Decision 2012-310 ATCO Gas and Pipelines Ltd. - AUC · AUC Decision 2012-310 (November 22, 2012)...

Decision 2012-310

ATCO Gas and Pipelines Ltd.

Asset Swap Application November 22, 2012

The Alberta Utilities Commission

Decision 2012-310: ATCO Gas and Pipelines Ltd.

Asset Swap Application

Application No. 1608166

Proceeding ID No. 1723

November 22, 2012

Published by


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Calgary, Alberta

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Fax: 403-592-4406

Web site: www.auc.ab.ca

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

AUC Decision 2012-310 (November 22, 2012) • i

Contents

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

2 Background ........................................................................................................................... 3

3 Issues ...................................................................................................................................... 5

4 Discussion of issues ............................................................................................................... 6 4.1 Depreciation ................................................................................................................... 7

4.1.1 Commission finding .......................................................................................... 7 4.2 Tranche timing and non-monetary adjustment .............................................................. 8

4.2.1 Commission finding .......................................................................................... 9

4.3 Income tax and other costs ........................................................................................... 10 4.3.1 Commission finding ........................................................................................ 11

4.4 Conclusion ................................................................................................................... 12

4.5 Other - board directions ............................................................................................... 14

5 Order .................................................................................................................................... 15

Appendix 1 – Proceeding participants ...................................................................................... 17

Appendix 2 – Summary of Commission directions .................................................................. 18

Appendix 3 – Tranche Timing and Asset Swap Map .............................................................. 19

List of tables

Table 1. Asset values to be swapped......................................................................................... 8

AUC Decision 2012-310 (November 22, 2012) • 1


Calgary, Alberta

Decision 2012-310

ATCO Gas and Pipelines Ltd. Application No. 1608166

Asset Swap Application Proceeding ID No. 1723

1 Introduction

1. ATCO Gas and Pipelines Ltd. (AGPL), carrying on business under the trade name ATCO Pipelines (AP), filed an application with the Alberta Utilities Commission (AUC or

Commission) on February 15, 2012, requesting approval, pursuant to Section 26(2)(d) of the Gas

Utilities Act, RSA 2000, c. G-5 to transfer certain assets to NOVA Gas Transmission Ltd.

(NGTL) in exchange for assets of approximately equal net book value from NGTL consistent

with the terms of an integration agreement between AP and NGTL dated April 7, 2009.

Integration combines AP and NGTL’s physical assets in Alberta under a single rates and service

structure that operates assets under a single integrated system. The asset transfer exchanges and

realigns facilities between AP and NGTL to align asset ownership with their respective operating

areas.1

2. The legal requirement for AUC approval of the asset dispositions involved is found in Section 26(2)(d) of the Gas Utilities Act. Section 26(2)(d) of the Gas Utilities Act provides:

(2) No owner of a gas utility designated under subsection (1) shall

(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. The Commission and its predecessor, the Alberta Energy and Utilities Board (EUB), have traditionally applied a “no harm test” in assessing an application for the disposition of utility

property under Section 26(2)(d) of the Gas Utilities Act. In the present case, application of the no

harm test requires the Commission to consider whether any of service quality, service reliability

or customer rates are likely to be adversely affected by the transfer by AP of assets of

1 Once integration is completed, AP will own and operate assets located primarily around the Calgary –

Edmonton corridor (AP Footprint), while NGTL will own and operate assets located in the balance of Alberta

(NGTL Footprint).

Asset Swap Application ATCO Gas and Pipelines Ltd.

2 • AUC Decision 2012-310 (November 22, 2012)

approximately $114.6 million in net book value in exchange for NGTL assets of approximately

$115.6 million in net book value.

4. In this decision, the Commission considers this no harm test in deciding whether to approve this asset transfer; but the cost implications of the application on AP’s revenue

requirement associated with the exchange or transfer of assets between AP and NGTL is subject

to further scrutiny in AP’s next general rate application. AP’s rate base and the implications of

such for rate-making purposes is not determined in this decision but rather will be decided at the

time of AP’s next rate application.

5. On February 17, 2012, the Commission issued notice of this application. Any party who wished to intervene in this proceeding was required to file a statement of intent to participate

(SIP) with the AUC by March 2, 2012.

6. The Commission received an SIP from the following parties:

BP Canada Energy Company

NGTL

Encana Corporation

Canadian Association of Petroleum Producers (CAPP)

Office of the Utilities Consumer Advocate (UCA)

ATCO Gas, a division of ATCO Gas and Pipelines Ltd.

The City of Calgary

7. In their SIP, each of BP Canada Energy Company and Encana Corporation indicated that it had no issues with the application but reserved the right to participate. NGTL supported AP’s

application and reserved the right to participate. The UCA submitted that it neither opposed nor

supported the application and expected to file information requests and submit final argument.

As well, the UCA indicated that it was uncertain whether it would file evidence but reserved the

right to do so. CAPP, ATCO Gas and The City of Calgary did not object to the application.

8. Based on the submissions received from parties, the Commission determined that a written proceeding was suitable. Through a series of letters,2 the Commission established a

process schedule, with argument and reply argument due July 19, 2012 and August 2, 2012

respectively.

9. On July 4, 2012, the Commission received an email from Lacombe County that raised concerns regarding the novation of existing crossing agreements applicable to the pipeline assets

in Lacombe County being exchanged between AP and NGTL.

10. In a letter dated July 11, 2012, the Commission requested that Lacombe County file a statement of intent to participate if it wanted its July 4, 2012 email to be included and considered

on the public record of Proceeding ID No. 1723 (ATCO Pipelines Asset Swap application).

11. In an email dated July 11, 2012, Lacombe County filed its SIP with the AUC. Inadvertently, the SIP was not placed onto the public record of Proceeding ID No. 1723. As a

result, on October 25, 2012, the AUC requested that Lacombe County refile its SIP.

2 Exhibits 13.01, 18.01 and 24.01.



12. On October 26, 2012, Lacombe County refiled its SIP, along with documentation on crossing agreements.

13. On October 30, 2012, the Commission established a process schedule to address the concerns raised by Lacombe County’s October 26, 2012 SIP regarding the novation of existing

crossing agreements applicable to the pipeline assets in Lacombe County being exchanged

between AP and NGTL.

14. Both NGTL and AP were afforded an opportunity to file a reply submission to address Lacombe County’s SIP and standing in the current proceeding, and provide submissions on

further process by November 1, 2012. Lacombe County was also given an opportunity to reply to

any submissions from NGTL and AP by November 5, 2012.

15. The Commission received a submission from AP on October 31, 2012, followed by a reply from Lacombe County dated November 6, 2012.

16. Based on the review of submissions from Lacombe County and AP, the Commission ruled on Lacombe County’s submission. In its November 9, 2012 ruling, the Commission found

that AP’s October 31, 2012 response provided Lacombe County with the assurance sought in its

SIP, in addition to that already extended in AP’s Landowner Package,3 that novations or

assignments of such agreements needed for the ongoing operation of the pipeline assets being

transferred to AP will be properly affected in the ordinary course of conveyancing.

17. The Commission considers that the record for this proceeding closed on November 9, 2012.

18. In reaching the determinations contained within this decision, the Commission has considered all relevant materials comprising the record of this proceeding, including the

evidence and argument 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.

2 Background

19. In order to streamline the provision of natural gas transmission services and address competitive pipeline issues in Alberta, AP and NGTL entered into the Alberta System

Integration Agreement dated April 7, 2009 (Integration Agreement).4 The Integration Agreement

requires AP and NGTL, subject to necessary regulatory approvals, to exchange ownership of

certain physical assets within distinct operating territories or “footprints” in Alberta (Asset

Swap), and to work together in Alberta under a single rates and services structure, while

maintaining separate ownership, management and operation of their own assets (Integration).

NGTL would be the party that interfaces contractually with customers for regulated gas

transmission services using the combined regulated AP and NGTL gas transmission systems

within Alberta (collectively, the Alberta System). AP’s approved revenue requirement would be

3 Exhibit 20.01, AUC-AP-9(a) attachment.

4 On September 8, 2008, ATCO Ltd. issued a news release indicating that AP and NGTL had reached a proposed

agreement to provide seamless natural gas transmission service to customers.



included in NGTL’s revenue requirement through a monthly charge from AP to NGTL. The total

Alberta System revenue requirement would therefore be composed of the AP revenue

requirement approved by the Commission and charged to NGTL plus the NGTL revenue

requirement approved by the National Energy Board (NEB).5 This would form the basis for the

determination of Alberta System rates and tariffs for all customers. As part of the

implementation of the Integration, all AP contracts would be transitioned to Alberta System

contracts with NGTL.

20. On June 26, 2009, AP filed an application (Integration Application) with the AUC that sought a number of approvals from the Commission with respect to Integration and a request to

approve AP’s revenue requirement for each of 2010, 2011 and 2012. On April 29, 2009, the

Commission approved AP’s request to negotiate the revenue requirements for 2010, 2011 and

2012 and the parties reached a negotiated settlement on the requirements.

21. In its Integration Application, AP requested that the Commission:

(i) issue an Order, pursuant to section 22 of the Gas Utilities Act, declaring that Integration is in the public interest and furthers the convenience of the public and to

provide approval for AP to proceed with implementing Integration

(ii) approve, pursuant to section 36 of the Gas Utilities Act:

(a) the AP revenue requirements for 2010, 2011 and 2012, as set out in the

Negotiated Settlement

(b) the AP charge payable by NGTL to AP as of the Integration implementation date

and equal to the AP revenue requirement as approved under (a)

(iii) approve the transitioning of AP contracts to NGTL Alberta System contracts,

effective on the Integration implementation date, in accordance with the Integration

Application, pursuant to sections 22 and 36 of the Gas Utilities Act

(iv) approve, the sale of AP assets to NGTL to effect a swap of assets between AP and

NGTL, as reflected in the Integration Agreement; and provide such further and other

relief as AP may request or the Commission may deem appropriate, pursuant to

section 26 of the Gas Utilities Act6

22. In Decision 2010-228,7 the Commission approved AP’s 2010-2012 Negotiated Settlement (Settlement) with regard to its 2010-2012 General Rate Application (GRA) Phase I and

concluded that the proposal to integrate regulated gas transmission services in Alberta involving

the AP and NGTL systems was in the public interest and furthered the convenience of the public.

23. Decision 2010-228 also approved the proposed AP-NGTL asset swap in principle.8 The transitioning of AP contracts to NGTL Alberta System contracts effective on the implementation

of integration, and a swap of certain assets between AP and NGTL were to be determined in a

separate proceeding. Contract transitioning was approved in Decision 2011-1609 and the transfer

5 NGTL is regulated by the NEB.

6 Proceeding ID No. 223, ATCO Pipelines Alberta, System Integration Application, page 19. 7 Decision 2010-228: ATCO Pipelines 2010-2012 Revenue Requirement Settlement and Alberta System

Integration, Application No. 1605226, Proceeding ID. 223, May 27, 2010. 8 Decision 2010-228, page 46, paragraph 167.

9 Decision 2011-160: ATCO Pipelines Contract Transition, Application No. 1606374, Proceeding ID No. 732,

April 20, 2011. In paragraph 151 Decision 2011-260, AP was directed to notify the Commission of the date that

AP contracts cease to exist and customer contracts are transitioned to NGTL. In a letter dated August 23, 2011,

AP advised the Commission that the Integration Implementation date was October 1, 2011.

http://www.auc.ab.ca/applications/decisions/Decisions/2010/2010-228.pdfhttp://www.auc.ab.ca/applications/decisions/Decisions/2011/2011-160.pdf



of certain assets to implement a portion of the asset swap is the subject of the current

proceeding10 before the Commission.

24. On August 12, 2010, the NEB also approved Integration in Decision RHW-1-2010. In May 2011, AP and NGTL applied to the Federal Competition Bureau for an advisory opinion

(and Advance Ruling Certificate) under the Competition Act. On July 8, 2011, the Federal

Competition Bureau issued a standard “No Action” letter, with no conditions regarding

Integration and the Asset Swap and requesting notification of the closing date.

25. AP’s integration with NGTL was effective on October 1, 2011. As of this date, AP no longer invoices customers directly, but instead invoices NGTL monthly, based on AP’s approved

revenue requirement.11

26. AP and NGTL entered into an Asset Swap Agreement dated June 15, 2011 (Asset Swap Agreement).12 The key components of the Asset Swap Agreement are as follows:

it provides for the overall asset transfer to be conducted in one or more tranches (closings)

it provides for a due diligence process on behalf of the transferee

it provides for non-monetary adjustments for closings prior to the final closing to ensure no harm to the rate base of either party as a result of the timing and selection of assets for

each closing

it provides for monetary adjustments at the final closing for: (i) any difference in aggregate net book value of the assets received by a party; (ii) any expenditures in respect

of the assets not already included in the value of the assets; and (iii) any abandonment

costs relating to the assets already collected by the transferee13

Upon completion of the operational review of all assets within each tranche applications to

approve transfer of pipeline and facility licenses will be made to the AUC and the NEB

respectively. The close of each tranche will occur upon the completion of the license transfer of

each respective tranche.

3 Issues

27. Before reaching a determination with respect to approval of AP’s asset transfer and related dispositions, the Commission must address “the no harm test” and the specific concerns

raised by the UCA:

1. the treatment of information that will allow accurate depreciation costs to be calculated in the future

10

Application No. 1608166, Proceeding ID No. 1723. 11

Decision 2011-494: ATCO Pipelines 2011 Final Revenue Requirements, Final Rates Filing and Deferral

Account, Application No. 1607451, Proceeding ID No. 1314, December 20, 2011, page 2. 12

A copy of the executed Asset Swap Agreement is provided as Attachment 2 to the application. 13

Exhibit 1, application, page 5, paragraph 15.



2. the potential that AP will earn an additional return on mid-year rate base as a result of the timing of asset tranche transfers

3. AP income tax treatment under the Asset Swap Agreement

4 Discussion of issues

28. The no harm test considers the proposed transaction in the context of both potential financial impacts and service level impacts to customers and has been reviewed in several EUB

and Commission decisions. The test was summarized in Decision 2000-4114 when the EUB

stated:

The Supreme Court of Canada has stated that the Board’s jurisdiction to “safeguard the

public interest in the nature and quality of the service provided to the community by

public utilities” is “of the widest proportions.”15

The Board has also noted that its

governing legislation provides no explicit guidance for the exercise of the Board’s

discretion in approving an asset disposition by a designated owner of a public utility.16

The Board has held that its discretion under essentially similar provisions of the GU Act

must be exercised according to a “no harm” standard. More specifically, the Board has

held that it must be satisfied that customers of the utility will experience no adverse

impact as a result of the reviewable transaction.17

…

The Board believes that its duty to ensure the provision of safe and reliable service at just

and reasonable rates informs its authority to approve an asset disposition by a public

utility pursuant to Section 91.1(2) of the PUB Act. Therefore, the Board is of the view

that, subject to those issues which can be dealt with in future regulatory proceedings …,

it must consider whether the disposition will adversely impact the rates customers would

otherwise pay and whether it will disrupt safe and reliable service to customers. As

already noted, the Board also accepts that it must assess potential impacts on customers

in light of the policy reflected in the EU Act, namely the unbundling of the generation,

transmission and distribution components of electric utility service and the development

of competitive markets and customer choice. As a result, rather than simply asking

whether customers will be adversely impacted by some aspect of the transactions, the

Board concludes that it should weigh the potential positive and negative impacts of the

transactions to determine whether the balance favours customers or at least leaves them

no worse off, having regard to all of the circumstances of the case. If so, then the Board

considers that the transactions should be approved.

________________

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

16 Decision U99102, p.7

17 See Decision U98084, NOVA Corporation, et al., Application for Regulatory Approvals in

Connection with a Proposed Merger of NOVA Corporation and TransCanada Pipelines

Limited (May 19,1998), p. 6; Decision U98097, Westcoast Energy Inc. et al., Sale of Shares

in Centra Gas Alberta Inc. from Westcoast Energy Inc. to AltaGas Services Inc. (June 29,

1998), p.3; Decision U99102, supra, p.8

14

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

File No. 6404-3, July 5, 2000, pages 7 and 8.

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



4.1 Depreciation

29. In its information request UCA-AP-3(b), the UCA questioned whether AP was aware of the depreciation procedures used by NGTL with respect to the assets being transferred from

NGTL to AP.15 AP’s response was that AP is generally aware of the depreciation procedures

NGTL uses to depreciate its assets but has not done an analysis of the specific procedure used in

relation to the assets to be transferred. AP added that it will be engaging a depreciation expert to

perform a depreciation study to incorporate the NGTL assets into AP’s asset base.16

30. The UCA submitted that there is a clear risk that when AP and its depreciation expert(s) conduct future depreciation studies, they will discover the information required for estimating

the historical and forecast life and net salvage is deficient, incomplete, or otherwise needs to be

supplemented by information currently held by NGTL.17

31. The UCA noted that following a similar failure to scrutinize asset data after the transfer of assets from TransAlta to Aquila Networks Canada (Alberta) Ltd. (ANCA), the Commission’s

predecessor stated in EUB Decision 2003-019:18

The Board notes ANCA’s comments that it was unaware of the deficiencies in the

required data for a depreciation study. The Board considers that it was the responsibility

of ANCA to take all reasonable steps available to it, to ensure that it was able to provide

a depreciation study when it made the commitment to its customers and stakeholders that

it would do so.

32. The UCA argued that AP should at least be requesting NGTL to provide all available information needed to ensure the data being incorporated into AP’s depreciation data matches

and has integrity. The UCA requested that the Commission make clear in any decision approving

this application that any associated future harm to customers, such as delayed or expensive

depreciation studies, incomplete or imprecise estimations of life and net salvage, or ad hoc

depreciation methods for the transferred assets, will be at the expense of AP and not its

customers.19

33. In reply argument, AP submitted that it is taking all prudent steps to acquire and ensure the accuracy of the information and data required to perform a depreciation study and discounted

the UCA’s concern that NGTL would not cooperate with AP on an ongoing basis with respect to

matters affecting the Alberta System. AP argued that the Integration Agreement specifically

contains a “Further Assurances” clause committing the parties to continue working together once

Integration is implemented.20

4.1.1 Commission finding

34. The Commission recognizes that the Asset Swap and its depreciation implications for AP have not been subject to an extensive review by a depreciation expert. Consistent with Decision

2003-019, the Commission considers that any deficiencies in the data required to conduct a

15

Exhibit 16.02, page 4. 16

Exhibit 21.01. 17

Exhibit 31.01 UCA argument, paragraph 13. 18

Decision 2003-019: Aquila Networks Canada (Alberta) Ltd., 2002/2003 Distribution Tariff, Application No.

1250392, February 28, 2003, page 62. 19

Exhibit 31.01, UCA argument, paragraph 17. 20

Exhibit 33, AP reply argument, pages 1-2.

http://www.auc.ab.ca/applications/decisions/Decisions/2003/2003-019.pdf



depreciation study, the depreciation method previously employed by NGTL, and the impact of

any required future adjustments to depreciation costs, estimations of life, or net salvage are to be

borne by AP’s shareholders, unless AP is able to justify why customers should bear any

subsequent adjustments. The Commission directs AP to advise the Commission of any material

adjustments to depreciation under consideration or being made (including changes to

environmental liabilities and abandonments) in its next general rate application.

35. The Commission considers that any adverse future consequences resulting from this concern raised by the UCA may be dealt with more effectively in AP’s next general rate

application. Accordingly the Commission is not persuaded that depreciation matters raised by the

UCA are likely to result in harm to AP customers.

4.2 Tranche timing and non-monetary adjustment

36. The Asset Swap transfers assets of approximately equal net book value between AP and NGTL in four tranches (see Appendix 3) over an 18-month period to align asset ownership with

the respective operating areas.21 The value of each of these tranches as at December 31, 2010, is

provided below (these are preliminary values which will be updated at the time of each closing).

Table 1. Asset values to be swapped

NGTL Assets transferring to AP ($millions) AP Assets transferring to NGTL ($millions)

Tranche Historic

cost Accumulated depreciation

Net book value

Tranche Historic

cost Accumulated depreciation

Net book value

1 12.9 -6.1 6.8

1 28.4 -10.8 17.6

2a 96.5 -52.6 43.9

2 32.5 -13.4 19.1

3 19.9 -9.5 10.4

3 6.3 -2.2 4.1

4a 100.3 -45.8 54.5

4 96.3 -22.5 73.8

Total 229.6 -114 115.6

163.5 -48.9 114.6

37. The Asset Swap Agreement also provides for adjustments for tranche closings prior to the final closing to prevent harm to the rate base of either party as a result of the timing and

selection of assets for each tranche closing. These consist of monetary adjustments for

differences in aggregate net book value and also abandonment costs related to the assets already

collected by the transferee. Further, any adjustments required for differences in line pack with

respect to transferred assets will be made pursuant to Article 7.2(b) of the Asset Swap

Agreement.

38. The UCA argued that AP’s proposed asset swap in four tranches could result in rate base additions for AP greater than its retirements during the calendar year. As such, the annual return

could be over and above the amount that would be earned absent the asset swap.22

39. The UCA submitted that it remained unclear how the mechanics of the bilateral agreement between AP and NGTL would affect AP’s filings before the Commission. As shown

in Ms. Radway’s evidence and information request responses on behalf of the UCA, depending

on how the regulatory information is filed, and notwithstanding the presence of the Non-

Monetary Adjustment in the Asset Swap Agreement, the UCA stated that it is possible for AP to

21

Exhibit 1, Application, Attachment 4 Schedule A & Schedule B, pages 19-21. 22

Exhibit 31.01, UCA argument, paragraph 18.



earn an increased return based on the actual mid-year rate base additions, amounting to between

$1 million and $1.5 million.23 The UCA submitted that to avoid any extra return, inadvertently or

otherwise, and to ensure transparency in the years where the assets are transferred, the AUC

should include a condition preventing AP from earning an increased return as a result of transfer

timing. The UCA added that AP should also be directed to include the reconciliation of the

tranche transfers in subsequent annual regulatory filings. The UCA further submitted that to

ensure transparency, such a reconciliation table should include the capital additions and

retirements on an actual basis as separate line items.24

40. AP submitted that the Non-Monetary Adjustment mechanism would eliminate any differences in the net book value of the rate base additions and retirements as part of the Asset

Swap Agreement. AP stated that the only time when rate base would be impacted by a difference

in the tranche values is at the time of the final asset swap tranche.

41. AP noted that Section 3.3(b) of the Asset Swap Agreement states:

The Non-Monetary Adjustments are intended to ensure no harm to the rate base of either

Party as a result of the timing and selection of Transferred Assets at each Closing.

(emphasis added by AP).

42. AP argued that the Non-Monetary Adjustment mechanism allows the value of the tranches being swapped to be equalized prior to the completion of the Asset Swap and ensures

that the rate bases of AP and NGTL remain unchanged. The UCA’s evidence should therefore be

rejected.25


43. The Commission is satisfied that the Non-Monetary Adjustment mechanism will negate any increased return that might result from the timing of asset tranche transfers with varying net

book values prior to completion of the Asset Swap. The Commission finds that the rebuttal

evidence submitted by AP26 satisfactorily demonstrates that the Non-Monetary Adjustment

mechanism will operate to offset the cumulative difference in the tranche values so that rate base

remains unchanged after the first three tranches. Any difference in rate base will only occur after

the final tranche is completed as a result of the difference between the $115.6 million transferred

from NGTL to AP and the $114.6 million being transferred from AP to NGTL. This will result

in a net $1 million increase in rate base for AP. Even if the Commission were to accept the

UCA’s evidence, any increased return that might occur should be weighed against the forecast

benefit or savings27 associated with Integration. Given the expected monetary benefit of

Integration, the Commission expects any resulting marginal increase in return will be immaterial.

The UCA’s recommendation regarding the inclusion of a condition preventing AP from earning

an increased return as a result of transfer timing is therefore unnecessary and is rejected.

44. The Commission concurs with the UCA’s submission that AP should file a reconciliation of each of the tranche transfers, similar in format to that shown in the tables included in AP’s

23

Exhibit 23.03, paragraph A10 and Exhibits 29.01 and 29.03 re: AUC-UCA-1(a) and (b). 24

Exhibit 31.01, UCA argument, paragraphs 22-24. 25

Exhibit 32.01, AP argument, paragraph 14. 26

Exhibits 30.01 and 30.02. 27

Exhibit 1, application, paragraph 11, net cumulative savings for the period from 2010 through 2017 to

customers are $41.3 million.



rebuttal evidence. This will help to monitor the progress of the asset swap and serve as a check

that the Non-Monetary Adjustment mechanism is functioning as represented by AP. The

Commission directs AP to submit the reconciliation of the tranche transfers upon the closing of

each tranche and also as part of the subsequent general rate application(s) and the subsequent

Rule 005: Annual Reporting Requirements of Financial and Operational Results (Rule 005)

annual regulatory filings. To ensure transparency, the reconciliation tables should include the

capital additions and retirements on an actual basis as separate line items.28

4.3 Income tax and other costs

45. The UCA expressed concerns that AP identified increased income tax as a consequence of the Asset Swap, due to different capital cost allowances between the incoming and exiting

assets, and that AP proposed to capture these extra expenditures in the “Integration deferral

account”.29 As part of its evidence30 the UCA submitted the following concerns with this

proposal:

It is not clear that the “Integration deferral account” currently exists.

Decision 2010-228 notes that AP stated in an Information Request response that it “may” have an “Integration deferral account” in 2010 resulting from AP’s Negotiated

Settlement with regard to its 2010-2012 General Rate Application (GRA) Phase I –

but that is not the approval of an actual deferral account.

The Settlement’s treatment of income taxes does not consider a deferral account.

Using a deferral account to broadly capture income tax (or other material costs) without any sense of their magnitude does not allow the Commission to apply the “no

harm test” to the transfer of a regulatory asset, required under s. 26(2)(d)(i) of the

Gas Utilities Act .

Upon disposition, a deferral account would represent an increased cost to AP ratepayers that will have to be paid at some point, contrary to the Alberta System

Integration Agreement.

46. In order to assess harm, the UCA submitted that there must be full disclosure and transparency in the sale of any regulated asset. The UCA argued that there must be full

disclosure of costs included in AP’s Integration deferral account, and absent that transparency,

costs such as income tax should not be approved for inclusion in AP’s Integration deferral

account.

47. To ensure that the Asset Swap’s benefits to customers are not significantly eroded, the UCA submitted that the Commission should condition any approval of the present application on

the basis that increased AP customer costs, which are neither included in the application’s net

present value calculation nor offset by a matching benefit from the NGTL system, should be

borne by AP’s shareholders and not its customers.

48. AP indicated that its proposed treatment of the increase in income taxes due to lower capital cost allowance deduction claims resulting from the Asset Swap is consistent with the

spirit and intent of the Integration Agreement. Section 5.1(a) of the Integration Agreement states:

The swap of assets will not affect the revenue requirement of either Party.

28

Exhibit 31.01, UCA argument, paragraphs 22-24. 29

Exhibit 20.01, AUC-AP-7(f). 30

Exhibit 25.03, UCA evidence A16 and A17.

http://www.auc.ab.ca/acts-regulations-and-auc-rules/rules/Pages/Rule005.aspx



AP added that Section 5.1(b) (ii) of the Integration Agreement further states:

… the intent that neither Party is to be negatively impacted by such swap …

49. AP argued that the charges in the deferral account will be completely offset by tax deductions for NGTL.31

50. AP argued that the UCA’s submission was entirely inappropriate for a number of reasons. First, it amounted to requiring AP to “guarantee” the savings that will result from integration.

That had never been part of the Integration equation, nor had AP’s return been premised on any

such risk. Imposing such a risk would certainly have return implications. Further, the condition

requested by the UCA places non-symmetrical risk on AP. AP submitted that the UCA was

seeking to have the Commission make rate determinations that may affect a number of

stakeholders. AP did not consider the current process was the proper forum to make such a

determination and potentially affected parties had not had notice that such issues may be raised.

The proper forum for determining AP's revenue requirement is a rate proceeding where all

relevant facts are before the Commission and all interested parties have an opportunity to

participate.32


51. Section 5.1(a) and Section 5.1(b) (ii) of the Integration Agreement indicates that neither party is intended to be impacted by the swap of assets between parties. The Commission is

mindful of the submission of the UCA that “[u]sing a deferral account to broadly capture income

tax costs (or other material costs) without any sense of their magnitude does not allow the

Commission to apply the “no harm test” to the transfer of a regulatory asset,33 required under s.

26(2)(d)(i) of the Gas Utilities Act (GUA)”. The Commission accepts AP’s contention that any

increase in income taxes for AP as a result of reduced capital cost allowance deductions will be

offset by a corresponding decrease for NGTL, all other things being equal. Even though this

means that the revenue requirements for each of AP and NGTL may be affected by the Asset

Swap, the overall combined revenue requirements are not likely to be materially impacted and it

is this combined revenue requirement which is used in determining customers’ rates. As such,

customers are not likely to be harmed by a potential increase in AP’s income taxes associated

with the Asset Swap as the combined revenue requirement and rates are essentially unchanged.

52. With respect to the UCA’s submission that it is not clear that an Integration deferral account was approved by the Commission, Decision 2010-228 states:

“Flow through” items are items that either: (i) have offsetting revenues and expenses (e.g.

franchise fees); or (ii) have the difference between the actual amount and forecast amount

placed in a deferral account for collection from or refund to customers at a later time (e.g.

hearing costs, Integration costs/savings).34

53. Although Decision 2010-228 may not have explicitly approved an Integration deferral account, the Commission approved the Settlement as filed which contained the above section. As

31

Exhibit 32.01, AP argument, paragraph 20. 32

Exhibit 33.01, AP reply argument, paragraph 21. 33

Decision 2000-41, as cited in Exhibit 1, application, paragraph 52. 34

Decision 2010-228, paragraph 37.



a result, the Commission considers that creation of an Integration deferral account was therefore

implicitly approved. The Commission is satisfied that AP’s proposal to capture the extra cost in

the “Integration deferral account” is reasonable. The Commission and interested parties will be

given the opportunity to examine and challenge any extra income tax expenditures when AP files

application to settle the balance in the Integration deferral account. The Commission directs AP

to clearly identify any increased income tax amounts resulting as a consequence of the Asset

Swap in AP’s Integration deferral account approval application.

4.4 Conclusion

54. The Asset Swap Agreement provides for adjustments for tranche closings prior to the final closing to prevent harm to the rate base of either party as a result of the timing and selection

of assets for each closing. These consist of monetary adjustments for differences in aggregate net

book value and also abandonment costs related to the assets already collected by the transferee.

Section 3.3(b) of the Asset Swap Agreement also includes Non-Monetary Adjustments intended

to ensure no harm to the rate base of either party as a result of the timing and selection of

transferred assets at each tranche closing. AP and NGTL also conducted province-wide

landowner and stakeholder information publication and consultation efforts and no formal

objections to the Asset Swap were recorded throughout the process.

55. When evaluating AP’s asset transfer and considering whether the” no harm test” is satisfied, the Commission is mindful of the overall benefits of Integration when weighed against

specific costs identified in the asset transfer approval application. In Decision 2010-228, the

Commission concluded the following with respect to Integration:

Integration eliminates stacked tolls for customers who transport gas in Alberta on both the AP and NGTL pipeline systems, eliminates the need for duplicative terms of service,

and reduces the regulatory burden and costs which result when NGTL and AP compete

for customers in Alberta, often leading to protracted and contentious regulatory

proceedings.35

Integration should enhance the orderly, efficient, and cost effective expansion of the Alberta System in that system planning for an expansion is anticipated to be performed

on a coordinated basis.36

The exclusive footprint areas should lead to efficiencies for facility applications.37

The 2010-2012 GRA Phase I Settlement forecasted cost savings to AP’s customers due to Integration, and reduced business risk for AP.38

Most customers requiring the use of both the AP and NGTL pipeline systems should benefit by the removal of dual or stacked tolls that inhibited cost effective transportation

of gas in the province. However, the rate impact to individual customers will be explored

in NGTL’s rate application to the NEB.39

35

Decision 2010-228, paragraph 131. 36




Decision 2010-228, paragraph 132.



56. Based on its review of the evidence in this proceeding, the Commission is satisfied that AP has met the requirement of the no harm test, specifically as it relates to concerns regarding

service quality, reliability, and increased costs to customers, which has been applied by the

Commission in determining whether to approve a disposition under Section 26(2)(d) of the Gas

Utilities Act. In reaching its finding on the “no harm test,” the Commission relied significantly

on the assertions in AP’s application:

In applying the no harm test, the Commission first considers if the disposition would

disrupt safe and reliable service to customers or otherwise affect the quality and/or

quantity of services being provided to ratepayers. It is respectfully submitted that the

proposed disposition of the AP Swap Assets in conjunction with Integration will not

disrupt safe and reliable service, nor will it adversely affect the quality and/or quantity of

services being provided to ratepayers. On the contrary, the proposed swap will allow for

the efficiencies and streamlining of service contemplated by Integration to be fully

realized.

........ With respect to the potential for the proposed disposition to adversely impact the

rates customers would otherwise pay, it is respectfully submitted that the proposed

disposition will have no such adverse impact. The proposed disposition involves a swap

of AP assets for NGTL assets of approximately equal value. As such, the respective rate

bases of AP and NGTL remain unchanged as a result of the swap.40

57. The Commission finds that the UCA’s concerns with respect to income tax, increased return due to tranche timing and differences in the net book value of assets transferred between

NGTL and AP, and depreciation, have been adequately addressed by AP. Further the

Commission is satisfied that AP’s landowner and stakeholder engagement adequately informed

affected parties of the intended asset transfer by AP. Nevertheless, the implications of the Asset

Swap for rate-making purposes should not be construed as approved by this decision and remain

subject to further scrutiny and determination in AP’s next general rate application(s).

58. The Commission is also satisfied that AP and NGTL have entered into four operating agreements “to ensure the safe and reliable operation of the pipeline system during the Asset

Swap and on an ongoing basis once the Asset Swap is completed.” The agreements consist of the

following:

i. The Transitional Operating Agreement41

ii. The Long-Term Operating Agreement

iii. The Odourization Agreement

iv. The Cathodic Protection Services Agreement42

59. In response to CAPP-AP-5(i),43 AP explained that it will not be requesting further approvals for the Asset Swap, but will be applying for the required pipeline and facility license

transfers 30 days in advance of the closing of each tranche. The Commission considers that AP’s

40

Exhibit1, application, paragraphs 53 -54. 41

Once all assets are transferred, this agreement will no longer be in effect. 42

Exhibit 1, application, page 14, paragraph 44. 43

Exhibit 19.01.



proposed timeline to address pipeline and facility license transfers is reasonable. The

Commission directs AP to provide written notice to the AUC that the tranche is ready to close 30

days prior to each tranche closing date in accordance with Section 6(f) of the Transitional

Operating Agreement.

60. AP’s asset transfer to NGTL and related dispositions are approved as filed pursuant to Section 26(2)(d) of the Gas Utilities Act.

4.5 Other - board directions

61. In Decision 2010-228, the Commission directed AP clarify the matter of outstanding directions in its future detailed application for the Asset Swap:

The Commission has compiled a summary of outstanding directions from 2003 to the end

of 2009 (refer to Appendix 5), many of which are ongoing and some applicable to a GRA

Phase II. AP should review and identify those that will be become redundant in the event

Integration receives universal approval and a GRA Phase II or other routine filings

become unnecessary. AP is directed to clarify the matter of outstanding directions in its

future detailed application for the Asset Swap.44

62. The Commission is satisfied that AP’s application complies with the above direction from Decision 2010-228 because it clearly identified the proceedings wherein AP has complied

with outstanding directions, where a direction continues to be an ongoing matter to be addressed

in a future application, and the specific cases where Integration has made the direction moot.

44

Decision 2010-228, page 48, paragraph 179.



5 Order

63. It is hereby ordered that:

(1) ATCO Gas and Pipelines Ltd.’s asset transfer to Nova Gas Transmission Ltd. and

related disposition is approved as filed pursuant to Section 26(2)(d) of the Gas Utilities

Act and subject to the Commission’s directions in this decision.

Dated on November 22, 2012.


(original signed by)

Mark Kolesar

Vice-Chair

(original signed by)

Anne Michaud

Commission Member



Appendix 1 – Proceeding participants

Name of organization (abbreviation) counsel or representative

ATCO Pipelines (AP)

N. Gretener B. Jones S. J. Mah

ATCO Gas (AG)

A. Green M. Bayley

BP Canada Energy Company

C. G. Worthy The City of Calgary

D. Evanchuk M. Rowe H. Johnson

Canadian Association of Petroleum Producers (CAPP)

R. Fairbairn K. Folkins

Encana Corporation

R. Powell D. Dunlop

Lacombe County

T. Hager

NOVA Gas Transmission Ltd. (NGTL)

L. Angus

Office of the Utilities Consumer Advocate (UCA)

R. B. Wallace M. Keen B. Shymanski

The Alberta Utilities Commission Commission Panel

M. Kolesar, Vice-Chair A. Michaud, Commission Member

Commission Staff

J. Petch (Commission counsel) M. McJannet R. Armstrong, P.Eng. N. Mahbub D. Mitchell L. Ou



Appendix 2 – 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 Asset Swap and its depreciation implications for AP have not been subject to an extensive review by a depreciation expert. Consistent with

Decision 2003-019, the Commission considers that any deficiencies in the data required

to conduct a depreciation study, the depreciation method previously employed by NGTL,

and the impact of any required future adjustments to depreciation costs, estimations of

life, or net salvage are to be borne by AP’s shareholders, unless AP is able to justify why

customers should bear any subsequent adjustments. The Commission directs AP to advise

the Commission of any material adjustments to depreciation under consideration or being

made (including changes to environmental liabilities and abandonments) in its next

general rate application. ................................................................................... Paragraph 34

2. The Commission concurs with the UCA’s submission that AP should file a reconciliation of each of the tranche transfers, similar in format to that shown in the tables included in

AP’s rebuttal evidence. This will help to monitor the progress of the asset swap and serve

as a check that the Non-Monetary Adjustment mechanism is functioning as represented

by AP. The Commission directs AP to submit the reconciliation of the tranche transfers

upon the closing of each tranche and also as part of the subsequent general rate

application(s) and the subsequent Rule 005: Annual Reporting Requirements of Financial

and Operational Results (Rule 005) annual regulatory filings. To ensure transparency, the

reconciliation tables should include the capital additions and retirements on an actual

basis as separate line items. ............................................................................. Paragraph 44

3. Although Decision 2010-228 may not have explicitly approved an Integration deferral account, the Commission approved the Settlement as filed which contained the above

section. As a result, the Commission considers that creation of an Integration deferral

account was therefore implicitly approved. The Commission is satisfied that AP’s

proposal to capture the extra cost in the “Integration deferral account” is reasonable. The

Commission and interested parties will be given the opportunity to examine and

challenge any extra income tax expenditures when AP files application to settle the

balance in the Integration deferral account. The Commission directs AP to clearly

identify any increased income tax amounts resulting as a consequence of the Asset Swap

in AP’s Integration deferral account approval application. ............................. Paragraph 53

4. In response to CAPP-AP-5(i), AP explained that it will not be requesting further approvals for the Asset Swap, but will be applying for the required pipeline and facility

license transfers 30 days in advance of the closing of each tranche. The Commission

considers that AP’s proposed timeline to address pipeline and facility license transfers is

reasonable. The Commission directs AP to provide written notice to the AUC that the

tranche is ready to close 30 days prior to each tranche closing date in accordance with

Section 6(f) of the Transitional Operating Agreement. ................................... Paragraph 59

http://www.auc.ab.ca/acts-regulations-and-auc-rules/rules/Pages/Rule005.aspx



Appendix 3 – Tranche Timing and Asset Swap Map

(return to text)

Appendix 3 - Tranche Timing

(consists of 3 pages)

Appendix 3 - Asset Swap Map

(consists of 1 pages)

- 4 -

Phases Site Pre-Closing Activities Responsibilities Phase V-VII None anticipated Not applicable 9. Diagram of Pre-Closing Activities

The following diagram illustrates the Pre-Closing Activities:

Transferring Party is Owner

Receiving Party is Owner

Time

Month 0

Month 6

Month 8

Month 9

AUC / NEBApproval

PreliminaryEng. Design

ATCO – TCPL Project Launch, Site

discovery and Project Execution Plan

Tranche 1

Phase I -Tranche planning

and detailed site Design

Procurementbegins Phase II -

ConfigurationFAT

(Testing) Phase VI -AUC / NEB

30 daynotification

Phase III -Initial Acceptance

Checklist-processed for

each site

Site FacilityOwnership

Site FacilityOperator

Phase VII -Tranche Closes

Transferring Party is Operator Receiving Party is Operator

Receiving Party is Operator

Receiving Party is Operator

Phase IV -Site

Commissioning

Phase V -Acceptance

Checklist Processed

Pre-Closing Activities

Future Tranches 2-4...

Diagram of Pre-Closing Activities

Both Parties*Receiving Party is Operator

Both Parties*

Transferring Party is OperatorBoth Parties*

Both Parties*


Both Parties*Both Parties*


Project KickoffProject Execution

Plan start

*Both Parties- During this time, Transferring Party operates equipment it owns; Receiving Party operates gas control and equipment installed during

Pre-Closing Activities

Project Close out

Legend

Transferring Party

Receiving Party

60-90 days per Tranche

ATCO PipelinesAsset Swap Application - Attachment 4

February 15, 2012

Page 19 of 21


ATCO Gas and Pipelines Ltd. Appendix 3 - Tranche Timing Page 1 of 3

AUC Decision 2012-310 (November 22, 2012)

SCHEDULE “B”

Tranche Map

See attached page.


February 15, 2012

Page 20 of 21




- 2 -


February 15, 2012

Page 21 of 21




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209

Drift Pile River

I.R.

Lake

Bistcho Lake

I.R. 150F

I.R. 150D

Boyer

I.R. 154A

I.R. 154B

I.R. 152B

I.R. 212

I.R. 151A

Creek

Amber River

I.R. 226

I.R. 210

I.R. 154

Pakashan

Woodland Cree

I.R. 211

I.R. 164A

John D’Or

Woodland CreeI.R. 227

Clear Hills

Jackfish

Woodland Cree

I.R. 150C

Assineau River

I.R.

Sucker

Upper Hay River

Child Lake

Lakes

Sturgeon

I.R. 152C

Swan River

Point

I.R. 163

I.R. 214

Lake

Horse

Sturgeon Lake

Hay

I.R. 150E

I.R. 150

I.R. 187

Halcro

150A

William McKenzie

Sturgeon Lake

I.R. 155B

I.R. 207

I.R. 151K

I.R. 164

Carcajou Settlement

Zama Lake

PrairieBushe River

PRAIRIE

GRANDE

RN

A

SH

DE

XI

MT

II

FALHER

RIV ER

V ALLEYV IEW

MANNING

HIGH

HIGH

LAKE LEV EL

SEXSMITH

RAINBOW

PEACE

W EMBLEY

FAIRV IEW

McLENNAN

BEAV ERLODGE

PRAIRIE

RIV ER

GRIMSHAW

SPIRIT

71

20

5

13

64

99

12

84

79

19

63

85

13

80

18

118

24

17

8

93

108

120

3

90

11

77

74

7

96

118

65

7

8

97

24

128

9

191

67

204

7

16

1517

105

87

94

115

126

16

9

116

69

102

110

4

13

8

117

82

1425

2

104

125

11

91

72

119

66

510

11

101

86

63

111

23

76

98

23

112

89

92

73

12

81

6

109

107

124

11

122

75

14 9

78

10

83

12

22 21

22

121

9

10

123

114

10

100

262

113

70

21

95

88

15

103

River

River

Smoky

River

River

River

Wapiti

Wapiti

Smoky

Smoky

Peace

iPeace

River

r

aec

P

ev

R

e

Bison

L.

Buffalo Bay

W inagami

Lake

Kimiwan

Lake

Bear L.

L.

Cardina

l

L.

Lake

SaskatoonL.

Lake

Eva

Lubicon

Hay

Wadlin

Giroux

L.

Bay

Auger

Bay

L

g

Zama

rtk

Mr

a

Lake

e

a

ea

Lake

Utikuma

Bistcho Lake

LakeLesser Slave

Utikoomak LakeI.R. 155 Utikoomak

LakeI.R. 155A

I.R. 231Grouard

Freeman I.R. 150BGrouard I.R. 229

Grouard I.R. 230

Tallcree

I.R. 173

Tallcree

I.R. 173A

Fort Vermilion I.R. 173B

Beaver RanchI.R. 163B

BeaverRanch

I.R. 163ABeaver Ranch

I.R. 173C

Wadlin Lake

I.R. 221

131

Dog Head

Clearwater

I.R. 166C

I.R. 174B

I.R. 175

I.R. 194

I.R. 150G

Allison Bay

Sand

Gregoire Lake

Lake

I.R. 166D

Gambler

Chipewyan

I.R. 201G

I.R. 218

Chipewyan

I.R. 166

I.R. 201C

Chipewyan

Wabasca

166A

Charles Lake

Point

I.R. 162

I.R. 224

I.R.

I.R. 176B

I.R. 176

Fox

Cold

Gate

I.R. 225

I.R.

Sawridge

Indian Cemetery

Wabasca

Lake

Chipewyan

Lake

Colin Lake

Old Fort

Namur River

201F

I.R. 150H

Devil’s

I.R. 201E

Fort McKay

I.R.

I.R. 201D

Chipewyan

Chipewyan

I.R. 219

Gregoire

I.R. 167

Wabasca

Chipewyan

Namur River

Gregoire Lake

I.R. 166B

I.R. 176A

I.R. 201A

Beaver

Cornwall Lake

I.R. 217

I.R. 201B

I.R. 220

I.R. 223

I.R. 174A

Wabasca

Jean Baptiste

I.R. 174

Heart Lake

Sawridge

I.R. 183

House River

Janvier

I.R. 178

Wabasca

Lake

I.R. 149B

I.R.

Chipewyan

201

AIR W EAPONS RANGE

COLD LAKE

NATIONAL

PARK

BUFFALO

W OOD

W OOD BUFFALO

D

H

M

AR

F T

H

U

D I

R

A N

IE

F I

I

O

N

T

F

E R

I

M

LAC

LAKE

FORT SMITH

LA BICHE

SLAV E

ATHABASCA

125

79

120

6

9

123

94

93

81

76

1

83

108

5

119

112

88

3

96

1

111

84

74

101

64

125

109

12

100

8

108

87

101

7

82

94

63

100

26

73

92

23

71

78

15

99

126

89

4

21

75

63

5

113

3

74

91

115

2

16

16

104

85

7

1320

67

65

107

80

3

64

106

96

118

11

116

19

89

9

69

66

5 4

109

25

103

15

110

104

23

124

121

126

99

17

91

24

95

8

65

121

22

118

73

17

98

97

14

70

6

19

72

107

22

7

106

95

114

84

122

105

3

79

24

122

11

78

86

2

70

87

97

86

18

71

124

85

82

105

75

5 4

76

1

14

111

115

1320

1

88

66

4

90

10

113

72

67

77

68

110

81

119

114

83

123

103

77

6

117

21

69

102

90

120

102

2

18

112

2

116

92

117

93

12

98

t

h

A

River

Atha

basca

Athabasca

t

b

er

a

River

Peace

River

sa

River

b

Atha

basca

v

c

a

River

a

hc

River

a

A

s

Ri

a

Rvr

iSla

ve

River

Slave

e

McClelland

Lake

L.

Pinehurst

Lake

Lake

Lakes

Fort

Wabasca

Lake

Lake

Lake

Touchwood

Sand

Arch

Colin

Andrew

Lake

L.

Legend

Seibert

Leggo

Lela

nd

Chipewyan L.

Cornwall

Heart

Willow Lake

Gardiner Ls.

Lake

Bay

Old

Conibear

English

Bay

NamL.

ur

Lake

L.

Muskwa

Lake

Beaver

Lake

Island

Thultue

South

Lake

Lake

Lake

Richardson

Lake

Lake

Rock

Charl

es

L.

Lake

st

Lake

Winefred

Baril

Gordon

ao

Peerless

Lake

Garson

Lake

Lake

Lake

Lake

Wentzel

Lake

rWab

cL.

Calling

Lake

ah

N

Graham

Mamawi

Biche

Lac

la

Claire

Lake

I.R. 149A

Winefred Lake

I.R. 194B

I.R. 194ACowper Lake

REGIONAL MUNICIPALITY OF

COLD

LAKE

Cold Lake

Cold

Lake

LEGAL

DRUMHELLER

BENTLEY

LA

KE

HILLSSW AN

S I X T H

M E R I D I A N

FORT MCMURRAY

95

52

AWN

Piikani

Piikani

Tsu T’ina

ATCO Pipelines

TCT

TCT (Nova Ventures)

TRANSMISSION LINES

Alliance Pipeline

INFORMATION THEREON IS MADE .

NO WARRANTY OR REPRESENTATION AS TO THE COMPLETENESS OF SAID MAP OR

PRODUCED BY ATCO Pipelines - GRAPHICS

M ap 1

M ap 3

M ap 2

M ap 4

M ap 5

M ap 10Set of 3

M ap 11

M ap 7

M ap 6

M ap 14

M ap 12

M ap 27

M ap 28M ap 23

M ap 24

M ap 31M ap 30

M ap 29

M ap 32

M ap 35

M ap 33

M ap 34

M ap 37

M ap 38

M ap 36

M ap 19

M ap 20

Set of 3

M ap 17

M ap 15

M ap 49

M ap 43M ap 44

M ap 46

M ap 40

M ap 48

M ap 21

M ap 22

M ap 18

M ap 51

M ap 47

M ap 53

M ap 52

M ap 54

M ap 55

56

M ap

REVISED:

Set of 6

Set of 3

Set of 2

M ap 57

M ap 58Set of 2

Integration Areas

Proposed ATCO Central Area Footprint

1

2

4

2a

4a

3

Proposed Tranches

Set of 2

(2011)INTEGRATION M APFINAL ATCO NGTL

SEPTEMBER 06, 2011

ATCONGTL

NGTLATCO

ATCONGTL

NGTLATCO

BLOCK VALVE

LAC LA NONNE

BLOCK VALVE

TCT TRANSMISSION

P

P

P

273m m MOP 7240kPa

15175

1517615174

PEERS

CREEK RECEIPT

FROM SOUTH CARROT

168m m

11452 11453

1145411455

25100

43 44

2

TO

PE

ER

S S

UC

TIO

N

FR

OM

PE

ER

S D

ISC

HA

RG

E

COMPRESSOR

03-33-53-13-W 5M

24176 26690

24177323m m MOP 6550kPa

16-02-57-3-W 5

12-23-41-19-W 4

273m m MOP 7240kPa

15-35-52-20-W 5

24820

24844

24851

24846 24847

SUNDANCE CREEK

COMPRESSOR

24848

24849

24852

24845

SUNDANCE CREEK

COMPRESSOR TIE-IN

N.E.35-52-20-W 5

273m m MOP 7240kPa


February 15, 2012

Page 2 of 2


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