IN THE MATTER OF

the Utilities Commission Act, R.S.B.C. 1996, Chapter 473

and

An Application by Terasen Gas Inc.

for Approval of a Gas Supply Mitigation Incentive Program

for the November 1, 2010 to October 31, 2013 Three-Year Period

BEFORE:               L.F. Kelsey, Commissioner                                           July 20, 2010

O R D E R

WHEREAS:

A.      By Order G-98-95 the British Columbia Utilities Commission (the Commission) approved an Off-System Incentive Program (OSIP) for Terasen Gas Inc. (Terasen Gas) (formerly known as BC Gas Utility Ltd.) for
a two-year period commencing January 1, 1996; and

B.      As part of its May 5, 1997 Revenue Requirements Application for 1998 to 2002, Terasen Gas filed a revised incentive plan.  During the Alternative Dispute Resolution process, it was agreed by all parties to deal with the form of gas cost incentive plan(s) that would succeed OSIP in a series of separate meetings.  The yearly meetings resulted in agreed-to plans sent to the Commission for approval.  The following Commission Orders approved a Gas Supply Mitigation Incentive Program (GSMIP) for each subsequent gas contract year:  Order G-125-97 for 1997/98, Order G-92-98 for 1998/99, Order G-82-99 for 1999/2000, Order G-106-00 for 2000/01, and Order G-124-01 for 2001/02; and

C.      Commission Order G-79-02 approved of the 2002/03 GSMIP in the form of the GSMIP Settlement Document attached as Appendix A; and

D.      The following Commission Orders approved the continuance of the 2002/03 GSMIP for each subsequent gas contract year without any revisions to the formula or the Service Quality Indicators:  Order G-67-03 for 2003/04, Order G-98-04 for 2004/05, Order G-83-05 for 2005/06, Order G-137-06 for 2006/07, Order
G-85-07 for 2007/08 and Order G-156-08 for 2008/09; and

E.       Commission Order G-101-09 approved the continuance of the 2002/03 GSMIP for the 2009/10 gas contract year with the understanding that GSMIP will be reviewed in 2010; and

F.       On July 13, 2010 Terasen Gas applied confidentially to the Commission for approval of a GSMIP for the November 1, 2010 to October 31, 2013 three-year period (the Application); and

G.     Terasen Gas proposes a negotiated settlement process to deal with the application and included a Proposed Regulatory Timetable in the Application; and

H.      The Commission considers that establishing a regulatory process and timetable for the review of the Application is necessary and in the public interest.

NOW THEREFORE the Commission orders as follows:

1.       The Application will be subject to a negotiated settlement process according to the Regulatory Timetable attached as Appendix B has been established.

2.       Interveners should register with the Commission, in writing or electronic submission, by Tuesday, August 3, 2010.  Interveners should specifically state the nature of their interest in the Application and identify generally the nature of the issues that they intend to pursue during the proceeding and the nature and extent of their anticipated involvement in the review process.

DATED at the City of Vancouver, in the Province of British Columbia, this      21^st                  day of July 2010.

                                                                                                                                BY ORDER

                                                                                                                                Original signed by:

L.F. Kelsey

Commissioner

Attachments

BC GAS UTILITY LTD.

The parties, consisting of Counsel representing the British Columbia Public Interest Advocacy Centre, BC Gas Utility Ltd. and the British Columbia Utilities Commission (Commission or BCUC), have met to consider revisions to the existing incentive arrangement.  The parties reviewed options for the year November 2002 through October 2003 (GSMIP 2002/03).  The parties agreed to continue with a GSMIP for the coming year that will generate sharing revenue based on mitigation recovery but will allow the Commission to disapprove of any Incentive payment if BC Gas’ overall Gas Supply service is deemed not acceptable for the Contract year.  To provide the BCUC the information to assess performance a number of Service Quality Indicators (SQI’s) have been developed.  A requirement to provide certain market information to assist Staff in its analysis is also included.  BCUC Staff will review performance under the SQI’s and the Commission shall have the right to disapprove of mitigation revenue sharing if it deems the performance of BC Gas under the SQI’s is not acceptable.  The revised mitigation sharing mechanism will continue to limit BC Gas’ revenue sharing in excess of $1 million.  The following objectives have not changed and should continue to serve as the guiding principles in determining the structure of GSMIP.

GSMIP Objectives and Guiding Principles

1.            Supply Security

                The plan should discourage any activity that might adversely affect the security of supply or total net gas costs.

2.            Alignment of Interests

                The plan should ensure that BC Gas maximizes net revenues from its off-system business activities.

3.            Fair and Reasonable Incentives

                The plan should be structured to avoid paying incentives for activities and results already achieved, but reward new, substantial exertions by the Company.

4.            Simplicity

                The plan should be structured in such a way that it minimizes administrative effort.

5.            Fair and Reasonable Performance Targets

The plan should ensure that performance targets and expected productivity improvements are just and reasonable and that the level of incentive sharing corresponds to the level of excellence demonstrated by BC Gas’ gas procurement and mitigation activities.

This document sets out the terms of GSMIP 2002/03, which those participating in the meetings consider to be appropriate for implementation by BC Gas.  Agreement on the terms and conditions of this arrangement involved compromise, and this settlement represents a balance of interests and consensus among the parties.

Key Components of Gas Supply

The key components of Gas Supply are sequential as follows:

1.       Development of an Annual Contracting Plan to acquire an optimum mix of transport, storage and supply contracts including implementation of the Annual Contracting Plan.

2.       Planning and implementing the Price Risk Management Plan.

3.       Managing counterparty risk and credit exposures.

4.       Ensuring 100% Firm customer commodity supply reliability.

Providing acceptable performance in these four key components should indicate that BC Gas has met the criteria of acceptable service quality for Firm customers.

GSMIP Structure

1.            Term

                The term of GSMIP 2002/03 will commence on November 1, 2002 and will expire on October 31, 2003.  In order to determine the incentive to be received by BC Gas in 2003, the Company’s performance during the gas contract year ending October 31, 2003 will be examined.  If appropriate, and upon approval by the Commission, BC Gas will then withdraw from the Gas Cost Reconciliation Account any incentive amounts earned.

2.            Expiration & Incentive Review

                GSMIP 2002/03 is recognized as temporary or interim in nature, applying to the November 1, 2002 - October 31, 2003 contract period only.  At the end of the period it will be reviewed and its disposition — i.e. abandonment, replacement or continuation — will be subject to Commission approval.

3.            Service Quality Indicators

The Service Quality Indicators (SQI’s) are being introduced into the GSMIP plan to provide information for the BCUC to assess the overall performance of the Gas Supply Function.  Each of the SQI’s will have identifiable targets that establish acceptable performance.  At the year-end BC Gas is required to file a report on performance relative to the SQI’s.  The Commission will then determine if the results of the SQI’s determine that BC Gas has provided an acceptable level of overall Gas Supply Service in the year.  The SQI’s are as follows:

3.1.       Annual Contract Plan (ACP) - Portfolio Optimization

As part of the ACP submission, BC Gas shall provide a cost summary template that will illustrate the expected overall costs of the proposed portfolio vs. the current portfolio.  Commodity and asset pricing used to determine overall costs for both portfolios will be based on forward market expectations at the time of submission.  For example, if current asset costs are forecast to increase in cost for the coming contract year that will be the new baseline used in the comparator analysis.

Performance Target: The ACP must be submitted to the BCUC by March 31 of each year.  The approved ACP, including any revisions throughout the year, must be successfully implemented over the contracting period recognizing those market conditions that may arise.

3.2.       Price Risk Management Plan (PRMP) Implementation

BC Gas submits the PRMP to the Commission each spring to seek approval for hedging limits for the following contract periods.  Once the BCUC approves the PRMP, BC Gas begins implementation within the approved guidelines.  BC Gas then provides to the BCUC all trade data including submission of quarterly updates on the mark to market activities.  From time to time the Staff also request information on status of the plan and BC Gas’ strategy position.  PRMP activities are an important part of the Gas Supply Function with the financial positions often having a significant impact on overall gas costs.

Performance Target: BC Gas is to continue to provide the PRMP in a timely fashion meeting the expectations of the Commission for approval.  BC Gas is to implement the PRMP including any approved revisions within the guidelines presented in the plan including any provisions or understanding about transaction volumes within stated timelines.

3.3.       Counterparty Risk and Credit Exposure Management

Implementation of financial and physical transactions necessary to optimize Gas Supply management for Firm customers creates significant credit exposure.  BC Gas has a conservative and well defined credit policy that is actively managed and has avoided non-recoveries over the last 2 years of volatile markets.  This has been a significant benefit to Firm customers.  Credit exposure now has a significant influence on Term gas contracting and need to minimize surplus sales and associated credit risk.  BC Gas is to provide a report that summarizes credit management activities over the year, outlining mitigation strategies put in place to manage marketplace dynamics and identifying any defaults.

Performance Target:  BC Gas is to show that it has effectively managed credit exposure for Firm customers prudently avoiding potential non-recoveries if deemed reasonably preventable.

3.4.       Commodity Supply Reliability

BC Gas must balance cost minimization with supply reliability.  Ensuring that Firm customers have 100% of Firm requirements is an over-riding objective of Gas Supply.  BC Gas shall provide a report to the Commission identifying any curtailments of Firm customers over the year.  This report will also identify curtailments of Interruptible customers.  Supply reliability also includes reliability of assets contracted by BC Gas to meet customer needs.  Contract default and Interruptible curtailments are subject to market conditions so targets are not being established for them.  BC Gas will also summarize reliability measures put in place for the contracting year and a summary of any supply failures of commodity, pipeline and storage assets.

Performance Target:  100% delivery of Firm customer demand.

4.            Gas Cost and Market Pricing Information

This information is to be provided to the Commission on a monthly basis to provide the BCUC Staff relevant market information.

4.1.         Regional Local Distribution Companies Rate Indicators

BC Gas is to provide a report that summarizes monthly Gas Costs as available for other regional LDC’s such as Cascade, Puget, Avista, Northwest Natural and ATCO over the contract year.  BC Gas will also provide a summary of the portfolio’s utilized by each of these other LDC’s and illustrate differences from the BC Gas portfolio.  Determination of the regional LDC portfolios will be through review of public information and discussion with each of their respective Gas Supply departments and will therefore be an estimate only.  Regulator approved and implemented financial price fixing activity and deferral treatment vary significantly between the LDC’s and drive rates to a large extent so individual LDC rates could vary significantly at a given time.

4.2.         BC Gas Actual Gas Costs and Market Index prices

BC Gas shall provide actual incurred monthly Gas Costs before hedging.  BC Gas shall also provide data on actual Daily and Monthly Index prices at Sumas, NYMEX, AECO and Station 2.  This Data will used to calculate Gas Cost proxy’s for purchasing 100% of daily Firm demand at both the Sumas and AECO Daily Midpoint Index for reference.  BC Gas shall also provide historical Gas Cost and market price information back to January 1997 to provide historical illustrations.  Because the Sumas Daily price does not meet intra-day balancing needs and there is insufficient market liquidity to ever consider this kind of purchase strategy the comparison is only a proxy and does not define any true measure other than to show how the portfolio approach protects customers from much of the market volatility even before hedging activity.

                4.3.         Commodity Costs compared to Market

BC Gas develops a portfolio of pipeline, storage and commodity contracts that provide supply reliability and price diversity for Firm customers.  The majority of BC Gas’ Firm demand is in the Lower Mainland and is tied to the Sumas Hub.  The Sumas market is currently not liquid and is subject to considerable volatility.  BC Gas must be a significant contributor to managing demand variability at this location.  The portfolio of assets is accepted as necessary to manage Firm customer load variability and access less volatile supply sources upstream.  Value recovery realized on transport and storage assets is subject to the volatile nature of market conditions and will vary considerably from year to year.  Therefore, performance on contracted assets should be based on portfolio development and recovery of available mitigation value as proposed in this plan.  

The portfolio assets provide commodity purchasing options to BC Gas.  BC Gas commodity buying should be reasonably competitive with market price availability.  BC Gas will provide monthly data on actual Gas commodity purchase costs before hedging compared to Sumas, Station 2 and AECO Monthly and Daily Index priced gas.

5.            Sharing Mechanism

                Objectives

▪  Continue with separate commodity and transport revenue mechanisms combining the two revenues into one overall sharing allocation.

▪  Revise the sharing hurdle to reference total monthly gas purchase cost instead of just the fixed component.  The total gas purchase cost shall be the monthly Sumas Index.  The existing commodity mechanism concept of sharing on the last $1/GJ of hurdle rate revenue will continue in concept, but the hurdle for 2002/03 will be based on total gas purchase cost as identified by the Sumas Monthly Index rather than contractual fixed costs as in 2001/02.

▪  Revise the sharing mechanism to reflect lower available surplus Firm customer volumes using a linear adjustment to the $1/GJ hurdle rate revenue sharing proportion to maintain the potential for $1 million sharing with a high level of recovery on actual Firm volumes resold.  Transport and storage revenue assumptions are factored into this mechanism to recognize this revenue contributes to the overall sharing capability to $1 million.  Continue to cap total sharing at 1.25% after $1 million sharing is earned.

6.            Incentive Structure Summary

BC Gas recovers mitigation revenue from recovery of revenue from surplus term gas purchased for Firm customers and third party recovery of value from unutilized Firm customer pipeline capacity and storage assets.  Each of these activities is distinctly separate transactions.  Eligible commodity sharing and transport and storage margin will be combined to calculate the basis for BC Gas’ final incentive sharing.

a)      Eligible Commodity Resale

BC Gas’ commodity sharing reward is dependent primarily on how close it can come to achieving full recovery of purchase costs for core customers regardless of commodity pricing and volume available for resale.  BC Gas’ revenue sharing on each gas unit resold will be dependent on total surplus Firm volumes sold in the contract year.  The lower the Firm volume available the higher the BC Gas sharing on total revenue recovered.  The amount of resale revenue BC Gas shares is based on a discount from the Monthly Sumas Index.  This discount from the Index varies based on the formula 17 / (Annual PJ sold).  The formula factors in a total revenue recovery from transport and storage mitigation of $ 3 million.  This formula allows BC Gas to achieve $1 million of sharing revenue if it achieves 100% full recovery of purchase costs on all re-sales and the $3 million of asset mitigation.  The methodology is further detailed in the attached Definitions and on the following table.

Justification for the new Commodity Sharing Mechanism

▪  It will better align BC Gas and customers to margin recovery per unit resold.

▪  It will better incent BC Gas for overall cost optimization by reducing sharing revenue uncertainty associated with resale volume availability.

b)    Transport and Storage

The existing transportation and storage mechanism works well and shall be continued.  This activity will include the net revenue from spot gas purchases and sales transacted to recover revenue from core transportation and storage assets.

BC Gas Sharing Incentive

The parties agree to combine the transport and storage revenue with the eligible commodity revenue to create one sharing mechanism. BC Gas’ incentive share will be 5% of the Total Eligible Margin up to the first $1 million sharing earned.

▪  When BC Gas achieves $1 million sharing, the BC Gas share will reduce to 1.25% on all remaining Total Eligible Margin.

The sharing mechanism is illustrated below:

The proposed new mechanism meets the objective of limiting BC Gas’ sharing in the case of extreme mitigation revenue opportunity available but still provides reasonable sharing when minimal or more historic opportunity, such as is forecast next year, is available to be recovered by BC Gas.

7.            Employee Incentives

                Within the context of other incentive plans and market competitive compensation levels for employees, BC Gas will continue to recognize those Gas Supply and Industrial Services employees deemed to have directly or indirectly contributed toward the generation of net revenues achieved under this GSMIP 2002/03.  Such incentive compensation will be based upon and related to the incentive earnings of BC Gas.

8.            Regulatory & Management Reporting

                In order for the Commission to adequately monitor and evaluate the Company’s performance, the already well-developed record-keeping and reporting procedures will be continued.  BC Gas will also continue with its current practice of regular quarterly filings with the Commission consisting of a summary report that details all off-system and non-core on-system activity and associated financial impacts.  This report will be submitted to the BCUC within two months of the quarter-end.  BC Gas will also provide an update on the status of the SQI’s and Gas Cost and Market Pricing on a monthly basis within two weeks of the month-end.

                BC Gas will also continue to keep distinct and separate records, for audit purposes, of its daily “Priority Schedule”, which determines the available supply and its marginal costs, a daily “Load Forecast Sheet”, which details all on-system supply requirements, and a “Deal Sheet” for each and every transaction that will feature all information as it relates to the economics of each transaction.

                BC Gas will confer with Commission staff to ensure that these reports provide an appropriate level of disclosure and audit capability with a minimum of administrative burden.  Commission staff will examine the calculation of any incentive payments received under the GSMIP 2002/03 and the Commission will make any appropriate adjustments.  For the benefit of interested parties, an overview report will be issued by Commission staff at the end of the term.  Such report shall provide an analysis of the effectiveness of the GSMIP 2002/03.

Definitions

Terasen Gas Inc.

An Application for Approval of a Gas Supply Mitigation Incentive Program

for the November 1, 2010 to October 31, 2013 Three-Year Period

REGULATORY TIMETABLE