Document:

Exhibit

EXHIBIT 10.1

Enbridge Pipelines Inc.
(“Enbridge”)

COMPETITIVE TOLL SETTLEMENT Dated July 1, 2011
(the “CTS”)

Table of Contents

	
			
	PART I – INTRODUCTORY MATTERS
	1

	 
	1. RECITALS
	1

	 
	2. PRINCIPLES
	1

	PART II – INTERPRETATION
	3

	 
	3. DEFINITIONS
	3

	 
	4. INTERPRETATION
	10

	PART III – TERM AND APPLICABILITY
	12

	 
	5. TERM OF SETTLEMENT
	12

	 
	6. APPLICABILITY OF CTS vs. CANADIAN AGREEMENTS
	12

	 
	7. APPLICABILITY OF CTS vs. U.S. AGREEMENTS
	12

	PART IV – TOLLS AND RELATED FINANCIAL MATTERS
	13

	 
	8. INTERNATIONAL JOINT TOLLS
	13

	 
	9. CANADIAN LOCAL TOLLS
	13

	 
	10. ANNUAL TOLL ADJUSTMENT
	14

	 
	11. OUTSTANDING AMOUNT SURCHARGE
	15

	 
	12. ALLOWANCE OIL
	15

	 
	13. CONTINGENT TOLL ADJUSTMENTS
	16

	 
	14. TOLL INCENTIVES
	17

	 
	15. LAND MATTERS CONSULTATION INITIATIVE
	17

	 
	16. CAPITAL EXPENDITURES
	18

	 
	17. LINE 5 CLAIM
	23

	 
	18. COMMODITY SURCHARGE
	24

	PART V - RENEGOTIATION AND/OR TERMINATION OF THE CTS
	25

	 
	19. MIMIMUM THRESHOLD VOLUMES
	25

	 
	20. MATERIAL CHANGE IN BUSINESS CIRCUMSTANCES
	25

	 
	21. EVENTS TRIGGERING A RENEGOTIATION PERIOD
	26

	PART VI – OTHER CTS MATTERS
	27

	 
	22. REPRESENTATIVE SHIPPER GROUP
	27

	 
	23. SERVICE LEVELS
	27

	 
	24. GENERAL TANKAGE PRINCIPLES
	27

	 
	25. END OF TERM ISSUES
	30

	PART VII – GENERAL PROVISIONS
	32

	 
	26. REPORTING AND FILING REQUIREMENTS
	32

	 
	27. AUDIT
	32

	 
	28. ACCOUNTING
	33

	 
	29. AFFILIATES
	33

	 
	30. DISPUTE RESOLUTION
	35

	PART VIII – LINE 9 MATTERS
	36

	 
	31. LINE 9
	35

	SCHEDULE “A” - CANADIAN MAINLINE
	 

	SCHEDULE “B” - LAKEHEAD SYSTEM
	 

	SCHEDULE “C” - LINE 9 FACILITIES EAST BOUND SERVICE
	 

	SCHEDULE “D” - TABLE OF IJT TOLLS
	 

	SCHEDULE “E” - TABLE OF CLT TOLLS
	 

	SCHEDULE “F” - TABLE OF OUTSTANDING AMOUNT SURCHARGE
	 

	
			
	SCHEDULE “G” – ENBRIDGE MAINLINE REFERENCE CAPACITIES
	 

	SCHEDULE “H” - CANADIAN AGREEMENTS
	 

	SCHEDULE “I” - U.S. AGREEMENTS
	 

	SCHEDULE “J” – ILLUSTRATIVE EXAMPLE OF APPLICATION OF CTS vs. CANADIAN AGREEMENT
	 

	SCHEDULE “K” – ILLUSTRATIVE EXAMPLES OF CAPITAL EXPENDITURES UNDER SECTION 16.3 & 16.4
	 

	SCHEDULE “L” – ILLUSTRATIVE EXAMPLES OF CALCULATION OF MINIMUM THRESHOLD VOLUMES
	 

	SCHEDULE “M” – MAINLINE CAPITAL REPORTING TEMPLATE
	 

	SCHEDULE “N” – ENBRIDGE SERVICE LEVELS
	 

	SCHEDULE “O” – LINE 9 CAPITAL REPORTING TEMPLATE
	 

PART I – INTRODUCTORY MATTERS

1.    RECITALS
		
	1.1
	Enbridge is a body corporate continued under the laws of Canada, having its registered office in the City of Calgary, in the Province of Alberta.  Enbridge owns and operates those assets set forth in Schedule “A” (the “Canadian Mainline”), a common carrier pipeline system regulated under the National Energy Board Act.

		
	1.2
	Enbridge Energy Limited Partnership owns and operates those assets set forth in Schedule “B” (the “Lakehead System”), a pipeline system regulated by the FERC.

		
	1.3
	Together the Canadian Mainline and the Lakehead System comprise the “Enbridge Mainline”.

		
	1.4
	CAPP represents companies large and small, that explore for, develop, and produce natural gas and crude oil throughout Canada.

		
	1.5
	The CTS was negotiated by representatives from Enbridge, CAPP and from Shippers of Record that delivered the majority of the volumes of liquid hydrocarbons on the Enbridge Mainline in 2010 (the “2011 Negotiating Team”) and where the context requires, reference to the “2011 Negotiating Team” includes Enbridge, CAPP and such Shippers of Record.

		
	1.6
	The CTS provides for an international joint toll for all hydrocarbons shipped from Western Canadian Receipt Points on the Canadian Mainline to delivery points on the Lakehead System and  to delivery points on the Canadian Mainline located downstream of the Lakehead System during the Term. The CTS also establishes the local tolls for transportation services solely within Canada,  from  receipt  points  on  the  Canadian  Mainline  to  delivery  points  on  the  Canadian Mainline through the Canadian Local Toll.  Transportation and related services solely within the U.S., from receipt points on the Lakehead System to delivery points on the Lakehead System, will continue to be governed by the FERC Tariff Rates.

		
	1.7
	The Enbridge Board of Directors and the CAPP Board of Governors have approved the principles that comprise the CTS.

		
	2.
	PRINCIPLES

		
	2.1
	No one element of the CTS is to be considered as acceptable to any party in isolation from all other aspects of this settlement.  The parties intend that the CTS be viewed as a whole, reflecting the allocation of risks and rewards between Enbridge and its Shippers over the Term.

		
	2.2
	The 2011 Negotiating Team agrees that the CTS, including the rate principles set forth herein, are the result of good faith arm’s length negotiations, which have resulted in an agreement that is believed to be fair and equitable to Enbridge and all Shippers.  Accordingly, each member of the 2011 Negotiating Team has agreed not to, directly or indirectly, commence or support any application, motion or other proceeding before an applicable regulator for the purpose of asking such regulator to set rates for the Enbridge Mainline during the Term which are inconsistent with the rate design and rates contemplated by the CTS, unless otherwise provided hereunder.   For clarity, neither the foregoing, nor anything else in this CTS, is intended to, and shall not, be construed  as  a  waiver  of  any  parties’  right  to  complain,  protest  or  otherwise  dispute  any agreement 

(1)

that may be reached between Enbridge and the Representative Shipper Group pursuant to any other matter as set out herein.
		
	2.3
	The rate design and rates contained in the CTS will be without prejudice to any positions that may be taken by any party in respect to matters governed by the CTS for periods following expiry or termination of the CTS.  In particular, and without restricting the generality of the above, the 2011 Negotiating Team confirms that the selection of certain capital structures, interest rates, equity returns and operating costs, required for the purposes of implementing the backstopping principles set forth in Article 16 of the CTS, do not in any way form a precedent for the future, nor do these represent the position of either Enbridge or the Shippers as to the capital structure, interest expense, equity return and operating costs that would be appropriate absent this negotiated settlement.

		
	2.4
	The 2011 Negotiating Team intends that the principles set forth in the CTS will be applicable solely to the Enbridge Mainline during the Term and will not form a precedent.

		
	2.5
	There will be no priority access on the Enbridge Mainline during the Term.

		
	2.6
	Subject to Section 7.2, the existing U.S. Agreements in effect as of June 30, 2011 will not be impacted by the CTS during the Term.  Moreover, the tolls and tariffs on file with FERC and in effect from time to time pursuant to such U.S. Agreements shall not apply to hydrocarbons transported on the Canadian Mainline or under the IJT unless otherwise agreed between Enbridge and the Representative Shipper Group.

		
	2.7
	For clarity, the CTS does not provide for an international joint tariff for hydrocarbons shipped from receipts points on the Lakehead System to delivery points on the Canadian Mainline. However, nothing in the CTS precludes Enbridge from offering additional joint tariffs.

(2)

PART II – INTERPRETATION

3.    DEFINITIONS
3.1    The following terms found in the CTS have the meanings set out below:
		
	(a)
	“2010 Depreciation Technical Update Study” means the depreciation study approved by the NEB on May 12, 2010 pursuant to file number E101-2010-04 01.

		
	(b)
	“2011 Interim ITS Tolls” means those tolls in effect resulting from the 2011 ITS.

		
	(c)
	“2011 ITS” means a negotiated toll settlement for the period from January 1, 2011, until December 31, 2011, approved by the NEB on March 31, 2011 pursuant to Order T0I-02-2011.

		
	(d)
	“2011 Negotiating Team” has the meaning given to it in Section 1.5.

		
	(e)
	“2012 Edmonton Tanks” means those four tanks described in Schedule “A”.

		
	(f)
	“2021 Negotiating Team” has the meaning set out in Section 25.1.

		
	(g)
	“Alberta Clipper Canada Settlement Agreement” means the Alberta Clipper Canada Settlement dated June 28, 2007 as described in Schedule “H”.

		
	(h)
	“Allowance Oil” means the percentage of all hydrocarbons tendered to the Enbridge Mainline, which Enbridge is entitled to collect in kind as more fully described in Article 12.

		
	(i)
	“Backstopping Agreement” means an agreement whereby a Shipper agrees to backstop Enbridge’s revenue requirement for Shipper Supported Expansion Projects.

		
	(j)
	“Canadian Agreements” means those agreements set forth in Schedule “H” which are in effect as of June 30, 2011.

		
	(k)
	“Canadian Mainline” has the meaning given to it in Section 1.1.

		
	(l)
	“Canadian Sourced Hydrocarbons” means volumes of liquid hydrocarbons produced in Canada and including the diluents required to facilitate transportation of such hydrocarbons in pipelines regardless of whether the diluents were produced in Canada or not.

		
	(m)
	“Capital Expenditures” has the meaning given to it in Section 16.1.

		
	(n)
	“Capital Reporting Template” means the template set forth in Schedule “M”.

		
	(o)
	“CAPP” means Canadian Association of Petroleum Producers.

		
	(p)
	“CLT” or “Canadian Local Toll” has the meaning given to it in Section 9.1 

		
	(q)
	“Contingent Toll Adjustment” has the meaning given to it in Section 13.1.

		
	(r)
	“Currently Outstanding Adjustment Amounts” has the meaning given to it in Section 11.3.

(3)

		
	(s)
	“Declining Bracket Mechanism” means the methodology approved by the NEB on March 24, 2006 in order number A-TT-FT-ENB 09 (4200-E101-9). (t)    “Dispute” has the meaning given to it in Section 30.1.

		
	(u)
	“Dispute Notice” has the meaning given to it in Section 30.2. 

		
	(v)
	“Enbridge” means Enbridge Pipelines Inc.

		
	(w)       
	“Enbridge  Service  Levels”  means  the  service  levels  described  within the  Enbridge Service Levels Manual as modified from time to time, the current version of which is attached hereto as Schedule “N”.

		
	(x)
	“Enbridge Tariff” means the tolls and tariffs, including the rules and regulations, for the Enbridge Canadian Mainline filed with the NEB.

		
	(y)
	“Enbridge Mainline” has the meaning given to it in Section 1.3.

		
	(z)
	“Enbridge Mainline Receipt & Delivery Points” has the meaning given to it in Section 14.2.

		
	(aa)      
	“Enbridge Specific Regulatory Change” means material change to an Existing Law or the coming into force of a New Law or regulatory action resulting in a Final Order that affects only the Enbridge Mainline, provided such action has not been initiated by Enbridge or Enbridge Energy Limited Partnership or is not the result of negligent or willful misconduct by Enbridge or Enbridge Energy Limited Partnership.

		
	(bb)   
	“Existing Law” means any law, regulation or order of a Canadian or U.S. governmental, tribunal or regulatory body enacted, promulgated, adopted or issued as of July 1, 2011, that has not been repealed, materially revised, rescinded or of spent force before July 1, 2011, even if the date of implementation or the date by which compliance is required occurs after July 1, 2011.

		
	(cc)
	“FERC” means the Federal Energy Regulatory Commission.

		
	(dd)   
	“FERC Tariff Rates” or “FTR” means the existing tariff rates, including the rules and regulations, for the Lakehead System on file and in effect with the FERC, as amended and supplemented from time to time, including those tariff rates that FERC approves to go into effect pursuant to the U.S. Agreements.

		
	(ee)     
	“Final Order” means an order or directive, issued on or after the date the CTS is filed with the NEB, from a regulator having jurisdiction over Enbridge, including an order or directive to perform hydrostatic testing on the Enbridge Mainline,   provided that such order or directive is not an interim order or a recommendation, Enbridge acts reasonably in mitigating the impact of any such order or directive, and Enbridge has given timely notice to the Representative Shipper Group of such order or directive.

		
	(ff)    
	“Force Majeure” means any act of God, war, acts of terrorism, civil disturbances, civil insurrection or disobedience, acts of public enemy, power disruptions or other disruptions of critical services, blockades, insurrections, riots, epidemics, landslides, lightning, 

(4)

earthquakes, explosions, fires or floods, or any other like event which is beyond the reasonable control of Enbridge and which Enbridge has been unable to prevent or provide against by the exercise of reasonable diligence at reasonable cost. For clarity, a pipeline leak, break, pressure restriction, repair, corrosion or other like event shall not on its own be considered a Force Majeure, unless such event is caused by one of the events set forth in the first sentence of this definition.
		
	(gg)
	“GDPP” means the annual average Canada Gross Domestic Product at Market Prices Index, published by Statistics Canada on or about February 28th, (Catalogue No. 13- 019-X “Implicit price indexes, gross domestic product”) for the prior year.

		
	(hh)      
	“GDPP Index” in any given year is calculated as the ratio of the annual change in GDPP over the GDPP for the prior year and is expressed as a percentage. For clarity, the GDPP Index applicable for 2012 would be (GDPP for 2011- GDPP for 2010) / GDPP for 2010.

		
	(ii)
	“IJT” or “International Joint Tariff” has the meaning given to it in Section 8.1.

		
	(jj)
	“Integrity Capital” means Capital Expenditures incurred to repair, maintain or replace portions of the Enbridge Mainline in order to manage pipeline defects, which may occur as metal loss (eg. corrosion), cracks (eg. stress corrosion cracking), and mechanical damage (eg. dents).

		
	(kk)
	“Investment Grade” has the meaning given to it in the Enbridge Tariff.

		
	(ll)
	“Lakehead System” has the meaning given to it in Section 1.2.

		
	(mm)
	“Line 5 Claim” means the claim by Enbridge referenced in Ontario Case Docket No. 07-CV-338616-PD3.

		
	(nn)
	“Line 9” means those assets set forth in Schedule “C”.

		
	(oo)   
	“LMCI” or “Land Matters Consultation Initiative” means the NEB Land Matters Consultation Initiative (RH-2-2008) and the decisions, directions and orders issued in that proceeding.

		
	(pp)
	“Major Enbridge Mainline Expansion Capital” has the meaning given to it in Section 16.3.

		
	(qq)
	“Material Change in Business Circumstances” has the meaning given to it in Section 20.1.

		
	(rr)
	“Minimum Threshold Volume” has the meaning given to it in Section 19.1.

		
	(ss)
	“Monthly Moving Average Volume” has the meaning given to it in Section 19.4. 

		
	(tt)
	“NEB” means National Energy Board.

		
	(uu)     
	“New Law” means any law, regulation, order or directive of a Canadian or U.S, governmental, tribunal or regulatory body enacted, promulgated, issued or adopted after 

(5)

July 1, 2011 and includes any material change to or amendment of Existing Law or any final and binding decision of any relevant judicial or regulatory authority interpreting Existing Law in a manner that is materially different than how such Existing Law was interpreted or applied as of July 1, 2011.
		
	(vv)
	“NGL” means natural gas liquids.

		
	(ww)
	“Nine Month Moving Average” has the meaning given to it in Section 19.3.

		
	(xx)
	“Non Enbridge Mainline Receipt & Delivery Points” has the meaning given to it in Section 14.3.

		
	(yy)     
	“Northern PADD II or Sarnia” means the following delivery points included in the Enbridge Mainline Delivery Points: Clearbrook, Minnesota; Superior, Wisconsin; Lockport   &   Mokena,   Illinois;   Flanagan,   Illinois;   Griffith,   Indiana;   Stockbridge, Michigan;  Marysville,  Michigan;  Rapid  River,  Michigan;  West  Seneca,  New  York; Sarnia, Ontario; and Nanticoke, Ontario.

		
	(zz)   
	“Oil Pipeline Uniform Accounting Regulations” means the Oil Pipeline Uniform Accounting Regulations as issued by the NEB in Canada and 18 C.F.R. Part 352 in the United States.

		
	(aaa)
	“Outstanding Amount Surcharge” has the meaning given to it in Section 11.1.

		
	(bbb)
	“Over/Short Position” has the meaning given to it in Enbridge’s Practice Applicable to Automatic Balancing.

		
	(ccc)     
	“Regulatory Change(s)” means the coming into force of a New Law broadly applicable to the Enbridge Mainline and all similar liquids pipelines, excluding changes to Existing Laws with respect to (i) the FERC Index Rate and, (ii) tax rates, but including, changes to Existing Laws or a New Law that establishes a new type of tax or taxation, such as the implementation of a new carbon tax on the transportation of hydrocarbons.

		
	(ddd)
	“Renegotiation Notice” means a written notice to renegotiate the CTS given  under Article 21;

		
	(eee)
	“Renegotiating Team” has the meaning given to it in Section 21.4.

		
	(fff)
	“Representative Shipper Group” has the meaning given to it in Section 22.2.

		
	(ggg)
	“Shipper” means a shipper of hydrocarbons on the Enbridge Mainline.

		
	(hhh)
	“Shipper of Record” means the Shipper invoiced for provision of services on the Enbridge Mainline.

		
	(iii)
	“Shipper Supported Expansion Project” has the meaning given to it in Section 16.4. 

		
	(jjj)
	“Shippers Line 5 Portion” has the meaning given to it in Section 17.1.

		
	(kkk)
	“Supporting Shipper” means a Shipper who supports a Shipper Supported Expansion Project by executing a Backstopping Agreement pursuant to Article 16. 

(6)

		
	(lll)
	“Term” has the meaning given to it in Section 5.1.

(mmm) “U.S.” means United States of America.
		
	(nnn)  
	“U.S. Agreements” means all existing and future agreements and/or settlements for the transportation of hydrocarbons on the Lakehead System, including but not limited to, those settlements set forth in Schedule ”I”.

		
	(ooo)
	“Western Canadian Producers” means producers of hydrocarbons originating in the Northwest Territories, British Columbia, Alberta, Saskatchewan and Manitoba.

		
	(ppp)
	“Western Canadian Receipt Points” means receipt points on the Canadian Mainline in Alberta, Saskatchewan and Manitoba.

4.    INTERPRETATION
4.1    In the CTS, unless the context otherwise requires:
		
	(a)
	the singular includes the plural and vice versa;

		
	(b)
	a grammatical variation of a defined term has a corresponding meaning;

		
	(c)        
	subject to the definitions of Existing Law and New Law, reference to any law means such law as amended, modified, codified, replaced or re-enacted, in whole or in part, and in effect from time to time, including rules and regulations promulgated thereunder and reference to any section or other provision of any laws means that provision of such law from time to time in effect and constituting the substantive amendment, modification, codification, replacement or re-enactment of such section or other provision;

		
	(d)        
	references to an Article, Section, Subsection, Paragraph or Schedule by number or letter or both refer to the CTS;

		
	(e)        
	“CTS”, “the CTS”, “herein”, “hereby”, “hereunder”, “hereof”, “hereto” and words of similar import are references to the whole of the CTS in which it is used and not, unless a particular Section or other part thereof is referred to, to any particular Section or other part;

		
	(f)
	“including” means including without limiting the generality of any description preceding or succeeding such term and for purposes hereof the rule of ejusdem generis shall not be applicable to limit a general statement, followed by or referable to an enumeration of specific matters, to matters similar to those specifically mentioned;

		
	(g)        
	Schedules attached to the CTS, form part of the CTS.  Where there is a conflict between the body of the CTS and any Schedule other than Schedules “J”, “K”, “L”, “M” and “O”, the language of such Schedule will prevail.  Schedules “J”, “K”, “L”, “M” and “O” are included for illustrative purposes only, and where there is a conflict between the body of the CTS and a Schedule, the body of the CTS will prevail for only those Schedules;

		
	(h)
	the phrases “the aggregate of”, “the total of”, “the sum of”, or a similar phrase means “the aggregate (or total or sum), without duplication, of”;

(7)

		
	(i)
	all references to currency are to the lawful money of Canada, unless otherwise indicated; 

		
	(j)
	references to time of day or date means the local time or date in Calgary, Alberta;

		
	(k)        
	if any word, phrase or expression is not defined in the CTS, such word, phrase or expression will, unless the context otherwise requires, have the meaning attributed to it in the  usage  or  custom  of  the  hydrocarbon  pipeline  transportation  business  in  North America;

		
	(l)
	where any payment or calculation is to be made, or any other action is to be taken, on or as of a day that is not a business day, that payment or calculation is to be made, or that other action is to be taken, as applicable, on or as of the next following business day; and

		
	(m)
	the  division  of  the  CTS  and  the  recitals,  table  of  contents  and  headings  are  for convenience of reference only and shall not affect the construction or interpretation hereof.

(11)

PART III – TERM AND APPLICABILITY

		
	5.
	TERM OF SETTLEMENT

		
	5.1
	The term of the CTS will commence July 1, 2011 and terminate on June 30, 2021 (the “Term”), unless terminated earlier hereunder or extended pursuant to Section 5.2.  The CTS will replace the 2011 ITS, effective as of the start of the Term.

		
	5.2
	The Term may be extended by mutual agreement of Enbridge and the 2021 Negotiating Team, provided that such extension shall be for a period of no less than 1 year.

		
	6.
	APPLICABILITY OF CTS vs. CANADIAN AGREEMENTS

		
	6.1
	During the Term, the CTS will supersede the Canadian Agreements, provided however that any calculations that would otherwise have been made pursuant to the Canadian Agreements will be deemed to have been made during the Term.

		
	6.2
	Upon the termination or expiry of the CTS, any of the Canadian Agreements that have not expired or terminated will come back into effect as of the date of termination or expiry of the CTS.   Any toll and other adjustments that are permitted in the Canadian Agreements shall continue thereafter for their respective then remaining terms.  For clarity, the terms under any of the Canadian Agreements shall be deemed to have been applicable during the Term and shall continue to apply thereafter.  The assets under the Canadian Agreements will be included in the Canadian Mainline at their remaining undepreciated costs.  An illustrative example is set forth in Schedule “J”.

		
	6.3
	Notwithstanding this Article 6, CAPP preserves the audit rights pursuant to the terms of the Alberta Clipper Canada Settlement agreement.

		
	7.
	APPLICABILITY OF CTS vs. U.S. AGREEMENTS

		
	7.1
	Subject to Section 7.2, the U.S. Agreements will remain in place, and the tariff rates on file with FERC and in effect from time to time pursuant to such U.S. Agreements shall continue to be utilized in calculating the FTR during the Term but neither such tariff rate nor the FTR will apply to hydrocarbons transported under the IJT during the term of the CTS unless otherwise agreed between Enbridge and the Representative Shipper Group pursuant to Section 13.1.

		
	7.2
	Where any of the U.S. Agreements expires or terminates during the Term and is replaced by a future  agreement  and/or  settlement  for  the  transportation  of  hydrocarbons  on  the  Lakehead System, such future agreements and/or settlements will apply in accordance with their respective terms; provided, however, that any tariff rates on file with FERC and in effect from time to time pursuant to such future agreements and/or settlements will not apply to hydrocarbons transported under the IJT unless otherwise agreed between Enbridge and the Representative Shipper Group pursuant to Section 13.1   Any toll and other adjustments that are permitted pursuant to a U.S. Agreement shall continue to be utilized in calculating the FTR during the Term.

(12)

PART IV – TOLLS AND RELATED FINANCIAL MATTERS

		
	8.
	INTERNATIONAL JOINT TOLLS

		
	8.1
	Subject to applicable law, effective as of July 1, 2011, tolls for transportation, inclusive of receipt and delivery terminalling services, of hydrocarbons from Western Canada Receipt Points on the Enbridge Mainline to delivery points (i) on the Lakehead System, and (ii) on the Canadian Mainline that are downstream of the Lakehead System are the amounts set forth in Schedule “D” as adjusted pursuant to Section 10.1 (the “International Joint Tariff” or “IJT”).  All IJT tolls are calculated on a distance adjusted basis for transmission and for commodity types, based on and with reference to an initial IJT toll of U.S. $3.85 per barrel for movement of heavy crude oil from Hardisty, Alberta to any of the delivery points in the Chicago, Illinois area (Mokena, Griffith, Lockport).   In addition, the applicable Outstanding Amount Surcharge as provided in Section 11 will also be collected.

		
	9.
	CANADIAN LOCAL TOLLS

		
	9.1
	Subject to applicable law, and approval by the NEB, effective as of July 1, 2011, tolls, inclusive of receipt and delivery terminalling services, for transportation of hydrocarbons solely on the Canadian Mainline are the amounts set forth in Schedule “E” (the “Canadian Local Toll”, or “CLT”).  The CLTs are calculated using the 2011 Interim ITS Tolls as a starting point, adjusted for the Currently Outstanding Adjustment Amounts outlined in Section 11.3 which will be collected through the Outstanding Amount Surcharge.  The CLT is intended to replace the 2011 Interim ITS Tolls as of July 1, 2011.  After July 1, 2011 there will be no further true-up for prior Canadian Mainline tolls.

		
	10.
	ANNUAL TOLL ADJUSTMENT

		
	10.1
	Commencing effective July 1, 2012, the IJT tolls and the CLT shall be adjusted annually, up or down, at a rate equal to 75% of the GDPP Index.

		
	10.2 
	The tankage revenue requirement used to determine receipt and delivery tankage fees in Canada in effect on July 1, 2011 will be adjusted annually, up or down, by 75% of the GDPP Index beginning July 1, 2012.  An annual volume forecast will then be used to determine the average tankage fees in effect on July 1 each year and establish the actual receipt and delivery tankage fees in accordance with the Declining Bracket Mechanism.  If the actual revenues collected for receipt and delivery tankage fees are greater than, or less than, what the tankage revenue requirement was for the applicable calendar year, (including differences due to the Declining Bracket Mechanism), then such difference will be used to subtract from or add to, as applicable, the next year’s tankage revenue requirement.  Shippers will be required to pay the applicable receipt and delivery tankage fees for volumes transported under the IJT or the CLT. Notwithstanding the preceding, Enbridge may seek future  NEB approval for a different toll design and regulatory treatment for tankage fees with the endorsement of the Representative Shipper Group.

		
	10.3
	The CLT from receipt points in Canada to the International Boundary, near Gretna, Manitoba, from the International Boundary, near Sarnia, Ontario to delivery points in Canada and from receipt points in Ontario to the International Boundary, near Chippawa, Ontario will be further adjusted in the event that the sum of the CLT and FTR is not greater than or equal to the IJT tolls in effect in any given year.  Enbridge will file with the NEB an application to adjust only the CLT from 

(13)

receipt points in Canada to the International Boundary near Gretna, Manitoba; from the International Boundary, near Sarnia, Ontario to delivery points in Canada; and from receipt points in Ontario to the International Boundary, near Chippawa, Ontario to ensure that the IJT is maintained in accordance with regulatory requirements.

		
	11.
	OUTSTANDING AMOUNT SURCHARGE

		
	11.1
	A per barrel toll surcharge in the amount set forth in Schedule “F” (the “Outstanding Amount Surcharge”) will be added to the IJT tolls and the CLT for the 24 month period from July 1, 2011 to June 30, 2013 in order to permit Enbridge to collect Currently Outstanding Adjustment Amounts. The Outstanding Amount Surcharge is $0.067 per barrel for movements of heavy crude oil from Hardisty, Alberta to the U.S. border near Gretna, Manitoba and is adjusted for distance and by commodity-type for all barrels transported in Canada.

		
	11.2
	Any of the Currently Outstanding Adjustment Amounts that remain uncollected by Enbridge as of June 30, 2013 shall be immediately due to Enbridge.  Likewise, an over collection of the Currently   Outstanding   Adjustment   Amounts   collected   through   the   Outstanding   Amount Surcharge as of June 30, 2013 will be immediately due to the Shippers.  For clarity, any under or over collection of the Currently Outstanding Adjustment Amounts as of June 30, 2013 will be recovered or paid by increasing or decreasing, as applicable, the 2014 IJT and CLT tolls effective July 1, 2014 through a one-time surcharge, which adjustment will be on a per barrel basis. The Outstanding Amount Surcharge will be based on a forecast of total sum shipment volume for the IJT and CLT for the calendar year beginning July 1, 2014, which surcharge will be adjusted for distance and by commodity-type for all barrels transported in Canada.   Any under or over collection remaining as of July 1, 2015 will not be collected or refunded.   For clarity, the Currently Outstanding Adjustment Amounts are amounts due to Enbridge as a result of the interim tolls from January 1, 2010 to June 30, 2011.  Any variance relative to the period from April 1, 2011 to June 30, 2011 shall be for Enbridge’s sole account.

		
	11.3
	The “Currently Outstanding Adjustment Amounts” total $69.7 million and is comprised of the following:

(i)         a total of $130.0 million as of December 31, 2010 to recover the remaining 2010 ITS revenue shortfall;
		
	(ii)
	a total of $72.7 million as of March 31, 2011 to credit all applicable net tax loss carry forwards calculated using the applicable 2011 tax rates; and

		
	(iii)
	a total of $12.4 million to recover amounts due to Enbridge under the 2011 ITS for the toll variance from January 1, 2011 until March 31, 2011.

		
	12.
	ALLOWANCE OIL

		
	12.1
	For transportation under the IJT, Enbridge shall collect in kind a percentage of all hydrocarbons delivered off the Enbridge Mainline in the amount of 1/10th of 1 percent of the volume of hydrocarbons physically delivered under the IJT.  The IJT Allowance Oil will be collected and divided between the Canadian Mainline and the Lakehead System as 1/20th of 1 percent to each carrier.

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	12.2
	For transportation under the CLT, Enbridge shall collect in kind or deduct as Allowance Oil a percentage of all hydrocarbons delivered off the Enbridge Mainline, in the amount of 1/20th of 1 percent of the volume of hydrocarbons physically delivered under the CLT.

		
	12.3
	Enbridge  shall  be  permitted,  at  its  discretion,  to  resell  to  Shippers  the  Allowance  Oil hydrocarbons  collected  for  transportation  under  the  IJT  or  CLT  at  a  price  determined  in accordance with the method described in the following Sections.

		
	12.4
	Each month, each Shipper who either: (i) has crude or NGL delivered off the Enbridge Mainline in such month; or (ii) holds an Over/Short Position on the Enbridge Mainline at the end of such month, shall furnish to Enbridge a unit price for each crude and NGL stream delivered or held, as applicable.   For each refined product stream Enbridge will utilize the prices it receives from refined product Shippers for the purpose of balancing delivery of product batches.  Except as provided below, the prices for crude, NGL, and refined product streams so furnished shall be the prices at which Shippers’ Allowance Oil for each hydrocarbon stream tendered to Enbridge by each Shipper shall be resold to each Shipper by Enbridge.

		
	12.5
	In the event that a Shipper does not provide a price for any crude or NGL stream, the Allowance Oil value for that Shipper will be deemed to be the simple average of the prices for that crude or NGL stream received by Enbridge from all other Shippers of that crude or NGL stream for the month that the Allowance Oil volume is being collected whose transaction prices have been accepted by Enbridge as reasonable pursuant to Section 12.6.

		
	12.6
	Notwithstanding the provisions of Section 12.4, if the price furnished to Enbridge by any Shipper for any crude or NGL stream is unreasonable, in the sole opinion of Enbridge, acting reasonably, the Allowance Oil resale value for that Shipper for the crude or NGL stream in question shall be the simple average of the prices for that crude or NGL stream received by all other Shippers of that crude or NGL stream for the month whose transaction prices have been accepted by Enbridge as reasonable.   Alternatively, Enbridge may choose to use the average of the monthly prices posted for light sweet crude at Edmonton by Imperial Oil Limited, Shell Canada Ltd., Flint Hills Resources and Suncor Energy Inc., or their respective successors, adjusted for quality, pursuant to industry information determined by Enbridge.  The average of the monthly prices posted for light sweet crude at Edmonton must be based on all posted prices if all are posted, but if not all are posted, based on no less than three posted prices.  In the event that the posted prices cannot be determined in accordance with the above, Enbridge will meet with impacted Shippers to negotiate an appropriate price.

		
	13.
	CONTINGENT TOLL ADJUSTMENTS

		
	13.1
	In addition to those other adjustments described in this Part IV, the IJT and the CLT will be adjusted for the following, subject to NEB approval (each, a “Contingent Toll Adjustment”):

		
	(a)       
	any  changes  in  toll  methodology  that  may  be  agreed  to  by  Enbridge  and  the Representative Shipper Group;

		
	(b) 
	any incremental tolls resulting from an NEB order in relation to the Land Matters Consultation Initiative;

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	(c)
	any Major Enbridge Mainline Expansion Capital as described in Article 16;

		
	(d)
	any Material Change in Business Circumstances as described in Article 20; and

		
	(e)
	any other changes that are mutually agreed to by Enbridge and the Representative Shipper Group.

		
	13.2
	For clarity, if Enbridge and the Representative Shipper Group are unable to reach agreement on the amount of any Contingent Toll Adjustment identified under Section 13.1 (c) or (d), then Enbridge  or  the  Representative  Shipper  Group  may  refer  the  issue  of  the  amount  of  the Contingent Toll Adjustment to dispute resolution under Article 30.

		
	13.3
	If the NEB does not approve any Contingent Toll Adjustment identified under Section 13.1 that has been agreed to by Enbridge and the Representative Shipper Group, then a NEB hearing to determine the amount of such Contingent Toll Adjustment may be requested.

		
	14.
	TOLL INCENTIVES

		
	14.1
	Enbridge may offer toll incentives onto the Enbridge Mainline, provided such toll incentives on the Enbridge Mainline are offered equally to all Shippers to all Enbridge Mainline Receipt & Delivery Points, as adjusted for distance and commodity types.

		
	14.2
	“Enbridge Mainline Receipt & Delivery Points” means those receipt and delivery points as set forth in Schedule “A” and Schedule “B” as may be adjusted with the agreement of Enbridge and the Representative Shipper Group. For greater certainty, the IJT tolls applicable to delivery points on the Enbridge Mainline shall be the same, irrespective of the specific facilities or path used to effect such deliveries.

		
	14.3 
	"Non Enbridge Mainline Receipt & Delivery Points"are not Enbridge Mainline Receipt & Delivery Points.

		
	14.4
	A toll incentive may also be offered for delivery of hydrocarbons to Non Enbridge Mainline Receipt & Delivery Points subject to Section 14.5.

		
	14.5
	As required by regulations, tolls to Non Enbridge Mainline Receipt & Delivery Points must be greater than the toll to the nearest upstream Enbridge Mainline Receipt & Delivery Point and must be offered equally to all similarly situated Shippers, as adjusted for distance and commodity types.

		
	15.
	LAND MATTERS CONSULTATION INITIATIVE

		
	15.1
	All Canadian pipeline assets owned by Enbridge that are regulated by the NEB, including the Canadian  Mainline,  are  being  addressed  in  the  LMCI.     The  LMCI  will  determine  the methodology by which costs for abandonment should be collected by a pipeline.  Enbridge will file all required information under LMCI as per the NEB schedules for the Canadian Mainline.

		
	15.2
	The CTS is unrelated to the ultimate decision regarding the responsibility for abandonment costs for the Canadian Mainline.  The CTS is agreed to on a “without prejudice” basis with respect to pipeline abandonment costs for the Canadian Mainline and does not in any way limit either Enbridge or any Shipper’s right to make submissions and fully participate in the LMCI or any other proceeding related to abandonment of a pipeline.

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16.    CAPITAL EXPENDITURES
		
	16.1
	“Capital Expenditures” means expenditures on the Enbridge Mainline made by Enbridge which, under Oil Pipeline Uniform Accounting Regulations, require capitalization as fixed assets and which would be capitalized on, or after, July 1, 2011. Capital Expenditures must be prudent, reasonable and to the benefit of the Enbridge Mainline and include, but are not limited to, maintenance, integrity, equipment additions, improvements and new facilities. Capital Expenditures would include expansion of the Enbridge Mainline such as expanded pipeline capacity, increased storage capacity, or the creation of new or expansion of existing Enbridge Mainline Receipt & Delivery Points.

		
	16.2
	Enbridge is responsible for all Capital Expenditures during the Term, meaning the IJT tolls and CLT will not be adjusted for Capital Expenditures unless otherwise agreed to by Enbridge and the Representative Shipper Group.  The 2012 Edmonton Tanks are deemed to be included in the Canadian Mainline as at June 30, 2011, and are therefore included in the IJT tolls and the CLT.

		
	16.3
	Enbridge will negotiate with the Representative Shipper Group prior to undertaking any single project on the Enbridge Mainline with expected Capital Expenditures greater than $250 million that  expands  pipeline  capacity,  increases  storage  capacity,  or  creates  or  expands  Enbridge Mainline Receipt & Delivery Points (“Major Enbridge Mainline Expansion Capital”). With the agreement of Enbridge and the Representative Shipper Group, the IJT tolls and respective CLT may be adjusted to allow Enbridge to recover Major Enbridge Mainline Expansion Capital as allowed for under Section 13.1(c).  An illustrative example of Major Enbridge Mainline Expansion Capital is set forth as Example #1 in Schedule “K”.

		
	16.4
	Projects  on  the  Enbridge  Mainline  which  require  Capital  Expenditures  and  which  are  not supported by Enbridge because the incremental revenues associated with such project would not cover the incremental costs, may proceed if there is sufficient financial support from Supporting Shipper(s) pursuant to this Article 16 (a “Shipper Supported Expansion Project”).   An illustrative example of a Shipper Supported Expansion Project is set forth as Example #2 in Schedule “K”.

		
	16.5
	By execution of a Backstopping Agreement and confirmation that the proposed project creates no adverse operational issues for Enbridge, as determined by Enbridge acting reasonably, Enbridge will agree to undertake such Shipper Supported Expansion Projects in accordance with the terms of such Backstopping Agreement.  In the event that Enbridge is unable to secure NEB approval for construction of the Shipper Supported Expansion Project, the Supporting Shipper(s) will be required to reimburse Enbridge for all of such Shipper Supported Expansion Project’s reasonable and prudent development costs as defined in the applicable Backstopping Agreement.

		
	16.6
	Subject to Section 16.10, additional revenues derived from tolls, including receipt and delivery terminalling and transmission, collected on the incremental volumes transported on the Enbridge Mainline related to such Shipper Supported Expansion Project, net of any direct incremental costs (“Net  Incremental  Revenue”)  will  be  credited  to  the  Backstopping  Agreement’s  revenue requirement.

		
	16.7
	The Backstopping Agreement will ensure that the annual revenue requirement associated with the incremental project capital is met either through Net Incremental Revenue from associated 

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incremental throughput or with annual or lump sum payments from the Supporting Shipper(s). The form and terms of a Backstopping Agreement will be developed on a project by project basis but will utilize the following parameters: a) the term will be no less than 5 years and no more than 10 years and can extend past the end of the Term; b) threshold return on equity of between 11 to 15 percent after tax; and c) capital structure of 45 percent equity.  The return on equity will be negotiated between Enbridge and the Supporting Shipper(s), and the parties acting reasonably will consider such risks as volume, capital, cost, credit, financial or other relevant risks.  An 11 percent return would be appropriate in a circumstance when Enbridge accepted no volume risk, did not share in any operating or capital cost risk, and credit risk was secured by either a letter of credit or a shipper with an Investment Grade credit rating. A 15 percent return would be appropriate in a circumstance when Enbridge accepts substantially more risk with respect to volumes, capital, cost, credit or financial elements of the project. Similar Shipper Supported Expansion Projects will be evaluated on a similar basis and using similar principles.
		
	16.8 
	At the end of the Term, there will be no net rate base impact to the Enbridge Mainline as a result of Shipper Supported Expansion Projects.

		
	16.9
	For  example,  for  a  Shipper  Supported  Expansion  Project  to  construct  new  tanks,  the Backstopping Agreement will require the recovery of the capital cost of the tank through accelerated depreciation.  To the extent that such accelerated depreciation exceeds Enbridge’s normal depreciation rates, the excess will be credited against rate base and future depreciation expense will be reduced accordingly.

		
	16.10
	Enbridge will consider the Net Incremental Revenue from incremental volumes associated with the Shipper Supported Expansion Projects compared to the incremental capital cost to determine the amount and type of Backstopping Arrangement it will require.  To establish incremental volumes from existing movements, Enbridge will use an appropriate time frame, typically the 12 month period immediately preceding the month in which Enbridge anticipates the in-service date for the new facilities.

		
	16.11
	The  Backstopping  Agreement  will  incorporate  any  terms  that  would  allow  the  Supporting Shipper(s)’s commitment to be reduced by Net Incremental Revenue or capital contribution provided by one or more other Shipper(s).

		
	16.12
	Backstopping Agreements are to allow the provision of services, but nothing in this Section 16 is intended to provide any priority service to Supporting Shipper(s).

		
	17.
	LINE 5 CLAIM

		
	17.1
	Following final resolution of the Line 5 Claim, the Canadian Mainline portion of any amounts (net of reasonable litigation costs incurred after June 30, 2011) actually paid to Enbridge, recovered for that period of the Line 5 Claim from January 1, 1995 to March 31, 2011, including any accrued interest, shall be determined, and such portion shall be shared between Enbridge and the Shippers, with Enbridge to receive 50% and the Shippers to receive 50% (the "Shippers Line 5 Portion”).  Enbridge shall credit the Shippers Line 5 Portion against the next applicable toll filing for both the IJT and the CLT. The Shippers Line 5 Portion will be calculated on the basis of the required 

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sharing under the various incentive tolling settlements that cover the period from January 1, 1995 to March 31, 2011 where the associated costs were shared between Enbridge and the Shippers.

		
	18.
	COMMODITY SURCHARGE

		
	18.1
	Any changes in the commodity surcharge in effect on April 1, 2011, must be mutually agreed to by both Enbridge and the Representative Shipper Group.  The intent of any adjustment to the commodity surcharge methodology considered during the Term is to be revenue neutral.

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PART V - RENEGOTIATION AND/OR TERMINATION OF THE CTS

		
	19.
	MIMIMUM THRESHOLD VOLUMES

		
	19.1
	“Minimum Threshold Volume” means a throughput of:

		
	(a)
	1,250,000 barrels per day to December 31, 2014, then

		
	(b)
	1,350,000 barrels per day during the remainder of the Term of Canadian Sourced Hydrocarbons on the Enbridge Mainline ex-Gretna, Manitoba, as may be adjusted pursuant to Section 19.2 and 19.5.

		
	19.2
	The Minimum Threshold Volume will be reduced by the amount that the Bakken/Three Forks U.S. production receipts exceed 305,000 barrels per day into the Enbridge Mainline, less those volumes in excess of 305,000 barrels per day that are transported to delivery points other than the Enbridge Mainline Delivery Points into Northern PADD II or Sarnia (for example, incremental transportation of Bakken/Three Forks U.S. production on Mustang/Spearhead or other Non Enbridge Mainline Delivery Points).

		
	19.3
	“Nine Month Moving Average” means the sum of the Monthly Moving Average Volumes for the 9 months preceding the date of calculation, divided by 9.

		
	19.4
	“Monthly Moving Average Volume” means the volume of Canadian Sourced Hydrocarbons transported on the Enbridge Mainline ex-Gretna, Manitoba in a calendar month, divided by the number of days in such month.

		
	19.5
	In the event that Nine Month Moving Average falls below the Minimum Threshold Volume, Enbridge and the Representative Shipper Group will determine if the cause of the shortfall was due to capacity loss on the Enbridge Mainline.  If it is determined that the shortfall was due to capacity loss on the Enbridge Mainline for reasons other than Force Majeure, the Minimum Threshold Volume will be reduced by the corresponding shortfall amount. For purposes of determining the applicable capacity loss, Enbridge will use the historical Nine Month Moving Average of volumes from Canadian receipt points through Gretna as well as deliveries ex- Superior.     Schedule  “G”  sets  forth  upstream  and  downstream  capacity  amounts  as  at December 31, 2010 as reference points for ex-Gretna capacity.

		
	19.6
	Illustrative examples of the calculation of Minimum Threshold Volume are set forth in Schedule “L”.

		
	20.
	MATERIAL CHANGE IN BUSINESS CIRCUMSTANCES

		
	20.1
	“Material Change in Business Circumstances” means:

		
	(i)
	Regulatory  Change(s)  or  Enbridge  Specific  Regulatory  Change(s)  which  results  in cumulative  expenditures in a calendar year for operating costs on the Enbridge Mainline, calculated to include an amount for depreciation expense (not including depreciation expense resulting from Integrity Capital ) and subtract applicable capital cost allowance, increasing by more than $10,000,000 over what such annual operating costs would have been (based on Enbridge’s applicable operating standards immediately prior to the 

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Regulatory Change(s) or Enbridge Specific Regulatory Change(s)) absent the Regulatory Change(s) or Enbridge Specific Regulatory Change(s); or
		
	(ii)        
	Regulatory Change(s) which results in cumulative expenditures (commencing on the date of the first such Regulatory Change) for Integrity Capital on the Enbridge Mainline increasing by more than $100,000,000 over what such costs would have been absent the Regulatory Changes, provided however that such Regulatory Changes(s) are broadly applicable to the Enbridge Mainline and all similar liquids pipelines.

		
	20.2 
	The IJT and CLT include (and therefore Enbrige is responsible for) the first $10,000,000 in operating  expenses  in  each  calendar  year  on  the  Enbridge  Mainline  associated  with  any Regulatory  Changes  or  Enbridge  Specific  Regulatory  Changes,  as  applicable,  and  the  first $100,000,000 of Integrity Capital during the Term on the Enbridge Mainline associated with any Regulatory Changes.  In calculating that amounts attributable to such operating expenses or Integrity Capital, Enbridge shall deduct from such calculation any amount that Enbridge would have otherwise spent absent such Regulatory Change or Enbridge Specific Regulatory Change, as applicable.

		
	21.
	EVENTS TRIGGERING A RENEGOTIATION PERIOD

		
	21.1
	If the Keystone XL pipeline project does not receive the required U.S. presidential permit by January 1, 2013, then the Representative Shipper Group may, on or before February 1, 2013, provide to Enbridge a Renegotiation Notice.

		
	21.2
	If the Material Change in Business Circumstances referred to in Section 20.1(ii) occurs, Enbridge will, as soon as reasonably practicable following such occurrence, provide notice to the Representative Shipper Group.  Following receipt of such notice, the Representative Shipper Group and Enbridge shall meet to determine whether they can agree to a Contingent Toll Adjustment under Article 13.  In the event a Contingent Toll Adjustment is not agreed to within 90 days, then the Representative Shipper Group may provide to Enbridge a Renegotiation Notice.

		
	21.3
	If the Nine-Month Moving Average is less than the Minimum Threshold Volume, then Enbridge may, as soon as is reasonably practicable following the occurrence of such event, provide to the Representative Shipper Group a Renegotiation Notice.

		
	21.4
	Upon receipt by either Enbridge or the Representative Shipper Group of a Renegotiation Notice, Enbridge and the Representative Shipper Group (the “Renegotiating Team”) shall meet and use reasonable efforts to agree on how the CTS can be amended to accommodate the events referred to in Section 21.1, 21.2, or 21.3 above.

		
	21.5
	If, within 90 days following receipt of the Renegotiation Notice, the Renegotiating Team is unable to agree on how the CTS can be amended, then the Renegotiating Team may agree to extend the renegotiation period.   If the Renegotiating Team does not agree to extend the renegotiation period, then the CTS terminates and Enbridge will file a new toll application for the Canadian Mainline.

		
	21.6
	The IJT and the CLT will apply during the renegotiation period and will become the interim toll after the renegotiation period until a new toll filing is approved by the NEB.

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PART VI – OTHER CTS MATTERS

		
	22.
	REPRESENTATIVE SHIPPER GROUP

		
	22.1
	Enbridge will work with its Shippers, CAPP and Western Canadian Producers to develop, by July 3, 2012, and thereafter file with the NEB, a transparent process, in compliance with current regulatory requirements, to review and administer issues related to the CTS and the formation of the  Representative  Shipper  Group.    This  process  is  intended  to  be  used  toward  reaching agreement on the resolution of issues related to the CTS during the Term and to provide a counter-party to negotiate any required changes to the CTS resulting from unanticipated events relating to the CTS, with a view to reducing adversarial aspects of NEB and FERC hearings, as well as reducing hearing time and associated costs.

		
	22.2
	The Representative Shipper Group will have representation from CAPP, CAPP members and other Shippers or interested parties as applicable (the “Representative Shipper Group”).

		
	23.
	SERVICE LEVELS

		
	23.1
	The Enbridge Service Levels, as adjusted from time to time, will continue to apply.

		
	24.
	GENERAL TANKAGE PRINCIPLES

		
	24.1
	During the Term, Enbridge will provide sufficient receipt and breakout tankage to manage the receipt and transportation of crude petroleum in accordance with the Enbridge Service Levels under normal operating conditions.

		
	24.2
	Any incremental delivery tankage requirements requested by a Shipper are the responsibility of that Shipper.

		
	25.
	END OF TERM ISSUES

		
	25.1
	Enbridge and the Representative Shipper Group will, no later than July 1, 2019, establish a group for  the  purposes  of  negotiating  a  new  settlement  following  expiry  of  the  CTS  (the  “2021 Negotiating Team”).  The 2021 Negotiation Team will begin to negotiate a new settlement that is applicable after the expiry of the CTS.   The 2021 Negotiating Team will also review and endorse discretionary capital projects proposed by Enbridge under the CTS in the last two years of the CTS, prior to Enbridge undertaking any such discretionary capital projects.  Discretionary capital projects will include any projects less than $250 million excluding maintenance capital and Integrity Capital projects. If negotiations for a new settlement fail, the CTS will terminate on June 30, 2021 and Enbridge will, exercising reasonable diligence, file a new application for tolls with the NEB for the Canadian Mainline.   The IJT and CLT tolls will become the interim tolls until the new toll application is approved by the NEB.

		
	25.2
	At the end of the Term, Enbridge will not carry forward amounts based on toll or volume variances in a new settlement agreement or extended CTS unless otherwise agreed to by Enbridge and the 2021 Negotiation Team.

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	25.3
	Unless otherwise mutually agreed to by Enbridge and the 2021 Negotiating Team, the cumulative amount spent by Enbridge on maintenance and integrity in the last two years of the CTS must be equal to or greater than an amount equal to the average annual amount spent by Enbridge on maintenance and integrity, excluding any amounts spent as a result of Regulatory Changes or Enbridge Specific Regulatory Changes, in the first eight years of the CTS multiplied by 2.

		
	25.4
	The 2010 Depreciation Technical Update Study incorporates a truncation date of 2039 which was approved by the NEB on May 8, 2010.   At the end of the Term, the depreciation rates to be applied to rates subject to the NEB’s jurisdiction, exclusive of the rates covered by Section 25.5 below,  will  be  based  on  the  depreciation  truncation  date  implicit  in  the  2010  Depreciation Technical Update Study subject to Section 25.5.

		
	25.5
	Applicable depreciation rates for the assets comprising the Enbridge Mainline are set forth in Schedules “H” and “I”.

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PART VII – GENERAL PROVISIONS

		
	26.
	REPORTING AND FILING REQUIREMENTS

		
	26.1
	Each February during the Term, Enbridge will provide the Representative Shipper Group with a summary of capital additions for the prior year and forecast capital additions for the current year to the Enbridge Mainline rate base in total and will detail individual items that exceed $50 million, and the aggregate amount of capital under Shipper Supported Expansion Project(s) in accordance with the Capital Reporting Template. Enbridge will continue to meet with Shippers to annually review the Enbridge Mainline integrity plan, metrics and overall operating plan.

		
	26.2
	In addition, each February of 2019, 2020 and 2021, Enbridge will provide a summary of the forecast capital additions to the Enbridge Mainline rate base for all pending projects or future projects anticipated to be initiated before the end of the Term that exceed $50 million that could result in an addition to the Enbridge Mainline rate base either before or after the end of the Term.

		
	26.3
	Enbridge shall file with the applicable regulator and make available to interested parties copies of the CTS tolls and tariffs for each year.

		
	26.4
	Subject to NEB approval, the intention of the CTS is that Enbridge will be exempt from the requirement for Enbridge to file financial forecasts and Financial Surveillance Reports, consistent with the relief granted pursuant to Board Order TO-3-2000, as amended.

		
	27.
	AUDIT

		
	27.1
	Enbridge shall file an external auditors’ report for the Enbridge consolidated financial statements with the NEB annually for each fiscal year ending December 31 by March 31 of the following year. The same such auditor’s report will be provided to all other interested parties on request.

		
	27.2
	The Enbridge consolidated financial statements for each fiscal year ending December 31st will be audited by an independent auditor and reported in a manner consistent with Canadian Auditing Standards.  The purpose of this audit is to confirm that the financial results as reflected on are in accordance with the provisions of the CTS, including the completeness and accuracy of the annual tolls and any relevant surcharges.

		
	27.3
	Upon 60 days notice to Enbridge by the Representative Shipper Group, and subject to Enbridge’s confidentiality obligations to third parties, the Representative Shipper Group shall be able to, on two occasions, elect to engage an independent accountant or other auditor to conduct its own audit of the Enbridge financial results and of all data and information related to and necessary to establish compliance with the CTS, provided that no such audit shall occur any later than 24 months from the end of the Term.  The independent accountant or other auditor will enter into a confidentiality agreement with Enbridge to ensure non-disclosure of confidential or commercial information.  Enbridge agrees to undertake all reasonable commercial efforts to assist in the completion of the audit on a timely basis, during normal business hours.  Shippers shall bear all third party costs associated with such audits.

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	28.
	ACCOUNTING

		
	28.1
	Enbridge will continue to use flow through tax accounting as directed by the NEB under order Order TO-1-92.

		
	29.
	AFFILIATES

		
	29.1
	Enbridge agrees  to abide by the Enbridge Canadian Affiliate Relationship Code which was developed in collaboration with CAPP, as may be amended from time to time, the current version of which is posted on Enbridge’s website at:

http://www.enbridge.com/InvestorRelations/CorporateGovernance/~/media/Site%20Documents/ Investor%20Relations/Corporate%20Governance/Key%20Documents/carc-epi-2010.ashx .

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	30.
	DISPUTE RESOLUTION

		
	30.1
	To facilitate the resolution of any disputes regarding the CTS in an efficient and expedited manner, disputes arising under this CTS (“Dispute”) shall be resolved in accordance with the dispute resolution mechanism set forth in this Article 30.  For clarity, this Article 30 is not intended to permit a party to renegotiate terms that have been agreed to in the CTS or to resolve deadlocks between the parties over an action where the approval of any parties is required under this CTS to such action.

		
	30.2
	In the event of a Dispute, either of Enbridge or a Shipper(s) (the Shipper or group of Shippers initiating the Dispute the “Disputing Shipper Group”) that wishes to initiate dispute resolution shall  give  written  notice  (the  “Dispute  Notice”)  to  any  party  of  a  Dispute  and  outline  in reasonable detail the relevant information concerning the Dispute.  The Disputing Shipper Group may self-form and is not dependent on formation pursuant to Section 22.1.  Within fourteen (14) days following receipt of the Dispute Notice, Enbridge and the Disputing Shipper Group will each appoint representatives to meet to discuss and attempt to resolve the Dispute.   Such representatives shall be individuals that are technically qualified to appreciate and assess the Dispute and have authority to negotiate the Dispute.  If the Dispute is not settled within ninety (90) days of receipt of the Dispute Notice, the negotiation will be deemed to have failed.

		
	30.3
	If the Dispute is not resolved pursuant to the process above, the Dispute may be referred to the NEB or other applicable regulator by either Enbridge or the Disputing Shipper Group, to be resolved on an expedited basis.

		
	30.4
	Notwithstanding the above, any parties retain all rights for dispute resolution with the applicable regulator.

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PART VIII – LINE 9 MATTERS

		
	31.
	LINE 9

		
	31.1
	Enbridge owns and operates Line 9, a common carrier pipeline system regulated under the NEB Act. The assets included in Line 9 are outlined in Schedule “C”.

		
	31.2
	Line 9 tolls are currently set on a standalone basis and will continue to be set on a standalone basis under the CTS regardless of whether Line 9 is used for East to West or West to East service or is used for partial East to West and partial West to East service.  Standalone tolling under the CTS continues to treat Line 9 assets as separate and distinct assets from the Enbridge Mainline assets.   Standalone tolling under the CTS continues to base Line 9 tolls on the separate and distinct Line 9 rate base.

		
	31.3
	Line 9 tolls are currently published under an NEB approved Line 9 Tariff. Subject to applicable law and approval by the NEB, tolls for transportation of hydrocarbons on Line 9 will continue to be published under a separate Line 9 tariff. In the event that Enbridge applies to reverse service on Line 9 and such reversal is approved by the NEB, such that Line 9 or a portion of Line 9 is operated in a fashion that allows volumes to flow from the Canadian Mainline into Line 9 and supports flow of hydrocarbons from West to East in Line 9, Enbridge may file, at its discretion, a negotiated International Joint Tariff for delivery on Line 9 at that time.

		
	31.4
	In the event that Enbridge files an application to reverse service on Line 9 or a portion of Line 9 and such reversal is approved by the NEB, the stand alone toll for the transportation of hydrocarbons on Line 9 in a West to East service (“Line 9 Local Tolls”) shall be adjusted annually, up or down, at a rate of 75% of the GDPP Index.

		
	31.5
	The CTS is unrelated to any decision regarding the possible reversal of Line 9. The CTS does not limit in any way a party’s rights to make submissions and fully participate in any Line 9 reversal facilities application and is entirely without prejudice to the position of any party in such an application.

		
	31.6
	Subject to applicable law, tolls under a negotiated international joint tariff for the transportation of hydrocarbons from the Canadian Mainline to delivery points on Line 9 will be published when available.

		
	31.7
	Enbridge may offer incentives in order to attract incremental volumes onto Line 9, provided such toll incentives on Line 9 are offered equally to all shippers on Line 9, as adjusted for distance and commodity types.

		
	31.8
	The CTS is unrelated to any decision regarding the responsibility for the costs of abandoning Line 9. The CTS is entirely without prejudice to the position of any party on the question of responsibility for the cost of abandonment of Line 9.

		
	31.9
	All Canadian pipeline assets owned by Enbridge that are regulated by the NEB, including Line 9, are being addressed in the LMCI process. The LMCI process will determine the methodology by which costs for abandonment should be collected by a pipeline.  Enbridge will file all required information under LMCI as per the NEB schedules for Line 9.  Through the LMCI process, whatever 

(36)

abandonment costs the NEB approves for pre-collection from shippers on Line 9 will form part of the standalone costs of Line 9.  Enbridge will not apply for abandonment of Line 9 during the Term unless ordered to do so by the NEB.
		
	31.10
	For  greater  certainty,  all  parties  may  fully  participate  in  the  LMCI  process  or  any  other proceeding related to abandonment and the CTS does not limit in any way a party’s right to make submissions regarding Line 9 abandonment or abandonment costs. The CTS is unrelated to the ultimate decision regarding the responsibility for abandonment costs for Line 9.

		
	31.11 
	"Line 9 Capital Expenditure" means expenditures on the Line 9 made by Enbridge which, under Oil Pipeline Uniform Accounting Regulations, require capitalization as fixed assets. Line 9 Capital Expenditures must be prudent, reasonable and to the benefit of Line 9 and include, but are not limited to, maintenance, integrity, equipment additions, improvements and new facilities. Line 9 Capital Expenditures would include expansion of Line 9 such as expanded pipeline capacity, increased storage capacity, or the creation or expansion of new Line 9 receipt and delivery points.

		
	31.12
	Enbridge is responsible for all Line 9 Capital Expenditures on Line 9 during the Term.

		
	31.13
	Enbridge will negotiate with shippers on Line 9 prior to any single project on Line 9 with expected Line 9 Capital Expenditures greater than $25 million that expands pipeline capacity, increases storage capacity, or creates or expands new Line 9 receipt and delivery points.

		
	31.14
	Projects on Line 9 which require Line 9 Capital Expenditures and which are not supported by Enbridge because the incremental revenues associated with such project would not cover the incremental costs, may proceed if there is sufficient financial support from a shipper(s) on Line 9 (a “Line 9 Shipper Supported Expansion Project”).

		
	31.15
	By execution of  an agreement whereby a  shipper on Line 9 agrees to backstop Enbridge’s revenue requirement for Line 9 Shipper Supported Expansion Projects (a “Line 9 Backstopping Agreement”) and confirmation that the proposed project creates no adverse operational issues for Enbridge, as determined by Enbridge acting reasonably, Enbridge will agree to undertake such Line 9 Shipper Supported Expansion Projects in accordance with the terms of such  Line 9 Backstopping Agreement.  In the event that Enbridge is unable to secure NEB approval for construction of the project, the shipper on Line 9 who supports a Line 9 Shipper Supported Expansion Project by executing a Line 9 Backstopping Agreement (the “Line 9 Supporting Shipper(s)") will be required to reimburse Enbridge for all of the project's reasonable and prudent development costs as defined in the applicable Line 9 Backstopping Agreement.

		
	31.16
	Subject to Section 31.20, additional revenues derived from tolls, including receipt and delivery terminalling and transmission, collected on the incremental volumes transported on the Enbridge Mainline and Line 9 related to such Line 9 Shipper Supported Expansion Project, net of any direct incremental costs (“Net Line 9 Incremental Revenue”) will be credited to the Line 9 Backstopping Agreement’s revenue requirement.

		
	31.17
	The Line 9 Backstopping Agreement will ensure that the annual revenue requirement associated with the incremental project capital is met either through Net Line 9 Incremental Revenue from associated incremental throughput or lump sum payments from the Line 9 Supporting Shipper(s). The form and terms of a Line 9 Backstopping Agreement will be developed on a project by project 

(36)

basis but will utilize the following parameters: a) the term will be no less than 5 years and no more than 10 years and can extend past the end of the Term; b) threshold return on equity of between 11 to 15 percent after tax; and c) capital structure of 45 percent equity.  The return on equity will be negotiated between, Enbridge and the Line 9 Supporting Shipper(S), and the parties acting reasonably, will consider such risks as volume, capital, cost, credit, financial or other relevant risks.  An 11 percent return would be appropriate in a circumstance when Enbridge accepted no volume risk, did not share in any operating or capital cost risk, and credit risk was secured by either a letter of credit or a shipper with an Investment Grade credit rating. A 15 percent return would be appropriate in a circumstance when Enbridge accepts substantially more risk with respect to volumes, capital, cost, credit or financial elements of the project. Similar Line 9 Shipper Supported Expansion Projects will be evaluated on a similar basis and using similar principles.
		
	31.18
	At the end of the Term, there will be no net rate base impact to Line 9 as a result of Line 9 Shipper Supported Expansion Projects.

		
	31.19
	For example, for a Line 9 Shipper Supported Expansion Project to construct new tanks, the Line 9 Backstopping Agreement will require the recovery of the capital cost of the tank through accelerated depreciation.  To the extent that such accelerated depreciation exceeds Enbridge’s normal depreciation rates for Line 9, the excess will be credited against the Line 9 rate base and future depreciation expense will be reduced accordingly.

		
	31.20
	Enbridge will consider the Net Line 9 Incremental Revenue from incremental volumes associated with Line 9 Shipper Supported Expansion Projects compared to the incremental capital cost to determine the amount and type of Line 9 Backstopping Arrangement it will require.  To establish incremental volumes from existing movements, Enbridge will use an appropriate time frame, typically the 12 month period immediately preceding the month in which Enbridge anticipates the in-service date for the new facilities.

		
	31.21
	The Line 9 Backstopping Agreement will incorporate any terms that would allow the Line 9 Supporting Shipper’s commitment to be reduced by Net Line 9 Incremental Revenue or capital contribution provided by one or more other shipper(s) on Line 9.

		
	31.22
	Line 9 Backstopping Agreements are to allow the provision of services, but nothing in this Article 31 is intended to provide any priority service to Line 9 Supporting Shippers.

		
	31.23
	Each February during the Term, Enbridge will provide shippers on Line 9 with a summary of capital additions for the prior year and forecast capital additions for the current year to the Line 9 rate base in total and will detail individual items that exceed $5 million, and the aggregate amount of capital under a Shipper Supported Expansion Project in accordance with the Line 9 Capital Reporting Template included in Schedule “O”. Enbridge will continue to meet with shippers on Line 9 to annually review the Line 9 integrity plan, metrics and overall operating plan.

		
	31.24
	In addition, each February of 2019, 2020 and 2021, Enbridge will provide a summary of the forecast capital additions to the Line 9 rate base for all  pending projects or future projects anticipated to be initiated before the end of the Term that exceed $5 million that could result in an addition to the Line 9 rate base before the end of the Term.

(37)

		
	31.25
	Enbridge shall file with the NEB and make available to interested parties copies of the Line 9 tolls and tariffs for each year.

(38)

SCHEDULE “A” - CANADIAN MAINLINE

	
	
	PIPELINES & FACILITIES

	Line 1

	Line 2

	Line 3

	Line 4

	Line 5

	Line 6B

	Line 7

	Line 10

	Line 11

	Line 65

	Line 67

	All related facilities associated with the above noted pipelines

	
		
	RECEIPT POINTS
	DELIVERY POINTS

	Edmonton, Alberta
	Edmonton, Alberta

	Hardisty, Alberta
	Hardisty, Alberta

	Kerrobert, Saskatchewan
	Kerrobert, Saskatchewan

	Regina, Saskatchewan
	Stony Beach, Saskatchewan

	Cromer, Manitoba
	Regina, Saskatchewan

	Sarnia, Ontario
	Milden, Saskatchewan

	Westover, Ontario
	Gretna, Manitoba

	 
	Sarnia, Ontario

	 
	Nanticoke, Ontario

2012 Edmonton Tanks
		
	(a)
	Tank #36, shell capacity of 260,000 barrels per day in service on or about September 1, 2012; 

		
	(b)
	Tank #38, shell capacity of 186,000 barrels per day in service, on or about September 1, 2012;

		
	(c)
	Tank # 33 and Tank # 37 each with shell capacity of 372,000 barrels expected to be in service on, or about, December 1, 2012; and

		
	(d)
	the demolition of Tank #13 and Tank #17.

A-1

SCHEDULE “B” - LAKEHEAD SYSTEM

	
	
	PIPELINES & FACILITIES

	Line 1

	Line 2

	Line 3

	Line 4

	Line 5

	Line 6A

	Line 6B

	Line 10

	Line 14/64

	Line 61

	Line 62

	Line 65

	Line 67

	All related facilities associated with the above noted pipelines

	
		
	RECEIPT POINTS
	DELIVERY POINTS

	Clearbrook, Minnesota
	Clearbrook, Minnesota

	Mokena, Illinois
	Superior, Wisconsin

	Griffith, Indiana
	Lockport & Mokena, Illinois

	Stockbridge, Michigan
	Flanagan, Illinois

	Lewiston, Michigan
	Griffith, Indiana

	 
	Stockbridge, Michigan

	 
	Marysville, Michigan

	 
	Rapid River, Michigan

	 
	West Seneca, New York

B-1

SCHEDULE “C” - LINE 9 FACILITIES EAST BOUND SERVICE

	
	
	PIPELINES & FACILITIES

	Line 9

	All related facilities associated with the above noted pipeline

	
		
	RECEIPT POINTS
	DELIVERY POINTS

	Sarnia, Ontario
	North Westover, Ontario

	 
	Montreal, Quebec

C-1

SCHEDULE “D” - TABLE OF IJT TOLLS

These tolls will escalate each July 1 by 75% of GDPP Index beginning July 1, 2012.
 Schedule  “ D” ( Part 1) - IJT Tolls in U.S. Dollars per Cubic Meter
	
							
	IJT-JOINT TRANSPORTATION RATES
($USD PER CUBIC METER)

	FROM
	TO
	RATE

	NGL
	CND
	LIGHT
	MEDIUM
	HEAVY

	Edmonton Terminal, Alberta
	Clearbrook, Minnesota
	—
	12.5702
	13.3780
	14.3201
	15.9705

	Superior, Wisconsin
	14.3227
	15.0655
	15.8733
	17.0053
	18.9850

	Lockport, Illinois
	—
	20.7469
	21.5547
	23.1509
	25.9473

	Mokena, Illinois
	—
	20.7469
	21.5547
	23.1509
	25.9473

	Flanagan, Illinois
	—
	20.7469
	21.5547
	23.1509
	25.9473

	Griffith, Indiana
	—
	20.7469
	21.5547
	23.1509
	25.9473

	Stockbridge, Michigan
	—
	22.8831
	23.6909
	25.4579
	28.5542

	Rapid River, Michigan
	17.1569
	—
	—
	—
	—

	Marysville, Michigan
	21.4046
	22.8831
	23.6909
	25.4579
	28.5542

	Corunna or Sarnia Terminal, Ontario
	21.7335
	23.2139
	24.0295
	25.8058
	28.9124

	Nanticoke, Ontario
	—
	25.2211
	26.2112
	28.1620
	31.5741

	West Seneca, New York
	—
	25.5215
	26.5317
	28.5270
	32.0181

	Hardisty Terminal, Alberta
	Clearbrook, Minnesota
	—
	—
	11.9587
	12.7872
	14.2390

	Superior, Wisconsin
	—
	—
	14.4540
	15.4724
	17.2535

	Lockport, Illinois
	—
	—
	20.1354
	21.6180
	24.2158

	Mokena, Illinois
	—
	—
	20.1354
	21.6180
	24.2158

	Flanagan, Illinois
	—
	—
	20.1354
	21.6180
	24.2158

	Griffith, Indiana
	—
	—
	20.1354
	21.6180
	24.2158

	Stockbridge, Michigan
	—
	—
	22.2716
	23.9250
	26.8227

	Rapid River, Michigan
	—
	—
	—
	—
	—

	Marysville, Michigan
	—
	—
	22.2716
	23.9250
	26.8227

	Corunna or Sarnia Terminal, Ontario
	—
	—
	22.6102
	24.2729
	27.1809

	Nanticoke, Ontario
	—
	—
	24.7919
	26.6291
	29.8425

	West Seneca, New York
	—
	—
	25.1124
	26.9941
	30.2865

D-1

Schedule  “ D” ( Part 1) - IJT Tolls in U.S. Dollars per Cubic Meter - continued

	
							
	IJT-JOINT TRANSPORTATION RATES
($USD PER CUBIC METER)

	FROM
	TO
	RATE

	NGL
	CND
	LIGHT
	MEDIUM
	HEAVY

	Kerrobert Station, Saskatchewan
	Clearbrook, Minnesota
	—
	—
	10.5313
	—
	12.4975

	Superior, Wisconsin
	11.7606
	—
	13.0266
	—
	15.5120

	Lockport, Illinois
	—
	—
	18.7080
	—
	22.4743

	Mokena, Illinois
	—
	—
	18.7080
	—
	22.4743

	Flanagan, Illinois
	—
	—
	18.7080
	—
	22.4743

	Griffith, Indiana
	—
	—
	18.7080
	—
	22.4743

	Stockbridge, Michigan
	—
	—
	20.8442
	—
	25.0812

	Rapid River, Michigan
	14.5948
	—
	—
	—
	—

	Marysville, Michigan
	18.8425
	—
	20.8442
	—
	25.0812

	Corunna or Sarnia Terminal, Ontario
	19.1715
	—
	21.1828
	—
	25.4394

	Nanticoke, Ontario
	—
	—
	23.3645
	—
	28.1011

	West Seneca, New York
	—
	—
	23.685
	—
	28.5450

	Regina Terminal, Saskatchewan
	Clearbrook, Minnesota
	—
	—
	7.6683
	—
	9.0047

	Superior, Wisconsin
	—
	—
	10.1636
	—
	12.0192

	Lockport, Illinois
	—
	—
	15.8450
	—
	18.9815

	Mokena, Illinois
	—
	—
	15.8450
	—
	18.9815

	Flanagan, Illinois
	—
	—
	15.8450
	—
	18.9815

	Griffith, Indiana
	—
	—
	15.8450
	—
	18.9815

	Stockbridge, Michigan
	—
	—
	17.9812
	—
	21.5884

	Rapid River, Michigan
	—
	—
	—
	—
	—

	Marysville, Michigan
	—
	—
	17.9812
	—
	21.5884

	Corunna or Sarnia Terminal, Ontario
	—
	—
	18.3198
	—
	21.9466

	Nanticoke, Ontario
	—
	—
	20.5015
	—
	24.6083

	West Seneca, New York
	—
	—
	20.8221
	—
	25.0522

	Cromer Terminal, Manitoba
	Clearbrook, Minnesota
	—
	—
	5.6002
	5.9201
	6.4816

	Superior, Wisconsin
	7.3226
	—
	8.0955
	8.6053
	9.4961

	Lockport, Illinois
	—
	—
	13.7769
	14.7509
	16.4584

	Mokena, Illinois
	—
	—
	13.7769
	14.7509
	16.4584

	Flanagan, Illinois
	—
	—
	13.7769
	14.7509
	16.4584

	Griffith, Indiana
	—
	—
	13.7769
	14.7509
	16.4584

	Stockbridge, Michigan
	—
	—
	15.9131
	17.0579
	19.0653

	Rapid River, Michigan
	10.1568
	—
	—
	—
	—

	Marysville, Michigan
	14.4045
	—
	15.9131
	17.0579
	19.0653

	Corunna or Sarnia Terminal, Ontario
	14.7335
	—
	16.2517
	17.4057
	19.4235

	Nanticoke, Ontario
	—
	—
	18.4334
	19.7620
	22.0852

	West Seneca, New York
	—
	—
	18.7539
	20.1269
	22.5291

D-2

Schedule  “ D” ( Part 2) - IJT Tolls in U.S. Dollars per Barrel

	
							
	IJT-JOINT TRANSPORTATION RATES
($USD PER BARREL)

	FROM
	TO
	Rate

	NGL
	CND
	LIGHT
	MEDIUM
	HEAVY

	Edmonton Terminal, Alberta
	Clearbrook, Minnesota
	—
	1.9985
	2.1269
	2.2767
	2.5391

	Superior, Wisconsin
	2.2771
	2.3952
	2.5237
	2.7036
	3.0184

	Lockport, Illinois
	—
	3.2985
	3.4269
	3.6807
	4.1253

	Mokena, Illinois
	—
	3.2985
	3.4269
	3.6807
	4.1253

	Flanagan, Illinois
	—
	3.2985
	3.4269
	3.6807
	4.1253

	Griffith, Indiana
	—
	3.2985
	3.4269
	3.6807
	4.1253

	Stockbridge, Michigan
	—
	3.6381
	3.7666
	4.0475
	4.5398

	Rapid River, Michigan
	2.7277
	—
	—
	—
	—

	Marysville, Michigan
	3.4031
	3.6381
	3.7666
	4.0475
	4.5398

	Corunna or Sarnia Terminal, Ontario
	3.4554
	3.6907
	3.8204
	4.1028
	4.5967

	Nanticoke, Ontario
	—
	4.0098
	4.1672
	4.4774
	5.0199

	West Seneca, New York
	—
	4.0576
	4.2182
	4.5354
	5.0905

	Hardisty Terminal, Alberta
	Clearbrook, Minnesota
	—
	—
	1.9013
	2.0330
	2.2638

	Superior, Wisconsin
	—
	—
	2.2980
	2.4599
	2.7431

	Lockport, Illinois
	—
	—
	3.2013
	3.4370
	3.8500

	Mokena, Illinois
	—
	—
	3.2013
	3.4370
	3.8500

	Flanagan, Illinois
	—
	—
	3.2013
	3.4370
	3.8500

	Griffith, Indiana
	—
	—
	3.2013
	3.4370
	3.8500

	Stockbridge, Michigan
	—
	—
	3.5409
	3.8038
	4.2645

	Rapid River, Michigan
	—
	—
	—
	—
	—

	Marysville, Michigan
	—
	—
	3.5409
	3.8038
	4.2645

	Corunna or Sarnia Terminal, Ontario
	—
	—
	3.5947
	3.8591
	4.3214

	Nanticoke, Ontario
	—
	—
	3.9416
	4.2337
	4.7446

	West Seneca, New York
	—
	—
	3.9926
	4.2917
	4.8152

D-3

Schedule  “ D” ( Part 2) - IJT Tolls in U.S. Dollars per Barrel - continued

	
							
	IJT-JOINT TRANSPORTATION RATES
($USD PER BARREL)

	FROM
	TO
	RATE

	NGL
	CND
	LIGHT
	MEDIUM
	HEAVY

	Kerrobert Station, Saskatchewan
	Clearbrook, Minnesota
	—
	—
	1.6743
	—
	1.9869

	Superior, Wisconsin
	1.8698
	—
	2.0711
	—
	2.4662

	Lockport, Illinois
	—
	—
	2.9743
	—
	3.5731

	Mokena, Illinois
	—
	—
	2.9743
	—
	3.5731

	Flanagan, Illinois
	—
	—
	2.9743
	—
	3.5731

	Griffith, Indiana
	—
	—
	2.9743
	—
	3.5731

	Stockbridge, Michigan
	—
	—
	3.3140
	—
	3.9876

	Rapid River, Michigan
	2.3204
	—
	—
	—
	—

	Marysville, Michigan
	2.9957
	—
	3.3140
	—
	3.9876

	Corunna or Sarnia Terminal, Ontario
	3.0480
	—
	3.3678
	—
	4.0445

	Nanticoke, Ontario
	—
	—
	3.7147
	—
	4.4677

	West Seneca, New York
	—
	—
	3.7656
	—
	4.5383

	Regina Terminal, Saskatchewan
	Clearbrook, Minnesota
	—
	—
	1.2192
	—
	1.4316

	Superior, Wisconsin
	—
	—
	1.6159
	—
	1.9109

	Lockport, Illinois
	—
	—
	2.5192
	—
	3.0178

	Mokena, Illinois
	—
	—
	2.5192
	—
	3.0178

	Flanagan, Illinois
	—
	—
	2.5192
	—
	3.0178

	Griffith, Indiana
	—
	—
	2.5192
	—
	3.0178

	Stockbridge, Michigan
	—
	—
	2.8588
	—
	3.4323

	Rapid River, Michigan
	—
	—
	—
	—
	—

	Marysville, Michigan
	—
	—
	2.8588
	—
	3.4323

	Corunna or Sarnia Terminal, Ontario
	—
	—
	2.9126
	—
	3.4892

	Nanticoke, Ontario
	—
	—
	3.2595
	—
	3.9124

	West Seneca, New York
	—
	—
	3.3104
	—
	3.9830

	Cromer Terminal, Manitoba
	Clearbrook, Minnesota
	—
	—
	0.8904
	0.9412
	1.0305

	Superior, Wisconsin
	1.1642
	—
	1.2871
	1.3681
	1.5098

	Lockport, Illinois
	—
	—
	2.1904
	2.3452
	2.6167

	Mokena, Illinois
	—
	—
	2.1904
	2.3452
	2.6167

	Flanagan, Illinois
	—
	—
	2.1904
	2.3452
	2.6167

	Griffith, Indiana
	—
	—
	2.1904
	2.3452
	2.6167

	Stockbridge, Michigan
	—
	—
	2.5300
	2.7120
	3.0311

	Rapid River, Michigan
	1.6148
	—
	—
	—
	—

	Marysville, Michigan
	2.2901
	—
	2.5300
	2.7120
	3.0311

	Corunna or Sarnia Terminal, Ontario
	2.3424
	—
	2.5838
	2.7673
	3.0881

	Nanticoke, Ontario
	—
	—
	2.9307
	3.1419
	3.5113

	West Seneca, New York
	—
	—
	2.9816
	3.1999
	3.5818

D-4

SCHEDULE “E” - TABLE OF CLT TOLLS

These tolls will escalate each July 1 by 75% of GDPP Index beginning July 1, 2012.

Schedule  “ E” ( Part 1) - CLT Tolls in Canadian Dollars per Cubic Meter

CLT - LIGHT CRUDE TRANSMISSION AND TERMINALLING TOLLS 
($CDN PER CUBIC METRE)

	
									
	To (Delivery Points)‰
	§§From(Receipt Points)ˆˆ

	Edmonton Terminal, AB
	Hardisty Terminal, AIB
	Kerrobert Station, SK
	Regina Terminal, SK
	Cromer Terminal, MB
	International Boundary near Sarnia, ON
	Sarnia Terminal, ON
	Westover, ON

	Edmonton Terminal, AB
	1.484
	—
	—
	—
	—
	—
	—
	—

	Hardisty Terminal, AB
	2.947
	—
	—
	—
	—
	—
	—
	—

	Kerrobert Station, SK
	4.418
	2.955
	—
	—
	—
	—
	—
	—

	Milden, SK
	5.370
	3.908
	—
	—
	—
	—
	—
	—

	Stony Beach Take-off, SK
	7.368
	5.905
	4.434
	—
	—
	—
	—
	—

	Regina Terminal, SK
	7.368
	5.905
	4.434
	1.484
	—
	—
	—
	—

	Gretna Station, MB
	11.865
	—
	—
	5.981
	—
	—
	—
	—

	International Boundary near Gretna, MB
	11.404
	9.941
	8.470
	5.519
	3.388
	—
	—
	—

	Corunna or Sarnia Terminal, ON
	11.990
	10.528
	9.056
	6.106
	3.975
	0.586
	1.484
	—

	Nanticoke, ON
	14.239
	12.776
	11.305
	8.354
	6.223
	2.835
	3.732
	1.121

	International Boundary near Chippawa, ON
	14.012
	12.549
	11.078
	8.127
	5.996
	2.608
	3.505
	0.886

CLT - MEDIUM CRUDE TRANSMISSION AND TERMINALLING TOLLS 
($CDN PER CUBIC METRE)

	
						
	To (Delivery Points) ‰
	§§From (Receipt Points)ˆˆ

	Edmonton Terminal, AB
	Hardisty Terminal, AIB
	Cromer Terminal, MB
	International Boundary near Sarnia, ON
	Westover, ON

	Edmonton Terminal, AB
	1.484
	—
	—
	—
	—

	Hardisty Terminal, AB
	3.064
	1.484
	—
	—
	—

	Kerrobert Station, SK
	—
	3.073
	—
	—
	—

	Stony Beach Take-off, SK
	7.839
	6.259
	—
	—
	—

	Regina Terminal, SK
	7.839
	6.259
	—
	—
	—

	International Boundary near Gretna, MB
	12.2236
	10.657
	3.579
	—
	—

	Corunna or Sarnia Terminal, ON
	12.831
	11.251
	4.174
	0.594
	—

	Nanticoke, ON
	15.259
	13.679
	6.602
	3.023
	1.172

	International Boundary near Chippawa, ON
	15.053
	13.473
	6.396
	2.816
	0.957

E-1

Schedule  “ E” ( Part 1) - CLT Tolls in Canadian Dollars per Cubic Meter - continued

CLT - HEAVY CRUDE TRANSMISSION AND TERMINALLING TOLLS 
($CDN PER CUBIC METRE)

	
							
	To (Delivery Points) ‰
	§§From (Receipt Points)ˆˆ

	Edmonton Terminal, AB
	Hardisty Terminal, AIB
	Kerrobert Station, SK
	Regina Terminal, SK
	Cromer Terminal, MB
	International Boundary near Sarnia, ON

	Edmonton Terminal, AB
	1.484
	—
	—
	—
	—
	—

	Hardisty Terminal, AB
	3.268
	1.484
	—
	—
	—
	—

	Kerrobert Station, SK
	5.063
	3.279
	—
	—
	—
	—

	Stony Beach Take-off, SK
	8.663
	6.878
	5.083
	—
	—
	—

	Regina Terminal, SK
	8.663
	6.878
	5.083
	1.484
	—
	—

	International Boundary near Gretna, MB
	13.693
	11.909
	10.114
	6.514
	3.914
	—

	Corunna or Sarnia Terminal, ON
	14.302
	12.517
	10.722
	7.123
	4.523
	0.609

	Nanticoke, ON
	17.045
	15.260
	13.465
	9.866
	7.266
	3.352

	International Boundary near Chippawa, ON
	16.875
	15.090
	13.295
	9.696
	7.096
	3.182

CLT - GASOLINE AND CONDENSATE TRANSMISSION AND TERMINALLING TOLLS 
($CDN PER CUBIC METRE)

	
						
	To (Delivery Points) ‰
	§§From (Receipt Points)ˆˆ

	Edmonton Terminal, AB
	Hardisty Terminal, AIB
	Regina Terminal, SK
	International Boundary near Sarnia, ON
	Sarnia Terminal, ON

	Edmonton Terminal, AB
	1.484
	—
	—
	—
	—

	Hardisty Terminal, AB
	2.829
	—
	—
	—
	—

	Kerrobert Station, SK
	4.183
	2.837
	—
	—
	—

	Milden, SK
	5.060
	—
	—
	—
	—

	Stony Beach Take-off, SK
	6.897
	—
	—
	—
	—

	Regina Terminal, SK
	6.897
	—
	1.484
	—
	—

	Gretna Station, MB
	11.034
	—
	5.621
	—
	—

	International Boundary near Gretna, MB
	10.571
	—
	—
	—
	—

	Corunna or Sarnia Terminal, ON
	11.150
	—
	—
	0.578
	1.484

	Nanticoke, ON
	13.218
	—
	—
	2.647
	3.552

	International Boundary near Chippawa, ON
	12.970
	—
	—
	2.399
	3.305

E-2

Schedule  “ E” ( Part 1) - CLT Tolls in Canadian Dollars per Cubic Meter - continued

CLT - NATURAL GAS LIQUIDS TRANSMISSION AND TERMINALLING TOLLS 
($CDN PER CUBIC METRE)

	
				
	To (Delivery Points) ‰
	§From (Receipt Points)ˆ

	Edmonton Terminal, AB
	Kerrobert Station, SK
	Cromer Terminal, MB

	International Boundary near Gretna, MB
	10.363
	7.723
	3.149

	Corunna or Sarnia Terminal, ON
	10.940
	8.299
	3.726

E-3

Schedule  “ E”  (Part 2) - CLT Tolls in Canadian Dollars per Barrel

CLT - LIGHT CRUDE TRANSMISSION AND TERMINALLING TOLLS 
($CDN PER BARREL)

	
									
	To (Delivery Points) ‰
	§§From (Receipt Points)ˆˆ

	Edmonton Terminal, AB
	Hardisty Terminal, AIB
	Kerrobert Station, SK
	Regina Terminal, SK
	Cromer Terminal, MB
	International Boundary near Sarnia, ON
	Sarnia Terminal, ON
	Westover, ON

	Edmonton Terminal, AB
	0.236
	—
	—
	—
	—
	—
	—
	—

	Hardisty Terminal, AB
	0.468
	—
	—
	—
	—
	—
	—
	—

	Kerrobert Station, SK
	0.702
	0.470
	—
	—
	—
	—
	—
	—

	Milden, SK
	0.854
	0.621
	—
	—
	—
	—
	—
	—

	Stony Beach Take-off, SK
	1.171
	0.939
	0.705
	—
	—
	—
	—
	—

	Regina Terminal, SK
	1.171
	0.939
	0.705
	0.236
	—
	—
	—
	—

	Gretna Station, MB
	1.886
	—
	—
	0.951
	—
	—
	—
	—

	International Boundary near Gretna, MB
	1.813
	1.580
	1.347
	0.878
	0.539
	—
	—
	—

	Corunna or Sarnia Terminal, ON
	1.906
	1.674
	1.440
	0.971
	0.632
	0.093
	0.236
	—

	Nanticoke, ON
	2.264
	2.031
	1.797
	1.328
	0.989
	0.451
	0.593
	0.178

	International Boundary near Chippawa, ON
	2.228
	1.995
	1.761
	1.292
	0.953
	0.415
	0.557
	0.141

CLT - MEDIUM TRANSMISSION AND TERMINALLING TOLLS 
($CDN PER BARREL)

	
						
	To (Delivery Points) ‰
	§§From (Receipt Points)ˆˆ

	Edmonton Terminal, AIB
	Hardisty Terminal, AB
	Cromer Terminal, MB
	International Boundary near Sarnia, ON
	Westover, ON

	Edmonton Terminal, AB
	0.236
	—
	—
	—
	—

	Hardisty Terminal, AB
	0.487
	0.236
	—
	—
	—

	Kerrobert Station, SK
	—
	0.488
	—
	—
	—

	Stony Beach Take-off, SK
	1.246
	0.995
	—
	—
	—

	Regina Terminal, SK
	1.246
	0.995
	—
	—
	—

	International Boundary near Gretna, MB
	1.945
	1.694
	0.569
	—
	—

	Corunna or Sarnia Terminal, ON
	2.040
	1.789
	0.664
	0.095
	—

	Nanticoke, ON
	2.426
	2.175
	1.050
	0.481
	0.186

	International Boundary near Chippawa, ON
	2.393
	2.142
	1.017
	0.448
	0.152

E-4

Schedule  “ E”  (Part 2) - CLT Tolls in Canadian Dollars per Barrel - continued

CLT - HEAVY CRUDE TRANSMISSION AND TERMINALLING TOLLS 
($CDN PER BARREL)

	
							
	To (Delivery Points) ‰
	§§From (Receipt Points)ˆˆ

	Edmonton Terminal, AIB
	Hardisty Terminal, AIB
	Kerrobert Station, SK
	Regina Terminal, SK
	Cromer Terminal, MB
	International Boundary near Sarina, ON

	Edmonton Terminal, AB
	0.236
	—
	—
	—
	—
	—

	Hardisty Terminal, AB
	0.520
	0.236
	—
	—
	—
	—

	Kerrobert Station, SK
	0.805
	0.521
	—
	—
	—
	—

	Stony Beach Take-off, SK
	1.377
	1.094
	0.808
	—
	—
	—

	Regina Terminal, SK
	1.377
	1.094
	0.808
	0.236
	—
	—

	International Boundary near Gretna, MB
	2.177
	1.893
	1.608
	1.036
	0.622
	—

	Corunna or Sarnia Terminal, ON
	2.274
	1.990
	1.705
	1.132
	0.719
	0.097

	Nanticoke, ON
	2.710
	2.426
	2.141
	1.569
	1.155
	0.533

	International Boundary near Chippewa, ON
	2.683
	2.399
	2.114
	1.542
	1.128
	0.506

CLT - GASOLINE AND CONDENSATE TRANSMISSION AND TERMINALLING TOLLS 
($CDN PER BARREL)

	
						
	To (Delivery Points) ‰
	§§From (Receipt Points)ˆˆ

	Edmonton Terminal, AB
	Hardisty Terminal, AB
	Regina Terminal, AB
	International Boundary near Sarnia, ON
	Sarnia Terminal, ON

	Edmonton Terminal, AB
	0.236
	—
	—
	—
	—

	Hardisty Terminal, AB
	0.450
	—
	—
	—
	—

	Kerrobert Station, SK
	0.665
	0.451
	—
	—
	—

	Milden, SK
	0.804
	—
	—
	—
	—

	Stony Beach Take-off, SK
	1.097
	—
	—
	—
	—

	Regina Terminal, SK
	1.097
	—
	0.236
	—
	—

	Gretna Station, MB
	1.754
	—
	0.894
	—
	—

	International Boundary near Gretna, MB
	1.681
	—
	—
	—
	—

	Corunna or Sarnia Terminal, ON
	1.773
	—
	—
	0.092
	0.236

	Nanticoke, ON
	2.102
	—
	—
	0.421
	0.565

	International Boundary near Chippawa, ON
	2.062
	—
	—
	0.381
	0.525

E-5

Schedule  “ E”  (Part 2) - CLT Tolls in Canadian Dollars per Barrel - continued

CLT - NATURAL GAS LIQUIDS TRANSMISSION AND TERMINALLING TOLLS 
($CDN PER BARREL)

	
				
	To (Delivery Points) ‰
	§From (Receipt Points)ˆ

	Edmonton Terminal, AB
	Kerrobert Station, SK
	Cromer Terminal, MB

	International Boundary near Gretna, MB
	1.648
	1.228
	0.501

	Corunna or Sarnia Terminal, ON
	1.739
	1.319
	0.592

E-6

SCHEDULE “F” - TABLE OF OUTSTANDING AMOUNT SURCHARGE

The Outstanding Amount Surcharge does not escalate.

Schedule  “ F”  (Part 1) - IJT Surcharges in U.S. Dollars per Cubic Meters

IJT - SURCHARGES 
($USD PER CUBIC METER)

	
							
	FROM
	TO
	RATE

	NGL
	CND
	LIGHT
	MEDIUM
	HEAVY

	Edmonton Terminal, Alberta
	Clearbrook, Minnesota
	—
	0.3703
	0.4025
	0.4347
	0.4911

	Superior, Wisconsin
	0.3623
	0.3703
	0.4025
	0.4347
	0.4911

	Lockport, Illinois
	—
	0.3703
	0.4025
	0.4347
	0.4911

	Mokena, Illinois
	—
	0.3703
	0.4025
	0.4347
	0.4911

	Flanagan, Illinois
	—
	0.3703
	0.4025
	0.4347
	0.4911

	Griffith, Indiana
	—
	0.3703
	0.4025
	0.4347
	0.4911

	Stockbridge, Michigan
	—
	0.3703
	0.4025
	0.4347
	0.4911

	Rapid River, Michigan
	0.3623
	—
	—
	—
	—

	Marysville, Michigan
	0.3623
	0.3703
	0.4025
	0.4347
	0.4911

	Corunna or Sarnia Terminal, Ontario
	0.3658
	0.3739
	0.4064
	0.4389
	0.4958

	Nanticoke, Ontario
	—
	0.4539
	0.4934
	0.5328
	0.6019

	West Seneca, New York
	—
	0.4631
	0.5034
	0.5437
	0.6141

	Hardisty Terminal, Alberta
	Clearbrook, Minnesota
	—
	—
	0.3459
	0.3736
	0.4220

	Superior, Wisconsin
	—
	—
	0.3459
	0.3736
	0.4220

	Lockport, Illinois
	—
	—
	0.3459
	0.3736
	0.4220

	Mokena, Illinois
	—
	—
	0.3459
	0.3736
	0.4220

	Flanagan, Illinois
	—
	—
	0.3459
	0.3736
	0.4220

	Griffith, Indiana
	—
	—
	0.3459
	0.3736
	0.4220

	Stockbridge, Michigan
	—
	—
	0.3459
	0.3736
	0.4220

	Rapid River, Michigan
	—
	—
	—
	—
	—

	Marysville, Michigan
	—
	—
	0.3459
	0.3736
	0.4220

	Corunna or Sarnia Terminal, Ontario
	—
	—
	0.3498
	0.3778
	0.4268

	Nanticoke, Ontario
	—
	—
	0.4368
	0.4717
	0.5329

	West Seneca, New York
	—
	—
	0.4468
	0.4826
	0.5451

F-1

Schedule  “ F”  (Part 1) - IJT Surcharges in U.S. Dollars per Cubic Meters-continued

IJT - SURCHARGES 
($USD PER CUBIC METER)

	
							
	FROM
	TO
	RATE

	NGL
	CND
	LIGHT
	MEDIUM
	HEAVY

	Kerrobert Station, Saskatchewan
	Clearbrook, Minnesota
	—
	—
	0.2890
	—
	0.3526

	Superior, Wisconsin
	0.2601
	—
	0.2890
	—
	0.3526

	Lockport, Illinois
	—
	—
	0.2890
	—
	0.3526

	Mokena, Illinois
	—
	—
	0.2890
	—
	0.3526

	Flanagan, Illinois
	—
	—
	0.2890
	—
	0.3526

	Griffith, Indiana
	—
	—
	0.2890
	—
	0.3526

	Stockbridge, Michigan
	—
	—
	0.2890
	—
	0.3526

	Rapid River, Michigan
	0.2601
	—
	—
	—
	—

	Marysville, Michigan
	0.2601
	—
	0.2890
	—
	0.3526

	Corunna or Sarnia Terminal, Ontario
	0.2636
	—
	0.2929
	—
	0.3574

	Nanticoke, Ontario
	—
	—
	0.3799
	—
	0.4635

	West Seneca, New York
	—
	—
	0.3899
	—
	0.4757

	Regina Terminal, Saskatchewan
	Clearbrook, Minnesota
	—
	—
	0.1749
	—
	0.2134

	Superior, Wisconsin
	—
	—
	0.1749
	—
	0.2134

	Lockport, Illinois
	—
	—
	0.1749
	—
	0.2134

	Mokena, Illinois
	—
	—
	0.1749
	—
	0.2134

	Flanagan, Illinois
	—
	—
	0.1749
	—
	0.2134

	Griffith, Indiana
	—
	—
	0.1749
	—
	0.2134

	Stockbridge, Michigan
	—
	—
	0.1749
	—
	0.2134

	Rapid River, Michigan
	—
	—
	—
	—
	—

	Marysville, Michigan
	—
	—
	0.1749
	—
	0.2134

	Corunna or Sarnia Terminal, Ontario
	—
	—
	0.1788
	—
	0.2181

	Nanticoke, Ontario
	—
	—
	0.2658
	—
	0.3242

	West Seneca, New York
	—
	—
	0.2758
	—
	0.3365

F-2

Schedule  “ F”  (Part 1) - IJT Surcharges in U.S. Dollars per Cubic Meters-continued

IJT - SURCHARGES 
($USD PER CUBIC METER)

	
							
	FROM
	TO
	RATE

	NGL
	CND
	LIGHT
	MEDIUM
	HEAVY

	Cromer Terminal, Manitoba
	Clearbrook, Minnesota
	—
	—
	0.0925
	0.0999
	0.1128

	Superior, Wisconsin
	0.0832
	—
	0.0925
	0.0999
	0.1128

	Lockport, Illinois
	—
	—
	0.0925
	0.0999
	0.1128

	Mokena, Illinois
	—
	—
	0.0925
	0.0999
	0.1128

	Flanagan, Illinois
	—
	—
	0.0925
	0.0999
	0.1128

	Griffith, Indiana
	—
	—
	0.0925
	0.0999
	0.1128

	Stockbridge, Michigan
	—
	—
	0.0925
	0.0999
	0.1128

	Rapid River, Michigan
	0.0832
	—
	—
	—
	—

	Marysville, Michigan
	0.0832
	—
	0.0925
	0.0999
	0.1128

	Corunna or Sarnia Terminal, Ontario
	0.0867
	—
	0.0963
	0.1041
	0.1175

	Nanticoke, Ontario
	—
	—
	0.1833
	0.1980
	0.2236

	West Seneca, New York
	—
	—
	0.1933
	0.2088
	0.2359

F-3

Schedule  “ F”  (Part 2) - IJT Surcharges in U.S. Dollars per Barrel

IJT - SURCHARGES 
($USD PER BARREL)

	
							
	FROM
	TO
	RATE

	NGL
	CND
	LIGHT
	MEDIUM
	HEAVY

	Edmonton Terminal, Alberta
	Clearbrook, Minnesota
	—
	0.0589
	0.0640
	0.0691
	0.0781

	Superior, Wisconsin
	0.0576
	0.0589
	0.0640
	0.0691
	0.0781

	Lockport, Illinois
	—
	0.0589
	0.0640
	0.0691
	0.0781

	Mokena, Illinois
	—
	0.0589
	0.0640
	0.0691
	0.0781

	Flanagan, Illinois
	—
	0.0589
	0.0640
	0.0691
	0.0781

	Griffith, Indiana
	—
	0.0589
	0.0640
	0.0691
	0.0781

	Stockbridge, Michigan
	—
	0.0589
	0.0640
	0.0691
	0.0781

	Rapid River, Michigan
	0.0576
	—
	—
	—
	—

	Marysville, Michigan
	0.0576
	0.0589
	0.0640
	0.0691
	0.0781

	Corunna or Sarnia Terminal, Ontario
	0.0582
	0.0594
	0.0646
	0.0698
	0.0788

	Nanticoke, Ontario
	—
	0.0722
	0.0784
	0.0847
	0.0957

	West Seneca, New York
	—
	0.0736
	0.0800
	0.0864
	0.0976

	Hardisty Terminal, Alberta
	Clearbrook, Minnesota
	—
	—
	0.0550
	0.0594
	0.0671

	Superior, Wisconsin
	—
	—
	0.0550
	0.0594
	0.0671

	Lockport, Illinois
	—
	—
	0.0550
	0.0594
	0.0671

	Mokena, Illinois
	—
	—
	0.0550
	0.0594
	0.0671

	Flanagan, Illinois
	—
	—
	0.0550
	0.0594
	0.0671

	Griffith, Indiana
	—
	—
	0.0550
	0.0594
	0.0671

	Stockbridge, Michigan
	—
	—
	0.0550
	0.0594
	0.0671

	Rapid River, Michigan
	—
	—
	—
	—
	—

	Marysville, Michigan
	—
	—
	0.0550
	0.0594
	0.0671

	Corunna or Sarnia Terminal, Ontario
	—
	—
	0.0556
	0.0601
	0.0679

	Nanticoke, Ontario
	—
	—
	0.0694
	0.0750
	0.0847

	West Seneca, New York
	—
	—
	0.0710
	0.0767
	0.0867

F-4

Schedule  “ F”  (Part 2) - IJT Surcharges in U.S. Dollars per Barrel-continued

IJT - SURCHARGES 
($USD PER BARREL)

	
							
	FROM
	TO
	RATE

	NGL
	CND
	LIGHT
	MEDIUM
	HEAVY

	Kerrobert Station, Saskatchewan
	Clearbrook, Minnesota
	—
	—
	0.0460
	—
	0.0561

	Superior, Wisconsin
	0.0414
	—
	0.0460
	—
	0.0561

	Lockport, Illinois
	—
	—
	0.0460
	—
	0.0561

	Mokena, Illinois
	—
	—
	0.0460
	—
	0.0561

	Flanagan, Illinois
	—
	—
	0.0460
	—
	0.0561

	Griffith, Indiana
	—
	—
	0.0460
	—
	0.0561

	Stockbridge, Michigan
	—
	—
	0.0460
	—
	0.0561

	Rapid River, Michigan
	0.0414
	—
	—
	—
	—

	Marysville, Michigan
	0.0414
	—
	0.0460
	—
	0.0561

	Corunna or Sarnia Terminal, Ontario
	0.0419
	—
	0.0466
	—
	0.0568

	Nanticoke, Ontario
	—
	—
	0.0604
	—
	0.0737

	West Seneca, New York
	—
	—
	0.0620
	—
	0.0756

	Regina Terminal, Saskatchewan
	Clearbrook, Minnesota
	—
	—
	0.0278
	—
	0.0339

	Superior, Wisconsin
	—
	—
	0.0278
	—
	0.0339

	Lockport, Illinois
	—
	—
	0.0278
	—
	0.0339

	Mokena, Illinois
	—
	—
	0.0278
	—
	0.0339

	Flanagan, Illinois
	—
	—
	0.0278
	—
	0.0339

	Griffith, Indiana
	—
	—
	0.0278
	—
	0.0339

	Stockbridge, Michigan
	—
	—
	0.0278
	—
	0.0339

	Rapid River, Michigan
	—
	—
	—
	—
	—

	Marysville, Michigan
	—
	—
	0.0278
	—
	0.0339

	Corunna or Sarnia Terminal, Ontario
	—
	—
	0.0284
	—
	0.0347

	Nanticoke, Ontario
	—
	—
	0.0423
	—
	0.0515

	West Seneca, New York
	—
	—
	0.0438
	—
	0.0535

F-5

Schedule  “ F”  (Part 2) - IJT Surcharges in U.S. Dollars per Barrel-continued

IJT - SURCHARGES 
($USD PER BARREL)

	
							
	FROM
	TO
	RATE

	NGL
	CDN
	LIGHT
	MEDIUM
	HEAVY

	Cromer Terminal, Manitoba
	Clearbrook, Minnesota
	—
	—
	0.0147
	0.0159
	0.0179

	Superior, Wisconsin
	0.0132
	—
	0.0147
	0.0159
	0.0179

	Lockport, Illinois
	—
	—
	0.0147
	0.0159
	0.0179

	Mokena, Illinois
	—
	—
	0.0147
	0.0159
	0.0179

	Flanagan, Illinois
	—
	—
	0.0147
	0.0159
	0.0179

	Griffith, Indiana
	—
	—
	0.0147
	0.0159
	0.0179

	Stockbridge, Michigan
	—
	—
	0.0147
	0.0159
	0.0179

	Rapid River, Michigan
	0.0132
	—
	—
	—
	—

	Marysville, Michigan
	0.0132
	—
	0.0147
	0.0159
	0.0179

	Corunna or Sarnia Terminal, Ontario
	0.0138
	—
	0.0153
	0.0165
	0.0187

	Nanticoke, Ontario
	—
	—
	0.0291
	0.0315
	0.0356

	West Seneca, New York
	—
	—
	0.0307
	0.0332
	0.0375

F-6

Schedule  “ F”  (Part 3) - CLT Surcharges in Canadian Dollars per Cubic Meter

CLT-LIGHT CRUDE SURCHARGE
($CDN PER CUBIC METER)

	
									
	To (Delivery Points) ‰
	§§From (Receipt Points)ˆˆ

	Edmonton Terminal, AIB
	Hardisty Terminal, AIB
	Kerrobert Station, SK
	Regina Terminal, SK
	Cromer Terminal, MB
	International Boundary near Sarnia, ON
	Sarnia Terminal, ON
	Westover, ON

	Edmonton Terminal, AB
	—
	—
	—
	—
	—
	—
	—
	—

	Hardisty Terminal, AB
	0.057
	—
	—
	—
	—
	—
	—
	—

	Kerrobert Station, SK
	0.113
	0.057
	—
	—
	—
	—
	—
	—

	Milden, SK
	0.150
	0.094
	—
	—
	—
	—
	—
	—

	Stony Beach Take-off, SK
	0.228
	0.171
	0.114
	—
	—
	—
	—
	—

	Regina Terminal, SK
	0.228
	0.171
	0.114
	—
	—
	—
	—
	—

	Gretna Station, MB
	0.402
	—
	—
	0.174
	—
	—
	—
	—

	International Boundary near Gretna, MB
	0.403
	0.346
	0.289
	0.175
	0.092
	—
	—
	—

	Corunna or Sarnia Terminal, ON
	0.406
	0.350
	0.293
	0.179
	0.096
	0.004
	—
	—

	Nanticoke, ON
	0.493
	0.437
	0.380
	0.266
	0.183
	0.091
	0.087
	0.025

	International Boundary near Chippawa, ON
	0.503
	0.447
	0.390
	0.276
	0.193
	0.101
	0.097
	0.034

CLT - MEDIUM CRUDE SURCHARGE 
($CDN PER CUBIC METRE)

	
						
	To (Delivery Points) ‡
	§§From (Receipt Points)ˆˆ

	Edmonton Terminal, AB
	Hardisty Terminal, AIB
	Cromer Terminal, MB
	International Boundary near Sarnia, ON
	Westover, ON

	Edmonton Terminal, AB
	—
	—
	—
	—
	—

	Hardisty Terminal, AB
	0.061
	—
	—
	—
	—

	Kerrobert Station, SK
	—
	0.061
	—
	—
	—

	Stony Beach Take-off, SK
	0.246
	0.185
	—
	—
	—

	Regina Terminal, SK
	0.246
	0.185
	—
	—
	—

	International Boundary near Gretna, MB
	0.435
	0.374
	0.100
	—
	—

	Corunna or Sarnia Terminal, ON
	0.439
	0.378
	0.104
	0.004
	—

	Nanticoke, ON
	0.533
	0.472
	0.198
	0.098
	0.027

	International Boundary near Chippawa, ON
	0.544
	0.483
	0.209
	0.109
	0.037

F-7

Schedule  “ F”  (Part 3) - CLT Surcharges in Canadian Dollars per Cubic Meter-continued

CLT-HEAVY CRUDE SURCHARGE
($CDN PER CUBIC METER)

	
							
	To (Delivery Points) ‰
	§§From (Receipt Points)ˆˆ

	Edmonton Terminal, Alberta
	Hardisty Terminal, Alberta
	Kerrobert Station, Saskatchewan
	Regina Terminal, Saskatchewan
	Cromer Terminal, Manitoba
	Internationl Boundary near Sarnia, Ontario

	Edmonton Terminal, AB
	—
	—
	—
	—
	—
	—

	Hardisty Terminal, AB
	0.069
	—
	—
	—
	—
	—

	Kerrobert Station, SK
	0.138
	0.069
	—
	—
	—
	—

	Stony Beach Take-off, SK
	0.278
	0.209
	0.139
	—
	—
	—

	Regina Terminal, SK
	0.278
	0.209
	0.139
	—
	—
	—

	International Boundary near Gretna, MB
	0.491
	0.422
	0.353
	0.213
	0.113
	—

	Corunna or Sarnia Terminal, ON
	0.496
	0.427
	0.357
	0.218
	0.118
	0.005

	Nanticoke, ON
	0.602
	0.533
	0.463
	0.324
	0.224
	0.111

	International Boundary near Chippawa, ON
	0.614
	0.545
	0.476
	0.336
	0.236
	0.123

CLT - GASOLINE AND CONDENSATE SURCHARGE 
($CDN PER CUBIC METRE)

	
						
	To (Delivery Points) ‰
	§§From (Receipt Points)ˆˆ

	Edmonton Terminal, AIB
	Hardisty Terminal, AIB
	Regina Terminal, SK
	International Boundary near Sarnia, ON
	Sarnia Terminal, ON

	Edmonton Terminal, AB
	—
	—
	—
	—
	—

	Hardisty Terminal, AB
	0.052
	—
	—
	—
	—

	Kerrobert Station, SK
	0.104
	0.052
	—
	—
	—

	Milden, SK
	0.138
	—
	—
	—
	—

	Stony Beach Take-off, SK
	0.209
	—
	—
	—
	—

	Regina Terminal, SK
	0.209
	—
	—
	—
	—

	Gretna Station, MB
	0.369
	—
	0.160
	—
	—

	International Boundary near Gretna, MB
	0.370
	—
	—
	—
	—

	Corunna or Sarnia Terminal, ON
	0.374
	—
	—
	0.004
	—

	Nanticoke, Ontario
	0.454
	—
	—
	0.084
	0.080

	International Boundary near Chippawa, Ontario
	0.463
	—
	—
	0.093
	0.089

F-8

Schedule  “ F”  (Part 3) - CLT Surcharges in Canadian Dollars per Cubic Meter-continued

CLT - NATURAL GAS LIQUIDS SURCHARGE 
($CDN PER CUBIC METRE)

	
				
	To (Delivery Points) ‰
	§From (Receipt Points)ˆ

	Edmonton Terminal, AB
	Kerrobert Station, SK
	Cromer Terminal, MB

	International Boundary near Gretna, MBnitoba
	0.362
	0.260
	0.083

	Corunna or Sarnia Terminal, Ontario
	0.366
	0.264
	0.087

F-9

Schedule  “ F”  (Part 4) - CLT Surcharges in Canadian Dollars per Barrel

CLT - LIGHT CRUDE SURCHARGE 
($CDN PER BARREL)

	
									
	 
	Edmonton Terminal, AIB
	Hardisty Terminal, AIB
	Kerrobert Station, SK
	Regina Terminal, SK
	Cromer Terminal, MB
	International Boundary near Sarnia, ON
	Sarnia Terminal, ON
	Westover, ON

	Edmonton Terminal, AB
	—
	—
	—
	—
	—
	—
	—
	—

	Hardisty Terminal, AB
	0.009
	—
	—
	—
	—
	—
	—
	—

	Kerrobert Station, SK
	0.018
	0.009
	—
	—
	—
	—
	—
	—

	Milden, SK
	0.024
	0.015
	—
	—
	—
	—
	—
	—

	Stony Beach Take-off, SK
	0.036
	0.027
	0.018
	—
	—
	—
	—
	—

	Regina Terminal, SK
	0.036
	0.027
	0.018
	—
	—
	—
	—
	—

	Gretna Station, MB
	0.064
	—
	—
	0.028
	—
	—
	—
	—

	International Boundary near Gretna, MB
	0.064
	0.055
	0.046
	0.028
	0.015
	—
	—
	—

	Corunna or Sarnia Terminal, ON
	0.065
	0.056
	0.047
	0.028
	0.015
	0.001
	—
	—

	Nanticoke, ON
	0.078
	0.069
	0.060
	0.042
	0.029
	0.014
	0.014
	0.004

	International Boundary near Chippawa, ON
	0.080
	0.071
	0.062
	0.044
	0.031
	0.016
	0.015
	0.005

CLT - MEDIUM CRUDE SURCHARGE 
($CDN PER BARREL)

	
						
	To (Delivery Points) ‰
	§§From (Receipt Points)ˆˆ

	Edmonton Terminal, AIB
	Hardisty Terminal, AB
	Cromer Terminal, MB
	International Boundary near Sarnia, ON
	Westover, ON

	Edmonton Terminal, AB
	—
	—
	—
	—
	—

	Hardisty Terminal, AB
	0.010
	—
	—
	—
	—

	Kerrobert Station, SK
	—
	0.010
	—
	—
	—

	Stony Beach Take-off, SK
	0.039
	0.029
	—
	—
	—

	Regina Terminal, SK
	0.039
	0.029
	—
	—
	—

	International Boundary near Gretna, MB
	0.069
	0.059
	0.016
	—
	—

	Corunna or Sarnia Terminal, ON
	0.070
	0.060
	0.017
	0.001
	—

	Nanticoke, ON
	0.085
	0.075
	0.031
	0.016
	0.004

	International Boundary near Chippawa, ON
	0.086
	0.077
	0.033
	0.017
	0.006

F-10

Schedule  “ F”  (Part 4) - CLT Surcharges in Canadian Dollars per Barrel-continued

CLT - HEAVY CRUDE SURCHARGE 
($CDN PER BARREL)

	
							
	To (Delivery Points) ‰
	§§From (Receipt Points)ˆˆ

	Edmonton Terminal, AIB
	Hardisty Terminal, AIB
	Kerrobert Station, SK
	Regina Terminal, SK
	Cromer Terminal, MB
	International Boundary near Sarnia, ON

	Edmonton Terminal, AB
	—
	—
	—
	—
	—
	—

	Hardisty Terminal, AB
	0.011
	—
	—
	—
	—
	—

	Kerrobert Station, SK
	0.022
	0.011
	—
	—
	—
	—

	Stony Beach Take-off, SK
	0.044
	0.033
	0.022
	—
	—
	—

	Regina Terminal, SK
	0.044
	0.033
	0.022
	—
	—
	—

	International Boundary near Gretna, MB
	0.078
	0.067
	0.056
	0.034
	0.018
	—

	Corunna or Sarnia Terminal, ON
	0.079
	0.068
	0.057
	0.035
	0.019
	0.001

	Nanticoke, Ontario
	0.096
	0.085
	0.074
	0.052
	0.036
	0.018

	International Boundary near Chippawa, ON
	0.098
	0.087
	0.076
	0.053
	0.038
	0.020

CLT - GASOLINE AND CONDENSATE SURCHARGE 
($CDN PER BARREL)

	
						
	To (Delivery Points) ‰
	§§From (Receipt Points)ˆˆ

	Edmonton Terminal, AB
	Hardisty Terminal, AB
	Regina Terminal, SK
	International Boundary near Sarnia, ON
	Sarnia Terminal, ON

	Edmonton Terminal, AB
	—
	—
	—
	—
	—

	Hardisty Terminal, AB
	0.008
	—
	—
	—
	—

	Kerrobert Station, SK
	0.017
	0.008
	—
	—
	—

	Milden, SK
	0.022
	—
	—
	—
	—

	Stony Beach Take-off, SK
	0.033
	—
	—
	—
	—

	Regina Terminal, SK
	0.033
	—
	—
	—
	—

	Gretna Station, MB
	0.059
	—
	0.025
	—
	—

	International Boundary near Gretna, MB
	0.059
	—
	—
	—
	—

	Corunna or Sarnia Terminal, ON
	0.059
	—
	—
	0.001
	—

	Nanticoke, ON
	0.072
	—
	—
	0.013
	0.013

	International Boundary near Chippawa, ON
	0.074
	—
	—
	0.015
	0.014

F-11

Schedule  “ F”  (Part 4) - CLT Surcharges in Canadian Dollars per Barrel-continued

CLT - NATURAL GAS LIQUIDS SURCHARGE 
($CDN PER BARREL)

	
				
	To (Delivery Points) ‰
	§From (Receipt Points)ˆ

	Edmonton Terminal, AB
	Kerrobert Station, SK
	Cromer Terminal, MB

	International Boundary near Gretna, Manitoba
	0.058
	0.041
	0.013

	Corunna or Sarnia Terminal, ON
	0.058
	0.042
	0.014

F-12

SCHEDULE “G” – ENBRIDGE MAINLINE REFERENCE CAPACITIES

As of December 31, 2010 excluding temporary capacity restrictions: 
	
	
	Upstream Pipeline Capacity

	 

	a) Line 1 - 240 kbpd

	b) Line 2 - 440 kbdp

	c) Line 3 - 390 kbpd

	d) Line 4 - 800 kbpd

	e) Line 67 - 450 kbpd

	f) Line 65 - 185 kbpd

	 

	Downstream Pipeline Capacity:

	 

	a) Line 5 - 490 kbpd

	b) Line 6A - 670 kbpd

	c) Line 6B - 290 kbpd

	d) Line 14/64 - 320 kbpd

	e) Line 61 - 320 kbpd

	f) Line 62 - 130 kbpd

	g) Line 7 - 150 kbpd

	h) Line 10 - 70 kbpd

	i) Line 11 - 120 kbpd

G-1

SCHEDULE “H” - CANADIAN AGREEMENTS

	
				
	 
	Agreement
	Relevant Dates
	Applicable
Depreciation
Term/End Date(s)

	1
	System Expansion Project (SEP) I
	SEP I assets in-service December 1, 1996
	Canadian Mainline Depreciation Truncation date of 2039

	2
	IPL/LPL and CAPP SEP II Risk Sharing Agreement dated December 8, 1998
	Agreement begins January 1, 1999 and has 15 year term
	Canadian Mainline Depreciation Truncation date of 2039

	3
	Terrace Toll Agreement Statement of Principles dated October 21, 1998
	Terrace Surcharge ends December 31, 2013
	Terrace Phases Depreciation Truncation date of Dec 31, 2024 (25 years)

	4
	Alberta Clipper Canada Settlement dated June 28, 2007
	Alberta Clipper assets in-service April 1, 2010 and agreement has 15 year term
	Depreciation calculated over 30 years

	5
	Line 4 Extension Settlement dated June 28, 2007
	Line 4 Extension assets in-service April 1, 2009 and agreement has 15 year term
	Depreciation calculated over 30 years

	6
	Southern Access Enbridge Pipelines Surcharge Terms (Appendix A of the Mainline Expansion Toll Mechanism dated January 31, 2008)
	Southern Access assets in-service May 31, 2008 and agreement has 30 year term
	Depreciation calculated over 30 years

	7
	2011 ITS dated April 1, 2011
	Effective to tolls from April 1, 2011 to December 31, 2011
	Canadian Mainline Depreciation Truncation date of 2039

H-1

SCHEDULE “I” - U.S. AGREEMENTS

	
				
	A
	Facility Surcharge Mechanism Agreement inclusive of the following:
	Relevant Dates
	Applicable Depreciation Term/End Date(s)

	1
	Superior Manifold Modification Project-FERC Docket No. 0R04-2
	Assets included in 2004 filing
	*Depreciation truncation date calculated as 2031 based on 2006 Lakehead System Depreciation Study

	2
	Griffith Hartsdale Transfer Lines Project-FERC Docket No, 0R04-02
	Assets included in 2004 toll filing
	*Depreciation truncation date calculated as 2031 based on 2006 Lakehead System Depreciation Study

	3
	Hartsdale Lease Tanks-FERC Docket No. 0R04-02
	Lease tanks in-service in January 2004. Agreement expires December 31, 2012 with option to renew for 1 year
	*Depreciation truncation date calculated as 2031 based on 2006 Lakehead System Depreciation Study

	4
	Southern Access Mainline Expansion Surcharge Terms (Exhibit III of Offers of Settlement)-FERC Docket No. 0R06-03
	Southern Access assets in-service April 1, 2008 and agreement has a 30 year term
	Depreciation calculated over 30 years per agreement

	5
	Tank 34 at Superior Terminal & Tank 79 at Griffith Terminal-FERC Docket No. 0R08-10
	Assets included in 2008 filing
	*Depreciation truncation date calculated as 2031 based on 2006 Lakehead System Depreciation Study

	6
	Clearbrook Manifold-FERC Docket No. 0R08-10
	Assets included in 2008 filing
	*Depreciation truncation date calculated as 2031 based on 2006 Lakehead System Depreciation Study

	7
	Tank 35 at Superior Terminal & Tank 80 at Griffith Terminal-FERC Docket No. 0R08-10
	Assets included in 2008 filing
	*Depreciation truncation date calculated as 2031 based on 2006 Lakehead System Depreciation Study

	8
	Alberta Clipper U.S. Expansion (U.S. Term Sheet dated June 28, 2007)-FERC Docket No, 0R08-10
	Alberta Clipper assets in-service April 1, 2010 and agreement has 15 year term
	Depreciation calculated over 30 years per agreement

	9
	Line 3 Conversion Project-FERC Docket No, 0R10-7
	Assets included in 2010 filing
	*Depreciation truncation date calculated as 2031 based on 2006 Lakehead System Depreciation Study

	10
	Line 6B Capital/Integrity-FERC Docket No. 0R11-5-000
	Assets included in 2011 filing
	Depreciation calculated over 30 years per agreement

	B
	The 1998 Offer of Settlement FERC Docket No. 0R99-2, subsequently approved by FERC by letter dated December 21, 1998 inclusive of the following:
	Relevant Dates
	 

	1
	SEP II Expansion Surcharge (1998 Offer of Settlement)
	SEP II assets in-service January 1, 1998 and agreement has 15 year term
	Remaining life of 7 years upon expiry of agreement in 2013

	2
	Terrace Toll Agreement Statement of Principles dated October 21, 1998
	Terrace Surcharge ends December 31, 2013
	Terrace Phases Depreciation Truncation date of Dec 31, 2024 (25 years)

	3
	350 Centistoke Agreement (1998 Offer of Settlement)
	Assets included in 1998 filing
	*Depreciation truncation date calculated as 2031 based on 2006 Lakehead System Depreciation Study

	4
	Southern Access Quality Guarantee
	Assets included in 2008 filing
	*Depreciation truncation date calculated as 2031 based on 2006 Lakehead System Depreciation Study

	C
	The 1996 Offer of Settlement FERC Docket Nos. IS92-27, et al., subsequently approved by FERC by letter dated October 18, 1996 inclusive of the following:
	Relevant Dates
	Applicable Depreciation Term/End Date(s)

	1
	Integrity Non-Routine Adjustments (Appendix E of 1996 Offer of Settlement)
	Assets and costs which were included under the 1996 Settlement Agreement executed August 28, 1996
	*Depreciation truncation date calculated as 2031 based on 2006 Lakehead System Depreciation Study

	Note*-Subject to future FERC approved depreciation studies

I-1

SCHEDULE “J” – ILLUSTRATIVE EXAMPLE OF APPLICATION OF CTS vs. CANADIAN AGREEMENT

Assumptions for Project A:

1.   Project A agreement dated November 30, 2009 has a 30 year term commencing January 1, 2010 and ending December 31, 2040.
2.   The Agreement stated straight line depreciation over 30 years at a depreciation rate of 3 1/3rd %
annually.
3.   Rate base is equal to the Net Book Value of Project A capital assets.
4.   The capital cost of Project A at January 1, 2010 is $50,000,000.
5.   All power and operating costs are flow through except as otherwise agreed.
6.   The agreed to fixed operating costs charges to Project A were agreed to be $3,000,000 for the calendar year ending December 31, 2010 and are allowed to escalate at 50% of the GDPP Index annually.
7.   The CTS supersedes the Project A agreement from July 1, 2011 to June 30, 2021.
8.   From January 1, 2010 to December 31, 2021 $1 million of actual capital costs are spent on the Project A assets annually for maintenance and integrity – assume additions occur evenly throughout each year.
9.   GDPP Index is 3% annually

Based on the above assumptions, at the end of the CTS on July 1, 2021, the following Project A terms would be relevant:

1)   The approximate rate base would be $40,150,538 based on the following schedule:

	
					
	PERIOD
	DATE
	Rate Base at Period End
	Additions for Period Ending
	Depreciation for Period Ending

	0
	January 1, 2010
	$50,000,000
	N/A
	N/A

	1
	December 31, 2010
	49,318,350
	$1,000,000
	1,681,650

	2
	June 30, 2011
	48,965,038
	$500,000
	853,313

	3
	June 30, 2012
	48,233,438
	$1,000,000
	1,731,600

	4
	June 30, 2013
	47,468,538
	$1,000,000
	1,764,900

	5
	June 30, 2014
	46,670,338
	$1,000,000
	1,798,200

	6
	June 30, 2015
	45,838,838
	$1,000,000
	1,831,500

	7
	June 30, 2016
	44,974,038
	$1,000,000
	1,864,800

	8
	June 30, 2017
	44,075,938
	$1,000,000
	1,898,100

	9
	June 30, 2018
	43,144,538
	$1,000,000
	1,931,400

	10
	June 30, 2019
	42,179,838
	$1,000,000
	1,964,700

	11
	June 30, 2020
	41,181,838
	$1,000,000
	1,998,800

	12
	June 30, 2021
	40,150,538
	$1,000,000
	2,031,300

	13
	December 31, 2021
	39,642,400
	$500,000
	1,028,138

2)   The fixed operating cost charges that will be allocated to Project A for the period from July 1, 2021 to December 31, 2021 would be $1,766,923.40 ($3,533,846.80X 50%) based on the following schedule:

	
				
	YEAR
	Date
	Fixed Operating Costs Allowed
	50% of GDPP Index

	0
	December 31, 2010
	$3,000,000
	 

	1
	December 31, 2011
	$3,045,000
	1.5%

	2
	December 31, 2012
	$3,090,675
	1.5%

	3
	December 31, 2013
	$3,137,035.10
	1.5%

	4
	December 31, 2014
	$3,184,090.70
	1.5%

	5
	December 31, 2015
	$3,231,852
	1.5%

	6
	December 31, 2016
	$3,280,329.80
	1.5%

	7
	December 31, 2017
	$3,329,534.80
	1.5%

	8
	December 31, 2018
	$3,379,477.80
	1.5%

	9
	December 31, 2019
	$3,430,169.90
	1.5%

	10
	December 31, 2020
	$3,481,622.50
	1.5%

	11
	December 31, 2021
	$3,533,846.80
	1.5%

J-1

SCHEDULE “K” – ILLUSTRATIVE EXAMPLES OF CAPITAL EXPENDITURES UNDER SECTION 16.3 & 16.4

Example #1 – Section 16.3
Assumptions:
1.   The Representative Shipper Group has requested that Enbridge expand capacity on the Enbridge Mainline by 150,000 barrels per day by December 31, 2017.
2.   Enbridge has completed a capital cost estimate that the project will cost approximately$500,000,000 – 1⁄2 in Canada and 1⁄2 in the U.S.
Per Section 16.3, the anticipated capital cost of the project will exceed $250,000,000.  As a result, Enbridge would be required to work with the Representative Shipper Group to negotiate any adjustment to the applicable IJT and CLT.
Conclusion: Enbridge would negotiate with the Representative Shipper Group to determine if the IJT and CLT need to be adjusted. 
Example #2 – Section 16.4
Assumptions:
1.   One shipper, Shipper Z, has requested that Enbridge increase receipt tankage at the Edmonton terminal on the Canadian Mainline to accommodate incremental volumes of 15,000 barrels per day by June 30, 2015 from a new production area.
2.   Enbridge has reviewed the service request details and is not confident that the 15,000 barrels per day of anticipated increased volumes will be required by June 30, 2015 and is uncertain, if such volumes are received on the Enbridge Mainline at the Edmonton Terminal, when the volumes would exit the Enbridge Mainline. As such, the economic benefit to Enbridge and the overall benefit of adding additional tanks into the Canadian Mainline rate base cannot be confirmed.
3.   Shipper Z and Enbridge are prepared to enter into a Backstopping Agreement to support the tankage service request on the following terms, consistent with Section 16:
		
	a.
	10 year term beginning July 1, 2015 to the earlier of June 30, 2025 or such time as all financial commitments of Shipper Z under the Backstopping Agreement have been fulfilled.

		
	b.
	 Based on a capital structure of 45% equity 

		
	c.
	Cost of debt of 6%

		
	d.   
	Enbridge will accept a return of 13% return on equity based on the overall risks assumed 

		
	e.
	Effectively amortize the cost of the capital over the 10 year term of the agreement; Revenue in Excess of the Revenue Requirement will be applied to the capital balance at the end of each year such excess is generated.

		
	f.
	Shipper Z will backstop based on 15,000 barrels per day – assumes that barrels enter the Enbridge Mainline in Edmonton and are transported to Chicago area with an initial toll of$4.50 per barrel increasing @ 2.25% per year, less incremental operating costs.

		
	g.   
	Incremental operating cost (power) is initially $1.00 per barrel escalating at 2.25% per year.

		
	h.   
	To accommodate the incremental volumes, Enbridge constructed a new tank at the Edmonton Terminal for a cost $80,000,000 with an in-service date of July 1, 2015

		
	i.
	Annual incremental operating costs were $500,000 in the first year increasing at 3% per year.

		
	j.
	The Tankage expenditures result in an 8% CCA class and the tax rate is 25% for all year. k.   Upon fulfillment of all commitments by Shipper Z under the Backstopping Agreement, the net present value of the future CCA will be paid as a credit to Shipper Z.

Conclusion:
Based on the above assumptions and the delivery profile outlined below, the following table outlines the annual financial outcome:
	
						
	Year Ended
	Average Daily Barrels
	Revenue Requirement (including incremental asset operating costs)
	Revenue Generated (less incremental transportation costs)
	Excess Revenue (net of tax)/(Shortfall Payment) (grossed up for tax)
	Cumulative Capital Recovered (including net Excess Revenue)

	June 30, 2016
	11,000
	18,533
	14,053
	(5,972)
	8,000

	June 30, 2017
	12,000
	16,680
	15,675
	(1,339)
	16,000

	June 30, 2018
	12,000
	15,971
	16,028
	42
	24,042

	June 30, 2019
	13,000
	15,245
	17,754
	1,882
	33,924

	June 30, 2020
	12,500
	14,303
	17,455
	2,364
	44,288

	June 30, 2021
	13,000
	13,297
	18,562
	3,948
	56,237

	June 30, 2022
	14,000
	12,106
	20,439
	6,250
	70,487

	June 30, 2023
	15,000
	6,778
	14,395
	11,711
	80,000

	July 31, 2023
	N/A
	(5000)*
	N/A
	N/A
	N/A

	June 30, 2024
	N/A
	N/A
	N/A
	N/A
	N/A

	June 30, 2025
	N/A
	N/A
	N/A
	N/A
	N/A

*- Capital payout achieved at end of preceding contract year.  Agreement is terminated and shipper is paid out present value of future capital cost allowance deductions.

K-1

SCHEDULE “L” – ILLUSTRATIVE EXAMPLES OF CALCULATION OF MINIMUM THRESHOLD VOLUMES

Minimum Threshold Volumes Example #1
Assumptions:
1.   Enbridge Mainline throughput ex-Gretna has been at 1,275,000 barrels per day on average for the 9 month period ending July 31, 2016.
2.   The Enbridge Mainline has received 325,000 barrels per day of the Bakken/ Three Forks U.S. production on average for the same 9 month period ending July 31, 2016.
3.   All the Bakken/ Three Forks U.S. production received on the Enbridge Mainline for the nine month period ending July 31, 2016 were delivered into Northern PADD II or Sarnia.
4.   There are no other adjustments to the Minimum Threshold Volume.
Based on the above assumptions, the applicable Minimum Threshold Volume would be:
		
	•
	1,350,000 barrels per day (per Section 19.1 – after December 31, 2014)

		
	•
	Less 20,000 barrels per day (per Section 19.2 – reduced by the amount that Bakken Three Forks US receipts exceed 305,000 barrels per day)

= Minimum Threshold Volumes of 1,330,000 barrels per day 
Conclusion:  Enbridge would be in a position to provide a Renegotiation Notice. 
Minimum Threshold Volumes Example #2
Assumptions:
1.   Enbridge Mainline throughput ex-Gretna has been at 1,200,000 barrels per day on average for the 9 month period ending December 31, 2012.
2.   The Enbridge Mainline has received 385,000 barrels per day of the Bakken/ Three Forks U.S. production on average for the same 9 month period ending December 31, 2012.
3.   20,000 barrels per day of the Bakken/ Three Forks U.S. production received on the Enbridge Mainline for the nine month period ending December 31, 2012 were delivered into Mustang.
4.   365,000 barrels per day of the Bakken/ Three Forks U.S. production received on the Enbridge Mainline for the nine month period ending December 31, 2012 were delivered into Northern PADD II or Sarnia.
5.   There are no other adjustments to the Minimum Threshold Volume.
Based on the above assumptions, the applicable Minimum Threshold Volume would be 
		
	•
	1,250,000 barrels per day (per Section 19.1 – before December 31, 2014)

		
	•
	Less 60,000 barrels per day (per Section 19.2 – reduced by the amount that Bakken Three Forks U.S. receipts exceed 305,000 barrels per day delivered into PADD II or Sarnia

= Minimum Threshold Volumes of 1,190,000 barrels per day
Conclusion:  Enbridge would NOT be in a position to provide a Renegotiation Notice. 
Minimum Threshold Volumes Example #3
Assumptions:
1.   On May 31, 2013 flooding of the Red River in Manitoba, significantly impacted the Canadian Mainline, in a manner that was beyond reasonable design or operational considerations and reduced throughput ex-Gretna to 1,000,000 barrels per day. Enbridge has undertaken its best efforts, which are considered reasonable by industry standards, between May 31, 2013 and February 28, 2014 to repair the damage and remove all pressure restrictions.
2.   Enbridge Mainline throughput ex-Gretna was 1,500,000 barrels per day on average for the 9 month period ending May 30, 2013.
3.   Enbridge Mainline throughput ex-Gretna was 1,000,000 barrels per day on average for the 9 month period ending February 28, 2014.
4.   There are no other adjustments to the Minimum Threshold Volume.
Based on the above assumptions, the applicable Minimum Threshold Volume would be:
		
	•
	1,250,000 barrels per day (per Section 19.1 – before December 31, 2014)

		
	•
	There is no adjustment to the Minimum Threshold Volume for capacity loss on the Enbridge Mainline pursuant to Section 19.5 since the capacity loss was due to a Force Majeure event.

= Minimum Threshold Volumes of 1,250,000 barrels per day
Conclusion:  Enbridge would be in a position to provide a Renegotiation Notice.

L-1

SCHEDULE “M” – MAINLINE CAPITAL REPORTING TEMPLATE

	
					
	 
	A
	B
	C
	D

	1
	Capital Project AFE Number
	Capital Project Expenditure in Prior years
	Capital Project Expenditure during Past Calendar Year
	Capital Project Expenditure Forecast for Current Calendar Year

	2
	Canadian Mainline: Each Project AFE in excess of $50 M in Canadian $
	 
	 
	 

	3
	Project A
	CDN$ in 2010 & prior
	CDN$ in 2011
	CDN$ in 2012

	4
	Project B
	CDN$ in 2010 & prior
	CDN$ in 2011
	CDN$ in 2012

	5
	Project C
	CDN$ in 2010 & prior
	CDN$ in 2011
	CDN$ in 2012

	6
	Canadian Mainline: Total of Shipper Supported Capital Projects less than $50 M per project in Canadian $
	 
	 
	 

	7
	Sum of all other AFEs
	 
	 
	 

	8
	Total
	 
	 
	 

	9
	Lakehead System: Each Project AFE in excess of $50 M in US$
	 
	 
	 

	10
	Project X
	US$ in 2010 & prior
	US$ in 2011
	US$ in 2012

	11
	Project Y
	US$ in 2010 & prior
	US$ in 2011
	US$ in 2012

	12
	Project Z
	US$ in 2010 & prior
	US$ in 2011
	US$ in 2012

	13
	Lakehead System: Total of Shipper Supported Capital Projects less than $50 M per project in US$
	 
	 
	 

	14
	Sum of all other AFEs
	 
	 
	 

	15
	Total
	 
	 
	 

Note: Example provided for reporting in February 2012.
Amounts in columns B & C will be actual results while amounts in columns D will be forecast and subject to amendment/change.

M-1

SCHEDULE “N” – ENBRIDGE SERVICE LEVELS

N-1

Enbridge Pipelines Inc. 
Enbridge Energy Partners, L.P. 
Enbridge Pipelines (Toledo) Inc.

Service    Levels

April, 2011

	
		
	Enbridge Service Levels
	Page 2

1.    INTRODUCTION
This document provides information respecting Enbridge’s operation and service levels.
The Service Levels and system operation are based on the system configuration in place for the second quarter of 2011.  The actual service of the pipeline on a day-to-day basis will depend on numerous variables.  Enbridge will use reasonable efforts to operate the pipeline system in accordance with current Service Levels.
As changes occur to the pipeline system configuration and operation, or customer requirements, Service Level revisions will be undertaken to reflect such changes.
Enbridge is obligated to provide transportation service pursuant to the terms and conditions specified by the tariff Rules and Regulations, on file with the National Energy Board (NEB).  Service Levels provided in this document are not intended to amend the tariff Rules and Regulations.
The Service Levels described encompass both the Enbridge Canadian and United States (U.S.) Mainline1 transportation systems.  The service references for Lakehead2 are not intended to amend the service rules and regulations outlined in Lakehead’s tariff, on file with the Federal Energy Regulatory Commission (FERC).
The Enbridge Service Levels described in this document are broken into three sections: Operations, Procedures and Reporting, and Communications.  The Operations section describes movement associated with the current Mainline System operation.  For the commodities shipped on the system this section describes normal line routings, transit times, tankage considerations and batch management.  The Procedures and Reporting section outlines scheduling events, supply control activities and other general movement information.  The Communication section provides a statement on the general principles around communication to Enbridge’s customer base.

1 Enbridge Pipelines Inc., Enbridge Energy Partners, L.P., and Enbridge Pipelines (Toledo) Inc.
2 Enbridge Energy Partners, L.P.

	
		
	Enbridge Service Levels
	Page 3

2.       OPERATIONS
A.  General
Enbridge provides transportation service using a batched system to retain commodity integrity and shipper ownership for a wide variety of Crude Petroleum, Refined Products and Natural Gas Liquids (NGL).  The Enbridge system is a supply driven system, with shippers (producers, marketers and refiners) nominating supplies onto the system on a monthly basis.  These supplies are scheduled and routed through the system to identified delivery locations.  Nominations for local transfers through an Enbridge terminal are routed as operating conditions allow. During the month supplies are received from feeder pipelines/transfer facilities into the various Enbridge receipt facilities where the supplies are aggregated for shipment and/or directly injected into the Mainline System.  Subject to the operating conditions of the pipeline system, shippers may request changes to injection and  delivery  location,  volume  and  commodity  type  on  receipt  and delivery and ownership, which may result in operational adjustments.
B.  Ratability
Enbridge’s  objective  is  to  operate  its  system  so  that  nominations  are  pumped  and delivered on a ratable and predictable basis. Delivery ratability and predictability are primarily dependent upon ratable supply into Enbridge.  Supply ratability can affect Enbridge’s ability to meet the Service Levels described below.
C.  Commodity Receipt Summary (Tables 1A and 1B)
The Enbridge system transports a wide variety of commodities, including both Canadian and U.S. receipts.  Tables 1A and 1B depict the current approved receipt commodities with their acronyms, receipt locations, and feeder pipeline/transfer facilities on both the Enbridge and Lakehead transportation systems.  New commodities not in the table must be  applied  for  through  the  applicable  service  request  procedure.    Commodities  not shipped for a period of time or which revert to a commingled stream are subject to removal from the table, and will be required to be re-applied for to be re-instated.
D.  Commodity Routing Summary by Pipeline Segment (Table 2)
Enbridge provides batch transportation service where commodities are segregated according to quality specifications and standards to minimize interfacial contamination between batches and track batch ownership.
Individual pipeline segments comprising the Enbridge Mainline System are used to transport  specific  commodities.     Allocation  of  commodities  to  these  pipelines  is dependent upon several factors, including but not limited to petroleum quality, supply, tankage constraints, connectivity, receipt and delivery patterns, ratability, apportionment and power costs.
Enbridge reserves the right to revise commodity allocations to optimize pipeline operations in a fair and equitable manner.

	
		
	Enbridge Service Levels
	Page 4

The summary provided in Table 2 provides the base Service Level routings and permissible routing of commodities.  A schematic system diagram is attached to this table (as Figure 1) and describes the general commodity slate for each pipeline segment.
E.  General Pipeline Operations
The following outlines pipeline operations for each pipeline segment.
Upstream of Superior Pipelines
Line 1 (Edmonton to Superior)
Line  1  originates  at  Edmonton  and  extends  to  Superior,  Wisconsin  transporting natural gas liquids (NGL), refined products, synthetics and required synthetic buffers. There are six refined products cycles (three gasoline and three distillate cycles) and six NGL cycles per month. All NGL and refined product volumes are pumped as a direct receipt from feeder pipeline or connected refineries.
		
	•
	Refined products are injected at Edmonton and Regina and are delivered at Milden Take-off, Regina and Gretna.

		
	•
	NGL is injected at Edmonton, Kerrobert and Cromer and is transported to breakout facilities at Superior Terminal.

All crude volumes access breakout tankage at Superior before being re-pumped over Lines 5, 6, 14 or 61, or as tank transfer deliveries to Murphy.  NGL advances through the NGL spheres to be re-pumped over Line 5 or as sphere transfer deliveries to BP- NGL.
Line 2 (Edmonton to Superior)
The pipeline segment from Edmonton to Cromer is referred to as Line 2A and the pipeline segment from Cromer to Superior is referred to as Line 2B.  All Line 2A volumes breakout into Cromer tankage before being re-pumped on Line 2B.
Line 2A (Edmonton to Cromer)
		
	•
	Line 2A originates at Edmonton and pumps condensate, light synthetic, sweet, light sour and high sour batches.  Batches are scheduled to pump with compatible crude types adjacent to one another, if available.

		
	•
	At Hardisty, deliveries of condensate, light synthetic, sweet, light sour and high sour crude batches may be scheduled to Express Pipeline, Hardisty Caverns, L.P., Gibsons, Husky, Flint Hills Resources, Enbridge Hardisty Contract Terminal, or Enbridge Mainline tankage. During deliveries, if possible, injections of light synthetic are scheduled simultaneously to optimize Line 2 operations.

		
	•
	At Kerrobert, deliveries of condensate to Plains occur simultaneously, if possible, with sweet injections.

	
		
	Enbridge Service Levels
	Page 5

		
	•
	At  Regina,  deliveries  of  condensate  to  Plains  and  light  synthetic  crudes  to Consumers Co-op or Wascana Pipeline occur simultaneously, if possible, with light synthetic or high sour injections.

		
	•
	At Cromer, all incoming Line 2A volumes access breakout tankage.

Line 2B (Cromer to Superior)
		
	•
	At Cromer all Line 2A volumes along with sweet and light sour receipts entering the  system at Cromer are rescheduled and reinjected on a daily cycle including condensate, light synthetic, sweet, light sour and high sour receipts.

		
	•
	At  Clearbrook,  mostly  light  synthetic  along  with  some  sweet  and  high  sour batches are delivered to Minnesota Pipeline. During these Line 2 deliveries "windows" U.S. sweet volumes are injected.   There is also the ability to inject light sour and medium crude coming from Line 65 via Clearbrook tankage if necessary.

		
	•
	At Superior, the volumes access breakout tankage and are scheduled to re-pump over Lines 5, 6, 14, or 61, or as tank transfer deliveries to Murphy.

Line 3 (Edmonton to Superior)
Line 3 originates at Edmonton and pumps condensate, light synthetic, sweet, light sour and high sour batches.  Batches are scheduled to pump with compatible crude types adjacent to one another, if available.
At Hardisty, available deliveries of condensate, light synthetic, sweet, light sour and high sour batches may be scheduled to Express Pipeline, Gibsons, Husky and Flint Hills Resources.  During these Line 3 deliveries “windows”, if possible, injections of high sour from Gibsons or light synthetic batches from Enbridge Mainline Tankage are scheduled to optimize Line 3 operations.
At Clearbrook, in the event that deliveries are scheduled off of Line 3, volumes coming from Line 65 via Clearbrook tankage may be injected.  If required, U.S. sweet and/or volumes coming from Line 2B via Clearbrook tankage may also be injected. Line 3 cannot deliver to Clearbrook tankage.
At Superior, the volumes access breakout tankage and are scheduled to re-pump over Lines 5, 6, 14, or 61, or as tank transfer deliveries to Murphy.
Line 4 (Edmonton to Superior)
Line 4 originates at Edmonton and pumps heavy volumes received at Edmonton, Hardisty, Kerrobert and Regina.  Some of the volumes originating at Hardisty and Kerrobert are scheduled for injection on a nominal 2-day cycle.
		
	•
	At Edmonton available volumes of heavy are scheduled and pumped in each cycle.  Sarnia Special volumes are pumped on an as-requested basis subject to the availability of receipt tankage.

	
		
	Enbridge Service Levels
	Page 6

		
	•
	At  Hardisty  deliveries  of  heavy  crude  batches  to  Express  Pipeline,  Hardisty Caverns, L.P., Flint Hills Resources, Enbridge Hardisty Contract Terminal, and Gibsons  are available off  Line 4.    Hardisty Line 4  injections  from  Gibsons, Husky, Flint Hills Resources, Hardisty Caverns, L.P., Enbridge Hardisty Contract Terminal, and Enbridge mainline tankage commence with Hardisty deliveries and are  scheduled  in  a  predetermined  pattern  each  cycle.  Upon  completion  of delivered and breakout volumes Line 4 is shutdown ex Edmonton.

		
	•
	At Kerrobert, heavy volumes from Plains and Inter Pipeline are injected over Line4. Available deliveries to Plains are scheduled simultaneous with injections.

		
	•
	At Stoney Beach heavy crude side stream deliveries are made to Gibsons.

		
	•
	At  Regina  deliveries  of  heavy  crude  oil  batches  to  Consumers  Co-op  and Wascana Pipeline are available from Line 4.   To the extent possible, heavy injections are scheduled to occur simultaneously with scheduled deliveries.

		
	•
	At Clearbrook Line 4 volumes are delivered to Minnesota Pipeline.  During these deliveries  U.S.  medium  and  volumes  coming  from  Line  65  via  Clearbrook tankage may be injected.   If required, quality trains of U.S. sweet and/or some sweet, light sour or high sour batches coming from Line 2B via Clearbrook tankage may also be injected. Line 4 cannot deliver to Clearbrook tankage.

		
	•
	At Superior Line 4 incoming volumes access breakout tankage. Line 4 volumes are scheduled to re-pump over Lines 6, 14 or 61 or as tank transfer deliveries to Murphy.

Line 67 (Hardisty to Superior)
Line 67 originates at Hardisty and can pump heavy, heavy high tan, heavy low resid or cracked material to Clearbrook or Superior. It can also pump Edmonton heavies should they deliver to Enbridge Hardisty Contract Terminal or Enbridge Mainline tankage.
At Clearbrook Line 67 volumes can be delivered to Minnesota Pipeline. Line 67 cannot deliver to Clearbrook tankage.
At Superior Line 67 incoming volumes access breakout tankage. Line 67 volumes are scheduled to re-pump over Lines 6, 14 or 61 or as tank transfer deliveries to Murphy.
Line 65 (Cromer to Clearbrook)
Line 65 transports medium and light sour crude from Cromer to Clearbrook.  All volumes that are not delivered to Minnesota Pipeline, access breakout tankage and can be reinjected on Lines 3, 4 or 2B for shipment to Superior.
Downstream of Superior Pipelines
Line 5 (Superior to Sarnia)

	
		
	Enbridge Service Levels
	Page 7

Line 5 transports condensate, light synthetic, sweet, light sour and NGL volumes destined for Sarnia and east of Sarnia delivery points.  When possible, compatible batches are scheduled to pump adjacent to one another.
At Rapid River scheduled NGL volumes are side-stream delivered for stripping of their required components.  Concurrent with the side stream deliveries are side stream injections of stripped NGL.
At Lewiston scheduled U.S. sweet volumes are injected.
After  the  scheduled  deliveries  have  been  made  at  Marysville  and  Sarnia  area refineries the balance of the Line 5 incoming volumes access breakout tankage at Sarnia for subsequent movement on Line 7.  When necessary, Line 5 and Line 6B delivery conflicts at Sarnia are directed to Enbridge tankage prior to being delivered directly to the refinery.
Line 61 (Superior to Flanagan)
Line 61 can transport all approved mainline commodities except NGL, refined products and cracked material.
At Flanagan all volumes access breakout tankage and are either reinjected on the Line 55 contract pipeline for movement to Cushing, Oklahoma or are reinjected on Line 62 for movement to Griffith/Hartsdale.
Line 62 (Flanagan to Griffith/Hartsdale)
Line 62 can transport heavy crude from Flanagan breakout tankage to Griffith / Hartsdale terminal. Volumes destined for delivery beyond Griffith/Hartsdale access breakout tankage for subsequent reinjection on Line 6B.  Volumes can also access the BP Whiting refinery utilizing Griffith/Hartsdale delivery tankage.
Line 6 (Superior to Sarnia)
Line 6 transports volumes of heavy, heavy high tan and heavy low resid crudes for delivery in the Chicago area and those destined for delivery at Sarnia / Toronto / Buffalo area refineries.  Quality trains of light synthetic and medium destined to Mustang Pipeline are also scheduled on Line 6 because it is the only line connected to Lockport terminal.
Line 6A (Superior to Griffith/Hartsdale)
		
	•
	The pipeline segment from Superior to Griffith/Hartsdale is referred to as Line 6A.

		
	•
	In the Chicago area, deliveries can be made at Lockport, Mokena and Griffith.

		
	•
	Volumes delivered at Lockport can be pumped over Mustang Pipeline for subsequent movement from Lockport to Patoka.

		
	•
	Volumes destined for delivery beyond the Chicago area access breakout tankage at Griffith/Hartsdale and are scheduled to pump ex Griffith. Deliveries destined for BP 

	
		
	Enbridge Service Levels
	Page 8

Whiting  utilize  Griffith/Hartsdale  delivery  tankage  for  subsequent transfers to the refinery.
Line 6B (Griffith/Hartsdale to Sarnia)
		
	•
	The pipeline segment from Griffith/Hartsdale to Sarnia is referred to as Line 6B. 

		
	•
	At Stockbridge volumes destined for Samaria and Toledo access breakout tankage for subsequent movement over Line 17.

		
	•
	Scheduled Line 6B deliveries occur at Marysville and the Sarnia area refineries. The  remaining  Line  6B  volumes  destined  for  delivery  east  of  Sarnia  access breakout tankage at Sarnia for subsequent movement over Line 7 to connecting lines through Westover Terminal. When necessary, Line 6B and Line 5 delivery conflicts  at  Sarnia  are  directed  to  Enbridge  tankage  prior  to  being  delivered directly to the refinery.

Line 14/64 (Superior to Griffith/Hartsdale)
Line 14/64 transports volumes ranging between condensate and medium crudes for delivery at Mokena and Griffith respectively. It is also possible for volumes transported  on  Line  64  to  access  breakout  tankage  at  Griffith/Hartsdale  for subsequent movement on Line 6B.
Even though the summary provided in Table 2 of this document (Commodity Routing Summary by Pipeline Segment) allows heavier commodities into Line 14/64, in normal operations it is considered a light crude oil line.
Line 17 (Stockbridge to Toledo)
Line 17 transports volumes of light sour, high sour, medium, heavy, heavy high tan, heavy low resid crude for delivery at Samaria and Toledo.
Line 7 (Sarnia to Westover) 
Line 10 (Westover to Kiantone) 
Line 11 (Westover to Nanticoke)
Volumes pumped over Line 7 access breakout tankage at Westover.  These volumes are subsequently rescheduled to pump over Line 10 for delivery to United Refining at Kiantone and Line 11 for delivery to Imperial Oil at Nanticoke.
F.  Predicted Pipeline Transit Times (Table 3)
Predicted transit times associated with service offered by Enbridge are provided on the Oil Movement Manager / Shipper Information System (OM2/SIS) Portal.  Proxy transit times are updated weekly, and are based on original Notices of Shipment (NOS) and Revised Notices of Shipment.
Table 3 provides instructions for using the OM2/SIS Transit Time Calculator.
G.  Minimum Batch Size (Table 4)

	
		
	Enbridge Service Levels
	Page 9

The nominal batch size in the Enbridge system is 10,000 m3 and is subject to nominations on each pipeline and feeder pipeline requests.  Batch sizes are generally a function of the volume nominated, as well as the size and number of available receipt, break-out and delivery tanks for given commodities (both within the Enbridge Mainline System and with connected feeder pipelines and refineries).
Minimum Batch Size
A shipper’s minimum monthly nomination volume, for any commodity, is typically restricted to the minimum batch sizes defined in Table 4.  This table sets out batch size considerations for the base Service Levels.  Minimum batch sizes are set based on the requirements of measurement, quality, tank utilization, capacity impact, pipeline integrity and administrative efficiency. The minimum batch size for movement on the Enbridge Mainline System is determined by the size indicated for the pipeline of delivery.
Maximum Batch Size
Maximum batch sizes are generally determined by terminal tankage availability or other operational considerations.  Currently 12,000 m3 is the largest typical batch size transported on the system; however larger batch sizes or double-batching of commodities can be reviewed by Enbridge on an individual basis with consideration to system and shipper constraints.
Enbridge and Shippers must ensure that nominated volumes can be divided into standard batch sizes within the minimum and maximum batch size parameters.  Batch sizes may also be impacted by cycle sizes on each line to maintain overall system quality guidelines.
H. Tankage Operations and Utilization by Commodity Category (Table 5)
Receipt, breakout and delivery tankage is required for the transportation of specific commodities on the Enbridge System.  Table 5 outlines the commodities that utilize tankage at various terminal locations associated with the base Service  Levels.   The tankage allocation in Table 5 is predicated on factors including but not limited to preserving the petroleum quality of batches transported on the Enbridge system. To the greatest extent possible, Enbridge will advise shippers prior to making any significant changes to tank utilization.
Actual time in tankage at each location will be dependent upon commodity allocations to each tank, system operating conditions and/or third party operations.  As a result, tankage retention times at individual locations may vary significantly as detailed in Tankage Operation.
Tankage Operation
Tanks on the Enbridge / Lakehead system are an integral part of the physical pipeline system.   There are four basic categories for tanks: receipt, breakout, delivery and operational as detailed below.
Receipt Tankage

	
		
	Enbridge Service Levels
	Page 10

Receipt tankage is designed to accumulate incoming volumes until such time that the volumes are scheduled to pump.  In some cases a volume or batch may pump as soon as it is received.  However at other times, especially for smaller volumes or equalized streams, volumes may be accumulated until such time that a batch is available to pump.
The Enbridge system has been historically designed such that receipt tankage is provided for a nominal retention time of 4 days. Regular operation and recent analysis indicate that retention times are moving below 4 days. Shippers and feeders should be aware of the retention times for their respective commodities.
Breakout Tankage
Breakout tankage is designed and built at locations where there is a substantial rate change, due to volumes entering or leaving the system, and may also be considered to preserve the quality of the streams. At these locations, volumes are received to breakout tankage and re-pumped on another line segment.  At breakout locations the retention time in tankage is defined as the time between landing and re-pumping batches.  The Enbridge system has been designed such that breakout tankage is provided for a nominal retention time of 2 days.
Breakout  tankage  is  designed  and  built  mainly  to  reduce  power  costs,  pressure cycling and capital costs for new pipeline expansions. Below some examples are described where breakout tankage is required.
		
	•
	Line  2A  volumes  currently  access  breakout  tankage  at  Cromer,  and  these volumes along with other receipts entering the system at Cromer are subsequently rescheduled on Line 2B.

		
	•
	At Superior there are 5 incoming pipelines and 4 outgoing pipelines, but none of the incoming rates match the outgoing rates. Therefore all volumes are required to access breakout tankage and volumes are rescheduled for subsequent movement on the various outgoing lines.

The actual time in tankage can vary from batch to batch depending on pipeline conditions  with  consideration  given  to  but  not  limited  to  scheduling,  petroleum quality or unplanned interruptions.  Consideration will be given to shipper requests as operational conditions allow.
Delivery Tankage
At some delivery locations the receiving refinery is not able to receive crude volumes at the full Enbridge mainline rate.  In these situations, the scheduled delivery volume will first access an Enbridge delivery tank and then be transferred over to the refinery at a lower transfer rate.   Superior and Griffith are locations where this type of operation occurs.
Operational Tankage
Tankage may be utilized for operational considerations to "absorb" the flow rate change from operating to shut down mode, and vice versa.     There is Mainline tankage available 

	
		
	Enbridge Service Levels
	Page 11

at Hardisty, Kerrobert, Regina, and Clearbrook that may be utilized as Operational tankage if required.

	
		
	Enbridge Service Levels
	Page 12

3.    PROCEDURES AND REPORTING
A.  Commodity Testing (Table 6)
Enbridge conducts various standard tests for commodities transported on the pipeline system.    These  standard  tests  are  summarized  for  each  commodity  with  respect  to location, frequency, and type of test in Table 6, Commodity Testing Summary. Commodity quality measurement is also provided in Table 6.
B.  Shipper Services Business Activities  (Tables 7 & 8)
To manage the logistics of transporting commodities through its system, Enbridge and industry have developed a set of procedures and reporting requirements with respect to nominations, supply control and scheduling activities on its system.   These are summarized in Table 7 (Scheduling Calendar) and Table 8 (Shipper Services Business Activities).
4.    COMMUNICATIONS
An  important  component  of  Enbridge  service  is  communication  to  its  customers. Enbridge operations can have a material impact on oil markets and, in turn, on producers, marketers, shippers and refiners.  As such, Enbridge will strive to provide these impacted parties with timely access to system related information on its commodity movements, operational decisions and events.
Where unscheduled and unplanned events impact, or potentially impact, Enbridge operations, these will be communicated to Enbridge customers as quickly as possible, subject to any commercial considerations.   Ideally, changes to planned or scheduled events  will  be  communicated  with  prior  notice.  Generally  and  where  feasible,  the objective will be to inform impacted parties of events or circumstances so that there are "no surprises" regarding system operations.
Enbridge also has a reciprocal expectation on its customers to provide accurate and timely information in order to fulfill the above noted communication obligations.

LIST OF TABLES
AND FIGURES

	
				
	ENBRIDGE SERVICE LEVELS

	List of Figures

	Figure 1
	Pipeline System Configuration

	List of Tables

	Table 1
	Commodity Receipt Summary

	 
	Table 1A
	Commodity Receipt Summary – Canada

	 
	Table 1B
	Commodity Receipt Summary – United States

	Table 2
	Commodity Routing Summary by Pipeline Segment

	Table 3
	Instructions for Using the OM2/SIS Transit Time Calculator

	Table 4
	Minimum Batch Size

	Table 5
	Tank Utilization by Commodity Type

	Table 6
	Commodity Testing Summary

	 
	Table 6A
	General Testing

	 
	Table 6B
	Sweet Streams Testing

	 
	Table 6C
	Sour Streams Testing

	 
	Table 6D
	Condensate Sampling Procedures and Testing – Edmonton Terminal

	 
	Table 6E
	Line 1 Synthetic Buffer Testing

	Table 7
	Scheduling Calendar

	Table 8
	Shipper Services Business Activities

	 
	Table 8A
	Supply Management

	 
	Table 8B
	Carriers Inventory Table

	 
	Table 8C
	Oil Accounting

	
		
	List of Figures
	 

	Figure 1-Pipeline System Configuration
	 

	 
	Page 1

Figure 1
Pipeline System Configuration – Quarter 1, 2011

	
		
	List of Tables
	 

	Table 1-Commodity Receipt Summary
	 

	 
	Page 2

Table lA
Commodity Receipt Summary - Canada

	
				
	Receipt Location
	Quality Category
	Transport Commodity
	Feeder Pipeline or Transfer Facility
Company Name [Facility Name]

	Edmonton
	NGL
	Natural Gas Liquids (NGL)
	BP [Fort Saskatchewan Facility]

	Refined Products
	Gasoline
	Imperial Oil [Strathcona Refinery], Suncor [Edmonton Refinery]. Shell [Scotford Refinery]

	Distillate
	Imperial Oil [Strathcona Refinery], Suncor [Edmonton Refinery], Shell [Scotford Refinery]

	Condensate
	Condensate Blend (CRW)1
	BP [Coed Pipeline], Gibsons [Edmonton Terminal], Keyera [Fort Saskatchewan Pipeline], Pembina [Peace Pipeline, Drayton Valley Pipeline, Swanhills Pipeline], Suncor [Edmonton Refinery, Oil Sands Pipeline], Plains [Rainbow Pipeline, Rangeland Pipeline, Joarcam Pipeline], Kinder Morgan [North 40 Terminal], Enbridge [Southern Lights Pipeline]

	Light Synthetic
	Suncor A (OSA)
	Suncor [Oil Sands Pipeline]

	Suncor C (OSC)
	Suncor [Oil Sands Pipeline]

	Syncrude (SYN)
	Pembina [Alberta Oil Sands Pipeline], Kinder Morgan [North 40 Terminal], Plains [Rangeland Pipeline]

	Premium Albian Synthetic (PAS)
	Inter Pipeline [Corridor Pipeline], Kinder Morgan [North 40 Terminal]

	Shell Premium Synthetic (SPX)
	Inter Pipeline [Corridor Pipeline]

	Shell Synthetic Light (SSX)
	Inter Pipeline [Corridor Pipeline]

	CNRL Light Sweet Synthetic Blend (CNS)
	Pembina [Horizon Pipeline]

	CNRL Synthetic Custom Blend (CNC)
	Pembina [Horizon Pipeline]

	Sweet
	Mixed Blend Sweet (SW)1
	Plains [Rainbow Pipeline, Joarcam Pipeline], Gibsons [Edmonton Terminal], Pembina [Bonnie Glen Pipeline, Peace Pipeline, Drayton Valley Pipeline, Swanhills Pipeline], Kinder Morgan [North 40 Terminal]

	Light Sour
	Low Sulphur Sour (SLE)1
	Gibsons [Edmonton Terminal], Inter Pipeline [Central Alberta Pipeline], Pembina [Drayton Valley], Plains [Joarcam Pipeline, Rangeland Pipeline], Kinder Morgan [North 40 Terminal]

	High Sour
	High Sulfur Sour (SHE)1
	Gibsons [Edmonton Terminal], Pembina [Peace Pipeline], Kinder Morgan [North 40 Terminal]

	Heavy
	Albian Heavy Synthetic (AHS)
	Kinder Morgan [North 40 Terminal], Inter Pipeline [Corridor Pipeline]

	Albian Residual Blend (ARB)
	Kinder Morgan [North 40 Terminal], Inter Pipeline [Corridor Pipeline]

	Cold Lake (CL)
	Inter Pipeline [Cold Lake Pipeline West], Kinder Morgan [North 40 Terminal]

	Wabasca Heavy (WH)
	Plains [Rainbow Pipeline], Kinder Morgan [North 40 Terminal]

	Heavy High Tan
	Peace Heavy (PH)
	Plains [Rainbow Pipeline], Kinder Morgan [North 40 Terminal]

	Seal Heavy (SH)
	Plains [Rainbow Pipeline]

	Access Western Blend (AWB)
	Devon & MEG [Access Pipeline]

	Albian Muskeg River Heavy (AMH)
	Inter Pipeline [Corridor Pipeline]

	Stratoil Cheecham Blend (SCB)
	Enbridge [Waupisoo Pipeline]

	Surmont Heavy Blend (SHB)
	Enbridge [Waupisoo Pipeline]

	Heavy Low Resid
	Suncor H (OSH)
	Enbridge [Waupisoo Pipeline]

	Albian Vacuum Blend (AVB)
	Inter Pipeline [Corridor Pipeline], Kinder Morgan [North 40 Terminal]

	Cracked
	CNRL Heavy Sour Synthetic Blend (CNH)
	Pembina [Horizon Pipeline]

	Other
	Caroline Condensate (CCA)
	Plains [Rangeland Pipeline]

	Sarnia Special (SSS)
	Imperial Oil [Strathcona Refinery]

1 Component streams indicated represent the current feeder components for each stream respectively.

	
		
	List of Tables
	 

	Table 1-Commodity Receipt Summary
	 

	 
	Page 3

Table lA  Continued
Commodity Receipt  Summary - Canada

	
				
	Receipt Location
	Quality Category
	Transport Commodity
	Feeder Pipeline or Transfer Facility
Company Name [Facility Name]

	Hardisty
	Light Synthetic
	Suncor A (OSA)
	Enbridge [Athabasca Pipeline]

	Suncor C (OSC)
	Enbridge [Athabasca Pipeline]

	Husky Synthetic Blend (HSB)
	Husky [Hardisty Terminal]

	BP Sweet Synthetic Blend (BSS)
	Enbridge [Hardisty Caverns]

	Long Lake Light Synthetic Blend (PSC)
	Enbridge [Athabasca Pipeline]

	Sweet
	Long Lake Sweet Blend (PSW)
	Enbridge [Athabasca Pipeline]

	Light Sour
	BP Sour Blend (BSO)
	Enbridge [Hardisty Caverns]

	Long Lake Sour Blend (PSO)
	Enbridge [Athabasca Pipeline]

	High Sour
	Hardisty Sour (SO)
	Gibsons [Hardisty Terminal]

	Heavy
	Cold Lake (CL)
	Inter Pipeline [Cold Lake Pipeline South], Flint Hills [Hardisty Terminal]. Gibsons [Hardisty Terminal], Enbridge [Hardisty Caverns]

	BP Synthetic Heavy Blend (BSH)
	Enbridge [Hardisty Caverns]

	BP Conventional Heavy Blend (BCH)
	Enbridge [Hardisty Caverns]

	Western Canadian Blend (WCB)
	Husky [Hardisty Terminal]

	Western Canadian Select (WCS)
	Husky [Hardisty Terminal], Enbridge [Hardisty Caverns]

	Bow River (BR)
	Gibsons [Hardisty Terminal]

	Lloydminister Hardisty (LLB)
	Husky [Hardisty Terminal], Enbridge [Hardisty Caverns]

	Heavy High Tan
	Mackay River Heavy (MKH)
	Enbridge [Athabasca Pipeline], Flint Hills [Hardisty Terminal], Gibsons [Hardisty Terminal]

	Long Lake Heavy SynBit Blend (PSH)
	Enbridge [Athabasca Pipeline]

	Christina SynBit (CSB)
	Gibsons [Hardisty Terminal]

	Borealis Heavy Blend (BHB)
	Enbridge [Athabasca Pipeline], Flint Hills [Hardisty Terminal], Gibsons [Hardisty Terminal]

	Heavy Low Resid
	Suncor H (OSH)
	Enbridge [Athabasca Pipeline], Flint Hills [Hardisty Terminal], Gibsons [Hardisty Terminal]

	Cracked
	Pine Blend Special (PBS)
	Flint Hills [Hardisty Terminal]

	Suncor Cracked C (OCC)
	Enbridge [Athabasca Pipeline]

	Kerrobert
	NGL
	Natural Gas Liquids (NGL)
	BP [Kerrobert Caverns]

	Sweet
	Mixed Blend Sweet (SW)
	Inter Pipeline [Mid-Saskatchewan Pipeline]

	Heavy
	Lloydminister Kerrobert (LLK)
	Plains [Manito Pipeline]

	Smiley Coleville (SC)
	Inter Pipeline [Mid-Saskatchewan Pipeline]

	Regina
	Refined Products
	Gasoline
	Consumers Co-operative [Regina Refinery]

	Distillate
	Consumers Co-operative [Regina Refinery]

	Light Synthetic
	Newgrade Synthetic Blend A (NSA)
	Consumers Co-operative [Regina Upgrader]

	Newgrade Synthetic Blend X (NSX)
	Consumers Co-operative [Regina Upgrader]

	High Sour
	Moose Jaw Tops (MJT)
	Plains [South Saskatchewan Pipeline]

	Heavy
	Fosterton (F)
	Plains [South Saskatchewan Pipeline]

	Cromer
	NGL
	Natural Gas Liquids (NGL)
	Enbridge [Westspur Pipeline]

	Sweet
	Mixed Blend Sweet (SW)
	Tundra [Tundra Pipeline]

	Light Sour
	Light Sour Blend (LSB)1
	Enbridge [Virden Pipeline, Westspur Pipeline], Penn West [Waskada Pipeline], Tundra [Tundra Pipeline]

	Medium
	Midale (M)1
	Enbridge [Virden Pipeline, Westspur Pipeline]

	Sarnia
	Condensate
	BP Condensate Blend (ACB)
	BP [Sarnia Extraction Plant]

1 Component streams indicated represent the current feeder components for each stream respectively.

	
		
	List of Tables
	 

	Table 1-Commodity Receipt Summary
	 

	 
	Page 4

Table lB
Commodity Receipt Summary- United  States

	
				
	Receipt Location
	Quality Category
	Transport Commodity
	Feeder Pipeline or Transfer Facility
Company Name [Facility Name]

	Clearbrook
	Sweet
	U.S. Sweet-Clearbrook (UHC)
	Enbridge Energy Partners [North Dakota]

	Mokena
	Sweet
	U.S. Sweet-Mokena (UHM)
	Chicap Pipeline Company [Chicap Pipeline]

	High Sour
	U.S. High Sour-Mokena (UOM)
	Chicap Pipeline Company [Chicap Pipeline]

	Heavy
	U.S. Heavy-Mokena (UVM)
	Chicap Pipeline Company [Chicap Pipeline]

	Rapid River
	NGL
	Natural Gas Liquids (NGL)
	BP [Rapid River]

	Lewiston
	Sweet
	U.S. Sweet-Lewiston (UHL)
	Markwest Pipelines [Michigan Crude Pipeline]

	
		
	List of Tables
	 

	Table 2-Commodity Routing Summary by Pipeline Segment
	 

	 
	Page 5

Table 2
Commodity Routing Summary by Pipeline Segment
	
																			
	Receipt Location
	Quality Category
	Transport Commodity
	Line 1
	Line 2
	Line 3
	Line 4
	Line 67
	Line 65
	Line 5
	Line 14/64
	Line 6A
	Line 6B
	Line 61
	Line 62
	Line 17
	Line 7
	Line 10
	Line 11

	Edmonton
	NGL
	Natural Gas Liquids (NGL)
	Ÿ
	 
	 
	 
	 
	 
	Ÿ
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Refined Products
	Gasoline
	Ÿ
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Distillate
	Ÿ
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Condensate
	Condensate Blend (CRW)
	 
	Ÿ
	Ÿ
	 
	 
	 
	w
	w
	w
	 
	w
	 
	 
	w
	w
	w

	Light Synthetic
	Suncor A (OSA)
	Ÿ
	Ÿ
	Ÿ
	 
	 
	 
	Ÿ
	Ÿ
	Ÿ
	 
	Ÿ
	 
	 
	w
	w
	w

	Suncor C (OSC)
	w
	Ÿ
	Ÿ
	 
	 
	 
	Ÿ
	w
	w
	 
	w
	 
	 
	w
	w
	w

	Syncrude (SYN)
	Ÿ
	Ÿ
	Ÿ
	 
	 
	 
	Ÿ
	Ÿ
	Ÿ
	 
	Ÿ
	 
	 
	Ÿ
	Ÿ
	Ÿ

	Premium Albian Synthetic (PAS)
	w
	Ÿ
	Ÿ
	 
	 
	 
	Ÿ
	Ÿ
	w
	 
	w
	 
	 
	w
	w
	w

	Shell Premium Synthetic (SPX)
	 
	Ÿ
	Ÿ
	 
	 
	 
	Ÿ
	Ÿ
	w
	 
	w
	 
	 
	w
	w
	w

	Shell Synthetic Light (SSX)
	 
	Ÿ
	Ÿ
	 
	 
	 
	Ÿ
	Ÿ
	w
	 
	w
	 
	 
	w
	w
	w

	CNRL Synthetic Custom Blend (CNC)
	 
	Ÿ
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 

	CNRL Light Sweet Synthetic Blend (CNS)
	 
	Ÿ
	Ÿ
	 
	 
	 
	Ÿ
	Ÿ
	Ÿ
	 
	 
	 
	 
	Ÿ
	Ÿ
	Ÿ

	Sweet
	Mixed Blend Sweet (SW)
	 
	Ÿ
	Ÿ
	 
	 
	 
	Ÿ
	Ÿ
	w
	 
	Ÿ
	 
	 
	Ÿ
	Ÿ
	Ÿ

	Light Sour
	Low Sulphur Sour (SLE)
	 
	Ÿ
	Ÿ
	w
	 
	 
	Ÿ
	Ÿ
	w
	w
	Ÿ
	 
	 
	w
	w
	w

	High Sour
	High Sulfur Sour (SHE)
	 
	w
	Ÿ
	w
	 
	 
	 
	Ÿ
	w
	Ÿ
	Ÿ
	 
	w
	Ÿ
	Ÿ
	w

	Heavy
	Albian Heavy Synthetic (AHS)
	 
	 
	 
	Ÿ
	 
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	w
	w
	w

	Albian Residual Blend (ARB)
	 
	 
	 
	w
	 
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	w
	w
	w

	Cold Lake (CL)
	 
	 
	 
	Ÿ
	 
	 
	 
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ

	Wabasca Heavy (WH)
	 
	 
	 
	Ÿ
	 
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ

	Heavy High Tan
	Peace Heavy (PH)
	 
	 
	 
	Ÿ
	 
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	w
	Ÿ
	Ÿ
	Ÿ
	Ÿ

	Seal Heavy (SH)
	 
	 
	 
	Ÿ
	 
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	w
	Ÿ
	Ÿ
	Ÿ
	Ÿ

	Access Western Blend (AWB)
	 
	 
	 
	Ÿ
	 
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	w
	Ÿ
	Ÿ
	Ÿ
	Ÿ

	Albian Muskeg River Heavy (AMH)
	 
	 
	 
	w
	 
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	w
	Ÿ
	 
	 
	 

	Statoil Cheecham Blend (SCB)
	 
	 
	 
	Ÿ
	 
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	w
	Ÿ
	 
	 
	 

	Surmont Heavy Blend (SHB)
	 
	 
	 
	Ÿ
	 
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	w
	Ÿ
	 
	 
	 

	Heavy Low Resid
	Suncor H (OSH)
	 
	 
	 
	w
	 
	 
	 
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	w
	Ÿ
	 
	 
	 

	Albian Vacuum Blend (AVB)
	 
	 
	 
	w
	 
	 
	 
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	w
	Ÿ
	 
	 
	 

	Cracked
	CNRL Heavy Sour Synthetic Blend (CNH)
	 
	 
	 
	Ÿ
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Other
	Caroline Condensate (CCA)
	 
	Ÿ
	Ÿ
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Sarnia Special (SSS)
	 
	 
	 
	w
	 
	 
	 
	Ÿ
	Ÿ
	Ÿ
	 
	 
	 
	w
	 
	w

	
		
	List of Tables
	 

	Table 2-Commodity Routing Summary by Pipeline Segment
	 

	 
	Page 6

Table 2 Continued
Commodity Routing Summary by Pipeline Segment
	
																			
	Receipt Location
	Quality Category
	Transport Commodity
	Line 1
	Line 2
	Line 3
	Line 4
	Line 67
	Line 65
	Line 5
	Line 14/64
	Line 6A
	Line 6B
	Line 61
	Line 62
	Line 17
	Line 7
	Line 10
	Line 11

	Hardisty
	Light Synthetic
	Suncor A (OSA)
	 
	Ÿ
	Ÿ
	 
	 
	 
	Ÿ
	Ÿ
	Ÿ
	 
	Ÿ
	 
	 
	w
	w
	w

	Suncor C (OSC)
	 
	Ÿ
	Ÿ
	 
	 
	 
	Ÿ
	w
	w
	 
	w
	 
	 
	w
	w
	w

	Husky Synthetic Blend (HSB)
	 
	Ÿ
	Ÿ
	 
	 
	 
	Ÿ
	Ÿ
	Ÿ
	 
	Ÿ
	 
	 
	Ÿ
	Ÿ
	Ÿ

	BP Sweet Synthetic Blend (BSS)
	 
	Ÿ
	Ÿ
	 
	 
	 
	w
	Ÿ
	w
	 
	 
	 
	 
	w
	w
	w

	Long Lake Light Synthetic Blend (PSC)
	 
	Ÿ
	Ÿ
	 
	 
	 
	Ÿ
	Ÿ
	w
	 
	Ÿ
	 
	 
	Ÿ
	Ÿ
	Ÿ

	Sweet
	Long Lake Sweet Blend (PSW)
	 
	Ÿ
	Ÿ
	 
	 
	 
	Ÿ
	Ÿ
	w
	 
	w
	 
	 
	Ÿ
	Ÿ
	Ÿ

	Light Sour
	BP Sour Blend (BSO)
	 
	w
	Ÿ
	w
	w
	 
	w
	Ÿ
	w
	w
	w
	 
	w
	w
	w
	w

	Long Lake Sour Blend (PSO)
	 
	w
	Ÿ
	w
	w
	 
	w
	Ÿ
	Ÿ
	Ÿ
	w
	 
	w
	Ÿ
	Ÿ
	Ÿ

	High Sour
	Hardisty Sour (SO)
	 
	w
	Ÿ
	w
	w
	 
	 
	Ÿ
	w
	Ÿ
	Ÿ
	 
	w
	Ÿ
	Ÿ
	Ÿ

	Heavy
	Cold Lake (CL)
	 
	 
	 
	Ÿ
	Ÿ
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ

	BP Synthetic Heavy Blend (BSH)
	 
	 
	 
	Ÿ
	w
	 
	 
	w
	Ÿ
	Ÿ
	w
	w
	Ÿ
	w
	w
	w

	BP Conventional Heavy Blend (BCH)
	 
	 
	 
	Ÿ
	w
	 
	 
	w
	Ÿ
	Ÿ
	w
	w
	Ÿ
	w
	w
	w

	Western Canadian Blend (WCB)
	 
	 
	 
	Ÿ
	w
	 
	 
	w
	Ÿ
	Ÿ
	w
	w
	Ÿ
	Ÿ
	Ÿ
	Ÿ

	Western Canadian Select (WCS)
	 
	 
	 
	Ÿ
	Ÿ
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ

	Bow River (BR)
	 
	 
	 
	Ÿ
	w
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ

	Lloydminister Hardisty (LLB)
	 
	 
	 
	Ÿ
	Ÿ
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ

	Heavy High Tan
	MacKay River Heavy (MKH)
	 
	 
	 
	Ÿ
	w
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	w
	w
	Ÿ
	Ÿ
	Ÿ

	Long Lake Heavy SynBit Blend (PSH)
	 
	 
	 
	Ÿ
	w
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	w
	w
	Ÿ
	Ÿ
	Ÿ

	Christina SynBit (CSB)
	 
	 
	 
	Ÿ
	w
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	w
	w
	Ÿ
	Ÿ
	Ÿ

	Borealis Heavy Blend (BHB)
	 
	 
	 
	Ÿ
	w
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	w
	w
	Ÿ
	Ÿ
	Ÿ

	Heavy Low Resid
	Suncor H (OSH)
	 
	 
	 
	Ÿ
	w
	 
	 
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	w
	Ÿ
	 
	 
	 

	Cracked
	Pine Blend Special (PBS)
	 
	 
	 
	Ÿ
	w
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Suncor J (OSJ)
	 
	 
	 
	Ÿ
	w
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Suncor Cracked C (OCC)
	 
	 
	 
	Ÿ
	w
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 

	
		
	List of Tables
	 

	Table 2-Commodity Routing Summary by Pipeline Segment
	 

	 
	Page 7

Table 2 Continued
Commodity Routing Summary by Pipeline Segment
	
																			
	Receipt Location
	Quality Category
	Transport Commodity
	Line 1
	Line 2
	Line 3
	Line 4
	Line 67
	Line 65
	Line 5
	Line 14/64
	Line 6A
	Line 6B
	Line 61
	Line 62
	Line 17
	Line 7
	Line 10
	Line 11

	Kerrobert
	NGL
	Natural Gas Liquids (NGL)
	Ÿ
	 
	 
	 
	 
	 
	Ÿ
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Sweet
	Mixed Blend Sweet (SW)
	 
	Ÿ
	 
	 
	 
	 
	Ÿ
	Ÿ
	w
	 
	 
	 
	 
	 
	 
	 

	Heavy
	Lloydminister Kerrobert (LLK)
	 
	 
	 
	Ÿ
	 
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ

	Smiley Coleville (SC)
	 
	 
	 
	Ÿ
	 
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ

	Regina
	Refined Products
	Gasoline
	Ÿ
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Distillate
	Ÿ
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Light Synthetic
	Newgrade Synthetic Blend A (NSA)
	 
	Ÿ
	w
	 
	 
	 
	Ÿ
	Ÿ
	w
	 
	 
	 
	 
	Ÿ
	Ÿ
	Ÿ

	Newgrade Synthetic Blend X (NSX)
	 
	w
	w
	Ÿ
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 

	High Sour
	Moose Jaw Tops (MJT)
	 
	Ÿ
	w
	 
	 
	 
	Ÿ
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Heavy
	Fosterton (F)
	 
	 
	 
	Ÿ
	 
	 
	 
	w
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	Ÿ

	Cromer
	NGL
	Natural Gas Liquids (NGL)
	Ÿ
	 
	 
	 
	 
	 
	Ÿ
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Sweet
	Mixed Blend Sweet (SW)
	 
	Ÿ
	 
	 
	 
	w
	Ÿ
	Ÿ
	w
	 
	Ÿ
	 
	 
	Ÿ
	Ÿ
	Ÿ

	Light Sour
	Light Sour Blend (LSB)
	 
	Ÿ
	w
	 
	 
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	w
	Ÿ
	w
	w
	Ÿ
	Ÿ
	Ÿ

	Medium
	Midale (M)
	 
	w
	w
	 
	 
	Ÿ
	 
	Ÿ
	Ÿ
	Ÿ
	Ÿ
	w
	w
	Ÿ
	w
	Ÿ

	Clearbrook
	Sweet
	U.S. Sweet-Clearbrook (UHC)
	 
	Ÿ
	Ÿ
	w
	 
	 
	Ÿ
	Ÿ
	w
	 
	Ÿ
	 
	 
	Ÿ
	Ÿ
	Ÿ

	Mokena
	Sweet
	U.S. Sweet-Mokena (UHM)
	 
	 
	 
	 
	 
	 
	 
	 
	Ÿ
	Ÿ
	 
	 
	 
	Ÿ
	w
	Ÿ

	High Sour
	U.S. High Sour-Mokena (UOM)
	 
	 
	 
	 
	 
	 
	 
	 
	Ÿ
	Ÿ
	 
	 
	w
	Ÿ
	w
	Ÿ

	Heavy
	U.S. Heavy-Mokena (UVM)
	 
	 
	 
	 
	 
	 
	 
	 
	Ÿ
	Ÿ
	 
	 
	Ÿ
	Ÿ
	w
	Ÿ

	Rapid River
	NGL
	Natural Gas Liquids (NGL)
	 
	 
	 
	 
	 
	 
	Ÿ
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Lewiston
	Sweet
	U.S. Sweet-Lewiston (UHL)
	 
	 
	 
	 
	 
	 
	Ÿ
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Sarnia
	Condensate
	BP Condensate Blend (ACB)
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 
	Ÿ
	Ÿ
	 

5/2/2011

	
		
	List of Tables
	 

	Table 2-Commodity Routing Summary by Pipeline Segment
	 

	 
	Page 8

Commodity Routing Legend
	
			
	Routing
	Receipt
	Definition

	Existing Routing
	Ÿ
	"Existing Routing" reflects the expected nominal crude routing for each commodity by pipeline.

	Permissible Routing
	w
	"Permissible Routing" reflects the nominal crude routing for each commodity by pipeline that is not typical and is at the discretion of Enbridge.

	No Routing Indicated
	 
	Movements not indicated as Existing Routing require prior authorization from Enbridge.

5/2/2011
Table 2 Disclaimer
1. The Commodity Routing Summary by Pipeline Segment Table is intended for reference only and is based on typical movements by commodity at the moment this document is issued.
2. The Commodity Routing Summary by Pipeline Segment Table considers only the injection of commodities at the Original Approved Receipt Locations and it does not cover injections from Commercial Storage Facilities, Merchant Tankage or Breakout Tankage.
3. The Commodity Routing Summary by Pipeline Segment Table does not include commodity routings that Enbridge can adopt during abnormal or extraordinary operational conditions.
4. Confirmation on specific commodity routings please contact your Enbridge pipeline scheduler.

	
		
	List of Tables
	 

	Table 3-Instructions for Using the SIS Transit Time Calculator
	 

	 
	Page 10

Table 3
Instructions for Using the OM2/SIS Transit Time Calculator
	
		
	1
	Internet connection and privilege to access into the OM2/SIS Portal

	2
	On the OM2/SIS home page click "Transit Time Calculator" at up left corner

	3
	Select "Single or Multiple Lines" depending on the section of the Mainline that you want to check and "Time Period" (NOS month in which you want to calculate the transit time)

	
		
	List of Tables
	 

	Table 3-Instructions for Using the SIS Transit Time Calculator
	 

	 
	Page 11

Table 3 Continued
Instructions for Using the SIS Transit Time Calculator

	
		
	4
	For example, to calculate the transit time from Edmonton to United for a particular commodity in the month of April 2010, you must know the routing: lines 2A/2B/5/7/10 (see commodity routing on Table 2) and click on "Create Report"

	5
	See the report

	
		
	List of Tables
	 

	Table 3-Instructions for Using the SIS Transit Time Calculator
	 

	 
	Page 12

Table 3 Continued
Instructions for Using the SIS Transit Time Calculator

	
		
	5
	See the report (continued)

	6
	"Export to Excel" or "Exit" to start a new calculation

	
		
	List of Tables
	 

	Table 4-Minimum Batch Size
	 

	 
	Page 13

Table 4
Minimum Batch Size

Shippers are requested to sup ply a certain minimum volume to the Enbridge/L.a kehead system such that thevolume of the commodity tendered wi II be equal to or exceed the minimum batch size set  for the required transportation route of the batch. The nominal batch size on the Enbridge system is 10,000 m3, however the minimum batch volume for each pipeline segment is  provided below.

	
			
	Line
	Minimum Batch Size (m3)
	Comments

	1
	3,500
	Refined Products deliveries. NGLs and buffers have their own set of guidelines

	2A
	5,000
	All deliveries

	2B
	8,000
	All deliveries

	3
	8,000
	All deliveries except Hardisty, which is allowed 5,000 m3

	4
	10,000
	All deliveries

	67
	8,000
	All deliveries

	65
	8,000
	All deliveries

	5
	8,000
	All deliveries except NGLs, which have their own set of guidelines

	6A
	8,000
	All deliveries

	14
	8,000
	All deliveries

	61
	8,000
	All deliveries

	62
	8,000
	All deliveries

	6B
	8,000
	All deliveries

	7
	8,000
	All deliveries

	10
	8,000
	All deliveries

	11
	8,000
	All deliveries

	17
	8,000
	All deliveries

4/19/2011

	
		
	List of Tables
	 

	Table 5-Tank Utilization by Commodity Type
	 

	 
	Page 14

Table  5
Tank Utilization by Commodity Type

	
													
	Transport Commodity
	Crude Quality Category
	Edmonton
	Hardisty
	Regina
	Cromer
	Clearbrook
	Superior
	Flanagan
	Griffith
	Stockbridge
	Sarnia
	Westover

	Condensate Blend (CRW)
	Condensate
	Note 2
	 
	 
	B/BG,F
	 
	B/BG,F
	B/BG,F
	B/BG,F
	 
	B/BG,F
	 

	BP Condensate Blend (ACB)
	 
	 
	 
	 
	 
	 
	 
	 
	 
	R/B
	B/BG,F

	Suncor A (OSA)
	Light Synthetic
	R/S
	R/S
	 
	B/BG
	 
	B/BG
	B/BG,F,H
	B/BG
	 
	 
	B/BG,F,H

	Suncor C (OSC)
	R/B
	R/B
	 
	B/BG
	 
	B/BG
	B/BG,F,H
	B/BG
	 
	 
	B/BG,F,H

	Syncrude (SYN)
	R/S
	 
	 
	B/BG
	 
	B/BG
	B/BG,F,H
	B/BG
	 
	B/BG,H
	B/BG,F,H

	Premium Albian Synthetic (PAS)
	R/S
	 
	 
	B/BG
	 
	B/BG
	B/BG,F,H
	B/BG
	 
	B/BG,H
	B/BG,F,H

	Shell Premium Synthetic (SPX)
	R/S
	 
	 
	B/BG
	 
	B/BG
	B/BG,F,H
	B/BG
	 
	B/BG,H
	B/BG,F,H

	Shell Synthetic Light (SSX)
	R/S
	 
	 
	B/BG
	 
	B/BG
	B/BG,F,H
	B/BG
	 
	B/BG,H
	B/BG,F,H

	CNRL Light Sweet Synthetic Blend (CNS)
	R/S
	 
	 
	B/BG
	 
	B/BG
	B/BG,F,H
	B/BG
	 
	B/BG,H
	B/BG,F,H

	CNRL Synthetic Custom Blend (CNC)
	R/B
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Husky Synthetic Blend (HSB)
	 
	R/S
	 
	B/BG
	 
	B/BG
	B/BG,F,H
	B/BG
	 
	B/BG.H
	B/BG,F,H

	BP Sweet Synthetic Blend (BSS)
	 
	 
	 
	B/BG
	 
	B/BG
	 
	B/BG
	 
	 
	 

	Long Lake Light Synthetic Blend (PSC)
	 
	R/S
	 
	B/BG
	 
	B/BG
	B/BG,F,H
	B/BG
	 
	B/BG,H
	B/BG,F,H

	New grade Synthetic Blend A (NSA)
	 
	 
	R/S
	B/BG
	 
	B/BG
	B/BG,F,H
	B/BG
	 
	B/BG,H
	B/BG,F,H

	New grade Synthetic Blend X (NSX)
	 
	 
	R/B
	 
	 
	 
	 
	 
	 
	 
	 

	Mixed Blend Sweet (SW)
	Sweet
	Note 2
	 
	 
	B/C
	 
	B/BF
	B/BG,F,H
	B/BF
	 
	B/BF,G,H
	B/BF,G,H

	Long Lake Sweet Blend (PSW)
	 
	R/S
	 
	B/BF
	 
	B/BF
	B/BG,F,H
	B/BF
	 
	B/BF,G,H
	B/BF,G,H

As  a first option, a commodity will cross bottoms with the  s arne  commodity. Second, third, and fourth choices are  noted ins upers cript in  preferential order.
Commodity Group Codes- A-Heavy, B-Heavy High Tan,  C-Cracked, D-Medium, E-High Sour, F-Sweet, G-Light Synthetic, H-Condensate, 1-Light Sour, J-Heavy Low  Resid
 
4/18/2011

	
		
	List of Tables
	 

	Table 5-Tank Utilization by Commodity Type
	 

	 
	Page 15

Table 5 Continued
Tank Utilization by Commodity Type
	
													
	Transport Commodity
	Crude Quality Category
	Edmonton
	Hardisty
	Regina
	Cromer
	Clearbrook
	Superior
	Flanagan
	Griffith
	Stockbridge
	Sarnia
	Westover

	U.S. Sweet-Clearbrook (UHC)
U.S. Sweet-Lewiston (UHL)
U.S. Sweet-Mokena (UHM)
	Sweet
	 
	 
	 
	 
	Note 5

	Edmonton Light Sour (SLE)
	Light Sour
	Note 2
	 
	 
	B/B
	 
	B/B
	B/BI,E,D
	B/BI,E,D
	 
	B/BI,E
	B/BI,E,D,A

	BP Sour Blend (BSO)
	 
	 
	 
	B/B
	 
	B/B
	B/BI,E,D
	B/BI,E,D
	 
	 
	 

	Long Lake Sour Blend (PSO)
	 
	R/S
	 
	B/BI
	 
	B/BI
	B/BI,E,D
	B/BI,E,D
	 
	B,BI,E,D
	B/BI,E,D,A

	Light Sour Blend (LSB)
	 
	 
	 
	Note 2
	B/BI
	B/BI
	B/BI,E,D
	B/BI,E,D
	 
	B/BI,E,D
	B/BI,E,D,A

	High Sulfur Sour (SHE)
	High Sour
	Note 2
	 
	 
	B/C
	 
	B/C
	BBE,I,D
	B/BE,I,D
	 
	B/BE,I,D
	B/BE,I,D,A

	Moose Jaw Tops (MJT)
	 
	 
	R/S
	B/BE
	 
	B/BE
	BBE,I,D
	 
	 
	 
	 

	Hardisty Sour (SO)
	 
	 
	 
	B/C
	 
	B/C
	BBE,I,D
	B/BE,I,D
	 
	B/BE,I,D
	B/BE,I,D,A

	U.S. High Sour-Mokena (UOM)
	 
	 
	 
	 
	 
	 
	 
	Note 5

	Midale (M)
	Medium
	 
	 
	 
	Note 2
	B/S
	B/BD,E,A
	B/BD,E,A
	B/BD,E,A
	 
	B/BD,E,A
	B/BD,E,A,I

	Albian Heavy Synthetic (AHS)
	Heavy
	R/S
	 
	 
	 
	 
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA
	B/BA,D,E,I

	Albian Residual Blend (ARB)
	R/B
	 
	 
	 
	 
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA
	B/BA,D,E,I

	Cold Lake (CL)
	R/S
	 
	 
	 
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA
	B/BA,D,E,I

	Wabasca Heavy (WH)
	R/S
	 
	 
	 
	 
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA
	B/BA,D,E,I

	BP Synthetic Heavy Blend (BSH)
	 
	 
	 
	 
	 
	B/BA,B
	 
	B/BA,B
	B/BA,B
	B/BA
	B/BA,D,E,I

	BP Conventional Heavy Blend (BCH)
	 
	 
	 
	 
	 
	B/BA,B
	 
	B/BA,B
	B/BA,B
	 
	 

	Western Canadian Blend (WCB)
	 
	 
	 
	 
	 
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA
	B/BA,D,E,I

	Western Canadian Select (WCS)
	 
	 
	 
	 
	 
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA
	B/BA,D,E,I

As  a first option, a commodity will cross bottoms with the  s arne  commodity. Second, third, and fourth choices are  noted ins upers cript in  preferential order.
Commodity Group Codes- A-Heavy, B-Heavy High Tan,  C-Cracked, D-Medium, E-High Sour, F-Sweet, G-Light Synthetic, H-Condensate, 1-Light Sour, J-Heavy Low  Resid
 
4/18/2011

	
		
	List of Tables
	 

	Table 5-Tank Utilization by Commodity Type
	 

	 
	Page 16

Table 5 Continued
Tank Utilization by Commodity Type

	
													
	Transport Commodity
	Crude Quality Category
	Edmonton
	Hardisty
	Regina
	Cromer
	Clearbrook
	Superior
	Flanagan
	Griffith
	Stockbridge
	Sarnia
	Westover

	Bow River (BR)
	Heavy
	 
	 
	 
	 
	 
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA
	B/BA,D,E,I

	Lloydminister Hardisty (LLB)
	 
	 
	 
	 
	 
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA
	B/BA,D,E,I

	Lloydminister Kerrobert (LLK)
	 
	 
	 
	 
	 
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA
	B/BA,D,E,I

	Smiley Coleville (SC)
	 
	 
	 
	 
	 
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA
	B/BA,D,E,I

	Fosterton (F)
	 
	 
	R/S
	 
	 
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA,B
	B/BA
	B/BA,D,E,I

	U.S. Heavy-Mokena (UVM)
	 
	 
	 
	 
	 
	 
	 
	Note 5

	Peace Heavy (PH)
	Heavy High Tan
	R/S
	 
	 
	 
	 
	B/BB,B/CB
	B/BB,A
	B/BB,A
	B/BB,A
	B/BB,A
	B/BB,A,D,E,I

	Seal Heavy (SH)
	R/C
	 
	 
	 
	 
	B/BB,B/CB
	B/BB,A
	B/BB,A
	B/BB,A
	B/BB,A
	B/BB,A,D,E,I

	Access Western Blend (AWB)
	R/S
	 
	 
	 
	 
	B/BB,B/CB
	B/BB,A
	B/BB,A
	B/BB,A
	B/BB,A
	B/BB,A,D,E,I

	Albian Muskeg River Heavy (AMH)
	R/B
	 
	 
	 
	 
	B/BB,B/CB
	B/BB,A
	B/BB,A
	B/BB,A
	B/BB,A
	B/BB,A,D,E,I

	Surmont Heavy Blend (SHB)
	R/S
	 
	 
	 
	 
	B/BB,B/CB
	B/BB,A
	B/BB,A
	B/BB,A
	B/BB,A
	B/BB,A,D,E,I

	MacKay River Heavy (MKH)
	 
	R/S
	 
	 
	 
	B/BB,B/CB
	B/BB,A
	B/BB,A
	B/BB,A
	B/BB,A
	B/BB,A,D,E,I

	Long Lake Heavy SynBit Blend (PSH)
	 
	R/S
	 
	 
	 
	B/BB,B/CB
	B/BB,A
	B/BB,A
	 
	B/BB,A
	B/BB,A,D,E,I

	Christina Syn-Bit (CSB)
	 
	 
	 
	 
	 
	B/BB,B/CB
	B/BB,A
	B/BB,A
	B/BB,A
	B/BB,A
	B/BB,A,D,E,I

	Borealis Heavy Blend (BHB)
	 
	 
	 
	 
	 
	B/BB,B/CB
	B/BB,A
	B/BB,A
	 
	B/BB,A
	B/BB,A,D,E,I

	Statoil Cheecham Blen (SCB)
	R/S,R/BB,R/CB
	 
	 
	 
	 
	B/BB,B/CB
	B/BB,A
	B/BB,A
	 
	B/BB,A
	B/BB,A,D,E,I

	Suncor H (OSH)
	Heavy Low Resid
	R/S
	R/S
	 
	 
	 
	B/BJ,B,A
	B/BJ,B,A
	B/BJ,B,A
	B/BJ,B,A
	B/BJ,B,A
	 

	Albian Vacuum Blend (AVB)
	R/B
	 
	 
	 
	 
	B/BJ,B,A
	B/BJ,B,A
	B/BJ,B,A
	B/BJ,B,A
	B/BJ,B,A
	 

	Pine Blend Special (PBS)
	Cracked
	 
	Note 3
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Suncor Cracked C (OCC)
	 
	R/SNote 3
	 
	 
	 
	 
	 
	 
	 
	 
	 

	CNRL Heavy Sour Synthetic Blend (CNH)
	R/SNote 3
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Caroline Condensate (CCA)
	Other
	R/SNote 3
	 
	 
	 
	 
	 
	 
	 
	 
	 
	 

	Sarnia Special (SSS)
	R/BA
	 
	 
	 
	 
	B/BD,A,B
	 
	B/BD,A,B
	B/BD,A,B
	 
	 

As a first option, a commodity will cross bottoms with the same commodity. Second, third, and fourth choices are noted in superscript in preferential order. 
Commodity Group Code s – A-Heavy, B -Heavy High Tan, C-Cracked, D-Medium, E-High Sour, F-Sweet, G-Light Synthetic, H-Condensate, I-Light Sour, J-Heavy Low Resid

	
		
	List of Tables
	 

	Table 5-Tank Utilization by Commodity Type
	 

	 
	Page 17

Table 5 Continued
Tank Utilization by Commodity Type

Tank Service Legend

	
				
	Service
	Receipt
	Breakout
	Tank Service Definitions

	Segregated
	R/S
	B/S
	Crude streams that does not share tankage with other crude streams.

	Share Common Bottoms
	R/B
	B/B
	Crude streams that can share tank bottoms with other crude types;
-As a first option, a commodity will cross bottoms with the same commodity.
-As second option, a commodity will cross bottoms within its identified Commodity Group.
-Third, fourth, and fifth choices are noted in superscript in preferential order.

	Commingled
	R/C
	B/C
	Crude components that share tankage with other like-cruide components to form single commingled streams e.g. SW, SLE, SHE, SO, CRW, LSB, M. Crude streams that can be commingled with a given commodity are noted in superscript in preferential order.

	No Tankage Requirement
	 
	 
	 

General Notes
1.   Above tankage references Enbridge facilities only.
2.   The CRW, SW, SLE, SHE, LSB and M commodities are blended from their individual components and are combined on receipt and segregated receipt service is provided for these streams.
3.   OCC, PBS, CNH and CCA require buffering.
4.   SHE and SO will be commingled as required at breakout locations.  Once commingled, they are treated as a single commodity and may cross bottoms with compatible sours.
5.   US and Foreign crude is received at Clearbrook, Mokena, and Lewiston on the Enbridge system.
- US sweet crude will cross bottoms with commodity group “F”.
- US Sour crude will cross bottoms with commodity groups, in the order of "E", "D", and "I".
- US medium crudes will move through the system the same as Midale.
- US heavy crude streams will move through the system the same as heavy streams.
6.   Natural Gas Liquids, Gasoline, and Distillate do not utilize Enbridge tankage and are therefore not included in this table.
 

5/31/2010

	
		
	List of Tables
	 

	Table 6-Commodity Testing Summary
	 

	 
	Page 18

Table 6
Commodity Testing Summary

	
			
	Transport Commodity
	Quality Category
	Test

	Refined Products (Gasoline and Distillate)
	Products
	2

	Condensate Blend (CRW)
	Condensate
	3,6,7

	Amoco Condensate (ACB)
	1,2,3

	Suncor A, Suncor C (OSA, OSC)
	Light Synthetic
	1,2,3,8*

	Syncrude (SYN)
	1,2,3,8*

	Premium Albian Synthetic (PAS)
	1,2,3

	Shell Premium Synthetic (SPX)
	1,2,3

	Shell Synthetic Light (SSX)
	1,2,3

	CNRL Light Sweet Synthetic Blend (CNS)
	1,2,3

	CNRL Synthetic Custom Blend (CNC)
	1,2,3

	Husky Synthetic Blend (HSB)
	1,2,3

	BP Sweet Synthetic Blend (BSS)
	1,2,3

	Long Lake Light Synthetic Blend (PSC)
	1,2,3

	Newgrade Synthetic Blend (NSA, NSX)
	1,2,3

	Mixed Blend Sweet (SW)
	Sweet
	1,2,3,4

	Long Lake Sweet Blend (PSW)
	1,2,3,4

	U.S. Sweet-Clearbrook (UHC)
	1,2,3,4

	U.S. Sweet-Lewiston (UHL)
	1,2,3,4

	U.S. Sweet-Mokena (UHM)
	1,2,3,4

	Low Sulphur Sour (SLE)
	Light Sour
	1,2,3,5

	BP Sour Blend (BSO)
	1,2,3,5

	Long Lake Sour Blend (PSO)
	1,2,3

	Light Sour Blend (LSB)
	1,2,3,5

	High Sulfur Sour (SHE)
	High Sour
	1,2,3,5

	Moose Jaw Tops (MJT)
	1,2,3

	Hardisty Sour (SO)
	1,2,3,5

	U.S. Sour-Mokena (UOM)
	1,2,3

	Midale (M)
	Medium
	1,2,3

General Notes:
Crude tests referenced in Table 6 are  detailed in Tables 6A  through 6E respectively. Test 3A on Table 6A and  phosphorus testing listed under  Test 4 on table  6B  are increrrental to base Service Levels and  the testing  costs are  being recovered separately.
*Test only performed when commodity used as line 1buffer.
 
4/18/2011

	
		
	List of Tables
	 

	Table 6-Commodity Testing Summary
	 

	 
	Page 19

Table 6 Continued
Commodity Testing Summary

	
			
	Transport Commodity
	Quality Category
	Test

	Albian Heavy Synthetic (AHS)
	Heavy
	1,2,3

	Albian Residual Blend (ARB)
	1,2,3

	Cold Lake (CL)
	1,2,3

	Wabasca Heavy (WH)
	1,2,3

	BP Synthetic Heavy Blend (BSH)
	1,2,3

	BP Conventional Heavy Blend (BCH)
	1,2,3

	Western Canadian Blend (WCB)
	1,2,3

	Western Canadian Select (WCS)
	1,2,3

	Bow River (BR)
	1,2,3

	Lloydminster Hardisty (LLB)
	1,2,3

	Lloydminster Kerrobert (LLK)
	1,2,3

	Smiley Coleville (SC)
	1,2,3

	Fosterton (F)
	1,2,3

	U.S. Heavy-Mokena (UVM)
	1,2,3

	Peace Heavy (PH)
	Heavy High Tan
	1,2,3

	Seal Heavy (SH)
	1,2,3

	Access Western Blend (AWB)
	1,2,3

	Albian Muskeg River Heavy (AMH)
	1,2,3

	Surmont Heavy Blend (SHB)
	1,2,3

	MacKay River Heavy (MKH)
	1,2,3

	Long Lake Heavy SynBit Blend (PSH)
	1,2,3

	Christina Syn-Bit (CSB)
	1,2,3

	Borealis Heavy Blend (BHB)
	1,2,3

	Statoil Cheecham Blend (SCB)
	1,2,3

	Suncor H (OSH)
	Heavy Low Resid
	1,2,3

	Albian Vacuum Blend (AVB)
	1,2,3

	Pine Blend Special (PBS)
	Cracked
	1,2,3

	CNRL Heavy Sour Synthetic Blend (CNH)
	1,2,3

	Suncor Cracked C (OCC)
	1,2,3

	Caroline Condensate (CCA)
	Other
	1,2,3

	Sarnia Special (SSS)
	1,2,3

General Notes:

Crude tests referenced in Table 6 are detailed in Tables 6A through 6E respectively. Test 3A on Table 6A and phosphorus testing listed under Test 4 on table  6B are incremental to base  Service Levels and the testing costs  are being recovered separately.
* Test only  performed when commodity used  as Line  1 buffer.

	
		
	List of Tables
	 

	Table 6-Commodity Testing Summary
	 

	 
	Page 20

Table 6A - General Testing

	
					
	Test
	Frequency
	Crude Types
	Tests
	Reporting

	1
	On Receipt
	All
	S&W, density
	Reported by receipt ticket to feeder pipeline.

	All heavy crudes
	Viscosity
	Reported to feeder on exception basis only on violation of tariff quality specifications.

	Select light and medium crudes
	Viscosity-tested during winter months to determine tariff category
	Reported to feeder on exception basis only on violation of tariff quality specifications.

	2
	On Delivery
	All
	S&W, density
	Reported by delivery ticket to delivery facility.

	On Receipt and Delivery
	Refined products and NGL
	Testing and reporting are in accordance with Enbridge's Line 1 Operations Manual.

	3
	Annual Crude Characteristics
	All
	Density, RVP, sulphur, viscosity (10°C, 20°C
	Annual crude characteristics report.

	3A
	Annual
	Random
	Organic Chloride, Olefinic content
	Reported to feeder on exception basis only on violation of quality specifications.

4/15/2011

	
		
	List of Tables
	 

	Table 6-Commodity Testing Summary
	 

	 
	Page 21

Table 6B – Sweet Streams Testing

	
						
	Test
	Location
	Frequency
	Test
	Comments
	Reporting

	4
	Receipt
	All receipt batches
	Density, sulphur, phosphorus
	Selected batch receipt composite for SW components (SW component feeders defined in Table 1)
	Ÿ Reported to feeder on exception basis only on violation of stream quality specifications per SW Receipt Quality Standard procedures
Ÿ Enbridge issues monthly Crude Equalization Program report by the 15th day of the following month

	Selected receipt batches
	Density, sulphur
	U.S. Sweet (UHC, UHL)
	Reported to feeder on exception basis only on violation of stream quality specifications per SW Receipt Sulphur Standard procedures

	All receipt batches
	Density, sulphur
	U.S. Sweet (UHM)
	Reported to feeder on exception basis only on violation of stream quality specifications per SW Receipt Sulphur Standard procedures

Table 6C – Sour Streams Testing

	
						
	Test
	Location
	Frequency
	Test
	Comments
	Reporting

	5
	Receipt
	Weekly
	Density, sulphur
	Selected batch receipt composite for Edmonton SLE & SHE and Cromer LSB feeder components
	Ÿ Reported to feeder on exception basis only on violation of respective stream quality specifications per SLE Receipt Sulphur Standard procedures
Ÿ Enbridge issues monthly Crude Equalization Program report by the 15th day of the following month

4/15/2011

	
		
	List of Tables
	 

	Table 6-Commodity Testing Summary
	 

	 
	Page 22

Table 6D – Condensate Sampling Procedures and Testing – Edmonton Terminal

	
											
	 
	 
	Composite Sample
	Monthly Testing
	Bimonthly Testing
	Quarterly Testing
	 

	Test
	Location
	Collection Frequency
	Tests
	Sample Type
	Test
	Sample Type
	Test
	Sample Type
	Test
	Reporting

	6
	Receipts
	1/week-continuous & batched feeders
	S&W density and Sulfur
	1 spot/mo
	Vapour pressure
	Select weekly composite
	Butane
	Random Compositeper CRW component stream
	Viscosity, Olefins, Organic Chlorides, Aromatics, Meracptans, H2S, Benzene, Mercury, Oxygenates, Total Suspended Solids, Phosphorous (Volatile)
	Enbridge issues monthly Condensate Equalization Program report by the 15th day of the following

	1 spot/mo
	Sulphur

	7
	Delivery at Edmonton
	1/week
	S&W and density
	1 spot/mo
	Vapour pressure
	1 spot/mo
	Butane
	 
	 
	S &W and density reported by delivery ticket to delivery facility

Table 6E – Line 1 Synthetic Buffer Testing

	
					
	Test
	Location
	Frequency
	Test
	Reporting

	8
	Edmonton
	Batch pump out
	Density, copper strip and sediment content
	Reported to feeder on exception basis only on violation of Line 1 Quality Guidelines

4/15/2011

	
		
	List of Tables
	 

	Table 7-Scheduling Calendar
	 

	 
	Page 23

Table 7
Scheduling Calendar

	
			
	Business Day
	Activity
IF NO Apportionment
	Activity
IF Apportionment

	1
	Notices of shipment due to Enbridge
(Notice of shipment dates issued by Enbridge per COLC calendar)
	Notices of shipment due to Enbridge
(Notice of shipment dates issued by Enbridge per COLC calendar)

	1
	If no apportionment is determined, so announced
	If apportionment is determined, verification procedures commence

	2
	Commence compiling new month's schedule
	Twenty-four (24) hours after feeder verification procedures commence, apportionment announced and revised notices of shipment requested

	3
	 
	Revised notices of shipment received

	4
	Complete scheduling sequence for Lines 1, 2, 3, 4, 67 and 65 and issue via OM2/SIS
	Commence compiling new months schedule

	5
	Complete scheduling sequence for Lines 5, 6, 14, 61, 62, 16 and 17 and issue via OM2/SIS
	 

	6
	Complete scheduling sequence for Lines 7, 10 and 11 and issue via OM2/SIS
	Complete scheduling sequence for Lines 1, 2, 3, 4, 67 and 65 and issue via OM2/SIS

	7
	 
	Complete scheduling sequence for Lines 5, 6, 14, 61, 62, 16 and 17 and issue via OM2/SIS

	8
	 
	Complete scheduling sequence for Lines 7, 10 and 11 and issue via OM2/SIS

5/4/2010

	
		
	List of Tables
	 

	Table 7-Scheduling Calendar
	 

	 
	Page 24

Table 7 Continued
Scheduling Calendar

Scheduling Notes

	
	
	1.  Schedule  Updates and Changes

	Pipeline schedules are updated on a daily basis, including the processing of changes resulting from shipper requests and due to varying operating conditions. All changes submitted through OM2/SIS  affecting pump orders (next 48 hours) will be prompted to give proper notification to the Pipeline Schedulers as per the Line Space Queue rules.

- Any changes or updates that directly affect the next 48 hours of business must be received no later than 2:00 pm MST.

- Charges as a result of emergency may be accepted after 2:00pm MST if accompanied by a direct telephone communication, and must be acknowledged by Enbridge.

	2.  Accepting Increases in Nominations

	Pipeline Initially Apportioned
Batch requests located in the line space queue will be honored if the pipeline, or any segment thereof was initially apportioned, and space has become available either due to shippers reducing volumes or an increase in capacity occurs.  "When either condition occurs, the first shipper in the queue will be contacted and given mtification t::l-Ere is spare capacity and option of adding a batch   In all cases prior to beirg accepted by Enbridge, the feeder pipeline mrnt verifY any extra volumes tendered.  If the total remains less than the available capacity, the volumes will be accepted.   If spare capacity still remains, the next shipper in the queue will be contacted.

Pipeline At or Below Capacity
If nominations for t::l-E  pipeline, or any segment thereof indicates that space is available for the month, or in the case of a pipeline initially at capacity and space becomes available, shippers may increase volumes, on a first come basis, at any time up to the point that the increase brings that segment to capacity. Any volume increases that cannot be accommodated  at this time should be submitted to our line space queue. "When space becomes available on a pipeline that is initially at capacity shippers will be notified through the Oil Movement Manager/Shipper Information System (OM2/SIS)  Portal that increases to nominations will be accepted.

5/4/2010

	
		
	List of Tables
	 

	Table 8-Shipper Services Business Activities
	 

	 
	Page 24

Table 8A
Supply  Management

	
			
	Process
	Activity
	Reporting

	Nominations
	Due on a specific date and time as specified on the Crude Oil Logistics Committee (COLC) Forecast Reporting Calendar.
	Enbridge issues letter to all shippers, feeders and interested parties by November 30 each year for the following year's nomination calendar.

	Apportionment
	Ÿ All nomination information is compiled to determine if apportionment required.

Ÿ If required, announced by the end of first business day after initial nominations are due (as outlined in the COLC forecast-reporting calendar). Revised Notices of Shipment due back 24 hours from time of announcement.

Ÿ If not required, announcement is made the afternoon of the day Notices of Shipment are due
	Enbridge issues letter to all shippers, feeders and interested parties in accordance with Scheduling Calendar (Table 7).

	Ticketing
	Tickets are pulled each Monday morning or as specified per COLC forecast reporting calendar.
	No Enbridge reporting for this activity.

	Weekly Splits
	Weekly splits are required to be provided to Enbridge by 12:00 pm each Tuesday or as specified by the COLC forecast reporting calendar.
	Enbridge issues Splits Reports to all shippers by end of respective week.

	Month-end Splits
	Ÿ Feeders notified of month-end total deliveries to Enbridge by end of day on 2nd working day of the new month for the previous month.

Ÿ Feeders provide to Enbridge month-end splits (within 24 hours after notified by Enbridge) 3rd working day of new month for previous month.
	No Enbridge reporting for this activity.

	Month-end Close
	Supply management month-end close occurs on the 4th working day of the new month for the previous month.

Note: Timely completion is dependent on all industry information being provided to Enbridge on time.
	Enbridge issues reports to all shippers and feeders with information pertaining to previous month's activities by 12:00 pm on the 6th working day of the following month.

	Non-Performance Penalty (NPP) Process
	Refer to tariff Rules and Regulations under Non-Performance.
	Ÿ Enbridge issues Shipper Nomination and Actual Supply Report to all shippers and interested parties.

Ÿ For a shipper(s) in violation of NPP, Detail of Shipper Performance Report issued after month end close.

5/31/2010

	
		
	List of Tables
	 

	Table 8-Shipper Services Business Activities
	 

	 
	Page 25

Table 8B
Carriers Inventory

	
			
	Process
	Activity
	Reporting

	Supply Control Shippers Position Report
	Ÿ Summarizes shipper activity in the system.

Ÿ Sent out at month-end after close off is completed.

Note: Timely completion is dependent on all industry information being provided to Enbridge on time.
	Reporting for this activity is included in Month-end Close reporting.

	Retention Stock
	Calculated quarterly using a combination of 2 months actual receipts and 1 month nominations.
	Enbridge issues Retention Stock Report to shippers quarterly via OM2/SIS.

	Balancing Shipper's Positions
	Ÿ Automatic Balancing procedure available in the Tariffs and Tolls section at www.enbridge.com

Ÿ Performed on an on going basis.
	No Enbridge reporting for this activity.

Table 8C 
Oil Accounting

	
			
	Process
	Activity
	Reporting

	Monthly Shippers Balance
	Preliminary statements issued the 6th/7th working day, with final statements including Automatic Balancing transactions and pricing by the 15th working day.

Note: Timely completion is dependent on all industry information being provided to Enbridge on time.
	Enbridge issues Monthly Shippers Balance Statement.

	Tariff Invoicing
	Issued on the 4th working day after the 15th; and the 4th working day after the last working day of each month.
	Enbridge issues Tariff Invoices.

5/31/2010

SCHEDULE “O” – LINE 9 CAPITAL REPORTING TEMPLATE

	
					
	 
	A
	B
	C
	D

	1
	Capital Project AFE Number
	Capital Project Expenditure in Prior year
	Capital Project Expenditure during Past Calendar Year
	Capital Project Expenditure Forecast for Current Calendar Year

	2
	Line 9: Each Project AFE in excess of $5 M in Canadian
$
	 
	 
	 

	3
	Project A
	CDN $ in 2010 & prior
	CDN $ in 2011
	CDN $ in 2012

	4
	Project B
	CDN $ in 2010 & prior
	CDN $ in 2011
	CDN $ in 2012

	5
	Project C
	CDN $ in 2010 & prior
	CDN $ in 2011
	CDN $ in 2012

	6
	Line 9:
Total of Line 9 Shipper Supported Capital Projects less than $5 M per project in Canadian $
	 
	 
	 

	7
	Sum of all other AFEs
	 
	 
	 

	8
	Total
	 
	 
	 

O-1Exhibit

EXHIBIT 10.2

ENBRIDGE INC.

EXECUTIVE EMPLOYMENT AGREEMENT 
BETWEEN

ENBRIDGE INC.
- and -
[        ]

Dated as of [            ]

Pre-2014 Form of Executive Employment Agreement

TABLE OF CONTENTS
Page
	
			
	Article 1 DEFINITIONS AND INTERPRETATION
	1

	1.1
	Definitions
	 

	1.2
	Headings
	 

	1.3
	Governing Law and Attornment
	 

	1.4
	Singular; Gender
	 

	 
	 
	 

	Article 2 EMPLOYMENT
	5

	2.1
	Position, Duties and Responsibilities of Executive
	 

	2.2
	Term of Agreement
	 

	2.3
	Termination of Agreement upon Disability of Executive
	 

	2.4
	Termination of Agreement by the Corporation for Cause
	 

	2.5
	Termination of Employment by the Corporation or the Executive
	 

	2.6
	Other Termination by Executive
	 

	2.7
	Pension Plans
	 

	2.8
	Continuing Provisions
	 

	 
	 
	 

	Article 3 NON-COMPETITION AND CONFIDENTIALITY
	12

	3.1
	Non-Competition While Employed
	 

	3.2
	Non-Competition Following Termination of Employment
	 

	3.3
	Non-Solicitation of Employees
	 

	3.4
	Confidentiality
	 

	 
	 
	 

	Article 4 GENERAL
	0

	4.1
	Notices
	 

	4.2
	Time
	 

	4.3
	Legal Fees and Expenses
	 

	4.4
	Replacement and Integration
	 

	4.5
	Amendment
	 

	4.6
	Waivers
	 

	4.7
	Further Assurances
	 

	4.8
	Severability
	 

	4.9
	Enurement
	 

EXECUTIVE EMPLOYMENT AGREEMENT
THIS AGREEMENT made effective the [   ] day of [        ] between:
ENBRIDGE INC., a body corporate under the Canada Business Corporations Act, with offices in the City of Calgary, in the Province of Alberta (hereinafter called the "Corporation")
- and -
[        ], of the City of Calgary, in the Province of Alberta (hereinafter called the "Executive").

WHEREAS:
		
	(a)
	the Executive is an executive of the Corporation and is considered by the Board of Directors of the Corporation to be a valued employee of the Corporation and has acquired outstanding and special skills and abilities and an extensive background in and knowledge of the Corporation's business and the industry in which it is engaged; and

		
	(b)
	the Board of Directors recognizes that it is essential, in the best interests of the Corporation, that the Corporation retain the continuing dedication of the Executive to his office and employment and that this can best be accomplished if the personal uncertainty facing the Executive in the event of a Corporation initiated termination of employment of the Executive is alleviated;

NOW THEREFORE THIS AGREEMENT WITNESSETH that in consideration of the mutual covenants herein contained, it is hereby agreed as set forth below.

ARTICLE 1
DEFINITIONS AND INTERPRETATION
		
	1.1
	Definitions

In this Agreement:
		
	(a)
	"affiliate" a person shall be deemed to be an affiliate of another person if one of them is controlled by the other or both are controlled by the same person, and if two persons are affiliates of the same person at the same time they are deemed to be affiliates of each other;

-2-

		
	(b)
	"Annual Compensation" means the sum of the Annual Salary and the Annual Incentive Bonus;

		
	(c)
	"Annual Salary" means the annual salary of the Executive established by the HRCC and payable by the Corporation or its affiliates, determined as at the end of the month immediately preceding the month in which the termination of employment occurs and if at the relevant time an annual salary level has not been established, it shall be calculated by multiplying by 12 the monthly salary of the Executive in effect for the month preceding the month in which a termination of employment occurs pursuant to Article 2.  Notwithstanding the foregoing, and in the event that the termination of employment occurs pursuant to Section 2.5(a)(ii), the Annual Salary shall be deemed to be the annual salary of the Executive established by the HRCC and payable by the Corporation or its affiliates, determined as at the end of the month immediately preceding the first event or series of events constituting the constructive dismissal of the Executive, as contemplated by Section 2.5(a)(ii) herein;

		
	(d)
	"Annual Incentive Bonus" means the annual incentive bonus of the Executive under the Corporation's short term incentive plan;

		
	(e)
	"Confidential Information" means the information, processes, know how, data, trade secrets, techniques, knowledge and other confidential information not generally known or lawfully available to the public relating to or connected with the business or corporate affairs and operations of the Corporation and its affiliates;

		
	(f)
	"constructive dismissal" means, unless expressly consented to in writing by the Executive, any action that constitutes constructive dismissal (as defined at common law) of the Executive, including without limiting the generality of the foregoing;

		
	(i)
	a decrease in the title, position or reporting relationships of the Executive, including without limiting the generality of the foregoing, ceasing to directly report to the board of directors of the Corporation and of its control person, if any, or ceasing to be a full member of the most senior formal groups or committees (as of the effective date hereof its Executive Leadership Team, its Corporate Leadership Team, its Operations and Integrity Committee and its Investment Committee) involved in corporate stewardship of the Corporation and of its control person, if any;

-3-

		
	(ii)
	a material decrease in the Executive's responsibilities or powers;

		
	(iii)
	a reduction in the Annual Salary of the Executive;

		
	(iv)
	a reduction in the value of the Executive's pension benefits (including without limiting the generality of the forgoing the defined benefit pension plan or the supplemental benefit pension plan); or

		
	(v)
	any material reduction in the value of the Executive's other employee benefits, plans and programs, other than a reduction in the value of the Executive's Annual Incentive Bonus as a result of the normal application of the performance criteria under the Annual Incentive Bonus.

		
	(g)
	"control person" means a person, or a group of persons acting jointly or in concert, that are in a position to exercise, directly or indirectly, effective control of another person, whether through:

		
	(i)
	the ownership or control of:

		
	A.
	a majority of, or

		
	B.
	in the case of a person whose voting securities or interests are widely held or publicly traded, 20% or more of,

the voting securities or interests of such other person(including without limiting the generality of the foregoing of any securities or interests which are convertible or exchangeable into voting securities or interests forming part of the holdings of the person or group of persons, whether or not at relevant time such conversation or exchange has taken place, and including securities or interests of a person or group of persons which carry the right to vote under circumstances that have occurred and are continuing); or
		
	(ii)
	contract or other legal rights,

and "control" in respect of a person shall have a corresponding meaning;
provided that a person holding voting securities or interests in the ordinary course of business as an investment manager and who is not, individually or acting jointly or in concert with other persons, 

-4-

using such holding to exercise effective control shall not be considered a control person;
		
	(h)
	"defined benefit pension plan" means the Corporation's registered pension plan, entitled "Retirement Plan for the Employees of Enbridge Inc. and Affiliates" and dated July 1, 2001, as amended or replaced from time to time in accordance with the terms of such registered pension plan;

		
	(i)
	"Human Resources and Compensation Committee" or "HRCC" means the committee of the Board of Directors of the Corporation from time to time appointed to fix the remuneration of executives of the Corporation or, if such committee has not been appointed, means the Board of Directors of the Corporation;

		
	(j)
	"Pensionable Bonus" means the portion of Annual Incentive Bonus which is used under the defined benefit pension plan and the supplemental benefit pension plan to determine final or best average earnings;

		
	(k)
	"person" means an individual, a partnership or incorporated or unincorporated association, syndicate or organization, a company, corporation or other body corporate wherever or however incorporated, a trust or any government or governmental authority or instrumentality;

		
	(l)
	"RCA" shall have the meaning set out in Section 2.7;

		
	(m)
	"Retiring Allowance" shall have the meaning set out in Section 2.5(b);

		
	(n)
	"supplemental benefit pension plan" means the non-registered supplemental pension plan, entitled "The Enbridge Supplemental Pension Plan" and dated January 1, 2000, as amended or replaced from time to time in accordance with the terms of such supplemental pension plan; and

		
	(o)
	"supplementary undertaking" shall have the meaning set out in Section 2.7.

		
	1.2
	Headings

The headings of the articles, sections, clauses and paragraphs herein are inserted for convenience of reference only and shall not affect the meaning or interpretation hereof.  Unless otherwise stated, all references to articles, sections, clauses or paragraphs in this Agreement are to those set out in this Agreement.

-5-

		
	1.3
	Governing Law and Attornment

This Agreement shall be construed and interpreted in accordance with the laws of the Province of Alberta and the federal laws of Canada applicable therein.  Each of the parties hereby irrevocably attorns to the jurisdiction of the courts of the Province of Alberta with respect to any matters arising out of this Agreement.
		
	1.4
	Singular; Gender

All words importing the singular number include the plural and vice versa, and all words importing gender include the masculine, feminine and neuter genders.

ARTICLE 2
EMPLOYMENT
		
	2.1
	Position, Duties and Responsibilities of Executive

The Executive shall have such responsibilities and powers as the Board of Directors or the bylaws of the Corporation may from time to time prescribe and are currently contemplated by his position as [        ] or substantially equivalent duties and responsibilities.  Except as may be authorized by the Board of Directors of the Corporation, the Executive shall devote the whole of his time to the Executive's duties hereunder and shall use his best efforts to promote the interests of the Corporation and its affiliates.
		
	2.2
	Term of Agreement

The term of this Agreement shall commence on the effective date hereof and, subject to Section 2.8, shall continue in effect to and including the earliest of:
		
	(a)
	the effective date of voluntary retirement of the Executive in accordance with the retirement policies established for senior employees of the Corporation;

		
	(b)
	the effective date of voluntary resignation of the Executive other than pursuant to Section 2.5(a)(ii);

		
	(c)
	the death of the Executive; or

		
	(d)
	the effective date of termination of the employment of the Executive by the Corporation, including pursuant to Section 2.5 (a)(ii).

		
	2.3
	Termination of Agreement upon Disability of Executive

If at the end of any month the Executive is and has been for a period of more than 12 consecutive months unable to perform the essential duties specified 

-6-

pursuant to this Agreement in the normal and regular manner due to mental or physical disability, this Agreement may be terminated by the Corporation on 30 days' prior written notice.  Notwithstanding anything contained in this Section 2.3, the Executive shall, after such termination, continue to be entitled to all benefits provided under the disability and pension plans of the Corporation or its affiliates applicable to the Executive at the date of and during the time of this Agreement.
		
	2.4
	Termination of Agreement by the Corporation for Cause

The Corporation may terminate this Agreement at any time without notice in the event the Executive shall be convicted of a criminal act of dishonesty resulting or intending to result directly or indirectly in gain or personal enrichment of the Executive at the expense of the Corporation, or for just cause as defined at common law, pursuant to written notice setting forth particulars of such cause.
		
	2.5
	Termination of Employment by the Corporation or the Executive 

		
	(a)
	Except where such termination is pursuant to Sections 2.2(a), 2.2(b), 2.2(c), 2.4 or 2.6 the provisions of this Section 2.5 shall apply:

		
	(i)
	where the Corporation terminates the employment of the Executive for any reason;

		
	(ii)
	where the Executive terminates his employment with the Corporation within a period of 180 days following constructive dismissal of the Executive.  For this purpose the Executive may within a period of 180 days following the constructive dismissal of the Executive terminate his employment with the Corporation upon 30 days' prior written notice to the Corporation.  For greater clarity, the said 30 day notice may be given at any time up to the 150th day of the said 180-day period; or

		
	(iii)
	where the Corporation terminates this Agreement pursuant to Section 2.3.

		
	(b)
	In the event of termination of employment as provided in Section 2.5(a), the Executive shall be entitled to receive, and the Corporation shall pay to the Executive, a retiring allowance (the "Retiring Allowance") computed as hereinafter provided, which shall include all statutory entitlement under employment standards legislation and all common law entitlement to reasonable notice.  The Retiring Allowance shall be that amount which is equal to three times the sum of:

-7-

		
	(i)
	the Annual Salary; and

		
	(ii)
	the average of the last two payments of the Annual Incentive Bonus paid to the Executive immediately preceding the date of such termination of employment.

		
	(c)
	In addition to the Retiring Allowance calculated in accordance with Section 2.5(b):

		
	(i)
	the Corporation shall pay to the Executive the cash value of three times the last annual flex credit allowance provided to the Executive immediately preceding the date of such termination of employment under the Corporation's flexible benefit program unless the Executive continues to be covered through the Corporation's annuitant benefit program or the benefits program of another employer of equal value (and in the case that such other employer's benefit program is of lesser value, the Executive shall be paid the difference in such values).  Alternatively, at the Executive's election, the Corporation shall provide continuation of the benefit coverage, for three years, with the exception of those benefits which may not be continued pursuant to the applicable plan text, including long term disability coverage;

		
	(ii)
	the Corporation shall pay to the Executive an Annual Incentive Bonus for the calendar year in which the termination of employment occurs, prorated based upon the number of days of employment of the Executive in the calendar year to the total number of days in the year and calculated based on the last Annual Incentive Bonus payment received by the Executive.  In addition, the Executive shall receive all accrued and unpaid annual vacation pay to the date of termination.  In addition, where the Executive holds rights under other plans to cash incentive compensation (including without limiting the generality of the foregoing, any performance stock units) the Executive shall be paid for the period in which he was employed a pro-rated amount based upon the number of days in the applicable period under the plan the Executive was employed to the number of days in the applicable plan period and such amounts shall be paid to the Executive within 30 days of the date on which amounts so payable under such plans are determined;

		
	(iii)
	the Corporation shall pay to the Executive the cash value of three times the last annual flexible perquisite allowance 

-8-

provided to the Executive immediately preceding the date of such termination of employment under the Corporation's executive flexible perquisites program less any amounts prepaid to the Executive but unearned by virtue of such termination of employment (as of the effective date of this Agreement this amount is $49,500);
		
	(iv)
	the Corporation shall pay to the Executive a lump sum payment equivalent to the Corporation's portion of contributions on behalf of the Executive to the Corporation's employee savings plan for a three year period based upon the base salary of the Executive as at the effective date of termination; and

		
	(v)
	the Corporation shall pay for financial counselling and/or career counselling assistance for the Executive to a maximum of $20,000.

		
	(d)
	The Executive shall have, and shall be deemed to have had, as of the effective date of termination, three years of additional service added to the service (calculated at 2% accrual rate) already accrued at the effective date of termination under the Corporation's defined benefit pension plan and supplemental benefit pension plan.  In addition, in the event of termination pursuant to Section 2.5 (a) prior to January 9, 2014, the Executive shall be credited with an additional .5% accrual rate under the Corporation's defined benefit pension plan and supplemental pension plan for each year of service between 2008 and 2014, up to a maximum of 3%.

		
	(e)
	Notwithstanding the provisions of any plan under which such options have been issued, if at the effective date of termination of employment as provided in Section 2.5(a) the Executive holds exercisable but unexercised options for the purchase of shares or other securities under any of the Corporation's or its affiliates' stock option plans, the Executive shall be entitled to exercise all options so held in accordance with the terms of such plans; provided further that any provision in any such plan which purports to terminate such options in the event of termination of employment for any reason shall not be applicable or, if such provision is applicable under such plan to prevent such exercise, the provisions of Section 4.4 shall apply.  If the Executive holds options for the purchase of shares or other securities under any of the Corporation's or its affiliates' stock option plans which are not vested or otherwise not exercisable at the date of termination of employment in circumstances where this Section 2.5 applies, the Corporation shall 

-9-

pay to the Executive a cash amount representing the excess, if any, of the fair market value of the shares or other securities on the date of termination of employment over the exercise price for such options.  Fair market value on the date of termination of employment shall mean the last board lot sale price on the Toronto Stock Exchange (or such other exchange on which the greatest volume of trading of such shares or other securities takes place for the 30 trading days prior to the date of termination) on the last trading day prior to the date of termination of employment.
		
	(f)
	The Corporation and the Executive agree that the provisions of Section 2.5 are fair and reasonable and that the amounts payable by the Corporation to the Executive pursuant to Section 2.5 are reasonable estimates of the damages which will be suffered by the Executive in the event of the termination of his employment with the Corporation in the circumstances set out in Section 2.5, and shall not be construed as a penalty, nor shall the Executive be required to mitigate any loss resulting from the termination, including without limiting the generality of the foregoing, any amounts required to be paid pursuant to this Agreement.

		
	(g)
	The amounts payable by the Corporation to the Executive pursuant to Section 2.5 shall not be reduced by any amounts earned by the Executive after the termination of the employment of the Executive.

		
	(h)
	All amounts paid by the Corporation to the Executive pursuant to Section 2.5 shall satisfy and forever discharge all liabilities, claims or actions that the Executive may or shall have against the Corporation arising from the termination of employment of the Executive whether at common law or under statute or otherwise.

		
	(i)
	Subject to the provisions of Sections 2.5(c) and 2.5(e), the Corporation shall, at the option of the Executive, pay the amounts provided under this Section 2.5 to the Executive on the effective date that the employment of the Executive is terminated, or as soon thereafter as reasonably practical, but in any event within 30 days of the effective date of such termination, less all applicable statutory deductions, or arrange a schedule of instalment payments of such amounts as determined by the Executive.  Upon payment to the Executive of the amounts provided for under this Section 2.5 and, if applicable, a duly signed written agreement of the Corporation to make all instalment payments thereof on a timely basis in accordance with the Executive's determinations as provided for in the foregoing sentence, the Executive and the Corporation shall 

-10-

execute and deliver to the other the releases in the forms of Schedules A and B, respectively.
		
	2.6
	Other Termination by Executive

Notwithstanding anything to the contrary herein, in addition to the right of the Executive to terminate his employment under the circumstances described in Section 2.5, the Executive shall be entitled to terminate this Agreement and his employment with the Corporation at his pleasure upon 30 days' prior written notice to such effect.  In such event, the Executive shall not be entitled to any further compensation from the effective date of his termination of employment, except for such compensation as accrued prior to and on the effective date of termination of employment.  The Corporation acknowledges and agrees that the Corporation shall have no remedy against the Executive, in law or otherwise, upon the termination of this Agreement and the Executive's employment with the Corporation in accordance with this Section 2.6.
		
	2.7
	Pension Plans

The Corporation undertakes and agrees with the Executive (herein, the "supplementary undertaking") to pay or cause to be paid to the Executive the amounts provided for in the supplemental benefit pension plan as modified by this Section 2.7, which amounts are supplemental to the amounts to be paid to the Executive under the defined benefit pension plan, such that the Executive will receive an annual pension equal to the annual pension that the Executive would be entitled to under the defined benefit pension plan but for the fact that retirement benefits under the defined benefit pension plan are subject to a maximum pension limitation as fixed from time to time under the Income Tax Act (Canada) and the rules and regulations from time to time promulgated by Canada Revenue Agency thereunder.  In particular, the Executive (or the Executive's spouse or beneficiary as defined in the supplemental benefit pension plan) is entitled to receive:
		
	(a)
	benefits determined in accordance with the supplemental benefit pension plan, being certain amounts that would be payable from the defined benefit pension plan but for limitations imposed by the Income Tax Act (Canada), all as specified in the supplemental benefit pension plan; and

		
	(b)
	if Section 2.5(d) applies, benefits determined in accordance with the supplemental benefit pension plan pursuant to Section 2.7 (a) above as if:

		
	(i)
	three additional years of credited service were applied in the lifetime retirement income formula in the defined benefit pension plan, and three additional years of continuous service were granted for other purposes of the defined 

-11-

benefit pension plan (calculated at 2% accrual rate).  In addition, in the event of termination pursuant to Section 2.5 (a) prior to January 9, 2014, the Executive shall be credited with an additional .5% accrual rate for each year of service between 2008 and 2014, up to a maximum of 3%.
		
	(ii)
	for the purposes of determining final or best average earnings, for each of the three additional years of credited service provided for pursuant to Section 2.7 (b) (i) above:

		
	A.
	the Executive's salary for such years shall be deemed to be his annual salary as at the date of termination of employment, and

		
	B.
	the Annual Incentive Bonus used in calculating the Pensionable Bonus for each of such additional years shall be deemed to be the average of the last two payments of Annual Incentive Bonus paid to the Executive.

Notwithstanding the provisions of Section 2.5(d) and this Section 2.7, the defined benefit pension plan and the supplemental benefit pension plan, the aggregate pension payable to the Executive (or the Executive's spouse or beneficiary as defined in the supplemental benefit pension plan) under such pension plans shall not exceed $1,750,000 per annum; provided that the Executive may request that the Board of Directors of the Corporation or the HRCC consider increasing the amount of $1,750,000 per annum in the following circumstances:
		
	(a)
	where in any period of 12 consecutive months the increase in the Consumer Price Index (all items) for Canada (as published by Statistics Canada) is greater than 10%; or

		
	(b)
	where any other member of the Executive Leadership Team with approximately the same number of credited years of service for purposes of the defined benefit pension plan and the supplemental benefit pension plan would receive an annual pension greater than $1,750,000 per annum;

and the Board or the HRCC may in its discretion determine within 90 days of the request being made by the Executive if such an increase will be made and, if so, the amount of such increase.
The Corporation represents and undertakes to the Executive that the supplementary undertaking is and shall hereafter be maintained fully funded in a retirement compensation arrangement (as referred to in the Income Tax Act (Canada)) separately maintained under a trust arrangement established by the Corporation (the 

-12-

"RCA").  The supplementary undertaking shall be funded from amounts in the RCA with any amount that cannot be funded from the RCA being paid by the Corporation.  In addition, the Corporation agrees that the portion of the Annual Incentive Bonus used in calculating Pensionable Bonus for all years of credited service shall not be less than 50% of Annual Incentive Bonus for each applicable year.
		
	2.8
	Continuing Provisions

Notwithstanding the termination of this Agreement under Article 2, the provisions of Sections 2.5, 2.6, 2.7 and 2.8 and Article 3 and all other provisions hereof which by their terms are to be performed following the termination hereof shall survive such termination and be continuing obligations, and all rights of the Executive to compensation and benefits which have accrued prior to such termination shall remain payable and enforceable regardless of such termination.

ARTICLE 3
NON-COMPETITION AND CONFIDENTIALITY
		
	3.1
	Non-Competition While Employed

The Executive recognizes and understands that in performing the duties and responsibilities of his employment as outlined in this Agreement, he will occupy a position of high fiduciary trust and confidence, pursuant to which he has developed and will develop and acquire wide experience and knowledge with respect to the businesses carried on by the Corporation and its affiliates and the manner in which such businesses are conducted.  It is the expressed intent and agreement of the Executive and of the Corporation that such knowledge and experience shall be used solely and exclusively in the furtherance of the business interests of the Corporation and its affiliates and not in any manner detrimental to them.  The Executive therefore agrees that so long as he is employed by the Corporation pursuant to this Agreement he shall not engage in any practice or business in competition with the business of the Corporation or any of its affiliates.
		
	3.2
	Non-Competition Following Termination of Employment

In the event of termination of the Executive's employment for any reason, the Executive agrees that he will not, directly or indirectly, for a period of 12 months from the date of termination of employment, without the prior written consent of the Corporation (not to be unreasonably withheld) either alone or in partnership or in conjunction with any person or persons, firm, association, syndicate, company or corporation (collectively, a "Business Entity") as principal, agent, shareholder, employee, director or in any other manner whatsoever carry on or be engaged in or concerned with or interested in, or advise, lend money to, guarantee the debts or obligations of or permit his name or any part thereof to be used or employed by any Business Entity engaged or interested in the transportation, distribution or marketing of crude oil, natural 

-13-

gas or natural gas liquids, the gathering or processing of natural gas including the extraction of natural gas liquids, power generation, transmission, distribution or marketing, the production, transmission, distribution or marketing of renewable or green energy including wind, solar or thermal: (i) within any province of Canada; (ii) within Canada; (iii) within any state of the continental United States of America, including Alaska; (iv) within the continental United States of America, including Alaska; or (v) within North America.  If any covenant or provision in this Section 3.2 is determined to be void or unenforceable in whole or in part, it shall be deemed not to affect or impair the validity of any other covenant or provision, and each of Sections 3.2(i) to (v) are hereby declared to be separate and distinct covenants (and for this purpose each province or state intended to be named in Sections 3.2(i) and (iii) shall be considered to be set forth in a separate subclause of Section 3.2 and to be a separate and distinct covenant).  The Executive agrees that the provisions of this Section 3.2 are reasonable in the interests of the Corporation and its continuing business and operations.  The foregoing provisions of Section 3.2 shall not apply to the acquisition by the Executive, directly or indirectly, or through any Business Entity of up to 1% of the shares or other securities of a Business Entity quoted or traded on any public stock exchange in Canada or the United States of America.
If the Executive fails to comply with this Section 3.2, the Corporation shall be entitled to cancel all unvested or unexercised options or performance share units and to terminate the payment to the Executive of any amounts the Executive is entitled to under the Corporation's supplemental benefit pension plan.
		
	3.3
	Non-Solicitation of Employees

Except with the prior written consent of the Corporation, the Executive shall not solicit or cause to be solicited for employment any officer or employee of the Corporation, any of its subsidiaries or any partnership where the Corporation or one of its subsidiaries acts as the general partner for a period of 24 months from the termination of the employment of the Executive with the Corporation.  For this purpose, solicitation does not include advertising in periodicals or newspapers of general circulation.
If the Executive fails to comply with this Section 3.3, the Corporation shall be entitled to cancel all unvested or unexercised options or performance share units and to terminate the payment to the Executive of any amounts the Executive is entitled to under the Corporation's supplemental benefit pension plan.
		
	3.4
	Confidentiality

The Executive further recognizes and understands that in the performance of his employment duties and responsibilities outlined in this Agreement, he will become knowledgeable, aware and possessed of Confidential Information concerning the business of the Corporation and its affiliates.  The Executive agrees that, except with the consent of the Board of Directors of the Corporation or his superior, or as required 

-14-

by applicable law, he will not disclose such Confidential Information to any unauthorized persons so long as he is employed by the Corporation pursuant to this Agreement and for a period of two years thereafter; provided that the foregoing shall not apply to any Confidential Information which is or becomes known or available to the public or to the competitors of the Corporation or its affiliates other than by a breach of this Agreement by the Executive.

ARTICLE 4
GENERAL
		
	4.1
	Notices

Any notice required or permitted to be given to a party hereunder shall be in writing and may be given by mailing the same (provided there is no threatened or pending disruption of postal services), postage prepaid, or delivering the same, addressed to such party at the following address:
To the Corporation:
Enbridge Inc.
3000, 425 - 1st Street SW
Calgary, Alberta T2P 3L8
Attention:    Chairman of the Board of Directors
To the Executive:
[        ] 
[        ] 
[        ]
Any notice aforesaid if delivered shall be deemed to have been delivered on the first business day following the date on which it was delivered or if mailed shall be deemed to have been received on the third business day following the date on which it was mailed.  Any party may change its address for service from time to time by a notice given in accordance with the foregoing.
		
	4.2
	Time

Time shall be of the essence of this Agreement.
		
	4.3
	Legal Fees and Expenses

The Corporation shall pay all reasonable costs incurred by the Executive, as determined in the sole discretion of the President and Chief Executive Officer, in respect of legal, consulting and accounting expenses in connection with the negotiation 

-1-

and execution of this Agreement.  The Corporation shall pay all costs, charges and expenses incurred in respect of legal, consulting and accounting expenses (including legal fees, charges and disbursements on an as between a solicitor and his own client basis) incurred by the Executive or his estate in taking any action or enforcing any right or benefit provided to the Executive by this Agreement; provided only that the Executive is substantially successful in any such action or in enforcing any such right or benefit, and providing further that payments pursuant to this Section 4.3 shall not exceed a maximum amount of $20,000 or such greater amount as may be ordered by any court or other competent authority.
		
	4.4
	Replacement and Integration

The provisions of this Agreement replace and supersede the Executive Employment Agreement dated as of January 9, 2008 and the offer of employment dated March 19, 2008 each between the Executive and the Corporation.  The provisions of this Agreement are in addition to and not in substitution for the other terms, conditions and provisions concerning the employment of the Executive by the Corporation, whether contained in benefit or incentive plans (including without limiting the generality of the foregoing, short term incentive plans, performance incentive plans and long term incentive plans) or otherwise, and where there is any conflict between this Agreement and such other terms, conditions and provisions this Agreement shall govern and prevail.  In the event any plan under which any benefit or incentive is granted does not permit a benefit or incentive to be received in circumstances contemplated by this Agreement, the Corporation shall pay to the Executive a cash amount equal to the value of the benefit or incentive provided for in this Agreement.  This Agreement together with such other terms, conditions and provisions constitute the entire Agreement between the parties hereto pertaining to the subject matter hereof.
		
	4.5
	Amendment

This Agreement may not be amended or modified in any respect except by written instrument signed by the parties hereto.  This Agreement shall, if the Executive so requests in writing, be amended to modify its provisions to provide the Executive with the same rights in respect of circumstances where a person becomes a control person of the Corporation or its affiliates as may be provided for in any agreement entered into after the effective date of this Agreement (other than amended and restated employment agreements that may be entered into after the effective date hereof with employees who were members of the Executive Management Team on January 9, 2008) with any other employee of the Corporation or any of its affiliates.  The Corporation shall, within 10 days of the entering into of any such agreement with another employee, notify the Executive in writing of the details of such provisions (but shall not be required to disclose the identity of the other employee).

-2-

		
	4.6
	Waivers

No waiver by either party hereto of any breach of any of the provisions of this Agreement shall take effect or be binding upon the party unless in writing and signed by such party.  Unless otherwise expressly provided therein, such waiver shall not limit or affect the rights of such party with respect to any other breach.
		
	4.7
	Further Assurances 

The parties hereto agree to execute and deliver such further and other documents and perform and cause to be performed such further and other acts and things as may be necessary or desirable in order to give full effect to this Agreement and every part hereof.
		
	4.8
	Severability

If any provision of this Agreement shall be held to be invalid, illegal or unenforceable, the validity, legality or enforceability of the remaining provisions of this Agreement shall not in any way be affected or impaired thereby.
		
	4.9
	Enurement

This Agreement shall enure to the benefit of and be binding upon the parties hereto and their respective heirs, legal personal representatives, successors and permitted assigns.

-3-

IN WITNESS WHEREOF the Corporation has hereunto affixed its corporate seal and caused this Agreement to be duly executed and delivered by its duly authorized officers in that behalf and the Executive has hereunto set his hand and seal this ___________ day of February, 2013 and effective as of the day and year first written above.
	
				
	 
	 
	 
	ENBRIDGE INC.

	 
	 
	 
	 

	 
	 
	 
	Per:   /s/ [                  ]

	 
	 
	 
	[                       ]

	 
	 
	 
	[                       ]

	 
	 
	 
	 

	 
	 
	 
	 

	 
	 
	 
	Per:   /s/ [                  ]

	 
	 
	 
	[                       ]

	 
	 
	 
	[                       ]

	 
	 
	 
	 

	 
	 
	 
	 

	SIGNED AND DELIVERED in the
	)
	 
	 

	presence of:
	)
	 
	 

	 
	)
	 
	 

	/s/ [                      ]
	)
	 
	[                    ]

	Witness
	)
	 
	[                         ]

	[                          ]
	)
	 
	 

SCHEDULE A
Release
KNOW ALL MEN BY THESE PRESENTS that I, [        ], of the City of Calgary, in the Province of Alberta, in consideration of the amounts (including without limiting the generality of the foregoing, if applicable, payment of instalments of such amounts) provided in Sections 2.5 and 2.7 of the Executive Employment Agreement (the "Contract") dated as of [        ] between me and Enbridge Inc. (the "Corporation") and for other good and valuable consideration, inclusive of any statutory severance or benefits in accordance with the Employment Standards Code (Alberta), the receipt (other than in respect of the future instalments referred to above, if any) and sufficiency of which is hereby acknowledged, do for myself, my executors and assigns hereby remise, release and forever discharge the Corporation, its respective predecessors, successors and assigns, from all manner of actions, causes of action, claims or demands, past, present or future, which against the Corporation, its respective predecessors, successors and assigns, I ever had, now have, or can, shall or may hereafter have, by reason of or arising out of any cause, matter or thing whatsoever done or admitted to be done, occurring or existing up to and inclusive of the date of this Release and in particular, without in any way restricting the generality of the foregoing, in respect of all claims, past, present or future, directly or indirectly related to or arising out of or in connection with my relationship with the Corporation, its respective predecessors, successors and assigns, as an employee, officer, director or trustee, and the termination of my employment from the Corporation, on [            ].  Words or terms defined in the Contract and not otherwise defined herein shall have the meanings ascribed to them in the Contract.
AND FOR THE SAID CONSIDERATION I represent and warrant that I have not assigned to any person any of the actions, causes of action, claims, suits, executions or demands which I release by this Release, or with respect to which I agree not to make any claim or take any proceeding herein.
NOTWITHSTANDING ANYTHING CONTAINED HEREIN, this Release shall not extend to or affect, or constitute a release of, my right to sue, claim against or recover from the Corporation and shall not constitute an agreement to refrain from bringing, taking or maintaining any action against the Corporation in respect of:
		
	(a)
	any corporate indemnity existing by statute or contract or pursuant to any of the constating documents of the Corporation provided in my favour in respect of my having acted at any time as a director, trustee or officer or any of such positions with the Corporation or any of its affiliates or of any person for which I acted as a director, trustee or officer of at the request of the Corporation or any of its affiliates;

		
	(b)
	my entitlement to any insurance maintained for the benefit or protection of the directors, trustees or officers of the Corporation or of any of its 

- 2 -

affiliates or of any person for which I acted as a director, trustee or officer of at the request of the Corporation or any of its affiliates, including without limitation, directors', trustees' and officers' liability insurance; or
		
	(c)
	my entitlement to any amounts that may arise under the Sections and Articles of the Contract referred to in Section 2.8 of the Contract.

IT IS HEREBY AGREED that, except as provided herein, the terms of the Contract and of this Release will be kept confidential.  Subject to the following, I shall not communicate any such terms to any third party under any circumstances whatsoever, although I shall be at liberty to disclose to third parties that a mutually acceptable release was agreed upon.  Notwithstanding the foregoing, I shall be permitted to disclose the terms of the Contract and this Release to my spouse, and my tax, financial and legal advisors, and to make any disclosures of the terms of the Contract and this Release as may be required to allow me to comply with any applicable provision of the law.  In such event, I shall require that my spouse, and any such tax, financial or legal advisor execute the undertaking provided in Schedule C to the Contract prior to the disclosure of the terms of the Contract and this Release and shall advise the Corporation of such disclosure and provide the Corporation with a copy of such undertaking.  In the event of any disclosure required by law, upon becoming aware of any such I shall, provided I am legally permitted to do so, promptly advise the Corporation of the required disclosure prior to making such disclosure and shall, to the extent legally permitted to do so, provide the Corporation with reasonable opportunity to seek protective orders or other assurances that confidential treatment will be afforded to such information.  The invalidity or unenforceability of any provision of this Release shall not affect the validity or enforceability of any other provision of this Release, which shall remain in full force and effect.
I HEREBY DECLARE that I have read all of this Release, fully understand the terms of this Release and voluntarily accept the consideration stated herein as the sole consideration for this Release for the purpose of making a full and final settlement with the Corporation.  I further acknowledge and confirm that I have been given an adequate period of time to obtain independent legal counsel upon the meaning and the significance of the terms herein.
IN WITNESS WHEREOF, I have hereunto  
set my hand this [   ] day of [               ].
	
			
	 
	 
	 

	Witness
	 
	[                           ]

SCHEDULE B
Release
KNOW ALL MEN BY THESE PRESENTS that Enbridge Inc. (the "Corporation"), a corporation incorporated under the laws of Canada, in consideration of the delivery by [            ] (the "Executive") of a Release dated the date hereof and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, for itself, its affiliates and it and their respective predecessors, successors and assigns, hereby remises, releases and forever discharges the Executive and his heirs, legal personal representatives and assigns from all manner of actions, causes of action, claims or demands, past, present or future, against the Executive or his heirs, legal personal representatives and assigns which the Corporation, its affiliates or its or their respective predecessors, successors and assigns ever had, now have, or can, shall or may hereafter have, by reason of or arising out of any cause, matter or thing whatsoever done or omitted to be done, occurring or existing up to and inclusive of the date of this Release and in particular, without in any way restricting the generality of the foregoing, in respect of all claims, past, present or future, directly or indirectly related to or arising out of or in connection with the Corporation's or its affiliates' relationship with the Executive, as an employee, officer, director or trustee of the Corporation or its affiliates.  Words or terms defined in the Contract (as defined below) and not otherwise defined herein shall have the meanings ascribed to them in the Contract.
AND FOR THE SAID CONSIDERATION the Corporation represents and warrants that neither it nor its affiliates has assigned to any person any of the actions, causes of action, claims, suits, executions or demands which it releases by this Release, or with respect to which it and its affiliates agrees not to make any claim or take any proceeding herein. .
IT IS HEREBY AGREED that, except as provided herein or as required by law, the terms of the Executive Employment Agreement (the "Contract") dated as of  
[        ] between the Corporation and the Executive and of this Release will be kept confidential.  None of the Corporation or its affiliates, or any of their employees, officers, directors or trustees shall communicate any such terms to any third party under any circumstances whatsoever, although the Corporation shall be at liberty to disclose to third parties that a mutually acceptable release was agreed upon.  In the event of disclosure required by law, upon becoming aware of such the Corporation shall , provided it is legally permitted to do so, promptly advise the Executive of the required disclosure prior to making such disclosure and shall, to the extent legally permitted to do so, provide the executive with reasonable opportunity to seek protective orders or other assurances that confidential treatment will be afforded to such information.  The invalidity or unenforceability of any provision of this Release shall not affect the validity or enforceability of any other provision of this Release, which shall remain in full force and effect.

- 2 -

IN WITNESS WHEREOF, the Corporation has duly executed and delivered this Release this ● day of ●, 20●
	
		
	 
	ENBRIDGE INC.

	 
	Per:

	 
	●

	 
	Chair, Board of Directors

	 
	Per:

	 
	●

	 
	●

SCHEDULE C
Undertaking
I, __________________________________________ of________________________ 
      [print name of person giving the undertaking]    [suite number and street address] 
 
_____________________, ______________, _________________________________     [city, town, etc.]                    [province/state]                      [country] 
 
being the _________________________________________________________, of ● 
                       [describe relationship to the "Executive", as defined hereinafter, eg: spouse, tax, financial or legal advisor] 
(the "Executive") for good and valuable consideration, the receipt and sufficiency of which I hereby acknowledge, agree to keep strictly confidential the terms and conditions of the Executive Employment Agreement dated as of October 1, 2012 made between Enbridge Inc. and the Executive, and any release thereof, all as may be disclosed to me by the Executive.
I further acknowledge that I will make no use whatsoever of the information comprising the terms and conditions of such Executive Employment Agreement, and any release thereof, except as may be required for the purposes of my providing advice and direction to the Executive in my aforesaid capacity.
IN WITNESS WHEREOF, I have hereunto set my hand this _______ day of ________, 20●.
	
			
	 
	 
	 

	[witness' signature]
	 
	[signature of person giving the undertaking]

	 
	 
	 

	 
	 
	 

	[print name of witness]
	 
	 

	 
	 
	 

	 
	 
	 

	[suite number and street address]
	 
	 

	 
	 
	 

	 
	 
	 

	[city, town]
	 
	 

	 
	 
	 

	 
	 
	 

	[province, country]
	 
	 

	 
	 
	 

	 
	 
	 

	[postal code]

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