.

IGCAA submitted that AIPA’s concern regarding use of comparable data could be met by taking
the approach advanced by IGCAA, and that AIPA’S alternative proposal was not satisfactory.

88 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


Specifically, IGCAA considered that AIPA’s 40/60 approach suffered from the same
deficiencies as the ATCO approach because it is impossible to justify the ratio arrived at in light
of the factors that cause UFG. As IGCAA previously discussed, since almost all of the major
causes of UFG are attributable to ATCO Gas, it is impossible to have a UFG ratio of less than
2.4 and 2.8:1.

PICA
PICA considered that IGCAA provided a very selective analysis of data to justify its ultimate
position of support for a 3 to 1 ratio for allocation of UFG.83 At the heart of IGCAA’s position,
PICA suggested, is reliance on data from a group of 15 U.S. transmission pipelines that IGCAA
claims are representative of ATCO Pipelines. However, PICA notes that this data was presented
by ATCO only as a second level check on the reasonableness of their proposed approach and no
witness was presented to defend the data. In PICA’s submission, IGCAA’s use of such
unsupported data is clearly self-serving, having elevated this supplementary data to a position of
primary importance, not justified by the evidence.

PICA noted that, with regard to Mr. Wolnik’s U.S. data, ATCO suggests the anomalies identified
by Mr. Liddle during cross-examination with respect to data from the states of California,
Washington and New York are “small or isolated.” PICA submitted that, when the 1996 UFG
data for California represents over half of the total U.S. UFG, it is hard to believe one could
characterize this as a “small or isolated” number.84 The California data for the years 1995, 1996
and 1997 also calculates 10-15% UFG for the state of California. Similarly, in no way can this be
characterized as a “small” quantity.

PICA noted Mr. Wolnik’s suggestion that any exclusion would be a “manipulation” of the data.
However, PICA reiterated its view that in statistical analysis, “manipulation” of data represented
by removal of unreasonable outliers, is a reasonable and well-accepted technique.

MI
The MI noted that publicly available information from the “Shipper News” could have been
referred to, but ATCO relied on the US EIA data. The MI considered that the evidence suggests
that the data actually relied on was taken at face value without necessarily attempting to make a
determination as to how the EIA handled UFG estimates. In the MI’s view, cross-examination
demonstrated numerous inconsistencies in ATCO’s data. The MI submitted that the study should
not be relied upon, even on an interim basis.

Referring to IGCAA’s proposal for a reduction to 0.25% for the UFG rate applicable to
transportation customers, the MI submitted that this proposal was based on information on 15
transmission companies, extracted from a source even less reliable than the 60 transmission
companies used in the original study.




        83
             IGCAA Argument, paragraph 21-27
        84
             Tr. p. 775, lines 5-10

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2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


Calgary
Calgary stated that it is clear from the evidence that:

    •   With respect to the US data, the issue in the first instance is not whether Mr. Wolnik
        attempted to “manipulate the data.”85 The problem is that Mr. Wolnik did not review or
        analyze the data for reasonableness or understanding. There is a significant difference
        between “manipulating the data”, and accepting it without question, without noting the
        obvious inconsistencies; and
    •   ATCO Pipelines suggests86 that Mr. Vander Veen misinterpreted the data. First, it should
        be said that at least Mr. Vander Veen attempted to interpret the data. Furthermore,
        Mr. Wolnik used a denominator of 21.262 Tcf for consumption, including fuel, for all
        U.S. interstate transmission pipelines. However, CAL-ATCO Pipelines.96 shows 23.5
        Tcf of receipts for just 15 out of 60 transmission pipeline companies. The ATCO
        Pipelines claim that the difference is due to “interstate transfers” is without foundation,
        given that it is clear from page 7 of Mr. Wolnik’s report (attached to CAL-ATCO
        Pipelines 94(a)), that the receipts in his study include interstate transfers.

Views of the Board
The Board notes that, in the apparent absence of available Canadian data, ATCO developed its
analysis of UFG using data from a wide range of US distribution and transmission companies for
the years 1992 through 1998. While Calgary challenged ATCO’s interpretation of the data, and
pointed to related conflicts or inconsistencies, the Board notes ATCO’s counter argument that
Calgary demonstrated a misunderstanding of system operation, which affected the conclusions
derived from its interpretation of the data. In the Board’s view, Calgary did not present a
compelling case to refute the results of ATCO’s study.

With respect to IGCAA’s submission that the allocation to transmission should be based on the
average UFG from the 15 U. S. companies sampled by ATCO in addition to the main study, the
Board agrees with ATCO and PICA that this sample was carried out by way of a second level
check on the reasonableness of the main study and serves purely as directional confirmation of
the study. In addition, as PICA pointed out, no witness was presented to defend this sample data.
Accordingly, the Board does not accept IGCAA’s recommendation for use of the sample data.

The Board is not persuaded that compelling evidence has been presented to challenge the results
of ATCO’s study, and considers that the use of the US data presented in evidence and the results
obtained provide a reasonable basis for allocation of UFG between distribution and transmission
customers. The Board is concerned that the inclusion of all of the data, without any attempt to
address whether the reported results are reasonable does create a significant and legitimate
concern. The Board would not have a concern had obvious outliers been excluded, provided that
the technical rationale for doing so was also provided so that it would be possible to test the
effects of this step. However, the Board does not believe that in this case, this would have led to
a sufficiently substantive change to the final results to warrant a requirement for ATCO to re-do
its analysis. Accordingly, the Board is prepared to accept the US data provided by ATCO in
        85
             APS Argument, p. 10
        86
             APS Argument, p. 11

90 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


evidence, noting that with the introduction of appropriate metering, it will in the future no longer
be necessary to rely on external data.

6 .3 Allocation of UFG to Customer Groups
 .5
Position of ATCO
ATCO pointed out the Application indicates that the work completed by Mr. Wolnik was used
only to derive a ratio between distribution and transmission systems, and in no way did ATCO
use the experience in the U.S. to say “this is now my UFG level.” In fact the ratio developed was
applied to a blended UFG level (Rider ‘D’) of AGS and APS. ATCO submitted that this type of
calculation was completed to ensure that the resultant UFG levels for AGS and APS were fair
and reasonable, and indicated that the derivation of the representative UFG is as outlined in the
response to CCA.ATCO Pipelines 21(h).

Referring to IGCAA’s development of what they believed to be an appropriate ratio of 3.0:1
(Distribution to Transmission), ATCO noted that this was based upon assuming that the average
of the 15 U.S. transmission companies (.25%) was more reflective of what the ATCO experience
should be. IGCAA then multiplied the .25% by 2000 TJ, which they claimed is the average loss
over the past eight years (ATCO did note that IGCAA provided no reference to this volume).
ATCO observed that, as a result, IGCCA attributed 500 TJ to Transmission and 1500 TJ to
Distribution.

However, ATCO submitted that IGCAA’s calculations are flawed. ATCO observed that the next
step in the process is to divide the TJ’s of UFG into the throughputs of the respective systems (as
outlined in CCA.ATCO Pipelines 21(h)). ATCO indicated that by doing so, the UFG rates by
unit of throughput are established. Using the values identified by IGCAA of 500 TJ and 1500 TJ,
UFG rates of .33% and 1.55% are the results. In addition, ATCO stated that the current fuel
value of 0.17% must be added to the transmission value of 0.33%.

Accordingly, ATCO considered that IGCAA’s assertion that their methodology supports the
AltaGas rate is incorrect.

ATCO noted that AIPA also attempted to develop a revised allocation, based simply upon
extracting the 1997 data from the overall UFG experience, with the result being a 2.1:1 ratio, and
an end result of 0.45% transmission UFG and 1.47% distribution UFG.

ATCO considered that, while on the surface the AIPA argument would appear reasonable, the
one consideration not accounted for was the conservatism that ATCO had considered in its
application of the ratios. ATCO indicated that, as noted by Mr. Wolnik and his contacts at GRI,
the 0.70% for transmission companies was “conservative” or high. The 1998 data of 0.54% for
transmission companies was believed to be more representative of today’s transmission systems.
It was ATCO’s position that it was most appropriate to use the most conservative data rather than
proceeding with either the 0.54% allocation or the 0.25% of 15 companies surveyed.

ATCO submitted that, overall, to selectively eliminate data from an analysis is not appropriate as
it would be equivalent to changing one small piece of a forecast without consideration for


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2001/2002 General Rate Application – Phases I and II                              ATCO Pipelines South


impacts in other areas. Accordingly, ATCO indicated that the Board should not consider the
recommendation from AIPA.

ATCO noted that, in Mr. Roth’s cross-examination of Mr. Johnson of the City of Calgary,
Mr. Johnson stated:

        The fact that it is allocated amongst all shippers or -- and I guess it is actually not
        all shippers, because the producers negotiated their way out of it. But the fact that
        it is paid by everyone else …87

ATCO also noted Calgary’s statement that:

        ATCO Pipelines has requested that the treatment of UFG be changed so that
        Producers do not contribute any volume for UFG on deliveries.88

ATCO pointed out that the statement that producers are not allocated UFG is categorically
incorrect, and that, as stated by Mr. Lidgett many times in cross-examination, all customers,
including producers, are allocated UFG on their physical deliveries off of the pipeline system.

ATCO noted the MI statement that:

        Prior to the February, 1999 Industrial/Producer Settlement, ATCO Pipelines
        applied the UFG Rider D equally to all customers. Following the February 1999
        I/P Settlement, UFG was only collected on deliveries off the system. Effectively,
        producer gas that was delivered on-system no longer incurs any UFG charges.89

ATCO considered the MI statement incorrect, with respect to two issues. First, the UFG Rider D
value has historically been applied to delivered volumes. Prior to February 1999, the Rider D
value was applied to all producer volumes as these volumes were "deemed" to be delivered off
the pipeline. ATCO pointed out that, in fact, only a portion was physically delivered off, with the
remainder delivered to customers on-system, where UFG was also collected on delivered
volumes. This past practice had the producer group cross-subsidizing both the core consumers
and industrials as UFG was collected twice for on-system deliveries at the expense of the
producers.

With regard to the MI’s assertion that Producer gas delivered on-system subsequent to February
1999 incurs no UFG, ATCO indicated that this is incorrect, as the Company collects UFG from
deliveries off its system. If the volumes are delivered on-system, it is the end-use customer,
typically an Industrial, that pays the UFG.




        87
           Tr. p. 1546
        88
           Calgary Argument, p. 56
        89
           MI Argument, p.21

92 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


ATCO referred to the following additional MI statement:

        It is further submitted that even the current method is biased in favour of
        producers in that they are not charged any UFG at receipt points, notwithstanding
        that the very large majority of UFG is related to measurement problems. All
        receipts and deliveries are measured either on to or off of the system and therefore
        those errors should be allocated to all customers.90

ATCO pointed out that, within this statement, it appears that the MI were introducing evidence
to suggest a new UFG methodology. That is, that all volumes receipted and delivered should
attract UFG. ATCO submitted that, as this appeared to be new evidence, it should not be
considered.

ATCO stated that, if closely considered, the Company believed that the MI itself would not
consider this recommendation. By collecting UFG on both receipts and deliveries, the throughput
to be considered must be the total receipted for a customer class and total delivered to the same
customer class. ATCO indicated that the result would be that ATCO Gas customers would be
allocated more UFG, as follows:

    •   ATCO Gas volumes are 100% receipted from NGTL interconnects and 100% delivered
        via ATCO Pipelines to ATCO Gas.
    •   Industrials physically receipt a small portion of their volumes from the NGTL system,
        with 100% delivered off.
    •   Producers receipt 100% of their volumes onto the ATCO Pipelines system and a portion
        is physically delivered off.

ATCO noted that significant producer volumes are delivered to industrial consumers. ATCO
indicated that UFG on the volume delivered to an industrial is collected from the Industrial
customer, and considered that the MI proposal would have ATCO Gas or core customers
contributing more than their fair share when compared to the Board approved methodology of
collecting only on deliveries.

ATCO referred to AIPA’s argument that ATCO Pipelines has no basis for applying the
percentages to delivered, rather than receipt volumes. ATCO pointed out that in the Application,
the Company has not sought any change to the current Board approved practice of applying UFG
to delivered volumes. ATCO noted that no intervener submitted evidence requesting the Board to
change the current methodology of applying UFG to delivered volumes. In addition, ATCO
pointed out that the evidence shows that no material change to the blended UFG rate would
occur, regardless of where it would apply. ATCO stated that the Board must disregard this
request by AIPA.

ATCO referred to IGCAA’s comment that the lack of metering between ATCO Pipelines and
ATCO Gas has led to a situation where industrial (and producer) customers are paying a
disproportionate share of UFG. ATCO indicated that this is clear in the evidence. ATCO stated

        90
             MI Argument, p. 27

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2001/2002 General Rate Application – Phases I and II                          ATCO Pipelines South


that this lack of metering causes the cross-subsidization whereby I/Ps contribute more than their
fair share, and in fact, as noted by IGCAA, in a year of the highest gas prices experienced, the
core (ATCO Gas) contributed virtually nothing to UFG. ATCO pointed out that this is a result of
the blended UFG rate currently in use and is neither fair nor reasonable. The installation of
metering and interim use of the allocation of Rider “D” as applied for would correct this situation
of cross-subsidization.

Positions of the Interveners
IGCAA
IGCAA argued that it was essential that the Board deal with the proper allocation of UFG in this
GRA. IGCAA stated that the major factors causing UFG were attributable to the operations of
ATCO Gas distribution system and not ATCO Pipelines transmission system. To establish more
accurate UGF between transmission and distribution, IGCAA supported the installation of
interconnect metering between ATCO Gas and ATCO Pipelines to ensure a fair allocation of
UFG in the long term. However, IGCAA objected to the interim allocation methodology
proposed by ATCO. IGCAA argued that the 2.3:1 ratio used by ATCO overstated the amount of
UFG allocated to ATCO Pipelines. IGCAA stated that the evidence showed a ratio of 3:1 split
between ATCO GAS and ATCO Pipelines would be appropriate to allocate the blended UFG. In
addition, IGCAA opposed ATCO’s proposal to assign the costs for interconnect metering to
general assets and proposed that these costs be characterized as dedicated assets.

With respect to the equity issue, IGCAA referred to ATCO’s evidence indicating that the gas
distribution system was the major factor causing UFG, and not the ATCO Pipelines transmission
system. IGCAA referred to submissions by ATCO indicating that ATCO Gas caused most, if not
all of the UFG attributable to measurement inaccuracy, as well as almost all of the UFG
attributable to accounting errors, theft, cyclical billing and heating values on gas deliveries.
IGCAA submitted that fugitive emissions was the only factor identified where ATCO Gas was
not the major or exclusive contributor, but noted that the evidence was that, in this respect,
ATCO Gas was responsible for between 2.4 to 2.85 times more UFG than ATCO Pipelines.

IGCAA submitted that, in light of substantial evidence on the record, the Board cannot allow the
same blended rate of UFG for both ATCO Gas and ATCO Pipelines, and considered that equity
requires that ATCO Gas, as mainly responsible, should bear the cost associated with it.

PICA
PICA and MI were critical of ATCO’s UFG analysis wherein no comparable UFG data from
Canadian companies was used in the analysis provided by its witness. PICA and MI argued that
no reasonable evidence was presented to support the interim UFG split between ATCO Gas and
ATCO Pipelines.

PICA noted that the only party supporting ATCO’s UFG proposal is IGCAA, and that, in fact,
IGCAA went further, recommending an even more favorable interim solution of using a ratio of
3 to 1 rather than the 2.3 to 1 ratio proposed by ATCO. PICA indicated however, that IGCAA’s
underlying support for its position has some significant errors. First, IGCAA argues that
measurement losses are directly proportional to the number of customers or meters involved.

94 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


However, PICA submitted that the absolute volume of measurement error at any specific meter
location depends on a combination of the percentage error and the volume of gas being measured
at that location. Accordingly, PICA stated that, to suggest that measurement error is almost
exclusively attributable to ATCO Gas because there are 400,000 customers on ATCO Gas
compared to 160 on ATCO Pipelines ignores the fact that industrial customers served off ATCO
Pipelines have individual volumes with orders of magnitude larger than core customers on
ATCO Gas. PICA pointed out that BR-25(d) shows actual 2000 volumes were 40,536 TJ for
industrial, 2,008 TJ for Gas Alberta and 110,110 TJ for ATCO Gas.

PICA stated that second, IGCAA ignores the fact volumes received by both industrial and core
customers have to be measured into the system from either producers connected to the ATCO
Pipelines system or interconnects from the NGTL system. The definition of UFG is simply the
difference between the amount of gas measured into a system and the amount of gas measured
out of that system. PICA stated that all measurements, both in and out, contribute to the absolute
volume of measurement error, and since the error can be either positive or negative, some of
these measurement errors cancel out. Accordingly, PICA submitted that IGCAA is in error,
again, when it assumes all factors contribute to positive (i.e. lost) UFG. In particular, IGCAA
identifies accounting errors related to transferring measured volumes to electronic billing
systems, heat value differences and cycle billing as factors primarily, or exclusively, arising from
the metering into ATCO Gas. PICA stated that, while these factors will create a measurement
error, there is no evidence to support IGCAA’s suggestion these factors will always create a net
positive UFG over any given period of time. In fact, PICA pointed out that, over time, it is more
reasonable to expect these factors should average out to zero, since there is no inherent reason
for the creation of either a negative or positive error. In fact, the only UFG factors always
positive are those of theft and fugitive emissions. PICA indicated that, while the evidence
indicates theft is only known to have occurred on ATCO Gas to date, the evidence is also clear
that both ATCO Gas and ATCO Pipelines contribute to fugitive emissions, a point
acknowledged by IGCAA in its Argument.

AIPA
AIPA disagreed with the calculation of transmission UFG as proposed by ATCO. AIPA
suggested that the 1997 UFG for ATCO be eliminated from the data set as being
unrepresentative and therefore, on the basis of the revised data set from 1992-1996 and 1998, the
average UFG for ATCO Pipelines would be 2.17% of consumption and the UFG for
transmission-only deliveries would be 0.70%. AIPA indicated that the recalculated percentages
would result in a UFG ratio of 2.2:1 for distribution/transmission split. Furthermore, AIPA
suggested that a 40%/60% split between transmission/ distribution would be more appropriate
until better data from metering is available. Also, AIPA rejected the proposal by ATCO to
calculate the UFG percentages to the delivered volumes rather than the receipt volumes. AIPA
recommended that applying UFG percentages to receipt volumes would ensure that gas destined
for exchange or storage would not escape UFG responsibility.

MI
The MI argued that ATCO had not met its burden of proof in demonstrating that the ratio of
2.3:1 is reasonable or appropriate for splitting its blended UFG. The MI argued that ATCO’s


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proposal to install custody transfer metering and the interim UFG allocation method would shift
a cost component to the core customers and enable ATCO to be more competitive in the
industrial and producer rates. The MI suggested that both proposals should be denied, and
submitted that the five-year average 0.88% UFG was a reasonable proxy for ATCO Gas South
percentage based upon a pure Alberta distribution company’s experience and that 1.52% split
proposed by ATCO Pipelines as the UFG for ATCO Gas was inordinately high.

The MI submitted that UFG, being largely related to measurement problems, should be allocated
to all customers, as all receipts and deliveries were measured either on to or off of the system.

The MI noted that IGCAA was the only party supporting ATCO’s UFG proposal, and went
further, by recommending a more favorable solution to itself, using a ratio of 3:1. The MI
however, submitted that IGCAA’s underlying support for its position contained some significant
errors.

The MI considered that IGCAA’s position provides very selective analysis of data to justify its
position of 3:1 ratio for allocation of UFG. The MI agreed with PICA that this data was
presented by ATCO only by way of a second level check on the reasonableness of their
approach, and presented no witness to defend the data. The MI submitted that IGCAA’s use of
such unsupported data is clearly self-serving and not justified by the evidence.

Calgary
Calgary submitted that due to the failure to examine relevant Canadian data, and the flawed use
of U.S. data by Mr. Wolnik, the ratio between pipeline and gas proposed by ATCO cannot be
accepted. Calgary stated that the attempt to shore up Mr. Wolnik’s work through reference to
other U.S. data is unpersuasive, and that the transcript shows the complete lack of diligence that
went into selecting the sample of 15 U.S. pipelines91 to supposedly confirm Mr. Wolnik’s work.
In Calgary’s view, ATCO failed to in any way attempt to establish the relevance of its 15 U.S.
company sample to ATCO Pipelines/ATCO Gas.

Calgary noted that IGCAA seems to argue against itself to some degree, because it states that
those who cause UFG should pay for it.92 Calgary noted however, that in doing so, IGCAA
focuses on ATCO Gas, ignoring the fact that in the I/P settlement the producers, under the
receipt tolls, are not subject to Rider “D” either. Further, Calgary noted that IGCAA states that
ATCO Pipelines cannot collect UFG from ATCO Gas.93 This, however, ignores the fact that
under the “residual” form of ratemaking proposed by ATCO, any UFG not charged to other
customer groups is implicitly charged to ATCO Gas, which in turn implicitly charges its
customers for both the ATCO Pipelines residual UFG, and the ATCO Gas UFG. Calgary stated
that furthermore, to the extent that all the UFG is included in the numerator in determining the
Rider “D” percentage, but not all of the volumes are included in the denominator (i.e. the
producer receipts), the UFG percentage is higher than it should be.


        91
           Tr., pp. 864-865
        92
           IGCAA Argument, p. 2
        93
           IGCAA Argument, p. 4

96 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                    ATCO Pipelines South


Views of the Board
Having accepted the methodology used by ATCO to determine the UFG allocation, the Board is
satisfied that ATCO’s interpretation of the data in the study supports its conclusion of a 2.3:1
allocation between distribution and transmission customers. The Board therefore, accepts
ATCO’s 2.3:1 ratio to allocate UFG for the test years.

AIPA argued that 1997 data in the study should be dismissed, suggesting that a 40%/60%
allocation would be more appropriate until better data is available. The Board is not convinced
that AIPA has provided sufficient technical support for this argument. However, the Board
considers that there is merit in AIPA’s recommendation for application of UFG to storage and
exchange volumes. Accordingly, the Board directs ATCO to ensure that UFG is applied to
storage and exchange volumes.

With respect to the MI’s argument in favor of application of UFG to receipt volumes, the Board
accepts ATCO’s rationale that such a proposal would result in core customers contributing more
than their fair share when compared to the methodology of collecting UFG on deliveries only.
Therefore the Board rejects the notion of adding receipt volumes to delivered volumes in the
calculation of UFG.


7       UTILITY REVENUES

7.1     Transportation Revenue
In the Application, ATCO forecast transportation revenues of $40.04 million (2001) and $40.3
million (2002). Transportation revenue is derived from provision of service to three distinct
market segments, and from penalty revenue as set out as follows:

                                                  ($million)
                                                                    2001        2002
                        Distributing Companies                      23.55       23.97
                        Producers                                   15.34       15.28
                        Industrial                                   0.86        0.83
                        Penalty Revenue                              0.28        0.25
                        Total Revenue                               40.03       40.34

ATCO makes up over 97% of revenues from service to Distribution Companies. The remaining
3% represents revenue from service to Gas Alberta. The revenue forecasts for ATCO Gas are
based on 100% demand charges continuing at the 1999 and 2000 rate of $1.82/GJ/month. The
ATCO Gas contract demand is determined by ATCO Gas on a yearly basis, and is forecast to
increase by 2.7% in 2001 over 2000 and 1.7% for 2002 over 2001. Gas Alberta revenues
decreased from 1999 to 2000 reflecting a change from sales to transportation service plus the rate
reduction approved in Decision 2000-16.

Industrial revenue is forecast to decrease by 69% ($1.97 million) in 2001 over 2000 and by a
further 3% ($0.28 million) for 2002 compared to 2001, primarily due to competitive pressures at


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the largest two industrials. The combined contract demand for these industrials, NOVA
Chemicals Joffre and Agrium Carseland, represent three quarters of the total ATCO industrial
demand in 2002.

ATCO indicated that the competition for industrial service has intensified with the competitive
market evolution for pipelines. ATCO’s primary competitor has neither a delivery toll nor a UFG
charge for deliveries within Alberta. In contrast, ATCO’s rates include both, thereby putting
ATCO’s delivery service under considerable pressure. Physical deliveries of gas to industrial
customers provide the opportunity to attract producer volumes, which is a basic business premise
of ATCO. Retention of industrial volumes is therefore a priority.

ATCO noted that the revenue projections filed in evidence were reviewed and no contrary
evidence was submitted, with it understanding that the rate charged to AGS was a placeholder
and the Board will establish the appropriate rate required to achieve the awarded revenue
requirement of APS. ATCO stated that the current forecast for 2001 is “bang on pretty well
exactly with what the application forecasts for 2001.”94

ATCO stated that, consistent with prospective ratemaking, the Company is not seeking changes
to the Industrial and Producer components, and that the impact of the loss of an industrial is
significant in terms of both the lost industrial revenue and the producer revenue enabled by that
industrial load. For example, the Lafarge Exshaw termination95 was not forecast and will impact
2002 revenues negatively by $400,000.

ATCO stated that the decision to operate AGS and APS as separate divisions necessitates that
the terms of gas transmission service be established. ATCO filed key terms with respect to how
gas transmission service is provided by APS to AGS, and has requested approval of this
agreement in this proceeding, noting that exclusivity, the ten year term (7.5 years remaining), the
selection by AGS of its contract demand and the APS obligation to build to meet that demand are
among the key components of the agreement.

ATCO calculated that a toll to provide transmission service to AGS is simply the total revenue
requirement less revenue received from Producer, Industrial and Gas Alberta customers divided
by the AGS contract demand. This calculation was provided as an undertaking at Tr. p. 1483,
line 16 and is reproduced as follows:




        94
             Tr. p. 1175, lines 10-12
        95
             Tr. p. 593, lines 5-24

98 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                             ATCO Pipelines South




                                                2001                 2002               Reference
     Revenue Requirement                       $41,145             $42,110         Table 4.1-1
     Producer Revenue                          $15,340             $15,281         Table 5.1-1
     Industrial Revenue                        $ 866               $ 838           Table 5.1-1
     Gas Alberta Revenue                       $ 643               $ 669           Table 5.1-1
     Franchise Tax                             $ 280               $ 251           Table 5.1-1
     Residual Rev. Requirement                 $24,016             $25,071         Calculated
     AGS Demand (TJ/d)                            1049                1067         CAL-ATCO-71(b)
     AGS Rate ($/GJ/mo)                        $1.9078             $1.9580         Calculated
     AGS Rate ($/GJ/mo)                        $1.9329                             Average

ATCO considered that rates negotiated with Producer and Industrial customers are reasonable
and that those customers bear their fair share of costs as demonstrated by the COS Study
provided, and noted that the recently negotiated rates with Gas Alberta result in $275,000 less
revenue each year than forecast in the Application. As demonstrated in the calculation above,
ATCO indicated support for prospective ratemaking and has used the higher, originally forecast
revenues from Gas Alberta to calculate the residual revenue requirement attributable to AGS.
ATCO considered that, having negotiated reasonable rates with all of its customers except AGS,
it is also reasonable that the residual revenue requirement be used to establish a rate for gas
transmission service for AGS.

ATCO submitted that the Company is requesting approval for a rate of $1.93 per GJ of contract
demand per month to provide transmission service to AGS.

ATCO noted PICA’s suggestion that the forecast of producer revenues is overly pessimistic,
particularly in 2002 which shows a net decline in revenues and that “… a more reasonable
forecast of producer revenue would be $16 million, reflecting at least a modest rate of continuing
growth.” ATCO pointed out that no evidence was brought forward to support PICA’s statement.
ATCO stated that the system is full, the Company has pledged additional revenues to the
deferred account and that the loss of Lafarge Canada will negatively impact producer revenues.
ATCO stated, that without industrial load, the Company cannot practically increase producer
volumes.

ATCO noted AIPA’s submission that revenue from I/P customers is understated by $0.6 million
and $0.8 million in 2001 and 2002 respectively due to an under estimation of
overrun/interruptible revenue, and AIPA’s recommendation that the calculation of overrun
(monthly basis) in the revised I/P settlement be rejected in favour of the calculation of overrun
(daily basis) in the original settlement.

ATCO calculated that the change in calculation of overrun from a daily basis to a monthly basis
would decrease revenue from the I/P customers by an estimated $154,000 per year, offset by
increased revenue from I/P customers by an estimated $141,000 per year by changing from a
90% demand rate to a 100% demand rate. ATCO provided the calculation of these revenue
effects is shown in more detail in Exhibit 161, pointing out that these are two of the many give
and takes” negotiated as part of the entire I/P settlement. ATCO stated that the I/P settlement as

                                                         EUB Decision 2001-97 (December 12, 2001) • 99
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


filed with the Board indicated that the total effect of all changes from the original I/P settlement
did not impact the core customers..

ATCO argued that AIPA did not base its determination of a $0.6 million and $0.8 million over-
run/interruptible revenue underestimation on the change from daily to monthly calculation of
overrun charges at all. Instead, AIPA's calculation is simply based upon the ratio of
overrun/interruptible volumes to firm contract demand (CD) in 1999 and 2000 and continuing
this ratio into 2001 and 2002, which assumes that the pipeline system can accommodate ever-
increasing volumes without limit. ATCO submitted that this is not the case as the lack of an on-
system market precludes incremental system receipts. ATCO referred to the statement of the
Company’s witness Mr. Belsheim that “we are pretty much at capacity on the system.”96

ATCO has forecast increasing firm CD through the period 1999 to 2002, and, as the system is
essentially at capacity, the Company has forecast decreasing overrun/interruptible volumes.
ATCO lacks the pipeline capacity to increase overrun/interruptible volumes as suggested by
AIPA. As noted in the Application, the decrease in overrun/interruptible volumes are primarily
caused by customers switching from interruptible to firm service.

ATCO has asked the Board to approve the exclusive transportation agreement between APS and
AGS (filed in AIPA 3 (c)), which provides the fundamental obligations of both APS and AGS.
ATCO pointed out that this is a 10-year (7.5 years remaining) agreement with yearly contract
demand selection (up or down), investment obligations, service obligations and pricing numbers
as approved by the Board. ATCO noted the MI’s statement “The ATCO Gas and Pipelines board
of directors has not yet signed off on this ten year exclusive agreement between AGS and APS.”2
ATCO considered that the MI incorrectly concluded that this agreement requires specific board
of director approval – it does not.

ATCO noted the MI’s statement that “APS has not filed nor sought Board approval of
transmission tariffs…”, which is untrue. ATCO pointed out that the Company has presented
forecast revenues based on a placeholder of $1.82/GJ/month, forecast a shortfall in revenue at
this rate in the application, filed the transportation agreement between APS and AGS, requested
Board approval of this agreement, discussed how the $1.82/GJ/month would be revised based on
the revenue requirement determined by the Board and requested a rate of $1.93/GJ/month.97

ATCO noted that the CCA attempted to make an issue over temperature for design and billing
demand. ATCO indicated that the Company has attempted to be as helpful as possible by
providing the temperatures used by AGS to calculate its requirements. ATCO believes that the
gas transportation agreement and numerous questions answered by Mr. Belsheim clarified the
issue that the Company does not design to temperatures, but designs to the contract demand
selected yearly by AGS and bills based on the Phase 2 cost allocation basis.




        96
             Tr. p .808 line 5-6
        97
             Tr. p. 1302, line 15

100 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


Positions of the Interveners
PICA
PICA stated that a key component of ATCO’s revenue forecasts is the projection made for
producer transportation revenue. In particular, ATCO projects a significant reduction in the
historical level of revenue growth from producers during the two forecast test years due to
greater capacity limitations.

PICA noted that, in response to its cross examination on these capacity limitations, Mr. Belsheim
did not take a definitive position on whether ATCO would expand mainline capacity and thereby
remove the capacity limitations. PICA noted that Mr. Belsheim described the situation as being
“on the cusp.” While PICA was encouraged by the care ATCO is apparently taking before
making mainline investments to reduce capacity limitations, it is possible the current limitations
may be resolved once the situation is moved “over the cusp”. Consequently, PICA submitted that
the forecast of producer revenues is overly pessimistic, particularly in 2002, which shows a net
decline in revenues. In PICA’s view, a more reasonable forecast of producer revenue would be
$16 million, reflecting at least a modest rate of continuing growth.

MI
The MI noted ATCO’s statement that “it is reasonable that the residual revenue requirement be
used to establish a rate for gas transportation service for AGS.” The MI agreed with Calgary and
PICA that the Board should adopt the revised COS Study prepared by Calgary for purposes of
designing the AGS tariff rather than accept the residual or revenue credit method proposed by
ATCO. The MI submitted that the revenue credit method falls out of closed door negotiations,
and unfairly requires that residual revenues be collected from AGS’ customers.

The MI submitted that the Phase I revenue requirement determined by the Board should be
allocated to I/P customers, AGS and the FGA based on the COS Study submitted by Calgary.
The MI considered that ATCO had failed to meet its burden of proof to demonstrate the
appropriateness of the residual or revenue credit method of determining the tariff applicable to
AGS for transportation service.

AIPA
Referring to the new rates arising from the I/P Settlement, AIPA noted that the new
Transportation Firm Service (TFS) rate is simply a demand charge rather than a demand and
variable charge as in the original rates. AIPA expressed concern that ATCO attempted to justify
this approach by suggesting that the additional amount of demand revenue, from 90% in the
original settlement to 100% in the new settlement, would offset the reduction in over-run
revenues.

AIPA considered it likely that I/P customers would incur over-run service on a daily basis, and
pointed out that, with the original settlement, such daily over-run volumes would incur an over-
run charge of $0.08063/GJ for each over-run GJ on a daily basis. AIPA noted however, that as
ATCO indicated, since this class of customer runs close to 100% demand, there will be no
effective increase in revenues from the original rates as the original and new TFS rates are
equivalent at 100% load factor.

                                                       EUB Decision 2001-97 (December 12, 2001) • 101
2001/2002 General Rate Application – Phases I and II                         ATCO Pipelines South




AIPA summarized the Producer over-run/interruptible parameters demonstrating a reduction in
the related volumes and revenues. AIPA suggested that there was an understatement of Producer
over-run/interruptible revenues of $0.6 million (2001) and $0.8 million (2002), which should be
incorporated in an adjusted revenue requirement forecast.

AIPA submitted that the monthly TFS over-run rate is an unwarranted change, which should be
rejected, and the original daily over-run rate maintained where higher revenues could be
incorporated in the revenue requirement forecast.

Views of the Board
The Board notes that the rate for service provided by the Company to ATCO Gas South for 1999
and 2000 was $1.82/GJ, and that ATCO carried this rate forward as a placeholder for the test
years in the Application. The Board believes that the results of the Company’s COS Study, as set
out in Section 8 of this Decision, demonstrate a rate for 2001 of $1.89/GJ. Therefore the Board
is satisfied that the rate of $1.82/GJ charged to ATCO Gas South for service in 1999 and 2000
appears to have been reasonable.

With respect to the calculation supporting ATCO’s proposed rate to AGS of $1.93/GJ for the test
years, the Board agrees with the intervener submissions that the rate should not be based on the
residual revenue requirement remaining after deducting revenues from I/P customers and Gas
Alberta. The Board is also not persuaded that the rate determination should be based on the
average of the residual of the revenue requirements for the test years.

The Board considers that the rate for provision of service to ATCO Gas South on a going
forward basis should be determined based on the results of the Company’s COS Study. In this
regard, in Section 8 of this Decision, the Board has directed ATCO to prepare a 2002 COS Study
applying the methodology approved for the 2001 COS Study examined in this Proceeding. The
Board expects ATCO to determine a distribution rate on a going forward basis based on the
results of the 2002 COS Study. The Board also expects ATCO to apply the rates determined
from the 2001 and 2002 COS Studies in determining the forecast revenues for the respective test
years.

The Board does not find it necessary to approve the 10-year agreement with ATCO Gas South
covering the terms and conditions of transportation service as this is an agreement between two
divisions of the same corporate entity. In the Board’s view the agreement effectively represents
an internal accounting practice and the Board has addressed the issue of the charges to be
accounted for, as discussed in the preceding paragraphs of this Section.

The Board notes ATCO’s challenge to PICA’s submission that the forecast of Producer revenues
is overly pessimistic, and agrees that no evidence was brought forward to support PICA’s
statement. The Board notes that an increase in the industrial load has not been forecast and is
prepared to accept ATCO’s position that increasing the volume of producer loads is dependent
on an increase in industrial load.




102 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


7 .1 NOVA Chemicals Joffre
 .1
The largest decrease ($1.2 million from 2000 to 2001) results from the November 1, 2000
reduction of contract demand from 28 TJ/D as specified under the long term NOVA Chemicals
Joffre contract. Subsequent to the installation of ATCO’s first transmission line to the plant (mid
1970’s), two other pipelines have been installed to the Joffre site, namely a regulated NGTL
pipeline and a non-regulated TransCanada Ventures pipeline. While both pipelines were justified
to accommodate growth, NOVA Chemicals now has the flexibility to decontract its requirements
with ATCO.

Under the terms of the specific long-term contract, the contract demand decreases to 12 TJ/D
(point to point rates with a 50/50 demand/commodity split and throughput based UFG charges).
Under these terms, NOVA Chemicals’ most economic option is to reduce its throughput to zero,
resulting in $308,700 per year in demand charges being paid to ATCO, but eliminating both the
commodity and throughput based UFG portions. ATCO is renegotiating this contract with two
objectives. Specifically, ATCO wishes to have NOVA throughput on the system to reduce the
allocation of UFG to other delivery customers as well as to offset any reduction in the $308,700
of industrial demand with producer revenues. ATCO anticipates that a special contract rate will
be negotiated similar to the trial one month special contract which was in place for November
2000. The revenue forecast for 2001 and 2002 assumes that the NOVA Chemicals toll is reduced
to zero and only the $12,000/year fixed charge is retained.

While this results in contract demand revenue of zero, the special contract would provide
incentive for NOVA Chemicals to use ATCO Pipelines, and the physical deliveries on the
system will encourage the addition of producer receipts. ATCO has forecast the incremental
producer receipts (8 TJ/D) plus interruptible revenues sufficient to offset the reduced demand
charges ($296,700) for both 2001 and 2002. The special contract will also require a reduced
UFG charge in the order of 0.5%. Retention of this industrial load benefits other delivery
customers since the total UFG is unlikely to change, the allocation of UFG is by throughput, and
NOVA Chemicals deliveries will “absorb” a portion of the UFG which would otherwise be
allocated to other industrial and distributing company customers.

ATCO pointed out that the NOVA Chemicals Joffre contract filed with the Board on June 20,
2001 was addressed at length in this proceeding and with no contrary evidence. The Board is
asked to acknowledge the necessity of the non-standard terms of this contract.

Views of the Board
The Board acknowledges the information filed by ATCO prior to the commencement of these
proceedings providing details of the special contract with NOVA Chemicals, and ATCO’s
representations with respect to the need for the special arrangements. The Board accepts ATCO’s
submission that the special arrangement is necessary to retain the volumes on the system, and
encourage the addition of producer receipts. The Board notes that no interveners took issue with
the special contract with NOVA Chemicals. Accordingly, the Board approves the special
contract with NOVA Chemicals Joffre.




                                                       EUB Decision 2001-97 (December 12, 2001) • 103
2001/2002 General Rate Application – Phases I and II                          ATCO Pipelines South


7 .2 Agrium Carseland
 .1
In the original I/P settlement, the Agrium rates were partially rebated to reflect competitive
bypass options. In the 2001 and 2002 forecasts, the Agrium rates are forecast to be entirely
rebated (the rebate increases by $825,000 for 2001 compared to 2000), consistent with the
proposed I/P reopener settlement and reflecting growth. The requirements behind this change are
the NGTL Products and Pricing approval (zero delivery tolls), regulatory acceptance of alternate
pipelines and higher gas prices (higher costs to Agrium of providing ATCO Pipelines UFG).

Views of the Board
The Board notes ATCO’s submission with respect to the need for the special arrangements with
Agrium, and acknowledges ATCO’s rationale for increasing the rate rebates with respect to this
customer. Accordingly, the Board approves the increase in rebate to Agrium, noting that no
interveners took issue with the increase in rebate.

7 .3 Other Industrial Markets
 .1
Another revenue decrease results from the firm service delivery decontracting notice served by
Continental Lime who have stated that they are switching to coal in 2001. Customers can
typically decontract with a rolling 12 month notice. This reduces ATCO’s delivery contract
demand by 4.3 TJ.D or $81,000/year on a full year basis.

Fuel switching to coal has also been reported by the press with respect to Lafarge Canada at its
cement plant at Exshaw, ATCO’s third largest industrial customer. To the Application date, no
contract termination notice had been received.

ATCO indicated that there is a very real risk of other plant shutdowns due to high feedstock
prices. Industrials producing products such as fertilizer and petrochemicals compete in a world
market, and the increase in natural gas feedstock prices shifts the feedstock cost versus shipping
costs in an unfavourable direction for North American plants. ATCO stated that, if an industrial
were to cease or reduce its operations, ATCO would generally collect 90% of the delivery
revenue for 12 months and none thereafter. More importantly, the physical “sink” for producer
receipts disappears, resulting in lower producer receipts and/or increased charges to deliver the
gas physically to NGTL in the warmer months.

Industrial growth is forecast in 2001 with the installation of a co-generation plant at Agrium
Carseland. Net revenues excluding fixed charges are zero (100% rebate of tolls). However, this
facility represents additional throughput to share the UFG, and it will reduce the charges to the
deferred account (a larger physical “sink” results in lower deliveries to NGTL in the warm
summer months).

Views of the Board
The Board is satisfied with ATCO’s submissions with respect to the rationale for variances in
revenues from industrial markets and related operational matters, noting that no interveners took
issue with ATCO’s submissions.



104 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


7 .4 Producers
 .1
Producer revenues are anticipated to increase by 5.3% ($774,000) in 2001 over 2000, and to
stabilize at approximately the same level for 2002 a decrease of $59,000 from 2001. Almost half
of ATCO’s producer receipts are dually connected with NGTL, with ATCO receiving the larger
portion of the receipts. The NGTL Products and Pricing decision reduced receipt tolls at dually
connected locations such as Shell Jumping Pound and the Entice area, increasing the risk of loss
of these revenues.

Producer Firm Service receipts can generally be decontracted on 12 months’ notice. The industry
currently forecasts well-by-well declines in the 10%-25% range per year. However, high gas
prices currently provide incentive for producers to invest in new wells and facilities to mitigate
this decline. To mid November 2000, ATCO has been served with notices of receipt firm service
decontracting of 30 TJ/D for 2001, which will take effect primarily in the first half of 2001. The
full year revenue impact of 30 TJ/D is approximately $800,000.

ATCO has forecast the recontracting of this 30TJ/D plus contracting of firm producer revenues
equating to 50TJ/D on a full year basis for 2001 over 2000. The increase in 2001 is partially a
result of interruptible load switching to firm load. ATCO forecasts that 25 TJ/D of existing
interruptible load at dually connected sites will convert to firm load on April 1, 2001. For 2002,
ATCO has forecast that the Company will again entirely offset decontracting plus add an
incremental 6 TJ/D on a full year basis for 2002.

The overrun/interruptible revenues are forecast to decrease by 33% ($507,000) for 2001 over
2000 and have been forecast to decrease by 19% ($195,000) in 2002 over 2001. The primary
reason for the decrease is the switch of interruptible load to firm load, with a full year impact in
2002.

Views of the Board
The Board is satisfied with ATCO’s submissions with respect to the rationale for variances in
producer revenues and related operational matters, noting that no interveners took issue with
ATCO’s submissions.

7 .5 PanCanadian Carseland Contract
 .1
Position of ATCO
ATCO noted that Mirant Americas Energy Marketing Canada Ltd. (Mirant) raised concerns
about the PanCanadian non-standard contract. ATCO submitted that, while Mirant’s concern is
that costs associated with the PanCanadian contract exceed revenue and that as a result, APS
should have let the PanCanadian volumes leave the system, Mirant’s analysis is flawed. ATCO
observed that Mirant had attempted to isolate costs for PanCanadian specifically, when costs to
physically deliver gas to the NGTL system are actually incurred on a pooled basis. ATCO stated
that the danger in Mirant's approach is to oversimplify what is a much more complex calculation.

ATCO noted that Mirant’s evidence calculated costs for PanCanadian volumes physically
flowing to the NGTL system 365 days a year. However, ATCO stated that physical flows to
NGTL are only half of total exchange volumes due to netting of incoming volumes for the core.

                                                       EUB Decision 2001-97 (December 12, 2001) • 105
2001/2002 General Rate Application – Phases I and II                             ATCO Pipelines South


During the hearing, Mirant abandoned its approach used in evidence and reduced the 365 days to
214 days, considered by ATCO to be arbitrary, as it represents the summer season for gas
contracts but has nothing to do with actual physical deliveries to NGTL.

ATCO considered that Mirant missed two important facts. Firstly, as part of the settlement, all
dually connected plants receive a discounted exchange fee owing to their competitive advantage
over non-dually connected plants arising from their ability to easily leave the APS system for
NGTL. ATCO indicated that, if PanCanadian was under the standard I/P settlement, it would
have received an exchange fee discount. Mirant’s calculation of PanCanadian costs ignored this.
Secondly, ATCO has agreed to contribute towards the exchange fee deferred account all revenue
associated with receipt revenue incremental to what was forecast in the Application. ATCO
stated that Mirant ignored this as well. Both of these factors reduce the exchange fee costs of
which some portion has to be allocated to the PanCanadian costs in Mirant’s approach, as
indicated by the Company’s witness Mr. Dixon. ATCO provided the following calculation to
indicate the net benefit to all customers of the non-standard PanCanadian contract:

                                                         $Million over 2001/2002
                                          Factors Known at Time of
                                                 Settlement               Factors Known Today
    PanCanadian Receipt Revenue                     $4.6                          $4.6
    Loss of Exchange Fee Revenue                    $0.6                          $2.3
    Net Benefit                                     $4.0                          $2.3


ATCO stated that Mirant did not calculate incremental costs attributable to the non-standard
PanCanadian contract correctly, noting that Mirant states:

        The revenue for the Special Contract will be the ATCO Receipt Toll of 7.4
        cents/GJ or $2.3 million/annum on 85 TJ/day. The actual incremental cost of
        moving one GJ of gas from the ATCO system for delivery off of the NGTL
        system is 27.3cents/GJ or $8.5 million/annum. The net cost of the Special
        Contract is more than $6 million/annum.98

ATCO stated that this calculation assumes that all of the 85 TJ/d assumed for PanCanadian
volumes from the Carseland area must physically flow to the NGTL system every day of the year
incurring costs of $8,469,825 (85,000 GJ/d x 365 days/yr x $0.273¢/GJ), which is simply not
true. ATCO can direct PanCanadian volumes to interconnections with the NGTL system where
there are incoming volumes for core customers to reduce the net physical flow to the NGTL
system and the resulting costs. ATCO indicated that, as exchange service is available to any
shipper on the ATCO Pipelines system, a review of the overall ATCO Pipelines (South) system
flows is in order.

ATCO stated that producer receipts on its system are forecast to exceed industrial and core
market deliveries throughout the test period. The excess producer receipts are exchanged to the
NGTL system to access markets on that system. Producer receipt volumes and industrial delivery

        98
             Mirant Evidence, p.4

106 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


volumes are relatively constant throughout the year. Core market deliveries vary considerably
due to their temperature sensitive load. This variability gives rise to different flow patterns on the
ATCO system in winter versus summer.

ATCO indicated that the Company receipts volumes from the NGTL system to supply the core
market while also delivering excess producer volumes to the NGTL system via exchange service.
These offsetting volumes reduce net physical flows from ATCO to NGTL and resulting costs.
ATCO stated that, on average over the year, physical deliveries to the NGTL system are only
about one-half of the total producer exchange volumes.

ATCO stated, therefore, that volumes from the PanCanadian non-standard contract will not incur
incremental costs as high as Mirant has calculated. The correct calculation is much more
complicated and is affected by gas price, exchange activity, NGTL Tolls, ATCO UFG rates,
South to North transfer activity, storage activity and core demand (i.e. temperature). ATCO
stated that all of these factors are variable, some highly so, resulting in exchange service costs
that are very difficult to forecast.

ATCO noted that Mirant also failed to show the very significant change in gas prices that
occurred shortly after the I/P settlement was negotiated. Nevertheless, ATCO stated that it could
demonstrate that the non-standard PanCanadian Contract still has a net benefit to all customers
using the higher gas prices that have occurred but were unknown at the time the non-standard
contract was filed with the Board.

ATCO indicated that, while Producers electing to exchange their volumes to the NGTL system
pay an exchange fee any time they elect such service, the costs incurred to provide exchange
service vary throughout the year, being higher in the summer as core market demand is lower in
the summer months. Both the exchange fee revenue and the costs to provide exchange service
are collected in an Exchange Fee Deferred Account, with the desire for revenue and costs to
offset each other by the end of the I/P settlement period.

The I/P settlement specified an exchange fee of 2.0¢/GJ for dually connected plants which would
have applied to the PanCanadian plants in the Carseland area in the absence of a non-standard
contract. The PanCanadian special contract specifies a zero exchange fee for its Carseland
volumes, thereby reducing exchange revenue by $620,500 annually (85,000 GJ/day x 365
days/yr x $0.02/GJ).

On June 4, 2001 the Company filed an amendment with the EUB regarding the South Exchange
Deferred Account. The exchange fee proposed for dually connected plants is to change from a
fixed 2¢/GJ charge to 50% of the standard exchange fee. This is forecast to be a 5.3¢/GJ
exchange fee for dually connected plants starting on November 1, 2001.

ATCO submitted that, with this amendment, the PanCanadian non-standard contract will
decrease exchange fee revenues by $766,050 in 2001 (85,000 GJ/d x 304 days x $0.02/GJ +
85,000 GJ/d x 61 days x $0.05 GJ/) and $1,551,250 in 2002 (85,000 GJ/d x 365 x $0.05/GJ).
This is far less than Mirant’s calculated cost of $8,500,000 in each of 2001 and 2002. ATCO



                                                       EUB Decision 2001-97 (December 12, 2001) • 107
2001/2002 General Rate Application – Phases I and II                                 ATCO Pipelines South


provided an analysis based on the exchange rate of 5.3¢/GJ for dually connected plants in this
amendment, indicating that the PanCanadian contract was still of benefit overall to customers.

ATCO indicated that PanCanadian approached the Company in 2000 with a competitive
transportation alternative to ATCO whereby PanCanadian would construct its own pipeline to a
large industrial customer in the Carseland area. ATCO reviewed this alternative and determined
that it was a serious bypass threat. There were no regulatory or geographical obstacles to
building the pipeline and the economics would result in an equivalent transportation rate of
6.1¢/GJ which is lower than APS’ 7.4¢/GJ receipt rate. Further, relatively high gas prices, which
were driving ATCO UFG charges higher, provided an environment where the large industrial
customer was also very interested in this alternative. Time was also of essence, as PanCanadian
was preparing to pour a concrete pad for a new gas plant in the area. PanCanadian had some
flexibility in locating this plant, and in the absence of an acceptable contract with ATCO would
have located the plant away from APS facilities and as close as possible to the large industrial
customer.

ATCO and PanCanadian were able to negotiate a ten year agreement whereby the PanCanadian
volumes would remain on the ATCO system, no bypass pipeline would be built and the
Company would waive the exchange fee for PanCanadian volumes from the Carseland area.
ATCO indicated that it was clearly beneficial for all of ATCO’s customers to maintain the
PanCanadian volumes at the cost of foregoing the exchange fee revenue from PanCanadian. On
November 29, 2000 ATCO filed both the I/P settlement and the non-standard contract with
PanCanadian. ATCO pointed out that, at the time of this filing, the exchange fee for dually
connected plants (which applies to PanCanadian) was 2.0¢/GJ. Therefore ATCO was able to
maintain receipt revenues of 7.4¢/GJ while foregoing exchange revenue of 2.0¢/GJ, clearly a net
benefit to all customers. ATCO submitted that this was the best information available at the time.

In conclusion, ATCO submitted that the Company has met the criteria established for it by the
Board with respect to non-standard or competitive rates (Decision E93098,99 dated December 30,
1993, p.61).

ATCO also stated that, contrary to Mirant’s submission, the PanCanadian contract meets all of
the criteria for load retention rates in Decision U97096,100 dated November 14, 1997,with the
exception of being able to confirm long run benefits beyond the current settlement (ending
December 31, 2002). With respect to the latter point, ATCO submitted that while long-run
benefits may not be confirmed today as the situation post settlement is unknown, the best proxy
for future rates would be the settlement’s provisions, which are what the Company used in its
analysis.

ATCO did not take issue with whether EUB Decision E93098 (CWNG GRA) or U97096 (NGTL
Load Retention) is used to evaluate the PanCanadian non-standard contract, noting that while the
wording of each decision is somewhat different, the intent is largely the same to ensure that any
discounted rate offered to retain a customer still provides an overall net benefit to all customers
on the system. ATCO noted that indeed this is the focus of Mirant’s argument.

        99
             Decision E93098 Canadian Western Natural Gas Company Limited, 1993/1994 GRA, Phase II
        100
             Decision U97096 NOVA Gas Transmission Ltd., Load Retention Service

108 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South




Positions of the Interveners
PanCanadian
PanCanadian submitted that the evidence in this proceeding demonstrates that the rates
negotiated in the transportation arrangement with ATCO are just and reasonable and not unduly
discriminatory, and should be approved by the Board.

Noting that Mirant, the only party expressing opposition to the contract, represents 400
producers on behalf of Pan-Alberta Gas Ltd (Pan-Alberta), PanCanadian submitted that this in no
way should imply that Mirant is giving evidence on behalf of those 400 producers in this
proceeding. PanCanadian pointed out that, as a producer to the Pan-Alberta pool, it clearly does
not support the Mirant argument.

PanCanadian submitted that, in any event, the positions advanced by Mirant have been shown by
the evidence to be wrong. Specifically, PanCanadian noted that ATCO was required to negotiate
a transportation arrangement with PanCanadian to respond to a credible bypass threat, and there
is a benefit to the other shippers in the retention of the Carseland volumes on the ATCO system.

PanCanadian noted that Mirant raised no issue about the credibility of PanCanadian’s bypass
threat, but during cross-examination, indicated that Mirant was not sure that PanCanadian would
actually build a competitive pipeline. PanCanadian submitted that, unlike ATCO, Mirant did not
conduct an analysis of PanCanadian’s alternatives, or enter into discussions with PanCanadian
about the alternatives. PanCanadian submitted that it could have pursued viable transportation
options in the Carseland area had ATCO not negotiated the special transportation arrangement.

Referring to suggestions by Mirant in testimony that the best alternative would have been to have
the PanCanadian volumes remain on the system at the rates negotiated by the I/P settlement,
PanCanadian pointed out that this would not have been an acceptable alternative, as
PanCanadian’s bypass opportunity had lower associated costs, and absent the special contract,
PanCanadian would have removed its Carseland volumes from the ATCO system.

PanCanadian referred to the evidence provided by ATCO to demonstrate that a net benefit
accrues to all ATCO shippers from the PanCanadian special contract. Specifically, PanCanadian
pointed out that the revenue it pays is $2.3 million per year (receipt toll of 7.4¢/GJ on 85
TJ/day), which significantly exceeds the loss of exchange revenue, arising from the zero
exchange fee specified in the contract, of either $0.6 million/year (based on the 2.0¢/GJ set out in
the I/P settlement) or $1.5 million/year (based on the 5.3¢/GJ exchange fee proposed in ATCO’s
June 4, 2001 amendment).

PanCanadian considered that, in the final analysis, ATCO’s customers are clearly better off with
the special contract, and noted that, while there is foregone revenue associated with the zero
exchange fee, ATCO was able to retain $2.3 million/year in receipt toll revenue, which is a
benefit to all ATCO shippers.




                                                       EUB Decision 2001-97 (December 12, 2001) • 109
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


PanCanadian submitted that ATCO was clearly in the best position to assess the circumstances
surrounding the transportation of PanCanadian’s Carseland volumes. PanCanadian had a viable
bypass option, meaning that to retain the volumes on the system, a negotiated rate would benefit
the overall system and existing customers.

PanCanadian noted however, that Mirant contend that the Board should deny the special
contract, on the basis that the exchange fee should not be zero, but should be 27.3¢/GJ (the
Mirant assessment of the costs of providing exchange service). PanCanadian submitted that
Mirant’s position is totally out of step with marketplace reality, and questioned why, if ATCO
could not have retained the PanCanadian volumes at the discounted 2¢/GJ exchange fee, how
could the Company have retained the volumes at a 27.3¢/GJ exchange fee.

PanCanadian stated that the fact is that the Board has accepted the principle that market based
exchange fees, aimed at enabling ATCO to compete, are just and reasonable, and submitted that,
based on this principle, the PanCanadian contract should be approved. PanCanadian submitted
that Mirant’s allegation of no net benefit arising from the PanCanadian contract is based on a
flawed calculation of the costs of providing exchange service to PanCanadian. In conclusion,
PanCanadian submitted that the evidence demonstrates that the Mirant is wrong, and further
substantiates the view that the Board should conclude that the PanCanadian contract, with its
7.4¢/GJ receipt charge, will provide a net benefit to all ATCO customers.

Mirant
Mirant indicated that the sole issue it would address is the non-standard contracts, which
are clearly outside of the re-opened I/P settlement and therefore require Board approval.
Mirant requested that the Board deny approval of the PanCanadian (Carseland Area)
special contract on the ground that the costs exceed the revenue, and it does not therefore
satisfy the criteria for approval of a load retention contract. Mirant concluded shippers are
better off allowing these volumes to leave the ATCO system, than remaining under the
terms of the special contract and paying no exchange fee.

Mirant pointed out that it would specifically address four (4) issues:

    •   the “test” for approval of a load retention contract;
    •   the proper equation for the measurement of the benefits of a load retention contract;
    •   the definition of the costs of moving gas under the special contract; and
    •   the volume to which the costs are to be applied under the special contract.

Mirant indicated that there appears to be consensus among the parties on the “test” for approval
of a load retention contract, indicating that all customers must be better off with the retention of
the volumes at the negotiated rate than with the loss of the customer from the ATCO system.
Mirant viewed this as a concise summary of the Decision U97096 (NGTL Load Retention
Service), but noted that ATCO relied instead upon Decision E93098, which framed the criteria in
a slightly different fashion.

In Mirant’s view, the special contract with PanCanadian does not meet any of the four criteria
enunciated in the NGTL Load Retention Service Decision. However, Mirant focused upon the

110 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                             ATCO Pipelines South


criterion that there should be a net benefit to all on the system, as Mirant’s position is that
approval of the special contract should be denied on that basis alone.

Mirant submitted that there is also consensus on the proper measurement of the net benefits
under a load retention contract. Mirant considered that all customers would be better off with the
retention of the volumes at a negotiated rate than with the loss of the customer from the ATCO
system, provided the revenues generated by the contract exceed the costs (i.e. net benefits =
revenue – costs).

Mirant considered that the disputes center on the costs component of the net benefits equation,
specifically:

    •   The definition of the costs/GJ; and
    •   The volume to which the costs are to be applied.

Mirant’s definition of the costs/GJ component is:

        Costs/GJ = NGTL Toll + NGTL Fuel + ATCO UFG

According to Mirant, ATCO conceded that Mirant had correctly identified the cost components,
but chose instead the following definition:

        Costs/GJ = Exchange Fee for dually connected plants.

Mirant submitted that ATCO’s definition confused costs with revenues in several respects and
was therefore fundamentally flawed.

With respect to the volume to which the costs are applicable, Mirant noted that the parties agree
that:

    •   The costs are only applicable to the net deliveries to NGTL from ATCO; and
    •   ATCO forecasts the net deliveries to NGTL from ATCO to exceed 85 TJ/day in
        2001 and 2002 for nine (9) and seven (7) months respectively.

Mirant noted that ATCO however, alleged the incremental costs are $2.3 million/annum not $8.5
million/annum because Mirant’s calculation:

    1. assumed that the incremental costs would be incurred on every day of the year;
       and
    2. attributed incremental costs to all 85 TJ/day flowing under the Special Contract.

To simplify these issues and to demonstrate their sensitivity to gas prices, Mirant recalculated the
cost of the special contract on a per GJ basis rather than annually. Mirant’s recalculation using
ATCO’s advice that the incremental costs are only incurred during the summer, demonstrated
that the costs still exceed the revenues, and will continue to exceed the revenues until gas prices
fall to $2.57/GJ or $1.64/GJ. Even ATCO does not foresee gas prices falling to those levels.

                                                        EUB Decision 2001-97 (December 12, 2001) • 111
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South




In short, Mirant’s position was that, if the volumes under the special contract leave the ATCO
system, there will be 85 TJ/day less creating incremental costs.

Mirant calculated that the costs/GJ of the special contract clearly exceed the revenues at any
reasonably foreseeable gas price. Mirant noted that ATCO agreed that, under those
circumstances, other customers on the ATCO system would be adversely affected. The special
contract does not, therefore, meet the criteria for approval of load retention contracts.

Mirant noted that the costs of the special contract would escalate the negative balance in the
South Exchange Deferred Account, the disposition of which has not been determined.

Further, Mirant stated that the ATCO system is full, and ATCO has actually had to curtail
shipments, so why would ATCO offer a discount to retain gas on the system, when it is turning
away gas that could be shipped at the full tariff?

Accordingly, Mirant requested the Board to:

    1.    deny ATCO’s application for approval of the PanCanadian special contract on
          the grounds that it does not satisfy the criteria for load retention contracts;
    2.    order ATCO to reimburse the South Exchange Deferred Account the exchange
          fees Pan-Canadian would have had to pay in the absence of the special contract;
          and
    3.    order ATCO to file with the Board and to provide interested parties with a copy
          of any non-standard contracts, and any related arrangements at the time ATCO
          notifies the Board of the non-standard contract.

PICA
PICA supported the argument submitted by Mirant. Specifically, PICA noted the consistency in
the argument of Mirant with respect to how to evaluate the impact of retention of the
PanCanadian volume and the position of PICA with respect to how to evaluate the cost of
attachment of new producer volumes. In both instances, PICA stated that the correct approach is
to examine the incremental costs (incurred or avoided) versus the incremental revenues (gained
or lost) to determine if the proposal should go forward.

PICA noted Mirant’s statement that ATCO has had to curtail new producer volumes. PICA
considered that, as Mirant correctly points out, it does not make sense to try to retain load at less
than full tariff from a producer with a feasible economic bypass when there are other producer
loads without economic bypass and willing to pay full tariff. PICA also considered it
unreasonable for ATCO to justify the PanCanadian contract on a “rolled in” basis while at the
same time using an incremental basis to evaluate new producer requests for service. PICA
submitted that, when properly analyzed on an incremental basis, the only conclusion one can
reach is that the special PanCanadian contract should not be approved.




112 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


Views of the Board
Based on the submissions of ATCO and PanCanadian, the Board is satisfied that the Company’s
non-standard contract with PanCanadian was necessary to maintain the producer volumes on the
system. The Board considers it clear that, in the absence of a contract of this nature,
PanCanadian had a credible by-pass opportunity.

The Board notes the concerns expressed by Mirant that costs associated with the PanCanadian
contract exceed the related revenues, and that the Company should have allowed the volumes to
leave the system. While recognizing that the calculations presented by Mirant would appear to
support this position, the Board also considers that there is merit to the counter-arguments of
ATCO and PanCanadian in this regard. In particular, the Board considers that considerable
weight must be given to ATCO’s submission that Mirant’s position is based on a scenario where
costs are isolated for PanCanadian specifically, which may tend to oversimplify what is a much
more complex calculation.

In the Board’s view, it must be recognized that ATCO is in the best position to evaluate the
extent to which the revenues from PanCanadian contribute to the system as a whole, and is
prepared to accept ATCO’s submission that the non-standard contract will not incur incremental
costs as Mirant has calculated.

The Board also acknowledges the submissions of Mirant and PICA that the non-standard
contract with PanCanadian does not meet the criteria required for approval of a load retention
contract, as set out in Decision U97096. However, the Board agrees with ATCO that the criteria
were established specifically for NGTL, and furthermore, that the PanCanadian contract
generally satisfies those criteria, to the extent that the discounted rate offered to retain the
customer still provides an overall net benefit to all customers on the system.

Accordingly, the Board is satisfied with ATCO’s representations with respect to the rationale for
entering into the non-standard contract and the resultant benefits that will accrue to the system as
a whole. The Board therefore approves the contract with PanCanadian, but agrees with Mirant,
that, where the Company notifies the Board of a special arrangement with a transportation
customer, there is also a need to file sufficient information with the Board and interested parties
to facilitate evaluation of the special arrangement, including the impact on other customers on
the system. Accordingly, the Board directs ATCO for all future non-standard contracts, to
provide the Board and all interested parties with the following:

    •   an analysis of all costs incurred to provide the service, including costs to the South
        Exchange Deferred Account;
    •   an analysis of the competitive alternative; and
    •   a copy of the non-standard contract.




                                                       EUB Decision 2001-97 (December 12, 2001) • 113
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


8       COST OF SERVICE STUDY

8.1     Background
On November 19, 2000, ATCO Pipelines filed an application for approval of a successfully
negotiated settlement with I/P customers. The Board approved the revised settlement in Decision
2001-53.

By letter dated March 1, 2001, following extended correspondence with the Board and interested
parties, ATCO agreed to take the risk that any adjustments to revenue requirement or revenue
forecasts in the GRA could be allocated to customer classes other than core.

By letter dated March 8, 2001, the Board expressed the view that, given the potential impact of
the I/P settlement on core customers, a comprehensive examination of relevant cost allocation
issues in the GRA would be necessary. The Board considered that a comprehensive examination
of cost allocation issues could only be achieved with the filing of a COS Study by ATCO in
advance of the hearing. Accordingly, the Board directed ATCO to file a COS Study and related
information by March 19, 2001, to allow for examination of both Phase I and Phase II
components of the rate proceeding during the hearing.

In accordance with the direction of the Board, ATCO filed a COS Study on March 19, 2001.

In Decision 2000-16, the Board approved several changes in CWNG’s rate design and costing
methodology that were appropriate to maintain CWNG’s position in an increasingly competitive
market with specific reference to the classification and distribution methodologies related to
transmission costs. Specifically, CWNG proposed to address potential inequities in cost
allocation that may have resulted from the use of the Modified Seaboard Formula used in former
GRA’s.

Furthermore, in Decision 2000-16, the Board directed that, at the next Phase II proceeding
CWNG:

        •   formulate a methodology that will facilitate determination of the costs of
            providing service to the Industrial/Producer class, and incorporate the results
            in the COS study; and,
        •   address the other issues of concern as set out below:
            • consideration of the use of Distance of Haul (DoH) methodology in the
                review of costs.

In response to these directives, ATCO developed methodologies to determine the costs of
providing service to the I/P class with and without DoH. ATCO filed its COS Study on
March 19, 2001 describing the methodologies proposed and depicted the results of both studies
in separate tables.




114 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                   ATCO Pipelines South


Position of ATCO
In the COS Study, ATCO furnished estimates of the cost of providing transmission service to
three customer groups served by the Company, namely, Gas Utilities, Industrial customers and
gas Producers. The allocation to customer classes and related unit costs were calculated in the
COS Study, with results determined separately with and without use of DoH methodology.
ATCO submitted that the COS Study results would not be used to set rates, but to test the
reasonableness of the rates negotiated with I/P customers. ATCO considered that, if the results of
the COS Study demonstrate that the costs of providing service to the I/P class are covered by
revenue generated from the rates agreed with that class, those rates meet the reasonableness
criterion.

A summary of the results of the COS Study was shown in the following table:

                     Table A: COS Study – Distance of Haul NOT Incorporated

                             Gas Utilities   Gas Utilities   Industrial   Industrial   Producer     Producer
        Source of Data
                              Revenue           Rate          Revenue        Rate      Revenue        Rate
                               $(000)         $/GJ/mo          $(000)      $/GJ/mo      $(000)      $/GJ/mo
          COS Study             24,291           1.98          3,152        2.02        13,005         1.92

        Existing Rates          23,553          1.82*           N/A          N/A         N/A           N/A

       Settlement Rates          N/A             N/A            866         1.50        15,340         2.25

*This rate is applicable to ATCO Gas volumes only. Gas Alberta volumes were charged a
throughput rate of $0.195 per GJ. In the settlement with Gas Alberta, the demand part of the rate
was set at $1.95 / GJ of monthly demand. The revenue on the new settled rate from Gas Alberta
is forecast at $379,400.101

The results in Table A indicated that the combined revenues from the Industrials and Producers
exceeded the filed costs for the two groups.

In the DoH study, distance data was combined with peak day demand volumes for each of the
customer groups to develop volume-distance factors that were applied to costs that vary with
distance. Generally, DoH results were evaluated by ATCO Gas as unstable and volatile due to
changing flows arising from daily changes in demand. The DoH for Industrial customers
remained significantly less than for the Gas Utilities and Producers over various flow patterns.
The results from the DoH study indicate that the cost of serving the Industrials should be less
than shown in Table A, and the cost of serving the Utilities should increase.




        101
              APS.CAL.135 (c) p. 3 of 6

                                                              EUB Decision 2001-97 (December 12, 2001) • 115
2001/2002 General Rate Application – Phases I and II                                        ATCO Pipelines South


The results of incorporating the DoH study was shown in the following table:

                                          Table B – DoH Included

  Source of Data       Gas Utilities   Gas Utilities    Industrial    Industrial      Producer      Producer
                        Revenue           Rate           Revenue         Rate         Revenue         Rate
                         $(000)         $/GJ/mo           $(000)       $/GJ/mo         $(000)       $/GJ/mo
  COS Study
                          26,515           2.10           2,372          1.52          12,261             1.81
  Including DoH


Subsequent to the original submission on March 19, 2001, a number of revisions to the COS
Study were filed. The following is a chronology of COS Study filings:

    March 19                COS Study                  Original Filing (per Tables A & B above)
    April 17                BR-APS.44                  Assuming no use of Vintage Method
    June 15 (Note 1)        Rebuttal Evidence          Recalculated using Dedicated Plant Method
    July 13                 BR-APS.47                  Illustrating minimal impact of revision to Gas Alberta
                                                       peak demand

    Note 1 – Adopted by ATCO as its position in this proceeding. The results of the COS Study
    filed in rebuttal evidence on June 15, 2001 were:


                                                                                Excluding     Including
                                                                                  DoH            DoH
         Total Cost Allocated to Industrial/Producer class                       $17,008         15,858
         Total Revenue forecast for Industrial/Producer class                    $16,206        $16,206
         Revenue/cost ratio                                                        95.3%       100.23%

ATCO submitted that the revenue/cost ratios as determined from the results of the COS Study,
which are within the Board’s accepted guidelines, demonstrate that the 2001/2002 I/P rates
agreed in the I/P Settlement are reasonable, and that the I/P customers bear their fair share of the
costs of transmission service.

Views of the Board
The following paragraphs of this Section of the Decision set out the Board’s findings and
conclusions arising from its evaluation of ATCO’s COS Study.

8 .1 COS Study Methodology
 .1
The APS COS Study included a process to:

    •   Identify general use plant that was shared or jointly used by more than one customer
        group;
    •   Identify plant that was dedicated to or used solely by a customer group;


116 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


    •   Identify historical uses and responsibilities for the pipeline system and determine how
        they affect the current responsibilities for assets;
    •   Identify and segregate components of the system that may vary with DoH;
    •   Assign as many operating and maintenance costs as possible directly to the function
        causing the cost so that the use of allocation factors would be minimized; and
    •   Employ cost categories of functions that would enable marketing and customer support
        costs to be assigned/ allocated to the users of these services.

The COS Study was prepared using a four-step procedure:

    •   Asset and operating costs were grouped using an accepted system of accounts;
    •   The costs were functionalized into administration, marketing, customer support, pipeline,
        compression and measurement and regulating functions;
    •   The functionalized costs were classified into customer, throughput or demand costs; and
    •   The functionalized and classified costs were distributed, allocated or assigned to the three
        customer groups using distribution factors such as peak day demand or gas flow.

In order to establish the costs of providing service to the I/P class, in compliance with the
direction of the Board in Decision 2000-16, ATCO submitted that it was inappropriate to
replicate the methodology used in the CWNG 1998 Phase II GRA. ATCO considered it more
important to focus on identifying and segregating plant and associated costs to the three major
customer groups, which resulted in establishing three categories of plant use namely, sole use by
the I/P group, sole use by the utilities group and joint use by the I/P and Utilities groups. ATCO
considered that fairness dictated that costs associated with facilities dedicated to a specific
customer group not be charged to the other groups that do not use or require such facilities.

In the study, ATCO described direct assignment (sole use) as the process of designating a cost
directly to a single category without use of any apportionment mechanism. In contrast, joint use
costs were apportioned to customer groups by means of allocation factors developed from
informed judgment and analysis. In the original COS Study, ATCO used the direct assignment
technique to segregate sole use plant costs for the I/P group, but used a proxy for this technique
to identify and assign costs to the Utilities group. Specifically, the proxy, based on identification
of plant mains built prior to 1984, and allocation of the related cost to the Utilities group,
resulted in 30% of the cost of those mains being allocated to the Utilities. Subsequently, after
making the decision that the direct assignment method was preferable to use for purposes of
allocating costs to the Utilities group, ATCO developed a conservative estimate that at least $17
million, or 20% of general mains were dedicated to the Utilities group. ATCO submitted that it
would continue to adopt this conservative estimate of 20% in spite of the fact that a subsequent
detailed review, undertaken during the proceedings, indicated that more than $26 million or
28.5% of the mains are dedicated to the Utilities group.

After direct assignment of sole use costs, all remaining costs, considered joint-use, were
allocated between the groups using simple distribution factors. In this regard, ATCO pointed out
that, in addition to those asset costs directly assigned, approximately 66% of O&M costs and
61% of administration costs were also allocated by direct assignment. ATCO considered that this
demonstrates significant progress towards meeting the criteria set out by Calgary that “the

                                                       EUB Decision 2001-97 (December 12, 2001) • 117
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


perfect class COS study would have no allocations, all costs would be deemed directly
assignable.”102

ATCO introduced the DoH methodology into the COS Study at the cost distribution stage by
combining contract demand or peak day responsibility with DoH data to arrive at volume-
distance factors for each customer group, which were used to distribute pipeline and compression
costs that vary with distance. ATCO submitted it was not the intent to draw quantitatively precise
conclusions from the DoH analysis but rather to make directional observations and conclusions
from the results. ATCO summarized the directional observations in the following points:
    •   The distances of haul for the Utilities and Producers are about equivalent under the flow
        conditions analyzed.
    •   The DoH for deliveries to the Industrial customers is consistently shorter than for the
        other customer groups under all flow conditions.

ATCO recommended that the Board recognize these observations when evaluating the
reasonableness of the Industrial rates.

Views of the Board
The Board has reviewed the methodology used by ATCO in the preparation of the COS Study
filed in on March 19, 2001, and more fully described in response to BR-37 to BR-43. The Board
agrees that the methodology utilized by CWNG in the 1998 GRA was not entirely applicable to
ATCO Pipelines South and that certain changes were necessary to comply with the requirements
of Decision 2000-16 and to reflect the reorganization from CWNG to ATCO Pipelines South.

The Board notes that in the initial methodology filed in this proceeding, ATCO made the
following changes from the procedures approved in the last GRA by CWNG:

    •   Identification of three customer classes, namely: Utilities, Industrials and Producers. The
        Board considers the use of three customer classes to be an appropriate approach;
    •   Identification of five distinct cost functions as compared with the ten functions used in
        the last GRA. The Board considers the use of five functions to be an appropriate
        approach given the business environment of ATCO Pipelines, with only a transmission
        service offering as compared to the former CWNG, which included transmission, gas
        supply, distribution and customer accounting and contact services; and
    •   Adoption of a procedure of directly assigning costs of dedicated fixed plant providing
        service to the I/P class and directly assigning the costs of pre-1984 vintage facilities to
        the Utility class. The Board’s views regarding the direct assignment of specific
        transmission costs are addressed in Section 8.2.2 of this Decision.




        102
              APS-CAL.16(d)

118 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


8.2     Specific Issues Arising
8 .1 Distance of Haul
 .2
Position of ATCO
ATCO noted that Calgary recommended elimination of DoH methodology from the COS Study,
on the basis of criteria indicating that DoH methodology is only appropriate in the case of long
linear pipeline systems. ATCO expressed concern however, with Calgary’s failure to address the
appropriateness of these criteria to a pipeline system with network characteristics. ATCO
recommended that the Board give some weight to the DoH and recognize that under the wide
range of flow conditions analyzed, the DoH for the Industrial customers is consistently less than
for the other two customer groups included in the COS Study.

Referring to Calgary’s concern about the treatment of isolated receipt points, ATCO indicated
that these receipt points carry small weight in the overall volume-distance calculation, and were
not included in the DoH analysis. With respect to Calgary’s comments concerning direction of
flow, ATCO provided evidence that the DoH analysis recognizes the correct direction of flow on
the Carseland line under different flow conditions.

Regarding the allegations of Calgary with respect to DoH sampling techniques, ATCO
indicated that, while the analysis did not employ a sample of receipt and delivery points,
several small volume points were amalgamated, but not selected on a sample basis.
ATCO stated that a few points were excluded because they are not part of the integrated
system and would carry very little weight in terms of their volume and distance.

ATCO noted that Calgary chose to ignore the Company’s evidence that relative DoH
comparisons have indicated consistently that the distance gas is hauled for industrial customers is
significantly less than for the other two groups.

Positions of the Interveners
Calgary
Calgary noted that ATCO filed several Class Cost of Service Studies (COS Studies) in this
proceeding, initially including a vintage costing methodology as well as vintage costing
including DoH, which were subsequently abandoned and replaced with the dedicated plant
concept. Calgary therefore chose not to address the vintage costing approach, but submitted that
all of the APS COS Studies are flawed with respect to both the DoH methodology and dedicated
plant analysis.

Calgary considered that the ATCO COS Study is rife with methodology errors, noting that
ATCO proposes to use a mix of dedicated, incremental and allocation costing methodologies
driven by an unrealistic DoH study. Calgary considered these factors render the COS Studies
fatally flawed and of no assistance in this proceeding.

While in agreement with ATCO that, in Decision 2000-16, the Board instructed the Company to
study the impacts of DoH, Calgary submitted that, instead of applying the concept to the realities
of the ATCO system, the Company embarked upon a simulation and sampling analysis of DoH

                                                       EUB Decision 2001-97 (December 12, 2001) • 119
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


based upon unproven techniques. By way of illustration, Calgary referred to the accepted
regulatory criteria for employing DoH concepts in pipeline costing as set forth in Calgary’s
written evidence, which include the following:

    •   The Pipeline system is several hundred kilometers in length with gas flowing in a single
        direction.
    •   The initial upstream function of the pipeline is to accumulate volumes for long distance
        downstream transportation.
    •   Customer demand diminishes towards the terminus of the pipeline system.
    •   Pipe size and or the number of loops tend to decrease towards the terminus of the system
        due to the diminishing demand.
    •   The system can be zoned for purposes of cost allocation and rate design.

Calgary submitted that the ATCO system does not meet any of these criteria, and that under its
dedicated and incremental plant concepts, use of the DoH methodology is additionally flawed.
Regarding ATCO’s claim that Calgary failed to address the application of DoH for a pipeline
with network characteristics, Calgary stated that the fact that pipelines with network
characteristics do not meet accepted regulatory criteria is precisely why Calgary submitted that
the DoH analysis be rejected.

In Calgary’s view, the DoH study appeared to be based upon the structure defined as the
mainline system, but giving no recognition to the numerous communities served directly from
the NGTL system.

Calgary pointed out that, rather than being based on actual DoH data for each class of service,
the DoH study is predicated on a simulation analysis and sample data, rather than DoH, for
which ATCO offers no evidence with respect to statistical or operational validity.

In addition, Calgary expressed concern that the DoH analysis includes numerous flows which,
depending on the season are bi-directional, a condition that violates one of the primary criteria
for use of DoH, long haul directional transportation. Calgary also expressed concern that the
ATCO system fails to meet the criterion that the upstream function of the system needs to be
used to accumulate volumes for long distance transportation, noting that there are
interconnections scattered throughout the system, which, when coupled with bi-directional flow,
and the year around north bound flow of the Carseland Line, clearly demonstrates that the ATCO
system does not meet the basic criteria for use of DoH. Calgary also made reference to other
specific characteristics of the ATCO system that in Calgary’s view rendered use of the DoH
inappropriate, including:

•   The fact that the load in the City of Calgary area represents over 70% of the utility load, with
    pipe size at its maximum diameter feeding into the city of Calgary area; and
•   A primary reason for utilizing DoH is the establishment of individual rate zones, whereas in
    ATCO’s case, the DoH methodology was applied to the entire system with uniform system
    rates being negotiated for transmission customers.



120 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


Calgary submitted that the DoH study is flawed in its design, flawed in its sampling technique
and inappropriate when judged against empirical criteria.

Views of the Board
The Board regards ATCO’s DoH study as responsive to the requirement stipulated in Decision
2000-16. The Board also notes Calgary’s criteria defining the applicability of DoH
methodologies, and Calgary’s recommendation that, since the ATCO DoH study contravenes
these basic criteria, the results of the study should be rejected.

The Board accepts Calgary’s recommended criteria for application of DoH concepts and agrees
that the ATCO pipeline network does not meet these criteria. Therefore, the Board considers the
results of the DoH study inappropriate for quantitative determination of cost assignment to
customer classes of ATCO. However, the Board also notes ATCO’s submission that the results
of the DoH study are intended only as directional support for the main COS Study. The Board
notes that in all of the DoH scenarios presented in evidence, the comparisons have indicated
consistently that the distance gas is hauled for Industrial customers is significantly less than for
the Utilities and Producer classes. Therefore, the Board finds the results of the DoH study useful
when evaluating revenue to cost ratios for the Industrial customers.

In conclusion the Board accepts the Company’s submission that the results of the DoH study are
to be used only as directional support for the main study. The Board considers that any additional
DoH studies of the ATCO system would be of no further benefit unless circumstances change in
the future to the point where the Company’s transmission system exhibits characteristics that
more closely fulfill the criteria set out by Calgary.

8 .2 Direct Assignment
 .2
Position of ATCO
ATCO stated that, after the IR process was largely completed, the Company found time to
consider alternative procedures to the use of vintage costing as a proxy for the direct assignment
approach to identify the facilities dedicated to the Utilities group. Accordingly, ATCO used the
direct assignment methodology in developing the COS Study results in its June 15, 2001 rebuttal
evidence, ATCO considered that this should eliminate any concerns about vintage costing
previously held by Calgary.

A second issue for ATCO resulted from Calgary’s allegation that the Company used the
dedicated assignment procedure to introduce incremental costing. Specifically, Calgary alleged
that ATCO had allocated all of the Banff looping costs to ATCO Gas South. ATCO actually
allocated all of these looping costs to the Utilities group, which includes AGS and Gas Alberta,
as these loops were built to serve the core customers, (i.e. all customers excluding the I/P group).
ATCO stated that cross-examination of Calgary’s witnesses by ATCO’s counsel established the
following points:

    •   the bulk of the loop costs were included in Phase IV looping which cost over $12 million;
    •   Phase IV looping feeds into the existing line downstream of the industrial loads east of
        Canmore and west of Seebe; and

                                                       EUB Decision 2001-97 (December 12, 2001) • 121
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


    •   Phase IV looping occurred in 1997 [actually 1998] when the industrial demand projection
        was “flat lining.”

ATCO submitted that the evidence on the record makes it clear that the bulk of the Banff loop
expenditures were made to serve growth in the core market and were not required to meet I/P
demands.

Shortly after filing rebuttal evidence on June 15, 2001, the Company, in response to intervener
requests, filed details supporting the plant determined to be dedicated for sole use of the Utilities
group. ATCO pointed out that, ultimately, approximately $26 million of plant in service was
determined to be dedicated to the Utilities group, and that at Calgary’s request and specifications,
work orders were provided for over $22 million of this dedicated plant. In spite of being able to
demonstrate a sound basis for the estimate of $26 million for plant dedicated to the Utilities
group, the Company chose to remain with its conservative estimate of $17 million presented in
its June 15, 2001 rebuttal evidence. In ATCO’s view, with the inclusion of such a conservative
estimate in the COS Study analysis, the Company has demonstrated that the negotiated I/P rates
are reasonable. Considering its application of the dedicated plant methodology to the Utilities
group and its use of a very conservative estimate of $17 million of plant dedicated to this group,
ATCO questioned Calgary’s preoccupation with the plant components making up the estimated
total of $26 million identified in Exhibit 148.

ATCO maintained that regrettably, a few interveners, particularly Calgary, chose to totally
ignore, or reject without explanation, the information provided by the Company in rebuttal
evidence (Exhibits 99 and 162). ATCO submitted that the Board directions in Decision 2000-16
clearly required the Company to formulate a methodology that would indicate the cost of
providing service to the I/P class. ATCO did not interpret this direction to constrain the
methodology to be used to determine the true cost of providing service other than to be fair and
reasonable in distributing the costs to customer groups. In ATCO’s view, the use of the dedicated
plant method is an example of the application of the fairness principle, to the extent that
customers groups are not allocated responsibility for facilities they do not use. ATCO pointed
out that the map attached to Exhibit 99 clearly indicated those mains dedicated to the Utilities
group, and that allocation of any of the costs associated with those facilities to the I/P group
would not result in determination of the true cost of providing service to that class. ATCO
considered that Calgary’s proposal for use of the rolled-in treatment of costs in lieu of the direct
assignment would distort the determination of the true cost of serving each customer group, and
result in an unfair allocation. With respect to the Barrons to Vulcan line, ATCO refuted
Calgary’s comments on double charging, stating that ATCO did not do so and that Calgary
confused COS methodology with rate making.

With regard to the CCA, ATCO noted that, like Calgary, the CCA selectively used excerpts from
exhibits that focus on the industrial load in the Canmore/Banff corridor rather than taking a
balanced approach to examining the cause for the Banff loops, which the Company’s June 15,
2001 rebuttal evidence demonstrated was due solely to growth in the core customer load in
Canmore and Banff.




122 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                      ATCO Pipelines South


While acknowledging the CCA’s recommendation that the COS study should be updated to
exclude volumes on the isolated facilities from the volumes on the integrated facilities, ATCO
submitted that this revision would have no significant effect on the results, given that the
volumes on the isolated facilities are dwarfed by the very large volumes delivered to Calgary and
Lethbridge.

Referring to PICA’s comments about last minute changes to core customer data, ATCO
indicated that the changes, as summarized in its rebuttal evidence, were prompted by questions
from Calgary and other interveners and overall resulted in more reliable data, with a larger
amount of the mains being identified as dedicated to the Utilities group. ATCO stated that all
parties had the data for the plant dedicated to the Utilities group since late March, and no
questions arose until the last day of the hearing. ATCO acknowledged that the South and East
Main Line expansion projects are dedicated to the I/P group and should be assigned to them
100%, but submitted that the change would not have a significant effect on the COS Study
results.

ATCO rejected PICA’s allegation of selective cherry picking, and submitted that the omission of
the South and East Main Line project was isolated.

ATCO submitted PICA is incorrect in reaching the conclusion that ATCO has been
inconsistent between its system planning and cost causation treatment. ATCO pointed out
that the majority of system costs are classified as joint costs, and are shared by all
customer groups. ATCO indicated that these costs relate to the mainline facilities, or
backbone, as described by PICA, and provide benefits to all customer groups. ATCO
stated that it is only the extremities or isolated parts of the system that are used solely by
one group and classified as dedicated plant.

Regarding AIPA’s position, ATCO indicated that AIPA is correct in alleging that Account 465
for dedicated mains is understated, since the capital additions for the test years are for dedicated
Measuring and Regulating (M&R) equipment, not mains, and are included in Account 467.
Furthermore, ATCO indicated that the cost of service analysis was prepared for 2001 only,
resulting in the exclusion of 2002 data.

Positions of the Interveners
Calgary
Calgary pointed out that ATCO initially adopted a vintage plant allocation concept, but
following data requests by the interveners (and evidence from Calgary), the Company replaced
vintage costing with a dedicated plant concept. Following discussions among the parties and
before the Board, a meeting between ATCO, interveners and Board Staff was held on the
evening of July 4, 2001 to review the process and procedure used by ATCO to assign
approximately $17 million of plant “dedicated” to the Utilities class in its rebuttal COS Study.
On July 4, 2001, it was agreed ATCO would provide supporting documentation for the “top 50”
dedicated plant units based on net plant value. Documentation supporting the $17 million was
filed by APS on July 5, 2001.103
        103
              Exhibit 131, Designated Lines for Core Customers

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2001/2002 General Rate Application – Phases I and II                               ATCO Pipelines South




On the evening of July 6, 2001, ATCO provided a revision to its original dedicated plant filing,
increasing the amount of dedicated plant to $22.4 million, a 31% increase.104 This document
required re-evaluation of the previously agreed “top 50” list, and following this review and a
conference call on July 9, 2001, involving all parties, Calgary asked an additional 30 clarifying
questions pertaining to the database used in the July 6, 2001 revision. ATCO responded to these
requests on July 11, 2001, and revised the dedicated plant balance to $26.1 million, 54% greater
than the value in its rebuttal evidence for which details were provided on July 5, 2001. Calgary,
after reviewing the database provided on July 11, 2001, decided not to ask any further questions
about the third revised database to ensure no further changes and delay the completion of
Calgary’s supplemental evidence.105

Calgary understood from ATCO’s various filings, that the dedicated plant analysis is applied
exclusively to facilities used or deemed to be used by AGS. No comparable analysis has been
conducted for mainline or isolated facilities, which may be wholly applicable to Gas Alberta or
the I/P classes.

Furthermore, Calgary noted that many of the facilities assumed to be dedicated to “utility” are
systems which are exclusively attached to the NGTL system and receive no service from the
ATCO mainline. Consequently, even if the Board were to assume that the identified facilities
were appropriately allocated to AGS customers, the approach does not meet the objective of
similar treatment for all classes of service. Calgary also expressed concern that facilities
dedicated to AGS in the COS Study appeared also to be used by Gas Alberta.106

Calgary expressed concern that the dedicated plant concept used by ATCO raises the issue of
area costing and rate making which existed before the GURDI (Gas Utilities Rate Design
Inquiry) Report No. E80100. Two examples are:

•   Calgary could advocate that ATCO’s methodology be employed to determine the costs
    applicable to serve only the residents of Calgary. Specifically, customers in Calgary should
    not, for example, be charged for the Banff line looping as ATCO argues that this looping is
    dedicated to core customers west of the Jumping Pound interconnection. The same could be
    said for facilities flowing north from Calgary; and
•   Based on the map included in Exhibit 99, the customers served from the Barrons to Vulcan
    line, which receives its gas supply exclusively from the NGTL system, would be unfairly
    treated through area rate making. These customers are exclusively served off the NGTL
    system by ATCO alleged “dedicated” facilities but their rates still include costs for additional
    APS mainline facilities allocated to the utility class. This double costing, direct assignment
    and mainline allocation is another example of the tilt APS has built into its COS Studies to
    inflate the costs assigned and allocated to the utilities class. At this time, with the agreement
    with Gas Alberta, the utilities class consists exclusively of the APS affiliate, AGS.



        104
            Exhibit 167, Calgary Supplemental Evidence, Attachment CAL-SUPP.3
        105
            Exhibit 167, Calgary Supplemental Evidence, p. 2, line 20 to p. 5
        106
            Exhibit 167, Calgary Supplemental Evidence, Attachment CALL-SUPP.6, Wrentham Flow Diagram 1

124 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                     ATCO Pipelines South


Calgary submitted that ATCO’s treatment of the Banff line looping introduces yet another
radical departure from utility rate design in Alberta. Calgary referred to this as an example of
“incremental costing”, which occurs when facilities are already in place, and new or expanded
facilities are required to meet increased demands. In incremental costing methodology, the
decision is made to allocate the expansion costs to the customer or customer classes “causing”
the incremental demand.

Calgary pointed out that the Banff line was originally built to satisfy both industrial and core
market loads, and when CWNG investigated expanding the capacity of the Banff line, growth in
both industrial and core market demand was expected,107 with industrial demand being the most
urgently identified need.

Calgary argued that, while it may, at some time, prove appropriate to re-examine the rolled-in
costing and ratemaking approach for Alberta utilities, the time to do so is either in an inquiry
specifically set up for the purpose (as was done in GURDI) or on a well defined basis for a given
utility where there is time for full examination of the issues. Calgary considered it inappropriate
to suggest a fundamental departure from long held ratemaking principles in rebuttal evidence
filed shortly before the start of the hearing, creating a significant disadvantage to interested
parties in examining the issues.

Referring to ATCO’s statement that the sole purpose of its COS Studies was to evaluate the
reasonableness of the I/P settlement,108 Calgary stated that, based upon the numerous flaws and
inconsistencies which it pointed out, the COS Studies cannot be used for this or any other
purpose, and consequently, the reasonableness of the I/P and Gas Alberta settlements have to be
questioned.

AIPA
AIPA noted that, in the COS Study, ATCO directly assigns mains costs to the I/P Customers,
which for 2001, results in a mid-year credit amount of $400,000 for plant in service. AIPA
referred to ATCO’s testimony indicating that this credit arises principally from the large amount
of accumulated depreciation on quickly depreciating I/P property. AIPA considered that despite
the large increases in plant in service for I/P additions shown in the Application, no such
increases are recognized in the COS study. AIPA submitted that Account 465 (Dedicated I/P
Mains) is understated in the COS study, thereby negatively impacting core market rates. AIPA
considered that this should be corrected by ATCO in a refiling.

CCA
The CCA made reference to excerpts from records of previous proceedings to demonstrate the
requirements of industrial customers for reliable supply, and the fact that the value of looping for
those customers is higher than for core customers. The CCA noted that core customers are better
able than industrial customers to withstand short-term outages, as core customers do not lose
“product, lose firebrick from the interior of the kiln or possible warp the steel outer shell.” The
CCA pointed out that the gas received by customers along the line to Banff cannot be separated

        107
              Exhibit 167, Calgary Supplemental Evidence, p. 13 of 16 at line 1
        108
              CAL-APS.127(a)

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2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


into that received from the original and loop line projects, and that the lines are interconnected,
not only for construction purposes but also to improve reliability for both core and non-core
loads. The CCA considered that the interconnections would also reduce the pressure of the
original Banff line, which should increase the life of the original line due to reduced stress on the
pipe. The CCA submitted that the Carbon loop projects are joint assets that should be allocated
to both core and non-core customers.

The CCA also made reference to an exchange at Tr. p.1407 and 1408 concerning “isolated
facilities” to illustrate the concern that contract demand and peak day volume data does not
distinguish core facilities that are physically separate from the ATCO transmission system. The
CCA considered that the Board should direct ATCO to update its COS study to allocate costs to
joint facilities for volumes that flow only on those joint facilities, and submitted that volumes
flowing on isolated designated core facilities should be removed from the allocation factor.

FGA
The FGA submitted that the Board should not accept ATCO’s dedicated asset approach, but
should approve a “rolled-in” COS Study with all assets properly allocated. However, should the
Board consider that this approach has merit for future studies, the FGA suggested the proposal
should be examined in a collaborative process.

Views of the Board
The Board notes that, having directly assigned the dedicated facilities to customer classes,
ATCO allocated the remaining costs for general plant on the basis of allocation factors
developed for this Application.

The Board also notes however that, subsequent to the completion of the interrogatory process,
ATCO replaced the procedure of directly assigning the costs of pre-1984 vintage facilities to the
Utility class with a new procedure whereby the entire transmission system was evaluated to
determine those parts of the transmission system that were specifically dedicated to the Utility
class. The revisions were incorporated in the amended COS Study filed by ATCO on June 15,
2001.

The Board notes that the direct assignment methodology used by ATCO is considered by some
interveners to be a significant departure from the methodology approved in past COS studies and
Decisions. The Board’s conclusions on consistency of the direct assignment methodology with
previously accepted methodologies, are set out in section 8.2.5 of this Decision (Rolled In
Principle (GURDI)). In the following paragraphs the Board sets out its views on the results of
ATCO’s direct assignment methodology.

The Board notes Calgary’s statement that “the perfect class cost of service study would have no
allocations; all costs would be deemed directly assignable.”109

The Board notes that the assignment of costs relating to the Banff line loop was the subject of
significant discussion during the proceeding. The Board examined the purpose and use of the
        109
              APS-CAL.16(d)

126 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


Banff line loop and the revisions to the evidence identifying the costs for the various phases of
that project. Calgary argued that ATCO introduced incremental costing into its COS Study in the
process of assigning all of the Banff looping costs to the Utilities. By contrast, ATCO took the
position that all four phases of the Banff loop were allocated to the Utilities, including Gas
Alberta, and that there was therefore no incremental costing. The Board notes that the original
study prepared by CWNG in October 1989, defined the need for looping the Banff transmission
line to serve the projected growth in Banff, Canmore and the Industrial customers near
Exshaw.110 The Board also notes that the Banff Phase 4 loop extends from the point near the
Seebe crossing to a point immediately east of Canmore, past the location of the last Industrial
customer, and that the Phase 4 looping project was completed in 1998 at a time when the
Industrial load was “flat-lining.” Therefore, the Board agrees with ATCO that the Phase 4 loop at
the present time is for the sole purpose of providing service to the growing core market in the
Utility class. On the basis of the above, the Board considers it appropriate to directly assign the
actual costs of the Banff Phase 4 loop to the Utilities class.

The Board notes, based on the submission of Calgary, that the amount of $17 million in asset
value directly assigned by ATCO to the Utilities class is understated by $9 million. The Board
agrees with Calgary that ATCO’s estimate is understated, due to failure to capture all of the
relevant data in the short time frame available for preparation of the revised COS Study.

However, based on review of the Banff looping project, the Board is not persuaded that the
understatement is as significant as calculated by Calgary. For example, the Board considers that
the first three phases of the looping project should have been assigned to general plant for
allocation between the Utilities and I/P classes, rather than to the Utilities class directly. The
Board notes that this factor reduces the understatement to $5.5 million, in contrast to the amount
of $9 million indicated by Calgary.

Recognizing the uncertainty with respect to the amount of any potential adjustment to costs
directly assigned to the Utilities class, the Board agrees with ATCO’s request that the COS Study
should reflect the original assignment of $17 million in asset value to the Utilities class,
acknowledging that any increase in this amount would result in shifting of costs to core
customers.

Accordingly, the Board accepts the assignment of costs to the Utilities and I/P classes as set out
in ATCO’s COS Study filed in rebuttal evidence on June 15, 2001.111

8 .3 Allocation Issues
 .2
Position of ATCO
ATCO referred to Calgary’s proposal that all M&R costs, except those pertaining to UFG
metering costs, be allocated on a factor weighted equally between peak day and annual volume,
and that for UFG meter costs, annual volumes should be used as the allocator.



        110
              Exhibit 163 p. 11 of 46
        111
              Exhibit 99

                                                       EUB Decision 2001-97 (December 12, 2001) • 127
2001/2002 General Rate Application – Phases I and II                         ATCO Pipelines South


ATCO pointed out that peak day/contract demands were used as the allocator for M&R costs and
continued to recommend this approach for allocating these costs, on the basis that these costs are
determined by the peak hour/day capacity requirements. ATCO submitted that cost responsibility
should be based on this cost determinant, and referred to Calgary’s acknowledgement in an
information response that the initial cost of meters would vary with their hourly/daily capacity.
ATCO submitted that, in proposing a revised cost allocator for M&R costs, the City is not being
true to the principle of cost causality as the basis for fair allocation of costs to user groups.

ATCO submitted that Calgary had employed some unreasonable cost allocation techniques in
proposing adjustments to the allocation of M&R costs, resulting in excessive costs being driven
to the I/P Group.

ATCO submitted that Calgary’s assertion that system-wide SCADA costs are allocated 50/50 to
North and South is incorrect, and referred to the Company’s June 15, 2001 rebuttal evidence
showing the allocation of O&M and G&A expenses 67%/33% to North and South. ATCO
indicated that, capital costs associated only with the hardware and software residing within the
control center, have been allocated 50/50, but SCADA related costs at receipt, delivery and in
other points are included with M&R costs. ATCO provided the rationale for the capital cost split
its rebuttal evidence.

Referring to the FGA’s position that although marketing costs are only 3% of revenue
requirement, further prescribed refinements could be cost effective, ATCO considered it unclear
that any refinement would be cost effective.

ATCO acknowledged the FGA’s desire for intra-class allocation of costs with two reservations.
First, the reliability of COS studies diminishes as cost is broken into smaller components, and
second, the issue of cost effectiveness raised by the FGA is a significant consideration when
evaluating the practicality of this proposal.

ATCO agreed with the FGA that Gas Alberta should not be allocated any significant M&R costs,
indicating that there may be some modest M&R system costs for which Gas Alberta should have
shared responsibility. Referring to the FGA’s argument that the Board should direct ATCO to
refine its COS Study by the time of its next GRA, as it directed ATCO Electric, ATCO agreed
that the Company is prepared to collaborate with interested parties to develop such refinements,
if so directed by the Board.

Positions of the Interveners
Calgary
Calgary submitted that, with the possible exception of the response to BR-APS.44, ATCO COS
Studies cannot reliably be used to evaluate the rate levels proposed for the I/P class and Gas
Alberta in their respective settlements. Calgary considered that the studies are based on flawed
analyses in that the demands of the Banff looping line core customers are also included in the
mainline allocation factor for transmission cost, even though all gas is supplied from Jumping
Pound through what APS deems to be an incremental assignment of the cost of this line to
customers of its affiliate AGS.


128 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                        ATCO Pipelines South




Calgary referred to the AGPL proposal to allocate the costs of the system wide SCADA 50% to
the North and 50% to the South,12 noting that, based upon the ATCO Application there is no
analytical support for this allocation. Calgary pointed out that ATCO defends this allocation on
the basis that the system is shared equally between the north and south systems,112 an explanation
that does not provide any analysis based upon the factors which influence the cost of a SCADA
system.

Calgary submitted that, as with all other allocations between affiliates and their business units,
strict adherence to sound cost allocation principles should be utilized. Calgary noted that to date,
interveners and the Board have been unable to examine the fundamental data supporting the
allocation of costs supporting the APS revenue requirement.

Calgary prepared an analysis based upon cast causation of SCADA systems in its written
evidence113 for purpose of allocating the SCADA costs between the north and south, which
demonstrated by use of cost causation factors that the proper allocation of the SCADA system
should be 35.7% to the South and 64.3% to the North. The allocation factor was calculated using
a weighted percent method from the sum of kilometers of pipe, number of receipt points, number
of delivery points, and number of customers. Calgary therefore, submitted that the Board should
reject the 50/50 allocation proposed by AGPL and adopt the Calgary proposed allocation based
on analytical procedures.

With respect to marketing costs, Calgary noted the FGA argument based on BR-APS.37 that
coincident demand is the driving force in the incurrence of marketing costs. Calgary considered
however, that neither a complete reading of BR-APS.37 nor any ATCO evidence, cross-
examination responses or IR responses, nor any other document associated with this proceeding
supports an allocation of marketing costs on the basis of coincident demand.

Calgary noted that the FGA argued that number of receipt points, relative throughput or contract
demand should be used to allocate marketing costs. Calgary pointed out that neither ATCO nor
Calgary used any of these factors to allocate marketing costs. Calgary pointed out that ATCO
allocated 40% of marketing cost to the Utilities class prior to its settlement with the FGA, and
elected not to modify its COS Studies to reflect and test this settlement. Calgary considered that,
as there are only two utilities in the Utilities class, logic would dictate that under the ATCO
methodology, the utilities were equally responsible for marketing costs. Consequently, Calgary
considered its initial split of marketing cost of only 25% to Gas Alberta is conservative given the
ATCO evidence.

Calgary noted that the FGA also argued that they should not pay for any of the general system
M&R costs. Calgary considered that, as is evident from the ATCO COS Studies, all customers
must bear responsibility to pay for the general system M&R costs. Calgary noted that ATCO
assigned the dedicated M&R cost directly to the I/P class and then allocated general system


        12
           Exhibit 4, APS Application, Section 2.3, p. 10 of 10
        112
            Exhibit 4, APS Application, Section 2.3 p. 10, Volume 2, p. 303/3-13
        113
            Exhibit 76, Written Evidence of The City of Calgary, p. 11 of 14, line 1 - 10

                                                               EUB Decision 2001-97 (December 12, 2001) • 129
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


M&R cost to the I/P and Utilities classes. Calgary, like ATCO, followed this procedure in its
COS Studies.

Calgary further noted that the FGA argued that the I/P class pays for its M&R cost in the On
Charge,114 but that there is no COS Study applicable to the On Charge. Calgary considered this
argument to be unsupported in the proceeding.

Calgary noted that the FGA also attempted to introduce its own COS Study in Argument, an
inappropriate procedure, and stated that the Board should be clear that this is not a “corrected
[Calgary] cost of service study and should reject it.”115

FGA
The FGA considered the first COS Study filed by ATCO to be adequate for the purposes of these
proceedings, pointing out that the rate agreed by Gas Alberta in the MOU was developed from
that COS Study. However, the FGA referred to two concerns with that study, which warrant a
direction of the Board. First, the FGA considered that the allocation of marketing expense
between the three customer classes appeared to have been based on ATCO’s judgment with
respect to growth in coincident peak demand rather than on a study to determine the factors that
actually drive the marketing costs. Second, the FGA expressed concern that no intra-class
allocations have been done where a class of service, such as Utilities and Industrial, has more
than one rate.

The FGA considered the situation of ATCO and AE to be similar, in that, as a result of electric
industry restructuring, AE had very little experience as a “wires only” distributor. Referring to
the methodology described by AE for allocation of marketing expenses, the FGA noted that the
Board approved AE’s direct assignment of marketing costs to customer classes based on direct
assignment carried out judgmentally, noting that a detailed study might not be cost-effective. The
FGA pointed out that the Board found that AE’s judgment represented the best available
information during industry reorganization, but directed AE to continue to refine its COS study
for submission at the next Distribution Tariff Application. The FGA considered that a similar
finding should apply in these proceedings, on the basis that ATCO’s judgment, tempered by its
views of growth in coincident peak demand, represents the best information available, given the
lead time for preparation of the study and recognizing that the function represents 3% of system
costs. The FGA considered that the recent corporate reorganization had provided ATCO with
less than two years of experience on which to base a study, and in any case, the Company may
not wish to conduct its marketing activity in the same manner on a prospective basis.
Furthermore, the FGA considered that the Board’s decision to include a COS study for
consideration with Phase I matters, may not have allowed ATCO sufficient time to study all
functions, noting that Calgary’s COS expert adopted without challenge, ATCO’s assignment of
marketing expense for his own study. For these reasons, the FGA submitted that ATCO’s
assignment of marketing expense should be accepted for purposes of these proceedings, with a
direction from the Board, as in the case of AE, to refine the COS study by the time of the next


        114
              FGA Argument, p. 10 of 15
        115
              FGA Argument, p. 13 of 15

130 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


GRA. The FGA provided some views on factors to be considered by ATCO in taking steps to
refine the marketing cost component of the study on an ongoing basis.

However, the FGA did not consider that ATCO would expend the same planning effort at one of
Gas Alberta’s delivery points as would be expended for a City of Calgary gate station, where a
1% error in demand would represent a far greater volume error. Accordingly, the FGA
considered that development of a proper allocator for the Utilities class should include some
weighting for the size of the delivery point, much the same way metering costs are weighted for
meter size when allocating those costs. The FGA submitted that a study of ATCO’s actual
operations would quickly determine which factors drive costs and would provide the most
appropriate allocation of marketing costs between and within classes.

However, the FGA acknowledged, that a different type of intra-class allocator might need to be
developed for other classes that may require more business development, if intra-class allocation
is required. While, in the FGA’s view, intra-class allocation may not be necessary for classes that
have negotiated all the rates in their category, on an ongoing basis, the Board should direct that
costs be allocated to the various industrial and producer rates, only if customers in those classes
request such detail in the COS Study. However, the FGA submitted intra-class allocation of all
cost functions should be determined for the Utilities class as long as no comprehensive Utilities
settlement exists and core customers identify the need for such an allocation.

In conclusion, the FGA submitted that:

    •   the Board should direct ATCO to study the direct assignment or allocation of marketing
        expenses among its three customer classes;
    •   the Board should direct ATCO to develop rational allocations or directly assign, if
        possible, costs to different rate classes within a customer class, where those customers
        have not all reached agreement on rates; and
    •   the Board should refer ATCO’s proposal for direct assignment of assets to customer
        classes, to a collaborative process of all system users.

Views of the Board
Custody Transfer Meters
The Board notes ATCO’s position that custody transfer meter costs relate to the peak demand at
the delivery point. The Board also notes Calgary’s submission that the custody transfer meters
should be allocated on the basis of throughput at the delivery point. The Board agrees with
Calgary that the purpose of installing the custody transfer meters is for determining the volume
of gas sold to AGS and will result in a more precise determination of UFG for ATCO. Therefore,
the Board considers that the custody transfer meters should be allocated on the ratio of volume
sold rather than demand at each station. The Board therefore directs ATCO to allocate the cost of
the custody transfer meters using the ratio of volume throughput to each customer class. The
remaining costs for M & R shall be allocated on the basis of the ratio of demand for each
customer class.




                                                       EUB Decision 2001-97 (December 12, 2001) • 131
2001/2002 General Rate Application – Phases I and II                        ATCO Pipelines South


System Wide SCADA (Capital, O&M, and G&A)
The Board notes ATCO’s allocation of system wide asset related SCADA costs at 50% to the
Company and 50% to APN. ATCO justified its allocation on the basis that if the merger of
CWNG and NUL had not occurred, each entity would have had to replace their respective
SCADA systems with virtually identical systems and at the same cost for each system.

The Board also notes Calgary’s analysis that system wide SCADA costs should be allocated at
35.7% to ATCO and 64.3% to APN on the basis of the weighted factor derived by Calgary for
the SCADA allocation, including kilometers of pipe, number of receipt points, number of
delivery points and number of customers.

The Board accepts ATCO’s allocation of system wide SCADA costs between the Company and
APN at 50/50 % on the basis that SCADA computer equipment would cost the same amount to
the Company and APN if separate systems were required for each business unit. The Board
considers Calgary’s factors derived for allocating asset related system wide SCADA costs as not
being representative of the appropriate costs to each business unit.

Furthermore, the Board notes that ATCO will be responsible for 33% of the system wide O&M
and G & A costs associated with the operation of the single SCADA system that is used for both
the Company and APN. The Board notes that Calgary’s recommended allocation for sharing of
the O&M costs between the Company and APN is 35/65% respectively, which is similar to the
ATCO allocation. Therefore, the Board accepts the allocation by ATCO of 33% of SCADA
O&M and related G & A expenses as reasonable.

Allocation of Marketing and Planning Expense
The Board notes that since 1999, little history is available for use in projecting marketing
expense, and that ATCO used judgment to derive the allocation factors for the forecast of
marketing expense. The Board also notes that ATCO was of the view that the cost of marketing
was derived from the business development effort required to obtain new customers and to retain
existing customers, and the planning effort to build a network to accommodate the load growth
on the pipeline network.

The Board notes that the interveners did not object to the allocation factors to the customer
classes. However, Calgary recommended that of the 40% of total marketing costs allocated to the
Utilities, 10% should be attributable to Gas Alberta. The Board notes that the Gas Alberta
demand is 1.5% of total system demand and 1.4% of total system throughput. The Board also
notes that Gas Alberta suggested that its fair allocation of marketing costs, based upon a
reasonable assignment, would be approximately $20,000 per year. For the purposes of the
sharing of marketing costs and testing the reasonableness of the Gas Alberta settlement rate, the
Board accepts the amount of $20,000 as a fair estimate of marketing costs assignable to Gas
Alberta and therefore, accepts the allocation factor of 1.5% of total marketing expense to Gas
Alberta.




132 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                     ATCO Pipelines South


However, the Board directs ATCO to improve the study of marketing expense and file the results
at the next GRA when the Company will have a longer history of data with respect to marketing
expenses at the time when the forecast is prepared for future test years.

8 .4 AGS Peak Demand
 .2
Position of ATCO
ATCO referred to rebuttal evidence, wherein ATCO Gas witness Ms. Fraser-Steffler is quoted,
indicating that the demand ATCO Gas places on the ATCO Pipeline system is based on an
ambient temperature of -36ºC. for a 24-hour period. ATCO submitted that any adjustment to a
peak demand of 1,049 TJ per day for ATCO Gas South is not justified and will be in error.

ATCO noted that Calgary adjusted the peak demand to 965 TJ/d, despite the fact that the
Company was provided with a peak (or billing) demand of 1049 TJ/d by ATCO Gas South for
the year 2001. ATCO submitted that Calgary’s adjustment was based on a misunderstanding of
the methodology used by ATCO Gas to determine peak day demand.

ATCO stated that the CCA was incorrect in claiming that the Company uses a peak design
temperature of -40ºC, and re-emphasized the information provided elsewhere in evidence, that
AGS uses a 24-hour design temperature of -36ºC and the Company used the resulting demand
from AGS.

Positions of the Interveners
Calgary
Calgary noted that ATCO and AGS continue to use some variant of -40ºC to determine the
contract demand applicable to ATCO. Calgary referred to the response to CAL-APS.71, where
ATCO advised that the demand is calculated on -40ºC, then, in rebuttal evidence, stated that the
demand is based upon a peak design temperature of -36ºC for a 24-hour day, which encompasses
a four-hour peak of -40ºC.116 Calgary submitted that it is unclear if this equates to a 28-hour day
or 20 hours at -36ºC and 4 hours at -40ºC.

Calgary considered that, if based on the latter, the effective temperature for the calculation would
be -36.67ºC (20x36 + 4x40)/24). However, in response to information requests from Calgary,
ATCO stated that the peak demand used to design its pipeline expansion is -36ºC. However,
Calgary pointed out that, AGS advised that the design day demand is based on -36ºC plus or
minus 4º, introducing a -32ºC standard into the equation.

Furthermore, Calgary noted that, in response to an undertaking, ATCO shows that -40ºC has not
been seen in Calgary or Lethbridge for approximately 50 years, indicating that Calgary and the
Board have been provided with multiple conflicting verbal and written responses. However,
Calgary indicated that, at no time did either AGS or APS provide the actual calculation, which
developed the AGS contract demand used by ATCO for COS Studies purposes and that it
proposes to use for billing.

        116
           Exhibit 99, APS Rebuttal Evidence to The City of Calgary’s Written Evidence Related to the Cost of
Service Study, p. 5 of 8 line 15

                                                             EUB Decision 2001-97 (December 12, 2001) • 133
2001/2002 General Rate Application – Phases I and II                             ATCO Pipelines South




Calgary pointed out that, in response to BR-APS.49 ATCO stated that it does not have sufficient
line pack to meet the four-hour peak based on -40ºC, and claims that it must design its system
based upon a four-hour window of -40ºC. However, Calgary referred to various information
responses indicating that ATCO is designing these expansions on the basis of -36ºC.

Calgary considered that, under a combination of -40º, -36º, and -32º, the “line pack” argument
does not measure up to scrutiny, noting that a daily demand of 1,243,000 GJ (-40º) equates to an
hourly demand of 51,792 GJ per hour. Calgary calculated that four hours of that -40º demand
would equate to 207,168 GJ, whereas, based upon a daily -36º demand of 1,049,000 GJ, four
hours of -40º demand would leave 841,832 GJ to be delivered over the remaining 20 hours (i.e.
42,092 GJ per hour). Calgary further calculated that the average hourly demand for the entire -
36º day would be 43,708 GJ per hour. Therefore, according to Calgary, the four-hour peak (at -
40º) would require an excess delivery of 8,084 GJ per hour for the four-hour period, as compared
to the daily average.

Calgary submitted that the obvious question regarding the adequacy of hourly supply is the
potential sources of this supply. While line pack can meet some of the hourly fluctuations, the
Carbon storage facility could meet all the hourly fluctuations in load. Until it restricted its use of
Carbon (and then surrendered all Carbon capacity to ATCO MidStream) AGS had the right to
300,000 GJ of daily withdrawal capacity or 12,500 GJ per hour, well in excess of the 8,084 TJ
per hour of excess requirements (even before line pack is taken into consideration) for the four-
hour -40º period. Carbon storage can also deliver to NGTL to offset hourly drafting on the
NGTL system. Carbon storage can also deliver volumes directly to the Calgary load area
replacing line pack on an hourly basis.

Calgary pointed out that load directly attached to NGTL must also be considered, and noted that,
included in the contract demand of 1,049,000 GJ per day are the loads of numerous communities
and areas which are not connected to the ATCO mainline. These loads are served exclusively
from the NGTL system, yet they are included in the contract demand of 1,049,000 GJ, which
APS claims it cannot meet off its system for a four-hour peak at -40º. Calgary expressed concern
that ATCO had not made any attempt to reconcile this obvious inconsistency.

Based upon the multiple conflicting explanations of how the contract demand is calculated, the
fact that -40ºC has not been experienced for 50 years, the lack of independent review of the
contract demand determination between affiliates and the and the unwillingness of AGS/APS to
provide the underlying data and calculations, Calgary urged the Board to reject the contract
demand based on minus forty degrees for calculating the AGS demand and require AGS and
APS to provide the calculation details based upon a temperature no lower than -36ºC. As noted,
Calgary submitted that the Board should also be seriously concerned when one regulated utility,
AGS, gives up storage capacity to an unregulated affiliate (ATCO MidStream) saying it no
longer needs storage for operational purposes, and then APS claims that it needs what appear to
be unrealistic design standards because its line pack cannot support cold day demands.

Calgary submitted that ATCO and AGS have failed to meet the required burden of proof to
support the affiliate contract demand of 1,049,000 GJ per day, that the contract demand should


134 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


be calculated on -36ºC and that AGS/APS should provide the full and complete underlying data
used to determine the affiliate contract demand.

CCA
The CCA also made reference to evidence filed by Calgary and to an exchange at Tr. pp. 1418-
1421 to illustrate the concern that ATCO has failed to prove its case for use of a design criteria
or allocation factor based on -40°C for the whole system. The CCA submitted that the lowest
temperature recorded in the major core load centers was -36.4°C in Calgary in 1968, and -35.6°C
in Lethbridge in 1954, and considered it unlikely that both centers would reach minimum
temperatures at the same time. The CCA also expressed concern that ATCO incorporates a
system design to -40°C, which does not match the design of the AGS system to -36°C,
submitting that over-design of the transmission system will increase costs of the entire system,
with a resultant increase in rates. The CCA submitted, therefore, that the design criteria and
billing demand be established at -33°C, indicating that its understanding of the ASHRAE
standard is that, at that temperature, furnaces run at 100% capacity and lower temperatures will
not generate increased gas requirements.

Views of the Board
The Board notes that ATCO has determined the peak demand for AGS as the demand placed by
AGS on the ATCO system. The quantity of demand of 1049 TJ/day for AGS was determined by
AGS at a projected coincident demand for a peak day throughput when the average temperature
for that day within the AGS distribution system would be -36°C. This average is the simple
arithmetic mean of the high temperature of -32°C and low temperature of -40°C for the peak day,
a calculation consistent with procedures used by CWNG. AGS notified the Company that within
the peak day, it is reasonable to expect that for a 4-hour period within that peak day, a consistent
low temperature of -40°C can be expected and that the Company should use this information to
determine how it would provide an additional supply for that four-hour period when the
instantaneous demand is higher than the demand averaged over a 24-hour peak day.

The Board understands that ATCO must determine if its pipeline network will have the capacity
to meet the additional demand for the short-term four-hour peak requirement to AGS on the peak
day. The additional delivery required to fulfill the added demand during the four-hour -40°C
peak will require an added delivery of 8,084 GJ/hr, which cannot be met utilizing available line
pack. Calgary stated that until the time of the restrictions on use of Carbon, ATCO had the right
to 12,500 GJ/hr capacity to deliver into the NGTL system or directly into the ATCO Carbon line
to meet the four-hour peak.

Calgary and the CCA argued that AGS has placed a demand on the Company’s system that may
be over-stated due to the required delivery for a four-hour instantaneous coincident demand at a
-40°C peak temperature, resulting in AGS having to pay a higher than required demand charge to
the Company. To address this concern, Calgary suggests a reduced demand for AGS from 1049
to 965 TJ/day and utilized this recalculated demand in its COS Study for allocation ratios.

The Board also notes Calgary’s concern that the peak day demand projections are based upon a
day when the temperature would fall to a low of -40°C and that -40°C has not been experienced

                                                       EUB Decision 2001-97 (December 12, 2001) • 135
2001/2002 General Rate Application – Phases I and II                          ATCO Pipelines South


for 50 years. Calgary suggests that the appropriate low temperature for the peak demand
projection is -36°C. The Board also notes that the CCA suggests the peak demand should be
projected for a peak day when the average temperature is -33°C. The Board also acknowledges
that the concern of the interveners with the peak demand projection is that ATCO is required to
build pipeline and associated facilities to deliver a projected peak demand that may never be
realized, thereby, over-building the system capacity at a cost to all consumers.

Notwithstanding the concerns expressed by the various Interveners, the Board is particularly
cognizant of the fact that the highest peak demand will also occur at the most extreme weather
conditions. The Board strongly believes that, although the probability of such an event is low, the
danger of a gas outage due to loss of sufficient supply poses an extreme risk to the welfare of the
consumers at that specific time. The Board considers that the provision of continuous supply
during times of extreme weather conditions is a key responsibility of the utility. Therefore the
Board does not find the low temperature standard recommended by Calgary and the CCA, while
it would result in reduced costs to consumers to provide adequate protection against the
significant impacts should these conditions arise. As a result, the Board does not find that a
reduction in the demand forecast along with the commensurate reduction in the pipeline network
capacity is warranted.

The Board evaluated the evidence presented at both this proceeding and the AGS proceeding
regarding the issue of peak demand and is satisfied that the AGS nominated peak demand of
1,049 TJ/day for 2001 and 1,067 TJ/day for 2002 is appropriate. The Board is satisfied that AGS
has forecast the peak demand for the AGS customers for a peak day when the average
temperature is -36°C calculated as an arithmetic mean. Therefore, the Board accepts the ATCO
forecast of the peak demands as follows:

                                                       2001 Peak Demand    2002 Peak Demand
                  Customer Class
                                                            TJ/ day              TJ/day
    ATCO Gas                                                 1,049               1,068
    Gas Alberta                                                 16                16.8
    Industrials                                                130                 132
    Producers                                                  563                 561
    Total Coincident Demand                                  1,758             1,777.8



8 .5 Rolled In Principle (GURDI)
 .2
Position of ATCO
ATCO’s rebuttal evidence addressed four issues with respect to the COS Study methodology, but
ATCO considered that two of those issues required further comment by the Company. First,
ATCO referred to Calgary’s allegation that the Company has violated the rolled-in costing
principle prescribed in the GURDI Report No. E80100 issued by the Public Utilities Board in
July 1980. ATCO categorically rejected this allegation, citing its comment made in supplemental
testimony:


136 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


        All costs for dedicated or sole use facilities for each customer group are
        accumulated and combined with joint use facility costs and allocated to all
        customers across the system in the group under analysis.117

ATCO considered that the methodology used results in system-wide, rolled-in costing for the
facilities jointly used or shared by two or more customer groups. ATCO submitted that its
treatment of dedicated facilities for the Utilities group and the I/P group complies with the
GURDI Report. In this regard, ATCO pointed out that this conclusion was supported by
references in Calgary’s May 15 evidence to excerpts from the GURDI Report. Specifically,
ATCO noted that each of these references cited page 22 of the GURDI Report where it is stated
that “communities served by isolated gas supply and transmission facilities should continue to be
charged rates which reflect the specific identifiable costs of such facilities.”

ATCO pointed out that, through the direct assignment procedure, the Company has identified
dedicated assets for the Utilities group and the I/P group and has treated these customer groups
consistently despite Calgary’s allegation to the contrary. ATCO submitted that it has complied
with the intent of the GURDI Report, recognizing that the application of the principles and
guidelines emanating from GURDI have evolved over time, and in response to the unique
conditions and circumstances experienced by each utility. ATCO considered that the Board
appeared to recognize this when directing ATCO in Decision 2000-16 “to formulate a
methodology” to better facilitate the determination of the cost of providing service to the
industrial and producer classes.

In ATCO’s view, the focus and tone of intervener argument indicated that these parties saw the
ATCO market as a total monopoly, where COS Studies can be used in an inflexible, mechanical
way to assess rates. The Company had noted in evidence the mixed, partly competitive market in
which it operates. ATCO pointed out that employment of rolled-in costing as the sole
determinant of pricing would provide no flexibility, and would result in the potential for loss of
industrial and producer revenues, leading to higher costs for remaining customers.

ATCO also referred to its evidence illustrating that the impact of the loss of I/P markets on the
core market would be an estimated monthly transmission rate for the Utilities group on a stand-
alone basis of $2.75/GJ, which should clearly indicate to interveners that aggressive and
unwarranted cost loading on the I/P sector may put ATCO in an uncompetitive situation, with
resulting undesirable consequences for the remaining customers.

ATCO referred to PICA’s support for Calgary’s rolled-in costing methodology, contrasted by a
recommendation for permission for customers on the AGS system to seek economic bypass
transmission and/or competitive bypass rates from AGS in the same manner as is presently
enjoyed by transmission customers served by ATCO. In ATCO’s view, while PICA wants the
opportunity to cherry pick for the advantage of its individual customers on a go forward basis,
there is little doubt that rolled-in costing will not provide the competitive bypass rates
anticipated, since PICA appears to be pursuing rates based on the cost of specific facilities
dedicated to serve the individual customers.

        117
              Exhibit 162

                                                       EUB Decision 2001-97 (December 12, 2001) • 137
2001/2002 General Rate Application – Phases I and II                         ATCO Pipelines South




ATCO considered that the FGA should await release of NGTL’s first COS Study this fall before
commenting on the methodology used by TransCanada for its Alberta system. In ATCO’s view,
the FGA’s concerns with the dedicated plant method may be significant to Gas Alberta and may
provide the basis for refinement in future studies, but will have no significant impact on the
overall results of ATCO’s COS Study.

Positions of the Interveners
Calgary
Calgary submitted that the dedicated costing approach applied to the Utilities class, which now
consists exclusively of service by ATCO to its affiliate ATCO Gas South, is fundamentally
flawed and cannot be used to either evaluate rates charged to the I/P group or Gas Alberta.
Calgary considered the dedicated plant analysis flawed in the following areas:118

    •   the dedicated/incremental costing technique is not in compliance with the Board’s long
        held policy of rolled-in costing adopted following the GURDI Inquiry;
    •   the ATCO proposed dedicated/incremental proposal is only being applied to facilities
        alleged to have been constructed to serve AGS, or now being deemed to only serve AGS;
    •   the ATCO proposed concept raises the issue of abandoning rolled-in integrated costing
        and rate making and reverting to area costing;
    •   the evident problems with analyzing the source database as it was modified three times
        over seven days; and
    •   the inclusion of incremental costs.

Calgary pointed out that, prior to GURDI, utility rates were set on an “area” basis. Following
GURDI, the Board decided that, for integrated utility systems, it was generally not possible to
precisely identify facilities associated with certain customers and directed utilities to utilize
rolled-in costing. Calgary submitted that there can be no doubt that the ATCO system is
“integrated.” By its own evidence ATCO shows bi-directional flows, system wide gas input and
output points, and an operationally integrated system.

Calgary pointed out that, under rolled-in costing, all costs are allocated to the various customer
classes and each class pays a uniform rate for service. The ATCO proposal on the other hand,
moved away from this long held regulatory tenet, by effectively isolating one customer, its
affiliate AGS, for one costing method and applying a different method to Gas Alberta and the I/P
customers. In Calgary’s view, this approach was not as compatible with rolled-in rate making,
and, on a rolled-in costing basis none of the rates proposed by ATCO were justified. In fact,
Calgary stated that the only rolled-in COS Study prepared by ATCO, in response to BR-APS.44,
showed that the appropriate rate to be charged to AGS is $1.77 per GJ of monthly contract
demand, as compared to the $1.93 that APS proposed to charge.119




        118
              Exhibit 167, Calgary Supplemental Evidence, p.6, line 4
        119
              APS Response to Undertaking at p. 1483 line 16

138 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


FGA
The FGA agreed with Calgary that ATCO’s proposal for direct assignment of dedicated assets
represents a departure from the “rolled-in” COS studies used by all other utilities and pipelines in
Alberta, noting that TCPL uses DoH and pipe size to determine rates in its most recent COS
study. The FGA noted that TCPL does not distinguish assets by customer. Accordingly, while
indicating openness for change in COS methodologies, and expressing the view that direct asset
assignment might result in a more accurate study, the FGA considered that the proposal should
be approached with caution. The FGA suggested that the Board should consider ATCO’s
proposal only after the inherent difficulties have been worked out. By way of illustration, the
FGA pointed out that the assets built under the rural gas program have not been properly
identified, or if identified, the related contribution has not been reflected. The FGA referred to
some examples to support this view.

The FGA submitted that the Board should not accept ATCO’s dedicated asset approach, but
should approve a “rolled-in” COS Study with all assets properly allocated. However, should the
Board consider that this approach has merit for future studies, then FGA suggested the proposal
should be examined in a collaborative process.

Views of the Board
The Board notes that the GURDI Report envisaged situations that may allow a deviation from
the procedure of setting rates based upon fully distributed cost allocation methodologies. The
GURDI Report stated:

        … the Board considers that fully distributed costs should be used as the starting
        point in rate design. If rates deviate from fully distributed costs because of non-
        economic factors (or other factors) the quantum of revenues that does not reflect
        the fully distributed cost of service must be clearly identified and deviation from
        fully distributed costs must be justified.120

The Board believes that the circumstances faced by ATCO at this time require that the Company
must be able to react effectively to competitive market alternatives available to the I/P class. The
Board also believes, that the resulting market pressures contribute to the need to establish special
rates with Transportation customers in order to retain transportation volumes on the system. The
Board recognizes that ATCO operates in a mixed, partly-competitive market, wherein
employment of rolled-in, fully distributed costing would result in rates that are not competitive.
In reaching this conclusion, the Board has evaluated the results of the COS Study filed by the
Company in response to ATCO-BR-44, which demonstrates a significant shortfall in revenues
from the I/P class resulting from use of a largely rolled in methodology. The Board considers
that development of rates on this basis would likely result in loss of industrial and producer
revenues, thereby leading to higher costs to the remaining customers.




        120
              GURDI Report, p.100

                                                       EUB Decision 2001-97 (December 12, 2001) • 139
2001/2002 General Rate Application – Phases I and II                             ATCO Pipelines South


The Board notes Calgary’s statement that:

        ... the perfect class cost of service study would have no allocations; all costs
        would be deemed directly assignable.121

The Board also notes that Calgary’s COS Study filed in Exhibit 76, May 15, 2001 and revised on
July 13, 2001, which was based upon the evidence provided by ATCO in response to
BR-ATCO.37 and BR-ATCO.44, also incorporated the concept of direct assignment of plant
dedicated to the I/P classes.

The Board recognizes that the procedure of direct assignment of dedicated facilities introduced
in this proceeding is a departure from the methodology emanating from GURDI and approved in
prior COS Studies and GRA’s. The Board acknowledges the concern of the Interveners that the
dedicated and incremental costing methodology conflicts with the long held practice of rolled-in,
fully distributed costing and rate design.

In considering the need for ATCO to react to competitive market pressures, the Board believes
that this proceeding is a transitional step, resulting from the first application by ATCO as a
stand-alone unit, in isolation from APN and ATCO Gas. In the Board’s view, these are factors
which justify re-assessment of the continuing appropriateness of the COS Study methodologies
espoused by GURDI, or adoption of alternative methodologies. The Board recognizes that the
business environment in which ATCO operates has changed substantially since the issuance of
the directives in the GURDI Report in 1980, and that the application of the principles emanating
from the GURDI Report since that time may need modification to adapt to the new
circumstances being experienced by Alberta’s utilities today. Major changes in ATCO’s business
environment since the issuance of the GURDI Report include the deregulation of transportation
service within Alberta, postage stamp rate design for distribution, and the restructuring of tolls
and tariffs for NGTL. The Board considers the changes in business environment significant
enough to warrant the use of methodologies that do not conform to GURDI. In this respect, the
Board considers the direct assignment methodology adopted by ATCO is now more appropriate
than rolled-in, fully distributed costing for the purposes of ATCO’s COS Study in this
proceeding. In coming to this conclusion, the Board also notes that the continued use of the
GURDI methodology in the COS Study could result in a large under-recovery of revenue
requirement from the I/P class, which would represent a significant and punitive expense to the
Company.

The Board anticipates that future rate applications of ATCO Pipelines will include both the
Company and APN and, at that time, the COS Study will include the costs for both business
units. The Board recognizes that the current process accommodates a transition for ATCO and
accepts that this, together with significantly increased competitive pressures, has resulted in a
proposal by ATCO for a departure from the preceding COS Study methodology approved in the
GURDI Report. Accordingly, the Board accepts ATCO’s proposal for use of a dedicated
assignment methodology, acknowledging that this acceptance is specific to this Application, and
that the methodology may not necessarily be used in future proceedings.

        121
              APS-CAL.16(d)

140 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South




8 .6 Splitting the Utilities Group
 .2
Position of ATCO
ATCO pointed out that, throughout the Application, the Utilities group included both ATCO Gas
South and Gas Alberta, and submitted that Calgary had no basis and insufficient data to make an
arbitrary distinction. ATCO cited marketing and customer support as two cost categories for
which Calgary had insufficient data to make the distinction, and referred to the statement by
Calgary’s witness that marketing costs should be split 50/50 despite the evidence on the record
that ATCO Gas South accounts for 98.5% of the Utility group demand, compared to 1.5% by
Gas Alberta. ATCO also noted that ATCO Gas South accounts for nearly 96% of Utility group
delivery points. Based on the foregoing, ATCO submitted that Calgary’s proposal should be
dismissed.

Positions of the Interveners
Calgary submitted that its revised COS Studies (Exhibit 167) were developed based upon the
data provided by APS, and that it developed new allocation factors to revise its study with the
continued use of rolled-in costing methodologies. These methodologies were used to split the
costs assignable to the Utilities class between Gas Alberta and AGS.

Calgary noted that the FGA rejected Calgary’s revised COS Study and suggested that certain
allocations were inappropriate. The FGA criticized Calgary’s intra-class allocation of marketing
expense at 25% to Gas Alberta and 75% to AGS based upon the sole judgement and experience
of Calgary’s expert witness wherein the witness also indicated that upon reflection, he would
revise the allocation to a 50/50 % split. Calgary noted that the FGA also rejected Calgary’s
allocation of $57,000 M&R expense allocated to Gas Alberta. Calgary stated that the FGA
pointed out that it will own and operate the M&R equipment for the gas delivered to Gas Alberta
at its own expense, and therefore, Gas Alberta must not be allocated any of ATCO’s cost of
M&R stations from the cost of assets remaining in the general system assets pool. Calgary noted
that the FGA claimed this situation was analogous to CWNG’s previous cost of service studies.
Calgary pointed out that CWNG as an integrated gas utility, incurred costs on its own
distribution system and since the co-ops served by Gas Alberta had their own distribution
systems, CWNG did not allocate distribution costs to the Gas Alberta Rate 6 at the transmission
delivery points.

Views of the Board
The Board considers that combining Gas Alberta and AGS under the Utilities heading is an
appropriate classification. The Board considers that dividing the Utilities classification into even
more discrete customer groupings on the basis of demand or throughput ratios would result in a
small proportion of costs being allocated to Gas Alberta on the basis of its relative demand and
throughput. The Board notes that any distortion in cost assignment due to seasonal or annual
variations would result in an unwarranted and unjustifiable variation in the revenue/cost ratio.
Accordingly the Board is satisfied with ATCO’s proposal to combine Gas Alberta and AGS
under the Utilities classification



                                                       EUB Decision 2001-97 (December 12, 2001) • 141
2001/2002 General Rate Application – Phases I and II                          ATCO Pipelines South


The Board considers that reliable data and evidence has been presented to allow a reasonable
projection of relative costs between Gas Alberta and AGS in the Utilities class. The Board has
already expressed its view as to the amount of costs considered appropriate to Gas Alberta for
marketing and M&R costs.

8 .7 Gas Alberta Settlement
 .2
Position of ATCO
ATCO submitted that Calgary erred in concluding that the benefits arising from the reduction in
O&M expense and rate base arising from the Gas Alberta settlement should accrue solely to the
customers of ATCO Gas. ATCO pointed out that the benefits of both the O&M and rate base
reduction should accrue to the Utilities group, which includes both ATCO Gas South and Gas
Alberta.

Positions of the Interveners
Calgary
Calgary noted that, towards the end of the proceeding, ATCO introduced a settlement for Gas
Alberta, but never proposed to test this settlement nor modify its COS Studies to demonstrate
that the settlement with Gas Alberta was just and reasonable.

Calgary noted that ATCO’s argument stated that Calgary had insufficient data to conduct a COS
Study with Gas Alberta as a standalone class, and in doing so, conveniently ignored two crucial
issues. Calgary pointed out that, first, the onus rests on the Company, not Calgary, to justify the
Gas Alberta settlement, and that Calgary at least attempted to carry out an analysis, which ATCO
had not. Calgary stated that secondly, ATCO had yet to provide the underlying data for its
allocation of marketing costs.

Calgary noted that ATCO provided the demands and volumes applicable to Gas Alberta, which
allocate over 90% of the allocable costs in the ATCO COS Studies. Calgary stated it had more
than adequate data to conduct its study in terms of developing allocation factors, indicating that
Calgary provided the only analysis of the Gas Alberta settlement versus fully allocated rolled-in
costs, and found the settlement rates to be well below applicable cost levels.

Calgary noted that the FGA argued the agreement it has reached with ATCO produced a just and
reasonable rate for the services that ATCO would provide to the FGA.

Calgary stated that unfortunately, neither ATCO nor the FGA presented any empirical evidence
during the hearing to justify this position, nor did ATCO modify its COS Studies to demonstrate
that the proposed rate to the FGA was cost justified. Calgary also noted that the FGA did not
propose an independent COS Study to show that the Gas Alberta rate was just and reasonable.
Calgary stated that the record to support the FGA position was, an assertion that the proposed
ATCO rate for transmission service was just and reasonable. Calgary submitted that an assertion
does not meet the onus of proof for the just and reasonable standard.




142 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


FGA
The FGA submitted that the MOU between ATCO and Gas Alberta was open, transparent, and
in the public interest, and that the Board must regard the MOU as a package to be either
approved or denied in its entirety.

The FGA considered that the intra-class allocation of marketing expense should be done using a
reasonable cost driver, once a study has determined a reasonable allocation. The FGA referred to
ATCO’s testimony that business development and the planning function drove marketing costs,
with planning being the primary aspect for the Utilities class. In describing the planning function
with respect to AGS, the FGA referred to the Company’s description of the process as one of
planning for the 1877 delivery points of AGS, and pointed out that, since Gas Alberta has only
77 delivery points, all requiring planning attention, Gas Alberta should be allocated, at most,
77÷1877 or 4.01% of Utilities marketing costs.

The FGA submitted that the Board should not accept ATCO’s dedicated asset approach, but
should approve a “rolled-in” COS study with all assets properly allocated. However, should the
Board consider that this approach has merit for future studies, the FGA suggested the proposal
should be examined in a collaborative process.

In conclusion, the FGA submitted that:

    •   the MOU between Gas Alberta and ATCO should be approved without change; and
    •   as all other interveners are silent on the matter of the MOU between ATCO and Gas
        Alberta. The FGA consider that, since no issue has been taken with the MOU, the Board
        should approve it in its entirety.

Views of the Board
As noted by the Board previously in this Section, ATCO did not separately allocate costs to Gas
Alberta and AGS in its COS Study. Therefore, no revenue to cost ratio comparisons were
provided by ATCO to evaluate the reasonableness of the terms stipulated in the MOU filed by
ATCO on June 21, 2001. On the other hand, the Board notes that allocations between the
Utilities were made by both Calgary and the FGA using ATCO data which highlighted revenue
to cost ratios. These allocations and ratios were set out in Calgary’s supplemental testimony,
filed on July 13, 2001 (Exhibit 167) and FGA Argument, respectively.

The Board notes that the MOU incorporates terms requiring Gas Alberta to purchase and
operate, at its own expense, the Custody Transfer Master Meters for each tap delivering gas from
the ATCO system. Since Gas Alberta will be providing the master meters at its own expense, the
Board does not consider it appropriate to include an allocation of costs for master meters as a
part of the M&R costs in the revenue requirement for Gas Alberta, as suggested by Calgary.

As described earlier, the Board considers that $20,000 is a reasonable estimate of the annual
marketing expense to be allocated to Gas Alberta.




                                                       EUB Decision 2001-97 (December 12, 2001) • 143
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


On the basis of the preceding considerations, the Board accepts the argument of the FGA. The
Board finds that the allocation of costs by Calgary is not justified, and the revenue to cost ratios
used by Calgary are invalid. As indicated earlier in the Decision, the Board considers that the
combination of Gas Alberta and AGS under the Utility classification is appropriate, and that the
COS Study demonstrates that the rate negotiated with Gas Alberta will not result in a transfer of
costs within the Utilities classification. Therefore, the Board considers that the terms of service
negotiated in the settlement, as described in the MOU, are acceptable and that the agreement
results in just and reasonable rates. Accordingly, the Board approves the rates and terms and
conditions of service with Gas Alberta as set out in the MOU, attached as Appendix 1 to this
Decision.

8 .8 Calgary’s COS Study
 .2
Position of ATCO
ATCO noted that Calgary was the only intervener to specifically address ATCO’s COS Study, in
written evidence filed on May 15, 2001 and supplemental testimony filed on July 13, 2001
(Exhibit 167), with comments on and proposed revisions to the COS Study. ATCO referred to
Calgary’s statement in its May 15 evidence:

        Calgary has accepted the vast majority of APS’s functionalization, classification
        and distribution functions. The changes identified above are all designed to
        correct the tilt in the APS study to drive costs to the “utilities” (AGS and FGA)
        and away from the I/P rate class.

ATCO took strong exception to Calgary’s attempt “to correct the tilt”, which ATCO considered
implied an improper motive on the part of the Company and which, in its view was not
warranted.

ATCO stated that Calgary’s COS Studies resulted in costs being shifted away from ATCO Gas
South and on to Gas Alberta and the I/P group. ATCO submitted that these adjustments should
be rejected.

ATCO concluded that it had responded to the Board’s direction from an earlier Decision by
providing a simple but useful COS study, and that the revenue-to-cost ratios generated in its COS
Study demonstrate that the negotiated I/P rates are reasonable.

ATCO also stated that, in accordance with Direction 13 from Decision 2000-16, ATCO had
developed a methodology for the COS Study which identified dedicated or sole use costs to be
borne separately by the I/P and Utilities groups, and which also identified joint use costs to be
shared by all user groups on the pipeline. ATCO argued that fairness considerations dictated that
the responsibility for use of pipeline facilities should be determined on this basis so that a user
group does not bear responsibility for costs associated with facilities the group does not use.
Finally, ATCO submitted that its COS Study methodology did not violate principles and
guidelines identified in the 1980 GURDI report.




144 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                ATCO Pipelines South


In conclusion, ATCO noted that Calgary’s proposed COS Study was based on ATCO’s study,
but with significant adjustments. ATCO submitted that Calgary’s COS Study results should be
rejected on the basis that the adjustments are flawed and without merit.

ATCO expressed concern that several parties indicated support in argument for Calgary’s COS
Study, without supporting their positions with critical review through the IR process or oral
cross-examination. The apparent ease with which these parties arrived at this position caused
ATCO to question whether the recommendations of those parties were determined primarily by
fair and relevant costing and ratemaking principles, or by narrow and immediate interests.

Positions of the Interveners
Calgary
Calgary referred to its COS Study (attached to Exhibit 167) which was based upon rolled-in
costing, and recognized the proposed settlement agreement between ATCO and Gas Alberta, as
well as the I/P settlement with the I/P classes of service. Calgary stated that the study was totally
predicated upon data provided by ATCO. Calgary submitted that when the Board’s long held
rolled-in costing and ratemaking principles were adhered to, the rates proposed by ATCO for
Gas Alberta and the I/P classes, and the residual rate for AGS, are shown to be unjust,
unreasonable and not in the public interest. Accordingly, Calgary considered that the settlement
rates should be rejected and adjusted to reflect the values set forth in the Calgary COS Study.

Calgary referred to Exhibit 169, in which the FGA attempted to characterize the methodology
used by Calgary in its revised COS Study. Calgary submitted that the methodology as
characterized by the FGA was incorrect and did not represent the approach to the changes
Calgary implemented between its original study and the revised study attached to Exhibit 167.
As indicated by Mr. Vander Veen,122 Calgary in its revised study started over and developed four
sets of allocation factors based upon the data provided by ATCO. A review of the revised
allocation factors used by Calgary demonstrates this point. In its original and revised studies the
allocation factors were as follows:

                                       Calgary Original COS Study
      Factor               Utilities         Gas Alberta           Industrials          Producers
        C                        0.4             0.0                      0.2                  0.4
        D                   0.5782               0.0                 0.0791               0.3427
        V                    0.353               0.0                   0.117                0.530
        W                   0.4656               0.0                0.09805              0.43635




        122
              Volume 7, p. 1551-1553

                                                           EUB Decision 2001-97 (December 12, 2001) • 145
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


                                     Calgary Revised COS Study
      Factor             Utilities          Gas Alberta        Industrials         Producers
        C                      0.3                0.1                0.2                 0.4
        D                 0.5765              0.0096             0.0777              0.3362
        V                 0.3474              0.0066             0.1171              0.5299
        W                 0.4618              0.0077             0.0973              0.4332


Calgary submitted that it was obvious in reviewing the allocation factors, that new factors were
developed for each class. Calgary did not just split the Utilities column as alleged by the FGA in
its Exhibit 169. Calgary developed new allocation factors and revised its study continuing to use
rolled-in costing methodologies for all classes. Calgary submitted that the Board should
recognize that the Calgary studies were prepared based upon data provided by ATCO.

MI
The MI considered that the COS Study filed by ATCO on March 19, 2001 contained several
departures from long-standing methods approved for CWNG, most notably vintage costing and
DoH, both of which appear to be designed to shift costs to core customers to enable ATCO to be
more competitive on I/P rates. The MI noted that ATCO used these factors to allocate asset-
related costs associated with pipeline and compression. The MI noted that the COS study filed by
Calgary on May 15, 2001 eliminated vintage costing and DoH methodology, and proposed other
changes including allocation of the custody transfer metering on a volumetric basis. However, in
rebuttal evidence on June 15, 2001, ATCO stated that DoH methodology would not be
eliminated, but reverted to allocation of shared facilities based on contract demand, which led,
after various meetings with interveners, to identification of $22.4 million of dedicated laterals to
core customers.

The MI concurred with the concerns set out in Calgary’s supplemental testimony of July 13,
2001, and submitted that the revised Calgary COS Study should be used as the basis to test the
costs negotiated with the I/P class.

FGA
Acknowledging that Calgary’s COS Study incorporated some worthwhile improvements to the
ATCO study, such as an attempted intra-class allocation for the Utilities class to determine costs
for AGS and Gas Alberta, the FGA submitted that two errors rendered Calgary’s study
unsuitable for establishing a rate for Gas Alberta. First, the FGA referred to Calgary’s proposed
intra-class allocation of 25% to Gas Alberta and 75% to AGS based on judgement and
experience, noting the subsequent testimony of Calgary’s witness that, in hindsight, a more
appropriate allocation would be 50/50.

The FGA considered that Calgary’s highly variable judgement was no substitute for the more
studied approach of ATCO, which did not support a 50/50 or 25/75 allocation, but instead
indicated that growth in coincident demand was the primary factor driving allocation of
marketing costs. The FGA submitted that, if Calgary truly accepted ATCO’s description of how
marketing costs were allocated among the three customer classes, then no more than 5% of the

146 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


Utilities’ marketing costs should be allocated to Gas Alberta, based on the forecast of Gas
Alberta’s volume growth in TJ/day of peak demand for the test years.

The FGA considered that the second error in Calgary’s COS Study related to the allocation of
M&R expense to Gas Alberta. The FGA submitted that Calgary’s allocation of $57,000 to Gas
Alberta betrayed a lack of understanding of the manner in which a pipeline system works, and
costs are incurred. The FGA stated that the “general system costs” as defined in Calgary’s
testimony, are costs associated with putting gas on the ATCO system, noting that M&R costs
are allocated and paid for by producers and any other party through ATCO’s on-system charges.
The FGA considered that, if these “general system costs” are then re-allocated to those who pay
only for delivery of gas, as in Calgary’s COS study, a serious double counting must exist in that
study.

The FGA pointed out that the rates to AGS and Gas Alberta are the charges incurred for gas
delivered off the ATCO system, and M&R costs allocated to the Utilities class are the costs of
the meters owned by ATCO for custody transfer purposes, associated with delivery off the
system. The FGA noted that ATCO owns all the meters at custody transfer points for AGS and
Industrial customers, but not all of those at Gas Alberta’s delivery points. The FGA submitted
that Calgary failed to understand the provisions of the MOU dealing with the sale of meters to
Gas Alberta, and pointed out that the co-ops have always owned their pressure control facilities.
The FGA noted that Gas Alberta will operate and maintain its part of the system and will allow
ATCO access to the measurement data at no cost, and indicated that Gas Alberta does not
impose any direct or indirect costs on ATCO for M&R at its delivery points. In other words, the
FGA considered that Gas Alberta must not be allocated any of ATCO’s cost of M&R to delivery
customers.

The FGA considered this situation analogous to the situation that prevailed in CWNG’s previous
COS Studies, whereby CWNG, as an integrated utility, incurred costs on its distribution system,
and co-ops served by Gas Alberta had their own distribution systems, thereby imposing no
distribution costs on the CWNG system. Accordingly, CWNG allocated no distribution costs to
Rate 6 at the transmission system delivery points.

The FGA clarified that the COS Study it supported for the purposes of these proceedings was the
rolled-in COS Study performed by ATCO Pipelines. The FGA stated that it was obvious that the
ATCO Pipelines DoH study was not useful for developing a rate for Gas Alberta, since it did not
specifically identify nor address a DoH to Gas Alberta delivery points.123

The FGA considered that the Calgary COS Study failed a test of reasonableness and consistency.
The FGA pointed out that in its study, Calgary proposed that all M&R costs, except those
attributed to UFG, be allocated on a factor that was weighted equally between peak demand and
annual volume, and for metering costs associated with UFG, Calgary proposed using annual
volumes to allocate UFG. The FGA viewed Calgary’s treatment of meters in its cost of service
study as nothing more than a dedicated asset proposal under the guise of matching costs to
customer classes. The FGA considered that the effect of Calgary’s proposal would be that meter

        123
              FGA-ATCOP.29 a)

                                                       EUB Decision 2001-97 (December 12, 2001) • 147
2001/2002 General Rate Application – Phases I and II                          ATCO Pipelines South


assets for one customer would be handled in a different manner and with a different allocation
than for other customers. In other words, Calgary on the one hand criticized ATCO Pipelines for
its dedicated asset proposal but, on the other hand, espoused a dedicated asset proposal with
respect to the UFG meters.

The FGA agreed with ATCO that it was reasonable that a company would spend 50% of its
Utility marketing effort on an entity that has 4% of Utility connections and 1.6% of Utility
demand. The FGA questioned whether or not ATCO was properly managed if it actually
expended as much marketing effort on Gas Alberta as it did on ATCO Gas. The FGA submitted
that Mr. Vander Veen’s judgment that 50/50 was the proper allocation was not only
unreasonable, but also ludicrous and displayed little knowledge of either ATCO Pipelines or Gas
Alberta.

The FGA considered that another unreasonable result in Calgary’s COS Study was its arbitrary
allocation of meters partly to demand and partly to volume, pointing out that it is well
understood in the gas transmission business, that the cost of meters is proportional to the
maximum flow, i.e. peak demand. The FGA stated that the reasonable manner of classifying the
cost of meters was to demand, as proposed by ATCO Pipelines in its COS Study, which ensures
the optimum cost recovery through demand rates.

The FGA had some concerns with ATCO’s COS Study,124 but stated that the ATCO COS Study
did not contain the serious errors in methodology found in the Calgary study, the latter remaining
uncorrected to the end of the proceedings. The FGA concluded that the ATCO “rolled-in” cost of
service study was based on the best information available at the time the study was performed
and provides reasonable results, and considered that any deficiencies, which might exist, could
be corrected by the time of ATCO’s next GRA. The FGA submitted that the ATCO “rolled-in”
COS is the one that should be accepted and used in these proceedings.

Views of the Board
The Board notes that Calgary’s COS Study and the allocation factors derived were based upon
data supplied in ATCO’s COS Study. Allocation factors used by Calgary were: Factor C related
to customer costs, Factor D related to peak demand, Factor V relate to volume throughput and
Factor W, weighted on the basis of demand and throughput ratios to allocate Asset Related Other
and O&M Other costs.

The Board notes that Factors C, D and V are identical to the ATCO COS Study factors.
However, the Board considers that Factor W, derived by Calgary by arithmetic weighting of
demand and volume, yields a factor that does not relate to cost causation in terms of asset related
and O&M costs. The Board considers that Calgary’s calculation of Factor W was based on
combining two different units and that the application of this factor skews the results of the COS
Studies significantly enough to warrant non-acceptance of the use of Factor W. Therefore, the
Board rejects Calgary’s allocation of costs related to Factor W.



        124
              Federation and Gas Alberta argument, pp. 2-7

148 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


With respect to costs related to UFG metering, as stated earlier in the Decision, the Board
accepts Calgary’s proposal that UFG metering costs are related to volume throughput and agree
that the asset related and specific O&M related costs for the UFG meters should be allocated on
the ratio of volume throughput.

Previously, the Board has provided reasons for considering the Calgary allocation to Gas Alberta
as shown in Exhibit 167 to be invalid. For the same reasons, the Board does not accept Calgary’s
COS Study results and instead places reliance on the results shown in the revised COS Study
filed by ATCO on June 15, 2001 (Exhibit 99).

8.3       Rate Design
Position of ATCO
ATCO expressed significant concern with Calgary’s position on the Company’s proposal for
determining the rate for AGS, indicating that Calgary appeared to ignore the potential benefit of
leverage that ATCO has accorded AGS for any adjustments to the revenue requirement that the
Board may make. ATCO submitted that its proposal resulted in symmetrical treatment for
adjustments in either direction.

Positions of the Interveners
Calgary
Calgary noted that ATCO, in response to an undertaking125 provided its proposed methodology
for establishing the rate it proposes to charge its affiliate AGS for transmission service. Calgary
submitted that this proposal must be reviewed from two critical perspectives:

      •   the revenue requirement which ATCO assigns to AGS; and
      •   the appropriate contract demand.

Calgary referred to ATCO’s proposal that the revenue responsibility for AGS should be the
residual revenues remaining after deduction of costs relating to Producer, Industrial, and Gas
Alberta service plus franchise tax from revenue requirement. In Calgary’s view, this approach
was not based upon appropriate cost allocation analysis or upon sound ratemaking principles. In
particular, Calgary indicated that ATCO included in this calculation, the transfer to AGS of
several million dollars of discounts to the Industrial customers. By way of example, Calgary
pointed out that the discount to Agrium was transferred to AGS under this calculation, and in
Calgary’s submission, it was unconscionable to expect customers of AGS, an affiliate of APS, to
absorb discounts granted by the Company to Industrial customers.

Calgary reiterated its point, already discussed earlier in this Section, that the ATCO COS Studies
did not justify the rate levels contained in the I/P and Gas Alberta settlements, pointing out that
the settlement rates were well below the levels based on the Board’s long held policy of rolled-in
costing and ratemaking. Calgary considered that the ATCO proposal attempted to develop rates
for its affiliate based upon the revenue credit methodology, and not on cost based ratemaking
pursuant to existing regulatory policy. Calgary pointed out that, in Decision 2000-45, the Board
          125
                Tr., p. 1483/16

                                                       EUB Decision 2001-97 (December 12, 2001) • 149
2001/2002 General Rate Application – Phases I and II                           ATCO Pipelines South


directed ATCO to file a COS Study designed to circumvent the revenue credit problem, not to
create another one.

Calgary considered that the issue of contract demand, primarily addressed in its own COS Study
argument, must also be considered in the design of an appropriate cost based rate. Calgary’s
COS Study attached to Exhibit 167, based upon fully rolled-in costing methodology, determined
that an appropriate rate for AGS would be $1.711 per GJ of contract demand based upon a
demand of 965,000 GJ per month (using 2001 costs). Calgary pointed out that, in contrast and
using 2001 as a base, ATCO calculated that the rate should be $1.91126 based on an artificial
contract demand of 1,049,000 GJ per day. Calgary submitted that the Agrium discount of $1.8
million inflated this rate by $0.143 per month per unit of contract demand. Calgary argued that
this was inflated even further by other discounts.

Calgary expressed the hope that the Board would be as critical as the interveners with ATCO’s
proposal to seek to recover Industrial and Producer discounts from customers of its affiliate,
AGS. Calgary urged the Board to reject rate design based upon the revenue-crediting concept
proposed, and establish rates based on fully allocated rolled-in cost for all classes of service.
Calgary considered that rates between affiliates should be subject to strict scrutiny, fully
allocated costing procedures, and independent review of internal contract demand
determinations.

Views of the Board
Previously in this Section, the Board has addressed the various aspects of ATCO’s COS Study
and alternatives proposed by Calgary. The Board has examined the evidence presented in the
June 15, 2001 revised COS Study of ATCO. As previously indicated, for the purposes of this
GRA, the Board is satisfied with the dedicated assignment methodology used by ATCO in the
revised COS Study filed on June 15, 2001.

With the revisions described in previous paragraphs, the Board notes that the revenue to cost
ratio determined for the Utility class, in the revised COS Study, would be approximately 98%
based on interim rates for AGS and the rates established for Gas Alberta in the MOU, and
approximately 95% for the I/P class with settlement rates. In addition, the rate that would result
from the Revised COS Study assuming 100% of costs recovered from the Utilities class would
be $1.89/GJ/month of contract demand. Therefore, in light of the relative ratios and relative
rates, and the reasons set out in Section 8.2.5 of this Decision, the Board accepts the
methodology in ATCO’s COS Study.127

The Board notes ATCO’s statement in Exhibit 31 wherein the Company, in order to preserve the
benefits of the negotiated I/P settlement committed to:

        … take the risk that any adjustments to revenue requirement or revenue forecasts
        in the upcoming General Rate Application could be allocated to customer classes
        other than core.

        126
              Undertaking response at Tr. p. 1483/16
        127
              Exhibit 99, June 15, 2001 revision

150 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South




The Board also notes ATCO’s request for a rate for service provided to AGS of $1.93/GJ/mo of
contract demand, based on the average of the total revenue requirement for the test years less
producer, industrial, Gas Alberta and franchise tax revenues. The Board does not accept ATCO’s
proposal for establishment of a rate for the Utilities class on this basis. The Board notes that
ATCO’s calculation results in costs attributable to the I/P class being transferred to the Utilities
class, due to the netting of rebates against industrial revenues. Accordingly, the Board considers
that a separate rate should be established for each test year based on the results of COS Studies
that identify the costs of providing service to the Utilities class in those years.

In preceding paragraphs, the Board determined that the rate contained in the MOU for Gas
Alberta was just and reasonable. The Board also considers that the revenue to cost ratios as
identified in the COS Study filed on June 15, 2001, support the conclusion that the settlement
rates, as approved for the Industrial and Producer class, do not result in an inappropriate transfer
of costs to the Utilities class.

The Board notes AIPA’s submission that ATCO’s rates are based on a simple demand charge,
rather than a demand and variable charge. The Board accepts the Company’s position that most
customers with Transportation Firm Service run close to 100% demand, but believes that
distribution customers might not operate at this level. Accordingly, the Board is willing to accept
the design of ATCO’s distribution rate, based on a full demand structure for the test year period,
but directs ATCO to provide a better rationale for demand rate in the next GRA. The Board
accepts the Company’s submission that the demand rate for Transportation service for customers
other than distribution, together with the change in overrun methodology, will result in revenue
neutrality.

As indicated above, the Board considers that the rates for the Utilities class should be determined
for each test year based on the results of COS Studies prepared by the Company for those years.
Accordingly, the Board directs ATCO to revise its 2001 COS Study, as filed on June 15, 2001, to
reflect the adjustments set out in other sections of this Decision. The Board also directs the
Company to propose a rate for the Utilities class for the 2001 test year based on the results of the
revised COS Study.

For the purposes of setting just and reasonable rates on a go-forward basis, the rates should be
based upon a COS Study reflecting 2002 approved revenue requirements. Accordingly, the
Board directs ATCO to prepare and file with the Board, a COS Study based upon the 2002
forecasts and using the methodology approved in this Decision for the 2001 COS Study. In
refiling the COS studies for each test year, the Board expects ATCO to submit the studies at the
level of detail shown in the response to BR-37.

As indicated previously, the Board will not allow the Company to collect from either the
combined I/P class or from Gas Alberta any under-recovery resulting from the re-allocation of
costs using procedures to be followed by ATCO in refiling the COS Studies, after reflecting
adjustments to revenue requirement and rate base as set out in other sections of this Decision.




                                                       EUB Decision 2001-97 (December 12, 2001) • 151
2001/2002 General Rate Application – Phases I and II                                                                  ATCO Pipelines South


9       SUMMARY OF DIRECTIONS

This section is provided for the convenience of readers. In the event of any difference between
the Directions in this section and those in the main body of the report, the wording in the main
body of the Decision shall prevail.

1.      Accordingly, the Board directs ATCO to reduce the forecasts for capital additions by 3%
        in 2001 and 5% in 2002. ................................................................................................... 16

2.      Accordingly, the Board directs ATCO to reduce the 2001 test year opening balance of
        Property, Plant and Equipment by $1.99 million to recognize actual expenditure in the
        year 2000........................................................................................................................... 17

3.      Accordingly, the Board directs ATCO to recalculate its lead/lag study with application of
        a zero lag to transactions with ATCO Gas South. ............................................................ 28

4.      Accordingly, the Board directs ATCO to recalculate the NWC balance using an expense
        lag of 34.16 days for payments for affiliate services (excluding I-Tek)........................... 29

5.      In Decision 2000-9, the Board directed ATCO to apply a zero expense lag to the retained
        earnings component of common equity return and an expense lag for the common
        dividend component based on the methodology used to calculate the preferred dividend
        lag. The Board therefore, directs ATCO to make the appropriate adjustment to the
        lead/lag study to comply with this requirement................................................................ 29

6.      Accordingly, as indicated by the calculations in the table above, the Board directs ATCO
        to reduce O&M forecasts by $491,000 in 2001, and $341,000 in 2002. .......................... 57

7.      Accordingly, the Board directs ATCO to reduce the reserve for injuries and damages to
        $175,000 for each test year. .............................................................................................. 66

8.      Accordingly, the Board directs ATCO to revise its depreciation calculations for the test
        years to reflect use of the Equal Life Group method for Contract #30............................. 72

9.      Accordingly, while satisfied with the results of a technical update for the purpose of these
        proceedings, the Board directs ATCO to file a full depreciation study for the next GRA.
        ........................................................................................................................................... 72

10.     Accordingly, the Board directs ATCO to recalculate income tax expense and liabilities
        for the test years using those rates announced or substantively enacted by the federal and
        provincial governments for those years. ........................................................................... 77

11.     Accordingly, the Board directs ATCO to ensure that UFG is applied to storage and
        exchange volumes............................................................................................................. 97




152 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                                                                ATCO Pipelines South


12.      Accordingly, the Board directs ATCO for all future non-standard contracts, to provide the
         Board and all interested parties with the following:

              •     an analysis of all costs incurred to provide the service, including costs to the
                    Exchange Deferred Account;
              •     an analysis of the competitive alternative; and
              •     a copy of the non-standard contract. ................................................................... 113

13.      The Board therefore directs ATCO to allocate the cost of the custody transfer meters
         using the ratio of volume throughput to each customer class. The remaining costs for M
         & R shall be allocated on the basis of the ratio of demand for each customer class. ..... 131

14.      However, the Board directs ATCO to improve the study of marketing expense and file
         the results at the next GRA when the Company will have a longer history of data with
         respect to marketing expenses at the time when the forecast is prepared for future test
         years. ............................................................................................................................... 133

15.      Accordingly, the Board is willing to accept the design of ATCO’s distribution rate, based
         on a full demand structure for the test year period, but directs ATCO to provide a better
         rationale for using a 100% demand rate in the next GRA. The Board accepts the
         Company’s submission that the demand rate for Transportation service for customers
         other than distribution, together with the change in overrun methodology, will result in
         revenue neutrality............................................................................................................ 151

16.      Accordingly, the Board directs ATCO to revise its 2001 COS Study, as filed on June 15,
         2001, to reflect the adjustments set out in other sections of this Decision. .................... 151

17.      The Board also directs the Company to propose a rate for the Utilities class for the 2001
         test year based on the results of the revised COS Study................................................. 151

18.      Accordingly, the Board directs ATCO to prepare and file with the Board, a COS Study
         based upon the 2002 forecasts and using the methodology approved in this Decision for
         the 2001 COS Study. In refiling the COS studies for each test year, the Board expects
         ATCO to submit the studies at the level of detail shown in the response to BR-37....... 151



10       ORDER

THEREFORE, IT IS ORDERED THAT:

      1) ATCO Pipelines South shall refile its 2001/2002 GRA, on or before February 15, 2002,
         incorporating the findings of the Board in this Decision.

      2) ATCO Pipelines South, in its refiling, shall include all of the supporting schedules
         necessary for the Board to make its final determination respecting ATCO’s 2001/2002



                                                                              EUB Decision 2001-97 (December 12, 2001) • 153
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


        revenue requirement. The refiling shall be at a level of detail sufficient to reconcile with
        the original filing and demonstrate compliance with the Board’s findings.

    3) With respect to transactions with Affiliates and transactions related to pension and post
       employment benefits, ATCO Pipelines South shall include in the revenue requirement for
       the test years, the related expenditures and revenues as filed in the General Rate
       Application, pending final determination of these amounts in the ATCO Affiliates and
       ATCO Pension proceedings. ATCO will be required to adjust the amounts, included as
       “placeholders” in the revenue requirement for the test years, after the Board has issued
       decisions on the ATCO Affiliates and ATCO Pension proceedings.

    4) ATCO Pipelines South, in its refiling, shall determine the rate, for the test years, for
       transmission service to ATCO Gas South, based on the results of the Cost of Service
       Study for each test year, refiled as directed by the Board in this Decision. The rates so
       determined for each test year will applied on an interim basis, pending final
       determination of the revenue requirement for the test years after the Board has issued
       decisions on the ATCO Affiliates and ATCO Pension proceedings.

    5) ATCO Pipelines South, in its refiling, shall determine the amount of surplus or shortfall
       for 2001, and propose a methodology for disposition of the amount on an interim basis
       pending final determination of the revenue requirement for the test years after the Board
       has issued decisions on the ATCO Affiliates and ATCO Pension proceedings.

    6) The rates, tolls and charges for Gas Alberta Inc., attached as Schedule “A” to this
       Decision are effective for all consumption on and after January 1, 2002.




154 • EUB Decision 2001-97 (December 12, 2001)
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South


Dated in Calgary, Alberta on December 12, 2001

ALBERTA ENERGY AND UTILITIES BOARD


(original signed by)


B. F. Bietz, Ph.D.
Presiding Member


(original signed by)


Gordon J. Miller
Member


(original signed by)


C. Dahl Rees
Acting Member




                                                       EUB Decision 2001-97 (December 12, 2001) • 155
2001/2002 General Rate Application – Phases I and II                             ATCO Pipelines South




                                                                           Effective by Decision 2001-97
                                                            This replaces Gas Alberta Transportation Rate
                                                                     Previously effective August 30, 2000



                                          SCHEDULE “A”



                             ATCO PIPELINES SOUTH (ATCO)
                          GAS ALBERTA TRANSPORTATION RATE


Gas Alberta Inc. (GA) will be charged a monthly demand charge for service of $1.95/GJ of daily
capacity for the period January 1, 2001 through December 31, 2002.

This rate will be combined with the following contract demand quantities to generate the annual
amounts that ATCO will charge GA:

               •     Contract Demand for 2001           15.787 TJ per day
               •     Contract Demand for 2002           16.782 TJ per day


The applicable rate for service for any period following December 31, 2002, shall be the rate for
such period as approved by the Alberta Energy and Utilities Board.




                                                       EUB Decision 2001-97 (December 12, 2001) • 157
2001/2002 General Rate Application – Phases I and II                            ATCO Pipelines South




                                             APPENDIX 1


                                  Memorandum of Understanding
                                     (consisting of 3 pages)




                                                       EUB Decision 2001-97 (December 12, 2001) • 159
                                                                                 l nes
                                                                      AT C O Pipe i South
2001            l         i t
    /2002 Genera Rate Appl ca ion - Phases I and II                             Appendix 1




                                                      EUB Decision 2001-97 (December 12, 2001)
                                                                 l nes
                                                      AT C O Pipe i South
2001            l         i t
    /2002 Genera Rate Appl ca ion - Phases I and II             Appendix 1




EUB Decision 2001-97 (December 12, 2001)
                                                                                 l nes
                                                                      AT C O Pipe i South
2001            l         i t
    /2002 Genera Rate Appl ca ion - Phases I and II                             Appendix 1




                                                      EUB Decision 2001-97 (December 12, 2001)

				
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