Attachment A7 Tab 11 Part A – Review and Variance Application Exhibit C30-11-2, RH-003-2011, Final Argument of Enbridge Gas Distribution Inc. Compendium of References. RH-003-2011 FINAL ARGUMENT OF ENBRIDGE GAS DISTRIBUTION INC.
NOVEMBER, 2012
COMPENDIUM
OF
REFERENCES ENBRIDGE GAS DISTRIBUTION INC.
COMPENDIUM
OF
REFERENCES
TAB 1
1
2
3 TCPL's 2012-2013 Toll Application
4
5
6
7
8
9 Hearing Order RH-003-2011
10
11
12
13
14 MAS Evidence
15
16
• 17
18 •
19 March 9, 2012
20
I I- INTRODUCTORY COMMENTS
2 Firm secure supply of natural gas at competitive prices is one of the cornerstones of success 3 for any gas distributor. The recent emergence of new shale gas reserves near Ontario and 4 Quebec, and elsewhere in North America, has however changed the gas dynamics in 5 Canada.
6 Most of the conventional production basins located in Canada and the United States have 7 matured and show production declines. On the other hand, emerging supply gas that comes 8 particularly from reserves in low-permeability wells and shale gas offer very strong growth 9 perspectives. Already, on a continental basis, their development more than offsets the 10 decline in the production of conventional gas. In fact, the exploitation of this non-conventional 11 gas resource is revolutionizing the North American market right now.
12 Tolls on the TransCanada PipeLines Limited system (TransCanada or TCPL) tolls have 13 increased substantially over the last few years. As a result, TransCanada is seeing a rapid 14 and significant decrease in volumes transported by its gas pipeline. The market is reacting 15 strongly by looking for alternative routes if the trend continues because the pan-Canadian 16 pipeline is questioning the economical viability transmission route in the long term.
17 On September 1, 2011, TCPL filed an application with the National Energy Board (Board or 18 NEB) for approval of the Business and Services Restructuring Proposal (Restructuring 19 Proposal) and Mainline tolls for 2012 and 2013. This Restructuring Proposal by TransCanada 20 proposes fundamental changes to principles that have sustained the development of the 21 TransCanada system.
22 II- MARKET AREA SHIPPERS
23 Enbridge Gas Distribution Inc. (Enbridge), Gaz Metro Limited Partnership (Gaz Metro) and 24 Union Gas Limited (Union Gas), collectively the Market Area Shippers (MAS), commonly 25 reject TransCanada's Restructuring Proposal and have developed an Alternative Proposal 26 (MAS Alternative Proposal).
27 MAS do not believe that TransCanada has demonstrated that the changes proposed are 28 likely to address the fundamental issues which are currently impeding competitive tolls on the 29 Mainline. MAS believe that it would be prudent for the Board to reject the TCPL 30 Restructuring Proposal in favour of the MAS Alternative Proposal
31 MAS also oppose deferral of costs over the long term for the benefit of low tolls in one 32 particular year.
1
1 In reviewing TransCanada's Restructuring Proposal, and in designing the MAS Alternative 2 Proposal, the MAS was guided by the following objectives:
3 a) Enhance the economic viability of the Mainline in the short and long term; 4 b) Achieve a just and reasonable risk and reward allocation for all parties that derive a 5 benefit from the Mainline over the short and long term; 6 c) Achieve a just and reasonable allocation of costs amongst all parties that derive a 7 benefit from the Mainline; and 8 d) Ensure open, transparent and competitive access to natural gas supply and 9 transportation services.
10
11 Finally, MAS are asking for just and reasonable tolls that are not unduly discriminatory and 12 are therefore asking the NEB to reject TransCanada's Restructuring Proposal. MAS retained 13 four expert witnesses to review the evidence submitted by TransCanada and also to examine 14 the merits of the MAS Alternative Proposal. Paule Bouchard, from RSM Richter Chamberland 15 LLP (RSM), provides her expert opinion with respect to TransCanada's depreciation 16 proposal. Bruce Henning, from ICF International (ICF), provides his expert opinion to assess 17 the likely market impact of TransCanada's Restructuring Proposal and the MAS Alternative 18 Proposal. Russ Feingold, from Black and Veatch Corporation (B&V), provides his expert 19 opinion on the toll impact of TransCanada's Restructuring Proposal and the MAS Alternative 20 Proposal as well as a review of the appropriateness of certain proposed changes to toll 21 design. Finally, Dr. Jeff Makholm, from National Economic Research Associates Inc (NERA), 22 provides his expert opinion on TransCanada's Restructuring Proposal and the MAS 23 Alternative Proposal, with respect to tolling and regulatory principles.
24 III- MAS AND THEIR GAS DISTRIBUTION ACTIVITIES
25 A. ENBRIDGE GAS DISTRIBUTION FRANCHISE AND DISTRIBUTION SERVICES
26 Enbridge Gas Distribution Inc. ("Enbridge") is an Ontario corporation with its head office in the 27 City of Toronto. It is a regulated natural gas distribution utility that carries on the business of 28 selling, distributing, transmitting and storing natural gas within Ontario.
29 Enbridge provides service to approximately 1.9 million residential, commercial and industrial 30 customers throughout central and eastern Ontario which includes the Greater Toronto Area, 31 the Niagara Peninsula, Barrie, Midland, Peterborough, Brockville, Ottawa and other Ontario 32 communities as indicated in the Figure below.
2
1 Enbridge holds approximately 1 million GJ/d of Firm Transportation on the TransCanada 2 Mainline. In addition, Enbridge also contracts for Short-Term Firm Transportation capacity, 3 which equates to approximately $73 million of discretionary revenue based on 2012 interim 14 tolls.
Enbridge Service Area rim TransCanada Pipelines thOon Gas
5
6
7 B. GAZ METRO FRANCHISE AND DISTRIBUTION SERVICES
8 Gaz Metro's distribution activity is regulated by the Regie de l'énergie. Gaz Metro's 9 distribution system serves about 300 municipalities in Québec and is comprised of over 10 10 000 km of pipeline of various dimensions. Gaz Metro presently serves more than 180 000 11 customers, comprised of over 2 000 industrial customers, over 50 000 commercial customers 12 and more than 130 000 residential customers who consume more than 5 400 million m 3 of 13 natural gas per year.
14 For both the Northern and Southern Zones, Gaz Metro's distribution network is exclusively 15 supplied by facilities wholly owned by TransCanada. In addition, a large portion of Gaz 16 Metro's distribution network is only connected to Gazoduc Trans Québec & Maritimes Inc
3
1 (TQM) facilities and must absolutely be supplied through the TQM system. The map below 2 shows a graphic representation of the Gaz Metro system and its interconnection with 3 TransCanada's integrated system.
• • . . flrn d faipipaat audlainlaniaiian de gaz naturet qualia:c'• ..• ■•,..q.ao•imaaa • . earrmorrrIurmerOorace. .
Gar lanitie—Innurart Gualkrel nlininterien me,
—.L.:11or Imapen • . •-.. TransOnarla C.arneian Garelnis — . • . • Pam de arnmeskra rounur.FI.• IItate de Ihrelsen. Cartuu.rn minemarror... jUsIne de liquatartiee am.finuraurarebri
C;d2-1.tro 4
5
6 C. UNION GAS FRANCHISE AND DISTRIBUTION SERVICES
7 Union Gas is an Ontario Corporation with its registered head office at the City of Chatham in 8 the Province of Ontario. Union is a regulated public utility that conducts an integrated natural 9 gas utility business, combining the operations of purchasing, storing, transporting and 10 distributing gas for customers in its franchise areas as well as storing and transporting natural 11 gas for others.
12 Union serves 1.3 million residential, commercial and industrial customers throughout 13 Northern and South Western Ontario. Union relies exclusively on TransCanada to provide 14 service to its northern and eastern Ontario customers.
15
4 ENBRIDGE GAS DISTRIBUTION INC.
COMPENDIUM
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TAB 2 National Energy Board
RH-003-2012
TransCanada Mainline Restructuring Application
MAS Opening Statement
I. INTRODUCTION
1 Mr. Chairman, Members of the Board, the Market Area Shippers (MAS) appreciate the
opportunity to share their views on the proposed restructuring of Mainline tolls and services.
3 The MAS are the three largest natural gas local distribution companies in Ontario and Quebec —
4 Enbridge Gas Distribution Inc., Gaz Metro Limited Partnership, and Union Gas Limited. The
5 MAS represent approximately 3.4 million end use consumers and almost 60% of the firm
6 contract demand revenue on the Mainline.
7 The MAS (or their predecessor entities), have been shippers on the Mainline since its inception
8 in 1958. They are dependent on the Mainline now and will remain captive to it for the
9 foreseeable future. The MAS rely on firm transportation services provided by TransCanada to
10 meet their obligations to serve their customers.
11 The sharp reduction in long haul flows on the Mainline has, and continues to, put increasing
12 upward pressure on Mainline tolls. The reduction in long haul flows also increases the cost
13 burden carried by TransCanada's captive shippers. It is in this context that MAS opposes the
14 Restructuring Proposal (RP).
15 The RP fails to address the root cause of the Mainline's lack of competitiveness which the MAS
16 believe are costs that can no longer be supported by current and projected billing
17 determinants. Instead the RP unreasonably and inappropriately: shifts costs among system
18 segments via changes to accumulated depreciation; impedes opportunities for supply
19 diversification through toll design changes; and defers into the future costs that cannot be
20 reasonably recovered today. The RP attempts to fix what is not broken and it fails, critically, to
21 ensure the competitiveness of short haul transportation on the TransCanada system. Finally,
1
and perhaps most importantly, if approved, the RP would make it more difficult in the future to
find and implement a proper solution to the problems facing the Mainline.
II. CONCERNS ABOUT THE RESTRUCTURING PROPOSAL
3 The MAS' concerns regarding the major elements of the RP include:
Depreciation
4 The proposed $1.2 billion transfer of accumulated depreciation is an attempt by TransCanada
5 to protect itself from the risk of impairment on Northern Ontario Line assets and transfer the
6 problem to other segments of the system — including the Eastern Triangle. This shift results in
7 inappropriate adjusted net book value for each segment and subsequently impacts any
8 proposed solution for the problems facing the Mainline by hiding the true cost to provide
9 service on each segment. Inappropriate net book values for each segment could have
10 implications for future tolling methodologies, such as segmented tolls or alternative uses for
11 Mainline assets should conversion to oil become a reality. The MAS do not propose a write-
12 down. However the MAS believe that TransCanada's proposal does not comply with GAAP and
13 fails to respect long-standing regulatory principles. Postponing recovery of prudently incurred
14 costs in the face of significant throughput uncertainty is not in the best interests of
15 TransCanada or its shippers.
Toll Design
16 It is the Mainline's cost structure — not toll design — that impedes its competitiveness. Current
17 and projected throughput simply cannot sustain the Mainline's costs. If the RP were to be
18 approved and implemented, the changes in toll design that have been proposed by
19 TransCanada would cause inappropriate leakage of costs from long haul paths to short haul
20 paths and impede the competitiveness of the one segment not impacted by declining billing
21 determinants, the Eastern Triangle.
2 The existing toll methodology has been in place for many years, tested by the Board, accepted
by the marketplace, and relied upon by current shippers in making contracting decisions.
TransCanada has not provided any compelling case for change.
It is the MAS position that ensuring competitiveness of short haul transportation paths is
essential and TransCanada's proposed changes to Toll Design are inconsistent with that
objective.
TQM TBO Allocation
7 The direct cost-allocation of TQM TBO costs is unjustly discriminatory, not in the public interest
8 and inconsistent with the treatment of other Mainline TBOs and Mainline assets in general. On
9 this basis tolls resulting from the RP would not be just and reasonable.
Toll Zones
10 TransCanada has failed to provide sufficient evidence to demonstrate that the removal of toll
11 zones will improve the long-term sustainability of the Mainline. Zones have been a long
12 standing component of TransCanada's toll design, the removal of which is an attempt to fix
13 something that is not broken.
Great Lakes' Right-Sizing
14 TBO with Great Lakes Transmission Company should be limited to a contract demand which
15 matches TransCanada's requirements to serve its firm service shippers. Consideration should
16 always be given to, amongst other things, the efficient movement of gas on the TransCanada
17 system — including acting on opportunities to reduce distance of haul and its commitments to
18 Great Lakes TBO generally.
Mainline Services Including RAM
19 The proposed service changes to IT and STFT bid floor pricing and the Multi-Year Fixed Pricing
20 service do not provide an adequate balance between the additional flexibility requested by
21 TransCanada, on the one hand, and any risk that would be assumed by TransCanada, on the
3
1 other. TransCanada should not be provided a "trial" period during which it could exercise the
2 flexibility that it is seeking without proper accountability and the assumption of commensurate
3 risk on its part.
Further, the objective of attracting additional long haul billing determinants to the Mainline
5 would be undermined if TransCanada's proposal to eliminate RAM were to be approved. The
6 diminished value of service offered to shippers in the RP will not attract additional billing
7 determinants. Further, existing long haul shippers receive significant value from RAM as an
8 offset against high tolls. Its elimination would only serve to replace that benefit with reduced
9 value.
Cost of Service
10 Failure to reduce costs on the Mainline is the major impediment to the Mainline's viability.
11 Reliance on the Long Term Adjustment Account and the establishment of a new Short-Term
12 Adjustment Account —thereby shifting present costs to future generations of shippers — will not
13 solve the problem. Considering the uncertainty about future Mainline throughput postponing
14 cost-recovery could provide an incentive for further decontracting.
III. THE MAS PROPOSAL
15 The MAS recognize that the current situation facing the Mainline is the consequence of
16 significant changes in the natural gas market. It was not created by imprudence on
17 TransCanada's part in managing its assets and costs, by LDCs seeking supply diversity and lower
18 cost supplies for their end users, or by producers that no longer hold long haul firm
19 transportation contracts.
20 The question should not be "Who's responsible?" but rather "What is the most fair and
21 appropriate mechanism to deal with the problem?" All stakeholders have acted rationally in
22 accordance with their specific interests and in response to changes in both the supply of natural
23 gas and the requirements for pipeline service. Nevertheless, it remains in all stakeholders'
24 interest to contribute to a fair and effective solution.
4 1 The situation is critical — more critical than TransCanada has acknowledged — and urgent action
2 is essential. It is just as important, however, that no further obstacles be placed in the path to a
3 solution. Implementation of the RP would do just that.
4 It is in this context as well and in consideration of the extensive discussion related to alternative
5 approaches beyond the test year period that MAS wishes to amend its proposal to span a 2
6 year timeframe, from 2012 to 2013, rather than maintain its original time frame of 2012 to
7 2014. In MAS' view, upon release of a Decision in this proceeding parties should move
8 immediately to consider alternative mechanisms to improve the viability of the Mainline
9 according to guidance provided by the Board.
10 For these reasons, the MAS believe that the Alternative Proposal is the preferred proposal of all
11 that have been presented to the Board. All of its features will not be repeated here. It is,
12 though, worth highlighting the objectives that the MAS Proposal is designed to achieve:
13 1. Enhance the economic viability of the Mainline in the short and long term;
14 2. Achieve a just and reasonable risk and reward allocation for all parties that derive a
15 benefit from the Mainline over the short and long term;
16 3. Achieve a just and reasonable allocation of the costs amongst all parties that derive a
17 benefit from the Mainline over the short and long term;
18 4. Ensure open, transparent and competitive access to natural gas supply and
19 transportation service.
20 The MAS believe that its Proposal, if applied to determine TransCanada's tolls for 2012 and
21 2013, would provide the most appropriate base from which all parties, together, could pursue a
22 longer-term solution for the Mainline.
23 Appendix A contains the MAS response to the generic questions posed by the Board in its letter
24 dated 7 September 2012.
5 ENBRIDGE GAS DISTRIBUTION INC.
COMPENDIUM
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TAB 3 April 27, 2012
1.2 Reference: (i) Written evidence of the MAS, page 5, lines 5-7.
Preamble: In its evidence, the "MAS consider that all three LDCs are captive shippers of the TransCanada system.
Request: (a) Please describe what is meant by the term "captive shippers".
(b) Is it the assertion of the MAS members that they are captive to the TransCanada Mainline system both in terms of where they receive their gas supply and where they receive deliveries from TransCanada?
(c) Have any members of the MAS supported, constructed or had an affiliate take an equity stake in pipelines that allowed them to non-renew their long haul contracts on the Mainline and source their supply at locations other than Empress?
(d) Has any of the MAS members contracted for capacity or pursued contracting for capacity on pipeline systems that allowed them to non-renew their long haul contracts on the Mainline and source their supply at locations other than Empress?
(e) Please list and provide the details of all projects proposed by MAS members or their affiliates to bring U.S. supply to Ontario and/or Quebec.
(f) Are there any current or projected flows of the LDC's that bypass the TransCanada system? If so, does this imply the LDC's are not captive?
(g) Please identify all the options other than the Mainline that connect to each of the MAS LDCs, and the capacity associated with each such option.
Response: a) Shippers are defined as "captive" if they are physically connected to the TransCanada system and must absolutely rely on TransCanada's transportation services, whether it be for long or short haul, to meet their gas needs and cannot supply themselves completely without TCPL's system. As Shippers leave the Mainline due to uncompetitive tolls, the costs are re-allocated to, and borne by captive shippers.
b) The term "captive" in this instance relates to the fact that the MAS members must necessarily contract with TransCanada in order to deliver the gas to their franchise. As for the gas supply, theoretically MAS members could purchase the gas supply at different points however the purchase is of no use if there is no capacity available to bring that gas supply to the customers. Even WCSB supplies
Page 3 of 115 April 27, 2012
procured on Alliance and transported on Vector must use TCPL to reach customers in Ontario and Quebec. c) Yes, however encouraging new sources of supply as well as new infrastructure into an LDC's service territory is critical to securing long-term supply regardless of whether or not the provider of the infrastructure is an affiliate. In addition, minimizing risk by diversifying contract terms, supply basins and upstream pipelines is also Crucial to ensuring diversity and security of supply.
d) Yes.
e) Please refer to MAS response to CAPP 11 c). Enbridge and GMI do not currently have a project to bring U.S. supply to enter Ontario or Quebec.
All MAS members are captive as defined in a) above because they cannot completely withdraw from reliance on TCPL.
g) The following pipelines connect to Union's South system:
Panhandle — 195 Mmcf/day Bluewater — 200 Mmcf/day SCPL Michcon — 200 Mmcf/day Vector — 1.5 Bcf/d Parkway (Cons) — 1.3 Bcf/day Lisgar (from Union to EGD)— 0.7 Bcf/day Tecumseh — 2.2 Bcf/day Tecumseh Sombra Line Extension (TSLE)— 0.4 Bcf/day
Union's north system is entirely fed from the TransCanada Mainline.
Gaz Metro's and Union's Northern franchise service areas are only connected to the integrated system of TransCanada and TQM.
Enbridge's franchise areas are connected only to the TransCanada Mainline and Union Dawn —Trafalgar system.
Page 4 of 115 ENBRIDGE GAS DISTRIBUTION INC.
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TAB 4 Contract DemandLevelsandTollseffectiveNovember1,2000 Item # TCPL FT-CDA TCPL FT-CDA TCPL FT-CDA TCPL FT-CDA TCPL FT-EDA TCPL FT-EDA TCPL FT-CDA TCPL FT-CDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL STSKirkwalltoCDA TCPL FT-EDA TCPL FT-EDA ANR Transportation ANR Transportation ANR Transportation ANR Transportation ANR Transportation TCPL STSKirkwall/ParkwaytoEDA TCPL STSKirkwall/ParkwaytoEDA TCPL STSKirkwalltoCDA Vector Pipeline Vector Pipeline- Alliance Pipeline Michcon Transportation Michcon Transportation Nova Transmission Nova Transmission Nova Transmission Niagara GasTransmission Union GasDawnto Kirkwall Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoKirkwall Transportation Empress toCDA Empress toCDA Empress toEDA Empress toCDA Empress toCDA Empress toCDA Empress toCDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA AECO toEmpress AECO toEmpress AECO toEmpress Empress toEDA Empress toEDA Empress toEDA Willow toColumbus SW HeadstationtoWillowF Empress toEDA Empress toEDA Alberta toU5border Corunna toTecumseh Corunna ColumbusLink Corunna ColumbusLink Corunna ColumbusLink SE HeadstationtoWillowR Cdn bordertoDawn Chicago toCdnborder Cdn bordertoDawn Chicago toCdnborder Kalkaska toColumbus US bordertoChicago . Route Daily Volume Contracted 1,560,926 G1 282,690 al 177,049 al 142,457 al 153,700 al 235,875 al 101,285 al 72,708 al 45,000 al 26,952 al 26,319 21,584 al 32,357 al 26,952 GJ 15,520 al 15,683 al 10,773 al 10,773 al 19,692 GJ 35,806 al 35,089 G1 50,052 GJ 10,000 35,806 al 20,848 al 53,455 al 15,000 10,692 GJ 10,000 10,000 28,833 al 11,209 al 83,349 GJ 79,000 dth 96,000 dth 7,613 1,713 4,013 al 7,500 dth 7,568 dth 7,567 dth 2,125 7,500 8,039 GJ 2,125 10 75 mmct al GJ G.I GJ dth dth dth dth 10 3 3 m m 3 3
varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies ae Charge Rate Fuel Demand Monthly 29.42293 Wal 29.42293 $/al 29.42293 $/al 29.42293 29.42293 VGJ 29.42293 5/al 29.42293 $/al 29.42293 Wal 29.42293 $/al 29.42293 5/al 29.42293 5/al 29.42293 $/al 29.42293 $/al 29.42293 Wal 29.42293 $/al 29.42293 Val 29.42293 Wal 29.42293 $/GJ 52.08100 $/10 29.42293 $/al 17.11860 $US/dth 4.25000 $US/dth 9.25000 $US/dth 0.00000 0.00000 8.31900 4.52242 $/al 4.52242 $/al 0.79833 VGJ 4.56300 $US/dth 4.52242 $/al 2.40917 $/al 2.40917 $/al 0.79833 5/G1 2.50000 $/G.1 2.50000 Wal 2.50000 $/al 2.50000 Val 2.50000 $/al 0.57050 Val 7.01400 $US/dth 0.57050 $/al 7.01400 $US/dth 2.50000 VG 1.52100 $US/dth WO $US/dth $uS/dth Sus/dth $/10 3 3 m m 3 3
Commodity Charge 0.04179 0.04179 0.04179 0.04179 0.04179 0.04179 0.04179 0.04179 0.04179 0.04179 0.04179 0.04179 0.04179 0.04179 0.04179 0.04179 0.04179 0.00239 0.00003 0.04179 0.00003 0.04179 0.00239 $/al $/al $/al $/al VGJ $/al $/al $/al 5/al Oct31/04 $/al Wal 5/Gl G Oct31/07 VGJ $/al Val $/G1 Wal $/al Val Val WO WO Wal Expiry Date Mar 31/01 Mar 31/01 Mar 31/02 Oct 31/03 Oct 31/03 Oct 31/03 Oct 31/03 Apr 15/04 Oct 31/06 Oct 31/05 Oct 31/10 Oct 31/04 Oct 31/02 Oct 31/02 Oct 31/03 Oct 31/05 Oct 31/01 Oct 31/07 Oct 31/01 Oct 31/02 Oct 31/07 Oct 31/02 Oct 31/02 Oct 31/06' Oct 31/01 Oct 31/15 Oct 31/07 Oct 31/07 Oct 31/07 Oct 31/10 Oct 31/03 Oct 31/15 Oct 31/15 Oct 31/15 Oct 31/15 Oct 31/05 Oct 31/06 Oct 31/06 Oct 31/09 Oct 31/03 Oct 31/10 Oct 31/09 Oct 31/05 Oct 31/15
I. 1. 0Z-£00-H 9 L -90-Z 1, OZ :PH Contract DemandLevelsandTollseffectiveNovember1,2001 Item # TCPL FT-EDA TCPL FT-CDA TCPL FT-CDA TCPL FT-CDA TCPL FT-CDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA ANR Transportation ANR Transportation TCPL STSKirkwall/ParkwaytoEDA TCPL STSParkwaytoCDA TCPL STSKirkwalltoCDA TCPL STSKirkwalltoCDA Vector Pipeline- Alliance Pipeline ANR Transportation TCPL STSKirkwall/ParkwaytoEDA Vector Pipeline Michcon Transportation Michcon Transportation Nova Transmission Niagara GasTransmission Nova Transmission Union GasParkwaytoDawn-Cl Union GasDawntoKirkwall Union GasDawntoKirkwall Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoKirkwan Transportation Empress toCDA Empress toCDA Empress toCDA AECO toEmpress AECO toEmpress Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toCDA Alberta toUSborder Corunna toTecumseh Willow toColumbus SE HeadstationtoWillowR SW HeadstationtoWillowF Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Cdn bordertoDawn Chicago toCdnborder Cdn bordertoDawn Chicago toCdnborder US bordertoChicago Kalkaska toColumbus Corunna ColumbusLink Empress toEDA Route Daily Volume Contracted 1,560,926 282,690 177,049 142,457 153,700 107,000 804,617 al 235,875 101,285 72,708 42,770 26,952 26,319 21,584 32,357 35,806 35,089 26,952 15,520 50,052 20,848 15,520 10,000 10,773 10,773 19,692 35,806 53,455 10,692 10,000 15,000 10,000 83,349 79,000 96,000 28,833 4,013 7,613 7,568 7,567 1,713 2,125 2,125 8,039 75 G1 G1 G1 GJ G1 G1 G1 G1 G1 G1 G1 G1 G1 al al G1 G1 al al G1 G1 dth dth dth dth dth G1 G1 G1 G1 G1 G1 G1 al al al al al al dth dth mmcf 10 10 3 3 m m 3 3
ais 32.99445 32.99445 varies varies ais 32.99445 32.99445 varies 32.99445 varies 32.99445 varies 32.99445 varies varies 32.99445 varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies 7.20875 varies varies 13.18220 varies varies varies varies varies varies varies varies ae Charge Rate Fuel Demand 830.73000 Monthly 32.99445 32.99445 32.99445 53.96800 32.99445 32.99445 32.99445 32.99445 32.99445 33.99445 32.99445 4.25000 2.58833 0.90750 2.58833 0.90750 0.90750 8.34030 9.25000 4.56300 4.90369 0.57050 4.90369 2.55400 2.12800 2.55400 2.55400 2.55400 2.55400 2.12800 7.20875 0.57050 1.52100 $/G1 $/G1 $/G1 $/G1 $/G1 $/al $/G.1 $/G1 5/G.I $/G1 $/G1 $/G1 5U5/dth $US/dth $/G1 $/G1 $/G1 $/al $/G1 5/ai $/G1 $/G1 $/al 5/G1 $/10 $/10 $115/dth $US/dth 5uS/dth 5uS/dth 5u5/dth $/G1 $/G1 $/G1 $/G1 $/G1 $/G1 $/G1 $/G1 $/G1 $/al $/G1 Wal $US/dth 3 3 m m 3 3
Commodity Charge _ 0.00253 0.04757 0.04757 0.04757 0.04757 0.04757 0.04757 0.04757 0.00002 0.00002 0.00253 0.00002 0.04757 0.04757 0.04757 0.04757 0.04757 0.04757 0.04757 0.04757 0.04757 0.04757 0.04757 Val $/G1 $/al Wal $/G1 $/G1 $/G1 $/G1 Wal $/G1 $/G1 $/G1 $/G1 $/G1 $/al 5/al $/G1 5/al 5/al $/G1 5/al $/al $/G1 Expiry Date Mar 31/02 Mar 31/04 Apr 15/04 Oct 31/03 Oct 31/03 Oct 31/03 oct 31/07 Oct 31/07 Oct 31/02 Oct 31/07 Oct 31/06 Oct 31/05 Oct 31/10 Oct 31/04 Oct 31/02 Oct 31/02 Oct 31/03 Oct 31/05 Oct 31/04 Oct 31/03 Oct 31/15 Oct 31/15 Oct 31/02 Oct 31/02 Oct 31/02 Oct 31/15 oct 31/05 Oct 31/11 Oct 31/10 Oct 31/10 Oct 31/09 Oct 31/03 Oct 31/03 Oct 31/15 Oct 31/15 Oct 31/15 Oct 31/06 Oct 31/06 Oct 31/06 Oct 31/07 Oct 31/09 Oct 31/02 Oct 31/03 Oct 31/02 Oct 31/05
I. 1- 0Z-000-1-121 91, -90-Z1. 0Z :Pend Contract DemandLevelsandTollseffectiveNovember1,2002 Item # TCPL FT-CDA TCPL FT-EDA TCPL FT-CDA TCPL FT-CDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA ANR Transportation ANR Transportation TCPL STSKirkwall/ParkwaytoEDA TCPL STSParkwaytoCDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA ANR Transportation ANR Transportation ANR Transportation TCPL STSKirkwall/ParkwaytoEDA TCPL STSParkwaytoCDA TCPL STSParkwaytoCDA Michcon Transportation Michcon Transportation Vector Pipeline Vector Pipeline- Alliance Pipeline Niagara GasTransmission Nova Transmission Nova Transmission Nova Transmission Union GasParkwaytoDawn-Cl Union GasDawntoParkway Union GasDawntoParkway/Kirkwall/Lisgar Union GasDawntoParkway Union GasDawntoKirkwall Union GasDawntoParkway Union GasDawntoKirkwall Union GasDawntoParkway Union GasDawntoParkway Transportation AECO toEmpress Alberta toUSborder Willow toColumbus AECO toEmpress AECO toEmpress Empress toCDA Empress toCDA Empress toCDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Corunna ColumbusLink Corunna ColumbusLink Corunna ColumbusLink SE HeadstationtoWillowRt SW HeadstationtoWillowR Empress toEDA Cdn bordertoDawn Chicago toCdnborder Corunna toTecumseh Cdn bordertoDawn Chicago toCdnborder Empress toEDA Empress toEDA Kalkaska toColumbus US bordertoChicago Route Daily Volume Contracted 1,764,678 al 804,617 GJ 282,690 GJ 101,285 al 177,049 GJ 107,000 al 119,391 G. 153,700 GJ 142,457 al 23,321 al 72,708 al 37,400 al 35,806 al 53,455 al 32,123 al 79,000 dth 96,000 dth 27,290 GJ 26,952 GJ 21,584 al 32,357 al 83,349 al 28,833 al 35,089 al 35,806 al 92,822 GJ 37,370 al 10,692 al 10,000 dth 15,000 dth 10,000 dth 10,773 al 10,773 al 19,692 GJ 15,520 GJ 2,125 7,500 dth 7,500 dth 7,568 dth 7,567 dth 7,613 al 2,125 10 8,039 al 75 mmcf 103m3 3 m 3
varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies Rate Fuel Monthly Demand Charge 831.99000 $/10 46.99600 $US/dth 12.83920 $US/dth 33.36564 VGJ 33.36564 VGJ 33.36564 $/GJ 33.36564 $/GJ 33.36564 $/al 33.36564 $/GJ 33.36564 VGJ 33.36564 $/GJ 33.36564 $/al 33.36564 $/al 33.36564 $/al 33.36564 $/G. 33.36564 $/al 4.40000 $US/dth 2.55400 $/al 2.55400 $/GJ 2.12800 $/GJ 2.50000 Wal 2.55400 Val 2.55400 $/al 2.55400 $/GJ 0.57050 $/al 7.21820 $US/dth 0.57050 $/G.1 7.21820 $US/dth 4.56300 $US/dth 0.15000 $US/dth 4.73229 $/al 4.73229 $/al 4.73229 $/al 2.12800 Val 1.52100 $US/dth 8.98300 $US/dth 9.40000 $US/dth 2.65917 Val 2.65917 VGJ 0.82333 VG.] 0.82333 VGJ 0.82333 WGJ 1.73170 $US/dth 3 m 3
Commodity Charge 0.05585 0.00001 0.00001 0.05585 0.05585 0.05585 0.05585 0.05585 0.05585 0.05585 0.05585 0.05585 0.00319 0.00319 0.00001 0.05585 0.05585 0.05585 $/al $/al $/al Val $/al $/al Val $/al Wal $/G1 $/GJ $/al $/al $/al VGJ $/GJ Val WEI Expiry Date Mar 31/04 Mar 31/06 Oct 31/15 Oct 31/15 Oct 31/15 Oct 31/15 Oct 31/05 Oct 31/06 Oct 31/06 Oct 31/07 Oct 31/07 Oct 31/07 Oct 31/07 Oct 31/07 Apr 15/04 Mar 31/03 Oct 31/15 Oct 31/15 Oct 31/06 Oct 31/05 Oct 31/04 Oct 31/03 Oct 31/03 Oct 31/03 Oct 31/03 Oct 31/12 Oct 31/11 Oct 31/10 Oct 31/10 Oct 31/09 Oct 31/05 Oct 31/03 Oct 31/09 Oct 31/03 Oct 31/03 Oct 31/03 Oct 31/03 Oct 31/07 Oct 31/06 Oct 31/05 Oct 31/10 Oct 31/04 Oct 31/03
1. 1. 0Z-£00-HH 91.-90-Z 1. 0Z loolld Contract DemandLevelsandTollseffectiveNovember1,2003 Item # TCPL FT-CDA TCPL FT-EDA TCPL FT-EDA TCPL FT-CDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-Iroquois TCPL FT-Iroquois TCPL FT-EDA TCPL FT-DawntoEDA TCPL FT-DawntoCDA TCPL FT-DawntoCDA TCPL STSParkwaytoCDA TCPL STSParkwaytoCDA TCPL STSKirkwall/ParkwaytoEDA TCPL STSKirkwall/ParkwaytoEDA TCPL STSParkwaytoCDA ANR Transportation ANR Transportation ANR Transportation TCPL STSParkwaytoEDA ANR Transportation Vector Pipeline- Alliance Pipeline Nova Transmission Nova Transmission Vector Pipeline Niagara GasTransmission Michcon Transportation Michcon Transportation Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoKirkwall Union GasParkwaytoDawn-Cl Union GasDawntoParkway Union GasDawntoKirkwall Union GasDawntoParkway/Kirkwall/Lisgar Union GasDawntoParkway Transportation Empress toCDA Empress toEDA Empress toEDA Empress toCDA Empress toEDA Empress toEDA Empress toEDA Empress toIroquois Empress toIroquois Empress toEDA Empress toEDA AECO toEmpress AECO toEmpress Willow toColumbus Corunna ColumbusLink Corunna ColumbusLink SE HeadstationtoWillowRt SW HeadstationtoWillowR Alliance toSt.Clair Chicago toCdnborder Alberta toUSborder Cortmna toTecumseh St. ClairtoDawn Cdn bordertoDawn Chicago toCdnborder Cdn bordertoDawn US bordertoChicago Kalkaska toColumbus Route Daily Volume Contracted 1,764,678 153,700 114,000 145,000 142,000 101,285 149,818 804,617 107,000 70,000 21,584 32,357 28,650 27,643 26,952 15,000 35,806 37,370 10,773 10,773 19,692 28,833 35,089 92,822 96,000 15,000 10,000 83,349 79,000 10,000 35,806 20,848 32,123 15,000 37,400 53,455 10,692 7,613 4,818 7,568 7,567 8,039 9,716 2,125 2,125 75 al al al al al al al al al al al al al dth al al al al al al dth dth al dth dth dth Gi al al dth al dth rnmcf 10 10 GJ Dth al al al al al al al al al 3 3 m m 3 3
varies varies varies vva varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies v varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies Rate Fuel ar a r r i i ees ees s s
Monthly Demand Negotiated Toll Negotiated Toll Charge 827.08750 $/10 34.74741 VGJ 34.74741 VGJ 34.74741 $/G.1 34.74741 $/al 34.74741 $/G1 34.93337 VGJ 34.93337 $/al 34.74741 $/G.1 34.74741 Val 34.74741 VGJ 34.74741 Val 45.66000 $US/dth 14.05430 $US/dth 4.16603 $/al 4.16603 $/al 0.84083 Val 4.48200 $US/dth 2.74583 $/al 0.84083 Val 0.84083 Val 8.67417 $/al 2.74583 VGJ 9.98200 $US/dth 9.48200 $US/dth 4.85832 5/G1 4.85832 $/al 2.74583 $/al 7.15240 $US/dth 0.57050 Val 7.15240 $US/dth 4.56300 $US/dth 0.57050 $/al 1.52100 $US/dth 2.07400 $/al 2.49000 $/al 2.49000 $/al 2.07400 5/al 1.25380 $US/dth 2.49000 $/al 2.49000 $/GJ 2.49000 Val 2.49000 VGJ 3 m 3
Commodity Charge 0.06066 VGJ 0.06066 VGJ 0.06066 $/G1 0.06066 $/al 0.06066 Val 0.06066 VGJ 0.06066 $/al 0.06066 Val 0.00001 $/al 0.01416 5/al 0.00602 Val 0.00602 Val 0.06158 VGJ 0.06158 5/G1 0.06066 $/al 0.00345 $/al 0.00001 $/GJ 0.00345 $/GJ 0.00001 $/al 0.00345 $/al Expiry Date Oct 31/04 Mar 31/04 Oct. 31/10 Mar 31/07 Oct 31/04 Oct 31/05 Oct 31/10 Oct 31/05 Oct 31/04 Oct 31/04 Oct 31/15 Oct 31/05 Oct 31/06 Oct 31/04 Oct 31/06 Oct 31/06 Oct 31/07 Oct 31/07 Oct 31/07 Apr 15/04 Oct 31/04 Oct 31/10 Oct 31/04 Oct 31/04 Oct 31/05 Oct 31/07 Oct 31/06 Oct 31/15 Oct 31/15 Oct 31/15 Oct 31/15 Oct 31/06 Oct 31/15 Mar 31/14 Oct 31/04 Oct 31/09 Oct 31/04 Oct 31/04 Oct 31/04 Oct 31/12 Oct 31/11 Oct 31/10 Oct 31/09 Oct 31/05
1, 1, 0Z-000-1-1?:1 91. -90-Z 1. 0Z :pond Contract Demand Levels and Tolls effective November 1, 2004
Contracted Fuel Monthly Commodity Item # Transportation Route Daily Volume Rate Demand Charge Charge Expiry Date TCPL FT -CDA Empress to CDA 47,200 G.1 varies 34.47970 $/G1 0.05552 $/G1 Oct 31/05 TCPL FT -EDA Empress to EDA 32,357 G1 varies 34.47970 $/G1 0.05552 Wal Oct 31/05 TCPL FT -EDA Empress to EDA 21,584 G1 varies 34.47970 $/G1 0.05552 $/G1 Oct 31/05 TCPL FT -EDA Empress to EDA 7,613 G.I varies 34.47970 $/G.1 0.05552 $/G1 Oct 31/05 TCPL FT -EDA Empress to EDA 19,692 GI varies 34.47970 WO 0.05552 $/al Oct 31/10 TCPL FT -EDA Empress to EDA 10,773 GI varies 34.47970 5/G1 0.05552 We Oct 31/05 TCPL FT -EDA Empress to EDA 10,773 G.I varies 34.47970 $/al 0.05552 $/G1 Oct 31/06 TCPL FT -EDA Empress to EDA 26,952 GI varies 34.47970 $/al 0.05552 $/G1 Oct 31/07 TCPL FT -Iroquois Empress to Iroquois 27,643 G.I varies 33.87323 WGI 0.05452 VG! Mar 31/07 TCPL FT -Iroquois Empress to Iroquois 28,650 G.I varies 33.87323 $/G1 0.05452 Val Oct 31/05 TCPL FT -Dawn to CDA 145,000 G.I varies 4.40572 Val 0.00543 Val Oct 31/05 TCPL FT -Dawn to CDA 4,818 GI varies 4.40572 WO 0.00543 $/GJ Oct 31/05 TCPL FT -Dawn to EDA 114,000 GI varies 8.63713 $/G1 0.01257 $/al Oct 31/10 TCPL STS Parkway to CDA 153,700 G.1 varies 1.13333 Val 0.00004 WG.1 Oct 31/05 TCPL STS Parkway to CDA 37,370 al varies 1.13333 $/G1 0.00004 Val Oct 31/05 TCPL STS Parkway to CDA 92,822 G.I varies 1.13333 $/al 0.00004 $/G.1 Oct 31/05 TCPL STS Kirkwall/Parkway to EDA 35,806 G.I varies 2.94500 $/GJ 0.00306 $/G1 Oct 31/05 TCPL STS Kirkwall/Parkway to EDA 35,089 G.1 varies 2.94500 WO 0.00306 $/G1 Apr 15/04 TCPL STS Parkway to EDA 9,716 G1 varies 2.94500 $/GJ 0.00306 $/G1 Oct 31/05 Nova Transmission AECO to Empress 8,039 G1 varies 4.99894 5/GI Oct 31/09 Nova Transmission AECO to Empress 28,833 al varies 4.99894 Val Oct 31/07 ANR Transportation SW Headstation to Willow Run 7,567 dth varies 9.48200 $uS/dth Oct 31/07 ANR Transportation Corunna Columbus Link 10,000 dth varies 4.25000 $uS/dth Oct 31/06 ANR Transportation SE Headstation to Willow Run 7,568 dth varies 9.98200 $US/dth Oct 31/06 ANR Transportation Corunna Columbus Link 15,000 dth varies 1.25380 $US/dth Oct 31/06 Michcon Transportation Willow to Columbus 15,000 dth varies 1.52100 $US/dth Oct 31/06 Michcon Transportation Kalkaska to Columbus 10,000 dth varies 4.56300 $tiS/dth Oct 31/06 Niagara Gas Transmission Corunna to Tecumseh 2,125 1030 varies 45.66000 VG Oct 31/05 Alliance Pipeline Alberta to US border 2,125 103m3 varies 862.10460 $/103m3 Oct 31/15 US border to Chicago 75 mmcf varies 14.67670 $US/dth Oct 31/15 Vector Pipeline - Chicago to Cdn border 96,000 dth varies 7.25280 $US/dth Oct 31/15 Cdn border to Dawn 101,285 G1 varies 0.40730 $/al Oct 31/15 Vector Pipeline Chicago to Cdn border 79,000 dth varies 7.25280 $uVdth Oct 31/15 Cdn border to Dawn 83,349 G.1 varies 0.40730 $/G1 Oct 31/15 Alliance to St. Clair 142,000 Dth varies Negotiated Toll Oct 31/04 St. Clair to Dawn 149,818 GJ varies Negotiated Toll Oct 31/05 Union Gas Dawn to Kirkwall 32,123 al varies 1.96800 Val Mar 31/14 Union Gas Dawn to Parkway 1,764,678 al varies 2.33400 $/al Union Gas Dawn to Parkway 10,692 G.I varies 2.33400 Val Oct 31/05 Union Gas Dawn to Parkway 53,455 G.1 varies 2.33400 Wai Oct 31/09 Union Gas Dawn to Parkway/Kirkwall/Lisgar 20,848 G.1 varies 2.33400 $/G1 Oct 31/10 Union Gas Dawn to Kirkwall 35,806 G1 varies 1.96800 $/G1 Oct 31/10 Union Gas Dawn to Parkway 107,000 G1 varies 2.33400 Val Oct 31/11 Union Gas Dawn to Parkway 37,400 GI varies 2.33400 We Oct 31/12 Union Gas Parkway to Dawn - Cl 600,000 G1 Mar 31/06 Contract DemandLevelsandToll;effectiveNovember1,2005 Item # TCPL FT-CDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-CDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-DawntoEDA TCPL FT-DawntoCDA TCPL FT-DawntoCDA TCPL FT-Iroquois TCPL FT-Iroquois TCPL STSParkwaytoCDA TCPL STSParkwaytoCDA TCPL STSParkwaytoEDA TCPL STSKirkwall/ParkwaytoEDA TCPL STSKirkwall/ParkwaytoEDA TCPL STSParkwaytoCDA ANR Transportation ANR Transportation ANR Transportation ANR Transportation Alliance Pipeline Michcon Transportation Nova Transmission Nova Transmission Michcon Transportation Vector Pipeline- Niagara GasTransmission Vector Pipeline Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoKirkwall Union GasDawntoParkway Union GasDawntoKirkwall Union GasDawntoParkway/Kirkwall/Lisgar Union GasDawntoParkway Union GasParkway to Dawn-Cl Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoParkway Transportation Empress toCDA Empress toCDA Empress toEDA Empress toEDA Empress toEDA Empress Empress toEDA Empress toIroquois Empress toIroquois Empress toEDA Empress toEDA AECO toEmpress AECO toEmpress Willow toColumbus/BelleRix SW HeadstationtoWillowRI SE HeadstationtoWillowRu Corunna ColumbusLink Alberta toUSborder Corunna toTecumseh Kalkaska toColumbus/Belle Corunna ColumbusLink Cdn bordertoDawn Chicago toCdnborder Alliance toSt.Clair Chicago toCdnborder US bordertoChicago Cdn bordertoDawn St. ClairtoDawn to Route EDA Daily Volume Contracted 1,764,678 145,000 al 153,700 al 114,000 101,285 al 600,000 al 106,000 al 149,818 GJ 142,000 Dth 107,000 GI 47,200 GJ 21,584 al 32,357 al 15,000 GI 28,833 al 28,650 al 27,643 al 26,952 GI 37,370 al 10,773 GJ 10,773 al 19,692 al 35,089 al 35,806 al 92,822 al 96,000 dth 83,349 al 79,000 dth 10,000 15,000 dth 10,000 dth 15,000 dth 37,400 al 32,123 al 57,100 al 35,806 20,848 53,455 10,692 al 7,613 GJ 4,818 al 8,039 al 7,568 9,716 GI 2,125 10 7,567 dth 2,125 75 al dth dth mmcf 10 GI al al al 3 3 m
m 3 3
varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies Rate varies varies varies varies varies varies varies varies Fuel varies varies varies varies varies varies varies varies varies varies Monthly Demand Negotiated Toll Negotiated Toll Charge 888.67000 28.84047 28.84047 5/al 28.84047 28.84047 28.84047 28.85681 28.84047 28.84047 28.84047 28.84047 28.85681 46.34800 15.06350 3.73634 00 0.96333 5/al 7.35015 3.73634 4.59246 4.59246 2.52333 2.52333 2.52333 4.56300 1.52100 7.06910 4.17000 0.57791 0.57050 9.48200 9.98200 2.33400 2.33400 0.57050 2.33400 2.33400 2.33400 1.96800 2.50000 2.33400 1.25380 1.96800 2.50000 .. 99 66 333333 5/51 Val 5/GI 5/al $/al Val $/al Val $/al $/al $/al 5/G1 Val 5/al 55 5/G1 SUS/dth SUS/dth WSJ 5/al 5/al $US/dth $US/dth $us/dth 5/10 $/10 SUS/dth $/al $US/dth $us/dth 5/al SUS/dth $/al $/al Val 5/GI Val $/al $/al $/al 5/G1 5/al / GG .1.1 3 3 m m 3 3
Commodity Charge 0.04934 $/al 0.04934 $/al 0.04934 5/al 0.04934 $/al 0.04934 WEI 0.04940 Val 0.04934 5/al 0.04934 $/al 0.04934 Val 0.00486 S/G1 0.01137 $/al 0.00486 $/al 0.04940 $/al 0.04934 Val 0.00281 Val 0.00281 5/al 0.00005 $/al 0.00005 5/al 0.00005 $/al 0.00281 5/al Expiry Date Oct Oct 31/07 Oct 31/06 Oct 31/06 Oct 31/06 oct 31/06 Oct Mar 31/07 Oct 31/07 Oct 31/07 Oct 31/07 Oct 31/06 Oct 31/06 Oct 31/06 Oct 31/07 Oct 31/10 Oct 31/07 Oct 31/07 Oct 31/15 Oct 31/15 Oct 31/06 Oct 31/06 Oct 31/06 Mar 31/06 Oct 31/07 Oct 31/07 Oct 31/07 Oct 31/07 Oct 31/07 Oct 31/15 oct 31/15 oct 31/15 Oct 31/15 Oct 31/09 Oct 31/07 Oct 31/10 Oct 31/06 Oct Oct 31/11 Oct 31/10 Oct 31/10 Oct 31/09 Oct 31/07 Oct 31/12 Oct 31/12 Oct 31/12 Oct 31/19 Oct 31/18 31/06 31/06 31/06
L L OZ-£00-H2:1 91, -90-Z L OZ :10el!d
Contract Demand Levels and Tolls effective November 1, 2006
Contracted Fuel Monthly Commodity Item 4 Transportation Route Daily Volume Rate Demand Charge Charge Expiry Date TCPL FT -CDA Empress to CDA 47,200 al varies 26.47419 Val 0.06464 Val Oct 31/07 TCPL FT -CDA Empress to CDA 15,000 El varies 26.47419 Val 0.06464 Val Oct 31/07 TCPL FT -EDA Empress to EDA 32,357 al varies 26.47419 Val 0.06464 Val Oct 31/07 TCPL FT -EDA Empress to EDA 21,584 al varies 26.47419 Val 0.06464 Val Oct 31/07 TCPL FT -EDA Empress to EDA 7,613 Gl varies 26.47419 Val 0.06464 Val Oct 31/07 TCPL FT -EDA Empress to EDA 19,692 al varies 26.47419 Val 0.06464 Val Oct 31/10 TCPL FT -EDA Empress to EDA 10,733 GJ varies 26.47419 Val 0.06464 Val Oct 31/07 TCPL FT -EDA Empress to EDA 10,733 al varies 26.47419 Val 0.06464 Val Oct 31/07 TCPL FT -EDA Empress to EDA 26,952 al varies 26.47419 Val 0.06464 Val Oct 31/07 TCPL FT -Iroquois Empress to Iroquois 27,643 al varies 26.26804 Val 0.06421 VGJ Oct 31/08 TCPL FT -Iroquois Empress to Iroquois 28,650 al varies 26.26804 Val 0.06421 Val Oct 31/07 TCPL FT -Dawn to CDA 145,000 al varies 3.46353 Val 0.00640 Val Oct 31/07 TCPL FT -Dawn to CDA 4,818 al varies 3.46353 Val 0.00640 Val Oct 31/07 TCPL FT -Dawn to EDA 114,000 al varies 6.74971 Val 0.01481 Val Oct 31/10 TCPL FT -EDA Empress to EDA 7,418 al varies 26.47419 Val 0.06464 Val May 04/08 TCPL STS Partway to CDA 153,700 GJ varies 0.96583 Val 0.00012 Val Oct 31/07 TCPL STS Parkway to CDA 37,370 al varies 0.96583 Val 0.00012 Val Oct 31/07 TCPL STS Parkway to CDA 92,822 al varies 0.96583 Val 0.00012 Val Oct 31/07 TCPL STS Kirkwall/Parkway to EDA 35,806 al varies 2.34333 Val 0.00361 Val Oct 31/07 TCPL STS Kirkwall/Parkway to EDA 35,089 al varies 2.34333 VG./ 0.00361 Val Oct 31/07 TCPL STS Parkway to EDA 9,716 al varies 2.34333 VG! 0.00361 Val Oct 31/07 Nova Transmission AECO to Empress 8,039 GJ varies 3.75219 VGJ Oct 31/09 Nova Transmission AECO to Empress 28,833 G1 varies 3.75219 Val Oct 31/07 ANR Transportation SE Headstation to Willow Fti 2,523 dth varies 9.98200 $US/dth Oct 31/07 ANR Transportation SW Headstation to Willow R 7,567 dth varies 9.48200 $US/dth Oct 31/07 ANR Transportation Corunna Columbus Link 5,000 dth varies 1.25380 $US/dth Oct 31/07 ANR Transportation Corunna Columbus Link 2,442 dth varies 1.06460 $US/dth Oct 31/07 Michcon Transportation Willow to Columbus/Belle Ri 7,461 dth varies 1.52100 $US/dth Oct 31/07 Niagara Gas Transmission Corunna to Tecumseh 208 103m3 varies 45.22100 5/103m3 Oct 31/07 Alliance Pipeline Alberta to US border 2,125 103m3 varies 794.90050 $/103m3 Oct 31/15 US border to Chicago 75 mmcf varies 15.35450 SUS/dth Oct 31/15 Vector Pipeline - Chicago to Cdn border 96,000 dth varies 7.07220 $US/dth Oct 31/15 Cdn border to Dawn 101,285 al varies 0.57050 Val Oct 31/15 Vector Pipeline Chicago to Cdn border 79,000 dth varies 6.69160 $1.15/dth Oct 31/15 Cdn border to Dawn 83,349 al varies 057050 5/G3 Oct 31/15 Vector Pipeline Alliance to St. Clair 142,000 Dth varies Negotiated Toll Oct 31/07 St. Clair to Dawn 149,818 GJ varies Negotiated Toll Oct 31/07 Union Gas Dawn to Kirkwall 32,123 al varies 1.96800 Val Oct 31/12 Union Gas Dawn to Parkway 1,764,678 al varies 2.33400 Val Oct 31/12 Union Gas Dawn to Parkway 10,692 al varies 2.33400 Val Oct 31/07 Union Gas Dawn to Partway 53,455 al varies 2.33400 Val Oct 31/09 Union Gas Dawn to Parkway/Kirkwall/Lisgar 20,848 al varies 2.33400 VGJ Oct 31/10 Union Gas Dawn to Kirkwall 35,806 al varies 1.96800 Val Oct 31/10 Union Gas Dawn to Parkway 107,000 al varies 2.33400 Val Oct 31/11 Union Gas Dawn to Parkway 37,400 al varies 2.33400 Val Oct 31/12 Union Gas Dawn to Parkway 106,000 G1 varies 2.33400 Val Oct 31/18 Union Gas Dawn to Parkway 57,100 al varies 2.33400 Val Oct 31/19 Union Gas Parkway to Dawn - Cl 436,586 al Val Mar 31/16 Union Gas Parkway to Dawn - Cl 75,000 GJ Mar 31/08 Union Gas Parkway to Dawn - Cl 45,000 GJ Val Mar 31/09 Union Gas Parkway to Dawn - Cl 39,450 GI VGJ Mar 31/10 Contract DemandLevelsandTollseffectiveNovember1,2007 Item # TCPL FT-EDA TCPL FT-EDA TCPL FT-CDA TCPL FT-CDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-Iroquois TCPL FT-Iroquois TCPL FT-Iroquois TCPL FT-EDA TCPL FT-EDA TCPL FT-DawntoEDA TCPL FT-DawntoCDA TCPL FT-DawntoCDA TCPL FTNR-ParkwaytoCDA TCPL STSParkwaytoCDA TCPL STSParkwaytoCDA TCPL STSParkwaytoCDA ANR Transportation TCPL STSParkwaytoEDA TCPL STSKirkwall/ParkwaytoEDA TCPL STSKirkwall/ParkwaytoEDA ANR Transportation ANR Transportation ANR Transportation Vector Pipeline- Alliance Pipeline Nova Transmission Vector Pipeline Vector Pipeline Niagara GasTransmission Michcon Transportation Nova Transmission Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoKirkwall Union GasDawntoParkway Union GasDawntoKirkwall Union GasDawntoParkway/Kirkwall/Lisgar Union GasParkwayto Dawn-Cl Union GasParkwaytoDawn-Cl Union GasParkwaytoDawn-Cl Union GasParkwaytoDawn-Cl Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoParkway Transportation Empress toCDA Empress toCDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toIroquois Empress toIroquois Empress toIroquois AECO toEmpress AECO toEmpress Empress toEDA Alberta toUSborder Willow toColumbus/Belle SE HeadstationtoWillowRu Empress toEDA Alliance toSt.Clair Corunna ColumbusLink Corunna ColumbusLink SW HeadstationtoWillowRi Cdn bordertoDawn Chicago toCdnborder Cdn bordertoDawn Chicago toCdnborder Corunna toTecumseh St. ClairtoDawn US bordertoChicago Route Daily Volume Contracted 1,764,678 145,000 153,700 114,000 101,285 436,586 142,000 149,818 106,000 107,000 2,124.6 21,584 32,357 47,200 25,000 27,643 26,952 28,650 19,692 15,000 25,000 10,773 10,773 35,806 45,455 92,822 37,370 25,000 35,089 28,833 96,000 20,848 83,349 79,000 32,123 45,000 35,806 53,455 39,450 75,000 57,100 37,400 10,692 7,613 4,818 7,418 7,567 2,523 9,716 208.3 7,461 2,442 dth 5,000 8,039 75 61 61 G1 G1 al 61 61 61 al G1 al 61 G1 61 G1 G1 G1 61 al al 61 G1 G1 al al dth dth 61 61 61 dth dth 61 dth dth lO mmcf 10 61 61 al 61 61 G1 G1 Dth 61 GJ 61 61 G1 al 61 61 s 3 m m a 3
varies varies varies varies varies varies varies varies varies varies varies varies varies varies ais 1.10000 varies varies varies varies varies varies varies varies varies varies varies xrries varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies Rate varies varies Fuel Demand Charge Negotiated Toll Negotiated Toll Monthly 833.87240 29.12790 29.12790 29.12790 29.12790 29.12790 29.12790 29.12790 29.12790 28.44322 29.12790 29.12790 28.44322 28.44322 29.12790 29.12790 46.99600 15.48640 3.71821 4.18000 4.18000 7.36364 3.71821 9.48200 9.98200 2.55667 2.55667 2.55667 1.10000 1.10000 7.10870 1.75011 0.57050 7.10870 0.57050 1.52100 $LIS/dth 1.25380 1.25380 2.03600 2.03600 2.03600 2.39200 2.39200 2.39200 2.39200 2.03600 2.39200 2.39200 - 5/61 $/61 5/61 Val 5/61 $/61 $/61 $/61 $/61 5/61 $/61 5/61 5/61 $/61 5/61 5/61 Val Val 5/61 $/G1 $US/dth $/61 $/61 5/61 $/al $/61 5/61 $US/dth 5U5/dth 51J5/dth 5/61 5/61 $US/dth 5/61 5US/dth 5/10 $US/dth $/10 5/61 $/al 5/61 5/61 $/61 5/61 $/61 5/G1 5/61 $/61 5/61 $/61 $/61 5/61 3 3 m m 2 3
Commodity Charge 0.07269 0.07269 0.07269 0.07269 0.07269 0.07269 0.07269 0.07269 0.07269 0.07097 0.07097 0.07269 .79 $/61 0.07097 0.07269 0.01635 0.00687 0.00687 .09 5/61 0.00394 0.00394 .09 5/61 0.00394 0.00176 0.00010 0.00010 0.00010 0.07269 - $/61 5/61 5/61 5/61 $/al 5/G1 5/G1 5/61 5/61 Val 5/61 $/al 5/61 $/al 5/61 $/al $/al $/al $/61 $/61 $/6.1 $US/dth $US/dth $US/dth $115/dth /1 Oct31/09 5/G1 5/61 Val Val 5/61 $US/dth 5U5/dth U/t Oct31/15 $US/dth $/lO $US/dth ' s m a
Expiry Date May 31/08 May 04/08 Mar 31/08 Oct 31/08 Oct 31/08 Oct 31/08 Oct 31/08 Apr 01/09 Oct 31/08 Oct 31/08 Oct 31/08 Oct 31/10 Oct 31/08 Oct 31/08 Oct 31/13 Oct 31/08 Oct 31/10 Oct 31/08 Oct 31/08 Oct. 31/19 Oct. 31/18 Oct 31/12 Oct. 31/11 Oct 31/10 Oct. 31/10 Oct. 31/09 Oct 31/09 Oct 31/08 Oct 31/08 Oct 31/08 OCt 31/08 Mar 31/09 Oct 31/15 Oct 31/15 Oct 31/15 Oct 31/07 Oct 31/07 Oct 31/07 Oct 31/07 Oct 31/15 Oct 31/07 Oct 31/08 Oct 31/08 Oct 31/08 Mar 31/10 Mar 31/08 Mar 31/16 Oct 31/15 Oct 31/07 Oct 31/08 Oct 31/12 Oct 31/08 Oct 31/12
I- 1. 0Z-£00-1-Pd 91, -90-Z 1. 0Z Tepd Contract DemandLevelsandTollseffectiveNovember1,2008 Item # TCPL FT-CDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-CDA TCPL FT-EDA TCPL FT-Iroquois TCPL FT-Iroquois TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL STSParkwaytoEDA TCPL STSKirkwall/ParkwaytoEDA TCPL STSParkwaytoCDA TCPL STSParkwaytoCDA TCPL STSParkwaytoCDA TCPL STSParkwaytoCDA TCPL FT-DawntoEDA TCPL FT-DawntoCDA TCPL FT-DawntoCDA TCPL FTSNParkwaytoCDA TCPL STSKirkwall/ParkwaytoEDA Vector Pipeline Vector Pipeline- Alliance Pipeline Vector Pipeline Nova Transmission Nova Transmission Union GasDawntoParkway/Kirkwall/Lisgar Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoKirkwall Union GasParkway toDawn-Cl Union GasParkwaytoDawn Union GasParkwaytoDawn Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoKirkwall Transportation Cl Cl Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toCDA Empress toCDA Alliance toSt.Clair Empress toEDA Empress toIroquois Empress toIroquois Empress toEDA Empress toEDA Empress toEDA Alberta toUSborder AECO toEmpress AECO toEmpress St ClairtoDawn Cdn bordertoDawn Chicago toCdnborder ****** Cdn bordertoDawn Chicago toCdnborder US bordertoChicago Route Daily Volume Contracted 1,764,678 - 2,124.6 436,586 153,700 114,000 145,000 101,285 106,000 107,000 149,818 142,000 40,093 27,643 26,952 21,584 32,357 25,000 28,650 25,000 15,000 20,848 45,000 79,000 10,773 10,773 19,692 85,000 35,089 35,806 92,822 37,370 39,450 57,100 37,400 53,455 32,123 83,349 96,000 28,833 35,806 10,692 7,613 4,818 9,716 8,036 572 75 GJ al al al El al al al al al al GJ GJ al al al G1 al al al GJ al GJ al al GJ GJ al GJ GJ al al GJ GJ al GJ al dth GJ dth 10 al G1 GJ GJ Dth mmcf 3 m 3
.varies varies varies varies varies varies varies varies varies va ries varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies va ries varies va ries varies varies varies va ries varies varies varies varies varies varies varies varies Rate Fuel Negotiated Toll Negotiated Toll Demand 922.71210 $/10 Monthly Charge 38.93622 $/G1 38.93622 $/G1 38.93622 $/GJ 38.93622 $/G1 38.93622 $/G1 38.93622 $/G1 38.93622 $/GJ 38.67452 $/al 38.67452 $/G1 38.93622 $/G1 38.93622 $/al 38.93622 $/al 38.93622 WGJ 16.39140 $US/dth 4.45 4.45 4.86708 $/al 0.57050 5/GJ 7.09730 $US/dth 9.85413 $/GJ 4.86708 $/al 0.007005/GJ 2.16907 Val 3.26250 Val 3.26250 $/GJ 3.26250 $/al 1.29667 $/al 1.29667 5/GJ 1.29667 5/GJ• 0.57050 $/al 7.09730 $US/dth 2.35400 $/al 2.35400 $/G1 2.35400 $/GJ 2.35400 5/al 2.35400 $/al 2.00400 Wal 0.54500 Wal 1.29667 $/G1 2.00400 5/al 2.00400 5/al 2.35400 VGJ 2.00400 $/al - VGJ 5/GJ 5/al $/al 3 m 3
Commodity Charge 0.12339 $/G1 0.12339 VGJ 0.12339 VGJ 0.12339 VGJ 0.12339 WGJ 0.12339 VGJ 0.12339 $/GJ 0.12339 $/G1 0.12520 $/GJ 0.12520 $/GJ 0.12339 $/GJ 0.12339 5/al 0.12339 VGJ 0.00022 $/al 0.00022 $/G1 0.02893 Wal 0.01215 $/GJ 0.01215 $/GJ 0.00312 $/G1 0.00700 VGJ 0.00700 $/GJ 0.00022 $/GJ 0.00022 $/al ------ VGJ VGJ $/GJ $/al $US/dth $/al $US/dth $US/dth $/10 5/al 5/al $/al VGJ 5/al $/al $/al Wal WGJ $/GJ 5/GJ $/G1 3 m 3
Expiry Date Oct 31/19 Apr 01/09 Oct 31/15 Oct 31/15 Oct 31109 Oct 31/10 Oct 31/09 Oct 31/09 Oct 31/09 Oct 31/09. Oct 31/09 Oct 31/15 Oct 31/15 Oct 31/15 Oct 31/15 Oct 31/10 Mar 31/10 Mar 31/09 Mar 31/16 Oct 31/09 Oct 31/09 Oct 31/13 Oct 31/09 Oct 31/09 Oct 31/09 Oct 31/09 Oct 31/09 Oct 31/09 Oct 31/10 Oct 31/09 Oct 31/09 Oct 31/09 Oct 31/09 Oct 31/09 Oct 31110 Oct 31/18 Oct 31/11 Oct 31/10 Oct 31/10 Oct 31/09 Oct 31/08 Oct 31/12 Oct 31/12 Oct 31/09 Oct 31/09 Oct 31/12 Nov 1/18
I. 1, 0Z-000-1-P21 91, -90-Z1. 0Z :1091!J
Contract Demand Levels and Tolls effective November 1, 2009
Contracted Fuel Monthly Commodity Item # Transportation Route Daily Volume Rate Demand Charge Charge Expiry Date TCPL FT -CDA Empress to CDA 40,093 al varies 33.37571 Val 0.09272 $/al Oct 31/10 TCPL FT -CDA Empress to CDA 15,000 GJ varies 33.37571 $/GJ 0.09272 $/al Oct 31/10 TCPL FT -CDA Empress to CDA 25,000 al varies 33.37571 $/al 0.09272 Val Oct 31/10 TCPL FT -EDA Empress to EDA 32,357 al varies 33.37571 $/GJ 0.09272 $/GJ Oct 31/10 TCPL FT -EDA Empress to EDA 21,584 al varies 33.37571 $/al 0.09272 $/GJ Oct 31/10 TCPL FT -EDA Empress to EDA 7,613 al varies 33.37571 $/GJ 0.09272 VGJ Oct 31/10 TCPL FT -EDA Empress to EDA 19,692 GJ varies 33.37571 VGJ 0.09272 $/al Oct 31/10 TCPL FT -EDA Empress to EDA 10,773 al varies 33.37571 VGJ 0.09272 Val Oct 31/10 TCPL FT -EDA Empress to EDA 10,773 GJ varies 33.37571 $/al 0.09272 VGJ Oct 31/10 TCPL FT -EDA Empress to EDA 26,952 GJ varies 33.37571 VGJ 0.09272 VGJ Oct 31/10 TCPL FT -EDA Empress to EDA 25,000 al varies 33.37571 $IGJ 0.09272 VGJ Oct 31/13 TCPL FT -EDA Empress to EDA 56,293 GJ varies 33.37571 VGJ 0.09272 $/al Oct 31/10 TCPL FT -Iroquois Empress to Iroquois 27,643 al varies 32.51411 $/GJ 0.09019 $/GJ Oct 31/09 TCPL FT -Iroquois Empress to Iroquois 28,650 GJ varies 32.51411 $/al 0.09019 WGJ Oct 31/09 TCPL STFT-CDA (Jan - Feb) Empress to CDA 50,000 GJ va ries 33.37571 Val 0.09272 VGJ Feb 28/10 TCPL STFT-EDA (Jan - Feb) Empress to EDA 25,000 al varies 33.37571 $/GJ 0.09272 Val Feb 28/10 TCPL STS Parkway to CDA 153,700 al varies 0.93583 Wal 0.00015 $/GJ Oct 31/10 TCPL STS Parkway to CDA 37,370 al varies 0.93583 $/al 0.00015 $/GJ Oct 31/10 TCPL STS Parkway to CDA 92,822 al varies 0.93583 $/GJ 0.00015 VGJ Oct 31/10 TCPL STS Parkway to CDA 572 GJ varies 0.93583 $/al 0.00015 WEI Oct 31/10 TCPL STS Kirkwall/Parkway to EDA 35,806 GJ varies 2.58833 Val 0.00499 VGJ Oct 31/10 TCPL STS Kirkwall/Parkway to EDA 35,089 al varies 2.58833 VGJ 0.00499 $/GJ Oct 31/10 TCPL STS Parkway to EDA 9,716 GJ varies 2.58833 VGJ 0.00499 $/GJ Oct 31/10 TCPL FT SN Parkway to CDA 85,000 GJ varies 1.69666 $/GJ 0.00209 $/GJ Jun 30/2011 TCPL FT -Dawn to CDA 145,000 GJ varies 3.98389 WGJ 0.00880 VGJ Oct 31/10 TCPL FT -Dawn to CDA 4,818 al va ries 3.98389 $/al 0.00880 VGJ Oct 31/10 TCPL FT -Dawn to EDA 114,000 al va ries 8.17713 VGJ 0.02087 $/GJ Oct 31/10 Nova Transmission AECO to Empress 8,036 al varies 4.87000 Val - Val Oct 31/10 Nova Transmission AECO to Empress 28,833 GJ varies 4.87000 $/GJ - VGJ Oct 31/10 Alliance Pipeline Alberta to US border 2,124.6 103m3 varies 926.54020 $/103m3 - $/103m3 Oct 31/15 US border to Chicago 75 mmcf varies 16.01200 $US/dth - SUS/dth Oct 31/15 Vector Pipeline - Chicago to Cdn border 96,000 dth varies 7.02720 $US/dth $US/dth Oct 31/15 Cdn border to Dawn 101,285 al varies 0.57050 VGJ $/GJ Oct 31/15 Vector Pipeline Chicago to Cdn border 79,000 dth varies 7.02720 $US/dth - $US/dth Oct 31/15 Cdn border to Dawn 83,349 al varies 0.57050 $/al WEI Oct 31/15 Vector Pipeline Alliance to St. Clair 142,000 Dth varies Negotiated Toll Val Oct 31/10 St Clair to Dawn 149,818 GJ varies Negotiated Toll $/al Oct 31/10 Union Gas Dawn to Kirkwall 32,123 al varies 2.00700 $/GJ - $/GJ Nov. 1/14 Union Gas Dawn to Parkway 1,764,678 al varies 2.35800 Val $/al Nov. 1/14 Union Gas Dawn to Parkway 10,692 al varies 2.35800 $/GJ $/GJ Oct. 31/10 Union Gas Dawn to Parkway 53,455 GJ varies 2.35800 $/GJ $/al Oct. 31/09 Union Gas Dawn to Parkway/Kirkwall/Lisgar 20,848 GJ varies 2.35800 $/GJ - WO Oct. 31/10 Union Gas Dawn to Kirkwall 35,806 al varies 2.00700 $/GJ - $/al Oct. 31/10 Union Gas Dawn to Parkway 107,000 al varies 2.35800 Val $/GJ Oct. 31/11 Union Gas Dawn to Parkway 37,400 al varies 235800 $/GJ - S/G-I Oct 31/12 Union Gas Dawn to Parkway 106,000 al varies 2.35800 Val - $/GJ Oct 31/18 Union Gas Dawn to Parkway 57,100 al varies 2.35800 $/al WEI Oct. 31/19 Union Gas Parkway to Dawn 436,586 al varies 0.54600 $/GJ $/al Mar 31/14 Contract DemandLevelsandTollseffectiveNovember1,2010 Item # TCPL FT-CDA TCPL FT-CDA TCPL FT-EDA TCPL FT-EDA TCPL FT-CDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL FT-EDA TCPL STSParkwaytoCDA TCPL STFT-EDA(December-February)EmpresstoEDA TCPL STFT-CDA(December-February)EmpresstoCDA TCPL STFT-CDA(November-March) TCPL STSKirkwall/ParkwaytoEDA TCPL STSParkwaytoCDA TCPL STSParkwaytoCDA TCPL FT-ParkwaytoCDA TCPL FTSN-ParkwaytoCDA TCPL STSParkwaytoEDA TCPL STSKirkwall/ParkwaytoEDA TCPL FT-Dawntolnoquois TCPL FT-DawntoEDA TCPL FT-DawntoCDA TCPL FT-DawntoCDA Alliance Pipeline Nova Transmission Nova Transmission Vector Pipeline- Vector Pipeline Vector Pipeline Vector Pipeline Vector Pipeline Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoKirkwall Union GasParkwayto Dawn Union GasDawntoParkway/Kirkwall/Lisgar Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoParkway Union GasDawntoParkway/Kirkwall/Lisgar Union GasDawntoKirkwall Transportation Empress toEDA Empress toEDA Empress toCDA Empress toCDA Empress toCDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toEDA Empress toCDA Empress toEDA AECO toEmpress AECO toEmpress Alberta toUSborder Alliance toSt.Clair Alliance toSt.Clair Alliance toSt.Clair US bordertoChicago Chicago toCdnborder Cdn bordertoDawn Chicago toCdnborder Cdn bordertoDawn St. ClairtoDawn St. ClairtoDawn St ClairtoDawn Route Daily Volume Contracted 1,764,678 101,285 153,700 150,000 200,000 114,000 145,000 106,000 436,586 107,000 2,124.6 40,093 32,357 21,584 42,226 26,952 15,000 37,370 50,000 50,000 28,833 25,000 10,773 19,692 96,000 35,806 92,822 85,000 35,089 10,773 79,000 83,349 40,000 52,753 57,100 37,400 50,000 32,123 50,000 50,000 52,753 35,806 20,848 53,455 52,753 10,692 8,375 7,613 8,036 4,818 9,716 572 75 GJ al al GJ al al al al al GJ al al GJ al al al al al al al al al al al al al al al al mmcf dth al dth 10 al GJ Dth Dth GJ al al al al al al Dth GJ al al al GJ al G1 3 m 3
varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies varies NegotiatedToll varies varies varies varies varies varies varies varies varies varies varies varies varies varies Rate Fuel .
Demand Charge Negotiated Toll Negotiated Toll Negotiated Toll Negotiated Toll Negotiated Toll Monthly 960.28620 47.77094 47.77094 47.77094 47.77094 47.77094 47.77094 47.77094 47.77094 47.77094 47.77094 47.77094 47.77094 47.77094 47.77094 47.77094 10.82669 11.46271 6500 $US/dth 16.50000 1.17750 3.52250 1.17750 2.23781 3.52250 3.52250 1.17750 5.46696 5.46696 2.22307 6.03000 7.01040 0.57050 6.03000 .14 5U5/dth 7.01040 0.57050 2.36600 2.36600 2.36600 2.01400 0.55100 2.01400 2.36600 2.36600 2.36600 2.36600 2.36600 2.36600 $/al 5/al 5/al 5/al $/al 5/al 5/al 5/al 5/al 5/al $/al 5/al 5/al 5/al 5/al Wal 5/GJ Val 5/G1 Val 5/al 5/al 5/al 5/al $/al 5/al 5/al Wal 5/al 5/10 5U5/dth 5/G1 5/al Val 5/al 5/al $/al $/5.1 5/al 5/al 5/al 5/al 5/al 5/al 5/al 3 m 3
Commodity Charge 0.06753 0.06753 0.06753 0.06753 0.06753 0.06753 0.06753 0.06753 0.06753 0.06753 0.06753 0.06753 0.00012 0.06753 0.00363 0.00012 0.00012 0.06753 0.06753 0.00363 0.01509 0.00630 0.00630 0.00159 0.00152 0,00363 0.01413 - - - - - 5/al $/G1 5/al 5/al 5/al 5/al 5/al 5/al 5/al 5/al $/G1 $/0 5/al 5/al 5/al $/al 5/al 5/al 5/al 5/al 5/al $/al 5/al 5/al $/al 5/GJ $/al 5/al 5US/dth $1.1S/dth 5US/dth 5/al 5/10 5/al $/al Val 5/al 5/al Val 5/al 5/al 5/al WSJ Wal Val 5/al 5/al 3 m 3
Expiry Date Mar 31/11 Oct 31/11 Oct 31/11 Mar 31/12 Oct 31/11 Oct 31/11 Oct 31/11 Oct 31/11 Oct 31/11 Oct 31/11 Oct 31/11 Oct 31/11 Oct 31/11 Oct 31/11 Feb 28/11 Oct 31/11 Oct 31/11 Oct 31/11 Feb 28/11 Oct 31/11 Oct 31/11 Oct 31/11 Oct 31/13 Oct 31/11 Oct 31/12 Oct 31/15 Oct 31/11 Oct 31/15 Oct 31/15 Oct 31/15 Oct 31/15 Oct 31/15 Oct. 31/11 Oct. 31/11 Oct. 31/11 Oct. 31/11 Oct. 31/12 Oct. 31/19 Oct. 31/18 Oct. 31/11 Oct 31/13 Mar 31/14 Mar 31/14 Jun 30/11 Mar 31/14 Oct 31/12 Oct 31/13 Oct 31/13 Oct 31115 Oct 31/21 Oct 31/15 Oct 31/15 Oct 31/15
Z1. 10 LI. abed
L 1. 0Z-COO-H2:1 91. -90-ZL OZ :PHA
Contract Demand Levels and Tolls effective November 1, 2011
Monthly Contracted Fuel Demand Commodity Itern # Transportation Route Daily Volume Rate Charge Charge Expiry Date TCPL FT -CDA Empress to CDA 40,093 al Varies 63.84842 $/al 0.14377 $/al Oct 31/12 TCPL FT -CDA Empress to CDA 15,000 al Varies 63.84842 WSJ 0.14377 $/al Oct 31/12 TCPL FT -CDA Empress to CDA 8,375 al Varies 63.84842 $/al 0.14377 $/al Oct 31/12 TCPL FT -EDA Empress to EDA 32,357 al Varies 63.84842 $/al 0.14377 $/al Oct 31/12 TCPL FT -EDA Empress to EDA 21584 GJ Varies 63.84842 Val 0.14377 $/GI Oct 31/12 TCPL FT -EDA Empress to EDA - 7,613 GJ Varies 63.84842 $/GJ 0.14377 $/al Oct 31/12 TCPL FT -EDA Empress to EDA 19,692 al Varies 63.84842 Val 0.14377 $/al Oct 31/12 TCPL FT -EDA Empress to EDA 10,773 al Varies 63.84842 $/al 0.14377 5/G.1 Oct 31/12 TCPL FT -EDA Empress to EDA 10,773 G.I Varies 63.84842 $/al 0.14377 Val Oct 31/12 TCPL FT -EDA Empress to EDA 26,952 al Varies 63.84842 $/al 0.14377 $/al Oct 31/12 TCPL FT -EDA Empress to EDA 25,000 al Varies 63.84842 WO 0.14377 $/al Oct 31/13 TCPL FT -EDA Empress to EDA 42,226 al Varies 63.84842 WSJ 0.14377 5/al Oct 31/12 TCPL FT-IROQUOIS Empress to Iroquois 26,956 al Varies 62.15396 Val 0.14034 $/al Oct 31/12 TCPL STFT-CDA Empress to CDA 50,000 al Varies 63.84842 $/al 0.14377 $/al Mar 31/12 TCPL STFT-CDA Empress to CDA 75,000 al Varies 63.84842 $/al 0.14377 $/GJ Feb 29/12 TCPL STFT-CDA Empress to CDA 75500 al Varies 63.84842 VGJ 0.14377 $/al Mar 31/12 TCPL STFT-CDA Empress to CDA 50,000 G1 Varies 63.84842 $/al 0.14377 $/al Feb 29/12 TCPL STFT-EDA Empress to EDA 25,000 G1 Varies 63.84842 $/al 0.14377 WSJ Feb 29/12 TCPL STFT-EDA Empress to EDA 25,000 GJ Varies 63.84842 5/G1 0.14377 Val Mar 31/12 TCPL STFT-EDA Empress to EDA 25,000 al Varies 63.84842 $/al 0.14377 5/al Feb 29/12 TCPL STS Parkway to CDA 153,700 al Varies 1.69730 Val 0.00024 $/al Oct 31/12 TCPL STS Parkway to CDA 92,822 al Varies 1.69730 $/al 0.00024 Val Oct 31/12 TCPL STS Parkway to CDA 37,370 al Varies 1.69730 Val 0.00024 Val Oct 31/12 TCPL STS Kirkwall/Parkway to EDA 35,089 al Varies 4.84530 Val 0.00757 $/al Oct 31/12 TCPL STS Kirkwall/Parkway to EDA 35,806 al Varies 4.84530 $/al 0.00757 $/al Oct 31/12 TCPL STS Parkway to EDA 9,716 al Varies 4.84530 Val 0.00757 Val Oct 31/12 TCPL FT-Parkway to CDA 572 al Varies 3.14523 Val 0.00350 $/al Oct 31/13 TCPL FT-SN Parkway to CDA 85,000 al Varies 3.17490 Val 0.00326 $153 Dec 31/17 TCPL FT-Dawn to CDA 4,818 al Varies 7.49321 Val 0.01360 WG.1 Oct 31/12 TCPL FT-Dawn to CDA 145,000 GJ Varies 7.49321 5/al 0.01360 WO Oct 31/12 TCPL FT-bawn to EDA 114,000 al Varies 15.52514 $/al 0.03229 5/GI Oct 31/12 TCPL FT-Dawn to Iroquois 40,000 al Varies 14.71519 $/GJ 0.03038 $/al Mar 31/13 Nova Transmission AECO to Empress 8,036 al Varies 5.87000 Val $/103m3 Oct 31/13 Nova Transmission AECO to Empress 28,833 al Varies 5.87000 $/al $/103m3 Oct 31/13 Alliance Pipeline Alberta to US border 2,124.6 103m3 varies 981.16000 $/103m3 $/103m3 Oct 31/15 US border to Chicago 75 mmcf varies 17.92340 $US/dth $US/dth Oct 31/15 Vector Pipeline - Chicago to Cdn border 96,000 dth varies 7.01400 $US/dth $US/dth Oct 31/15 Cdn border to Dawn 101,285 al varies 0.57050 Val Val Oct 31/15 Vector Pipeline Chicago to Cdn border 79,000 dth varies 7.01400 $US/dth $US/dth Oct 31/15 Cdn border to Dawn 83,349 G1 varies 0.57050 Val 5/al Oct 31/15
1 d Vector Pipeline Alliance to St. Clair 50,000 Dth varies Negotiated Toll Oct 31/13 2:
varies Negotiated Toll Oct 31/13 H St. Clair to Dawn 52,753 GJ 911. - Bed Oct 31/15 D
G Vector Pipeline Alliance to St. Clair 50,000 Dth varies Negotiated Toll :I St. Clair to Dawn 52,753 GJ varies Negotiated Toll Oct 31/15 £00 Z Union Gas Dawn to Kirkwall 32,123 al varies 1.98500 Val 5/G1 Mar 31/14 - 0
1,764,678 GI varies 2.33200 $/al Val Mar 31/14 0 Z1.
Union Gas Dawn to Parkway 0Z Z1. 4 Val Oct. 31/12 1. 2.33200 Val - Union Gas Dawn to Parkway 10,692 al varies I,
Union Gas Dawn to Parkway 53,455 al varies 2.33200 Val $/al Oct. 31/12 Z I. 90
Union Gas Dawn to Parkway 20,848 GJ varies 2.33200 $/GJ $/al Oct. 31/12 - Union Gas Dawn to Kirkwall 35,806 al varies 1.98500 5/al 5/al Oct. 31/12 91, Union Gas Dawn to Parkway 107,000 al varies 2.33200 WSJ Val Oct. 31/12 Union Gas Dawn to Parkway 37,400 GJ varies 2.33200 5/al 5/al Oct. 31/12 Union Gas Dawn to Parkway 106,000 al varies 2.33200 $/al Val Oct. 31/18 Union Gas Dawn to Parkway 57,100 al varies 2.33200 $/al $/al Oct. 31/19 Union Gas Dawn to Parkway/Kirkwall/Lisgar 200,000 al varies 2.33200 VG! Val Oct 31/22 Union Gas Parkway to Dawn 436,586 al 0.54500 5/al Mar 31/14 ENBRIDGE GAS DISTRIBUTION INC.
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TAB 5 TCPL's 2012-2013 Toll Application
9 Hearing Order RH-003-2011
10
11
12
13
14 MAS Evidence
15
16
17
18
19 March 9, 2012
20 Un on Gas Limited
.Manlloba •
LEGEND — Union Gas Pipelines — Interconnect Pipelines o Union Gas CornpreSsorS DiStRICT BOUNDARIES a an r7i Windsor/Chatham Loridon/Samia RI Waterloo/Brantford i•'YALGAR 0 Hamilton 8F6 Ay 0:1 El Halton pg Eastern Northeast Li Northwest nongas
dattyleWiliV"'" 1
2
3
4 D. MAS FRANCHISES
5 All three MAS members are physically connected to the TransCanada Mainline and must rely 6 on TransCanada's services to meet their customers' gas needs. As a result, MAS consider I7 that all three LDCs are captive shippers of TransCanada's system. 8 The following chart shows the percentage of the TransCanada Mainline cost of service that is 9 paid by MAS:
5 ENBRIDGE GAS DISTRIBUTION INC.
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TAB 6 TransCanada PipeLines Limited NOVA Gas Transmission Ltd. and Foothills Pipe Lines Ltd.
Application for Approval of Restructuring and Mainline Final Tolls for 2012 AND 2013
National Energy Board Proceeding RII-003-2011
Opening Statement of TransCanada PipeLines Limited (Greg Lohnes, President, Natural Gas Pipelines)
1 Good morning Mr. Chairman, members of the Board, ladies and gentlemen. I appreciate the
2 opportunity to make an opening statement on behalf of TransCanada. My purpose in doing
3 so is to provide some perspective on TransCanada, on the current situation of our Mainline,
4 and on the Application that we have placed before the Board.
5 We have asked the Board to approve a restructuring of our Canadian natural gas pipeline
6 business and services, and to approve final tolls for our Mainline for 2012 and 2013.
7 Why have we made this Application? It is because we believe that it is crucial to enhance the
8 long term economic viability of the Mainline and the Western Canada Sedimentary Basin as
9 a whole. The recent dramatic changes in the natural gas business environment in North
10 America have created a situation where that viability is at risk. The Mainline is essential to
11 the Canadian natural gas industry and TransCanada is seeking to achieve through its
12 proposals in this Application, material reductions in the costs of transportation from the
13 WCSB to ex-basin markets.
14 TransCanada has provided safe and reliable service on the Mainline to the producers of
15 Western Canada and the consumers of eastern North America for over 50 years. It has
16 operated for decades within the regulatory compact and under the traditional cost of service
17 regulatory model. That model generated predictable revenues and provided confidence that
18 TransCanada would have the opportunity to recover its invested capital over the economic Business and Services Restructuring and Mainline 2012-2013 Tolls Application TransCanada Opening Statement Page 2 of 7
1 life of the facilities that it built and operates. The key elements of the traditional model - low 2 risk, modest returns on equity, low borrowing costs, slow return of capital through low 3 depreciation rates, and flow-through taxes - have translated into the lowest possible tolls for 4 our shippers. Under the cost of service model, TransCanada has been precluded from 5 exercising market power and charging market-based rates.
6 Mainline risk increased with the move to "competition amongst the few" regulated pipelines 7 that started in the late 1990s - a fact that the Board recognized on two occasions with 8 increases in the approved common equity level of the Mainline capital structure. Recent 9 developments, however, have significantly increased that risk.
10 In 2007, Mainline receipts at the Alberta/Saskatchewan border were 6 Bcf/d. In 2011, they 11 were 3.2 Bcf/d. What has caused the change? It resulted from a combination of events. 12 New, developing basins in the United States - particularly Rockies gas and Marcellus Shale 13 gas - have been connected to the domestic and export markets that the Mainline has 14 historically served with gas from the WCSB. Demand has increased in existing intra-Alberta 15 markets, reducing the supply available to the Mainline. New markets for WCSB gas are 16 developing offshore, driving western LNG export projects. Gas prices have collapsed, 17 leading to decline in supply development in the WCSB.
18 The effect has been a dramatic increase in Mainline tolls. Calculated using the traditional 19 cost of service methodology, the annualized Empress to Southwest Zone toll would have 20 increased from 0.86 VGJ in 2007 to $2.07 $/GJ in 2011. Mainline toll increases are 21 projected to continue in the near term under the status quo cost allocation, toll design and 22 services .
23 The reality is that recent events have combined to create a situation where maintaining the 24 status quo would significantly increase the Mainline business risk and could jeopardize the 25 long term economic viability of the Mainline and the WCSB.
1 26 The fact that the current situation exists due to developments that are beyond the control of 27 TransCanada does not mean that TransCanada should do nothing about it. To the contrary, Business and Services Restructuring and Mainline 2012-2013 Tolls Application TransCanada Opening Statement Page 3 of 7
TransCanada recognizes it has an obligation to take appropriate action to ensure the long 2 term economic viability of the Mainline. It is why we have spent so much time and effort in 3 an attempt to reach a negotiated solution with our stakeholders. It is why we conduct ongoing 4 analysis of facilities utilization to ensure optimal configurations, and why redeployment of 5 facilities are pursued when appropriate opportunities arise (examples are the conversion of 6 Line 100-1 from Mainline gas service to Keystone oil service, the transfer of compressors 7 from the Mainline to the Alberta System, and the current active pursuit of conversion of parts 8 of the Mainline to oil service to move oil from Alberta to the East Coast). And in the present 9 circumstances, it is why we have put such significant time and resources into developing the 10 Restructuring Proposal advanced in our Application.
11 We developed the Restructuring Proposal with the objective of improving Mainline and 12 WCSB viability through material reductions in the tolls for transportation from NIT to ex- 13 Basin markets served through TransCanada infrastructure, and through the implementation of 14 service enhancements and economic efficiencies. The Proposal is a comprehensive response 15 to the new market reality. It is a series of cost allocation, toll design and service changes that 16 advance the public interest in a manner that is equitable and balanced among TransCanada 17 and its stakeholders. It does so within the existing regulatory model, consistent with 18 established regulatory principles, practices and expectations. The result is just and 19 reasonable, non-discriminatory tolls.
20 We are also bringing this Application because the issues facing the Mainline and its 21 stakeholders have not been resolvable through negotiation. The significant efforts of all • 22 parties to reach settlement have been unsuccessful, which means that we have to turn to the 23 Board to decide matters that remain in dispute.
24 We are proud of our record of settlements. Through negotiation, we and our stakeholders 25 have often been able to reach consensus solutions on our pipelines. In the present 26 circumstances of the Mainline, we worked extensively with stakeholders over a long period 27 of time in an effort to reach a workable agreement, but without success. The diversity of ENBRIDGE GAS DISTRIBUTION INC.
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TAB 7 TransCanada PipeLines Limited M-003-2011 Response to NEB June 1, 2012 Page 1 of 6 NEB 6.8
Topic Alternate Supply Scenarios
Reference: i) Application: Appendix Cl (revised), lines 9-19, (PDF page 79) and lines 1-17, (PDF page 80). Figures A-2 and A-3. [A2G7S0] ii) TransCanada Response to NEB I.R 1.5 (c): Page 27 of 526. [A2J7Q3] iii) TransCanada Application: Appendix Cl (revised). lines 1-8, PDF page 36, Figure 116. [A2G7S0]
Preamble: In reference i), TransCanada outlines the high, low and base case long- term price forecasts it used in its throughput study.
In reference ii), TransCanada notes that implementation of the Restructuring Proposal may not mean that Western Canada Sedimentary Basin (WCSB) gas shipped on the Mainline will compete successfully with Marcellus gas in Pennsylvania or New York, but a more competitive Mainline will better enable WCSB gas to compete with Marcellus gas as Marcellus gas reaches for markets outside those states.
In reference iii), TransCanada compares its Base, high and low case WCSB supply scenarios to those from the NEB's 2009 reference case scenario.
Request: a) Please consider the following scenario: Shale gas production in the U.S. increases faster than anticipated in the throughput study and natural gas production from liquids rich gas plays in the U.S. increases as drilling activity increases in those plays. The continued over- supply of natural gas results in a natural gas price that remains at or near the current level. i. Discuss the effects of the scenario on WCSB natural gas supply availability. ii. Discuss the effects of the scenario on Mainline throughputs. b) Further to your answer in reference ii) above, please indicate which markets are likely to provide the best option for WCSB gas. In your answer, please also identify current and possible future competing supply sources for those markets. c) Discuss the impacts on the Restructuring Proposal if TransCanada's high WCSB supply scenario is realized. In your answer, please identify the impacts on throughput, tolling and shippers. Page 2 of 6 NEB 6.8 d) Discuss the effectiveness of the Restructuring Proposal if the NEB's low case WCSB supply scenario in reference iii) is realized.
Response
(a) For the purpose of this response, TransCanada has defined the "current" price to reflect the low price environment of 2011 and 2012. The average plant gate price, in these 2 years, is $3.00 Cdn/Mcf and is based on the actual 2011 price of $3.40 Cdn/Mcf and TransCanada's expected 2012 price of $2.66 Cdn/Mcf. For the purposes of this response TransCanada has defined "current" prices to be in the $3.00 to $3.50 Cdn/Mcf range. As an introductory comment on the supply impact of lower prices it is important to note that, in addition to the level of natural gas prices, liquids prices are also an important driver of activity in the WCSB. Furthermore, upstream investment decisions are made on the basis of expected prices, not current prices, although in some situations the two may not be materially different. If the current low price environment of $3.00-$3.50Cdn/Mcf were to persist over the forecast period, TransCanada would expect its WCSB supply forecast to track below its low case primarily due to the expectation of lower conventional supply. However, activity in the conventional regions is already significantly curtailed and most of the current activity and future growth is being focused on higher productivity, lower cost unconventional prospects that generally benefit from having a higher liquids content. While there will be some slow down in activity in these areas as well, economics are still favourable. Activity in the high liquids regions of the Montney and Deep Basin plays will continue to be robust due to high-grading and capital deployment from the less economic regions in the WCSB. As an unconventional play without significant liquids content, the economics of Horn River gas development would be challenged, although on going technological improvements are likely to continue to lower unit costs. As a sidebar, while TransCanada has not included supply from the Duvernay Shale play in any of its forecasts, there is potential that it could also be economic at the "current" low gas prices. In addition, in the medium term, the potential for Westcoast LNG exports is expected to result in increased development activity. This activity should be largely independent of the level of NIT prices, since producers would be expecting to market that gas at netbacks substantially above the "current" level of NIT. Page 3 of 6 NEB 6.8
In conclusion, prices sustained at "current" levels can be expected to reduce WCSB supply levels from the TransCanada low case supply path. However, there are several factors (LNG development, the growing importance of liquids-rich plays) that suggest the reduction from the TransCanada's low case supply may not be substantial.
ii In general, lower levels of WCSB gas production result in reduced Mainline throughputs, particularly through the prairies and in the Northern Ontario line (NOL). However, absent the addition of new competing infrastructure, eastern market areas (Eastern Ontario Triangle - EOT) throughputs may not be reduced as significantly since throughput on this part of the system is largely driven by demand levels and since it also has access to supply sources other than the WCSB. Relevant for this discussion are the low Mainline throughput cases (Cases 4 and 5) as presented in the Application, Appendix Cl: Throughput Study, pages 10 -11 of 79. Both Case 4 (Restructuring Proposal) and Case 5 (Status Quo) are based on TransCanada's low WCSB supply case. As shown in Figure 2.2 of the Study, Mainline Western Receipts (MWR), the flow into the prairies section of the Mainline, drops 2 to 3 •Bcf/d in Cases 4 and 5 relative to Cases 1 and 2 which are based on TransCanada's WCSB base supply case. Meanwhile, in the EOT, flows (which can be approximated as the total volume of NOL flow and Parkway receipts from 'Union) are only reduced by about 0.1 to 0.2 Bcf/d from the base to the low WCSB supply cases.' This illustrates how throughput on the western Canada long haul portion of the Mainline is much more dependent on the performance of WCSB gas supply than is throughput in the EOT. The WCSB gas supply level described in the response to (a) i above could be somewhat lower than TransCanada's low supply case for the 2012-2020 forecast period. As such, MWR could also be somewhat lower than in Cases 4 and 5 in the Study. However, given that this supply scenario is similar to the one used in Cases 4 and 5 of the Study, TransCanada expects the Restructuring Proposal to be of benefit here too. For its low WCSB supply scenario, TransCanada's assessment indicates that the Restructuring Proposal also has a positive impact on MWR which average about 0.2 Bcf/d higher in Case 4 compared to Case 5 (Status Quo). Furthermore, tolls for the Restructuring Proposal Case 4 are also lower than in the Status Quo Case 5 as shown in the response to Tenaska 1.31 (iii) and in the response to (c) below. While TransCanada has not prepared detailed analysis on the NIT price impact between throughput Cases 4 and 5, the NIT price benefit of the Restructuring Proposal in this low WCSB production environment is expected to be in the 8 — 12 cent range, just below the 13 cent benefit estimated for
1 TransCanada's response to NEB 2.62(b). Page 4 of 6 NEB 6.8
Cases 1 and 2 (which evaluate the Restructuring Proposal in TransCanada's base WCSB production scenario).
TransCanada expects that, in low supply throughput cases, most traditional markets will continue to be served to some extent by WCSB gas. WCSB gas will be allocated to the different regional markets on the basis of netback optimization. Each market (except for the US Northeast markets served by exports at Niagara and Chippewa) will likely continue to provide attractive opportunities for volumes on an ongoing basis and/or for larger volumes on a seasonal, monthly or daily basis. Assuming the question refers to regional markets, the regional markets that TransCanada expects "are likely to provide the best option for WCSB gas" are those where there is the least amount of competition from other sources of supply. As the question makes clear, the issue is not only one of how much supply competition there is today, but how much there may be in the future. Over the past five years several new supply sources have developed and there is no reason to believe that this will not continue to occur. It is, of course, difficult or impossible to predict where the new supply areas will develop. To the extent that the "best" markets are those with the least competition, TransCanada expects that the best options for WCSB gas will remain the intra- basin market and markets along the Mainline in Manitoba and Northern Ontario. TransCanada also expects the balance of Ontario and Quebec to remain important and attractive markets for WCSB gas, despite the fact that there is competition from Rockies gas, Marcellus gas, and other US gas supply that can be accessed at Dawn. The extent to which WCSB gas continues to serve these markets will depend, in part, on whether, and to what extent, bypass infrastructure is put in place (some projects may bypass the Mainline but continue to flow WCSB gas). The extent to which the WCSB continues to serve these markets is partly a function of tolls. The tolls set under the Restructuring Proposal (as opposed to those under the Status Quo ) will lead to higher volumes of WCSB gas in the Ontario and Quebec market and create an economic environment where there is less risk of bypass and displacement of WCSB gas out of these markets. This point also applies to WCSB exports through Iroquois and PNGTS. The Pacific Northwest and the Midwest are also expected to remain important markets, despite the fact that each—particularly the US Midwest—has competing sources of supply. The competing source of supply in the Pacific Northwest is the Rockies, while in the Midwest, there are several: the Rockies, mid-continent, and gulf coast supply areas. Northern California is also expected to remain an important market, with the competition in this market coming from Rockies gas. Page 5 of 6 NEB 6.8
The Northeast US market has become more challenging due to the development of Marcellus gas and with the completion of the REX pipeline. The markets in the Northeast traditionally served by exports at the Niagara and Chippawa export points are expected to be primarily served by US supplies in the foreseeable future. The expected development of the Utica Shale in Ohio will tend to force Marcellus supply North, East and West, making competition in parts of the Northeast more intense. WCSB gas is expected to continue to find a market in the Northeast through the Waddington export point on the Iroquois Pipeline. The extent to which this market is maintained for WCSB gas is a function of whether or not, new infrastructure is built which would allow Marcellus gas to displace WCSB gas on the Iroquois Pipeline. Finally, Asian markets should provide an attractive market for WCSB gas beginning near the end of the decade. The attractiveness of the Asian market will be a function of: the differential between the price WCSB gas can command in the Asian market and the price it can be sold for at NIT. This, in turn, will depend on the level of oil prices and pricing dynamics for LNG in the Asian market.
(c) As in the base or low WCSB supply cases, TransCanada expects the Restructuring Proposal to also be of benefit in TransCanada's high WCSB supply case. As discussed in the response to NEB 2.62, Cases 6 and 7 incorporate TransCanada's high WCSB supply case for the Restructuring Proposal (Case 6) and the Status Quo (Case 7) tolling structures. As shown in Attachment NEB 2.62(b), TransCanada predicts MWR to be about 0.35 Bcf/d higher in Case 6 relative to Case 7 for the 2012 — 2020 time period. With higher WCSB supply, shippers are expected to have lower tolls in Cases 6 and 7 as compared to tolls in Cases 1 and 2 and in particular, the Restructuring Proposal tolls in Case 6 are also lower than in the Status Quo Case 7. The table in Attachment NEB 6.8c, originally provided in response to Tenaska 1.31 (iii) for Cases 1 - 5, now also includes tolls for Cases 6 and 7. As shown, tolls in Case 6 (Restructuring Proposal) are significantly lower than in Case 7 (Status Quo). While TransCanada has not prepared detailed analysis on the NIT price impact between throughput Cases 6 and 7, the NIT price benefit of the Restructuring Proposal in this high WCSB production environment is expected to be greater than the 13 cent benefit estimated for Case 1 and 2 (which evaluate the Restructuring Proposal in TransCanada's base WCSB production case).
(d) The WCSB supply levels in the 2009 NEB low case in reference iii) are lower than those assumed in TransCanada's Cases 4 and 5. Lower supply levels can be expected to result in lower MWR and at lower levels of MWR TransCanada Page 6 of 6 NEB 6.8
expects (all other things equal) the MWR flow benefit of the Restructuring Proposal would also generally reduced. TransCanada also notes that the 2011 NEB low case of WCSB supply 2 is higher than the 2009 NEB low case in reference iii) and is similar to TransCanada's low WCSB supply case used in Cases 4 and 5. As such, TransCanada expects that the effectiveness of the Restructuring Proposal in the 2011 NEB low case would be similar to that shown between Cases 4 and 5 which estimated an average 2011- 2020 MWR increase of about 0.2 Bcf/d. It is also important to note that Case 5 does not include the market and infrastructure responses which were included in Case 3 and thus the MWR impact between a Status Quo outcome and a Restructuring Proposal outcome is understated when using the Case 4 versus Case 5 result as a basis of comparison. Please also refer to the response to (a) ii above.
2 National Energy Board, Canada's Energy Future: Energy Supply and Demand Projections to 2035, November 2011 ENBRIDGE GAS DISTRIBUTION INC.
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TAB 8
WRITTEN REPLY EVIDENCE OF PAUL R. CARPENTER
and cost of capital of the Mainline, and of other entities regulated by the Board, to 2 increase substantially.
Q5. What is your overall response to CAPP's evidence on the subject of the 4 Mainline's business risk?
5 A5. CAPP's evidence takes the position that the Mainline's business risk is "somewhat" 6 higher than it was in 2004. CAPP points to the Mainline's base case supply and 7 throughput forecasts as evidence that circumstances on the Mainline appear to be 8 improving and that the Mainline's supply problems are or may be temporary. CAPP 9 also claims that the Mainline's competitive risk (one of the components of business 10 risk) is "somewhat" higher than it was in 2004 and 2008. CAPP also says that the 11 Mainline's business risk is less than in 2008 when the Board evaluated the business 12 risk of TQM in its Decision RH-1-2008.
13 Contrary to CAPP's position, there has been a substantial and evident increase in the 14 Mainline's business risk since it was last reviewed by the Board in 2004. It has also 15 increased substantially even since the Board evaluated the business risk of TQM in 16 2008. 1 The Mainline has become marginalized as a source of supply in U.S. gas 17 markets over the past eight years, and particularly in the last three or four years, as a 18 result of increased competition from new sources of gas supply in the Lower 48 19 (namely gas from the Rocky Mountains and emergent and growing U.S. shale gas 20 supplies in the mid-Atlantic states). While CAPP attempts to downplay these 21 significant changes, it has done so by selectively focusing on the Mainline's base 22 case supply and throughput forecasts. While those forecasts are important, it is the 23 low case forecasts that are relevant to an evaluation of business risk. The base case 24 forecasts are highly uncertain, as reflected in the other supply and throughput 25 scenarios provided by TCPL. Moreover, CAPP's witnesses appear to have focused
I It is not clear why CAPP chooses to reference 2008 as a relevant date, given that the last time the Board reviewed the Mainline's business risk in the context of the fair return for the Mainline was in 2004.
WRITTEN REPLY EVIDENCE OF PAUL R. CARPENTER
1 Q18. What is wrong with Mr. Johnson's and Dr. Booth's reliance on the TCPL base 2 case forecasts?
3 A18. I find their use of the base case projections to be misplaced in a business risk analysis, 4 especially with .respect to their suggestion that the Mainline's problems either are, or 5 may be, temporary. Their reliance on the base case forecasts without consideration of 6 the range of outcomes (and particularly the low case) seems particularly questionable 7 given that the base case forecasts assume that no LNG export projects are built in 8 British Columbia—yet the LNG projects proposed in British Columbia appear to be 9 advancing. Current gas commodity prices are also significantly lower than the price 10 forecast implicit in TransCanada's base case forecast, having declined significantly 11 since that analysis was performed and the Application filed in this proceeding (see 12 Figure 1 below). The company indicates in its reply evidence that under current 13 market conditions it would now place a higher probability on the low case outcome 14 associated with the throughput study filed with this Application. 13
13 See TransCanada's reply evidence on Fair Return.
12 WRITTEN REPLY EVIDENCE OF PAUL R. CARPENTER
1 2 Both Mr. Johnson and Dr. Booth have ignored the implications of the other supply 3 and throughput cases presented by TCPL in its evidence. For example, TCPL's 4 Cases 4 and 5 (low supply cases) project 2020 Mainline throughput of 1.8 Bcf/d and 5 1.6 Bcf/d, respectively. Moreover, even if TCPL's base case projections prove to be 6 accurate, it is not at all clear that the Mainline's problems are resolved. The base case 7 projections show 2020 Mainline throughput of 4.4 Bcf/d.
8 Interestingly, Dr. Booth acknowledges that he is "not entirely" confident in TCPL's 9 forecasts and finds that there is "more uncertainty surrounding" its current throughput 10 forecasts than its 2008 forecast (in part due to the development of shale gas). 15 Given 11 this acknowledgement, I do not understand how Dr. Booth can claim that the 12 Mainline is less risky than it was in 2008.
13 Q19. How do you respond to suggestions that the Mainline's problems may be 14 temporary and that the Mainline's supply and throughput circumstances appear 15 to be improving?
16 A19. Whether the Mainline's problems are temporary and/or improving is highly uncertain 17 and I think it is premature to reach any conclusions to this effect. There are too many 18 uncertainties now facing the Mainline to reach any conclusion that market and supply 19 conditions are going to improve for the Mainline over the next eight years. These 20 uncertainties are captured by the wide range of forecasts that TCPL has offered, the 21 implications of which have been ignored by Mr. Johnson and Dr. Booth. Continued 22 growth of shale supplies from the Marcellus and/or Utica shale plays, or the 23 development of substantial LNG export capacity in British Columbia may prevent the 24 type of improvement in the Mainline's business environment that Mr. Johnson and 25 Dr. Booth are suggesting.
15 Evidence of Dr. Booth, p. 34, lines 11-12 and p. 37, lines 1-5.
14 ENBRIDGE GAS DISTRIBUTION INC.
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TAB 9 Business and Services Restructuring and . Mainline 2012-2013 Tolls Application Final Reply Evidence Page 35 of 62 October 12, 2012
1 negative impact of higher tolls on customers was used, in part, as a basis for testimony that tolls 2 are no longer just and reasonable:
3 The MAS members are not suggesting that the assets associated with the 4 Northern Ontario Line are not used and useful. However, they are 5 underutilized and that underutilization, because of its net book value, has 6 manifested itself in terms of rates that are causing a toll spiral and are no 7 longer just and reasonable. 74 8 9 TransCanada fully recognizes that tolls, particularly long-haul tolls, have increased over the past 10 three years. This is largely a consequence of lower billing determinants due to shippers, such as 11 the MAS members, taking advantage of the opportunity to shift from long-haul service to short- 12 haul service and to shorter-term services that better match their seasonal and daily requirements. I13 However, this does not mean customers are paying more on an average unit basis for 14 transportation service on TransCanada. In fact, in 2011 customers on average paid lower unit 15 costs for Mainline service than they did a decade ago.
16 TransCanada has experienced some declines in net deliveries. As shown by the line in 17 Figure 1,75 net deliveries by TransCanada in 2011 were approximately 2,450,000 TJs, or 12.3% 18 lower than the quantity delivered on average during the period from 1999 to 2004.
74 55TR28757, as corrected in the Volume 56 errata. 75 Average VGJ = Total system wide invoiced dollars / Total GJs Delivered excluding Welwyn and Centram SSDA.
Business and Services Restructuring and Mainline 2012-2013 Tolls Application Final Reply Evidence Page 40 of 62 October 12, 2012
3.9 Capacity between Parkway and Maple and Competition with LDCs
1 The MAS proposal and the evidence of the MAS panel demonstrate the conflicting and at times 2 competitive interests of MAS members and TransCanada. The contracting decisions of the MAS 3 members, such as switching to short haul service, and relying on the use of discretionary services 1 4 have increased tolls for remaining long haul shippers, which include the MAS members. For 5 instance, to the extent that Union switches from long haul to short haul to serve the Union CDA, 6 it increases long haul tolls to the Union NDA, Union WDA and Union EDA.
7 During cross examination, Ms. Piett questioned why TransCanada would participate in the MAS 8 members regulatory proceedings. 79 The answer is obvious. TransCanada's participation is to 9 ensure that provincial regulators are aware of the costs and consequences of activities like 10 shifting to short haul transportation.
11 Some of the evidence provided by the MAS panel, particularly by Union's witness, Ms. Piett, 12 portrays TransCanada as managing its system in a way that is harmful to end-users. These 13 comments are addressed here, and placed into a broader context.
14 Ms. Piett provided views on the capacity between Parkway and Maple. She suggested that 15 TransCanada has been reluctant to build along this path, and that serving markets east of Dawn 16 using GLGT backhaul could impede access to Marcellus and Utica supplies. She stated:
17 For some time now, Union Gas has had the view that the transportation 18 capacity between Parkway and Maple -- which is in the Oakville area, it's 19 around 35 kilometres -- is constrained and it's causing the price spikes that 20 we've seen before the record now.
21 We also know that if it isn't expanded sufficiently, it has the potential to stifle 22 the uptake of the more competitive gas supply in our area, in Marcellus and 23 Utica so -- from entering Ontario and Quebec. So, for some time, Union Gas
55TR29335-29337. ENBRIDGE GAS DISTRIBUTION INC.
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TAB 10
Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part A: Executive Summary Section 1.0: Introduction and Executive Summary Page 1 of 20
1.0 INTRODUCTION AND EXECUTIVE SUMMARY
1.1 The Application Recent and dramatic changes in the business environment of natural gas supply, 2 demand and transportation in North America have raised significant issues that 3 impact the long term economic viability of existing pipeline infrastructure and supply 4 basins.
5 TransCanada has developed a comprehensive response to the new market reality. 6 The Restructuring Proposal is a suite of cost allocation, toll design and service 7 changes that is intended to enhance the long term economic viability of the Mainline 8 and the WCSB as a whole through material reductions in the cost of transportation 9 from NIT to ex-Basin markets served through TransCanada infrastructure, and the 10 implementation of service enhancements and economic efficiencies consistent with 11 established regulatory principles, practices and expectations.
12 The Restructuring Proposal impacts not only the TransCanada Mainline and its 13 stakeholders but also the TransCanada Alberta System and the TransCanada Foothills 14 System and their stakeholders. The Alberta System is owned by NGTL and the 15 Foothills System is owned by three subsidiaries of Foothills.' TransCanada is the 16 owner of both NGTL and Foothills, and is the operator of the three systems. 17 Consequently, TransCanada, NGTL and Foothills jointly request Board approval of 18 the Restructuring Proposal.
19 TransCanada also requests approval of Mainline Final Tolls for 2012 and 2013. 20 Elements of the Restructuring Proposal directly affect components of the Mainline 21 revenue requirement and the allocation of costs and revenues to the tolls for services.
1 Foothills Pipe Lines (Alta.) Ltd., Foothills Pipe Lines (Sask.) Ltd. and Foothills Pipe Lines (South B.C.) Ltd.
Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part A: Executive Summary Section 1.0: Introduction and Executive Summary Page 4 of 20
1 Notwithstanding the substantial capacity expansions, it became increasingly apparent 2 that the average term of Mainline contracts was reducing, and that TransCanada was 3 no longer assured of the historical and largely captive markets upon which its
4 expansions had been premised. TransCanada applied to the Board over a course of 5 years for a number of measures that were designed to retain and improve firm long 6 haul load on the Mainline. Some of those proposals were approved by the Board (e.g. 7 FT-RAM, Southwest Zone (RH-1-2002), North Bay Junction (RH-3-2004)) and 8 others were not (e.g. pricing discretion (RH-1-99), term-differentiated rates 9 (RH-4-93), changes to contract renewal policies (RH-4-93)), having been opposed by 10 some stakeholders as unnecessary to preserve firm long haul throughput on the 11 Mainline. An inability to achieve consensus among TransCanada and stakeholders or 12 Board approval for contested proposals resulted in TransCanada only being able to 13 implement a few measures to respond to evolving throughput risks.
14 Recently, rapid and dramatic developments in natural gas supply, markets and 15 contracting practices have had a significant impact on WCSB production and 16 Mainline receipts and deliveries:
17 HI. Supply:
18 • WCSB production has fallen by 3 billion cubic feet per day (Bcf/d) over the
19 last several years, and is currently at a level that is below the bottom of the 20 range forecast by TransCanada in 2004. Notwithstanding an anticipated mid- 21 term recovery from non-conventional gas, forecasts of production show a 22 decline in supply over the long term;
23 • New infrastructure has made Rockies gas and liquefied natural gas (LNG) 24 available in markets traditionally served by the Mainline;
25 • New shale gas production in the US has emerged more quickly and strongly 26 than anticipated, and there are now robust forecasts of future US shale gas
Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part A: Executive Summary Section 1.0: Introduction and Executive Summary Page 5 of 20 1 supply in proximity to domestic and export markets historically served by the 2 Mainline; and
3 • Shale gas is being developed in Canada in proximity to eastern markets that
4 have historically been served exclusively or predominantly through WCSB sources and Mainline services.
6 • Markets:
7 • • Export markets in the US Northeast that have been served in part through long 8 haul contracts on the Mainline have been dramatically eroded by new supplies 9 located in closer proximity to those markets;
10 • Increasing intra-Alberta market demand continues to reduce the WCSB 11 supply that is available for transportation on the Mainline. This trend is 12 forecast to continue in the long term; and
13 • Potential Pacific coast LNG exports would absorb a substantial amount of 14 WCSB supply.
15 • Contracting practices:
16 • Annual firm contracts are not being renewed. Shippers are using discretionary 17 services, which are essentially firm for most of the year due to available 18 capacity, in their place; and
19 • Two-thirds of remaining contracts are short-haul, which generates 20 significantly fewer billing determinants.
21 The combination of supply, market and contracting developments resulted in 22 Mainline WCSB receipts dropping from 6.0 Bcf/d in 2007 to 3.4 Bcf/d in 2010. The 23 effect has been an increase in the annualized Southwest Zone toll from 0.86 $/GJ in 24 2007 to 2.07 $/GJ in 2011. 3 Absent restructuring, Mainline toll increases are
3 As included in the TransCanada Application for Approval of Mainline Final 2011 Tolls, page 1 of 16. Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part A: Executive Summary Section 1.0: Introduction and Executive Summary Page 6 of 20
1 projected to continue in the near term under the status quo cost allocation, toll design and services.
3 Given the current and evolving circumstances, TransCanada believes it is in the 4 public interest to implement changes that will enhance the economic viability of the 5 Mainline and the WCSB, and that will improve the efficiency and operating 6 effectiveness of its pipeline systems. The Restructuring Proposal will achieve these 7 results.
1.4 Development of the Restructuring Proposal
8 In October 2009 TransCanada initiated a consultative process within the Mainline 9 Tolls Task Force (TTF) to address throughput and system utilization developments 10 and to discuss possible rate design, cost allocation and service responses. Informed 11 by its discussions with stakeholders, TransCanada developed a comprehensive 12 Mainline Competitiveness Package that included toll, tariff, service, and cost 13 allocation changes. The Mainline Competitiveness Package was presented to 14 stakeholders in March 2010 with the objective of reaching a negotiated resolution.
15 Discussions with the TTF and its Alberta System counterpart, the Tolls, Tariff, 16 Facilities and Procedures Committee (TTFP), did not result in a settlement.
17 TransCanada undertook further consultations through 2010, ultimately reaching an 18 agreement with some stakeholders that formed the basis of the TransCanada 19 December 2010 application for 2011 Mainline interim tolls. That application was 20 opposed by other stakeholders and was not approved by the Board, with the result 21 that the agreement was not implemented.
22 In early 2011 TransCanada undertook further consultations, and while another 23 agreement was reached with some stakeholders, it too was opposed, with the 24 consequence that it could not be implemented either. ENBRIDGE GAS DISTRIBUTION INC.
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TAB 11 Business and Services Restructuring and Mainline 2012-2013 Tolls Application Appendix Cl : Throughput Study TransCanada Page 55 of 79 tn &Wows to deliver Revised June 29, 2012
ATTACHMENT A
Case 1 - TransCanada Eastern Market Flows * Part D (Bcf/d)
TC Flow Ontario Quebec TC TC Non-TC Ontario Queb ec Mainline into Ontario Demand Demand Exports/ Exports/ TC Exports/ Flow Demand Demand Western (NOL & TC served served Imports Importt Imports @ Year into serVed served Receipts TBO on by Noir- . ,by Noir- @ @ Waddington Ontarie bv TC 11 bv TC1/ GLGT) - ' - TC TC Chippawa Niagara 2000 6.8 5.0 0.3 1.6 0.6 1.3 0.3 0.8 0.8 2001 6.0 4.5 0.7 1.5 0.5 1.0 0.3 0.7 0.8 2002 6.4 4.6 0.8 1.6 0.6 1.2 0.2 0.9 0.9 2003 5.9 4.2 1.3 1.6 0.5 1.2 0.2 0.8 0.9 2004 5.7 4.0 1.2 1.6 0.5 1.1 0.2 0.8 0.9 2005 6.3 4.5 1.0 1.6 0.5 1.2 0.2 0.9 1.0 2006 6.1 4.4 1.0 1.5 0.5 1.1 0.2 0.8 1.0 2007 5.7 3.8 1.6 1.4 0.6 1.3 0.2 0.8 1.0 2008 5.2 3.4 1.8 1.4 0.5 1.3 0.2 0.8 0.9 2009 4.3 2.4 2.4 1.3 0.5 1.4 0.2 0.4 0.8 2010 3.4 1.7 2.4 1.3 0.5 1.3 0.2 0.2 0.6 2011 3.2 1.2 3.0 1.3 0.5 1.5 0.1 0.1 0.5 2012 2.4 1.0 2.8 1.2 0.5 1.4 0.0 0.0 0.5 2013 2.6 1.1 2.5 1.3 0.5 1.4 0.0 -0.2 0.5 2014 2.8 1.1 2.3 1.2 0.5 1.3 0.0 -0.2 0.5 2015 3.1 1.1 2.3 1.2 0.5 1.3 0.0 -0.2 0.5 2016 3.6 1.3 2.3 1.2 0.5 1.4 0.01 0.0 -0.2 0.5 2017 3.9 1.4 2.1 1.2 0.5 1.4 0.02 0.0 -0.2 0.5 2018 3.9 1.4 2.4 1.3 0.6 1.4 0.04 0.0 -0.2 0.5 2019 3.7 1.3 2.2 1.3 0.6 1.4 0.05 0.0 -0.3 0.5 2020 3.6 1.3 2.3 1.5 0.5 1.5 0.08 0.0 -0.5 0.5
Note: 1. Includes pipeline fuel * Numbers may not add due to rounding. ENBRIDGE GAS DISTRIBUTION INC.
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TAB 12
Market Area Shippers Panel Examination by Mr. Khan
29110. What we, looking at the North American gas. market, were seeing was the maturation of the traditional production from the Western Canadian Sedimentary Basin and a growing requirement for gas within Alberta and we were looking at that time at where the gas supplies were going to come from.
29111. By the time we reached 2009, we were starting to get the inkling as to what has been often called in the industry the "shale gas revolution", but we didn't really know exactly how large that was going to be at the time. ,
29112. But what you saw was you saw the availability for lower-cost gas supplies to be available into the markets in Eastern Canada from other locations, and those were the kinds of conditions that could have been seen and identified at that point.
29113 There were a lot of forecasts there out there -- and forecast is just a forecast, as Dr. Langford has said in this proceeding -- but the reality was that there were a lot of forecasts that were not showing sufficient robust gowth in the Western Canadian Sedimentary Basin to stem the tide in the declines in throughputs that were occurring. Ours was one of them.
29114. TransCanada had a different view of the market. Unfortunately, I suppose ours was closer to right in that we find ourselves here in these conditions today. And these aren't going to change.
29115. One last thing I just say here -- and we'll probably get to it under the other things -- is about the future as well.
29116. While we've been sitting in this proceeding, we've looked at forecast of throughput and where the market has been going and they have changed. The market conditions in North America were very unfavourable to producers. As a result, TransCanada's update to the throughput looked at a decline of about 900 million cubic feet a day for 2012 coming -- coming out. Eight hundred (800) in 2012 and 900 in 2013.
/29117. The Marcellus has faced those exact same market conditions in North America and, yet, Marcellus production over this year has increased by a billion cubic feet a day. And what's more, we're now projecting that those increases are going to continue.
Transcript Hearing Order RH-003-2011
Market Area Shippers Panel Examination by Mr. Khan 29118. The lowest cost supplies in North America in terms of the new shale production are right on the map that's been sitting in front of us in close proximity to Eastern Canada and the market is saying that those are the opportunities.
29119. We're now projecting that the Marcellus will remain roughly at parity at Henry Hub for the foreseeable future and, in fact, beyond 2020, it may sell at a discount to Henry Hub. So the opportunity to get -- to avail the market with those supplies of gas is quite extensive.
29120. I'm sorry. I guess I went on a little bit but I hadn't had too much chance to talk so far since I've been here.
29121. MR. KHAN: You'll have lots ---
29122. MS. PIETT: Mr. Khan, if I could just add one thing. You were asking how do we know that we're in a toll spiral.
29123. And I think if we just look at the tolls themselves, since 2007 to 2013 -- so that's the Status Quo forecast that's just a few months away -- we will see tolls from Empress to the EDA go from $1.03 to 3.03; so that's about a threefold increase in just six years.
29124. And we have no reason to think that that trend won't continue and no amount of cost shifting or cost allocation is going to change the fact that customers in the East will continue to look for ways to avail themselves of the most economical supply that there is, which is exactly what Mr. Henning was talking about.
29125. And, in fact, if we didn't do that, our Ontario Energy Board, I think, or the Quebec Régie would have something to say to us about that if we weren't looking for the best deal for our customers.
29126. So we have no reason to think that that $3 toll that's now forecast for status quo for 2013 won't be $4 and then $5 and the only way that we can see -- which is exactly what our proposal was all about -- was taking costs out of the system.
29127. It's not about attracting more long-haul volume to the system. We just don't see that that's a practical endeavour for us to look at.
Transcript Hearing Order RH-003-2011 ENBRIDGE GAS DISTRIBUTION INC.
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TAB 13 TCPL's 2012-2013 Toll Application
Hearing Order RH-003-2011
Evidence Prepared by: Bruce B. Henning
March 9, 2012 March 9, 2012 Evidence prepared by Bruce B. Henning
1 Question: What are the likely impacts of the shift in costs on long-haul transportation
2 volumes?
3 Answer: Based on my analysis of North American natural gas markets, the decrease in long-haul
4 tolls is unlikely to be sufficient to drive a significant increase of natural gas onto the
5 TCPL Mainline. In order to increase flows on the Mainline, the decrease in tolls needs to
6 be sufficient to make TransCanada more competitive with other natural gas export routes from the WCSB, or increase gas prices in the WCSB by enough to stimulate significant
increases in natural gas supply. I don't believe that the impact on rates will be sufficient
9 to accomplish either of these objectives. Even though long-haul tolls will decrease, they
10 will still not be low enough to attract significant throughput increase.
11
12 The decrease in long-haul rates will have a modest impact on natural gas prices at AECO.
13 This is expected to be about 40 percent of the total reduction in long-haul tolls. The
14 increase in price will stimulate modest amounts of additional natural gas supply from the
15 WCSB. However, I anticipate that only a portion of this modest growth will be
16 transported on the TransCanada Mainline. Even at the lower rates made possible by the
17 shift is costs from long-haul to short-haul shippers, TCPL rates will remain above the
18 levels needed to attract significant additional flows. 19
20 Question: What are the likely impacts of the shift in costs on short-haul transportation
21 volumes? 22 Answer: Based on my analysis of North American natural gas markets, I expect the increase in
23 short-haul tolls relative to a proposal that does not shift costs to an energy-based charge 24 to substantially reduce the competitiveness of the eastern end of the TransCanada System
25 in both the short and long term. Growth in natural gas production from the Marcellus is
12 ICF International ENBRIDGE GAS DISTRIBUTION INC.
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TAB 14
1
2
3 TCPL's 2012-2013 Toll Application
4
5
6
7
8
9 Hearing Order RH-003-2011
10
11
12
13
14 MAS Evidence
15
16
17
18
19 March 9, 2012
20
1 TransCanada would have the discretion to determine the length and paths for which to offer 2 the MFP service. Finally, "variances between forecast and actual MFP service revenue will 3 be treated like variances for all other firm services and be recorded in a revenue deferral 4 account for subsequent disposition." 28
5 6 6. What is MAS position on TransCanada's proposed changes
7 to services and pricing?
8 MAS oppose TransCanada's proposed changes to services and pricing. MAS believe that 9 any proposed solution should focus on addressing the underlying issue of TransCanada's 10 cost structure. The proposed changes to services and pricing are not required and in fact, 11 may detract from increasing the Mainline competitiveness. TransCanada has not 12 demonstrated that the proposed changes will provide an enduring solution.
13 Moreover, TransCanada is required to demonstrate the positive long-term impact of its 14 proposed services changes. However, TransCanada has failed to provide sufficient evidence 15 to demonstrate that the proposed changes would improve the long-term sustainability of the 16 Mainline. MAS, therefore, oppose the MFP and the proposed changes to its discretionary 17 pricing.
18 I. CONCLUSION ON TRANSCANADA'S PROPOSAL
19 1. What are the final conclusions of MAS concerning
20 TransCanada's Restructuring Proposal?
21 MAS believe that, while the proposed reduction in tolls is commendable, the changes 22 proposed do not adequately address the underlying issue of TransCanada's cost structure. 23 As a result, MAS believe TransCanada's Restructuring Proposal is not a sustainable solution 24 for the short or longer term and should therefore be rejected by the Board.
25 2. Do the MAS have an Alternative Proposal to TransCanada's
26 Restructuring Proposal?
28 28 TransCanada's Application, Part C, Section 8.0: Mainline Service and Pricing Proposals, p. 34 of 39.
35 ENBRIDGE GAS DISTRIBUTION INC.
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TAB 15 IN THE MATTER OF TRANSCANADA APPLICATION FOR APPROVAL OF THE BUSINESS AND SERVICES RESTRUCTURING PROPOSAL AND MAINLINE TOLLS FOR 2012 AND 2013
HEARING ORDER RH-003-2011
Expert Report and Direct Testimony
PREPARED BY
JEFF D. MAKHOLM, PH.D. NATIONAL ECONOMIC RESEARCH ASSOCIATES INC 200 CLARENDON STREET, 11TH FLOOR BOSTON, MA 02116 USA
ON BEHALF OF
MARKET AREA SHIPPERS GROUP (MAS)
Boston March 2012
1 III. Executive Summary
2 Q9. Please provide a summary of your conclusions.
3 A9. My conclusions are as follows:
4 1. Competition in the gas market portends chronic underutilization for a portion of the 5 TransCanada Mainline capacity, as major new sources of gas exist to serve the largest 6 Canadian gas markets that are much closer to these markets than traditional gas supply 7 sources in Alberta.
8 2. The appropriate regulatory objectives for dealing with TransCanada's Mainline excess 9 capacity problems should be to (a) achieve an economically sustainable Mainline in the 10 short and long term; (b) achieve a just and reasonable risk and reward allocation among 11 all TransCanada stakeholders in the short and long term; (c) achieve a just and 12 reasonable cost allocation among shippers; (d) ensure that all Canadian gas consumers 13 continue to have open, transparent and competitive access to supply, transportation 14 services and markets.
15 3. TransCanada's Restructuring Proposal does not work to advance such regulatory 16 objectives. Rather, it seeks effectively to shift costs and risks to captive shippers in 17 Eastern Canada through multiple direct and indirect means, and thus it obscures the 18 identification of which portion of Mainline capacity is indeed economically sustainable 19 and which is not. The amount of cost to be shifted to captive shippers is unprecedented.
20 4. TransCanada repeatedly presents as a main goal of its Restructuring Proposal to 21 enhance the competitiveness of the Western Canadian Sedimentary Basin ("WCSB"), 22 which, as a goal for the Board, is both impractical and unjustified.
23 5. The main methods that TransCanada proposes to shift costs and risks to captive 24 shippers in Eastern Canada are contrary to accepted methods of pipeline tolling;
25 a. Allocating the recorded value of an integrated pipeline company's rate base to 26 particular regions or segments (via the transfer of accumulated depreciation)
5
1 A64. I do so first by evaluating the proposal against the appropriate tolling objectives I use to 2 evaluate all of TransCanada's proposals, namely (1) whether it promotes an economically- 3 sustainable Mainline; (2) whether it represents a reasonable allocation of risk and reward 4 among stakeholders; (3) whether it represents a just and reasonable cost allocation among 5 TransCanada's shippers; and (4) whether it ensures open, transparent and competitive access by 6 shippers to gas supplies, transportation services and markets. Second, I review the decisions of 7 regulatory boards in North America facing similar requests to shift accumulated depreciation 8 among pipeline regions. 9 I. The appropriate tolling objectives
10 Q65. Please comment on TransCanada's depreciation proposal in relation to the objective of 11 achieving an economically sustainable Mainline.
12 A65. TransCanada's proposal has two parts: (1) shifting accumulated depreciation to the NOL 13 (which means, in effect, transferring rate base out of the NOL) and (2) lengthening the 14 depreciable lives for the segments receiving the new allocation of rate base (to 2036 for Prairies 15 and 2050 for the Eastern Triangle). That lengthening of the depreciable lives hides the effect of 16 the rate base transfer to the Prairies and Eastern Triangle segments effectively pushes the cost 17 collection of the transferred rate base into the future.
18 Let me emphasize my last point, because the combined effect of these two parts of 19 TransCanada's proposal forms the principal basis for its ineffectiveness, either in providing a 20 genuine solution to its excess capacity problem or in providing for a reasonable risk/reward 21 tradeoff for stakeholders. That is, the proposal is a large shift in responsibility for the risk of 22 unused capacity away from TransCanada and toward the shippers at the ends of its Mainline. 23 As shown at Section 5, page 22 of 22, TransCanada is proposing to write down more than half 24 of the book value of its NOL segment (from $2,058,746,000 to $858,746,000) by setting the 25 stage to charge more from within the other segments.
26 Q66. Regarding your second objective, does the shift of rate base to the outer segments increase the 27 risk for customers using those segments that they will bear a larger portion of the cost on the 28 Mainline if TransCanada's hopeful forecasts of increased usage do not materialize?
39 ENBRIDGE GAS DISTRIBUTION INC.
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TAB 16 TransCanada Pipelines Limited (TransCanada), NOVA Gas Transmission (NGTL), Foothills Pipe Lines Ltd (Foothills) Application for Approval of the Business and Services Restructuring Proposal and Mainline Final Tolls for 2012 and 2013
Hearing Order RH-003-2011
File OF Tolls Group 1 — T211-2011-04-01
MAS Alternative Proposal
March 9, 2012
1 viability of the Mainline. This is of particular importance for the MAS. As long-term shippers on
2 the Mainline the MAS have a vested interest in ensuring the economic viability of the Mainline
3 now and in the future.
4 Q. What are the objectives underlying the MAS Alternative Proposal?
5 A. The MAS suggest that any effort to solve the issues facing the Mainline must be designed to
6 achieve several primary objectives. These objectives are identified below and described in
7 greater detail in subsequent sections of this evidence:
a) Enhance the economic viability of the Mainline in the short and long term;
9 b) Achieve a just and reasonable risk and reward allocation for all parties that derive a
10 benefit from the Mainline over the short and long term;
11 c) Achieve a just and reasonable allocation of costs amongst all parties that derive a
12 benefit from the Mainline; and
13 d) Ensure open, transparent and competitive access to natural gas supply and
14 transportation services.
15 Q. Please describe the elements of the MAS Alternative Proposal.
16 A. The MAS Alternative Proposal is comprised of the following elements which are explained in
17 greater detail in subsequent sections of this evidence:
18 1) Term of three years from 2012 to 2014 inclusive. Tolls for this period would be based on 19 TransCanada's approved forecast of cost of service and billing determinants for each 20 year of this term;
1 2) No shift in accumulated depreciation from the Prairies and Eastern Triangle segments to
2 the Northern Ontario Line ("NOL") segment and instead a shortened economic planning
3 horizon for the NOL segment. The economic plannint horizon for this segment would
4 be 2020 with the economic planning horizons for the Prairies and Eastern Triangle
5 segments remaining at 2036 and 2050 respectively as proposed by TransCanada. This
will immediately raise depreciation expense and thus the revenue requirement and tolls
over the next nine years but considerably reduce tolls post 2020;
3
1 3) Removal from the revenue requirement of the equity return associated with the NOL
2 segment from the revenue requirement in each year from 2012 to 2020. This element
3 recognizes that the NOL segment is not, nor is it likely to become, sufficiently utilized
4 during this period. Removal of the equity return on the NOL segment will serve to
5 reduce the revenue requirement for the next nine years; % 6 4) Implementation of an incentive mechanism that allows TransCanada an opportunity to
7 earn back the foregone equity return on the NOL segment via cost savings over the term
8 of the proposal. For cost savings amounts less than a certain threshold TransCanada
9 would not be required to pass these savings onto shippers. However, cost savings
0 greater than the threshold would be shared with shippers;
1 5) Continued application of the current tolling methodology including, without limitation,
the current cost allocation methodology which consists of zonal tolling and the
3 allocation of the costs of TQM transportation by others over all shippers; 124 6) Additions to the Long Term Adjustment Account would not be permitted. This element 15 will prevent the deferral of current costs for recovery from long-term shippers 16 dependent on the Mainline and thereby reduce intergenerational subsidies; 17 7) Preservation of the current Mainline services and toll structures, including the Risk
18 Alleviation Mechanism, and discretionary service tolls; 9 8) Introduction of a new firm bi-directional service and other service enhancements in the
0 form of additional nomination windows. Provision of these services will enhance the
1 current service offerings on the Mainline and enable shippers to use their Mainline /2 contracts more effectively when moving natural gas from source to market; and 3 9) A contribution from Western Canada Sedimentary Basin ("WCSB") market participants . 24 Producers along with the MAS and other shippers derive a benefit from the Mainline. 25 The MAS believe that accordingly all stakeholders should provide a contribution to 26 ensure the short and long-term economic viability of the Mainline.
27 Q. Why have the MAS selected a three year term for the purposes of the Alternative 28 Proposal?
4
1 at Appendix A of the MAS Evidence and in the evidence of Jeff Makholm of National Economic
Research Associates Inc. at Appendix D of the MAS Evidence.
Q. If the MAS Alternative Proposal is approved by the Board do the MAS propose that
TransCanada also contribute its proposed $25 million corporate contribution?
A. No. Rather than contributing $25 million as a direct reduction to the revenue requirement as
proposed by TransCanada, the MAS propose instead that TransCanada's contribution be made
through foregoing the equity return on the NOL segment.
8 Q. Why are the MAS proposing that TransCanada forego the equity return component of the
9 rate base assets related to the NOL segment?
10 A. The MAS have concluded that, given the circumstances currently facing TransCanada,
11 contributions from all stakeholders are required, To that end the MAS propose that
12 TransCanada, shippers (including the MAS), and WCSB producers should contribute to a
13 solution that lowers tolls, supports toll stability and addresses the cost structure from which
14 tolls are derived.
15 Q. How would the MAS propose that TransCanada contribute?
16 A. The MAS propose that TransCanada contribute by foregoing, subject to an incentive
17 mechanism, the equity return on the NOL segment including the impact of income taxes,
18 through to and including 2020. This time frame is consistent with the depreciation treatment
19 proposed by the MAS. In other words, it is proposed that rate base amounts related to the NOL
20 would not be included for purposes of calculating the equity return component of the
21 TransCanada revenue requirement,
22 Q. How would the MAS propose that TransCanada be permitted to mitigate the impact of this
23 contribution on its overall return?
24 A. The MAS propose that TransCanada be provided with an incentive to reduce costs and
25 thereby mitigate the impact of its contribution.
6
1 A. The MAS propose that the incentive mechanism operate as follows: Savings amounts would
2 be calculated only when the actual O&M and debt capital costs are lower than the Benchmark
3 Board Approved Cost amounts in a particular year. For O&M plus debt capital cost savings up
4 50% of the NOL segment return TransCanada would not include any amounts in the Short-Term
5 Adjustment Account. For savings amounts greater than 50% of the NOL segment return
6 TransCanada would record, as a credit to the Short-Term Adjustment Account, 50% of the
7 difference between 50% of the NOL segment return and the actual amount saved. This
8 calculation apportions 50% of amounts greater than 50% of the NOL segment return to the
9 account of TransCanada and 50% of the amounts greater than 50% of the NOL segment return
10 to the revenue requirement for disposition in subsequent test years via the Short-Term
11 Adjustment Account.
12 To be clear the MAS would expect that none of TransCanada's cost savings would be permitted
13 to come at the expense of system integrity or reliability. TransCanada would have to itemize
14 and justify cost savings for each year at the TTF and may be subject to further scrutiny by the
15 Board if the justification is deemed to be inadequate.
16 The amounts provided in Table 1 and herein discussed are for illustrative purposes only and
17 would ultimately be determined based on the Board approved amounts and actual amounts
18 incurred for each of these cost categories. If in any given year TransCanada's O&M and capital
19 debt costs are greater than the Board approved amounts for that year, then any savings in the
20 subsequent years would be calculated net of the amounts greater than the Board approved
21 amounts from the prior year.
22 Q. The MAS have concluded that contributions from all stakeholders are required. What
23 contribution would shippers make?
24 A. Shippers would contribute by continuing to bear throughput risk and the risk of cost
25 variances. In addition, shippers would contribute by bearing the higher cost of depreciation
26 arising from the shortened economic planning horizon for the NOL segment. To facilitate the
27 incentive mechanism and in order for shippers to retain throughput risk and risk related to
8 1 variance on costs, the MAS propose that the Short-Term Adjustment Account be retained but
2 with several changes.
13 Q. What changes do the MAS propose in respect of the Short-Term Adjustment Account?
4 A. Included in the Short Term Adjustment Account would be variances related to throughput
5 and all cost variances other than those related to O&M and capital debt cost savings. O&M and
6 capital debt cost savings in excess of the 50% threshold discussed above would also be included
7 subject to the incentive mechanism.
8 Q. Why should disposition of the Short-Term Adjustment Account occur over a rolling three
9 year period?
10 A. The MAS propose that the Short-Term Adjustment Account be disposed of over a rolling
11 three year period beginning in 2013 in order to limit the deferral of variances to a shorter time
12 frame. The MAS believe that the three years is an appropriate period of time over which to
13 assess the effectiveness of the incentive mechanism and to provide TransCanada with a
14 reasonable opportunity to adapt and respond.
15 It is important that TransCanada be well-positioned to respond to future market changes.
16 Extending the disposition of the Short-Term Adjustment Account beyond the three year rolling
17 period is inconsistent with that objective. Further, longer disposition periods increase the
18 occurence of intergenerationa I cross subsidies which is unfair to long-term shippers.
19 Q. Do the MAS support TransCanada's proposed toll design changes?
20 A. No. The MAS recommend that, subject to the changes suggested by the MAS, the toll design
21 changes proposed by TransCanada not be implemented and that the current toll design
22 methodology be maintained for the test years from 2012 to and including 2014.
23 Q. What changes to toll design is TransCanada proposing?
24 A. The proposed changes include:
25 • The elimination of toll zones;
9
1 In order for a shipper to achieve firm bi-directional service on the Mainline under the current
2 suite of services offered by TransCanada the shipper is required to maintain two separate Firm
3 Transportation contracts; one from point A to point B and another from point B to point A.
4 Each contract is priced the same and paying twice for the same path is not competitive.
5 Q. Why are the MAS requesting bi-directional service at this time?
6 A. The MAS believe that any means that may enable TransCanada to enhance the value and
7 competitiveness of contracting on the TransCanada system should be explored. A critical
8 component to achieving this objective is the development of new services that address the
9 needs of the market.
10 The MAS members continue to seek safe, reliable and competitive alternatives to serve their
11 customers. The ability to transport natural gas bi-directionally on a firm annual or, at a
12 minimum, a firm seasonal basis allows the MAS members to use their Mainline contracts more
13 effectively to move natural gas from its supply source to its market area and/or storage. STS is
14 the closest service to what the MAS require. However, STS is a "tied" service in that it is only
15 available if the shipper holds long haul Mainline capacity.
16 Offering competitively priced and valued services that respond to the market's needs would
17 better enable TransCanada to adapt to the ever-evolving marketplace for natural gas supply,
18 demand and transportation.
19 Q. Are there any other service enhancements that the MAS would propose TransCanada
20 offer?
21 A. Yes. One other enhancement that would enable shippers to better serve their markets would
22 be the provision of additional nomination windows on firm services.
23 Q. Please explain this concept.
24 A. When asked why additional nomination windows are not offered to shippers TransCanada, in
25 response to Gaz Metro Round 1 Information Request #61.5 provided the following rationale:
16
the Mainline, bumpable IT would likely not have a material benefit to the value of FT
2 service at this time."
3 TransCanada contends that the provision of extra nomination windows to Firm Transportation
4 contracts is not possible because the Mainline is operated as a no bump pipeline. However,
5 TransCanada also indicates that with the excess capacity available on the Mainline the
6 introduction of bumpable services to facilitate the additional nomination windows would not
7 add any value for firm shippers. These positions are clearly at odds. The MAS believe that the
8 introduction of additional nomination windows for Firm Transportation contracts would greatly
9 enhance TransCanada's service offerings and would not constrain TransCanada's ability to
10 operate the Mainline. Given the load balancing requirements of the MAS additional nomination
11 windows for Firm Transportation contracts would be a service enhancement valued by the MAS
12 (and potentially other shippers as well).
13 Q. What is the position of the MAS regarding TransCanada's Alberta System Extension
14 proposal?
15 A. As discussed above the MAS support the principle that all parties who benefit from the
16 Mainline should make some contribution toward lowering Mainline tolls. This contribution
17 must be enduring for a period of time at least equal to the term of the MAS Alternative
18 Proposal. The Alberta System Extension is consistent with that principle, however, the MAS
19 take no position on whether this is the preferred way to achieve such a contribution from WCSB
20 producers.
21 Q. Can you please provide context for this principle?
22 A. In response to IGCAA Round 1 Information Request #29 TransCanada states:
23 "The proposed changes to the Alberta System are required as part of the Restructuring.
24 Absent approving the Alberta System Extension, Alberta System shippers would derive
25 substantial benefits from the balance of the Proposal without making a direct contribution."
26 Furthermore, in response to NEB Round 1 IR #2.8 TransCanada states:
18
1 "...while producers currently contract for virtually no capacity on the Mainline and the
2 Foothills System, the total infrastructure of the TransCanada Pipelines Systems was put in
3 place over the course of decades to serve the needs of producers. The premise of the
4 facilities expansion, supported by producers, was that increased capacity out of the WCSB
5 was in the Canadian public interest and would be utilized to transport WCSB gas to markets
6 over the economic life of the infrastructure. Further, producers persuaded regulators to 7 approve shorter term contractual commitments for the recovery of the cost of the
8 infrastructure. Those costs — prudently incurred to provide producers with market access —
9 must now be recovered in current and future tolls despite the absence of continuing
10 contractual commitments from those who urged TransCanada and the Board to approve the
11 investment in the infrastructure on the basis of current and future need."
12 The MAS hold a large portion of all Mainline contracts and pay a majority of the Mainline
13 revenue requirement which includes the costs of facilities originally put into service to provide
14 market access for producers. Many producers currently do not make a direct contribution to
15 the Mainline revenue requirement in the form of holding Firm Transportation contracts with
16 TransCanada.
17 Q. If the NEB does not approve the Alberta System Extension proposal do the MAS have any
18 recommendations for the Board?
19 A. Yes. The MAS recommend that, if the Alberta System Extension is not approved, other
20 mechanisms be explored to ensure that all parties that derive a benefit from the Mainline make
21 a fair and appropriate contribution.
22 Q. Have the MAS determined the toll impact of the Alternative Proposal?
23 A. Yes. Black & Veatch developed a toll model which replicates as closely as possible the tolls
24 proposed by TransCanada under its Restructuring Proposal. This model was then used to
25 compare the tolls that would result from implementing the MAS Alternative Proposal to the
26 expected tolls under TransCanada's Restructuring Proposal. This analysis was carried out to
27 2025 in order to assess short-term and long-term impacts of the MAS Alternative Proposal.
19 ENBRIDGE GAS DISTRIBUTION INC.
COMPENDIUM
OF
REFERENCES
TAB 17
1 National Energy Board 2 RH-003-2012
3 TransCanada Mainline Restructuring Application
4 Appendix A: MAS Response to Generic Questions Posed by the Board
5 In considering the Board's generic questions MAS has the following comments:
6 Vision
7 Q. What is your vision for the Mainline 5 to 7 years from now?
8 A. The MAS share the following forward looking perspective of the Mainline beyond the test
9 period:
10 1) Eastern Triangle
11 The MAS view the Eastern Triangle as a robust, expanding system, fully contracted and
12 operating at relatively high load factors. The Eastern Triangle remains necessary in serving
13 customers of the three MAS LDCs despite changing supply dynamics across North America.
14 From this perspective the MAS shippers remain captive on the TransCanada system. As supply
15 shifts in North America it is likely that shippers in eastern Canada will diversify their supply
16 portfolios and source natural gas supply from new sources arriving into Canada at
17 Niagara/Chippawa and Dawn. The Eastern Triangle is necessary for these new supplies to reach
18 the market.
19 It is therefore likely that short-haul will represent a greater proportion of Mainline system use
20 over the next decade. Recent contracting decisions are evidence of this. Gaz Metro and Union
21 requested contracts with TransCanada in 2012 for an additional 250,000 Gild and 110,000 GJ/d
22 for deliveries to the GMi-EDA and Union NDA and EDA respectively commencing in 2014. Both
23 Gaz Metro and Union executed long term 10-year agreements to support much needed
24 facilities along the path from Dawn to market, expecting the capacity to be available in 2014.
25 Disappointingly this project will be delayed until 2015. Having access to capacity through the
1
1 existing Parkway to Maple bottleneck will be critical in allowing the market to develop and
2 access new and economic sources of supply.
The MAS share Mr. Johannson's concern about "leakage" of problems from other parts of the
4 Mainline system. Shifting of costs, by whatever means, must not be permitted to impair
5 fairness in the setting of short haul tolls in the Eastern Triangle. To the extent that
6 TransCanada's Restructuring Proposal (RP) affects the Eastern Triangle, it may cause the next
7 "accident", which must be avoided. Appropriately set tolls will facilitate expansions of eastern
8 segments of the TransCanada system and provide for cost effective delivered service for
9 eastern consumers.
10 As a result of changing flows the MAS support consideration of segmented tolling on the
11 Mainline. This is more fully discussed in the MAS' comments respecting TransCanada's response
12 to U-45.
13 2) Mainline Long Haul
14 The MAS expect continuing challenges over the next decade in attracting significant
15 incremental Western Canadian Sedimentary Basin (WCSB) supplies to the TransCanada system
16 at Empress to serve eastern Canadian markets.
17 The availability of WCSB gas to serve Eastern markets has dramatically declined from 11.9 Bcf/d
18 in 2007 to 9.0 Bcf/d in 2011 1. Concurrently, Mainline Western Receipts have declined from 5.7
19 Bcf/d to 3.2 Bcf/d over that same period 2. The changes in gas supply and demand balances over
20 time have contributed to the escalation in Mainline tolls with, for example, the Empress to
21 Eastern Zone toll increasing from $1.03/GJ in 2007 to $2.24/GJ in 2011. The MAS foresee
22 decreasing reliance on WCSB gas supplies serving eastern markets.
23 In Alberta, near term effects of low gas prices combined with growing intra-Alberta demand
24 from oil sands will impact the amount of gas available for export from Alberta. Significant
25 increases in U.S. based supply immediately adjacent to the eastern market area signal less
1 B40, Appendix Cl: Throughput Study, Page 52 of 79 2 B40, Appendix Cl: Throughput Study, Page 53 of 79
2
1 reliance on WCSB supply via the Mainline. Development of alternative supplies such as those in
2 the Marcellus and Utica basins present opportunities for new and cost effective supply options.
3 In light of these supply and market developments, MAS continue to foresee the need to
4 substantially reduce Mainline costs. The MAS Alternative Proposal accomplishes this by
5 allowing TransCanada to recover the entire Northern Ontario Line investment over a nine year
6 period in conjunction with a contribution in the form of reduced return. Conversion of a part of
7 the Mainline to oil may also be an opportunity to reduce costs as well.
8 Q. Are we likely to relive the dramatic change in the environment that occurred between
9 2006 and 2010 on the Mainline?
10 A. The MAS note that the rapid and dramatic changes recently experienced do not preclude
11 the possibility of a similar situation occurring again. The only certainty is change. Advances in
12 new technology which allow access to previously unrecoverable resources or the discovery of
13 new sources of natural gas supply and the resultant impacts on natural gas flows and
14 infrastructure are extremely difficult to predict. In addition, LNG demand may represent a
15 larger opportunity for WCSB producers.
16 Q. Can you envision an economically viable Mainline that relies less on FT and relies more on
17 other services? And if so what would it take for this new reality to be sustainable?
18 A. The MAS expect continuing reliance on short haul FT and less reliance on long haul FT.
19 Where excess capacity exists, to the extent that it remains in service, other service options may
20 be plausible provided that market power and transparency concerns can be satisfactorily
21 addressed. MAS believe there is no reason to depart from cost-based tolling for those portions
22 of the Mainline that can support the continued use of this approach.
23 Regulatory Process
24 Q. How can regulation respond to changes in a fast changing world?
25 A. MAS believe that regulation must be forward-looking to embrace rather than resist an ever
26 changing landscape for the natural gas market. Canadian consumers should not be delayed in
3
1 realizing the benefits of competitively priced new supply located in close proximity to markets.
2 Tolls should not be distorted to favour one source of supply over another nor one transporter
over another. Regulation must be capable of providing the necessary direction to ensure fair,
4 efficient and sustainable outcomes in a fast changing world. Regulation has in place the tools
5 for market participants to determine and negotiate the responses required to respond to a fast
6 changing world provided all parties are working from an appropriate base and with appropriate
7 regulatory direction. Regulatory direction should lay out the principles and framework which
8 TransCanada and its shippers need to consider, and it should reflect the changes that have and
9 continue to take place in North America.
10 Q. How can regulation change to allow for increased pricing discretion or risk-sharing?
11 A. MAS do not believe that implementing pricing discretion is an option that can be
12 implemented for the 2012 and 2013 test years. Maintaining current cost allocation and rate
13 design principles and requiring contributions from all Mainline stakeholders per the MAS
14 Alternative Proposal are important for setting an appropriate base for the 2014 test year and
15 beyond. Changes in regulation post 2013 must ensure that shippers continue to pay reasonable
16 cost based tolls where sustainable. Where increased pricing discretion and risk sharing are
17 necessary to ensure reasonable tolls, regulation must exercise oversight to ensure that the
18 market continues to exhibit sufficient competition and that risk sharing is fair to all parties. The
19 MAS comments on TransCanada's response to U-45 discuss one possible scenario within which
20 these concepts could be accommodated.
21 Toll Methodology, Services and Pricing
22 Discretionary Services
23 Q. Is it appropriate to allow for increased flexibility and increased risk and reward in pricing
24 of discretionary services and if so:
25 Q. How should it be transitioned?
26 Q. When should it be implemented?
4 1 Q. What mechanism should be used?
2 Q. Is it consistent with the regulatory compact?
3 Q. Should TransCanada assume some risk for underutilized capacity?
4 Q. What information should be provided to customers?
5 A. MAS believe that increased flexibility and increased risk and reward in pricing of
6 discretionary services could be implemented but only after concerns about the extent of
7 TransCanada's potential market power are satisfactorily addressed. As TransCanada noted in
8 its response to U-45 at page 8, the competitive value of each Mainline path over an extended
9 period of time is difficult to ascertain. The appropriate framework for risk-reward and
10 transparency must be addressed prior to implementation of pricing flexibility or any other
11 alternative tolling methodology.
12 Q. Should the Board provide direction on pricing and service flexibilities and TransCanada
13 occupying the at risk space, beyond what can be implemented in this proceeding?
14 A. The MAS believe that, within a proper framework, consideration of pricing discretion,
15 service flexibility and risk sharing options could be helpful for all parties in working toward an
16 effective solution for the Mainline post 2013. The MAS would welcome direction from the
17 Board in this regard.
18 Multi-Year Fixed Pricing Service (MFP)
19 If MFP were implemented, should it be implemented with an incentive or risk mechanism and
20 if so:
21 Q. What should the mechanism be?
22 Q. What degree of risk sharing is appropriate?
5
1 Q. Could "at-risk" MFP work alongside the MFP described in section 8.0 of the Application?
2 A. Market power concerns, particularly as they relate to captive customers like the MAS
3 members suggest caution in applying "at-risk" or market based tolling methods, particularly
4 given TransCanada's acknowledgment of the difficulty in ascertaining the competitiveness of
5 various transportation paths. Please refer to the MAS comments on TransCanada's response to
6 U - 45 for a description of the factors that the MAS believe should be taken into account when
7 adopting an incentive or risk mechanism related to the MFP concept.
8 Core/Non - Core
9 Q. What factors should TransCanada, its stakeholders and the Board consider in determining
10 whether it is appropriate to move to a core/non-core kind of business model?
11 A. Beyond the test period, MAS believe that the Core/Non-Core concept is a potential
12 alternative. However this alternative should be only considered in conjunction with cost based
13 tolls and segmentation of the Mainline for tolling purposes. Please refer to the MAS comments
14 on TransCanada's response to U-45.
15 Market Based Rates
16 Q. How and where could TransCanada have market based rates?
17 A. In order to have market based tolls a competitive transportation market must exist.
18 Currently many, if not most, paths on TransCanada do not operate in a competitive market
19 which would preclude the adoption of market based rates.
20 Involvement in Commodities
21 Q. How would TransCanada's involvement in the commodity market work in the context of
22 regulation and what impact, if any, would it have on you?
23 A. The MAS members cannot conceive of a scenario in which TransCanada's involvement in
24 the commodity market would provide benefits to shippers or end-users.
6
1 Cost of Capital — Debt Costs
2 Q. To what extent would it be appropriate for TransCanada to be at risk for the cost of new
3 debt issuances going forward such that cost-of-service tolls would recover the market cost of
4 new debt, with a possible commensurate increase in the allowed rate of return?
5 A. In the event that the Board approves an ATWACC methodology for TransCanada in this
6 proceeding the MAS note that TransCanada has accepted that they should be at risk for the
7 cost of new debt issuances going forward.
8 The MAS Alternative Proposal includes debt cost savings as a component of its incentive
9 mechanism. If the Board were to grant TransCanada's request for the change in methodology,
10 debt cost savings would not qualify for inclusion in the incentive mechanism.
11 Toll Spiral
12 Q. What should the Board do if it were to find that its decisions on the individual aspects of
13 the restructuring proposal and intervenor proposals would still produce tolls that would be
14 part of a toll spiral?
15 A. In the MAS' view this would imply that, based on the evidence presented in this case, the
16 Board would find that the cost structure underpinning tolls was too high to be supported by
17 projected billing determinants. In this case the Board would presumably provide a decision on
18 final tolls for the 2012 and 2013 test years along with guidance and a framework on how to
19 arrive at a solution for the Mainline post 2013. This would require identification of an amount
20 of costs that would not be included in tolls. The guidance and framework provided by the
21 Board would provide direction on how these costs are to be treated when working towards a
22 solution for the Mainline. Please refer to the MAS comments on TransCanada's response to U-
23 45 for a description of one possible solution for the Mainline that could be explored.
7
Mainline Viability
2 Q. Should the Board be concerned about the viability of the Mainline?
3 A. Yes. The Mainline has and will remain an integral part of the market for natural gas in
4 Canada and the U.S. for the foreseeable future.
Q. Can any lessons be learned and imported from the US experience, as part of the evolving
6 Mainline toolkit, to make the Mainline continue to move in an economically-viable fashion?
7 A. MAS welcome and will consider any proposal that will improve the viability of the Mainline.
8 The FERC has dealt with many of the same issues and ideas in the past and have held many
9 generic hearings that have resulted in the current competitive market with pipelines bearing
10 some risk. These are complicated issues that require full examination. Please refer to the MAS
11 comments on TransCanada's response to U-45 for one such proposal.
12 Q. To what extent is the WCSB's continued viability tied to that of the long-haul Mainline
13 service to eastern markets? (New Question)
14 A. The WCSB's continued viability is not tied to TransCanada's long-haul service to eastern
15 markets. Natural gas flows will respond to changes in demand for and supply of natural gas.
16 Recently announced projects which will enable the westerly flow of WCSB supplies and flows of
17 supplies from the U.S. into Ontario and onto Quebec are evidence of this. Regulation should
18 accommodate rather than delay or impede these changing flows by approving the timely
19 expansion of facilities necessary to accommodate them.
20 Undertaking #45
21 Q. Do you have a view on the viability of the scenario outlined in undertaking 45?
22 Q. Do you have any comments on TransCanada's response to Undertaking 45 (once filed)?
23 A. In the scenario presented by Board counsel that led to U-45, TransCanada was asked to give
24 its impressions about a situation where a full cost based tolls methodology was not producing
25 just and reasonable tolls on some or all paths, that these FT tolls needed to be set lower using
8 1 another methodology, and that TransCanada would be given unlimited flexibility to determine
2 pricing for discretionary services.
3 TransCanada produced an answer containing its views about the scenario. The MAS agree with
4 TransCanada in several respects:
5 1) Fundamental changes to the regulatory model should be considered through a fair process
for all stakeholders including TransCanada and its shippers; such fundamental changes are
7 not possible for 2012 and 2013;
8 2) As long as a cost-based methodology produces tolls that are just and reasonable, it should
9 remain the basis of the regulatory model;
10 3) The regulatory model should not have a "paralytic effect" on TransCanada's ability to invest
11 in facilities where billing determinants support such costs;
12 4) TransCanada must be provided a reasonable opportunity to earn a fair return on and of
13 prudently-incurred costs; and
14 5) To the extent that a cost-based methodology produces tolls that are not just and
15 reasonable - implying that a reduction from the cost of service is required - a fair sharing of
16 the risk of non-recovery of certain costs should be determined and properly bounded by
17 clear rules.
18 However, TransCanada also persisted in asserting — repeatedly — that the RP addresses current
19 Mainline needs and provides an appropriate platform for future change. The MAS could not
20 disagree more strongly. The RP serves only to shift costs in a manner that would ultimately
21 obscure the main issue facing the Mainline which is a cost structure that cannot be supported
22 by current and projected billing determinants. The cost shifts requested in the RP will distort
23 the costs related to each segment of the Mainline in a manner that will make future
24 determinations of a viable tolling model for the Mainline all the more difficult to ascertain.
25 TransCanada and its experts, who were questioned on numerous occasions by intervenors and
26 the Board about the need to change the current regulatory model, have stated repeatedly that
9 1 the need to move away from the current cost-based regulatory model was "a long way" 3 from
2 today. It is obvious from the various and diverse interventions in this proceeding that this is
3 simply not the case.
4 Dramatic changes in the supply and demand environment surrounding the Mainline have been
5 occurring for a number of years. These changes can be expected to continue and increasing
6 pressure on the viability of the Mainline requires a close and careful consideration of
7 fundamental structural changes in the near term.
Common among the intervenors' positions (but notably absent from TransCanada's approach
9 to this proceeding) is recognition of the difficulty in maintaining the current cost-based
10 regulatory model in the face of drastic changes in the natural gas market. Intervenors agree
11 that current and declining billing determinants on the Mainline are not sufficient to cover the
12 full cost of service of the Mainline. TransCanada persists in denying this reality.
13 TransCanada must be provided with a reasonable opportunity to recover its cost of service.
14 However the MAS are obliged to serve their customers efficiently and to respond appropriately
15 to changes in the market for natural gas. The MAS regulators expect them to act in the best
16 interest of their rate payers. In a market characterized by options from multiple basins it is
17 reasonable and prudent for the MAS to shift and diversify their supply sources. There will
18 inevitably be shifts in both market demand and supply flows as the economics of various supply
19 options change. Impacts on shippers and ultimately end-use customers must be a component
20 of determining just and reasonable tolls.
21 Views on the Viability of the NEB Scenario
An enduring solution must allow for just and reasonable tolls for shippers and a sustainable and
reasonable opportunity for TransCanada to earn a fair return on and of its prudently-incurred
24 investments. The MAS welcome proposals and guidance from the Board and have some
25 preliminary thoughts on a multi-step process to accomplish the scenario outlined by the Board. 1223
3 T34 — paragraph 6248
1 0
1 So long as they are just and reasonable, cost-based tolls should remain the basis of the
2 regulatory model. Further, the MAS believe that it is not practical for the Board to set tolls on
3 every path based on the cost of an alternative.
The division of the cost of service between core and non-core activities along with a full
5 understanding of the costs to provide service along various paths is a potential idea that should
6 be explored along with other options. One option would be the division of the Mainline into
three segments: Prairies, Northern Ontario Line and the Eastern Triangle. The MAS offer the
following for consideration by the Board and other stakeholders as one example of a possible
framework for such a segmented approach to Mainline tolling:
10 1. TransCanada's rate base and operation costs would be segmented between the current
11 segments of the Mainline to obtain three segmented costs of service;
12 2. Volumes from firm transportation would be forecasted for each individual segment;
13 3. Tolls would initially be calculated using the current toll-setting methodology applied on
14 a segmented basis. Depending on the reasonableness of the resulting tolls, there would
15 be two paths for the Board to set the FT tolls:
16 a. When deemed reasonable, the cost-based toll would prevail;
17 b. Otherwise, FT tolls would be set at a lower level than cost-based, relying on a
18 pre-determined method;
19 4. The segmented firm tolls would serve as a recourse rate for all shippers in order to
20 prevent potential abuse of market power by TransCanada. TransCanada would be
21 provided with additional flexibility to maximize discretionary revenues;
22 5. At year end, the actual total cost of service of TransCanada would be subtracted from
23 the actual revenues originating from the segmented firm tolls and from discretionary
4 revenues. Any under or over earnings would be placed in a variance account and t 2 25 disposed of according to a pre-determined transparent method which would include
26 sharing of risk/reward.
27 In general terms such an approach would feature a more direct cost allocation among segments
28 and increased flexibility for TransCanada in respect of discretionary services. This approach
11
could potentially be used in conjunction with elements of other proposals currently before the
Board in this hearing. For example, a full return of NOL capital over a reduced economic
planning horizon as contemplated in the MAS Alternative Proposal could be carried forward 4 and applied to the segmentation approach. However, the toll design and services would be
determined specifically and individually for each system segment.
The MAS consider that such an approach has the potential to achieve just and reasonable tolls 7 while also providing TransCanada a reasonable opportunity to earn a fair return on and of its
prudently-incurred investments.
It would not be practical, nor in the public interest to implement such significant changes
0 immediately. Measured steps will be required and the MAS respectfully encourage the Board
to immediately initiate a process — and provide relevant guidelines —through which
12 TransCanada and other stakeholders could consider implementation of such an approach.
13 Among the various elements that should be considered as part of that process are:
14 1. Cost allocation methodology to determine the segmented costs of service;
15 2. Price flexibility, transparency and monitoring in discretionary pricing;
16 3. Sufficient regulatory oversight, especially to prevent the abuse of market power and to
17 satisfactorily respond to and address any shipper complaints;
18 4. Process and onus to demonstrate the reasonableness of the cost-based tolls;
19 5. Determination of the just and reasonable tolls when cost-based tolls are deemed
20 unreasonable;
21 6. Determination of the appropriate sharing of the risk/reward and by extension variance
22 account disposition.
23
24
25
12 Implementation of the Scenario
In its response to U-45 TransCanada states:
"... the existing low-risk/low return regulatory model should be modified through more
modest sets of changes over time. A phased-in approach to change would allow the
Board, TransCanada, its investors, and all stakeholders to incorporate the information
gained from the activities undertaken to that point to re-evaluate the appropriateness of
implementing further change (i.e., a "gated decision making process"). "4
The MAS agree with TransCanada in this regard. It would not be practical or in the public
interest to implement significant changes immediately. Significant change will have to occur in
10 measured steps with guidance from the Board. Implementation of significant change is simply
11 not possible for the test year period under consideration in this proceeding and any guidance
12 provided by the Board should pertain to test years 2014 and beyond. The MAS respectfully
13 suggest that the Board provide guidance and initiate a process for the investigation and
14 implementation of changes to the current regulatory model. The MAS believe the model
15 suggested above warrants significant consideration as part of this process.
16 The MAS do not underestimate the challenges associated with pursuing the development and 17 implementation of this sort of regulatory model. However, the approach outlined above is a 18 potentially viable means of increasing the long-term sustainability of the Mainline and one that 19 is worthy of serious consideration.
20 Next steps
21 The MAS interpret the Board's generic questions to indicate that it has recognized the difficult
22 circumstances confronting the Mainline and the urgent need for substantial and innovative
23 solutions to address these circumstances. The MAS believe the extraordinary amount of energy,
24 thoughts and views that have been brought forward by all stakeholders in this proceeding have
4 1381, TransCanada Response to Undertaking U-45,pages 11-12
13
been beneficial in shedding light on the challenges facing the Mainline and the possible
solutions to improving viability of the Mainline.
Unsuccessful attempts to reach settlements prior to the current hearing are due mainly to the
profound differences in stakeholders' views on who should contribute to solving the current
challenge.
The MAS respectfully urge the Board to include in its decision guidance on stakeholder
contributions. Guidance in this regard may include:
1. What is the extent of the regulatory protection for shareholders? 9 2. Is there a limit to cost-based tolls? 10 3. Should the Board intervene to prevent a potential armageddon scenario? 11 4. What are the signs that should lead the Board to intervene to protect the public 12 interest? 13 5. Should all stakeholders who benefit, directly or indirectly, from the Mainline support a 14 share of the associated costs?
15 Once guidance is provided stakeholders will be better equipped to reconcile current differences
16 of opinion and agree on the changes required to restore Mainline viability.
17 MAS believe that its Alternative Proposal, if applied to the derivation of tolls for 2012 and 2013, 18 would be the most suitable to allow parties to negotiate, from an appropriate base, a solution 19 that will address the long-term viability of the Mainline.
14 Attachment A7 Tab 12 Part A – Review and Variance Application Exhibit C61-12, RH-003-2011, Tenaska Marking Canada Opening Statement and Response to Board Questions.
NATIONAL ENERGY BOARD
TRANSCANADA PIPELINES LIMITED, NOVA GAS TRANSMISSION LTD., AND FOOTHILLS PIPE LINES LTD. (“TRANSCANADA”)
BUSINESS AND SERVICES RESTRUCTURING PROPOSAL AND 2012-2013 MAINLINE FINAL TOLLS APPLICATION
HEARING ORDER RH-003-2011
TENASKA MARKETING CANADA OPENING STATEMENT AND RESPONSE TO BOARD QUESTIONS
The purpose of this Opening Statement is to set out Tenaska Marketing Canada’s (“Tenaska’s”) responses to the questions set out in Appendix A to the Board’s letter of September 7, 2012 filed as Exhibit A34-1.
5 Vision
1. What is your vision for the Mainline 5 to 7 years from now?
Introduction 10 Throughout its evidence Tenaska has emphasized the importance of maintaining and improving the competitiveness of the Mainline. For Tenaska competitiveness is not a vague or abstract ideal. It is a concrete quality of the Mainline system that arises directly from how the pipeline’s tolls and tariffs are structured and priced. Tenaska’s vision for the Mainline, where a “vision” is a 15 hoped-for and reasonably achievable outcome, is one in which the Mainline becomes much more competitive in attracting new supply and market, that increased competitiveness attracts new discretionary IT, STFT, and FT shippers to the system, and that new market activity materially 2
increases flows and revenues, reduces tolls to more reasonable levels, and ultimately makes all stakeholders better off.
Tenaska believes that a much more competitive Mainline, and the new business and incremental 5 flows it would generate, are achievable within the existing regulatory model based on proposals that have been advanced in this case by TransCanada and Tenaska. In what follows we briefly describe the elements of a more competitive Mainline that we believe would be able to attract significant new business under the existing service structure and the Mainline’s existing toll- making methodology. 10 At the same time, Tenaska recognizes that the Board has expressed an interest in parties’ views on the need for and potential value of a more fundamental rethinking of the Mainline’s services in the current environment, and we will describe here in general terms the approach we believe could be effective in pushing the Mainline further down the competitive path if that becomes 15 necessary.
Background and Nature of the Problem
The problem that Mainline stakeholders face is that tolls are very high and throughputs are very 20 low. That is a consequence of the fact that the Mainline has been a bad competitor. While that has not been entirely TransCanada’s fault, the fact is that the Mainline has lost roughly 2/3 of its customers over the past several years. If it were in a competitive business it would likely be in financial distress.
25 The reason the Mainline is still in business, and TransCanada continues to earn its full allowed return, is that there is a significant domestic consumption load in eastern Canada that is almost completely captive to the Mainline and that, because it has no alternatives, has endured a more than doubling of Mainline transportation tolls in just a few years.
30 In order for Mainline tolls to be reduced, and the lot of captive customers to be improved, more gas has to flow on the system. The Mainline has to compete more effectively to attract more 3
business in order to average down the unit fixed costs that are now borne mostly by captive customers. Obviously anything that can be done to reduce the system’s costs will be helpful, but those costs are largely fixed, absent some large disallowance.
5 When we are considering the issue of how to increase throughput on the Mainline, the important issue is not the effect of the toll level on the existing captive customer base. The captive load will not increase if Mainline tolls decline, because it is a physical requirement that is already being met with existing services. That load will not decrease if tolls go up, precisely because it is captive and has no economically viable alternatives. 10 The question of how to reduce tolls and make consumers better off therefore comes down to one of how the Mainline can attract “discretionary” business. By that we mean gas that flows not because it physically has to, but because the operation of the integrated continental natural gas transportation and gas commodity market makes that economically attractive. For these purposes 15 it does not matter whether discretionary flows happen under IT, STFT, or FT services. Those are all simply tools that market participants can use in responding to economic signals in the course of facilitating competitive or discretionary gas flows.
As a practical matter, given how the market generally operates, the main focus will often be on 20 short term services, i.e. IT and STFT, but FT service can also be used as a “discretionary service” in the sense that it is used to transport discretionary volumes. For these purposes we are therefore not concerned solely with short term services, and part of Tenaska’s vision for a more competitive Mainline concerns the attributes of FT service and its usefulness as a vehicle for competitive activity. Tenaska and other marketers have utilized FT in that way extensively in the 25 past, and Tenaska would like to be an FT shipper for its own account in the future.
If the objective is to have the Mainline attract more business and flow more gas, the incremental gas has to come from somewhere, and it has to go somewhere on competitive terms. To the extent we are concerned about the long-haul system, that means that it must be economically 30 possible for someone, i.e. marketers, to go into the Alberta market and bid gas away from GTN, Northern Border, and Alliance, and then sell that incremental supply into a downstream market 4
at a delivered price that will attract buyers who have alternatives. On the Mainline, that means primarily markets at Emerson, Dawn, and potentially eastern export points like Niagara and Waddington.
5 The variable in all of this that is within the control of the Board is the design and pricing of discretionary services, where those include IT and STFT, but also FT to the extent that it can be used by parties like Tenaska to move incremental discretionary volumes. What that means, if the objective is to move more gas on the Mainline, is that the Board must make the Mainline’s discretionary services – including all of IT, STFT, and FT – better and cheaper and more 10 valuable to potential discretionary shippers than they are now.
Maintaining the Existing Competitive Level
As a first step in making the Mainline more competitive the Board should at least avoid making 15 the system less competitive, which is what approval of many of TransCanada’s proposals would do. The Application includes at least three proposals that would reduce the competitiveness of the Mainline.
First, Tenaska believes that the ASE is a flawed concept for various reasons, but on this issue in 20 particular it explained in its evidence how implementation of that scheme would add costs and risks to commodity markets on the Mainline and make the Mainline less attractive as a vehicle for moving discretionary gas.
Second, TransCanada’s proposals to increase the bid floors for IT and STFT services are obvious 25 examples of proposals that would make services that can be used to move discretionary volumes less competitive by making them potentially much more expensive. Tenaska’s position, as outlined in its evidence and as explained in the responses to other Board questions, is that increasing IT and STFT tolls, whether on a discretionary basis or not, would reduce Mainline flows and harm both consumers and producers by making discretionary services and 30 transportation paths less economic.
5
The third major TransCanada initiative that would make the Mainline less competitive is the elimination of RAM. The RAM feature of the existing long-haul FT service facilitates the movement of discretionary gas flows by enabling FT shippers to utilize alternate or non-primary paths to access discretionary markets when market conditions permit. The commercial effect of 5 RAM is to reduce the cost and increase the value of FT service by a very significant amount, and if the Mainline is to ever attract new discretionary shippers and new discretionary throughput using the FT service it is essential that RAM be retained.
Even in the current market the RAM feature has enabled ‘traditional’ FT shippers to use their FT 10 entitlements in the secondary market to attract significant discretionary throughputs to the system by providing short term transportation at a lower cost than the Mainline can. In addition to benefiting the FT shippers by reducing their delivered gas costs, that activity has significantly increased physical flows on the Mainline, reduced prices in competitive markets at Emerson and Dawn, and created new and incremental demand for gas in Alberta for the benefit of WCSB 15 producers.
Eliminating RAM would therefore not only foreclose any possibility of the Mainline ever attracting new FT shippers, it would effectively eliminate the secondary market on the Mainline and make the Mainline less competitive than it is now, and almost all Mainline stakeholders 20 worse off than they are now, by eliminating those discretionary flows and the associated benefits for FT shippers.
Increasing Competitiveness Under the Existing Regulatory Model
25 Merely preventing the Mainline from becoming less competitive than it already is does not address the question of how the Mainline can be made more competitive. Tenaska sees three main improvements that can be made to the Mainline’s tolls and tariffs within the existing regulatory model that would make the system more competitive.
30 First, whatever its other shortcomings, the Restructuring Proposal includes various cost of service proposals, including lower depreciation rates, lower O&M costs (relative to the levels 6
embedded in current tolls), and perhaps implementation of the long term adjustment account, that would meaningfully reduce the Mainline’s revenue requirement. Those proposals, in conjunction with a reasonable ROE and any other cost reductions the Board might order, would reduce the base level of tolls and improve the overall competitiveness of the system. 5 Second, improving the competitiveness of the Mainline will require that tolls be made more stable and predictable. For marketers, the constant and uncontrollable risk of large and unpredictable changes in FT tolls during the term of an FT contract has made contracting for FT service as a discretionary marketing tool almost impossible since 2008. Tenaska is optimistic that 10 TransCanada’s proposed short term adjustment mechanism will stabilize tolls enough that those toll risk problems will no longer be an insuperable barrier to competitive marketing activity using FT service.
Third, the Mainline can be made more competitive by making the STFT service more flexible 15 and commercially useful. That service is hopelessly inadequate to the demands of the modern competitive gas market and the needs of potential discretionary shippers. Implementing Tenaska’s proposals for extending RAM and diversions to STFT and short-haul FT services would revolutionize the Mainline environment for discretionary shippers and generate numerous new opportunities for them to make firm commitments to the Mainline, go into Alberta and buy 20 gas that would otherwise move on other systems, and ship that gas to customers at downstream points at prices that make commercial sense.
Tenaska believes that with these improvements the Mainline would attract a great deal of new interest and new contracting activity from the marketing community. The fact that TransCanada 25 was recently able to attract an incremental discretionary FT shipper on the Empress/Dawn path demonstrates that, even with the current restrictions on RAM and in the face of the very high current tolls, the economics of incremental discretionary Mainline business are still at least close to being favourable even without the improvements we have identified. With those improvements, the scope for new activity and new discretionary flows would expand 30 considerably.
7
Long Term Alternative
Tenaska’s general view is that it would be reasonable in the context of this proceeding to implement the elements of a more competitive Mainline that we have identified within the 5 existing regulatory model, and then give the market some reasonable amount of time to show us what it can do if the existing constraints on the Mainline’s competitiveness are removed. Those improvements would continue to be necessary in order to enable shippers to compete with each other and with the pipeline to move discretionary volumes even if some further restructuring of the Mainline’s business model is undertaken. 10 Tenaska acknowledges that it may be possible to go further in promoting the competiveness of the Mainline by moving beyond the constraints of the Mainline’s existing business model. Probably the key factor in inducing discretionary flows on any pipeline is flexibility in the pricing of discretionary services, i.e. the ability to effectively discount tolls in order to meet 15 competition. Within the existing Mainline model it is primarily the RAM mechanism that creates that pricing flexibility through the commercial operations of firm shippers and the ability that RAM gives them to ‘flex’ tolls on various paths to capture market opportunities and create efficiencies that result in new discretionary flows. There is however a limit to the pricing flexibility individual at-risk shippers can provide in the secondary market because at the end of 20 the day they must recover in the market the full cost of the firm services that they contract for.
If it turns out that RAM flexibility and firm shipper ingenuity alone are by some measure ‘not enough’ to generate the increased levels of discretionary throughput that the Mainline is reasonably capable of, then the Board and the industry would want to consider more radical 25 approaches.
In Tenaska’s view that essentially means some version of the ‘discounting’ model that is in place for U.S. pipelines. Under that model pipelines are allowed to selectively discount the rates they charge below the cost-based level in order to attract and retain discretionary loads. If they do that, 30 they are also allowed to account for that discounting activity in the development of their transportation rates through a discount adjustment to the rates paid by captive or maximum rate 8
customers. This mechanism creates more “firepower” than is available to Mainline shippers using RAM in relation to the system’s ability to reduce prices for discretionary services, essentially because the discount adjustments recovered from captive customers allow the pipelines to operate from a lower cost base while still recovering all of their costs in rates. 5 Tenaska is not opposed in principle to a discounting model for the Mainline. If a fundamental change in the Mainline’s business and regulatory model is needed in order to bring the Mainline up to a reasonable standard of competitiveness, some variant of the discounting model is almost certainly the only practical and potentially effective alternative. If it is necessary to have a 10 ‘vision’ for the Mainline beyond what is achievable under the existing Mainline construct, the discounting model is it.
The model as it has been developed by the FERC over the past 25 years adheres to the principle that rates for all services and all shippers cannot exceed a cost-based level (including any 15 discount adjustment) and ensures that the pipelines’ rates are set at a level that gives them a reasonable opportunity to recover their costs. While in Tenaska’s view it is necessary under a discounting model to impose some level of throughput risk on the pipeline, to ensure that its pricing decisions are reasonable and ultimately benefit customers, that risk is in principle symmetrical and can be controlled through the toll-setting process. 20 At the same time, Tenaska has not recommended adoption of the discounting concept in this case, based on two general concerns. First, it is not obvious to Tenaska that a discounting model would necessarily be effective in the Mainline context and given the Mainline’s market circumstances. One obvious concern in this area is that the Mainline could choose never to discount, and 25 therefore never make an effort to attract incremental throughput, if that strategy would be beneficial for TransCanada as a whole in light of its interests in GTN, Northern Border, Great Lakes, ANR, Tuscarora, Iroquois, and Portland, all of which are in one way or another factors in the Mainline’s business. The Board and parties have no way of knowing what TransCanada’s incentives are in that connection, and forcing the Mainline to compete, e.g. by deliberately 30 setting tolls at a level that would not recover costs, would raise various issues.
9
A more practical concern for the purposes of this proceeding is that it would be very difficult to overstate the complexity and range of new issues that would arise in the course of developing a version of the general discounting model that would be appropriate and effective in the Mainline’s circumstances and within the broad framework of the Board’s approach to pipeline 5 regulation. Tenaska noted some broad categories of these in its direct evidence, and identified “the acceptable limits of toll discrimination, whether toll flexibility would actually increase revenues, inter-affiliate transactions, reporting requirements, what services could be discounted, the impact of changes in the Mainline’s risk on appropriate rates of return, the timing of rate applications, the need for and nature of mechanisms for prospectively accounting for discounts in 10 rates, and so on.”
While it would obviously not be impossible to develop a discounting model for the Mainline, it would be a very significant undertaking for the Board and the industry to, first of all, examine all of the potential issues around whether a discounting model would actually work and otherwise 15 be appropriate in the Mainline context, and then go on to actually identify and resolve the innumerable design and implementation issues that would present themselves.
2. Are we likely to relive the dramatic change in the environment that occurred between 2006 and 2010 on the Mainline? 20 Tenaska has no special insight into how the supply and market environment is likely to change, beyond what is indicated by TransCanada’s evidence. Tenaska’s only comment in this area is that, even if some new dramatic change occurs, it is not clear that it would necessarily affect regulatory practice or the pipeline’s business model. Ideally the regulatory regime and pipeline 25 toll methodology will be “robust” in the sense that they function adequately under a wide range of market scenarios.
30 10
3. Can you envision an economically viable Mainline that relies less on FT and relies more on other services? And if so, what would it take for this new reality to be sustainable?
Yes. The Mainline’s historical “reliance” on FT service has nothing to do with the viability of 5 the Mainline and does not enhance that viability. If anything, TransCanada’s preoccupation with “preserving the value” of FT has undermined the Mainline’s viability by making it less competitive than other pipelines that do not take such a narrow view. Ultimately the viability of the Mainline is a function of its ability to attract shippers, which is a function of the ability of shippers who use the system to operate successfully in upstream and downstream commodity 10 markets. If gas moves on the system, it makes no difference whether it moves under one-day, one-month, or one-year contracts.
If the Mainline wants to be competitive in attracting shippers, it should be selling whatever services the market wants, because that will maximize throughput and revenues, minimize tolls, 15 minimize consumer prices, and maximize producer prices. Whether “what the market wants” is 3-year firm service, 1-year firm service, 5 month firm service, or daily firm or interruptible service makes no difference in the end, especially to a pipeline that enjoys full revenue deferral accounts. In fact “the market” likely wants all of those services in different combinations at different times. 20 Historically the Mainline’s reliance on FT service has been the practical result of the Mainline making its short term services, especially STFT, as unattractive as possible, as Tenaska described in its evidence. As the market has evolved away from base-load long-term FT service provided to LDC’s, the net effect of TransCanada’s approach has likely been to reduce throughput by 25 restricting the range of commercially useful products that it offers. Potential shippers who do not want or need 1-year FT service, but who find the Mainline’s STFT commercially unworkable, have likely taken their business and their gas elsewhere, to the detriment of captive Mainline customers.
30
11
Regulatory Process
4. How can regulation respond to changes in a fast changing world?
5 Ideally the regulatory regime should be flexible enough to respond effectively to market changes without having to be modified on a continuous basis.
If the question is intended to suggest that there may be a difficulty with the slowness of the regulatory process, and that to remedy that problem a pipeline like the Mainline should be able to 10 unilaterally modify its terms and conditions of service, the design of its services, or the design or level of its tolls, without obtaining prior Board approval, Tenaska strongly opposes that suggestion.
5. How can regulation change to allow for increased pricing discretion or risk-sharing? 15 See generally the discussion in response to Q.1 and Q.6
Toll Methodology, Services, and Pricing 20 Discretionary Services
6. Is it appropriate to allow for increased flexibility, and increased risk and reward in pricing of discretionary services, and if so: 25 - How should it be transitioned? - When should it be implemented? - What mechanism should be used? - Is it consistent with the regulatory compact? 30 - Should TransCanada assume some risk for underutilized capacity? - What information should be provided to customers? 12
Tenaska is not opposed in principle to “increased flexibility” or discretion in the pricing of discretionary services, or indeed long term firm services. However, it believes that pricing discretion is only appropriate where the pipeline is financially at risk for the revenue 5 consequences of its pricing decisions, and that pricing discretion should only extend to reducing tolls below a cost-based level, and never to increasing them above a cost-based level.
Accountability and Risk
10 It is essential that a pipeline that has pricing discretion also bear the financial consequences of exercises of that discretion. The purpose of giving a pipeline pricing discretion is to enable it to make decisions that will benefit customers by attracting shippers away from competitors and increasing throughput. To the extent that captive customers bear the costs of those discounts, it is essential that there be a reasonable expectation that any discounting behaviour will “work”, in 15 the sense that it actually does increase revenues and is not a matter of the pipeline simply wasting shipper money. The regulator cannot supervise and monitor that effectively, so a pricing discretion scheme can only work (or at least be presumed to work) for the benefit of customers if the pipeline itself has a financial incentive to make appropriate and efficient pricing decisions and that incentive is exactly aligned with the interests of customers. 20 TransCanada’s pricing discretion proposal for IT and STFT services involves no risk for shareholders and no financial incentive for TransCanada to ensure that its pricing decisions result in any benefit for shippers or other parties. It should be rejected on that ground alone, although an even more fundamental problem is that TransCanada’s proposal involves a completely 25 inappropriate discretion to increase prices above the cost-based level.
At a general level, Tenaska believes that any incremental risk imposed on the pipeline should be symmetrical, i.e. with no expected impact on revenues or returns on average in the long term. It also believes that it is appropriate to limit the amount of risk imposed on the pipeline to the 30 minimum level needed to ensure that the incentives the risk is intended to create are effective and 13
achieve the purpose of benefiting customers. There is no point in imposing risk on the pipeline beyond that level.
Upward Discretion versus Downward Discretion 5 Much of the discussion of pricing flexibility and pricing discretion in this proceeding appears to assume that there is no important difference between discretion to adjust prices above a cost- based level and discretion to reduce or discount prices below a cost-based level. The Application itself contemplates only upward pricing discretion, as do the short term pricing proposals from 10 ANE. The Board’s NEB 6.4 and U-45 models appear to contemplate unlimited pricing flexibility in either direction, and it appears that some parties may support that concept.
Tenaska’s position is that there is an important difference between discretion to decrease short term tolls relative to cost and discretion to increase those tolls relative to cost. The ability to 15 discount tolls may be appropriate, because it may benefit all stakeholders by increasing throughput, decreasing tolls, reducing market area prices, and supporting producing area prices. It is on that basis that the FERC regulatory model allows discounting. Discretion to increase prices above a cost-based level, however, generally has the opposite effect, and should not be permitted. It is important to understand and highlight the adverse impacts and market costs that 20 discretion to set tolls for discretionary services at an above-cost level would create for market participants.
The rationale for giving pipelines the ability to impose above-cost short term tolls appears to be that it is beneficial because the extra revenue collected will be credited to long term FT tolls 25 under a cost of service toll methodology. In effect, the idea is that it is reasonable to charge above-cost tolls to short term shippers in order to subsidize below-cost tolls charged to captive long term shippers.
The central difficulty with this analysis is that it focuses only on pipeline tolls and ignores the 30 effects of higher short term transportation prices on the market and on the producers and 14
consumers that depend on the transportation system and competitive commodity markets at either end of the Mainline.
Supporters of upward pricing discretion for short term services may imagine that there is “free 5 money” to be extracted from short term shippers for the benefit of captive customers, but that is not so. Short term shippers will not absorb price increases for short term services. If the transport price goes up, for any reason, short term shippers will simply not buy service unless the commodity prices at either end of the path adjust to compensate. If the price of transport goes up, consumers must pay higher prices and/or producers must accept lower prices if gas is to continue 10 to flow. If gas does not continue to flow, consumers must find some more expensive alternative supply, and producers must find some less attractive alternative market.
No matter how the market reacts to a transportation price increase, the result must be some combination of higher costs for consumers and lower revenues for producers. The subsidy for 15 captive FT customers, if it materializes at all, will not come from short term shippers like Tenaska, but ultimately at the expense of gas consumers in the market area, e.g. Dawn, and gas producers in the production area, e.g. Empress/NIT, through adverse changes in commodity market prices.
20 From the perspective of consumers and producers, transport costs between Empress and Emerson, or for that matter NIT and Dawn, would ideally be zero, but the constraint under the regulatory model is that transport prices must be high enough to enable the pipeline to recover its costs. That is appropriate, and necessary in order to be fair to the pipeline’s owners. However, allowing the pipeline to charge a toll that is higher than what is necessary to meet that constraint, 25 i.e. higher than a cost-based toll, is pointlessly harmful to the consumers and producers the pipeline is there to serve.
The alleged benefit of allowing the pipeline to impose above-cost tolls on the market, i.e. below- cost tolls for captive customers, is not a genuine benefit at all, or at any rate will not come even 30 close to offsetting the losses suffered by other market participants.
15
First, it is not obvious, simply as a matter of fairness, why it makes sense to charge above-cost tolls to short-term shippers, and indirectly to the producers and consumers who depend on those services, in order to enable FT shippers to pay below-cost tolls.
5 In any event, increasing short term tolls may or may not actually increase revenues for the benefit of long term shippers, depending on the extent to which higher prices reduce the amount of service purchased. This goes to the existence and effectiveness of the financial incentives the pipeline has to actually maximize revenues. Even if an appropriate incentive is in place, that does not guarantee that the pipeline will respond appropriately to it by actually pricing at a revenue- 10 maximizing level, and there may be no way of checking whether it does or not. Higher short term transport prices might decrease revenues, or not change them at all.
If the pipeline is able to exploit upward pricing discretion to increase its revenue above what it would receive at cost-based tolls, captive shippers will benefit from paying below-cost tolls, but 15 that subsidy will not lead to any changed behaviour that would benefit anyone else in the market. The subsidy or discount is not needed to keep them on the system, because they are captive, and there is no reason to think that a minor subsidy to captive customers would induce them to increase their FT entitlements.
20 The most serious problem with the suggested justification for allowing pipelines to charge above-cost tolls for short term services is that the costs imposed on upstream producers and downstream consumers will almost always be far larger than the alleged benefit flowing to captive FT shippers. This is not a zero-sum game where any subsidy provided to captive FT customers through higher short term prices would equal the market losses of Alberta producers 25 and Dawn consumers. Market prices are determined on the margin, and in the Mainline context increases in the effective cost of short term transport on the Empress/Emerson path, for example, will affect market prices for virtually all gas purchased at Dawn and all gas sold at NIT. An increase in short term transportation prices on the Emerson path that increased pipeline revenues by $10 million per year could result in flow changes and commodity price changes at NIT and 30 Dawn that would cost producers and eastern consumers hundreds of millions of dollars per year.
16
The fact is that there is a fundamental disconnect between the pipeline’s interests and the interests of producers and consumers when the pipeline has discretion to increase tolls beyond the cost-based level necessary to enable it to recover its costs. A pipeline with upwards short term service pricing discretion will rationally seek to increase tolls to whatever turns out to be 5 the revenue maximizing level from its perspective, but those toll increases will always result in some combination of lower system flows, higher consumer prices, and lower producer prices that are almost certain to have negative effects on producers and consumers that far outweigh any benefit to the pipeline or other shipper groups.
10 Note as well that there is no way of making the pipeline “accountable” for those adverse system flow and upstream and downstream market price impacts on consumers and producers, because those impacts happen in the competitive commodity markets, outside the revenue stream of the pipeline.
15 Tenaska’s position therefore is that it is never appropriate to give the Mainline discretion to increase tolls for short term or discretionary services above a cost-based level. That is true whether discretionary toll increases happen under a mechanism like the one proposed by TransCanada with a 160% cap, or with a 300% cap as proposed by ANE, or under “market-based rate” authority, or “light-handed regulation”, or a discretionary pricing scheme with stripped- 20 down FT as a “recourse”. Tolls for discretionary services that are higher than the cost-based level needed to allow the pipeline to recover its costs are inappropriate no matter how they are arrived at.
With respect to the reasonableness of the pipeline having discretion to discount or reduce tolls, 25 see generally the discussion in the response to Q.1. With respect to the bullet-point implementation questions identified in this question, Tenaska’s view is that designing and implementing a reasonable discounting mechanism, assuming that was found to be appropriate, would be a complex exercise that would involve a detailed consideration of these issues and many more. At this point Tenaska has no specific suggestions on the matter. 30
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7. Should be Board provide direction on pricing and service flexibilities and TransCanada occupying at risk space, beyond what can be implemented in this proceeding?
5 Tenaska would welcome any observations or general directions from the Board concerning the direction it thinks TransCanada should be taking in relation to encouraging and facilitating competition in the market by the pipeline and firm shippers within a cost-based rate-making framework. However, Tenaska’s view is that further processes of some kind would be required in order for the Board to make well-informed decisions in relation to whether and how to 10 fundamentally alter the Mainline’s regulatory and business models.
Multi-Year Fixed Pricing Service (MFP)
8. If MFP were implemented, should it be implemented with an incentive or risk mechanism 15 and if so:
- What should the mechanism be? - What degree of risk sharing is appropriate? - Could “at-risk” MFP work alongside the MFP described in section 8.0 of the 20 Application?
At this point Tenaska is not in a position to offer an opinion on the appropriateness and design of the MFP service, although it may comment on the matter in argument.
25 As a practical matter it is unlikely that there would be any demand for an MFP service as proposed by TransCanada for the purpose of moving incremental discretionary gas on the Mainline. Without RAM no marketer-shipper will subscribe for long term firm service of any kind, whether FT or MFP. Even if RAM is retained and made a part of the MFP service, a three year minimum term would not be workable in the current market because there is insufficient 30 forward market liquidity that far into the future to enable shippers to take on the risks associated with a three year term. 18
Core/Non-Core
9. What factors should TransCanada, its stakeholders and the Board consider in determining 5 whether it is appropriate to move to a core/non-core kind of business model?
As we understand the core/non-core model, the Mainline’s rate base and revenue requirement would be divided into two components: (a) an FT or ‘core’ system for captive customers who would be charged cost-based rates derived from the costs allocated to the ‘core’ revenue 10 requirement, and (b) a non-core system that would be the responsibility of TransCanada, which it would use to provide services at essentially unregulated prices to all other customers, and from which it would retain all revenues.
At a high level, Tenaska believes that this model would reduce the competitiveness of the 15 Mainline and, under most variants of the model, make all stakeholders worse off than they are under the current model.
The problem is that the main point of the proposal appears to be to give the Mainline some version of market-based rate authority for all “discretionary” services, as we have defined them. 20 For the Mainline that almost certainly implies tolls that are higher than the cost-based level. Tenaska has explained in its response to Q.6 why pipelines should not be allowed to increase their tolls above a cost based level. Tolls that are higher than they need to be to enable the pipeline to recover its costs simply make the pipeline less competitive and result in some combination of lower throughputs, higher market-area gas prices, and lower producer revenues 25 than would be seen under conventional cost-based tolls.
Even without considering the mechanics of the proposed model, Tenaska therefore believes that the core/non-core model would be inappropriate because it involves what would amount to the deregulation of a significant portion of the Mainline’s business in circumstances where there is 30 no basis for doing that and the market result would be to make Mainline stakeholders worse off.
19
The other issues with the model revolve around the design of the tolls for the regulated or core FT service. On that issue the model would generate widely differing outcomes for core customers and TransCanada depending on how the allocation of the rate base and revenue requirement was done. 5 If the theory was that rate base and revenue requirement would be allocated to the core based on the ratio of FT or core capacity entitlements to system capacity, the practical effect would be to design the FT tolls based on system capacity rather than FT units. The calculated FT rates would then be comparable to the tolls that prevailed when the Mainline was fully booked with FT 10 service, but lower because the revenue requirement has declined since then. It is reasonable to expect that the eastern zone FT toll in that scenario would be considerably less than $1.00/GJ. TransCanada would then be faced with having to recover perhaps 2/3 of its revenue requirement from discretionary shippers. Even with market-based rate authority, that might be difficult to do.
15 On the other hand, if the allocation theory was that FT/core customers would be responsible for the costs of all facilities that their gas physically came in contact with during transportation, the allocation to core customers might be 95% of the revenue requirement. In that case FT tolls would be very high, i.e. much higher than today. TransCanada would then use its market based rate authority to maximize its revenue from non-core services in exactly the same way as it 20 would under the first cost allocation theory, absorb 5% of the revenue requirement as the “cost” of providing that service (rather than absorb 2/3 of the revenue requirement as in the first case) and keep the remainder as profit over and above the allowed return recovered from the core customers.
25 These two approaches would thus yield vastly different results in relation to the tolls charged to captive customers, the profitability of the scheme for TransCanada, and the allocation of costs and risks between TransCanada shareholders and captive customers. While it would be possible to devise some hybrid cost allocation methodology that did not so obviously favour either captive customers or TransCanada shareholders, it is not clear to Tenaska what that would be, or 30 that it would not end up being essentially arbitrary.
20
In any event, none of that would have anything to do with the market outcome on the discretionary services side of the ledger, where in either case the pipeline would simply maximize its revenues in the prevailing market circumstances, with whatever negative effects that generated for system throughputs and consumer and producer prices. It would then add those 5 revenues to whatever revenues it was entitled to get from the core customers and see how it did relative to cost. Under the “proportional” cost allocation scheme for the core service, with $0.90/GJ FT tolls, it might lose a lot of money, but under the second more pipeline-friendly scheme with $3.00/GJ tolls it would make a lot of money.
10 Market Based Rates
10. How and where could TransCanada have market-based rates?
Tenaska’s short answer to this question is that TransCanada should never have market-based 15 rates for any services, any customers, or any paths. Because market-based rates and various disguised versions of market-based rates have been discussed in this proceeding Tenaska wishes to set out its analysis of this question and explain the basis for its answer.
Market-based Rates 20 Market-based rates are simply an extreme version (i.e. in the sense that under market based rates the pipeline also sets the terms and conditions of service) of pricing discretion where the discretion extends to both increasing and decreasing tolls relative to a cost-based level. Tenaska has explained in its response to Q. 6 why it is inappropriate to allow a pipeline like the Mainline 25 to increase its tolls above a cost-based level, and market-based rates are simply one way of giving a pipeline that ability. To the extent the suggestion is that the pipeline be allowed to reduce its tolls below a cost-based level, that implies a discounting model that would raise various other issues, as discussed in Tenaska’s response to Q.1.
30 The fact that a pipeline faces some competition, in the sense that not all of its customers are fully captive in the way that most of the Mainline’s domestic LDC and industrial customers are, does 21
not imply that it is not necessary or appropriate to regulate the tolls charged to those segments of the market that have alternatives. All major U.S. pipelines face extensive competition in this sense, with most facing more competition than the Mainline, and some having almost no fully captive customers, yet no long-line gas transmission pipeline has qualified for market-based rate 5 authority.
Tenaska’s understanding is that market-based rates may be appropriate in situations where toll regulation is essentially superfluous and unnecessary because competition will prevent the pipeline from increasing its rates above a competitive level in any event. For example, if a 10 pipeline was in a situation where the market required it to provide all of its services to all of its customers at a discount to cost-based rates, and that situation was expected to continue, it could be argued that there is little point in regulating the pipeline’s rates at a cost-based level because it could never actually collect the full cost-based rates in the market anyway. Such a pipeline would already be in something like the Armageddon situation that TransCanada has discussed. In 15 such a case market based rate authority would presumably do no harm to customers, but it would change nothing for the pipeline from a commercial perspective. Tenaska’s understanding is that the market-based rate concept as it has been developed by the FERC is not intended to be a device for enabling pipelines to increase their rates above a cost-based level.
20 The Mainline is simply not in a situation where the tolls it is able to charge are constrained by competition to a competitive level in any meaningful way, and the Mainline is not even remotely similar to the hypothetical pipeline that is forced by the market to sell all of its services to all of its customers at a discount. The Mainline has more than doubled the tolls it charges across every path on the system in just a few years, without ever failing to recover its costs, and there is no 25 reason to doubt that it could double them again over a short period if that became necessary. TransCanada has said that it would continue to earn its allowed return if it increased the eastern zone toll to $3.05/GJ under the revised “Status Quo” case in the June 29 update. It has asked for authority to increase its tolls for short term services by 60% over the cost-based level, and it would not ask for that authority if it did not believe that it could increase it revenues and 30 maintain its profitability while increasing its tolls by that much or more.
22
Even if it were thought that somehow the Mainline’s tolls would be constrained to a cost-based level by competition, there is no benefit to be derived from giving it the authority to try to prove otherwise. If it succeeded in that and was able to increase its revenues by increasing its tolls above a cost-based level, that would simply result in lower throughputs, higher market-area 5 prices, and lower producer revenues as described in the response to Q.6.
Regulated FT Service as a “Recourse”
In the discussion of market-based rates and the various business model alternatives that have 10 been put to TransCanada’s witnesses, it has been suggested that an alternative to pure market based rates for the Mainline would be to give it unlimited pricing discretion for discretionary services, but with a cost-based FT service as a “recourse” that would limit the pipeline’s ability to increase tolls for short term services above a competitive level. This is simply ‘deregulation’, or ‘market-based rates’ in disguise, because the constraint it creates on the pipeline’s market 15 power is so loose and ineffective that it is not a real constraint at all.
In order to see this, it will be useful to clarify how the notion of a recourse service and a recourse rate is applied in the context of the FERC negotiated rate doctrine, which is the source of the recourse concept. The general notion is that pipelines and shippers may negotiate any rates and 20 rate designs they like as long as the shipper always has the option of subscribing for a comparable recourse service at a cost-based recourse rate if it does not like the negotiated rate offer from the pipeline. The concept is that no rational shipper will agree to a negotiated rate offer if it expects itself to be worse off under the rates proposed by the pipeline than it would be under the recourse rate. 25 As a practical matter this mechanism is often used in the context of new pipelines, with Alliance being a well-known example. In that situation negotiated rates can end up being higher than the notional “recourse rate” that the pipeline has in its tariff, at least for some periods. The reason for that may be that the pipeline has leverage on shippers, because it can say that if the shipper does 30 not agree to the proposed negotiated rate the pipeline will not be built and the shipper will not get the capacity it seeks. 23
In cases where service is being offered on existing facilities, so the pipeline is physically able to provide the recourse service at a recourse rate, the negotiated rate mechanism is typically used in situations where the pipeline and the shipper use the freedom to negotiate to agree on a non- 5 standard rate design that allocates risk, e.g. market or throughput risk, in a non-standard way, for example through the use of rates that recover fixed costs in a commodity charge. In that situation the shipper never expects to be worse off, using whatever criteria are important to it, than it would be under the recourse rate, because otherwise it would elect the recourse rate. The FERC’s negotiated rate mechanism was never intended to be a mechanism to help pipelines extract 10 above-cost rates from shippers, and in fact the mechanism has been carefully crafted to avoid that result whenever possible.
The key point for these purposes is that the recourse service is always the same service as the service proposed to be provided under the negotiated rate. Pipelines and shippers are not allowed 15 to negotiate terms and conditions of service, so the pipeline cannot invent a new service that is better than the recourse service and use that higher quality of service to extract an above-cost price from the shipper. Similarly with contract term – if the shipper wants to negotiate a rate for a one-month firm service, the “recourse” is a one-month firm service at a just and reasonable cost-based price for one-month service. The pipeline can never say: “here is the above-cost rate I 20 am offering for one-month service, and if you do not agree to that rate I will withhold the one- month service from you and you can contract for one-year service at a cost-based rate instead.”
Exactly that reasoning appears to have been suggested as a rationale for giving the Mainline unlimited pricing discretion for short term services under potential new regulatory models for the 25 Mainline, apparently on the theory that it provides ‘protection’ for short term shippers. This type of reasoning may also provide part of the justification for TransCanada’s proposed higher bid floors for short term service, i.e. if shippers do not like the minimum IT or STFT price TransCanada fixes, they can sign up for FT instead.
30 While superficially this type of ‘recourse’ creates a cap on the ability of the pipeline to extract an above-cost toll from the shipper, the cap is a multiple of the cost-based toll for the short term 24
service. If a shipper wants one-month firm service, but its only “recourse” is one-year firm service at a regulated cost-based toll, the only limit on the pipeline’s ability to extract as much as the shipper can be made to pay is the total cost of a one-year FT service, effectively a unit rate 12 times the cost-based rate for one-month service. That is not a genuine constraint, and the 5 practical result of such a scheme is unregulated or market based tolls for short term services that will be higher than the cost-based tolls.
In this connection TransCanada suggested, in the context of allowing it to charge unregulated prices for unregulated services against the backdrop of a regulated FT recourse service, that the 10 recourse service should be a “stripped down” version of the current FT service. Ideally, from the pipeline’s perspective, the stripped-down recourse service would be so useless, or so expensive to operate (e.g. if it resulted in large amounts of unutilized off-peak capacity) that the pipeline would be able to extract above-cost tolls from even highly captive customers in return for a commercially useful long-term ‘market-based’ firm transportation service. 15 “Light-Handed” Regulation
Another variation on the market-based rate theme is the suggestion that the pipeline be authorized to set whatever tolls it likes for certain services, subject to the shipper having a right 20 to complain to the Board if it is dissatisfied with the rate that is offered. With that structure, the key question is whether the regulator will accept as a valid complaint a claim that the proposed toll is not cost-based. If so, then the reasonable and efficient approach would be for the regulator to simply set maximum tolls at a cost-based level from the outset.
25 On the other hand, if the lack of a cost basis for the proposed toll is not a valid objection, it is difficult to see what a valid objection might be. If no cost-based objection can succeed, the ‘protection’ offered by light-handed regulation is an illusion and the practical result is unregulated market-based tolls that are higher than cost-based tolls.
30
25
Involvement with Commodities
11. How would TransCanada’s involvement in the commodity market work in the context of regulation and what impact, if any, would it have on you? 5 Tenaska’s understanding of TransCanada’s suggestion is that the Mainline would operate an unregulated merchant function within the regulated pipeline that would be entwined in some way with the regulated business. That notion is so foreign to the modern conception of how gas transmission pipelines are operated and regulated that Tenaska is unable to formulate any 10 opinion on how it would “work”. The proposal seems to contemplate that the Mainline could buy gas at Empress at a market price, transport it to a downstream point using unutilized capacity, sell the gas at a market price, and keep the difference. In that way the Mainline would “manage its risk” by making $1.00/GJ profits on gas marketing activities using Mainline capacity at no cost. If that is the proposal, it is clearly unreasonable. 15 If TransCanada Corp. wants to become involved in the commodity business, as it once was on a large scale, it is free to have an unregulated affiliate become a shipper on the Mainline and ship gas under standard transportation contracts on the same terms and at the same tolls as all other shippers. No other “involvement” in the commodity business would be appropriate. 20 Cost of capital – debt costs
12. To what extent would it be appropriate for TransCanada to be at risk for the cost of new debt issuances going forward such that cost-of-service tolls would recover the market cost 25 of new debt, with a possible commensurate increase in the allowed rate of return?
At this point in the proceeding Tenaska has no view on this issue, although it may address issues around risk related to debt costs in argument.
30
26
Toll Spiral
13. What should the Board do if it were to find that its decision on the individual aspects of the restructuring proposal and intervenor proposals would still produce tolls that would be part 5 of a toll spiral?
The Board’s decisions on the individual aspects of the restructuring proposal and the intervener proposals will result in just and reasonable tolls and tariffs, because that is what is required by the NEB Act. We expect that the Board’s determination of what is just and reasonable would be 10 informed by its opinion about whether a decision it was contemplating would lead to or be part of a toll spiral, and that it would generally seek to avoid that result unless it saw no alternative that would comply with the Act. If that were the situation, then the Board should set tolls at a just and reasonable level regardless of the expected commercial outcome. See as well the discussion below in response to Q.14. 15 Mainline Viability
14. Should the Board be concerned about the viability of the Mainline?
20 The Board should be concerned about the viability of the Mainline in the sense that everyone wants the Mainline to remain viable and a loss of viability would be expensive for customers and others affected by Mainline costs. In order to protect the Mainline’s viability the Board should ensure as far a possible that the Mainline becomes a competitive and economic pipeline, but it would do that anyway, regardless of whether ‘viability’ is actually an issue. 25 As a factual matter, Tenaska does not believe that there is a meaningful threat of the Mainline becoming non-viable in the foreseeable future. While markets can surprise, and in principle almost anything can happen, there does not appear to be any plausible “Armageddon” or “crash scene” threat based on what we know now. 30 27
In any event, any concerns the Board may have about the viability of the Mainline should not lead it to approve TransCanada proposals that it would not otherwise approve just because it thinks that doing so is necessary to keep the Mainline “viable” for shareholders. It would not be appropriate to harm producers by approving the ASE, or long haul FT shippers by eliminating 5 RAM, or Gaz Metro by allocating TQM costs exclusively to it, because the Board considers that doing any of those things would help to insulate TransCanada shareholders from market losses in a speculative Armageddon scenario far in the future.
15. Can any lessons be learned and imported from the U.S. experience, as part of the evolving 10 Mainline toolkit, to make the Mainline continue to move in an economically viable fashion?
Tenaska believes that it is useful for the Board to understand the concepts, principles, and toll and tariff mechanisms that have been considered and applied by the FERC. If appropriate and reasonable regulatory mechanisms that have been developed elsewhere can be adapted to 15 Canadian conditions there is no reason not to do that. As an example, Tenaska has identified the FERC’s discounting model as potentially being appropriate for the Mainline, although we consider that transplanting the mechanism into the Mainline context in an appropriate way would be a complex exercise.
20 16. To what extent is the WCSB’s continued viability tied to that of the long-haul Mainline service to eastern markets? (New Question)
While there is no doubt that the economics of gas production investment in the WCSB and the economics of Mainline transportation are inter-related to some extent, it seems unlikely that the 25 viability of the WCSB depends on that of the long-haul Mainline service. Tenaska believes that WCSB economics will be primarily influenced by broader market factors like continental gas prices, full cycle production costs in the WCSB versus other basins, and the economics of LNG exports. While the viability of long-haul Mainline service depends on there being enough gas available at Empress to meet whatever captive long-haul requirements the Mainline has, current 30 Mainline receipts are a fairly small portion of WCSB production. Even if WCSB production declined considerably the market would ensure that captive Mainline customers would be able to 28
meet their requirements at a market-clearing commodity price, i.e. by bidding enough gas away from other WCSB markets.
Undertaking 45 5 17. Do you have a view on the viability of the scenario outlined in Undertaking 45?
Tenaska’s understanding of the initial scenario that was put to TransCanada is that it would involve provision of FT service to long term firm customers at tolls that would be determined by 10 the Board on something other than a conventional cost basis to reflect the Board’s view of what a competitive toll would be. Our impression is that the competitive FT tolls could perhaps vary by path, and the general assumption seemed to be that in most cases they would be lower than conventionally determined cost-based tolls. In this scenario all other services would be sold by the Mainline at essentially unregulated prices and under unregulated terms and conditions, with 15 TransCanada retaining all of the revenue.
During the appearance of panel 10 a variation of this scenario was put to TransCanada under which the regulated FT rates would be designed in a way that would recover the pipeline’s entire revenue requirement, which would result in tolls that were much higher than current levels. 20 TransCanada would then be free to sell other services at unregulated or market-based rates, with revenues being shared in some proportion between the pipeline and, presumably, the FT shippers. For these purposes we will refer to these alternatives as the “primary scenario” and the “alternative scenario”.
25 Both of these scenarios are conceptually similar to the NEB 6.4 core/non-core model in that all services other than FT services provided to captive customers would be sold at effectively market-based rates. The U-45 scenarios differ from the core/non-core model described in NEB 6.4 only in that that they would employ different approaches to designing the core FT tolls.
30 Tenaska has the same basic concern with both of these models that it has with the core/non-core models discussed in the response to Q.9, which is that by allowing the pipeline to charge above- 29
cost market-based rates for discretionary services discretionary flows will be lower, market-area prices higher, and producer revenues lower than if the prices for discretionary services were capped at a cost-based level.
5 With respect to the viability of the proposed mechanisms for developing the regulated FT tolls, the two approaches would lead to different results for core customers and pipeline shareholders, just as the different cost allocation theories discussed in the response to Q.9 would lead to different results for those groups.
10 With respect to the primary scenario, it is difficult to comment on the reasonableness of the concept without a more complete understanding of how the FT tolls would be determined and, in particular, what the notion of a “competitive” level for FT tolls means in this context and how it would be determined. For captive firm customers that have no alternatives and highly inelastic demands, i.e. most of the Mainline’s current FT shippers, the notion of a ‘competitive’ toll has 15 limited meaning and significance. Almost by definition any toll that was set would be ‘competitive’ versus the alternatives because there are no alternatives and the customers will pay whatever price is set. The current $2.24/GJ eastern zone toll is not very attractive, but the existing customers pay it and will continue to do so unless they are able to physically by-pass the system. 20 If what the Board has in mind is some notion of toll competitiveness based on observed basis differentials, we do not believe that is a sound basis for designing FT tolls, or any regulated transportation tolls. Price formation mechanisms at natural gas market centers are extremely complex, often very opaque, apt to shift and change from day to day, and in any event driven by 25 marginal costs. Observed basis differentials are usually a function of transportation costs in some complicated and often unknown way, but they usually have no predictable relationship to the maximum firm toll for a given path and there is no reason to think that they should have such a relationship for most Mainline paths.
30 Assuming for these purposes that in the primary scenario the FT tolls would nevertheless be set at some below-cost level, that approach would raise cost recovery issues for TransCanada. 30
As a starting point, the scenario assumes that the FT services would under-recover the cost of providing them, resulting in some shortfall for the pipeline. On the other hand, both the primary and alternative scenarios involve the Mainline charging unregulated tolls for all other services, 5 and the pipeline would determine what its revenue maximizing set of unregulated tolls was. That level would probably yield revenues above a conventionally determined cost level, so the financial issue for the pipeline would be whether its revenues from unregulated services offset its under-recovery on the below-cost regulated service. There is no way of predicting that with the facts given, but the result could be under-recovery by the pipeline if the regulated FT tolls were 10 low enough.
In the alternative scenario the pipeline would avoid that risk by recovering all of its costs from the FT shippers, and selling all other services at unregulated tolls and keeping some proportion of the revenue. Thus, if the Mainline sold $400 million worth of discretionary services, and the 15 sharing mechanism was 50/50, it would keep $200 million in addition to its allowed return.
In Tenaska’s view neither approach would provide any benefit to the system as a whole in attracting incremental discretionary business. While TransCanada and captive customers would argue about how to divide responsibility for system costs through the toll design process for FT 20 services, the result in the end would be higher unit fixed costs for the market as a whole because the market-based rates charged for discretionary services would reduce rather than increase throughput, relative to the case where prices for discretionary services were capped at a cost- based level.
25 18. Do you have any comments on TransCanada’s response to Undertaking Response 45?
Tenaska has no comments on TransCanada’s response at this time. Attachment A7 Tab 13 Part A – Review and Variance Application Exhibit C4-27-3, RH-003-2011, Responses of the Industrial Gas Users Association (IGUA) to the NEB’s Generic Questions. RESPONSES OF THE INDUSTRIAL GAS USERS ASSOCIATION (IGUA) to the NEB’S GENERIC QUESTIONS September 21, 2012
Question: Should the Board provide direction on pricing and service flexibilities and
TransCanada occupying at risk space, beyond what can be implemented in this
proceeding?
Yes. It is critical the NEB provide parties with clear direction in its Reasons for Decision in
regards to how it views the appropriate sharing of risk in the context of evolving market
circumstances as between TransCanada and its toll payers. Absent such guidance from the NEB,
any future tolls negotiations will continue to be hampered by very different expectations.
MULTI-YEAR FIXED PRICING SERVICE (MFP)
Question: If MFP were implemented, should it be implemented with an incentive or
risk mechanism and if so:
• What should the mechanism be?
• What degree of risk sharing is appropriate?
• Could “at-risk” MFP work alongside the MFP described in section
8.0 of the Application?
Please refer to A.47 of the Amended Written Evidence of Murray A. Newton (Exhibit C4-10-2).
CORE/NON-CORE
Question: What factors should TransCanada, its stakeholders and the Board consider in
determining whether it is appropriate to move to a core/non-core kind of
business model?
6
RESPONSES OF THE INDUSTRIAL GAS USERS ASSOCIATION (IGUA) to the NEB’S GENERIC QUESTIONS September 21, 2012
The concept of bifurcating TransCanada’s rate base into two separate components so as to offer
shippers the option of choosing between a core recourse-type service and non-core services is not new.
However, before introducing such a model, IGUA believes that the following factors should be taken into account:
1. Whether this resolves the current underutilization problem on Long Haul (LH) and the
switch of volumes away from Long Haul to Short Haul (SH);
2. What the impact would be on captive shippers;
3. What the impact would be on TransCanada’s shareholders.
One of the more difficult challenges with such a model is also how to determine the appropriate
allocation of costs to each of these two separate classes of service. This is even more
problematic in a situation where pipeline capacity was primarily constructed to serve firm service requirements. The so-called non-core services would not have access to pipeline capacity had some firm shipper not previously paid demand charges to help pay for that capacity.
While IGUA understands shippers have no acquired rights or obligations related to pipeline capacity, it is nonetheless true that in today’s circumstances, non-core services would enjoy
mostly unconstrained access to firm capacity at a likely considerable discount from the toll
applicable to the core services. Therefore, it’s only fair and equitable that non-core services be
required to make some form of contribution to TransCanada’s fixed costs. Although the
magnitude of that contribution and the mechanics of how that contribution could be achieved are
beyond the scope of this answer, one way to accomplish a fair contribution would be with the
retention of some level of revenue crediting from the non-core services to the core service group.
7
RESPONSES OF THE INDUSTRIAL GAS USERS ASSOCIATION (IGUA) to the NEB’S GENERIC QUESTIONS September 21, 2012
The NEB included several working assumptions in its Information Request No. 6.4 (Exhibit
A25-1) addressed to TransCanada. This version of a core/non-core model posited a scenario
where the core service (FT) "rate base" would be tolled using a cost of service methodology and the non-core services would include a market based pricing methodology where TransCanada would gain the upside and would also be at risk for any downside. The non-core services would
be regulated on a lighter-handed or complaints basis. This model also assumed no revenue
crediting from the non-core to core services. TransCanada’s response to this Information
Request (Exhibit B27-1) assumed that all or nearly all of the Mainline’s costs would be allocated
to the core services.
IGUA has significant concerns about the fairness and equity of such a model since, under
TransCanada’s assumptions, such a model would bring even more upward tolling pressure to the core (FT) services (due to no revenue crediting from non-core), while at the same time possibly degrading the value of today’s FT by changing the core service to a stripped down "no frills" service without service enhancements such as diversion and renewal rights. In addition, TCPL would have unlimited ability to offer presumably lower tolls (in today’s market circumstances) to the non-core services. The revenues derived from the non-core services would not be required to be shared with the core services and so TransCanada would be able to gain all of the revenue upside from non-core services, while bearing little, if any, downside risk.
NEB Undertaking # 45 (Exhibit B-81) posited a slightly different scenario where the core service tolls would be set at the lower of cost-based or market-based tolls. Under this working assumption, TransCanada would be at risk for under-recovery of its core service revenues. As in the first scenario, TransCanada would be also have pricing flexibility for its non-core services
8
RESPONSES OF THE INDUSTRIAL GAS USERS ASSOCIATION (IGUA) to the NEB’S GENERIC QUESTIONS September 21, 2012
and would assume the risks (if any) while retaining all of the revenues under a much reduced
level of regulatory oversight.
IGUA agrees this model could not be implemented for 2012 and 2013. More to the point, if the
NEB concludes in this Hearing that it is no longer possible to set a just and reasonable toll for
today’s firm services because the resulting tolls are too high and too uncertain, and so such tolls
are likely to continue to encourage further de-contracting and the further loss of distance and volume billing determinants, then IGUA recommends the NEB adopt the IGUA proposal.
MARKET BASED RATES
Question: How and where could TransCanada have market based rates?
No further response at this time.
INVOLVEMENT IN COMMODITIES
Question: How would TransCanada’s involvement in the commodity market work in the
context of regulation and what impact, if any, would it have on you?
Today’s North American natural gas commodity market works well. The gas industry is already
blessed with a wide range of knowledgeable and experienced market participants who are active
in commodity markets and provide value to their customers in regards to helping them manage
their gas supply and transportation. Therefore, with the exception of managing its transportation
fuel costs, IGUA sees no useful role at this time for a regulated monopoly service provider such
as TransCanada to involve itself in the commodity business.
9
Attachment A7 Tab 14 Part A – Review and Variance Application Exhibit C2-6-3, RH-003-2011, Evidence of Drazen Consulting Group, Inc. on behalf of the Canadian Association of Petroleum Producers
TransCanada Pipelines Ltd.
Business and Services Restructuring and Mainline 2012‐2013 Tolls
Before the National Energy Board Hearing Order RH‐003‐2011
Evidence of Drazen Consulting Group, Inc.
on Behalf of the Canadian Association of Petroleum Producers
Project No. 111502 March 9, 2012 1 The Multi‐Year Proposal on Tolls
2 Overview 3 Q53 WHAT IS THE PROPOSAL FOR SETTING MAINLINE TOLLS?
4 A53 We recommend that the Board use a multi‐year approach to setting tolls instead of the
5 year‐by‐year approach that has been used heretofore by TransCanada. Based on
6 expected throughput, revenues and cost, by fixing a toll trajectory for a period of about
7 five years at a level based on the 2013 cost of service should be adequate to recover the
8 cost of service over that period. The differences between the revenues and cost of
9 service each year would be evened out in a Toll Stabilization Adjustment (TSA) account.
10 The results of this analysis are shown in Figure 4.
11 Figure 4 12 13 Toll Stabilization Adjustment Account
$1,800 $300 $200 $1,700 $100 $1,600 $0 $1,500 ($100) ($200) $1,400 ($300) $1,300 Mainline Revenues and TSA Revenue Requirement ($400) Account Balance $1,200 ($500)
14 The left‐hand graph shows revenues and expenses. The right‐hand graph shows the
15 cumulative balance in the TSA. In the initial years, when revenues do not fully recover
39 1 cost of service, the TSA is negative, meaning a cumulative shortfall. When the TSA
2 reaches zero, the toll regime is revisited.
3 Q54 HOW WILL A FIXED RATE RECOVER MAINLINE COSTS?
4 A54 TransCanada’s filing shows the cost of service decreasing from 2011 to 2012 and then
5 decreasing again from 2012 to 2013. In its response to CAPP 2‐47, TransCanada shows
6 the Mainline revenue requirement decreasing every year from 2015 on. At the same
7 time, throughput is expected to increase every year. Therefore, tolls can be set for a
8 multi‐year period at levels that recover less than the annual cost of service over the
9 initial years, but subsequently recover more than the annual cost such that the Mainline
10 has an opportunity to recover its full cost over time.
11 Benefits 12 Q55 WHAT ARE THE ADVANTAGES OF THIS APPROACH?
13 A55 The advantages are:
14 • It provides toll stability;
15 • It provides incentives for the Mainline to manage its costs and increase 16 revenue; and 17 18 • It avoids the need for entangling NGTL in solving the Mainline’s toll problem.
19 If the Mainline is to attract additional firm load, toll stability is essential. TransCanada
20 has proposed tolls for 2013 (2012 will have likely passed by the time of the decision),
21 but there is no guarantee about tolls after 2013. Even if the 2013 tolls are economically
22 attractive, shippers will be reluctant to sign contracts if they are unsure about future
40 1 levels. We see this from the reactions to TransCanada’s filings for the 2011 tolls.
2 Shippers who had agreed to the five‐year settlement agreement covering 2007‐2011
3 were greatly upset that the 2011 tolls were more than double the level that had been
4 predicted for that year at the beginning of the Agreement.
5 The requirement to live with pre‐determined tolls for a period of several years
6 will give TransCanada the incentive to achieve the targets and minimize costs. The
7 pipeline has requested greater pricing flexibility for STFT and IT. That flexibility gives the
8 Mainline the potential for increasing revenues from these services over and above the
9 level assumed in its 2013 forecast.
10 Q56 IS THERE ANY REASON FOR SHIPPERS TO BE CONCERNED ABOUT TOLLS AFTER 2013?
11 A56 Yes. The Short‐Term Adjustment account proposed by TransCanada is designed to
12 recover starting in 2014, any variances in 2012 and 2013. The 2012 revenue
13 requirement includes $174 million of unrecovered costs from previous years. Since any
14 new tolls will not be effective until 2013, it is likely that this amount will go into the
15 Short‐Term Adjustment account. In addition, any under recovery in 2012 will go into
16 the same account. Thus, there is a strong likelihood of toll increases after 2013.
17 Q57 WHAT EVIDENCE IS THERE THAT THE MAINLINE CAN REDUCE COSTS?
18 A57 The 2007‐2011 settlement agreement demonstrates evidence of TransCanada’s ability
19 to exceed its goals. That agreement included deferral account treatment for all
20 expenses other than operation, maintenance and administration (OM&A). The OM&A
41 1 levels were set at fixed levels for each of the five years, starting at $178 million in 2007
2 and increasing to $212 million in 2010 and $222 million in 2011.13 In fact, 2010 OM&A
3 was only $149 million and 2011 OM&A was $152 million14. TransCanada has described
4 the success of its efforts:
5 TransCanada has also actively managed its TBO capacity, which has 6 resulted in reductions in annual TBO costs through a reduced level of 7 contracted capacity on both the GLGT and Union systems. The reduction in 8 contract levels (excluding assignments), effective November 2010 and 9 November 2011, has led to an annual reduction of approximately $59 million 10 in GLGT TBO costs, and an $11 million in Union TBO costs.
11 The GLGT TBO Management Incentive program combined with the Municipal 12 and Capital Tax Savings program contained within the Performance Incentive 13 Envelope of both the 2006 Settlement and 2007‐2011 Settlement have also 14 resulted in additional cost savings of approximately $71 million. 15 (Application, Section 2.0, Page 23, emphasis added)
16 Q58 IS THERE ANY OTHER BENEFIT TO TRANSCANADA?
17 A58 Yes. As explained by Dr. Orans, the TSA mechanism provides the Mainline with the
18 opportunity to earn above the allowed return on equity.
19 Analysis 20 Q59 WHAT ARE THE COMPONENTS OF THE FORECAST?
21 A59 This analysis is based on TransCanada’s Restructuring Proposal with three structural
22 changes: (1) no Alberta System Extension; (2) keeping the “Status Quo” depreciation
23 accrual rates; and (3) using a conventional return on rate base approach (40% equity
13 2007 Mainline Tolls Settlement Application, Page 5. 14 Application, Section 12.0, Attachment 12.1, Tab 1, Schedules 1.1 and 1.2.
42 1 ratio and 9.5% return on equity) instead of TransCanada’s requested ATWACC.15
2 Q60 WHAT IS THE BASIS FOR YOUR FORECAST?
3 A60 We have projected the Mainline expenses and revenues for the period 2012 through
4 2020. The calculations for 2012 and 2013 are based on TransCanada’s forecast costs,
5 with the changes explained below. These costs were then projected out to 2020.
6 Q61 WHAT ARE THE BASE CASE RESULTS?
7 A61 The results are shown in Table 7:
Table 7
Mainline Revenue and Cost–Base Case ($Millions)
Cost of Surplus/ TSA Year Revenue Service (Deficit) Balance
2012 $1,447 $1,447 $0 $0 2013 1,433 1,519 (86) (86) 2014 1,502 1,524 (22) (111) 2015 1,563 1,561 2 (111) 2016 1,618 1,552 66 (47) 2017 1,639 1,541 98 (50) 2018 1,664 1,520 144 195 2019 1,677 1,491 181 381 2020 $1,690 $1,485 $205 $595
8 The amount that is “under recovered” (revenue less than that year’s cost of service) in
9 the early years is put into the TSA account. In later years, when revenues exceed each
10 year’s cost of service, the TSA is reduced. This forecast shows that by 2017 the Mainline
15 After Tax Weighted Average Cost of Capital.
43 1 will have recovered all of the costs (so the numbers are “grayed out”). At that point, the
2 TSA mechanism will no longer be needed and tolls can be reset.
3 Q62 IS THIS A DEPARTURE FROM COST OF SERVICE REGULATION?
4 A62 No. Tolls still recover the cost of service, but the matching takes place over a multi‐year
5 period.
6 Details of the Analysis 7 Q63 HOW DID YOU CALCULATE THE REVENUES?
8 A63 We used 2013 tolls designed to produce a $1.35/GJ toll for a transportation distance of
9 3,000 km. This indicates the cost to points in what is currently the Eastern Zone.16
10 These were held constant. Billing volumes are based on TransCanada’s “Case 1”
11 forecast.
12 Q64 HOW DID YOU ESTIMATE THE DISCRETIONARY MISCELLANEOUS REVENUES–THAT IS,
13 THE REVENUES FROM NON‐FT SERVICES?
14 A64 We used TransCanada’s assumptions, although we think they may understate the
15 revenues. The majority of the discretionary miscellaneous revenue is derived from STFT
16 and IT services. TransCanada estimated the “premium” on STFT and IT service—that is,
17 the amount above the floor bid price— to be in the range of $20 million to $80 million
18 (Response to NEB 2.32(c)). It used the $20 million figure (Application, Section 8, Page
16 This produces a NIT‐to‐Dawn toll of $1.20/GJ.
44 1 21). This seems inconsistent with its proposal to increase the bid floor on STFT from
2 100% to 150% of the FT toll at 100% load factor and to increase the IT floor from 110%
3 to 160%. In its response to CAPP 2‐43, TransCanada reported the results of a sensitivity
4 analysis in which IT and STFT tolls were set at the proposed new floor price of 160% of
5 the FT toll for the whole year and for all paths. It then went on to say that “it is not
6 likely that IT/STFT pricing would be at a 160% premium for all 365 days of the year and
7 for all paths”. However, assuming that the 160% floor price would apply for some days
8 of the year and some paths, it is reasonable to expect that the Mainline will receive an
9 increase in the discretionary service premium revenues.
10 For other miscellaneous revenue we used the same assumptions as
11 TransCanada.
12 Q65 HOW IS THE REVENUE REQUIREMENT DETERMINED?
13 A65 The calculation of revenue requirements for each year uses TransCanada’s projections
14 for 2012 and 2013 as the starting point plus the forecast of costs in the response to
15 CAPP 2‐47, with some slight modifications.
16 Q66 PLEASE EXPLAIN THE COMPONENTS OF THE REVENUE REQUIREMENTS.
17 A66 Operation, maintenance and administrative expenses are escalated at 2% per year.
18 These are the same as TransCanada’s assumptions in its response to CAPP 2‐47.
19 The cost of the TBO arrangements with Great Lakes Gas Transmission (GLGT) and
20 TQM are forecast to remain constant at $140 million per year, based on the response to
45 1 CAPP 2‐47. This may be conservative on the high side. TransCanada has already
2 reduced the GLGT cost significantly by decreasing its contract amount and by capacity
3 release.
4 Electric costs and tax on fuel are based on TransCanada’s forecast. These
5 increase through 2016 and then decrease.
6 Municipal and provincial capital taxes are forecast to increase at 3% annually.
7 TransCanada added $50 million per year for terminal negative salvage, starting in
8 2015. TransCanada says this is a placeholder, pending the outcome of the Land Matters
9 Consultation Initiative. We have included this.
10 Gross plant in service is based on TransCanada’s forecast. This forecast shows
11 capex of $39 million per year but gross plant in service decreasing at $24 million per
12 year. See the response to CAPP 200(e). This implies annual retirements of $63 million
13 per year, which is the figure we used.
14 Depreciation expense is calculated based on the status quo depreciation accrual
15 rates.
16 Return is calculated on a conventional basis, assuming a 40% equity ratio and a
17 return on equity of 9.5%, based on the evidence of Dr. Booth.
18 Income taxes are based on TransCanada’s forecast rate of 25.505%.
19 TransCanada’s forecast in CAPP 2‐47 shows the Capital Cost Allowance (CCA) to be $187
20 million in 2014, then remaining constant at $185 million per year from 2015 on. We
21 have calculated 2014 CCA to be $185 million, then decreasing amounts thereafter. The
22 2020 amount is $145 million. So in this respect the calculated income tax would be
46 1 lower using TransCanada’s forecast.
2 Q PLEASE SUMMARIZE THE MAIN ASSUMPTIONS IN YOUR REVENUE REQUIREMENTS
3 FORECAST.
4 A They are shown in Table 8.
Table 8
Inputs to Forecast
Annual Category Change/Value Comment
OM&A +1%/year Same as TransCanada CAPP 2‐47 Storage operating +2%/year Same as TransCanada CAPP 2‐47 Pipeline integrity +2%/year Same as TransCanada CAPP 2‐47 NEB cost recovery +2%/year Same as TransCanada CAPP 2‐47 Regulatory proc. & collab. +1%/year Same as TransCanada CAPP 2‐47 Gas related and electric varies Same as TransCanada CAPP 2‐47 Muni. and other taxes 3% Same as TransCanada CAPP 2‐47 Union Gas TBO Constant Same as TransCanada CAPP 2‐47 TQM TBO Constant Same as TransCanada CAPP 2‐47 GLGT TBO Constant Same as TransCanada CAPP 2‐47 Terminal neg. salvage $50M/year Same as TransCanada CAPP 2‐47 Equity ratio 40% Not specified in ATWACC Return on equity 9.50% ATWACC equiv. to ~ 12% RoE Income tax rate 25.505% Same as TransCanada CAPP 2‐47 CCA amount Decreasing Constant at $185M 2015 = $180M Gross plant additions $39M/year Same as TransCanada CAPP 2‐47 Retirements $63M/year Same as TransCanada CAPP 2‐47*
*TransCanada shows gross plant decreasing by $24M/year. With capex of $39M/year, retirements are $63M/year.
5 Q67 WHY DID YOU USE THE STATUS QUO DEPRECIATION RATES?
47 1 A67 This is explained by Dr. Orans.
2 Q68 WHAT OTHER ELEMENTS OF YOUR FORECAST DIFFER FROM TRANSCANADA’S
3 APPROACH?
4 A68 Our forecast extends the use of the Long‐Term Adjustment account. Recall that
5 TransCanada put $85 million of cost into the LTA in 2010 and proposes to put another
6 $100 million in 2012. Our forecast puts the 2011 variance ($174 million) and any further
7 2012 variance (yet to be determined) into the LTA for 2013. Following this, we have put
8 $100 million into the LTA each year.
9 Deferral Accounts 10 Q69 IS THE USE OF DEFERRAL ACCOUNTS CONSISTENT WITH PAST MAINLINE PRACTICE?
11 A69 Yes. The Mainline instituted a Long‐Term Adjustment (LTA) account in 2010, whereby
12 $85 million of cost was capitalized–that is, deducted from the cost of service and put in
13 the LTA–and amortized at the same rate as plant in service over a period of
14 approximately 30 years.17 For 2012, TransCanada has proposed deducting another $100
15 million from the revenue requirement and putting it into the LTA. This deferral was
16 done in order to mitigate the increase in tolls.
17 In this Application, TransCanada has proposed an additional deferral account,
18 which it calls the “Short‐Term Adjustment” account. This would absorb any variances in
19 revenues and expenses. The balances in this account would be amortized over five
17 See Section 12.0, Attachment 12.1, Tab 5 (Rate Base), Schedule 5.1.9.
48 1 years instead of the current practice of one year.
2 Finally, the proposed reduction in depreciation accrual rates is another form of
3 long‐term deferral. Depreciation expense would be reduced by over $100 million per
4 year (plus an additional $40 million in income taxes).
5 TransCanada itself says that using its “adjustment” (i.e., deferral) accounts is
6 useful in providing toll stability:
7 Increasing the bid floors will also result in greater revenue contributions on a 8 per‐unit basis relative to the current bid floors when IT and STFT services are 9 used. (Application, Section 8.0, Page 9)
10 Q70 HAVE OTHER UTILITIES USED DEFERRALS?
11 A70 Yes. An example is Express Pipeline, which also offered market‐based tolls that were
12 below cost of service in the initial years with the expectation that over time the full cost
13 would be recovered.18
14 In the U.S., several electric utilities that brought new nuclear plants on line faced
15 the prospect of “rate shock” if the full cost were placed in rates. They used “phase‐in”
16 plans, which deferred cost recovery to future years.
17 Q71 DOES THIS VIOLATE THE “REGULATORY COMPACT”?
18 A71 No. In fact, TransCanada itself seems to say the same thing regarding a long‐term
19 solution:
20 (a) (iii) TransCanada believes that long‐term considerations are relevant to 21 determine appropriate tolls. The various cost deferrals and incentive
18 Express Pipeline Ltd., OH‐1‐95.
49 1 aspects of the Restructuring Proposal are reflections of what TransCanada 2 views as the requisite long‐term perspective to the setting of current tolls. 3 Long‐term consideration should not, however, be utilized to result in 4 disallowance of recovery of costs that have been prudently incurred in 5 accordance with historical Board approvals.
6 (b) A short term shortfall between revenues and costs should not mean that all 7 prudently incurred costs should not be recoverable in the long term. Full 8 cost recovery would mean no need for capitalization or write off. (Response 9 to NEB 2.15, emphasis added)
10 Q72 IS THIS USE OF THE LONG‐TERM ADJUSTMENT ACCOUNT CONSISTENT WITH
11 REGULATORY PRACTICE?
12 A72 Yes. TransCanada itself says:
13 TransCanada views the Long‐Term Adjustment as an investment in the 14 system similar to pipe or compression, and as such, should be amortized over 15 a similar time frame. (TransCanada Response to NEB 3.16(b))
16 Q73 HOW DOES THIS USE OF THE LTA AFFECT RATE BASE?
17 A73 Future rate base amounts are similar to those forecast by TransCanada, as shown in
18 Table 9.
50 Table 9
Forecast Rate Base ($Millions)
Per TCPL DCGI Year (CAPP 2‐47) Forecast
2014 $5,538 $5,589 2015 5,285 5,290 2016 5,032 4,990 2017 4,780 4,688 2018 4,529 4,382 2019 4,278 4,075 2020 $4,028 $3,764
1 Q74 WHAT DID YOU ASSUME REGARDING 2012 REVENUES AND EXPENSES?
2 A74 Whatever is the difference between revenues and expenses for 2012 should be put in
3 the LTA. TransCanada made no assumption in this respect. As a placeholder, we have
4 used a figure of $125 million shortfall.
5 Q75 WHAT IS THE CARRYING COST ON THE LTA BALANCE?
6 A75 This is the same as the overall return on rate base, the same treatment as used by
7 TransCanada.
8 Q76 WHAT CARRYING COST WAS USED FOR THE TSA BALANCES?
9 A76 2.5%. This is discussed in the evidence of Mr. Johnson and Dr. Booth.
51 1 Benefit Sharing Mechanism 2 Q77 WHAT IS THE EFFECT IF THE MAINLINE CAN ACHIEVE COST SAVINGS AND ADDITIONAL
3 REVENUES?
4 A77 The effect is shown on Table 10. As a sensitivity study, we assumed for illustration that
5 the Mainline can achieve $20 million in annual after‐tax cost savings and $10 million in
6 annual after‐tax additional revenue (e.g., from the higher short‐term bid floor), starting
7 in 2014.
Table 10
TSA Balance‐Effect of Incentive ($Millions)
Without With Year Variances Variances
2012 $0 $0 2013 (86) (86) 2014 (111) (87) 2015 (111) (62) 2016 (47) 26 2017 50 126 2018 195 273 2019 381 460 2010 $595 $677
8 The balance for 2013 is the same as before, because the savings and extra revenue are
9 assumed to be achieved starting in 2014. The overall effect is that the TSA becomes
10 positive a year earlier.
52 1 Recommendation 2 Q78 ARE YOU RECOMMENDING THAT THE BOARD ADOPT THESE NUMBERS AS THE BASIS
3 FOR TOLLS?
4 A78 Not necessarily these exact numbers, but we recommend that the Board consider the
5 overall approach of a multi‐year basis for setting the tolls. We expect that other parties
6 will suggest various adjustments and these can be taken into account.
53 Attachment A7 Tab 15 Part A – Review and Variance Application Exhibit C7-5-2, RH-003-2011, Evidence of Alberta Northeast Gas, Limited
NATIONAL ENERGY BOARD
RH-3-2011
TRANSCANADA PIPELINES LIMITED, NOVA GAS TRANSMISSION LTD. AND FOOTHILLS PIPE LINES LTD.
APPLICATION FOR APPROVAL OF RESTRUCTURING PROPOSAL AND MAINLINE FINAL TOLLS FOR 2012-2013
EVIDENCE OF ALBERTA NORTHEAST GAS, LIMITED
March 9, 2012
National Energy Board of Canada, RH-3-2011 Page 14 of 55 TransCanada PipeLines Limited, NOVA Gas Transmission Ltd., Foothills Pipe Lines Ltd. Business and Services Restructuring Proposal and Mainline Final Tolls for 2012 and 2013 Evidence of Alberta Northeast Gas, Limited
1 system and promote economic utilization of TransCanada’s services. Second, under the 2 existing regulatory paradigm, ANE and other shippers bear all of the risks associated 3 with service and revenue declines on the system through the operation of the short and 4 long-term adjustment accounts. Failure to fully address the impediments to revenue 5 optimization will lead to unreasonable cost shifts to TransCanada’s long-term firm 6 shippers. ANE’s proposals make necessary changes to the terms and pricing flexibility for 7 discretionary services that will allow TransCanada to better optimize revenues. A related 8 proposal aligns TransCanada’s interests with those of its shippers by providing an 9 appropriate incentive for the Company to fully utilize the increased pricing flexibility 10 associated with changes to the discretionary services.
11 Q26. Which of TransCanada’s service design proposals will you address in your testimony? 12 A26. Our testimony addresses the appropriate terms of IT and STFT service and the need to 13 eliminate RAM. Our testimony also presents an incentive mechanism focused on 14 revenue sharing that is designed to provide additional benefits to TransCanada and its 15 shippers.
16 C. IT Service 17 Q27. Please describe the distinctions between the commitments made by FT, STFT and IT 18 shippers. 19 A27. Shippers relying on the various transportation services offered by TransCanada make 20 substantially different commitments to TransCanada. FT shippers commit to pay a full 21 proportionate share of TransCanada’s annual revenue requirement based on the 22 contract quantity and associated distance of haul. FT shippers also agree to pay any 23 future toll adjustments attributable to variances in TransCanada’s throughput or costs. 24 ANE’s FT commitments span primary terms of over ten years. FT shippers make the 25 maximum commitment to pay system costs through fixed charges.
26 Under the existing STFT service, shippers commit to pay fixed charges for as little as 7 27 days of the year and as long as 364 days. Data provided by TransCanada indicates that 28 the average term for STFT service over the last decade is 29 days.14 On a contract 29 volume-weighted basis, the average is only 25 days. This indicates that, on average, the 30 commitment of STFT shippers to pay the fixed costs of providing service is less than 10% 31 of the commitments of FT shippers on the system. Although STFT shippers are not 32 presently responsible for toll changes that occur during the term of their contracts, 33 TransCanada is proposing that in the future STFT tolls adjust consistent with the 34 derivative FT toll in order to limit gaming by shippers seeking to avoid anticipated toll 35 increases.
14 Derived from data presented in ANE-TransCanada 1.6(b). National Energy Board of Canada, RH-3-2011 Page 15 of 55 TransCanada PipeLines Limited, NOVA Gas Transmission Ltd., Foothills Pipe Lines Ltd. Business and Services Restructuring Proposal and Mainline Final Tolls for 2012 and 2013 Evidence of Alberta Northeast Gas, Limited
1 Figure 1 indicates the growth in STFT contracts overall, and the proportion of STFT 2 contracts that are for the minimum term of 7 days.
Figure 1 Count of STFT Contracts by Year Minimum 7-Day Term vs. Terms of 8 Days or Longer
800
600
400
200
- 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Count 7 Days Count Longer than 7 Days
3 IT shippers make the shortest and least commitment for the transportation service 4 received. IT shippers bid a price for service on the day and only pay the price bid. There 5 is no commitment to pay any fixed charge for service or to make any future contribution 6 to the costs of facilities relied upon to provide IT service.
7 Q28. Are there independent factors that influence the commitments shippers are willing to 8 make to take service? 9 A28. Yes. Traditionally, shippers that require reliable access to supplies or desire predictable 10 pricing opt for firm service. In order to secure firm service, these shippers make a 11 commitment to pay pipeline demand charges for multiple years to offset facility 12 investment costs. In tight capacity markets, shippers often extend commitments in 13 order to secure access to capacity rights. However, the substantial level of excess 14 capacity on the TransCanada system today is upending the typical factors that drive 15 contracting decisions. In particular, under-utilized facilities provide greater assurance to 16 shippers that firm service will be available when needed even for relatively short 17 durations during the peak period. Additionally, the reliability of IT service approaches 18 that of FT service as shippers are more certain that they will be able to schedule IT 19 service on the system. Under these circumstances, shippers are able to significantly 20 reduce their commitments to compensate TransCanada for the annual costs of 21 providing service. National Energy Board of Canada, RH-3-2011 Page 16 of 55 TransCanada PipeLines Limited, NOVA Gas Transmission Ltd., Foothills Pipe Lines Ltd. Business and Services Restructuring Proposal and Mainline Final Tolls for 2012 and 2013 Evidence of Alberta Northeast Gas, Limited
1 Q29. What relevance do these market circumstances have to the design of the prices and 2 terms for TransCanada’s discretionary services? 3 A29. On many paths, shippers take advantage of the substantial sunk investment in 4 TransCanada facilities by relying extensively on STFT and IT service in instances where 5 they previously utilized FT service. When discretionary services are readily substituted 6 for firm service, it is essential to examine the potential for the pricing relationships 7 among FT, STFT and IT services to contribute to revenue erosion.
8 Moreover, it is important to recognize that traditionally IT service relied upon facilities 9 that were required to provide service to firm shippers during some times of the year, 10 but not throughout the year. Facilities were not constructed to provide IT service and 11 there were comparatively modest amounts of excess capacity. The situation is starkly 12 different today. Excess capacity on substantial portions of the system means that 13 facilities relied upon to serve IT shippers are not needed at any time of the year to 14 provide year-round firm service. IT revenues no longer mitigate the costs of facilities 15 required to serve firm customers, but reduce the costs of excess capacity that are 16 ultimately borne by firm shippers.
17 By virtue of shipper utilization of its services, TransCanada is transforming into a peaking 18 pipeline. This is undesirable for the Company and for FT shippers that pay for the costs 19 of excess capacity on the system under the existing regulatory paradigm. The existing 20 menu of non-discretionary and discretionary services is a significant factor contributing 21 to this undesirable outcome.
22 Q30. What is your view of TransCanada’s proposal to set distinct bid floor prices by path 23 and to increase the maximum bid floor price to 160% of the FT toll? 24 A30. The purpose of these changes is to increase TransCanada’s opportunity to extract higher 25 revenues from IT shippers. The system-wide bid floor and the current maximum IT bid 26 floor price equal to 110% of the corresponding FT toll inappropriately restrict 27 TransCanada’s ability to increase discretionary revenues. Implementation of distinct bid 28 floors by path, which will allow TransCanada to set higher bid floors on portions of its 29 system that offer greater revenue opportunities from IT and STFT service, is an essential 30 requirement to generating additional discretionary revenues. While TransCanada’s 31 proposed increase to the maximum bid floor for IT service is a step in the right direction, 32 it falls short of providing TransCanada with the opportunity to optimize discretionary 33 revenues from IT shippers that desire transportation service. It also fails to conform to 34 the fundamental shifting role of discretionary revenues from a tool that mitigates costs 35 to an essential revenue stream required to reduce the costs of carrying excess capacity. National Energy Board of Canada, RH-3-2011 Page 17 of 55 TransCanada PipeLines Limited, NOVA Gas Transmission Ltd., Foothills Pipe Lines Ltd. Business and Services Restructuring Proposal and Mainline Final Tolls for 2012 and 2013 Evidence of Alberta Northeast Gas, Limited
1 ANE recommends that the maximum bid floor for IT service be set at 300% of the 2 corresponding FT toll. This is vital to preserving reasonable tolls for FT service as all FT 3 shippers, including ANE, are responsible for the full cost of TransCanada’s facility 4 investments net of any discretionary revenues. FT shippers not only pay for the annual 5 revenue requirement associated with the facilities necessary to provide service to them, 6 but also pay all of the costs of excess capacity that TransCanada is unable to mitigate 7 through discretionary services. Under these circumstances, ANE’s proposed maximum 8 bid floor of 300% of the corresponding FT toll will promote the sustainability of the 9 TransCanada system by bringing FT tolls closer to the levels representative of a fully 10 contracted system. The change in use of FT and IT services reflects a decline in the 11 reliability benefits of FT service relative to IT service. Failure to address this through 12 more substantial adjustments to IT pricing will allow IT service to further erode 13 TransCanada’s ability to optimize revenues from its facility investments.
14 Q31. Would your proposal result in IT shippers paying 300% of the FT price during 15 significant portions of the year? 16 A31. No. TransCanada will be responsible for setting the bid floor for IT service on each day 17 along each path. The bid floor represents the minimum bid that shippers must offer to 18 be awarded service. Daily market circumstances on individual transportation paths will 19 affect whether TransCanada is able to set the bid floor closer to the maximum level of 20 300% of the FT toll or closer to the minimum of 100% of the FT toll. One measure of 21 TransCanada’s ability to set higher minimum bid prices is the daily load factor of the 22 pipe. Figure 2 provides a summary of the percentage of maximum flow experienced on 23 the primary segments of TransCanada’s system.15
Figure 2 Utilization by Primary Segment November 2010 - October 2011 100%
75%
50%
25%
0% 1-Nov-10 1-Jan-11 1-Mar-11 1-May-11 1-Jul-11 1-Sep-11 Prairies NOL EOT
15 Source data provided in IGUA-TransCanada 1.1(a). National Energy Board of Canada, RH-3-2011 Page 18 of 55 TransCanada PipeLines Limited, NOVA Gas Transmission Ltd., Foothills Pipe Lines Ltd. Business and Services Restructuring Proposal and Mainline Final Tolls for 2012 and 2013 Evidence of Alberta Northeast Gas, Limited
1 As indicated in Figure 2, TransCanada operates at below a 50% utilization rate 2 throughput much of the year. Revenue optimization will require TransCanada to set the 3 bid floor below the maximum level throughout much of the year.
4 Q32. Why is 300% of the FT toll an appropriate maximum bid floor? 5 A32. Establishing the appropriate maximum bid floor price is not a formulistic exercise, and 6 instead entails the application of reasoned judgment. Various factors should be weighed 7 in establishing the appropriate maximum bid floor price; however, the primary 8 consideration is the need to offset the costs of excess capacity borne by firm shippers. 9 For this reason, it is important to maximize the revenue that TransCanada is able to 10 generate through IT service through a higher maximum bid floor. Establishing a 300% 11 maximum bid floor will allow TransCanada to increase IT revenues on some days and 12 along some paths when market circumstances allow it to set a floor price higher than 13 the 160% proposed by TransCanada.
14 Even at a price equal to 300% of the corresponding FT toll, IT shippers make no 15 commitment to pay the annual revenue requirements of the facilities used to provide 16 service. The potential for harm is not to the IT shipper that may pay more for service 17 that entails no commitment, but to FT shippers that must pay all of the unrecovered 18 costs of excess TransCanada capacity under the existing regulatory compact.
19 Q33. Do you expect TransCanada will be able to set a bid floor above 160% in some 20 situations? 21 A33. Yes. TransCanada’s analysis presented in Table 8-2 of the Application demonstrates that 22 there are many days where the implied value of TransCanada’s IT service is above 160% 23 of the FT toll for at least the Dawn to Iroquois path based on basis differentials alone. 24 Further, institution of the changes proposed in the present Application is expected to 25 make it more likely that the basis differential will exceed the maximum toll for a given 26 path.16 As noted by TransCanada, it is appropriate to provide the Company with more 27 flexibility to capture greater discretionary revenues from IT and STFT services in order to 28 offset the revenue requirements imposed on FT shippers.17 TransCanada expert Reed 29 also noted that a maximum bid floor above the level TransCanada proposed would 30 provide it with additional pricing flexibility and could provide a greater opportunity to 31 optimize TransCanada's revenues.18
16 TransCanada Application: Part C: Appendix C4: Direct Evidence of John J. Reed, p. 64, lines 14-17. 17 NEB-TransCanada 2.33(a). 18 ANE-TransCanada 1.23(b). National Energy Board of Canada, RH-3-2011 Page 19 of 55 TransCanada PipeLines Limited, NOVA Gas Transmission Ltd., Foothills Pipe Lines Ltd. Business and Services Restructuring Proposal and Mainline Final Tolls for 2012 and 2013 Evidence of Alberta Northeast Gas, Limited
1 Q34. Doesn't your 300% bid floor proposal provide TransCanada with even more discretion 2 than its 160% bid floor proposal? 3 A34. Yes. The extra price discretion is to allow TransCanada to capture the extra revenue that 4 may be available in peak periods, when it may be able to price the service at levels that 5 exceed 160% of the FT toll. Broad pricing flexibility is needed in order to address the 6 substantial concerns associated with excess capacity created by TransCanada’s current 7 operating environment. Without broader discretion in the pricing of IT service, the 8 balancing of FT and IT interests is not achieved due to the fact that FT shippers are 9 responsible for the costs of the underutilization of TransCanada’s system.
10 Q35. Do you agree with TransCanada’s proposal to lower the minimum bid floor for IT 11 service to 100% of the corresponding FT toll? 12 A35. The Company’s proposal to lower the bid floor to 100% of the corresponding FT toll also 13 provides pricing flexibility to meet changing circumstances in the interruptible markets. 14 However, the ability to acquire IT service at a 100% load factor price of the FT toll raises 15 equity concerns on a pipeline system with substantial levels of excess capacity. This is 16 particularly true given the fact that anytime the bid floor is set at a 100% load factor, 17 TransCanada is unlikely to receive any higher revenues as a result of bidding.19
18 ANE believes the pricing flexibility to lower the bid floor is reasonable when considered 19 in the context of two of ANE's proposals. The first is that it is essential that TransCanada 20 be afforded substantial flexibility to set bid floors well above the existing level of 110% 21 of the corresponding FT toll. This is accomplished under ANE’s proposed maximum bid 22 floor of 300% of the corresponding FT toll and to a lesser extent under TransCanada’s 23 proposal. Second, it is essential to provide a means of ensuring that shippers are 24 protected against TransCanada setting a bid floor below 110% in situations when it is 25 not absolutely necessary. ANE’s proposed revenue incentive mechanism discussed later 26 in ANE’s evidence provides such a safeguard.
27 Q36. Are you proposing any precautions to address the exercise of this pricing discretion by 28 TransCanada? 29 A36. We acknowledge the Board's previously stated concerns in RH-1-99 with respect to how 30 pricing discretion may be used: 31 The Board notes that the exercise of pricing discretion necessarily entails 32 the potential for error or for misjudgment of the market. In the Board’s 33 view, there should be accountability for any such error or misjudgment. 34 TransCanada’s proposal for pricing discretion was not accompanied with
19 TransCanada Application: Part C: Section 8.0: Mainline Services and Pricing Proposals, p. 12, lines 1-3. National Energy Board of Canada, RH-3-2011 Page 20 of 55 TransCanada PipeLines Limited, NOVA Gas Transmission Ltd., Foothills Pipe Lines Ltd. Business and Services Restructuring Proposal and Mainline Final Tolls for 2012 and 2013 Evidence of Alberta Northeast Gas, Limited
1 direct accountability for the consequences of the exercise of its 2 discretion.
3 In terms of aligning TransCanada's interests with those of the shippers for the 4 consequences of the exercise of its pricing discretion, ANE is proposing an incentive 5 mechanism (see Section III) to incent TransCanada to exercise this discretion in a 6 manner that will maximize overall system revenues.
7 Given the need to optimize discretionary revenues to offset the costs of excess capacity 8 on the system, the revenue consequences of failing to provide TransCanada with 9 adequate pricing discretion for IT and STFT service are significant. ANE believes that 10 TransCanada has identified the proper factors to take into consideration in applying the 11 pricing discretion.
12 Q37. Is ANE’s maximum bid floor proposal reasonable for IT shippers? 13 A37. Yes. Even though IT shippers make no commitment to contribute to the annual costs of 14 TransCanada’s facilities, ANE’s proposal still provides IT shippers with a capped bid floor, 15 albeit a higher one than existed in the past. Unlike FT and STFT shippers, IT shippers are 16 not subject to subsequent pricing adjustments for variations in TransCanada costs or 17 volumes. The excess capacity situation on TransCanada provides IT shippers with access 18 to TransCanada facilities even during peak periods. Nothing in ANE’s proposal 19 diminishes the service benefits that IT shippers enjoy on the TransCanada system. FT 20 shippers are subsidizing the entire system, especially IT shippers.
21 As is demonstrated through TransCanada’s evidence in this proceeding, market 22 conditions will prevent the Company from setting the bid floor at the maximum level for 23 many days during the year.20 Therefore, there is little likelihood that the IT revenues will 24 cover the full costs of facilities utilized to provide service, even if IT shippers contribute 25 300% of the corresponding FT toll on some days during the year. Accordingly, the costs 26 of providing IT service will continue to be subsidized by FT shippers. IT Shippers always 27 have the option of purchasing STFT service or FT service if either of these services better 28 meet the shippers' needs for daily toll certainty above that afforded under ANE’s 29 recommendations.
30 D. STFT Service 31 Q38. Please summarize TransCanada’s proposed changes to STFT service. 32 A38. TransCanada proposes to implement term-differentiated maximum bid floors for STFT 33 service. Under TransCanada's proposal: (i) the maximum bid floor for STFT service with a
20 See, for example, TransCanada Application: Part C: Section 8.0: Mainline Services and Pricing Proposals, Figure 8-1, p. 7. National Energy Board of Canada, RH-3-2011 Page 21 of 55 TransCanada PipeLines Limited, NOVA Gas Transmission Ltd., Foothills Pipe Lines Ltd. Business and Services Restructuring Proposal and Mainline Final Tolls for 2012 and 2013 Evidence of Alberta Northeast Gas, Limited
1 term of at least a full winter or summer season would increase to 140% of the 2 corresponding FT toll; (ii) the maximum bid floor for STFT service with a term of at least 3 a calendar month but less than a season would increase to 150% of the corresponding 4 FT toll; and (iii) the maximum bid floor for STFT service with a term of seven days but 5 less than a calendar month would increase to 160% of the corresponding FT toll. 6 TransCanada also proposes to retain the flexibility to price all STFT service as low as 7 100% of the corresponding FT toll to respond to market circumstances.
8 Q39. What are your views concerning TransCanada’s proposal to address concerns 9 associated with the impact of STFT service terms on TransCanada’s revenue? 10 A39. By focusing on the price of the STFT service alone, TransCanada ignores fundamental 11 structural issues that allow STFT service to compete with its own FT service. The fact 12 that STFT service is a firm service that may be purchased for as little as seven days 13 provides a sizeable economic advantage compared to FT service that unnecessarily 14 hampers TransCanada’s ability to generate firm revenues. STFT offers shippers the 15 ability to lock up firm capacity rights on TransCanada for a short period of time at a 16 steep discount relative to the year-round costs of the service. Even though TransCanada 17 has proposed to increase the maximum bid floor for STFT service, the short 18 commitment undercuts TransCanada’s firm revenue opportunities. The trends in 19 utilization of STFT service as TransCanada’s capacity situation has worsened reveal the 20 underlying problems with offering firm service for limited terms when it is widely known 21 that substantial excess capacity is available on the system.
22 Q40. Do any shippers purchase STFT service for terms that are one month or less? 23 A40. ANE obtained data regarding the utilization of STFT from TransCanada in ANE- 24 TransCanada 1.6. An analysis of these data reveal that the majority of STFT service is 25 purchased with a contract term that is less than a full season. In fact, the average 26 contract length for STFT service for the period 2000 through 2011 is 29 days. Twenty- 27 five percent of the STFT contracts over this period reflected the minimum term of seven 28 days. In the most recent year, 33% of the contracts reflected a term of seven days and 29 for the most recent peak month of January, 62% of the STFT contracts initiated during 30 the month were for the minimum seven-day term.
31 Even though STFT service is purchased by shippers on average for terms less than one 32 month in duration, STFT accounted for more than 30% of total firm volumes on the 33 system. The chart prepared by TransCanada in APPrO-TransCanada 1.14(a), reproduced 34 below, reveals that shippers shape their STFT contract entitlements to meet the 35 required flows rather than electing FT service to meet peak requirements. Shaping of 36 STFT entitlements occurs during the peak winter months of December through February 37 as a result of the ability to purchase STFT service for minimum terms of seven days. This National Energy Board of Canada, RH-3-2011 Page 22 of 55 TransCanada PipeLines Limited, NOVA Gas Transmission Ltd., Foothills Pipe Lines Ltd. Business and Services Restructuring Proposal and Mainline Final Tolls for 2012 and 2013 Evidence of Alberta Northeast Gas, Limited
1 further contributes to the use of TransCanada as a peaking pipeline by non-discretionary 2 service shippers.
Chart from APPRO-TransCanada 1.14(a)
3 Q41. What are the consequences of selling substantial levels of firm service with a minimal 4 contract term? 5 A41. Allowing shippers to secure firm rights to TransCanada’s system to meet peak needs 6 without committing to pay for the costs of the associated facilities results in a revenue 7 requirement shortfall. The availability of short-term firm service is limiting 8 TransCanada’s ability to extract the higher revenues from its investments from users 9 that utilize STFT service to meet firm peak needs. At the current bid floor price of 100% 10 of the FT toll, shippers taking service for seven day terms during the peak period receive 11 service at a 98% discount compared to the annual cost of providing service. This incents 12 shippers to limit their commitments to the shortest time practical given the ease with 13 which capacity is acquired at the minimum bid price. Under the existing regulatory 14 framework that allows TransCanada to pass on the unrecovered costs of its system to 15 remaining firm customers, a substantial portion of the toll increases over recent years is 16 attributable to paying for the revenue shortfalls attributable to selling firm service to 17 shippers with minimal commitments to compensate TransCanada.
18 Unfortunately, TransCanada’s proposal will have little, if any, effect on this underlying 19 problem with STFT service. Even if TransCanada were able to increase the bid floor to 20 160% of the corresponding FT toll for all STFT service with terms of less than one month, 21 shippers would still be able to acquire service for seven days during the peak period at a National Energy Board of Canada, RH-3-2011 Page 23 of 55 TransCanada PipeLines Limited, NOVA Gas Transmission Ltd., Foothills Pipe Lines Ltd. Business and Services Restructuring Proposal and Mainline Final Tolls for 2012 and 2013 Evidence of Alberta Northeast Gas, Limited
1 97% discount compared to the annual costs of providing service. Reducing the discount 2 from 98% to 97% will have virtually no impact on stemming future migration from FT to 3 STFT service. Figure 3 shows the percentage of the annual revenue requirement paid by 4 STFT shippers at 100% and 140% load factor rates based on the number of days of 5 service.
Figure 3 STFT Revenues vs. Revenue Requirement Based on Days of Service
100%
75%
50%
25%
0% 7 21 35 49 63 77 91 105 119 133 147 Revenue Requirement Revenues at 100% Load Factor Toll Revenues at 140% Load Factor Toll
6 Q42. How can these concerns be addressed in order to ensure that the structure of STFT 7 service does not reduce TransCanada’s ability to optimize revenues from its 8 investments in facilities? 9 A42. The proper focus on limiting the ongoing revenue erosion created by STFT service is on 10 establishing an appropriate minimum term. An extremely short minimum commitment 11 for firm service is no longer appropriate given the excess capacity on the system 12 throughout substantial portions of the year. ANE believes that the minimum term for 13 STFT service should be increased to five months to reflect the current and expected 14 market circumstances on TransCanada. In order to maintain its competitiveness, 15 TransCanada must realize appropriate revenue levels from shippers desiring firm 16 service. A five month commitment is reasonable in view of the substantial facility 17 investments made by TransCanada to provide firm service.
18 ANE also believes that pricing flexibility is an important tool for TransCanada to optimize 19 discretionary service revenues from STFT service. Depending on the path or season that 20 the service is offered, STFT service may provide greater opportunities to maximize 21 revenues than at other times or on other paths. Therefore, TransCanada should be 22 provided with the ability to set the minimum bid floor between 100% and 140% of the National Energy Board of Canada, RH-3-2011 Page 24 of 55 TransCanada PipeLines Limited, NOVA Gas Transmission Ltd., Foothills Pipe Lines Ltd. Business and Services Restructuring Proposal and Mainline Final Tolls for 2012 and 2013 Evidence of Alberta Northeast Gas, Limited
1 corresponding FT toll consistent with the Company’s recommendations. Further, ANE’s 2 incentive proposal is an important means of ensuring that TransCanada exercises its 3 discretion in a manner that achieves the greatest revenues as a means of lowering 4 future tolls.
5 Q43. Does STFT service with a minimum term of five months represent an attractive service 6 offering? 7 A43. Increasing the minimum term for STFT service to five months still provides shippers with 8 a substantial discount compared with the annual costs of providing service and with 9 traditional FT service. STFT shippers would avoid 58% of the costs of subscribing for 10 annual firm service at the bid floor of 100% of the corresponding FT toll under a 11 minimum term of five months. At a bid floor of 140% of the corresponding FT toll, STFT 12 shippers would avoid 42% of the costs of subscribing for year-round FT service. These 13 represent substantial savings for shippers that require firm service, but are not willing to 14 commit to year-round costs.
15 It is possible that some parties that are presently utilizing STFT service may oppose 16 ANE’s recommendation to increase the minimum term to five months. No doubt these 17 shippers have grown accustomed to the benefits of avoiding responsibility to pay for the 18 facilities relied upon to provide firm service during the peak periods. TransCanada would 19 not have constructed the facilities to provide peak period firm service to shippers 20 making such limited commitments in return. Even with the longer term, FT shippers will 21 still subsidize the costs of providing firm service for periods that are shorter than a year; 22 however, the level of the subsidy will be significantly reduced.
23 Q44. Is ANE’s proposed minimum term of five months for STFT service an appropriate 24 solution to the challenges associated with excess capacity on the system? 25 A44. Yes. Shippers that require firm service, but are unwilling to commit to annual FT service 26 will continue to be able to acquire STFT service at a substantial discount relative to 27 TransCanada’s annual revenue requirements. Shippers that do not require firm service 28 and do not desire to purchase five month service will have the option of relying on 29 TransCanada’s IT service. TransCanada recognizes that increasing the minimum term of 30 STFT service could allow it to further optimize revenues and better encourage further 31 longer-term contracting.21
21 ANE-TransCanada 1.23(c). Attachment A7 Tab 16 Part A – Review and Variance Application Flamborough (Town) v Canada (National Energy Board), [1987] FCJ No 360, 81 NR 229 (FCA) Page 1
Indexed as: Flamborough (Town) v. Canada (National Energy Board) (F.C.A.)
IN THE MATTER OF an appeal from the National Energy Board; AND IN THE MATTER OF the National Energy Board Act and the regulations made therunder; AND IN THE MATTER OF Order No. XO-1-83 dated May 4, 1983, issued to Interprovincial Pipe Line Limited pursuant to s. 49 of the National Energy Board Act; AND IN THE MATTER OF a public hearing held pursuant to subsections 17(1) and 20(3) of the National Energy Board Act held in 1985 under Order No. MH-1-83, as amended, for the purpose of reviewing that portion of the National Energy Board Order XO-1-83 approving the location of the two proposed propane loading facilities, Board File No. 1755-J1-43; AND IN THE MATTER OF Order No. AO-2-XO-1-83 dated December 18, 1985, and the National Energy Board reasons for decision in respect of the said Order issued January 10, 1986 Between Corporation of the Town of Flamborough and Regional Municipality of Hamilton-Wentworth, Appellants, and National Energy Board and Interprovincial Pipe Line Limited, Respondents
[1987] F.C.J. No. 460
[1987] A.C.F. No 460
81 N.R. 229
5 A.C.W.S. (3d) 109
Court No. A-288-86
Federal Court of Appeal Toronto, Ontario
Heald, Mahoney and Marceau JJ.
Heard: May 4, 1987 Judgment: May 7, 1987 Page 2
Energy -- Approval of loading facilities for propane -- Right to a fair hearing.
D. Estrin, for the Appellants. L. Keough, for the National Energy Board. J.W. Brown, Q.C. and N. Finkelstein, for Interprovincial Pipe Line.
MAHONEY J. (for the Court, allowing the appeal):-- This appeal, by leave granted pursuant to section 18 of the National Energy Board Act, R.S.C. 1972, c. N-6, is concerned with an order of the Respondent, National Energy Board (NEB), which approved the location of truck and rail delivery and loading facilities for propane within the Appellants' municipal boundaries. The facilities are proposed to be ancillary to a pipeline owned and operated by the Respondent, Interprovincial Pipe Line Limited (IPL). The facilities are located some distance apart: the truck facility on Ontario Highway No. 6 near Harper Corners, the rail facility on a Canadian Pacific line near Flamborough Centre. There are 20 existing residential units within one kilometer of the rail site and 165 within two. There are 45 and 170 respectively within the same distances of the truck site. The NEB had initially approved the facilities without a hearing after invoking section 49 of the Act. It made an or- der. It then determined that a public hearing ought to be held. The order in issue amends the original order. Major items of concern at the hearing were public safety and the management of emergencies. The NEB's hearing occupied 34 days: 30 days in which it received evidence followed by four days of argument. In presenting their evidence and cross-examining witnesses tendered by others, the Appellant municipalities had the objec- tive of satisfying the NEB that the facilities ought not be located within their boundaries at all. While the evidence re- ceived by the NEB certainly gave a clear indication of most, if not all, of the safety and emergency management con- cerns, it was not directed to pertinent conditions that might be stipulated should the location approvals be confirmed. In the course of argument cousel for IPL (Transcript, Vol. 31, p. 5523) observed:
I do not propose at this point to address any question of what conditions -- or additional condi- tions to those that are there -- may be part of the Board's affirming order were the Board to accept our submissions. I would be prepared to do that at the Board's convenience or at a later stage. The Appellants supported that proposal. The suggestion was disposed of by the Chairman (Vol. 33, p. 5731ff.) in the folloiwng terms:
... yesterday you left the impression, Mr. Brown, that you felt that should the Board's decision be in favour of IPL, you would then expect that there would be some process where there would be a discussion or some exchange of views with respect to conditions that might be attached to that decision, and I think I was trying to make it quite clear that this hearing will come to an end when argument finishes and the Board has to reach its decision.
Should the decision be in favour of IPL, the Board, in its discretion, will attach whatever con- ditions it feels appropriate and will not seek any further views from any of the parties. In the decision issued, at pages 24 and 29, the NEB dealt with the matter in the following manner:
6.3 Contingency Plans
It was the view of Intervenors that Interprovincial should have presented contingency plans for the proposed facilities during the hearing. As such plans were not provided, the Town/Region re- quested that, should the facilities be approved, it have the opportunity to comment on any emer- gency response plans which Interprovincial might submit.
Page 3
Views of the Board
The safety of the public residing near the proposed facilities is of primary importance to the Board. The Board is well aware of the hazards associated with propane, and feels that careful contingency planning could mitigate potential damage from a serious propane incident.
The Board would require Interprovincial to provide an emergency procedures manual for review and approval by the Board before leave-to-open the facilities is granted. That manual would be expected to address emergency measures to be followed on-site, in the event of a propane release. After Board approval of the manual Interprovincial would be required to provide the Town and Region with copies of the manual. If local authorities decide to develop evacuation plans for the population in the areas near the sites, Interprovincial would be expected to co-operate in formu- lating such plans, should it be requested to do so.
7.3.3 Operating Manuals
The Town/Region questioned Interprovincial's witnesses regarding both the availability and the intended contents of a site operating manual. Intervenors implied, through questioning, that it was difficult to fully assess the safety of the site without such manuals.
Interprovincial indicated that the final site design would have to be completed and hardware or- dered before manuals could be written. Interprovincial stated that it had obtained a manual in use at a propane depot in Alberta, to provide reference material in producing its own. Questioning by Intervenors revealed that the manual was for a manned site and would not be directly applicable to an unmanned truck terminal.
Views of the Board
The Board would require Interprovincial to file the site operating manuals for Board approval. In- terprovincial should take care to ensure that the operating manuals comply fully with the re- quirements of the Pipeline Regulations and detail the procedures for items such as on-site secu- rity, loading and routine maintenance. The Board also would require that Interprovincial file cop- ies of the approved operating manuals with the Town and Region. Under section 26 of the Act, IPL will require the leave of the NEB to open the facilities. In the order in issue the NEB stipulated a number of conditions. No. 12 required that an operations manual covering a lengthy list of items be submit- ted for approval before leave to open would be granted. No. 13 required submission of an emergency response manual including, but not limited to, a lengthy list of items. No. 14 required submission for approval of a staff training program and No. 15 a noise monitoring program. This Court's order, granting leave to appeal, is expressed in the following terms:
This application is granted and the applicants are accordingly granted leave to appeal from the Order of the National Energy Board No. AO-2-XO-1-83 dated December 18, 1985, and the Rea- sons given by the Board in respect of that Order on the following questions:
Did the Board breach the principles of natural justice, procedural fairness or fundamental jus- tice in imposing the conditions contained in paragraphs 12, 13, 15 and 15 of its Order
a) Without providing the applicants with an opportunity to lead evidence or make submis- sions as to the precise content of such conditions prior to the making of the order, and b) Without providing the applicants with an opportunity to lead evidence and make submis- sions as to whether such conditions have been complied with prior to leave to open being granted. Page 4
In my opinion, the hearing undertaken by the NEB was inherently a two-stage process entailing, firstly, the determi- nation of whether the earlier approval of the locations should be confirmed and, secondly, a determination of the condi- tions under which the facilities ought to be permitted to be operated on those locations. The Appellants had the same right to be heard on the second stage as on the first. Given the expertise available to the NEB, one may well question the value of the Appellants' input into the prepara- tion of the operations manual and the staff training program. The Appellants' counsel conceded that the noise monitor- ing program, while important to them, was not something they felt strongly required their input. That is all beside the point. As was said by LeDain, J., in Cardinal et al. v. Kent Institution, [1985] 2 S.C.R. 643 at 661:
... I find it necessary to affirm that the denial of a right to a fair hearing must always render a de- cision invalid, whether or not it may appear to a reviewing court that the hearing would likely have resulted in a different decision. The right to a fair hearing must be regarded as an independ- ent, unqualified right in the sense of procedural justice which any person affected by an adminis- trative decision is entitled to have. It is not for a court to deny that right and sense of justice on the basis of speculation as to what the result might have been had there been a hearing. In any event, it is foreseeable that some emergencies arising in connection with the facilities could have effects requir- ing management outside their boundaries. The value of the Appellants' input as well as their right to have input in this area is obvious. That the presence of the facilities may impose a financial burden on the municipalities for the provision of emergency services is, likewise, not to be ignored. I would allow this appeal, set aside paragraph 12, 13, 14 and 15 of Order No. AO-2-XO-1-83 and refer the matter back to the NEB for reconsideration on a basis not inconsistent with these reasons. In referring the matter back I would make clear that the Appellants and IPL are entitled to be heard as to what, within the contemplation of those paragraphs, IPL is to be required to deal with as a precondition of leave to open and also to be heard on those subjects before that material is approved. That said, the NEB is master of its own procedures. It may determine how it will afford the parties a fair hearing. This judgment is not to be construed as necessarily requiring a resumption of the public hearing. MAHONEY J.A.
Attachment A7 Tab 17 Part A – Review and Variance Application Exhibit B-10-2, RH-003-2011, TransCanada Response to NEB 3.39 TransCanada PipeLines Limited RH-003-2011 Response to NEB February 6, 2012 Page 1 of 4 NEB 3.39
Reference:
i) TransCanada Response to Union 8(e), pages 3-4 (PDF pages 14-15) [A2J7T4];
ii) TransCanada Response to NEB 1.3(b), page 3 (PDF page 18) [A2J7Q3].
Preamble:
In reference i), TransCanada explains that the annual revenue requirement is not calculated by segment, but that it can provide estimates based on simplifying assumptions. TransCanada provides an estimate of the eastern segment costs, including TQM TBO costs, and revenue contributions. TransCanada calculates 2012 shortfalls of $154 million with the Restructuring Proposal implemented in its entirety, and $194 million if the proposed cost allocation changes within the Restructuring Proposal were not put into effect. TransCanada concludes, “under the Restructuring Proposal, the eastern segment revenues do not recover eastern segment costs.”
Reference ii) states, “TransCanada considered the use of cost of service allocation within regions as opposed to the current system-wide allocation.”
Request:
a) Discuss the extent to which the estimated $154 million shortfall provides insight into how well the Restructuring Proposal, as a whole, is aligned with tolling principles. b) Provide a cost and revenue analysis similar to that provided in reference i), for other segments of the Mainline. Describe any assumptions made.
c) Explain which aspects of the Restructuring Proposal result in the eastern segment revenues not recovering eastern segment costs.
d) Discuss whether, ideally, the Mainline toll methodology should result in each segment’s revenues recovering that segment’s costs.
e) Explain why TransCanada rejected the use of cost of service allocation within regions or segments as a method to allocate costs.
f) Confirm that due to the nature of the proposed allocation of TQM TBO costs, the TQM portion of the “eastern segment” contributes equal revenues and costs in the Page 2 of 4 NEB 3.39
analysis in reference i), except with regard to East Hereford delivery pressure costs. If not confirmed, explain in detail.
Response: a) TransCanada does not believe that the shortfall provides material insight into how well the Restructuring Proposal, as a whole, is aligned with tolling principles due to the integrated nature of the Mainline other than, to the extent that segmented costs can be determined and reflect cost causation, that the Restructuring Proposal is an improvement over the existing Status Quo cost allocation methodology. Please see the responses to parts (c), (d) and (e) below. b) As an integrated system, TransCanada does not calculate the annual Mainline revenue requirement by segment, zone, or other geographical delineations. However, estimates can be provided for three segments, Prairies, NOL and Eastern segments, based on simplifying assumptions. For the results of this analysis, please refer to attachment NEB 3.39b. The cost information has been provided with and without the proposed accumulated depreciation transfer. However, TransCanada believes the most appropriate representation of segment cost is post transfer of accumulated depreciation, which appropriately accounts for consumed service value and remaining economic life of each segment. In addition, the information also includes revenue cases without the proposed Alberta System extension, as requested in CAPP 2.6, and without the proposed cost allocation changes.
In this analysis, the Prairies segment is defined as Mainline facilities from Empress to Station 41, including the lateral to Emerson. The NOL segment is defined as facilities east of Station 41 up to and including Station 116 at North Bay, plus Line 900 for Sault-Ste-Marie. The Eastern segment is defined as facilities east of Station 116 at North Bay and east of St. Clair.
The cost analysis was derived from the 2012 Restructuring Proposal costs. By individual cost item, the specific costs of each segment were determined as a percentage of total system costs, using allocation factors by geographical region when available. This was done for Municipal Taxes, Electric Costs and Tax on Fuel. Depreciation expense for each segment was determined using the appropriate segment depreciation rate (either before or after the accumulated depreciation transfer) applied to the segment Gas Plant in Service (GPIS). The remaining cost items, where specific geographical information was not available, were allocated based on the percentage of segment rate base to total system rate base. For completeness, GLGT TBO costs are included as part of the NOL segment. Union TBO and TQM TBO costs were included as part of the Eastern segment.
Page 3 of 4 NEB 3.39
The revenue analysis was derived using 2012 Restructuring Proposal tolls multiplied by throughput for each segment. For transportation which is forecast to cross multiple segments, the segment revenue from the Energy-Distance component of the toll was determined based on the proportion of distance within each segment compared to the total path, assuming a distance based on shortest distance to the individual DDA. Also for transportation crossing multiple segments, the revenue from the energy component of the toll was determined by applying 50% of the Energy component revenue to the Prairies segment and 50% to the Eastern segment. Revenues for deliveries to the TQM system are included as part of the Eastern segment.
For the sensitivities where the Alberta Extension proposal is excluded and/or the cost allocation proposal is excluded, segmented costs are not impacted. However, segmented revenues are adjusted to reflect the removal of the Alberta System FT contract revenues from the Prairies segment and / or the change in cost allocation. The cost and revenue calculations may not balance precisely due to the simplified methodology used in the analysis and due to rounding.
The analysis shows that none of the scenarios provided result in perfect balance of segmented costs and revenues, nor does TransCanada believe that is required (please refer to response d). TransCanada notes that the proposed transfer of accumulated depreciation and the cost allocation changes do result in segmented costs and revenues being more balanced. c) The cost allocation methodology utilized historically by the Mainline, and which is also being proposed to be continued in the Restructuring Proposal, is a system- wide unit cost approach. The use of a system-wide unit cost reflects the integrated nature of the Mainline and its costs, and means that cost and revenues are recovered through the entire system and not specifically by individual segments. This approach is the same for both the Status Quo and Restructuring Proposal tolls. The cost allocation methodology of using system average unit costs and the cost functionalization between energy and energy-distance produce this result. However the changes made to the cost functionalization in the Restructuring Proposal is an improvement over the existing methodology. d) It is not necessarily ideal for the Mainline toll methodology to result in each segment’s revenues recovering that segment’s embedded costs for an integrated system such as TransCanada, even if those costs could be accurately determined. An exact match between each segment’s revenues and each segment’s embedded costs would be the result of a “zone-gate” toll design. However, it is far more common to design rates through allocation of system-wide costs in a way that produces reasonable relationships and price signals as between the different rates and services. Moreover, an overriding principle of reasonable rates is that they should produce sufficient revenues to recover the total costs of service. There are Page 4 of 4 NEB 3.39
a number of different cost allocation and toll design methodologies that can be utilized to develop natural gas transportation tolls, e.g., postage stamp, zonal, zone-gate, zone of delivery, zone matrix, pure distance, and more than one can be found to be just and reasonable for a particular pipeline. In addition, there are tolling principles that should be considered other than pure cost causation. In terms of the Mainline specifically, the proposed cost allocation and toll design balances a number of competing interests, and as discussed in the Application, TransCanada believes that its cost allocation and toll design methodology is just and reasonable. e) TransCanada chose to continue to utilize the current methodology of using system average unit costs rather than establishing unit costs on a segmented basis for the following reasons:
First, using system average unit costs is more aligned with the integrated nature of Mainline system. For example the GLGT system and the NOL facilities are used to provide not only service within each of their respective segments, but rather are also used to provide service from Dawn to other points in the eastern triangle. Even though long-haul service that spans segments has been decreasing, these services still generate the majority of the Mainline revenue and TransCanada believes these volumes will increase with the implementation of the Restructuring Proposal.
Second, this is consistent with the historical methodology employed on the Mainline and TransCanada does not believe this methodology needs to be changed at this time.
Third, by using system average costs, the tolls for all services are more stable, simpler and easier to administer. f) Confirmed. Business and Services Restructuring Application and Mainline 2012-2013 Tolls Application Attachment NEB 3.39b
Revenue Requirement and Asset Values Allocated by Segment:
2012 Restructuring 2012 Restructuring (w/o accum depr shift) Line # Gross Revenue Requirement ($000's) Prairies NOL Eastern Total Prairies NOL Eastern Total Allocation Method (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Transmission By Others 1 - GLGT - 59,111 - 59,111 - 59,111 - 59,111 GLGT allocated to NOL 2 - Union - - 30,042 30,042 - - 30,042 30,042 Union Allocated to Eastern 3 - TQM - - 80,000 80,000 - - 80,000 80,000 TQM Allocated to Eastern 4 Storage Operating Costs 6,748 2,477 6,517 15,742 4,724 5,857 5,162 15,742 Allocated by Rate Base % 5 NEB Cost Recovery & Collaborative Costs 4,376 1,606 4,226 10,208 3,063 3,798 3,347 10,208 Allocated by Rate Base % 6 Return 203,951 74,860 196,985 475,796 141,873 175,899 155,030 472,802 Allocated by Rate Base % 7 Income Taxes 67,784 24,880 65,468 158,132 59,216 73,418 64,707 197,341 Allocated by Rate Base % 8 Municipal and Provincial Capital Taxes 41,269 46,584 36,729 124,582 41,269 46,584 36,729 124,582 Geographical assignment 9 Pipeline Integrity 40,551 14,884 39,166 94,601 28,387 35,195 31,019 94,601 Allocated by Rate Base % 10 Depreciation 123,343 74,524 89,218 287,085 86,791 245,356 69,545 401,692 GPIS x composite rate 11 Adjustment Account (42,034) (15,429) (40,599) (98,062) (29,193) (36,195) (31,900) (97,288) Allocated by Rate Base % 12 Regulatory Amortizations 74,759 27,440 72,206 174,405 52,333 64,885 57,187 174,405 Allocated by Rate Base % 13 Fuel Gas Tax 1,454 - 139 1,593 1,454 - 139 1,593 Geographical assignment 14 Electrical Costs 22,512 4 4,398 26,913 22,512 4 4,398 26,913 Geographical assignment 15 Operations, Maintenance and Administrative 74,800 27,456 72,245 174,501 52,362 64,920 57,218 174,501 Allocated by Rate Base % 16 TransCanada Contribution / Incentives (10,716) (3,933) (10,350) (25,000) (7,502) (9,301) (8,197) (25,000) Allocated by Rate Base % 17 Gross Revenue Requirement 608,794 334,464 646,390 1,589,649 457,289 729,530 554,426 1,741,245
Asset Values ($000's, as of Dec 31, 2012) 18 Gross Plant 3,809,883 5,296,828 3,290,320 12,397,031 3,809,883 5,296,828 3,290,320 12,397,031 As per filed schedule (1) 19 Accumulated Depreciation 1,485,756 4,454,654 1,001,855 6,942,265 2,179,719 3,350,782 1,469,103 6,999,604 As per filed schedule (2) 20 Working Capital 38,588 14,164 37,270 90,022 27,013 33,491 29,518 90,022 Allocated by Rate Base %
Asset % Values Used For Allocation Rate Base Dep Rate Rate Base Dep Rate 21 Prairies 43% 3.2% 30% 2.2% 22 NOL 16% 1.4% 37% 4.5% 23 Eastern 41% 2.7% 33% 2.1%
Geographical Revenue Requirement Allocations:
Line # Municipal Taxes Proportion Electrical Cost Proportion 24 Alberta 1% Electric Energy Aftercoolers 2.4% 25 Sask Border to Stn 41 32% Montreal Line Electric Units 16.1% 26 Stn 41 to NBJ 37% Stn. 9E & 17E 43.1% 27 NBJ to Quebec 27% Stn. 41F & 41G 38.2% 28 Quebec (TQM) 2% Stn. 52C 0.0% 29 Stn. 123C 0.2% Sales Tax on Fuel Proportion 30 Saskatchewan 83.0% 31 Manitoba 7.1% 32 Quebec 9.9% (1) Application, Section 12, Attachment 12.1, Tab 5, Schedule 5.3.1 (2) Application, Section 12, Attachment 12.1, Tab 5, Schedule 5.3.2 Business and Services Restructuring Application and Mainline 2012-2013 Tolls Application Attachment NEB 3.39b Revenue by Segment and Service ($000's) (a) (b) (c) (d) (e) (f) (g) (h) (i)
Base Restructuring Proposal Scenarios
2012 Restructuring 2012 Restructuring (w/o accum depr shift) Line # Service Prairies NOL Eastern Total Prairies NOL Eastern Total 1 FT 452,397 274,759 316,472 1,043,628 498,319 311,264 340,979 1,150,563 2 FT-SN - - 15,948 15,948 - - 16,140 16,140 3 STS 2,702 2,155 76,277 81,134 2,846 2,441 81,031 86,318 4 NDMR (77) - 15,674 15,596 (77) - 15,674 15,596 5 DMR 286,123 60,305 58,520 404,947 315,751 68,317 60,153 444,221 6 Other 15,831 2,978 9,589 28,399 15,916 3,076 8,936 27,928 7 Total 756,975 340,197 492,479 1,589,651 832,755 385,098 522,913 1,740,766
Sensitivities Without the Proposed Cost Allocation Changes
2012 Restructuring 2012 Restructuring (w/o accum depr shift) Line # Service Prairies NOL Eastern Total Prairies NOL Eastern Total 8 FT 449,932 308,842 306,252 1,065,026 496,041 342,517 331,594 1,170,152 9 FT-SN - - 9,969 9,969 - - 10,656 10,656 10 STS 2,151 2,422 71,256 75,829 2,341 2,686 76,423 81,450 11 NDMR (77) - 15,674 15,596 (77) - 15,674 15,596 12 DMR 286,975 67,786 41,538 396,299 316,522 75,177 44,574 436,272 13 Other 16,183 3,421 7,323 26,927 16,210 3,446 8,201 27,858 14 Total 755,164 382,470 452,012 1,589,646 831,037 423,826 487,121 1,741,984
Sensitivities Without the Proposed Alberta System Extension
2012 Restructuring 2012 Restructuring (w/o accum depr shift) Line # Service Prairies NOL Eastern Total Prairies NOL Eastern Total 15 FT 233,332 278,221 339,144 850,696 259,335 312,733 364,793 936,861 16 FT-SN - - 19,751 19,751 - - 20,394 20,394 17 STS 3,137 2,182 82,543 87,861 3,325 2,452 87,746 93,523 18 NDMR (77) - 15,674 15,596 (77) - 15,674 15,596 19 DMR 454,280 61,065 70,050 585,395 502,600 68,640 72,981 644,220 20 Other 17,220 2,086 9,786 29,093 17,303 2,131 10,142 29,576 21 Total 707,891 343,554 536,948 1,588,393 782,485 385,956 571,729 1,740,171
Sensitivities Without the Proposed Alberta System Extension and Cost Allocation Changes
2012 Restructuring 2012 Restructuring (w/o accum depr shift) Line # Service Prairies NOL Eastern Total Prairies NOL Eastern Total 22 FT 245,105 312,736 317,795 875,637 270,969 346,840 343,697 961,507 23 FT-SN - - 11,651 11,651 - - 12,390 12,390 24 STS 2,352 2,452 74,314 79,118 2,549 2,720 79,615 84,883 25 NDMR (77) - 15,674 15,596 (77) - 15,674 15,596 26 DMR 463,735 68,640 46,703 579,078 511,943 76,126 49,910 637,978 27 Other 17,716 2,371 8,955 29,042 17,749 2,386 9,390 29,525 28 Total 728,830 386,200 475,092 1,590,123 803,132 428,072 510,675 1,741,879 Business and Services Restructuring Application and Mainline 2012-2013 Tolls Application Attachment NEB 3.39b Summary of Segmented Revenues vs. Costs ($000's) (a) (b) (c) (d) (e) (f) (g)
Base Restructuring Proposal Scenarios
2012 Restructuring 2012 Restructuring (w/o accum depr shift) Line # Prairies NOL Eastern Prairies NOL Eastern 1 Revenues 756,975 340,197 492,479 832,755 385,098 522,913 2 Costs 608,794 334,464 646,390 457,289 729,530 554,426 3 Difference 148,181 5,733 (153,912) 375,466 (344,432) (31,513)
Sensitivities Without the Proposed Cost Allocation Changes
2012 Restructuring 2012 Restructuring (w/o accum depr shift) Line # Prairies NOL Eastern Prairies NOL Eastern 4 Revenues 755,164 382,470 452,012 831,037 423,826 487,121 5 Costs 608,794 334,464 646,390 457,289 729,530 554,426 6 Difference 146,370 48,006 (194,378) 373,748 (305,705) (67,304)
Sensitivities Without the Proposed Alberta System Extension
2012 Restructuring 2012 Restructuring (w/o accum depr shift) Line # Prairies NOL Eastern Prairies NOL Eastern 7 Revenues 707,891 343,554 536,948 782,485 385,956 571,729 8 Costs 608,794 334,464 646,390 457,289 729,530 554,426 9 Difference 99,097 9,089 (109,443) 325,197 (343,574) 17,304
Sensitivities Without the Proposed Alberta System Extension and Cost Allocation Changes
2012 Restructuring 2012 Restructuring (w/o accum depr shift) Line # Prairies NOL Eastern Prairies NOL Eastern 10 Revenues 728,830 386,200 475,092 803,132 428,072 510,675 11 Costs 608,794 334,464 646,390 457,289 729,530 554,426 12 Difference 120,036 51,736 (171,298) 345,843 (301,458) (43,751) Attachment A7 Tab 18 Part A – Review and Variance Application Exhibit B-42, RH-003-2011, TransCanada Response to Undertaking U-11. TransCanada PipeLines Limited Exhibit No.
National Energy Board Hearing Order RH-003-2011 Undertaking U-11
Response to Undertaking given by TransCanada to Mr. Manning at Transcript Reference Vol. 18, Paragraph 19812, with respect the short-haul toll increase required generate $109 million.
Undertaking: For TransCanada to look at the short-haul volumes that are in the eastern zone only relating to case 39(a) and see what toll increase is required to generate $109 million.
Response: TransCanada understands the undertaking request to pertain to scenario 3(a), the revenue versus cost allocation sensitivity under 2012 Restructuring Proposal excluding the Alberta System Extension that is presented in response to NEB 3.39b. TransCanada further understands the undertaking request to pertain to eastern short haul transportation in the Eastern segment rather than the Eastern Zone, since zones currently only apply to long haul transportation.
With 2012 forecast firm and discretionary eastern short haul quantities of approximately 4.4 PJ/d embedded in the scenario 3(a) developed in response to NEB 3.39, the estimated toll increase that would generate an additional $109 million in revenues is approximately $0.07/GJ. For this calculation, eastern short haul quantities are defined as forecast transportation with a receipt point and a delivery point downstream of St. Clair and North Bay Junction (inclusive). Attachment A7 Tab 19 Part A – Review and Variance Application National Energy Board Reasons for Decision GH-5-89, TransCanada PipeLines Limited, Vol 1, Tolling and Economic Feasibility, November 1990. CANADA National Energy Board
Reasons for Decision
TransCanada Pipelines limited
GH-5-89 c.
November 1990
Volume 1 Tolling and Economic Feasibility
( \..... Chapter 4 Other Part IV Matters ------~ ...... ,,' 4.1 Renewal Rights for Short-term could still obtain short-term transportation/sales Contracts service from LDC's, who would in tum obtain long-term firm service from TransCanada under At the time of the RH-3-86 hearing, Aggregate Contracts or Umbrella-T service TransCanada's short-term transportation and contracts. TransCanada indicated that it had short-term sales service toll schedules stated that Umbrella-T service contracts with most of the a shipper could, upon six months' notice from eastern Canadian local distribution companies TransCanada, be required to elect to either extend ("LDC's") for three-quarters ofthe domestic direct its service to a term of 15 years or terminate its purchases and that it had commenced service, ifTransCanada required capacity for new negotiations with Union, which currently offers a long-term firm service. In its RH-3-86 Decision, form of Umbrella-T service to its customers, for the Board decided that TransCanada had to similar types of transportation contracts in its obtain the Board's approval before any such franchise area. However, TransCanada admitted "bumping" of service occurred. Subsequently, as that there might be a few direct purchase stipulated in the GH-2-87 Decision, bumping was shippers who would prefer to continue with short removed and TransCanada's FS Toll Schedule term FS contracts and who consequently would be was amended to permit a firm shipper to renew required to contract for long-term service or be its firm service contract for a period of no less bumped at the time ofrenewal. than one year and to revise its Contract Demand or Operating Demand to a level no greater than TransCanada and AEC believe the risk of short- the Contract Demand set out in the original term users going off the pipeline system is greater contract or the original Operating Demand than with long-term users because short-term established by the Board for that contract, upon shippers could possibly obtain gas supplies the shipper providing written notice no less than through alternative transportation systems such ~ six months prior to the termination of the FS as St. Clair Pipelines Limited ("St. Clair") and the ~ transportation contract. Northern Border pipeline expansion proposal or go to alternative fuels. TransCanada, AEC, TransCanada, AEC, PanCanadian, WGML, GMi, ProGas and PanCanadian and WGML took the Selkirk, MASSPOWER and ANE opposed the position that existing as well as new shippers continuation of the renewal rights for short-term were the cause of the requirements for new contracts in their present form. These companies facilities because, in the absence of existing generally held the view that long-term shippers shippers renewing their contracts, capacity would face the risk of having to pick up the cost of the become available which could be allocated to new unused capacity if short-term shippersdeciue not shippers and hence reduce the expansion to renew. requirements and the risk of overbuilding facilities. AEC suggested thatan existing shipper TransCanada and AEC believed that during a should also be allowed to reduce its level ofservice period of major facilities expansion, renewals of ifit no longer required all of it and if there were existing contracts should be for a term of 10 years another party prepared to take the service. or more. However, when the pipeline is not in an expansion mode, TransCanada believed that year TransCanada, AEC, PanCanadian, WGML and to-year renewals should be permitted while AEC ProGas also expressed the view that long-term took the view that, during a period not exceeding contracts reflect a stronger commitment to the the next two years, contract renewals should be pipeline system and hence reduce the risk of permitted for a short-term period. capacity under-utilization. AEC argued that if potential new shippers were willing to pay tolls TransCanada, AEC, PanCanadian, WGML and and enter into long-term transportation contracts, GMi took the position that the requirement for then the cost of the short-term contracts to the renewal of contracts for a period of 10 years or short-term shippers was below "market value". more would not deny short-term shippers access Consequently AEC believed longer term contracts~ to direct purchase gas because such shippers ....,i.
30 are a reflection of "market value" for pipeline arrangements for facilities in the U.S. to bringgas ""- capacity. into Canada was currently not competitive and that there was no uncontracted transportation IGUA, Union, Consumers', CCPA, ICI, General available in the U.S. to get gas into Union's Chemical, ICG Utilities (Manitoba) Ltd. ("ICG franchise area. Consumers' believed that the risk (Manitoba)") and the APMC took the position that of under-utilization caused by users going off the the renewal rights provision should continue TransCanada system in favour of importing gas without any bumping. It was generally their view was relatively small. Consumers' also stated that that short-term contracts and renewal rights are U.S. gas through these import points would more necessary to provide shippers with flexibility. It likely be competing for growth in the eastern was argued that industrial users have limited Canadian markets rather than displacing gas ability to pass on the risks and costs of long-term already transported on the TransCanada system. contracts. Consequently, in the absence of short term contracts and renewal rights, industrial Union, Consumers' and GMi all indicated that users would be squeezed out of the transportation Umbrella-T service is available, in one form or service market. IGUA further stated that this another, as an option for short-term shippers to would be contrary to the intent of the Agreement fall back on if a minimum 10-year contract term on Natural Gas Markets and Prices which were established. IGUA indicated that although envisioned a multiplicity of buyers and sellers to some of its members were under Umbrella-T ensure a responsive, market-oriented service arrangements, others preferred to control environment. their transportation directly. Consumers' believes that some end users want to continue to be As to the question of whether short-term contracts shippers for administrative reasons. For example, pose an added risk to the pipeline system, IGUA, a short-term shipper may have more than one Union and Consumers' indicated that there is no plant in a franchise area or plants in more than evidence of unrecovered demand charges from one LDC franchise area. Thus, the end user, by short-term contracts and related renewals and controlling transportation, could shift its gas from that, for the most part, the related markets are one plant to another. long-term, enduring markets. Further, the level of risk is also reduced by the ability to assign IPAC and Canadian Hunter held the view that if contracts, divert gas or reallocate capacity to the a rolled-in toll methodology is retained there queue for service. IGUA also held the view that should be no change to the renewal rights policy. long-term contracts do not provide sufficient However, these companies took the position that, evidence of a shipper's commitment to if the Board were to adopt an incremental toll TransCanada's system but that the high methodology, the renewal rights provision should utilization of either long-term or short-term be reviewed. IPAC further stated that under contracts does. It was IGUA's evidence that most incremental tolling, existing shippers should be short-term shippers operated at 100 percent load treated on the same basis as new shippers and, factor, while some long-term shippers, upon renewal, existing shippers should have to particularly to the export market, operated at match the term of the longest competing request substantially below that level. for service on the system, namely 10 to 15 years.
In relation to short-term shippers going off the ProGas, PanCanadian and the APMC argued system because of the economics of gas prices that, during times of pipeline expansion, short versus those of alternate fuels, IGUA indicated term contract renewals should be looked at more that industrial customers do not switch back and closely. forth in a significant way and are, by and large, users of natural gas on an ongoing basis. Views ofthe Board Although Union and Consumers' agreed that short-term shippers could potentially leave the The evidence on the continued appropriateness of TransCanada system and access gas by using the the renewal rights of shippers using short-term St. Clair and Windsor import points, these parties contracts to serve long-term markets focussed on did not believe that this was likely to occur. the risk that such shippers might cease to use Union stated that making long-term TransCanada's pipeline system. This event could
31 result in pipeline under-utilization, particularly if Decision ~. it occurred after a major facility expansion. ~ Although the risk of pipeline under-utilization is The Board has decided that the existing inherent in short-term contracts, the number of renewal rights policy for shippers using short-term transportation transactions, the short-term contracts continues to be demonstration that such transactions are serving appropriate. long-term gas markets and the current demand for pipeline access combine to ensure that the risk 4.2 Zonal vs. Point-to-Point Tolls for is minimal at the present time and into the Export Volumes foreseeable future. In the RH-1-88 Phase II proceeding, the Board The potential risk of short-term shippers, examined the issue of the appropriateness of primarily industrial customers, switching to designing tolls for volumes delivered. to the export alternative fuels is minimal. Such end users have market on a point-to-point basis when tolls for made long-term commitments in plant and domestic volumes are calculated on a zonal basis. equipment to use natural gas either as fuel or as In the RH-1-88 Phase II Decision, the Board found feedstock. Thus an industrial user's decision to that the distinction of traffic as being either switch to an alternative fuel would not be based export traffic or domestic traffic should continue solely on the price of gas, but on other factors as to be taken into account in determining whether well. In regard to alternative supplies ofU.S. gas, such traffic is carried under substantially similar the necessary pipeline capacity is not available circumstances and conditions. Accordingly, the now and is not certain to be available in the Board decided that the then existing point-to foreseeable future. The evidence also indicates point methodology for export traffic remained that the volumes shipped on a short-term basis appropriate. are relatively small and, therefore, the risk of major capacity under-utilization would be At the request of certain parties, the Board correspondingly low. decided to re-examine the issue of point-to-point 0., versus zonal tolls for export volumes. . . The Board also notes that the risk of capacity under-utilization would tend to be reduced by the IPAC submitted that it is inconsistent and use of alternatives such as Umbrella-T service, unjustly discriminatory to have customers on assignments, and diversions by short-term TransCanada pay different tolls for service which shippers. is essentially the same. IPAC was of the view that there is no difference between a customer or The Board authorized the current short-term market in the United States and one in Canada in contract and renewal rights provisions in respect of service on the TransCanada system. TransCanada's tariff to provide producers, Given that it would be extremely cumbersome for marketers and end users with transportation TransCanada and its shippers to establish point options to access gas markets and gas supplies. to-point tolls for domestic service, IPAC stated The existing tariffprovisions have given shippers that it would be more appropriate to have export flexibility in choosing the term and form of customers pay tolls calculated on the same zonal transportation services to meet the particular basis as domestic deliveries. circumstances of their long-term market requirements. The evidence also suggests that The arguments of many parties centred on the these tariff provisions, together with the removal interpretation of the word "traffic" in section 62 of of the bumping provision from TransCanada's the Act and the appropriateness of the Board's tariff, have enhanced the development of a more decision in RH-1-88 to expand the previous market-oriented and competitive gas definition, found in GH-2-87, to distinguish environment. Therefore, the Board is not between domestic and export traffic. persuaded that any changes to the existing short term contract and renewal rights provisions in IPAC, PanCanadian, APMC and Natural TransCanada's tariffare warranted. presented legal arguments in support of theiro disagreement with the broad definition of traffi, .. ~ contained in the RH-1-88 Decision. Based on a
32 Attachment A7 Tab 20 Part A – Review and Variance Application National Energy Board Reasons for Decision RH-4-93, TransCanada PipeLines Limited, Tolls, June 1994. CANADA National Energy Board
Reasons for Decision
TransCanada PipeLines Limited
RH-4-93
June 1994
Tolls Chapter 10 Contract Renewals
10.1 Renewals Policy
TransCanada’s current renewals policy of a 1-year minimum contract term with renewal rights having a six-month renewal notice period was first approved by the Board in GH-2-87 (issued in July 1988). Since that Decision, no changes have been made to the policy. The policy was last reviewed in GH-5-89.
TransCanada expressed the view that, since the last review, the natural gas marketplace has experienced significant change as a result of market evolution and continued deregulation both in the U.S. and Canada. Since the implementation of the current policy, TransCanada’s system has been significantly expanded to accommodate the demand for pipeline capacity to serve both new and existing markets. Recently, TransCanada and other interested parties have voiced some concern about the continued appropriateness of the current policy. To address this issue, the TransCanada 1994 Tolls Task Force formed a Renewals Sub-Committee to review the current renewals policy. The Sub- Committee was unable to reach a consensus on the existence of a problem with the current renewals policy nor on alternative policies.
This issue was originally scheduled to be heard as part of GH-2-93. However, following submissions from interested parties, the Board deferred it to this proceeding.
TransCanada proposed changes to its Transportation Tariff to address the concerns it had regarding the continued appropriateness of the current renewals policy. TransCanada cited several reasons for believing that a change was needed including: incompatibility between the renewal notice period and the planning and construction cycle; the risk to the system associated with the volume of short-term transportation contracts; increased competition from other gas sources; changes in U.S. regulation and the need for congruence between Canadian and U.S. policies; the increase in assignments and diversions; and the lack of a smooth contract expiry profile. The proposed changes would be effective for contracts expiring on or after 31 October 1994.
TransCanada proposed that the current renewals policy be modified to provide a range of renewal notice periods from 6 to 18 months with a sliding scale of fees ranging from no fee for an 18 month or greater notice of renewal or termination to a fee equal to 3% of the annual Demand Toll for a 6 month notice of renewal (Renewal Fee) or termination (Exit Fee). An 18-month renewal notice period without fee was chosen by TransCanada as it believed that this was most compatible with TransCanada’s planning and construction cycle. At 18 months, TransCanada’s costs to modify or terminate an expansion would be minimal. An 18-month period would also provide TransCanada with more time to find new shippers in the event of non-renewal of capacity. TransCanada indicated that the current level of short-term contract volumes is approximately the same as it has been for the past several years, and that it has been able to fully absorb non-renewed capacity into its expansions. However, with the declining average contract term, lack of a smooth expiry profile and expected smaller future expansions, the potential exists for the level of contract non-renewals to increase dramatically in the future. TransCanada was of the view that this potential increase in contract non-
XXXXXX 59 renewals, when combined with the inability to fully absorb all non-renewed capacity into expansions or to seek new shippers within the short time available, would expose TransCanada and its remaining shippers to greater risk of system underutilization. TransCanada considered that its proposal would provide short-term shippers with an incentive to indicate their intentions earlier. Renewal or exit fees paid as a result of this proposal would be credited to a deferral account and would be used to offset the toll effects of future non-renewals.
CAPP expressed concern that, while the current renewals policy affords shippers with a high degree of flexibility, it might result in unnecessary system expansion. CAPP preferred to see a policy which is more compatible with TransCanada’s planning and construction cycle. CAPP proposed that the minimum contract term for which automatic renewal rights apply be extended to 2 years and that the renewal notice period vary depending on whether or not TransCanada is in an expansion cycle. In an expansion cycle, CAPP considered that an appropriate notice period would be 12 months. In an non- expansion cycle, the renewal notice period would be 6 months. CAPP did not support renewal fees. CAPP argued that the TransCanada renewal fee proposal was inappropriate as it was not cost-based and did not provide the terms and conditions demanded by the market. CAPP also argued that the current renewals policy is not compatible with TransCanada’s current planning and construction cycle, which could lead to overbuilding.
APMC shared the concerns expressed by CAPP regarding the potential for overbuilding and the desire to achieve a balance between the needs of shippers and those of the system. APMC proposed that the minimum contract term for which automatic renewal rights apply be extended to 2 years and that the renewal notice period be extended to 12 months. APMC argued that its proposal balanced the need of shippers for flexibility with the need for greater system planning certainty and more equitably allocated cost responsibility amongst shippers. APMC did not support renewal fees. APMC argued that the TransCanada proposal was inappropriate as it was not cost-based, would only provide the advanced renewal notice desired by TransCanada if the fees were set at the right level, and would not send the appropriate market signals. APMC also argued that the current renewals policy was inappropriate as it does not address the potential problem of overbuilding the TransCanada system. NSP and Wascana supported the APMC proposal.
Centra Ontario and Consumers’ argued that the TransCanada proposal was inappropriate as it would either decrease the flexibility enjoyed by shippers or increase the cost of that flexibility. They argued that the minimum term for which renewal rights apply should remain at 1 year but that the renewal notice period could be extended to 12 months in recognition of the potential for overbuilding which exists with a 6-month renewal notice period. This proposal was also supported by Northern Natural and ProGas in argument. Quebec advocated a 1-year minimum contract term with renewal rights having a renewal notice period between 10 and 13 months.
IGUA, Union and Ontario argued for the retention of the existing policy of a minimum 1-year term and 6-months renewal notice period. They were of the view that TransCanada’s proposal as well as the other proposals put forward by intervenors were premature and partial and should be rejected, arguing that more time was needed to properly develop a better solution. They also argued that TransCanada’s Renewal Fee proposal in conjunction with its Contract-term Toll Differential proposal would increase inefficiencies on the system, shift risk to LDCs and other shippers who lack adequate means to mitigate or hedge against the risk and increase the incentive for shippers to use TransCanada as a "swing" pipeline. IGUA, Union and Ontario also argued that the CAPP and APMC proposals
60 XXXXXX decreased the flexibility of shippers. The view that no change is warranted was also supported by F&V, Natural, the Northeast Group and Vermont Gas.
GMi argued that none of the proposals before the Board adequately addressed the risk of non-renewal of short-term contracts. GMi proposed that the renewal notice period be extended to 18 months to provide TransCanada with the notice it required for compatibility with its planning and design cycle.
Views of the Board
In GH-5-89, the Board considered proposed revisions to TransCanada’s renewals policy and determined that a change was not warranted. The evidence and arguments presented in this proceeding that shippers with short-term contracts pose a risk of system underutilization are similar to those presented in GH-5-89. Arguments have been made that circumstances have changed since GH-5-89 to the extent that a change to the renewals policy is now warranted. The Board is of the view that the evidence indicates otherwise. The volumes under short-term contracts have remained essentially the same since GH-5-89 and are expected to continue to be so into the foreseeable future. TransCanada continues to apply for expansions to its system. While the level of competition faced by TransCanada from sources of gas delivered by pipelines other than TransCanada is greater than at the time of GH-5-89, it still remains low. The experience to date with the changes in the U.S. as a result of FERC Order 636 is limited and cannot provide conclusive proof that TransCanada’s current policy requires modification to be congruent with U.S. policies.
The views of the Board expressed in GH-5-89 remain valid today. The current renewals policy was authorized to provide producers, marketers and end-users with flexible transportation options based on market principles. As the market is demanding greater rather than less transportation flexibility, the Board is not persuaded that the proposed changes to the existing renewals provisions in TransCanada’s Transportation Tariff are warranted.
Decision
The Board denies all proposed changes to the existing renewals provisions in TransCanada’s Transportation Tariff.
10.2 Contract-term Tolling Differential Proposal
To supplement its proposed changes to the Renewals Policy, TransCanada proposed that a tolling differential be applied to all contracts based on their remaining term to expiry as of 1 January each year. TransCanada originally proposed that there be a premium of 2% for one-year contracts, and a 2% discount for 20-year contracts, to be implemented 1 January 1995. Shippers with 10-year contracts would pay the "base" toll, which contained neither a premium nor a discount. In final argument, TransCanada revised its proposal such that all 1-year contracts would pay the "base" toll, with longer-term contracts receiving a discount up to 4% for 20-year contracts.
XXXXXX 61 Attachment A7 Tab 21 Part A – Review and Variance Application National Energy Board Reasons for Decision GH-3-96, TransCanada PipeLines Limited, Facilities, November 1996. CANADA National Energy Board
Reasons for Decision
TransCanada Pipelines limited
GH-3-96
November 1996
Facilities • demonstrate that, with respect to the new firm export services, all necessary U.S. and Canadian federal regulatory approvals, including applicable long-term Canadian export authorizations have been granted;
• demonstrate that, with respect to the transportation services of new firm volumes, the transportation service contracts have been executed;
• demonstrate that, with respect to the transportation services of new firm volumes, all necessary U.S . and Canadian regulatory approvals have been received for any required downstream facilities or transportation services;
• demonstrate that, with respect to the transportation services of new firm volumes, gas supply contracts have been executed; and '
• identify any changes to TransCanada's base case requirements and the requirements for which the applied-for facilities are required.
The Board is satisfied that the aforementioned certificate conditions will ensure that only firm aggregate requirements underpin the construction of new facilities.
Consistent with the views expressed in the GHW-3-89 Reasons for Decision and for the purposes of this application, ' the Board does not require detailed gas supply information in support of Centra Ontario's, Consumers' and Union's services since these requests result from normal market growth within their franchise areas.
Taking into account the specific qualifications and conditions noted above, and for the purposes of this Part III proceeding, the Board is satisfied with the gas supply arrangements outlined for domestic and export shippers.
3.4 TransCanada's Amended Shippers Non-Approved FT Contracts
TransCanada's original 1997-98 Facilities Application, dated 3 April 1996, contained nine projects totalling 3 574 103m3/d (126.3 MMcfd) of requested new firm service. TransCanada indicated its reluctance to construct additional facilities to increase combined c~pacity given the current contract renewal rights as set out in Article 8 of the Ff Toll Schedule. TransCanada submitted that the current contract renewal rights provisions provide a disincentive for existing shippers to extend their expiring transportation contracts for longer than the minimum period of one year or to provide notice earlier than six months prior to the expiry date of the contract. TransCanada further submitted that it initiated talks with the industry and affected stakeholders regarding TransCanada's contract expiry profile as well as the concerns of others about the terms and conditions associated with FT service.
On 2 August 1996, TransCanada filed its amended 1997-98 Facilities Application, including ten additional projects, for a total of 19 projects requiring a total of 8 118 103m3/d (286.7 MMcfd) of new finn service. To be included in TransCanada's amended Facilities Application, the "amended application" shippers, referred to by TransCanada as bullpen shippers, executed Precedent Agreements which contain clauses that are not included in the original expansion shippers' Precedent Agreements. In effect, the amended shippers agreed to enter an FT contract having renewal rights that are different
22 GH-3-96 from those currently in the Tariff, knowing the change would follow industryrrransCanada discussions and Board approval. TransCanada submitted that it did not expect t~e Board to render any decisions related to this issue in this proceeding.
None of the amended shippers expressed an interest in discussing the non-approved FT contract issue during the hearing. TransCanada contended that nothing should be inferred from a party's silence on the record of the application with respect to these matters. TransCanada indicated that it did not wish to make changing the renewal rights a major issue in the proceeding as it did not wish to prejudice ongoing discussions.
During the hearing, TransCanada submitted, moreover, that it had made arrangements with each of the amended shippers that would allow TransCanada to proceed with construction of all of the applied-for facilities in the event a certificate is granted, and to do so even if the Board were to issue a future Part IV decision, regarding contract renewal rights, that is not satisfactory to TransCanada. TransCanada further submitted that the amended shippers would be treated equally, that the arrangements would not require a Part IV approval from the Board, and that the arrangements would not bear on the rights of the other shippers.
Views of the Board
In determining whether the applied-for facilities for the amended shippers should be certificated, the Board is mindful of TransCanada's undertaking that the construction of those facilities is not dependent upon a future Part IV proceeding dealing with the contract renewal rights. The Board also acknowledges TransCanada's undertaking to treat all amended shippers equally, its assurances that any arrangement with the amended shippers will not have a negative impact on the rights of other shippers, and its assurances that all amended shipper's projects wilI be included in the future construction of the applied-for facilities in the event that a certificate is granted.
The Board is of the view, therefore, that the facilities required for the amended shippers' projects should be included in any approval granted.
GH-3-96 23 Attachment A7 Tab 22 Part A – Review and Variance Application National Energy Board Reasons for Decision RH-1-97, TransCanada PipeLines Limited, 1997 Tolls & FST Conversion Proposal, September 1997 CANADA National Energy Board
Reasons for Decision
TransCanada PipeLines Limited
RH-1-97
September 1997
1997 Tolls & FST Conversion Proposal Chapter 1 Background and Application
By application dated 19 March 1997 and revised on 29 April 1997, TransCanada applied to the NEB pursuant to sections 59, 60 and 65 of the Act for orders fixing final tolls that the Applicant may charge in respect of transportation services rendered by the Applicant effective 1 January 1997, and disallowing any existing tolls or portions thereof that are inconsistent with the tolls so fixed.
In its letter dated 26 March 1997, the Board acknowledged receipt of TransCanada’s 1997 Tolls Application and gave parties the opportunity to submit to the Board, by 15 April 1997, any comments that they may have had regarding TransCanada’s application. This comment period was in accordance with the terms of TransCanada’s Incentive Settlement.
On 15 April 1997, Consumers submitted a complaint to the Board regarding the allocation units used by TransCanada to calculate tolls, but indicated that it wished to negotiate with TransCanada to attempt to resolve this matter and undertook to advise the Board of the outcome by 30 April 1997.
On 30 April 1997, the Board approved TransCanada’s request for revised interim tolls effective 1 May 1997 (Order AO-2-TGI-7-96). The request for interim tolls was based on revisions to TransCanada’s 1997 Tolls Application.
In letters dated 30 April 1997 and revised 1 May 1997, Consumers indicated that it had been unable to resolve the allocation units issue with TransCanada and requested that the Board establish a written proceeding to deal with the matter.
By letter dated 6 May 1997, TransCanada applied, pursuant to sections 59 and 70 of the Act, for approval to enter into a combination of storage, balancing and transportation contracts, and to purchase "start-up" gas to replace the FST which Consumers and Union have elected to convert to FT service.
On 8 May 1997, the NEB indicated that it would consider Consumers’ complaint regarding TransCanada’s allocation units and any other issues related to the revisions contained in TransCanada’s revised application dated 29 April 1997 by way of an oral hearing and that a Hearing Order would be issued shortly.
On 22 May 1997, the Board issued Hearing Order RH-1-97 and added TransCanada’s FST Conversion proposal to the List of Issues. On 23 May 1997, the Board indicated that the hearing would take place in Calgary starting on 28 July 1997.
On 4 June 1997, TransCanada advised the Board that it would be filing proposed tariff changes in RH-1-97 that would affect the contract renewal rights of all FT, FST and STS shippers.
On 10 June 1997, the Board advised parties that contract renewal rights would be added to the RH-1-97 List of Issues.
The Board then received a letter from CAPP dated 9 June 1997, submitting that the issue of contract renewal rights is significant and controversial and transcends the scope of the issues that led to the
RH-1-97 1 RH-1-97 proceeding. CAPP submitted that the existing timetable would not provide parties with sufficient time to address this issue and urged the Board to establish a separate proceeding and to provide parties with more time to adequately deal with the contract renewal rights issue.
On 12 June 1997, TransCanada filed its explanatory and written direct evidence on the allocation units issue as well as its Right of First Refusal ("ROFR") proposal concerning contract renewal rights.
After considering the views of parties, the Board advised on 13 June 1997, that it would hear the contract renewal rights issue separately in a second phase (Phase 2) of the RH-1-97 public hearing commencing 19 August 1997.
On 19 June 1997, CAPP proposed that TransCanada’s expansion policy requirements concerning the market and supply evidence to be provided by expansion shippers also be included in Phase 2 of the Board’s RH-1-97 proceeding as this issue is related to contract renewal rights.
In a letter dated 3 July 1997, the Board asked parties to comment on CAPP’s proposal of 19 June 1997.
In its comments dated 11 July 1997, TransCanada requested that the Board allow the Company to amend its Application by replacing its ROFR proposal with a proposal calling for a 12-month notice period and a two-year minimum contract term. TransCanada also requested that the time fixed by the Board for the commencement of Phase 2 of RH-1-97, be extended from 19 August 1997 to 22 September 1997, including the adoption of TransCanada’s proposed timetable.
After considering parties’ comments, the Board, on 18 July 1997, advised that Phase 2 of RH-1-97 would be severed from RH-1-97 and a separate proceeding established to address TransCanada’s contract renewal rights issue and its expansion policy requirements. On 23 July 1997, the Board published Hearing Order RH-3-97 in this regard.
The RH-1-97 public proceeding, which lasted three days, was held in the Board’s Hearing Room in Calgary, Alberta on 28, 29 and 30 July 1997. The following matters were considered:
a) The allocation units issue;
b) Revisions to TransCanada’s 1997 Tolls Application filed 29 April 1997; and
c) The FST conversion issue.
2 RH-1-97 Attachment A7 Tab 23 Part A – Review and Variance Application National Energy Board Reasons for Decision GH-3-98, TransCanada PipeLines Limited, Facilities, November 1998. National Energy Board
Reasons for Decision
TransCanada Pipelines limited
GH-3-98
November 1998
Facilities TransCanada explained that, because of the uncertainty surrounding the design requirements at the time that a decision relating to its application had to be made, it decided to use the Alternative Mechanism as a risk mitigation measure. TransCanada identified these risks as being the risk of firm service customers not renewing their contracts in April 1999 and the risk of incurring pipe and compressor cancellation costs should the new facilities become unnecessary due to a reduction in its aggregate requirements.
2.2 Alternative Mechanism
The new facilities proposed in TransCanada's 22 July 1998 revision to its application would not enable TransCanada to meet its forecast of aggregate requirements for the 1999-2000 contract year. To satisfy the balance of the 1999-2000 aggregate requirements, TransCanada proposed to rely on the Alternative Mechanism. The Alternative Mechanism would involve pursuing arrangements other than constructing additional facilities, such as temporary or long-term acquisition of capacity on the secondary market, capacity exchanges, capacity loans or any other arrangement proposed by gas market participants.
Considering both the uncertainty related to its requirements and the ongoing negotiations with its pipe suppliers, TransCanada determined at that time that the appropriate design approach would be to construct facilities to meet a net increase in firm service requirements of 3 059.5 103m3/d (108.0 MMcfd) and to rely on the Alternative Mechanism to provide 2 832.9 103m3/d (100.0 MMcfd) of capacity to meet the remaining increase in firm service requirements.
TransCanada further reduced its forecast of aggregate requirements for 1999-2000 in the 21 August 1998 revision to its application, reflecting the removal of the Kirkland Lake and the CoEnergy projects. TransCanada indicated that the Kirkland Lake project had been delayed by one year and removed from the 1999 contract year queue. TransCanada indicated that the precedent agreement between TransCanada and CoEnergy terminated on 9 August 1998 because CoEnergy failed to provide TransCanada with additional gas supply information. As a result of the removal of these projects, the net incremental firm service requirements considered in TransCanada's application were reduced to 3 787.5 103m3/d (133.7 MMcfd). TransCanada indicated that due to its reliance on the Alternative Mechanism, the removal of these projects, along with other minor contract adjustments, would not change its construction plans. Instead, its use of the Alternative Mec}:lanism would be reduced by a total of 2 104.9 103m3/d (74.3 MMcfd) to 728.0 103m3/d (25.7 MMcfd).
TransCanada indicated that the volumes to be served via the Alternative Mechanism could change further due to the possibility of changes in the heat content of the gas delivered to TransCanada's system. Should the heat content of the gas decrease as forecast, TransCanada explained that it may require additional capacity which could be acquired quickly and on a short-term basis via the Alternative Mechanism.
In balancing the capacity to be provided by new facilities with the capacity to be provided by the Alternative Mechanism, TransCanada stated that it proceeded cautiously, noting that it could be at risk should it not be able to obtain sufficient capacity to meet its firm service Obligations at a reasonable price.
TransCanada stated that it intended to consult with its stakeholders and the Tolls Task Force ("TTF") before contracting for the Alternative Mechanism. This consultation would include consideration of
4 GH-3-98 the scope of the Alternative Mechanism, any arrangements or approvals that TransCanada may require, and an appropriate request for proposals ("RFP") process. TransCanada indicated that issues related to the potential impact of the Alternative Mechanism on the secondary markets and on gas commodity trading would also be discussed with parties.
The Canadian Association of Petroleum Producers ("CAPP") stated that it supports the creation of capacity in a cost-efficient manner. CAPP noted that the Alternative Mechanism raises a number of questions that should be the subject of discussion at the TTF prior to implementation.
PanCanadian Petroleum Limited ("PanCanadian") indicated that TransCanada's application should be approved without prejudicing a full and fair exploration of the Alternative Mechanism through the TTF and a subsequent Part IV proceeding.
2.3 Request for Proposals Process
The Consumers' Gas Company Limited ("Consumers,,)l was of the view that TransCanada's current facilities planning process is inadequate. Consumers' position was that TransCanada should issue an RFP for the provision of acquired capacity prior to its annual determination of the need for additional facilities. This acquired capacity, either on its own or together with new facilities, would serve TransCanada's incremental requirements.
Consumers proposed that TransCanada should be required to include in its facilities applications a complete and detailed description of the options available, as well as an explanation of how it determined the appropriate mix of facilities and acquired capacity. Consumers stated that, without such an exercise, it could not be satisfied that TransCanada's proposed set of facilities were optimal to meet the underpinning requirements.
Vector Pipeline Limited Partnership ("Vector") explained that, as a new entrant in the marketplace, it was facing substantial challenges in offering competitive transportation services, given TransCanada's market dominance and also TransCanada's ability to roll the costs of new expansions into its overall cost of service. Vector argued that, in the absence of competition, the Board must create a surrogate for competition. Vector submitted that, in the context of the current regulatory framework, this required the Board to direct TransCanada to seek the most economic solution between the construction of new facilities and the acquisition of transportation rights from other providers.
Vector proposed the use of an RFP to solicit Alternative Mechanism proposals and questioned whether the Board should approve TransCanada's application without first requiring TransCanada to conduct such an RFP. Vector suggested that the primary factor of relevance in the selection of proposals should be the incremental cost of constructing new facilities compared to the incremental cost of acquiring capacity through the Alternative Mechanism. Vector proposed that other relevant factors should include the term of financial commitment, flexibility and reliability, but that TransCanada should justify any selection that does not represent the lowest incremental cost.
1 The Consumers' Gas Company Limited changed its name to Enbridge Consumers Gas, effective 6 October 1998.
GH-3-98 5 Attachment A7 Tab 24 Part A – Review and Variance Application TransCanada PipeLines Limited 2001 and 2002 Tolls and Tariff Application, Hearing Order RH-1-2001, TransCanada Reply Evidence and TransCanada PipeLines Limited 2001 and 2002 Tolls and Tariff Application, Hearing Order RH-1-2001, TransCanada Reply Evidence Errata. TransCanada PipeLines Limited RH-I-2001 Reply Evidence September 12, 2001 Page 16 of36
1 issue. The Board is not getting the benefit of the range of considered input it 2 otherwise would enjoy.
3
4 The 1999 Expansion
5 Q.21 On behalf of PG&E/El Paso, Ms. A. Cheung suggests that the 1999 expansion 6 (approved following GH-j-98) was imprudent. Does TransCanadit agree?
7 A21 No. At the time of the GH-3-98 application (filed in April, 1998), the Alliance 8 Pipeline hearing was underway with TrlmsCanada and a number of other parties 9 opposing the project. The Vector pipeline application had not even been filed. 10 The Alliance Pipeline was approved by the Board in November, 1998 and 1 construction started in June, 1999. The Vector pipeline received its Board 12 approval in M~rch, 1999:' 'The Maritimes & Northeast Pipelin~ had been 13 approved by the Board in December, 1997.
14 In the midst ,of these events, shippers were maintaining their requests for new .15 service on the TransCanada system. TransCanada had an obligation pursuant to 16 Precedent Agreements (''PAs'') to serve those shippers needing new transportation 17 services. These PAs were signed over the period from April 1997 to March 1998.
18 As stated many times on the record of the GH-3-98 proceeding, TransCanada 19 closely monitored its shippers', transportation requirements from late 1997 to early 20 1998 (Ex. B-4, as revised). The message received from its shippers was 21 consistent, that is TransCanada capacity. was still considered to be a valuable 22 commodity. An active secondary market continued to exist and shippers still 23 needed incremental capacity by virtue of the new PAs that were executed in early ~4 1998 for services starting November 1, 1999. The need for new capacity was 25 further substantiated by the election in early 1998 by a vast majority of firm TransCanada PipeLines Limited RH-1-2001 Reply Evidence September 12, 2001 Page 17 of36
1 shippers to in fact increase their contract demands by an aggregate of some 50 2 MMcfd when TransCanada converted from volumetric to energy billing.
3 In May/June 1998 the natural gas market and T values were substantially changed 4 from what had existed only a few months before. With the sharp drop in current 5 T values and updated forecasts of future T values, TransCanada actively pursued 6 a number of measures to mitigate the potential impact of overbuilding its system, 7 as detailed in the chart below:
Date(s) Action Results
May-June, 1998 A request for Proposals in 44.4 MMcfd returned; this respect to the turnback of represented a saving of about $155 unneeded finn capacity. MM in incremental capital cost. Union Gas' requirements reduced by38MMcfd.
June-November, The renegotiation of pipe Cancellation charges reduced f,om 1998 .contracts. approximately $108 million to approximately $10 million.
July, 1998 Revised filing to reflect Expansion capacity reduced to from reduced requirements of 208 290 MMcfd to 108 MMcfd, and MMcfd. "Alternative costs reduced from $984 MM to Mechanism" for 100 MMcfd $404 MM. introduced as an alternative to construction.
July, 1998 A request for an early Out of approximately 1.1 Bcfd of indication from shippers that eligible non-renewals, no shipper may not be renewing Ff communicated any intent not to services on the system. renew its Ff service.
August, 1998 2nd filing revision reflecting No change in facility requirements. removal of Kirkland Lake and Alternative Mechanism reduced to CoEnergy volumes. New 26MMcfd. requirements reduced to 134 MMcfd.
October- Customer communications. No customer indicated its intent not November, 1998 to renew its contract. TransCanada PipeLines Limited RH-1-2001 Reply Evidence September 12, 2001 Page 18 of36
I
December, 1998 Board approval of all applied Construction commences on four of forfacilities. Certificate and five approved winter construction exemption order applied for loops. and received.
May, 1999 6 month notice given for non All construction to be completed renewals. TransCanada re except the loop from MLV 6-7 due evaluated the economics of to the Androscoggin PA not being completing construction of the converted into an executed contract 1999 expansion. (12.8 MMcfd).
October, 1999 Advised Board that the loop from MLV 88 - 89 was cancelled, due to ongoing issues with the Constance Lake Band.
Q.22 What do you say to the allegation' TransCanada had the choice to not 3 proceed with the 1999 expansion and in fact should n~t hay\! proceeded?
4 A.22 Based on the facts known at the time immediately following the Board's decision, 5 the cancellation of the 1999 construction program, rather than being prudent as 6 suggested by PG&EIEI Paso, would in fact have been imprudent and possibly 7 resulted in costs greater than any potential savings from not building.
8 Furthermore, had TransCanada not built over the winter of 1998/99 and cancelled 9 the remaining construction, as Ms. Cheung suggests, and all the existing shippers 10 renewed their contracts, TransCanada would have breached its contractual 11 obligations and been at risk for potential contract damages.
12 The magnitude of non-renewed capacity first became apparent when renewal 13 notices were due, by April 30, 1999. At this time construction of the remaining 14 facilities and procurement of material had progressed significantly; Four loop
< ~ sections had been completed during the winter and placed into service, and 16 significant progress had been made on the remaining facilities. Of the $404 MM TransCanada PipeLines Limited RH-I-200l Reply Evidence September 12, 2001 Page 19 of36
1 approved cost, $270 MM (or 67%) had been either spent or committed. Detailed 2 analysis by TransCanada at this time showed that the impact on delivered cost of 3 building versus cancelling was $O.OOl/GJ (using $2.82 /GJ gas). The fuel savings 4 achieved by installing the additional loop and highly efficient compressor units 5 offset the incremental cost of completing the project. This analysis included the 6 partial recovery ofmaterial costs through resale.
7 Additional benefits to completing the construction included reduced emissions of 8 greenhouse and other gases that would result from increase efficiency and 9 reduced fuel consumption, and the addition of facilities that could be useful for 10 longer-term growth ofthe system.
11 To suggest that TransCanada expanded its system irresponsibly just because the '\ Board authorized the new facilities is a misrepresentation of the facts and 13 TritlisCanada's intent. It is in no one's interest to expand the TransCanada system· 14 blindly for the sole reason that a Board approval exists. TransCanada had gone to 15 great lengths to mitigate the impact of the 1999 expansion and was successful in 16 minimizing the construction of new facilities and the consequent costs. 17 TransCanada had prudently completed its scaled back 1999 construction program; 18 it should not now bear costs resulting from system under-utilization allegedly 19 related to the 1999 expansion.
20 Q.23 PG&EIEI Paso state that just because no parties seriously challenged the 21 economic feasibility evidence underpinning the 1999 application it should not 22 be impIiedthat TransCanad,a had adequately demonstrated that the facilities 23 would be used and useful [Written Evidence of A. Cheung, p. 7]. Does 24 TransCanada agree? TransCanada PipeLines Limited 'RR-I-2001 Reply Evidence September 12, 2001 Page 20 of36
1 A.23 Not at all. If the evidence had been inaccurate or deficient it would not have 2 passed regulatory review. TransCanada's evidence was open to scrutiny by all 3 parties and the Board. The Board agreed with TransCanada's submissions.
4 Today, with the benefit of more than two and a half years of 20120 hindsight, 5 PG&EfEl Paso are casting doubt on TransCanada's actions. At the time those 6 decisions had to be made, PG&EfEl Paso was silent, induding with regard to any 7 concerns that they could have raised with TransCanada's application for relief 8 from the Board's certificate conditions.
9
10 Cost Causation and Economic Principles
Q.24 The CA suggests the Settlement violates the "cost causation" principle. Do 12 you agree?
13 A.24 No. The Settlement provisions related to the treatment of contract non-renewals 14 are entirely consistent with cost causation principles.
15 Cost causation is a toll design principle which dictates that shippers who cause 16 costs should be the shippers who pay for those costs', [The Board defined the 17 principle in those terms most recently in RH-I-99 Reasons, p. vL] The Board has 18 stated that one of the primary principles of toll design is setting prices for service 19 which are cost based and reflect the principle of "user pay" to the greatest extent 20 possible. [Board Reasons for Decision, RH-4-86 respecting Interprovincial Pipe 21 Line Limited, p. 35,] Cose causality has also been described as "...the principle 22 that the tolls should reflect those costs caused by the provision of service to the 23 particular customers." [Traditional and Incentive Regulation: Applications to 24 Natural Gas Pipelines in Canada, Mansell and Church, Van Horne Institute for j International Transportation and Regulatory Affairs, p. 56.] It is accepted that 26 due to such things as "...practical considerations and limitations on cost TransCanada rn bu1ines.s to deliver m ERRATA SHEET
REVISIONS TO REPLY EVIDENCE OF TRANSCANADA PIPELINES LIMITED
RH-1-2001
REFERENCE REVISION p. 4, I. 5 revise the word "facilities" to read "service"
p.11,1.17 remove capitalization on the word "OR" to read "or''
p. 16, II. 23-24 delete the words "in early 1998" to maintain consistency with previous paragraph that correctly indicates "from April 1997 to March 1998." (p.16, I. 17)
p. 17, table, column delete the word "to" for the line to read "Expansion capacity "Results", third entry, reduced from" line 1 p.19,1.8 revise the word "increase" to read "increased"
p. 27, I. 24 insert the words "65% of the revenue shortfall amounts of" after the words "at risk for"
p. 28, I. 2 revise the values shown to read as follows "decrease by 0.2% in 2001 and between 0.8% and 1.2% in 2002."
p. 34, I. 23 revise "2000" to read "2001"
September 19, 2001 Attachment A7 Tab 25 Part A – Review and Variance Application Exhibit B-5-7, RH-003-2011, Section 2.0: TransCanada PipeLine Systems Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part B: Background Section 2.0: The TransCanada Pipeline Systems Page 6 of 32 Revised October 31, 2011
1 the existing Revised Interim 2011 Tolls approved by Order AO-1-TGI-04-2010 for 2 the remainder of 2011. TransCanada further proposed to adjust for the difference 3 between the annualized Final 2011 Tolls and the tolls charged in 2011 on a 4 retrospective basis4 by carrying the difference forward for inclusion in the 2012 5 revenue requirement to be recovered through tolls. TransCanada submitted that this 6 approach would provide greater toll certainty and stability for 2011 compared to other 7 adjustment methodologies, such as adjusting for the difference on a retroactive basis 8 or on a retrospective basis over the latter part of 2011.
9 In its Decision on TransCanada’s April 29, 2011 Mainline Final 2011 Tolls 10 Application, the Board decided that the Settlement will continue to apply for the 11 purpose of determining the 2011 revenue requirement. However, the Board 12 concluded that a more detailed evidentiary record was required before deciding on 13 certain of the flow-through elements of the revenue requirement.5 The Board 14 directed TransCanada to file such information by October 31, 2011.6 TransCanada 15 has included information on flow-through elements of the 2011 revenue requirement 16 in Section 12.0 of the Application.
2.2.5 System Evolution
17 The Mainline rate design and tolls were first reviewed by the NEB in 1973.7 At the 18 time of that review, the geographic footprint of the system, the toll methodology, and 19 core services shared many fundamental similarities to that of the Mainline today. For 20 example, the system transported gas from Empress to Eastern markets, utilized cost-
4 Defined as the making of orders that attach new consequences to past transactions such as prospective orders that take into account losses or gains incurred or accrued prior to the effective date of the order (NOVA, an Alberta Corp .v. Amoco Canada Petroleum Co. [1981] 2 SCR 437 QL page 6 of 20). In this instance, TransCanada proposed that recovery of the annualized Final 2011 Tolls on a retrospective basis should be implemented through inclusion in the 2012 Revenue Requirement of the difference between the annualized Final 2011 Tolls as approved by the Board in the Mainline Final 2011Tolls Application and the tolls charged from January 1, 2011 through December 31, 2011. 5 NEB letter to TransCanada dated September 9, 2011 enclosing Order TG-007-2011, pages 2-3. 6 NEB letter to TransCanada dated September 27, 2011 enclosing Hearing Order RH-003-2011, page 2. 7 RH-1-72 Phase II Proceeding.
Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part B: Background Section 2.0: The TransCanada Pipeline Systems Page 7 of 32 Revised October 31, 2011
1 based tolls that were determined based on allocating total system costs across 2 associated energy and energy-distance billing determinants, and established common 3 long-haul tolls to expansive zones, with the FT toll being the primary toll and the 4 benchmark toll for other services.
5 Since the first review of Mainline tolls, the environment in which TransCanada has 6 operated has evolved, sometimes rapidly, to an increasingly competitive North 7 American and global market. Notwithstanding the need to adapt to the continuously 8 changing business environment, certain objectives have remained constant over time.
9 Throughout its history, TransCanada has sought to maximize long-term system 10 utilization and to ensure that only prudent and economically feasible system 11 expansions were pursued. It has proposed both new services and alternate service 12 terms and conditions intended to optimize the utilization of existing facilities, reduce 13 costs, and to adjust service terms, all with a view to enhancing the viability and 14 competitive position of the Mainline.
15 Prudent Investment in Mainline Facilities
16 Investments made in the Mainline have been prudently incurred and TransCanada has 17 taken steps to avoid unnecessary expansion. TransCanada has sized expansions in 18 accordance with the criteria established by the Board.
19 The Board’s approach to TransCanada’s investment in facilities has always required 20 that TransCanada establish, among other things, that proposed expansion facilities are 21 supported by supply and markets, and that they will be economically feasible. 22 Economic feasibility has been defined by the Board as a demonstration that there is a
Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part B: Background Section 2.0: The TransCanada Pipeline Systems Page 8 of 32 Revised October 31, 2011
1 reasonable likelihood of the facilities being used at a reasonable level over their 2 economic life and a reasonable likelihood of the demand charges being paid.8
3 From inception and through the early years of Mainline development, the decision to 4 construct an all-Canadian system, and in particular the construction of the Northern 5 Ontario segment of the Mainline, was influenced by government policy. A 1966 6 Agreement between the Federal Government and TransCanada required that the 7 volume of gas transported through the NOL be a minimum of 65 % of the total 8 volume transported in each year by TransCanada from Western Canada for use in 9 Eastern Canada.
10 When the NEB first reviewed Mainline tolls in 1970,9 it concluded that the Mainline 11 assets constructed prior to that time, including investments in the NOL, were used 12 and useful. They were included in TransCanada’s first approved rate base.
13 During the late 1980s and 1990s TransCanada was under considerable pressure from 14 both producers and markets to expand its system to transport natural gas from the 15 WCSB to both domestic and export markets. For example, during the GH-2-87 16 proceeding, producers supported expansion of the Mainline system to meet the 17 8.9 106m3/d (315 MMcf/d) of new firm contracted service commencing in November 18 1988, support that was unopposed by downstream intervenors.
19 The Board expressed the following view in the GH-2-87 Decision:
20 The Board notes the current high level of utilization of the 21 TransCanada system and the current difficulties that shippers 22 of new natural gas volumes have in gaining access to the 23 system in view of capacity constraints. This lack of capacity 24 may result in long-term firm transportation requirements for 25 contract years 1988-89 and 1989-90 not being served in a 26 timely fashion. Therefore, an expansion of the TransCanada 27 pipeline system is required.
8 GH-5-89 Decision, Volume 1, page 26. 9 RH-1-70 Decision, TransCanada Rates Application Phase I, page 4-2.
Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part B: Background Section 2.0: The TransCanada Pipeline Systems Page 9 of 32 Revised October 31, 2011
1 The GH-5-89 proceedings considered applications by TransCanada for 2 1,988 kilometres of pipeline, the installation of 21 new compressor units, and two 3 new compressor stations at a cost of $2.44 billion, to meet 23.5 106m3/d 4 (829 MMcf/d) of demand. These facilities were supported by both producers and 5 downstream markets. A majority of intervenors also supported the inclusion of an 6 additional 1 470 103m3/d (52 MMcf/d) of advanced uncontracted capacity (Advance 7 Capacity) in GH-5-89. This Advance Capacity did not have signed transportation 8 service commitments but the Board approved Advance Capacity stating:
9 Due to the numerous requests for firm service, the general 10 support given by parties for advance capacity, and the time 11 needed to complete a construction program for a November 12 1991 in-service date, the Board believes that a level of advance 13 capacity of 1,470 103m3/d (52 MMcf/d) is appropriate at this 14 time.10
15 To reach the conclusion that facilities are in the public interest, the Board is 16 required11 to consider supply, markets, economic feasibility, financeability, and any 17 other public interest that may be affected by granting or refusing of the application. 18 As noted above, the determination of economic feasibility requires a conclusion by 19 the Board, on the evidence, that the facilities will be used and useful over their 20 economic life and that demand charges will be paid.12
21 Strong demand for new capacity on the Mainline to take WCSB gas to existing and 22 new markets continued through to the end of the 1990s. TransCanada’s application 23 for 1998 facilities (heard in proceeding GH-2-97) added 11.8 106m3/d (417 MMcf/d) 24 of Mainline capacity. The application was broadly supported, and both those
10 GH-5-89 Decision, Volume 2, page 6. 11 In the GH-3-97 Decision at page 7 the Board found that English and French versions of section 52 convey different meanings. The English version states that the Board may have regard to the factors described in paragraphs (a) through (e), while the meaning of the French version does not convey any element of discretion and says that the factors in paragraphs (a) though (e) must be considered. Applying the rules of statutory interpretation applicable in this context, the Board ruled that the French version of section 52 conveyed the intention of Parliament and is the version which must be applied. 12 See for example GH-5-89 Decision, Volume 1, page 26.
Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part B: Background Section 2.0: The TransCanada Pipeline Systems Page 10 of 32 Revised October 31, 2011
1 facilities and the facilities for TQM’s PNGTS Extension to East Hereford (considered 2 in proceeding GH-1-97) were said by WCSB producers to be necessary to meet the 3 “indisputable” need for additional capacity to transport WCSB gas to markets. 4 TransCanada, shippers and the Board agreed with the need for further capacity on the 5 Mainline. TransCanada’s application for 1999 facilities (heard in proceeding GH-3- 6 98), which added a further 3.8 106m3/d (133 MMcf/d) of capacity, was also supported 7 by producers and markets and approved by the Board.
8 The change from a long period of widespread support for expansion of the Mainline 9 to a period of concern about over-capacity came suddenly and unexpectedly, as 10 illustrated in the Board’s RH-1-99 Decision. The Board denied TransCanada’s 11 request for flexibility in establishing IT service tolls, agreeing with parties that argued 12 the initiative was unnecessary because the potential for excess capacity and migration 13 from FT service to IT service was temporary, and would pass when the WCSB and 14 eastern markets caught up with the then-recent and expected additions of capacity out 15 of the basin. The Board stated:
16 With respect to potential future non-renewals, the Board accepts 17 IGUA’s and the LDCs’ arguments that long-term obligations of 18 various firm shippers, such as the obligation to serve the core 19 market or contractual obligations to supply manufacturing and co- 20 generation plants, would likely prevent decontracting to the level 21 suggested by TransCanada. Accordingly, the Board has not been 22 persuaded that under-utilization of TransCanada’s system will be a 23 serious long-term problem.
24 The Board recognizes that short-term under-utilization is expected, 25 given the recent facilities expansions out of the WCSB and the 26 construction of competing pipelines. The Board agrees with CAPP 27 that the “lumpiness” of capacity additions is common and in fact 28 can be a positive situation for the industry, since supply and 29 markets are no longer constrained by the lack of transportation 30 capacity. The Board also agrees with intervenors that, given the 31 complexity of the market and the long-term forecasts of increased
Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part B: Background Section 2.0: The TransCanada Pipeline Systems Page 11 of 32 Revised October 31, 2011
1 natural gas demand and production growth, the period of excess 2 capacity should be relatively short term.13 3 … 4 Finally, the Board is of the view that the evidence does not support 5 TransCanada’s assertion that migration from FT to IT is a long-term 6 problem.14
7 In the 1999-2001 period, with the roughly-contemporaneous arrival of the Alliance 8 Pipeline and the occurrence of non-renewals on the Mainline, expansion ceased and 9 TransCanada focused on the load retention measures discussed below. When at that 10 time several parties suggested that TransCanada had over-expanded, WCSB 11 producers responded (in proceeding RH-1-2001) with the same position; that the 12 over-capacity out of the basin was not alarming and was to be expected until WCSB 13 supply caught up with the capacity.
14 The current under-utilization of the Mainline was not foreseen or foreseeable by 15 TransCanada, its stakeholders or the Board at the time of the applications for, support 16 of, and approvals of the expansions of the Mainline.
17 In the initial years of Mainline operations, the Board made clear that it had ultimate 18 responsibility for determining the optimal size of the TransCanada system:
19 Clearly it is the Board’s responsibility to prevent the 20 construction by any applicant of facilities that are in excess of 21 those needed to meet its market requirements, because 22 excessive facilities construction simply has a burden of 23 unnecessary expense upon consumers of natural gas. Equally 24 clear is the Board’s responsibility to avoid creating a shortage 25 of gas in a market area by refusing to approve the construction 26 of sufficient facilities to deliver the gas which would otherwise 27 be available to that market in the volumes desired.15
13 RH-1-99 Decision, page 7. 14 RH-1-99 Decision, page 10. 15 National Energy Board Report to the Governor in Council, In the Matter of the Application under the National Energy Board Act, of TransCanada PipeLines Limited, April 1972, pages 5-13.
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1 The Board’s responsibility for oversight of expansions has not changed over time. In 2 more recent years the approach of the Board focused on the assurances that 3 TransCanada was required to provide in order to demonstrate that expansions would 4 be in the public convenience and necessity:
5 TransCanada has the onus to demonstrate through its evidence that an 6 expansion is economically feasible. This evidence must demonstrate, 7 among other things, that TransCanada has assured itself that there is 8 or will be adequate natural gas supplies and viable natural gas markets 9 in the long term to ensure the financial viability of the pipeline as a 10 going concern.16
11 and
12 . . . the Board continues to believe that TransCanada is in the 13 best position to assess the risks associated with the individual 14 projects underpinning an expansion of its facilities and, in 15 particular, to determine the risk associated with the recovery of 16 demand charges. The Board continues to believe that 17 TransCanada should have the discretion to determine whether 18 there is reasonable expectation of a long-term requirement for 19 capacity expansion.17
20 In assessing economic feasibility, TransCanada reviews both its existing requirements 21 and each new request for service. TransCanada seeks, through various means, to 22 obtain existing shipper intentions and needs for utilization and likelihood of renewal 23 of their transportation contracts.
24 To optimize the size of expansions, TransCanada frequently engages in collaborative 25 discussions with upstream inter-connecting pipelines (e.g., NGTL) and downstream 26 inter-connecting pipelines (e.g., GLGT and Tennessee Gas Pipeline Company) to 27 ensure that capacity on its system is matched as closely as possible at points of inter- 28 connection.
16 GH-4-88 Decision at page 49. 17 GH-3-96 Decision at page 45.
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1 Before TransCanada will expand its system, prospective shippers must provide 2 evidence that they have secured sufficient supply dedicated to the proposed new 3 service contract to utilize the capacity for ten years. TransCanada also generally 4 requires evidence that the market for the gas is certain for at least that ten year period. 5 Finally, TransCanada requires at least a ten year firm transportation contract 6 commitment from the shipper, along with financial assurances that support the 7 payment of demand charges. These requirements have been colloquially called the 8 “10/10/10” policy.
9 Shipper information is critically reviewed with follow-up and corroborative 10 information being pursued when necessary. Only after TransCanada is satisfied with 11 the merits of a potential expansion – its economic feasibility – does TransCanada 12 proceed to apply for, and, if approval is obtained, construct facilities.
13 TransCanada minimized the need for facilities by constructing the Mainline in 14 conjunction with the use of storage in Ontario and Michigan. Gas is injected into 15 storage during off-peak periods and withdrawn from storage during peak periods. 16 This avoids the need for TransCanada to size much of the Mainline for peak periods.
17 For many years, this feature of the design of the TransCanada system was coordinated 18 with the use of a discounted firm service, with the discount being attributable to the 19 fact that TransCanada avoided peak period facilities by having the right to tender the 20 volumes to be taken by the shipper on any given day, rather than the normal situation 21 in which the shipper nominates the volumes to be delivered by TransCanada. This 22 service (no longer used, and proposed in this Application to be removed from the 23 Tariff) was called “Firm Service Tendered” (FST). In the 1990s, the FST discount 24 was reduced to the point that the service was no longer attractive to shippers, who 25 then converted their FST volumes to FT.
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1 TransCanada avoided unnecessary expansion when FST shippers converted to FT 2 service. Absent the FST volume, the addition of approximately $611 million of 3 additional facilities was estimated to be required to serve the increased firm peak day 4 load. Rather than seeking to construct such facilities, TransCanada contracted for 5 upstream and downstream storage, balancing and transportation services at lower 6 cost.18 These alternate arrangements also afforded TransCanada flexibility in 7 adjusting the size of its overall integrated system to accommodate short-term 8 increases or decreases in aggregate contract requirements from time to time.
9 Another example of TransCanada’s efforts to avoid over-expansion took place in 10 1998. At that time TransCanada had requests for incremental firm service that 11 required construction of incremental facilities. The time required to design, obtain all 12 necessary approvals, purchase materials, and construct facilities was in excess of 24 13 months. However, existing firm service contract holders have the right to elect to 14 renew, or not, existing contracts on only 6 months prior notice. Therefore, there was 15 a risk that TransCanada could receive notice of non-renewal of existing contracts 16 shortly before new facilities came into service to meet obligations under new 17 contracts; resulting in uncontracted capacity and higher costs. To address this risk, 18 TransCanada sought, unsuccessfully, to change its renewal provisions as described 19 below. TransCanada took three other, innovative steps to minimize this risk in its 20 1998 Facilities expansion. First, TransCanada requested that all shippers voluntarily 21 provide notice of renewal and non-renewal earlier than the six month notice period 22 set out in the Tariff. Second, TransCanada provided existing shippers the option to 23 turn back existing contracts to free up capacity for incremental contracts and 24 minimize construction of new facilities. Third, TransCanada designed its expansion 25 to minimize costs and the risk of excess capacity in the event that some existing 26 shippers non-renewed their contracts. To ensure that obligations could be met in the
18 Application to convert FST to FT service effective November 1, 1998 (RH-1-97), Exhibit B-4, Appendix B, page 26.
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1 event that all existing contracts were renewed, TransCanada proposed, and the Board 2 accepted, the use of alternative, market contracts to serve incremental requirements 3 (the Alternative Mechanism). Existing shippers subsequently non-renewed existing 4 contracts and TransCanada’s use of these innovative measures avoided the 5 construction of unnecessary facilities.
6 Following the 1998 expansion, TransCanada also developed Turnback Procedures as 7 part of its Tariff. The objective of these procedures is to avoid unnecessary facility 8 expansions. These procedures provide existing shippers with an opportunity to 9 relinquish existing firm contracts so as to reduce or eliminate the need for incremental 10 facilities or TBO to serve new long-term firm contracts.
11 Over the last few years, TransCanada has also sought alternate means of meeting its 12 firm short-haul obligations other than through facility expansions. This has resulted 13 in the implementation of commercial arrangements such as DOS-MN service, Dawn- 14 to-Dawn service on the Union system and backhaul transportation on the GLGT 15 system. These arrangements represent cost-effective ways of meeting firm service 16 obligations through the use of existing infrastructure on the Mainline and other 17 transportation systems.
18 TransCanada has also redeployed natural gas pipeline assets where facilities were 19 under utilized. The sale of Mainline gas pipeline assets for conversion to oil service 20 and use as part of the Keystone Pipeline project made efficient use of assets that were 21 still used and useful but no longer necessary for natural gas service. In its Reasons 22 for Decision approving the transfer of assets from TransCanada to TransCanada 23 Keystone Pipeline GP Ltd., the Board recognized that a number of TransCanada’s 24 recent initiatives brought forward for regulatory approval were driven by the new 25 competitive environment and were attempts to improve the economic viability of the 26 Mainline and to maximize the utilization of facilities. The Board expressed the view
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1 that the transfer of assets associated with the proposed Keystone Pipeline project was 2 no exception:
3 For much of its operating history, the TransCanada Mainline has been 4 the major transporter of gas from the WCSB to eastern markets in 5 Canada and the United States. As supply continued to grow, 6 TransCanada received approval from the Board to expand the 7 Mainline a number of times. In the 1990s, the regulatory environment 8 encouraged competition and market-based outcomes. The 9 commencement of service in 2000 on the Alliance and Vector 10 pipelines created a new and competitive path to take significant 11 WCSB gas to markets that had traditionally been served by the 12 Mainline.
13 A critical aspect of the approval of the Alliance pipeline was the 14 conclusion that off-loading of the incumbent pipelines would be 15 temporary and that supply growth would refill them. During this 16 proceeding, the Applicants stated that the Mainline had, in fact, lost 17 about 42.5 million m3/d (1.5 Bcf/d) of contracted volumes, which 18 have not come back. In the RH-1-2001 Decision, the Board suggested 19 that a review of TransCanada’s business and regulatory framework 20 was necessary. The message the Applicants correctly took from the 21 RH-1-2001 Decision was that TransCanada needed to become more 22 competitive in the future.
23 Since the end of 2001, TransCanada has come to the Board with 24 various proposals to increase its competitiveness. Some were 25 successful in getting Board approvals while others were not. All 26 demonstrate TransCanada’s attempt to respond to competition. For 27 example, TransCanada filed a request for discretion in IT pricing, 28 which was opposed by stakeholders, and was denied by the Board. 29 TransCanada filed the Southwest Zone application and the North Bay 30 Junction application for a new receipt and delivery point, both of 31 which were approved by the Board. Also, an application to increase 32 depreciation rates, so that tolls could be more competitive in the 33 future, was approved by the Board. The Board approved biddable FT- 34 NR (non-renewable firm transportation), although the biddable aspect 35 was later overturned on review. The recent application for Firm 36 Transportation-Short Notice and Short Notice Balancing services was 37 approved in general (although not the tolling proposal for Short 38 Notice Balancing).
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1 The Board recognizes that TransCanada’s efforts were driven by the 2 new competitive environment. They were attempts to make the 3 Mainline more competitive and to maximize utilization of facilities. 4 The proposed project is no exception.19 [Citations omitted]
5 The sale and redeployment of Mainline compressor facilities to NGTL for use on the 6 Alberta System is another example of TransCanada’s focus on reducing unnecessary 7 costs across its systems. TransCanada recently applied for and received Board 8 approval to sell compressor unit 49C and three auxiliary cooler facilities from 9 compressor unit 49C to NGTL at Gold Creek, which reduced the Mainline rate base 10 by $14.8 million and the annual Mainline revenue requirement by $2.8 million. By 11 using facilities from the Mainline, NGTL will also be able to reduce the costs 12 associated with the purchase of new compression and cooling facilities by 13 $3.3 million.20 Additionally, TransCanada has recently applied for Board approval to 14 sell Mainline compressor unit 43C and the remaining ten auxiliary cooler facilities to 15 NGTL to use at its Berland River location which will reduce the annual Mainline 16 revenue requirement by $2.0 million.
17 The Mainline facilities included in rate base continue to be used and useful. 18 However, due to its limited firm contractual underpinning, the Mainline has more 19 capacity that the volumes that are tendered to it on an average day. This situation 20 does not mean than any of the costs of the existing plant have been imprudently 21 incurred. In fact, all facilities were installed on the basis of regulatory approvals of 22 the Board following a determination that the facilities were required by the present 23 and future public convenience and necessity. Throughout its history TransCanada has 24 undertaken steps to avoid unnecessary expansion and has taken the initiative to 25 redeploy assets no longer required for natural gas service. Despite existing and
19 MH-1-2006 Decision, page 57. 20 Application for the Sale and Purchase of TransCanada Mainline Station 43 - Unit C Compressor Facilities and Station 49 – Unit C Aerial Coolers (Facilities) Pursuant to section 74(1)(a) and (b) of the NEB Act.
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1 forecast lower flows on the Mainline today, facilities that have been prudently 2 constructed and placed into service remain used and useful today.
3 Response to Competition
4 In the same timeframe that the Alliance project was being considered by the Board, in 5 1998, the Canadian Association of Petroleum Producers (CAPP), the Small Explorers 6 and Producers Association of Canada, TransCanada and NGTL entered into an 7 Accord21 by which it was agreed, among other things, that existing pipelines facing 8 the emergence of pipeline to pipeline competition should have appropriate tools that 9 would give them the flexibility to compete. The signatories further agreed that 10 changes in existing regulatory practice were required, and to that end, agreed to 11 negotiate a proposal for a new regulatory framework for an increasingly competitive 12 environment, new toll and tariff structures for the Mainline and the Alberta System 13 that contemplated the changing risk/reward balance of the emerging competitive 14 environment, a term differentiated pricing mechanism, incentives for early renewals, 15 longer shipper contract renewal period and other tools. The parties agreed they would 16 negotiate this comprehensive new regulatory framework proposal by December 31, 17 1998.
18 However, attempts to develop a comprehensive new business and regulatory model 19 became protracted and the December 31, 1998 target established in the Accord was 20 not met. TransCanada and stakeholders continued to work towards the development 21 of a comprehensive restructuring model. In its decision on the 2001 Tolls 22 Application for the Mainline, the Board noted that a review of TransCanada’s 23 business and regulatory framework was necessary, and that it was encouraged by the
21 Agreement on Natural Gas Pipeline Regulation, Competition and Change to Promote a Competitive Environment and Greater Customer Choice (the Accord), April 7, 1998.
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1 commitment of most parties to negotiate a future business and regulatory model in the 2 near term.22
3 Discussions between TransCanada and its stakeholders continued. However, by the 4 RH-1-2002 proceeding, TransCanada indicated that it was pessimistic about the 5 probability of achieving consensus. It noted that, given the diversity and conflicting 6 interests across the Mainline, it was not practical to expect to achieve consensus on 7 fundamental change to the business and regulatory model, particularly if any 8 redistribution of costs was involved.23 TransCanada also observed that it had proven 9 to be extremely difficult and often impossible to achieve consensus among 10 stakeholders on even minor items of change.24
11 Following the issuance of the RH-1-2002 Decision, TransCanada carefully 12 considered whether to continue to pursue a new comprehensive business and 13 regulatory model with its stakeholders. The model considered at that time was one 14 that would involve a comprehensive change to existing toll design, rates and services. 15 Considering a range of likely future gas flow scenarios, TransCanada concluded in 16 the 2002 timeframe that it could best achieve its Mainline business goals by 17 proposing changes within its existing toll design and tariff structure, on a case-by- 18 case basis, where appropriate.25
19 As noted in the extract from the Board’s MH-1-2006 Decision, above, TransCanada 20 has sought to address specific competitive challenges and opportunities on a case-by- 21 case basis since 2002. Some proposals were approved while others were not. All 22 demonstrated TransCanada’s attempt to respond to competition.26 In the context of
22 RH-1-2001 Decision, page 14. 23 Exhibit B-26 RH-1-2002 TransCanada Reply Evidence, page 4 of 20. 24 Exhibit B-12 RH-1-2001 TransCanada Reply Evidence, pages 1-14. 25 Exhibit B-10, RH-3-2004 Proceeding, TransCanada letter to the Board dated 31 March 2004 – Updates to the 15 September 2003 NBJ Application Additional Information, Appendix A, page 4 and 5 of 6. 26 MH-1-2006 Decision, page 57.
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1 the North Bay Junction (NBJ) application, the Board opined on TransCanada’s 2 obligation to adapt to market conditions in the following terms:
3 TransCanada, as owner and operator of the Mainline, has 4 primary responsibility to ensure that the pipeline remains 5 adapted to a rapidly changing natural gas market environment. 6 TransCanada is attempting in various ways to respond to a 7 decrease in long-haul contracted capacity and related flows on 8 the NOL and to devise strategies that will enable the Mainline 9 to compete effectively for transportation volumes. The Board 10 is of the view that, subject to the merits of specific proposals 11 put before it, efforts of this kind are to be supported.27
12 TransCanada has consistently sought to implement service changes that improve the 13 service choices available to shippers, protect the value of FT service, encourage firm 14 service contracting, and improve the economic viability and competitive position of 15 the Mainline.
16 TransCanada has expanded its suite of services through the introduction of more 17 flexible services, namely STFT, Capacity Release (CR), Enhanced Capacity Release 18 (ECR), Parking and Loans (PALS), and Multiple Handshakes and Pooling (MHPS).
19 TransCanada has implemented market responsive bidding processes for IT, LT-WFS 20 and STFT services, discretionary pricing for MHPS, and negotiated prices and terms 21 for PALS.
22 In its RH-1-2002 Decision, the Board approved increasing the bid floor for IT service 23 from 80% to 110% of the 100% load factor FT service toll. The Board agreed with 24 TransCanada that such a bid floor would more appropriately reflect the value of IT 25 service relative to FT service. This proposal was made after the Board denied an 26 earlier TransCanada application that would have provided discretion to adjust the bid 27 floor for IT and STFT services in response to market conditions (RH-1-99 Decision).
27 RH-3-2004 Decision, pages 36 and 37.
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1 TransCanada introduced the FT RAM feature in an attempt to encourage FT 2 contracting by providing credits for unutilized demand charges. While TransCanada 3 is seeking approval to discontinue RAM in this Application in light of its current 4 negative impacts on the Mainline, the objective of the implementation of RAM was to 5 encourage FT service contracting.
6 Virtually all efforts to provide new and innovative services and pricing have been 7 challenged to some extent by stakeholders. Implementation of most of the service 8 and pricing initiatives that have been put in place has taken extensive time and effort, 9 both through the Tolls Task Force and through litigation at the Board. For example:
28 10 • STFT service and MHPS were both litigated at the Board;
29 30 11 • PALS required three Task Force Resolutions and litigation at the Board before 12 it was made a permanent feature of the Tariff; and
13 • Balancing Service, which later became the foundation for Limited Balancing 14 Agreements (LBAs) with inter-connecting operators, required four Task Force 15 Resolutions before it became permanent.31
16 TransCanada attempted unsuccessfully over a number of proceedings to change the 17 contract renewal policy, implemented in its current form as part of the GH-2-87 18 Decision, in an effort to encourage shipper commitment to the Mainline.32 A 19 TransCanada proposal was rejected in the RH-4-93 Proceeding.33 Concerns over 20 renewal provisions were also raised in the GH-3-96 Proceeding.34 Subsequently, 21 TransCanada initiated extensive consultations with its shippers but no consensus 22 could be reached. TransCanada filed a renewal policy proposal with the Board in
28 NEB File Numbers 4775-T1-1-5 and 4775-T1-1-7, respectively. 29 Resolutions 97-12, 98-05, and 99-08. 30 NEB File Number 4775-T1-1-8. 31 Resolutions 97-25, 98-16, 98-22, 11.98. 32 GH-5-89 Decision, Vol. 1, page. 30; RH-4-93 Decision, pages 59-61. 33 RH-4-93 Decision, pages 59-61. 34 GH-3-96 Decision, page 22.
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1 RH-1-97 that would have introduced a right of first refusal mechanism. The proposal 2 was ultimately placed in abeyance in light of significant stakeholder opposition.35
3 In an effort to increase contractual support and improve toll stability, TransCanada 4 sought approval of a contract-term tolling differential proposal in RH-4-93.36 The 5 proposal was widely opposed and was denied by the Board.
6 TransCanada also applied for, but was denied, the ability to contract for additional 7 storage and transportation services on other pipelines, which could have been bundled 8 with TransCanada’s assets to provide enhanced balancing and transportation 9 services.37
10 Notwithstanding the responses of stakeholders and the rejection of a number of 11 proposals by the NEB, TransCanada has continued to pursue opportunities to improve 12 its competitiveness through service and pricing innovations.
13 Cost Management
14 TransCanada has effectively managed Mainline costs, and continues to do so. Over 15 the past decade, the Mainline gross revenue requirement (excluding deferrals and 16 adjustment charges) has decreased from $2.2 billion in the year 2000 to $1.7 billion in 17 2010. In the same period, the Mainline rate base has decreased from $9.4 billion to 18 $6.4 billion. Operations, Maintenance and Administrative (OM&A) costs, the largest 19 of the costs TransCanada can directly control, have been reduced from $179.6 million 20 in 2000 to $144.7 million in 2010, despite inflation over this period.
21 Most recently, the Settlement provided for the implementation of performance 22 incentives if cost savings and performance targets were achieved by TransCanada.
35 RH-1-97 Decision, pages 1-2. 36 RH-4-93 Decision, pages 61-63. 37 NEB File Number 4775-T001-1-10.
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1 These incentives, coupled with TransCanada’s ongoing prudent management of costs, 2 have resulted in effective and efficient Mainline operating practices.
3 Mainline fuel consumption has been reduced in recent years. While a large part of 4 this reduction is due to changes in system flows, the reduction is also due to 5 TransCanada adapting its operations and compressor configurations to efficiently 6 manage the lower and more volatile flows.
7 TransCanada has also actively managed its TBO capacity, which has resulted in 8 reductions in annual TBO costs through a reduced level of contracted capacity on 9 both the GLGT and Union systems. The reduction in contract levels (excluding 10 assignments), effective November 2010 and November 2011, has led to an annual 11 reduction of approximately $59 million in GLGT TBO costs, and an $11 million in 12 Union TBO costs.
13 The GLGT TBO Management Incentive program combined with the Municipal and 14 Capital Tax Savings program contained within the Performance Incentive Envelope 15 of both the 2006 Settlement and 2007-2011 Settlement have also resulted in 16 additional cost savings of approximately $71 million.
17 These initiatives have contributed to reducing the Mainline cost of service, although 18 cost reductions have been at a slower pace than the reduction in billing determinants, 19 resulting in toll increases.
20 Some Mainline costs are outside of TransCanada’s control. For example, consistent 21 with the Board’s RH-3-82 Decision, TransCanada has recovered the cost of taxes on a 22 flow-through rather than on a normalized tax basis. Had the normalized method been 23 maintained, as TransCanada advocated in 1982, TransCanada would have collected 24 deferred (normalized) taxes through tolls in years where Mainline throughput was at 25 levels much higher than current and forecast levels. The flow-through tax
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1 methodology results in current costs that are higher than could have been realized 2 under normalized taxes.
2.3 TransCanada Alberta System
2.3.1 System Description
3 The TransCanada Alberta System is an extensive (approximately 24 000 km of 4 pipeline) gas gathering and transportation system located in Alberta and north-east 5 BC that is used to transport natural gas from receipt points to delivery points, 6 including points of interconnection with ex-WCSB pipelines. Maps of the Alberta 7 System under the existing methodology and the Restructuring Proposal are provided 8 in Appendix B1. The facilities that currently comprise the Alberta System have been 9 designed, constructed and operated since 1954 to meet the needs of customers. The 10 Alberta System became subject to federal jurisdiction and regulation by the NEB on 11 April 29, 2009 pursuant to the Board’s GH-5-2008 Decision. Prior to that time, the 12 Alberta System was subject to regulation by the Alberta Utilities Commission (AUC) 13 and its predecessors.
14 The Alberta System has recently expanded its footprint into BC to connect new 15 sources of WCSB supply. The Groundbirch Pipeline Project, approved by the Board 16 with Certificate GC-115, was placed into service on December 1, 2010. The 17 Groundbirch Mainline (Saturn Extension) was approved in June 2011 by Board Order 18 XG-N081-07-2011 with pipeline construction beginning in August 2011. The Horn 19 River Project has also been approved by the Board under Certificate GC-117, with 20 pipeline construction due to begin in the winter of 2011.
21 The Alberta System 2011 Total Revenue Requirement is $1,277.6 million. The 22 Alberta System rate base in 2011 is forecast to be $4.9 billion.
Attachment A7 Tab 26 Part A – Review and Variance Application National Energy Board Reasons for Decision RH-1-2006, TransCanada PipeLines Limited, Tolls and Services, November 2006. •_ t<' . National Energy Office national ,'. A Board de I'lmergie
Reasons for Decision
TransCanada Pipelines Limited
RH-1-2006
November 2006
Tolls and Services
Canada Views ofthe Board
The Board is of the view that if a shipper wishes to convert an FT contract to an Ff-SN contract at any time, TransCanada should accommodate the request where feasible.
Decision
The Board directs TransCanada to allow shippers to convert an FT contract into an FT-SN contract at any time, subject to meeting the requirements for FT-SN service and TransCanada's ability to implement the service.
2.2 FT-SN Toll Design
The proposed FT-SN toll at 100 percent load factor is 110 percent of the 100 percent load factor FT toll. TransCanada proposed that all revenue from the Ff-SN service be credited against the Mainline gross revenue requirement as Non-Discretionary Miscellaneous Revenue.
Position of TransCanada
TransCanada indicated that the Ff-SN toll is premised on TransCanada's existing firm transportation service which is an integrated cost of service based toll. It noted that the Short Notice Services design maximizes the use of existing Mainline facilities in order to provide the services to the new market.
TransCanada stated that the Ff-SN toll is 10 percent higher than the Ff toll to reflect an estimate of the opportunity cost of potentially foregone discretionary revenue. More specifically, because the Ff-SN service provides the shipper with guaranteed access to the contract demand at aJl nomination windows, any unused FT-SN capacity is not available for discretionary services. In order to quantify the potential discretionary revenue impact of Ff-SN, TransCanada analyzed the revenues from discretionary services from 200 I to 2005, as shown in Table 2-2.
Table 2-2 Discretionary Revenue Evaluation ($ Million) 2001 2002 2003 2004 2005 Gross Revenue from IT, FT 101.2 726.1 177.8 136.9 258.8 diversions/ARP, STS overrun and PALS Less Ff-RAMlAOS/Ff Make-Up 0.0 661.7 0.0 23.4 138.8 Credits Net Discretionary Revenues 101.2 64.4 177.8 113.5 120.0
18 RH-1-2006 The potential percentage impacts of these discretionary revenues on the Eastern Zone FT tolls for 2001 to 2005 are shown in Table 2-3 .
Table 2-3 Discretionary Revenue Evaluation (Percentage Impact on Eastern Zone FT Toll) 2001 2002 2003 2004 2005 5.0% 3.2% 9.4% 6.6% 7.5%
TransCanada noted that the information in Table 2-3 was considered in establishing the premium on the FT -SN toll. A premium of 10 percent was chosen as a conservative measure of the net impact on discretionary revenue of FT-SN.
In response to IGUA' s proposal that the FT-SN toll be set at 115 percent of the FT toll to reflect the true value of the FT -SN service, TransCanada argued that neither IGUA nor others submitted evidence respecting the appropriateness of value-based tolls nor a quantification of other costs to be considered.
TransCanada noted that current billing detenninants are based on contract quantity multiplied by distance. Any form of discount or premium would require an adjustment to either the quantity or distance in order to get the appropriate revenue allocated to the service. TransCanada explained that if the quantity was adjusted this would impact the fixed energy charge. If the distance was adjusted, the load centre would be impacted. Because of these impacts, TransCanada recommended that FT -SN revenues be included in Non-Discretionary Miscellaneous Revenue which, by way of functionali zation, provides a fixed cost contribution.
Positions of Parties
APPrOIGTA Generators
APPrO and the GTA Generators noted that the 10 percent premium reflects a conservative estimate by TransCanada that is based on the average contribution of discretionary revenue during the period from 2001 to 2005. APPrO and the GTA Generators indicated that since the average historical discretionary revenue during that period was 7.1 percent, FT -SN shippers are going to pay more than what the analysis suggests. That being said, APPrO and the GTA Generators indicated that they are willing to support the FT-SN toll as proposed.
CAPP
CAPP agreed that the FT-SN should be cost based and should attract a premium. It noted that the 10 percent premium should be considered to be the absolute minimum that should be levied as the impact of the capacity reservation feature of FT-SN is greater than the potential foregone discretionary revenue. CAPP suggested the premium should reflect the impact of FT-SN service on the lost opportunity for FT shippers to optimize the use of their contracts with FT-RAM, Authorized Overrun Service (AOS) and FT Makeup and the impact on fuel usage.
RH-1-2006 19 CAPP recommended that a review of the premium be conducted should circumstances so suggest. lGUA
IGUA stated the Ff-SN toll at 110 percent of the Ff toll is inappropriately low and recommended that the Ff-SN toll should be increased to at least 115 percent of the Ff toll. IGUA suggested that the Board consider the value of service criteria and other cost causation factors in determining whether the 10 percent premium is just and reasonable. More specifically, in determining the value of Ff-SN compared to Ff service, IGUA suggested the Board should consider the adverse impacts on existing shippers such as reduced system flexibility, increased exposure to balancing fees and higher costs for discretionary service. IGUA also submitted that the Board should consider the extent to which the actual Interruptible Transport1ltion (IT) premium in 2005 exceeded the Ff toll. IGUA stated that the average amount paid for IT service in the Union CDA, the Enbridge CDA and at the Iroquois delivery point wa~ 115 percent of the Ff toll. In considering cost causation, IGUA suggested the Board should consider the potential costs avoided by Ff-SN shippers such as daily load balancing charges and penalties.
Regarding the treatment of the Ff-SN revenue, IGUA questioned whether it is appropriate to exclude the Ff-SN volume and distance allocation factors in deriving Ff tolls. IGUA regarded the volume-distance methodology to be a core facet of TransCanada's toll design.
IGUA noted that there is evidence on the record to support the finding that TmllsCanada has failed to give appropriate weight to facts pertaining to toll design principles, which should have been considered.
Coral
Coral indicated that it has no objection to the proposed tolling for Ff-SN and it does not advocate a value-based toll for Ff-SN as proposed by IGUA.
Enbridge
Enbridge stated that it seems illogical to exclude Ff-SN from the calculation of billing determinants. It noted that Ff-SN is a firm year-round service just like Ff. Enbridge recommended that the contract demand for FT-SN be counted for toll design purposes and that only the revenue attributable to the premium should be allocated to misoellaneous revenue. Enbridge noted that it understood the premium is not locked in, nor should it be.
Gaz Metro
Gaz Metro stated that the 10 percent premium should constitute a minimum and should be adjusted as required. Gaz Metro recommended that the Board establish an adjustment mechanism to ensure the premium reflects the reality of the impacts of the Ff-SN service.
20 RH-1-2006 Union
Union indicated that it is prepared to accept Ff-SN service subject to periodic review of the toll premium, given that the opportunity cost pricing methodology is a novel and as yet untried method of rate-making.
Ontario
Ontario noted that if the premium is approved, it would mark the first time opportunity cost has been used for rate-making purposes for any Group I NEB regulated pipeline. Ontario indicated that TransCanada had not provided sufficient rationale for moving to an opportunity cost rate design. Nevertheless, given that APPrO and the GTA Generators indicated a willingness to pay a 10 percent premium for Ff-SN, Ontario stated that the 10 percent premium appears reasonable under the circumstances.
Ontario submitted that the Board should direct TransCanada to submit revised Ff-SN service tolls for the Board's review within two years of the Board's Decision, or sooner if possible. Ontario indicated that the revised Ff-SN tolls should be developed using standard toll design principles other than opportunity cost.
Quebec
The Procureur general du Quebec (Quebec) noted that a small premium beyond the 10 percent proposed by TransCanada should be imposed. This small premium should take into account costs beyond the opportunity cost of foregone discretionary revenue such as the costs of additional meters and flow control valves and additional staff needed to handle the increase in nomination windows.
Views ofthe Board
The Board agrees with the premise that the FT -SN toll should be cost based. The Board is not persuaded by lGUA's argument that TransCanada should include the value of the service in detennining its toll. In the Board's view, a value-based methodology would be more appropriate in a situation where a clear comparison can be made of the value of one service relative to another service. The Board does not agree that the value of the premium for FT -SN should be compared to the average premium that shippers are willing to pay for IT service. The characteristics of Ff-SN and IT are different and the requirement to pay tolls also differs between the two services. Accordingly, the Board is prepared to accept the concept of opportunity cost as a methodology in order to calculate the FT -SN toll.
However, the Board is concerned that the detennination of the 10 percent premium is somewhat arbitrary. The 10 percent premium is almost three percentage points higher than the average contribution of discretionary revenue to the Eastern Zone toll over the past five years and almost one
RH-1-2006 21 percentage point higher than the highest contribution over the past five years. The Board is of the view that not all costs have been considered and included in the premium. IGUA, CAPP and Quebec have provided suggestions of what costs, in their view, could be considered in determining the premium.
Given the various cost considerations suggested and the lack of consensus on what costs should be considered, the Board considers that it would be appropriate at this time to provide a measured approval of the IT-SN opportunity cost methodology toll. Further, the Board notes that most parties have suggested that the premium should undergo a regular periodic review. The Board agrees and directs TransCanada to conduct a yearly recalculation of the opportunity cost of the foregone discretionary revenues that can be attributed to the IT-SN service. The Board would prefer that this be done in consultation with the TIF. In addition, the Board expects TransCanada, in consultation with its stakeholders, to review the impacts of Ff-SN and thoroughly consider all the costs that should be reflected in the IT-SN toll premium in future LOll filings with the Board.
Regarding the treatment of the IT-SN revenue, the Board is not persuaded that the total Ff-SN revenue should be credited against the Mainline gross revenue requirement as Non-Discretionary Miscellaneous Revenue. The Board accepts the view that IT-SN, which is a firm service, should be treated in the same manner as IT service. More specifically, the Board is of the view that the contract demand for IT-SN should be included in the calculation of the allocation units for toll design purposes. Given the somewhat arbitrary value of the premium, the Board directs that the revenues attributed to the IT-SN premium should be included in Non Discretionary Miscellaneous Revenue.
Decision
The Board approves the FT-SN toll methodology as filed.
The Board directs TransCanada to conduct a yearly recalculation of the opportunity cost of the foregone discretionary revenues that can be attributed to the FT-SN service. TransCanada shall include the revised FT-SN toll and all relevant calculations and documentation in its annual toll application to the Board.
If, as a result of consultations with stakeholders, TransCanada develops a methodology other than opportunity cost, which reflects costs that should be included in the premium,
22 RH-1-2006 Attachment A7 Tab 27 Part A – Review and Variance Application National Energy Board Order TG-08-2006 ORDER TG-08-2006
IN THE MATTER OF the National Energy Board Act and the regulations made thereunder; and
IN THE MATTER OF an application filed by TransCanada PipeLines Limited (TransCanada) pursuant to Part IV of the Act for an order approving amendments to the Tariff of TransCanada’s Mainline to implement two new services designed to meet the requirements of gas- fired electrical power generators: Firm Transportation – Short Notice (FT-SN) service and Short Notice Balancing (SNB) service; and
IN THE MATTER OF Hearing Order RH-1-2006.
BEFORE the Board on 23 November 2006.
WHEREAS TransCanada filed an application dated 1 May 2006, pursuant to Part IV of the Act, for an order approving certain amendments to the Mainline Tariff to implement FT-SN and SNB services;
AND WHEREAS on 29 June 2006, the Board issued Hearing Order RH-1-2006;
AND WHEREAS an oral public hearing was held on 18, 19, 20, 21, 22 September 2006 in Toronto, Ontario and on 27, 28, 29 September 2006 in Calgary, Alberta during which time the Board heard the evidence and argument presented by TransCanada and interested parties;
AND WHEREAS the Board’s decisions on the application are set out in its RH-1-2006 Reasons for Decision dated November 2006, and in this Order;
THEREFORE, IT IS ORDERED, pursuant to Part IV of the Act, that:
1. FT-SN and SNB services are approved, effective immediately.
2. The proposed toll methodology for FT-SN service is approved, subject to an annual recalculation of the opportunity cost of the foregone discretionary revenue.
3. The proposed toll methodology for SNB service is denied and TransCanada is directed to develop an alternative tolling methodology which addresses the concerns of the Board in the RH-1-2006 Reasons for Decision.
…/2
-2-
4. TransCanada shall file with the Board and serve on the Mainline shippers, Tolls Task Force members and parties to the RH-1-2006 proceeding all revisions to the Mainline Tariff necessary to conform with the decisions outlined in the RH-1-2006 Reasons for Decision and with this Order.
5. TransCanada shall file, two years after natural gas starts to flow under an FT-SN contract, a report on the use of FT-SN and SNB services.
NATIONAL ENERGY BOARD
Michel L. Mantha Secretary
TG-08-2006
Attachment A7 Tab 28 Part A – Review and Variance Application Exhibit B-5-11, RH-003-2011, Section 8.0: Mainline Services and Pricing Proposals. Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part C: Business and Services Restructuring Proposal Section 8.0: Mainline Services and Pricing Proposals Page 35 of 39 Revised October 31, 2011
1 sold in the first year of an MFP Block will contribute to a variance. Accordingly, 2 TransCanada does not propose an MFP-specific deferral account; rather, it proposes 3 to address variances in the same revenue deferral account proposed to be used for all 4 services.
5 John J. Reed of Concentric, whose expert evidence is presented as Appendix C4 to 6 the Application, addresses the consistency of MFP service with the Board’s principles 7 of no unjust discrimination and cost-based/user pay. Mr. Reed provides his view of 8 MFP service as an appropriate response to the current circumstances facing the 9 Mainline.
8.5 Pricing of Firm Transportation Short Notice Service for 2012 and 2013
10 The pricing of FT-SN service is presented in response to the Board’s direction in its 11 RH-1-2006 Decision that TransCanada seek approval of the FT-SN toll each year,22 12 and is not advanced as part of the Restructuring Proposal. TransCanada proposes to 13 continue the existing 10% FT-SN toll premium for 2012 and 2013.
14 FT-SN service is designed to meet the needs of shippers who have highly variable 15 and unpredictable load profiles such as gas-fired electrical power generators. FT-SN 16 service is a renewable, assignable firm service with a minimum one year contract 17 term that permits intra-day nominations as frequently as every 15 minutes, with up to 18 96 nomination windows per day. The full contracted FT-SN capacity is reserved 19 throughout the gas day to accommodate FT-SN service nominations. This is different 20 from FT service where a shipper is only assured access to capacity in the first of four 21 nomination windows.
22 Since its implementation, FT-SN service has been priced at a 10% premium over the 23 equivalent FT toll. The premium is intended to reflect an estimate of the opportunity
22 RH-1-2006 Decision, page 22.
Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part C: Business and Services Restructuring Proposal Section 8.0: Mainline Services and Pricing Proposals Page 36 of 39 Revised October 31, 2011
1 cost of potentially foregone discretionary revenue as a result of any unused FT-SN 2 capacity not being available for discretionary services.
3 As part of its annual calculation in support of the FT-SN tolling methodology, 4 TransCanada conducts a yearly recalculation of the opportunity cost of the foregone 5 discretionary revenues that can be attributed to the reserved capacity feature of FT- 6 SN service and includes the revised FT-SN toll and relevant calculations and 7 documentation in its annual toll application to the Board. This calculation takes the 8 gross annual revenue from certain discretionary services and subtracts RAM credits23 9 to arrive at a net discretionary revenue amount. This net discretionary revenue is then 10 used to calculate the potential percentage impact on the Eastern Zone toll. The results 11 of this annual calculation for the years 2001 – 2010 are shown in Table 8-5 below. 12 While the percentage impact on the Eastern Zone toll has fluctuated from year to 13 year, it remains in the same range as the 2001 to 2005 data that were presented to the 14 Board in the RH-1-2006 proceeding. On this basis, TransCanada proposes to 15 continue the existing 10% premium for 2012 and 2013.
Table 8-5: Discretionary Revenue Evaluation 2001-2010 ($ million) 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Gross Discretionary 101 726 178 137 259 236 288 390 382 490 Revenues* Less RAM 0 (662) 0 (23) (139) (165) (183) (256) (291) (440) Credits Net Discretionary 101 64 178 114 120 71 105 134 92 50 Revenues Eastern Zone Toll 1.00 1.13 1.20 1.19 1.00 0.94 1.03 1.31 1.19 1.64 ($/GJ) % Impact on Eastern Zone 5.0% 3.2% 9.4% 6.6% 7.5% 4.7% 6.5% 8.6% 7.9% 3.6% toll *Includes revenues from IT, Diversions, ARPs, STS Overrun and PALS.
23 Or predecessors of RAM credits, such as AOS and FT-Make Up credits.
Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part C: Business and Services Restructuring Proposal Section 8.0: Mainline Services and Pricing Proposals Page 37 of 39 Revised October 31, 2011
1 Although TransCanada supports the continuation of the 10% FT-SN toll premium for 2 2012 and 2013, a number of factors could support a higher premium. For example, 3 the proposed elimination of the RAM feature and proposed changes to the pricing of 4 IT and STFT services suggest that the net discretionary revenue impact calculated in 5 Table 8-5 may be larger in the future. Also, TransCanada notes that the current FT- 6 SN contracts are all located on short-haul paths with receipt points of Parkway or 7 Kirkwall, which are more prone to discretionary service restrictions than other 8 locations on the Mainline. This indicates that forgone discretionary revenues 9 associated with reserved capacity may be higher on these paths than on the Mainline 10 as a whole.
11 While these factors would directionally support a higher premium for FT-SN service, 12 TransCanada proposes to continue the existing 10% premium for 2012 and 2013 until 13 more operating information on the impact of the Restructuring Proposal is available.
8.6 Elimination of Services
14 TransCanada proposes to eliminate four Mainline services that are no longer required: 15 LT-WFS; FST; FBT; and ITB.
16 LT-WFS and FST services have not been used in a long time and there are no 17 contracts remaining under either service. A limited quantity of LT-WFS capacity was 18 approved by the Board in the RH-3-94 Decision24 and the last LT-WFS contract 19 expired on March 31, 2005. The conversion of FST service to FT service was 20 addressed in the RH-1-97 Decision.25 The last FST contract was converted to FT 21 service on October 31, 2000.
24 RH-3-94 Decision, pages 17-19. 25 RH-1-97 Decision, section 7.3.
Attachment A7 Tab 29 Part A – Review and Variance Application TTF Resolution 01.2008, dated January 10, 2007
2007 TOLLS TASK FORCE ISSUE Date Accepted As Issue: Issue Number: January 10, 2007 01.2008 Date Issue Originated: Sheet Number: January 10, 2007 1 of 1 Issue Originated By: TransCanada Individual to Contact: Telephone Number Gordon Betts (403) 920-6834
ISSUE: SNB Tolling Methodology
RESOLUTION The TTF agrees to the SNB tolling methodology, as described in the attached Explanatory and supporting illustrative tables. The methodology incorporates a cost based approach that utilizes Mainline average unit costs to generate tolls that would be applicable to all SNB contract quantities uniformly for locations within a domestic zone and adjacent export points.
The details of the SNB tolling methodology are included in the attached Explanatory and supporting illustrative tables.
______BACKGROUND On May 1, 2006 TransCanada applied to the NEB for an order approving two new services to meet the requirements of gas-fired electrical power generators; namely, Firm Transportation – Short Notice (FT-SN) and Short Notice Balancing (SNB). TransCanada’s application included proposed toll methodologies for both services.
The NEB approved the FT-SN service including the proposed toll methodology. The Board also approved the SNB service but rejected the proposed toll methodology for SNB. The NEB directed TransCanada to develop an alternative methodology which addresses the concerns outlined in the RH-1-2006 Reasons for Decision and it was the view of the Board that “a cost-based averaging approach by geographic area should be used”.
Revised Date – January 18, 2008 1 of 2
The methodology was developed to be consistent with the Board’s view. The methodology creates a cost based toll, uses Mainline system average unit costs, and provides uniform tolls for locations located in close proximity. The averaging of corridors within the existing zonal boundaries represents an averaging approach by geographic area. The methodology is transparent and not situation specific, therefore providing consistent tolls to shippers operating under similar circumstances (i.e. FT-SN contract paths, SNB quantities).
As per the Board‘s direction in its RH-1-2006 Reasons for Decision, TransCanada will file with the NEB any SNB tolls before providing the service.
TransCanada will provide an update, as per the Board’s direction in its RH-1-2006 Reasons for Decision, on the use of SNB service and toll methodology as part of its Short Notice Services report that is due after two years of operating experience with the services. At that time TransCanada and the TTF will evaluate whether a change is appropriate for the toll methodology.
______
VOTING RESULTS:
Unopposed resolution at the January 18, 2008 TTF meeting in Calgary
Revised Date – January 18, 2008 2 of 2
Explanatory - SNB Toll Methodology
The SNB toll methodology incorporates the estimated facilities utilized by SNB service, average annual cost per kilometre of pipe, average annual cost per megawatt of power and compression structures, average annual cost of linepack and storage gas and a general and administration charge. This methodology provides a cost basis for SNB tolls and will incorporate the differences in costs for providing service on the various corridors of the Mainline.
The estimated facilities required to provide the SNB service is based on a facilities simulation incorporating the companion FT-SN contract and assumes the corridor is fully utilized. Each simulation highlights the percentage utilization of the loop sections and the number of megawatts necessary to provide SNB service. The estimated facilities required to provide the SNB service on a specific corridor will not be re-visited in the future Test Years, unless there is a significant change to the facility set in the corridor. The attached tables illustrate the facilities utilized for the corridors underpinning the proposed toll for the Eastern Zone and adjacent export points.
The annual costs are based on the Net Revenue Requirement’s functionalized fixed transmission cost prorated over net plant associated with each of pipeline, compression structures, compressors, and linepack and storage gas. The annual costs are then divided by the appropriate units for each net plant category. The units are kilometres of pipe, number of compressor stations, total system megawatts, and linepack and storage gas quantities. The general and administration charge is based on the functionalized fixed energy costs excluding the cost of metering. This calculation results in SNB tolls reflecting a contribution to all costs within the Net Revenue Requirement (excluding Electric Costs and Tax on Fuel).
The illustrative 2007 SNB toll in the accompanying tables reflects how the methodology would average the tolls based on a range of SNB contract quantities, a range of FT-SN service quantities and average the corridors. The Eastern zone’s SNB toll would be the average of the Parkway to Maple corridor, the Kirkwall to Niagara corridor, and the Eastern corridor (the Eastern corridor would consist of the facilities from Station 130 North to Station 116; Station 116 East to the Line1200/Line 100 tie-in at kilometre post 3064 km; South to Station 130). For the purposes of this SNB methodology, the corridors have been defined as domestic zones including the adjacent export points. The potential SNB toll will be charged to all SNB contract quantities uniformly within the domestic zone and adjacent export points.
In each Test Year, the SNB toll will be updated to reflect the Test Year projected Net Revenue Requirement. This ensures the SNB toll continues to reflect the annual owning and operating costs of the Mainline. The revenue generated from
SNB service will be included as part of Non-Discretionary Miscellaneous Revenue.
In the event there are further SNB requests, in a different zone, they will be charged a toll for that specific zone, and design simulations will be prepared for that SNB toll Calculation.
The attached tables illustrate the facilities underpinning the SNB toll for the Eastern Zone between the Parkway receipt location, located at Kilometre post 2997km, and the Maple compressor station 130, located at Kilometre post 2950km, (Parkway corridor); between station 130 and boundary of the Eastern Zone 2660 km or located 23 Km south of station 116, and between the boundary of the Eastern Zone, 2660 km or located 23 Km east of station 116, on the North Bay shortcut to the Line1200/Line 100 tie-in at kilometre post 3064 km, and south to the Maple compressor station 130 (Eastern corridor); as well as between the Kirkwall point, located at Kilometre post 1047km, and the Niagara Falls and Chippawa export points, located at Kilometre post 3129 km and 3132 km respectively, (the Kirkwall corridor) see attached map #1. The attached tables illustrate the assumptions and calculations underpinning the proposed SNB toll for the Eastern Zone.
Table 1 illustrates the facilities utilized for these corridors. The Parkway corridor facilities for the various SNB contract quantities require either a 2 MW compressor unit or a 7 MW compressor unit and, in most cases various percentages of two loop sections. The Kirkwall corridor would require the use of various loop sections along the Niagara lateral. These facilities are used to determine the costs and resulting toll for SNB service.
Table 2 illustrates the pipeline kilometres, compression units, compression MW total, functional distribution of net revenue requirement and net plant assumptions. The cost per unit calculations are based on this data and are applied to the facilities utilized for SNB service within each corridor
Table 3 calculates the Illustrative 2007proposed toll for SNB service using the proposed methodology. The toll is calculated based on the average of SNB quantities from 50 TJ’s to 200 TJ’s for all corridors described above.
TTF Issue A-2 SNB Tolling Methodology
Illustrative 2007 Facilities Utilization Table 1
Parkway Corridor
Maple C/S Unit Maple C/S Unit Addition Niagara Extension Niagara Extension Addition (7 MW) (2 MW) Loop (12.8 km X NPS Loop (13.8 km X 42) MLV 203 to MLV NPS 42) MLV 202 204) to MLV 203 Pipeline SNB Qty FT-SN Qty Percentage utilization of the above Facilities MW's Utilized KM's Utilized (TJ) (TJ/d)
50 50 0% 100% 0% 0% 2.0 - 100 100% 0% 6% 0% 7.0 0.8 150 100% 0% 19% 0% 7.0 2.4 200 100% 0% 35% 0% 7.0 4.5 250 100% 0% 61% 0% 7.0 7.8 300 100% 0% 100% 1% 7.0 12.9 100 100 100% 0% 6% 0% 7.0 0.8 150 100% 0% 20% 0% 7.0 2.6 200 100% 0% 40% 0% 7.0 5.1 250 100% 0% 78% 0% 7.0 10.0 300 100% 0% 100% 5% 7.0 13.5 150 150 100% 0% 20% 0% 7.0 2.6 200 100% 0% 40% 0% 7.0 5.1 250 100% 0% 82% 0% 7.0 10.5 300 100% 0% 100% 6% 7.0 13.6 200 200 100% 0% 40% 0% 7.0 5.1 250 100% 0% 82% 0% 7.0 10.5 300 100% 0% 100% 7% 7.0 13.8
1/18/2008 TTF Issue A-2 SNB Tolling Methodology
Illustrative 2007 Facilities Utilization Table 1
Kirkwall Corridor
SNB Quantity Pipe Diameter Start Location End location Length (TJ) (km)
50 24 MLV 1701 MLV 1703 20.1 36 MLV 1301 MLV 1302 25.3 45.4
100 24 MLV 1701 MLV 1703 20.1 36 MLV 1301 MLV 1302 25.3 36 MLV 209 MLV 211 32.8 78.2
150 36 MLV 1701 MLV 1703 20.1 36 MLV 1301 MLV 214 103.3 123.4
200 42 MLV 1701 MLV 1703 20.1 42 MLV 211 MLV 214 32.7 48 MLV 1301 MLV 211 70.7 123.5
Eastern Corridor
Sundridge C/S Unit Sundridge C/S Unit Addition (1 MW) Addition (6 MW) Pipeline SNB Qty FT-SN Qty MW's Utilized KM's Utilized (TJ) (TJ/d)
50 100% 1- 100 100% 1- 150 100% 6- 200 100% 6-
1/18/2008 TTF Issue A-2 SNB Tolling Methodology Table 2 Illustrative Example 2007 Unit Cost Calculation
System assests Total Mainline Pipeline KM's 15,004 A Total Mainline Compressor Units 141 B Total Mainline Compressor MW's 2,312 C Total Mainline Linepack and Storage Gas quantity (GJ) 27,600,000 D
Functional Distribution of Net Revenue Requirement Fixed Transmission Costs (TD Schedule 2.1) $ 1,420,521,000 E
Total Mainline Net Plant (TD Schedule 2.2, 2.3) $ 7,087,326,508 F
Asset Allocated Value Transmission Cost Net Plant - Pipeline $ 4,863,390,000 G 974,774,849 K = (G/F) x E Net Plant - Compression Structure$ 220,000,000 H 44,094,853 L = (H/F) x E Net Plant - Compression Equipment $ 1,895,400,000 I 379,897,201 M = (I/F) x E Net Plant - Linepack and Storage Gas $ 56,441,000 J 11,312,535 N = (J/F) x E
Cost per Unit Calculation Total cost per pipeline kilometre $/KM/yr $ 64,967.7 O = K/A Total cost per compressor unit $/unit/yr $ 312,729.5 P = L/B Total cost per megawatt $/MW/yr $ 164,315.4 Q = M/C Total per unit cost of linepack and storage gas $/GJ/yr $ 0.41 R = N/D General & Administration $/GJ $ 0.0277 S see details below
1/18/2008 TTF Issue A-2 SNB Tolling Methodology Table 2
Example Calculation for General & Administration Charge "S"
Functional Distribution and Classification of Net Revenue Requirement For the Test Year ending December 31, 2007 ($000's)
Line Fixed Transmission No. Particulars Total Energy Fixed Variable (a) (b) (c) (d) (e) 1 Transmission by Others 308,859 - 302,230 6,629 2 Operations, Maintenance and Administrative 178,100 72,586 85,336 20,178 3 Municipal and Provincial Capital Taxes 122,560 957 121,603 - 4 Delivery Pressure on TBO 3,571 - 3,571 - 5 Debt Redemptions/(Gains) (44,520) (373) (44,147) - 6 Electric Costs and Tax on Fuel 83,907 - - 83,907 7 Pipeline Interity and Insurance Deductible Costs 46,527 - 46,527 - 8 Compressor Repair and Overhaul Costs 57,239 - 57,239 - 9 Storage Operating costs 13,887 - 13,887 - 10 Depreciation 389,392 4,442 384,950 - 11 Income Taxes 178,480 1,496 176,984 - 12 Regulatory Amortizations (36,313) - (36,313) - 13 Perfomance Incentive Envelope 15,900 7,950 7,950 - 14 Regulatory Proceeding and Collaborative (TTF) Costs 3,555 1,778 1,778 -
15 NEB Cost Recovery 5,039 5,039 - 16 Return 5,137 5,137 - 17 Gross Revenue Requirement 1,331,320 99,012 110,714
Non-Discretionary Miscellaneous Revenue 18 - Sales Meter Station Charges - - 19 - Storage Transportation Service (10,705) (10,205) (500) 20 - Sale of Delivery Pressure (637) - (637) 21 Sub-Total Non-Discretionary (11,342) (10,280) (49,956) (1,137)
Discretionary Miscellaneous Revenue 22 - Miscellaneous Discretionary (11,342) (2,357) (278,863) - 23 Total Miscellaneous Revenue (22,684) (12,637) (328,819) (1,137) 24 Net Revenue Requirement 1,308,636 86,375 1,405,664 109,577 25 Interim Revenue Adjustment - (IRA) 1,274,610 913 14,857 1,158
26 Net Revenue Requirement Including (IRA) 1,618,543 87,288 1,420,521 110,735
Fixed Energy costs related to G&A $000's/yr 79,403 T = Lines 2+14+15 Proportion of Total Miscellaneous Revenue to Attribute to G&A $000's/yr (10,134) U = Line 23 x (T / Line 17) Functional Distribution of Net Fixed Energy from the Net Revenue Requirement $000's/yr 69,268 V = T + U
2007 Total System Firm Service Allocation Units TJ/d 6,848 X
General & Administration $/GJ 0.0277 S = V / (X x 365)
1/18/2008 TTF Issue A-2 SNB Tolling Methodology Table 3
Illustrative Example 2007 SNB Toll Calculation
Parkway Corridor Linepack and AVERAGE COSTING Compressor MW's KM's Compressor Storage Gas Pipe Cost G&A SNB Qty FT-SN Qty Required Required Required Cost Cost Cost Cost per Unit Charge Toll Line (TJ) (TJ/d) ($/yr) ($/yr) ($/yr) ($/yr) ($/GJ/d) ($/GJ/d) ($/GJ/d)
50 50 1 2 - 641,360 20,494 - 661,854 0.036 0.028 0.064 50 100 1 7 0.77 1,462,937 20,494 49,895 1,533,326 0.084 0.028 0.112 50 150 1 7 2.43 1,462,937 20,494 158,001 1,641,432 0.090 0.028 0.118 50 200 1 7 4.48 1,462,937 20,494 291,055 1,774,486 0.097 0.028 0.125 50 250 1 7 7.81 1,462,937 20,494 507,268 1,990,698 0.109 0.028 0.137 50 300 1 7 12.94 1,462,937 20,494 840,552 2,323,983 0.127 0.028 0.155 100 100 1 7 0.77 1,462,937 40,987 49,895 1,553,820 0.043 0.028 0.070 100 150 1 7 2.56 1,462,937 40,987 166,317 1,670,242 0.046 0.028 0.073 100 200 1 7 5.12 1,462,937 40,987 332,634 1,836,559 0.050 0.028 0.078 100 250 1 7 9.98 1,462,937 40,987 648,637 2,152,562 0.059 0.028 0.087 100 300 1 7 13.49 1,462,937 40,987 876,414 2,380,338 0.065 0.028 0.093 150 150 1 7 2.56 1,462,937 61,481 166,317 1,690,736 0.031 0.028 0.059 150 200 1 7 5.12 1,462,937 61,481 332,634 1,857,053 0.034 0.028 0.062 150 250 1 7 10.50 1,462,937 61,481 681,901 2,206,319 0.040 0.028 0.068 150 300 1 7 13.63 1,462,937 61,481 885,379 2,409,798 0.044 0.028 0.072 200 200 1 7 5.12 1,462,937 81,975 332,634 1,877,547 0.026 0.028 0.053 200 250 1 7 10.50 1,462,937 81,975 681,901 2,226,813 0.031 0.028 0.058 200 300 1 7 13.77 1,462,937 81,975 894,345 2,439,257 0.033 0.028 0.061
Parkway Average ($/GJ)* 0.086 A
Kirkwall Corridor Linepack and AVERAGE COSTING Compressor MW's KM's Compressor Storage Gas Pipe Cost G&A SNB Qty FT-SN Qty Required Required Required Cost Cost Cost Cost per Unit Charge Toll (TJ) (TJ/d) ($/yr) ($/yr) ($/yr) ($/yr) ($/GJ/d) ($/GJ/d) ($/GJ/d)
50 50 - - 45.40 - 20,494 2,949,532 2,970,026 0.163 0.028 0.190 100 100 - - 78.20 - 40,987 5,080,471 5,121,459 0.140 0.028 0.168 150 150 - - 123.40 - 61,481 8,017,010 8,078,491 0.148 0.028 0.175 200 200 - - 123.50 - 81,975 8,023,507 8,105,482 0.111 0.028 0.139
Kirkwall Average ($/GJ)* 0.168 B
Eastern Corridor Linepack and AVERAGE COSTING Compressor MW's KM's Compressor Storage Gas Pipe Cost G&A SNB Qty FT-SN Qty Required Required Required Cost Cost Cost Cost per Unit Charge Toll (TJ) (TJ/d) ($/yr) ($/yr) ($/yr) ($/yr) ($/GJ/d) ($/GJ/d) ($/GJ/d)
50 50 1 1 - 477,045 20,494 - 497,539 0.027 0.028 0.055 100 100 1 1 - 477,045 40,987 - 518,032 0.014 0.028 0.042 150 150 1 6 - 1,298,622 61,481 - 1,360,103 0.025 0.028 0.053 200 200 1 6 - 1,298,622 81,975 - 1,380,597 0.019 0.028 0.047
Eastern Average ($/GJ)* 0.049 C
Example of daily equivalent SNB Toll, Eastern Zone with 3 corridors ($/GJ/d)* 0.101 D = (A+B+C)/3
*SNB Tolls will be a monthly demand charge per GJ of SNB contract quantity
Illustrative 2007 SNB Toll ($/GJ/Mo) 3.07144
1/18/2008 Empress WYOMING
Legend: 2 BURSTALL
SuffieldEmpress 391 Richmond
MONTANA 392
S Bayhurst 5
Current Swift CABRI 393 Liebenthal Storage Facility Interconnect Point / Hub Union Gas Portland Natural Gas Transmission System (61.71%) Iroquois Gas Transmission System (40.96%) LP which is 33.4% owned by TransCanada) (30% owned by TC PipeLines, Northern Border Pipeline Company Trans Québec & Maritimes Pipeline (50%) Great Lakes Gas Transmission (50%) Foothills Pipe Lines (100%) Alberta System (100%) Canadian Mainline (100%) Compressor Station Pipeline 394 Shackleton
Success
9 1 HERBERT Saskatchewan
Herbert SASKATCHEWAN
13 2 Moose Jaw CARON Zone
Regina 3
17 Steelman
REGINAGrand Coulee
DAKOTA SOUTH
4
5 21 NEBRASKA Moosomin
Welwyn GRENFELL 6 Turbine Repair
Power Generation 25
7 MOOSOMIN DAKOTA NORTH Brandon - Power (100%) (Under Construction) - Power (100%) (In Development) - Power (100%) - Bruce Power L.P. (31.6%) (50%) - TransCanada Turbines - Sedimentary Basins
2006_can_ml_sales_mkt_tar_del_area.F H10 - April 3 2006 - Willis TC Mapping
8 30
RAPID CITY Manitoba
MANITOBA
9 Emerson
Zone 34
PORTAGE
10 L A
LA PRAIRIE K
E
Winnipeg W
I
N
N
I
P
E G
MAP IS REPRESENTATIVE NOT TO SCALE TO NOT REPRESENTATIVE IS MAP
11 1
Delivery Areas 41
Spruce ILE DES CHENES
43 2 SPRUCE
MINNESOTA 12
IOWA 45 SSDA CDA SWDA NDA WDA EDA NCDA
SSMDA MDA FALCON LAKE
3 13
Kenora 49 Eastern Delivery Area North Central Delivery Area
Central Delivery Area Southwestern Delivery Area Sault Ste. Marie Delivery Area Northern Delivery Area Western Delivery Area Manitoba Delivery Area Saskatchewan Southern Delivery Area KENORA
4 52
Dryden VERMILION BAY
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Website: www.transcanada.com/Customer_Express Website: Call Centre: (403) 920-PIPE (7473) following: the of one or Representative Sales Customer your contact please If you would like additional copies of this map or have any questions or comments, 75 NIPIGON
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Northern 11 Vector Pipeline 12 CALSTOCK Sault Ste. Marie Kapuskasing
Tariff Zones & Delivery Areas Sault Ste. Marie Sault Zone
SMOOTH ROCK FALLS 92
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Power Plant Power Grandview Saint John SCOTIA NOVA Attachment A7 Tab 30 Part A – Review and Variance Application National Energy Board Letter T211-2010-03 01, TransCanada PipeLines Limited, Union Dawn Receipt Point Surcharge Application, September 3, 2010 File OF-Tolls-Group1-T211-2010-03 01 3 September 2010
Mr. Murray Sondergard Director, Regulatory Services TransCanada PipeLines Limited 450 – 1st Street SW Calgary, AB T2P 5H1 Facsimile 403-920-2409
Dear Mr. Sondergard:
TransCanada PipeLines Limited (TransCanada) - Union Dawn Receipt Point Surcharge Application
On 13 August 2010, TransCanada filed an application with the National Energy Board requesting approval of:
• the methodology for establishing the recovery of the cost of the Union Gas Service Contract and the associated fuel requirement; • the creation of the Union Dawn Receipt Point Surcharge Deferral Account; • the resulting amendments to the Tariff; and • the resulting amendments to the Mainline Toll Design Schedules, including the level of the Union Dawn Receipt Point Surcharge, effective 1 November 2010.
The Board notes the application was supported by unopposed Tolls Task Force Resolution 01.2010: Dawn to Dawn (TCPL) Service (User Pay).
The Board has examined TransCanada’s application and approves the application as filed.
TransCanada is directed to serve a copy of this letter on its Tolls Task Force Members, its Mainline shippers, and other interested persons.
Yours truly,
Anne-Marie Erickson Secretary of the Board Attachment A7 Tab 31 Part A – Review and Variance Application TTF Resolution 01.2010, dated May 12, 2010
2010 TOLLS TASK FORCE ISSUE Date Accepted As Issue: Resolution: May 12, 2010 01.2010 Date Issue Originated: Sheet Number: 1 of 4 Issue Originated By: TransCanada Individual to Contact: Telephone Number Don Bell 416 869-2191
ISSUE: Dawn to Dawn (TCPL) Service (User Pay)
______RESOLUTION
TransCanada and stakeholders agree that TransCanada seek to contract for a five year term of 500 TJ/day of Dawn to Dawn (TCPL) capacity (“Union Gas Service”) in the Union Gas Firm Dawn to Dawn (TCPL) Transportation Service Open Season (“Union Gas Open Season”). If successful, TransCanada will include the annual costs of Union Gas Service in the Mainline revenue requirement and fuel rates, in order to facilitate receipt of gas from Union Dawn facilities to Union Dawn (TransCanada’s receipt point at Dawn).
Stakeholders agree that these costs of Union Gas Service will be included in the Mainline revenue requirement and fuel rates for the duration of the Union Gas Service contract and will be tolled directly to all Mainline transportation with a receipt of gas at Union Dawn via a toll applicable to this service. The fuel charges associated with this Union Gas service will also apply directly to all Mainline transportation with a receipt at Union Dawn. Stakeholders agree with the toll methodology as described in the background and also agree not to oppose the filing of this methodology with the National Energy Board (“NEB” or “Board”). In the event that there is no Mainline transportation from Union Dawn, members agree that this cost will be recovered by all shippers via the revenue requirement for the remaining term of the service with Union Gas. Stakeholders acknowledge that the implementation of this Dawn to Dawn toll and fuel charge shall not set a precedent.
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The stakeholders and TransCanada also agree to the creation of a regulatory deferral account to manage annual variances in revenue recovery related to the cost of this Union Gas Service.
______BACKGROUND Due to de-contracting and substantial changes in flows at Dawn, exchange can no longer be relied upon to move gas between Union Dawn facilities and Union Dawn (TransCanada’s receipt point at Dawn).
Physical facilities are required by November 1, 2010 to ensure that interruption of firm volumes does not occur.
Union has posted an open season for new capacity to provide firm transportation for up to 500 TJ/d from Union Dawn facilities to Union Dawn. The 500 TJ/d was determined to be sufficient to prevent firm service interruptions this winter.
For reasons of efficiency some shippers have requested that TransCanada bid into the Open Season on their behalf and that all costs associated with TransCanada holding such service on the shippers’ behalf would be subject to full cost recovery.
Cost Allocation
Stakeholders agree that these costs will be recovered via a Dawn to Dawn toll and fuel charge, applicable to all transportation originating at Union Dawn to be recovered over the term of the Union Gas Service contract. The following describes the terms required for inclusion in the Mainline Tariff.
Toll Methodology:
Annual Mainline Toll = Annual Cost of Service to Union Annual Mainline FT Contracts with Union Dawn Receipt
Illustrative Example: For an annual cost of service at $2 million and using the Union Dawn receipt FT contract quantity as of November 1, 2010 at 1,287,904 GJs/day: - the monthly demand charge would be $0.12941/GJ/month - the daily equivalent 100% LF toll would be $0.0043/GJ (or 0.43 cents/GJ)
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The Dawn to Dawn toll will be an additional monthly demand charge to all FT, FT-NR, FT-SN, contracts with a Union Dawn receipt. As well, any other service which is nominated and scheduled with a Union Dawn receipt will pay the daily equivalent toll.
Fuel Recovery
The fuel ratio for the Dawn to Dawn service will be set annually and will be an incremental fuel ratio in addition to the transport fuel ratio for all transportation services nominated and scheduled with a Union Dawn receipt. Fuel variances will be captured in the system wide fuel over/under balance.
Fuel Ratio Methodology:
Annual ML Fuel Ratio = Forecast of Annual GJs provided to Union for Service Forecast of annual Union Dawn receipts scheduled onto TC (GJs)
Illustrative Example: Annual forecast of GJs provided to Union for Service: 500,000 GJ/d X 10 winter days X Union FR of 0.75% = 37,500 GJs Forecast of annual Union Dawn receipts scheduled onto TCPL: 700,000 GJs/d X 365 days = 255,500,000 GJs Annual M/L Fuel ratio for Dawn to Dawn TC service: 37,500 GJs / 255,500,000 GJs = 0.015%
The Dawn to Dawn toll will change on an annual basis depending on the cost of the service (including deferral balance effects) and applicable billing determinants.
In light of the timeline imposed by the timing of the Union Open Season for Dawn to Dawn capacity, draft Tariff language has not been prepared at this time. Draft Tariff language reflective of this Resolution will be prepared following successful acquisition of the Union Gas Service. TTF members will be provided an opportunity to comment on the consistency of the Tariff language with the terms of the resolution prior to the Tariff language being filed with the NEB. However, the Tariff language will not be subject to an additional TTF vote.
The TTF acknowledges that the implementation of this Dawn to Dawn toll and fuel charge shall not set a precedent.
Nominations and Operations
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Should TransCanada be successful in obtaining capacity in Union’s Open Season, TransCanada would hold firm service on Union from the “Union Dawn Facilities” to the interconnection point between TransCanada and Union (“Union Dawn”). This capacity would be used to move gas received by TransCanada from its shippers. However, the receipt point specified in TransCanada’s shipper contracts is not “Union’s Dawn Facilities”, but rather is “Union Dawn”.
To address this mismatch in receipt/delivery points and avoid the need to amend receipt points in all TransCanada shipper contracts at Dawn, TransCanada proposes to condition its bid in the Union Open Season on Union’s agreement to an effective nomination/allocation process where TransCanada and Union would continue to confirm shippers nominations at Union Dawn on TransCanada and Dawn (TCPL) on Union.
______
VOTING RESULTS:
Unopposed Resolution at special Task Force meeting on May 25, 2010 in Calgary.
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Attachment A7 Tab 32 Part A – Review and Variance Application Exhibit B-5-2, RH-003-2011, Attachment 12.1: Revenue Requirement, Tab 2 – Transportation by Others Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part E: Mainline 2012-2013 Revenue Requirement Attachment 12.1: Revenue Requirement Tab 2 – Transportation by Others Page 18 of 32
1 costs in 2012 are forecast to be $76.9 million. A total of $17.8 million in revenues 2 associated with assignments is expected to be generated and credited to Mainline 3 shippers. The net total GLGT TBO cost for 2012 is forecast to be $59.1 million.
4 The forecast 2013 TBO costs reflect the estimated costs related to the above-noted 5 forecast GLGT capacity commencing November 1, 2012 for the entire 2013 Test 6 Year. As shown in Schedule 2.4, GLGT TBO costs in 2013 are forecast to be 7 $63.1 million. A total of $25.0 million in revenues associated with assignments are 8 expected to be generated and credited to Mainline shippers. The net total GLGT 9 TBO cost for 2013 is forecast to be $38.1 million.
10 For the purpose of forecasting 2012 and 2013 GLGT TBO costs, TransCanada has 11 assumed the estimated capacity would be acquired at the same rate as existing 12 contracted capacity.
4.0 Union Gas Limited System
13 The Union system is a large diameter pipeline system extending from Dawn to 14 Parkway, Ontario. A map of the Union system is provided at Figure 4. The 15 Mainline interconnects with the Union system at three locations; Dawn near 16 Sarnia, Ontario; Kirkwall near Guelph, Ontario; and Parkway in Mississauga, 17 Ontario. Union is regulated by the Ontario Energy Board (OEB) and the tolls paid 18 by TransCanada for service on the Union system reflect the OEB-approved 19 methodology and rates.
Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part E: Mainline 2012-2013 Revenue Requirement Attachment 12.1: Revenue Requirement Tab 2 – Transportation by Others Page 19 of 32
Figure 4: The Union System
1 TransCanada has long held firm transportation contracts with Union for M12 and 2 C1 services. The M12 service agreements provide for firm transportation between 3 Dawn and either Parkway or Kirkwall while the historical C1 service agreement 4 that was terminated on August 31, 2011 provided for firm transportation between 5 Parkway and Kirkwall.
6 Combined with capacity held on the GLGT system and Mainline facilities between 7 St. Clair and Dawn, Union system capacity between Dawn, Kirkwall and Parkway 8 completes the functional loop of the Mainline, allowing WCSB gas to be 9 transported either through the NOL or the GLGT/Union systems to eastern 10 domestic and export markets. Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part E: Mainline 2012-2013 Revenue Requirement Attachment 12.1: Revenue Requirement Tab 2 – Transportation by Others Page 20 of 32
1 Union M12 capacity between Dawn and Parkway enables Mainline delivery of long 2 haul and short haul volumes to Parkway and other locations in the Eastern Triangle. 3 Union M12 capacity between Dawn and Kirkwall enables delivery of long haul and 4 short haul volumes to Kirkwall and the Niagara and Chippawa export point. Union 5 C1 capacity service between Parkway and Kirkwall enables gas transported through 6 the NOL to be delivered at Kirkwall and the Niagara and Chippawa export points.
7 The interconnection between the Mainline and the Union system at Parkway allows 8 bi-directional flow. The pattern of flow has traditionally been driven by the storage 9 facilities at Dawn, with deliveries from the Mainline to the Union system during the 10 summer period and deliveries from the Union system to the Mainline during the 11 winter period. Accordingly, utilization of the M12 (Dawn to Parkway) capacity has 12 been highest in the winter while utilization of the C1 (Parkway to Kirkwall) 13 capacity has been highest in the summer.
14 Contracts held by TransCanada for Union system service were generally entered 15 into in response to long term service requests for Mainline services. Generally, 16 these contracts had an initial term of ten years, which is required by Union when 17 new facilities are required. Following the expiry of the initial term, Union contracts 18 can be renewed for a one-year term, but a two-year prior notice is required. 19 Accordingly, renewal decisions for November 1, 2011 had to be made by 20 October 31, 2009.
21 The level of Union TBO capacity is also considered in the annual planning process, 22 through which TransCanada takes into account a number of factors, including its 23 firm contract levels on the Mainline, its forecast of flows along the paths utilizing 24 the Union system, the level of operational flexibility required, the lowest-cost 25 means of meeting firm requirements, and the impact to Mainline revenues and tolls.
Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part E: Mainline 2012-2013 Revenue Requirement Attachment 12.1: Revenue Requirement Tab 2 – Transportation by Others Page 21 of 32
1 One factor impacting Union TBO renewal decisions is the difference in renewal 2 provisions in the Union and Mainline tariffs. Union requires a minimum of 24 3 months notice for a one year renewal of capacity. In contrast, the Mainline Tariff 4 allows shippers to renew firm contracts with only six months notice. TransCanada 5 must therefore evaluate Union capacity renewal decisions 18 months prior to 6 knowing Mainline shipper renewal decisions. In this context, TransCanada must 7 ensure it retains sufficient capacity to meet Mainline shipper requirements should 8 they elect to renew their contracts, which is their unilateral right to do. Should 9 Mainline shippers decide not to renew volumes for which Union capacity was 10 required, it may take from 18 to 24 months before TransCanada can relinquish a 11 corresponding amount of service on the Union system.
12 As a result of de-contracting and substantial changes in flows at Dawn, exchange 13 can no longer be relied upon to move gas between the Union Dawn facilities and 14 TransCanada’s interconnecting receipt point at Dawn (Union Dawn Receipt Point). 15 Effective November 1, 2010, TransCanada entered into a new C1 (Dawn to Dawn) 16 service agreement for 500,000 GJ/day of capacity with Union on behalf of Mainline 17 shippers, which was required to move gas to the Union Dawn Receipt Point in order 18 to prevent interruptions to the firm services requirements at the Union Dawn 19 Receipt Point. Combined with GLGT capacity from St. Clair to Emerson and 20 transportation on the NOL, the C1 (Dawn to Dawn) service enables TransCanada to 21 meet firm requirements with receipt at the Union Dawn Receipt Point while 22 optimizing the use of existing infrastructure.
23 Another change in the use of Union TBO capacity has been the change in flows to 24 Niagara and Chippawa. Historically, TransCanada used M12 (Dawn to Kirkwall) 25 and C1 (Parkway to Kirkwall) services to meet requirements to these locations. 26 With the recent reduction in flow and possible reversal associated with receipts at Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part E: Mainline 2012-2013 Revenue Requirement Attachment 12.1: Revenue Requirement Tab 2 – Transportation by Others Page 22 of 32
1 Niagara Falls, TransCanada’s requirements for M12 (Dawn to Kirkwall) and C1 2 (Parkway to Kirkwall) services have been reduced. However, new requirements for 3 capacity for Union TBO from Kirkwall to Parkway have emerged. In response to 4 these changing requirements, TransCanada converted M12 (Dawn to Parkway) and 5 C1 (Parkway to Kirkwall) into M12X contracts commencing September 1, 2011. 6 M12X is a new bi-directional service Union developed to provide firm 7 transportation between the points Dawn, Kirkwall and Parkway on its system. 8 TransCanada also entered into a new M12 (Kirkwall to Parkway) service agreement 9 that will commence November 1, 2012.
10 In addition to firm M12 and C1 service agreements, TransCanada also uses 11 interruptible and overrun service on the Union system from time to time when the 12 use of these services results in the lowest overall operating cost for the Mainline, 13 and where the use of these services allows the Mainline to generate additional 14 discretionary revenue.
15 A discussion of TransCanada’s capacity and cost management of the Union system 16 TBO is provided in Section 4.1. The contracting profiles on Union during the Base, 17 Forecast and Test Years are discussed in Sections 4.2 through 4.5.
4.1 Union System TBO Capacity and Cost Management
18 TransCanada believes it has been prudent in entering into Union TBO contracts 19 over time and in its recent contracting decisions. TransCanada has appropriately 20 adjusted contract profiles over time to reflect changes in Mainline contracting 21 profiles and capacity requirements. Figure 5 summarizes the contract levels on the 22 Union system and associated demand charges between 2004 and 2013.
Attachment A7 Tab 33 Part A – Review and Variance Application RH-003-2011 Transcript, Vol 23, lines 25608-25611
NATIONAL ENERGY BOARD OFFICE NATIONAL DE L’ÉNERGIE
Hearing Order RH-003-2011 Ordonnance d’audience RH-003-2011
TransCanada PipeLines Limited (TransCanada), NOVA Gas Transmission Ltd. (NGTL) and Foothills Pipe Lines Ltd. (Foothills) Application dated 1 September 2011 for Approval of the Business and Services Restructuring Proposal and Mainline Final Tolls for 2012 and 2013
TransCanada PipeLines Limited (TransCanada), NOVA Gas Transmission Ltd. (NGTL) et Foothills Pipe Lines Ltd. (Foothills) Demande datée du 1er septembre 2011 visant l’approbation de la proposition de restructuration d’entreprise et de services ainsi que des droits définitifs exigibles sur le réseau principal en 2012 et 2013
VOLUME 23
Hearing held at L’audience tenue à
Novotel Toronto Centre 45 The Esplanade Toronto, Ontario
July 11, 2012 Le 11 juillet 2012
International Reporting Inc. Ottawa, Ontario (613) 748-6043
TransCanada-NOVA-Foothills Panel 5 Examination by Mr. Mondrow at how that would shake out in the marketplace, and that’s a very complex alternative world to evaluate.
25607. So no, I certainly can’t accept your proposition, but again, to me, you’re fundamentally changing the nature of the services that TransCanada provides by taking that capacity out of its control and putting it into the control of others.
25608. MR. POHLOD: I would actually even go further and say that it would introduce inefficiencies into the market. And let me give you one example. It wasn’t that long ago that TransCanada contracted for a Dawn to Dawn service with Union, which is effectively, you know, a small TBO. And TransCanada had obligations from Dawn on the TransCanada system to delivery points on the TransCanada system.
25609. The option existed at that time of having the individual shippers contract with Union to enable those individual shippers to get gas from Union Dawn to TransCanada Dawn so that TransCanada would be in a position to receive the gas and transport it to its delivery points.
25610. If -- there were numerous discussions with shippers, and TransCanada initially was even suggesting that the approach there or the best approach might be to have shippers hold those contracts directly, and TransCanada was urged -- more than urged -- shippers, in general, pleaded or demanded that TransCanada hold that capacity because in having TransCanada hold that capacity we could use the integrated system to more effectively or efficiently provide for those deliveries.
25611. If each individual shipper had to hold that capacity they would have to hold, probably in aggregate, substantially more capacity because they would each have to hold the volume that would be required to affect their individual deliveries. Whereas, TransCanada could look at it from an aggregate perspective and hold less of that service because it had other options that it could rely on as part of the integrated system to affect those deliveries.
25612. MR. MONDROW: It’s hard to wean a market from a paternalistic approach.
25613. Let me line my ducks back up and we’ll come back at this perhaps in a bit more order and a bit more clarity with a future panel. But I appreciate your evidence on that, Mr. Pohlod. Thank you.
Transcript Hearing Order RH-003-2011 Attachment A7 Tab 34 Part A – Review and Variance Application National Energy Board Reasons for Decision GH-2-87, TransCanada PipeLines Limited, Applications for Facilities and Approval of Toll Methodology and Related Tariff Matters, July 1988. CANADA
NATIONAL ENERGY BOARD
Reasons for Decision
TransCanada PipeLines Limited
Applications for Facilities and Approval of Toll Methodology and Related Tariff Matters
GH-2-87
July 1988 vice provided (i.e., FS or IS) and not to the busi· 8.3 Delivery Pressure Toll ness motives either of the shipper or the carrier nor to circumstances and conditions created by contract (such as the terms of gas sales or pur In its 9 June 1987 application, as amended, chase contracts), or by government policy (for ex· TransCanada proposed to install facilities to pro ample, pre· and post;.. 31 October 1985). vide at Niagara Falls and Iroquois a minimum delivery pressure in excess of that specified in its To the extent that the new facilities form part of General Terms and Conditions. the integrated system, the Board agrees with those parties to the hearing who submitted that According to TransCanada, the prOV1S1on of a section 52 precludes the adoption of an incremen guaranteed pressure higher than that stipulated tal toll methodology. Each of the alternate and in the General Terms and Conditions is a service the incremental methodologies would afford dif which is distinct and different from the other ferent, segregated treatment to new facilities and transmission services rendered on its system. cost of service components required to deliver Accordingly, TransCanada proposed the imposi all, or a portion of, the incremental volumes. tion of an incremental delivery pressure charge This would result in different tolls being paid for at Iroquois. the same service to the same zone, and even to the same delivery point, and would, in the Board's TransCanada took the position that the incre view, violate section 52 of the Act. To adopt, for mental delivery pressure at Niagara Falls example, the alternative incremental approach should be "grandfathered", even though the con would inescapably result in FS tolls charged at tractual obligation to provide incremental pres different rates to different shippers in respect of sure on a firm basis would not commence until traffic of the same description moving over the 1 November 1988. It argued that since the Board same route under substantially similar circum had approved, pursuant to section 35(2) of the stances and conditions; such a situation is spe National Energy Board Part VI Regulations, an cifically prohibited by section 52. amendment to the Boundary contract which spec ified the incremental pressure obligation at A finding, in the circumstances of this case, that Niagara Falls, it would be consistent for the the integrated nature of TransCanada precludes Board to grandfather such obligation. the adoption of other than a rolled-in methodolo gy does not, in the Board's view, necessarily Noting the different toll treatments of the costs of mean that all new facility additions must be providing additional pressure at Iroquois, treated in a similar fashion. When identifiable Niagara Falls and other delivery points, the facilities which do not increase the throughput Board decided to review delivery pressure tolls as capacity on the integrated system are installed to a generic issue. Accordingly, the List of Issues provide a custom service to a specific user or was amended to include the following: group of users, then such discrete facilities might not form part of the integrated system. In such "IV-4 The question of whether a toll. cases, these facilities can, in the Board's view, be rather than a surcharge which the subject of a separate toll, calculated on the ba should be credited to sis of either a rolled-in or incremental methodol TransCanada's cost of service, ogy; this would not constitute a contravention of should be set to recover the costs of section 52 of the Act. any existing or proposed facilities on the TransCanada System which are required to supply natu· Decision ral gas. at existing or proposed de livery points, at a minimum deliuery pressure higher than that Except where set out in Section 8.3 of these specified in the General Terms Reason., ,,11 costs of all those facilities ei and Conditions. Also, the appro ther approved under section 44 or exempt.. ed under section 49 of the Act, in this priate methodology to determine proceeding, will be rolled-in to the the toll or surcharge." TransCanada rate base_
73 TransCanada's General Terms and Conditions specify that the minimum pressure shall he not less. than a gauge pressure of 2800 kPa (400 psig). TransCanada has an obligation to deliver gas at TransCanada testified that it is contractually ob 4500 kPa (650 psig) at Sarnia and Dawn. Since ligated to provide pressure in excess of 2800 kPa at TransCanada's Dawn Extension consists of only eleven locations, namely, Emerson, Sudbury, line pipe, this pressure originates from compres Dawn, Sarnia, St. Lazare, Dauphin, Spruce, sion facilities installed on the Great Lakes sys Thunder Bay, Timmins, Kirkland Lake and tem. In theory, TransCanada could have Lisgar. TransCanada incurs incremental costs initially installed a smaller size line had its con at the following five locations: Emerson, tractual obligation been to guarantee only Sudhury, Dawn, Sarnia and St. Lazare (see 2800 kPa (400 psig). However, increased require Figure 8.1). ments subsequent to construction would have ne cessitated compression or loop. Therefore, TransCanada could not identifY the theoretical Emerson facilities modifications necessary to maintain the higher delivery pressure at Samia and Dawn. At Emerson, Manitoba, TransCanada has a con tractual obligation to provide gas to Midwestern and Great Lakes at 5171 kPa (750 psig). Since TransCanada first began to provide a delivery pressure higher than 2800 kPa (400 psig) at TransCanada is contractually obligated to pro Emerson, facilities have been added to meet in vide a minimum delivery pressure of 2800 kPa creased volume requirements while maintaining (400 psig) at the ultimate delivery points on the Or increasing the delivery pressure. Therefore, TQM system. As there are no compression facili TransCanada was not able to separate the facili ties on the TQM system, TransCanada must pro ties added to increase the delivery pressure from vide a pressure at St. Lazare which is sufficiently those added to provide increased deliveries. high to meet these obligations, Although a mini mum pressure at St. Lazare is not specified in the ,c" Emerson is the only location where TransCanada contract, evidence indicated that a pressure in the recovers a revenue from the sale of delivery pres range of 4200 kPa (6lO psig) is satisfactory. sure. The delivery pressure charge currently in TransCanada could not identify the specific fa place is a result of an estimate of required facili cilities and associated costs required to provide ties based on market requirements during the the necessary pressure to TQM. 1975-76 to 1979-80 contract years, as forecasted by TransCanada in 1974. Therefore, the charge at TQM's transportation costs are incorporated Emerson does not reflect the current cost of pro into TransCanada's revenue requirement. viding the delivery pressure service. Therefore, any charges for additional pressure to meet TQM's delivery pressure requirements would, in effect, be a transportation cost to Sudbury TransCanada and rolled into TransCanada's cost of service. The Sudbury sales meter station is located at North Bay adjacent to compressor station 116. TransCanada has an obligation to deliver gas to Niagara Falls ICG Ontario at that station at not less than 6200 kPa (900 psig). As the prevailing pressure at TransCanada has been providing pressure at the suction side of the station is less than 6200 kPa, Niagara in excess of 2800 kPa (400 psig) since TransCanada makes the deliveries from the dis 1980 on a best efforts basis. Pursuant to the charge side. TransCanada did not quantify pre Boundary Phase II gas purchase agreement which cisely the incremental cost of compressing the was executed on 14 September 1987, TransCanada Sudbury volumes at station 116 but estimated that will have a firm obligation to deliver gas at it was in the range of$40,OOO per year. Niagara Falls at 4826 kPa (700 psig) once facili
74 Figure 8.1 Locations Where TransCanada is Contractually Required to Provide Pressure in Excess of 2800 kPa
/ / \ / \ / Ontario \ I Queoec \ Manitoba \ i , \ \ , \ \ \ \
?-~?-~ \ U , ~ ~\~'''''0?'i'- Dauphin i -' , \ Spruce J \ - ~\E~;son Canada '- _.',/ r·, ...... u.s A " ~'eet ...... --...... --l.ltlrelt
Legend
• Compressor Station
TCPL Pipeline
Provision of Additional Delivery Pressure
0'1 ties are in place to transport the last 0.071 106m3/d through a demand charge which would be based (2.5 MMcfd) increment of the Boundary exports upon contracted volumes. All variable costs pursuant to Licence GL-83. This is scheduled to would be recovered through a commodity charge. occur by 1 November 1988. TransCanada indi cated that the requirement for a higher delivery The demand charge would recover the fixed oper pressure at Niagara Falls is due to capability re ating and maintenance expenses, return, depre strictions downstream on the Tennessee pipeline ciation, and taxes associated with the system. It estimated that 6.8 km of the applied-for incremental facilities. 914-mm O.D. Niagara Line loop was required to provide the higher delivery pressure. The commodity charge would recover the cost of incremental fuel consumed to increase the pres sure to the requested level. TransCanada pro Iroquois posed to cost the fuel at the average price of natural gas at the Alberta border without including the toll TransCanada proposed to construct facilities at for moving that fuel to the point of consumption. It Iroquois to guarantee a delivery pressure of submitted that costing the fuel at the Alberta bor 9928 kPa (1440 psig). The additional facilities der would be consistent with the way in which fuel necessary to provide this pressure were identified is costed for the purpose of determining transpor as compressor station 1401 and 4.5 km of heavy tation tolls. wall pipe on the Iroquois Extension. TransCanada proposed to modify the existing one-part pressure charge in place at Emerson. Base Pressure for tlu! Calculation ofDelivery Currently the charge is applied to volumes actual Pressure Tolls ly received. However, in providing the pressure, TransCanada incurs certain fixed costs which TransCanada testified that the appropriate costs to are unrelated to the volumes taken by Great Lakes be recovered through a delivery pressure toll are and Midwestern. These fixed costs are recovered the costs that are incurred in raising the pipeline from all TransCanada toll payers in the event that pressure from the minimum level required by the Midwestern and Great Lakes reduce their takes. safe, effective and efficient operation of the pipe Also, a one-part charge requires TransCanada's line to the requested level. It indicated that oper shareholders to bear the risk of under recovery if ating its compressor stations to discharge gas at Great Lakes and Midwestern take less gas than the MAOP resulted in optimum efficiency. In forecasted at the time that tolls are established. view of the range of compression ratios (the ratio For these reasons, 'fransCanada submitted that of discharge pressure over suction pressure at a the existing Emerson pressure charge should be compressor station) that prevail acrosS the pipe made a two-part toll. line system, suction pressures do not fall below 4480 kPa (650 psig) during normal operation but TransCanada proposed that the revenue from the may drop as low as 4000 kPa (580 psig) in the pressure charges at Emerson and Iroquoi s be event ofthe loss of an upstream compressor unit. credited to its cost of service under "Other Operating Income" prior to cost allocation and toll design. This is consistent with the current Toll Methodology treatment of the revenue from the Emerson charge. 'fransCanada testified that a surcharge for the provision of incremental pressure is a toll as de TransCanada argued that only those who request fined in section 2 of the Act. In its view, the words the incremental delivery pressure service should "toll" and "surcharge" could be used pay the incremental toll. interchangeably.
TransCanada proposed that a two-part toll, com Views oflnterverwrs posed of a demand and a commodity component, be set at Iroquois to recover the incremental costs The CPA did not take a position on the generic is associated with the provision of additional pres sue of delivery pressure tolls. However, it submit sure. All the fixed costs would be recovered ted that, if the Board certificates compressor 76 station 1401 on the Iroquois Extension, the owning Vermont Gas supported Champlain's sub and operating costs of the station should be the missions. subject of a pressure charge. ProGas submitted that the Board's decision on de IPAC took the position that the redpient ofincre livery pressure charges must be consistent at all mental pressure should not be necessarily delivery points in order to prevent discrimina obliged to pay a charge. According to IPAC, tion. It suggested that the best manner to ensure whether a purchaser at a given receipt point on the against discrimination is to remove all pressure TransCanada system should be obliged to pay a charges on the TransCanada system. pressure charge depends to a very considerable degree on wh ether that party requested the higher Consumers argued that the provision of pressure pressure. higher than that required by the tariff and higher than the pressure that would otherwise prevail at ANE argued that the costs of providing incremen or near the delivery point is a custom service that tal pressure should be rolled-in in order to pre does not provide any system-wide benefits. vent inconsistent and discriminatory treatment. Accordingly, the users of such custom service It submitted that if a delivery pressure charge is should pay the resultant owning and operating levied at Iroquois then, by virtue of Part IV of the costs. According to Consumers, a pressure charge Act, every party receiving incremental delivery should be levied at Niagara Falls, Emerson and pressure at other delivery points should be Iroquois and should be designed on a demand! charged on the same basis and not only at loca commodity basis so that the fixed costs would be tions where the costs are readily identifiable. recovered regardless of the degree of use of the According to ANE, the level of pressure requested service. may affect the quantum of the charge but should not affect whether the charge itself is imposed. GMi stated that a delivery pressure charge should ANE stated that the project participants would be established to cover the difference in costs be have to negotiate the manner in which a delivery tween the delivery of gas at the level requested pressure toll levied at Iroquois would be borne. and the level necessary for normal operation. It suggested that, for deliveries to a transmission Boundary supported rolling-in the cost of provid system, a minimum pressure of 4480 kPa ing delivery pressure in excess of that specified (650 psig) represented a suitable operational in the General Terms and Conditions. It submit leveL ted that, should the Board choose to set a toll or charge for the provision of higher than normal KannGaz submitted that there should be no extra delivery pressures, all parties receiving this ser charge if the minimum delivery pressure sup vice should pay for it on the same basis. plied to a downstream system is not greater than the minimum normal operating pressure on the Champlain did not object in principle to the impo upstream system. It supported the imposition of a sition of a separate pressure charge for the provi~ pressure charge at Iroquois since the design oper sion of delivery pressure at a higher than normal ating pressure of the IGTS pipeline is higher than operating pressure. It argued that a pressure of that of the TransCanada pipeline. 4482 kPa (650 psig) should be considered as the floor for pressure charges between transmission OSP opposed the establishment of an incremental companies since evidence indicated this was the pressure charge at export points since it may raise minimum pressure at the suction side of questions of discrimination in the United States. TransCanada'5 compressors under normal oper It noted that Great Lakes provides TransCanada ations. Champlain also suggested that the tolls with gas at a minimum of 5000 kPa (725 psig) at for the service should be included in St. Clair without levying a pressure charge. It TransCanada's tariff and that the conditions un argued th at the imposition of a new delivery pres· der which excess delivery pressure is offered sure charge, unless it were included as part of the should be in the General Terms and Conditions TransCanada demand charge and therefore had rather than in individual contracts. no effect on the border price, would result in Con
71 siderable delays and uncertainty since it would using and benefiting from this service should be necessitate renegotiation and approval of all of required to bear the incremental costs in order to the contracts associated with the OSP project. ensure that undue cross-subsidization by other tollpayers does not occur. Therefore, to ensure Tennessee supported TransCanada's position that only those using and henefiting from the ser that no delivery pressure charge should be levied vice pay, a separate and incremental tolling ap for the minimum pressure of 4826 kPa (700 psig) proach is necessary. to be provided at Niagara Falls commencing 1 November 1988. In Tennessee's view, delivery pressures at this level are normal at the interface (i) Base Pressure of two high pressure transmission systems and reflect sound engineering economics. The current General Terms and Conditions of TransCanada's tariff specifY a minimum deliv Midwestern stated that it was prepared to abide by ery pressure of 2800 kPa (400 psig). This mini the agreement currently in place at Emerson, mum does not take into account the operational which provides for a one-part commodity pressure requirement of maintaining TransCanada's charge. However, should there be changes to the pipeline pressure above 4480 kPa (650 psig) under pressure charge in light of the Board having normal operations and above 4000 kPa (580 psig) raised the question, it was Midwestern's submis under loss-of-unit conditions. The Board is of the sion that there should be no separate charge view that all shippers using the TransCanada for pressure at Emerson. According to system are entitled to a minimum delivery pres Midwestern, the delivery pressure at Emerson is sure not less than that which TransCanada must normal in light of the integrated nature of ensure for the safe, effective and efficient opera the TransCanada/Great Lakes system. tion ofthe integrated system as a whole. However, Furthermore, the evolution of facilities to deliver in certain cases such as when the shipper receives gas at Emerson is such that the allocation ofcosts gas in a low pressure system, a delivery pressure to the provision ofpressure would be arbitrary. of that magnitude is not required. In these cases TransCanada and the customers may agree to a Ontario submitted that a pressure charge for the lower guaranteed minimum pressure provision of excess delivery pressure is appropri ate. The charge should be designed to recover the estimated annual owning and operating costs of Decision providing delivery pressure above the prevailing operating pressure of the line on the Canadian TransCanada is directed to amend section side ofthe export point. IX of its General Term.. and Conditions to provide that the II1inimum pressure at each delivery point shall be not Ie... than a gauge pressure of 4000 kPa (580 psig) unless a Views oftheBoard lesser minimum pressure is agreed to by the parti.... As indicated in Section 6.4, commencing on page 48 of these Reasons, the provision of additional delivery pressure is a separate and distinct trans (ii) DeliveryPressure Toll Methodology portation service. Only a limited number of ship pers require additional pressure at the various TransCanada proposes to treat the costs ofprovid delivery points and the service is in many re ing incremental pressure in three different spects unique at each such point. The facilities ways. At several points, where TransCanada is which are, or are deemed to be, necessary to pro required to provide incremental pressure, it pro vide the service can be separately identified and poses to "grandfather" the obligation and not re stated apart from the integrated rate base. In this quire the shippers using or benefiting from the case, the application of section 52 of the Act is not service to pay the incremental costs. At Emerson, determinative. The situation would allow either the current one-part charge that is in effect and a rolled-in or incremental approach to be contem proposed to be continued, albeit under a two-part plated. However, in accordance with the princi formula, is contractually based and does not re ples of cost causation and "user-pay", the shippers flect the costs of providing the service. At
78 Iroquois, and presumably any other new delivery Similarly, the prOVISIOn of delivery pressure point, TransCanada proposes to establish a two would require that the pipeline system carry from part toll. The Board finds that, were the Alberta border an incremental amount of gas TransCanada to implement the three different that would be consumed at the last compressor sta toll treatments that it proposes for the cost of pro tion(s) upstream of the shipper's delivery point, viding incremental delivery pressure, the result By adding the FS toll to the fuel costs at the Alberta ing tolls would be unjustly discriminatory and border, the incremental costs of both the facilities therefore contrary to section 55 ofthe Act, and the fuel required to move that incremental fuel volume would be allocated to the shippers us Certain of the costs of providing incremental de ing the delivery pressure service, In the Board's livery pressure do not vary with throughput, In view, this would be consistent with the methodolo order to ensure that these fixed costs are properly gy currently in place for the FS toll and with prin recovered from the shippers which use and benefit ciples of "user pay" and cost causation, from this service, the incremental delivery pres Therefore, the commodity component of the deliv sure toll should be a two-part tolL The demand ery pressure toll should recover: component should recover the fixed owning and operating costs of the facilities that are, or are (i) the costs of the compressor fuel used to ele deemed to be, necessary to raise the pressure vate the pressure of the delivered gas to the from: requested level; and
(a) the higher of: (ii) the FS transportation toll at 100% load fac tor to move that fuel from the Alberta bor (1) 4000 kPa (580 psig); or der to the zone in which it is consumed,
(2) the prevailing line pressure that Consistent with the toll design methodology used would be required at all times (in for other services, shippers on TransCanada re cluding the loss-of-unit conditions) questing a delivery pressure service should have in the absence of the incremental the option of providing their own fuel. Such ship pressure obligation; pers would pay, as part of the commodity charge to: for the delivery pressure service, the appropriate FS toll for shipper-provided fuel. (b) the requested guaranteed minimum pressure. The Board does not accept TransCanada's propo sal that only the specific parties that initially re TransCanada's pipeline system is designed to quested incremental pressure should pay an transport its shippers' volumes together with the incremental pressure toll at a given delivery fuel consumed along the system which is neces point whereas other parties receiving gas at the sary to transport these volumes, TransCanada same delivery point would not be required to pay incurs fuel-related costs as follows: any incremental charges. In the Board's view, the pressure at any delivery point where the gas is 0) the fixed cost of the facilities required to co-mingled both upstream and downstream can move the fuel volumes; and not be seen as being required by only one particu lar shipper, The costs of providing incremental (ii) the variable costs associated with the fuel pressure are related to the total volume delivered itself and its transportation. at the deli very point, Charging only the parties that request the service could result in two parties Under current toll-making methodology for FS, receiving the same service at the same point pay the system's total fuel-related costs are allocated ing different tolls, This situation would be con on a volume-distance basis, Therefore, a shipper trary to section 52 of the Act. Accordingly, the pays, as part of the toll, the allocated portion of the Board finds that all shippers using or benefiting fuel-related costs incurred in moving gas to the from incremental delivery pressure at a specific ultimate point of delivery, delivery point should be charged the appropriate toll, Dooision TransCanada also addressed the burden of proof created by section 56 of the Act which reads as The Board direct. Tran.Canada to develop follows: tolls, in accordance with the methodology set out above, to recover the incremental "Where it is shown that a company makes costs incurred at each delivery point on the TransCanada system where it is obligated any discrimination in tol/s, service or fa by contract to provide incremental pres· cilities against any person or locality, the sure. TransCanada shall record the reve burden of proving that the discrimination nues from these tolls in account 579, is not unju.st lies upon the company." Miscellaneous Operating Revenue, in ac cordance with the Board'frl Gas Pipeline Stating that section 56 applies to a pipeline compa Uniform Accounting Regulations. The Board ny charging or proposing to charge a discrimina· will review the proposed toUs at the RH·l· tory toll, TransCanada submitted that an 88 proceedings. intervenor proposing a discriminatory toll, can be subject to no less a burden than that created by section 56. TransCanada's views were supported 8.4 Burden of Proof by the APMC.
In their submissions on the appropriate tolling ANR disagreed that the section 56 burden applies methodology with respect to the applied·for facili to intervenors. It stated that TransCanada's posi ties, several parties addressed the concept of bur tion is premised on an invalid reading of section den of proof. The Board therefore considers it 56. appropriate to deal with the matter in this chapter.
Consumers stated that in the context of adminis Views ortM Boord trative proceedings, the burden of proof is typical ly cast upon the applicant. When the applicant "Burden of proof' is a fundamental concept in has made a prima facie case, its burden has been proceedings before a Court. Ifa party is unable to .... discharged and the burden shifts to those parties satisf'y the burden cast upon it, the Court has no op opposed to the applicant's position. However, in tion but to deny the relief sought by that party, the specific situation wherein an intervenor pro thereby ruling in favour of that party's poses a change in the status quo of something that adversary. the applicant does not propose to alter, the initial burden of proof lies with such intervenor. Unlike a Court, the Board, in arriving at its deci Consumers therefore concluded that a proponent sions does not focus on the specific interests oftwo of change to the existing rolled-in toll methodolo adversarial parties but must focus its attention on gy bears the burden of proof. the wider public interest. It is therefore inappro priate to designate a burden of proof with respect to Consumers position was opposed by no-one and each of the issues before the Board in a public was supported by the APMC and TransCanada. hearing. Were the Board to decide each issue on TransCanada qualified its support by stating that the basis of the strict mles pertaining to burden of there are certain situations wherein no party proof, it would, in a situation wherein an appli bears the burden of proof. An example of such a cant and an intervenor take opposite positions on situation, cited by TransCanada, is Issue IlI-3 of a particular issue and provide equally unpersua these proceedings which reads as follows: sive evidence, be nonetheless obligated to adopt the position ofthe intervenor. "Is it in the public interest to provide new facilities for presently uncontracted Although the Board does not consider it appropri Canadian market demand which is fore ate to establish a burden of proof with respect to casted to exist in contract years commenc each issue in a public hearing, it nonetheless con ing November 1988 and November 1989?" siders that an applicant has the burden of estab lishing on the balance of probability that the relief In TransCanada's opinion such an issue is akin sought in its application should be granted. For to an enquiry by the Board and, as such, no bur example, with respect to its original 9 June 1987 den of proof is therehy created. Attachment A7 Tab 35 Part A – Review and Variance Application Exhibit B-5-10, RH-003-2011, Section 7.0: Toll Design Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part C: Business and Services Restructuring Proposal Section 7.0: Toll Design Page 31 of 49 Revised October 31, 2011
1 As recently as the RH-1-2007 Gros Cacouna Receipt Point Application, TransCanada 2 supported rolled-in treatment of TQM TBO costs. However, current circumstances 3 are fundamentally different than those expected in that proceeding. At that time, new 4 facilities would have connected large quantities of new supply to serve multiple 5 Mainline markets, similar to the manner in which the GLGT and Union capacity is 6 utilized by TransCanada to provide Mainline service today. This justified a “rolled- 7 in” approach. However, without the new LNG supply, the current TQM TBO is only 8 serving a subset of shippers’ markets at the far eastern end of the Mainline.
9 The proposed changes are responsive to the current business environment and will 10 improve cost accountability and better reflect the principle of user pay.
11 John J. Reed of Concentric assesses in his evidence in Appendix C4 the proposal to 12 recover the cost of TQM TBO solely from the shippers utilizing the TQM system. 13 Mr. Reed determines that based on the existing Mainline circumstances, the TQM 14 TBO is sufficiently different from other TBO capacity to justify a different tolling 15 treatment. The proposal is viewed as consistent with the accepted principles of cost- 16 based/user-pay and economic efficiency. Mr. Reed also concludes that more 17 precisely reflecting cost causation will improve the price signals for Mainline 18 capacity and improve the competitive position of the Mainline.
7.5 Delivery Pressure Tolls
19 The sale of delivery pressure is a miscellaneous service designed to recover, on an 20 incremental basis, costs associated with guaranteeing a minimum delivery pressure 21 higher than the system minimum pressure specified in the Tariff. Currently, delivery 22 pressure tolls apply at the following locations: Emerson 1, Emerson 2, Dawn, 23 Niagara, Iroquois, Chippawa, and East Hereford. Delivery pressure tolls and 24 associated fuel are intended to recover the facilities and operating costs associated 25 with providing the additional pressure at these locations. Delivery pressure tolls and Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part C: Business and Services Restructuring Proposal Section 7.0: Toll Design Page 32 of 49 Revised October 31, 2011
1 fuel are currently charged on an incremental basis in addition to the regular 2 transportation toll and fuel.
3 In the GH-2-87 proceeding, the Board decided that those shippers using and 4 benefiting from the provision of incremental delivery pressure should pay a separate 5 delivery pressure toll based on the incremental costs of providing the service.10 The 6 current delivery pressure tolling methodology was subsequently approved in Decision 7 RH-1-88.11
8 TransCanada proposes to maintain incremental tolling for delivery pressure service at 9 all locations currently subject to a delivery pressure toll. However, due to changing 10 flow levels at some of these locations, TransCanada proposes to implement a system- 11 wide average delivery pressure toll and fuel ratio that would apply uniformly at all 12 applicable locations, as opposed to location-specific delivery pressure tolls and fuel. 13 This approach will reduce the tolls at delivery points experiencing significant declines 14 in throughput and provide for more stable delivery pressure tolls and fuel at all 15 applicable locations.
16 Currently, delivery pressure tolls are calculated on the basis of firm contract level, 17 with any revenues gained from discretionary services to a delivery point that is 18 subject to a delivery pressure toll being captured in the Mainline revenue deferral 19 account for future disposition. TransCanada proposes to use both firm contracts and a 20 forecast of discretionary services in the allocation units used to calculate the delivery 21 pressure toll. Variances between forecast and actual costs and revenues associated 22 with delivery pressure will be included in the determination of the delivery pressure 23 tolls in subsequent years. This approach is consistent with the manner in which 24 overall Mainline tolls are calculated.
10 GH-2-87 Decision, pages 73-80. 11 RH-1-88 Decision, PDF pages 100-102. Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part C: Business and Services Restructuring Proposal Section 7.0: Toll Design Page 33 of 49 Revised October 31, 2011
1 By implementing this change, 2012 will be a transition year in which both a deferral 2 from all 2011 discretionary services and a forecast of revenue from discretionary 3 services for 2012 will be reflected in the delivery pressure calculations. This will 4 result in 2012 delivery pressure tolls being somewhat lower than would be expected 5 in subsequent years.
6 Impact and Justification
7 TransCanada’s proposal to modify the calculation of delivery pressure tolls is 8 intended to respond to facts and circumstances associated with current usage of the 9 Mainline. Under current flows on the system, certain locations subject to delivery 10 pressure tolls have experienced significant throughput reductions, which have caused 11 increases in the level of the applicable delivery pressure tolls. For example, the daily 12 equivalent delivery pressure toll applicable to the East Hereford export point has 13 increased from 0.06 $/GJ in 2007 to 0.21 $/GJ in 2011. The current delivery pressure 14 methodology can therefore act as a disincentive to use the Mainline at certain 15 locations.
16 The proposal is expected to significantly reduce the delivery pressure toll at delivery 17 pressure locations currently experiencing lower flows, while causing minor increases 18 in the delivery pressure toll at other delivery pressure locations. Table 7-6 compares 19 the delivery pressure tolls and fuel ratios that would have applied in 2011 under the 20 existing and proposed methodology. For comparison purposes, the proposed method 21 reflects the 2011 forecast of discretionary flows, but excludes the deferral balances 22 from the previous year. This approach provides a more meaningful comparison to 23 assess the reasonableness of the proposal, as it avoids a double-counting effect of 24 discretionary revenues on a forecast and deferral basis that will only occur in 2012. Business and Services Restructuring and Mainline 2012-2013 Tolls Application Part C: Business and Services Restructuring Proposal Section 7.0: Toll Design Page 34 of 49 Revised October 31, 2011
Table 7-6: Impact of Proposed Change to Delivery Pressure Tolls and Fuel - Based on 2011 Applied-for Annualized Final Tolls Current Current Proposed Proposed Method Method Method Method Toll Fuel Location Toll Fuel Ratio Toll Fuel Ratio Difference Difference ($/GJ) (%) ($/GJ) (%) ($/GJ) (%) Emerson 1 0.0026 0.14 0.0106 0.24 0.0080 0.10 Emerson 2 0.0041 0.14 0.0106 0.24 0.0065 0.10 Dawn* 0.0016 0.00 0.0106 0.24 0.0090 0.24 Niagara 0.0176 0.00 0.0106 0.24 -0.0070 0.24 Iroquois 0.0286 0.69 0.0106 0.24 -0.0180 -0.45 Chippawa 0.0318 1.34 0.0106 0.24 -0.0212 -1.10 East 0.2152 0.00 0.0106 0.24 -0.2046 0.24 Hereford *Dawn includes Union SWDA, Enbridge SWDA and Dawn Export.
1 The proposal to average the delivery pressure tolls will have no significant impact on 2 the tolls at non delivery pressure locations.
3 Under the proposed methodology, only those who benefit from incremental delivery 4 pressure will pay for it, although, going forward it would occur in an aggregated 5 fashion. On balance, TransCanada believes that in the current circumstances of the 6 Mainline, the toll stability benefit that would result from the proposed modification 7 outweighs strict adherence to the cost based/user pay principle.
8 In his evidence in Appendix C4, John J. Reed of Concentric addresses the 9 appropriateness of the delivery pressure tolling proposal and concludes that it will 10 continue to be consistent with the cost-based/user-pay principle.
7.6 Toll Design Simplifications
11 TransCanada proposes the following toll design simplifications:
12 • use of the shortest distance of haul for each transportation path, which will be 13 applicable to the determination of tolls and fuel ratios for all services; Attachment A7 Tab 36 Part A – Review and Variance Application National Energy Board Reasons for Decision RH-2-2008, Land Matters Consultation Initiative Stream 3, Pipeline Abandonment – Financial Issues, May 2009.
Reasons for Decision
Land Matters Consultation Initiative Stream 3
RH-2-2008
May 2009
Pipeline Abandonment - Financial Issues
4. Landowners will not be liable for costs of pipeline abandonment.
5. At this time, the use of pooling as a general mechanism for setting aside funds to cover the costs of abandonment is not efficient from a regulatory or economic perspective.
6. Timing of abandonment of a pipeline for the purpose of estimating future abandonment costs should be the shorter of anticipated economic life or physical life.
7. The removal of all large-diameter abandoned pipe from agricultural land is not a prudent or effective approach for the purpose of establishing preliminary abandonment cost estimates.
8. Abandonment costs are a legitimate cost of providing service and are recoverable upon Board approval from users of the system.
9. Funds for abandonment costs should be collected and set aside in a transparent manner.
10. Funds for abandonment costs should not be collected as part of depreciation and should be a separate element of cost of service.
11. Any funds set aside for abandonment must be held in such a manner that they can only be used for the purposes of abandonment and abandonment planning.
12. The Board, as an independent and quasi-judicial tribunal, does not promote the development of tax policies or initiatives.
3.3 Discussion of Key Principles and Considerations
3.3.1 Principles relating to the Board’s General Mandate
In order to have all pipelines regulated by the NEB abandoned safely and effectively, regardless of ownership of the facilities, there must be adequate funds set aside to cover all abandonment activities. In the Panel’s view, pipeline companies are ultimately responsible for the full costs of constructing, operating and abandoning their pipelines. The Board will hold the regulated company responsible for these costs.
There are a number of methods by which the Board could hold a company responsible and seek to ensure that adequate funds are set aside for abandonment. For example, in addition to the Board’s jurisdiction under Part IV of the NEB Act previously discussed, in the Panel’s view, the Board also has a broader mandate within which it may consider funding of future abandonment costs. This consideration may fall within the Board’s consideration of the present and future public convenience and necessity when a company seeks approval for a project under Part III of the NEB Act. It may also fall within the Board’s authority with respect to providing for the protection of property and the environment. As a result, the Panel is of the view that the Board has regulatory authority to ascertain whether there are adequate funds set aside for the
RH-2-2008 33 abandonment of facilities it regulates, and to impose or enact additional regulatory requirements that endeavor to ensure such funding.
While these key principles apply to all companies regulated by the NEB, the details on how each company collects or sets aside funds for abandonment activities may differ. For example, Group 1 and Group 2 companies may have different methodologies for setting aside funds, and certain Group 2 companies may not collect funds from users if they do not have third-party shippers. Should a Group 2 company that does not charge tolls propose a methodology other than collecting future abandonment costs through tolls, the Panel recommends that the Board consider whether the alternative methodology ensures that adequate funds are set aside for abandonment costs and meets the goal of holding the pipeline company responsible for the full costs of abandoning its pipeline system.
The Panel notes Westcoast’s submissions, which are summarized in Chapter 2, on excluding, at a minimum, Westcoast from any regulatory requirements to set aside abandonment funds for its gathering and processing facilities. There was no evidence presented at the hearing that persuaded the Panel that Westcoast, or any other company, would be unable to provide a preliminary estimate of abandonment costs. It is clear that the provision of preliminary estimates requires the use of a number of assumptions, some of which will be refined over time. This may result in adjustments to the estimates and, potentially, the collection methodology. However, the need to use assumptions rather than actual numbers is not sufficient rationale for not embarking on the exercise. In order to assist companies, the Panel recommends that companies use the Base Case assumptions set out in the Framework, discussed below, if companies are not able to determine reasonable pipeline-specific assumptions to calculate their own specific preliminary estimates.
The Panel notes that companies may have different proposals for collection or setting aside of funds. The Panel recommends that the Board remain open to companies submitting different proposals based on the facts of their particular facilities. It is also recommended that the Board exercise its discretion whether to approve or deny such proposals, including proposals regarding the timing of collection or setting aside of funds. The Panel recommends that the discretion be based on pipeline-specific information before the Board, including estimated costs to abandon those particular facilities, rather than estimates that rely extensively on the Base Case assumptions. This will provide the Board with the best information upon which it can make its determination.
3.3.2 Principles relating to Risk
The Board’s regulatory oversight role applies to the entire lifecycle of a pipeline or facility. Using a goal-oriented approach to regulation, the Board defines desired outcomes, but allows companies to decide how best to achieve these outcomes throughout the lifecycle of the pipeline or facility. Companies are accountable for their own performance and are expected to identify and manage risk throughout a facility’s lifecycle.9
9 This approach is more fully described in the Board’s Annual Report 2008, available at http://www.neb-one.gc.ca/clf- nsi/rpblctn/rprt/nnlrprt/nnlrprt-eng.html at pages 5 and 6
34 RH-2-2008
The Panel does not believe that it is practicable for regulated companies to eliminate all risk no matter what the cost, as was submitted by CAPLA. At some point on the continuum of possible risks, a point of diminishing returns is reached, where the cost of trying to eliminate all risk is out of proportion to the incremental benefits that might result. However, the Panel reiterates that one of the goals reflected in the principles of the Framework is that landowners will not be liable for the costs of pipeline abandonment.
The Panel recognizes that currently there may be some risk of unfunded or underfunded abandonment. However, with respect to the risk of unfunded abandonment, no evidence was submitted during the proceeding that persuaded the Panel there were pipeline systems anticipated to be abandoned in the foreseeable future. As a result, it is not necessary for abandonment funds to be set aside immediately; there is time to establish a proper framework. Concerning the risk of underfunded abandonments, the Panel is of the view that over time these risks can largely be mitigated. As discussed in the Framework, there will be appropriate mechanisms in place to review abandonment cost estimates, and the accumulation of funds and growth of funds over time. These regular reviews will also mitigate the over-collection of funds from users, thereby ensuring a responsible approach to funding abandonment. The Panel also recommends that there be appropriate ongoing oversight by the Board of abandonment funding. In addition, the Panel notes that pipeline companies have an incentive to set aside and recover sufficient funds from their users so that they, and their shareholders, are not left with the responsibility for any shortfalls. All of these factors will help mitigate the risks of underfunded or unfunded abandonment.
The concept of pooling was raised during the hearing as a possible mechanism for setting aside abandonment funds or to address residual risk. After considering the views of parties, the Panel finds that the use of pooling, as a general method of setting aside the full costs of abandonment, would not be a prudent regulatory instrument at this time. In addition, using current resources to develop an appropriate pooling mechanism as a method of managing any small residual risks associated with unfunded or underfunded pipelines would not be efficient from a regulatory or economic perspective.
In the Panel’s view, Board and company resources would be better directed to addressing other fundamental aspects, such as determining preliminary estimates and developing appropriate mechanisms to set aside adequate funds for abandonment. The Panel does not consider that there is currently a need to develop a stand-alone pooling mechanism to address either abandonment funding as a whole or residual risk. However, the Panel notes the Board’s broad authority over abandonment funding and recommends that the Board not foreclose the possibility of implementing pooling mechanisms or contingency planning of some sort in the future.
3.3.3 Principles relating to Assumptions
One of the fundamental aspects to be determined by all companies is their preliminary estimates of the amount of funds needed to be set aside now, and on an ongoing basis, to cover the costs of abandonment. The assumed timing of abandonment of a pipeline is critical to this estimate. In the Panel’s view, using a range of reasonable timeframes within which abandonment could occur may be a way to address uncertainties surrounding timing of abandonment, although there are likely other ways to deal with these uncertainties as well. Notwithstanding the various ways
RH-2-2008 35 abandonment timing could be dealt with, in the Panel’s view, based on the evidence heard in the proceeding, economic life should generally be used to determine the timing (or ranges of timing) of abandonment rather than physical life. In the current market environment and given the ability of existing technology to extend physical life, it would be unlikely for physical life of a pipeline to be the determining timing factor. However, to accommodate those cases, the Panel recommends that timing for the purpose of calculating preliminary estimates on the amount of funds needed to be set aside should be based on the shorter of a pipeline’s anticipated economic life or physical life.
Another key aspect critical to calculating preliminary estimates is the method of abandonment. As noted in the September 1985 Background Paper on Negative Salvage Value, there are three basic pipeline abandonment options available. These are removal, abandonment in place with continuing maintenance, and outright abandonment in place. In order to prepare their preliminary estimates of abandonment costs, many pipeline companies indicated that they needed guidance from the Board on the most appropriate abandonment standard to use. Several parties were of the view that it would not be possible to prepare their preliminary estimates until the LMCI Stream 4 process was completed, while CAPLA argued that its default technical assumption should be used for agricultural land.
The Panel recommends that the Board not wait until the Stream 4 process is completed before implementing the Framework discussed below. This Report sets out a number of high-level, goal-oriented principles related to certain technical assumptions to provide guidance to companies. In addition, the Framework is sufficiently robust to allow companies to begin work on their preliminary estimates, either by using the Base Case assumptions or their own pipeline- specific assumptions. The outcomes from LMCI Steam 4 may inform this process and feed into the ongoing processes for review over time, but it is not necessary to wait until the Stream 4 process is completed before any action is taken. The Panel is of the view that the preparation of preliminary estimates and the work planned for Stream 4 can proceed in parallel.
With respect to CAPLA’s default technical assumption, the Panel was not persuaded on the evidence that removal of all large-diameter pipelines from all agricultural land is a necessary assumption. The Panel is of the view that in the absence of case-specific considerations, such as environmental, cost-related or risk-related considerations, mandated use of this assumption is not appropriate. Such a broad and general assumption would be neither prudent nor effective for establishing preliminary estimates of the costs of abandonment.
As a result, the Panel does not recommend use of this assumption as a Base Case assumption. However, it is within companies’ discretion to use this assumption as they consider appropriate in preparing preliminary estimates of abandonment costs. Companies should use assumptions that make sense for the particular circumstances of their systems. The Panel recommends that pipeline companies be required to justify to the Board any assumptions used to calculate pipeline-specific preliminary estimates.
3.3.4 Principles relating to Collecting and Setting Aside Funds
With respect to a pipeline company’s ability to collect funds to cover abandonment costs from its users, the Panel has stated in the key principles that abandonment costs are legitimate costs of
36 RH-2-2008
providing service and are recoverable upon Board approval from users of the system. In order to receive Board approval to collect future costs from users, pipeline companies are to come forward in a timely manner with a proposal for the collection of just and reasonable tolls, of which future abandonment costs will be a component. In each case, the Board will determine whether the funds sought to be collected are appropriately part of just and reasonable tolls for the regulated facility. For those Group 2 companies that do not charge tolls, alternative methods for setting aside abandonment funds must be developed and filed with the Board.
If companies do not submit proposals to collect these future costs from tollpayers or otherwise set aside abandonment funds in a timely manner, the Panel recommends that the Board identify other regulatory requirements that could ensure coverage of abandonment costs. Examples of other options may include the posting of bonds or letters of credit.
In order to meet the goal of ensuring that there are adequate funds to safely and effectively abandon pipelines, it is a fundamental principle that any funds set aside for abandonment must be held in such a manner that they will only be used for the purposes of abandonment and abandonment planning, and will not be available to third parties. To allow otherwise could increase the risk of underfunded or unfunded abandonments. Accordingly, the Panel recommends that all companies develop an appropriate mechanism to set aside funds to meet this principle. During the hearing, a number of possibilities were discussed, including a trust that provides restrictions in its constating documents and setting up restricted access accounts. In their filings to the Board, as further discussed in the Framework, companies may propose any mechanism that, in their opinion, appropriately meets this goal, even if these mechanisms were not discussed during this proceeding.
The tax treatment of the funds collected and set aside for abandonment received considerable attention during the hearing. The Panel notes that parties raised no other proposals, other than changes to the Income Tax Act, that would result in a tax treatment satisfactory to industry parties for these funds. The Panel acknowledges that the tax treatment of abandonment funds will impact the amount of funding required to cover the costs of future abandonment activities.
Some parties suggested that the Board take a lead role in initiating changes to the Income Tax Act. CAPP went further and argued that the Board has a statutory obligation to increase the tax efficiency of collecting and setting aside funds for abandonment. It submitted that this statutory obligation stemmed from the Board’s advisory functions with respect to safety of pipelines, pursuant to Part II of the NEB Act.
What was not clear from CAPP’s argument was how the tax treatment of funds collected affects the safety of pipelines, particularly if the Board mandates collection of abandonment funds regardless of the tax treatment of such funds. Further, the Panel notes that no party, including CAPP, presented evidence that a safety impact is possible or might be realized in the absence of income tax changes. While the tax treatment may affect the willingness of the pipeline industry to collect funds or the amount that may be required to be set aside, based on the evidence presented to the Panel, there is no basis to make a finding that there is a connection between tax treatment of the funds and the safety of the pipelines themselves. Safety of pipelines is dependant upon physical aspects of the pipeline, and is overseen by the Board already through its regulation of the construction, operation, maintenance and abandonment of pipelines throughout
RH-2-2008 37 their life. Accordingly, the Panel was not persuaded that the Board is statutorily obligated to assist industry on this matter.
Furthermore, the Panel is of the view that the Board, as an independent and quasi-judicial tribunal, should not promote the development of tax policies or initiatives. Tax treatment of the abandonment funds that will be collected is an issue for the pipeline companies, working with others in industry, to pursue with the Department of Finance. As industry has submitted that changes in tax treatment are necessary, parties should endeavour to seek such change in a timely manner. However, as already noted, the funding of abandonment costs remains the responsibility of each pipeline company, regardless of tax implications. Tax efficiency is a goal of, not a deterrent to, the collection of funds for pipeline abandonment.
3.4 Framework
Given the above key principles and discussion, the Panel is of the view that it is now an opportune time to develop a framework to meet the goal of having adequate abandonment funds available for abandonment and abandonment planning when required. Setting aside of abandonment funds is required; however, it need not begin until some fundamental issues have been addressed and a framework has been implemented. This will allow accumulation of abandonment funds to proceed in an orderly fashion. The Panel is of the view that there is time to address certain outstanding issues and to implement a framework that will work for all pipeline companies regulated by the Board.
In reaching this conclusion, the Panel considered the following factors:
• No pipeline systems are anticipated to be abandoned in the foreseeable future. • Applying the concept of risk management, as opposed to the concept of zero risk, parties did not present any evidence at the hearing that persuaded the Panel that time is of the essence in terms of the Board needing to require immediate collection or setting aside of funds. • It would not be prudent from an economic efficiency perspective to implement a framework that results in the over-accumulation or under-accumulation of abandonment funds. • In the Panel’s view, the immediate collection or set aside of a nominal amount would divert resources away from tackling the fundamental aspects of abandonment funding.
Notwithstanding the recommendation to implement a framework applicable across the industry, pipeline companies are not precluded from filing an application with the Board to begin the collection or setting aside of funds for abandonment while the Framework is being implemented. If this should occur, the Panel recommends that the Board consider the application on its merits at that time.
In addition, the Panel notes that the Board is not precluded from considering the full costs of constructing, operating and abandoning a pipeline as part of its consideration of the present and future public convenience and necessity of a project when a company seeks approval under Part
38 RH-2-2008
III of the NEB Act, should the Board determine that doing so is appropriate based on the case before it.
Overview of Framework and Action Plan
It is essential that all regulated companies accept the responsibility for the full costs of their facilities, including abandonment costs. In the Panel’s view, a fundamental element of accepting responsibility is the quantification, albeit approximate at this stage, of that responsibility.
Consequently, the Panel finds that pipeline companies are responsible for coming forward to the Board with estimates of funds needed for abandonment, justifying any assumptions used, and with proposals for the mechanisms and timing of the collection and setting aside of those funds. The ultimate goal is to have all companies begin to set aside funds to cover future abandonment costs no later than five years from the date of the decision of the Board. To achieve this goal, a number of steps must be completed within this five-year period, including the Board’s assessment of filings. These steps are described below and summarized in Chapter 4, Action Plan and Base Case Assumptions.
The Panel recognizes that, should the Board adopt the proposed Framework and Action Plan, there will be increased regulatory interaction between stakeholders and the Board. This includes increased filings by companies within the next five years, resulting in increased assessments, and potentially hearings, by the Board over that same period with respect to those filings. Additional resources to hold and participate in at least one further technical conference will also be required. While these resources are not insignificant, the Panel is of the view that in order to progress on the issue of financial aspects of abandonment, an increased regulatory role, at least in the short to mid-term, is inevitable.
The Panel encourages all stakeholders to identify ways to increase efficiency, while respecting the key principles, the goals set out therein and ultimate goal of the Framework and Action Plan to ensure that funds are available when abandonment costs are incurred. Further, the Panel recommends that the Board also remain open to, and itself seek out, opportunities to increase regulatory efficiencies, even if acting on those opportunities results in refinements to the Framework and Action Plan.
Preliminary Estimates
As an essential first step, the Panel recommends that the Board direct each company under NEB jurisdiction (Group 1 and Group 2) to submit a preliminary estimate of its total future abandonment costs and the amount required to be set aside using basic assumptions regarding economic life and the method of abandonment.
To facilitate these submissions, the Panel has provided Base Case assumptions in this Report that companies may use to develop these preliminary estimates. A technical conference will be held to assess and discuss these assumptions. Following the discussion of these assumptions, and the issuance of a revised set of Base Case assumptions as necessary, each company will be expected to prepare and file an estimate of abandonment costs and the amount required to be set aside using the Base Case assumptions. Alternatively, should it not wish to rely on the Base Case assumptions, a company may file with the Board its pipeline-specific estimate of abandonment
RH-2-2008 39 costs for its pipeline system. The pipeline-specific estimate should be accompanied by discussion and supporting evidence for any assumptions the company is using that differ from the Base Case assumptions.
If a Group 1 company is using all of the Base Case assumptions, or if a Group 2 company is using either the Base Case or pipeline-specific assumptions, no approval is necessary for its preliminary estimates. If a Group 1 company is using any pipeline-specific assumptions, Board approval of the preliminary estimates is required.
The Panel recommends that Westcoast be required to calculate preliminary estimates for abandonment costs for its transmission (Zones 3 and 4) and its gathering and processing (Zones 1 and 2) facilities.
Collection of Funds
Group 1 companies would be required to file, for approval, a proposal for collecting the amount of funds required. Group 2 companies that charge tolls would file their proposals for collecting funds for abandonment. These proposals should contain discussion and justification of the time horizon and methodology for collecting future abandonment costs from users of the pipeline system.
Group 2 companies that do not charge tolls need not complete this step, but would be required to file with the Board their proposals for setting aside the amount of funds required (as discussed in the next step).
Concerning the method of collection, the Panel agrees with many of the parties who indicated that collecting abandonment funds should be transparent and this can be achieved for Group 1 or Group 2 companies that charge tolls through either tolls or a toll surcharge. However, there may be other transparent methods that companies wish to propose to the Board. The Panel is also of the view that abandonment funds should be separate from depreciation as an element of cost of service and that the funds should be segregated by pipeline.
Concerning negotiated toll settlements, the Panel’s view is that within the timeframe established in the Action Plan, the majority of toll settlements will have expired. In the interim, in entering into new toll settlements, parties will be aware of this Framework and Action Plan. The Panel expects that parties will ensure that any new toll settlements address abandonment funding matters resulting from the Framework and Action Plan.
Setting Aside Funds
All Group 1 companies would be required to file, for approval, a proposed process and mechanism to set aside the funds. All Group 2 companies would file with the Board a proposed process and mechanism to set aside the funds.
40 RH-2-2008
The Panel recommends that any process and mechanism for setting aside the funds for abandonment have the following attributes:
• funds must be maintained in a segregated account and not be commingled with a company’s general corporate funds; • funds must be managed by an independent, third party; • funds collected must be protected from creditors; • funds must be protected from misuse or use for a purpose other than abandonment; • regular reviews (at least every five years) of the amount of funds set aside and disbursed from the segregated account must be incorporated, and regular reporting to the Board and stakeholders must be built in; • funds must be segregated by pipeline; • funds must be subject to Board audit, as appropriate; • companies must develop a sound investment policy for abandonment funds as ultimately, accountability for the collection and governance of the funds rests with each pipeline company; and • the process for accessing the funds must be clearly set out in the mechanism.
Pipeline companies are expected to demonstrate to the Board how the mechanism they have chosen meets the goal of ensuring that adequate funds will be set aside to cover all pipeline abandonment activities. In the Panel’s view, it is not necessary to use a one-size-fits-all approach. The market may play a role in determining the appropriate mechanism that a particular company may decide to adopt.
The Panel does not see a need to comment on the merits of the concept of deferral of collection or exemptions from collection or setting aside of funds. In the Panel’s view, this is a level of detail beyond the scope of this proceeding, and is best addressed on a case-specific basis. As a result, this concept may form part of a company’s proposal for collection and setting aside funds. However, as noted above in the Key Principles section, the Panel recommends that, as a prerequisite to considering any proposals to defer collection or set aside of funds, companies be required to submit information on a pipeline-specific basis, rather than using the Base Case assumptions. This will allow the Board to have before it the best information possible, upon which it may exercise its discretion to approve or deny such a proposal.
The Panel was not persuaded by CAPLA’s submissions advocating the involvement of landowners in an oversight committee role to review abandonment funding. A role of such a committee requires a significant amount of time, resources and financial expertise. Further, given the key principles noted above, the ongoing Board oversight of this matter and that interested parties may participate in future NEB abandonment-related proceedings, the Panel does not recommend the establishment of an external oversight committee.
RH-2-2008 41 Access to Funds
As noted in Chapter 2, many parties in the hearing indicated that Board guidance on accessing the funds would be needed. In the Panel’s view, funds should be accessible only for abandonment purposes. “Abandonment purposes” may include the development of an abandonment plan, as well as the undertaking of activities (for example, surveys and studies) to prepare an abandonment plan or to carry out an abandonment, and the continuation of post- physical abandonment activities (for example, monitoring or perpetual maintenance).
Pouce Coupé initially submitted that access to accumulated funds should also be permitted for decommissioning of facilities. Others argued that access should be restricted to covering abandonment, and abandonment process activities (such as pre-planning). The Panel notes that both deactivation and decommissioning contemplate continuation of system service. Provided service continues, revenue will be generated from the collection of tolls, from which funds should be available to cover these costs. Consequently, the Panel recommends that access to the funds should generally not be permitted for decommissioning or deactivation of facilities, unless the Board authorizes the access on the facts of a particular case before it.
Accordingly, in order to access the funds to cover costs of physically abandoning facilities and the costs for undertaking abandonment planning activities, companies will generally require a Board order, for example, pursuant to paragraph 74(1)(d) of the NEB Act.
As summarized in Chapter 2, Pouce Coupé argued that at least Group 2 companies should be able to access funds without a Board order. Instead, it submitted that Board oversight of the funds could be exercised through annual reporting of a company’s access to the funds and audits by the Board of the funds. The Panel notes the expansive definition of “abandonment purposes” proposed herein, the requirement under the NEB Act to seek leave to abandon, and the recommendation that the Board exercise its discretion to authorize access in other circumstances as appropriate. Consequently, the Panel was not persuaded there is a need for a broad exception to the access procedure, such as the exception proposed by Pouce Coupé for Group 2 companies.
While the Board cannot mandate the process for accessing funds for abandonment of facilities that have fallen outside of the Board’s jurisdiction, the Panel would recommend that companies consider, in the development of any mechanisms for setting aside the funds, the conditions for accessing funds should the related facilities fall within provincial or territorial jurisdiction at a later date. This may require sufficiently broad provisions or specifically-drafted provisions for access to encompass this potential situation. Exercising foresight on this issue now while developing appropriate mechanisms may save time and complications at a later date.
42 RH-2-2008 Attachment A7 Tab 37 Part A – Review and Variance Application Exhibit B-10-2, MH-001-2012, TransCanada PipeLines Limited, Application for Approval of Cost Estimates TransCanada PipeLines Limited Abandonment Cost Estimate Application Section 6.0: Relief Requested Page 50 of 50
6.0 RELIEF REQUESTED
1 TransCanada requests that the NEB issue an order approving:
2 • the apportionment of the Mainline into the various land use and general 3 categories as described in the Application;
4 • the proposed method of abandonment for pipeline situated in the various land 5 use and general categories as described in the Application;
6 • the cost estimates, that will be updated from time to time, for abandoning the 7 respective portions of the Mainline situated in the various land use and general 8 categories as described in the Application;
9 • the total Cost Estimate of $1,641,810,000 that will be updated from time to 10 time, for abandoning the respective portions of the Mainline situated in the 11 various land use and general categories as described in the Application; and
12 • granting such further and other relief as TransCanada may request or the 13 Board may consider appropriate.
Attachment A7 Tab 38 Part A – Review and Variance Application National Energy Board Reasons for Decision MH-001-2012, Abandonment Cost Estimates, Pipeline Abandonment – Financial Issues, February 2013.
Reasons for Decision
Abandonment Cost Estimates
MH-001-2012
February 2013
Pipeline Abandonment – Financial Issues
8.9 TransCanada Keystone The Board directs TransCanada Keystone to submit to the Board revised cost estimates based on an assumption of 20 per cent removal for large diameter pipe in the “Agricultural, Cultivated” and “Agricultural, Non-Cultivated” sub-categories. TransCanada Keystone is further directed to adjust Cost Category 3b (Post-Abandonment Provision), to provide for perpetual monitoring and perpetual remediation, using its own company-specific monitoring costs (as approved by the Board in Chapter 6) and unit removal costs (as approved by the Board in Chapter 4), but using the Base Case methodology. Finally, the Board directs TransCanada Keystone to report contingency as a separate line item in its revised cost estimates. The Board approves all other aspects of TransCanada Keystone’s cost estimates as filed.
8.10 TransCanada PipeLines The Board directs TransCanada PipeLines to submit to the Board revised cost estimates based on an assumption of 20 per cent removal for medium and large diameter pipe in the “Agricultural, Cultivated” and “Agricultural, Non-Cultivated” sub-categories. TransCanada PipeLines is further directed to adjust Cost Category 3b (Post-Abandonment Provision), to provide for perpetual monitoring and perpetual remediation, using its own company-specific monitoring costs (as approved by the Board in Chapter 6) and unit removal costs (as approved by the Board in Chapter 4), but using the Base Case methodology. Finally, the Board directs TransCanada PipeLines to report contingency as a separate line item in its revised cost estimates. The Board approves all other aspects of TransCanada Pipelines’ cost estimates as filed.
8.11 Trans-Northern The Board directs Trans-Northern to submit to the Board revised cost estimates based on an assumption of 20 per cent removal for medium diameter pipe in the “Agricultural, Cultivated” and “Agricultural, Non-Cultivated” sub-categories. The Board approves all other aspects of Trans-Northern’s cost estimates as filed.
8.12 Westcoast The Board directs Westcoast to submit to the Board revised cost estimates based on an assumption of 20 per cent removal for medium and large diameter pipe in the “Agricultural, Cultivated” and “Agricultural, Non-Cultivated” sub-categories. The Board also directs Westcoast to submit to the Board a revised cost estimate in which Cost Category 3b (Post-Abandonment Provision), is adjusted to provide for perpetual monitoring and perpetual remediation, using its own methodology and monitoring and remediation costs (as approved by the Board in Chapter 6). The Board approves all other aspects of Westcoast’s cost estimates as filed.
69
Attachment A7 Tab 39 Part A – Review and Variance Application MH-001-2012, TransCanada’s Filing of Revised Cost Estimates, letter dated April 16, 2013
450 - 1 Street S.W. Calgary, Alberta, Canada T2P 5H1
Tel: (403) 920-7838 Fax: (403) 920-2310 Email: [email protected]
April 16, 2013 Filed Electronically
National Energy Board 444 Seventh Avenue S.W. Calgary, Alberta T2P 0X8
Attention: Sheri Young, Secretary of the Board
Dear Ms. Young:
Re: TransCanada PipeLines Limited (TransCanada) Abandonment Cost Estimates – MH-001-2012 Filing of Revised Cost Estimates
TransCanada provides its revised abandonment cost estimates in accordance with the Board’s directions in the Abandonment Cost Estimates MH-001-2012 Decision (MH-001-2012 Decision).
Attachment 1 presents the revised cost estimates in the format applied to Table 5-1, which was included in TransCanada’s application for abandonment cost estimates on November 30, 2011.1 Those cost estimates were developed using company-specific assumptions. In response to the Board’s directions in the MH-001-2012 Decision, TransCanada also provides these cost estimates in Attachment 2 adapted to a format similar to the NEB Undertaking during the MH-001-2012 Proceeding2 to facilitate a comparison of TransCanada’s cost estimates.
In section 8.10 of the MH-001-2012 Decision, the Board directed TransCanada to submit revised cost estimates applying a series of specific assumptions as defined by the Board. The following sets out the Board’s directions for the specific assumptions TransCanada was to apply to revise its cost estimates and TransCanada’s response to each direction:
1) …submit to the Board revised cost estimates based on an assumption of 20 per cent removal for medium and large diameter pipe in the “Agricultural, Cultivated” and “Agricultural, Non-Cultivated” sub-categories.
1 Abandonment Cost Application, Section 5.0: Abandonment Cost Estimate, p. 46 of 50, pdf p. 51. 2 Board counsel’s request at Transcript reference 5921 to 5924, November 16, 2012. April 16, 2013 Ms. S. Young Page 2 of 3
The revised removal costs for 20% of medium and large diameter pipe are $578,941,000 in the “Agricultural, Cultivated” sub-category and $43,413,000 in the “Agricultural, Non- Cultivated” sub-category. The removal costs in these categories were calculated by multiplying 20% of the kilometre-length of medium and large diameter pipe by the unit removal cost per kilometre (km) in each category.
The original cost estimates filed by TransCanada on November 30, 2011, incorporated 540.8 km of pipe in the small, medium and large diameter categories of “Agricultural, Cultivated” and “Agricultural, Non-Cultivated” lands into a separate sub-category identified as “Non-Agricultural, Future Development.”3 This sub-category was to reflect cost estimates for the future removal of pipe on lands that were currently categorized as “Agricultural” but that would be subject to potential future development based on urban development trends.
In responding to the Board’s direction in the MH-001-2012 Decision, TransCanada has incorporated the 540.8 km of pipe from the “Non-Agricultural, Future Development” sub-category into the broader “Agricultural, Cultivated” sub-category. The new sub-category for medium and large diameter pipe of “Agricultural, Cultivated – Removal” also incorporates the sub-category previously defined as “Non-Agricultural, Future Development”.
2) …adjust Cost Category 3b (Post-Abandonment Provision) to provide for perpetual monitoring and perpetual remediation, using its own company-specific monitoring costs…and unit removal costs…, but using the Base Case methodology.
The Post-Abandonment Provision has been revised to $69,236,000 to provide for perpetual monitoring and perpetual remediation activities.
3) …report contingency as a separate line item in its revised cost estimates.
The previously filed “Above Ground Facilities” abandonment cost estimates of $386,798,000 had included 95% cost estimate and 5% contingency. To comply with the Board’s direction, this estimate has been split into a revised cost estimate of $368,379,000 and a separate line item for contingency of $18,419,000.
The revised “Pipeline Facilities” abandonment cost estimate of $1,690,649,000 has also been split into a revised cost estimate of $1,610,142,000 and a separate line item for contingency of $80,507,000.
No other changes have been made to the assumptions supporting the cost estimates filed on November 30, 2011. TransCanada’s total revised cost estimate of $2,146,683,000 will be incorporated in the Collection Mechanism application, which TransCanada will file on or before May 31, 2013.
3 Abandonment Cost Application, Section 3.0: Abandonment Assumptions, Table 3-3, p. 27 of 50, pdf p. 32. April 16, 2013 Ms. S. Young Page 3 of 3
Should the Board require additional information regarding this filing, please contact Stella Morin at (403) 920-6844 or [email protected].
Yours truly, TransCanada PipeLines Limited
Original signed by
Kevin Thrasher Senior Legal Counsel Law & Regulatory Affairs
Attachments
cc: Parties to MH-001-2012 TransCanada PipeLines Limited Attachment 1 Table 5-1 Page 1 of 1
Abandonment Cost Estimates Estimated Costs2 Land Use Type Method1 ($000) Pipeline Facilities Cultivated A 152,684 Cultivated R 578,941 Agriculture Cultivated with Special Features R 96,052 Non-Cultivated A 11,073 Non-Cultivated R 43,413 Existing Development A 23,555 Non-Agriculture Future Development R 0 No Future Development A 103,657 Environmental Sensitive Areas A 11,347 Water Crossings A 229,846 Other Road and Rail Crossings A+ 168,137 Gravel Road Crossings A/A+ 190,272 Other Crossings (Utility) A 1,167 Subtotal Pipeline Facilities 1,610,142 Contingency 80,507 Total Pipeline Facilities 1,690,649 Above Ground Facilities Compressor Stations 326,733 Aerial Coolers 19,709 Meter Stations 21,937 Subtotal Above Ground Facilities 368,379 Contingency 18,419 Total Above Ground Facilities 386,798
Total Pipeline Abandonment 2,077,447 Post-Abandonment Provision 69,236 TOTAL 2,146,683 1 A=Abandon in place, A+=Abandon in place with special treatment, R=Removal TransCanada's assumption for abandon in place is that all water, paved road, railway crossings and medium/large diameter gravel road crossings include cutting and capping of pipes with steel plates at both ends
2 May not sum due to rounding
TransCanada PipeLines Limited Attachment 2 Page 1 of 1
Abandonment Cost Estimates Category Category and Sub-Category Revised April 16, 2013 No. 1 Engineering and Project Management 53,131 2 Abandonment Preparation a. Land Access and Clean up 55,254 b. Pipeline Purging and Cleaning 211,553 3 Pipeline Abandonment-in-Place a. Basic Pipeline Abandonment-in-Place 87,539 b. Provision for Post-Abandonment Activities 69,236 4 Special Treatment 540,379 5 Pipeline Removal a. Pipeline Removal and Backfilling 525,203 b. Pipeline Removal - Land Restoration 137,085 6 Above-Ground Facilities a. All Facilities 368,379 b. Portions Removed included in 6a. c. Portions Left in Place N/A 7 Contingency 98,926 Abandonment Cost Estimate 2,146,685 TransCanada Abandonment Cost Estimate was developed using company-specific methodology, as described in TransCanada abandonment cost estimate application on November 30, 2011. This table provides information adapted to a format comparable to TransCanada response on November 16, 2012 to the NEB Undertaking during the MH-001-2012 Proceeding. Some category descriptions in this table may differ from the company-specific methodology.
Attachment A7 Tab 40 Part A – Review and Variance Application Exhibit A1-1, MH-001-2013, NEB Letter dated March 12, 2013, Re RH-2-2008 Action Plan, as amended on June 1, 2012, Set Aside Mechanism (SAM) and Collection Mechanism (COM) Filings. Files: OF-AF-SAC 02 OF-AF-SAC 03 12 March 2013
To: All pipeline companies regulated under the National Energy Board Act
RH-2-2008 Action Plan, as amended on 1 June 2012 Set-Aside Mechanism (SAM) and Collection Mechanism (COM) Filings
In May 2009, the National Energy Board (Board) issued its RH-2-2008 Reasons for Decision. In that decision the Board included a five-year Action Plan with the goal of having all companies begin to set-aside abandonment funds no later than five years from the date of the decision. The Action Plan requires companies to file abandonment cost estimates and set-aside and collection mechanisms.
The Board has assessed companies’ abandonment cost estimates, which were filed in 2011. The Board’s decisions in respect of the cost estimates to date are contained in the MH-001-2012 Reasons for Decision (Group 1 companies), and its 14 February 2013 letter (Group 2 companies). Companies filing revised abandonment cost estimates must do so by 16 April 2013.
The next step in the Action Plan is for companies to file their proposed set-aside mechanism. All companies are required to subsequently file their proposed collection mechanism. Accordingly, the Board is providing the following information and guidance regarding the set-aside and collection mechanism filings.
Set-Aside Mechanism Filings
On 28 February 2013, Group 1 companies filed a joint application regarding their set-aside mechanism. The Board intends to issue a Hearing Order setting out the process for its assessment of this filing shortly.
The Action Plan requires Group 2 companies to file their set-aside mechanism by 31 May 2013. The Board anticipates combining its assessment of the Group 1 and Group 2 filings into one process. A revised Hearing Order would be issued after 31 May 2013.
Collection Mechanism Filings
Collection mechanism filings are required to be filed with the Board no later than 31 May 2013.
…/2 -2-
The Board reminds Group 2 companies that do not charge tolls that they are required to file a Collection Period (that is, the number of years proposed to fully fund the future abandonment costs). The Collection Period could be included with these companies’ set-aside mechanism filings, or may be filed separately. Shortly after receipt of the collection mechanism filings, the Board will notify parties as to the process for its assessment of these filings. The Board anticipates assessing the majority of companies’ the set-aside and collection mechanism filings in one process. As stated above, a revised Hearing Order would be issued after 31 May 2013.
The Board reminds companies that they are ultimately responsible for the costs of abandonment and for making sure that appropriate funds are estimated, collected and set-aside for such purposes. Accordingly, companies should use a Collection Period that is appropriate for their specific circumstances.
The Board notes that many pipeline companies have previously indicated that they do not expect to abandon their entire system at one time, but rather to abandon parts of their systems on different timelines. The Board would expect companies in these situations to include in their filing a collection plan, which would include:
(1) A forecast of the annual balance of the funds to be set-aside for each year of the Collection Period;
(2) Approximate plans for drawing on the funds; and
(3) A forecast of the amount of revenue deposited.
The Board recognizes that the collection plan will be approximate and therefore likely to change in the future. However, this plan will assist the Board with its review of the filings. The Board may request this information during the course of its assessment of a company’s filing.
The Board will be assessing each filing in light of the principles and considerations set out in the RH-2-2008 Reasons for Decision as well as the requirements of the National Energy Board Act. Collection Periods and plans must not be included with other aspects negotiated with shippers under the Guidelines for Negotiated Settlements of Traffic, Tolls and Tariffs.
Finally, the Board notes that in its 4 March 2010 letter, it set 3.5 per cent as a Base Case assumption for the rate of return on funds collected. As stated in the Board’s 4 March 2010 letter, if companies propose a higher return on funds invested, the Board would expect to see a clear articulation of risk allocation and return among shippers, the pipeline and any affected public, as well as a discussion of whether the pipeline has the support of interested parties for the plan. The Board reminds all companies proposing a higher return on funds invested to include a discussion of the above points in their collection mechanism filing.
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Next Steps
As discussed above, the Board will issue a Hearing Order shortly. The Hearing Order will include a List of Issues. Parties will subsequently be given an opportunity to comment on that List of Issues.
The Board anticipates that the oral portion of the hearing for the set-aside and collection mechanism filings will be held in the fourth quarter of 2013. The Board expects to hold this hearing in Calgary and to provide options for remote participation such as teleconference or webinar. The Board notes that because this proceeding is not an oral facility hearing, pursuant to Board’s Participant Funding Program, funding is not available for the assessment of these applications. As stated in the 1 June 2012 Action Plan, the NEB will consider Group 1 companies’ proposals for collection and set-aside mechanisms by 31 May 2014. The Board’s primary focus will be on determining the amount of funding to be set-aside each year.
Group 1 company set-aside mechanism filings can be found on the Board’s website at www.neb-one.gc.ca, Regulatory Documents, View applications, Other Proceedings and Reports, Abandonment Funding. The Board will advise as to the location on its website of the other set-aside and collection mechanism filings once they are filed with the Board.
A Process Advisor is available to answer questions regarding the hearing process. Please direct any enquiries to Danielle Moffat, Process Advisor at 403-299-2786 or toll free 1-800-899-1265, or [email protected].
Yours truly,
Sheri Young Secretary of the Board
c.c.: Parties to the MH-001-2012 proceeding Attachment A7 Tab 41 Part A – Review and Variance Application Exhibit B-10-7, RH-003-2011, TransCanada's response to CAPP 2-47.
TransCanada PipeLines Limited RH-003-2011 Response to CAPP February 6, 2012 Page 1 of 4 CAPP 2-47
Reference:
TransCanada response to CAPP IR 200
Preamble:
TransCanada declines to provide a long run financial forecast for the Mainline under the status quo and restructuring proposal alternative on the grounds that it is confidential and similarly does not answer several questions.
Request:
(a) Why would TransCanada regard this information as commercially sensitive when similar data and long term financial projections were provided by IOL in the Mackenzie Valley Pipeline hearing before the NEB in 2006, EGNB before the NBEUB in 2010 and Heritage Gas before the NSUARB in 2011? Please explain how this would harm TransCanada’s competitive position and with respect to whom?
(b) Please confirm that such long term financial projections could be provided on a confidential basis to select interveners who sign a confidentiality agreement.
(c) Please confirm that no financial projections were provided to TransCanada’s financial witnesses. If this cannot be confirmed please provide the same financial projections that were provided to TransCanada’s witnesses.
(d) Please confirm that no long term financial projections have been provided to either bond rating agencies or other external financial analysts. If this cannot be confirmed please provide the same financial projections that were provided.
(e) Please provide the financial forecast to 2017 provided in answer to CAPP IR 200 in an Excel spreadsheet with the financial linkages clearly displayed to allow sensitivity analysis with respective to critical values.
(f) Please confirm that TransCanada has not developed a financial forecast for the status quo scenario, that is, the scenario where the NEB would deny its current application? If not confirmed, please provide the forecast.
(g) Is it correct to infer from the answer to CAPP 200(e) that in its budget cycle TransCanada only provides a two year forecast? Page 2 of 4 CAPP 2-47
Response:
(a) through (d)
TransCanada understood that CAPP 200 sought long range financial forecasts for "TransCanada", not the Mainline. TransCanada's response was that it "considers its long-range financial forecasts for the Company to be confidential and commercially sensitive", which is the case. TransCanada is, however, able to provide a long term financial forecast for the Mainline. Please refer to the Application, Section 12.0, Tab 1-Revenue Requirement for the 2012 to 2013 financial forecast for the Restructuring Proposal.
Please refer to the following tables for the 2014 to 2020 financial forecast information for the Restructuring Proposal. TransCanada completed only a two year forecast (2012 and 2013) in its most recent annual budget cycle. The information for 2014 to 2020 includes high level assumptions. All figures are in ($million) unless otherwise stated.
Forecast Rate 2014 2015 2016 2017 2018 2019 2020 Base Average Gross 12,738 12,714 12,690 12,666 12,641 12,617 12,603 Plant in Service Average (7,534) (7,754) (7,972) (8,191) (8,408) (8,626) (8,852) Accumulated Depreciation Average Operating 00000 0 0 and Debt Service Deferrals Average Long 174 170 166 161 157 153 149 Term Adjustment Account Average Working 160 155 148 144 139 134 128 Capital, Deferrals & Other Average Rate Base 5,538 5,285 5,032 4,780 4,529 4,278 4,028 Plant Additions(*) 37 39 39 39 39 39 39
Note (*): Plant additions for 2014-2020 only include a high level estimate of maintenance and general plant capital; no capacity capital additions have been assumed.
Page 3 of 4 CAPP 2-47
Forecast Rate 2014 2015 2016 2017 2018 2019 2020 of Return After-tax 7.00% 7.00% 7.00% 7.00% 7.00% 7.00% 7.00% Weighted Average Cost of Capital (ATWACC) Adjustment for 1.17% 1.10% 1.07% 1.18% 1.07% 1.04% 1.07% Embedded Cost of Debt ATWACC 8.17% 8.10% 8.07% 8.18% 8.07% 8.04% 8.07% Adjusted for Embedded Cost of Debt Deemed Equity 40% 40% 40% 40% 40% 40% 40% Income Tax 25.505% 25.505% 25.505% 25.505% 25.505% 25.505% 25.505% Rate Average 2,810 2,627 2,523 2,523 2,319 2,197 2,142 Funded Debt Amount Average 522 552 505 353 407 378 284 Unfunded Debt Amount Average 8.41% 8.36% 8.21% 8.21% 8.09% 7.98% 7.90% Funded Debt Rate Average 2.70% 2.70% 2.70% 2.70% 2.70% 2.70% 2.70% Unfunded Debt Rate
Forecast Gross Revenue 2014 2015 2016 2017 2008 2009 2020 Requirement Transportation By Others 140 140 140 140 140 140 140 Storage Operating Costs 16 17 17 17 18 18 19 Pipeline Integrity and 100 100 100 100 100 100 100 Insurance Deductible Costs NEB Cost Recovery 9 9 9 9 10 10 10 Return 452 428 406 391 365 344 325 Income Taxes 190 182 174 169 160 152 146 Depreciation 293 292 292 291 291 290 290 Regulatory Proceeding 1 1 1 1 1 1 1 Costs and Collaborative (TTF) Costs Electric Costs and Tax on 40 46 53 49 50 43 44 Fuel Municipal and Provincial 133 137 141 145 149 154 158 Capital Taxes Regulatory Amortizations 0 0 0 0 0 0 0 Operations, Maintenance 177 181 184 188 192 196 200 Page 4 of 4 CAPP 2-47
and Administrative Long Term Adjustment 4 4 4 4 4 4 4 Account Short Term Adjustment 0 0 0 0 0 0 0 Account Terminal Negative 0 50 50 50 50 50 50 Salvage(*) Gross Revenue 1,555 1,587 1,571 1,554 1,530 1,502 1,487 Requirement
Note (*): Terminal Negative Salvage is a placeholder pending the outcome of the Land Matters Consultation Initiative. Until a process is determined to collect and set aside abandonment funds this placeholder cannot be estimated with any degree of accuracy.
Forecast Other 2014 2015 2016 2017 2018 2019 2020 Mainline Western Receipts (Bcf/d) 4.1 4.3 4.5 4.6 4.7 4.8 4.8 Cost to NGTL (Alberta System 385 399 399 408 432 445 434 Extension) Toll ($/GJ): SMB to Union SWDA 0.87 0.85 0.80 0.78 0.72 0.73 0.71 Toll ($/GJ): Union Dawn to Enbridge 0.17 0.17 0.16 0.15 0.14 0.14 0.14 CDA
e) Please refer to Attachment CAPP 2-47e. TransCanada is also providing the attachment in electronic format capable of computer calculation to the Board and the requesting party/parties. The data will be provided in a CD format to other parties upon request by e-mail at [email protected].
f) Confirmed, except for the 2012 and 2013 revenue requirements, which are provided in response to EGD 2-1.1. g) Yes.