Utility Asset Disposition November 26, 2013 - AUC · Utility Asset Disposition AUC Decision...

Decision 2013-417

Utility Asset Disposition November 26, 2013

The Alberta Utilities Commission

Decision 2013-417: Utility Asset Disposition

Application No. 1566373

Proceeding ID No. 20

November 26, 2013

Published by


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Website: www.auc.ab.ca

http://www.auc.ab.ca/

AUC Decision 2013-417 (November 26, 2013) • i

Contents

1 Introduction ........................................................................................................................... 1

2 Overview of judicial and Alberta regulatory decisions before and after Stores Block .. 5 Introduction .................................................................................................................... 5 2.1

Regulatory practice in Alberta before TransAlta ........................................................... 5 2.2

Regulatory practice in Alberta after TransAlta .............................................................. 8 2.3

Stores Block ................................................................................................................. 11 2.4

Alberta Court of Appeal decisions subsequent to Stores Block .................................. 15 2.5

2.5.1 Carbon ............................................................................................................. 15 2.5.2 Harvest Hills ................................................................................................... 16 2.5.3 Salt Caverns .................................................................................................... 19

2.5.4 Deferred gas account appeal ........................................................................... 21 Additional AUC decisions after Stores Block ............................................................. 21 2.6

2.6.1 Decision 2009-004 – Carbon Storage Scoping ............................................... 21

2.6.2 Decision 2009-253 – Review and Variance.................................................... 22 2.6.3 Decision 2011-176 – Fortis Special Charge ................................................... 24 2.6.4 Decision 2011-450 – 2011-2012 ATCO Gas GRA ........................................ 24

2.6.5 Decision 2011-474 – 2011 Generic Cost of Capital ....................................... 27 2.6.6 Decision 2012-068 – Disposition of Salt Cavern Assets ................................ 27

2.6.7 Decision 2012-172 – ATCO Electric 2011-2012 GTA Compliance Filing ... 28 Consideration of Stores Block in other jurisdictions ................................................... 29 2.7

2.7.1 Bell Canada v. Bell Aliant Regional Communications .................................. 29

2.7.2 Toronto Hydro Electric System Ltd. v. Ontario Energy Board ...................... 30 2.7.3 FortisBC Inc. v. Shaw Cablesystems Ltd. ...................................................... 31

2.7.4 NEB Decision RH-003-2011 – TransCanada PipeLines Limited .................. 31 Principles derived from court and AUC decisions ....................................................... 32 2.8

Remaining matters to be considered ............................................................................ 35 2.9

3 Final revised issues list ........................................................................................................ 35 Issue 1 – Asset disposition issues ................................................................................ 35 3.1

3.1.1 Issue 1.1 – Ordinary course dispositions ........................................................ 35 3.1.2 Supplemental process on depreciation principles ........................................... 40 3.1.3 Issue 1.2 – Reinvestment of sales proceeds .................................................... 42

Issue 2 – Used or required to be used issues ................................................................ 45 3.2

3.2.1 Issue 2.1 – Stranded assets .............................................................................. 45 3.2.1.1 Issue 2.1.1 – Definition of stranded assets including a threshold

dollar size and / or definition of the smallest units of property to

potentially be considered stranded. .................................................. 45 3.2.1.2 Issue 2.1.2 – Applicability of Stores Block to a determination of

responsibility for stranded assets. ..................................................... 47

3.2.1.3 Issue 2.1.3 – Application of the relevant legislation to a

determination of responsibility for stranded assets owned by gas

utilities. ............................................................................................. 49 3.2.1.4 Issue 2.1.4 - Application of the Electric Utilities Act and other

relevant legislation to a determination of responsibility for stranded

assets owned by electric utilities. ..................................................... 52

ii • AUC Decision 2013-417 (November 26, 2013)

3.2.1.5 Issue 2.1.5 – Applicability of stranded asset findings to the 2011 and

2012 test years. ................................................................................. 53

Issue 2.2 – Responsibility for ongoing costs of retired assets...................................... 54 3.3

Issue 2.3 – Ongoing cost responsibility for retired assets subject to settlements ........ 58 3.4

Issue 2.4 – Verification of operational purpose ........................................................... 65 3.5

4 Commission findings ........................................................................................................... 66 Application of Stores Block ......................................................................................... 66 4.1

Do Stores Block principles also apply to the disposition of assets inside the ordinary 4.2

course of business? ...................................................................................................... 67 Inclusion of assets in rate base ..................................................................................... 68 4.3

Depreciation ................................................................................................................. 71 4.4

4.4.1 Does the depreciation methodology comply with the principles in Stores

Block and subsequent cases? .......................................................................... 72

4.4.2 Does the Commission have the authority to include, as a part of its

depreciation methodology, a provision that charges/refunds to customers on a

prospective basis, depreciation rate adjustments resulting from an over or

under recovery of depreciation expense in prior years? ................................. 74 Stranded assets and post-retirement costs .................................................................... 76 4.5

4.5.1 Special facilities tariffs ................................................................................... 78 4.5.2 Review and variance applications ................................................................... 79

4.5.2.1 Decision 2011-474, 2011 Generic Cost of Capital ........................... 79 4.5.2.2 Decision 2011-450, 2011-2012 ATCO Gas GRA ............................ 79

Criteria and conditions for assets disposed of outside the ordinary course of business4.6

..................................................................................................................................... 81 Reinvestment of sales proceeds ................................................................................... 82 4.7

4.7.1 Verification of operational purpose ................................................................ 82

Summary ...................................................................................................................... 83 4.8

Appendix 1 – Proceeding participants ...................................................................................... 87

Appendix 2 – Summary of Alberta legislation ......................................................................... 90

1. Alberta Energy and Utilities Board Act, RSA 2000, c A-17 ...................................... 90 2. Alberta Utilities Commission Act, SA 2007, c A-37.2 ............................................... 90

3. Electric Utilities Act, SA 2003, c E-5.1 ...................................................................... 91 4. Transmission Regulation, AR 086/2007 ................................................................... 101 5. Gas Utilities Act, RSA 2000, c G-5 .......................................................................... 104 6. Roles, Relationships and Responsibilities Regulation, AR 186/2003....................... 110 7. Public Utilities Act, RSA 2000, c P-45 ..................................................................... 111

Appendix 3 – Summary of Commission directions ................................................................ 114

AUC Decision 2013-417 (November 26, 2013) • 1


Calgary, Alberta

Decision 2013-417

Application No. 1566373

Utility Asset Disposition Proceeding ID No. 20

1 Introduction

1. The Alberta Utilities Commission (AUC or Commission), by notice dated April 2, 2008,

(notice) initiated the Utility Asset Disposition proceeding. The notice referred to the Supreme

Court of Canada’s decision in ATCO Gas & Pipelines Ltd. v. Alberta (Energy & Utilities Board),

2006 SCC 4, [2006] 1 S.C.R. 140 (Stores Block) and stated:

The Stores Block Decision may have various implications with respect to regulation of

Alberta utilities. In particular, the guidance provided by the courts may require re-

consideration of certain aspects of traditional regulatory approaches to the acquisition and

disposition of utility assets and to the setting of just and reasonable rates. Parties have

argued various interpretations of the Stores Block Decision in several recent proceedings

before the EUB and in various ongoing proceedings before the Commission. The

Commission would like to develop a comprehensive understanding of these potential

implications through this Proceeding and then to apply that understanding in a consistent

manner in future decisions.

This single proceeding approach has the advantage of allowing broad stakeholder

participation on focused issues thereby avoiding the disadvantages associated with a

piecemeal consideration of these issues through a series of specific applications. These

disadvantages include:

time and cost inefficiencies resulting from multiple and perhaps overlapping

proceedings, and any reviews and appeals therefrom;

the potential for inconsistent treatment of similar applications;

uncertainty with respect to any aspect of the Commission’s approach to rate

related matters is disruptive to all stakeholders; and

the potential that certain stakeholders will be unable to effectively participate on

material issues if they are considered in a variety of specific applications.

(footnote omitted)

2. The notice set out the three principal objectives of the proceeding, stating that the

Commission intended to:

provide interested parties an opportunity to advance and defend their interpretation of

the Stores Block Decision

provide interested parties an opportunity to identify and explore the potential

implications of the Stores Block Decision to utility regulation in Alberta

develop a consistent, principled approach to applying the guidance provided by the

Stores Block Decision, while providing sufficient flexibility to address the specifics

of each proceeding

Utility Asset Disposition

2 • AUC Decision 2013-417 (November 26, 2013)

3. The Commission considered that a single proceeding with broad stakeholder participation

from all Commission regulated utilities and their stakeholders to be timely, and in the best

interest of regulatory efficiency, procedural fairness and regulatory certainty.

4. Following the filing of initial submissions on the Issues List attached as Appendix A to

the notice, ATCO Gas and ATCO Pipelines (divisions of ATCO Gas and Pipelines Ltd.) and

ATCO Electric Ltd. (collectively the ATCO Utilities) filed a motion to suspend the proceeding.

In Decision 2008-123,1 the Commission suspended the Utility Asset Disposition proceeding in

light of proceedings before the Alberta Court of Appeal relating to issues before the Supreme

Court of Canada in Stores Block. The Commission determined:

The Commission acknowledges that additional clarification of the meaning, scope and

application of the Stores Block Decision by the courts can provide additional direction

for the Commission and will further the Commission’s goal of avoiding potentially

inconsistent decisions.2

5. The matters that were before the Alberta Court of Appeal referred to in Decision

2008-123 have been addressed,3 as discussed below.

6. In Decision 2012-154,4 with respect to a review and variance application of Decision

2011-474,5 the 2011 Generic Cost of Capital decision, the Commission noted that a stranded

assets issue had arisen and directed that the matter be further considered in the Utility Asset

Disposition proceeding or in a new generic proceeding. The Commission stated:

39. The review panel notes that the Commission sought to have the issues raised by

the Stores Block decision of the Supreme Court of Canada, including the issue of

stranded assets, resolved when the Commission initiated the Utility Asset Disposition

Rate Review Proceeding (Proceeding ID No. 20) on April 2, 2008. Following a number

of procedural steps, Proceeding ID No. 20 was suspended on November 20, 2008. Given

this and the submission of ATCO Utilities, the review panel considers that the issue of

stranded assets and who bears the risk in relation to stranded assets should be evaluated

in the context of the relevant legislation and case law and therefore expects to either re-

initiate Proceeding ID No. 20 or initiate a generic proceeding regarding asset disposition

and stranded assets. The Commission will establish this proceeding after the issuance of a

Commission decision on the Rate Regulation Initiative (Proceeding ID No. 566).6

(footnote omitted)

1 Decision 2008-123: Review of Rate Related Implications of Utility Asset Dispositions Following the Supreme

Court’s Calgary Stores Block Decision, Reasons for Decision on Motion by the ATCO Utilities dated

October 21, 2008, Application No. 1566373, Proceeding ID No. 20, November 28, 2008. 2 Decision 2008-123, page 14.

3 ATCO Gas and Pipelines Ltd. v. Alberta (Energy and Utilities Board), [2009] A.J. No. 489, 2009 ABCA 171

(Harvest Hills) and ATCO Gas and Pipelines Ltd. v. Alberta (Utilities Commission), 2009 ABCA 246 (Salt

Caverns). 4 Decision 2012-154: Decision on Request for Review and Variance of AUC Decision 2011-474, 2011 Generic

Cost of Capital, Application Nos. 1608120, 1608122, 1608126, 1608127, 1680129 and 1608136, Proceeding ID

No. 1697, June 4, 2012. 5 Decision 2011-474: 2011 Generic Cost of Capital, Application No. 1606549, Proceeding ID No. 833,

December 8, 2011. 6 Decision 2012-154, paragraph 39, pages 10 to 11.

http://www.auc.ab.ca/applications/decisions/Decisions/2008/2008-123.pdf





7. In Decision 2012-156,7 with respect to a review and variance application of Decision

2011-450,8 the ATCO Gas 2011-2012 General Rate Application Phase I decision, the

Commission noted that an issue with respect to production abandonment costs had arisen and

directed that the matter be further considered in the Utility Asset Disposition proceeding or in a

new generic proceeding. The Commission stated:

110. With respect to the submissions of AG and interveners regarding the correct

interpretation of the legislation and case law regarding production abandonment, the

review panel notes that in Decision 2012-154, the Commission stated that it would either

re-initiate the Utility Asset Disposition Rate Review Proceeding (Proceeding ID No. 20)

or establish a generic proceeding to address asset disposition and stranded assets after the

issuance of a Commission decision on the Rate Regulation Initiative (Proceeding ID No.

566). For the purposes of regulatory efficiency, the review panel considers that the

discussion regarding production abandonment and the Stores Block line of cases should

form part of either Proceeding ID No. 20 or the generic proceeding. To the extent that the

issue of previous settlement agreements impacts AG’s production abandonment costs,

this issue can be addressed either in Proceeding ID No. 20 or the generic proceeding. In

the interim, the Commission directs AG to maintain a placeholder of zero with respect to

these costs, to be adjusted upon completion of either Proceeding ID No. 20 or the generic

proceeding.9 (footnote omitted)

8. In a letter dated June 28, 2012,10 addressed to each of AltaGas Utilities Inc. (AltaGas),

AltaLink Management Ltd. (AltaLink), ATCO Utilities, ENMAX Power Corporation

(ENMAX), EPCOR Distribution & Transmission Inc. (EPCOR) and FortisAlberta Inc. (Fortis)

(collectively the Alberta Utilities), the Commission confirmed that the issue of risk with respect

to stranded assets, including whether or not the findings of the Commission would apply to the

2011 and 2012 test years, would be referred to the Utility Asset Disposition proceeding or to a

generic proceeding. The Commission stated:

In Decision 2012-154, the Commission found that “the issue of stranded assets and who

bears the risk in relation to stranded assets should be evaluated in the context of the

relevant legislation and case law and therefore expects to either re-initiate Proceeding ID

No. 20 or initiate a generic proceeding regarding asset disposition and stranded assets.”

The Commission has reviewed the Utilities’ letter and considers that the issues raised by

the Utilities will be determined as part of either Proceeding ID No. 20 or another generic

proceeding. In that proceeding, the Commission will consider whether its findings should

apply to 2011 and 2012 or prospectively. Following completion of either Proceeding ID

No. 20 or another generic proceeding, and if the matter has not already been addressed,

the Commission will establish a proceeding to determine whether any adjustments to the

fair return of the Utilities should be made for 2011 and 2012.11 (footnote omitted)

7 Decision 2012-156: ATCO Gas (a Division of ATCO Gas and Pipelines Ltd.), Decision on Request for Review

and Variance of AUC Decision 2011-450, Application No. 1608121, Proceeding ID No.1698, June 08, 2012. 8 Decision 2011-450: ATCO Gas (a Division of ATCO Gas and Pipelines Ltd.), 2011-2012 General Rate

Application Phase I, Application No. 1606822, Proceeding ID No. 969, December 5, 2011. 9 Decision 2012-156, paragraph 110, page 27.

10 Exhibit 24.01, Proceeding ID No. 1697: Applications to review and vary Decision 2011-474: 2011 Generic Cost

of Capital. 11

Commission letter dated June 28, 2012, paragraphs 8 and 9.





9. In Decision 2012-237,12 the distribution performance-based regulation (PBR) decision,

the Commission noted that it “will shortly issue bulletins to commence a proceeding on the

generic cost of capital and to either continue Proceeding ID No. 20 with respect to Utility Asset

Dispositions or initiate a generic proceeding regarding asset disposition and stranded assets.”13

10. In a letter dated October 17, 2012, the Commission recommenced the Utility Asset

Disposition proceeding to address Stores Block related matters. As part of the written process

schedule that was established, the Commission provided an opportunity for parties not

previously registered in the proceeding to file a statement of intention to participate (SIP) by

October 31, 2012. Similarly, any existing party to the proceeding that no longer intended to

participate was required to advise the Commission by October 31, 2012. The Commission

provided an updated issues list and requested comments from interested parties regarding

potential revisions to the issues list. Following review of the comments received, the

Commission issued a final revised issues list on December 7, 2012.

11. In Decision 2012-311,14 after noting that similar matters were raised in Decision

2012-154, the Commission determined that consideration of the costs associated with two former

AltaGas production well sites should be referred to the Utility Asset Disposition proceeding.

12. The following table summarizes the process steps followed subsequent to

recommencement of the proceeding on October 17, 2012:

Process step Deadline date

Statement of intent to participate November 30, 2012

Submissions on draft revised issues list November 30, 2012

Final issues list issued by the Commission December 7, 2012

Written submissions from all parties January 16, 2013

Information requests to all parties February 1, 2013

Information request responses from all parties February 22, 2013

Rebuttal evidence from all parties March 15, 2013

Argument from all parties May 3, 2013

Reply argument from all parties June 3, 2013

Commission supplemental information requests to parties June 25, 2013

Supplemental information responses from parties July 31, 2013

Supplemental argument from parties August 23, 2013

Supplemental reply argument from parties August 28, 2013

13. During the course of the proceeding, evidence was received from the Alberta Utilities,

the Office of the Utilities Consumer Advocate (UCA), The City of Calgary (Calgary), and

TransAlta Corporation.

14. The Commission considers that the record for the proceeding closed on August 28, 2013.

12 Decision 2012-237: Rate Regulation Initiative, Distribution Performance-Based Regulation, Application

No. 1606029, Proceeding ID No. 566, September 12, 2012. 13

Decision 2012-237, paragraph 1002, page 213. 14

Decision 2012-311 (Errata): AltaGas Utilities Inc., 2010-2012 General Rate Application – Phase I Compliance

Filing Pursuant to Decision 2012-091, Application No. 1608512, Proceeding ID No. 1921, December 5, 2012.


http://www.auc.ab.ca/applications/decisions/Decisions/2012/2012-311%20(Errata).pdf



15. In reaching the determinations set out within this decision, the Commission has

considered all relevant materials comprising the record of this proceeding, including the

evidence, argument and reply argument and supplements thereto, provided by each party.

Accordingly, references in this decision to specific parts of the record are intended to assist the

reader in understanding the Commission’s reasoning relating to a particular matter and should

not be taken as an indication that the Commission did not consider all relevant portions of the

record with respect to that matter.

16. This decision will first provide an overview of judicial and Alberta regulatory decisions

before and after Stores Block, then it will review the comments received from parties on the final

revised issues list, followed by the findings of the Commission.

2 Overview of judicial and Alberta regulatory decisions before and after Stores

Block

Introduction 2.1

17. This section reviews the development of the regulatory and case law, primarily Alberta

based, related to the sale or removal of assets from utility rate base before and after the Supreme

Court of Canada’s decision in Stores Block. Specifically, this overview will review decisions

related to:

(i) the requirement of Section 26(2) of the Gas Utilities Act, RSA 2000, c. G-5 and Section

101(2) of the Public Utilities Act, RSA 2000, c. P-4515 for prior regulatory approval of a

disposition of an asset by a designated utility outside of the ordinary course of business

(ii) the removal from utility rate base and customer rates of assets that are no longer “used or

required to be used to provide service to the public within Alberta” as that term is used in

Section 37(1) of the Gas Utilities Act and Section 90(1) of the Public Utilities Act

18. This review is intended to provide a context for the discussion of the matters before the

Commission in this proceeding. It is anticipated that this decision will assist parties in future

related proceedings by providing clarity on the Commission’s treatment of these matters leading

to increased regulatory efficiency. This anticipated benefit was noted by the Commission in its

correspondence of October 17, 2012, recommencing this proceeding when it stated:

…the Commission expects the interpretations and principles established by this

proceeding to be applied in relevant future applications, subject always to the ability of

parties to argue that they should not be applied in the particular circumstances of a

specific application.16

Regulatory practice in Alberta before TransAlta 2.2

19. Section 26(2)(d) of Gas Utilities Act and Section 101(2)(d) of the Public Utilities Act

require a utility designated under Section 26(1) or 101(1) respectively, to obtain Commission

approval before it may “sell, lease, mortgage or otherwise dispose of or encumber its property,

franchises, privileges or rights, or any part of it or them,” outside the “ordinary course of the

15

See Appendix 2, Summary of Alberta legislation. 16

Exhibit 54.01, paragraph 13.



owner’s business.” The legislation provides that a sale or other disposition concluded without

such approval is void.

20. Upon application of a utility for approval of an asset disposition, the Commission’s

predecessors17 have applied a “no harm test” to determine if ratepayers could be negatively

impacted by a proposed transaction.18 This no harm test was also used by the regulator to assess

applications relating to the sale of a utility’s business and with respect to the merger of utilities.

Harm can result either through higher rates or by degradation of service. If a proposed

transaction resulted in a material harm to customers that could not otherwise be mitigated, the

regulator would deny the application.

21. Prior to the Alberta Court of Appeal’s decision in TransAlta Utilities Corporation v.

Alberta (Public Utilities Board), (1986) 68 A.R. 171 (TransAlta) the Alberta regulator generally

allocated the entire gain or loss arising on an approved sale of a specific utility asset to the

customers of the utility. In Order E8411519 the Public Utilities Board (PUB) explained the

regulatory practice followed before TransAlta whereby customers benefited from gains on sale

and also absorbed losses when it considered the sale of a water franchise by TransAlta Utilities

Corporation (TransAlta Corp.) to the County of Strathcona No. 20. The PUB stated:

In Alberta, under the provisions of the Public Utilities Board Act, all utility assets that are

used or required to be used to provide service to utility customers are permitted to be

included in the rate base of the utility at the original cost of those assets (assuming the

original cost is prudent). In fixing and approving customer rates, the Board is required to

fix a fair return on the rate base. The fair return forms part of the revenue requirement of

the utility. The Board also fixes the depreciation rate to be applied to the assets which

form the rate base and the resulting depreciation expense also forms part of the revenue

requirement of the utility. The revenue requirement is funded through customer rates

which are approved as just and reasonable by the Board.

Through this process or mechanism, the Board is required to be satisfied that the owner

of the utility is given the opportunity to earn a return of his investment in the utility assets

and a fair return on his investment in those assets. At the same time the Board is required

to be satisfied that the customers are paying just and reasonable rates for the utility

service they receive.

The Board generally takes into account, inter alia, any relevant evidence with respect to

inflation or deflation in the test year or test years in fixing the fair return on rate base.

Therefore, as a general rule, the Board considers that any profit or loss (being the

difference between the net book value of the assets and the sale price of those assets)

17

Public Utilities Board and the Alberta Energy and Utilities Board. 18

The Alberta Energy and Utilities Board summarized the general principles of the “no-harm” test in several

decisions, including: Decision 2000-41: TransAlta Utilities Corporation, Sale of Distribution Business,

Application No. 2000051, July 5, 2000, and in Decision 2001-65, ATCO Gas – North (A Division of ATCO

Gas and Pipelines Ltd.), Sale of Certain Petroleum and Natural Gas Rights, Production and Gathering Assets,

Storage Assets and Inventory: Reasons for Decision 2001-46, Application Nos. 2001017, 2001020, 2001030 &

2001070, July 31, 2001. 19

Order No. E84115: TransAlta Utilities Corporation, IN THE MATTER OF an Application by TransAlta

Utilities Corporation to the PUB for an Order or Orders approving the sale to the County of Strathcona No. 20

of all the property, franchises, privileges or rights used to supply water to customers within Sherwood Park,

Alberta, File No. E3.11.87(1) (g)-4, October 12, 1984.



resulting from the disposal of utility assets should accrue to the benefit of the customers

of the utility and not to the shareholders of the utility.20

22. Despite this general rule, however, the PUB approved the request of TransAlta Corp. to

retain the loss on sale for the shareholders because it was exiting the water utility business and it

was unfair to pass on the loss to electricity customers when the water assets did not form part of

the electric utility rate base.

23. The PUB commented further on the state of affairs prior to TransAlta in Decision

E84113,21 a proceeding which dealt with the sale of land and a building by Canadian Western

Natural Gas Company Limited to the Town of Okotoks. Both the land and the building were sold

for a gain over net book value. In awarding the gain on sale to customers, the PUB stated:

Therefore, as a general rule, the Board considers that any profit of loss (being the

difference between the net book value of the assets and the sale price of those assets)

resulting from the disposal of utility assets should accrue to the benefit of the customers

of the utility and not to the shareholders of the utility.

Depending upon the circumstances of each case (including the matter of prudency of

management of the utility in the acquisition and disposal of utility assets), the Board

considers that no exception to the general rule should be made whether or not the

transaction is in the ordinary course of business of the utility. This is not to say that the

question of “in the ordinary course of business” is irrelevant when considering the

Board’s approval under section 91(1)(h) of the Public Utilities Board Act.

Furthermore, the Board considers that, depending upon the circumstances of each case,

no exception to the general rule should be made whether the transaction involves

depreciable or non-depreciable utility assets.22

24. The position reflected in the above cases was summarized by the Alberta Energy and

Utilities Board (EUB) in Decision 2001-6523 where it stated:

...the treatment of any gain or loss on sale of utility assets would depend on the merits of

a particular case. It was noted, however, that prior to the decision of the Alberta Court of

Appeal in TransAlta Utilities Corporation v. Alberta (Public Utilities Board), the Board

had adopted a general rule that any difference between the NBV of utility assets included

in rate base and the sale proceeds of those assets should accrue to customers, whether the

difference was positive or negative.24 (footnote omitted)

20

PUB Order E84115, pages 12 to 16. 21

Decision No. E84113: Canadian Western Natural Gas Company Limited, In the matter of an Application by

Canadian Western Natural Gas Company Limited respecting the sale of certain property, File No.

E4.7.24(2)(g)-4, October 12, 1984. 22

Decision No. E84116: TransAlta Utilities Corporation and City of Edmonton, In the matter of an Application by

TransAlta for an Order or Orders of the PUB approving the disposition of a part of its property, franchises,

privileges or rights to the City of Edmonton, File No. E3.6.87(1)(g)-5, October 12, 1984, pages 19-20. 23

Decision 2001-65: ATCO Gas – North, a Division of ATCO Gas and Pipelines Ltd., Sale of Certain Petroleum

and Natural Gas Rights, Production and Gathering Assets, Storage Assets and Inventory: Reasons for Decision

2001-46, Application Nos. 2001017, 2001020, 2001030 & 2001070, File Nos. 6405-14, 6405-15, 6405-16 &

6405-18, July 31, 2001. 24

Decision 2001-65, page 11.




25. TransAlta modified and clarified the regulatory practice in Alberta with respect to the

allocation of a gain or loss arising upon sale of a utility asset outside of the ordinary course of

business. The case involved a partial loss of franchise and service area by TransAlta Corp. upon

the enlargement of the boundaries of the City of Edmonton through annexation. The

compensation paid to TransAlta Corp. was based on the reproduction cost new; less depreciation

methodology stated in the Hydro and Electric Energy Act, RSA 2000, c. H-16. In Decision

E84116 the PUB directed that the gain over net book value realized by TransAlta Corp. in the

disposition to Edmonton of the utility assets within the annexed service area should accrue to the

benefit of customers. The Court of Appeal disagreed in part, concluding:

The decisive point is that present value of plant was chosen for calculation of fair

compensation under the Hydro and Electric Energy Act for partial loss of franchise...The

Board, when it is calculating revenue, must respect that legislative object. The Board

order here nullifies the effect of the Hydro and Electric Energy Act...25

26. The court approved the PUB allocation from the purchase price of an amount equal to the

net book value to shareholders. The court also approved an allocation to customers of an amount

based on the depreciation paid to date by customers directing that “the present value of the

depreciation allowance should be accounted for as revenue,”26 thereby decreasing rates. The

court made this determination because: “[T]o the extent, then, that allowance for depreciation

has been made, the original investment has already been returned to the investors.”27 The balance

of the proceeds, however, were allocated by the court to the utility and its shareholders, stating:

“[s]ubject to the depreciation allowance, the proceeds must be deemed to be the present value of

this portion of the rate base, and should not be assigned to revenue.”28 Amounts, other than the

net book value, were to be adjusted for inflation because of the reproduction cost new; less

depreciation methodology used in calculating the price paid by Edmonton to TransAlta Corp.

Regulatory practice in Alberta after TransAlta 2.3

27. The EUB’s interpretation and application of TransAlta was explained in

Decision 2001-65 which incorporated the findings of the EUB in Decision 2001-41.29 The EUB

stated in Decision 2001-65:

In the TransAlta Appeal, the Court of Appeal held that the Board had erred in that case in

allocating all of the gain on disposition of assets to customers. The Court agreed, in

principle, that shareholders were entitled to a return of the NBV and customers were

entitled to a return of depreciation expense paid through their rates. However, the Court

held that compensation should be in terms of current dollars, with current dollars being

measured by the ratio of the actual sale price to original cost of the assets.

In Decision 2000-41, the Board summarized its interpretation and subsequent application

of the TransAlta Appeal as follows:

In subsequent decisions, the Board has interpreted the Court of Appeal’s

conclusion to mean that where the sale price exceeds the original cost of

25

TransAlta, page 10. 26




Decision 2001-41: ESBI Alberta Ltd., 2001 General Tariff Application, Part J: Refiling of Revenue

Requirement and Tariff Calculations for DTA Rates, Application No. 2000135, File No. 1804-1, May 17, 2001.




the assets, shareholders are entitled to net book value (in historical

dollars), customers are entitled to the difference between net book value

and original cost, and any appreciation in the value of the assets (i.e. the

difference between original cost and the sale price) is to be shared by

shareholders and customers. The amount to be shared by each is

determined by multiplying the ratio of sale price/original cost to the net

book value (for shareholders) and the difference between original cost

and net book value (for customers). However, where the sale price does

not exceed original cost, customers are entitled to all of the gain on sale.

This approach to the allocation of sale proceeds has been referred to by several parties to

the current proceedings, including AGN, as the “TransAlta Formula”. The Board will use

this phrase for ease of reference.

In Decision 2000-41, the Board summarized what it considers to be the general rule with

respect to allocation of gains or losses on sales of utility assets:

The Board accepts that where particular rate base assets are being sold so

that they are no longer part of the regulated rate base, the disposition of

the gain on sale should, as a general rule, be treated according to the

principle set out by the Court of Appeal in the TransAlta Appeal and

subsequently applied by the Board.

For the purpose of this Decision, the Board confirms this general rule but notes once

again that it will be subject to the particular circumstances of the case. (footnotes

omitted)

28. When considering applications to dispose of utility assets outside of the ordinary course

of business the EUB applied the TransAlta Formula only if there was a gain on sale and only

after a consideration of the no harm test. The EUB first considered if there was harm to

ratepayers and if there was, a gain on sale could be applied to mitigate the harm. The gain on sale

would again be considered in the context of an allocation between shareholders and customers in

accordance with the TransAlta Formula. The EUB explained this analysis as follows:

...the Board is of the view that the no-harm amounts calculated for each Application are

threshold amounts. In other words, they represent the minimum amount that must be paid

to customers to save them harmless from the impacts of the proposed sales. However, in

some circumstances, the Board is of the view that customers may be entitled to more than

the no-harm amount. For the reasons given in Section 4.2 of this Decision, the Board

considers that it has the jurisdiction to do so.

In the Board’s view, if the TransAlta Formula yields a result greater than the no-harm

amount, customers are entitled to the greater amount. If the TransAlta Formula yields a

result less than the no-harm amount, customers are entitled to the no-harm amount. In the

Board’s view, this approach is consistent with its historical application of the TransAlta

Formula.

As explained in Decision 2000-41, according to the Board’s application of the TransAlta

Formula:



shareholders are entitled to a return of NBV;

customers are entitled to a return of excess depreciation (i.e. the

difference between NBV and original cost); and

any excess of sale proceeds over original cost should be shared according

to the ratio prescribed by the Court of Appeal in the TransAlta Appeal.

It should be noted that it is only when sale proceeds are greater than original cost that a

“current dollar” sharing of proceeds is necessary pursuant to the TransAlta Formula.30

29. As a result of the EUB’s application of the no harm test and the TransAlta Formula, if the

EUB determined that customers would be harmed by the proposed transaction, but that the harm

could be mitigated by application of a gain on sale of the asset, the EUB would consider

approving the transaction and applying all or a portion of the realized gain on sale as a credit to

rates by way of mitigation of the harm. The EUB would also apply the TransAlta Formula to the

gain and customers would receive a credit for the larger of the no harm amount and the amount

allocated under the TransAlta Formula. The EUB summarizes its jurisdiction to apply the

proceeds of disposition in this manner in the following extract from Decision 2001-65:

The Board considers that its power to mitigate or offset potential harm to customers by

allocating part or all of the sale proceeds to them, flows from its very broad mandate to

protect consumers in the public interest. This mandate has been recognized by the Alberta

Court of Appeal25

and the Supreme Court of Canada.26

It has also been referred to

recently on a number of occasions by the Board.27

In keeping with this broad mandate,

section 10(3)(d) of the Alberta Energy and Utilities Board Act28

authorizes the Board to

attach conditions to any order that the Board considers to be in the public interest. In the

Board’s view, conditions allocating sale proceeds to customers in order to mitigate harm

caused by proposed asset dispositions are fully within its jurisdiction as characterized by

the courts and reflected in the Board’s governing legislation.31

_______________ 25

Dome Petroleum Ltd. v. Alberta (Public Utilities Board) (1976) 2 A.R. 453, affd. [1977] 2

S.C.R. 822. 26

ATCO Ltd. v. Calgary Power Ltd. [1982] 2 S.C.R. 557, at 576 (per Estey J.). 27

For example, Decision 2000-41,[32]

p 7; and Decision 2000-46,[33]

ESBI Alberta Ltd.,

2001General Tariff Application, Phase I & II, Part A: System Support Services – Thermal Power

Purchase Arrangements (Appendix E) (July 11, 2000), p. 9. 28

S.A. 1994, c. A-19.5, as amended.

30. In cases where an approved disposition outside of the ordinary course resulted in sale

proceeds less than the original cost, a sharing under the TransAlta Formula was not required. In

these cases the previous rule still generally applied with the utility receiving proceeds in an

30

Decision 2001-65, pages 41 to 42. 31

Decision 2001-65, page 16 32

Decision 2000-41: TransAlta Utilities Corporation, Sale of Distribution Business, Application No. 2000051,

File No. 6404-3, July 5, 2000. 33 Decision 2000-46: ESBI Alberta Ltd., 2001 General Tariff Application Phase I & II Part A: System Support

Services – Thermal Power Purchase Arrangements (Appendix E), Application No. 2000135, File No. 1804-1,

July 11, 2000.

http://www.auc.ab.ca/applications/decisions/Decisions/2000/2000-41.pdfhttp:/www.auc.ab.ca/applications/decisions/Decisions/2000/2000-41.pdf




amount equal to the net book value and the balance going to customers.34 In the event that

proceeds were less than net book value, creating a loss, customers continued to bear the loss.35

31. In Decision 2002-037,36 the EUB dealt with the allocation of net proceeds, including a net

gain, arising from the sale by ATCO Gas of its Calgary Stores building and property, collectively

referred to as the “Stores Block.” The EUB found that ATCO Gas had satisfied the no harm test

in an earlier decision37 and the sale transaction was allowed to proceed. Decision 2002-037

confirmed the no harm finding and allocated the proceeds of sale, including the $5.4 million net

gain (equal to the difference between the purchase price less the original cost) between the utility

and customers. ATCO Gas was allocated from the net sale proceeds an amount equal to the net

book value and customers were allocated an amount equal to the accumulated depreciation. The

gain on sale, was allocated between utility shareholders and customers in accordance with the

TransAlta Formula. As a result, the $5.4 million net gain on sale was allocated $1.8 million to

utility shareholders and $3.6 million to customers.

32. Decision 2002-037 was appealed to the Alberta Court of Appeal38 which overturned the

EUB’s decision in part. The court indicated that “[c]onsumers of utilities pay for a service, but

by such payment, do not receive a proprietary right in the assets of the utility company.”39 The

court directed that the proceeds of sale, less an amount equal to accumulated depreciation, be

credited to the utility. A portion of the sale proceeds equal to accumulated depreciation remained

credited to customers. Leave to Appeal was subsequently granted by the Supreme Court of

Canada. As noted above, the Supreme Court of Canada’s decision is reported as ATCO Gas and

Pipelines Ltd. V. Alberta (Energy and Utilities Board) [2006] 1 S.C.R. 140, [2006] S.C.J. No.4,

2006 SCC 4 and is referred to as Stores Block in this decision.

Stores Block 2.4

33. In Stores Block the Supreme Court of Canada determined that the EUB did not have the

jurisdiction to allocate to ratepayers any portion of the sale proceeds arising from the sale of an

asset outside the ordinary course of business of a designated gas utility. In making this

determination, the Supreme Court of Canada overturned the portion of the Alberta Court of

Appeal’s decision which allocated to ratepayers a portion of the sale proceeds equal to the

accumulated depreciation on the depreciable assets sold by the utility. The court also found that

34

See for example PUB Order E93023, dated March 17, 1993, where the PUB approved a disposition of certain

properties owned by Northwestern Utilities Limited where proceeds did not exceed original cost. The utility

was entitled to recover the remaining net book value and customers were allocated the balance of the proceeds. 35

See for example:

● EUB Order U2001-143, Application No. 2001079, dated June 15, 2001, which approved the sale of the

Operations Centre of NOVA Gas Transmission Ltd. for less than book value in connection with the merger

of NOVA Gas Transmission Ltd. and TransCanada Pipelines Limited.

● EUB Order U2001-196, Application No. 2001112 dated August 3, 2001, in connection with the sale of the

Athabasca Maintenance Facility of NOVA Gas Transmission Ltd. for less than book value.

● EUB Decision 2001-108, UtiliCorp Networks Canada (Alberta) Ltd., Disposition of the High River

Facility, Application No. 2001145, dated December 11, 2001, which approved the disposition of

UtiliCorp’s High River facility for an amount less than book value. 36

Decision 2002-037: ATCO Gas and Pipelines Ltd., Disposition of Calgary Stores Block and Distribution of Net

Proceeds – Part 2, Application No. 1247130, File No. 6405-17-2, March 21, 2002. 37

Decision 2001-78: ATCO Gas and Pipelines Ltd., Disposition of Calgary Stores Block and Distribution of Net

Proceeds – Part 1, Application No. 1243019, October 24, 2001. 38

ATCO Gas & Pipelines Ltd. v. Alberta (Energy & Utilities Board), 2004 ABCA 3. 39

ATCO Gas & Pipelines Ltd. v. Alberta (Energy & Utilities Board), 2004 ABCA 3, paragraph 64.




the ability to allocate sale proceeds could not be implied from the statutory regime as necessarily

incidental to the explicit powers granted the EUB.40

34. The Supreme Court of Canada observed that “[a]dministrative tribunals or agencies are

statutory creations: they cannot exceed the powers that were granted to them by their enabling

statute.”41 Further, while “[d]iscretion is central to the regulatory agency policy process,… in

exercising this discretion, statutory bodies must respect the confines of their jurisdiction: they

cannot trespass in areas where the legislature has not assigned them authority.”42

35. The court directed that all net proceeds of sale arising from the sale of ATCO Gas’s

“Stores Block” building and property be allocated to the utility. In making this determination the

court emphasised that the EUB’s statutory powers are grounded in its rate making function. The

court stated:

The interpretation of the Alberta Energy and Utilities Board Act, R.S.A. 2000, c. A-17

("AEUBA"), the Public Utilities Board Act, R.S.A. 2000, c. P-45 ("PUBA"), and the Gas

Utilities Act, R.S.A. 2000, c. G-5 ("GUA") (see Appendix for the relevant provisions of

these three statutes), can lead to only one conclusion: the Board does not have the

prerogative to decide on the distribution of the net gain from the sale of assets of a utility.

The Board's seemingly broad powers to make any order and to impose any additional

conditions that are necessary in the public interest has to be interpreted within the entire

context of the statutes which are meant to balance the need to protect consumers as well

as the property rights retained by owners, as recognized in a free market economy. The

limits of the powers of the Board are grounded in its main function of fixing just and

reasonable rates ("rate setting") and in protecting the integrity and dependability of the

supply system.43

36. The Supreme Court of Canada acknowledged the no harm test employed by the EUB

when considering applications under Section 26(2) of the Gas Utilities Act and commented that

the EUB was able to carry out its statutory responsibilities without allocating the proceeds of

disposition to customers. The court stated:

In fact, it is not necessary for the Board in carrying out its mandate to order the utility to

surrender the bulk of the proceeds from a sale of its property in order for that utility to

obtain approval for a sale. The Board has other options within its jurisdiction which do

not involve the appropriation of the sale proceeds, the most obvious one being to refuse

to approve a sale that will, in the Board's view, affect the quality and/or quantity of the

service offered by the utility or create additional operating costs for the future.44

37. The court clearly stated that the property employed by the utility in providing utility

service to customers belongs solely to the utility and its shareholders. The regulatory compact

does not transfer a property right to customers. In making this point the court commented as

follows:

These goals have resulted in an economic and social arrangement dubbed the "regulatory

compact", which ensures that all customers have access to the utility at a fair price --

40

Stores Block, paragraphs 39, 52, 75, and 77. 41

Stores Block, paragraph 35. 42



Stores Block, paragraph 77. Also see paragraph 13 with respect to no harm test.



nothing more. As I will further explain, it does not transfer onto the customers any

property right. Under the regulatory compact, the regulated utilities are given exclusive

rights to sell their services within a specific area at rates that will provide companies the

opportunity to earn a fair return for their investors. In return for this right of exclusivity,

utilities assume a duty to adequately and reliably serve all customers in their determined

territories, and are required to have their rates and certain operations regulated.45

...The object of the statutes is to protect both the customer and the investor (Milner, at p.

101). The arrangement does not, however, cancel the private nature of the utility. In

essence, the Board is responsible for maintaining a tariff that enhances the economic

benefits to consumers and investors of the utility.46

...Thus, can it be said, as alleged by the City, that the customers have a property interest

in the utility? Absolutely not: that cannot be so, as it would mean that fundamental

principles of corporate law would be distorted. Through the rates, the customers pay an

amount for the regulated service that equals the cost of the service and the necessary

resources. They do not by their payment implicitly purchase the asset from the utility's

investors. The payment does not incorporate acquiring ownership or control of the

utility's assets. The ratepayer covers the cost of using the service, not the holding cost of

the assets themselves.47

38. Further, it is the utility and its shareholders that benefit from gains on the sale of utility

property and who must bear any loss arising from such sale. On this point the court stated:

The fact that the utility is given the opportunity to make a profit on its services and a fair

return on its investment in its assets should not and cannot stop the utility from benefiting

from the profits which follow the sale of assets. Neither is the utility protected from

losses incurred from the sale of assets. ...ownership of the assets is clearly that of the

utility; ownership of the asset and entitlement to profits or losses upon its realization are

one and the same.48

...Despite the consideration of utility assets in the rate-setting process, shareholders are

the ones solely affected when the actual profits or losses of such a sale are realized; the

utility absorbs losses and gains, increases and decreases in the value of assets, based on

economic conditions and occasional unexpected technical difficulties, but continues to

provide certainty in service both with regard to price and quality.49

...The capital invested is not provided by the public purse or by the customers; it is

injected into the business by private parties who expect as large a return on the capital

invested in the enterprise as they would receive if they were investing in other securities

possessing equal features of attractiveness, stability and certainty (see Northwestern

1929, at p. 192). This prospect will necessarily include any gain or loss that is made if the

company divests itself of some of its assets, i.e., land, buildings, etc.50

45






Stores Block, paragraph 70.



39. With respect to who bears the residual risk faced by a utility the court stated:

Ratepayers have made no investment. Shareholders have and they assume all risks as the

residual claimants to the utility's profit. Customers have only "the risk of a price change

resulting from any (authorized) change in the cost of service. This change is determined

only periodically in a tariff review by the regulator" (MacAvoy and Sidak, at p. 245).51

40. The Supreme Court of Canada also stated that an attachment of sale proceeds could not

be characterized as a refund of excessive rates paid by customers over time. Paragraph 71 of the

Stores Block decision provides:

From my discussion above regarding the property interest, the Board was in no position

to proceed with an implicit refund by allocating to ratepayers the profits from the asset

sale because it considered ratepayers had paid excessive rates for services in the past. As

such, the City's first argument must fail. The Board was seeking to rectify what it

perceived as a historic over-compensation to the utility by ratepayers. There is no power

granted in the various statutes for the Board to execute such a refund in respect of an

erroneous perception of past over-compensation. It is well established throughout the

various provinces that utilities boards do not have the authority to retroactively change

rates (Northwestern 1979, at p. 691; Re Coseka Resources Ltd. and Saratoga Processing

Co. (1981), 126 D.L.R. (3d) 705 (Alta. C.A.), at p. 715, leave to appeal refused, [1981] 2

S.C.R. vii; Re Dow Chemical Canada Inc. (C.A.), at pp. 734-35 ). But more importantly,

it cannot even be said that there was over-compensation: the rate-setting process is a

speculative procedure in which both the ratepayers and the shareholders jointly carry

their share of the risk related to the business of the utility (see MacAvoy and Sidak, at pp.

238-39).52

41. Although the court indicated that the EUB did not have the jurisdiction to allocate to

customers the gain on sale of a utility asset, it did indicate that the EUB could, in certain

circumstances, attach conditions to granting an approval for selling an asset. The court stated:

This is not to say that the Board can never attach a condition to the approval of sale. For

example, the Board could approve the sale of the assets on the condition that the utility

company gives undertakings regarding the replacement of the assets and their

profitability. It could also require as a condition that the utility reinvest part of the sale

proceeds back into the company in order to maintain a modern operating system that

achieves the optimal growth of the system.53

42. In addition, the court indicated that the EUB could in a rate setting context, consider the

impact of an approved sale transaction. In this regard, the court stated that the EUB could have

convened “a hearing of the interested parties in order to modify and fix just and reasonable rates

to give due consideration to any new economic data anticipated as a result of the sale.”54

43. With respect to assets that are sold within the ordinary course of business, the court

pointed out that Section 26(2) does not apply.55 The court also considered that Section 26(2) had

limited application to assets that were non-utility in character stating:

51








In fact, s. 26(2) can only have limited, if any, application to non-utility assets not related

to utility function (especially when the sale has passed the "no-harm" test). The provision

can only be meant to ensure that the asset in question is indeed non-utility, so that its loss

does not impair the utility function or quality.56

Alberta Court of Appeal decisions subsequent to Stores Block 2.5

44. Following Stores Block the EUB and/or the Commission, and subsequently the Alberta

Court of Appeal, considered a number of cases that referenced Stores Block. These decisions are

reviewed briefly below.

2.5.1 Carbon

45. ATCO Gas owned and included in utility rate base for many years a natural gas

production field which it subsequently converted primarily into a natural gas storage facility

(Carbon Storage). Carbon Storage was used for various utility purposes over the years including

natural gas supply, managing peak utility supply requirements, system load balancing,

emergency use and revenue generation through the lease of excess storage capacity to third

parties. Following deregulation of natural gas prices and the sale of ATCO Gas’s retail function

to Direct Energy Regulated Services, all uses for the Carbon Storage facility other than revenue

generation were discontinued. As a result of these developments, ATCO Gas took the position

that Carbon Storage was no longer “used or required to be used to provide service to the public,”

and was therefore not properly part of its rate base under Section 37 of the Gas Utilities Act.

46. In Decision 2007-00557 the EUB determined, that given the unique historical

circumstances of Carbon Storage, the asset continued to be used or required to be used to provide

a service to the public, namely revenue generation, and should be retained in rate base.58

47. The Alberta Court of Appeal overturned the EUB’s decision in ATCO Gas and Pipelines

Ltd. v. Alberta (Energy and Utilities Board) 2008 ABCA 200, leave to appeal to Supreme Court

of Canada refused, 32761 (December 4, 2008) (Carbon). The court found that the EUB had erred

in law or jurisdiction when it included Carbon Storage in rate base as an asset “used or required

to be used to provide service to the public within Alberta” when the only remaining function for

those facilities was to generate revenue. The court stated:

Section 37 of the Act is primarily forward looking. The Board’s jurisdiction is to set rates

“afterwards”, that is for the future: Northwestern Utilities v. City of Edmonton, [1979] 1

S.C.R. 684 at pg. 691. The words “used or required to be used” are intended to identify

assets that are presently used, are reasonably used, and are likely be used in the future to

provide services. Specifically, the past or historical use of assets will not permit their

inclusion in the rate base unless they continue to be used in the system. The fact that the

Carbon storage facility was previously used to provide service may provide some

context, but it is largely irrelevant to whether that asset should remain in the rate base.59

48. The court determined that “the only reasonable reading of s. 37 is that the assets that are

‘used or required to be used’ to provide service are only those used in an operational sense.”60 It

56


Decision 2007-005: ATCO Gas South, Carbon Facilities - Part 1 Module – Jurisdiction, (2005/2006 Carbon

Storage Plan), Application No. 1357130, February 5, 2007. 58

Decision 2007-005, page 27. 59

Carbon, paragraph 23. 60

Carbon, paragraph 25.




found that the failure of the EUB “to recognize the fundamental change in the role played by the

Carbon storage facility once it lost all of its operational purposes was unreasonable.”61 The court

went on to state: “[i]f the Carbon storage facility does not now meet the requirements of s. 37,

the appellant is entitled to a ruling to that effect.”62

49. The court further found that the concept of assets remaining in rate base indefinitely was

contrary to the Stores Block decision. The court stated:

The Act does not contain any provision or presumption that once an asset is part of the

rate base, it is forever a part of the rate base regardless of its function. The concept of

assets becoming “dedicated to service” and so remaining in the rate base forever is

inconsistent with the decision in Stores Block (at para. 69). Such an approach would

fetter the discretion of the Board in dealing with changing circumstances. Previous

inclusion in the rate base is not determinative or necessarily important; as the Court

observed in Alberta Power Ltd. v. Alberta (Public Utilities Board) (1990), 72 Alta. L.R.

(2d) 129, 102 A.R. 353 (C.A.) at pg. 151: "That was then, this is now."63

50. The Court of Appeal referred to the finding in Stores Block that customers do not obtain

an ownership interest in the assets of the utility in holding that the same principle applies to the

revenues generated from those assets. The court stated:

The service that they are entitled to is the delivery of gas on reasonable and just terms,

not revenue generation. Just as the end customers have no ownership interest in the assets

of the utility, they have no interest in the profits, unregulated revenues, or unregulated

businesses of the utility.64

2.5.2 Harvest Hills

51. EUB Decision 2007-10165 related to an application by ATCO Gas to subdivide certain

lands in the Harvest Hills area of Calgary which were included in rate base. The portion of the

subdivided lands being used for utility purposes would be retained in rate base and the remaining

portion of the lands (vacant property) would be sold to a third party with the net proceeds of sale

being retained by the utility shareholder.

52. The EUB applied the no harm test to the proposed transaction and determined that

financial harm would result to customers because ATCO Gas anticipated the need to construct

new facilities with a five kilometre radius of the Harvest Hills property within five years which

would require the acquisition of new property.

53. The EUB considered whether approval of the sale transaction could be conditioned to

attach the proceeds of sale in a manner contemplated by paragraph 77 of the Stores Block

decision where the Supreme Court of Canada stated:

This is not to say that the Board can never attach a condition to the approval of sale. For

example, the Board could approve the sale of the assets on the condition that the utility

company gives undertakings regarding the replacement of the assets and their

61





Decision 2007-101: ATCO Gas, Disposition of Land in the Harvest Hills Area, Application No. 1512932,

December 11, 2007.




profitability. It could also require as a condition that the utility reinvest part of the sale

proceeds back into the company in order to maintain a modern operating system that

achieves the optimal growth of the system.66

54. The EUB indicated that the “financial harm could possibility be mitigated through the

application of the net proceeds from the sale of the Harvest Hills Property to partially offset the

acquisition and construction costs of these new facilities, facilities that are required to maintain a

modern operating system and continued optimal growth of the distribution system.”67 The EUB

concluded that a condition could be attached to its approval of the sale transaction, stating:

…the Board believes that the most effective way to proceed with the application would

be a conditional sale approval in the manner described in paragraph 77 of the Stores

Block Decision. The Board is prepared to allow AG to sell the Harvest Hills Property,

under the condition that the gain on sale (which is to be calculated as the sale proceeds

less the original cost less prudently incurred disposition costs) be placed in a deferral

account.68

55. The disposition of the deferral account would be considered in the next general rate

application.

56. The Alberta Court of Appeal overturned the EUB’s decision in ATCO Gas and Pipelines

Ltd. v. Alberta (Energy and Utilities Board), 2009 ABCA 171, leave to appeal to Supreme Court

of Canada refused, 33269 (January 28, 2010) (Harvest Hills). In commenting on the finding of

the EUB of financial harm to customers, the court referred to the Stores Block and Carbon

decisions and commented as follows:

31…The Board's "no harm" test is well established and has been acknowledged by this

Court in its Stores Block decision (ATCO Gas and Pipelines Ltd. v. Alberta (Energy and

Utilities Board), 2004 ABCA 3, 339 A.R. 250 (at para.18) and by the Supreme Court

(Stores Block para. 13). The Board found financial harm in the fact that ATCO would

require more land to build facilities within four or five kilometres of the Harvest Hills

property. This geographic area was arbitrarily selected by the Board, and the new

facilities to be built within it had no direct relationship to the Harvest Hills lands. ATCO

indicated that this would be needed in approximately five years. As the cost of the land

would be significantly higher than the cost of the Harvest Hills property, the Board

reasoned that customers would be harmed financially.

32 In Stores Block, the Board found that there would be no harm to customers as a

result of the sale. In the Supreme Court, Bastarache J. observed that even by the Board's

own reasoning, it should only exercise its discretion to act in the public interest when

customers would be harmed or would face some risk of harm (at para. 84). In our view,

the harm contemplated by the Supreme Court must be harm related to the transaction

itself. Here, the Board found that there would be no harm to customers in terms of quality

or quantity of service as a result of the sale. Indeed, once the Harvest Hills property was

removed from the rate base, there would be a small reduction in the cost to customers.

Merely because the utility has plans to spend funds on capital assets in the future cannot

be "harm" in any logical sense. As the appellant points out, these expenditures will be

incurred independently of the sale of the Harvest Hills property. The Board's proposal to

subsidize those future expenditures by diverting the sale proceeds of the Harvest Hills

66


Decision 2007-101, pages 5 and 6. 68

Decision 2007-101, page 6.



property is effectively an appropriation of the sale proceeds to subsidize rates. This was

prohibited in Carbon (at para. 30). "Financial harm" resulting from the denial of access to

a revenue stream that could be used to subsidize rates is not properly characterized as

"harm" in this context. Accordingly, this rationale in support of the imposition of the

condition is unreasonable.69

57. The court went on to find:

Like the assets in Stores Block and Carbon, the Harvest Hills lands were once

legitimately included in the rate base. Absent the condition imposed by the Board, this

case is indistinguishable from Stores Block.70

58. With respect to paragraph 77 of the Stores Block decision and the circumstances in which

the regulator may place a condition on its approval of a sale transaction under Section 26(2) of

the Gas Utilities Act the court commented as follows:

The respondent City further submits that the closing words from para. 77 of the majority

decision in Stores Block support the Board's jurisdiction to impose the condition: "[The

Board] could also require as a condition that the utility reinvest part of the sale proceeds

back into the company in order to maintain a modern operating system that achieves

optimal growth of the system." The City points out that this Court has approved the use

of deferral accounts in the rate setting context: ATCO Electric Limited v. Alberta (Energy

and Utilities Board), 2004 ABCA 215, 361 A.R. 1. In light of other conclusions reached

by the majority in Stores Block, it is not reasonable to interpret this passage as giving the

Board the power to impose the condition which it did in this case. The Supreme Court

condemned any allocation for ratepayers "based on an unquantified future potential loss"

(at para. 84). In our view, a more reasonable interpretation of the Supreme Court's words

would permit the Board to impose a condition if there was a close connection between

the sale of the asset and the immediate resulting need to replace it. For example, the

utility might sell a pumping station and, in order to service the public, it might need to

access a different pumping station or even replace the existing one. The sale and purchase

would be closely connected. This is what the majority of the Supreme Court had in mind

when it stated that in some circumstances the Board could impose a condition that

required the utility to reinvest the proceeds of sale into the system.71

59. The court also provided guidance with respect to the timing of when assets that are no

longer “used or required to be used” should be removed from rate base. The court stated:

Section 37 of the GUA permits inclusion in the rate base of assets "used or required to be

used to provide a service to the public". While it is true that the surplus four acres of the

Harvest Hills lands were never physically used to provide utility services, that does not

mean that they were improperly included in the rate base. When these lands were

purchased the Board must have been satisfied that they were "used or required to be

used", and permitted their inclusion in the rate base. It later turned out that more land was

purchased than was actually needed. Perhaps the amount of land needed was

overestimated, or perhaps it was not possible to purchase a smaller parcel. In any event,

once it was determined that there was surplus land, it should have been removed from the

rate base as no longer "required to be used."72

69

Harvest Hills, paragraphs 31 and 32. 70

Harvest Hills, paragraph 29. 71


Harvest Hills, paragraph 14.



2.5.3 Salt Caverns

60. On October 1, 2007, ATCO Pipelines Ltd. (ATCO Pipelines) filed its 2008-2009 General

Rate application (GRA), Application No. 1527976, with the EUB. In that application ATCO

Pipelines excluded a certain portion of the assets comprising its salt cavern natural gas storage

facility from rate base.

61. On November 6, 2007, the EUB ruled that unilateral removal of the salt cavern assets

from rate base was a disposition out of the ordinary course of business according to

Section 26(2)(d) of the Gas Utilities Act requiring the prior consent of the EUB. ATCO Pipelines

was directed to refile its 2008-2009 GRA to include the removed assets.

62. On July 21, 2008, ATCO Pipelines, citing the Carbon decision, again indicated that it had

decided to withdraw a portion of the salt cavern assets from utility service effective immediately.

On July 30, 2008, the Commission restated the earlier ruling prohibiting the removal of the

assets from rate base and indicating that an application under Section 26(2)(d) of the Gas

Utilities Act was required to “…allow the Commission and interested parties to adequately

examine the merits of the application and assess whether or not the Identified Salt Cavern Assets

are used and useful or required to be used to provide service to the public within Alberta.”

63. ATCO Pipelines successfully appealed both the ruling of the EUB and the ruling of the

Commission.

64. In ATCO Gas and Pipelines Ltd. v. Alberta (Utilities Commission), 2009 ABCA 246,

leave to appeal to the Supreme Court of Canada refused, 33366 (January 28, 2010) (Salt

Caverns) the Alberta Court of Appeal referred to Carbon as confirming that the EUB lacked

jurisdiction to include assets in rate base that no longer had an operational purpose, stating:

…this Court’s recent decision in “Carbon” where the Court held that the Board had no

jurisdiction to include in rate base, assets which were not being used or required to be

used in providing service to the public, in an operational context. Past or historical use of

assets does not permit their inclusion in rate base unless they continue to be used in the

system.73

65. The court went on to determine that a unilateral withdrawal of an asset from utility

service and rate base by a utility when it determines that the asset is no longer used or required to

be used, was not a “disposition” as contemplated by the wording of Section 26(2)(d) of the Gas

Utilities Act.74 The mere ending of a particular use of an asset without an accompanying sale,

transfer or relinquishment of property to a third party was not a “disposition” and did not require

regulatory approval.75 The court commented that the removal of an asset from rate base without a

disposition involves the “used or required to be used” criteria for rate base as discussed in

Carbon, stating:

Ceasing to use an asset for utilities purposes involves the traditional criteria for what is in

the rate base (discussed in Part F above), and does not involve or require a s. 26

application at all. The 2008 "Carbon" decision (cited in the previous paragraph) clearly

73

Salt Caverns, paragraph 14. 74


Salt Caverns, paragraph 51.



adopts the decisions about the "used or required to be used" test, and defines that as

operational use in the utility: see para. 25 for example.76

66. The court also indicated that should the utility imprudently remove assets from rate base,

it may be unable to recover the financial consequences of such actions from customers. The court

stated:

Indeed, counsel for the appellant stressed to us what the Commission could do when

hearing a rate application if it found want of due prudence in starting or stopping the use

of some asset in the regulated utility. It could make some adjustment of values in the rate

base or in the expenses or return on investment, so that rates approved would not make

the consumers pay rates based on that type of imprudence.77

67. Again referring to the Carbon decision, the Court of Appeal emphasises that assets which

no longer are “used or required to be used” should not remain in rate base. The court stated:

It is true that s. 26 is a very useful section. But with or without it, an asset no longer used

to operate the utility is no longer part of the rate base, whatever its history or earning

capacity: “Carbon” decision, ATCO Gas and Pipelines v. Energy and Utilities Bd.,

2008 ABCA 200, 433 A.R. 183, 192-93 (paras. 28-30).78

68. The court also referred to the Stores Block decision and the inapplicability of Section 26

to assets which are no longer utility in character, stating:

The Supreme Court of Canada's 2006 "Stores Block" decision, supra, is also very clear

on the subject of s. 26. That section does not even apply to non-utility assets (or former

utility assets), nor to sales in the ordinary course of business, and it gives no power to

earmark or allocate sale proceeds (paras. 40-46).79

69. The Court of Appeal also clarified that it is the Commission that ultimately must

determine rate base for the utility, stating:

So a typical rate hearing does not spend much, if any, time justifying inclusion in the rate

base of every item of capital or equipment, nor even every big item. Rate hearings would

go on forever otherwise. But the final decision is the regulator's, not the utility

company's. See Phillips, op. cit supra, at 302…80

70. The Commission’s authority to determine rate base also applies to the exclusion of assets

that are presently in rate base. The test to apply is whether or not the assets remain “used or

required to be used.” On this point the court stated:

Can it be reasonably argued that this regulatory power is confined to ruling on adding

new items to the rate base, but inapplicable to excluding old or unused items? No.

Phillips, op. cit supra, at 302 quotes another established textbook and lists items which

regulatory commissions may exclude from the rate base. They include obsolete property,

76








property to be abandoned, overdeveloped property and facilities for future needs, and

property used for non-utility purposes.81

The paragraphs above show that the rate-regulation process allows and compels the

Commission to decide what is in the rate base, i.e. what assets (still) are relevant utility

investment on which the rates should give the company a return. The traditional test is

whether they are used or required to be used, and (as will be seen below) nothing in the

legislation changes that.82

2.5.4 Deferred gas account appeal

71. In Calgary (City) v. Alberta (Energy and Utilities Board)83 the Court of Appeal

considered the jurisdiction of the EUB to approve the use of deferral accounts, in particular the

deferred gas accounts used by ATCO Gas to ensure that consumers paid the cost of the gas they

consumed, with no resulting profit or loss to the utility's shareholders. The City of Calgary

submitted that sections 36 and 37 of the Gas Utilities Act relating to the EUB’s jurisdiction to

determine rates and rate base could not be relied on as authority to approve the use of the

deferred gas accounts because of the Supreme Court of Canada’s admonition in Stores Block

against the use of general statutory authority to ground the exercise of overly-broad powers. The

court dismissed this argument stating at paragraph 44:

Calgary argues against reliance on sections 36 and 37 as the source of the Board's

authority because of the Supreme Court's admonition against employing general statutory

authority to ground the exercise of overly-broad Board powers, see e.g., Stores Block at

para. 50. Elsewhere in the same decision, however, the Court emphasized the need to

determine whether the exercise of the proposed power is a "practical necessity for the

regulatory body to accomplish the object prescribed by legislation": para. 77. According

to the majority, such necessity was lacking in Stores Block. Here, for reasons outlined

above at paras. 36-37, the use of DGAs is required if the Board is to regulate utilities

effectively. Moreover, in Bell Aliant, Abella J. explained at paras. 51 - 53 that Stores

Block did not "preclude the pursuit of public interest objectives through rate-setting". She

contrasted Stores Block by pointing out that in Bell Aliant, the CRTC's rate-setting

authority and its ability to establish deferral accounts for that purpose were at the very

core of its competence. The same holds true in this case.

Additional AUC decisions after Stores Block 2.6

72. The AUC has commented and applied the Stores Block, Carbon, Harvest Hills and Salt

Caverns decisions in a number of other decisions, some of which have been, or which are

currently, the subject of review and variance applications and appeals to the Alberta Court of

Appeal. This section of the decision will review some of these decisions.

2.6.1 Decision 2009-004 – Carbon Storage Scoping

73. In Decision 2009-00484 the Commission determined certain questions and clarified the

scope of proceeding relating to the removal of the Carbon Storage assets of ATCO Gas from rate

base. In the course of its analysis, the Commission provided its understanding of the ability of

the Commission to place conditions on its approval to sell an asset under Section 29(2) of the

81



Calgary (City) v. Alberta (Energy and Utilities Board) [2010] A.J. No. 449, 2010 ABCA 132. 84

Decision 2009-004: ATCO Gas South, Removal of Carbon Related Assets from Utility Service Pre-hearing

Conference Scoping Decision, Application No. 1579086, Proceeding ID. 87, January 9, 2009.




Gas Utilities Act as contemplated by paragraph 77 of the Stores Block decision. The Commission

stated:

The Commission considers that paragraph 77 of the Stores Block Decision must be read

in a manner that is consistent with the overall findings of the Court. In general, the Stores

Block Decision stands for the premise that customers do not obtain a proprietary interest

in the assets of the utility even though customers have paid regulated rates to obtain

utility services utilizing those assets. Further, the utility is entitled to the value of its

assets on a disposition, provided the disposition and any consequences arising from the

disposition do not impact the quality or quantity of service to customers or adversely

affect the rates customers pay for those services.

…

An order denying a section 26(2) of the GUA, section 102(2) of the PUA application or

attaching conditions to it that would apply the “value” of the asset or the proceeds (or

deemed proceeds) arising from a sale to the benefit of ratepayers, must be directed at

protecting customer services or for preventing or mitigating rate impacts. Subject to the

comments below in respect of paragraphs 81 and 84 of the Stores Block Decision, the

Commission has no jurisdiction to attach the value of the asset or the proceeds arising

from a sale by way of conditions in other circumstances. In the absence of such

justification, the value of the asset, or the proceeds of sale belong to the owner of the

property, the utility, for the benefit of its investors.85

74. The Commission also discussed paragraph 81 of the Stores Block decision wherein the

court commented on the ability of the EUB to convene “a hearing of the interested parties in

order to modify and fix just and reasonable rates to give due consideration to any new economic

data anticipated as a result of the sale.” Intervener parties had submitted that this paragraph of

the Stores Block decision would allow the EUB to consider the value of the Carbon Storage

facility in a rate-setting proceeding as utility revenue arising from the “disposition” of the asset.

This revenue would then be taken into consideration as “new economic data” in determining

future rates. The Commission responded to this position in the following extract:

…any interpretation of paragraph 81 must be consistent with the overall tenor of the

Decision. Accordingly, the Commission considers that a finding of harm is a prerequisite

to the ability of the Commission to consider the value of Carbon in a rate-making context

for the purpose of limiting the right of the utility to deal with its property in the manner it

proposes. …Given the finding of the Commission in Section 4.2.2 above, that no harm

will result from the removal of Carbon from rate base, it is improper to utilize the

wording of paragraph 81 as a vehicle to consider the value of Carbon as revenue

available to off-set customer rates in a rate-making process…86

2.6.2 Decision 2009-253 – Review and Variance

75. Following the release of the Salt Caverns decision the Commission initiated a review and

variance of two decisions87 relating respectively to the ability of a utility to unilaterally withdraw

assets from rate base and the effective date for removal of ATCO Gas’s Carbon Storage facility

85



Decision 2009-004; Decision 2009-067: ATCO Gas South, Removal of Carbon Related Assets from Utility

Service, Preliminary Questions, Application No. 1579086, Proceeding ID. No. 87, June 26, 2009.



assets from rate base. In Decision 2009-253,88 the Commission varied its earlier findings and

determined that the effective date for the removal of Carbon Storage from rate base should be

“the date when ATCO management clearly indicated that Carbon no longer had an operational

purpose, was no longer used or required to be used in providing utility service and should be

withdrawn from rate base and utility service.”89 The Commission stated:

The Commission has carefully considered the guidance provided by the Court of Appeal

in the Salt Cavern Letters Appeal Decision that section 26 of the Gas Utilities Act does

not require the consent of the Commission prior to a utility removing an asset from rate

base, in light of the Court’s finding in the Carbon Appeal Decision that section 37 of the

Gas Utilities Act requires an asset to have an operational purpose in providing utility

services to be included within rate base. When these two decisions are read together it

appears that a utility may, without obtaining prior Commission approval, remove an asset

from rate base at the time that utility management considers that the asset is no longer

used or required to be used, or will soon become no longer used or required to be used, in

an operational sense to provide regulated utility services. However, as pointed out by the

Court of Appeal in paragraph 53 of the Salt Caverns Letters Appeal Decision quoted

above, the Commission has the authority to assess the prudence of the utility’s decision to

remove the asset from rate base and to adjust rate base and rates should a finding of

imprudence be made. The Commission may also adjust rates if the removal of an asset

from rate base results in rates for utility services no longer being just and reasonable.90

76. Leave to appeal Decision 2009-253 was refused by the Alberta Court of Appeal in

Calgary (City) v. Alberta (Utilities Commission), [2010] A.J. No. 540, 2010 ABCA 158

(Calgary Leave). In denying leave to appeal the Commission findings with respect to the

historical date for the removal from rate base and customer rates of the Carbon Storage assets of

ATCO Gas, McFadyen J. referred to the Salt Caverns decision and stated:

23. Ultimately, the court held that the final determination as to whether a certain asset is

to be used or is required to be used in providing utility service to the public falls within

the jurisdiction of the Commission. Nonetheless, the utility company need not first obtain

the Commission’s consent or approval when deciding that an asset is no longer used or

required to be used in providing service to the public. Although the Commission may

require that the utility prove that the asset is no longer being used in its operations, and

that the cessation of use of the asset is not imprudent, absent proof of imprudence, the

adjustment date must be the date on which the utility, in fact, stopped using the asset, not

the date on which the Commission agreed that the asset was no longer being used.

25 … The Commission’s decision as to the date on which the asset was no longer used or

required to be used in providing the service is entirely one of fact and in any event was

correctly decided. There is no suggestion that the Carbon facility was used or required to

be used in any operational sense, at any time beyond that date. As pointed out by this

court in the Carbon Decision and Salt Caverns, the Commission has no jurisdiction to

include in rate base any asset that is not being used or required to be used in the

operational sense.91

88 Decision 2009-253: ATCO Gas South, Review and Variance Proceeding Of Decision 2009-004 and Decision

2009-067 (Removal of Carbon Related Assets from Utility Service), Application No. 1605365, Proceeding ID

No. 281, December 16, 2009. 89

Decision 2009-253, paragraph 56. 90


Calgary (City) v. Alberta (Utilities Commission), [2010] A.J. No. 540, 2010 ABCA 158 at paragraphs 23 and

25.




2.6.3 Decision 2011-176 – Fortis Special Charge

77. In Decision 2011-17692 dealing with the application by Fortis for a special facilities

charge, the Commission quoted Stores Block and Carbon and came to the conclusion that utility

shareholders are at risk for any abandoned special facilities. The Commission stated:

37. Given the direction of the courts, it appears to the Commission that if a special

facility customer were to abandon the facilities and they were not, within a reasonable

period of time, used for other utility customers, those assets would have to be removed

from rate base and Fortis shareholders, not remaining utility customers, would bear

responsibility for costs.93

78. In the compliance filing decision, Decision 2012-084,94 the Commission indicated that in

approving the compliance filing it was not “authorizing the recovery of any future stranded

investments from other rate payers.”95 The Commission also noted that the issue of stranded

assets was the subject of a review and variance of Decision 2011-474, the 2011 Generic Cost of

Capital decision.96

2.6.4 Decision 2011-450 – 2011-2012 ATCO Gas GRA

79. In Decision 2011-450 the Commission dealt with the 2011-2012 GRA of ATCO Gas. In

this decision the Commission made certain findings with respect to assets that are no longer used

or required to be used but yet remain in rate base. It also considered who should bear the

responsibility for ongoing costs associated with assets that are no longer in rate base. The

Commission reviewed the Stores Block, Carbon, and Salt Caverns decisions and stated the

following:

The Commission considers that assets that are not properly in rate base because they are

no longer used or required to be used to provide utility service should not be reflected in

rates in any fashion. It is irrelevant whether the asset was fully consumed in providing

utility service or whether it has residual value or not.97

…

92

Decision 2011-176: FortisAlberta Inc., Application for Special Facilities Charge, Application No. 1606706,

Proceeding ID No. 909, May 2, 2011. 93


Decision 2012-084: FortisAlberta Inc., Compliance Filing – Special Facilities Charge, Application

No. 1608016, Proceeding ID No. 1647, March 23, 2012. 95


See also Decision 2012-155: EPCOR Distribution & Transmission Inc., Customer Specific Distribution Access

Service Rate for New Customer, Application No. 1608176, Proceeding ID No. 1731, June 8, 2012. In

paragraph 34 the Commission stated:

“Respecting the issue of stranded investments the Commission notes that there are no stranded assets at

stake on the facts of this proceeding. On June 4, 2012, the Commission issued Decision 2012-154

indicating that it expected to re-initiate Proceeding ID No. 20 (the Utility Asset Disposition Rate Review)

or initiate a generic proceeding regarding asset disposition and stranded assets after the issuance of a

Commission decision on the Rate Regulation Initiative (Proceeding ID No. 566). To the extent that the

stranded asset issue might arise as a result of the implementation of this new DAS rate for the new CS

customer, this can be addressed in either Proceeding ID No. 20 or the generic proceeding.” (footnote

removed) 97

Decision 2011-450, paragraph 315.





Neither the timing of the actual disposition of an asset nor the characterization of a

disposition as either within, or outside, the ordinary course of business, can logically

serve to distinguish the entitlements or obligations of ownership once the asset is no

longer used or required to be used to provide utility service. It would be unreasonable to

suggest that a utility could pass on the costs of ongoing obligations associated with the

ownership of an asset to ratepayers after the asset is no longer used or required to be used

to provide utility service simply by keeping the asset as a utility asset rather than moving

it to a non-utility account. Similarly, it would be illogical to require ratepayers to pay for

ongoing operational costs of an asset while the utility waits for an improvement in market

conditions in order to maximize potential gains or simply because the utility is unable to

dispose of the property because of associated liabilities or market conditions.

Accordingly, retired assets that are not anticipated to be disposed of at approximately the

same time that they are retired should be moved to a non-utility account where any

ongoing costs associated with the assets would be for the account of the utility

shareholder…98

80. The Commission also considered the Harvest Hills decision and commented on the

ability of the Commission to attach the proceeds of sale as a condition of approval under

Section 26(2) of the Gas Utilities Act. The Commission stated:

300. The Commission considers that the Harvest Hills decision established four

criteria that must be met before the Commission can attach a condition to the proceeds of

disposition of a utility asset which requires the utility to reinvest the proceeds into the

regulated system. The four criteria are:

there must be a disposition of property by a utility

the sale must be outside of the ordinary course of business, giving rise to the

jurisdiction of the Commission to review the transaction

there must be a close connection between the sale of the asset and the need to

replace it

the need to replace the asset must be immediate, in other words the need to

replace the asset must arise at the same time as the disposition99

81. With respect to intervener submissions suggesting that the above criteria could lead to

opportunistic timing of events, the Commission stated:

303. …This line of argument would suggest that the findings of the court in the Harvest

Hills decision with respect to the ability of the Commission to attach the proceeds of sale

where there is “a close connection between the sale of the asset and the immediate

resulting need to replace it” should not be allowed to be circumvented by the timing

chosen by the utility for the actual disposition of the retired property. If a utility is able to

avoid the establishment of a close connection between the sale of an existing asset and

the resulting need to replace it by simply removing the existing asset from rate base and

delaying the sale to a future period after the new asset is in service, unfairness and harm

to ratepayers in the form of higher rates would result because the utility would avoid the

potential attachment of the proceeds of disposition. This harm would occur despite the

Commission having previously approved the construction of the new facility and its

98

Decision 2011-450, paragraphs 319 and 320. 99




inclusion in rate base because rates could have been lower than otherwise would be the

case. Such a result would provide a utility with the motivation to arrange its affairs in a

manner that would not give rise to the possibility that the Commission might attach

conditions to the proceeds of sale.100

306. The Commission notes that the utility may have very practical reasons for delaying

or deciding not to sell an asset when it is retired, including the absence of a market in a

rural environment, poor market conditions, or because the utility has decided to retain the

asset to conduct a separate unregulated business.101

82. The Commission also considered whether ongoing reclamation and abandonment costs

associated with former natural gas production assets should be included in revenue requirement.

The Commission was asked to review the impact of a prior negotiated settlement on the issue.

On this issue the Commission stated as follows:

1001. AG confirmed that the “production abandonment costs relate to ATCO Gas’

obligation to abandon production properties which were previously used to provide utility

service.” It is not disputed by the parties that the assets to which these costs relate are no

longer “used in an operational sense” as required by the Carbon decision. It is also not

disputed that the assets are no longer used or required to be used to provide utility service

as required by Section 37 of the Gas Utilities Act and accordingly would not qualify for

rate base consideration. AG takes the position, however, that establishing that the

abandoned properties qualify for inclusion in rate base is not a prerequisite for recovery

of the applied for abandonment costs. AG refers to the Stores Block decision in support

for its position that the ongoing costs of abandonment in respect of an asset that has not

been moved to a non-utility account but which is no longer used or required to be used in

providing utility service, should be considered as part of the cost of providing utility

service and should be recovered from ratepayers as part of the cost of service.

1002. The Commission disagrees. The Stores Block decision can not be relied on for

the premise advanced by AG. The court stated that the “utility absorbs losses and gains,

increases and decreases in the value of assets.” As was the case with the Irma agency

office, the Commission considers that all costs, including the ongoing operational and

remediation costs associated with assets that no longer have an operational purpose and

are no longer used or required to be used to provide utility service, such as the abandoned

production assets, should be removed from revenue requirement and be for the account of

the utility shareholder as of January 1, 2011.

1003. AG referred to several EUB decisions which approved the inclusion of

production abandonment costs in rates in the past. Among these decisions were several

which approved settlement agreements reached with customers. These decisions pre-date

the Stores Block decision and the Carbon decision and accordingly the Commission has

not considered them to be relevant to a consideration to the costs to be allowed in revenue

requirement during the current test period.102 (footnotes omitted)

83. The Commission’s decision on production abandonment costs (among other matters) was

the subject of a review and variance application. In Decisions 2012-156 the review panel granted

a review of this issue finding that the record leading to “Decision 2011-450 shows that the issue

100



Decision 2011-450, paragraphs 1001 to 1003.



of these settlements was not canvassed in the proceeding.”103 The review panel then referred the

issue of who bears the risk of production abandonment costs to this proceeding, stating:

110. … For the purposes of regulatory efficiency, the review panel considers that the




this issue can be addressed either in Proceeding ID No. 20 or the generic proceeding.104

84. In Decision 2012-311 the Commission made a similar finding with respect to the

production abandonment costs of AltaGas. and referred the issue of who bears the risk of

recovery of the associated costs to this proceeding.

2.6.5 Decision 2011-474 – 2011 Generic Cost of Capital

85. In Decision 2011-474, 2011 Generic Cost of Capital, the Commission determined that

utility shareholders rather than ratepayers, are at risk with respect to stranded transmission

facility owner (TFO) assets (paragraphs 251 and 252 of Decision 2011-474), and extended these

comments to any stranded gas or electric transmission or distribution assets (paragraphs 542 to

545).

86. These findings were the subject of a review and variance application and in Decision

2012-154 the Commission referred the issue of stranded assets and who bears the risk of


2.6.6 Decision 2012-068 – Disposition of Salt Cavern Assets

87. In Decision 2012-068,105 Disposition of Salt Cavern Assets, the Commission approved

the application of ATCO Pipelines to transfer to an affiliate certain portions of its Salt Cavern

natural gas storage facility. In addition, the Commission required ATCO Pipelines to remove

from rate base and customer rates other portions of the facility that the Commission determined

to be no longer used or required to be used. The Commission established the date for removal of

the assets from customer rates as the date that ATCO Pipelines first advised the Commission that

these assets were no longer used or required to be used to provide utility services, but directed

compensation to the utility for a portion of time elapsed after that date on the basis of quantum

meruit. A previous Commission decision which included the entire facility in rate base and

customer rates was deemed to be a nullity on the basis that the Commission lacked the

jurisdiction to include in rate base and rates assets than no longer had an operational purpose or

context. In making these findings the Commission stated:

145. The Alberta Court of Appeal made it clear in the Carbon decision and the Salt

Caverns decision that the Commission has no jurisdiction to include in rate base assets

that are not used or required to be used to provide utility service in an operational

context…106

103



Decision 2012-068: ATCO Pipelines, ATCO Gas and Pipelines Ltd., CU Inc., Canadian Utilities Limited,

Disposition of Surplus Salt Cavern Assets in the Fort Saskatchewan Area, Application No. 1607245,

Proceeding ID No. 1196, March 16, 2012. 106





146. In the Salt Caverns decision, the court ruled that ceasing to use an asset for utility

purposes involves the traditional criteria for what is in the rate base, and does not require

a Section 26 Gas Utilities Act application…107

147. When the findings of the Court of Appeal in the Carbon and Salt Caverns decisions

are considered together it is apparent that the Salt Cavern Excess Assets did not belong in

rate base subsequent to AP’s determination that the assets were no longer used or

required to be used to provide utility service and that AP had the ability to unilaterally

remove the Salt Cavern Excess Assets from utility service as of July 1, 2009. The

Commission considers that it was incumbent upon AP to have acted immediately upon

the issuance of the Salt Caverns decision to unilaterally remove from utility service the

portion of the salt cavern assets that were not used or required to be used to provide

utility service and to notify the Commission that it would apply for approval to make the

required adjustments to rate base, revenue requirement and rates effective as of July 1,

2009…108

88. Leave to appeal Decision 2012-068 was granted by the Alberta Court of Appeal on

September 20, 2012.109 A decision on the full appeal is anticipated in due course. In its letter of

April 23, 2013,110 the Commission agreed to the request of the Alberta Utilities to proceed with

issuing a decision in this proceeding despite the outstanding Salt Caverns Disposition appeal.

However, in granting the request the Commission noted the potential relevance of the findings of

the court to the matters under consideration in this proceeding and stated:

22. Following release of the court’s decision on the Salt Caverns Disposition Appeal,

the Commission will consider what subsequent steps, if any, may be required. These

steps may include a Commission initiated review and variance of either or both of the

UAD decision and the 2013 GCOC decision.111

2.6.7 Decision 2012-172 – ATCO Electric 2011-2012 GTA Compliance Filing

89. In Decision 2012-172,112 the Commission considered the response of ATCO Electric to

Commission directions relating to the operational use of certain assets included in rate base. The

Commission noted its responsibility to determine rate base and referred to the statement in the

Carbon decision that rate base assets for a gas utility must have an operational use. The

Commission stated:

It is the responsibility of the Commission to make a determination on the assets to be

included in the rate base. This requires the Commission to decide whether the services

provided by the asset included in the rate base are required in an operational sense.17

_________________ 17

In Carbon Storage, the court stated at paragraph 25: “... the only reading of s. 37 is that the

assets that are ’used or required to be used’ to provide service are only those used in an

operational sense.”113

107



ATCO Gas and Pipelines Ltd. v. Alberta (Utilities Commission) 2012 ABCA 273. 110

Exhibit 106.01. 111

Exhibit 106.01, paragraph 5. 112

Decision 2012-172: ATCO Electric Ltd., 2011-2012 General Tariff Application Compliance Filing for

Directions Arising from AUC Decision 2011-459, Application No. 1608103, Proceeding ID No. 1687, June 22,

2012. 113





90. The Commission also noted that the present proceeding would “examine the criteria for

determination of whether assets are used or required to be used.”114

Consideration of Stores Block in other jurisdictions 2.7

91. The Stores Block decision has been considered by several courts and tribunals in

jurisdictions outside of Alberta. This section of the decision will review some of these other

proceedings and how Stores Block has been interpreted and applied.

2.7.1 Bell Canada v. Bell Aliant Regional Communications

92. In Bell Canada v. Bell Aliant Regional Communications115 the Supreme Court of Canada

considered two decisions of the Canadian Radio-television and Telecommunications

Commission (CRTC) relating to rates determined by way of a price cap formula and to the use of

deferral accounts. The decision reviewed the statutory authority of the CRTC to set rates in a

manner which encouraged competition and to direct the use of funds collected through a deferral

account to uses furthering certain objectives approved by the CRTC. In rendering its decision the

court confirmed the findings in Stores Block and distinguished it on the basis of the more

extensive powers granted to the CRTC, including the explicit legislative direction to consider the

objectives of the statute as opposed to the more general conditioning powers granted to the EUB

based on a rate base rate of return rate methodology. The court considered Stores Block which it

referred to as the ATCO decision and stated:

…It was argued that because the Board had the authority to make "further orders" and

impose conditions "in the public interest" on any order, it therefore had the ability to

order the disposition of the sale proceeds.

In holding that the Board had no such authority, Bastarache J. relied in part on the

conclusion that the Board's statutory power to make orders or impose conditions in the

public interest was insufficiently precise to grant the ability to distribute sale proceeds to

ratepayers (at para. 46). The ability of the Board to approve an asset sale, and its

authority to make any order it wished in the public interest, were necessarily limited by

the context of the relevant provisions (at paras. 46-48 and 50). It was obliged too to adopt

a rate base rate of return method to determine rates, pursuant to its governing statute (at

paras. 65-66).

Unlike ATCO, in the case before us the CRTC's rate-setting authority, and its ability to

establish deferral accounts for this purpose, are at the very core of its competence. The

CRTC is statutorily authorized to adopt any method of determining just and reasonable

rates. Furthermore, it is required to consider the statutory objectives in the exercise of its

authority, in contrast to the permissive, free-floating direction to consider the public

interest that existed in ATCO. The Telecommunications Act displaces many of the

traditional restrictions on rate-setting described in ATCO, thereby granting the CRTC the

ability to balance the interests of carriers, consumers and competitors in the broader

context of the Canadian telecommunications industry...116

114


[2009] S.C.J. No. 40, 2009 SCC 40. 116

Bell Canada v. Bell Aliant Regional Communications, paragraphs 51 to 53.



2.7.2 Toronto Hydro Electric System Ltd. v. Ontario Energy Board

93. In Toronto Hydro-Electric System Ltd. v. Ontario Energy Board,117 the Ontario Divisional

Court denied an appeal by Toronto-Hydro-Electric System Ltd. (THESL) of an Ontario Energy

Board (OEB) decision.118 As part of a general rate application, THESL had proposed a

consolidation of seven facilities into three, one of which would be a new facility. As a result of

the consolidation, three properties would be sold within the test period. The OEB approved the

consolidation but found that the properties to be sold would have continued to be used and useful

had the consolidation not proceeded. The OEB also determined that the proposal would result in

substantial costs to ratepayers. In order to defray these costs, the board allocated 100 per cent of

the after-tax gains on sale to ratepayers.

94. The court rejected the argument of THESL that the appropriation of the gain on sale by

the OEB was contrary to the findings of the Supreme Court of Canada in Stores Block. The court

distinguished Stores Block because the EUB was acting under a provision of its legislation which

required regulatory approval of an asset sale and it was not acting under its general rate making

jurisdiction as was the OEB in the present case. In this rate making context, the OEB was

allocating a revenue offset in a similar manner to how it would deal with other utility revenues.

In this regard, the court noted Section 81 of Stores Block and the statement that the EUB could

have convened “a hearing of the interested parties in order to modify and fix just and reasonable

rates to give due consideration to any new economic data anticipated as a result of the sale.”

Further, the court found that the OEB’s decision was supported because it had linked the

attachment of the gain to the need for replacement facilities. The court stated:

13. Although the appellant has characterized the legal issue as relating to jurisdiction -

whether the OEB has an express or implied power to attribute a property interest in the

assets of a utility to its ratepayers - I do not accept that characterization. Unlike ATCO,

which involved the Board's authority to attach conditions to its approval of the sale of a

utility's assets, the decision in this case was squarely within the rate setting authority of

the OEB. The question of law is whether the OEB may allocate the net after tax gains on

the sale of the properties to reduce THESL'S revenue requirements in the course of

establishing just and reasonable rates. It goes to the very core of the OEB mandate.

21. For the reasons that follow, I find that the OEB had the jurisdiction to allocate the net

gains from the sale of properties to the rate-setting formula and that its decision was

reasonable.

24. The appellant argues that ATCO stands for the proposition that a regulator cannot

allocate all the proceeds of sale of a utility's property to the ratepayers because this, as

noted, is contrary to the principle that customers do not have a property interest in the

assets of a utility. In ATCO, the decision was made under the regulator's power to

approve a sale, not under its rate-making power. However, the Supreme Court of Canada

noted at para. 81, that the Board had the ability to modify and fix just and reasonable

rates and to give due consideration to any new economic data anticipated as a result of

the sale of property.

30. The language that "the gains ...should go to the ratepayer" is unfortunate. However,

read in the context of the rate setting process as a whole, and the allocation of revenue to

117

Toronto Hydro-Electric System Ltd. v. Ontario Energy Board et al. (2009), 252 O.A.C. 188 (Div. Ct.), leave to

appeal to Ontario Court of Appeal refused, M37594 (September 14, 2009). 118

OEB Decision EB-2007-0680, Toronto Hydro-Electric System Ltd., dated May 15, 2008.



the formula used by the OEB in the decision, it is clear that the OEB was not granting the

ratepayers a property interest in the capital gains from the sale of the properties but was

allocating a revenue offset - in a similar treatment to revenue from other sources - to

adjust the revenue requirements of THESL for the 2008 year.

31. The OEB also considered the need to replace the functions of that property and the

costs to the ratepayer of doing so. It contrasted this case with another in which Union Gas

Ltd. wished to sell cushion gas. In that case, the OEB considered ATCO and allocated

100% of the gains to the utility, because the cushion gas was truly surplus, in that the

utility was not going to replace it. (Decision EB-2005-0211, June 27, 2007.)119

2.7.3 FortisBC Inc. v. Shaw Cablesystems Ltd.

95. The British Columbia Court of Appeal had occasion to consider Stores Block in FortisBC

Inc. v. Shaw Cablesystems Ltd. [2010] B.C.J. No. 2426, 2010 BCCA 552. At issue in this case

was the ability of the British Columbia Utilities Commission (BCUC) to consider an application

by Shaw Cablesystems Ltd. (Shaw) to order FortisBC Inc. (FortisBC) to continue to allow Shaw

to use FortisBC’s transmission infrastructure to support its telecommunications cables and to

direct a negotiated settlement of a rental amount. FortisBC submitted that Stores Block supported

the proposition that the BCUC’s powers must be read narrowly and that an arrangement between

the utility and a third party unrelated to electric transmission was outside the concept of the

regulatory compact and the scheme of electric utility regulation. The BCUC’s jurisdiction was

limited to regulating the utility’s facilities for electric transmission purposes.

96. The court dismissed the FortisBC argument on the basis that the Supreme Court of

Canada disallowed the EUB’s actions in allocating proceeds of disposition because the EUB had

to rely on a general conditioning provisions of its legislation while the BCUC had an express

authority over uses of utility facilities by non-utilities.120

2.7.4 NEB Decision RH-003-2011 – TransCanada PipeLines Limited

97. In RH-003-2011,121 the National Energy Board (NEB) considered a 2012-2013

restructuring proposal for tolls and services by TransCanada PipeLines Limited. In that decision,

the NEB was asked to consider the Stores Block decision in the context of a utility operating in

an increasingly competitive environment. Alberta intra-provincial demand for gas has increased

at the same time that competition for transporting western Canadian sourced gas has increased.

Further, western Canadian sourced gas is competing with other gas supply sources to meet

demand in eastern markets. This environment could result in certain utility assets no longer being

“used and useful.”

98. TransCanada PipeLines Limited submitted that the original NEB approvals received at

the time that assets are included in service, not the “used and useful” regulatory standard,

determines ongoing cost recovery. Accordingly, if an asset becomes no longer used or useful

prior to it being fully depreciated, the asset should be retired, and the remaining prudently

incurred costs recovered from ratepayers. Further, the disallowance of prudently incurred costs

119

Toronto Hydro, paragraphs 13, 21, 24, 30 and 31. 120

FortisBC Inc. v. Shaw Cablesystems Ltd., paragraph 50. 121

NEB Decision RH-003-2011: TransCanada PipeLines Limited, NOVA Gas Transmission Ltd., and Foothills

Pipe Lines Ltd., Business and Services Restructuring Proposal and Mainline Final Tools for 2012 and 2013,

March 2013.



would amount to confiscation or expropriation by the NEB of utility assets contrary to the

findings of the Supreme Court of Canada in Stores Block.

99. Certain interveners suggested that Stores Block stood for the premise that the risk of cost

recovery for assets that become no longer used or useful to provide service prior to becoming

fully depreciated, even in the context of increased competition, belonged to the utility.

100. The NEB considered that the standard for approving the construction of facilities with the

subsequent inclusion in rates of the associated prudent costs at the time that assets went into

service and the used and useful standard can be in potential conflict. However, it was incorrect to

consider a finding of prudence at the time an asset is placed into service as determinative of

future cost recovery. Such a position was inconsistent with the responsibility of the NEB to set

just and reasonable tolls on an ongoing basis.122 Further, a rule that would compel the NEB to set

tolls that allow full cost recovery irrespective of whether the underlying assets are used and

useful would erode “management’s responsibility for its investment decisions and management’s

responsibility to keep depreciation rates current.”123

101. The NEB considered that Stores Block could be distinguished on the facts but that the

case supported the NEB’s conclusion that utility shareholders bear the final risk of cost recovery

and that it would not be confiscatory to disallow cost recovery with respect to assets that were no

longer used or useful in certain circumstances. The NEB stated:

Given the foregoing, we are of the view that it would not be confiscatory to disallow

costs in appropriate circumstances.

In our view, this conclusion is consistent with the principles set out in Stores Block. That

case places the ultimate risk of asset ownership on the pipeline company and not its

customers. We recognize that Stores Block does not specify how a regulator must

calculate rate base or determine tolls. However, the Court made clear that the benefits and

risks of asset ownership, realized upon the disposition of an asset, rests with the utility.124

Principles derived from court and AUC decisions 2.8

102. The Commission considers the following principles have been established by Stores

Block and subsequent court and AUC decisions:125

(a) The Commission derives its jurisdiction from its enabling statutes. The limits of the

Commission’s powers “are grounded in its main function of fixing just and reasonable

rates (rate setting) and in protecting the integrity and dependability of the supply system.”

(Stores Block, paragraph 7)

(b) The Commission will apply the “no harm test” in assessing an application for approval to

dispose of a utility asset outside of the ordinary course of business under Section 26(2) of

the Gas Utilities Act or Section 101(2) of the Public Utilities Act. (Stores Block,

paragraphs 13 and 77; Harvest Hills, paragraph 31)

122

RH-003-2011, pages 38 to 42. 123

RH-003-2011, page 40. 124

RH-003-2011, page 41. 125

AUC decisions other than portions of decisions for which a review has been granted by the Commission and

which have been referred to this proceeding for further consideration.



(c) Utility assets are the property of the utility. Customers do not obtain a property interest in

utility assets by virtue of receiving, and paying for, utility service. (Stores Block,

paragraphs 63, 64 and 68)

(d) Utility shareholders are entitled to the net proceeds of disposition of an asset sold outside

of the ordinary course of business. Shareholders receive any gain and must bear any

financial loss arising upon disposition. “Ownership of the asset and entitlement to profits

or losses upon its realization are one and the same.”(Stores Block, paragraphs 67, 69 and

70)

(e) “Shareholders have and they assume all risks as the residual claimants to the utility's

profit.” Utility “shareholders are the ones solely affected” when the actual profits or

losses of a sale outside the ordinary course of business are realized; “the utility absorbs

losses and gains, increases and decreases in the value of assets, based on economic

conditions and occasional unexpected technical difficulties, but continues to provide

certainty in service both with regard to price and quality.” (Stores Block paragraphs 68

and 69)

(f) The Commission may impose a condition to its approval of a disposition of a utility asset

sold outside of the ordinary course of business which requires the utility to give

“undertakings regarding the replacement of the assets and their profitability.” It could

also require as a “condition that the utility reinvest part of the sale proceeds back into the

company in order to maintain a modern operating system that achieves the optimal

growth of the system.” (Stores Block, paragraph 77)

(g) Paragraph 77 of the Stores Block decision means that the Commission may impose a

condition to its approval of a disposition of a utility asset sold outside of the ordinary

course of business “if there was a close connection between the sale of the asset and the

immediate resulting need to replace it.” (Harvest Hills, paragraph 35)

(h) Four criteria must be satisfied before the Commission may attach a condition to its

approval of a disposition of a utility asset sold outside of the ordinary course of business:

(i) there must be a disposition of property by a utility

(ii) the sale must be outside of the ordinary course of business, giving rise to the

jurisdiction of the Commission to review the transaction

(iii)there must be a close connection between the sale of the asset and the need to

replace it

(iv) the need to replace the asset must be immediate, in other words the need to

replace the asset must arise at the same time as the disposition (Decision

2011-450, paragraph 300)

(i) Paragraph 81 of the Stores Block decision, wherein the court commented on the ability of

the EUB to convene “a hearing of the interested parties in order to modify and fix just

and reasonable rates to give due consideration to any new economic data anticipated as a

result of the sale,” must be read in the context of the entire decision and the principle that

ratepayers do not receive a property interest in utility assets. (Decision 2009-004, pages

14 and 15)

(j) The words “used or required to be used” in Section 37 of the Gas Utilities Act “are

intended to identify assets that are presently used, are reasonably used, and are likely to

be used in the future to provide services. Specifically, the past or historical use of assets



will not permit their inclusion in the rate base unless they continue to be used in the

system.” (Carbon, paragraph 23)

(k) The “only reasonable reading of s. 37 is that the assets that are ‘used or required to be

used’ to provide service are only those used in an operational sense.” (Carbon, paragraph

25; Salt Caverns, paragraph 56)

(l) The Commission has “no jurisdiction to include in rate base, assets which were not being

used or required to be used in providing service to the public, in an operational context”

(Salt Caverns, paragraph 14)

(m) The Gas Utilities Act “does not contain any provision or presumption that once an asset is

part of the rate base, it is forever a part of the rate base regardless of its function. The

concept of assets becoming ‘dedicated to service’ and so remaining in the rate base

forever is inconsistent with the decision in Stores Block….” “Previous inclusion in the

rate base is not determinative or necessarily important.” (Carbon, paragraph 29)

(n) “Past or historical use of assets does not permit their inclusion in rate base unless they

continue to be used in the system.” An “asset no longer used to operate the utility is no

longer part of the rate base, whatever its history or earning capacity” (Salt Caverns,

paragraphs 14 and 54)

(o) Revenue generation alone is an insufficient basis upon which to include an asset in the

rate base of a gas utility. Customers “have no interest in the profits, unregulated revenues,

or unregulated businesses of the utility.” (Carbon, paragraph 30)

(p) The Commission has the responsibility to determine the rate base, including “what assets

(still) are relevant utility investment on which the rates should give the company a

return.” (Salt Caverns, paragraphs 30, 31 and 52)

(q) A gas utility may unilaterally withdraw an asset from rate base that it considers no longer

used or required to be used to provide service to the public within Alberta; provided that,

should the utility act imprudently in removing an asset from rate base, the Commission

may disallow recovery of the resulting financial impacts from customers. (Salt Caverns,

paragraphs 51 and 53)

(r) Gas utility assets that no longer have an operational purpose and are no longer used or

required to be used by the utility in providing service to the public in Alberta, no matter

what the historical use of such assets, should be removed from rate base and should not

be reflected in customer rates. (Decision 2011-450, paragraphs 312 and 315; Decision

2012-068, paragraph 147)

(s) The effective date for removal of a gas utility asset from rate base and customer rates is

the earlier of: (i) the date that the utility advises the Commission that the asset is no

longer used or required to be used; or (ii) the date the Commission determines that an

asset no longer has an operational purpose and is no longer used or required to be used to

provide service to the public. (Salt Caverns, paragraphs 28, 31, 51, 52, 53 and 56;

Decision 2009-253, paragraph 54; Calgary Leave, paragraphs 23 and 25; Decision

2012-068, paragraphs 146 and 147)



Remaining matters to be considered 2.9

103. In its notice dated April 2, 2008,126 initiating this proceeding the Commission noted that

the Stores Block decision may have various implications with respect to regulation of Alberta

utilities and provided an issues list to focus submissions. The Commission explained further by

stating:

In particular, the guidance provided by the courts may require re-consideration of certain

aspects of traditional regulatory approaches to the acquisition and disposition of utility

assets and to the setting of just and reasonable rates. Parties have argued various

interpretations of the Stores Block Decision in several recent proceedings before the EUB

and in various ongoing proceedings before the Commission. The Commission would like

to develop a comprehensive understanding of these potential implications through this

Proceeding and then to apply that understanding in a consistent manner in future

decisions.127

104. In its October 17, 2012 letter128 recommencing this proceeding, the Commission noted

that additional judicial guidance had been received on certain of the matters addressed in the

original issues list and attached a draft revised issues list.129 Parties were requested to comment

on the draft revised issues list and following receipt of comments the Commission established

the final revised issues list which it attached to its correspondence of December 7, 2012.130

Although parties disagreed on the content and scope of the final revised issues list, the

Commission considered that the matters enumerated therein had not been fully addressed

through decisions of either the courts or the Commission and that all stakeholders would benefit

from a proceeding to review and clarify these matters.

105. The following section of this decision reviews the submissions received from the parties

on each of the matters identified in the final revised issues list.

3 Final revised issues list

Issue 1 – Asset disposition issues 3.1

3.1.1 Issue 1.1 – Ordinary course dispositions

106. Issue 1.1 of the final revised issues list provided:

This proceeding will review the extent to which the treatment of a gain or loss arising

upon disposition of a utility asset within the ordinary course of business and therefore

excluded from the provisions of Section 26(2)(d) of the Gas Utilities Act, RSA 2000, c.

G-5 and Section 101(2)(d) of the Public Utilities Act, RSA 2000, c. P-45, should continue

to be treated differently than a gain or loss on sale of a utility asset sold outside the

ordinary course of business. In considering this issue parties should specifically address

Stores Block applicable legislation, the Uniform Classification of Accounts Regulation

(Alberta Regulation 546/63) applicable to gas utilities and the Uniform System of

126

Exhibit 1.01. 127

Exhibit 1.01, pages 1 to 2. 128

Exhibit 54.01. 129

Exhibit 54.02. The draft revised issues list. 130

Exhibit 67.03. The final revised issues list.



Accounts approved in EUB Decision 2007-017[131] applicable to electric utilities.

(footnotes omitted)

107. All parties in this proceeding agreed that Stores Block stands for the premise that a utility

owns the property acquired by it in providing utility service and that customers do not obtain a

property interest in this property by virtue of receiving and paying for utility service.132 There

was also general agreement that Stores Block clarified that ownership of the assets means that

Alberta utilities and their shareholders are entitled to receive the net proceeds of disposition of an

asset sold outside the ordinary course of business.133 The utility receives any gain, and must bear

any loss, arising upon disposition. The UCA considered that Stores Block did not limit the

Commission’s ratemaking discretion to consider the disposition of an asset outside the ordinary

course of business when setting just and reasonable utility rates.

108. The Alberta Utilities submitted that Stores Block did not apply to a sale of an asset within

the ordinary course of business. The Alberta Utilities and the UCA agreed that any gains or

losses arising from the disposition of depreciable property accrue to ratepayers and any gains or

losses arising from the disposition of the non-depreciable portion accrue to the utility. While

agreeing with the other parties that gains and losses realized upon the disposition of a

depreciable asset within the ordinary course of business accrue to customers, Calgary submitted

that virtually all dispositions by a utility should be considered as being with the ordinary course

of business.

109. The Alberta Utilities submitted that “Stores Block does not address the disposition of

assets in the ordinary course.”134 The accounting for the disposition or retirement of assets in the

ordinary course is provided for in the Uniform Classification of Accounts for Gas Utilities,

Alberta Regulation 546/63 (UCAGU) and the Uniform System of Accounts (USA) for Alberta

electric utilities.135 136 Upon either retirement or sale of an asset within the ordinary course, any

gains or losses arising from the depreciable portion of the invested capital accrue to ratepayers

and the non-depreciable portion accrue to the shareholders.137

110. The UCA submitted that “it is not necessary to change the existing treatment of gains or

losses arising from the disposition of utility assets that are disposed of in the ordinary course of

business”138 as a result of the Stores Block decision. The UCA further submitted, that the court in

Stores Block had not intended to constrain or compromise the Commission’s rate-making

jurisdiction in relation to a) stranded assets or post-retirement costs, b) post-retirement

dispositions of non-depreciable assets, or c) the determination of utility rate base.139 The decision

131

Decision 2007-017: ATCO Electric Ltd., 2011-2012 General Tariff Application Compliance Filing for

Directions Arising from AUC Decision 2011-459, Application No. 1608103, Proceeding ID No. 1687, June 22,

2012. 132

Exhibit 108.02, Alberta Utilities argument, paragraph 64; Exhibit 112, Calgary reply argument, paragraph 98;

Exhibit 107, Calgary argument, paragraphs 3,17, 18, 22; Exhibit 80.02, UCA submission, paragraph 35. 133

Exhibit 80.02, UCA submission, paragraph 21; Exhibit 108.02, Alberta Utilities argument, paragraph 72. 134

Exhibit 77.02, Alberta Utilities submission, paragraphs 10 and 12; Exhibit 109.02, Alberta Utilities argument,

paragraphs 14 and 66. 135

Exhibit 108.02, Alberta Utilities argument, paragraph 14. 136

EUB Decision 2007-017: Implementation of the Uniform System of Accounts and Minimum Filing

Requirements for Alberta’s Electric Transmission and Distribution Utilities, Application No. 1468565, March 6,

2007. 137


Exhibit 80.02, UCA submission, paragraph 41. 139

Exhibit 111.02, UCA reply argument, paragraph 19.

http://www.qp.alberta.ca/1266.cfm?page=1963_546.cfm&leg_type=Regs&isbncln=9780779765867

http://www.auc.ab.ca/items-of-interest/usa-and-mfr/Documents/USA%20and%20MFR/Consensus%20UniformSystemofAccounts.pdf




was simply about Section 26(2) of the Gas Utilities Act and the Commission’s power to

condition Section 26(2) approvals. Stores Block identified a gap in the Commission’s jurisdiction

as it relates specifically to Section 26(2); it did not create new principles that in any way limited

the ratemaking discretion of the Commission.140 The UCA stated that the Stores Block decision:

…leaves it open to the Commission, in circumstances not involving GUA s. 26(2)

approvals, to make changes in those areas, or not, as it thinks appropriate, in order to

ensure that utility rates continue to be just and reasonable, subject of course to whatever

other constraints exist under the common law and as part of the overall legislative

scheme.141

…it is useful to consider whether the Commission could achieve the economic and risk-

related balance that it previously achieved via conditions imposed on GUA s. 26(2)

approvals using its general rate-making discretion, i.e. by simply directing in a general

rate or tariff application that a utility’s rate base be adjusted in whatever way the

Commission determined to be just and reasonable in order to appropriately allocate gains

and losses on dispositions of utility property between shareholders and customers.142

111. The Alberta Utilities replied to the UCA’s submission that the Commission’s ratemaking

powers were not affected by the Stores Block decision so that it could take into account the

proceeds of disposition of an asset outside of the ordinary course of business when setting rates

by stating that the proposal would “circumvent the intent of Stores Block.” Further, the UCA

proposal would amount to a “manipulation of rate base” and was “ nothing more than an attempt

to do indirectly that which the Courts have found cannot be done directly -- it is a patently

obvious attempt to impermissibly subsidize rates.”143

112. Calgary viewed that the Stores Block decision “substantially and fundamentally changed

the regulatory paradigm in Canada.” The decision established “that the risk of ownership of an

asset committed to utility service rested with the owner” and that “customers of the utility were

obligated to pay the utility for the service they received, but nothing more.”144

113. Calgary considered that the differentiation “between ‘in the ordinary course’ [of

business] and [outside the ordinary course of business] seems to be one of pragmatism.”145

Should a utility be required to obtain Commission approval for all dispositions, there would be

numerous applications to deal with dispositions that individually have little material impact on

the utility and its customers.

114. Calgary referred to the submissions of the Alberta Utilities on what constitutes a

disposition of an asset outside the ordinary course of business and concluded that “virtually none

of the dispositions of the utilities are outside of the normal course.”146 Therefore, except for the

very few dispositions outside of the ordinary course of business, “a valuation would be required

140





Exhibit 107.01, Calgary argument, paragraph 3. 145


Exhibit 107.01, Calgary argument, paragraph 7.



to deem proceeds and determine their treatment (either as a reduction of rates or as reinvestment

of proceeds as no cost capital).”147

115. Commenting on the submissions of Calgary, the UCA suggested that there is nothing

unsound with the argument that Stores Block established that utility shareholders have the

responsibility for all risks and costs associated with all utility property after it is removed from

utility service. Using this argument, utility shareholders would be responsible for any

unrecovered depreciation amounts associated with depreciable assets that are removed from

utility service for any reason.148

116. In addition to submissions on whether the Stores Block decision requires the Commission

to reconsider the different treatment presently accorded to assets disposed of inside and outside

of the ordinary course of business, the Alberta Utilities also made submissions on the criteria

used by the Commission in determining when assets fall into one category or the other. In

particular, the Alberta Utilities took issue with the Commission’s expansion of the criteria in

Decision 2011-450. The Alberta Utilities stated that there was no need or justification to broaden

the list of criteria used previously by the Commission and its predecessors149 which were outlined

in Order U2001-196.150 Order U2001-196 had stipulated that the quantum and materiality of the

proceeds of disposition as well as the net book value and frequency and type of sale transaction

were the relevant considerations in determining if a disposition was inside or outside the ordinary

course of business.151

117. In Decision 2011-450, the Commission indicated that it had reviewed the legislation,

prior regulatory decisions and addressed the criteria to apply when considering whether an asset

disposition by a utility is inside or outside the ordinary course of business and set out the

following:

276. This panel of the Commission concurs with the earlier decisions of the

Commission and its predecessor that materiality and frequency are relevant factors to

consider when determining whether the disposition of an asset is within or outside of the

ordinary course of business. The Commission considers that the approach outlined by

Ms. Wilson at the oral hearing provides a satisfactory balance between bringing multiple

minor applications to the Commission for review while ensuring that substantive

transactions are brought forward for consideration. The Commission agrees that $1.5

million is a reasonable transaction value at this time to use as a threshold guideline.

Should the transaction price be over $1.5 million, AG will be required to bring an

application for Commission approval under Section 26(2)(d) of the Gas Utilities Act. If

the transaction price is less than $1.5 million, AG should consider if there are other

factors that would suggest that the transaction is outside of the ordinary course of

business and therefore require the consent of the Commission to the disposition. Those

other factors would include:

the quantum and materiality of the proceeds of disposition in relation to the total rate

base of the utility

147


Exhibit 111.02, UCA reply argument, paragraph 10. 149

Exhibit 77.02, Alberta Utilities submission, paragraph 35. 150

Order U2001-196: NOVA Gas Transmission Ltd, the Sale of the Athabasca Maintenance Facility, Application

No. 2001112, File No. 6417-04, August 3, 2001. 151

Exhibit 77.02, Alberta Utilities submission, paragraph 25.


http://www.auc.ab.ca/applications/orders/utility-orders/Utility%20Orders/2001/U2001-196.pdf



the quantum and materiality of the net book value of the asset in relation to the total

rate base of the utility

whether all or any portion of the functionality of the asset being disposed of has been

relocated to an existing facility or relocated to a new facility

the frequency and type of disposition of like assets

the other party(ies) to the transaction and if the transaction involves an affiliate,

whether the ATCO Group Inter-Affiliate Code of Conduct has been complied with

the market value of the asset when compared to the consideration received on the

disposition

the allocation of sale proceeds between depreciable and non-depreciable property

the net book value of the assets

whether the asset was a utility or non-utility asset

any other unique or distinguishing aspect of the asset or of the transaction

277. If a review of the circumstances and factors described above do not suggest that a

transaction of less than $1.5 million should be considered to be outside of the ordinary

course of business, AG may proceed to deal with the disposition of the asset on the basis

that it is within the ordinary course of business.152

118. The Alberta Utilities submitted the following concerns with the additional criteria to be

assessed in determining whether a disposition is outside the ordinary course of business:153

(a) There was no evidence submitted in the proceeding leading to Decision 2011-450 to

support any change from the criteria outlined in Decision U2001-196.

(b) No other potentially affected utilities were afforded an opportunity to comment.

(c) The additional criteria will not promote regulatory efficiency.

(d) Whether the functionality of the asset that has been relocated should not factor into the

consideration of whether a transaction is outside the ordinary course.

(e) It is not clear what bearing the allocation of proceeds between depreciable or non-

depreciable property should have on the determination.

(f) Compliance with the Code of Conduct is not related in a determination of whether a

disposition of an asset is considered to be within or outside the ordinary course of

business.

(g) The disposition of a non-utility asset may not require the Commission’s prior approval

given the statement of the Supreme Court in paragraph 44 of the Stores Block decision

that “Section 26(2) can only have limited, if any application to non-utility assets.” The

court stated “[t]he provision can only be meant to ensure that the asset in question is

indeed non-utility, so that its loss does not impair the utility function or quality.” In

argument, the Alberta Utilities, clarified its position stating that no such Commission

approval was necessary154 and referred to the statement of the Alberta Court of Appeal at

paragraph 55 of the Salt Caverns decision: “[t]hat section [section 26(2)(d) of the Gas

Utilities Act] does not even apply to non-utility assets (or former utility assets) nor to

sales in the ordinary course of business, and gives no power to earmark or allocate sale

proceeds.”

152


Exhibit 77.02, Alberta Utilities submission, paragraphs 27 to 33. 154

Exhibit 108.02, Alberta Utilities argument, paragraph 43.



(h) The Commission did not provide any guidance as to the weight the various criteria

should be given when making an assessment.

(i) It is not clear what materiality threshold is to be used by all other Alberta utilities or how

the materiality threshold should change over time as a utility grows. Further, any

threshold should be based on net costs rather than on gross proceeds.

119. The Alberta Utilities submitted that “the uncertainty these new criteria impose could

result in virtually all ordinary course dispositions being brought to the Commission for approval

since the consequence of non-compliance is to render the transaction void.”155 The Alberta

Utilities requested that the Commission “provide more clarity and simplicity for all parties as to

when an assessment is required as to whether a disposition may be in, or not within, the ordinary

course of a utility’s business.”156

120. Calgary noted in argument that given the review of case law dealing with dispositions

outside the ordinary course of business in this proceeding, “the Commission will have to

determine what is a disposition in the ordinary course.”157

3.1.2 Supplemental process on depreciation principles

121. In order to assist the Commission in assessing if the Stores Block decision applied to

dispositions within the ordinary course of business, the Commission, in a second round of

information requests, sought parties’ views on the principles supporting various depreciation

methodologies in setting just and reasonable rates. Parties were asked to base their responses on

the assumption that the Stores Block and related Alberta Court of Appeal decisions interpreting

Stores Block apply to depreciable assets; and to discuss if the use of Iowa survivor curves158 in

mass property accounts159 was consistent with the principle that assets no longer used or required

to be used are to be removed from rate base. Further, the Commission questioned if it would be

necessary to discontinue the use of the amortization of reserve differences methodology in order

to give effect to the need to remove assets that are no longer used or required to be used from

rate base.

122. In summary, neither the Alberta Utilities nor the UCA indicated there was a need to

change existing depreciation methodologies, including the use of the amortization of reserve

differences, in order to be satisfied that assets that are no longer used or required to be used, have

been removed from rate base. Calgary did not submit responses to this second round of

information requests.

123. In response to the questions posed by the Commission, the Alberta Utilities expressed

concern about the premise of the Commission’s question and clarified its view that Stores Block

did not deal with removal of assets from regulation or rate base, but that Stores Block and related

155




Public Utility Depreciation Practices, August 1996, NARUC, page 321 provides the following definition of

Iowa survivor curves as “Several families of curve shapes derived empirically from analysis of the mortality

data for many different types of industrial property.” 159

Public Utility Depreciation Practices, August 1996, NARUC, page 322 provides the following definition of a

mass property group or account as “An account consisting of large numbers of similar units, the life of any one

of which is not, in general, dependent upon the life of any of the other units. For such classes of plant, the

retirement of a group of units occurs gradually until the last unit is retired. The retirements and additions to the

account occur more or less continually and systematically.”



Alberta Court of Appeal and other judicial decisions only stand as authority respecting

dispositions, and not retirements.160

124. The Alberta Utilities disputed any suggestion that the existing depreciation methodology

may impact the creation and materiality of stranded assets, pointing out that there is a distinction

between an entitlement to prudent cost recovery and the mechanisms to be employed to

accomplish cost recovery.161

125. The Alberta Utilities considered that “the prudent cost recovery mechanisms employed in

Alberta have always reconciled the inherent uncertainty between estimated and actual lives of

assets used to provide utility service by means of a depreciation reserve.”162

126. The Alberta Utilities stated that the “statutory scheme governing dispositions outside the

ordinary course of business (and Stores Block), therefore, represent an exception to the ordinary

course mechanisms designed to allow a utility to recover its prudent investment.”163 The Alberta

Utilities submitted that the statutory provision in Section 26 of the Gas Utilities Act requires

approval for disposition of any utility assets outside the ordinary course of business and that

upon an actual disposition outside the ordinary course of business, any losses on the sale of both

depreciable and non-depreciable property are the responsibility of the utility, as are the gains.164

127. The UCA indicated that the selection of a depreciation methodology and depreciation

parameters would likely influence the probability of stranded costs arising due to the variability

of depreciation rates influencing the rate of investment recovery by a utility. The UCA stated that

depreciation rates should be designed to recover the utility’s investment in facilities over the

facilities expected useful life, and should not be accelerated in a manner to reduce the probability

any asset might become stranded.165

128. The UCA viewed current depreciation methodologies as consistent with the requirement

that only assets that are used or required to be used to provide utility service should be in rate

base. The UCA stated:

The use of conventional depreciation methodologies, including the use of Iowa curves in

mass property accounts, is consistent with the principle that assets no longer used or

required to be used for utility service are to be removed from rate base.166

129. The UCA stated that standard deprecation methodology allocates the risk about the

uncertainty of the actual useful lives of assets “primarily to customers, in the sense that it utilizes

deferral accounts to ensure that in the long run the utility recovers exactly its original investment

in the depreciable property that it acquires and uses for utility purposes.”167 The UCA considered

that this result was “not inconsistent with the general principle that utilities should not be

160

Exhibit 124.02, AUC-AlbertaUtilites-18. 161





Exhibit 121.02, AUC-UCA-14(a). 166

Exhibit 121.02, AUC-UCA-14(b). 167

Exhibit 121.02, AUC-UCA-14(b).



allowed to include in their rate bases, and earn a return on, the cost of assets that have nothing to

do with the provision of utility service.”168

130. With respect to the amortization of reserve differences account the UCA stated:

The UCA does not believe that it is necessary to discontinue the use of the amortization

of reserve differences methodology in order to be consistent with Stores Block and the

relevant Alberta legislation.169

131. The UCA also stated it did not believe that Stores Block constrains the Commission's

jurisdiction to prescribe whatever depreciation methodologies it thinks are appropriate in order to

appropriately allocate risks and costs between utility shareholders and customers and fix just and

reasonable utility rates.170

132. TransAlta Utilities stated that it adopts the AltaLink depreciation parameters, and

accordingly had no response to the matters raised in the information request.171 Calgary indicated

that its position on matters arising in this proceeding had been previously placed on the record.172

3.1.3 Issue 1.2 – Reinvestment of sales proceeds

133. In the final issues list the Commission identified the following issue:

Harvest Hills provided guidance on paragraph 77 of Stores Block with respect to the

ability of the Commission to condition the approval of an asset disposition by requiring

the utility to “reinvest part of the sale proceeds back into the company in order to

maintain a modern operating system that achieves optimal growth of the system.” This

proceeding will consider if a reinvestment of a gain on sale pursuant to a Commission

condition in the circumstances described by the Court should be treated as a shareholder

capital investment in rate base by the utility and therefore entitled to earn a return or, if

the reinvestment of the gain should be treated as a reduction to the capital cost of the

replacement asset or as no-cost capital, thereby reducing customer rates. [footnote

omitted]

134. The Alberta Utilities stated that sales proceeds could not be confiscated, and any

reinvestment was entitled to earn a fair return like any other shareholder investment. Crediting

the gain to customer rates as an offset to the cost of replacement capital, as no-cost capital or as a

subsidy to customer rates was inconsistent with the case law. The UCA and Calgary submitted

that treatment of the gain as a shareholder capital investment unfairly increased rate base and

customer rates with no change in the quality or efficiency of the asset results. For this reason the

gain should either be treated as no cost capital or the proceeds should be allocated by the

Commission to ensure just and reasonable rates.

135. The Alberta Utilities submitted that the conditioning language in paragraph 77 of the

Stores Block case was obiter and cannot be considered without taking into account the context of

the language and the main principles of the decision. The Alberta Utilities stated:173

168


Exhibit 121.02, AUC-UCA-14(c). 170

Exhibit 121.02, AUC-UCA-14(c). 171

Exhibit 123.02, AUC-TransAlta-6. 172

Exhibit 120.01, letter from Calgary to the AUC dated July 31, 2013. 173




The notion of "reinvestment", considered in the context of the Court’s judgment,

relates to ensuring that the sale of a utility asset does not adversely impact in any

material way the utility's ability to ensure the continuation of safe and reliable utility

service following the disposition of the asset. That notion is core to the purpose of

section 26 of the GUA ascribed by the Supreme Court in paragraph 44 of the Stores

Block decision, as the UCA itself recognizes. It cannot be interpreted to require a

confiscation of shareholders’ proceeds, which prohibition was the ratio decidendi of the

decision.

136. The Alberta Utilities referred to dictionary definitions174 of “reinvestment” and submitted

that a reinvestment is still an investment by the utility in the expectation of a return.175 The

Alberta Utilities stated:

….Even if a "reinvestment" requirement was triggered, the use of the term by the Courts

could not be reasonably interpreted to contemplate either a donation of shareholder

property or a subsidy to customer rates. That conclusion is manifest on the face of the

Stores Block and the Carbon decisions, amongst others. Furthermore, the Electric

Utilities Act17

(“2003 EU Act” or “Current EU Act”) speaks expressly in terms of return

on investment, and a re-investment is just that – an investment.

137. The Alberta Utilities stated that the Harvest Hills decision clarified that paragraph 77 of

the Stores Block decision “cannot be construed to provide confiscatory powers over shareholder

proceeds in order to reduce customer rates.”176

138. The UCA submitted that the issue was whether a reinvestment meeting the requirement

as set out in Harvest Hills should be treated as an ordinary shareholder investment, attracting

normal allowed return, or treatment as no-cost capital.

139. The UCA submitted that asset replacement transactions that are treated as ordinary

investments “enable the utility to capture or ‘crystallize’ for their shareholders’ benefit increases

in the market value of the original non-depreciable asset.”177 The result is unfair to customers,

where there is an increase in rates with no change in the quality or amount of utility service that

is provided. This customer “harm” would be avoided by treating the amount of the gain on sale

that is reinvested in new utility assets as no-cost capital.178 The UCA’ s position is summarized

by the following extract from its argument:

It is important to appreciate that the form and content of any condition attached to any

necessary GUA s. 26(2) approval is not the fundamental issue here. The real issue is

whether the Commission has the power to ensure in one way or another that utility rates

are just and reasonable and that customers are not harmed by asset transactions

undertaken by the Utilities. In a context where the Commission is assumed to be limited

to attempting to condition s. 26(2) approvals as a means of ensuring a just and reasonable

result, the analysis presented by the UCA in its Initial Submission supports the “no-cost

capital” answer to the direct question posed in Issue 1.2.179

174

Exhibit 97.01, UCA-AlbertaUtilities-05. 175



Exhibit 109.02, UCA argument, paragraph 13. 178


Exhibit 109.02, UCA argument, paragraph 15.



140. The UCA submitted that a Section 26, Gas Utilities Act condition was not the only

mechanism that the Commission could employ by way of considering the proceeds of

disposition. The UCA argued that the Alberta legislative scheme as a whole should be

interpreted in a way that ensures that the Commission has the rate-making jurisdiction necessary

to protect customers’ interests, including the ability to direct whatever rate-related adjustments

are required in order to ensure that the end result is just and reasonable. Accordingly, the

Commission could take into consideration the proceeds of a disposition where the asset disposed

of is being replaced in several ways, including:180

…a ‘Stores Block paragraph 77’ type of condition, with any reinvestment treated as no-

cost capital. Beyond that, the UCA’s view is that the Commission likely has that ability

anyway, entirely apart from whether GUA s. 26(2) approvals are even required, simply as

part of its general power to ensure that utility rates are just and reasonable.

141. The UCA also noted that there would be other regulatory or ratemaking mechanisms that

the Commission could use to prevent this type of customer “harm,” including disallowances

based on prudence considerations, or refusals to approve the necessary asset dispositions where

Commission approval under Section 26 of the Gas Utilities Act is required.181

142. Calgary observed that virtually all utility assets that are disposed of are replaced by

another asset, with the only exceptions being those held for speculative purposes, such as the

Harvest Hills property that was disposed of. Calgary stated that when an asset sale is

accompanied by a replacement with a higher cost asset, then the rates may not be just and

reasonable.182

143. Calgary submitted that a utility should not be able to enhance its rate base by replacing

one asset with a newer more expensive assets even if the new assets were more efficient without

using the gain on sale on the replaced asset to offset the cost of the new asset. Calgary stated:

…the gain on the disposal of one asset that has been, or will be, obtained once the

replacement asset is put into service, should be treated as reinvested proceeds as zero

cost capital financing the rate base. To overcome the issue from the Harvest Hills

decision the approval of the disposition should be contingent on the replacement of the

asset required to perform the service, or the approval to acquire a new asset should be

contingent on the disposition of the old, when the new goes into service with the gain

if any credited against the cost of the new asset.183

144. Calgary also suggested that the Harvest Hills decision has a narrower application than

suggested by the Alberta Utilities, and that therefore it has limited application to this proceeding.

The obvious and fundamental distinction is that the Harvest Hills lands were never

used for utility service and did not serve a utility function, nor were the lands to be

replaced by alternate property…184

145. Calgary challenged the Alberta Utilities position that paragraph 77 of the Stores Block

decision only applies to cases where the asset sale will adversely impact service in a material

180



Exhibit 112.01, Calgary reply argument, paragraph 66. 183


Exhibit 112.01, Calgary reply argument, paragraph 79.



way. Calgary acknowledged that the Commission can refuse a sale if service were impacted,

however, paragraph 77 addresses circumstances where the Commission can attach conditions to

a sale which contemplate reinvestment or allocation of proceeds.185

146. Calgary argued that the Alberta Utilities position incorrectly tries to apply Harvest Hills,

where the issue was the allocation of proceeds, to limit Commission jurisdiction with regard to

reinvestment of proceeds.186

…Stores Block in paragraph 77 specifically used the words the Board “could also

require as a condition that the Utility reinvest part of the sale proceeds back into the

company.” [emphasis added by Calgary]

147. Calgary submitted that in paragraph 77 of the Stores Block decision, the “court was

clearly indicating to the Commission that it had powers to consider the allocation of proceeds in

a rate-setting regime to fix just and reasonable rates.”187

Issue 2 – Used or required to be used issues 3.2

148. Issue 2 of the final revised issues list requested the parties to consider stranded assets,

post-retirement costs and the need for verification of the continued use of utility assets in

providing utility services. This section of the decision reviews the submissions from parties on

each of these issues.

3.2.1 Issue 2.1 – Stranded assets

149. The first series of issues addressed under the “used or required to be used” standard

section of the final revised issues list related to stranded assets. Issue 2.1.1. stated:

3.2.1.1 Issue 2.1.1 – Definition of stranded assets including a threshold dollar size and /

or definition of the smallest units of property to potentially be considered

stranded.

150. None of the parties supported the use of a threshold dollar size in defining stranded

assets.

151. The Alberta Utilities submitted that assets which are depreciated through mass (property)

accounts should never be treated as stranded assets when they are retired in the ordinary course

of business. Because smaller dollar amounts are accounted for within the single mass (property)

account, the Alberta Utilities did not submit any threshold dollar size of stranded assets.188

152. The Alberta Utilities adopted the following definition of stranded costs which was

provided in the report provided on behalf of the Alberta Utilities by Mr. John Reed, of

Concentric Energy Advisors (Concentric):

…stranded costs can be defined as prudently-incurred costs (to avoid confusion

between stranded cost recovery and challenges based on prudence) that were incurred

with a reasonable expectation that they would be recoverable through the ratemaking

process. Further, these costs would become “stranded” to the extent they are found to be

185

Exhibit 112.01, Calgary reply argument, paragraphs 64 to 65. 186

Exhibit 112.01, Calgary reply argument, paragraphs 70 to 71. 187





no longer fully recoverable under the “traditional” ratemaking treatment being

accorded them, through non-utility purposes to which they could be applied, or as a

consequence of changed circumstances, including changes in law, regulatory policy,

market conditions, asset lives, or asset productivity. In this context, a finding that an

investment is no longer “used or required to be used” does not equate to the cost of

that investment being “stranded.”189

153. Concentric went on to describe three situations where an asset could become stranded:

●investments in plant that never went into operation (cancelled plant costs)

●assets which are no longer used or required to be used due to changes in the assets

themselves, technological changes or changed in supply and demand

●unrecovered costs due to retirement or abandonment and the associated post-retirement

costs.190

154. Concentric submitted that disallowing recovery by a utility of prudently incurred costs on

the basis that assets were no longer used or required to be used would be “far outside the norm

for regulators in North America and would be a radical departure from the regulatory

principles under which investors have committed their capital to Alberta’s utilities.”191

155. Concentric also referred to an article by Dr. Alfred Kahn in support of its position,

stating:

To this point, the noted regulatory economist and former regulator, Dr. Alfred Kahn,

argued that extreme applications of the “used-and-useful” test were “nonsensical” since

the “implicit bargain between consumers and investors” requires that investors receive

cost recovery for investments that “turn out sour,” and that ultimately capital costs

disallowed on the basis of used and useful will be compensated by the higher equity

return required by investors:192

156. On behalf of the Alberta Utilities, Mr. Steven Fetter commented on the operation of the

“regulatory compact,” stating:

I conclude that, under the traditional “regulatory compact”, a regulated utility in Alberta

should be compensated for any remaining undepreciated original cost of assets that were

the subject of prudent investment determined at the time the investment was made,

which become stranded for reasons that do not involve fault on the part of that utility.193

157. The UCA stated that stranded assets were assets that were no longer used and useful

because of a change in the market and the demand for utility service before the utility’s

investment was fully recovered. The UCA offered no view on stranded assets in terms of

threshold value, unit size or investment amount, and also submitted that a predetermination of

such matters may not be necessary or appropriate.194

189

Exhibit 77.03, Concentric Energy Advisors, paragraph 11. 190




Exhibit 77.04, Regulation unfettered evidence, page 2. 194

Exhibit 80.02, UCA submission, paragraphs 57 and 58.



158. Calgary submitted that no threshold was necessary, and a stranded asset is an asset that is

not used or required to be used.195

3.2.1.2 Issue 2.1.2 – Applicability of Stores Block to a determination of responsibility for

stranded assets.

159. The Alberta Utilities196 and the UCA197 argued that Stores Block has not changed the

responsibility for stranded assets or post-retirement costs or abandonment costs. In contrast,

Calgary submitted that Stores Block places the responsibly for stranded assets on the utility.198 199

160. The Alberta Utilities stated they are legally entitled to the opportunity to earn a fair return

on prudent investments and proposals to have utility shareholders bear risks for stranded assets

would interfere with that right.200 They further stated that “Stores Block has no relevance to the

determination of whom, as between ratepayers and a utility’s investor, bears the risk for stranded

assets.”201

161. The Alberta Utilities commented that existing depreciation methodologies provided for

the recovery of prudently incurred costs, stating:

There is no suggestion by the Supreme Court whatsoever that the existing depreciation

methodologies were flawed or were to change as a result of that judgement.202

162. The Alberta Utilities further submitted203 that paragraph 980 of Decision 2011-450

recognized that the use of the depreciation reserve account does not violate the principles

established in the Stores Block decision. Paragraph 980 states:

980. The Commission agrees with AG and the UCA that collection of the depreciation

reserve deficiency is not retroactive rate making and is not contrary to the court’s

findings in the Stores Block decision. Annual depreciation expense should reflect a

proper allocation of the cost of a utility asset over the life of the asset. By necessity, the

determination of depreciation expense in respect of any particular class of assets is an

estimate based on the best available data and on professional judgment. As better

information becomes available, the depreciation rates are revised with a cumulative

adjustment to the depreciation reserve account. This account is amortized on the same

basis as the related asset account with the amortized amounts recovered through or offset

against revenue requirement.

163. The UCA submitted that Stores Block does not require the Commission to allocate to

utility shareholders stranded asset costs and post-retirement and abandonment costs. Assets that

are no longer used or required to be used should be removed from rate base but there is nothing

195

Exhibit 76.01, Calgary submission, paragraph 24. 196


Exhibit 109.02, UCA argument, paragraphs 26, 35, and 49. 198

Exhibit 76.01, Calgary submission, paragraphs 25 to 27. 199

Exhibit 107.01, Calgary argument, paragraphs 18, 24, 98, and 106. 200

Exhibit 124.02, AUC-AlbertaUtilities-17, page 38. 201






stopping the Commission from allowing existing depreciation methodologies, including the

depreciation reserve account, to recover those costs.204

164. Calgary submitted that all assets that are not used or required to be used should be

removed from rate base and paid for by the utility. Calgary submitted: “[t]o place ratepayers at

risk for the stranded assets would be implying that they have risks associated with ownership,

without the benefits of ownership.”205 The shareholder has the ownership and risk of loss and

benefit of gain.

165. Calgary argued that utility customers pay for the service they are provided, but when an

asset no longer provides service or no longer has an operational purpose, customers have no

more cost responsibility including stranded assets and post-retirement costs and abandonment

costs.206

166. Calgary submitted that if the customers of the utility are not residual claimants to the

profits from the assets, then it follows that shareholders cannot be residual claimants against

customers for recovery of costs after the assets are no longer in service.207

167. Calgary submitted that:

Stranded assets are the result of unexpected changes in economic conditions or technical

difficulties. The Court dealt with those circumstances clearly in paragraph 69 of Stores

Block when it stated “shareholders are the ones solely affected when the actual profits or

losses of such a sale are realized; the utility absorbs losses and gains, increases and

decreases in the value of assets, based on economic conditions and occasional unexpected

technical difficulties.”208

168. Calgary submitted that: “[b]y having the costs of stranded assets and other post-

retirement costs subsidized by ratepayers after the asset is no longer used to provide service

severs the symmetrical risk that the Court expects the shareholders to bear.”209

169. Calgary further referred to the Stores Block decision stating:

To paraphrase the Court’s comments in Stores Block at paragraph 71, just because

ratepayers paid inadequate rates for the utility’s services in the past, there are no powers

in the statutes for the Board to execute such a recovery of costs of stranded assets in the

future. The risk is one of ownership and lies exclusively with the utilities’ shareholders

and investors.210

204

Exhibit 109.02, UCA argument, paragraphs 26, 35 and 49. 205


Exhibit 107.01, Calgary argument, paragraphs 18, 24, 98 and 106. 207




Exhibit 100.01, Calgary rebuttal evidence, paragraph 6.



3.2.1.3 Issue 2.1.3 – Application of the relevant legislation to a determination of

responsibility for stranded assets owned by gas utilities.

170. Section 2.1.3 of the final revised issues list provided:

Application of the relevant legislation to a determination of responsibility for stranded

assets owned by gas utilities. In particular, the Commission will consider the “used or

required to be used to provide service to the public within Alberta” rate base test to

stranded assets owned by gas utilities.

This proceeding will consider the applicability of Section 37 of the Gas Utilities Act and

Section 90 of the Public Utilities Act, as interpreted by Stores Block, Carbon and Salt

Caverns, to a determination of responsibility for stranded assets owned by gas utilities.

To the extent that shareholders are determined to be liable for stranded assets, any change

in risk to the utility will be assessed as part of the 2013 Generic Cost of Capital

proceeding.

171. The UCA and the Alberta Utilities submitted that retirements and the depreciation

process did not create stranded assets. Calgary submitted that the legislation places the

responsibility for stranded assets upon the shareholder.211

172. The Alberta Utilities submitted that “neither Stores Block nor Carbon changed the law

respecting gas utilities’ right to recover prudently incurred costs.”212 The Alberta Utilities also

pointed to Section 36 of the Gas Utilities Act which expressly provides that the Commission may

establish a method of depreciation in setting just and reasonable rates. With respect to the

Commission’s authority to determine the rate base in Section 37, the Alberta Utilities stated:

Section 37 of the GUA's reference to "rate base" only affects the calculation of a utility's

"return on" invested capital. It does not limit or impinge on the "return of" prudently

invested capital. Indeed, Subsection 37(2) expressly contemplates the continuing

application of approved depreciation rates and methods.

173. The Alberta Utilities also referred to Section 4(3) of the Roles, Relationships and

Responsibilities Regulation in support of its position that a gas utility is entitled to a reasonable

opportunity to recover its prudently incurred costs. Section 4(3) provides:

4(3) A gas distributor is entitled to recover in its tariffs the prudent costs as determined

by the Commission that are incurred by the gas distributor to meet the requirements of

subsection (1).

174. The Alberta Utilities submitted that the performance-based regulation provision of the

Gas Utilities Act, Section 45 continues to require the Commission to approve just and reasonable

rates.213

175. The Alberta Utilities also referred to court decisions involving several different types of

utilities, in which the court referred to the requirement that a utility be given a reasonable

211






opportunity to recover just and reasonable compensation for services provided. For example, in

ATCO Electric Ltd. v. Alberta (Energy and Utilities Board) the Alberta Court of Appeal stated:

Thus, both then and now, in assessing a utility's legitimate needs, the Board is required to

ensure that the utility has a reasonable opportunity to recover its costs, providing they are

prudent: British Columbia Electric Railway Co. v. British Columbia (Utilities

Commission) [1960] S.C.R. 837 at 843. Within this statutory framework, the Board's

discretion in fixing just and reasonable rates is relatively wide. As explained by this

Court in TransAlta Utilities Corp. v. Alberta Public Utilities Board (1986) 68 A.R. 171

(C.A.) at 177:

The key power of this Board is to fix "fair and reasonable" rates. This is a good

example of a wide discretion.214

176. The Alberta Utilities also noted that the depreciation reserve account provided a

reasonable opportunity to recover costs and it is used to recover unrecovered original investment

and return on any depreciable property that is retired or removed from rate base.215

177. The UCA submitted that while Section 37 of the Gas Utilities Act requires the

Commission to set a rate base for the property of the utility used or required to be used to

provide service, it does not require the Commission to remove from rates the cost of depreciable

assets which become no longer used or required to be used.216 The section does not restrict the

Commission “in relation to how it determines an appropriate level of depreciation expense to be

recovered in rates and subsequently accounted for in rate base.”217

178. The UCA submitted that Section 37 of the Gas Utilities Act does not require the

Commission to allocate stranded costs in any particular manner and “is fundamentally a matter

for the Commission to decide as part of its overall mandate to fix just and reasonable rates.”218

The UCA explained that there does not have to be a single rule dealing with the allocation of

stranded asset costs fitting all circumstances and that the reason why an asset becomes stranded

should be considered. For example, if an asset becomes stranded because of some unforeseeable

governmental or regulatory change, customers would most likely be responsible for the costs.

However, if the utility did understand that such changes were likely, but made the decision to

proceed with a capital investment anyway which subsequently became stranded, the shareholder

should likely bear the costs.219 In that same vein the UCA noted:

In our view the type of “hybrid” case presented by the stranded asset scenario, where the

assets were at one time needed for utility purposes, but have lost that character for some

market-related reason, leaves regulators with room for discretion in relation to the

allocation of costs and risks associated with stranded assets.220

179. The UCA does not support an interpretation of Stores Block that would prevent the utility

from recovering capital costs of stranded assets that have been removed from rate base.221 Stores

214

ATCO Electric Ltd. v. Alberta (Energy and Utilities Board) 2004 ABCA 215, at paragraph 131. 215

Exhibit 108.02, Alberta Utilities argument, paragraphs 17, 24 and 77. 216

Exhibit 80.02, UCA submission, paragraphs 70 and 71. 217





Exhibit 80.02, UCA submission, paragraphs 69 to 71.



Block, the UCA argued “cannot reasonably be read as imposing new general restrictions on the

Commission’s jurisdiction in relation to the setting of just and reasonable rates, for example in

connection with the fixing of depreciation rates.”222

180. The UCA stated in argument that in order for the Commission to change current

practices, it would need to change the depreciation mechanisms and the depreciation reserve

account systems in such a way that unrecovered costs can be identified and removed from

revenue requirement for the utilities.223 The UCA described the effect of current depreciation

practices as follows:

61. When depreciable assets are removed from service, the original cost is removed

from both the gross plant in service or gross investment and the accumulated

depreciation. If there are un-recovered or over-recovered costs associated with that asset,

given the Commission’s current use of the equal life group procedure of straight line

depreciation, those costs will be recovered from or refunded to customers over the

average remaining life of the asset account.

62. Under the standard depreciation methodology employed in Alberta and in most

other jurisdictions the utility maintains a system of depreciation reserve accounts and

reserve adjustments that, over time, have the general economic effect of ensuring that the

utility is able to recover in future depreciation charges and utility rates any of its original

investment that remains unrecovered at the time the asset is removed from rate base. In

conjunction with that, the usual practice is to do this in a way that enables the utility to

continue to earn its allowed return on the remaining outstanding investment.224 (footnote

omitted)

181. The UCA indicated that an interpretation of Section 37 which would eliminate the

Commission’s discretion to allow utilities to fully recover the cost of stranded assets through the

depreciation mechanism “would imply that the depreciation methodologies that have been

accepted and approved for decades by the Commission are effectively illegal.”225

182. Calgary referenced Section 37 of the Gas Utilities Act and Section 90 of the Public

Utilities Act which both use the term “shall” indicating that the Commission is required to

determine if assets in rate base are used or required to be used. Calgary therefore submitted that

“[t]here would appear to be no room or jurisdiction for charging customers for stranded

assets.”226 In addition, in argument Calgary stated that “[c]harging current customer for stranded

assets is inconsistent with the prohibition on retroactive rates, and the concept that the utility

shareholders have all the risks and rewards of ownership.”227

183. Calgary further noted that the Alberta Utilities appear to interpret “reasonable

opportunity” as an opportunity to have guaranteed recovery of return of capital and return on

capital. Calgary referred to paragraph 69 of the Stores Block decision noting that the court had

222





Exhibit 76.01, Calgary submission, paragraphs 29 to 32. 227




stated that shareholders bore the risk of changed economic conditions and unexpected technical

difficulties.228

3.2.1.4 Issue 2.1.4 - Application of the Electric Utilities Act and other relevant legislation

to a determination of responsibility for stranded assets owned by electric utilities.


Application of the Electric Utilities Act and other relevant legislation to a determination

of responsibility for stranded assets owned by electric utilities. The Commission will

also consider the applicability of the “used or required to be used to provide service to the

public within Alberta” rate base test to stranded assets owned by electric utilities.

This proceeding will apply the provisions of the Electric Utilities Act to a determination

of responsibility for stranded assets owned by electric utilities. This proceeding will also

consider the applicability of Section 37 of the Gas Utilities Act and Section 90 of the

Public Utilities Act, as interpreted by Stores Block, Carbon and Salt Caverns, to a

determination of responsibility for stranded assets owned by electric utilities.

To the extent that shareholders are determined to be liable for stranded assets, any change

in risk to the utility will be assessed as part of the 2013 Generic Cost of Capital

proceeding.

185. The Alberta Utilities submitted that the “rate base” and “used or required to be used”

language employed in the Gas Utilities Act does not apply to electric utilities. Further, the

provisions of the Electric Utilities Act requires electric utilities be given a reasonable opportunity

to recover their prudently incurred costs, including costs which subsequently become stranded.

The UCA submitted that the Commission has the discretion to determine risk for stranded assets

in accordance with the circumstances.

186. The Alberta Utilities submitted that the “used or required to be used” language which

appears in Section 37 of the Gas Utilities Act and Section 90 of the Public Utilities Act does not

apply to electric utilities because Section 116 of the Public Utilities Act expressly made Section

90, inapplicable to electric utilities. Accordingly , any rationale “for imposing stranded cost risk

on electric utilities – namely the Stores Block and Carbon decisions – is without foundation.”229

187. The Alberta Utilities referred to Section 122 of the Electric Utilities Act which provides

that an electric utilities tariff must provide the utility with a reasonable opportunity to recover

prudently incurred costs. Section 121(2) requires the Commission to ensure that a tariff is just

and reasonable. Further, the Alberta Utilities submitted that the performance-based regulation

section of the act, Section 120(2) does not detract from the requirement for just and reasonable

tolls.230 The Alberta Utilities stated:

The fact that costs, initially prudently incurred, subsequently become “stranded” or

relate to assets that are no longer considered used and useful is irrelevant to the statutory

direction contained in Section 122 of the Current EU Act.231

228







Neither Stores Block nor Carbon stand for the proposition that an electric utility under

the EUA is now no longer entitled to a reasonable opportunity for recovery of its

prudently incurred costs from customers.232 188. The Alberta Utilities further pointed to the direct assign provisions of the Electric

Utilities Act and the Transmission Regulation AR 86/2007 which require a transmission facilities

owner, except in certain circumstances, to comply with a direction from the Independent System

Operator (ISO) to file an application to build transmission facilities to meet a need identified by

the ISO. In such circumstances “it is manifestly unreasonable to imply a ‘used or required to be

used’ standard on cost recovery or to impose any related risk on the TFO.”233

189. The majority of the UCA’s comments with respect to gas utilities, applied to electric

utilities. In addition the UCA stated that there is no basis in the Electric Utilities Act which

requires any particular treatment of costs and risk. As such, the UCA submitted that it is at the

discretion of the Commission to determine risk for stranded assets in accordance with accepted

legal and regulatory principles.234 In argument, the UCA noted the provisions of the Gas Utilities

Act and the Electric Utilities Act, and went on to state:

The relevant legislation for both gas and electric utilities puts certain constraints on

the Commission by, for example, requiring the fixing of a rate base in the case of

gas utilities, and requiring the Commission to give electric utilities a reasonable

opportunity to recover their capital-related and operating costs, but none of those

provisions prescribe in detail how the Commission must calculate a rate base or measure

capital-related costs. They do not appear to prevent the Commission from, for example,

making whatever rate base adjustments it considers necessary in order to fairly balance

the interests of customers and shareholders in light of whatever asset transactions have

taken place since the utility’s last rate proceeding.235

190. Calgary noted in reply argument that “the Electric Utilities Act has a number of

references to assets being ‘used,’ which would be a narrower criterion than used and useful or

used and required to be used.”236

3.2.1.5 Issue 2.1.5 – Applicability of stranded asset findings to the 2011 and 2012 test

years.


The Commission stated in its letter of June 28, 2012 addressed to each of AltaGas

Utilities Inc., AltaLink Management Ltd., ATCO Utilities, ENMAX Power Corporation,

EPCOR Distribution & Transmission Inc. and FortisAlberta Inc. that the Commission

would consider in this proceeding “whether its findings should apply to 2011 and 2012 or

prospectively.

192. The Alberta Utilities and the UCA submitted that any change to the risk faced by the

utilities be adopted by the Commission prospectively and should not apply to 2011 or 2012.

Calgary did not make a submission on this issue.

232








193. The Alberta Utilities submitted that should any change to the risk faced by the utilities be

adopted by the Commission, it should only be applied on a prospective basis allowing the

Alberta Utilities and their investors and lenders a reasonable opportunity to react.237

194. The Alberta Utilities submitted that a prospective approach would be “far more efficient

than reopening the associated issues of risks and return, as a re-examination of 2010-2012

returns and capital structure would necessarily be required to ensure the Fair Return Standard is

upheld in all impacted periods.”238

195. The UCA noted that any change to the allocation of stranded assets and post-retirement

costs should be done on a prospective basis.239

Issue 2.2 – Responsibility for ongoing costs of retired assets 3.3

196. The final revised issues list summarized the issue with respect to the responsibility for

ongoing costs of retired assets under Issue 2.2 as follows:

Decision 2012-156 referred the Stores Block related issues associated with production

abandonment to this proceeding. In addition, Decision 2012-311 referred to this

proceeding reclamation costs for retired production facilities that raise issues regarding

the treatment of assets no longer required for the provision of utility service.

Accordingly, this proceeding will consider as between the gas utility shareholder and

ratepayers, who should be responsible for ongoing costs and liabilities associated with

assets that are no longer “used or required to be used” to provide utility service but which

have been fully consumed in providing utility service. The Commission will also

determine as between the electric utility shareholder and ratepayers, who should be

responsible for ongoing costs and liabilities associated with assets that are no longer

required to provide utility service but which have been fully consumed in providing

utility service.

197. While this issue deals with the responsibility for ongoing costs and liabilities associated

with retired gas and electric utility assets, the matter arose primarily in the context of Decisions

2012-156 and 2012-311 relating to the production and abandonment expenses for retired

production properties still owned by ATCO Gas and AltaGas, respectively. ATCO Gas retains

production and abandonment obligations for retired production property in both its north and

south service areas. The obligations in the north are the subject of settlement agreements240

discussed in Section 3.4 below.241

198. In the case of AltaGas, with the exception of an active station located at the retired

Stettler production site, there are no physical assets or costs related to the production assets

remaining in rate base. Each of the retired sites, excluding Stettler, has either had a reclamation

certificate issued or reclamation is currently in progress. AltaGas submitted that any ongoing

operational and remediation costs, and additional reclamation work required in the future, for all

former production sites should be recoverable from rate payers.242

237



Exhibit 94.02, AlbertaUtilities-UCA-01. 240


Decision 2001-104, Viking, and Decision 2002-116, Beaverhill Lake and Fort Saskatchewan. 242

Exhibit 96.01, AUC-AlbertaUtilities-07(a).



199. Decisions 2012-091243 and 2012-311 related to AltaGas’ 2010-2012 GRA Phase I,

permitted interim recovery of production abandonment costs for the retired assets, but any future

recovery is contingent on the Commission findings in this proceeding.244

200. The positions of the parties with respect to ongoing costs of retired assets, ranged from

the Alberta Utilities’ view that ratepayers are responsible for costs arising after assets have been

retired and removed from service, to Calgary’s view which stated that ratepayers are not

responsible for any ongoing costs of retired assets. The Alberta Utilities submitted that current

depreciation practices ensure customers pay no more and no less than the costs related to the

assets required to provide utility service while enabling utilities to recover their prudently

incurred costs to which they are entitled in accordance with legislation in Alberta. The UCA took

the position that neither the courts nor the legislation require the allocation of ongoing costs of

retired assets to be borne exclusively by the shareholders or by the customers. Allocation of these

costs remains a matter to be determined by the Commission in accordance with accepted

principles.

201. In its evidence, the Alberta Utilities stated that that the majority of ongoing costs once an

asset has been retired from service relate to its reclamation, remediation, removal and

abandonment which the Alberta Utilities refer to as “post-retirement costs.”245

202. The Alberta Utilities took the position that nothing in Stores Block, Carbon or subsequent

cases or in the legislation support a finding that would deny the utilities an opportunity to recover

prudently incurred costs including post-retirement costs. The Alberta Utilities submitted that

paragraph 68 of Stores Block confirms the ratepayers obligation to pay for full costs of service.246

203. The Alberta Utilities submitted that, in Decisions 2011-450 and 2011-474, the

Commission has appeared to mistakenly assume that Stores Block and related case law apply to

all dispositions and retirements, rather than only applying to dispositions outside the ordinary

course of business.247

204. The Alberta Utilities also pointed to long standing depreciation practices in Alberta that

make use of a depreciation reserve adjustment process, and provided a number of circumstances

under which differences might occur between forecasted post-retirement and actual post-

retirement costs.248 The Alberta Utilities submitted that both the UCAGU and USA recognize

that net salvage is something that occurs after an asset has been retired. Further, these

instruments indicate that “providing that the retirement occurs in the ordinary course of business,

accumulated depreciation is to be charged with the ledger value of the asset, and the cost of

removal, and credited with amounts realized for salvage.”249

205. The Alberta Utilities submitted that the depreciation reserve adjustment permits future

recovery of remaining net book value associated with groups of retired assets, in addition to any

243 Decision 2012-091: AltaGas Utilities Inc., 2010-2012 General Rate Application – Phase I, Application

No. 1606694, Proceeding ID No. 904, April 9, 2012. 244





Exhibit 77.02, Alberta Utilities submission, paragraphs 88 and 89. 249

Exhibit 77.02, Alberta Utilities submission, paragraphs 93 to 96.




unanticipated costs arising after assets have been retired and removed from service.250 It is a

necessary practice that ensures customers pay no more and no less than the costs related to the

assets required to provide utility service. It also enables utilities to recover their prudently

incurred costs to which they are entitled, in accordance with legislation in Alberta.251

206. The Alberta Utilities submitted that the Stores Block line of cases does not limit the

Commission’s discretion in the setting of just and reasonable tolls and that any argument to the

contrary is inconsistent with, sections 36 and 37(2) of the Gas Utilities Act, Section 4(3) of the

Roles, Relationships and Responsibilities Regulation and sections 102, 121 and 122 of the

Electric Utilities Act. The Alberta Utilities stated that these statutory provisions “reflect a

fundamental principle of utility regulation: utilities legally required to provide service are

entitled to recovery of their prudently incurred costs.”252

207. The Alberta Utilities viewed that the UCA’s position regarding continued recovery of

prudently incurred post-retirement costs appeared in general, to align with its own position.

208. The Alberta Utilities disputed Calgary’s view that Stores Block assigns ongoing

retirement costs to shareholders, stating that the ruling only applied to asset dispositions outside

the ordinary course of business and could not be expanded to post-retirement costs; costs which

do not involve a disposition.253 The Alberta Utilities further noted that the Salt Caverns decision

confirms that a removal from the rate base does not constitute a “disposition.”254

209. The UCA did not consider Stores Block or the legislation as requiring the allocation of

ongoing costs of retired assets exclusively to the shareholders or exclusively to customers. The

UCA submitted that the matter is to be determined by the Commission in accordance with

accepted principles.255 The UCA submitted that the issue should not “be addressed in the abstract

or answered with a rule or policy that must apply in all circumstances.”256

210. The UCA pointed to current depreciation practices that allow, upon asset retirement, the

actual salvage and other costs to be trued-up against the amounts already collected, such that

customers bear the actual costs incurred in relation to the retirement and abandonment of the

assets that were used to provide service to them.257

211. In response to an information request, the UCA agreed that inclusion in rate base was not

a prerequisite for recovery of the applied for abandonment costs in Decision 2011-450 respecting

abandoned properties.258

212. The UCA stated its view in the normal case, where utility assets are retired because they

have been consumed in providing service that it “may be inconsistent with the ‘reasonable

opportunity to recover costs’ principle to require utility shareholders to bear all of the risks and

costs associated with the retirement of such assets and the maintenance of those assets after

250


Exhibit 97.01, UCA-AlbertaUtilities-07. 252







Exhibit 94.02, AlbertaUtilities-UCA-03(a).



retirement.”259 The UCA indicated it was “difficult to see how that outcome is fair, at least absent

some potentially large compensating increase in allowed returns…”260 However, where an asset

has been transferred to an affiliate or redeployed into a non-utility use, it is difficult to see why

customers should bear the post-retirement obligations.261

213. With respect to the ability of utilities to true-up estimates of salvage and other post-

retirement costs against actual amounts after an asset has been retired, the UCA summarized its

views as follows:

…As a general matter the UCA sees no particular benefit to customers in allocating that

risk exclusively to shareholders by eliminating any true-up mechanism, although in

particular fact situations the conclusion could be different. For example, if a utility badly

mis-forecast its on-going post-retirement costs, especially on a consistent basis, it might

be argued that it would be appropriate to fix the utility with some of that forecasting risk,

and forecasts that were plainly unreasonable would give rise to arguments that the utility

should bear the financial responsibility for that.262

214. In response to the Alberta Utilities description of capital recovery risk for depreciable and

non-depreciable property, the UCA indicated that current practices of allocating capital recovery

risk does not resolve why “it would make sense for there to be a legal or jurisdictional rule that

assigns all capital recovery risk for non-depreciable property to shareholders, but a completely

opposite rule for depreciable property that assigns all cost-recovery risk to customers” and

further why this allocation process is a matter of the Commission’s jurisdiction, as opposed to

being simply a matter of what the Commission thinks is reasonable and appropriate.263

215. The UCA discounted Calgary’s premise that Stores Block establishes a rule of law that

for rate making purposes, that utility shareholders must be fixed with responsibility for all risks

and costs associated with utility property after it is removed from service. The UCA stated that if

the premise were true, then as a matter of law and jurisdiction shareholders would be responsible

for any unrecovered depreciation associated with depreciable assets removed from utility service

for any reason.264

216. Calgary viewed that “ratepayers should only be responsible for the costs associated with

assets that are used and useful.”265 Calgary stated this was consistent with the Supreme Court of

Canada’s ruling in Stores Block that customers only pay for the use of the assets266 and that

retired assets are no longer used by customers to provide utility service.

217. In its argument, Calgary stated its view that “the Stores Block decision substantially and

fundamentally changed the regulatory paradigm in Canada”267 in that the “decision established

that the risk of ownership of an asset committed to utility service rested with the owner.”268

Calgary submitted it is totally inconsistent with the concept of a customer’s responsibility to only

259






Exhibit 111.02, UCA reply argument, paragraph 10. 265



Exhibit 107.01, Calgary written argument, paragraph 3. 268

Exhibit 107.01, Calgary written argument, paragraph 3.



pay for service without rights with respect to an asset; to then have the customers pay costs

related to a retired asset. The exception is a rare circumstance that an asset has been retired from

rate base but is still providing service.

218. Calgary replied to the argument of the Alberta Utilities that a removal from rate base

does not constitute a disposition by stating:

With respect, the issue is not whether a disposition has occurred --- whether inside or

outside the ordinary course, or at all for that matter.

The issue of risk of recovery of post-retirement costs is one connected with ownership, as

per paragraph 69 of Stores Block.269

219. Calgary indicated that burdening ratepayers with ongoing costs for retired assets implies

a degree of retroactivity and that the previous cost of service rates were inadequate. Calgary

argued that on-going costs of retired assets are costs associated with asset ownership, where “the

Courts have been very clear that ratepayers have no ownership interest in the assets.”270

220. Calgary asserted that “if the law with respect to retroactivity, together with a property

interest orientation in proceeds, does not allow the refund to customers of past over-collection,

the same law and principles cannot provide for the recovery of past under-collection.”271 Calgary

submitted that utilities have the opportunity to collect the estimated costs of negative salvage

with respect to the assets employed in utility service, and to the extent that these costs were

poorly estimated, that is a risk of ownership which the utility shareholder must bear.272

Issue 2.3 – Ongoing cost responsibility for retired assets subject to settlements 3.4

221. The final revised issues list summarized the issue with respect to the ongoing cost

responsibility of retired assets subject to settlement agreements under Section 2.3 as follows:

Are utilities entitled to recover ongoing costs related to retired assets such as production

abandonment costs where these costs may have been at issue in previously approved

settlement agreements?

222. The Alberta Utilities’ view was that recovery of the production abandonment costs that

were addressed through settlements found to be in the public interest and approved by the

regulator should not be disturbed. The UCA stated that the Commission undoubtedly has the

ability to modify or eliminate existing settlement agreements, but that any interference in the

settlements should not be undertaken lightly. Calgary was of the view that ongoing cost

responsibility for retired assets is determined by asset ownership.

223. ATCO Gas made certain independent submissions within the written submissions of the

Alberta Utilities.273 ATCO Gas stated that responsibility for ongoing production abandonment

obligations in its north service area was addressed in negotiated settlement agreements which

had been approved by the regulator.274 These settlement agreements related to the sharing of sale

269

Exhibit 112.01, Calgary reply argument, paragraphs 97 and 98. 270


Exhibit 100.01, Calgary rebuttal evidence, paragraph 18. 272

Exhibit 100.01, Calgary rebuttal evidence, paragraph 18. 273

Exhibit 77.02, Alberta Utilities submission, starting at paragraph 118 to 137. 274




proceeds of certain production properties, the refund of net salvage previously collected by the

utilities for the properties that were sold, and the commitment of the customer parties to the

agreement, that any future abandonment costs related to the production assets that were not

included in the disposition and which had already been retired, would be the ongoing

responsibility of customers. ATCO Gas also seeks continued recovery from customers of

expenses incurred in the south service area for similarly retired and abandoned assets. None of

the retired production assets in the south service area are covered by a settlement agreement.

224. The following paragraphs provide a brief overview of the history respecting settlement

agreements in respect of production and abandonment costs for production properties owned by

ATCO Gas in its north service territory (ATCO Gas North).

225. The sale of the ATCO Gas North production assets in the Lloydminster,275 Westlock,

Peace River Arch, Phoenix fields and certain other fields276 were approved in Decision 2001-46277

and Decision 2001-65. The sale of the Viking Kinsella,278 Beaverhill Lake and Fort

Saskatchewan279 production properties was denied. Both decisions became the subject of a

review and variance (R&V) (Application No. 1244045) proceeding which resulted in Decision

2001-104.280

226. Decision 2001-104 granted the application for an R&V281 and approved the sale of the

Viking Kinsella properties in accordance with the “Joint Recommendation” of the utility and the

North Core Customer group representing various customer groups. The “Joint Recommendation”

was set out in the opening statements of ATCO Gas and the North Core Customer group which

reflected the agreement of the parties to recommend approval of the sale transactions. The

opening statements of each party also referred to “certain collateral commitments which are not

the subject of this proceeding.”282

227. The collateral commitments in the two opening statements were worded differently. In

the ATCO Gas opening statement, the collateral commitments contained the following language:

275

Decision 2001-46 and Decision 2001-65 (reasons for Decision 2001-46); respecting Application No. 2001070,

Order 4 of the decisions read: “The Application for the sale of certain petroleum and natural gas rights and

production and gathering assets, storage assets and inventory in the Lloydminster field to AltaGas (Sask.) Inc.

and AltaGas Services Inc. is approved.” 276


Order 2 of the decisions read: The Application for the sale of certain petroleum and natural gas rights and

production and gathering assets in the Westlock, Peace River Arch, Phoenix and other fields not operated by

ATCO Gas – North to Trioco Resources Inc. is approved;” 277

Decision 2001-46, ATCO Gas-North, A Division of ATCO Gas and Pipelines Ltd, Sale of Certain Petroleum

and Natural Gas Rights, Production and Gathering Assets, Storage Assets and Inventory, Application Nos.

2001017, 2001020, 2001030 & 201070, May 29, 2001. 278



production and gathering assets in the Viking Kinsella Field to Burlington Resources Canada Energy Ltd. is

denied;” 279



production and gathering assets in the Beaverhill Lake and Fort Saskatchewan fields to NCE Petrofund Corp.

and NCE Energy Corporation is denied;” 280

Decision 2001-104: ATCO Gas – North, a Division of ATCO Gas and Pipelines Ltd., Review and Variance of

Decisions 2001-46 and 2001-65, Application No. 1244045, File No. 6405-14-1, December 11, 2001. 281

Decision 2001-104, Order 2 of the decision reads: “Decisions 2001-46 and 2001-65 be varied in accordance

with the terms of this Order.” 282

Decision 2001-104, Appendix 3, Opening statement of the NCC, page 21.





Provided the Board approves the sale of the Viking properties on the terms and

conditions set forth above, ATCO Gas is committed to the following collateral

undertakings which do not require Board approval as part of these proceedings:

1. The Company will refund previously recovered negative net salvage. The amount, on a

revenue requirements basis, would be approximately $9 million. This would address the

Viking, Lloydminster and Westlock properties. In exchange for this refund, the NCC

agree that they are responsible for any additional abandonment or removal costs related

to the producing assets owned and previously abandoned by ATCO Gas or its

predecessor companies.283

228. The EUB commented as follows with respect to the collateral commitments:

The Opening Statements also set out certain Collateral Commitments between AGN and

the NCC. While both AGN and the NCC noted that the Collateral Commitments of each

party formed part of the basis for the overall Joint Recommendation, they agreed that the

Joint Recommendation was all the Board needed to approve in relation to the R&V

Application. Those items characterized as Collateral Commitments did not need to be

dealt with in this proceeding, but might be the subject of future proceedings.284

…As submitted by the parties, for purposes of this Decision, the Board has not

considered the Collateral Commitments to form part of the Joint Recommendation. To

the extent that the commitments have been considered by the Board, they have been

considered to be truly collateral to the Joint Recommendation. Nonetheless, when taken

together with the Joint Recommendation, the Collateral Commitments constitute a

balancing of the interests of customers and shareholders.285

229. The sale of the Beaverhill Lake and Fort Saskatchewan production assets was part of the

ATCO Gas North and North Core Customer group negotiated settlement approved in Decision

2002-116.286

230. Decision 2002-116 observed that:

A major component of the Settlement resulted from the inclusion of the sale of the BHL

& Ft. Sask producing properties, which was initially being dealt with in a separate

process. In the Settlement the parties have agreed that the sale should be approved and

that the North Core customers will receive $23,036,000. This is a fixed amount net of the

costs of disposition and return of the net book value of the assets to the shareholders.287

231. The settlement included the following provisions:

The following negotiated items, enumerated in sections 1 through 3, including

amendments to the agreement, other adjustments and related matters, will hereinafter be

collectively called the “Settlement”….

…2. Further matters included in the Settlement, as follows:

283

Decision 2001-104: Appendix 2, Opening statement of ATCO Gas, Section 2. Collateral Commitments,

page 18. 284

Decision 2001-104, Section 5, page 7. 285

Decision 2001-104, Section 7, page 11. 286

Decision 2002-116: ATCO Gas and Pipelines Ltd., (North), Application to Approve 2002 Rates, Amended

North Core Agreement and Sale of Beaverhill Lake and Fort Saskatchewan Properties, Application No.

1283224, December 24, 2002. 287

Decision 2002-116, Section 5.2, page 9.




(f) distribution of net proceeds of $23,036,000 related to the BHL & Ft. Sask disposition

to North Core customers, providing the Board approves the sale of the properties;

…

(i) the obligation of Customers to pay for all additional abandonment or removal costs

related to BHL & Ft. Sask producing assets;288

232. In its evidence in this proceeding, ATCO Gas considered that the matters agreed to are

not severable, and that in approving the payment to customers, “the Board also approved the fact

that customers would remain responsible for all future abandonment costs related to the

remaining production assets which had not been sold.”289

233. ATCO Gas also referred to subsequent proceedings where customers had acknowledged

ongoing cost responsibility for production abandonment costs. In the ATCO Gas 2005-2007

GRA (Application No. 1400690), the Consumer Group stated in argument that “the CG does not

object to the AG North proposal and amount of abandonment and removal costs forecast.”290

234. Further, ATCO Gas noted that in Decision 2008-113291 related to its 2008-2009 GRA, the

Commission stated: “[t]he UCA clarified that it agreed that continued recovery in rates of costs

related to assets which have been physically retired from service after retirement were

appropriate for production properties. This recovery, related to unrecovered production

abandonment costs, was not a guarantee though, and AG should justify these costs in each

GRA…”292

235. ATCO Gas summarized its view by stating that recovery of the production abandonment

costs in the north, was addressed through settlements found to be in the public interest and

approved by the regulator293 and resulted in “providing north customers in excess of $400 million

in sales proceeds including a refund of negative net salvage monies”294 in return for “customers'

commitment to being responsible for future abandonment costs…”295 Accordingly, “both the

regulator and customers have repeatedly acknowledged that the north customers of ATCO Gas

will and should continue to be responsible for all abandonment and post-retirement costs related

to the retired north production assets of ATCO Gas.”296

236. In its 2011-2012 GRA, ATCO Gas applied to recover production abandonment costs

related to 371 north and 119 south abandoned production properties which were previously used

to provide utility service. ATCO Gas described the costs as related to maintaining the

abandonment consistent with current standards and statutes. The costs were described as either

288

Decision 2002-116, Section 3, pages 3 and 4. 289


Exhibit 77.02, Alberta Utilities submission, paragraph 131, Referencing Application No. 1400690, Consumer

Group argument, page 85. 291

Decision 2008-113, ATCO Gas, 2008-2009 General Rate Application Phase I, Application No. 1553052,

Proceeding ID. 11, November 13, 2008. 292

Exhibit 77.02, Alberta Utilities submission, paragraph 132; referencing Decision 2008-113, page 95. 293

Exhibit 108.02, Alberta Utilities argument, paragraphs 134 and 135. 294







environmental remediation of well and other productions sites or management of issues with

previously abandoned properties, such as leaks causing gas migration to the surface.297

237. In the 2011-2012 GRA, ATCO Gas described the abandonment costs related to ATCO

Gas’s north production assets as being the subject of settlements that were found to be in the

public interest and approved by the regulator.”298

238. In Decision 2011-450, the Commission denied the recovery through rates of production

abandonment costs equal to $2.18 million in 2011 and $1.5 million in 2012 stating:

1002. …the Commission considers that all costs, including the ongoing operational and

remediation costs associated with assets that no longer have an operational purpose and

are no longer used or required to be used to provide utility service, such as the abandoned

production assets, should be removed from revenue requirement and be for the account of

the utility shareholder as of January 1, 2011.299

239. With respect to the relevance of the decisions which had approved settlement agreements

relating to the allocation of these production abandonment costs in the north service area, the

Commission stated:

1003. These decisions pre-date the Stores Block decision and the Carbon decision and

accordingly the Commission has not considered them to be relevant to a consideration to

the costs to be allowed in revenue requirement during the current test period.300

240. In Decision 2012-156, the Commission found that ATCO Gas had raised a substantial

doubt as to the correctness of Decision 2011-450 relating to the denial of production

abandonment costs and referred the matter to this proceeding.301

241. The Alberta Utilities submitted that there was nothing in the Stores Block line of cases

that would require the Commission to disrupt any existing settlement agreement.302 ATCO Gas

added that there is no legitimate basis, including consideration of the Stores Block or Carbon

decisions, for the AUC to disturb the effect of the utility’s agreements with customers.303

242. The Alberta Utilities considered that previously approved settlements regarding the

recovery of ongoing post-retirement costs should not be disturbed; viewing such agreements as a

“package of compromises”304 where “it would be unfair to single out any particular item within

an agreement for subsequent disallowance.”305

243. The Alberta Utilities stated that while increasingly stringent environmental regulations

have contributed to differences occurring between expected and actual reclamation costs, it is

297

Proceeding ID No. 969, ATCO Gas 2011-2012 General Rate Application volume 1, pages 5.1 to 6,

paragraph 15. 298




Exhibit 77.02, Alberta Utilities submission, paragraph 118; Decision 2012-156, paragraph 113. 302







consistent “with the UCAGU and USA and longstanding depreciation practice,”306 that the utility

is entitled to cover all such costs.

244. ATCO Gas also submitted that upholding the decision of the Commission to deny

recovery of production abandonment costs would result in customers being unjustly enriched.

This would also have serious implications for regulatory risk and regulatory cost of capital which

would need to be considered. Such a finding would overturn key elements of long-standing

agreements with customers previously found to be in the public interest by the regulator.307

245. When asked to explain the rationale for extending the settlement agreement in Decision

2001-104 for production and abandonment costs to be recovered from ratepayers beyond the test

years referenced in the settlement, the Alberta Utilities responded that the referenced decision

did not relate to any specific test period of ATCO Gas, but referred specifically to the settlement

arrangement.308

246. In response to an information request concerning asset retirement obligations,309 the

Alberta Utilities indicated that none of the Alberta Utilities have recorded an asset retirement

obligation. The Alberta Utilities clarified that this did not mean there is no obligation to incur

asset retirement costs, but due to the significance of discounting to the present value, the

estimated future retirement costs over time, the costs are not considered material.310

247. The Alberta Utilities noted that only Calgary, which has no direct interest in the ATCO

Gas North service areas, appeared to take issue with continued recovery of abandonment costs.

The Alberta Utilities indicated that as they retain the liability associated with these retired assets

in perpetuity, no time limit should be placed on the recovery of the on-going costs required to

comply with legislation, which may impose increasingly stringent standards.311

248. The UCA indicated that “the Commission no doubt has the ability to modify or eliminate

existing settlement agreements if doing so ensures that rates continue to be just and

reasonable,”312 but that “the Commission should not interfere with existing settlement agreements

lightly.”313 Further, the UCA was “not aware of any legal barrier to the Commission”314

concluding “that a settlement is producing rates that are not just and reasonable”315 and therefore

is not legally allowed to remain in effect. If such a conclusion were to be reached, the

Commission could take any necessary steps to ensure rates continue to be just and reasonable.316

Further, ATCO Gas is not contractually entitled to enforce its contract with affected customers

306


Exhibit 77.02, Alberta Utilities submission, paragraphs 136 and 137. 308

Exhibit 96.01, AUC-AlbertaUtilities-07(c). 309

An asset retirement obligation is a financial reporting standard based on FAS 143 that requires the reporting of

legal obligations associated with the retirement of property, plant and equipment assets at the end of their asset

lives. 310

Exhibit 96.01, AUC-AlbertaUtilities-07(d). 311

Exhibit 108.02, Alberta Utilities argument, paragraphs 137 and 138. 312

Exhibit 80.02, submission of the UCA, paragraph 106. 313

Exhibit 109.02, UCA argument, paragraph 60; referencing Exhibit 80.02, submission of the UCA,

paragraph 106. 314

Exhibit 95.02, AUC-UCA-8. 315

Exhibit 95.02, AUC-UCA-8. 316

Exhibit 95.02, AUC-UCA-8.



because utility rates are set by the Commission, and not by any agreement between the utility

and customers.317

249. On the other hand, the UCA indicated that abandoned properties do not need to qualify

for inclusion in rate base as a condition for recovery of associated abandonment costs,318 nor did

Stores Block and Carbon require the Commission to fix shareholders with production and

abandonment costs.319

250. Calgary submitted that the Gas Utilities Act and the Public Utilities Act require the

Commission to determine a rate base for gas utilities. If assets are not in rate base, their costs

should not be included in the costs of service and/or revenue requirement. To pass on the costs

associated with assets that are no longer in rate base to ratepayers amounts to retroactively

charging customers. Further, since the assets are not providing a service to customers, in an

operational sense, these costs must follow the ownership of the assets.320 321

251. In its rebuttal evidence,322 Calgary stated that whether the ATCO Gas production assets

were retired in the normal course, or not, should be irrelevant as would be the utility’s failure to

collect enough in the past to cover the current costs.

252. Calgary submitted that settlements such as those of ATCO Gas’s are “only applicable for

a set (test) period” after which the Commission must determine a new rate base and cost of

service based on the services being provided by assets which are used and useful.323

253. Calgary suggested there is nothing which can be read into Stores Block to suggest that the

Supreme Court of Canada was distinguishing between types of utility assets or timing when it

made its comments on ownership risk.324 Calgary suggested that the risks of ownership would

apply in circumstances where the utility simply retires the asset from service, as in the case of

production abandonment.325 Calgary clarified its point by stating that if the utility is unable to

dispose of an asset because of the associated abandonment costs, it would violate the Stores

Block principle that all ownership risks lie with the shareholder if the utility were to be able to

pass on these costs to customers.326

317

Exhibit 94.02, AlbertaUtilities-UCA-03(c). 318

Exhibit 94.02, AlbertaUtilities-UCA-03(a). 319

Exhibit 94.02, AlbertaUtilities-UCA-03(b). 320



Exhibit 100.01, Calgary rebuttal, paragraphs 15 and 16. 323







Issue 2.4 – Verification of operational purpose 3.5

254. The Commission identified the following issue in the final revised issues list:

Carbon determined that gas utility assets are “used or required to be used” to provide

utility service only when those assets are used in an “operational sense.” This proceeding

will consider how the Commission can obtain periodic assurance that assets notionally

included within a gas utility’s rate base continue to have an operational purpose in

providing utility service. The Commission will also determine if the same level of

scrutiny should be employed with respect to assets owned by electric utilities.

255. The Alberta Utilities argued that the rate base methodology used for gas utilities ensured

that only assets with an operational purpose were included in rate base. Electric utilities were

entitled to recover prudently incurred costs and that the concepts of “rate base” and “used or

required to be used” did not apply to electric utilities. The UCA and Calgary submitted that the

concept of rate base applied to both gas and electric utilities and that for utility assets to be

included in rate base, the utility must confirm or verify that those assets are required to provide

utility service. This could be accomplished as part of a general rate application or through the use

of a verification process.

256. The Alberta Utilities submitted that the concepts of “rate base” and “used or required to

be used” do not apply to electric utilities because Section 116 of the Public Utilities Act states

that Section 90 (determination of rate base) does not apply to electric utilities.327

257. With respect to gas utilities the Alberta Utilities stated:

The "used or required to be used" notion associated with the determination of a rate base

under the GUA and the PU Act is only part of the rate setting process. Continued

application of depreciation practices, for example, are expressly contemplated by

Sections 36 and 37 and have long co-existed with the rate base/rate of return

methodology reflected therein.328

Periodic assurance that rate base assets continue to have an operational purpose is

obtained through the rate setting process under section 37 of the GUA.329

258. The Alberta Utilities stated that the Alberta Court of Appeal’s decision in Salt Caverns

affirmed that the test for prudence in rate setting includes the presumption of prudence in favor

of the utility.330 “[O]nce found prudent, hindsight cannot later convert that finding into one of

imprudence.”331

259. The Alberta Utilities submitted the current rate making processes ensured assets are

retired as required and under PBR, the utilities would be incented to retire assets that were no

longer required to be used. It was also within the Commission’s authority to periodically review

and audit the assets in rate base.332

327






Exhibit 77.02, Alberta Utilities submission, paragraphs 144 to 148.



260. The UCA disagreed with the Alberta Utilities’ assertion that the concept of rate base does

not apply to electric utilities. The UCA’s view was that while the legislation does not require the

Commission to determine a rate base for electric utilities as part of or in the course of

determining just and reasonable tariffs for electric utilities, the Commission has jurisdiction

which it routinely uses to determine rate base.333

261. The UCA also submitted that the Commission should require the utilities to provide

substantial evidence, analysis and confirmation that all its assets in rate base are required for

utility service, over a longer time frame than is available in a rate application.334 However, the

UCA stated that it “does not have in mind any particular scheme or schedule for the type of

process that it suggested.”335

262. Calgary stated that any time a utility seeks approval of rate base for recovery of return, it

must verify that all its assets are useful and required to be used in an operational sense.336 Calgary

also argued that the utilities should be required to provide a list of all land, buildings and

structures, the cost of which is included in rate base or for which owning and operating costs are

included in rates. The list should specify the operational and functional purpose of each of these

assets. Where the size of the property exceed the portion used, as was the case with Harvest

Hills, the portion used for operation and functional purposes should be disclosed separately from

the portion used.337 Calgary also considered that a materiality threshold should not be used with

respect to the compilation of the list to ensure full disclosure.338

4 Commission findings

Application of Stores Block 4.1

263. The Supreme Court of Canada’s decision in Stores Block was issued in 2006. The court

found that the EUB could not allocate to customers a portion of the proceeds from the sale of

assets outside of the ordinary course of business of a gas utility. Rather, all proceeds of

disposition are the property of the utility shareholders. Similarly, all losses arising from a

disposition of an asset outside of the ordinary course of business are the responsibility of the

utility shareholders.

264. While Stores Block and the subsequent Alberta Court of Appeal decisions (Carbon,

Harvest Hills and Salt Caverns) dealt with the disposition of assets outside of the ordinary

course of business by gas utilities under Section 26(2) of the Gas Utilities Act, the Commission

considers that these cases are equally applicable to the disposition of assets by electric utilities

outside of the ordinary course of business under Section 101(2) of the Public Utilities Act. This

section applies to electric utilities and is to the same effect as Section 26(2) of the Gas Utilities

Act.

265. With the Supreme Court of Canada’s decision in Stores Block, the way in which the

treatment of gains and losses arising upon the disposition of utility assets under Alberta

legislation has evolved. The PUB had found that gains and losses on the disposition of all assets

333




Exhibit 76.01, Calgary submission, paragraphs 46 and 47. 337

Exhibit 92.01, AUC-Calgary-11. 338




were for the account of utility customers, whether inside or outside of the ordinary course of

business, and whether depreciable or non-depreciable property. Later, the EUB (after TransAlta)

had adopted the practice of sharing gains on the disposition of assets outside the ordinary course

and leaving the responsibility for losses with customers. In Stores Block, the Supreme Court of

Canada found that gains and losses on the disposition of all assets outside of the ordinary course

of business were for the account of the utility shareholders, not customers.

266. In making its decision, the Supreme Court of Canada reviewed many of the fundamental

principles of property law and how they apply to rate regulation. This review by the court

warranted a re-examination by the Commission of the way in which utility assets are treated for

rate regulation purposes in Alberta in order to ensure that the regulatory framework was

consistent with the principles the court had expressed.

267. The Commission commenced this proceeding in 2008 in order to do just that. However,

the proceeding was delayed and, in the interim, a number of other related cases came before the

Alberta Court of Appeal. The reasons given by the Alberta Court of Appeal in those decisions

provided further guidance on the interpretation of the Stores Block decision while raising other

matters for consideration.

268. One of the issues in this proceeding is whether Stores Block and the related Alberta Court

of Appeal decisions apply to more than just property disposed of outside of the ordinary course

of business. Among the fundamental principles that Stores Block addressed, the Supreme Court

of Canada provided a reminder that regulatory agencies derive their jurisdiction from their

enabling statutes and that the exercise of the powers granted must be grounded in the main

functions and purposes of the legislation. Clearly, this principle applies to more than just the

regulation of assets disposed of outside the ordinary course of business. Indeed, even the

Commission’s public interest mandate, including its mandate to approve only rates that are just

and reasonable, must be exercised within the confines of the grants of powers to the Commission

and in pursuit of the purposes of the various pieces of legislation being applied. The Supreme

Court of Canada stated: “[t]he limits of the of the powers of the Board are grounded in its main

function of fixing just and reasonable rates (“rate setting”) and in protecting the integrity and

dependability of the supply system.”339 Once again, this principle cannot be limited to dealing

with assets disposed of outside of the ordinary course of business.

269. In deciding the jurisdictional question on the ability of the Commission to allocate

proceeds of sale arising upon the disposition of a utility asset, the Supreme Court of Canada in

Stores Block needed to consider fundamental issues of rate regulation and the ownership and

treatment of utility assets. In particular, and most importantly for the issues raised in this

proceeding, the court emphasized that utility assets are the property of the utility company and its

shareholders and that customers of utility companies do not purchase a property interest in those

assets when they purchase utility services.340

Do Stores Block principles also apply to the disposition of assets inside the 4.2

ordinary course of business?

270. The Supreme Court of Canada in Stores Block was required to consider the jurisdiction of

the Alberta Energy and Utilities Board under Section 26(2) of the Gas Utilities Act in the context

of a sale of utility assets outside of the ordinary course of business. Neither Section 26(2) of the

339





Gas Utilities Act nor Section 101(2) of the Public Utilities Act applies to dispositions within the

ordinary course of business. In Stores Block, the court made only tangential reference to

dispositions of assets within the ordinary course of business. At paragraph 44 of the Stores Block

decision the Supreme Court of Canada stated:

44 It is interesting to note that s. 26(2) does not apply to all types of sales (and leases,

mortgages, dispositions, encumbrances, mergers or consolidations). It excludes sales in

the ordinary course of the owner's business. If the statutory scheme was such that the

Board had the power to allocate the proceeds of the sale of utility assets, as argued here,

s. 26(2) would naturally apply to all sales of assets or, at a minimum, exempt only those

sales below a certain value. It is apparent that allocation of sale proceeds to customers is

not one of its purposes.

271. The Alberta Utilities submitted that Stores Block only applies to dispositions outside of

the ordinary course of business and that the principles expressed in that decision cannot be said

to also apply to the disposition of utility property within the ordinary course of business. While

the Commission recognizes that Stores Block dealt with a disposition outside of the ordinary

course of business, the Commission considers that the utility asset ownership principles

established by Stores Block and discussed above must apply to all utility property, regardless of

whether the property is disposed of inside or outside of the ordinary course of business. To hold

otherwise and find that it is customers that receive the benefit of any gain or bear the risk of loss

for utility property other than in the case where it is disposed of outside of the ordinary course of

business would mean that customers must have acquired some sort of property interest in those

assets, contrary to the findings of the court in Stores Block. Indeed, paragraph 44 of the Stores

Block decision recognizes that there is no authority in the Gas Utilities Act (or by implication the

Public Utilities Act) to allocate gains or losses from the disposition of assets inside the ordinary

course of business. It is inconsistent with the principles in Stores Block to suggest that customers

do, or do not, gain a property interest in utility property, and receive the gains or bear the losses

accordingly, depending on the nature of the circumstances of the disposition of the asset.

272. In the Commission’s view these findings and principles apply equally to gas and electric

utilities.

Inclusion of assets in rate base 4.3

273. The Alberta Court of Appeal has recognized and applied the principle that utility assets

are the property of the utility company in finding that the Commission may not order that gas

utility assets remain in rate base unless they continue to be used or required to be used for utility

service and, indeed, “the rate-regulation process allows and compels the Commission to decide

what is in the rate base” determined on the basis of the “traditional test” of whether the assets are

used or required to be used.341 The Commission may not order that gas utility assets remain in

rate base for the sole purpose of capturing any revenues from those assets for the benefit of

customers. Further, a utility does not require the consent of the Commission to withdraw from

rate base and utility service, property that is no longer used or required to be used, or indeed any

other assets (subject to a prudency review). To require such assets to remain in rate base, would

deprive the utility and its shareholders of the revenue or other benefits derived from that

property. It is the gas utility and its shareholders that own the utility property and accordingly are

entitled to receive the benefits from, or bear the risk of loss or liability associated with, property

that is no longer used or required to be used to provide utility service.

341




274. This is made clear by the numerous references in the court cases to the requirement that

assets that are no longer used or required to be used for utility service may not be included in rate

base. For example, in Carbon the Alberta Court of Appeal stated:

Section 37 of the Act is primarily forward looking. The Board’s jurisdiction is to set rates

“afterwards”, that is for the future: Northwestern Utilities v. City of Edmonton, [1979] 1

S.C.R. 684 at pg. 691. The words “used or required to be used” are intended to identify

assets that are presently used, are reasonably used, and are likely be used in the future to

provide services. Specifically, the past or historical use of assets will not permit their

inclusion in the rate base unless they continue to be used in the system. The fact that the

Carbon storage facility was previously used to provide service may provide some

context, but it is largely irrelevant to whether that asset should remain in the rate base.342

275. The court determined that “the only reasonable reading of s. 37 is that the assets that are

‘used or required to be used’ to provide service are only those used in an operational sense.”343

The court further found that the concept of assets remaining in rate base indefinitely was

contrary to the Stores Block decision.

The Act does not contain any provision or presumption that once an asset is part of the

rate base, it is forever a part of the rate base regardless of its function. The concept of

assets becoming “dedicated to service” and so remaining in the rate base forever is

inconsistent with the decision in Stores Block (at para. 69). Such an approach would

fetter the discretion of the Board in dealing with changing circumstances. Previous

inclusion in the rate base is not determinative or necessarily important; as the Court

observed in Alberta Power Ltd. v. Alberta (Public Utilities Board) (1990), 72 Alta. L.R.

(2d) 129, 102 A.R. 353 (C.A.) at pg. 151: "That was then, this is now."344

276. In Harvest Hills, the Alberta Court of Appeal stated:

Section 37 of the GUA permits inclusion in the rate base of assets "used or required to be

used to provide a service to the public". … once it was determined that there was surplus

land, it should have been removed from the rate base as no longer "required to be

used."345

277. In Salt Caverns the Alberta Court of Appeal stated:

…this Court’s recent decision in “Carbon” where the Court held that the Board had no

jurisdiction to include in rate base, assets which were not being used or required to be

used in providing service to the public, in an operational context. Past or historical use of

assets does not permit their inclusion in rate base unless they continue to be used in the

system.346

278. Also in Salt Caverns:

Can it be reasonably argued that this regulatory power is confined to ruling on adding

new items to the rate base, but inapplicable to excluding old or unused items? No.

Phillips, op. cit supra, at 302 quotes another established textbook and lists items which

342








regulatory commissions may exclude from the rate base. They include obsolete property,

property to be abandoned, overdeveloped property and facilities for future needs, and

property used for non-utility purposes.347

The paragraphs above show that the rate-regulation process allows and compels the

Commission to decide what is in the rate base, i.e. what assets (still) are relevant utility

investment on which the rates should give the company a return. The traditional test is

whether they are used or required to be used, and (as will be seen below) nothing in the

legislation changes that.348

279. Once a gas utility asset is no longer used or required to be used, it must be removed from

rate base and the further disposition of that asset through a sale or other disposition, including

use for the provision of unregulated services, is the business of the company and its shareholders

– not of utility service customers (subject to approval if a disposition is made outside the

ordinary course or rate adjustments on prudence reviews). Accordingly, it is the gas utility and

its shareholders that receive the benefit of any gain or bear the risk of loss for all utility property

that ceases to be used or required to be used to provide utility service.

280. The Alberta Utilities submitted that the “used or required to be used to provide utility

service” concept and the line of Alberta Court of Appeal cases that deal with that concept do not

apply to electric utilities. They noted that the terms “rate base” and “used or required to be used

to provide utility service” are not included in the Electric Utilities Act. Further, the Alberta

Utilities note that the provisions of the Public Utilities Act that contained these terms were

expressly made inapplicable to electric utilities under Section 116 of that statute.

281. The Alberta Utilities also submitted that the Electric Utilities Act requires that a utility be

provided with an opportunity to recover prudently incurred costs and to earn a reasonable return

on its investment requires that once a utility asset is found to have been prudently incurred and

consequently included in utility service (rate base under the Commission’s electric utility

regulatory practice), it is to remain there until it has been fully paid for by customers, regardless

of whether it continues to be used or required to be used for the provision of utility service. The

Alberta Utilities stated:

Any discretion the Commission has to determine recoverability of costs and expenses is

limited to determining whether those costs were prudent when they were incurred. It is

contrary to the plain and ordinary meaning of the Current EU Act for the Commission to

apply a used and useful standard where the clear direction of the section [section 122] is

to base the decision on the prudence of costs when they were incurred.349(emphasis

included in original)

The fact that costs, initially prudently incurred subsequently become "stranded" or relate

to assets that are no longer considered to be "used and useful" is irrelevant to the statutory

direction contained in Section 122 of the current EUA.350

282. In the Commission’s view, this position is in conflict with the property ownership

principles enunciated in Stores Block. The Supreme Court of Canada stated:

347







The fact that the utility is given the opportunity to make a profit on its services and a fair

return on its investment in its assets should not and cannot stop the utility from benefiting

from the profits which follow the sale of assets. Neither is the utility protected from

losses incurred from the sale of assets…...ownership of the assets is clearly that of the

utility; ownership of the asset and entitlement to profits or losses upon its realization are

one and the same.351

Despite the consideration of utility assets in the rate-setting process, shareholders are the

ones solely affected when the actual profits or losses of such a sale are realized; the utility

absorbs losses and gains, increases and decreases in the value of assets, based on

economic conditions and occasional unexpected technical difficulties, but continues to

provide certainty in service both with regard to price and quality.352

283. The Commission also observes that while the terms “rate base” and “used or required to

be used to provide utility service” are not employed in the Electric Utilities Act, the same

concepts apply. Section 122 of the Electric Utilities Act requires the Commission in setting a

tariff to provide an “electric utility” with a reasonable opportunity to recover its prudent costs.

An “electric utility” is defined, in part, as a “transmission facility” or an “electric distribution

system” that is “used” to provide utility services. An “electric distribution system” is defined as

the assets and services “necessary to distribute electricity.” A “transmission facility” is a facility

that “transmits electricity” and includes “all property of any kind used for the purpose of, or in

connection with, the operation of the transmission facility.”353 Therefore, Commission-approved

tariffs for electric utilities must provide the electric utility a reasonable opportunity to recover the

prudently incurred costs of utility assets that are used in (necessary to) the provision of electric

utility service in the same way that Commission-approved tariffs for gas utilities must provide

the gas utility with a reasonable opportunity to recover the prudently incurred costs of utility

assets included in rate base. The Commission has no authority to include in rates the cost of

assets that are not presently used, reasonably used or are likely to be used in the future to provide

services to customers regardless of whether the statutory requirement is described as being “used

or required to be used” to provide gas utility service or “used” or “necessary to” the provision of

electric utility services. Therefore, the Commission finds that the principles related to assets used

or required to be used to provide utility service established in the Alberta Court of Appeal cases

dealing with gas utility assets apply equally to electric utility assets and, accordingly, the costs of

all utility assets of both gas and electric utilities that are no longer used or required to be used for

utility service must be removed from customer rates. All revenues generated by, and all costs

associated with, such assets that are no longer used or required to be used for utility service are

for the account of the utility shareholder.

284. Having reached the above conclusions, the question which then arises is whether there is

a statutory basis for dealing with the gains or losses associated with assets differently, depending

on the nature of the circumstances in which they cease to provide utility service.

Depreciation 4.4

285. Depreciation is the method by which the Commission determines the component of rates

intended to compensate the utility for the cost of the assets acquired by the utility for the purpose

of providing utility service. The underlying premise of depreciation is to return to the utility the

351



See sections 1(1), (m), (o) and (bbb) of the Electric Utilities Act.



cost of these assets over the period of time that they are used to provide utility service. The

positive or negative amounts arising from the retirement and net salvage activities associated

with the removal of utility assets from service are also estimated and included within the total

depreciation charge as a salvage component.

286. The Alberta Utilities maintained that the legislative provisions relating to the recovery by

utilities of prudently incurred costs including provisions relating to depreciation and return on

equity, together with the UCAGU and the USA, provide a complete framework for the recovery

of utility investment and return on that investment. This framework includes mechanisms for

cost recovery for assets that are retired or removed from utility service and for the disposition of

utility assets within the ordinary course of business. The Alberta Utilities and UCA emphasized

that the depreciation framework ensures that customers pay no more and no less than the costs of

the assets acquired and used for utility purposes.354

287. As noted above, the Supreme Court of Canada emphasized that the powers of the

Commission are grounded in its main function of fixing just and reasonable rates and in

protecting the integrity and dependability of the supply system. Further, the Commission’s

powers have to be interpreted within the context of its governing legislation.355 Each of the

Electric Utilities Act, the Gas Utilities Act and the Public Utilities Act require the Commission to

establish a tariff that fixes just and reasonable rates. Rates must provide a utility with a

reasonable opportunity to recover its prudently incurred costs and a reasonable return on its

equity investment in assets used to provide utility services. In this rate setting context, the

Commission may establish and approve methods of depreciation, amortization or depletion of

prudent utility investments.356

288. Two issues must be considered in determining whether the current regulatory framework

for depreciation complies with the principles set out by the Supreme Court of Canada and the

Alberta Court of Appeal for interpretation of the Commission’s powers. First, does the approved

depreciation methodology comply with the principles in Stores Block and subsequent cases?

Second, does the Commission have the authority to include, as a part of its depreciation

methodology, a provision that charges or refunds to customers, on a prospective basis,

depreciation rate adjustments resulting from an over or under recovery of depreciation expense

in prior years?

4.4.1 Does the depreciation methodology comply with the principles in Stores Block

and subsequent cases?

289. The Commission has approved a depreciation methodology which is intended to return to

the utility, the capital investment made by the utility in the assets used to provide utility services.

The approved depreciation methodology is intended to be used in calculating depreciation rates

which will return the original capital investment in each asset to the utility over its useful service

life. The depreciation methodology also includes a charge to recover the net of costs and/or

354



Electric Utilities Act, sections 118(1)(c) and 122(1)(a); Gas Utilities Act, sections 35(e), 36(b) and 37(2); Public

Utilities Act, sections 88(e), 89(b) and 90(2).



proceeds (called net salvage),357 associated with the retirement, decommissioning and any

ongoing remediation of an asset once it has reached the end of its useful service life.

290. The current depreciation methodology used in Alberta calculates depreciation on the

basis of mass property account categories.358 These mass property accounts are used for the

purpose of grouping homogeneous assets that are used in a comparable manner by the utility and

expected to have similar average life and net salvage characteristics. The use of mass property

accounts in general, also recognizes the impracticality of accounting for each utility asset

individually.

291. The depreciation methodology for the assets within each mass property account is

comprised of what is often referred to as a depreciation system and in Alberta primarily

incorporates a straight line method,359 a whole life technique,360 and an equal life grouping

procedure.361

292. The depreciation expense component of the revenue requirement is designed and forecast

to collect, over the service life, the full investment in each asset (including any anticipated net

removal and any anticipated future remediation costs minus any forecast salvage value).

Therefore each asset is targeted to be fully depreciated at the precise time its service life ends.

However, this cannot be achieved on an individual asset basis in a precise manner. This is so

because the assets of the utilities regulated by the Commission include thousands of relatively

small items such as meters, pipe segments, wire segments, poles, transformers, gas regulating

stations and many others. It is not practical, nor cost effective, to track the depreciation and net

book value of individual assets. Instead, all depreciable assets, including buildings and other

assets, are depreciated in groups of similar assets with similar expected service lives, known as

mass property accounts.

293. Iowa survivor curves (retirement dispersion curves) measure the life cycle of a class of

assets using observed life tables plotting actual life experiences, in order to determine an average

life cycle for depreciation purposes. Iowa survivor curves are used to predict the percentage of

assets in a mass property account that will retire each year. When a particular asset retires,

(whether before or after the estimated average service life of the group of assets in the mass

property account) it is assumed that the retirement occurred at a point in time that was allowed

for statistically in the estimation of the depreciation rate which considered the average service

357

Public Utility Depreciation Practices, August 1996, NARUC, page 322 provides the following definition of net

salvage as “The gross salvage for the property retired less its cost of removal.” 358

Exhibit 124.01, AUC-AlbertaUtilities-18; Exhibit 121.02, AUC-UCA-14(b). 359


straight line method as “A depreciation method by which the service value of plant is charged to depreciation

expense (or a clearing account) and credited to the accumulated depreciation account through equal annual

charges over its service life.” 360

Public Utility Depreciation Practices, August 1996, NARUC, page 327 provides the following definition of the

whole life technique where “The whole life technique bases the depreciation rate on the estimated average

service life of the plant.” The Commission notes that the whole life technique is in contrast to the remaining life

technique which depreciates over remaining life as to opposed to whole expected life from the date of

installation. 361


equal life group procedure as “A depreciation procedure by which each vintage is divided into equal life groups,

and the investment in each group is recovered over the expected life of that group. The vintage average life is

then computed as the reciprocally weighted average of the lives of the equal lives groups still surviving in the

vintage.”



life, Iowa survivor curve and net salvage. In effect the Iowa survivor curve anticipates that a

certain percentage of assets will retire each year. The actual mortality of plant assets is only

known with certainty after the plant has lived its useful life, as are the costs associated with the

retirement of utility plant. Statistically some assets will retire early and some assets will last long

past the expected average service life. As depreciation is collected in respect of the mass

property account, it is not ascribed or allocated to any particular asset within that mass property

account.

294. To the extent that a group of assets in a mass property account retires, on average, at a

faster or slower rate than contemplated, or the actual net salvage percentage differs from the

contemplated percentage, these differences are calculated at the time of the next depreciation

study and the difference is amortized over the remaining life of the assets that continue to

provide utility service and which continue to be accounted for in the mass property account.

295. Under this method, no gains or losses are considered to occur on the retirement and/or

disposal of individual assets in the ordinary course of business because they are retired or

disposed of at the end of their useful lives.362 The amount of accumulated depreciation collected

on each retired asset is considered to be exactly the amount that will result in no gain or loss. No

gains or losses are booked in the accounting records.

296. Accordingly, the Commission finds that the approved depreciation method currently used

by the majority of utilities in Alberta, which incorporates the use of mass property accounts in

conjunction with the straight line method, a whole life technique, equal life group procedure and

Iowa survivor curve and net salvage considerations, not only complies with the Stores Block and

Alberta Court of Appeal principles but that its development appears to have been informed by

those principles before these matters were addressed in these cases. The effect of this

depreciation method is to remove from rate base and customer rates depreciable assets that are

no longer used or required to be used to provide utility service.363

4.4.2 Does the Commission have the authority to include, as a part of its depreciation

methodology, a provision that charges/refunds to customers on a prospective

basis, depreciation rate adjustments resulting from an over or under recovery of

depreciation expense in prior years?

297. The depreciation method currently used by the majority of utilities in Alberta is based on

the assumption that the historical rate of retirement (or mortality) of a particular class of assets (a

mass property account) and the historical level of costs associated with the retirement of those

362

UCAGU Regulation, Section 8 (A), page 9, describes that “Ordinary retirements result from causes reasonably

assumed to have been contemplated in prior depreciation provisions, and normally may be expected to occur

when plant reaches the end of its expected service life. In the case of such a retirement, accumulated

depreciation shall be charged with the ledger value and the cost of removal and credited with amounts realized

for salvage and insurance. There is no charge or credit to income for an ordinary retirement.” USA Electric

Plant Instructions, Item 11, page 16 describes that “For retirements unless otherwise defined as gains or losses

on retirement, book value plus cost of removal less salvage value should be charged to the appropriate

accumulated provision for depreciation account.” 363

Some utilities employ the direct life (vintage) approach for some mass property accounts. These types of plant

accounts commonly are comprised of many units of lower cost items for which it is difficult to maintain

continuing plant records. Certain utilities have also used a vintage methodology for leasehold improvement and

computer related accounts and distribution mains. EPCOR Distribution & Transmission Inc. uses the direct life

depreciation method for all of its mass property accounts. The Commission’s findings with respect to the

acceptability of the depreciation method are applicable equally to this depreciation method because it is based

on the same cost recovery principles for assets used in providing utility service.



assets (net salvage costs) will continue into the future. Based on this assumption, a depreciation

study determines the rate of retirement for the assets within a mass property account, based on

the historical rate of actual retirements of those assets, to develop a depreciation rate. This

depreciation rate is intended to recover the capital cost of the assets within the mass property

account and associated retirement costs over their estimated useful lives. The actual asset

retirements occurring in a given year is unlikely to precisely equal the historical retirement

pattern that were used in developing the depreciation rate. New capital additions, actual asset

retirement experience and actual net salvage costs associated with the assets within a mass

property account, are continually recorded and this information is used in each new depreciation

study as the basis for updating the estimated depreciation rate (rate of retirement and net salvage

costs) for the mass property account.

298. It is only when a new depreciation study is prepared that the actual mortality and net

salvage experience of the entire mass property account is re-examined. A depreciation study

normally includes a calculation of what the theoretical accumulated depreciation balance, in

respect of assets still in service would be, had the depreciation parameters and corresponding

depreciation rate determined in the new depreciation study been applied to the mass property

account since the day those assets had been placed into service. When compared to the actual

accumulated depreciation balance, the resulting difference represents the amount at a specific

point in time that must be collected or refunded to customers on a prospective basis through

depreciation expense. The difference can be attributed to the group of assets within the mass

property account but cannot be attributed to any individual asset. The collection/refund

mechanism is called the amortization of reserve differences or the reserve true-up. The

amortization of reserve differences mechanism collects or refunds this difference from customers

over the remaining life of the assets in the mass property account.

299. The Commission has considered whether requiring customers to pay for the amortization

of reserve differences is inconsistent with the Stores Block and Alberta Court of Appeal

principles that it is the utility and its shareholders that, as owner of the assets, bear the risk or

benefit of under or over recovery of capital investment and that assets that are no longer used or

required to be used for utility service must be removed from customer rates. The Commission

has determined that it is not inconsistent with the Stores Block and Alberta Court of Appeal

principles because the purpose of the amortization of reserve differences, in normal

circumstances, is to correct for the forecasting uncertainties (expected in the use of mass

property accounts and Iowa survivor curves) so that customers pay no more and no less, and the

utilities recover no more and no less, than the cost of the assets used to provide utility service

over the period of time in which the assets provided utility service. Further, the Commission’s

mandate is to fix just and reasonable rates and in doing so it is permitted to exercise its discretion

to allow for the amortization of reserve differences in rates in the same way that it is permitted to

exercise its discretion to establish deferral accounts to deal with forecasting uncertainties for

other kinds of costs.364

300. In arriving at the above finding, the Commission has considered whether this approach is

inconsistent with the Supreme Court of Canada’s decision in Stores Block to overturn the Alberta

Court of Appeal’s decision to allow ratepayers to recover the amount of accumulated

depreciation on the stores block building. Stores Block permitted the utility to recover all of the

proceeds of disposition rather than simply the gain that may have been attributable to the

building (proceeds minus original cost and disposition costs) realized upon the sale. The apparent

364

See for example, Calgary (City) v. Alberta (Energy and Utilities Board) [2010] A.J. No. 449, 2010 ABCA 132.



inconsistency is that under the depreciation rules, it appears that at least a portion of the proceeds

from disposition of the stores block building (which was depreciable property) would have been

credited to customers through the mass property account mechanics. The Supreme Court of

Canada credited all proceeds, including those that may have been attributable to customers under

the depreciation rules, to the utility. In making its decision, the court applied the principle that it

is the utility that has the property interest in depreciable assets and has the right, as owner, to

make the business decision of whether to remove or not remove the property from utility service

at any time (subject to a prudence review by the Commission and in the case of a disposition, an

approval under the legislation).

301. The Commission’s approach is not inconsistent with the approach taken by the courts.

Under the approved depreciation rules, the Commission also applies the principle that it is the

utility that has the property interest in depreciable assets and in normal circumstances has the

right to make the business decision of whether to remove the property from utility service (and

therefore rate base and customer rates) prior to the end of its useful life as a utility asset or to

leave the asset in utility service (and therefore in rate base and customer rates) until retirement at

the end of its service life. In the case of a removal of a depreciable asset prior to the end of its

service life (by moving it to a non-utility account or through a disposition outside of the ordinary

course of business), the utility bears the risk of any loss and the benefit of any gains on the future

use of the property.365 Consistent with this approach, where a utility has decided to remove assets

prior to retirement and to dispose of those assets outside of the ordinary course of business, the

Commission has required the utility to remove at the same time all associated assets that are no

longer used or required to be used.366

Stranded assets and post-retirement costs 4.5

302. In this proceeding the Commission canvassed parties on the applicability, if any, of

Stores Block and the Alberta Court of Appeal decisions to the recovery of post-retirement and

abandonment costs associated with assets that are no longer used or required to be used to

provide utility service, and with respect to the recovery of capital invested by a utility in assets

which become stranded or no longer used or required to be used prior to the end of their service

life. Subject to the circumstances described below, the Commission considers that these issues

have been fully addressed in the above discussion of the depreciation method employed by

utilities in Alberta. Accordingly, in normal circumstances, the Commission finds that utilities

retain a reasonable opportunity to recover post-retirement costs, including abandonment costs,

and stranded asset costs under normal depreciation procedures.

303. The Commission remains of the view that it is required to remove from rate base and

customer rates assets that are not presently used, are not reasonably used and are unlikely to be

365

As stated in footnote 363 some utilities employ the direct life (vintage) approach for some mass property

accounts. These types of plant accounts commonly are comprised of many units of lower cost items for which it

is difficult to maintain continuing plant records. Certain utilities have also used a vintage methodology for

leasehold improvement and computer related accounts and distribution mains. EPCOR Distribution &

Transmission Inc. uses the direct life depreciation method for all of its mass property accounts. This

depreciation method also utilizes an amortization of reserve differences account mechanism when a change in

average service life of an account occurs requiring a change in the applicable depreciation rate. The

Commission’s findings with respect to the acceptability of the depreciation method and the use of the

amortization of reserve differences account are applicable equally to this depreciation method because it is

based on the same cost recovery principles for assets used in providing utility service. 366

Decision 2012-068.



used in the future to provide utility services.367 These assets may include obsolete property,

property to be abandoned, overdeveloped property and facilities for future needs, and-property

used for non-utility purposes and surplus land.368 These are examples of property that the

Commission may exclude from rate base that the Alberta Court of Appeal has identified in the

Carbon, Harvest Hills and Salt Caverns decisions. Indeed, in Salt Caverns, the Court of Appeal

said in paragraph 31 that the “rate-regulation process allows and compels the Commission to

decide what is in rate base, i.e. what assets (still) are relevant utility investment” according to the

used and required to be used test. In Harvest Hills the Court of Appeal stated in paragraph 14

that “once it was determined that there was surplus land, it should have been removed from rate

base as no longer ‘required to be used’…” This implies that the Commission and the utility each

have an obligation to remove assets from rate base (remove the costs from utility rates) when

they cease to be “relevant utility investment.”

304. As noted above, the Alberta Utilities stated that the legislative provisions relating to the

recovery by utilities of prudently incurred costs (not disposed of outside of the ordinary course of

business) including provisions relating to depreciation and return on equity, together with the

UCAGU and the USA, provide a complete framework for the recovery of utility investment and

return on that investment. The Commission agrees. The UCAGU in Section 8 states that

“ordinary retirements result from causes reasonably assumed to have been contemplated in prior

depreciation provisions, and normally may be expected to occur when plant reaches the end of its

expected service life.”369 The UCAGU also makes provision for “extraordinary retirements”370

defined as retirements “from causes not reasonably assumed to have been anticipated or

contemplated in prior depreciation or amortization provisions.”371 Under-recovery or

over-recovery of capital investment on ordinary retirements are for the account of customers

under the amortization of reserve differences described above. Under-recovery or over-recovery

of capital investment on extraordinary retirements (as is the case with assets disposed of outside

of the ordinary course of business or moved to a non-utility account) are for the account of the

utility. The treatment of retirements for electric utilities is to the same effect under the USA

Electric Plant Instructions.372

305. In the Commission’s view, the examples of property that the Commission is required to

exclude from rate base referred to above, are examples of extraordinary retirements or of unused

land. These types of assets must be retired (removed from rate base) and moved to a non-utility

account because they have become no longer used or required to be used as the result of causes

that were not reasonably assumed to have been anticipated or contemplated in prior depreciation

or amortization provisions. This conclusion is consistent with the court’s observation in Carbon

(paragraph 23) and again in Salt Caverns (paragraph 14) that “past or historical use of assets

does not permit their inclusion in rate base unless they continue to be used” for utility service. It

is also consistent with Stores Block as interpreted by the Court of Appeal at paragraph 29 of

Carbon: “[t]he concept of assets becoming ‘dedicated to service’ and so remaining in the rate

base forever is inconsistent with the decision in Stores Block.” (paragraph 69)

367


Salt Caverns, paragraph 28, Harvest Hills, paragraph 14. 369

UCAGU Regulation, Section 8 Retirements (A), page 9. 370

Ibid. 371

Ibid. 372

USA General Instructions Item 7, Extraordinary Items and Electric Plant Instructions, Item 11, Additions and

Retirements of Electric Plant.



4.5.1 Special facilities tariffs

306. In some cases, assets that were originally acquired for utility purposes are later employed

for non-utility purposes, including the provision of competitive services. A utility may also

construct new utility-type assets for non-utility purposes, including the provision of competitive

services.

307. In Decision 2011-176, the Commission considered an application by Fortis for approval

of a Special Facilities Charge. Fortis described this charge as follows:

The Special Facilities Charge is a charge that will be applicable to facilities on customer

owned or leased property, as requested by the customer and agreed to by FortisAlberta.

The charge is to be customer specific and would be set out in an agreement between the

customer and FortisAlberta. FortisAlberta would ensure recovery of the associated

revenue requirement of the applicable facilities, which will be calculated on a rate base of

net book value and will include return, income tax, depreciation and operating and

maintenance costs.373

308. In this case, Fortis was under no obligation by the Commission or under the Electric

Utilities Act or the regulations thereunder, to provide this service on the customer’s property. In

its application, Fortis “acknowledges that it could provide this service on an unregulated basis

and that it is not required to seek the Commission’s approval to provide this service or to charge

a rate for it.”374 Fortis also acknowledged that the customer could provide for electric facilities on

its own property.375 This could be done through self-supply, under contract with the local utility

company or under contract with any other qualified service provider. The obligation of the local

utility is limited to connecting the facilities on the customer’s property to the local distribution

system.376

309. The utility’s assets located on customer owned or leased property are being used to

provide a service that could be provided by other service providers. These assets are not used or

required to be used to provide an “electric distribution service” as defined in the Electric Utilities

Act. Therefore, the value of these assets should not be included in the determination of rates for

customers other than the special facilities customer.

310. The practice in Alberta has been for a utility to file an application for a special facilities

charge or similar charge to be included in its regulated tariff for some of these competitive or

non-utility services. The charge for the special facilities is designed to ensure that only the

special facilities charge customer pays the costs associated with special facilities assets.

However, the inclusion of the special facilities assets in rate base raises the possibility that

customers other than special facilities customers would be required, under the approved

depreciation method, to pay for those special facilities assets (including a rate of return), in the

event that the special facilities customer discontinued the service and no other use could be made

of the special facilities. Under the principles established in Stores Block and the Alberta Court of

Appeal cases, the risk of under recovery on this capital asset which was originally found to be

prudent and included in rate base, is for the account of the shareholder because it has ceased to

be used for “electric distribution service.”

373




In certain circumstances, customers may qualify for direct connection to the electric transmission system.



311. The Commission recognizes that the special facilities charge was approved in decisions

2011-176 and 2012-084 on the condition that if these special facilities assets became stranded,

their costs could not be recovered from other customers. The Commission is aware that it has

approved special facilities charges or similar charges for other regulated utility companies in

Alberta. In order to consider the various types of special facilities charges already in place and

how or whether they might be treated in a manner consistent with the Fortis special facilities

charge, the Commission directs that all utilities with approved special facility charges or similar

charges provide the Commission, by January 31, 2014, with a reference to the decision under

which the charge was approved and an explanation of how the service is offered.

4.5.2 Review and variance applications

4.5.2.1 Decision 2011-474, 2011 Generic Cost of Capital

312. In Decision 2011-474, the Commission considered an application by the Alberta Electric

System Operator (AESO) for approval of Rider I which would allow large industrial customers

to pay the construction contribution principal in equal monthly amounts, over a period of up to

20 years, plus a carrying cost (similar to an interest charge) on the unpaid contribution balance,

instead of paying the required construction contribution in one lump sum payment. Rider I would

also allow for contributions that were previously paid for transmission facilities to be refunded

and then re-paid through Rider I.377 Rider I would only be available to fund contributions to

transmission facility owners. The Commission approved in principle the application subject to

the condition that if a Rider I customer were to default on its Rider I payments, “no customer,

other than the customer who is adopting Rider I, should be required to pay for the recovery of the

cost of any portion of the assets financed by Rider I.”378 While the Commission referred to the

Stores Block and the Carbon decisions relating to prohibition against the inclusion in rate base of

assets that are no longer used or required to be used to provide utility service, the Commission’s

principal reason for its condition was that customers, other than the customers that have the

obligation to provide the customer contribution, should not be at risk for default on that

obligation.

313. Parties to the review and variance proceeding of Decision 2011-474 disagreed with the

findings at paragraphs 251 to 252 and 541 to 545, including the statement that “any stranded

assets, regardless of the reason for being stranded, should not remain in rate base” and that the

utilities must “bear the risk where the assets are no longer required for the provision of utility

service.” The Commission agrees that there are circumstances in which assets that are no longer

used or required to be used to provide utility service may remain in utility rates. These

circumstances are discussed in paragraphs 297 and 298 above. The reasons in Decision 2011-474

are varied accordingly, with no difference in the result of that case.

4.5.2.2 Decision 2011-450, 2011-2012 ATCO Gas GRA

314. In Decision 2011-450, the Commission disallowed the recovery of production

abandonment costs of $2.18 million and $1.5 million respectively from the 2011 and 2012

revenue requirements. The Commission noted that the production abandonment costs of

ATCO Gas related to assets that were “no longer ‘used in an operational sense’ as required by

the Carbon decision.”379 The Commission went on to determine that all ongoing abandonment

377

Proceeding ID No. 833, Exhibit 77.02, Appendix B – Previously-Filed Evidence on Amortized Construction

Contribution Rider I, page 36 of 58, paragraph 191, PDF page 32. 378





and remediation costs associated with the production assets should be removed from revenue

requirement and be for the account of the utility shareholder as of January 1, 2011.380 With

respect to whether the previously existing settlement agreements and the regulatory decisions

which approved them were a sufficient basis to require customers to continue to pay for

production abandonment costs, the Commission determined:

1003. …These decisions pre-date the Stores Block decision and the Carbon decision

and accordingly the Commission has not considered them to be relevant to a

consideration to the costs to be allowed in revenue requirement during the current test

period.381

315. The Commission’s findings were the subject of a review and variance application. In

Decision 2012-156 the review panel granted a review of this issue, finding that the record

leading to “Decision 2011-450 shows that the issue of these settlements was not canvassed in the

proceeding.”382 The review panel then referred the issue of who bears the risk of production

abandonment costs to this proceeding, stating:

110. …For the purposes of regulatory efficiency, the review panel considers that the




this issue can be addressed either in Proceeding ID No. 20 or the generic proceeding.383

316. In Decision 2012-311384 the Commission made a similar finding with respect to the

production abandonment costs of AltaGas and referred the issue of who bears the risk of


317. The Commission panel has reviewed the decisions related to production abandonment

costs from the perspective of its findings in this proceeding regarding depreciation methods,

including the treatment of salvage, post-retirement costs and ordinary retirements. Based on

those findings, the Commission finds, consistent with its findings above, that it may include the

production abandonment costs in customer rates if those production abandonment costs result

from causes reasonably assumed to have been contemplated in prior depreciation provisions, and

normally expected to occur when the plant reaches the end of its expected service life. The

evidence filed in the proceeding leading to Decision 2011-450 showed that production

abandonment costs had been included consistently in depreciation studies related to the

production facilities when they were in rate base. The inclusion of production abandonment costs

in rates for these assets is an accepted component of the net salvage calculation. Indeed,

production abandonment costs for assets no longer in rate base were included in settlement

agreements between customer groups and the utility demonstrating that recovery of these

production abandonment costs is an accepted component of the net salvage calculation.

Therefore, the Commission varies Decision 2011-450 to the extent necessary to include the

disallowed production abandonment costs in revenue requirement for the years in question.

Similarly, the Commission approves the inclusion of production abandonment costs for AltaGas

380





Decision 2012-311: AltaGas Utilities Inc., 2010-2012 General Rate Application – Phase I Compliance Filing

Pursuant to Decision 2012-091, Application No. 1608512, Proceeding ID No. 1921, November 23, 2012.



in revenue requirement for the years for which revenue requirement was determined in

Decision 2012-311.

Criteria and conditions for assets disposed of outside the ordinary course of 4.6

business

318. Prior to Decision 2011-450, the criteria used by the predecessors of the Commission to

determine whether the disposition of an asset should be treated as being outside of the ordinary

course of business was considered in several EUB decisions. In Order U2001-196385 the EUB

stated:

With respect to the disposition of assets the Board notes that the GU Act provides little

specific direction. The Board confirms that it must first determine whether the disposition

of an asset is outside the ordinary course of business for a utility. The proceeds of

disposition, NBV [net book value], frequency and type of sale would be among the

factors considered by the Board in that determination. The quantum, and materiality (in

relation to the total rate base) of the proceeds of disposition and the NBV would all be

considered. … The Board would be willing to consider setting a threshold level for asset

sales below which the Board would treat sales as being in the ordinary course of business

for the duration of the Settlement. …The final determination whether a disposition is

outside the ordinary course continues to rest with the Board.386

319. Decision 2011-450 found that other factors should also be considered for ATCO Gas to

determine whether the transaction being examined was outside the ordinary course of business.387

320. The Alberta Utilities requested that the Commission “provide more clarity and simplicity

for all parties as to when an assessment is required as to whether a disposition may be in, or not

within, the ordinary course of a utility’s business.”388 In the view of the Alberta Utilities, the new

criteria could result in virtually all ordinary course dispositions requiring Commission approval

since the consequence of non-compliance is to render the transaction void.389

321. The Commission considers that the criteria articulated in Order U2001-196 are sufficient

for the utility to determine whether a disposition is inside or outside the ordinary course of

business for the purpose of determining if an application for approval of the disposition must be

filed. While the additional criteria provided for in Decision 2011-450 may be useful to the

Commission in evaluating specific cases, the Commission does not consider that these criteria

are necessary for the utility to consider in making a determination of whether it must apply for

approval of a disposition. With this clarification of the additional criteria listed in Decision

2011-450, the utilities may limit the criteria they use in determining whether an application in

respect of a proposed disposition of an asset is necessary to the criteria described in Order

U2001-196.

322. The $1.5 million threshold established for ATCO Gas in Decision 2011-450 as a

guideline for determining when a transaction will be considered to be outside of the ordinary

course of business will continue to apply. Each other utility may apply for a monetary threshold

385

Order U2001-196: NOVA Gas Transmission Ltd, the Sale of the Athabasca Maintenance Facility, Application

No. 2001112, File No. 6417-04, August 3, 2001. 386

Order U2001-196, pages 3 and 4. 387



Exhibit 77.02, Alberta Utilities procedural submission, paragraph 29.

http://www.auc.ab.ca/applications/orders/utility-orders/Utility%20Orders/2001/U2001-196.pdf



guideline applicable to their company in determining if a transaction is within or outside of the

ordinary course of business.

Reinvestment of sales proceeds 4.7

323. In the final revised issues list, the Commission asked parties to comment on the

reinvestment of sales proceed issue with the following question:

Harvest Hills provided guidance on paragraph 77 of Stores Block with respect to the

ability of the Commission to condition the approval of an asset disposition by requiring

the utility to “reinvest part of the sale proceeds back into the company in order to

maintain a modern operating system that achieves optimal growth of the system.” This

proceeding will consider if a reinvestment of a gain on sale pursuant to a Commission

condition in the circumstances described by the Court should be treated as a shareholder

capital investment in rate base by the utility and therefore entitled to earn a return or, if

the reinvestment of the gain should be treated as a reduction to the capital cost of the

replacement asset or as no-cost capital, thereby reducing customer rates. [footnote

removed]

324. Stores Block confirmed that the assets employed by a utility in providing utility service

are the property of the utility and its investors. It also confirmed that the proceeds arising from

the disposition of a utility asset also belong to the utility. A requirement to re-invest these

proceeds “in order to maintain a modern operating system that achieves the optimal growth of

the system” must be done on a basis consistent with this principle. The Commission finds that a

reinvestment of utility proceeds in utility assets is a capital investment like any other and is

entitled to earn a fair return.

4.7.1 Verification of operational purpose

325. In the final revised issues list, the Commission sought submissions from parties on the

following matter:

Carbon determined that gas utility assets are “used or required to be used” to provide

utility service only when those assets are used in an “operational sense.” This proceeding

will consider how the Commission can obtain periodic assurance that assets notionally

included within a gas utility’s rate base continue to have an operational purpose in

providing utility service. The Commission will also determine if the same level of

scrutiny should be employed with respect to assets owned by electric utilities.

326. The Commission has considered the requirement that utility assets be used in an

“operational sense” and notes that in Carbon, the Alberta Court of Appeal explained that assets

that are used or required to be used to provide utility service are “presently used, are reasonably

used and are likely to be used in the future to provide services.”390 In the Commission’s view,

assets used in an “operational sense” means assets that are presently used, reasonably used or

likely to be used in the future to provide utility services.

327. In order to give effect to the court’s guidance that the “rate-regulation process allows and

compels the Commission to decide what is in the rate base, i.e. what assets (still) are relevant

utility investment on which the rates should give the company a return,”391 the Commission

directs each of the utilities to review its rate base and confirm in its next revenue requirement

390





filing that all assets in rate base continue to be used or required to be used (presently used,

reasonably used or likely to be used in the future) to provide utility services.392 Accordingly, the

utilities are required to confirm that there is no surplus land393 in rate base and that there are no

depreciable assets in rate base which should be treated as extraordinary retirements and removed

because they are obsolete property, property to be abandoned, overdeveloped property and more

facilities than necessary for future needs, property used for non-utility purposes,394 property that

should be removed because of circumstances including unusual casualties (fire, storm, flood,

etc.), sudden and complete obsolescence, or un-expected and permanent shutdown of an entire

operating assembly or plant.395 As stated above, these types of assets must be retired (removed

from rate base) and moved to a non-utility account because they have become no longer used or

required to be used as the result of causes that were not reasonably assumed to have been

anticipated or contemplated in prior depreciation or amortization provisions. Each utility will

also describe those assets that have been removed from rate base as a result of this exercise. At

this time, the Commission will not require the utilities to make additional filings to verify the

continued operational purpose of utility assets.

328. The Commission expects that more information about the distribution utilities’ assets will

become available through the asset monitoring requirements being developed by the

Commission through the process established by Bulletin 2012-09396 dated September 13, 2012. In

addition, the Commission has the authority to require the filing of any additional information

relating to any utility assets at any time it may be considered necessary.

Summary 4.8

329. Prior to the Supreme Court of Canada of Canada’s 2006 decision in Stores Block, the

Public Utilities Board had adopted the principle that all gains and losses on the disposition of

utility assets were for the account of utility customers. This principle applied whether the assets

were disposed of inside or outside of the ordinary course of business or whether or not those

assets were depreciable property. In response to TransAlta, the Alberta regulator modified its

approach by determining that gains from the disposition of utility assets outside of the ordinary

course of business would be shared between the utility company and its customers while losses

would continue to be for the account of the customers. The Supreme Court of Canada’s 2006

decision in Stores Block found that all proceeds, including any gains or realized losses, on the

disposition of gas utility assets outside of the ordinary course of business were for the account of

utility shareholders.

330. The Supreme Court of Canada’s decision, however, has much broader significance than

the narrow point directly at issue; namely the jurisdiction of the EUB to allocate proceeds on

disposition of a utility asset outside of the ordinary course of business. In resolving the issue, the

Supreme Court of Canada clarified the law on a number of fundamental regulatory principles. It

explained the underlying statutory interpretation principles and property law principles that

informed its decision. Utility customers, when they pay for utility service, do not acquire a

392

The Commission acknowledges that currently approved depreciation methods are premised on the assumption

in ordinary circumstances, assets will be retired when they reach the end of their useful life and are no longer

used or required to be used. 393



UCAGU, Section 8. 396

Bulletin 2012-09, Stakeholder consultation on AUC Rule 002: Service Quality and Reliability Performance

Monitoring and Reporting for Owners of Electric Distribution Systems and for Gas Distributors, September 13,

2012.

http://www.auc.ab.ca/news-room/bulletins/Bulletins/2012/Bulletin%202012-09.pdf



property interest in utility company assets. The utility and its investors, are entitled to the

benefits and are subject to the risks intrinsic to property ownership. Accordingly, any gains or

losses on utility assets are for the account of the utility and its shareholders, not customers.

331. This understanding of the underlying principles and statutory provisions evolved further

in the Alberta Court of Appeal. In a series of cases, the court applied the Stores Block principles

and provided further clarifications of the statutory provisions dealing with utility assets. In

particular, citing Stores Block and cases that preceded it, the Court of Appeal found that assets

that were no longer used or required to be used for gas utility service were to be removed from

rate base.

332. All of these principles and interpretations, while made in Stores Block and the related

Alberta Court of Appeal cases in the context of gas utility assets disposed of outside the ordinary

course of business, are fundamental to understanding the way in which utility regulation

legislation in Alberta has been designed, whether for gas or electric utilities and whether for

assets disposed of inside or outside the ordinary course of business. The court decisions made it

clear that rates should cover the costs of assets used or required to be used for utility service.

Accordingly, other assets were outside of the Commission’s purview and were of no concern to

the Commission unless their removal from utility service or their disposition would harm utility

customers, in which case the Commission’s authority to determine the prudence of the utility’s

actions would be engaged. A utility’s decision to dispose of an asset outside of the ordinary

course or within the ordinary course, or remove it from rate base through an ordinary retirement

or extraordinary retirement, should be considered by the Commission in the same manner,

namely the prudence of the action in light of the service and rate impacts to customers. Rates

must not include the costs of those assets or be reduced on account of any revenues from those

assets.

333. Indeed, contrary to the positions of some of the parties, the provisions in both the gas and

electric statutes dealing with the disposition of utility assets outside of the ordinary course of

business do not represent an exception to the regulatory framework that applied to other assets.

The Public Utilities Board had observed the same principles applied to all assets whether inside

or outside the ordinary course of business and whether depreciable or non-depreciable property.

This effectively provided customers with a property interest in all utility assets through a policy

of all gains and losses being for the account of the customers. The courts have now clarified the

matter, stating that all proceeds and losses on all utility assets are for the account of the

shareholders, as the sole owners of the utility assets. As property owner, the utility can expect

compensation from customers in respect of its asset only for so long as those assets are used (as

determined on a reasonable basis) to provide service to customers. Whatever the perspective, the

property law principles of ownership must be applied symmetrically to all utility assets.

334. Examination of the depreciation methods employed by utilities in Alberta and the

retirement provisions in the 1963 gas utility accounting regulation and the Commission’s

Uniform System of Accounts reveals that the principles expressed by the Supreme Court of

Canada and applied by the Alberta Court of Appeal, had been built into these instruments and, it

appears, informed their development. The depreciation and retirement methodologies reflect the

statutory requirement as interpreted by the Alberta Court of Appeal that assets no longer used or

required to be used for utility service must be removed from rate base.

335. Most of the time, this is accomplished through the ordinary retirement of assets when

they are no longer used or required to be used. Ordinary retirements are those that occur when



the asset has reached the end of its useful utility service life. At this point, it is considered fully

depreciated. It is removed from utility service (and rate base) and its acquisition cost and salvage

value have been fully recovered from the customers who received service through that asset

either during that period or through a depreciation adjustment made for that purpose after the

fact. In the case of the removal of assets from rate base before they are fully depreciated, any

future revenues or losses from those assets are for the account of the utility shareholders.

336. These observations lead to the conclusion that there is no need for changes to regulations

or rule changes to give effect to the courts’ decisions. The principles upon which they are based

already serve as the foundation for the legislation, regulations and rules in place.

Dated on November 26, 2013.


(original signed by)

Willie Grieve, QC

Chair


Tudor Beattie, QC

Commission Member


Anne Michaud

Commission Member



Appendix 1 – Proceeding participants

Name of organization (abbreviation) counsel or representative

ATCO Electric Ltd.

L. Smith, QC J. Janow L. Kizuk B. Yee L. Kerckhof D. Zavaduk

AltaLink Management Ltd. (AltaLink)

H. Williamson R Block T. Dalgeish, QC A. Lazic J. Piotto D. Morris J. Yeo T. Kanasoot R. Lavergne J. Wrigley K. Evans R. Pallister D. Madsen N. Burns

ATCO Gas and Pipelines Ltd.

L. Smith, QC D. Wilson A. Jukov D. Zavaduk L. Kizuk B. Yee

ATCO Gas D. Wilson A. Green

AltaGas Utilities Inc. (AltaGas) N. McKenzie J. Coleman C. Martin

BP Canada Energy Group ULC C. G. Worthy T. Angel

The City of Calgary (Calgary) D. Evanchuk M. Rowe

Canadian Association of Petroleum Producers R. Graham R. Fairbairn




Consumers’ Coalition of Alberta J. A. Wachowich J. A. Jodoin

Encana Corporation R. Powell D. Dunlop

ENMAX Power Corporation (ENMAX) K. Hildebrandt G. Weismiller D. Nering J. Schlauch T. Carle M. Coyte

EPCOR Utilities Inc. (EPCOR) D. Tenney L. Reid

FortisAlberta Inc. (Fortis) T. Dalgleish, QC M. Stroh J. Sullivan J. Croteau K. Hagel

City of Lethbridge M. Turner O. Lenz

NOVA Gas Transmission Ltd. C. Shaw

City of Red Deer M. Turner L. Gan

Shell Canada Energy R. Gall

Shell Energy North America (Canada) Inc. A. Cherkas

TransAlta Corporation R. Smith L. Berg

Terasen Gas Inc. D. Roy




Office of the Utilities Consumer Advocate (UCA) T. Marriot R. Daw G. Rock A. Glenn M. Stauft B. Shymanski

The Alberta Utilities Commission Commission Panel W. Grieve, QC, Chair T. Beattie, QC, Commission Member A. Michaud, Commission Member Commission Staff

B. McNulty (Commission counsel) D. Cherniwchan S. Allen B. Clarke L. Mullen R. Armstrong, P.Eng.



Appendix 2 – Summary of Alberta legislation

(return to text)

1. Alberta Energy and Utilities Board Act, RSA 2000, c A-17

Powers of the Board

15(1) For the purposes of carrying out its functions, the Board has all the powers, rights and

privileges of the ERCB and the PUB that are granted or provided for by any enactment or by law.

(2) In any case where the ERCB, the PUB or the Board may act in response to an application,

complaint, direction, referral or request, the Board may act on its own initiative or motion.

(3) Without restricting subsection (1), the Board may do all or any of the following:

(a) make any order that the ERCB or the PUB may make under any enactment;

(b) with the approval of the Lieutenant Governor in Council, make any order that the ERCB may,

with the approval of the Lieutenant Governor in Council, make under any enactment;

(c) with the approval of the Lieutenant Governor in Council, make any order that the PUB may,

with the approval of the Lieutenant Governor in Council, make under any enactment;

(d) with respect to an order made by the Board, the ERCB or the PUB in respect of matters

referred to in clauses (a) to (c), make any further order and impose any additional conditions

that the Board considers necessary in the public interest;

(e) make an order granting the whole or part only of the relief applied for;

(f) where it appears to the Board to be just and proper, grant partial, further or other relief in

addition to, or in substitution for, that applied for as fully and in all respects as if the

application or matter had been for that partial, further or other relief.

2. Alberta Utilities Commission Act, SA 2007, c A-37.2

Powers of the Commission

8(1) The Commission has all the powers, rights, protections and privileges that are given to it or

provided for under this Act and under any other enactment and by law.

(2) The Commission, in the exercise of its powers and the performance of its duties and functions

under this Act or any other enactment, may act on its own initiative or motion and do all things that

are necessary for or incidental to the exercise of its powers and the performance of its duties and

functions.

(3) In addition to the powers, duties and functions conferred or imposed on the Commission by this

Act or any other enactment, the Commission may carry out any other powers, duties and functions

determined by the Lieutenant Governor in Council.

(4) The Lieutenant Governor in Council may, by order, require the Commission to carry out any

function or duty specified in the order, including inquiring into, hearing and determining any matter or

thing in respect of any matter within the jurisdiction of the Commission under this Act or any other

enactment, and the Commission shall without unnecessary delay comply with the order.

(5) Without restricting subsections (1) to (4), the Commission may do all or any of the following:

(a) hear and determine all questions of law or fact;

(b) make an order granting the relief applied for;

(c) make interim orders;



(d) where it appears to the Commission to be just and proper, grant partial, further or other relief in

addition to, or in substitution for, that applied for as fully and in all respects as if the

application or matter had been for that partial, further or other relief.

(6) An order of the Commission takes effect at the time provided for by the order or, if no time is

provided for, on the date of the order.

(7) The Commission may delegate any of the powers, duties and functions conferred or imposed on it

under this or any other enactment to any member or any other person unless the regulations under

section 75 prohibit the delegation.

3. Electric Utilities Act, SA 2003, c E-5.1

Interpretation

1(1) In this Act,

(a) “affiliated electricity retailer” has the meaning given to it in regulations made by the Minister

under section 108;

(a.1) “affiliated gas retailer” has the meaning given to it in regulations made by the Minister under

section 108;

(a.2) “affiliated retailer” means an affiliated electricity retailer or an affiliated gas retailer;

(b) “ancillary services” means those services required to ensure that the interconnected electric

system is operated in a manner that provides a satisfactory level of service with acceptable

levels of voltage and frequency;

(c) “Balancing Pool” means the corporation established by section 75;

(d) “bill” or “billing” means an account for charges arising from the generation, transmission,

distribution or sale of electricity;

(e) “Commission” means the Alberta Utilities Commission established by the Alberta Utilities

Commission Act;

(f) “conduct” includes acts and omissions;

(f.1) “critical transmission infrastructure” means a transmission facility designated under the

Schedule as critical transmission infrastructure;

(g) “Crown” means the Crown in right of Alberta and includes an agent of the Crown;

(h) “customer” means a person purchasing electricity for the person’s own use;

(i) “dispatch” means a direction from the Independent System Operator to a market participant to

cause, permit or alter the exchange of electric energy or ancillary services;

(j) “distributed generation” means a generating unit that is interconnected with an electric

distribution system;

(k) repealed 2007 cA-37.2 s82(4);

(l) “distribution tariff billing” means an account for electric distribution service provided to a

retailer or a regulated rate provider;

(l.1) “electric distribution service” means the service required to transport electricity by means of an

electric distribution system

(i) to customers, or



(ii) from distributed generation to the interconnected electric system,

and includes any services the owner of the electric distribution system is required to provide by

the Commission or is required to provide under this Act or the regulations, but does not include

the provision of electricity services to eligible customers under a regulated rate tariff;

(m) “electric distribution system” means the plant, works, equipment, systems and services

necessary to distribute electricity in a service area, but does not include a generating unit or a

transmission facility;

(n) “electric energy” means the capability of electricity to do work, measured in kilowatt hours;

(o) “electric utility” means an isolated generating unit, a transmission facility or an electric

distribution system that is used

(i) directly or indirectly for the public, or

(ii) to supply electricity to members of an association whose principal object is to supply

electricity to its members,

the owner of which

(iii) is required by this Act or the regulations to apply to the Commission for approval of a

tariff,

(iv) is permitted by this Act or the regulations to apply to the Commission for approval of a

tariff, and has applied for that approval, or

(v) passes a bylaw that has been approved by the Lieutenant Governor in Council under section

138,

but does not include an arrangement of conductors intended to distribute electricity solely on

property of which a person is the owner or a tenant, for use solely by that person and solely on

that property or a facility exempted by Commission rules made under section 117;

(p) “electricity” means electric energy, electric power, reactive power or any other electromagnetic

effects associated with alternating current or high voltage direct current electric systems;

(q) “electricity services” means the services associated with providing electricity to a person,

including the following:

(i) the exchange of electric energy;

(ii) making financial arrangements to manage financial risk associated with the pool price;

(iii) electric distribution service;

(iv) system access service;

(v) ancillary services;

(vi) billing;

(vii) metering;

(viii) performing load settlement;

(ix) any other services specified in the regulations made by the Minister under section 115;

(r) “eligible customer” has the meaning given to it in regulations made by the Minister under

section 108;



(s) “exchange” means to provide electric energy to or receive electric energy from the

interconnected electric system;

(t) “farm transmission costs”, in respect of an owner of an electric distribution system, means

(i) the proportion of the owner’s costs of supplying electricity on 25 000 volt lines to the

service area boundaries of rural electrification associations that the total electricity supplied

to rural electrification association members within those boundaries for farm and farm

irrigation purposes bears to the total electricity supplied on those lines, and

(ii) an equivalent dollar amount per unit of electricity supplied by the electric distribution

system to farm and farm irrigation customers who are not members of rural electrification

associations;

(u) “generating unit” means the component of a power plant that produces, from any source,

electric energy and ancillary services, and includes a share of the following associated facilities

that are necessary for the safe, reliable and economic operation of the generating unit, which

may be used in common with other generating units:

(i) fuel and fuel handling equipment;

(ii) cooling water facilities;

(iii) switch yards;

(iv) other items;

(v) “hour” means 60 minutes or any period of less than 60 minutes established as an hour in

accordance with ISO rules;

(w) “Independent System Operator” means the corporation established by section 7;

(x) “industrial system” has the meaning given to it in the Hydro and Electric Energy Act;

(y) “information systems” means systems for the collection, storage and dissemination of data that

identify individual customer consumption of electricity from the interconnected electric

system;

(z) “interconnected electric system” means all transmission facilities and all electric distribution

systems in Alberta that are interconnected, but does not include an electric distribution system

or a transmission facility within the service area of the City of Medicine Hat or a subsidiary of

the City, unless the City passes a bylaw that is approved by the Lieutenant Governor in Council

under section 138;

(aa) “interval meter” means a meter that

(i) measures, at intervals of 60 minutes or less, the amount of electricity consumed, and

(ii) satisfies the standards for revenue collection under the Electricity and Gas Inspection Act

(Canada) and the Weights and Measures Act (Canada);

(bb) “isolated generating unit” means a generating unit that is determined to be an isolated

generating unit in accordance with the regulations made by the Minister under section 99;

(cc) “load settlement” means the process of determining the hourly consumption of electric energy

of each customer in Alberta and providing that information to the Independent System

Operator, retailers and regulated rate providers in order to identify responsibility for purchases

of electric energy exchanged through the power pool;



(dd) “market” means any type of market through or under which an offer, purchase, sale, trade or

exchange of electricity, electric energy, electricity services or ancillary services takes place in

relation to the production or consumption of electricity, electric energy, electricity services or

ancillary services;

(ee) “market participant” means

(i) any person that supplies, generates, transmits, distributes, trades, exchanges, purchases or

sells electricity, electric energy, electricity services or ancillary services, or

(ii) any broker, brokerage or forward exchange that trades or facilitates the trading of

electricity, electric energy, electricity services or ancillary services;

(ff) “Market Surveillance Administrator” means the corporation continued by section 32 of the

Alberta Utilities Commission Act;

(gg) “metering” means the purchase, installation, operation and reading of a meter that measures

and records the amount of electricity that flows through a particular point;

(hh) “Minister” means the Minister determined under section 16 of the Government Organization

Act as the Minister responsible for this Act;

(ii) “municipality” means a city, town, village, summer village, municipal district or specialized

municipality, a town under the Parks Towns Act or a municipality formed by special Act, and

includes a Metis settlement established under the Metis Settlements Act;

(jj) “owner”, in respect of a generating unit, a transmission facility or an electric distribution

system, means the owner, operator, manager or lessee of that unit, facility or system, or any

person who is acting as an agent for the owner, operator, manager or lessee, and in the event

that one of those persons becomes bankrupt or insolvent, includes any trustee, liquidator or

receiver appointed in respect of the bankruptcy or insolvency;

(kk) “person” includes an individual, unincorporated entity, partnership, association, corporation,

trustee, executor, administrator or legal representative;

(ll) “pool price” means the price for each hour established and reported by the Independent System

Operator, in accordance with the ISO rules, for electric energy exchanged through the power

pool;

(mm) “power pool” means the scheme operated by the Independent System Operator for

(i) exchange of electric energy, and

(ii) financial settlement for the exchange of electric energy;

(nn) “power purchase arrangement” means a power purchase arrangement included in Alberta

Regulation AR 175/2000, but does not include

(i) the power purchase arrangement that applies to the H.R. Milner generating unit;

(ii) the power purchase arrangement that applies to the Sturgeon generating units;

(iii) a power purchase arrangement that expires in accordance with the unit effective term

completion date specified in the power purchase arrangement;

(iv) a power purchase arrangement that is terminated under section 15.2 of the power purchase

arrangement;

(v) a power purchase arrangement that is terminated by the Balancing Pool;

(oo) “rate classification customer” has the meaning given to it in regulations made by the Minister

under section 108 or in a regulated rate tariff;



(pp) “rates” means prices, rates, tolls and charges;

(qq) “regulated rate provider” means the owner of an electric distribution system, or a person

authorized by the owner that provides electricity services to eligible customers in the owner’s

service area under a regulated rate tariff;

(rr) “record” includes

(i) information or data regardless of its physical form or characteristics;

(ii) information or data in a form that can produce sound, with or without a visual form;

(iii) information or data in electronic, magnetic or mechanical storage;

(iv) electronic data transmission signals;

(v) any other thing that is capable of being represented or reproduced visually or by sound, or

both;

(vi) anything in which information or data is stored, including software and any mechanism or

device that produces the information or data;

(ss) “regulations” means

(i) regulations made under this Act;

(ii) Alberta Regulation AR 175/2000;

(iii) regulations continued under this Act by a regulation made by the Minister under section

154;

(ss.1) “reliability standards” means the reliability standards made under section 142(1)(l.1);

(tt) “retail electricity services” means electricity services provided directly to a customer but does

not include electricity services provided to eligible customers under a regulated rate tariff;

(uu) “retailer” means a person who sells or provides retail electricity services and includes an

affiliated retailer;

(vv) “rural electrification association” means an association under the Rural Utilities Act that has as

its principal object the supply of electricity to its members;

(ww) “service area” means the area determined under the Hydro and Electric Energy Act from time

to time in which

(i) the owner of an electric distribution system may distribute electricity, or

(ii) a rural electrification association may distribute electricity to its members;

(xx) “service area of the municipality” means the service area for the electric distribution system

owned by a municipality or a subsidiary of a municipality;

(yy) “system access service” means the service obtained by market participants through a

connection to the transmission system, and includes access to exchange electric energy and

ancillary services;

(zz) “tariff” means a document that sets out

(i) rates, and

(ii) terms and conditions;



(aaa) “terms and conditions”, in respect of a tariff, means the standards, classifications, regulations,

practices, measures and terms and conditions that apply to services provided under the tariff;

(bbb) “transmission facility” means an arrangement of conductors and transformation equipment that

transmits electricity from the high voltage terminal of the generation transformer to the low

voltage terminal of the step down transformer operating phase to phase at a nominal high

voltage level of more than 25 000 volts to a nominal low voltage level of 25 000 volts or less,

and includes

(i) transmission lines energized in excess of 25 000 volts,

(ii) insulating and supporting structures,

(iii) substations, transformers and switchgear,

(iv) operational, telecommunication and control devices,

(v) all property of any kind used for the purpose of, or in connection with, the operation of the

transmission facility, including all equipment in a substation used to transmit electric

energy from

(A) the low voltage terminal,

to

(B) electric distribution system lines that exit the substation and are energized at 25 000

volts or less,

and

(vi) connections with electric systems in jurisdictions bordering Alberta,

but does not include a generating unit or an electric distribution system;

(ccc) “transmission system” means all transmission facilities in Alberta that are part of the

interconnected electric system.

(ddd) repealed 2007 cA-37.2 s82(4).

Purposes of the Act

5 The purposes of this Act are

(a) to provide an efficient Alberta electric industry structure including independent, separate

corporations to carry out the responsibilities of the Independent System Operator and the

Balancing Pool, and to set out the powers and duties of those corporations;

(b) to provide for a competitive power pool so that an efficient market for electricity based on fair

and open competition can develop, where all persons wishing to exchange electric energy

through the power pool may do so on non-discriminatory terms and may make financial

arrangements to manage financial risk associated with the pool price;

(c) to provide for rules so that an efficient market for electricity based on fair and open

competition can develop in which neither the market nor the structure of the Alberta electric

industry is distorted by unfair advantages of government-owned participants or any other

participant;

(d) to continue a flexible framework so that decisions of the electric industry about the need for

and investment in generation of electricity are guided by competitive market forces;



(e) to enable customers to choose from a range of services in the Alberta electric industry,

including a flow-through of pool price and other options developed by a competitive market,

and to receive satisfactory service;

(f) to continue the sharing, among all customers of electricity in Alberta, of the benefits and costs

associated with the Balancing Pool;

(g) to continue the framework established for power purchase arrangements;

(h) to provide for a framework so that the Alberta electric industry can, where necessary, be

effectively regulated in a manner that minimizes the cost of regulation and provides incentives

for efficiency.

Transmission facilities directions and proposals

35(1) The Independent System Operator may, at the time of preparing a needs identification document, after submitting a needs identification document to the Commission or after receiving Commission approval of a needs identification document,

(a) direct the owner of a transmission facility to submit, for Commission approval under the Hydro and Electric Energy Act, a transmission facility proposal to meet the need identified, or

(b) request market participants to submit, for approval by the Independent System Operator, a proposal to meet the need identified.

(2) The owner of a transmission facility must comply with a direction from the Independent System Operator under subsection (1) unless the owner gives written notice to the Independent System Operator, giving reasons, that

(a) a real and substantial risk of damage to its transmission facility could result if the direction were complied with,

(b) a real and substantial risk to the safety of its employees or the public could result if the direction were complied with, or

(c) a real and substantial risk of undue injury to the environment could result if the direction were complied with.

(3) Subject to subsection (2), on receiving a direction the owner of a transmission facility must prepare an application to meet the requirements or objectives of the direction and apply to the Commission for approval under the Hydro and Electric Energy Act.

2003 cE-5.1 s35;2007 cA-37.2 s82(4)

Duties of transmission facility owners

39(1) Each owner of a transmission facility must operate and maintain the transmission facility in a manner that is consistent with the safe, reliable and economic operation of the interconnected electric system.

(2) Each owner of a transmission facility must, in a timely manner, assist the Independent System Operator in any manner to enable the Independent System Operator to carry out its duties, responsibilities and functions.

(3) Each owner of a transmission facility must

(a) establish, in conjunction with owners of electric distribution systems, procedures and systems for load shedding in emergencies;

(b) provide the Independent System Operator in a timely manner with descriptions, ratings and operating restrictions relating to their transmission facility;



(c) inform the Independent System Operator in a timely manner of anticipated changes in their transmission facility that could affect the Independent System Operator in carrying out its duties, responsibilities and functions, including

(i) the capability of the transmission facility,

(ii) the status and availability of the transmission facility, including maintenance schedules, and

(iii) additions to, alterations to or decommissioning of transmission facilities or any part of

them;

(c.1) install and remove meters and perform metering, including verifying meter readings and verifying accuracy of meters that are directly connected to the owner’s transmission facility;

(d) comply with standards and practices established by the Independent System Operator to enable the Independent System Operator to carry out its duties, responsibilities and functions;

(e) provide the Independent System Operator with use of the owner’s transmission facility for the purpose of carrying out the Independent System Operator’s duties, responsibilities and functions.

(4) The owner of a transmission facility may refuse to comply with a direction from the Independent System Operator only if the owner notifies the Independent System Operator that the owner considers that

(a) a real and substantial risk of damage to its transmission facility could result if the direction were complied with;

(b) a real and substantial risk to the safety of its employees or the public could result if the direction were complied with;

(c) a real and substantial risk of undue injury to the environment could result if the direction were complied with.

2003 cE-5.1 s39;2007 cA-37.2 s82(4)

Part 2.1 Critical Transmission Infrastructure

Direction to apply

41.3 Subject to the regulations, the Independent System Operator must, in a timely manner, direct a person determined under the regulations to make an application in a timely manner to the Commission under the Hydro and Electric Energy Act for an approval of critical transmission infrastructure.

2009 c44 s2;2012 c6 s4

Distribution tariff

102(1) Each owner of an electric distribution system must prepare a distribution tariff for the purpose

of recovering the prudent costs of providing electric distribution service by means of the owner’s

electric distribution system.

(2) The owner of the electric distribution system must apply for approval of its distribution tariff

(a) to the Commission,

(b) to the council of a municipality, if the owner is a municipality or a subsidiary of a municipality

(i) that does not have an affiliated retailer that provides retail electricity services outside the

service area of the municipality, and



(ii) that does not provide electric distribution service outside the service area of the

municipality either on its own behalf or on behalf of another owner,

or

(c) to the board of directors of the association, if the owner is a rural electrification association.

(3) A distribution tariff of an owner of an electric distribution system that is a municipality or a

subsidiary of a municipality

(a) that has an affiliated retailer that provides retail electricity services outside the service area of

the municipality, or

(b) that provides electric distribution service outside the service area of the municipality, either on

its own behalf or on behalf of another owner,

takes effect as of January 1, 2004.

(4) A distribution tariff must be prepared in accordance with the regulations made by the Minister

under section 108.

Duties of owners of electric distribution systems

105(1) The owner of an electric distribution system has the following duties:

(a) to provide electric distribution service that is not unduly discriminatory;

(b) to make decisions about building, upgrading and improving the electric distribution system for

the purpose of providing safe, reliable and economic delivery of electric energy having regard

to managing losses of electric energy to customers in the service area served by the electric

distribution system;

(c) to operate and maintain the electric distribution system in a safe and reliable manner;

(d) if a transmission facility serves only one service area, to arrange for the provision of system

access service to customers in that service area, other than customers referred to in section

101(2);

(e) to install and remove meters and perform metering, including verifying meter readings and

verifying accuracy of meters that are directly connected to the owner’s distribution system;

(f) to maintain information systems relating to the consumption of electricity by customers;

(g) to provide to a retailer or the owner’s regulated rate provider sufficient, accurate and timely

information about the retailer’s or the regulated rate provider’s customers, including metering

information about the electricity consumed by those customers in order to enable the retailer or

regulated rate provider to bill and to respond to inquiries and complaints from customers

concerning billing for electricity services;

(h) to undertake financial settlement with the Independent System Operator for system access

service;

(i) to act as a regulated rate provider to eligible customers who pay a regulated rate for electricity;

(j) to appoint or act as a default supplier, in accordance with the regulations, for eligible

customers;

(k) to connect and disconnect customers and distributed generation in accordance with the owner’s

approved tariff and with principles established by the Commission regarding distributed

generation;

(l) to carry out distribution tariff billing for electric distribution service under a distribution tariff;



(m) to respond to inquiries and complaints from customers respecting electric distribution service;

(n) if the electric distribution system is not an electric utility, to comply with rules respecting

service standards made by the Commission under section 129(1) relating to

(i) billing and billing services to be provided to customers, and

(ii) the process, procedures and standards for transfer of data relating to distribution tariffs

as if the electric distribution system were an electric utility.

(2) Each owner of an electric distribution system must, in accordance with the regulations made by

the Minister under section 108, maintain the records and provide the records to the persons specified

in the regulations.

Preparation of tariffs

119(1) Each owner of an electric utility must prepare a tariff in accordance with this Act and the

regulations and apply to the Commission for approval of the tariff.

Tariff contents

120(1) A tariff must describe how it may change over the period for which it is intended to have effect.

(2) A tariff may provide

(a) that it is in effect for a fixed period or an indefinite period;

(b) for maximum rates;

(c) for increases or decreases in the rates to correspond to

(i) increases or decreases in fuel costs, taxes or other costs and expenses,

(ii) price indices, rates of inflation or similar measurements, and

(iii) other related costs or expenses approved by the Commission;

(d) for incentives for efficiencies that result in cost savings or other benefits that can be shared in an equitable manner between the owner of the electric utility and customers.

2003 cE-5.1 s120;2007 cA-37.2 s82(4)

Matters the Commission must consider

121(1) On giving notice to interested parties, the Commission must consider each tariff application.

(2) When considering whether to approve a tariff application the Commission must ensure that

(a) the tariff is just and reasonable,

(b) the tariff is not unduly preferential, arbitrarily or unjustly discriminatory or inconsistent with or

in contravention of this or any other enactment or any law, and

(c) if the regulations so require, the tariff incorporates the standard of liability imposed by the

regulations made by the Lieutenant Governor in Council under section 94, or that the

Commission has, in accordance with those regulations, considered and imposed a standard of

legal liability that it considers appropriate.

(3) A tariff that provides incentives for efficiency is not unjust or unreasonable simply because it

provides those incentives.



(4) The burden of proof to show that a tariff is just and reasonable is on the person seeking approval

of the tariff.

Costs and expenses recovered under a tariff

122(1) When considering a tariff application, the Commission must have regard for the principle that

a tariff approved by it must provide the owner of an electric utility with a reasonable opportunity to

recover

(a) the costs and expenses associated with capital related to the owner’s investment in the electric

utility, including

(i) depreciation,

(ii) interest paid on money borrowed for the purpose of the investment,

(iii) any return required to be paid to preferred shareholders of the electric utility relating to the

investment,

(iv) a fair return on the equity of shareholders of the electric utility as it relates to the

investment, and

(v) taxes associated with the investment,

if the costs and expenses are prudent and if, in the Commission’s opinion, they provide an

appropriate composition of debt and equity for the investment,

(b) other prudent costs and expenses associated with isolated generating units, transmission,

exchange or distribution of electricity or associated with the Independent System Operator if,

in the Commission’s opinion, they are applicable to the electric utility,

(c) amounts that the owner is required to pay under this Act or the regulations,

(d) the costs and expenses applicable to the electric utility that arise out of obligations incurred

before the coming into force of this section and that were approved by the Public Utilities

Board, the Alberta Energy and Utilities Board or other utilities’ regulatory authorities if, in the

Commission’s opinion, the costs and expenses continue to be reasonable and prudently

incurred,

(e) its prudent costs and expenses of complying with the Commission rules respecting load

settlement,

(f) its prudent costs and expenses respecting the management of legal liability,

(g) the costs and expenses associated with financial arrangements to manage financial risk

associated with the pool price if the arrangements are, in the Commission’s opinion, prudently

made, and

(h) any other prudent costs and expenses that the Commission considers appropriate, including a

fair allocation of the owner’s costs and expenses that relate to any or all of the owner’s electric

utilities.

4. Transmission Regulation, AR 086/2007

Assistance to the ISO

14(1) As part of the duties of a TFO under section 39 of the Act, the TFO must, as directed by the ISO, assist the ISO in

(a) preparing and updating forecasts,



(b) preparing, maintaining and updating the transmission system plan, and

(c) preparing and updating needs identification documents.

(2) In addition to the duties of a DFO under the Act, the DFO must, as directed by the ISO, assist the ISO in

(a) preparing and updating forecasts,

(b) preparing, maintaining and updating the transmission system plan,

(c) evaluating the relative merits of transmission and distribution options, and

(d) preparing and updating needs identification documents.

(3) In providing assistance to the ISO, the TFO and DFO must, in accordance with the directions of the ISO, respect the confidentiality of information of market participants.

AR 86/2007 s14;153/2010

Recovery of pre-construction costs

39 If an application under section 37 has been approved by the Commission under that section, if a needs identification document has been approved by the Commission under section 34 of the Act or if a direction has been given by the ISO under section 41.3 of the Act, a TFO may include in its tariff pre-construction costs, including

(a) feasibility studies,

(b) engineering,

(c) purchase of equipment and materials, and

(d) purchase of land or options to purchase land for future use or acquire a right or interest in land for future use as a right of way, as may be necessary, for long lead-time projects.

AR 86/2007 s39;255/2007;153/2010

Recovery of assistance costs

40(1) A TFO may include in its transmission tariff

(a) costs and expenses incurred by the owner in assisting the ISO in preparing forecasts, the transmission system plan, needs identification documents and updates to any or all of them, and

(b) the costs incurred by the owner to assist the Market Surveillance Administrator in preparing reports made under section 23(2).

(2) A DFO may include in its distribution tariff

(a) costs and expenses incurred by the owner in assisting the ISO in preparing forecasts, the transmission system plan, needs identification documents and updates to any or all of them,

(b) the cost of evaluating the relative merits of transmission facility and distribution options, and

(c) the costs incurred by the owner to assist the Market Surveillance Administrator in preparing reports made under section 23(2).

AR 86/2007 s40;153/2010

Recovery of other secondary costs

41(1) A TFO or DFO may include in its tariff any one or more of the following, as applicable:

(a) costs or expenses incurred as a consequence of a direction given by the ISO under this Regulation or any other enactment;



(b) costs and expenses

(i) of a maintenance upgrade, enhancement or other modification to a transmission facility

referred to in section 11(6),

(ii) incurred in implementing an expansion or enhancement to the transmission system access

service interconnection or a transmission facility project referred to in section 12,

(iii) incurred in order to implement the standards and rules under section 5, or

(iv) incurred in order to implement the reliability standards.

(2) In addition to its duties under section 17 of the Act, the ISO may do either or both of the following:

(a) certify to the Commission that a cost was incurred under subsection (1);

(b) notify the Commission of any concern the ISO has with respect to a cost referred to in subsection (1),

but the Commission must not require the ISO to make any statement with respect to the prudence of a TFO or a DFO in incurring a cost under subsection (1).

AR 86/2007 s41;255/2007

Additional criteria for the Commission for TFO tariffs

42 In addition to the matters taken into account by the Commission under section 122 of the Act, when considering an application for approval of a TFO tariff, the Commission must consider that it is also in the public interest to provide consumers the benefit of unconstrained transmission access to the competitive generation market

(a) by providing sufficient investment to ensure the timely upgrade, enhancement or expansion of transmission facilities, and

(b) by fostering a stable investment climate and a continued stream of capital investment for the transmission system.

AR 86/2007 s42;255/2007

Prudence of activities and costs

46(1) The Commission must consider that the ISO’s own administrative costs that have been approved by the ISO members are prudent unless an interested person satisfies the Commission that those costs or expenses are unreasonable.

(2) The Commission must consider that payments that are included in a TFO’s tariff made by a TFO to an owner or occupant of land pursuant to any agreement between the TFO and the owner or occupant that

(a) grants the TFO the right of entry in respect of the surface of the land, or

(b) provides for compensation resulting from or related to the use of the land for the purposes of locating transmission facilities on it,

are prudent unless an interested person satisfies the Commission that the payments are unreasonable. AR 86/2007 s46;255/2007;145/2013



5. Gas Utilities Act, RSA 2000, c G-5

Definitions

1(1) In this Act,

(a) “absorption plant” means any plant for treating or processing gas by absorption or otherwise

for the extraction from it of natural gasoline or other hydrocarbons;

(a.1) “affiliate” for the purposes of clause (g.1) has the meaning given to it in the Business

Corporations Act;

(b) repealed 2007 cA-37.2 s82(12);

(c) “butanes” means butanes as defined in the Oil and Gas Conservation Act;

(d) “charter” means any special or general Act of Alberta or Ordinance of the North-West

Territories by or by virtue of which a corporation is incorporated, and the certificate of

incorporation or other document issued by virtue of that Act or Ordinance, or granting powers

to a corporation;

(d.1) “Commission” means the Alberta Utilities Commission under the Alberta Utilities Commission

Act;

(e) “gas” means all natural gas both before and after it has been subjected to any treatment or

process by absorption, purification, scrubbing or otherwise, and includes all fluid hydrocarbons

not defined by clause (i) as oil;

(f) “gas pipeline”

(i) means a pipe or any system or arrangement of pipes wholly within Alberta whereby gas is

conveyed from a well-head or other place at which it is produced to any other place, or

from a place where it is stored, processed or treated to any other place,

(ii) includes all property of any kind used for the purpose of, or in connection with, or

incidental to the operation of a gas pipeline in the gathering, transporting, handling and

delivery of gas, and

(iii) without restricting the generality of the foregoing, includes tanks, surface reservoirs,

pumps, racks, storage and loading facilities, compressors, compressor stations, pressure

measuring and controlling equipment and fixtures, flow controlling and measuring

equipment and fixtures, metering equipment and fixtures and heating, cooling and

dehydrating equipment and fixtures, but

(iv) does not include any pipe or any system or arrangement of pipes that constitutes a

distribution system for the distribution of gas to ultimate consumers;

(g) “gas utility” means

(i) any gas pipeline,

(ii) any system, works, plant, pipes, equipment or service for the production, gathering,

conveying, transmission, transporting, delivery, furnishing or supplying of gas by retail or

wholesale, either directly or indirectly, to or for the public or any member of the public,

whether an individual or a corporation, other than the transportation, delivery, furnishing or

supplying by retail or wholesale, either directly or indirectly, of liquefied petroleum gas

(except propane and butanes) by means of tank car, tank wagon, cylinder or vessel,

(iii) any absorption plant or scrubbing plant, and

(iv) any system, well, works, plant, equipment or service for the production of gas or capable of

producing gas that may be declared by the Commission to be a gas utility;



(g.1) “gas utility pipeline” means a gas pipeline of a gas utility designated by regulation or of its

affiliates;

(h) “municipality” means a city, town, village or municipal district and includes a Metis

settlement;

(i) “oil” means crude bitumen and crude oil and all other hydrocarbons, regardless of gravity, that

are recovered in liquid form from a pool by ordinary production methods, but does not include

butanes;

(j) “owner of a gas utility” means

(i) a person owning, operating, managing or controlling a gas utility and whose business and

operations are subject to the legislative authority of Alberta, and the lessees, trustees,

liquidators of it or any receivers of it appointed by any court, but

(ii) does not include a municipality that has not voluntarily come under this Act in the manner

provided by section 4;

(k) “propane” means propane as defined in the Oil and Gas Conservation Act;

(l) “scrubbing plant” means any plant for the purifying, scrubbing or otherwise treating, of gas for

the extraction or removal from it of hydrogen sulphide or any other deleterious substance.

Supervision

22(1) The Commission shall exercise a general supervision over all gas utilities, and the owners of

them, and may make any orders regarding equipment, appliances, extensions of works or systems,

reporting and other matters, that are necessary for the convenience of the public or for the proper

carrying out of any contract, charter or franchise involving the use of public property or rights.

(2) The Commission shall conduct all inquiries necessary for the obtaining of complete information

as to the manner in which owners of gas utilities comply with the law, or as to any other matter or

thing within the jurisdiction of the Commission under this Act.

Investigation of gas utility

24(1) The Commission, on its own initiative or on the application of a person having an interest, may

investigate any matter concerning a gas utility.

(2) If in the opinion of the Commission it is necessary to investigate a gas utility or the affairs of the

owner of it, the Commission shall have access to and may use any books, documents or records with

respect to the gas utility and in the possession of any owner of the gas utility or municipality or under

the control of the Alberta Energy Regulator or a board, commission or department of the Government.

(3) If a person directly or indirectly controls the business of an owner of a gas utility within Alberta,

that person and any company controlled by that person shall give the Commission or its agent access

to any of the books, documents and records that relate to the business of the owner or shall furnish any

information in respect of it that may be required by the Commission.

Prohibitions

25 No owner of a gas utility shall

(a) make, impose or extract any unjust or unreasonable or unjustly discriminatory or unduly

preferential individual or joint rate, commutation rate or other special rate, toll, fare, charge or

schedule for any gas or service supplied or rendered by it within Alberta,

(b) adopt or impose any unjust or unreasonable classification in the making of or as the basis of

any individual or joint rate, toll, fare, charge or schedule for any gas or service rendered by it

within Alberta,

(c) adopt, maintain or enforce any regulation, practice or measurement that is unjust, unreasonable,

unduly preferential, arbitrarily or unjustly discriminatory or otherwise in contravention of law,



or provide or maintain any service that is unsafe, improper or inadequate, or withhold or refuse

any service that can reasonably be demanded and furnished when ordered by the Commission,

or

(d) make, or give, directly or indirectly, any undue or unreasonable preference or advantage to any

person or to any locality, or subject any particular person or locality to any prejudice or

disadvantage in any respect whatever.

Designated gas utilities

26(1) The Lieutenant Governor in Council may by regulation designate those owners of gas utilities

to which this section and section 27 apply.

(2) No owner of a gas utility designated under subsection (1) shall

(a) issue any

(i) of its shares or stock, or

(ii) bonds or other evidences of indebtedness, payable in more than one year from the date of

them,

unless it has first satisfied the Commission that the proposed issue is to be made in accordance

with law and has obtained the approval of the Commission for the purposes of the issue and an

order of the Commission authorizing the issue,

(b) capitalize

(i) its right to exist as a corporation,

(ii) a right, franchise or privilege in excess of the amount actually paid to the Government or a

municipality as the consideration for it, exclusive of any tax or annual charge, or

(iii) a contract for consolidation, amalgamation or merger,

(c) without the approval of the Commission, capitalize any lease, or

(d) without the approval of the Commission,

(i) sell, lease, mortgage or otherwise dispose of or encumber its property, franchises, privileges

or rights, or any part of it or them, or

(ii) merge or consolidate its property, franchises, privileges or rights, or any part of it or them,

and a sale, lease, mortgage, disposition, encumbrance, merger or consolidation made in

contravention of this clause is void, but nothing in this clause shall be construed to prevent in

any way the sale, lease, mortgage, disposition, encumbrance, merger or consolidation of any of

the property of an owner of a gas utility designated under subsection (1) in the ordinary course

of the owner’s business.

(3) Notwithstanding subsection (2), the approval, authority, permission or consent of the

Commission is not required in or with respect to

(a) the issue of any shares of its capital stock by an owner of a gas utility under the exercise of an

optional right of conversion attaching to any shares, stocks, bonds, debentures, debenture stock

or other evidence of indebtedness the issue of which has previously been approved by the

Commission or was not required to be approved by the Commission by reason of an existing

declaration made under subsection (4),

(b) a right of entry, sale, disposition or other proceedings for the enforcement of a mortgage or

charge created by trust deed or other instrument or security, in the enforcement of, or pursuant

to, the security thereby constituted or in the exercise of the rights or remedies thereby granted



or otherwise available at law, if the trust deed or other instrument or security was approved or

authorized by the Commission or was not required to be approved or authorized by the

Commission by reason of an existing declaration made under subsection (4), or

(c) the declaration or issuance of a stock dividend by an owner of a gas utility designated under

subsection (1).

(4) The Commission, on its own initiative or on the application of a person having an interest, may, or

on the order of the Lieutenant Governor in Council shall, declare that subsection (2) or any part of it

does not apply with respect to any transaction or class of transactions specified in the declaration.

(5) Where a declaration is made under subsection (4) in respect of a transaction entered into before

the making of the declaration, the transaction,

(a) in the case of a transaction under subsection (2)(d), is deemed to be no longer void and to have

been in force and effect from the date of the transaction, and

(b) in the case of a transaction under subsection (2)(a), (b) or (c), is deemed not to have been in

contravention of that subsection,

except that the declaration does not affect any other rights that have accrued prior to the declaration.

Definitions

28 In this Part,

(a) “affiliated electricity retailer” has the meaning given to it in the regulations;

(a.1) “affiliated gas retailer” has the meaning given to it in the regulations;

(a.2) “affiliated retailer” means an affiliated electricity retailer or an affiliated gas retailer;

(b) “customer” means a consumer of gas who takes delivery of the gas at its place of consumption

by means of a gas distribution system of a gas distributor;

(c) “default rate tariff” means the rates, tolls or charges fixed by the Commission, and the terms or

conditions fixed by the Commission, for gas services provided by a default supply provider;

(d) “default supply provider” means a gas distributor, or a person authorized by a gas distributor,

who provides gas services to customers pursuant to a default rate tariff;

(d.1) “distribution tariff” means the rates, tolls or charges fixed by the Commission, and the terms

and conditions fixed by the Commission, for gas distribution service provided by a gas

distributor;

(e) “gas distribution service” means the service required to transport gas to customers by means of

a gas distribution system, and includes any services the gas distributor is required to provide by

the Commission or is required to provide under this Act or the regulations;

(f) “gas distribution system” means a gas utility that delivers gas to customers through a system of

pipelines, works, plant and equipment that is primarily a low pressure system;

(g) repealed 2007 cA-37.2 s82(12);

(h) “gas distributor” means the owner, operator, manager or lessee of a gas distribution system;

(i) “gas services” means

(i) the gas that is provided and delivered, and

(ii) the services associated with the provision and delivery of the gas, including

(A) arranging for the exchange or purchase of the gas,



(B) making financial arrangements to manage the financial risk associated with the price of

gas,

(C) arranging for gas distribution service,

(D) arranging for delivery of gas to the gas distributor’s specified receipt point or points,

(E) storage,

(F) billing, collection and responding to customer billing inquiries,

(G) maintaining information systems, and

(H) any other services specified by the Minister by order as gas services;

(i.1) “Minister” means the Minister determined under section 16 of the Government Organization

Act as the Minister responsible for this Act;

(j) “retail gas services” means gas services that are provided by a retailer directly to customers and

that are not provided

(i) under a default rate tariff, or

(ii) at or upstream of the inlet to the gas distribution system to a customer acting on the

customer’s own behalf;

(k) “retailer” means a person who provides retail gas services, and includes an affiliated retailer;

(l) “service area”, with respect to a gas distributor, means the area within which customers take

delivery of gas at their place of consumption by means of the gas distribution system of the gas

distributor;

(m) “settlement system code” has the meaning given to it in the regulations.

Powers of Commission

36 The Commission, on its own initiative or on the application of a person having an interest, may by order in writing, which is to be made after giving notice to and hearing the parties interested,

(a) fix just and reasonable individual rates, joint rates, tolls or charges or schedules of them, as well as commutation and other special rates, which shall be imposed, observed and followed afterwards by the owner of the gas utility,

(b) fix proper and adequate rates and methods of depreciation, amortization or depletion in respect of the property of any owner of a gas utility, who shall make the owner’s depreciation, amortization or depletion accounts conform to the rates and methods fixed by the Commission,

(c) fix just and reasonable standards, classifications, regulations, practices, measurements or service, which shall be furnished, imposed, observed and followed thereafter by the owner of the gas utility,

(d) require an owner of a gas utility to establish, construct, maintain and operate, but in compliance with this and any other Act relating to it, any reasonable extension of the owner’s existing facilities when in the judgment of the Commission the extension is reasonable and practical and will furnish sufficient business to justify its construction and maintenance, and when the financial position of the owner of the gas utility reasonably warrants the original expenditure required in making and operating the extension, and



(e) require an owner of a gas utility to supply and deliver gas to the persons, for the purposes, at the rates, prices and charges and on the terms and conditions that the Commission directs, fixes or imposes.

RSA 2000 cG-5 s36;2007 cA-37.2 s82(12)

Rate base

37(1) In fixing just and reasonable rates, tolls or charges, or schedules of them, to be imposed,

observed and followed afterwards by an owner of a gas utility, the Commission shall determine a rate

base for the property of the owner of the gas utility used or required to be used to provide service to

the public within Alberta and on determining a rate base it shall fix a fair return on the rate base.

(2) In determining a rate base under this section, the Commission shall give due consideration

(a) to the cost of the property when first devoted to public use and to prudent acquisition cost to

the owner of the gas utility, less depreciation, amortization or depletion in respect of each, and

(b) to necessary working capital.

(3) In fixing the fair return that an owner of a gas utility is entitled to earn on the rate base, the

Commission shall give due consideration to all facts that in its opinion are relevant.

Excess revenues or losses

40 In fixing just and reasonable rates, tolls or charges, or schedules of them, to be imposed, observed

and followed afterwards by an owner of a gas utility,

(a) the Commission may consider all revenues and costs of the owner that are in the Commission’s

opinion applicable to a period consisting of

(i) the whole of the fiscal year of the owner in which a proceeding is initiated for the fixing of

rates, tolls or charges, or schedules of them,

(ii) a subsequent fiscal year of the owner, or

(iii) 2 or more of the fiscal years of the owner referred to in subclauses (i) and (ii) if they are

consecutive,

and need not consider the allocation of those revenues and costs to any part of that period,

(b) the Commission may give effect to that part of any excess revenue received or any revenue

deficiency incurred by the owner that is in the Commission’s opinion applicable to the whole

of the fiscal year of the owner in which a proceeding is initiated for the fixing of rates, tolls or

charges, or schedules of them, that the Commission determines is just and reasonable,

(c) the Commission may give effect to that part of any excess revenue received or any revenue

deficiency incurred by the owner after the date on which a proceeding is initiated for the fixing

of rates, tolls or charges, or schedules of them, that the Commission determines has been due to

undue delay in the hearing and determining of the matter, and

(d) the Commission shall by order approve

(i) the method by which, and

(ii) the period, including any subsequent fiscal period, during which,



any excess revenue received or any revenue deficiency incurred, as determined pursuant to clause (b)

or (c), is to be used or dealt with.

Incentives

45(1) Instead of fixing or approving rates, tolls or charges, or schedules of them, under sections 36(a), 37, 40, 41, 42 and 44, the Commission, on its own initiative or on the application of a person having an interest, may by order in writing fix or approve just and reasonable rates, tolls or charges, or schedules of them,

(a) that are intended to result in cost savings or other benefits to be allocated between the owner of the gas utility and its customers, or

(b) that are otherwise in the public interest.

(2) The Commission may specify terms and conditions that apply to an order made under this section. RSA 2000 cG-5 s45;2007 cA-37.2 s82(12)

6. Roles, Relationships and Responsibilities Regulation, AR 186/2003

Functions of gas distributor

4(1) A gas distributor must do the following:

(a) provide gas distribution service that is not unduly discriminatory;

(b) make decisions about building, upgrading and improving the gas distribution system for the

purpose of providing safe, reliable and economic delivery of gas to customers in the service

area served by the gas distribution system;

(c) arrange for adequate upstream transmission capacity for the purposes of clause (b);

(d) operate and maintain the gas distribution system in a safe and reliable manner;

(e) carry out gas distribution tariff billing for gas distribution service under the gas distributor’s

approved gas distribution tariff;

(f) connect and disconnect customers in accordance with the gas distributor’s approved gas

distribution tariff;

(g) perform metering, including verifying meter readings and verifying accuracy of meters;

(h) maintain information systems relating to the consumption of gas by customers;

(i) perform load balancing for the gas distribution system;

(j) perform functions that a settlement system code requires a gas distributor to perform;

(k) distribute public safety information;

(l) provide to a retailer or the gas distributor’s default supply provider sufficient, accurate and

timely information about the retailer’s or default supply provider’s customers, including

metering information about the gas consumed by those customers, in order to enable the

retailer or default supply provider to bill and to respond to inquiries and complaints from

customers concerning billing for gas services;

(m) act as a default supply provider to customers who pay a default rate for gas;

(n) respond to inquiries and complaints from customers respecting gas distribution service;

(o) if a customer makes an inquiry related to the functions of retailers or default supply providers,

direct the customer to the customer’s retailer or default supply provider;



(p) on the request of a customer, direct the customer to a source where the customer may obtain

the current list of licensed retailers maintained in accordance with the Fair Trading Act and the

regulations made under that Act.

(2) Each gas distributor must maintain records relating to the functions set out in subsection (1) and

make the records or the information in them available, or otherwise provide the records or

information, as required by the Act and the regulations.

(3) A gas distributor is entitled to recover in its tariffs the prudent costs as determined by the

Commission that are incurred by the gas distributor to meet the requirements of subsection (1).

7. Public Utilities Act, RSA 2000, c P-45

Fixing of rates

89 The Commission, either on its own initiative or on the application of a person having an interest,

may by order in writing, which is to be made after giving notice to and hearing the parties interested,

(a) fix just and reasonable individual rates, joint rates, tolls or charges, or schedules of them, as

well as commutation, mileage or kilometre rate and other special rates, which shall be imposed,

observed and followed subsequently by the owner of the public utility;

(b) fix proper and adequate rates and methods of depreciation, amortization or depletion in respect

of the property of any owner of a public utility, who shall make the owner’s depreciation,

amortization or depletion accounts conform to the rates and methods fixed by the Commission;

(c) fix just and reasonable standards, classifications, regulations, practices, measurements or

service, which shall be furnished, imposed, observed and followed subsequently by the owner

of the public utility;

(d) repealed RSA 2000 cR-4 s61 (2002 c30 s27);

(e) require an owner of a public utility to establish, construct, maintain and operate, but in

compliance with other provisions of this or any other Act relating to it, any reasonable

extension of the owner’s existing facilities when in the judgment of the Commission the

extension is reasonable and practical and will furnish sufficient business to justify its

construction and maintenance, and when the financial position of the owner of the public utility

reasonably warrants the original expenditure required in making and operating the extension.

Determining rate base


observed and followed subsequently by an owner of a public utility, the Commission shall determine a

rate base for the property of the owner of a public utility used or required to be used to provide service

to the public within Alberta and on determining a rate base it shall fix a fair return on the rate base.

(2) In determining a rate base under this section, the Commission shall give due consideration

(a) to the cost of the property when first devoted to public use and to prudent acquisition cost to

the owner of the public utility, less depreciation, amortization or depletion in respect of each,

and

(b) to necessary working capital.



(3) In fixing the fair return that an owner of a public utility is entitled to earn on the rate base, the

Commission shall give due consideration to all those facts that, in the Commission’s opinion, are

relevant.

Revenue and costs considered


observed and followed by an owner of a public utility,

(a) the Commission may consider all revenues and costs of the owner that are in the Commission’s

opinion applicable to a period consisting of

(i) the whole of the fiscal year of the owner in which a proceeding is initiated for the fixing of

rates, tolls or charges, or schedules of them,

(ii) a subsequent fiscal year of the owner, or

(iii) 2 or more of the fiscal years of the owner referred to in subclauses (i) and (ii) if they are

consecutive,

and need not consider the allocation of those revenues and costs to any part of such a period,

(b) the Commission shall consider the effect of the Small Power Research and Development Act

on the revenues and costs of the owner with respect to the generation, transmission and

distribution of electric energy,

(c) the Commission may give effect to that part of any excess revenue received or any revenue

deficiency incurred by the owner that is in the Commission’s opinion applicable to the whole

of the fiscal year of the owner in which a proceeding is initiated for the fixing of rates, tolls or

charges, or schedules of them, as the Commission determines is just and reasonable,

(d) the Commission may give effect to such part of any excess revenue received or any revenue

deficiency incurred by the owner after the date on which a proceeding is initiated for the fixing

of rates, tolls or charges, or schedules of them, as the Commission determines has been due to

undue delay in the hearing and determining of the matter, and

(e) the Commission shall by order approve the method by which, and the period (including any

subsequent fiscal period) during which, any excess revenue received or any revenue deficiency

incurred, as determined pursuant to clause (c) or (d), is to be used or dealt with.

Designated public utilities

101(1) The Lieutenant Governor in Council may by regulation designate those owners of public

utilities to which this section and section 102 apply.

(2) No owner of a public utility designated under subsection (1) shall

(a) issue any

(i) of its shares or stock, or

(ii) bonds or other evidences of indebtedness, payable in more than one year from the date of

them,

unless it has first satisfied the Commission that the proposed issue is to be made in accordance

with law and has obtained the approval of the Commission for the purposes of the issue and an

order of the Commission authorizing the issue,

(b) capitalize



(i) its right to exist as a corporation,

(ii) a right, franchise or privilege in excess of the amount actually paid to the Government or a

municipality as the consideration for it, exclusive of any tax or annual charge, or

(iii) a contract for consolidation, amalgamation or merger,

(c) without the approval of the Commission, capitalize any lease, or

(d) without the approval of the Commission,

(i) sell, lease, mortgage or otherwise dispose of or encumber its property, franchises, privileges

or rights, or any part of them, or

(ii) merge or consolidate its property, franchises, privileges or rights, or any part of them,

and a sale, lease, mortgage, disposition, encumbrance, merger or consolidation made in

contravention of this clause is void, but nothing in this clause shall be construed to prevent in

any way the sale, lease, mortgage, disposition, encumbrance, merger or consolidation of any of

the property of an owner of a public utility designated under subsection (1) in the ordinary

course of the owner’s business.

(3) Notwithstanding subsection (2), the approval, authority, permission or consent of the Commission

is not required in or with respect to

(a) the issue of any shares of its capital stock by an owner of a public utility under the exercise of

an optional right of conversion attaching to any shares, stocks, bonds, debentures, debenture

stock or other evidence of indebtedness the issue of which has previously been approved by the

Commission or was not required to be approved by the Commission by reason of an existing

declaration made under subsection (4),

(b) a right of entry, sale, disposition or other proceedings for the enforcement of a mortgage or

charge created by trust deed or other instrument or security, in the enforcement of, or pursuant

to, the security constituted by it or in the exercise of the rights or remedies granted in it or

otherwise available at law, if the trust deed or other instrument or security was approved or

authorized by the Commission or was not required to be approved or authorized by the

Commission by reason of an existing declaration made under subsection (4), or

(c) the declaration or issuance of a stock dividend by an owner of a public utility.

(4) The Commission, on its own initiative or on the application of a person having an interest, may, or

on the order of the Lieutenant Governor in Council shall, declare that subsection (2) or any part of it

does not apply with respect to any transaction or class of transactions specified in the declaration.

(5) Where a declaration is made under subsection (4) in respect of a transaction entered into before

the making of the declaration, the transaction,

(a) in the case of a transaction under subsection (2)(a), (b) or (c), is deemed not to have been in

contravention of that subsection, and

(b) in the case of a transaction under subsection (2)(d), is deemed to be no longer void and to have

been in force and effect from the date of the transaction,

except that the declaration does not affect any other rights that have accrued prior to the declaration.

Application of Act to electric utilities

116(1) Subject to subsection (2), sections 78 to 81, 88 to 95, 98, 99, 100, 103, 104, 106, 107, 108, 111

and 115 do not apply to an electric utility.



Appendix 3 – Summary of Commission 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 decision, the wording in the main

body of the decision shall prevail.

1. The Commission recognizes that the special facilities charge was approved in decisions

2011-176 and 2012-084 on the condition that if these special facilities assets became

stranded, their costs could not be recovered from other customers. The Commission is

aware that it has approved special facilities charges or similar charges for other regulated

utility companies in Alberta. In order to consider the various types of special facilities

charges already in place and how or whether they might be treated in a manner consistent

with the Fortis special facilities charge, the Commission directs that all utilities with

approved special facility charges or similar charges provide the Commission, by January

31, 2014, with a reference to the decision under which the charge was approved and an

explanation of how the service is offered. .. .................................................. Paragraph 311

2. In order to give effect to the court’s guidance that the “rate-regulation process allows and

compels the Commission to decide what is in the rate base, i.e. what assets (still) are

relevant utility investment on which the rates should give the company a return,” the

Commission directs each of the utilities to review its rate base and confirm in its next

revenue requirement filing that all assets in rate base continue to be used or required to be

used (presently used, reasonably used or likely to be used in the future) to provide utility

services. Accordingly, the utilities are required to confirm that there is no surplus land in

rate base and that there are no depreciable assets in rate base which should be treated as

extraordinary retirements and removed because they are obsolete property, property to be

abandoned, overdeveloped property and more facilities than necessary for future needs,

property used for non-utility purposes, property that should be removed because of

circumstances including unusual casualties (fire, storm, flood, etc.), sudden and complete

obsolescence, or un-expected and permanent shutdown of an entire operating assembly or

plant. As stated above, these types of assets must be retired (removed from rate base) and

moved to a non-utility account because they have become no longer used or required to

be used as the result of causes that were not reasonably assumed to have been anticipated

or contemplated in prior depreciation or amortization provisions. Each utility will also

describe those assets that have been removed from rate base as a result of this exercise.

At this time, the Commission will not require the utilities to make additional filings to

verify the continued operational purpose of utility assets. .. ......................... Paragraph 327

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