Decision 2004-096
ATCO Pipelines
2004 General Rate Application Phase II Compliance Filing
October 29, 2004
Alberta Energy and Utilities Board
ALBERTA ENERGY AND UTILITIES BOARD Decision 2004-096: ATCO Pipelines 2004 General Rate Application Phase II Compliance Filing Application No. 1363222
Published by Alberta Energy and Utilities Board 640 – 5 Avenue SW Calgary, Alberta T2P 3G4
Telephone: (403) 297-8311 Fax: (403) 297-7040
Web site: www.eub.gov.ab.ca
Contents
1 INTRODUCTION...... 1
2 THE APPLICATION ...... 1
3 COMPLIANCE WITH BOARD DIRECTIONS IN DECISION 2004-079 ...... 3
4 OTHER MATTERS RELATED TO DECISION 2004-079 ...... 7 4.1 North Issues...... 8 4.1.1 North Revenue Adjustments...... 8 4.1.1.1 Rate 5 Forecast Revenue versus Actual Revenue...... 8 4.1.1.2 Gas Alberta Forecast Revenue versus Actual Revenue...... 8 4.1.1.3 Town of Redwater Forecast Revenue versus Actual Revenue ...... 9 4.1.1.4 AltaGas Refund...... 9 4.1.1.5 Summary of Revenue Adjustments ...... 10 4.1.2 Rate 5 Customer Refunds ...... 10 4.1.3 Gas Alberta Refund...... 12 4.1.4 North Deficiency...... 12 4.1.5 Sales Service for Rate 5 Customers from November 1, 2004 to April 30, 2005...... 13 4.2 South Issues...... 14 4.2.1 AltaGas South Billing Unit...... 14 4.2.2 AP’s Proposed Treatment of South Surplus ...... 15 4.3 North and South Issues ...... 15 4.3.1 UFG/Fuel Recovery from OPR Service ...... 15 4.3.2 2005 Rates...... 16 4.3.3 Gas Alberta Metering Initiative ...... 16
5 COMPLIANCE WITH BOARD DIRECTIONS FROM OTHER PROCEEDINGS.. 17
6 SUMMARY OF BOARD DIRECTIONS...... 18
7 ORDER ...... 19
APPENDIX A – BOARD REVISED TRANSPORTATION SERVICE REGULATIONS AND FSU RATE SCHEDULE...... 20
APPENDIX B – RATE SCHEDULES...... 21
APPENDIX C – TRANSPORTATION SERVICE REGULATIONS...... 22
APPENDIX D– NORTH REFUNDS/CHARGES...... 23
APPENDIX E – NORTH SURCHARGES...... 24
APPENDIX F – TREATMENT OF SOUTH SURPLUS...... 25
APPENDIX G – REMAINING PLACEHOLDER ITEMS...... 26
EUB Decision 2004-096 (October 29, 2004) • i
APPENDIX H – REVISED SUMMARY OF BOARD DIRECTIONS ...... 27
APPENDIX I – CROSS REFERENCE BETWEEN ORIGINAL AND REVISED SUMMARY OF BOARD DIRECTIONS ...... 37
List of Tables
Table 1: North Forecast Revenue versus Actual Revenue Differences...... 10
ii • EUB Decision 2004-036 (April 28, 2004)
ALBERTA ENERGY AND UTILITIES BOARD Calgary Alberta
ATCO PIPELINES 2004 GENERAL RATE APPLICATION PHASE II Decision 2004-096 COMPLIANCE FILING Application No. 1363222
1 INTRODUCTION
On September 24, 2004, the Alberta Energy and Utilities Board (the Board) issued Decision 2004-079 (the Decision) regarding the 2004 General Rate Application (GRA) Phase II of ATCO Pipelines (AP or the Company). In the Decision, the Board directed AP to re-file its 2003/2004 Phase II GRA to incorporate the Board’s findings in the Decision and provide all of the supporting schedules necessary for the Board to make its final determination respecting AP’s 2004 rates (Compliance Filing).
On September 30, 2004 and prior to submitting its Compliance Filing, AP requested clarification from the Board on certain Phase II matters. On October 1, 2004, the Board provided AP with clarification on these matters.
On October 4, 2004, Abcom1 requested clarification from AP regarding the application of rates available to the Montana Band for the period November 1, 2004 to April 30, 2005. On October 5, 2004, AP responded to Abcom’s request.
On October 4, 2004, AP submitted its Compliance Filing to the Decision (the Application).
In a letter dated October 7, 2004, Samson Cree Nation (the Samson Band) indicated that it has not advised AP that it was seeking new transportation service to replace the existing sales service.
Parties provided their initial comments on the Application by October 15, 2004 and AP provided responses to parties’ initial comments on October 15, 2004 and October 19, 2004. IGCAA and CAPP provided further comments on October 22, 2004 and October 26, 2004 respectively. AP replied to IGCAA’s October 22, 2004 letter on October 27, 2004.
The Board considers that the record for the Application closed on October 27, 2004.
2 THE APPLICATION
In the Application, AP requested approval for:
• 2004 Cost of Service Studies • Final rates effective November 1, 2004
1 On behalf of the Montana Band
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• North surcharges for November 1, 2004 to December 31, 2004 • AP’s proposed treatment of the South surplus amount of $20,000 • Rate Schedules • Transportation Service Regulations • Responses to Board Directions • Rate 5 refunds/charges
In the Application, AP included adjustments resulting from Board Directions from the following:
• Decision 2004-079; • Clarification Letter from the Board dated October 1, 2004 with respect to Decision 2004- 079; • Decision 2004-078 (SCADA Project)2; • Decision 2004-030 with respect to the Stores Block Proceeds3.
The Application also took into account the Board’s letter dated July 30, 2004 with respect to discontinuation of Rate Rider J.
The rates reflected in the Application also took account of the finalization of certain placeholder amounts in revenue requirement that had been determined by the Board and included in AP’s Phase I Third Compliance Filing (Application 1354858) approved by Order U2004-389, dated October 20, 2004. The placeholder amounts arose out of the following decisions:
• Decision 2004-049 (Executive Compensation); • Decision 2004-052 (Generic Cost of Capital); • Decision 2004-059 (AP Phase I Second Compliance Filing).
The Order approved AP’s 2003/2004 revenue requirement, surplus/shortfall amount and the remaining placeholder amounts,4 which will be dealt with in future proceedings.
The Board directs that, within 30 days of issue of a Board decision that finalizes any of the remaining placeholder amounts as shown in Appendix G, AP shall file an application with the Board outlining the difference between the final amount approved in the decision and the placeholder amount. The application should also outline AP’s proposal for dealing with the over or under-recovery.
2 Decision 2004-078, ATCO Gas and ATCO Pipelines SCADA Project, dated September 17, 2004 3 Decision 2004-030, ATCO Gas and Pipelines Ltd. Disposition of Calgary Stores Block and Distribution of Net Proceeds – Part 2, Addendum to Decision 2002-037, dated March 30, 2004. In this Decision the Board directed that a portion of the proceeds arising from the disposition of the Calgary Stores Block be allocated to customers of AP South by a method to be approved by the Board. 4 As shown in Appendix G
2 • EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines
The rates approved effective November 1, 2004 in this Decision Report are fixed and final.
3 COMPLIANCE WITH BOARD DIRECTIONS IN DECISION 2004-079
This section only deals with Directions in the Decision where parties had concerns or where the Board required further clarification. Compliance with the balance of Directions contained in the Decision is discussed below. Other issues identified by parties that are related to the Decision, but do not fit directly within the scope of a Direction are dealt with in Section 4 of this Decision Report. Outstanding Directions from other proceedings that were dealt with in the Compliance Filing and for which parties had comments are discussed in Section 5 of this Decision Report.
The Board notes that the Summary of Board Directions in the Decision5 was not complete and in order to assist all parties, the Board has included a revised Summary of Board Directions (Revised List of Directions) for the Decision in Appendix H of this Decision Report. The Board has also provided a table in Appendix I of this Decision Report which cross references the Board Directions in the Decision to the Revised List of Directions. The Board notes that it has used the numbers from the Revised List of Directions within Section 3 of this Decision Report.
The Board has reviewed Directions included in the Revised List of Directions to ensure compliance within the Application. The Board notes that interveners expressed no material concerns with AP’s compliance with the majority of the Directions which required action by AP in the Compliance Filing. The Board also found AP to have taken satisfactory measures in addressing many of these Directions. Appendix H indicates the Board’s approval of the compliances measures taken by AP in respect of particular Board Directions contained in the Decision. The Board has not included any further discussion in this Decision Report on these Directions.
Appendix H also lists those Directions which require compliance steps to be taken in future proceedings or by future action. These Directions are also not addressed further in this Decision Report.
Board Direction No. 136 (Reference Page 49) Process for Assigning Nominations to Service Classes The Board directed AP to describe in the Compliance Filing its process for assigning Other Pipeline Receipt (OPR) and Other Pipeline Delivery (OPD) nominations made by a given customer to one of the primary service classes.
Parties No parties objected to AP’s compliance response to this Direction.
AP AP submitted that OPD and OPR nominations were assigned to Distributing Companies, Producers and Industrials and were based on the type of contract that the customer holds with
5 Pages 158-162 6 Original Direction #14 from Decision 2004-079
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AP. AP explained that for example, a customer whose primary service need is to receipt gas onto AP, will contract for receipt service. An account is assigned to each type of contract to record and balance the customer’s transportation business. A receipt contract holder will place nominations in their account for the receipt of gas at receipt points. To balance their receipt account the customer will arrange to transfer their gas to an on system delivery customer’s account or to place a nomination for an OPD. Conversely, a delivery contract holder who places a nomination in their account for the delivery of gas to their plant will balance their account by either accepting a transfer of gas from an on system receipt account or by placing a nomination for an OPR. The OPR and OPD nominations placed by each customer at the account level are tracked, and recorded by AP. Customers requiring more than one type of service (i.e., receipt service and delivery service) have separate contracts and accounts for each type of primary service. Therefore, OPR and OPD nominations can be confirmed to each of the primary service classes.
Views of the Board The Board accepts as reasonable AP’s description of its process for assigning a particular nomination (OPR and OPD) made by a given customer to one of the primary service classes.
Board Direction No. 177 (Reference Page 54) File Updated Rate Schedules, and Board Direction No. 298 (Reference Page 96) File Updated Transportation Service Regulations (TSR)
With respect to the Rate Schedules, the Board directed AP to file an updated version of all schedules in the Compliance Filing based on Board determinations in the Decision.
The Board also directed AP to file updated TSR in the Compliance Filing based on Board determinations in the Decision.
Various issues related to Peak Demand were dealt with in the updated Rate Schedules and TSR, which are addressed below.
Peak Design Demand Calgary Calgary commented that Section B paragraph (iv) of the FSU Rate Schedule limited the AP delivery at the point of delivery in any hour to the “Peak Design Demand”; however, paragraph (vi) defined “Peak Design Demand” as a 24 hour demand to be provided by the customer. Calgary submitted that either there needed to be a process for the customer to provide the hourly Peak Design Demand or paragraph (iv) needed to be modified to a 24-hour delivery.
AP In its response to Calgary’s comments, AP submitted a proposed revision to the wording in the filed FSU Rate Schedule and the TSR. AP suggested that to provide clarity, the words in the
7 Original Direction #18 from Decision 2004-079 8 Original Direction #26 from Decision 2004-079
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TSR, Clause (yy) “on a twenty-four hour basis” should be replaced with the words “in GJ/hour”. In addition, the final sentence9 in Rate Schedule FSU Clause B (vi) would be deleted.
Views of the Board While the Board has reviewed the comments of Calgary and AP with respect to this matter, the Board considers that in the circumstances, it may be appropriate to develop a new term and to revise the definition of an existing term.
The Board notes that the word “demand” was used in the term “Peak Design Demand” and also within the term and definition of “Peak Billing Demand”. The Board notes that in the context of AP’s services, demand usually means a quantity of energy that is related to a 24 hour period. The Board believes that the use of the word “demand” in relation to a one hour energy quantity (Peak Design Demand) could create confusion. Therefore, the Board suggests that the term “Peak Design Demand” should be replaced with the term “Maximum Design Quantity” and the definition of “Peak Billing Demand” should be revised to provide further clarity. The Board also suggests that the word “billing” should be inserted within clause 5.3 of the TSR. Appendix A to this Decision Report shows the Board’s suggested revisions to the TSR and FSU Rate Schedule with respect to this matter.
The Board recognizes that parties have not had the opportunity to consider the above amendments to the TSR and to the FSU Rate Schedule. Accordingly, the Board will allow parties to make submissions on the amendments until 4 p.m. on November 8, 2004. In the event the Board receives no substantive comments in respect of the amendments prior to that time, the amendments set out in Appendix A will become effective on November 15, 2004. The Board will notify parties on or before November 15, 2004 whether further process is required or to confirm that the amendments are in force.
With respect to the balance of the Rate Schedules and balance of the TSR, the Board considers that AP has complied with Direction No. 17 and No. 29.
Peak Billing Demand and Peak Design Demand for 2005 and 2006 Federation and Gas Alberta (FGA) With respect to the requirements identified in the FSU Rate Schedule, FGA requested the Board to clarify if it intended to use the 2004 demands for 2005 billing or if the Board intended that Other Distributing Companies10 nominate revised demands for 2005. If the latter was the case, FGA requested that the Board set a date for the submission of the 2005 required demands for FSU customers some time between the date of issue of this Decision Report and January 1, 2005.
FGA noted that the Board approved AP’s proposal regarding the Billing Commencement Date schedule that requires distributing companies to submit their demands for the 2006 calendar year on or before January 1, 2005. FGA requested that the Board vary its Direction in the Decision and set a realistic date for providing demands for the 2006 calendar year allowing customers time to institute a planning cycle to meet the Board-approved deadlines.
9 Both the Peak Billing Demand and the Peak Design Demand will be expressed on a 24-hour basis. 10 Distributing Companies other than ATCO Gas
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AP AP proposed that Other Distributing Companies provide point specific peak design demands and peak billing demands for 2005 by December 15, 2004 and for 2006 by April 30, 2005.
Views of the Board The Board understands that parties need to establish appropriate Peak Billing Demands for the next Billing Commencement Date and that the timing specified in the TSR could not be achieved for the 2005 calendar year, or realistically for the 2006 calendar year if there were any uncertainties associated with the data, forecasts or calculations. Therefore the present period and the 2005 calendar year should be considered as a transition period. In the circumstances, the Board accepts AP’s proposal requiring Other Distributing Companies to provide point specific Peak Design Demands11 and Peak Billing Demands for 2005 by December 15, 2004 and for 2006 by April 30, 2005 as a reasonable approach.
Peak Billing Demand Determination for Other12 Distributing Companies FGA With respect to the requirements in the FSU Rate Schedule, FGA requested clarification whether the demands that the Other Distributing Companies submit should be actual four-hour peak demands as measured by these companies or if the Board required that these demands be the daily demands grossed up by the 1.08 factor to achieve a four-hour demand number.
In addition, FGA requested that the Board define the process and the terms on which AP would obtain consumption pattern information from the Other Distributing Companies.
AP AP proposed that it file for acknowledgement by May 2005, a document describing the results of the discussions with Other Distributing Companies regarding the process and terms by which AP will obtain their consumption patterns to determine their four-hour billing demand.
Views of the Board In the Decision, the Board accepted the relationship between the average four-hour peak demand13 and the average 24-hour peak demand based upon the data filed in evidence. In addition, the Board directed AP, in its next GRA, to file a comprehensive study with adequate data to support the peak demand relationships for all customer classes. In the Decision the Board determined the four-hour peak demand for Gas Alberta on the basis of the filed evidence.
The determination of four-hour peak demands for future years may be achieved through various means, including the use of actual measured data for a four hour period during a time of high demand extrapolated to the four-hour demand at the lowest temperature, or through other mathematical or measurement means. The Board considers that AP and its distributing company customers are capable of defining a workable process of obtaining and communicating the
11 Peak Design Demand suggested to be changed to Maximum Design Quantity – see Board Direction No. 17 and 29. 12 Distributing Companies other than ATCO Gas 13 Defined as Peak Billing Demand in Transportation Service Regulations in Appendix C
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necessary data on consumption patterns to determine future peak demands. Failing agreement on a peak demand or data management process, either party may apply to the Board for resolution of the issue.
The Board does not see the need for it to give further Directions to parties at this time in terms of their data management.
In addition, the Board also accepts AP’s proposal that it file for acknowledgement by May 2005, a document describing the results of discussions with Other Distributing Companies.
Board Direction No. 4814 (Reference pages 139-140) Adjust Forecast 2004 Delivery Nominations With respect to forecast 2004 OPR commodity revenue and 2004 Other Pipeline Delivery Commodity (OPDC) revenue, the Board considered it appropriate to use forecast billing determinants (receipt nominations and delivery nominations respectively). However it appeared that AP used 2002 actual delivery nominations for purposes of deriving the OPDC revenue. The Board noted that AP filed Oversupply Delivery Costs (ODC) forecasts that would have been based on physical flows to NGTL. Therefore, in the Compliance Filing, the Board directed AP to either adjust the forecast physical flow data as required to establish a delivery nomination forecast for 2004 or to use 2002 actual OPD nominations as a substitute for 2004 forecast numbers. The Board requested that AP provide an explanation supporting its position on this matter.
AP ODC are incurred on physical flows to the NGTL system. AP forecast its ODC costs in the 2004 Phase II Application using 2002 actual data. In compliance with the Board’s Direction, AP used 2002 actual OPD nominations, excluding non-standard volumes, as a forecast of 2004 OPD nominations in the Cost of Service Studies included in the Compliance Filing.
Views of the Board With respect to the OPDC revenue billing determinants, the Board notes that AP indicated that it used 2002 actual OPD nominations, excluding non-standard volumes, as its forecast of 2004 OPD nominations in its Compliance Filing, consistent with the numbers used in its February 2, 2004 North and South COSS. AP’s rationale for using 2002 actual OPD nominations as its 2004 forecast appears consistent with its approach (use of 2002 actual data) for forecasting 2004 physical flows to NGTL and the resulting ODC.
Therefore, the Board accepts as reasonable AP’s proposed OPDC revenue billing determinants.
4 OTHER MATTERS RELATED TO DECISION 2004-079
This section deals with issues identified by parties that are related to the Decision but do not fit directly within the scope of a Direction from the Decision.
14 This direction was not included in the Summary of Board Directions in Decision 2004-079.
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4.1 North Issues 4.1.1 North Revenue Adjustments 4.1.1.1 Rate 5 Forecast Revenue versus Actual Revenue FGA FGA submitted that the revenues for the Rate 5 customers in 2004 were incorrectly portrayed in the calculation of the 2004 deficiency. FGA submitted that the Rate 5 customers were actually charged a fixed charge of $275.00 per month per delivery point and a commodity charge of $0.275 /GJ during the period January to February 2004, whereas AP calculated the revenue for all distributing companies at a demand rate of $1.806/GJ per month. FGA suggested the matter could be easily corrected by directing 2004 refunds to all Rate 5 customers.
AP AP submitted that since the Rate 5 customers were billed at Rate 5 consistent with the approved forecast and that this was the same amount as shown in Table 5.1-2 of the Third Phase I Compliance Filing for Other Distributing Companies, there was no concern with respect to Rate 5 customers for 2003.
With respect to Rate 5 customers for 2004, AP acknowledged that the approved forecast in the Phase II Compliance Filing assumed that the Rate 5 customers would be charged the FSU demand rate and that the revenue generated from the application of Rate 5 would have exceeded the revenue on FSU rate by an amount of $33,000. AP proposed to deal with this amount as one of a number of differences between forecast and actual revenue as discussed in Section 4.1.1.5 of this Decision Report.
Views of the Board The Board considers that AP has correctly forecast the 2003 revenue for Rate 5 customers, and therefore there is no adjustment required. For 2004, the Board accepts the $33,000 calculation as reasonable. The Board has addressed the matter of this excess amount in Section 4.1.1.5 of this Decision Report.
4.1.1.2 Gas Alberta Forecast Revenue versus Actual Revenue FGA FGA submitted that AP’s billings on commodity rates to Gas Alberta for the first three month of 2003 generated revenue in excess of the revenue forecast prepared on a demand basis. The FGA invited the Board to vary the Decision to include a refund to Gas Alberta of all earnings above revenue requirements.
AP AP stated that the difference between the 2003 approved revenue forecast for Gas Alberta North and the actual 2003 revenues from Gas Alberta (including the refund directed by the Board)15
15 In Decision 2004-079, the Board noted that the actual billings to Gas Alberta for the period from January 1, 2003 to March 1, 2004 were on commodity rates. The Board also determined that for the period April 1, 2003 to February 29, 2004, it was appropriate that the demand rate for Gas Alberta North be set equal to the AG 2003 demand rate.
8 • EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines
was $115,000. AP proposed to deal with this amount as one of a number of differences between forecast and actual revenue as discussed in Section 4.1.1.5 of this Decision Report.
Views of the Board The Board accepts the $115,000 calculation as reasonable. The Board has addressed the matter of this excess amount in Section 4.1.1.5 of this Decision Report.
4.1.1.3 Town of Redwater Forecast Revenue versus Actual Revenue FGA FGA submitted that the billing determinants for the FSU rate did not incorporate the fact that the Town of Redwater (Redwater) would be leaving the system as of November 1, 2004 and therefore, FGA suggested that the cost of service study should be corrected to account for the loss of this customer with a resultant restatement of revenues and rates.
AP AP acknowledged that Redwater would be leaving the system as of November 1, 2004 and as a result, $8,000 of forecast revenue would be lost. AP proposed to deal with this amount as one of a number of differences between forecast and actual revenue as discussed in Section 4.1.1.5 of this Decision Report.
Views of the Board The Board accepts the $8,000 calculation as reasonable. The Board has addressed the matter of this deficiency amount in Section 4.1.1.5 of this Decision Report.
4.1.1.4 AltaGas Refund FGA FGA noted that AP and AltaGas entered into an agreement to make a retroactive adjustment to AltaGas rates from January 1, 2003 to the date when the final FSU rates were approved. FGA submitted that AP should be directed to incorporate the adjustments to AltaGas in its Compliance Filing to reflect this agreement.
AP With respect to the agreement between AP and AltaGas to retroactively adjust rates to AltaGas from January 1, 2003 to the date that the final FSU rates are approved, AP proposed to deal with this amount of $109,000 as one of a number of differences between forecast and actual revenue as discussed in Section 4.1.1.5 of this Decision Report.
Views of the Board The Board accepts the $109,000 calculation as reasonable. The Board has addressed this matter in Section 4.1.1.5 of this Decision Report.
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4.1.1.5 Summary of Revenue Adjustments AP AP submitted that FGA has essentially proposed that the Phase I revenue requirement approved by the Board in Decision 2003-100 and subsequent filings be varied with respect to all forecast versus actual revenue differences. AP provided a summary of the differences in revenue in the North resulting from changes resulting from forecast and actual revenue, as follows:
Table 1: North Forecast Revenue versus Actual Revenue Differences
($000)
Rate 5 33
Gas Alberta 115
Town of Redwater (8)
AltaGas Refund (109)
North Net Difference 31
AP noted that the Board did not approve a deferral account for transportation revenue in Decision 2003-100 and argued that there will always be differences between forecast and actual transportation revenue. AP did not propose to adjust its Compliance Filing for these differences.
Views of the Board In Phase I, the Board considered a forecast of revenue on interim rates using forecast billing demands and volumes based upon a forecast of effective dates when various rates would be applicable for billing to customers. Subsequent changes in timing and other contractual arrangements between AP and its customers caused variance to the revenue forecast. The Board considers that the differences listed above are the result of changes from reasonable assumptions approved in Phase I and the application of rates to actual billings on actual effective dates. The Board considers that each of the items listed above is a reasonable deviation from the forecast and does not require AP to account for these differences in a revised compliance filing.
4.1.2 Rate 5 Customer Refunds FGA FGA submitted that AP calculated a negligible refund for the Samson Band and a deficit for Redwater due to the fact that seasonal customers take the bulk of their gas during the winter months and far less in the summer months. Since the Board truncated the 2004 refund to the period March to October, the largest portion of the revenue collected by AP above the forecasted revenue requirement from Rate 5 customers would not be refunded to the customers.
FGA suggested that the Board clarify or vary this part of the Decision to refund all Rate 5 customers including Montana Band the whole amount that AP has earned above the forecasted 2004 revenue requirement required from Rate 5 customers including the winter months of January and February 2004.
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The Samson Band The Samson Band submitted that at no time had it advised AP that it was seeking new transportation services to replace the existing sales service. The Samson Band also noted that it was providing formal notice that it would not accept the discontinuation of the sales service under the existing ATCO System permit agreement.
AP AP submitted that the amount of the refund to the Samson Band will be $731.30 and the charge to Redwater will be $1,504.86. AP submitted that the calculation of these amounts was provided in Appendix D.16
AP submitted that the Samson Band had not indicated that they wished to move to transportation service. AP proposed to allow the Samson Band to remain on sales service after November 1, 2004.
AP did not support any additional refunds to Rate 5 customers since these customers had not yet notified AP of an intention to convert to transportation service.
Views of the Board In the Decision, the Board noted the FGA’s submission that the Samson Band was eligible for an adjustment to the actual cost of providing service and that the Federation managed its anticipated transition from sales to transportation service by providing maximum daily operating demands for the Samson Band to AP on September 24, 2003. The Board also noted that AP submitted that the Samson Band had not requested to convert their service to a demand rate, nor had any peak demand been established for this customer.17 Given this apparent conflicting evidence, the Board directed AP to provide a refund to the Samson Band for the period from March 1, 2004 to the date of commencement of final rates in 2004 for the reasons outlined in the Decision.
In light of the new evidence provided by the Samson Band with respect to its desire to remain on transportation service, the Board considers it appropriate to modify its Direction in the Decision to remove the obligation to provide a refund to the Samson Band. The Board notes that the Samson Band does have the opportunity to continue on sales service until April 30, 2005.
With respect to the Redwater deficit amount calculated by AP, the Board notes that in the Compliance Filing, AP only calculated the difference between sales service and transportation service costs for the period March to August 2004. The Board directs AP to update the calculation by including the months of September and October 2004 and to provide the revised charge or refund to Redwater.
The Board notes FGA’s request to vary the Decision to refund all Rate 5 customers the whole amount that AP has earned above the forecasted 2004 revenue requirement required from Rate 5 customers including the winter months of January and February 2004. The Board reiterates its finding in the Decision that unless a Rate 5 customer notified AP in a timely way of an intention to convert to transportation service and provide a reasonable demand number for it, there would
16 Attachment 3 in the Compliance Filing 17 Decision 2004-079, p.151
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be no reason for AP to have forecast that customer to have been on transportation rates for the test period.
4.1.3 Gas Alberta Refund FGA FGA submitted that it did not take issue with AP’s calculation of the Gas Alberta refund amount directed by the Board. However, FGA indicated that it was concerned with the truncation of the 2003 refund period by the removal of the three winter months.18 Therefore, the FGA invited the Board to vary this part of the Decision on its own initiative to rectify the situation.
AP AP calculated a refund amount $334,795.04 for Gas Alberta North in response to the Board Direction.19AP did not support making a refund to Gas Alberta for the period January to March 2003.
Views of the Board The Board notes that the FGA is making an additional request to have the Board vary its Directions in the Decision through the compliance filing process rather than through a Review and Variance process. Ordinarily, the Board would expect material submissions to change a direction or conclusion reached by the Board in the original decision to be conducted through the Review and Variance process. The Board has not been convinced that the circumstances of this particular request are appropriate to consider a variation of the Decision through the compliance filing process. The Board accepts the $334,795.04 calculation shown in Appendix D as reasonable.
4.1.4 North Deficiency FGA FGA submitted that the North deficiency shown in Appendix E20 was generated largely by customers other than Rate 5 and Gas Alberta, and therefore, in the event that the Board does not vary the Decision with respect to refunds to Rate 5 and Gas Alberta, the Board should not allow AP to charge Rate 5 and Gas Alberta the deficiency rider surcharge.
AP AP submitted that FGA provided no evidence on which to base its assertion that the North deficiency was “generated largely by customers other than Rate 5 and Gas Alberta”. AP submitted that the deficiency was the result of revenue requirements being greater than the sum of revenues collected on interim rates for 22 months and the proposed Phase II final rates for the remainder of 2004. Therefore, AP proposed that all customers including Rate 5 and Gas Alberta should be allocated a fair share of the North deficiency.
18 January, February and March 19 Calculation shown in Appendix D 20 Attachment 1 in the Compliance Filing
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Views of the Board The Board considers that all parties contributed to the deficiency in revenue resulting from the application of interim rates and proposed final rates in 2004 in the North. Therefore, the Board considers that AP has appropriately determined the deficiency rider for the period November and December 2004 for each class and that the deficiency rider will be applicable to all customers within the class.
4.1.5 Sales Service for Rate 5 Customers from November 1, 2004 to April 30, 2005 FGA FGA submitted that should AP apply Rate 5 on a go-forward basis, AP would generate revenue in excess of revenue requirement, which would be contrary to the Decision. FGA submitted that in order to avoid generating excess revenue, AP should be enjoined from applying Rate 5 on a go-forward basis to any FSU customer. FGA further submitted that should the Board vary the Decision in favor of AP and permit AP to charge Rate 5 on a go-forward basis, then the excess revenue must be included in the Compliance Filing forecast.
Abcom Abcom noted that AP proposed to extend the existing Rate 5 until April 30, 2005. Abcom submitted that it did not believe this extension would comply with the Decision. Abcom noted the Board’s determination was that the FSU demand rate would be just and reasonable for all utilities in the class and that the Board considered that the Rate 5 customers should receive FSU service on a demand rate basis as proposed by AP. Abcom noted that the Board directed AP to continue sales service until April 30, 2005, but the Board did not specify that Rate 5 should be continued. Abcom, therefore, suggested that the proper sales rate for the period in question (November 1, 2004 to April 30, 2005) for the Montana Band would be the FSU rate plus Rider F (Cost of Gas).
Abcom further submitted that, if the Board should determine that sales service should be provided under Rate 5, the base energy charge should be reduced from $0.275/GJ to $0.074/GJ and the fixed charge should be reduced from $275.00 to zero.
AP AP submitted that the Decision ordered a single transportation rate after November 1, 2004 for all Distributing Companies. AP noted that the Board also ordered, as a transition issue, that sales service be extended to April 30, 2005.
AP explained that the $0.074/GJ energy charge that the Montana Band referred to is the volume equivalent FSU rate assuming a 100% load factor. AP submitted that since Distributing Companies experience a 27% load factor, the energy charge of $0.275/GJ is equivalent to the FSU demand rate at the 27% load factor. AP proposed that Rate 5 would be an appropriate and fair sales rate for the transition period effective from November 1, 2004. AP argued that FSU is a transportation rate and not appropriate for sales service.
AP proposed that if the Montana Band or any other Rate 5 sales customer converts to transportation service prior to April 30, 2005, AP would refund those customers the difference between the Rate 5 charges (excluding Rider F) and the FSU transportation rate for the transition
EUB Decision 2004-096 (October 29, 2004 • 13 2004 GRA Phase II Compliance Filing ATCO Pipelines
period from November 1, 2004 until the earlier of April 30, 2005 or conversion to FSU. AP submitted that this proposal would provide time for the customers to convert to transportation service in an orderly basis, would provide the same result as Montana Band’s proposal21 and would address the concern expressed by FGA regarding over-recovery of revenue requirements as a result of a partial year sales rate.
Views of the Board In the Decision, the Board allowed a transition period on sales rates as an option for Rate 5 Distributing Company sales customers, for a six month period ending April 30, 2005. The evidence provided during the Phase II proceeding indicated that certain Rate 5 customers may not have been able to conclude their natural gas supply arrangements with energy service providers by November 1, 2004. Therefore, at the request of parties, the Board permitted the continuation of Rate 5 sales service until April 30, 2005. This transition period would allow the time required by parties to make alternative gas supply arrangements.
In approving the transition period, the Board was aware that continuation of sales service at Rate 5 during winter months would likely result in revenue being greater than at FSU rates. However, the Board considers this revenue to be one of many differences in actual revenue as compared to forecast revenue. The Board accepts AP’s proposal as reasonable, in respect of providing a refund of the difference between the sales rate and the transportation rate, to any Rate 5 sales customer converting to transportation service during the transition period.
4.2 South Issues 4.2.1 AltaGas South Billing Unit FGA FGA submitted that the billing determinants and annual revenues in the South were incorrect due to an exclusion of 0.75 TJ demand for AltaGas that was transferred from Gas Alberta to AltaGas on July 1, 2003. FGA submitted that AP was collecting revenue for transportation service to this tap and should have included the revenue in the Compliance Filing.
AP AP confirmed that the peak demand that FGA referred to was included in the Gas Alberta peak demand used to calculate the forecast revenue for 2003, and therefore there was no revenue difference for 2003. However, AP agreed that this peak demand was inadvertently omitted from the peak demand approved in the Decision and the Compliance Filing. AP calculated that the amount of surplus would be $17,758 and considered that due to the amount being insignificant, it could be dealt with in a future compliance filing dealing with remaining placeholders.
Views of the Board The Board agrees with AP that the amount of $17,758 will be surplus to the 2004 revenue requirement. The Board concurs with AP that the amount does not warrant a revision to the Compliance Filing at this time. The Board directs AP to deal with this amount in its next filing in respect of the finalization of any of the remaining placeholders.
21 Setting the sales rate as the FSU demand rate
14 • EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines
4.2.2 AP’s Proposed Treatment of South Surplus AP AP determined that the revenue from interim and final rates for 2004 would exceed the 2004 revenue requirements by the amount of $20,000.22 AP proposed to refund this surplus amount in a future compliance filing following a Board decision on the ATCO ITEK placeholder, which is expected in 2005.
Views of the Board The Board notes that no parties objected to AP’s proposal to deal with the South surplus amount of $20,000.
The Board directs AP to deal with this amount in its next filing in respect of the finalization of any of the remaining placeholders.
4.3 North and South Issues 4.3.1 UFG/Fuel Recovery from OPR Service IGCAA IGCAA submitted it would be essential that UFG/Fuel recovery from OPR customers should be based upon actual physical receipts of gas onto AP and not nominations. IGCAA submitted that there were several mechanisms that could be used to deal with this issue.
CAPP CAPP disagreed with IGCAA’s request that UFG/Fuel should only be charged on physical receipts. CAPP requested that the Board support the concept of UFG/Fuel as a system cost and dismiss IGCAA’s proposal with respect to UFG/Fuel allocation.
AP AP submitted that there is no direct link between nominations and physical flow and since OPR charges are based upon nominations, IGCAA’s proposal to recover UFG/Fuel on a physical flow basis from OPR customers cannot be achieved. AP explained that UFG/Fuel is currently charged to the Exchange Deferred Account (EDA) on the basis of physical flows; however, the recovery of the EDA costs is achieved through a charge on exchange nominations.
Views of the Board As noted in its letter dated October 1, 2004, the Board has accepted that the current North and South Rider D charges would be applied to transportation receipt services effective November 1, 2004 and that new Rider D charges would be in place for January 1, 2005. While the Board notes the comments of IGCAA with respect to this matter, for the period November 1 to December 31, 2004, the Board is prepared to accept AP’s proposal to recover UFG/Fuel through OPR service on the basis of nominations.
With respect to the issue raised by IGCAA, the Board considers that it is more appropriate to deal with this matter as part of the proceeding which will deal with the AP Rider D application
22 See Appendix F. Attachment 2 in the Compliance Filing
EUB Decision 2004-096 (October 29, 2004 • 15 2004 GRA Phase II Compliance Filing ATCO Pipelines
that the Board has directed to be filed by November 1, 2004 and which will result in new Rider D charges on January 1, 2005.
In addition to the requirements outlined by the Board in the Decision with respect to the November 1, 2004 Rider D application, the Board requests that AP and AG indicate whether they are proposing to shift implementation of future Rider D charges from a calendar year basis to a gas year basis.23
4.3.2 2005 Rates IGCAA IGCAA submitted that given the significant changes that have occurred regarding AP’s rate design, a 2005 GRA or approved settlement was essential and therefore, the Board should make it clear that AP’s rates and services were only approved to the end of 2004.
AP With respect to IGCAA’s submission that rates should be approved until the end of 2004, AP submitted that IGCAA provided no compelling evidence to require a GRA for the period starting January 1, 2005. AP submitted that the Board should establish the AP rates without restriction or term.
Views of the Board With respect to IGCAA’s submission that the Board should make it clear that AP’s rates and services are only approved to the end of 2004, the Board does not consider that such a Direction is required. The Board notes that it has the authority to require a review of utility rates at any time it considers appropriate.
4.3.3 Gas Alberta Metering Initiative FGA With respect to Gas Alberta’s initiative to purchase meters that serve its delivery stations, FGA requested clarification of the Decision. FGA stated that AP had not reduced its rate base to reflect a transfer of responsibility for the meters to Gas Alberta, nor had AP reduced its operating expenses to reflect that AP does not have to maintain the meters in the North. FGA submitted that, to make Gas Alberta’s service a consistent postage stamp service between the North and South, the Board, in its decision on compliance, must resolve the inconsistency between the level of service received by Gas Alberta in the North and South.
AP AP submitted that by using postage stamp rate methodology for customer classes, the rate to each customer would be identical; however, the rate would not generate revenue equal to the cost of serving any specific customer. AP submitted that this result applied to all customer classes. Therefore, AP suggested that no further clarification was required.
23 Effective November 1, 2005 to October 31, 2006
16 • EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines
Views of the Board The Board recognizes Gas Alberta’s position that it owns custody transfer meters at the connections to AP in the South, whereas AP owns the custody transfer meters at the connections to Gas Alberta in the North24, therefore causing some degree of inconsistency in the level of service provided between the North and South. However, the Board considers that its determination in the Decision was fair and reasonable in light of the postage stamp rate design for customer classes referred to in Section 5.4.1, Page 70 of the Decision.
5 COMPLIANCE WITH BOARD DIRECTIONS FROM OTHER PROCEEDINGS
This section deals with outstanding Directions from other proceedings that were included in the Compliance Filing and for which parties had comments.
Response to Board Directions in Decision 2004-078 (SCADA Project) CCA CCA expressed concern with the SCADA costs associated with Decision 2004-078. CCA observed that in Decision 2004-078, the Board found that there should be no addition to rate base for the SCADA project until 2004. However, CCA observed that there appeared to be additions to account 496 for both the North and South and requested that if these costs were related to assets discussed in Decision 2004-078, these costs should be removed from the cost of service study.
AP AP noted that it updated the Cost of Service Studies to take into account the SCADA Project per Decision 2004-078. AP confirmed that the SCADA additions in the Cost of Service Studies only included the additions that were approved in Decision 2003-100 and also confirmed that the assets referred to in Decision 2004-078 were not included in the rate base or customer rates in either the North or South Cost of Service Studies.
Views of the Board The Board accepts AP’s confirmation that the SCADA additions in the Cost of Service Studies only included the additions that were approved in Decision 2003-100 and that the assets referred to in Decision 2004-078 were not included in the rate base or customer rates in either the North or South Cost of Service Studies.
Response to Board’s July 30, 2004 Letter with Respect to Discontinuation of Rate Rider J The Board approved the discontinuation of the collection of Rate Rider “J” effective August 1, 2004 and directed AP to incorporate any remaining balance associated with the 2001/02 South EDA into the AP Phase II compliance filing process for recovery from producers.
24 In its Argument with respect to the AP Phase II proceeding, Gas Alberta noted that it intended to own the custody transfer meters in the North.
EUB Decision 2004-096 (October 29, 2004 • 17 2004 GRA Phase II Compliance Filing ATCO Pipelines
AP The Board stated its expectation25 that AP discuss with customers an approach to address any EDA balances outstanding at October 31, 2004. AP has indicated that it will include the balance resulting from Rate Rider “J” in these discussions.
Views of the Board The Board considers that AP has adequately indicated its intention to comply with this Board Direction.
6 SUMMARY OF BOARD DIRECTIONS
This section is provided for the convenience of readers. In the event of any difference between the Directions in this section and those in the main body of the Decision, the wording in the main body of the Decision shall prevail.
1. The Board directs that, within 30 days of issue of a Board decision that finalizes any of the remaining placeholder amounts as shown in Appendix G, AP shall file an application with the Board outlining the difference between the final amount approved in the decision and the placeholder amount. The application should also outline AP’s proposal for dealing with the over or under-recovery...... 2 2. With respect to the Redwater deficit amount calculated by AP, the Board notes that in the Compliance Filing, AP only calculated the difference between sales service and transportation service costs for the period March to August 2004. The Board directs AP to update the calculation by including the months of September and October 2004 and to provide the revised charge or refund to Redwater...... 11 3. The Board agrees with AP that the amount of $17,758 will be surplus to the 2004 revenue requirement. The Board concurs with AP that the amount does not warrant a revision to the Compliance Filing at this time. The Board directs AP to deal with this amount in its next filing in respect of the finalization of any of the remaining placeholders...... 14 4. The Board directs AP to deal with this amount in its next filing in respect of the finalization of any of the remaining placeholders...... 15
25 Decision 2004-079, p. 118
18 • EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines
7 ORDER
IT IS HERBY ORDERED THAT: (1) The Rate Schedules and Rates, Tolls and Charges included in the Rate Schedules attached as Appendix B of this Decision Report are hereby approved as fixed and final for ATCO Pipelines effective on and after November 1, 2004, in accordance with and subject to the provisions of this Decision Report. (2) The surcharges for the North shown in attached Appendix E26 are hereby approved for the period November 1, 2004 until December 31, 2004. (3) The Transportation Service Regulations shown in Appendix C are hereby approved for ATCO Pipelines effective November 1, 2004, in accordance with and subject to the provision of this Decision Report. (4) ATCO Pipelines shall comply with all Directions in this Decision Report.
Dated in Calgary, Alberta on October 29, 2004.
ALBERTA ENERGY AND UTILITIES BOARD
(original signed by)
C. Dahl Rees Presiding Member
(original signed by)
B. T. McManus, Q.C. Member
(original signed by)
M. W. Edwards Acting Member
26 Also shown in the last page of the Rate Schedules.
EUB Decision 2004-096 (October 29, 2004 • 19 2004 GRA Phase II Compliance Filing ATCO Pipelines
APPENDIX A – BOARD REVISED TRANSPORTATION SERVICE REGULATIONS AND FSU RATE SCHEDULE
AP Transportation Service Regulations
Suggested Changes to Wording (shown in blackline)
Section 1.1 Definitions
(yy) “Peak Design Demand” shall mean the peak one hour demand of a Distributing Company expressed on a twenty-four hour basis.
(jj) “Maximum Design Quantity” shall mean the maximum one hour energy requirements of a Distributing Company expressed in GJ.
(zz) “Peak Billing Demand” shall mean the peak four hour demand maximum consecutive four hour energy requirements of a Distributionng Company expressed on a twenty- four hour basis multiplied by six, in order to express the amount on a twenty-four basis
5.3 Customer who has selected firm service for a minimum contractual term, shall, upon expiration of the minimum term of the Agreement, have the option to reduce the Contract Demand, Nominated Demand, or Peak Billing Demand of the said Agreement, provided one (1) year’s prior written notice has been provided to ATCO Pipelines.
AP FSU Rate Schedule
Suggested Changes to Wording (shown in blackline)
B) (iv) Customer acknowledges that ATCO Pipelines is not obligated to design the Gas Pipeline System or to deliver in any one hour at the Point of Delivery, a quantity of Gas exceeding the Peak Maximum Design Demand Quantity.
(vi) The Billing Commencement Date shall be January 1 of each year. Twelve months in advance of the Billing Commencement Date, Customer shall advise ATCO Pipelines, for ATCO Pipelines’ approval, both the Customer’s Peak Billing Demand and Peak Maximum Design Demand Quantity at each Point of Delivery. Should such notice not be received by ATCO Pipelines, both the Peak Billing Demand and Peak Maximum Design Demand Quantity for the current year will be carried forward. Both the Peak Billing Demand and the Peak Design Demand will be expressed on a 24- hour basis.
EUB Decision 2004-096 (October 29, 2004) • 20 2004 GRA Phase II Compliance Filing ATCO Pipelines
APPENDIX B – RATE SCHEDULES
Appendix B - Rate Schedules
(Consists of 35 pages)
EUB Decision 2004-096 (October 29, 2004) • 21 2004 GRA Phase II Compliance Filing ATCO Pipelines
APPENDIX C – TRANSPORTATION SERVICE REGULATIONS
Appendix C - Transportation Servic
(Consists of 37 pages)
EUB Decision 2004-096 (October 29, 2004) • 22 2004 GRA Phase II Compliance Filing ATCO Pipelines
APPENDIX D– NORTH REFUNDS/CHARGES
Appendix D - North Refunds/Charges.xls
(Consists of 1 page)
EUB Decision 2004-096 (October 29, 2004 • 23 2004 GRA Phase II Compliance Filing ATCO Pipelines
APPENDIX E – NORTH SURCHARGES
Appendix E - North Surcharges.xls
(Consists of 5 pages)
EUB Decision 2004-096 (October 29, 2004) • 24 2004 GRA Phase II Compliance Filing ATCO Pipelines
APPENDIX F – TREATMENT OF SOUTH SURPLUS
Appendix F - Treatment of South S
(Consists of 5 pages)
EUB Decision 2004-096 (October 29, 2004) • 25 2004 GRA Phase II Compliance Filing ATCO Pipelines
APPENDIX G – REMAINING PLACEHOLDER ITEMS
ATCO PIPELINES PLACEHOLDERS ($000’s)
2003 2004
North South Total North South Total
ATCO I-TEK service fees to be benchmarked • Direct O&M 1,405 939 2,344 1,544 1,035 2,579 • Included in ATCO Group Charges 53 15 68 54 15 69
Muskeg River Pipeline 5,149 5,149 5,015 5,015
Placeholder Total27 6,607 954 7,561 6,613 1,050 7,663
Date Source: Schedule 6, AP 2003/2004 GRA – Phase I, July 23, 2004 Refiling
27 As noted in Sections 4.2.1 and 4.2.2 of this Decision Report, the Board directed AP to include surplus amounts of $17,758 and $20,000 respectively in its next filing in respect of the finalization of any of the remaining placeholders for the South.
EUB Decision 2004-096 (October 29, 2004) • 26 2004 GRA Phase II Compliance Filing ATCO Pipelines
APPENDIX H – REVISED SUMMARY OF BOARD DIRECTIONS
DECISION 2004-079
No. Direction Page Board Comment 1. The Board agrees with CCA that the FSD rate was not designed for space 9 Subject to heating loads. In order to confirm that AP’s industrial rates are future appropriate for all customers within the Industrial customer class, the compliance. Board directs AP to file evidence in its next GRA to identify the number of industrial customers and associated load where the predominant requirement for gas is for processing or manufacturing use, and the number of industrial customers and associated load where the primary requirement for gas is for space or water heating, but where the operation is for manufacturing, processing or another industrial use.
2. No evidence was presented to indicate a specific amount of peak demand 11 Subject to that would be attributable to the isolated systems; however, the Board future considers that the peak demand for isolated systems would be compliance. insignificant due to the small number of customers being served from the isolated segments. However, for greater clarity in the future, the Board directs AP in its next GRA to remove the peak demand amount for all customer/service classes on “isolated systems” from the peak demand allocator used to allocate general system costs.
3. Therefore the Board directs AP to reallocate its marketing expenses in its 15 Approved Compliance Filing based on actual throughput for 2002.
4. The Board considers that AP’s throughput allocation factor appears 16 Approved reasonable for the Customer Support function. In addition, as discussed in Section 7.7, the Board has also determined that it is appropriate for AP to use 2002 actual throughput in this situation. Therefore the Board directs AP to allocate Customer Support expenses in its Compliance Filing based on actual throughput for 2002.
5. In addition, in its next GRA, the Board directs AP to address the 19 Subject to reasonableness of revising the peak demand numbers of the delivery future service classes for the purposes of allocating Salt Cavern expenses. The compliance. Board considers that the peak demands associated with Distributing Companies and Industrial customers on isolated pipeline systems may not directly cause the requirements of the Salt Cavern peaking facility.
6. The Board considers that throughput associated with the various receipts 25 Approved and deliveries remains a reasonable proxy for allocating the UFG CTM costs. Therefore, the Board directs AP, in its Compliance Filing, to allocate 100% of the UFG CTM asset related and O&M related expenses to the five service classes based on actual 2002 throughput.
EUB Decision 2004-096 (October 29, 2004) • 27 2004 GRA Phase II Compliance Filing ATCO Pipelines
No. Direction Page Board Comment 7. The Board agrees with IGCAA that, to the extent that AP could establish 32 Subject to that certain ODC would be incurred to avoid adding pipeline facilities, the future Board would consider making those ODC general system costs. compliance. Therefore, the Board directs AP, in its next GRA, to provide further evidence with respect to pipeline facility costs that were avoided through ODC as the least cost alternative (LCA) and to provide a forecast of the associated ODC for the appropriate test years.
8. As noted in Section 7.1, Peak Demand for Cost Allocation and Rate 34 Approved Design, the Board has directed AP to remove the straddle plant demand from the Industrial class demand. Therefore, the Board considers it appropriate to treat the revenue associated with the SPD service in a similar fashion to non-standard revenue and allocate the revenue as an income credit to all service classes (before reallocation of OPR and OPD revenues and expenses) based on four-hour peak demand. The Board directs AP to allocate the revenue resulting from SPD service to all service classes based on a four-hour peak demand.
9. The Board directs AP to file in its next Phase II application a North and 35 Subject to South schedule similar in concept to the response to IGCAA-AP02-1 (a). future compliance. 10. Given the timing of this Decision and the follow-up Compliance Filing, 47 Subject to the Board does not believe that AP would have enough time to discuss future potential OPR and OPD services with its customers in order to establish compliance. stand alone OPR and OPD services for 2004. The Board is prepared to accept AP’s position that OPR and OPD services should not be stand alone services at this time. The Board directs AP to confer with its customers to determine whether stand alone OPR and OPD services are practical and cost effective and to address this matter in its next GRA.
11. In this case, the Board considers that it is reasonable to base the 48 Approved reallocation on actual historical usage. Therefore, the Board directs AP in the Compliance Filing to use 2002 actual exchange receipt nominations made by the Primary Service Classes to reallocate the income credits and expenses determined for the OPR service class.
12. In this case, the Board considers that it is reasonable to base the 49 Approved reallocation on actual historical usage. Therefore, the Board directs AP in the Compliance Filing to use 2002 actual other pipeline delivery nominations made by the Primary Service Classes to reallocate the income credits and expenses determined for the OPD service class. Section 7.7, 2002 Versus 2004 Data provides Board directions with respect to the 2002 actual other pipeline delivery data.
13. The Board directs AP to describe in the Compliance Filing its process for 49 Approved assigning a particular nomination (other pipeline receipt and other pipeline delivery) made by a given customer to one of the Primary Service Classes.
28 • EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines
No. Direction Page Board Comment 14. Accordingly, the Board directs AP to ensure in the Compliance Filing, 52 Approved that the rates are increased by no more than 25% for any customer class in both the North and the South above the rates that were in place as of January 1, 2003.
15. Given that the Board approved the rate relationships proposed by AP with 53 Approved respect to the FSR demand and OR rates and FSR demand and interruptible receipt transportation (ITR) rates, the Board recognizes that as AP’s shifts Net Revenue Requirements to/from the Producer Receipt service class, the FSR OR revenue and IRT revenue will be impacted. The Board directs AP to take this revenue impact into account when establishing the Net Revenue Requirements for the Producer Receipt service class.
16. At this time, the Board is of the view that the rate differential due to 54 Approved system differences between the North and the South is of a magnitude that would not permit the use of a province wide weighted average rate. Therefore the Board directs AP to submit separate North and South rates for each customer class in its Compliance Filing.
17. With respect to the Rate Schedules, the Board directs AP to file an 54 Approved in updated version of all schedules in the Compliance Filing based on Board accordance determinations in this Decision. with and subject to the provision noted in Decision 2004-096. 18. The Board agrees with FGA that AP should develop planning procedures 76 Subject to with the Distributing Companies that would satisfy the needs of both the future distributing companies and AP. Therefore the Board directs AP to discuss compliance. this matter further with the Distributing Companies and to file a proposal in its next GRA. It appears to the Board that the details on such a proposal could be included in AP’s BP&P.
19. Therefore, the Board directs AP to refile the rate schedule for Delivery 80 Approved Transportation Service to Other Pipelines (Rates OPDM and OPDC) as part of its Compliance Filing in such a way that the OPDM and OPDC services are clearly defined and that the service provisions and service requirements with respect to the other pipelines (NGTL, Alliance and MIPL/TransGas) are clearly distinguished for both OPDM and OPDC. The Board requests that unique aspects of the OPDM and OPDC services with respect to each connecting pipeline be clearly defined. The rate schedules should also clearly indicate the responsibility of the customer with respect to charges from the other connecting pipelines.
EUB Decision 2004-096 (October 29, 2004 • 29 2004 GRA Phase II Compliance Filing ATCO Pipelines
No. Direction Page Board Comment 20. As noted in Section 3.7, Reallocation of OPR and OPD Expenses and 81 Approved Revenues, the Board has determined that a fully cost based OPD service with stand alone rates would not be required at this time. At present, the Board is prepared to accept AP’s proposed methodology for establishing the OPDC rate. However the Board considers that the rate will have to be updated by taking into account the revisions to AP’s cost allocations as reflected in this Decision. Therefore the Board directs AP to recalculate the OPDC rate for the North and South as part of the Compliance Filing. The new OPDC rate should be established by using the same expense and revenue categories that AP used in its proposed methodology, but the values assigned or allocated to the three delivery service classes for these expense and revenue categories will have to be updated based on the Board’s revised allocation and assignment methodologies described in this Decision.
21. Therefore, the Board directs AP, in the Compliance Filing, to revise the 83 Approved SPD rate to the OPDC rate without deductions and to effect the required changes in the income credit allocation section of the rate design.
22. In respect of the CCA concern, until some evidence is provided that 84 Subject to demonstrates to what extent the monthly fee may present with the MAS future rate, a barrier to smaller customers use of the account, the Board does not compliance. consider the rate to be unreasonable. Therefore, the Board approves the MAS rate schedule as proposed by AP. However, the Board directs AP to file a market barrier analysis on the MAS rate when it applies for any future variance in the rate, which may be on a stand alone basis or as part of its next Phase II GRA.
23. The Board considers it appropriate for AP to apply for rate riders as 84 Approved required, separate and apart from this proceeding. However, for completeness, the Board directs AP to include the current rate rider schedules for both the North and South in the Compliance Filing.
24. With respect to the shift of UFG/Fuel recovery to receipt services, the 88 Subject to Board agrees with the CG that there is uncertainty with respect to how future sharing of the UFG/Fuel charge between gas buyers and sellers would compliance. occur. The Board directs AP to file an application by November 1, 2004 outlining its proposal for recovering UFG/Fuel (Rider D) from transmission transportation customers for implementation on January 1, 2005.
25. In the hearing, AP indicated that it would expect to make a decision in 88 Subject to summer 2004 on whether the data received from the UFG meters in the future South would be reliable enough to move to a physical basis for UFG or compliance. whether one more year would be required using the allocation method. AP indicated that results in the North would be two years behind the South results because the UFG meters were installed later. With respect to the South, the Board directs AP to file its plans for determining UFG on a physical basis as part of the November 1, 2004 application required by the Board above.
30 • EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines
No. Direction Page Board Comment 26. The Board notes that there does not appear to be any information on the 88 Subject to record outlining AG’s position with respect to recovering the distribution future portion of UFG from its distribution transportation customers. In addition, compliance. AP has not outlined its plans, if any, with respect to removing the requirement for the DERS DSP customers to take the residual impact of Rider D inaccuracies. Therefore, the Board directs AP to work with AG so that the November 1, 2004 application noted above also outlines AG’s proposed mechanism for recovering distribution UFG and the impact to the DERS DSP customers.
27. With respect to AP’s request to directly charge line heater fuel to 93 Subject to customers who desire their delivered gas to be heated, the Board notes future that no interveners provided comment on this issue. The current practice compliance. is to recover this fuel for customer specific facilities through Rider D. The Board notes that, in addition to customers that incur Rider D charges, DSP customers would also pay for such line heater fuel. While the Board supports the concept that customers should pay for costs they cause, in this situation, the Board does not consider that AP has provided sufficient information with regard to the scope of this proposal and the cost to measure the line heater fuel. Therefore, the Board is not prepared to grant approval at this time and directs AP to file evidence including a detailed cost/benefit analysis with respect to this matter in its next GRA.
28. The Board views that the item related to contract term will be an integral 96 Approved requirement of the revised schedule of rates approved in this Decision. Therefore, the Board directs AP, in its Compliance Filing, to include the issue of contract term, currently Section 2.3 of the BP&P, into the appropriate sections of its RS.
29. The Board also directs AP to file updated TSR in the Compliance Filing 96 Approved in based on Board determinations in this Decision. accordance with and subject to the provision noted in Decision 2004-096. 30. The Board also accepts AP’s evidence, as discussed below, that the 106 Approved average four-hour peak is in the range of eight percent higher than the average 24-hour demand on a peak day. Therefore, the Board directs AP, in its Compliance filing, to revise the billing peak to equal the system design peak as adjusted for use of a four-hour demand period, for all members of the Distribution Companies Deliveries service class, and to further reflect other changes determined by the Board for Gas Alberta and the OPR revised peak as set forth below.
EUB Decision 2004-096 (October 29, 2004 • 31 2004 GRA Phase II Compliance Filing ATCO Pipelines
No. Direction Page Board Comment 31. However, the Board is not satisfied that a comprehensive study and 106 Subject to adequate data was provided to fully support the peak demand future relationships provided in this Application. Therefore, the Board directs compliance. AP, in its next GRA, to file a comprehensive study with adequate data to support the peak demand relationships for all customer classes.
32. With respect to the inclusion of the deemed demand for straddle plant 108 Approved service with the peak demand for the North Industrial service class, the Board agrees with IGCAA that in principle, it was not appropriate. Even though AP proposed to allocate the SPD revenue to the Industrial service class, the Board does not consider it appropriate to increase the expenses allocated to the Industrial service class by including a deemed demand for straddle plant service if the straddle plants would not pay the resulting FSD demand rate. The Board notes that AP proposed to set the SPD rate equal to the OPDC rate less the impact of removing Salt Cavern expenses and Other Directly Allocated expenses. Therefore, the Board directs AP to reduce the Industrial four-hour peak demand by 53 TJ/day. Given this determination, the Board does not consider it appropriate to allocate the SPD revenue to the Industrial class directly. Therefore, the Board also directs AP to allocate the revenue resulting from SPD service to all service classes based on four-hour peak demand. The Board’s determination with respect to the SPD rate is discussed in Section 5.6.
33. The Board considers that the benefits of non-standard contracts can alter 112 Subject to over time, and agrees with Calgary and the CG that a COSS which future includes the non-standard contracts as a stand alone class of service is the compliance. only way to observe the specific impacts of these contracts on the system and on all customer groups. Therefore, the Board directs AP in its next GRA, to provide a COSS which isolates the impact of non-standard contracts by including them as a separate class of service. Further the Board directs that AP address the impact and differences in results in the COSS if the non-standard contracts were specifically included within the Industrial and Producer classes.
34. In order to maintain transparency with respect to the OPR deferral 116 Subject to account, the Board directs AP to include the most current actual monthly future balances and end-of-year forecast balances for the North and South on its compliance. website and to update the information on a monthly basis.
32 • EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines
No. Direction Page Board Comment 35. The Board considers that it may be more appropriate to establish a stand 116 Subject to alone process for dealing with the OPR deferral components and to future establish an OPR commodity rate that recovers all cost components in the compliance. deferral account. Therefore, the Board directs AP to file, as part of its next GRA, such a stand alone proposal so that parties can express their views. The Board is also interested in receiving parties’ submissions with respect to alternative mechanisms to adjust the OPR rate that would balance rate stability with larger deferral account balances. The Board notes that this concern may not be an issue if AP files evidence in its next GRA indicating that stand alone OPR services are practical and cost effective as discussed in Section 3.7, Reallocation of OPR and OPD Expenses and Revenues.
36. With respect to AP’s proposal to bring the year-end balance in the OPD 117 Subject to deferral accounts forward to a future test year and to allocate the balance future to customer classes based on four hour peak demand, the Board directs compliance. AP to allocate the balance based on delivery nominations to other pipelines consistent with the Board’s findings in Section 3.7, Reallocation of OPR and OPD Expenses and Revenues.
37. Although the administration process related to the OPD deferral account 118 Subject to was not discussed to any great extent in this proceeding, for the time future being, the Board directs AP to follow a process similar to the process compliance. approved for the OPR deferral account. In particular, the Board expects that AP will discuss the approach for recovering or crediting the end-of- year balance with its customers on an annual basis. Given that the OPD deferral account is only expected to be in place for two months in 2004 (November and December), the Board directs AP to include the 2004 balance in the 2005 OPD deferral account and to begin formal reporting to its customers by April 30, 2006 with subsequent reporting to the Board by June 30, 2006.
38. The Board also directs AP to file, as part of the Compliance Filing, its 118 Approved plans with respect to booking forecast and actual ODC expenses in the EDA and OPD deferral accounts for 2004. In addition, the Board directs AP to provide, as part of the Compliance Filing, its forecast of OPDC revenues for the period November 1, 2004 to December 31, 2004.
39. In addition, the Board directs AP to discuss with its customers an 118 Subject to approach for modifying the OPD deferral account components (OPDC future rate adjustment, Summer IT/OR rate adjustment or other measures) if the compliance. forecast balance as of December 31, 2005 is greater than $1 million.
40. In order to maintain transparency with respect to the OPD deferral 118 Subject to accounts, the Board directs AP to include the most current actual monthly future balances and end-of-year forecast balances for the North and South on its compliance. website and to update the information on a monthly basis.
EUB Decision 2004-096 (October 29, 2004 • 33 2004 GRA Phase II Compliance Filing ATCO Pipelines
No. Direction Page Board Comment 41. As with the OPR deferral account, the Board considers that it may be 118 Subject to more appropriate to establish a stand alone process for dealing with the future OPD deferral components and to establish a stand alone OPDC rate that is compliance. adjusted as such, in order to target a zero forecast balance in the account. Therefore, the Board directs AP to file, as part of its next GRA, such a stand alone proposal so that parties can express their views. The Board is also interested in receiving parties’ submissions with respect to alternative mechanisms to adjust the OPDC rate that would balance rate stability with larger deferral account balances. The Board notes that the above matter may not be an issue if AP files evidence in its next GRA indicating that stand alone OPD services are practical and cost effective as discussed in Section 3.7, Reallocation of OPR and OPD Expenses and Revenues.
42. Accordingly, the Board believes it appropriate that the Rate 5 customers 126 Approved. who have not notified AP that they have put in place alternative arrangements should continue to receive sales service for a period of six months from November 1, 2004, being the commencement of the 2004/2005 gas year and the projected date for implementation of new rates pursuant to this Decision. The Board therefore directs AP to provide, or put in place necessary arrangements with DERS or another service provider to continue to provide, sales service until April 30, 2005, to those Rate 5 customers that have not otherwise notified AP that other service arrangements have been secured.
43. Following consultation with stakeholders, the Board directs AP to file 129 Subject to with the Board, for information, the mechanism and application guidelines future it proposes to utilize to implement the firm receipt threshold in compliance. determining available FSR service, including support for the forecasted threshold levels and proposed implementation dates. The mechanism and forecasting methodology may be further reviewed by the Board at the next GRA or upon application by an interested party.
44. With respect to throughput data for the purposes of cost allocation, the 139 Approved Board considers it appropriate for AP to use the 2002 actual adjusted percentage data shown in Tables 20 and 21. This data excludes throughput associated with non-standard contracts. However, the Board is concerned that the throughput numbers that support derivation of the throughput percentages may not relate to other material filed in this proceeding and the Phase I proceeding. Therefore, AP is directed to reconcile the North throughput numbers for each service class to the receipts and deliveries shown on Attachment IGCAA-AP-17 (c) and to the throughput shown on Attachment AUMA-EDM-AP-7 (b) from the Phase I proceeding. AP is also directed to reconcile the South throughput numbers for each service class to the receipts and deliveries shown on Attachment IGCAA-AP-17 (c). The Board requests a full explanation of how the numbers relate to each other. The Board also directs AP to explain whether the actual 2002 throughput numbers it identified for the OPR and OPD service classes were physical flows or nominations (paper flows).
34 • EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines
No. Direction Page Board Comment 45. With respect to OPR nomination data for the purposes of cost and income 139 Approved credit allocation and OPR service reallocation, the Board directs AP to use the 2002 actual adjusted data shown in Tables 22 and 23. This data excludes nominations associated with non-standard contracts.
46. The Board notes that in Section 3.7, Reallocation of OPR and OPD 139 Approved Expenses and Revenues, the Board directed AP to use other pipeline delivery nominations for allocating OPDC revenue (income credit) and for reallocating expenses and revenues assigned or allocated to the OPD service class. Therefore, the Board directs AP to confirm in the Compliance Filing that the 2002 actual adjusted data shown in Table 24 does not include any delivery nominations associated with non-standard contracts and that the nominations for each service class are appropriate. If AP confirms this matter, the Board expects AP to use the data in Table 25 as directed in Section 3.7. If the data does include non-standard delivery nominations, the Board directs AP to adjust the data by excluding such nominations. With respect to the South, the Board also directs AP to ensure that the 2002 actual adjusted delivery nominations shown in Table 26 are appropriate for the service classes in order to respond to the directions of the Board in Section 3.7 with respect to this matter.
47. With respect to forecast 2004 OPR commodity revenue and 2004 OPDC 139 Approved revenue, the Board considers it appropriate to use forecast billing determinants (receipt nominations and delivery nominations respectively). However, as noted above, it appears that AP used 2002 actual delivery nominations for purposes of deriving the OPDC revenue. The Board notes that AP has filed ODC forecasts that would have been based on physical flows to NGTL. Therefore, in the Compliance Filing, the Board directs AP to either adjust this forecast physical flow data as required to establish a delivery nomination forecast for 2004 or to use 2002 actual other pipeline delivery nominations as a substitute for 2004 forecast numbers. The Board requests that AP provide an explanation supporting its position on this matter.
48. As indicated, the revenue forecast by AP for the 2003 and 2004 test years 150 Approved was determined on AP’s proposed demand rates for transportation service to utilities, including Gas Alberta. However, the actual billings to Gas Alberta for the period from January 1, 2003 to March 1, 2004 were on commodity rates, which produced a higher amount of revenue. The Board considers that AP’s billings on commodity rates generated revenue in excess of the revenue forecast prepared on a demand basis. Therefore, the excess non-forecast revenue should be refunded to Gas Alberta without any adjustment to other revenue forecasts or other rates to recover the refund. The Board directs AP to calculate the refund as part of the Compliance Filing based on the findings in this Decision.
EUB Decision 2004-096 (October 29, 2004 • 35 2004 GRA Phase II Compliance Filing ATCO Pipelines
No. Direction Page Board Comment 49. As indicated, the revenue forecast by AP for the 2003 and 2004 test years 151 This was determined on AP’s proposed demand rates for transportation service Direction to utilities, including Rate 5 customers. However, the actual billings to has been Samson Band and Redwater for the period from March 1, 2004 to the date modified in of commencement of final rates in 2004 will have been on commodity this Decision rates, which produced a higher amount of revenue. The Board considers Report. that AP’s billings on commodity rates generated revenue in excess of the revenue forecast prepared on a demand basis. Therefore, the excess non- forecast revenue should be refunded to Samson Band and Redwater without any adjustment to other revenue forecasts or other rates to recover the refund. The Board directs AP to calculate the refund as part of the Compliance Filing based on the findings in this Decision.
50. With respect to demand billing determinants in the refund period, the 152 This Board directs AP to use the maximum daily quantity shown for Samson Direction Band and Redwater in the FGA argument. has been modified in this Decision Report.
36 • EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines
APPENDIX I – CROSS REFERENCE BETWEEN ORIGINAL AND REVISED SUMMARY OF BOARD DIRECTIONS
DECISION 2004-079
Original Summary of Board Directions Revised Summary of Board Directions Direction Number – Page Direction Number – Page
#1 – page 4 Not Applicable #2 – page 9 #1 – page 9 #3 – page 11 #2 – page 11 #4 – page 15 #3 – page 15 #5 – page 16 #4 – page 16 #6 – page 19 #5 – page 19 #7 – page 25 #6 – page 26 #8 – page 32 #7 – page 32 #9 – page 34 #8 – page 34 #10 – page 35 #9 – page 35 #11 – page 47 #10 – page 47 #12 – page 48 #11 – page 48 #13 – page 49 #12 – page 49 #14 – page 49 #13 – page 49 #15 – page 52 #14 – page 52 #16 – page 53 #15 – page 53 #17 – page 54 #16 – page 54 #18 – page 54 #17 – page 54 #19 – page 76 #18 – page 76 #20 – page 80 #19 – page 80 #21 – page 81 #20 – page 81 #22 – page 83 #21 – page 83 #23 – page 84 #22 – page 84 #24 – page 84 #23 – page 84 #25 – page 96 #28 – page 96 #26 – page 96 #29 – page 96 #27 – page 122 Not applicable #28 – page 148 Not applicable #29 – page 150 #48 – page 150 #30 – page 151 #49 – page 151 #31 – page 152 #50 – page 152 #24 – page 88 #25 – page 88 #26 – page 88 #27 – page 93 #30 – page 106 #31 – page 106
EUB Decision 2004-096 (October 29, 2004) • 37 2004 GRA Phase II Compliance Filing ATCO Pipelines
Original Summary of Board Directions Revised Summary of Board Directions Direction Number – Page Direction Number – Page
#32 – page 108 #33 – page 112 #34 – page 116 #35 – page 116 #36 – page 117 #37 – page 118 #38 – page 118 #39 – page 118 #40 – page 118 #41 – page 118 #42 – page 126 #43 – page 129 #44 – page 139 #45 – page 139 #46 – page 139 #47 – page 139
38 • EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix B Page i
ATCO PIPELINES
RATE SCHEDULES INDEX Page General Conditions ...... 1
Transportation Rates
1) Standard Rates
Receipt Transportation Service from Producers (Rates FSR, FSRS, ITR)...... 4 Receipt Transportation Service from Other Pipelines (Rate OPR)...... 8 Delivery Transportation Service to Industrials (Rate FSD)...... 10 Delivery Transportation Service to Distributing Companies (Rate FSU) ...... 13 Delivery Transportation Service to Other Pipelines (Rate OPDC)...... 15 Delivery Transportation Service to Other Pipelines (Rate OPDM) ...... 17 Delivery Transportation Service to Straddle Plants (Rate SPD)...... 19 Market Account Service (Rate MAS)...... 21
2) Non-standard Rates...... 22
3) Closed Rates ...... 23 (Existing rates will expire as indicated below and will no longer be offered as new service to Customers.)
(a) Rates Currently in Use
(i) North Rate 5 - Sales to Other Distribution Companies (expires April 30, 2005)
(ii) South None
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4) Rate Riders
General Description and Usage of Rate Riders ...... 24 Rider “A” North (ATCO Gas and Pipelines Ltd.) Rider “A” - South (ATCO Gas and Pipelines Ltd.) Rider “B” - North (ATCO Gas and Pipelines Ltd.) Rider “B” - South (ATCO Gas and Pipelines Ltd.) Rider “D” - North and South (ATCO Pipelines) Rider “E” - North and South (ATCO Pipelines) Rider “F” - North and South (ATCO Pipelines) Rider “K” - North and South (ATCO Pipelines) (expired Oct. 31, 2004)
Rate Riders “A”, “B”, and “E”, are common to ATCO Pipelines and ATCO Gas and may be revised on a regular basis. Refer to www.atcopipelines.com for the latest versions.
5) Attachment “A”’ (Surcharge for the period November 1, 2004 through December 31, 2004 - North Only)
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ATCO PIPELINES
GENERAL CONDITIONS APPLYING TO RATE SCHEDULES
1. Approval of Alberta Energy and Utilities Board:
Changes in Rates from time to time are subject to approval by the Alberta Energy and Utilities Board for the Province of Alberta.
2. Other Charges:
i) Specific Facilities Conditions
The Rates do not include additional costs incurred by ATCO Pipelines and payable by Customer for Specific Facilities or costs relating to conditions requested by the Customer at a Point of Delivery or Point of Receipt that are outside the scope of ATCO Pipelines’ standard policies.
ii) Other Conditions
The Rates do not include additional costs incurred by ATCO Pipelines and payable by Customer for levels of service beyond that normally provided (i.e. after normal hours for responding to Gas off- specification situations, meter switching at stations, etc.).
3. Unaccounted For Gas and Fuel (Rider "D"):
Rate Rider “D” charges are applied to all Rates that receipt gas onto ATCO Pipelines’ Gas Pipeline System (FSR, FSRS, ITR, OPR).
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4. Settlement of Monthly Imbalance Quantity
ATCO Pipelines requires Customers to settle an imbalance quantity monthly for any imbalance quantities greater than 5% for either a pack or a draft of the Gas Pipeline System. Customers holding market account service must balance to 0% at all times.
Magnitude of Reasons for Imbalance Imbalance Settlement by Quantity Quantity ATCO Pipelines Price
Less than or equal Over deliveries Not Required n/a to 5% Under deliveries Not Required n/a
Greater than 5% Over deliveries Purchase 75% of the Average Daily AECO “C” prices for that Month
Greater than 5% Under deliveries Sale 130% of the average Daily AECO “C” prices for that Month.
Settlement of Imbalance Quantity Arising from Adjustments When the Customer’s account is put out of balance by actual adjustments, the Customer is required to bring the account into balance by providing 1/25 of the imbalance amount on a daily basis over a 25-day period commencing on the first day of the month.
5. Interzonal Account Transfers
North to South and South to North Account Transfers are suspended.
6. Non-Compliance / Unauthorized Services
Where ATCO Pipelines has advised Customer to reduce transportation service to the Nomination as requested by ATCO Pipelines and a subsequent Non-Compliance notice has been issued to Customer, the charge on the Non-Compliance Quantity shall be five (5) times the NGX/AECO Intra-Alberta previous gas day trading instrument daily high. Should this price not be available, the charge will be based upon the industry-recognized daily reference price for the previous day.
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7. Storage
Gas delivered from the Gas Pipeline System into a storage or peaking facility (i.e. Carbon storage and salt cavern peaking) and returned does not incur charges under these Rate Schedules.
8. Agreements
Separate Agreements are required for service in each of the North and South zones.
9. Other Pipeline Receipt (OPR) and Other Pipeline Delivery Commodity (OPDC)
OPR and OPDC are available under FSR, ITR, FSD, FSU, and MAS Agreements (i.e. separate Agreements are not required for service under OPR and OPDC).
10. Agreement Term
Please refer to specific Rate Schedules for information pertaining to Agreement term.
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ATCO PIPELINES RECEIPT TRANSPORTATION SERVICE FROM PRODUCERS Rates FSR, FSRS, ITR
A) General Description
ATCO Pipelines’ receipt transportation service is available to Customers who physically receipt Gas onto the Gas Pipeline System at an on-system Point of Receipt. The Gas is then allocated to Customer’s receipt account on ATCO Pipelines’ system and is available to transfer to other Customer Accounts. As selected by Customer and approved by ATCO Pipelines, the service may be Firm or Interruptible Service. Overrun is defined by monthly flows in excess of the Contract Demand at a Point of Receipt and is considered Interruptible Service.
Refer to ATCO Pipelines’ Transportation Service Regulations and Business Policies & Practices for more information pertaining to the administration of this Rate.
B) Receipt transportation service is available under an Agreement provided that:
(i) Customer is served by ATCO Pipelines’ Gas Pipeline System.
(ii) Customer has the contractual control of Gas flows at the Point(s) of Receipt.
(iii) Customer has executed an Agreement (FSR, FSRS, ITR) with ATCO Pipelines which is subject to the provisions of this Rate Schedule and incorporates ATCO Pipelines’ Transportation Service Regulations as amended from time to time and approved by the Alberta Energy and Utilities Board.
(iv) Rider “D” (Unaccounted for Gas and Fuel) is applied to all Gas physically received under this Rate Schedule.
(v) This Rate is not applicable to Gas receipted onto the Gas Pipeline System from Other Pipelines.
(vi) Customer acknowledges that ATCO Pipelines is not obligated to design the Gas Pipeline System or to receive, at the Point of Receipt in any one hour, a quantity of Gas in excess of 1/24 the Contract Demand.
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix B Page 5
(vii) A $0.024/GJ credit (Carseland Rebate) is available to Producers who declare to ATCO Pipelines that their south zone, on-system receipts are designated for transfer to the Agrium Carseland Customer Account. This rebate applies to south zone on-system receipts only and is limited to a maximum of the actual consumption at the Agrium Carseland complex.
(viii) FSR Term: The standard firm service Agreement (FSR) term is 1 year and may commence at any time provided additional facilities are not required for the service to commence. A Customer may elect to enter into an Agreement for a longer term to support an investment by ATCO Pipelines.
These Agreements will continue in effect after the Minimum Term Date as specified in the Agreement unless Customer has provided 12 months prior written notice to terminate the service or reduce the applicable Contract Demand. Where the Customer has provided such notice, the service will terminate, or the Contract Demand reduced, on the first day of the month 12 months following the date on which notice was received.
(ix) FSRS Term: Short Term Firm Service (FSRS) is available for a 5 month term from November 1 through March 31 and does not include automatic renewal rights. Customer must provide 12 months written notice in advance of the requested Billing Commencement Date for continuance of the service for the subsequent period. Should this notice not be received by ATCO Pipelines, Customer must apply for new service.
(x) ITR Term: Interruptible service Agreements (ITR) are available for 1 year terms and may commence at the beginning of any month. These services do not include automatic renewal rights. Customer should reapply for the service a minimum of 30 days prior to the requested Billing Commencement Date for the service.
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix B Page 6
C) Transportation service charges at each Point of Receipt (Refer to B(vii) of this Rate Schedule for a description of the application of the Carseland Rebate).
(i) Rate FSR: FIRM RECEIPT TRANSPORTATION SERVICE
(a) North zone
Demand charge: $2.593 per Month per GJ of Contract Demand Overrun charge (October 1 through May 31): $0.070 per GJ Overrun charge (June 1 through September 30): $0.255 per GJ
Plus: Rider “D”
Plus: A surcharge as per Attachment “A” of these Rate Schedules for the period November 1, 2004 through December 31, 2004.
(b) South zone
Demand charge: $2.813 per Month per GJ of Contract Demand
Overrun charge (October 1 through May 31): $0.078 per GJ Overrun charge (June 1 through September 30): $0.240 per GJ
Plus: Rider “D”
(ii) Rate FSRS: SHORT TERM FIRM RECEIPT TRANSPORTATION SERVICE
Available from November 1 through March 31 only.
(a) North zone
Demand charge: $2.137 per Month per GJ of Contract Demand Overrun charge: $0.070 per GJ
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix B Page 7
Plus: Rider “D”
Plus: A surcharge as per Attachment “A” of these Rate Schedules for the period November 1, 2004 through December 31, 2004.
(b) South zone
Demand charge: $2.357 per Month per GJ of Contract Demand Overrun charge: $0.078 per GJ
Plus: Rider “D”
(iii) Rate ITR: INTERRUPTIBLE RECEIPT TRANSPORTATION SERVICE
(a) North zone
Interruptible charge (October 1 through May 31): $0.070 per GJ
Interruptible charge (June 1 through September 30): $0.255 per GJ
Plus: Rider “D”
Plus: A surcharge as per Attachment “A” of these Rate Schedules for the period November 1, 2004 through December 31, 2004.
Minimum charge: $3,600 per year, payable in advance of service commencement.
(b) South zone
Interruptible charge (October 1 through May 31): $0.078 per GJ Interruptible charge (June 1 through September 30): $0.240 per GJ
Plus: Rider “D”
Minimum charge: $3,600 per year, payable in advance of service commencement.
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ATCO PIPELINES RECEIPT TRANSPORTATION SERVICE FROM OTHER PIPELINES Rate OPR
A) General Description
ATCO Pipelines’ receipt transportation service from Other Pipelines is available to Customers who receipt Gas from Other Pipelines onto the Gas Pipeline System. Upon receipt by ATCO Pipelines of Customer’s Nomination and subsequent approval by ATCO Pipelines, Customer’s Gas shall be allocated through ATCO Pipelines’ account on Other Pipelines (i.e. ATCO Pipelines’ NIT account on NGTL) to Customer’s Account on ATCO Pipelines’ system. Gas is then available to transfer to other Customer Accounts.
Refer to ATCO Pipelines’ Transportation Service Regulations and Business Policies & Practices for more information pertaining to the administration of this Rate.
B) Receipt transportation service from Other Pipelines is available provided that:
(i) Customer is served off ATCO Pipelines’ Gas Pipeline System.
(ii) Customer has the contractual control of Customer’s Gas flows on the Gas Pipeline System.
(iii) Customer has executed an Agreement with ATCO Pipelines which incorporates ATCO Pipelines’ Transportation Service Regulations as amended from time to time and approved by the Alberta Energy and Utilities Board. An Agreement specific to OPR service is not required.
(iv) Rider “D” (Unaccounted for Gas and Fuel) is applied to all Gas Nominated for receipt under this Rate.
(v) This Rate is applied to all Gas Nominated for receipt from Other Pipelines.
(vi) This Rate is not applicable to Gas received onto the Gas Pipeline System from on-system Point(s) of Receipt.
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C) Transportation service charges at Other Pipelines point(s) of receipt
Rate OPR: RECEIPT TRANSPORTATION SERVICE FROM OTHER PIPELINES
(a) North zone
Commodity Charge: $0.0140 per GJ
Plus: Rider “D”
Plus: A surcharge as per Attachment “A” of these Rate Schedules for the period November 1, 2004 through December 31, 2004.
(b) South zone
Commodity Charge: $0.0140 per GJ
Plus: Rider “D”
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ATCO PIPELINES DELIVERY TRANSPORTATION SERVICE TO INDUSTRIALS Rate FSD
A) General Description
ATCO Pipelines’ delivery transportation service is available to Customers who physically take Gas off of the Gas Pipeline System at an on-system Point of Delivery for an Industrial. The Gas is then allocated to Customer’s delivery account on ATCO Pipelines’ system and is available to transfer to other Customer Accounts. Term-differentiated Rates are available for Customers selecting a longer Minimum Term Date.
Refer to ATCO Pipelines’ Transportation Service Regulations and Business Policies & Practices for more information pertaining to the administration of this Rate.
B) Delivery transportation service is available under an Agreement provided that:
(i) Customer is served off ATCO Pipelines’ Gas Pipeline System.
(ii) Customer has the contractual control of Gas flows at the Point(s) of Delivery.
(iii) Customer has executed an Agreement (FSD) with ATCO Pipelines which is subject to the provisions of this Rate Schedule and incorporates ATCO Pipelines’ Transportation Service Regulations as amended from time to time and approved by the Alberta Energy and Utilities Board.
(iv) This Rate is not applicable to Gas delivered to Other Pipelines from the Gas Pipeline System.
(v) Customer acknowledges that ATCO Pipelines is not obligated to design the Gas Pipeline System or to deliver in any one hour at the Point of Delivery, a quantity of Gas in excess of 1/24 the Nominated Demand.
(vi) For an average daily flow in a Month that falls between 90% and 110% of the Nominated Demand (Billing Demand), the charge will be the demand charge under this Rate applied to the average daily flow in that Month plus the fixed charge.
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Should the average daily flow in a Month exceed 110% of the Nominated Demand, an Overrun Charge will be applied to the difference between the total flow in the Month and 110% of the Nominated Demand (Billing Demand) times the number of days in the Month. The charge will be the Overrun Charge plus the demand charge applied to 110% of the Nominated Demand plus the fixed charge.
Should the average daily flow in a Month be less than 90% of the Nominated Demand, the charge will be the demand charge applied to 90% of the Nominated Demand (Billing Demand) plus the fixed charge.
(vii) Applicable Rate Riders:
Municipal Franchise Fee (Rider "A") Municipal Tax Rider (Rider "B") Deemed Value of Natural Gas (Rider "E")
(viii) FSD Term: The standard firm service Agreement (FSD) term is 1 year and may commence at any time provided additional facilities are not required for the service to commence. A Customer may elect to enter into an Agreement for a longer term to support an investment by ATCO Pipelines.
These Agreements will continue in effect after the Minimum Term Date as specified in the Agreement unless Customer has provided 12 months prior written notice to terminate the service or reduce the applicable Nominated Demand. Where the Customer has provided such notice, the service will terminate, or the applicable Nominated Demand reduced, on the first day of the month 12 months following the date on which notice was received.
C) Transportation service charges at each Point of Delivery
Rate FSD: FIRM DELIVERY TRANSPORTATION SERVICE
(a) North zone
Fixed charge: $1,000.00 per Month at each Point of Delivery
Demand charge: 1 or 2 year Minimum Term: $2.114 per Month per GJ of Billing Demand
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3 or 4 year Minimum Term: $2.013 per Month per GJ of Billing Demand 5+ years Minimum Term: $1.912 per Month per GJ of Billing Demand
Overrun charge: $0.073 per GJ
Plus: A surcharge as per Attachment “A” of these Rate Schedules for the period November 1, 2004 through December 31, 2004.
(b) South Zone
Fixed charge: $1,000.00 per Month at each Point of Delivery
Demand charge:
1 or 2 year Minimum Term: $1.558 per Month per GJ of Billing Demand 3 or 4 year Minimum Term: $1.484 per Month per GJ of Billing Demand 5+ years Minimum Term: $1.410 per Month per GJ of Billing Demand
Overrun charge: $0.054 per GJ
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ATCO PIPELINES DELIVERY TRANSPORTATION SERVICE TO DISTRIBUTING COMPANIES Rate FSU
A) General Description
ATCO Pipelines’ delivery transportation service for Distributing Companies is available to Customers who physically deliver Gas off of the Gas Pipeline System at an on-system Point(s) of Delivery to a Distributing Company. The Gas is allocated to Customer’s delivery account on ATCO Pipelines’ system and is then available to transfer to other Customer Accounts. As selected by Customer and approved by ATCO Pipelines, the delivery transportation service for Distributing Companies is Firm Service.
Refer to ATCO Pipelines’ Transportation Service Regulations and Business Policies & Practices for more information pertaining to the administration of this Rate.
B) Delivery transportation service for Distributing Companies is available under an Agreement provided that:
(i) Customer is served off ATCO Pipelines’ Gas Pipeline System.
(ii) Customer has the contractual control of Gas flows at the Point(s) of Delivery.
(iii) Customer has executed an Agreement (FSU) with ATCO Pipelines which is subject to the provisions of this Rate Schedule and incorporates ATCO Pipelines’ Transportation Service Regulations as amended from time to time and approved by the Alberta Energy and Utilities Board.
(iv) Customer acknowledges that ATCO Pipelines is not obligated to design the Gas Pipeline System or to deliver in any one hour at the Point of Delivery, a quantity of Gas exceeding the Maximum Design Quantity.
(v) This Rate is not applicable to Gas delivered to Other Pipelines from the Gas Pipeline System.
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(vi) The Billing Commencement Date shall be January 1 of each year. Twelve months in advance of the Billing Commencement Date, Customer shall advise ATCO Pipelines, for ATCO Pipelines’ approval, both the Customer’s Peak Billing Demand and Maximum Design Quantity at each Point of Delivery. Should such notice not be received by ATCO Pipelines, both the Peak Billing Demand and Maximum Design Quantity for the current year will be carried forward.
C) Transportation service charges at each Point of Delivery
Rate FSU: FIRM DELIVERY SERVICE FOR DISTRIBUTING COMPANIES
(a) North zone
Demand charge: $2.258 per Month per GJ of Peak Billing Demand
Plus: A surcharge as per Attachment “A” of these Rate Schedules for the period November 1, 2004 through December 31, 2004.
(b) South zone
Demand charge: $1.827 per Month per GJ of Peak Billing Demand
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ATCO PIPELINES DELIVERY TRANSPORTATION SERVICE TO OTHER PIPELINES (COMMODITY) Rate OPDC
A) General Description
Other Pipelines Delivery commodity service (OPDC) is available to Customers who deliver Gas to Other Pipelines from the Gas Pipeline System. This service is currently available to deliver gas to NGTL, Alliance and MIPL/TransGas. Customers must hold transportation service at the point of delivery on the Other Pipeline except where ATCO Pipelines holds a transportation account (i.e. ATCO Pipelines’ NIT account on NGTL). In the latter case, Customer’s gas shall be allocated through ATCO Pipelines’ account on NGTL to the Customer’s account on NGTL. Refer to ATCO Pipelines’ Transportation Service Regulations and Business Policies & Practices for more information pertaining to the administration of this Rate.
B) Delivery transportation service to Other Pipelines is available provided that:
(i) Customer is served off ATCO Pipelines’ Gas Pipeline System.
(ii) Customer has the contractual control of Customer’s Gas flows on the Gas Pipeline System.
(iii) Customer must have executed an Agreement with ATCO Pipelines (i.e. an Agreement specific to OPDC service is not required).
(iv) The Agreement is subject to the provisions of this Rate Schedule and incorporates ATCO Pipelines’ Transportation Service Regulations as amended from time to time and approved by the Alberta Energy and Utilities Board.
(v) This Rate is not applicable to Gas delivered from the Gas Pipeline System to on-system Point(s) of Delivery.
(vi) As incremental delivery capacity in excess of the Nominated Demand becomes available on the Other Pipeline, Customers holding OPDM service will have first priority to the Customer’s pro- rated share of this excess capacity. If the excess capacity is still not fully utilized, the remaining capacity will be available to those Customers holding OPDC service on a “first come, first served” basis.
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C) Transportation service charges at Other Pipelines point(s) of delivery
Rate OPDC: DELIVERY TRANSPORTATION SERVICE TO OTHER PIPELINES (COMMODITY)
(a) North zone
Commodity Charge: $0.058 per GJ
Plus: A surcharge as per Attachment “A” of these Rate Schedules for the period November 1, 2004 through December 31, 2004.
(b) South zone
Commodity Charge: $0.050 per GJ
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ATCO PIPELINES DELIVERY TRANSPORTATION SERVICE TO OTHER PIPELINES (MUST-FLOW) Rate OPDM
A) General Description
Other Pipelines Delivery Must-Flow Service (OPDM), is available to Customers who deliver Gas to Other Pipelines from the Gas Pipeline System. This service is currently available for delivery to NGTL, Alliance and MIPL/TransGas. In all cases, Customer must hold transportation service at the point of delivery on the Other Pipeline. For clarity, deliveries to NGTL through OPDM service are accomplished through Customer’s receipt service on NGTL.
Refer to ATCO Pipelines’ Transportation Service Regulations and Business Policies & Practices for more information pertaining to the administration of this Rate.
B) Delivery transportation service to Other Pipelines is available provided that:
(i) Customer is served off ATCO Pipelines’ Gas Pipeline System.
(ii) Customer has the contractual control of Customer’s Gas flows on the Gas Pipeline System.
(iii) The Customer must execute an Agreement (OPDM) which is subject to the provisions of this Rate Schedule and incorporates ATCO Pipelines’ Transportation Service Regulations as amended from time to time and approved by the Alberta Energy and Utilities Board.
(iv) This Rate is not applicable to Gas delivered from the Gas Pipeline System to on-system Point(s) of Delivery.
(v) When the Gas Pipeline System is available to effect delivery of the Nominated Demand and such Nominated Demand is not fully utilized by Customer resulting in ATCO Pipelines’ costs to deliver gas to any Other Pipeline, Customer shall reimburse ATCO Pipelines those costs. These charges will be based on the current Month’s average Oversupply Delivery Cost multiplied by a quantity of Gas equal to the Nominated Demand less either the amount the Customer actually delivered to the Other Pipeline on that day, or the amount ATCO Pipelines delivered to any Other Pipeline as a result of Customer not delivering the Nominated Demand, whichever is lower.
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(vi) As incremental delivery capacity in excess of the Nominated Demand becomes available on the Other Pipeline, Customers holding OPDM service will have first priority to the Customer’s pro- rated share of this excess capacity through Overrun service.
(vii) Monthly OPDM terms may be approved at ATCO Pipelines’ sole discretion and are not automatically renewed. Customer must reapply for the service.
(viii) OPDM Term: The standard firm service Agreement (OPDM) term is 1 year and may commence at any time provided additional facilities are not required for the service to commence. A Customer may elect to enter into an Agreement for a longer term.
These Agreements will continue in effect after the Minimum Term Date as specified in the Agreement unless either ATCO Pipelines or Customer has provided 12 months prior written notice to terminate the service or reduce the Nominated Demand. The service will terminate, or the Nominated Demand reduce, on the first day of the month 12 months following the date on which notice was received by either party.
C) Transportation service charges at Other Pipelines point(s) of delivery
Rate OPDM: DELIVERY TRANSPORTATION SERVICE TO OTHER PIPELINES (MUST-FLOW)
(a) North zone
Demand charge: $0.00 per Month per GJ of Nominated Demand Overrun charge: $0.058 per GJ
Plus: A surcharge as per Attachment “A” of these Rate Schedules for the period November 1, 2004 through December 31, 2004.
(b) South zone
Demand charge: $0.00 per Month per GJ of Nominated Demand Overrun charge: $0.050 per GJ
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ATCO PIPELINES DELIVERY TRANSPORTATION SERVICE TO STRADDLE PLANTS Rate SPD
A) General Description
ATCO Pipelines’ delivery transportation service for straddle plants is available to Customers who physically take Gas off of the Gas Pipeline System at a Point(s) of Delivery to a straddle facility (liquid extraction plant). The Rate is applied to the total energy removed in the straddle plant. The determination of the total energy amount is further detailed in the Agreement.
Refer to ATCO Pipelines’ Transportation Service Regulations and Business Policies & Practices for more information pertaining to the administration of this Rate.
B) Delivery transportation service to straddle plants is available under an Agreement provided that:
(i) Customer is served off ATCO Pipelines’ Gas Pipeline System.
(ii) Customer has the contractual control of Gas flows at the Point(s) of Delivery.
(iii) Customer has executed an Agreement (SPD) with ATCO Pipelines which is subject to the provisions of this Rate Schedule and incorporates ATCO Pipelines’ Transportation Service Regulations as amended from time to time and approved by the Alberta Energy and Utilities Board.
(iv) SPD Term: The standard service Agreement (SPD) term is 1 year and may commence at any time provided additional facilities are not required for the service to commence. A Customer may elect to enter into an agreement for a longer term.
These Agreements will continue in effect after the Minimum Term Date as specified in the Agreement unless ATCO Pipelines or Customer has provided 12 months prior written notice to terminate or reduce the service. Where either party has provided such notice, service will terminate on the first day of the month 12 months following the date on which notice was received.
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C) Transportation service charges at the straddle plant Point(s) of Delivery
Rate SPD: DELIVERY TRANSPORTATION SERVICE TO STRADDLE PLANTS
(a) North zone
Fixed charge: $1,000.00 per Month per Point of Delivery Commodity Charge: $0.058 per GJ
Plus: A surcharge as per Attachment “A” of these Rate Schedules for the period November 1, 2004 through December 31, 2004.
(b) South zone (Not Required)
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ATCO PIPELINES TRANSPORTATION SERVICE MARKET ACCOUNT Rate MAS
A) General Description
ATCO Pipelines’ market account service is available to Customers who wish to transact Account Transfers on the Gas Pipeline System.
Refer to ATCO Pipelines’ Transportation Service Regulations and Business Policies & Practices for more information pertaining to the administration of this Rate.
B) Transportation service under a market account is available under an Agreement provided that:
(i) Customer is served off ATCO Pipelines’ Gas Pipeline System.
(ii) Customer has executed an Agreement (MAS) with ATCO Pipelines which is subject to the provisions of this Rate Schedule and incorporates ATCO Pipelines’ Transportation Service Regulations as amended from time to time and approved by the Alberta Energy and Utilities Board.
(iii) Customer’s market account transactions exclude physical receipts and deliveries on the Gas Pipeline System.
(iv) The Customer Account must be balanced to “zero” at all times.
(v) MAS Term: Market Account Agreements (MAS) are available for 1 year terms and may commence at the beginning of any month. These services do not include automatic renewal rights and Customer should reapply for the service a minimum of 30 days prior to the requested Billing Commencement Date for the service.
C) Transportation service charges
Rate MAS: TRANSPORTATION SERVICE FOR MARKET ACCOUNTS (a) North zone Fixed charge: $1,000.00 per Month (b) South zone Fixed charge: $1,000.00 per Month
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2. NON-STANDARD RATES
(a) General Description
Non-standard Rates are agreed to by Customer and ATCO Pipelines and must be approved by the Board.
(b) Current Approved Agreements
(i) North Agrium Fort Saskatchewan and Redwater ATCO Power Valleyview Devon Grizzly Bear Creek Dow Chemical Fort Saskatchewan Shell Fort Saskatchewan Sherritt Fort Saskatchewan TransGas FSD (to be replaced with OPDM)
(ii) South Calpine Calgary Energy Centre Dow Chemical Chain Lakes (Prentiss) EnCana Carseland
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3. CLOSED RATES
(a) RATES CURRENTLY IN USE (NORTH)
(i) ATCO PIPELINES NORTH RATE NO. 5 SALES TO OTHER DISTRIBUTING COMPANIES FOR THE PURPOSE OF RESALE
Available on an annual contract to other Distributing Companies purchasing their total requirements from ATCO Pipelines for resale to other Customers except for standby, peaking or emergency service. This service will terminate effective May 1, 2005.
CHARGES:
Fixed charge: $275.20 per Month
Energy charges: Base $0.275 per GJ Gas Cost Recovery Rate Rider "F"
Minimum Monthly Charge: $1000.00
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4. RATE RIDERS
General Description
Rider "A" - Municipal Franchise Fee (ATCO Gas and Pipelines Ltd.) Customers located within a Municipality are assessed a Franchise Fee which is collected in lieu of Property Taxes. The Franchise Method is based on one of two collection methods - Method A which is applied to gross revenues or Method C, which is applied to gross revenues plus Rider "E".
Rider "B" - Municipal Property Tax and Specific Costs (ATCO Gas and Pipelines Ltd.) Customers located within a Municipality are assessed a Property Tax which is applied to Gross Revenues including Gas Costs (Rider "F") and excluding Deemed Value (Rider "E").
Rider "D" - Unaccounted For Gas (ATCO Pipelines) Receipt Transportation Customers (FSR, FSRS, ITR, OPR) will be assessed a combined UFG and fuel gas charge at each Point of Receipt. The UFG and fuel will be collected "in-kind" and applied on the Customer Account.
Rider "E" - Deemed Value of Gas (ATCO Pipelines) As Gas Cost Recovery (Rider "F") is not applied to transportation customers, a Deemed Value of gas is determined. Customers are subject to Deemed Value (Rider "E") if they are located within a Municipality using the Rider "A" Municipal Fee calculation, Method "C".
Rider "F" - Gas Cost Recovery Rate (ATCO Pipelines) Cost of Gas provided to customers under a sales service rate unless otherwise specified by a specific contract.
Rider “K” - 2003/2004 EDA Deficit Recovery (ATCO Pipelines) Producer Receipt Transportation customers (Rates FSR, FSRS, ITR) will be assessed a charge to recover the 2003/04 South EDA Deficit in the South and the 2004 North EDA deficit in the North. This Rate Rider terminates October 31, 2004.
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ATCO GAS AND PIPELINES LTD. - NORTH RIDER “A” TO ALL RATES AND ANY OTHER RATES THERETO
All charges under the Rates, including any charges under other Riders, to Customers situated within the communities listed on this Rider “A” are subject to the addition of the percentage shown. The percentage shown is to be applied as an addition to the billings calculated under the Rates including charges as allowed under other Riders in effect.
Method A. - Applied to gross revenues. Method C. - Applied to gross revenues and Rider “E”.
Municipality % Method Municipality % Method Edmonton* 33.40 A Red Deer 17.00 A Hughenden 10.98 A Camrose 15.00 A Hythe 8.70 C Fort McMurray 8.70 C Innisfree 17.50 A Grande Prairie 34.75 A Irma 5.26 C Lloydminster 7.00 C Itaska 12.00 A Spruce Grove 8.26 C Jasper 5.25 C St. Albert 5.26 C Kitscoty 5.25 C Wetaskiwin 8.27 C Lacombe 22.00 A Alberta Beach 10.61 A Lamont 35.00 A Alix 6.75 C Lavoy 5.25 C Amisk 9.10 A Legal 5.26 C Andrew 9.00 C Lougheed 16.67 A Bashaw 15.00 A Mannville 5.26 C Beaverlodge 8.70 C Mayerthorpe 9.42 A Bentley 0.00 A McLennan 6.25 C Berwyn 7.25 C Millet 20.00 A Bittern Lake 17.68 A Minburn 15.00 A Blackfalds 19.12 A Mirror 12.60 A Bon Accord 8.70 C Mundare 20.00 A Breton 12.47 A Nampa 16.84 A Bruderheim 10.00 A Onoway 5.00 A Caroline 5.26 C Oyen 8.70 C Chipman 5.26 C Peace River 7.25 C Clive 16.17 A Point Alison 5.26 C Clyde 9.47 A Ponoka 17.00 A Cold Lake 5.26 C Provost 11.00 A Consort 22.00 A Rimbey 24.00 A Coronation 10.05 A Rocky Mtn. House 5.26 C Czar 11.84 A Rycroft 5.25 C Donnelly 5.25 C Ryley 5.00 A Drayton Valley 6.26 C Sangudo 9.25 A Eaglesham 5.26 C Seba Beach 6.00 C Eckville 24.00 A Sexsmith 5.25 C Edgerton 15.00 A Sherwood Park 6.00 C Edson 5.26 C Silver Beach 5.26 C Entwistle 17.32 A Slave Lake 5.26 C Fairview 21.63 A Spirit River 24.00 A Falher 15.00 A Stony Plain 17.00 A Fox Creek 12.93 A Swan Hills 8.16 A Gibbons 8.70 C Sylvan Lake 20.00 A Girouxville 20.00 A Thorsby 11.69 A Golden Days 25.00 A Tofield 10.00 A Grand Centre 3.00 C Vegreville 8.11 C Grimshaw 28.00 A Vermilion 15.00 A Hardisty 5.26 C Veteran 9.73 A Hines Creek 5.25 C Viking 21.51 A Hinton*** 8.00 A Warburg 8.83 A Holden 5.25 C Whitecourt** 5.26 C
* Includes a $408, 333 maximum annual allowable assessment (Max) on any individual metered account. ** The deemed value of natural gas is applied only to Customers using less than 300,000 GJs per year *** Includes a $10, 000 maximum annual allowable assessment (Max) on any individual metered account.
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ATCO GAS AND PIPELINES LTD. - SOUTH RIDER “A” TO ALL RATES AND ANY OTHER RIDER THERETO
All charges under the Rates, including any charges under other Riders, to Customers situated within the communities listed on this Rider “A” are subject to the addition of the percentage shown. The percentage shown is to be applied as an addition to the billings calculated under the Rates including charges as allowed under other Riders in effect. Method A. - Applied to gross revenues, Rider “G” and the Market Value portion of Rider “H”. Method C. - Applied to gross revenues and Rider “E”. Municipality % Method Municipality % Method Municipality % Method Calgary 11.11 C Claresholm 5.25 C Lomond 5.26 C Lethbridge 32.30 A Coaldale 11.30 A Longview 16.00 A Acme 20.00 A Coalhurst 12.44 A Magrath 11.18 A Airdrie 7.50 C Cochrane 5.26 C Milk River 5.26 C Banff 5.25 C Coutts 5.26 C Nanton 5.25 C Banff Park 5.25 C Cowley 13.79 A Nobleford 5.26 C Barnwell 13.00 A Cremona 5.26 C Okotoks 5.25 C Barons 14.97 A Crossfield 11.23 A Olds 6.00 C Bassano 5.26 C Crowsnest Pass 5.26 C Penhold 5.26 C Beiseker 11.18 A Delburne 5.26 C Picture Butte 5.26 C Big Valley 5.26 C Didsbury 5.26 C Raymond 11.18 A Black Diamond 14.00 A Duchess 12.67 A Rockyford 5.26 C Bow Island 10.50 A Elnora 16.00 A Rosemary 14.78 A Bowden 5.26 C Foremost 21.0 A Standard 11.34 A Brooks 5.25 C Fort Macleod 12.50 A Stavely 11.18 A Burdett 11.18 A Glenwood 5.26 C Stirling 11.18 A Canmore 22.10 A Granum 5.25 C Strathmore 11.18 A Carbon 15.07 A High River 5.26 C Taber* 5.26 C Cardston 5.26 C Hill Spring 21.52 A Trochu 5.26 C Carmangay 15.97 A Hussar 13.74 A Turner Valley 10.00 A Carstairs 5.26 C Innisfail 5.26 C Vauxhall 5.26 C Champion 15.01 A Irricana 11.18 A Vulcan 7.00 C Linden 5.26 C
* Includes a $75,000 maximum annual allowable assessment on any individual metered account.
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ATCO GAS AND PIPELINES LTD. - NORTH RIDER “B” TO ALL RATES AND ANY OTHER RIDERS THERETO
This Rider is applicable to Customers resident in municipalities that receive a property tax under the Municipal Government Act or receive payment for specific costs which are not generally incurred by the Company. This Rider is the estimated percentage of gross revenue required to provide for the tax payable or specific cost incurred each year. To the extent that this percentage may be more or less than that required to pay the tax or specific cost, the percentage of gross revenue provided in the Rider will be adjusted on the 1st of February each year.
The percentage is to be applied as an addition to the billings calculated under the Rates including charges as allowed under other Riders in effect with respect to the following municipalities:
Fort Saskatchewan Onoway Wabamun Mundare Wembley Falher Stony Plain Indian Reserve Griouxville Paul Band Indian Reserve Golden Days Fort McMurray No. 468 Warburg First Nation Band Ryley Jarvis Bay Ponoka Norglenwold Millett Argentia Beach Stoney Plain Lakeview Provost Hinton Itaska Beach Sylvan Lake Viking Breton Bashaw Bentley Vermillion Blackfalds Edgerton Bruderheim Nampa Tofield Camrose Lamont Minburn Clive Lacombe
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ATCO GAS AND PIPELINES LTD. - SOUTH RIDER “B” TO ALL RATES AND ANY OTHER RIDERS THERETO
This Rider is applicable to Customers resident in municipalities that receive a property tax under the Municipal Government Act or receive payment for specific costs which are not generally incurred by the Company. This Rider is the estimated percentage of gross revenue required to provide for the tax payable or specific cost incurred each year. To the extent that this percentage may be more or less than that required to pay the tax or specific cost, the percentage of gross revenue provided in the Rider will be adjusted on the 1st of February each year.
The percentage is to be applied as an addition to the billings calculated under the Rates including charges as allowed under other Riders in effect with respect to the following municipalities:
Banff Siksika Nation Bow Island Foremost Rosemary Turner Valley Canmore Elnora
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ATCO PIPELINES NORTH AND SOUTH RIDER “D” UNACCOUNTED FOR GAS AND FUEL GAS
All Customers receipting Gas onto the Gas Pipeline System (FSR, FSRS, ITR, OPR) will be assessed a combined UFG and Fuel Gas charge as per the Rate Schedules. The UFG and Fuel Gas assessment will be made up “in-kind” from each Customer Account.
UFG and Fuel Rate for the period November 1, 2004 through December 31, 2004:
North 0.691% South 0.190%
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ATCO PIPELINES NORTH AND SOUTH RIDER "E" TO ALL TRANSPORTATION SERVICE RATES FOR THE DETERMINATION OF THE "DEEMED VALUE OF NATURAL GAS" FOR CALCULATION OF MUNICIPAL FRANCHISE FEE PAYABLE
In the absence of gas costs on a Customer’s bill, a “deemed value of natural gas” will be applied to the energy delivered to transportation service Customers in the determination of municipal franchise fee payable by transportation service Customers in municipalities that have agreed to accept payment of a percentage of gross revenues of the special franchise pursuant to Section 360 of the Municipal Government Act.
For both North and South Transportation Service Rates, the “Deemed Value”, is an amount equal to the Default Service Providers (DSPs) Gas Cost Flow-through Rate which currently is Direct Energy Regulated Services Rider “F”. Please refer to www.DirectEnergyRegulatedServices.com or call 1-866-420-3174 for the current value.
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ATCO PIPELINES NORTH AND SOUTH RIDER "F" TO ALL SALES SERVICE RATES FOR THE RECOVERY OF GAS COSTS
To be applied to the energy sold to Rate 5 sales service for the period November 1, 2004 through April 30, 2005.
The Gas Cost Recovery Rate is an amount equal to the Default Service Providers (DSPs) Gas Cost Flow-through Rate which currently is Direct Energy Regulated Services Rider “F”. Please refer to www.DirectEnergyRegulatedServices.com or call 1-866-420-3174 for the current value.
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ATCO PIPELINES NORTH AND SOUTH RIDER “K” TO ALL PRODUCER (ON-SYSTEM) RECEIPTS FOR 2003 AND 2004 EXCHANGE DEFERRED ACCOUNT DEFICITS
To be applied on all Producer (On-System) volumes received by the Company to recover the estimated 2003 and 2004 South Exchange Deferred Account Deficits for the South and the 2004 North Exchange Deferred Account Deficit for the North. This Rider will remain in effect until October 31, 2004. In the North, this rider will not be applied on:
• FSR, Overrun and Interruptible receipts that originate on isolated systems; • FSR, Overrun and Interruptible receipts that originate on restricted systems that are nominated to NGTL under the shipper’s own name up to a maximum of that month’s receipts.
Commodity Rate:
Variable North $0.009 per GJ South $0.036 per GJ
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5. ATTACHMENT A
NORTH SURCHARGES
Surcharges will be applied to the North rates listed below for the period November 1, 2004 to December 31, 2004.
Rate Rate Description Rate Type Surcharge FSR Firm Receipt Demand $0.374 per Month per GJ of Contract Demand Overrun $0.0101 per GJ FSRS Firm Short Term Receipt Demand $0.307 per Month per GJ of Contract Demand Overrun $0.0101 per GJ ITR Interruptible Receipt Interruptible $0.0101 per GJ OPR Receipt from Other Pipelines $0.002 per GJ FSD Firm Delivery - Industrials 1 or 2 year $0.305 per Month per GJ of Billing Demand 3 or 4 year $0.290 per Month per GJ of Billing Demand 5 year & $0.276 per Month greater per GJ of Billing Demand Overrun $0.0105 per GJ FSU Firm Delivery - Distributing $0.325 per Month Companies Demand per GJ of Peak Billing Demand OPDC Delivery to Other Pipelines Commodity $0.008 per GJ (Commodity) OPDM Delivery to Other Pipelines (Must Overrun $0.008 per GJ Flow) SPD Straddle Plant Commodity $0.008 per GJ 5 Sales to Distributing Companies Commodity $0.040 per GJ
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ATCO PIPELINES
TRANSPORTATION SERVICE REGULATIONS
INDEX
ARTICLE PAGE
1. INTRODUCTION 1 1.1 Definitions
2. GENERAL 9
2.1 Regulations Prevail 9 2.2 Requests for Service 9 2.3 Applicable Rate and Service Agreement 9 2.4 Agency 10 2.5 Title or Interest in the Gas 11 2.6 Facilities, Rights-of-Way and Access to Facilities 12
3. QUALITY OF GAS 14
4. MEASUREMENT 16
5. QUANTITY OF GAS 18
6. BALANCING OF CUSTOMER ACCOUNT 20
7. CURTAILMENT 21
8. RECEIPT AND DELIVERY PRESSURE 22
9. GAS LOST, UNACCOUNTED-FOR-GAS, AND FUEL GAS 23
10. RATES AND OTHER CHARGES 24
11. BILLINGS AND PAYMENTS 25
12. FORCE MAJEURE 27
13. TERMINATION ON DEFAULT 29
14. INDEMNITY 31
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15. NOTICES 32
16. ALLOCATIONS 33
17. MISCELLANEOUS 34
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ARTICLE 1 - INTRODUCTION
These Transportation Service Regulations have been approved by the Alberta Energy and Utilities Board (hereinafter referred to as "the Board") and may not be changed without the approval of the Board. Notice of any application to change these Regulations will be given in such manner as the Board from time to time directs.
These Transportation Service Regulations are common to ATCO Pipelines North and South Zones and form part of the Rate Schedules and apply to ATCO Pipelines and to every Customer supplied with Gas transportation service under Agreements, except as may be varied by Agreement and approved by the Board. ATCO Pipelines’ Business Policies and Practices provide a more detailed description of the application of the Transportation Service Regulations and Rate Schedules.
In the event that either the Customer or ATCO Pipelines are concerned that the strict application of any of these terms and conditions will cause particular hardship or inconvenience to such party, either may apply to the Board for modification of such terms and conditions provided that such modification will not result in the Customer receiving service under terms which are unjustly discriminatory or unduly preferential.
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1.1 Definitions
The following words or terms when used in these Transportation Service Regulations, the Rate Schedules, ATCO Pipelines’ Business Policies & Practices, or in an application, contract or Agreement for Gas service shall, unless the context otherwise requires, have the meanings given below:
(a) “Account Transfer” means the deemed delivery of quantities of Gas to, and deemed receipt of quantities of Gas from, one Customer Account and another Customer Account.
(b) “Act” means the Gas Utilities Act of the Province of Alberta, as amended from time to time and any legislative enactment in substitution or replacement thereof and, without limitation, any other applicable governmental regulation or order or direction of the Board.
(c) “Actual Variance” means the difference between the previous Month Actual and the previous month estimated Cumulative Imbalance Quantity.
(d) “Agent” mean a person, firm, partnership, corporation or organization who acts on behalf of the Customer as specified in Article 2 hereof.
(e) "Agreement" means the Gas transportation Agreement between ATCO Pipelines and Customer and includes all Schedules attached thereto and the Regulations.
(f) “Alliance” means the Alliance Pipeline system, or its successor.
(g) "Allocation Method" means the procedure used to assign portions of the Gas flows at a Point of Receipt or Point of Delivery to the various Customer Agreements and Rate Schedules.
(h) “Application for Service” means the Customer application described in Section 2.2, Request for Service.
(i) "Billing Commencement Date" means the commencement date for invoicing the tariffs and charges as set forth in Article 10; provided
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however that the Billing Commencement Date shall be adjusted by ATCO Pipelines if ATCO Pipelines is unable to commence the receipt or delivery of Gas under the Agreement on such date.
(j) “Billing Demand” means the maximum Industrial Gas flow in any twenty- four (24) hour period during the month subject to a minimum amount of 90% of the Nominated Demand and a maximum amount of 110% of the Nominated Demand.
(k) “Board” means the Alberta Energy and Utilities Board.
(l) “Business Policies & Practices” or “BP&P” means those general business policies and practices of ATCO Pipelines, which are filed for acknowledgement with the Board from time to time, and which apply to transportation service provided by ATCO Pipelines.
(m) "Common Stream Operator" means the operator of a facility at a Point of Receipt who, or which: (i) provides ATCO Pipelines with estimated quantities of Gas; (ii) provides ATCO Pipelines with the allocation of estimated, or actual, quantities of Gas to each Customer Account receiving Gas; (iii) accepts or rejects Nominations issued by ATCO Pipelines; (iv) implements, or coordinates the implementation, of the intended flow change specified in the Nomination; (v) acts on behalf of other upstream parties who deliver Gas to the Gas Pipeline System.
(n) “Commodity Charge” shall mean a charge which is based on throughput.
(o) "Contract Demand" means the maximum quantity of Gas in a Day that ATCO Pipelines shall be obligated to receive at the Point of Receipt, as specified in the Agreement.
(p) "cubic metre of Gas" or "m3" means the quantity of Gas which at a temperature of fifteen degrees Celsius (15oC) and at a pressure of one
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hundred one and three hundred twenty-five one-thousandths (101.325) kPa absolute occupies one (1) cubic metre.
(q) “Cumulative Imbalance Quantity” means the accumulated sum of the Daily Imbalance Quantity and prior period adjustments when applicable for each Day in the current Month.
(r) “Curtailment” shall have the meaning described in Article 7, Curtailment.
(s) "Customer" means a person, firm, partnership, corporation or organization who or which uses ATCO Pipelines' Gas transportation services.
(t) "Customer Account" means the record(s), as maintained by ATCO Pipelines, of the aggregate of Customer’s receipt and delivery quantities of Gas, inclusive of adjustments for Unaccounted For Gas, Fuel Gas, and Actual Variance.
(u) "Daily Imbalance Quantity" means the difference, each Day, between the total energy (GJ) contained in the Gas which was received by a Customer Account in such Day, and the total energy (GJ) contained in the Gas which was delivered from that Customer Account in such Day, inclusive of adjustments for Unaccounted For Gas, Fuel Gas, previous month closing imbalance, and Actual Variance. The Daily Imbalance Quantity may be qualified as “Estimated” when some, or all, estimated data are used in the calculation, or “Actual” when only actual data are used in the calculation.
(v) "Day" means a period of twenty-four (24) consecutive hours, beginning at eight hours (08:00), Mountain Standard Time.
(w) “Distributing Companies” means those parties whose function is to receive gas from ATCO Pipelines and redistribute such gas to their residential and commercial customers.
(x) “Exchange” means the mechanism by which ATCO Pipelines delivers to Customer, quantities of Gas destined to an Other Pipeline by exchange with Gas sourced from the Other Pipeline, subject to conditions set out in the Rate Schedules.
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(y) "Firm Service" means service under an Agreement to which Customer anticipates no curtailment except for Force Majeure, subject to conditions set out in the Rate Schedules.
(z) “Fuel Gas” means Customer’s share of ATCO Pipelines' transmission compressor fuel, as specified in Article 9 hereof.
(aa) "Gas" means all natural gas both before and after it has been subjected to any treatment or process by absorption, purification, scrubbing or otherwise, and includes all fluid hydrocarbons.
(bb) "Gas Pipeline System" means all those facilities, including the Specific Facilities, owned or used by ATCO Pipelines in the receipt, delivery, transportation, measurement and testing of Gas.
(cc) "GJ" means gigajoules or one billion (1 000 000 000) joules.
(dd) "Gross Heating Value" means the number of megajoules obtained from the combustion of a cubic metre of Gas at a temperature of fifteen degrees Celsius (15oC), with the Gas free of water vapor, and at a pressure of one hundred one and three hundred twenty-five one- thousandths (101.325) kPa absolute and with the products of combustion cooled to the initial temperature of the Gas and the water formed by the combustion condensed to the liquid state.
(ee) "Industrial” means a party whose predominant requirement for Gas is for process or manufacturing use, or whose primary requirement is for space and water heating, but where the operation is one of manufacturing or processing.
(ff) "Interruptible Service" means service under an Agreement to which Customer anticipates and permits interruption on short notice at the discretion of ATCO Pipelines, subject to conditions set out in the Rate Schedules.
(gg) “J” means joule.
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(hh) "kPa" means kilopascals of gauge pressure unless otherwise specified.
(ii) "Maximum Contract Pressure" shall have the meaning ascribed thereto in Article 8.
(jj) "Maximum Design Quantity" shall mean the maximum one hour energy requirements of a Distributing Company expressed in GJ.
(kk) “Minimum Term Date” means the date, if any, specified as such in Schedule “A” of the Agreement.
(ll) “MIPL/TransGas” means Many Islands Pipeline Limited/TransGas Limited, or its successor.
(mm) “Must-flow” shall have the meaning described in Rate Schedule OPDM.
(nn) "MJ" means megajoules or one million (1 000 000) joules.
(oo) "Month" means a period beginning at eight hours (08:00), Mountain Standard Time, on the first Day of a calendar month and ending immediately before eight hours (08:00), Mountain Standard Time, on the first Day of the next succeeding calendar month.
(pp) "NGTL" means NOVA Gas Transmission Ltd. or its successor.
(qq) “Nominated Demand” means the maximum instantaneous Gas flow expressed on a twenty-four (24) hour basis as set forth in the Agreement.
(rr) "Nomination" means a request in electronic, other written form or verbal for Gas to flow at a Point of Receipt, a Point of Delivery to or from Other Pipelines or for receipt into or delivery out of a Customer’s Account at a specified rate of flow and commencing at a specified time, or quantity on a specified date.
(ss) "Non-Compliance" means a Customer action or inaction that contravenes an instruction given, upon notice, by ATCO Pipelines.
(tt) "Non-Compliance Period" means the duration of Non-Compliance.
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(uu) "Non-Compliance Quantity" means the quantity of Gas, in each Day, by which a Customer exceeds the quantity of Gas contained in an instruction given, upon notice, by ATCO Pipelines.
(vv) "Other Pipeline” means a rate regulated pipeline facility not owned or operated by ATCO Pipelines and which is used to deliver or receive merchantable quantities of Gas to or from a facility owned or operated by ATCO Pipelines. The isolated NGTL systems interconnecting with ATCO Pipelines Chip Lake and Coaldale areas are not considered Other Pipelines.
(ww) “Overrun” means Gas at a Point of Receipt or Point of Delivery, which on a monthly basis exceeds the Contract Demand or Nominated Demand of the Firm Service Agreement, and which is Interruptible.
(xx) “Oversupply Delivery Costs” means the costs incurred to deliver supplies which exceed markets. It includes costs incurred due to pipeline capacity restrictions on segments of the Gas Pipeline System.
(yy) "Point of Delivery" means the point on ATCO Pipelines' system at which ATCO Pipelines delivers Gas from the Gas Pipeline System to Customer under the Agreement. It excludes deliveries from an Other Pipeline.
(zz) “Peak Billing Demand” shall mean the maximum consecutive four hour energy requirements of a Distributing Company multiplied by six, in order to express the amount on a twenty-four hour basis.
(aaa) "Point of Receipt" means the point on ATCO Pipelines' system at which Customer delivers Gas to the Gas Pipeline System under the Agreement. It excludes receipts from an Other Pipeline.
(bbb) “Pressure Guarantee” means that ATCO Pipelines will make all reasonable efforts to provide a specified customer with a specified pressure as defined in Section 8.3, Receipt and Delivery Pressure.
(ccc) "Prime Rate" means the rate of interest, expressed as an annual rate of interest, announced from time to time by the main branch of the Bank of
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Montreal in Calgary, Alberta as the reference rate then in effect for determining interest rates on Canadian dollar commercial loans in Canada
(ddd) “Producer” means a party receipting gas from a gas well, battery, or gas plant into the Gas Pipeline System. It excludes receipts first receipted to an Other Pipeline.
(eee) “Rate” means the charges specified on the Rate Schedule, Transportation Service Regulations, or Business Policies and Practices.
(fff) "Rate Schedule" means the rate schedule for the Rate specified in and applicable to the transportation service provided under the Agreement, or such other rate schedule in replacement thereof, as approved by the Board and determined by ATCO Pipelines to be in effect from time to time.
(ggg) "Regulations" means these Transportation Service Regulations.
(hhh) "Specific Facilities" means those facilities, other than general system facilities, installed by ATCO Pipelines for the benefit of Customer and required to receive or deliver Gas under the Agreement.
(iii) "103m3" means one thousand (1 000) cubic metres of gas.
(jjj) “Termination Date” means the date, if any, specified as such in Schedule “A” of the Agreement.
(kkk) "Unaccounted For Gas" or “UFG” means Customer's share of ATCO Pipelines' line loss and unaccounted for Gas, as specified in Article 9.
(lll) “Unauthorized Services’ shall have the meaning described in the Rate Schedules and Section 7.3, Curtailment.
(mmm)"Year" means a period of twelve (12) consecutive months commencing on the Billing Commencement Date.
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ARTICLE 2 - GENERAL
2.1 Regulations Prevail
No employee, agent or representative of ATCO Pipelines has authority to make any representation or agreement on behalf of ATCO Pipelines, which is inconsistent with these Regulations, unless such agreement is approved by the Board.
2.2 Requests for Service
Each application for Gas transportation service shall provide such information as ATCO Pipelines reasonably requires to assess the request for Gas transportation service. ATCO Pipelines' Business Policies & Practices (Requests For Service And Queue Procedure) sets out ATCO Pipelines’ service application procedures. Upon receipt of a request for Gas transportation service, ATCO Pipelines shall notify the applicant of any conditions which must be satisfied before an Agreement can be accepted and service commenced. ATCO Pipelines may reject requests for service if other than standard conditions are sought by the applicant, or if facilities are not available to provide safe and adequate service.
2.3 Applicable Rate and Service Agreement
Upon acceptance of an Application for Service, ATCO Pipelines shall designate the Rate Schedule options which will apply to the Customer's service requirements. Specific Rates may not be available if that Rate has been closed, if physical capacity does not exist, or in the case of Producer receipts, if the incremental benefit is less than the resultant incremental costs. Each Customer shall be required to sign an Agreement. The Transportation Service Regulations and Rate Schedules, as they may be from time to time amended by ATCO Pipelines and approved by the Board, shall form part of each Agreement.
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In the case where the Gas received by ATCO Pipelines under an Agreement is commingled with other Gas prior to receipt of the Gas at the Point of Receipt, Customer shall be responsible for all common stream arrangements.
2.4 Agency
The Agent, on behalf of each Customer for which it acts in connection with such Customer’s obligations under the Agreement, shall be responsible for Customer’s performance of its obligations under the Agreement, including, unless otherwise specified in writing and without limiting the generality of the foregoing, giving and receiving Nominations; purchasing or selling the amounts under Article 6, Balancing; making any payments due ATCO Pipelines under Article 6, Balancing; paying administration fees as per the applicable Rate Schedule, Transportation Service Regulations or Business Policies and Practices and giving to and receiving from ATCO Pipelines, notices under the Agreement.
Any Nomination or notice given or made by ATCO Pipelines to Agent under the Agreement shall be deemed for all purposes under the Agreement as having been given or made by ATCO Pipelines to Customer and any notice given by Agent to ATCO Pipelines or any act or omission by Agent in connection with Customer’s performance of its obligations under the Agreement shall be deemed for all purposes of the Agreement as having been given or done for and on behalf of, and with the approval and authority of, Customer.
Customer may change its Agent by giving ATCO Pipelines seven days advance written notice to that effect indicating the time and date when the change of Agent shall be effective.
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2.5 Title or Interest in the Gas
The Agreement is solely for the receipt, transportation, and delivery of Gas and Customer shall not acquire any title or interest in the Gas Pipeline System of ATCO Pipelines and ATCO Pipelines shall not acquire any title or interest in the Gas being transported under the Agreement.
Gas received by ATCO Pipelines from Customer shall be under the exclusive control of ATCO Pipelines from the time such Gas is received until it is delivered.
ATCO Pipelines does not dedicate the Gas Pipeline System or any segment thereof to Customer, and accordingly the routing and facilities used in the movement of Gas for Customer shall be at ATCO Pipelines’ discretion and may change from time to time.
ATCO Pipelines may in the course of receiving and delivering Gas in the Gas Pipeline System commingle such Gas with or exchange for Gas owned by or transported for others, or remove certain hydrocarbon components present in the Gas. As commingling, exchanging, or the removal of certain hydrocarbon components may alter the Gross Heating Value or constituent parts of the Gas received by ATCO Pipelines at the Point of Receipt, ATCO Pipelines shall not be required to deliver Gas with the same Gross Heating Value or containing the same constituent parts as Gas received and ATCO Pipelines shall make whatever compensating adjustments to volume and Gross Heating Value as may be warranted. In the event, and to the extent, that any hydrocarbon components in the Gas received at the Point of Receipt are absent from the Gas delivered as the result of commingling, exchanging or removal of such hydrocarbon components in the course of transporting the Gas, title to such hydrocarbon components shall, notwithstanding anything to the contrary otherwise contained in the Agreement, be deemed conclusively to have passed to ATCO Pipelines.
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2.6 Facilities, Rights-of-Way and Access to Facilities
2.6.1 Facilities Customer and ATCO Pipelines mutually undertake to operate and maintain their respective pipeline systems and equipment safely and in such a manner as not to interfere with the system or equipment owned by each of them. Each of them undertakes and agrees to consult with the other before commencing construction or operation of any new equipment or facilities which it reasonably expects might interfere with or affect the operation of the other’s pipeline system or equipment and to make modifications to the design or construction of any such equipment or facilities as practically may be requested of it to minimize any interference with the other’s pipeline system or equipment.
A Customer may be required to pay a Customer contribution for Specific Facilities required to provide service. ATCO Pipelines’ Business Policies & Practices (Investment Policy and Contract Term) set out ATCO Pipelines’ investment practice for any Specific Facilities.
2.6.2 Easements An applicant for service, as a Customer, shall grant or cause to be granted to ATCO Pipelines without cost to ATCO Pipelines, such easement or right-of-way in and upon the property owned or controlled by the applicant, upon which is situated the applicant's installation or complex requiring service, as ATCO Pipelines reasonably requires for its Gas line required to serve the applicant including extensions thereof, and other facilities necessary or incidental to the supply of service from such Gas line and extensions thereof.
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2.6.3 Right of Entry ATCO Pipelines shall have the right through its employees or agents to enter upon the installation or complex of the Customer at all reasonable times for the purpose of installing, maintaining and removing its facilities, reading, inspecting, repairing or removing metering devices of ATCO Pipelines, and for all other purposes incident to the supplying or discontinuance of service.
In the event that any of ATCO Pipelines’ equipment is situated within a Customer's installation or complex, ATCO Pipelines may require the Customer to ensure that ATCO Pipelines can obtain access to such equipment when required by ATCO Pipelines.
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ARTICLE 3 - QUALITY OF GAS
3.1 All Gas received under an Agreement shall be of merchantable quality and, without restricting the generality of the foregoing; (a) shall not contain sand, dust, gums, crude oil, impurities and other substances which may be injurious to pipelines or which may interfere with its transmission through pipelines or its commercial utilization; and (b) shall not have a hydrocarbon dewpoint in excess of minus ten degrees Celsius (-10oC) at an absolute pressure of five thousand five hundred (5 500) kPa; and (c) shall not contain more than six milligrams per cubic metre (6 mg/m3) of hydrogen sulphide; and (d) shall not contain more than five milligrams per cubic metre (5 mg/m3) of mercaptan sulphur; and (e) shall not contain more than twenty-three milligrams per cubic metre (23 mg/m3) of total sulphur; and (f) shall not contain more than two percent (2%) by volume of carbon dioxide; and (g) shall not contain more than sixty-four milligrams per cubic metre (64 mg/m3) of water vapor; and
(h) shall not exceed fifty degrees Celsius (50oC) in temperature; and
(i) shall be as free of oxygen as can be achieved through the exercise of all reasonable precautions, and shall not in any event contain more than four-tenths percent (0.4%) by volume of oxygen; and (j) shall have a Gross Heating Value of not less than thirty-six megajoules per cubic metre (36.0 MJ/m3); provided however that with the prior written consent of ATCO Pipelines, Gas of a lower Gross Heating Value may be delivered.
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If in ATCO Pipelines' sole opinion Gas received by ATCO Pipelines at the Point of Receipt fails to be of merchantable quality or fails to meet any one or more of the quality specifications set forth in this Article, ATCO Pipelines may at any time and from time to time immediately and without prior notice cease to receive Gas at the Point of Receipt pending the Customer remedy such failure to the satisfaction of ATCO Pipelines. ATCO Pipelines may install, at Customer's expense, such Specific Facilities including any Gas quality control, monitoring and/or shutdown equipment deemed necessary, in ATCO Pipelines' sole opinion, to ensure that Gas received by ATCO Pipelines at the Point of Receipt meets the quality specifications set forth in this Article.
3.2 Should ATCO Pipelines receive Gas from an Other Pipeline and the quality of Gas received fails to meet the quality specifications set forth in this Article, ATCO Pipelines may from time to time, and at its sole discretion, grant temporary relief from such quality of Gas specifications set forth in this Article.
3.3 All Gas delivered by ATCO Pipelines to Customer at the Point of Delivery shall have the Gross Heating Value and quality that results from the Gas having been commingled in ATCO Pipelines’ Gas Pipeline System.
3.4 Customer shall notify ATCO Pipelines as soon as practicable in the event of any adverse change in Gas quality that is determinable by Customer and which may be delivered into the Gas Pipeline System at the Point of Receipt.
3.5 ATCO Pipelines shall notify Customer or their Agent as soon as practicable in the event of any adverse changes in Gas quality that is determined by ATCO Pipelines and which may be delivered from the Gas Pipeline System at the Point of Delivery.
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ARTICLE 4 - MEASUREMENT
4.1 All measurements, calculations and procedures used in determining the quantities of Gas received at the Point of Receipt or delivered at the Point of Delivery, shall be in accordance with the Electricity and Gas Inspection Act being Chapter 87 of the Statutes of Canada, 1982, as amended and all applicable regulations issued pursuant thereto. ATCO Pipelines Business Policies & Practices (Measurement Practices) set out ATCO Pipelines measurement practices.
4.2 If at any time any of the measuring equipment is found to be registering inaccurately by an amount exceeding two percent (2%), or such other amount as mutually agreeable between Customer and ATCO Pipelines, the measured quantity shall be adjusted. The measuring equipment shall be adjusted at once to read as accurately as possible.
The quantity adjustment shall be calculated using a reading corresponding to the average hourly rate of flow for any period definitely known or agreed upon, or for a period of one-half (1/2) of the elapsed time since the last test.
If the measuring equipment is found to be out of service, the quantity of Gas received or delivered during such period shall be determined: (i) by using the data recorded by any check measuring equipment registering accurately; or (ii) if such check measuring equipment is not registering accurately but the percentage of error is ascertainable by a calibration test, by using the data recorded and adjusted to zero error; or (iii) if neither of the methods provided in (i) or (ii) above can be used, by estimating the quantity, by reference to quantities under similar conditions during a period when ATCO Pipelines’ equipment was registering accurately.
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4.3 If there are any compression facilities upstream of the Point of Receipt or downstream of the Point of Delivery, Customer shall provide sufficient pulsation dampening equipment to ensure that the compression facilities do not interfere with the operation of ATCO Pipelines’ facilities.
4.4 In the event Customer's facilities interfere with ATCO Pipelines’ ability to provide accurate measurement at the Point of Receipt or the Point of Delivery, ATCO Pipelines may immediately and without prior notice cease to receive or deliver Gas pending the remedy by Customer of the cause of such interference to the satisfaction of ATCO Pipelines.
4.5 ATCO Pipelines and Customer hereby agree that notwithstanding anything contained elsewhere in the Agreement, that where Other Pipelines, not ATCO Pipelines', measuring equipment is used or relied on by ATCO Pipelines for measuring Gas received or delivered under the Agreement, Other Pipeline’s measurement and testing of Gas procedures shall apply.
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ARTICLE 5 - QUANTITY OF GAS
5.1 Subject to the other provisions of this Article, ATCO Pipelines will receive from Customer, at the Point of Receipt or interconnection point with an Other Pipeline, the quantity of Gas, which Customer tenders for transportation.
5.2 Subject to the other provisions of this Article, ATCO Pipelines agrees to deliver to Customer, at the Point of Delivery or interconnection point with an Other Pipeline specified in the Agreement, the quantity of Gas which Customer tenders for transportation.
5.3 Customer who has selected firm service for a minimum contractual term, shall, upon expiration of the minimum term of the Agreement, have the option to reduce the Contract Demand, Nominated Demand, or Peak Billing Demand of the said Agreement, provided one (1) year’s prior written notice has been provided to ATCO Pipelines.
5.4 If by reason of the causes set forth in this Article, ATCO Pipelines is unable, in whole or in part, to receive or deliver the quantities of Gas provided for in the Agreement, then ATCO Pipelines shall be relieved of liability for not receiving or delivering such quantities, and ATCO Pipelines may curtail or discontinue receipts or deliveries of Gas under the Agreement during the continuance and to the extent of the inability; provided however that ATCO Pipelines shall endeavor to give reasonable notice of any curtailment or discontinuance of receipts or deliveries arising by virtue of such causes and shall promptly endeavor to remedy the cause of any curtailment or discontinuance of receipts or deliveries as soon as reasonably possible. Such notice shall specify ATCO Pipelines’ estimate of the duration of any such curtailment or discontinuance of receipts or deliveries under the Agreement. The causes above referred to shall include but not be limited to: (a) the necessity, in ATCO Pipelines’ sole opinion, of making modifications or improvements to the Gas Pipeline System; provided however that ATCO Pipelines shall, when practicable,
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endeavor to effect such modifications or improvements, which are not emergency in nature, at a time and in a manner which shall not unduly interfere with or interrupt receipts or deliveries of Gas; or (b) the necessity of making repairs to the Gas Pipeline System used to transport Gas; or (c) the operating conditions of the Gas Pipeline System.
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ARTICLE 6 - BALANCING OF CUSTOMER ACCOUNT
6.1 Customer Account(s) shall be accumulated and recorded by ATCO Pipelines, inclusive of the Daily Imbalance Quantity and Cumulative Imbalance Quantity, and made available to Customer in accordance with ATCO Pipelines’ Business Policies & Practices (Customer Accounts And Imbalance Management).
6.2 Customer shall at all times endeavor to maintain the Customer Account Daily Imbalance Quantity at zero, and the Customer Account Cumulative Imbalance Quantity trending toward zero.
6.3 ATCO Pipelines has the right to require Customer to take corrective action to balance the Customer Account Daily Imbalance Quantity to zero, or trend the Cumulative Imbalance Quantity toward zero, and Customer shall, upon receiving notice from ATCO Pipelines, promptly comply with such request.
6.4 In the event the Customer does not take corrective action provided for in this Article, ATCO Pipelines may take any reasonable action whatsoever to restrict or curtail the quantity of Gas received at the Point of Receipt or delivered at the Point of Delivery, to zero the Daily Imbalance Quantity or trend the Cumulative Imbalance Quantity to zero by restricting receipts into, or deliveries out of, the Customer’s Account(s).
6.5 In the event the Customer Account Cumulative Imbalance Quantity for the month exceeds the monthly limit, as specified in the General Conditions Applying to Rate Schedules, the amount that exceeds the monthly limit shall be settled by ATCO Pipelines purchasing from or selling to Customer the excess or deficiency at the prices specified in the General Conditions Applying to Rate Schedules. At the time of termination of the Agreement, the outstanding Customer Account Cumulative Imbalance Quantity shall be settled by the Customer transferring the outstanding Customer Account Cumulative Imbalance Quantity to another Customer Account or by ATCO Pipelines purchasing from or selling to Customer the outstanding
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Customer Account Cumulative Imbalance Quantity at the prices specified in the General Conditions Applying to Rate Schedules.
ARTICLE 7 - CURTAILMENT
7.1 In the event ATCO Pipelines has provided notice to Customer to restrict or curtail, as provided for in Article 5 - Quantity of Gas, the quantity of Gas received at the Point of Receipt or delivered at the Point of Delivery, or has provided notice to Customer to take corrective action, as provided for in Article 6, to zero the Daily Imbalance Quantity, and Customer does not comply with such notice(s), ATCO Pipelines may serve Customer with notice of Non-Compliance in accordance with ATCO Pipelines’ Business Policies & Practices (Curtailment Practice and/or Customer Accounts And Imbalance Management).
7.2 In the event Customer is in Non-Compliance, ATCO Pipelines shall, at its sole discretion, take any reasonable action whatsoever to restrict or curtail the quantity of Gas received at the Point of Receipt or delivered at the Point of Delivery, or to zero the Daily Imbalance Quantity by restricting receipts into, or deliveries out of, the Customer Account(s).
7.3 Customer shall pay to ATCO Pipelines charges as specified in with the General Conditions Applying to Rate Schedules, applicable to the Non- Compliance Quantity as incurred during the Non-Compliance Period.
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ARTICLE 8 - RECEIPT AND DELIVERY PRESSURE
8.1 Customer will deliver Gas, or cause Gas to be delivered, to ATCO Pipelines at the Point of Receipt or point of interconnection with an Other Pipeline at such pressures as ATCO Pipelines may require from time to time at the Point of Receipt or point of interconnection with an Other Pipeline up to the Maximum Contract Pressure.
8.2 The Maximum Contract Pressure of the Gas at the Point of Receipt or point of interconnection with an Other Pipeline shall be nine thousand nine hundred and thirty-six (9 936) kPa. ATCO Pipelines at its sole discretion may grant relief from the Maximum Contract Pressure at the Point of Receipt or point of interconnection with an Other Pipeline to permit receipt of Gas at a reduced pressure and such relief shall continue from the Day relief is granted until such time as ATCO Pipelines, upon twelve (12) Months prior written notice, revises the reduced pressure then in effect to a pressure not in excess of the Maximum Contract Pressure.
8.3 ATCO Pipelines agrees to deliver the Gas, or cause the Gas to be delivered, to Customer at the Point of Delivery or point of interconnection with an Other Pipeline at such pressures as are available in the Gas Pipeline System from time to time provided however, any Pressure Guarantee of a delivered pressure will be provided for in the Customer’s Agreement.
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ARTICLE 9 GAS LOST, UNACCOUNTED-FOR-GAS, AND FUEL GAS
9.1 Subject to Article 14, ATCO Pipelines shall not be responsible for Gas lost by pipeline rupture, explosion, fire or other similar calamity, but shall maintain and provide to Customer a record of Customer's proportionate share of any such loss and co-operate with all reasonable requests of Customer's insurers or their agents during the course of the investigation of any claim arising from any such loss.
9.2 Customer shall be responsible to ATCO Pipelines for Customer's share of ATCO Pipelines’ Unaccounted For Gas and Fuel Gas (excluding Gas lost referred to in Clause 9.1 of this Article) as indicated on the applicable Rate Schedule.
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ARTICLE 10 - RATES AND OTHER CHARGES
10.1 Customer shall pay to ATCO Pipelines, for transportation service provided under the Agreement, commencing on the Billing Commencement Date, the Rates and charges set forth in the Agreement.
10.2 Customer shall not be relieved by Force Majeure as described in Article 12 from the obligation to pay the Rates and charges set forth pursuant to this Article unless Force Majeure has been invoked by ATCO Pipelines, for a period of thirty (30) consecutive Days or longer and for more than fifty percent (50%) of the Contract Demand, Nominated Demand, or Peak Billing Demand whereupon the Customer’s monthly demand charges shall be reduced on a pro-rata basis for the number of Days Force Majeure, as invoked by ATCO Pipelines, is in effect.
10.3 Customer shall provide ATCO Pipelines with any financial information ATCO Pipelines reasonably requests in order that ATCO Pipelines may establish Customer's credit worthiness in accordance with ATCO Pipelines' Business Policies and Practices (Credit Policy).
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ARTICLE 11 - BILLINGS AND PAYMENTS
11.1 Billing: On or before the twentieth (20th) Day of each Month, ATCO Pipelines shall provide a bill to Customer for service provided during the preceding Month.
11.2 Payment: Customer agrees to pay ATCO Pipelines on or before the tenth (10th) Day following the rendering of the bill by ATCO Pipelines to Customer, the total amount payable by Customer as set forth in the bill. Each such payment shall be made in Canadian funds by cheque drawn in ATCO Pipelines' favour and delivered to ATCO Pipelines at the address stated in the Agreement or by such other method as may be acceptable to ATCO Pipelines.
11.3 Late Billing: If ATCO Pipelines provides a bill after the twentieth (20th) Day of a Month, then the date for payment shall be that Day which is ten (10) Days after the Day that such bill was rendered.
11.4 Interest on Unpaid Bills: ATCO Pipelines shall have the right to charge interest on the unpaid portion of any bill from the date payment is due until the date payment is actually made, at a rate of interest which is two percent (2%) per annum above the Prime Rate, which is in effect as of the period that such payment is unpaid, from the date when such payment is due until the same is paid.
11.5 Disputes: In the event Customer disputes any part of any bill, Customer shall nevertheless pay to ATCO Pipelines the full amount of the bill when payment is due.
11.6 Overpayment: In the event Customer disputes any part of a bill and it is finally determined that any final bill prepared pursuant to this Article was incorrect and an overpayment has been made, Customer shall be entitled to interest on the amount of any such overpayment at a rate of interest which is two percent (2%) per annum above the Prime Rate, which is in effect as of the period that such overpayment exists, from the date of any
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such overpayment until the date ATCO Pipelines makes reimbursement of such overpayment to Customer.
11.7 Billing Adjustments: Neither Customer nor ATCO Pipelines shall be entitled to interest for any adjustment to the bill which is the result of a reallocation by the Common Stream Operator or a change in the quantity of Gas measured.
11.8 Failure to Pay: In the event Customer fails to pay the full amount of any bill within sixty (60) Days after payment is due, ATCO Pipelines, in addition to any other remedy it may have, may suspend the receipt of or delivery of Gas until full payment is made. Such suspension shall not terminate or otherwise affect Customer's obligations to ATCO Pipelines.
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ARTICLE 12 - FORCE MAJEURE
12.1 Subject to the other provisions of this Article, if either party to the Agreement fails to observe or perform any of the covenants or obligations herein imposed upon it and such failure shall have been occasioned by, or in connection with, or in consequence of Force Majeure, as hereinafter defined, such failure shall be deemed not to be in breach of such covenants or obligations.
12.2 For the purposes of the Agreement, "Force Majeure" shall mean any acts of God, including therein, but without restricting the generality thereof, lightning, earthquakes and storms, and, in addition, shall mean any strikes, lockouts or other industrial disturbances, acts of the Queen's enemy, sabotage, wars, blockades, insurrections, riots, epidemics, landslides, floods, fires, washouts, arrests and restraints, civil disturbances, explosions, breakages of or accidents to machinery or lines of pipe, hydrate obstructions of lines of pipe, temporary failures of Gas supply, freezings of wells or delivery facilities, well blowouts, craterings, the orders of any court or governmental authority, any acts or omissions (including failure to take Gas) of a purchaser of Gas from, or a transporter of Gas to or for ATCO Pipelines, which are excused by any event or occurrence whether or not of the character or kind herein defined as constituting Force Majeure, lack of exchange capacity or pressure at interconnections with Other Pipelines, or any other causes, excepting financial, whether of the character or kind herein enumerated or otherwise, and not within the control of the party claiming suspension and whether or not arising out of or resulting from an event, cause or occurrence under the Agreement or otherwise, which, by the exercise of due diligence, such party could not have prevented or is unable to overcome.
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix C Page 28
12.3 Neither party shall be entitled to the benefit of the provisions of Clause 12.1 of this Article under any or all of the following circumstances: (a) to the extent that the failure was caused by the sole negligence of the party claiming suspension; or (b) to the extent that the failure was caused by the party claiming suspension having failed to remedy the condition where it is within that party's ability alone to do so and to resume the performance of such covenants or obligations, with reasonable dispatch; or (c) if the failure was caused by lack of funds or with respect to the payment of any amount or amounts then due under the Agreement; or (d) unless as soon as possible after the happening of the occurrence relied upon or as soon as possible after determining that the occurrence was in the nature of Force Majeure and would affect the claiming party's ability to observe or perform any of its covenants or obligations under the Agreement, the party claiming suspension shall have given to the other party notice, either in writing or by facsimile, to the effect that such party is unable by reason of Force Majeure (the nature whereof shall be therein specified) to perform the particular covenants or obligations.
12.4 The party claiming suspension shall likewise give notice, as soon as possible after the Force Majeure condition is remedied, to the effect that the same is remedied and that such party has resumed, or is then in a position to resume, the performance of such covenants or obligations.
12.5 Notwithstanding anything to the contrary in this Article expressed or implied, the parties agree that the settlement of strikes, lockouts and other industrial disturbances shall be entirely within the discretion of the particular party involved therein and such party may make settlement thereof at such time and on such terms and conditions as it may deem to be advisable and no delay in making such settlement shall deprive such party of the benefit of Clause 12.1 of this Article.
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix C Page 29
ARTICLE 13 - TERMINATION ON DEFAULT
13.1 If either party shall fail to perform any of the covenants or obligations imposed upon it under and by virtue of the Agreement (the "Defaulting Party"), then in any such event, the other party (the "Non-Defaulting Party") may at its option terminate the Agreement by proceeding as follows: (a) The Non-Defaulting Party shall cause a notice in writing to be given to the Defaulting Party advising as to the nature of any default and declaring it to be the intention of the Non-Defaulting Party to terminate the Agreement. (b) The Defaulting Party shall have ninety (90) Days after receiving any such notice to remedy the default specified and if, within the said period of ninety (90) Days, the Defaulting Party does remedy any such default to the satisfaction of the Non-Defaulting Party then the notice given pursuant to Clause 13.1(a) of this Article shall be deemed to be withdrawn and the Agreement shall continue in full force and effect. (c) In the event that Customer does not remedy any default of which it has been given notice by ATCO Pipelines to the reasonable satisfaction of ATCO Pipelines within the said ninety (90) Day period, then the Agreement shall thereafter terminate after the said ninety (90) Day period and the appropriate charges for all Specific Facilities, as well as the present value of all system tariffs that would be in effect until the termination of the Agreement, discounted at the rate as specified in ATCO Pipelines’ Business Policies and Practices (Investment Policy), shall become due and payable. All other rights and obligations of the parties under the Agreement shall cease upon termination of the Agreement; provided however that any such termination shall not affect any other remedy ATCO Pipelines may have at law or in equity.
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix C Page 30
(d) In the event that ATCO Pipelines does not remedy any default of which it has been given notice by Customer to the reasonable satisfaction of Customer within the said ninety (90) Day period, then Customer shall have the right to terminate the Agreement. All other rights and obligations of the parties hereunder shall cease upon the termination of the Agreement; provided however that any such termination shall not affect any other remedy Customer may have at law or in equity.
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix C Page 31
ARTICLE 14 - INDEMNITY
14.1 Customer agrees to indemnify and save ATCO Pipelines harmless from and against any and all claims, demands, suits, actions, debts, accounts, damages, costs, losses, liabilities and expenses of whatsoever nature or kind and howsoever and by whosoever made or incurred arising out of or in any way connected, either directly or indirectly, with any act, omission or default on the part of Customer under the Agreement; provided however that in no event, whether as a result of alleged negligence on the part of Customer or otherwise, shall Customer be liable to ATCO Pipelines for loss of profits or revenues, cost of capital, loss for failure to deliver Gas, cost of purchased or replacement Gas, claims of ATCO Pipelines’ customers for failure to deliver Gas, cancellation of permits, termination of contracts or other similar special or consequential damages or claims whatsoever.
14.2 ATCO Pipelines agrees to indemnify and save Customer harmless from and against all claims, demands, suits, actions, debts, accounts, damages, costs, losses, liabilities and expenses of whatsoever nature or kind and howsoever and by whosoever made or incurred arising out of the gross negligence or willful misconduct of ATCO Pipelines under the Agreement; provided however that in no event, whether as a result of alleged gross negligence on the part of ATCO Pipelines or otherwise, shall ATCO Pipelines be liable to Customer for loss of profits or revenues, cost of capital, loss for failure to deliver Gas, cost of purchased or replacement Gas, claims of Customer's customers for failure to deliver Gas, cancellation of permits, termination of contracts or other similar special or consequential damages or claims whatsoever.
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix C Page 32
ARTICLE 15 - NOTICES
15.1 Every notice, request, statement or bill provided for by the Agreement or any notice which either ATCO Pipelines or Customer may desire to give to the other shall be in writing to the address stated in the Agreement, or as mutually agreed between Customer and ATCO Pipelines.
15.2 Any notice may be given by mailing the same, postage prepaid, in an envelope properly addressed to the person to whom the notice is being given and shall be deemed to be given four (4) business Days after the mailing thereof, Saturdays, Sundays and statutory holidays excepted. Any notice may also be given by facsimile or other electronic communication addressed to the person to whom such notice is to be given at such person's address for notice, and any such notice so served shall be deemed to have been given twenty-four (24) hours after transmission of the same, Saturdays, Sundays and statutory holidays excepted. Any notice may also be delivered by hand to the person, or his representative, to whom such notice is to be given at such person's address for notice, and such notice shall be deemed to have been given when received by such person or his representative. Any notice may also be given by telephone followed immediately by letter, facsimile or other electronic communication and any notice so given shall be deemed to have been given of the date and time of the telephone notice.
15.3 In the event of disruption of regular mail every payment shall be personally delivered and every notice, demand, statement or bill shall be given by one of the alternative means set out in Clause 15.2 of this Article.
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix C Page 33
ARTICLE 16 - ALLOCATIONS
16.1 For the purpose of administering transportation Agreements, Gas flows at the Point of Receipt or Point of Delivery shall be allocated to determine the daily flow to be billed under the appropriate Rate Schedule. ATCO Pipelines' Business Policies & Practices (Allocation Practice) sets out ATCO Pipelines' allocation practice.
16.2 At locations where a portion of the Gas flowing belongs to parties other than Customer and ATCO Pipelines, all parties must agree in writing on the Allocation Method used between those parties at that location, and provide a copy to ATCO Pipelines prior to the effective date, if different than which is provided for in ATCO Pipelines' Business Policies & Practices (Allocation Practices).
16.3 If a Customer requests a change in the Allocation Method at a Point of Receipt or Point of Delivery other than which is provided for in ATCO Pipelines' Business Policies & Practices (Allocation Practices), such revised Allocation Method must be agreed to by all parties and be confirmed in a letter agreement. In the event Customer and ATCO Pipelines are unable to agree on an acceptable revised Allocation Method, ATCO Pipelines reserves the right to decide on the revised Allocation Method which will be used.
16.4 At locations where the Gas flowing is at an interconnection with an Other Pipeline, then the allocation procedures as agreed to between ATCO Pipelines and the Other Pipeline shall apply.
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix C Page 34
ARTICLE 17 - MISCELLANEOUS
17.1 In the interpretation of the Agreement, words in the singular shall be read and construed in the plural or words in the plural shall be read and construed in the singular where the context so requires.
17.2 The Agreement and the rights and obligations of the parties to the Agreement are subject to all applicable present and future laws, rules, regulations and orders of any legislative body or duly instituted authority now or hereafter having jurisdiction.
17.3 The Agreement contains the complete agreement between the parties and supersedes any prior agreement between the parties, whether written or verbal, with respect only to the transportation service rendered by ATCO Pipelines.
17.4 The parties hereto shall from time to time and at all times do all such further acts and execute and deliver all such further deeds and documents as shall be reasonably required in order to fully perform and carry out the terms of the Agreement.
17.5 The definitions of all units of measurement and their prefixes used throughout the Agreement shall be in accordance with the International System of Units.
17.6 No waiver by ATCO Pipelines or Customer of any default by the other under the Agreement shall operate as a waiver of a future default whether of a like or different character.
17.7 The Agreement shall apply mutatis mutandis to each Point of Receipt, Point of Delivery, deliveries to Other Pipelines, receipts from Other Pipelines, or Account Transfers.
17.8 The Agreement shall bind and inure to the respective successors and assigns of the parties thereto; provided however that no assignment shall release either party from such party's obligations under the Agreement
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix C Page 35
without the written consent of the other party to such release, which consent shall not be unreasonably withheld.
17.9 Nothing herein contained shall prevent any party to the Agreement from pledging or mortgaging its rights under the Agreement as security for its indebtedness.
17.10 The headings used throughout the Agreement are inserted for reference purposes only, and are not be considered or taken into account in construing the terms or provisions of any Article, Clause or Schedule nor to be deemed in any way to qualify, modify or explain the effect of any such provisions or terms.
17.11 The Agreement shall be construed in accordance with the laws of the Province of Alberta and the laws of Canada applicable therein.
17.12 Customer shall provide to ATCO Pipelines, for planning purposes, such forecasts of future Monthly volumes to be received or delivered under the Agreement as ATCO Pipelines may request from time to time.
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix D Page 1 of 1 CALCULATION OF RATE 5 REFUNDS/CHARGES AS PER BOARD DIRECTIONS 29 AND 30 OF DECISION 2004-079
1.) Gas Alberta - EUB Decision 2004-079, page 150
SALES SERVICE TRANSPORTATION SERVICE Variable Charge Fixed Charge Total Charge Demand (GJ) Demand Rate Total Demand Apr/03$ 67,322.92 $ 46,400.00 $ 113,722.92 48,100 $ 1.806 $ 86,868.60 May/03$ 45,024.20 $ 46,400.00 $ 91,424.20 48,100 $ 1.806 $ 86,868.60 Jun/03$ 25,370.39 $ 46,400.00 $ 71,770.39 48,100 $ 1.806 $ 86,868.60 Jul/03$ 20,710.03 $ 46,400.00 $ 67,110.03 48,100 $ 1.806 $ 86,868.60 Aug/03$ 20,386.19 $ 46,400.00 $ 66,786.19 48,100 $ 1.806 $ 86,868.60 Sep/03$ 37,632.04 $ 46,400.00 $ 84,032.04 48,100 $ 1.806 $ 86,868.60 Oct/03$ 55,260.50 $ 46,400.00 $ 101,660.50 48,100 $ 1.806 $ 86,868.60 Nov/03$ 115,597.17 $ 45,440.00 $ 161,037.17 48,100 $ 1.806 $ 86,868.60 Dec/03$ 124,775.57 $ 45,440.00 $ 170,215.57 48,100 $ 1.806 $ 86,868.60 Jan/04$ 159,680.42 $ 45,440.00 $ 205,120.42 48,100 $ 1.806 $ 86,868.60 Feb/04$ 112,030.22 $ 45,440.00 $ 157,470.22 48,100 $ 1.806 $ 86,868.60 Total Charges$ 783,789.65 $ 506,560.00 $ 1,290,349.65 $ 955,554.60
Refund / (Additional Charge) $334,795.05 Note - Gas Alberta invoiced as a transportation demand service customer at the interim demand rate of $1.806 and stated demand effective March 2004. Refund period ends February 2004.
2.) Samson Cree Nation - EUB Decision 2004-079, page 151
SALES SERVICE TRANSPORTATION SERVICE Variable Charge Fixed Charge Total Charge Demand (GJ) Demand Rate Total Demand Mar/04$ 4,666.02 $ 1,100.80 $ 5,766.82 2,230 $ 1.436 $ 3,202.28 Apr/04$ 3,332.52 $ 1,100.80 $ 4,433.32 2,230 $ 1.436 $ 3,202.28 May/04$ 2,925.40 $ 1,100.80 $ 4,026.20 2,230 $ 1.436 $ 3,202.28 Jun/04$ 1,144.72 $ 1,100.80 $ 2,245.52 2,230 $ 1.436 $ 3,202.28 Jul/04$ 637.51 $ 1,100.80 $ 1,738.31 2,230 $ 1.436 $ 3,202.28 Aug/04$ 634.01 $ 1,100.80 $ 1,734.81 2,230 $ 1.436 $ 3,202.28 Total Charges$ 13,340.18 $ 6,604.80 $ 19,944.98 $ 19,213.68
Refund / (Additional Charge) $731.30 Note - Samson Band to be invoiced as a transportation service customer beginning with September 2004. Therefore, the refund period ends August 2004.
3.) Town of Redwater - EUB Decision 2004-079, page 151
SALES SERVICE TRANSPORTATION SERVICE Variable Charge Fixed Charge Total Charge Demand (GJ) Demand Rate Total Demand Mar/04 $4,696.67 $275.20 $4,971.87 1,852 $1.436$ 2,659.47 Apr/04 $2,835.61 $275.20 $3,110.81 1,852 $1.436$ 2,659.47 May/04 $1,903.77 $275.20 $2,178.97 1,852 $1.436$ 2,659.47 Jun/04 $1,213.70 $275.20 $1,488.90 1,852 $1.436$ 2,659.47 Jul/04 $996.23 $275.20 $1,271.43 1,852 $1.436$ 2,659.47 Aug/04 $1,154.79 $275.20 $1,429.99 1,852 $1.436$ 2,659.47 Total $12,800.77 $1,651.20 $14,451.97$ 15,956.83
Refund / (Additional Charge) ($1,504.86) Note - Town of Redwater to be invoiced as a transportation service customer beginning with September 2004. Therefore, the refund period ends August 2004.
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix E Page 1 of 5 ATCO PIPELINES - NORTH 2004 Phase II Compliance Filing November-December 2004 Surcharge ($000) Line No 1 Total 2004 Revenue Requirement (1) (2) 95,965 2 Less: Natural Gas Supply (1) (1,780) 3 Less: Taxes other than Income - Rider A and B (3) (2,588) 4 91,597
5 Plus: SCADA O&M Costs (4) 64 6 Plus: Oversupply Delivery Costs (899 * 2/12) 150 8 Less: 2003 Surplus (5) (8,285) 7 Less: 2003 EDA Surplus (360) 8 Revenue to be collected Jan - Dec 2004 83,166
9 Jan - Feb 2004 Revenue at Previous Interim Rates (see Page 2 of 6) (14,984) 10 March to October 2004 Revenue at Current Interim Rates (see Page 3 of 6) (50,693) 11 Revenue Requirement to be collected November to December 17,488
12 Less: November to December Other Revenue (860) 13 16,628 14 Less: November to December Demand and Commodity Revenues at Phase II Rates (14,533) 15 November to December Shortfall at Phase II Rates 2,095
16 Surcharge Percentage on Phase II Rates 14.42%
1. per Table 4.1-2 of Phase I Third Compliance Filing - July 23, 2004 2. Reconciliation to Total Revenue on Page 5 of 5 2004 Revenue Requirement (line 1) 95,965 Add: Oversupply Delivery Costs (full year - line 6) 899 Add: SCADA O&M Costs (line 5) 64 Total Revenue (Page 5 of 5) 96,928 3. per Table 4.3-2 of Phase I Third Compliance Filing - July 23, 2004 4. per Decision 2004-078 5. per Table 5.2-2 of Phase I Third Compliance Filing - July 23, 2004
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix E ATCO PIPELINES - NORTH Page 2 of 5 2004 PHASE II COMPLIANCE FILING JANUARY TO FEBRUARY 2004 REVENUES AT PREVIOUS INTERIM RATES ($000)
Demand/Commodity Standard Revenue Line Distributing Producers Industrial/OR Straddle Alliance Rate 10 Rate 6 No Companies Wainwright Firm/IT Plant IT/Overrun Industrial Power Other Total
Revenue at Previous Interim Rates - January-February Billing Determinants 1 TJ/day 1,213 903 597 6 2 2 TJ 167 6,900 215 3,232 443 3
3 Rate $/GJ/Month 1.806 3.497 1.610 2.680 2.330 4 $/GJ 0.22 0.12647 0.05820 0.04932 $ 0.05 0.05400
5 Demand Revenue 4,381 37 7,188 1,935 159 22 31 8 13,762 6 IT/OR ------0 - 0 7 4,381 37 7,188 1,935 159 22 31 8 - 13,762 Other Revenue 8 Industrial Fixed 672 9 Rate 10 Industrial - Fixed 12 10 Industrial Shell 565 11 Industrial Non-Standard Commodity 2,360 12 Industrial Non-Standard Commodity Adjustment (1) (809) 13 Industrial Facility (2) 709 14 Straddle Plant - Fixed (2) 12 15 ATCO Power 111 16 Devon 134 17 Rate 6 Power Plants - Fixed 10 OPR 2,360 18 Other Revenue (2) (3) 1,194 19 Full Year Other Revenue 7,330 20 2/12 of Full Year 1,222 1,222
21 Jan - Feb 2004 Revenue at Previous Interim Rates 4,381 37 7,188 1,935 159 22 31 8 1,222 14,984
1. Represents UFG & Fuel Rate Adjustment per Table 5.1-2 of Third Phase I Compliance Filing dated July 23, 2004 2. Updated to agree with Attachment IGCAA-AP02-1(a). An updated schedule is provided on page 5 of 5 3. $1,394 (Page 5 of 5) less $200 for Rate 10 Industrial charges
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix E ATCO PIPELINES - NORTH Page 3 of 5 2004 PHASE II COMPLIANCE FILING MARCH TO OCTOBER 2004 REVENUES AT CURRENT INTERIM RATES ($000)
Demand/Commodity Standard Revenue Line Distributing Producers Industrial/OR Straddle Alliance Rate 10 Rate 6 No Companies Wainwright1 Firm/IT Plant IT/Overrun Industrial Power Other Total
Revenue at Current Interim Rates - March to October Billing Determinants 1 TJ/day 1,216 903 597 6 2 2 TJ 173 27,601 859 12,928 1,773 13
3 Rate $/GJ/Month 1.436 3.035 1.280 2.130 1.850 4 $/GJ 0.175 0.10976 0.04626 0.03921 $ 0.04 0.04300
5 Demand Revenue 13,966 30 24,955 6,152 507 70 100 26 45,806 6 IT/OR ------1 - 1 7 13,966 30 24,955 6,152 507 70 100 27 - 45,807 Other Revenue 8 Industrial Fixed 672 9 Rate 10 Industrial - Fixed 12 10 Industrial Shell 565 11 Industrial Non-Standard Commodity 2,360 12 Industrial Non-Standard Commodity Adjustment (2) (809) 13 Industrial Facility (3) 709 14 Straddle Plant - Fixed (3) 12 15 ATCO Power 111 16 Devon 134 17 Rate 6 Power Plants - Fixed 10 18 OPR 2,360 19 Other Revenue (3) (4) 1,194 20 Full Year Other Revenue 7,330 21 8/12 of Full Year 4,887 4,887
22 Mar - Oct 2004 Revenue at Current Interim Rates 13,966 30 24,955 6,152 507 70 100 27 4,887 50,693
1. Commodity revenue for March to June 2004. Demand revenue is included in Distributing Companies for July to October 2004. 2. Represents UFG & Fuel Rate Adjustment per Table 5.1-2 of Third Phase I Compliance Filing dated July 23, 2004 3. Updated to agree with Attachment IGCAA-AP02-1(a). An updated schedule is provided on page 5 of 5 4. $1,394 (Page 5 of 5) less $200 for Rate 10 Industrial charges
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix E ATCO PIPELINES - NORTH Page 4 of 5 2004 PHASE II COMPLIANCE FILING CALCULATION OF NOVEMBER TO DECEMBER 2004 SURCHARGE RATES ($000)
Demand/Commodity Standard Revenue Line Distributing Producers Industrial/OR Straddle No Companies Firm/IT Plant OPDC OPR Other Total
1 Revenue to be Collected in November to December 2004 (a) (1) 17,488
Revenue at Phase II Rates - November to December
Billing Determinants 2 TJ/day 1,313 903 599 3 TJ 6,900 215 3,232 7,456 28,095
4 Rate $/GJ/Month 2.258 2.593 2.013 5 $/GJ 0.070 0.073 0.058 0.058 0.01400
6 Demand Revenue 5,928 4,683 2,411 - - 13,021 7 Commodity Revenue 483 16 188 432 393 - 1,512 8 Subtotal 5,928 5,166 2,426 188 432 393 - - 14,533 9 Other Revenue (1) ------860 860 10 Total Revenue under Final Rates (b) 5,928 5,166 2,426 188 432 393 - 860 15,393
11 Revenue Shortfall (a-b) 2,095 12 Prorated Shortfall 854 745 350 27 62 57 - 2,095 13 Percentage surcharge required (c/b) 14.42% 14.42% 14.42% 14.42% 14.42% 14.42%
Nov to Dec Surcharge Rates 14 $/GJ/Month (4) 0.325 0.374 0.290 - - 15 IT/OR - $/GJ (4) 0.0101 0.0105 0.008 0.008 0.002 -
16 Surcharge Revenue - Demand 854 675 348 - - 1,876 17 Surcharge Revenue - Commodity 70 2 27 63 57 - 218 18 854 745 350 27 63 57 - - 2,095
Note 1: Full Year Other Revenue (line 20 on page 3 of 5) 7,330 Less: OPR (2,360) Plus: Rate 10 Industrial Demand Revenue 188 5,158 2/12 860
Note 2: OPDC and OPR revenues are credited to the respective OPD and OPR deferral accounts. ATCO Pipelines will charge the OPD Deferral Account for the $63,000 and the OPR Deferral Account for the $57,000 calculated above. Any variance between revenues actually collected by the surcharge on OPDC and OPR and the amounts calculated above will remain in the respective deferral accounts.
Note 3: To facilitate an efficient billing process, invoices for November and December 2004 will be billed using rates calculated as the addition of base (final rates) plus surcharge rates with a note on the invoice explaining this fact.
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix E ATCO Pipeline 2004 Phase II General Rate Application - Phase II Compliance Filing - October 2004 Page 5 of 5 North Year 2004 - Full Year Peak Contract Fixed Commodity Demand Fixed Other Demand Total Throughput Demand Demand Charge Charge Charge Revenue Revenue Revenue Revenue (TJ's) (TJ/day) (TJ/day) $/month $/GJ $/GJ/mo ($000's) ($000's) ($000's) ($000's) Distributing Companies ATCO Gas 1,234 1,234 (a) - $ - 2.258 - - 33,428 33,428 Altagas Transportation 22 22 - $ - 2.258 - - 596 596 Rate 5 - 11 11 2.258 298 298 Gas Alberta 43 43 (a) - $ - 2.258 - - 1,165 1,165 Wainwright (Jan to June) 340 3 - - $ 0.220 - 75 - 75 Wainwright (July to Dec) 3 3 - $ - 2.258 - - 81 81 Sub-total Distributing 1,316 1,313 - 75 35,569 35,644
Producers Producers Firm 896 896 - $ - 2.593 - - 27,878 27,878 ATCO Gas Firm 7 7 - $ - 2.593 - - 218 218 Producers IT/OR - Oct-May 32,862 - - $ 0.070 - - 2,300 - 2,300 Producers IT/OR - June-Sept. 8,540 $ 0.085 726 - 726 Producers Facility - - - - $ ------Sub-Total Producers 903 903 - 3,026 28,096 31,122
Industrial Industrial FSD One year 190 190 1,000.00 $ - 2.114 348 - 4,819 5,167 Industrial FSD three year 23 23 1,000.00 $ - 2.013 36 - 556 592 Industrial FSD five year 394 394 1,000.00 $ - 1.912 288 - 9,038 9,326 Straddle Plant Service 19,392 1,000.00 $ 0.058 - 12 1,125 - 1,137 Industrial Overrun 1,288 $ 0.073 94 94 Rate 6 Power Plants 20 2 2 860.00 $ 0.054 2.330 10 1 49 60 Industrial Facility - - - - $ - - - 709 - 709 Sub-Total Industrials 609 609 694 1,929 14,461 17,084
OPDC incl Alliance 44,734 $ 0.058 2,595 2,595 OPR 168,571 $ 0.014 2,360 2,360
Non-Standard Industrial - Shell Upgrader 77 - - 0.608 - 565 565 Industrial - Commodity 106,299 - - $ 0.02222 - - 2,360 - 2,360 UFG & Fuel Rate Adjustment (b) (809) (809) ATCO Power Cost of Service 9,250.00 - - 111 - - 111 Devon 3 (c) 134 134 Sub-total Non Standard 111 1,551 699 2,361
Gas Cost Recoveries 1,780 1,780 Franchise Fee Revenue (Riders A & B) 2,588 2,588 Other Revenue Pipeline and Lease Revenue Paddle River - - 25,650.00 - - 308 - - 308 Newport - - 2,080.00 - - 25 - - 25 AEC West - - 20,000.00 - - 88 - - 88 Rate 10 2,125 6 1,000.00 - 2.680 12 - 188 200 Liquids Revenue ------FBA Cost of Service 2,742 - - 0.28000 - - 773 - 773 433 773 188 1,394
Total Revenue 1,238 16,677 79,013 96,928
(a) Peak Demand for Distributing Companies revised to reflect Decision 2004-079 Table 15 (b) Revised to reflect the $809 UFG & Fuel Rate Adjustment per Table 5.1-2 of Third Phase I Compliance Filing dated July 23, 2004 EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix F Page 1 of 5
ATCO PIPELINES - SOUTH Phase II Compliance Filing Calculation of Revenue Surplus ($000) Line No 1 Total 2004 Revenue Requirement (1) (2) 39,690 2 Less: Taxes other than Income - Rider A and B (3) (740) 3 38,950
4 Plus: SCADA O&M Costs (4) 31 5 Plus: Oversupply Delivery Costs (4,457 * 2/12) 743 6 Less: 2003 Surplus (5) (232) 7 Less: Calgary Stores Block Refund (122) 8 Revenue to be collected Jan - Dec 2004 39,370
9 Jan - Feb 2004 Revenue under Previous Interim Rates (see Page 2 of 6) (5,662) 10 Mar - Oct 2004 Revenue under Current Interim Rates (see Page 3 of 6) (26,493) 11 Revenue Requirement to be collected Nov to Dec 7,215
12 Less: November to December Other Revenues (334)
13 Less: November to December Revenues at Phase II Rates (6,901)
14 Revenue Surplus (6) (20)
1. per Table 4.1-3 of Phase I Third Compliance Filing - July 23, 2004 2. Reconciliation to Total Revenue on Page 5 of 5 2004 Revenue Requirement (line 1) 39,690 Add: Oversupply Delivery Costs (full year - line 5) 4,457 Add: SCADA O&M Costs (line 4) 31 Total Revenue (Page 5 of 5) 44,178 2. per Table 4.3-3 of Phase I Third Compliance Filing - July 23, 2004 3. per Decision 2004-078 4. per Table 5.2-3 of Phase I Third Compliance Filing - July 23, 2004 5. Due to the dollar amount involved, ATCO is proposing to refund this surplus amount in the Compliance Filing following a Board Decision on the ATCO ITEK placeholder. This Decision is expected in 2005.
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix F Page 2 of 5 ATCO PIPELINES - SOUTH 2004 PHASE II COMPLIANCE FILING JANUARY TO FEBRUARY 2004 REVENUES AT CURRENT RATES ($000)
Demand/Commodity Standard Revenue Line ATCO Gas Producers Producers Industrial/OR No Gas Alberta Firm IT/OR Other Total
Revenue at Revious Interim Rates - January - February Billing Determinants 1 TJ/day 1,024 17 296 106 2TJ 2,047 77
3 Rate $/GJ/Month 1.605 1.950 2.250 1.500 IT/OR - $/GJ 0.08137 0.05425
4 Demand Revenue 3,287 66 1,332 318 5,003 5 IT/OR - - 167 4 171 6 3,287 66 1,332 167 322 5,174
Other Revenue 7 Industrial Fixed 144 8 Encana 2,253 9 Chain Lakes 116 10 Calpine 12 OPR 1,494 11 FSD Large Industrial (1,089) 12 Full Year Other Revenue 2,930 13 2/12 of Full Year 488 488
14 Jan - Feb 2004 Revenue at Previous Interim Rates 3,287 66 1,332 167 322 488 5,662
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix F Page 3 of 5 ATCO PIPELINES - SOUTH 2004 PHASE II COMPLIANCE FILING MARCH TO OCTOBER 2004 REVENUES AT CURRENT RATES ($000)
Demand/Commodity Standard Revenue Line ATCO Gas Producers Producers Industrial/OR No Gas Alberta Firm IT/OR Other Total
Revenue at Current Interim Rates - March - October Billing Determinants 1 TJ/day 1,024 17 296 106 2TJ 8,189 307
3 Rate $/GJ/Month 1.907 1.950 2.673 1.782 IT/OR - $/GJ 0.09666 0.06444
4 Demand Revenue 15,622 265 6,330 1,511 23,728 5 IT/OR - - 792 20 811 6 15,622 265 6,330 792 1,531 24,539
Other Revenue 7 Industrial Fixed 144 8 Encana 2,253 9 Chain Lakes 116 10 Calpine 12 OPR 1,494 11 FSD Large Industrial (1,089) 12 Full Year Other Revenue 2,930 13 8/12 of Full Year 1,953 1,953
14 Mar - Oct 2004 Revenue at Current Interim Rates 15,622 265 6,330 792 1,531 1,953 26,493
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix F Page 4 of 5 ATCO PIPELINES - SOUTH 2004 PHASE II COMPLIANCE FILING NOVEMBER TO DECEMBER 2004 REVENUE SURPLUS ($000)
Demand/Commodity Standard Revenue Line ATCO Gas Producers Industrial/OR No Gas Alberta Firm OPDC OPR Other Total
1 Revenue to be Collected in Nov to Dec. 2004 (a) (1) 7,215
Revenue at Phase II Rates - Nov. - Dec Billing Determinants 2 TJ/day 1,097 15 296 106 3 TJ 2,047 77 8,900 17,786
4 Rate $/GJ/Month 1.827 1.827 2.813 1.484 5 IT/OR - $/GJ 0.078 0.054 0.050 0.014
6 Demand Revenue ($000) 4,009 55 1,665 315 - 6,044 7 IT/OR ($000) - - 160 4 445 249 - 858 8 Subtotal 4,009 55 1,825 319 445 249 - 6,901 9 Other Revenue (1) ------334 334 10 Total Revenue from Final Rates (b) 4,009 55 1,825 319 445 249 334 7,235
11 Revenue Surplus (a-b) (20)
1. Other Revenue Industrial Fixed 144 Encana 2,253 Chain Lakes 116 Calpine 12 FSD Large Industrial (523) Full Year Other Revenue 2,002 2/12 334
EUB Decision 2004-096 (October 29, 2004) 2004 GRA Phase II Compliance Filing ATCO Pipelines Appendix F Page 5 of 5 ATCO Pipeline 2004 Phase II General Rate Application - Phase II Compliance Filing - October 2004 South Year 2004
Peak Contract Fixed Commodity Demand Fixed Commodity Demand Other Total Throughput Demand Demand Charge Charge Charge Revenue Revenue Revenue Revenue Revenue (TJ's) (TJ/day) (TJ/day) $/month $/GJ $/GJ/mo ($000's) ($000's) ($000's) ($000's) ($000's) Distributing Companies ATCO Gas 1097.3 1097.3 (a) - - $ 1.827 - - 24,054 - 24,054 Gas Alberta 15.1 15.1 (a) - - $ 1.827 - - 331 - 331 Sub-total Distributing 1,112.4 1,112.4 - - 24,385 - 24,385
Producers Producers Firm 293 293 - - $ 2.813 - - 9,889 - 9,889 ATCO Gas Firm - 3 3 - $ - $ 2.813 - - 101 - 101 Producers IT/OR - Oct-May 10,453 - - $ 0.078 $ - - 815 - - 815 Producers IT/OR - June-Sept. (b) 1,830$ 0.093 170 170 Producers Facility - - - - $ - $ ------Sub-Total Producers 296 296 - 986 9,990 - 10,975
Industrial Industrial FSD One year 12 12 1,000.00 $ -$ 1.558 60 - 224 - 284 Industrial FSD three year 82 82 1,000.00 $ -$ 1.484 36 - 1,459 - 1,495 Industrial FSD five year 12 12 1,000.00 $ -$ 1.410 48 - 203 - 251 Industrial Overrun 461 - - $ 0.054 - 25 - 25 Sub-Total Industrials 106 106 144 25 - 1,887 2,056
OPD 53,397 $ 0.050 2,670 2,670 Franchise Fee Revenue (Riders A & B) 740 740 OPR 106,714 $ 0.014 1,494 1,494
Non Standard Encana 83$ 2.250 2,253 2,253 Chain Lakes 650 0 7,820.00 $ 0.034 $ - 94 22 - - 116 Calpine 55 1,000.00 $ -$ - 12 - - - 12 Sub-total Non Standard 244 106 22 2,253 - 2,381
FSD Large Industrial Rebate 21,780 - - $ (0.024) $ - - (523) - - (523)
Sub-total Industrial 250 (1,067) 1,889 - 1,072
Total Revenue 250 4,673 38,515 740 44,178 (a) Peak Demand for Distributing Companies revised to reflect Decision 2004-079 Table 15 (b) IT/OR for June to September up to FSR rate of $0.093 goes to revenue requirement. Remainder up to $0.240 goes to OPD Deferral Account.
EUB Decision 2004-096 (October 29, 2004)