Reasons for Decision TransCanada PipeLines Limited RH-1-2001

Reasons for Decision TransCanada PipeLines Limited RH-1-2001
Reasons for Decision
TransCanada PipeLines
Limited
RH-1-2001
November 2001
Tolls and Tariff
National Energy Board
Reasons for Decision
In the Matter of
TransCanada PipeLines
Limited
2001 and 2002 Tolls and Tariff Application
RH-1-2001
November 2001
© Her Majesty the Queen in Right of Canada 2001 as
represented by the National Energy Board
© Sa Majesté la Reine du Chef du Canada 2001
représentée par l'Office national de l'énergie
Cat. No. NE22-1/2001-6E
ISBN 0-662-31118-3
No de cat. NE22-1/2001-6F
ISBN 0-662-86304-6
This report is published separately in both official
languages.
Ce rapport est publié séparément dans les deux
langues officielles.
Copies are available on request from:
The Publications Office
National Energy Board
444 Seventh Avenue SW
Calgary, Alberta, T2P 0X8
E-Mail: [email protected]
Fax: (403) 292-5576
Phone: (403) 299-3562
1-800-899-1265
Exemplaires disponibles sur demande auprès du:
Bureau des publications
Office national de l’énergie
444, Septième Avenue S.-O.
Calgary (Alberta), T2P 0X8
Courrier électronique: [email protected]
Télécopieur: (403) 292-5576
Téléphone: (403) 299-3562
1-800-899-1265
For pick-up at the NEB office:
Library
Ground Floor
En personne, au bureau de l’Office:
Bibliothèque
Rez-de-chaussée
Printed in Canada
Imprimé au Canada
Table of Contents
Recital and Appearances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii
Abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v
Glossary of Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vi
1.
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.1
Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.2
Overview of TransCanada’s Tolls Application . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
2.
Specific Tolls and Tariff Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
2.1
Sharing of Risk Associated with Contract Non-Renewals . . . . . . . . . . . . . . . . . . . . . . . 6
2.1.1 Proposal and Views of the CA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
2.1.2 Proposal and Views of PG&E/El Paso . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
2.1.3 Views of TransCanada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.1.4 Views of Parties Supporting TransCanada’s Position . . . . . . . . . . . . . . . . . . . 11
2.1.5 Views of Other Parties Opposing TransCanada’s Position . . . . . . . . . . . . . . . 12
2.2
Proposed New Service Enhancements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
2.2.1 Views of TransCanada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
2.2.2 Views of Parties Opposing TransCanada’s Proposal . . . . . . . . . . . . . . . . . . . . 16
2.3
Incentive Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
2.3.1 Views of Parties Opposing TransCanada’s Proposal . . . . . . . . . . . . . . . . . . . . 19
2.4
Pricing of IT Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
2.4.1 Views of Parties Opposing TransCanada’s Proposal . . . . . . . . . . . . . . . . . . . . 20
2.5
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
2.5.1 Views of Parties Supporting TransCanada’s Proposal . . . . . . . . . . . . . . . . . . . 21
2.5.2 Views of Parties Opposing TransCanada’s Proposal . . . . . . . . . . . . . . . . . . . . 21
2.6
Proposed Additions to Rate Base . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
2.7
Summary Views on the S&P Settlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
2.7.1 Views of TransCanada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
2.7.2 Views of Parties Supporting the S&P Settlement . . . . . . . . . . . . . . . . . . . . . . 23
2.7.3 Views of Parties Opposing the S&P Settlement . . . . . . . . . . . . . . . . . . . . . . . . 24
3.
Final Tolls versus Interim Tolls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.1
Final Tolls versus Interim Tolls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.1.1 Views of TransCanada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.1.2 Views of Parties Supporting TransCanada’s Position . . . . . . . . . . . . . . . . . . .
3.1.3 Views of Parties Opposing TransCanada’s Position . . . . . . . . . . . . . . . . . . . .
27
27
28
29
29
4.
Board’s Decisions resulting from RH-1-2001 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.1
The S&P Settlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.2
The Board’s Settlement Guidelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.3
Proposed Additions to Rate Base . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.4
Final Tolls versus Interim Tolls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.5
TransCanada’s 2003 Tolls and Tariff Application . . . . . . . . . . . . . . . . . . . . . . . . . . . .
31
31
31
31
31
31
5.
Disposition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
(i)
List of Tables
1-1
TransCanada’s 2001 Revenue Requirement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
List of Appendices
I
Toll Order AO-2-TGI-6-2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
(ii)
Recital and Appearances
IN THE MATTER OF the National Energy Board Act and the Regulations made thereunder; and
IN THE MATTER OF an application dated 3 May 2001 by TransCanada PipeLines Limited
(TransCanada) for certain orders respecting approval of the Mainline Service and Pricing Settlement 1 January 2001 to 31 December 2002 (the S&P Settlement) and the implementation of the provisions of
the S&P Settlement in TransCanada’s Tolls and Tariff for 2001; and
IN THE MATTER OF Hearing Order RH-1-2001;
HEARD in Calgary, Alberta on 18, 19, 20, 21, 24, 25, 26, 27 September 2001 and 1 and 2 October 2001;
BEFORE:
J.A. Snider
J.-P. Théorêt
D.W. Emes
Presiding Member
Member
Member
Appearances
Witnesses
C. K. Yates
P.R. Jeffrey
TransCanada PipeLines Limited
D.G. Davies
N.J. Schultz
Canadian Association of
Petroleum Producers
P.C.P. Thompson, Q.C.
Industrial Gas Users Association
R. Fraser
AEC Marketing
R. Power
Alliance Pipeline Ltd.
C. Worthy
BP Canada Energy Company
J.D. Brett
B. Czarnecki
Centra Gas Manitoba Inc.
H.P. Stephens
R. King
Cogenerators Alliance
G.E. Briden
A.S. White
G. Nettleton
Consumers’ Gas Company Ltd.
(Operating as Enbridge Consumers Gas)
K. McKnight
Coral Energy Canada Inc.
(iii)
M. Feldman
S.A. Emond
R.A. Whitmore
P.R. Carpenter
P.L. Fournier
Appearances
Witnesses
H. Huber
Dynegy Gas Transportation, Inc. and
Dynegy Marketing and Trade, a division of
Dynegy Canada Inc.
R. Cohen
L. Confrancisco
Foothills Pipe Lines Ltd.
R.R. Moore
Imperial Oil Resources
D. White
Marathon Canada Limited
E. Decter
Mirant Americas Energy Marketing Canada Ltd.
S. Scholli
Nexen Marketing
N. Gretener
L.E. Smith, Q.C.
PG&E Energy Trading, Canada Corporation/
El Paso Merchant Energy Group
C. Worthy
ProGas Limited
M. Imbleau
S. Trudeau
Société en commandite Gaz Métropolitain
N. Ruzycki
TransCanada Energy Ltd.
V.R. Gorr
TransGas Limited
M. Boyle
Trans Mountain Pipe Line Company Ltd.
G. Cameron
Union Gas Limited
A. Haskey
Westcoast Energy Inc.
C.J. Page
B. Prenevost
Alberta Department of Energy
J. Brisson
Procureur général du Québec
G. Delisle
A. Hudson
National Energy Board
(iv)
N.J. Bartlo
J.K. Hawks
R.G. DeWolf
A.S. Cheung
A.M. Moorhead
Abbreviations
Act
The National Energy Board Act
AOS
Authorized Overrun Service
Board
The National Energy Board
CA
The Cogenerators Alliance
Cardinal Power of Canada L.P. (Sithe Energies Inc.), Lake Superior
Power Limited Partnership, Tractabel Power, Inc. (West Windsor
Power), and TransAlta Energy Corporation
CAPP
The Canadian Association of Petroleum Producers
Centra
Centra Gas Manitoba Inc.
CoEnergy
CoEnergy Inc.
Coral
Coral Energy Canada Inc.
Eastern LDCs
Enbridge Consumers Gas, Gaz Métropolitain and Union Gas
FERC
Federal Energy Regulatory Commission
FST
Firm Service Tendered
FT
Firm Transportation
GJ/d
gigajoules/day
IGUA
The Industrial Gas Users Association
IT
Interruptible Transportation
NEB
the National Energy Board
OM&A
Operation, Maintenance and Administration
PG&E/El Paso
PG&E Energy Trading, Canada Corporation/El Paso Merchant
Energy Group
S&P
Services and Pricing
Sempra
Sempra Energy Trading Services Corp.
TBO
Transportation by Others
TransCanada
TransCanada PipeLines Limited
TTF
Tolls Task Force
U.S.
United States
WCSB
Western Canadian Sedimentary Basin
(v)
Glossary of Terms
Cost of Service
The total cost of providing service, including operating and
maintenance expenses, depreciation, amortization, taxes and
return on rate base. Generally, the cost of service of a pipeline
is the same as its revenue requirement.
Part III
The section of the National Energy Board Act which deals with
Facilities Construction
Part IV
The section of the National Energy Board Act which deals with
Traffic, Tolls and Tariffs
RH-2-95
Hearing Order in respect of TransCanada’s Application for new
tolls effective 1 January 1996
RH-1-99
Hearing Order in respect of Interruptible Transportation and
Short Term Firm Transportation Tariff Amendments
RH-4-2001
Hearing Order in respect of TransCanada’s Fair Return
Application dated 6 June 2001
Tolls Task Force
A joint industry Task Force initiated by TransCanada. Its
membership is comprised of a wide cross-section of the natural
gas industry, including representatives of the producing,
marketing, brokering and pipeline segments of the industry,
provincial government and local distribution and industrial
end-use customers
(vi)
Chapter 1
Introduction
As a means to improve the effectiveness of the regulatory process, the National Energy Board (the
Board) has supported the use of negotiated settlements since the middle 1980s as an alternative to
litigation. In September 1988, the Board revised its Guideline for Negotiated Settlements of Traffic,
Tolls and Tariff (the Settlement Guidelines) to provide clarity and commitment that the regulatory
community required to continue down the path of negotiated settlements.
In the early 1990s, settlements became more prevalent but two concerns persisted. The first concern was
a perceived reluctance by the Board to accept “package deals”. The second concern was the Board’s
inclination to hold hearings even where settlements existed. These matters were resolved when the
Board updated its Settlement Guidelines on 23 August 1994. These revised Settlement Guidelines
clarified the Board’s role with respect to settlements and established acceptable criteria for the settlement
process.
1.1
Background
In RH-2-95, the Board approved TransCanada PipeLines Limited’s (TransCanada) Incentive Cost
Recovery and Revenue Sharing Settlement (Incentive Settlement). The effect of the Incentive Settlement
was to provide the methodology for determining the Net Revenue Requirement to be utilized by
TransCanada to calculate tolls on its Mainline System for the Test Years 1996 to 1999 inclusive.
Starting around 1998, TransCanada entered into negotiations with its stakeholders on wide-ranging
changes to its tolls and tariff that eventually evolved into the Services and Pricing Negotiations.
In advance of the start of the 2000 Test Year, TransCanada held negotiations with stakeholders in an
attempt to extend the terms of the Incentive Settlement for one year. These negotiations were ultimately
unsuccessful.
On 17 December 1999, TransCanada filed its 2000 Tolls Application. In January 2000, TransCanada
advised the Board that discussions with stakeholders were ongoing and requested that the Board delay
establishing a procedure to process its 2000 Tolls Application. In April 2000, TransCanada filed a
revised 2000 Tolls Application which was supported by a negotiated settlement reached among its Tolls
Task Force (TTF) members. The Board approved the resulting tolls on an interim basis pending the
receipt of comments from interested parties who were not part of the TTF.
Three parties expressed their opposition to TransCanada’s 2000 Tolls Application. Subsequent
negotiations with these parties resulted in one remaining party still opposed. In July 2000, the Board
approved final tolls for 2000 and ruled that the settlement process utilized by TransCanada to reach a
settlement, together with the resulting discussions with non-TTF stakeholders, complied with the spirit of
the Board’s Settlement Guidelines.
RH-1-2001
1
During the remainder of 2000, TransCanada continued its negotiations with stakeholders regarding a
longer-term agreement on toll and tariff matters as well as 2001 tolls. On 7 December 2000,
TransCanada filed an application for interim tolls to take effect 1 January 2001. At that time,
TransCanada indicated that it would file an application for 2001 final tolls once discussions with its
stakeholders were completed.
On 22 February 2001, TransCanada issued a press release which indicated that it had reached a
settlement that resolved all toll and tariff issues, other than cost of capital issues, for the 2001 and 2002
Test Years. However, during March 2001, the Board received indications from certain interested parties
that they were opposed to the settlement.
On 3 May 2001, TransCanada filed its 2001 and 2002 Tolls and Tariff Application (the Tolls
Application) based on the terms of the Mainline Service and Pricing Settlement (the S&P Settlement).
There were thirteen signatories to the S&P Settlement covering a diverse representation of stakeholder
groups on the TransCanada Mainline System.
TransCanada stated that the S&P Settlement was achieved in accordance with the criteria for an
acceptable settlement process as set out in the Board’s Settlement Guidelines. TransCanada also stated
that all parties having an interest in its tolls and tariffs were provided with a fair opportunity to
participate and to have their interests recognized and appropriately weighed. In addition, TransCanada
submitted that the S&P Settlement produced adequate information on the public record for the Board to
understand the basis for the agreement and to assess its reasonableness.
The Board subsequently established a written process inviting comments from interested parties on any
issue related to TransCanada’s Tolls Application as well as comments on the need for, and nature of, a
further process to consider the Tolls Application.
On 8 June 2001, the Board ruled that the S&P Settlement was not in accordance with the Board’s
Settlement Guidelines, primarily because the S&P Settlement was opposed by certain parties that had
participated in the negotiation process. In its ruling, the Board indicated that it intended to treat the
proposed S&P Settlement as a common position of parties and was prepared to examine it on a
component by component basis. TransCanada subsequently advised the Board that both it and the
signatories to the S&P Settlement were prepared to proceed with the Tolls Application as filed.
On 22 June 2001, the Board issued the RH-1-2001 Hearing Order - Directions on Procedure which
established a process initially leading to an oral hearing to commence on 20 August 2001. On
22 July 2001, in response to a Notice of Motion filed by the Cogenerators Alliance (the CA), the Board
extended the Timetable of Events to commence the oral hearing on 17 September 2001 (subsequently
extended to 18 September 2001).
The Board’s revised List of Issues contained eight specific issues. Prior to the start of the oral hearing,
two issues were removed from the RH-1-2001 proceeding.
On 27 August 2001, the Board withdrew Issue g) “appropriate accounting treatment of any impact on rate
base and revenue requirement resulting from TransCanada’s proposed deactivation of certain
compression facilities” on the basis that it would be impractical to isolate and adequately address the
2
RH-1-2001
Part IV issues in a separate proceeding from one which would address the Part III and Onshore Pipeline
Regulation issues.
On 7 September 2001, the Board granted leave for Sempra Energy Trading Services Corp. (Sempra) to
withdraw its pre-filed evidence concerning Issue h) “the rights of Long-Term Winter Firm Service
(LT-WFS) shippers to the Turnback Procedure and to FT Make-Up and Authorized Overrun Service
(AOS) credits” and accordingly withdrew Issue h) from the RH-1-2001 proceeding.1
One procedural matter that arose prior to the oral hearing concerned the disclosure of shipper-specific
information (in response to an information request) regarding Interruptible Transportation (IT) Service.
TransCanada objected to disclosing this information on the grounds that it was confidential and
commercially sensitive. On 7 September 2001, the Board advised that it would consider submissions
from interested parties on this matter at the commencement of the hearing. On 18 September 2001, the
Board heard oral submissions on this matter from interested parties and subsequently issued the
following ruling:
“With respect to this matter, it was acknowledged by all parties, and the Board agrees,
that the information sought is commercially sensitive and that it cannot be formatted in a
way that will avoid confidentiality concerns. Further, the information sought, in the
Board’s view, is not critical to the Board’s decision-making nor have we [the Board]
been persuaded that it is critical to parties developing their cases.”
The RH-1-2001 oral hearing commenced on 18 September 2001 and was completed on 2 October 2001.
1.2
Overview of TransCanada’s Tolls Application
TransCanada’s Tolls Application was based on the terms of the S&P Settlement and covered the period
from 1 January 2001 to 31 December 2002. The S&P Settlement prescribed the toll methodology that
would be utilized, tariff provisions that would be applicable and the components that would comprise
TransCanada’s Revenue Requirement, with the exception of amounts relating to cost of capital, for the
2001 and 2002 Test Years. On 6 June 2001, TransCanada filed a separate application (i.e. the 2001 and
2002 Fair Return Application) seeking determination of its cost of capital for 2001 and 2002.
The S&P Settlement essentially follows a cost of service tolling methodology, with the exception of the
revenue associated with the Revenue/Asset Management Program and other incentive mechanisms. The
term of the S&P Settlement applies to TransCanada’s Test Years 2001 and 2002 respectively.
A summary of the major elements of the S&P Settlement is provided below.
•
1
Net Revenue Requirement (Article 4) - sets out how the 2001 and 2002 Net Revenue
Requirement would be derived (see Table 1-1).
Sempra was the only RH-1-2001 Party which was affected by this issue. During the course of the proceeding, Sempra
reached agreement with TransCanada to convert its LT-WFS contract to a Firm Transportation contract.
RH-1-2001
3
•
Incentive Mechanisms
•
Severance Program (Article 5) - would provide TransCanada with an incentive to
reduce employee-related costs and share with its shippers in the benefits achieved.
•
Revenue/Asset Management Program (Article 9) - would provide TransCanada with
an incentive to reduce costs associated with Transportation by Others (TBO) Assets and
Firm Service Tendered (FST) Replacement Assets and to generate incremental
transportation and other revenue. TransCanada’s commissions would be capped at
$5 million annually.
•
Incentive Programs (Articles 10.1 to 10.3) - three programs (i.e. Fuel Gas Incentive
Program, Foreign Exchange Management Program and Interest Rate Management
Program) under which Gains and losses would be shared by TransCanada and its
shippers.
•
Composite Depreciation Rates (Article 7) - rates would increase in 2001 by adding 0.10%
to the composite 2000 rate of 2.64% to equal 2.74% with a further addition of 0.15% in 2002
to 2.89% .
•
Transportation Services (Article 11) - revised methodology for determining the IT floor
price; introduction of FT service enhancements; and expedited process for approval of new
services.
•
Turnback Procedure (Article 12) - this process would require TransCanada to determine if
requests for incremental Firm Transportation (FT) Service could be met by turnback of
capacity by other shippers, prior to TransCanada considering new facilities or TBO.
•
Future Business and Regulatory Model (Article 13) - TransCanada undertook to develop a
future business and regulatory model for review and discussion with stakeholders.
TransCanada’s Tolls Application and supporting schedules were prepared to reflect the terms and
conditions contained in the S&P Settlement.2 Specific aspects of the S&P Settlement which were at issue
in the RH-1-2001 proceeding are discussed in Chapter 2. Chapter 2 concludes with Summary Views on
the S&P Settlement.
2
4
For the complete text of the S&P settlement, readers are referred to Appendix I of TransCanada’s Tolls Application
dated 3 May 2001 and to TransCanada’s Additional Written Evidence dated 13 July 2001.
RH-1-2001
Table 1-1
TransCanada’s 2001 Revenue Requirement
($ 000)
Transmission by Others
$381,073
FST Replacement Costs
35,235
Operations, Maintenance & Administrative (OM&A)
Pipeline Integrity and Insurance Deductible Costs
National Energy Board (NEB) Cost Recovery
222,878
31,331
9,565
Return *
836,963
Income Taxes
121,955
Depreciation
341,257
Foreign Exchange on Debt and Other Financing Costs
Gas Related and Electric Costs
0
80,083
Municipal and Other Taxes
118,967
Regulatory Amortizations
(77,587)
Pressure Charges
Gross Revenue Requirement
5,680
2,107,400
Miscellaneous Revenue
Non-Discretionary Miscellaneous Revenue
(70,106)
Discretionary Miscellaneous Revenue
(40,000)
Total Miscellaneous Revenue
Net Revenue Requirement
*
(110,106)
$1,997,294
TransCanada indicated that this amount was included for illustrative purposes only and is based on a rate of
return for 2001 of 9.61% (as per the Board’s RH-2-94 adjustment mechanism) and a deemed common equity
ratio of 30%. TransCanada filed a separate application (i.e. the 2001 and 2002 Fair Return Application RH-4-2001 Proceeding) seeking changes to the determination of its return for 2001 and 2002.
RH-1-2001
5
Chapter 2
Specific Tolls and Tariff Issues
2.1
Sharing of Risk Associated with Contract Non-Renewals
During 1999 and 2000, firm contract volumes on the TransCanada Mainline System decreased by
1.5 million gigajoules per day (GJ/d) or 18.8% of total throughput. These volumes include FT, FST and
Storage Transportation Service. TransCanada received notice that, effective 1 November 2001, a further
133,069 GJ/d of firm contracts would not be renewed. During the proceeding, TransCanada indicated
that a further 910,926 GJ/d of firm contracts will come up for renewal in 2002.
In its Tolls Application, TransCanada proposed utilizing its previously approved cost of service model to
allocate its Revenue Requirement and establish its tolls. TransCanada indicated that, under the cost of
service model, its revenue requirement is driven by the cost of facilities that have been constructed and
included in its rate base in accordance with approvals received from the Board and that these costs are
borne by firm shippers.
2.1.1
Proposal and Views of the CA
The CA suggested it was unfair for the entire impact of contract non-renewals to be borne by shippers.
The CA proposed a revenue shortfall sharing mechanism whereby each stakeholder group would bear a
portion of the revenue shortfall arising from non-renewals taking place after 1 January 2001.
TransCanada would shoulder the portion of revenue shortfall related to return and associated income
taxes (approximately 48%), remaining customers would bear the portion of revenue shortfall that
represents unavoidable costs (approximately 35%), while departing customers would contribute that
portion of revenue shortfall associated with the return of capital (approximately 17%). Implementation
would be through a system of “stranded costs surcharges” and “exit fees”. Departing customers who are
doing so as a result of diminished requirements would not be subject to an exit fee and their portion of
revenue shortfall would be absorbed by TransCanada. The CA suggested that its sharing mechanism
should be phased out as the transition to competition is completed. The CA further suggested a transition
period of five to six years, at the end of which TransCanada would be responsible for 100% of any
shortfall.
The CA also proposed that TransCanada introduce term-differentiated tolls based on a shipper’s
remaining contract term. The total pipeline costs would be separated into two pools. One pool, called
the "riskless portion", would be allocated following TransCanada's existing methodology to form a "base
rate". The other pool or "risk portion" would be allocated to each zone (or export point) based on the
weighted average remaining contract life of the zone. That amount would then be used to develop a rate
per "GJ-Year at risk" for each zone. The number of years at risk would be set as the investment life of
the pipeline (set by the CA at 19 years) less the number of years until contract expiry. Customers could
extend their contracts in order to obtain the lower rate associated with the extended term.
The CA submitted that TransCanada failed to provide sufficient evidence to determine whether the tolls
based on the S&P Settlement would be just, reasonable and non-discriminatory and considered the level
6
RH-1-2001
of support for the S&P Settlement to be insignificant. The CA suggested that it was telling that parties
who opposed the settlement were long-term captive customers. The CA also expressed the view that a
toll-setting methodology that places the entire burden of contract non-renewal risk on captive customers
cannot be just and reasonable.
The CA submitted that TransCanada’s proposal was contrary to the principles of cost causation and
allocative efficiency. The CA indicated that following the cost-causation principle, costs should be borne
by those who have caused them and suggested that under the S&P Settlement, all costs associated with
the abandonment of FT service were shifted to customers who did not cause them and had no opportunity
to avoid them. The CA also advanced that TransCanada could be causing some of the costs of contract
non-renewal by failing to secure renewals or re-market capacity. With respect to allocative efficiency,
the CA suggested that, by collecting any lost revenues from remaining customers, TransCanada would
not be exposed to the discipline of the marketplace, which could lead to a misallocation of resources in
the long run. The CA also submitted that, to absolve TransCanada from all cost responsibility associated
with contract non-renewals could result in double recovery of costs, since TransCanada is currently
allowed to earn a return that contains a risk premium and is in excess of the risk-free bond rate.
The CA submitted that a fundamental change in circumstances, such as the move to a more competitive
market for gas transportation, required a revamping of the toll setting methodology. It expressed the
view that certification of facilities by the Board did not confer a guarantee of revenue recovery, even
under the existing cost of service model of regulation.
The CA submitted that to continue to allocate the full burden of contract non-renewals onto firm shippers
would not be in line with the approach taken by regulators in the United States (U.S.). The CA submitted
that U.S. regulators have recognized the need to mitigate the cost impacts of non-renewal upon shippers
as well as the need to create an incentive for pipelines to become efficient and competitive.
The CA indicated that its revenue shortfall sharing mechanism would result in TransCanada and
departing customers sharing in the risk and costs of contract non-renewal, along with remaining shippers.
It argued that this would be a fair outcome since TransCanada was in the best position to influence the
level of non-renewals and departing customers were the direct cause of contract non-renewal costs.
The CA submitted that discussions on a competitive business and regulatory model should not be put off
until 2003. The CA proposed that the Board set a deadline of 30 to 60 days from the issuance of its
decision for TransCanada to submit for Board approval those competitive tools required to provide it
with a real opportunity to influence the level of non-renewals through flexibility and incentives in a
competitive environment.
The CA suggested that customers with shorter contract terms represent a bigger business risk than long
term shippers and submitted that a rate design that allocates the cost of risk without regard to the expiry
of a customer’s contract violated the cost causation principle. The CA indicated that this was the
impetus behind its proposal for term-differentiated tolls, a proposal that the CA believed would provide
an incentive for customers to extend their contracts.
RH-1-2001
7
2.1.2
Proposal and Views of PG&E/El Paso
PG&E Energy Trading, Canada Corporation and El Paso Merchant Energy Group (PG&E/El Paso)
jointly proposed an alternative cost-sharing proposal which entails a sharing of costs during 2001 and
2002 of the revenue-requirement impact of contract non-renewals in 2000, 2001 and 2002. Specifically,
TransCanada’s billing determinants for each test year would be reduced by 50% of the cumulative
decontracted units.
The PG&E/El Paso cost-sharing proposal would be coupled with a sharing of incremental transportation
revenues between TransCanada and shippers. TransCanada would be entitled to 50% of incremental
revenues, net of AOS and FT Make-Up Credits. In addition, there would be no limit on the amount of
incremental revenues TransCanada could earn.
PG&E/El Paso indicated that it took into account a number of factors in determining the 50% sharing
ratio for non-renewal costs. Factors considered included the experience of U.S. pipelines in bearing
decontracting risk, the fact that TransCanada’s shippers have borne all of the risk to date, the proposed
retention of the other terms of TransCanada’s Tolls Application, the view that TransCanada bears some
responsibility for FT contract non-renewals on its system, and the lack of pricing flexibility typically
provided pipelines in the U.S.
PG&E/El Paso submitted that past and potential future toll increases resulting from contract
non-renewals on TransCanada have had a significant adverse impact on their operations. PG&E/El Paso
expressed concerns with respect to TransCanada’s proposed full-rate recovery approach in a competitive
environment and suggested that the cost of service model of regulation did not preclude holding
TransCanada accountable for the cost of non-renewals. PG&E/El Paso submitted that TransCanada had
undertaken no initiatives to maintain throughput or to be competitive and pointed out that parties opposed
to the Tolls Application shared the trait of being contractually or physically captive to the TransCanada
system.
PG&E/El Paso provided several examples showing how the Federal Energy Regulatory Commission
(FERC) had addressed situations of major decontracting on U.S. pipelines. PG&E/El Paso submitted that
the U.S. experience indicated that the FERC had not granted approval of unilateral pipeline proposals
attempting to shift the impact of decontracting onto remaining shippers and that the FERC expected
pipelines to share in the risk of contract non-renewals and to pursue new markets. PG&E/El Paso
indicated that the majority of the financial impact had been borne by the pipelines over a specified
transition period, after which the pipelines were fully at risk. In each case, the FERC approved sharing
mechanisms in the context of a joint settlement agreement between a pipeline and its shippers.
PG&E/El Paso argued that U.S. pipelines were not always provided the tools required to address
non-renewal of capacity in advance of the imposition of increased risk. PG&E/El Paso also pointed to
cases where the FERC approved the use of exit fees to offset the costs of turned back capacity.
PG&E/El Paso submitted that U.S. pipelines could negotiate exit fees with customers wishing to leave
their system or to turn back some capacity before the end of a contract. However, the FERC has not
allowed pipelines to unilaterally impose an exit fee on customers whose contract term has expired.
While they made no value judgment regarding the prudency of TransCanada’s past decisions,
PG&E/El Paso expressed the view that TransCanada showed little inclination in its past planning and
8
RH-1-2001
conduct to minimize costs and render its system more competitive. PG&E/El Paso indicated that
TransCanada had been aware of the increasing competition and of the risk of underutilisation when it
expanded its system in 1998 and 1999 and should therefore be held at risk for that expansion.
PG&E/El Paso considered that adoption of their proposal would provide TransCanada with an incentive
to minimize costs and increase system utilization. They believed that the decontracting issue could not
be resolved in negotiations and suggested that the adoption of their proposal, which they viewed as a
transition, would act as a catalyst by ensuring that TransCanada has something at stake in negotiations on
a future business and regulatory model. PG&E/El Paso considered that it was appropriate to allocate
some of the impact of non-renewals to TransCanada in 2001 and 2002 and pointed to the potential for
significant non-renewals in that period. Finally, PG&E/El Paso indicated that the primary element of
their proposal was the sharing of risk and not the specific level or mechanics.
2.1.3
Views of TransCanada
TransCanada indicated that excess capacity on the Mainline is primarily the result of the construction of
additional pipeline capacity, including Alliance Pipeline Ltd. (Alliance) and Vector Pipeline Ltd.,
coupled with a delayed supply response in the Western Canada Sedimentary Basin (WCSB) to the
increased pipeline capacity. TransCanada also indicated that it had not been previously exposed to any
risk of underutilisation stemming from offloading to new greenfield pipelines.
TransCanada considered that it had been prudent and proactive in minimizing facilities and in reducing
the risk of underutilization. TransCanada submitted that it had been diligent in sizing its expansions,
maximizing system utilization, reducing controllable costs, introducing new services, instituting
innovative pricing, and attempting additional changes. TransCanada pointed out that no intervenors had
suggested that it had been imprudent.
TransCanada submitted that re-allocation of non-renewal risk could be just and reasonable if the pipeline
was provided with a real opportunity to influence the level of non-renewals through flexibility and
incentives to deal with such risks. TransCanada considered that risk allocation was not a
one-dimensional issue that could be determined in isolation, as it could impact various aspects of pipeline
operations, revenue requirement, and tolls and tariff.
TransCanada has undertaken to develop a future business and regulatory model for review and discussion
with stakeholders. The stated objectives of the future business model are to allow TransCanada to
effectively compete for market demand and gas supplies. TransCanada rejected the view expressed by
certain parties that further negotiations were futile and suggested that there was an increased likelihood
of success. TransCanada also indicated that if resolution through discussions with stakeholders could not
be achieved, it would seek the Board’s resolution in 2002.
TransCanada argued that parties supporting alternatives to its proposal were seeking to have
TransCanada share, after the fact, in the impacts of the realization of a risk that it did not bear and for
which it was not compensated. TransCanada contended that it had no reasonable opportunity to
influence the magnitude of the non-renewals. TransCanada also considered that the proposals of the CA
and PG&E/El Paso failed to contain the elements that would normally be expected in any new business
and regulatory framework. TransCanada argued that the proposals did not provide for an advance period
within which it could operate and influence shipper contracting decisions. In addition, TransCanada
RH-1-2001
9
submitted there was no symmetry between the lost revenues from non-renewals and the tools with which
to compete for potential incremental volumes or between the risk and reward involved.
TransCanada submitted that the financial impact of either alternative proposal would decrease its
earnings and cash flow without providing a meaningful opportunity to recover these losses, which might
impair its ability to service its debt and could hinder future growth.
TransCanada considered that the CA’s proposal was inconsistent with the cost causation principle.
TransCanada indicated that cost causation is a toll design principle that dictates that parties who cause
costs should be the parties who pay for those costs. TransCanada pointed to the fact that its system was
an integrated operation which has been tolled using a rolled-in methodology as an indication that the
costs of the integrated system have been incurred to provide service to the aggregate of all shippers
requiring service. TransCanada rejected the CA’s assertions that its proposal would result in double
recovery of costs and submitted that TransCanada had not in the past sought compensation in its
regulated return for risk of underutilisation.
TransCanada disagreed with the suggestion of PG&E/El Paso that it had the choice not to proceed with
the 1999 expansion of its system. TransCanada submitted that, based on the facts known at the time,
cancellation of the program could have resulted in breaches of contractual obligations. TransCanada
pointed out that the magnitude of non-renewed capacity first became apparent in April 1999, at which
point the expansion was already underway. TransCanada also pointed out that it had mitigated the
impact of the 1999 expansion by scaling back the construction program.
TransCanada submitted that direct analogies should not be drawn between U.S. and Canadian regulatory
frameworks, in light of major differences. Nonetheless, TransCanada suggested that the alternative
proposals advanced by the CA and PG&E/El Paso were inconsistent with U.S. regulatory precedents.
TransCanada submitted that the U.S. regulatory experience indicated that the financial impact of
non-renewals has not been imposed upon a pipeline unless it had been given the appropriate tools in
advance and that, absent a negotiated settlement, there was no precedent for the regulatory imposition of
a risk sharing proposal.
TransCanada submitted that the U.S. regulatory precedents indicate that the FERC expects a level of
symmetry with respect to risks and rewards and that such symmetry should be established in advance.
TransCanada pointed to pricing discretion and to the right of first refusal as tools that U.S. pipelines have
at their disposal to affect the level of contract non-renewals. TransCanada also noted that U.S. pipelines
were provided the opportunity to fully recover their prudently incurred costs and that FERC policy
allows pipelines to recover discounts in future rates.
With respect to exit fees, TransCanada noted that, historically, it has been FERC's policy to only approve
exit fees if they were the result of negotiations with shippers prior to their decision to depart a pipeline
system. TransCanada further noted that the FERC does not favour unilateral exit fees, on the grounds
that such requests lie outside the contracts between two parties, thus violating the principle of the
filed rate doctrine.
TransCanada noted that no party disputed the fact that the FERC has not approved unilateral proposals to
share the risks of contract non-renewal. TransCanada further noted that it is not asking the Board to
approve a unilateral proposal, but rather a proposal that is widely supported by its stakeholders.
10
RH-1-2001
2.1.4
Views of Parties Supporting TransCanada’s Position
The Canadian Association of Petroleum Producers (CAPP) urged the Board to approve
TransCanada’s Tolls Application as filed and reject the alternative proposals advanced by the CA and
PG&E/El Paso. CAPP indicated that the Tolls Application is based on a continuation of the existing cost
of service model, which has yielded tolls that have continually been found to be just and reasonable by
the Board. CAPP submitted that the Board should be reluctant to disturb individual components of the
S&P Settlement absent cogent evidence that the settlement, taken as a whole, would lead to results that
are inconsistent with the National Energy Board Act (the Act). CAPP expressed the view that none of
the parties opposed to the Tolls Application had presented such evidence.
CAPP viewed the non-renewal issue as one related to excess capacity, and considered a period of
pipeline underutilisation to be normal following major expansions (as it takes time for supply to grow
and catch up with added capacity). CAPP acknowledged that a consequence of the recent excess
capacity had been toll increases on TransCanada and suggested that it was opposition to these toll
increases that had precipitated the alternative proposals.
CAPP expressed concerns that, while the alternative proposals would have TransCanada take additional
risk, no parties addressed what TransCanada could expect by way of additional reward. CAPP drew a
distinction between risk and risk realization, and argued that, if a pipeline was put at risk, it should
expect to be rewarded for taking that risk whether or not it is realized. CAPP submitted that there was a
need to take a broader and longer-term view of the risk sharing issue and suggested that approval of the
alternative proposals would compromise future negotiations on a new business and regulatory model for
TransCanada.
CAPP considered that the Board should not give weight to the assertion that non-captive shippers
supported the Tolls Application while captive shippers opposed it. CAPP indicated that many gas
producers in Western Canada were captive to the TransCanada Mainline because there was in practice no
physical alternative available.
CAPP suggested that the cited FERC precedents were not entirely relevant to TransCanada. CAPP noted
that, apart from the fact that TransCanada was facing decontracting, there was no discussion of the
differences in comparative risks facing U.S. and Canadian pipelines. In addition, CAPP suggested that
there were significant differences in pricing policies and in models of regulation between U.S. and
Canadian-regulated pipelines.
CAPP expressed the view that the CA proposal for term-differentiated tolls was flawed since it was built
on the premise that business risk was determined solely by the number of years remaining in a shipper’s
contract.
The Industrial Gas Users Association (IGUA) urged the Board to approve TransCanada’s Tolls
Application and adopted the submissions of TransCanada and CAPP with respect to the deficiencies of
the alternative proposals.
The Eastern LDCs (Enbridge Consumers Gas, Société en commandite Gaz Métropolitain and Union
Gas Limited) made joint arguments in support of TransCanada’s Tolls Application. The Eastern LDCs
RH-1-2001
11
indicated that they valued the relative certainty of a negotiated solution and a non-litigious atmosphere
for future negotiations towards a comprehensive solution on a new business and regulatory model.
The Eastern LDCs submitted that they were acutely interested in the health of the TransCanada System
and pointed out that, for parts of their systems, they were physically captive to the TransCanada
Mainline. The Eastern LDCs suggested that the Board could, in theory, reject the Tolls Application and
the alternative proposals and send parties back to the negotiating table. While not in support of this
option, the Eastern LDCs considered it a better outcome than the adoption of either of the alternative
proposals.
The Alberta Department of Energy (ADOE) adopted the submissions made by CAPP with respect to
contract non-renewals and submitted that the proposals of the CA and PG&E/El Paso should be rejected.
The ADOE expressed the view that higher risk goes together with higher cost of capital. The ADOE
questioned the desirability of moving towards a U.S. model of regulation and pointed out that the FERC
had never unilaterally imposed a proposal for the sharing of risk of contract non-renewal. The ADOE
expressed concerns with respect to the CA proposal for term-differentiated tolls and exit fees.
BP Canada Energy Company (BP Canada) submitted that the Board should approve the proposal
contained in TransCanada’s Tolls Application and reject the alternative proposals on the grounds that
they are incomplete and less than fully developed. BP Canada considered that the merits of the
alternative proposals had not been demonstrated and that such changes should not be considered in
isolation.
TransGas Limited (TransGas) submitted that the historic sharing embodied in TransCanada’s Tolls
Application provided an appropriate sharing of risk associated with contract non-renewals and argued
that no party provided compelling evidence that the traditional risk-compensation balance was
inappropriate.
TransCanada Energy Ltd. supported the approval of TransCanada’s Tolls Application and expressed
the view that no Parties had advanced a viable alternative.
2.1.5
Views of Other Parties Opposing TransCanada’s Position
Centra Gas Manitoba Inc. (Centra) viewed the issues of contract non-renewals and related financial
consequences as the most significant issues facing TransCanada, its stakeholders and the Board. Centra
concluded that TransCanada had not done enough soon enough to address its competitive position and
accordingly considered that a portion of the financial consequences of non-renewal of FT contracts
should be borne by TransCanada.
Centra pointed to the Agreement on Natural Gas Pipeline Regulation, Competition and Change to
Promote a Competitive Environment and Greater Customer Choice (the Accord) that was signed by
TransCanada and other stakeholders on 7 April 1998. Centra considered that TransCanada, in signing
the Accord, recognized that it was assuming additional risk associated with competition. Centra
submitted that the Board should make a direct connection between TransCanada’s actions associated
with the Accord, the subsequent withdrawal of its opposition to Alliance and the current situation of
underutilised capacity.
12
RH-1-2001
Initially, Centra expressed the view that the financial impacts of FT contract non-renewals for 1999, 2000
and 2001 should be shared between TransCanada and its shippers for 2001, but did not advance a
specific sharing mechanism. In Final Argument, Centra indicated that it would be content to adopt the
proposal of PG&E/El Paso. Centra also expressed the view that there was adequate evidence on the
record for the Board to make a determination of the appropriate share that should be assigned to
TransCanada.
Coral Energy Canada Inc. (Coral) contended that the most important issue facing TransCanada, its
customers and the Board was the need for change in TransCanada’s business model and approach to
regulation. Coral expressed the view that TransCanada, by withdrawing its opposition to Alliance,
adopted from that moment forward, the responsibility for risk. Coral submitted that there was a low
probability of success for another round of negotiations
Coral indicated its support for the alternative proposal of PG&E/El Paso. Coral, however, recommended
a change to the revenue sharing portion of the PG&E/El Paso proposal by proposing that the sharing be
applied to IT revenues net of fuel cost.
CoEnergy Inc. (CoEnergy) indicated that it considered itself contractually captive to the TransCanada
Mainline System and expressed concerns over increasing tolls resulting from decontracting. CoEnergy
supported the alternative proposal of PG&E/El Paso.
The U.S. Northeast Group expressed concerns over increasing tolls on the TransCanada Mainline and
submitted that TransCanada’s Tolls Application provided no real answer to the decontracting problem.
The U.S. Northeast Group indicated its support for the position advanced by PG&E/El Paso.
The Consumers’ Association of Canada, the Public Interest Advocacy Centre, Brooklyn Navy
Yard Cogeneration Partners L.P., and Manitoba Conservation (Province of Manitoba) expressed
concerns in letters of comments over the impact of contract non-renewals on end-use customers.
Views of the Board
The Board acknowledges that non-renewal of firm contracts is a significant issue facing
TransCanada and its stakeholders. Further, the Board recognizes the impact nonrenewals have had on tolls and the importance of toll stability. At the same time, the
Board considers that contract non-renewals and the sharing of the related impacts affects
a broad range of issues, pointing to the need for a thorough and comprehensive
consideration of all factors involved in assessing potential solutions.
The Board sees a clear distinction between risk sharing and the sharing of the realization
of such risk. Absent clear evidence that TransCanada has been imprudent or that its
actions have caused contract non-renewals, the Board is not inclined to impose, after the
fact, the financial impact of the realization of a risk that TransCanada has not
traditionally borne. The Board notes that no party suggested that TransCanada has been
imprudent. Further, the Board is of the view that no party provided compelling evidence
supporting the view that TransCanada’s actions have caused contract non-renewals or
have contributed to their severity. On the contrary, most parties acknowledged that the
majority of contract non-renewals resulted from shippers opting to ship gas on competing
pipelines.
RH-1-2001
13
Some sharing of risk between TransCanada and its shippers may be appropriate if
considered on a prospective basis. Such consideration should also take into account the
appropriate balance between risk and reward and the tools required to manage such risk.
The Board considers that the alternative proposals advanced by the CA and
PG&E/El Paso failed in this regard. While both proposals would have TransCanada
share in the impact of the realization of the risk of contract non-renewals, neither
proponent adequately assessed the impact its proposal could have on related factors, such
as TransCanada’s ability to manage risk, long-term viability or cost of capital.
While there may be merit in assessing the concept of term-differentiated tolls as an
incentive for shippers to commit to longer-term contracts, the Board considers that the
proposal of the CA is ill-defined and may be unworkable. In addition, the CA’s proposal
for an exit fee would be contrary to the terms and conditions of shippers’ existing
contracts.
The Board notes that PG&E/El Paso supported its alternative proposal by pointing to the
examples of U.S. pipelines in dealing with situations of major contract non-renewals.
The Board believes that, in general, it is helpful to examine the approaches used by other
regulatory bodies. However, when attempting to apply the practices of one regulator to
the policies and decisions of another, it is important to examine and understand the
mandate within which the regulator operates and the context in which its decisions were
taken. In this case, given the subject matter of these proceedings, that examination
should include a careful assessment of the different business and regulatory models in
existence at the time of the relevant decisions.
The Board notes that the U.S. examples discussed in this proceeding indicate that the
FERC has only approved risk-sharing proposals within the context of an agreement
between a pipeline and its shippers. In addition, U.S. regulatory precedents support the
view that there needs to be a symmetry between the risk a pipeline bears and the tools
available to manage such risk.
For the reasons set out above and based on a review of all the evidence in this
proceeding, the Board is not persuaded that the risk-sharing proposals presented for
consideration by the CA and PG&E/El Paso would result in just and reasonable tolls on
the TransCanada Mainline System. That is not to say that the concepts contained in the
proposals could not form some part of a future comprehensive package of reforms.
Having rejected the risk-sharing proposals, the Board is left with consideration of the
proposal of TransCanada which would continue to allocate TransCanada’s costs to firm
shippers in 2001 and 2002, based on the traditional cost of service methodology. Based
on the evidence put forward in this proceeding, the Board is satisfied that continuing to
allocate the full cost of the pipeline to shippers, using the traditional cost of service
methodology, is appropriate for 2001 and 2002.
For the longer term, the Board shares the view expressed by many parties that a review
of TransCanada's business and regulatory framework is necessary. The Board is
encouraged by the commitment of most parties to negotiate, over the next few months, a
future business and regulatory model for TransCanada. Accordingly, the Board has high
expectations for these negotiations and trusts that all stakeholders will participate in
14
RH-1-2001
good faith with a goal to achieving an acceptable negotiated solution. Absent a
negotiated solution, the Board will be prepared to deal with outstanding issues.
The Board recognizes that the landscape in which TransCanada operates has changed
and that there may be a need for the framework in which it operates to evolve. Concepts
which may have been appropriate in the context of a virtual monopoly environment may
not necessarily be appropriate in a more competitive environment. Similarly, concepts
which were brought forward in the past and which were found inappropriate, may be
appropriate in the future.
The Board is concerned with the prospect of continued protracted negotiations that could
lead to a delay in the timely filing of an application from TransCanada for 2003 tolls and
tariff. The Board is reassured by the commitment of TransCanada to seek the Board’s
resolution in 2002, should a negotiated resolution not be achieved.
Nevertheless, the Board notes that, should such an application be filed late in 2002, it
could result in an extended period of uncertainty regarding TransCanada's tolls and tariff
for 2003. Accordingly, the Board directs TransCanada to file a comprehensive tolls and
tariff application for the 2003 Test Year (whether supported by a negotiated settlement
or not) by 1 September 2002.
2.2
Proposed New Service Enhancements
TransCanada proposed two new service enhancements to its FT Service, namely FT Make-Up Credits
and AOS Credits.
Under the FT Make-UP Credit proposal, the aggregate FT Demand Charge associated with each FT
shipper’s aggregate unutilized FT capacity rights in each month would be credited towards that FT
shipper’s aggregate IT Service invoice at the end of each month. Unutilized FT Make-Up Credits would
not rollover to subsequent months.
Under the AOS Credit proposal, an amount equivalent to 4.0% of each FT shipper’s aggregate monthly
FT Demand Charge would be credited towards that shipper’s aggregate IT Service invoice at the end of
each month. Unutilized AOS Credits would not rollover to subsequent months.
If the sum of a shipper’s FT Make-Up and AOS credits in any month exceeds a shipper’s aggregate IT
Service invoice in a particular month, then a shipper’s aggregate IT Service invoice for that month would
be deemed to be zero.
For both proposals, the credits would commence on the first day of the month immediately following
thirty days after the Board’s approval of these new service enhancements and would terminate on
31 December 2002.
TransCanada acknowledged that the implementation of the credits is expected to lead to a reduction in
net revenues from IT Service and thus higher FT tolls. Since IT revenues are considered as Discretionary
Miscellaneous Revenues (under the terms of the S&P Settlement), any resulting shortfall in these
revenues would be recovered through the use of deferral accounts in a subsequent year’s revenue
requirement.
RH-1-2001
15
2.2.1
Views of TransCanada
TransCanada argued that the proposed service enhancements would give additional value to FT contracts
by providing customers with increased flexibility of operation and reducing the incentive to migrate to
discretionary services such as IT Service. TransCanada stated that the proposed IT Service credit
mechanism offers several advantages over other possible methodologies for FT Make-up service and
AOS. For example, FT shippers would be able to choose when and how to use their credits to purchase
IT Service within a month. These credits could be used to purchase IT Service on any path. Also, the
simplicity of the credit mechanism would allow TransCanada to implement the service enhancements
sooner and at lower cost than other methodologies. Furthermore, to be entitled to the credits, a shipper
would need only to nominate for IT Service.
TransCanada stated that it already offers FT shippers a number of service features (e.g. assignment rights
and diversions) in order to provide shippers with additional flexibility and the ability to extract the
maximum value from their FT contracts. TransCanada submitted that, although the level of use of the FT
Make-Up and AOS credits would likely differ among FT shippers, these features would be available to
all FT shippers.
2.2.2
Views of Parties Opposing TransCanada’s Proposal
Centra stated that the proposed FT Make-Up and AOS Credits would provide it with little or no benefit
and would raise the overall level of tolls. Centra argued that the FT Make-up and AOS Credits are not
new services but instead provide the means to obtain cheaper IT Service. Centra added that the nature of
the credit mechanism for IT Service could exacerbate the migration from FT Service to IT Service.
Centra offered its vision of new FT Make-Up and AOS services. Centra suggested an FT Make-Up
service that would be a nominated service, subject to available capacity, in priority to IT Service and
AOS, available over any path with appropriate diversion charges, at incremental marginal cost.
Similarly, Centra suggested that an AOS service be a nominated service, attached to FT, in priority to IT
Service. AOS would be available over any path at incremental marginal cost subject to available
capacity. Centra acknowledged TransCanada’s estimate that implementation of its version of FT
Make-Up and AOS would take approximately one year and cost in excess of one million dollars.
The CA submitted that TransCanada’s proposed service enhancements would be discriminatory. The
CA argued that the benefits of the enhancements would be mainly for FT shippers who now use IT
Service, as their IT Service invoice would be reduced. The CA added that the existence of FT Make-Up
and AOS Credits might increase FT contract non-renewals.
PG&E/El Paso submitted that, if its proposal for allocating the impacts of FT contract non-renewals was
not accepted, it would be opposed to the proposed new service enhancements. PG&E/El Paso
commented that the proposed AOS and FT Make-Up Credits would not be “just and reasonable” as
captive shippers would have to pay the costs of the mechanism but would not receive the benefits.
PG&E/El Paso suggested that the proposed new services would encourage some FT shippers to reduce
their FT service obligations by substituting IT Service and AOS or FT Make-Up Credits at the expense of
long-term shippers.
16
RH-1-2001
Views of the Board
TransCanada currently operates its pipeline transmission business in a North American
environment that has evolved to include greater competition. The continuing viability of
Canadian pipelines during this evolutionary time is a matter of great interest to the
Board. In this context, it is important, if older pipeline systems are to remain viable, that
they have the opportunity and take action to retain their firm shippers and optimize
utilization of their pipeline systems.
In this instance, the Board agrees with TransCanada that the proposed new services
should give additional value to FT contracts and provide customers with increased
flexibility of operation. In addition, the Board notes the benefits stemming from the
cost-effective nature and timely implementation anticipated for these proposed service
enhancements.
While the Board recognizes that certain FT shippers may be in a better position than
others to make maximum use of the FT Make-Up and AOS Credits, the Board is satisfied
that all FT shippers will have an opportunity to access these credits, either directly or
through creative management of their gas portfolios. Furthermore, the varying ability of
shippers to utilize a service offered in a pipeline’s tariff is not unique to these new
services. For example, while diversions are available to all FT shippers (as a means to
facilitate the full benefit of their FT capacity), many shippers neither require nor use this
feature. With a complex, modern pipeline system and tariff, it would be unreasonable
and impractical to require a pipeline to offer only those services that could be utilized by
all shippers to the same extent. Accordingly, the Board is of the view that the proposed
service enhancements are not unduly discriminatory.
The Board notes the trial nature of these credit mechanisms and expects that
TransCanada, together with its shippers, will assess the merits of continuing or amending
these new service enhancements in the longer term.
2.3
Incentive Mechanisms
The following components of TransCanada’s S&P Settlement were presented as incentive mechanisms.
•
•
•
•
•
•
Severance Program (Article 5)
Inventory Management Program (Article 8)
Revenue/Asset Management Program (Article 9)
Fuel Gas Incentive Program (Article 10.1)
Foreign Exchange Management Program (Article 10.2)
Interest Rate Management Program (Article 10.3)
The Severance Program is designed to benefit both TransCanada and its shippers through a reduction in
TransCanada’s employee costs. Severance Costs for employees with termination dates during the term of
the S&P Settlement would be deferred and amortized over a three year period to allow for a matching of
severance costs and the related future cost savings. The related sustainable Severance Cost Savings
would be calculated annually as the amount of salaries, benefits and overhead costs that would be no
longer incurred. Severance Benefits would be calculated by subtracting the Severance Cost Savings from
the amortized Severance Costs in each test year. These benefits, whether positive or negative, would be
RH-1-2001
17
shared 70% for TransCanada and 30% for Shippers. The amount allocated to Shippers would be applied
against the Net Revenue Requirement in the following test year.
By letter dated 19 July 2001, TransCanada advised the Board that the Inventory Management Program,
as contemplated in Article 9 of the S&P Settlement, had been ratified by TTF Resolution 05.2001. The
Board approved Resolution 05.2001 on 10 September 2001, and accordingly, the Inventory Management
Program was not considered further within the context of the RH-1-2001 proceeding.
The Revenue/Asset Management Program is designed to minimize costs associated with TBO Assets and
FST Replacement Assets while generating incremental transportation and other revenue. Under this
program, TransCanada would be entitled to keep, as commission, a portion of the revenues it generates
from a specified group of services. The total commission could not exceed $5 million annually. The
commission payable to TransCanada would be recorded in an incentive deferral account and included in
the subsequent year’s net revenue requirement. Start-up gas would not form part of this program.
When the Tolls Application was filed, the Fuel Incentive Program was still under discussion; however,
this program was subsequently finalized and included as an appendix to TransCanada’s Additional
Written Evidence. The Fuel Incentive Program is designed to minimize total delivered costs, including
fuel gas and power costs for electric-driven compressors, while achieving an acceptable balance between
cost savings and level of service. Fuel usage would be measured against a target and TransCanada would
earn an incentive payment for volumetric reduction in fuel usage from this target, based on a negotiated
schedule. Customers would benefit through the month-to-month fuel recovery mechanism. The payment
to TransCanada under the Program would be limited to a maximum of $15 million and would result in a
corresponding increase in the 2003 Revenue Requirement.
The Foreign Exchange Management Program is a continuation of an existing program and is designed to
reduce losses incurred from foreign exchange transactions. Gains and losses, as measured around a
benchmark, incurred through the program would be shared equally between TransCanada and its
shippers. The Shippers’ share incurred in any given test year would be applied against the Net Revenue
Requirement in the subsequent year, whereas TransCanada’s share would be retained by the pipeline.
The Interest Rate Management Program is a continuation of an existing program and is designed to
reduce the long-term costs of funds in the actual debt portfolio and the issuance of new debt. Gains and
losses, as measured against a benchmark, incurred through the program would be shared equally between
TransCanada and its shippers. The Shippers’ share incurred in any given test year would be applied
against the Net Revenue Requirement in the subsequent year, whereas TransCanada’s share would be
retained by the pipeline.
TransCanada indicated that the incentive mechanisms would provide it with appropriate incentives to
maximize revenues and reduce costs, thereby aligning TransCanada’s interests with those of its
customers. TransCanada submitted that the incentive mechanisms would work together as a package,
whereby its motivation to cut costs (e.g., by fixing OM&A amounts and by allowing TransCanada to
keep all additional savings) would be balanced by its potential to earn additional revenues (e.g., through
the Severance Program, Revenue/Asset Management Program and Fuel Gas Incentive Program).
18
RH-1-2001
2.3.1
Views of Parties Opposing TransCanada’s Proposal
Centra stated that it generally supports the concept of performance-related enhancements; however, it
also indicated that the Revenue/Asset Management Program would allow TransCanada an opportunity to
earn additional revenue without having to do much. Centra commented that, in the case of a commission
on balancing fees, TransCanada may be encouraged in the wrong direction. Finally, Centra expressed the
view that the disposition of the incentive mechanisms should be contingent upon some degree of risk
sharing.
The CA submitted that it generally supports the notion of providing TransCanada with a proper set of
incentives; however, it suggested that the structure of the S&P Settlement is not the only framework in
which the pipeline could be motivated to maximize revenues and reduce costs. The CA also suggested
that, if the Board were to disallow TransCanada from flowing through all of the non-renewal costs to its
shippers, the business risk would then be allocated to TransCanada and its shareholders, and
TransCanada would be clearly encouraged to maximize revenues, retain load and reduce costs.
PG&E/El Paso’s stated position, with the exception of the issue of risk/revenue sharing, was to support
the remaining terms of the S&P Settlement, including the incentive mechanisms, so as not unravel the
entire application to the detriment of other shippers. Nonetheless, PG&E/El Paso expressed concern that
the proposed incentives appear to be no more than an attempt by TransCanada to attract additional
revenue without a proper risk/reward balance that would reflect a sharing of both the potential upsides
and downsides. PG&E/El Paso proposed a modification to the Revenue/Asset Management Program as
part of their alternative proposal for the sharing of risk associated with FT contract non-renewals (see
Section 2.1.2).
Views of the Board
The Board accepts that the proposed Incentive Mechanisms were designed as a package
to align the interests of TransCanada and its shippers. As such, these provisions in the
application were supported by a significant number of parties. The concerns raised by
Centra, the CA and PG&E/El Paso appear to the Board to be related more to their
interests in promoting a risk-sharing mechanism than to any specific difficulties with the
incentive mechanisms proposed by TransCanada.
In the Board's view, no significant doubt was raised with respect to the appropriateness
of the proposed incentive mechanisms.
2.4
Pricing of IT Service
Currently, IT Service is a daily biddable service with a floor price equal to 80% of the 100% load-factor
FT toll and no maximum bid price. The pricing of IT service was last reviewed as part of the RH-1-99
proceeding, in which the Board decided to raise the floor price of IT from 50% to 80% of the
100% load-factor FT toll, effective 1 May 2000.
In its Tolls Application, TransCanada proposed to maintain the daily and biddable nature of IT Service,
but suggested the establishment of a revised methodology for determining the IT floor price.
RH-1-2001
19
Under the proposed refinements, the floor price would be recalculated monthly to incorporate changes in
the forward price of fuel gas at Empress and would be revised on a seasonal basis to reflect projected
changes in marginal fuel ratios. While the floor price would continue to be based largely on incremental
marginal fuel costs, a contribution to fixed costs and the FT commodity toll would be added. A collar on
the floor price would be introduced and the minimum and maximum would be 80% and 120% of the
100% load factor FT toll respectively.
TransCanada submitted that the proposed changes represent a directional improvement over the current
fixed floor price. TransCanada indicated that the proposed monthly redetermination of the floor price
would ensure that the minimum price of IT Service is reflective of actual fuel gas costs, while the
seasonal redetermination of the floor price based on changes in operating conditions and throughput
would ensure that the floor price represents a better proxy of actual incremental marginal costs.
TransCanada also indicated that the addition of the FT commodity toll to the derivation of the floor price
would help ensure that all variable costs are recovered, while the addition of a contribution to the fixed
costs component would ensure that IT Service makes a contribution to fixed costs, providing benefit to
FT shippers. TransCanada submitted that the adoption of the minimum floor price level as proposed
would help deter migration of volumes from FT to IT Service, since a floor price strictly determined on
the basis of incremental fuel costs could result in a floor price well below the 80% level.
TransCanada expressed the view that the Board should not give serious consideration to Centra’s
proposal (i.e. that IT Service should be priced at least equal to the 100% load factor FT toll) since it was
only raised in Final Argument. TransCanada further submitted that evidence concerning migration from
FT to IT Service was insufficient to reject the proposal contained in the S&P Settlement and indicated
that IT Service would be discussed again as part of the next round of negotiations.
2.4.1
Views of Parties Opposing TransCanada’s Proposal
Centra argued that, if there was evidence of migration from FT to IT Service, IT Service should be priced
at least equal to the 100% load factor FT toll. Centra noted TransCanada’s view that the pricing of IT
Service had been a significant factor in FT contract non-renewals and subsequent migration from FT
Service to IT Service.
PG&E/El Paso expressed some concerns over the pricing of IT, but did not oppose TransCanada’s
proposal.
Views of the Board
The Board is of the view that TransCanada’s proposal for the pricing of IT Service
represents an improvement over the currently approved methodology, as it better ensures
that the IT floor price at least recovers the incremental marginal cost of providing the
service. These adjustments are particularly relevant in periods of high price volatility.
The Board is cognizant that TransCanada’s proposal resulted from a broad consensus
among stakeholders with diverse interests with respect to IT Service pricing.
The Board notes that the prospective terms and conditions for IT Service will be
discussed as part of the negotiations regarding the future business and regulatory model
20
RH-1-2001
for TransCanada. Therefore, in assessing the possible impact of TransCanada’s
proposal, the Board did not look beyond the 2001-2002 period.
2.5
Depreciation
According to the terms of the S&P Settlement, TransCanada’s composite depreciation rate would
increase in 2001 by adding 0.10% to the 2000 composite rate of 2.64% to equal 2.74% with a further
addition of 0.15% in 2002 to 2.89%.
TransCanada noted that depreciation rates have not changed since 1993 as parties agreed not to adjust
rates either as part of the four-year Incentive Settlement (1996 through 1999) or in the 2000 Tolls
Application. For 2001, TransCanada indicated that an increase in depreciation rates is warranted for two
reasons. First, there has been a $4.5 billion increase in rate base since the depreciation rates were last set
by the Board in 1993. Second, the economic life of the assets has been reduced as a result of changes in
WCSB supply and in TransCanada’s markets.
TransCanada indicated that, in 1992, the depreciation rates for assets such as pipe were based on a
35-year economic life truncating in 2026. TransCanada contended that, if the truncation date remained
unchanged, and recognizing the $4.5 billion addition to rate base (comprised mainly of pipeline and
compression assets), it would have to recover the value of assets over fewer than 35 years, resulting in
higher depreciation rates.
TransCanada stated that the S&P Settlement provides for depreciation rates to rise slightly in 2001 and
2002. TransCanada conceded that there is no depreciation study on the record. However, while
TransCanada noted that increased depreciation rates would cause tolls to increase, it stated the evidence
indicated that depreciation rates need to go up. TransCanada suggested that sufficient evidence was
presented during the hearing with respect to the question of the changing supply picture in the WCSB to
support the proposed changes to depreciation rates.
2.5.1
Views of Parties Supporting TransCanada’s Proposal
CAPP endorsed, what it considered to be a small increase in the composite depreciation rate, and noted
that the increase is supported, in part, by a change in the asset mix and vintage. CAPP indicated that the
amount of the increase was negotiated, and is certainly not material enough to transform the depreciation
cost from being acceptable to being unacceptable.
Coral indicated that it was concerned about the lack of evidentiary support for the proposed depreciation
rate changes but was willing to accept the proposal during the life of the current application.
TransGas supported the proposed changes to depreciation rates.
2.5.2
Views of Parties Opposing TransCanada’s Proposal
Centra expressed the view that depreciation rates should remain at their current levels as there is no
evidence on the record to support an increase in depreciation rates. Centra contended that, while
increasing return of capital is, perhaps, an understandable short term response to a perceived increase in
risk, it is not appropriate absent a comprehensive solution that addresses that risk.
RH-1-2001
21
Centra stated that the mere addition of assets does not, in and of itself, lead to a changed depreciation
schedule. Instead, Centra contended that the real issue is the economic life of the assets. Centra
indicated that TransCanada’s assumption of a truncation date of 2026 implied an economic life of
25 years but that there were no current depreciation study to support this view. Centra indicated that it
was inappropriate to change depreciation rates on an unproven assumption.
In Centra’s submission, if this had been a tolls case in the normal course, TransCanada would have been
required to fully justify its depreciation proposal. Centra suggested that a settlement should not change
the fundamental onus incumbent upon TransCanada, particularly for something as significant as
depreciation.
The CA did not indicate whether or not it agreed with TransCanada’s proposed depreciation rates but
stated that the depreciation rates embodied in the S&P Settlement serve only to further dilute
TransCanada’s incentive to compete or take other steps to retain potential lost volumes.
PG&E/El Paso questioned why TransCanada was proposing to raise depreciation rates, thereby further
burdening FT shippers during a period of extreme upward pressure on the Mainline System tolls.
Views of the Board
While the Board would normally expect a change in depreciation to be supported by a
depreciation study, it is prepared in this instance to approve the proposed increases
despite the absence of such a study.
In the Board's view, sufficient evidence was advanced on TransCanada's overall supply
and market situation to suggest that a comprehensive review of TransCanada’s
depreciation rates is warranted and would result in increased depreciation rates. In
addition, as indicated by CAPP, the Board considers the proposed changes to be
relatively small and can be supported, in part, by a change in the asset mix and vintage.
2.6
Proposed Additions to Rate Base
As part of its Tolls Application, TransCanada provided schedules of Transmission Plant additions for the
years 2000 and 2001. Total Transmission Plant additions were $196,096,000 for the year 2000 and
$82,751,000 for the year 2001.
TransCanada included four projects totalling $13,818,000 in its 2001 Test Year Schedule, described as
statistical forecasts, that did not have Board approval. During the proceeding, the Board inquired as to
why those projects should be allowed in rate base. TransCanada indicated that these projects were used
for forecasting purposes only and, upon further investigation, determined that the projects should not
have been included in rate base. The projects numbers were used for budgeting purposes only and were
inadvertently included as part of rate base additions. TransCanada estimated that the 2001 average Rate
Base, as filed in its Tolls Application, would be reduced by approximately $6.9 million as a result of
their removal.
22
RH-1-2001
Views of the Board
The Board accepts TransCanada’s estimated reduction to its proposed 2001 Rate Base
and is of the view that any revenue requirement impact associated with the removal of
these projects should be flowed through to the 2002 Test Year in the normal deferral
account manner.
2.7
Summary Views on the S&P Settlement
2.7.1
Views of TransCanada
TransCanada relied in part on the S&P Settlement as evidence of the justness and reasonableness of the
resultant tolls. TransCanada argued that the relevance of support from interested parties for settlements
is recognized in the Board’s Settlement Guidelines. TransCanada indicated that only five of the
stakeholders, representing less than 7% of annual TransCanada Mainline’ revenues, initially expressed
opposition. TransCanada concluded that while these numbers changed slightly over the course of the
hearing, there was no significant variation. Further, TransCanada expressed the view that the significant
level of support for the S&P Settlement, both in terms of the number and the diversity of supporters, is an
indication that the resultant tolls are just and reasonable.
With regard to the breadth of support, TransCanada submitted that the S&P Settlement was an agreement
among very diverse interests on significant and complex issues at a time of industry transition and
uncertainty. The negotiating process resulted in a greater appreciation by parties for each other’s
interests, and for the history, complexity and the interrelated nature of the issues. TransCanada
expressed the view that, as a stopgap or way station, the S&P Settlement would allow for parties to return
to the challenge of creating a new business and regulatory model to define its operation in the new
environment.
In conclusion, TransCanada argued that the substantial level of support for the S&P Settlement should be
accorded significant weight in the Board’s deliberations.
2.7.2
Views of Parties Supporting the S&P Settlement
CAPP urged the Board to look at the particular components of the Tolls Application and conclude that
they are acceptable. Further, CAPP encouraged the Board to recognize that the individual components of
the S&P Settlement were negotiated as a package and that the package as a whole should be approved.
The Eastern LDCs argued that Settlement Guidelines may be interpreted to accord significant weight to
highly-supported settlements. Nonetheless, the Eastern LDCs agreed that, when a party brings forth
sincere and credible opposition to a majority position, the Board should consider that opposition
carefully.
The Eastern LDCs asserted that the Board should note the diversity and size of the support for a disputed
settlement and ascribe to the settlement such relative significance as reflects those factors. In this case,
the Eastern LDCs submitted that there is not only a diversity, but the entire range of TransCanada’s
stakeholders in support of the S&P Settlement, and in numbers that represent a substantial majority of
those with commitments to the TransCanada Mainline System.
RH-1-2001
23
The Eastern LDCs noted that the S&P Settlement is not simply a proposal unilaterally brought forward
by TransCanada, which just happens to meet the approval of a substantial majority and diversity of
TransCanada’s stakeholders. Rather, the S&P Settlement was reached after considerable effort and
represented a compromise among parties on important features.
Finally, the Eastern LDCs submitted that, while it may be appropriate for the Board to develop guidelines
for disputed settlements, the onus is primarily on the industry to produce negotiated settlements or come
to the Board in a timely manner for resolution through litigation.
IGUA argued that the broad base of shipper support for the S&P Settlement is relevant to the Board’s
consideration as to whether the agreement will operate to produce just and reasonable tolls.
The ADOE submitted that just and reasonable tolls cannot be reduced to a mathematical formula based
on a number of supporting or opposing shippers. The ADOE stated that there are non-shipper
stakeholders, such as industry associations and governments, who are also concerned about just and
reasonable tolls and the public interest.
With respect to Centra’s and PG&E/El Paso’s comments that captive shippers have been disenfranchised,
the ADOE argued that contractually-captive shippers have voluntarily chosen to assume longer-term
contracts for business reasons.
The ADOE noted that there were parties, who were not signatories to the S&P Settlement, but who
supported it. Finally, the ADOE submitted that the Board should give a great deal of weight to the S&P
Settlement because it is fair, balanced and strongly supported.
BP Canada indicated that substantial weight should be given to the S&P Settlement in the Board’s
decision-making process. In BP Canada’s view, the parties to the S&P Settlement expended considerable
effort and resources to negotiate the settlement on the expectation that it would be an important
determinant of what is just and reasonable. BP Canada contended that, while a contested settlement in
itself may not be a demonstration that the settlement is in the public interest and that the resulting tolls
would be just and reasonable, it is important that a significant number of TransCanada’s stakeholders,
representing a substantial interest in the pipeline and a diverse range of individual interests, agreed on a
comprehensive set of interrelated issues. Further, BP Canada acknowledged that, while negotiating
positions are confidential, the process was open to all stakeholders.
BP Canada asserted that the Settlement Guidelines need to be reviewed to accommodate negotiations of
more complex issues by diverse groups of interests, including competitors. BP Canada asserted that
unanimity would be increasingly difficult to achieve in the future, and it would be unfortunate to
eliminate the benefits and efficiencies associated with pursuing negotiated settlements. BP Canada
suggested that parties need to know whether contested settlements will have standing; otherwise, they
may be reluctant to invest time and resources into negotiations.
2.7.3
Views of Parties Opposing the S&P Settlement
Centra argued that it is inappropriate to give weight to the S&P Settlement in accordance with some
numerical notion of support. Centra noted that the Settlement Guidelines do not deal with contested
settlements, and submitted that, once the Board made the decision that the S&P Settlement did not fall
24
RH-1-2001
within the meaning of the Settlement Guidelines, the S&P Settlement became nothing more than an
agreement among parties, whereby parties expressed support or opposition in argument. Accordingly, it
should be treated no differently than the handling of a proposal in a regular proceeding. In conclusion,
Centra submitted that the S&P Settlement ought to be accorded virtually no weight in the Board’s
deliberations.
The CA argued that a weighting of the demand volumes by remaining term of contract results in only
56% of the system affirmatively supporting the S&P Settlement. The CA asserted that this is not a
compelling level of support. Further, the CA interpreted the Settlement Guidelines to indicate that the
Board would not conclude that tolls are just and reasonable in the circumstances of an opposed
settlement.
Coral expressed the view that the Board must weigh all of the evidence put before it, regardless of the
level of support voiced for one proposal or another, in determining what is just and reasonable for its
stakeholders. Coral indicated that it would be productive to have a Board-appointed facilitator
participate in any future negotiations between TransCanada and stakeholders.
In keeping with TransCanada’s position that a lack of expressed opposition is assumed to be a lack of
opposition, PG&E/El Paso argued that a lack of expressed support can similarly be assumed to be a lack
of support. As such, no suggestion should be made as to the views of parties who have not clearly
identified their positions.
Finally, PG&E/El Paso argued that, if diversity of support is a relevant measure of success, then the
failure to attract support from a particular group (e.g., contractually-captive shippers) should also be a
relevant measure of failure.
Views of the Board
Given that TransCanada’s proposed S&P Settlement was opposed by certain parties who
participated in the negotiation process, the Board determined that the S&P Settlement
was not in accordance with its Settlement Guidelines. By letter dated 8 June 2001, the
Board advised TransCanada that it was prepared to treat the Tolls Application as a
common position of parties and asked whether TransCanada wished to proceed on that
basis. By letter dated 13 June 2001, TransCanada advised the Board that both the
pipeline and the signatories to the S&P Settlement wished to proceed with the Tolls
Application as filed.
In proceeding with the Tolls Application, the Board took the view that, in order to ensure
the proper exercise of its jurisdiction under Part IV of the Act, it had a responsibility to
examine the particular components of the S&P Settlement to determine whether each
was acceptable and appropriate.
While it examined each component of the S&P Settlement on its own merit, the Board
also took into account the fact that the individual components of the settlement were
negotiated as a package, thereby representing both compromises and an alignment of
interests. As such, the Board is reluctant to disturb individual components without clear
evidence that the S&P Settlement, taken as a whole, would lead to results which are
RH-1-2001
25
inconsistent with the Act. In this proceeding, the Board does not consider that it
received such evidence.
The Board acknowledges that, while some parties did not support the S&P Settlement,
all parties had a fair opportunity to participate in the negotiation process. Further, the
Board recognizes that the S&P Settlement received significant support from a broad
cross-section of TransCanada’s stakeholders. For these reasons, the Board believes that
it should give significant weight to the level of support accorded by stakeholders to the
S&P Settlement.
Finally, the Board wishes to reiterate its continued endorsement of the negotiated
settlement process. One issue central to this proceeding was what factors should be
considered and weighed by the Board when presented with a “contested settlement”.
The current Settlement Guidelines do not directly address this situation.
In addition, in the last few years, there has been considerable focus placed on the
potential development of Alternative Dispute Resolution (ADR) mechanisms which
might be utilized by the all stakeholders (and the regulator) to facilitate solutions to
issues confronting pipelines and their stakeholders.
Accordingly, the RH-1-2001 Panel will recommend to the full Board that a review of the
Board’s Settlement Guidelines be commenced in the near future. Such a review, it is
suggested, should include an examination of the “contested settlement” situation and the
potential for the use of ADR mechanisms.
26
RH-1-2001
Chapter 3
Final Tolls versus Interim Tolls
3.1
Final Tolls versus Interim Tolls
The following represents the sequence of events leading to the interim tolls currently in effect for
TransCanada
7 Dec. 2000
8 Dec. 2000
13 Dec. 2000
15 Dec. 2000
19 Dec. 2000
21 Dec. 2000
10 Jan. 2001
15 Jan. 2001
25 Jan. 2001
TransCanada filed its Application for Interim Tolls effective 1 January 2001
(based on an “Unopposed” TTF Resolution).
The Board issued its determination of the approved Rate of Return on Common
Equity for 2001 (9.61%).
The Board issued Order TGI-4-2000 approving TransCanada’s proposed interim
tolls as filed in its application.
The Board received two letters of complaint (the CA and PG&E/El Paso)
alleging irregularities in the TTF procedures.
The Board rescinded Order TGI-4-2000 and issued a new interim order
(TGI-6-2000) to be in force for one month beginning 1 January 2001. The Board
directed TransCanada to confirm its Application and established a written
process to receive parties’ comments on the appropriate level of interim tolls to
go into effect 1 February 2001.
TransCanada confirmed its intent to continue with its interim tolls application as
filed.
Comments were received from parties on the appropriate level of interim tolls
for 2001.
TransCanada filed its reply comments.
The Board issued its decision approving TransCanada’s proposed level of
interim tolls effective 1 February 2001 (AO-1-TGI-6-2000).
In its Tolls Application, TransCanada proposed that its currently-approved interim tolls continue pending
the Board’s final decision with respect to its RH-4-2001 Fair Return Application. TransCanada noted
that these tolls are based on the gross revenue requirement underlying TransCanada's approved final
2000 tolls, together with the volume determinants for 2001. TransCanada indicated that its Test Year
2000 Revenue Requirement included a rate of return of 9.90% on a deemed equity component of 30%
pursuant to the methodology set out in the Board’s RH-2-94 Multi-Pipeline Cost of Capital Decision.
IGUA raised the following two concerns:
a)
Should the Board set final tolls for 2001 in this proceeding based on the rate of return set
by the Board for 2001 (i.e., 9.61%) or should interim tolls continue until the Board
decides TransCanada's RH-4-2001 Fair Return Application?
b)
If interim tolls for 2001 are to continue, should they be based on the rate of return
approved by Order AO1-TG1-6-2000 being 9.90%, or on the rate of return of 9.61% set
by the Board for 2001?
RH-1-2001
27
IGUA proposed that TransCanada’s 2001 Tolls should be finalized using the rate of return on common
equity of 9.61% on a deemed common equity ratio of 30%. IGUA suggested that this rate be applied to
the terms of the S&P Settlement in order to: i) respect the RH-2-94 decision and order, ii) establish and
collect final tolls for 2001 in 2001, and iii) avoid shipper exposure to a massive retroactivity claim by
TransCanada.
IGUA submitted that the Board’s RH-2-94 Decision and the resulting order are mandatory and require
that TransCanada's return be adjusted annually using the formula set out in that decision. IGUA argued
that the Board should continue to apply the results of this formula until the Board decides that the
formula is no longer applicable. In IGUA’s view, if TransCanada wanted its cost of capital for the 2001
Test Year determined in a different manner, it should have filed an application for that relief before the
Board set TransCanada’s rate of return on common equity for the 2001 Test Year in the Board’s
8 December 2000 letter.
IGUA also argued that TransCanada’s 2001 Tolls should be finalized, rather than remain as interim,
because it is in the public interest that the books for 2001 be closed in 2001. It suggested that a period of
interim tolls which is more than 12 months in duration is unreasonable and not in the public interest,
particularly when the Board is being asked to do so in order that TransCanada can claim a retroactive
increase in profit.
Finally, IGUA suggested that, if interim tolls for 2001 are to continue, the level of interim tolls should be
adjusted to reflect the cost of capital set by the RH-2-94 formula as contained in the Board’s letter of
8 December 2000.
3.1.1
Views of TransCanada
TransCanada submitted that its tolls should remain interim at their current level until the Board makes a
determination on its cost of capital for 2001 and 2002 in the RH-4-2001 proceeding. TransCanada
submitted that neither the facts nor the law support IGUA’s position. TransCanada argued that, to accept
IGUA's conclusions, the Board must agree that the cost of capital element of the interim tolls for 2001
was rendered final by operation of the RH-2-94 return on equity adjustment mechanism after
TransCanada’s 2001 Interim Toll Application was filed and before the interim toll orders were issued.
TransCanada contended that the Board’s RH-2-94 ruling was suspended by the interim orders that the
Board issued. TransCanada noted that the Board’s initial interim order was made on 13 December 2000
in respect to its Interim Toll Application which was filed on 7 December 2000. TransCanada argued that
the Interim Toll Application was filed prior to the Board’s 8 December 2000 letter upon which IGUA
relies, and before the RH-2-94 directive would have gone into effect.
With respect to IGUA’s claim that TransCanada should not keep its books open beyond the end of 2001,
TransCanada noted that the Board has allowed this in the past. As an example, TransCanada referred to
the Board’s RH-1-88 decision where TransCanada’s 1988 Revenue Requirement was not decided until
August of 1989. TransCanada noted that the decision incorporated a return on equity adjustment back to
1 January 1988.
28
RH-1-2001
TransCanada suggested that, if it is successful in its RH-4-2001 Fair Return Application, the Board
would not issue a retroactive order, but rather, would issue a retrospective order that would allow the
collection of the return from the date of the order, or from a subsequent date, as determined by the Board.
TransCanada noted that its Tolls Application includes a Revenue Requirement and resulting tolls that are
illustrative only. To determine final tolls at this time would be to deny TransCanada’s RH-4-2001 Fair
Return Application for 2001 without having heard it and to accept that a 9.61% return on equity on a
30% deemed equity ratio is appropriate without any supporting evidentiary record. Finally, TransCanada
noted that the appropriate effective date for any change to TransCanada’s cost of capital for the Mainline
is an issue in the RH-4-2001 proceeding.
3.1.2
Views of Parties Supporting TransCanada’s Position
CAPP noted that TransCanada’s appropriate cost of capital will be addressed by the Board in the
RH-4-2001 proceeding and that CAPP will, as part of its case in that proceeding, address the issue of
whether any change in cost of capital should be retroactive, retrospective or prospective. As a result,
CAPP contended that TransCanada's tolls should remain interim until the RH-4-2001 proceeding is
concluded.
Centra, the Eastern LDCs and TransGas supported CAPP’s position.
3.1.3
Views of Parties Opposing TransCanada’s Position
Coral submitted that the Board should make a decision in this proceeding that TransCanada’s tolls for
2001 are final. Coral claimed that to do otherwise would unjustly and unreasonably burden shippers that
intend to use services on TransCanada in 2002. In Coral’s view, the potential magnitude of the recovery
from shippers is unjust and unreasonable, particularly in light of the discretion which TransCanada had
in the timing of filing its Fair Return Application.
Coral submitted that not finalizing the tolls for 2001 could trigger a collection of tolls from shippers who
were not responsible for causing them and that this is not in keeping with the principle of cost causation.
Views of the Board
The Board notes that its RH-2-94 Decision did not set a limit on the life of the
adjustment mechanism but did suggest that it should be expected to last at least 3 years.
Regarding potential changes to capital structure, the Board stated:
“The Board will be prepared to consider a reassessment of capital
structures, likely on an individual basis, in the event of a significant
change in business risk, in corporate structure or in corporate financial
fundamentals. ...Any reassessment of capital structure, for reasons such
as those expressed above, must be at the request of the pipeline itself, its
shippers or some other interested party. It would then be for the Board
to assess the merits of such a request.”
RH-1-2001
29
TransCanada’s request for a review of its allowed return in its Fair Return Application is
the first comprehensive request that the Board has received for a re-evaluation of the
Board’s findings in RH-2-94.
Section 19(2) of the Act authorizes the Board to make an interim order instead of a final
order and to “reserve its decision pending further proceedings in connection with any
matter.”
The Board is of the view that the interim tolls set by Order AO1-TG1-6-2000 were
interim in every respect, including cost of capital, and that the appropriate forum for
determining TransCanada’s cost of capital for 2001 and 2002 as well as the effective
date of any changes is the RH-4-2001 proceeding. While the Board recognizes that the
interim period in this case exceeds that normally contemplated or countenanced, in these
particular circumstances, the Board finds the duration to be warranted.
30
RH-1-2001
Chapter 4
Board’s Decisions resulting from RH-1-2001
4.1
The S&P Settlement
Decision
The Board is satisfied that the components of the S&P Settlement result in tolls that
are just and reasonable, and not unduly discriminatory.
Accordingly, the Board approves the S&P Settlement in its entirety.
4.2
The Board’s Settlement Guidelines
Decision
The RH-1-2001 Panel will recommend to the full Board that a review of the Board’s
Settlement Guidelines be commenced in the near future.
4.3
Proposed Additions to Rate Base
Decision
The Board accepts TransCanada’s estimated reduction to its proposed 2001 Rate
Base and directs that any revenue requirement impact associated with the removal
of these projects be flowed through to the 2002 Test Year in the normal deferral
account manner.
4.4
Final Tolls versus Interim Tolls
Decision
The Board directs that TransCanada’s current tolls, which were made interim by
Order AO1-TG1-6-2000, remain in effect pending the Board’s final decision in the
RH-4-2001 proceeding or as otherwise directed.
4.5
TransCanada’s 2003 Tolls and Tariff Application
Decision
The Board directs TransCanada to file a comprehensive tolls and tariff application
for the 2003 Test Year (whether supported by a negotiated settlement or not) by
1 September 2002.
RH-1-2001
31
Chapter 5
Disposition
The foregoing chapters together with Order No. AO-2-TGI-6-2000 constitute our Reasons for Decision in
respect of the Tolls Application heard by the Board in the RH-1-2001 proceeding.
J. Snider
Presiding Member
J.-P. Théorêt
Member
D.W. Emes
Member
Calgary, Alberta
November 2001
32
RH-1-2001
Appendix I
Toll Order AO-2-TGI-6-2000
ORDER AO-2-TGI-6-2000
IN THE MATTER OF the National Energy Board Act (the Act) and the regulations
made thereunder;
AND IN THE MATTER OF an application filed with the National Energy Board (the
Board) under File 4200-T001-15 by TransCanada PipeLines Limited (TransCanada) for
certain orders respecting tolls specified in a tariff pursuant to Part IV, Sections 59, 60, 64
and 65 of the Act.
BEFORE the Board on 1 November 2001.
WHEREAS the Board issued Hearing Order RH-1-2001 on 22 June 2001;
AND WHEREAS a public oral hearing was held pursuant to Hearing Order RH-1-2001 in Calgary,
Alberta during which time the Board heard the evidence and argument presented by TransCanada and
RH-1-2001 Parties;
AND WHEREAS the Board’s decisions on the Application are set out in its Reasons for Decision dated
November 2001, and in this Order;
AND WHEREAS the Board has considered the evidence and submissions, and has found that the tolls to
be charged by TransCanada in accordance with this Order are just and reasonable and not unduly
discriminatory;
THEREFORE, IT IS ORDERED, pursuant to section 21 of the Act, that:
1.
TransCanada’s current interim tolls, as set by Order AO-1-TGI-6-2000, are continued pending a
final order by the Board concerning TransCanada’s 2001 tolls in the RH-4-2001 proceeding.
NATIONAL ENERGY BOARD
Michel L. Mantha
Secretary
RH-1-2001
33
Was this manual useful for you? yes no
Thank you for your participation!

* Your assessment is very important for improving the work of artificial intelligence, which forms the content of this project

Download PDF

advertisement