CERISE MONTHLY NEWSLETTER Volume 7, Issue 11 November 2008 About The CERISE INSIDE THIS ISSUE Newsletter

“WHAT IS NEW” ( NOVEMBER ALERTS) Welcome to the Monthly CERISE Newsletter, a service 1 CANADA provided to you as CERISE subscribers. This document • ESC Advises that Looming Worker Shortage Could Impact Industry's Ability contains a compilation of to Meet Canada's Rising Electricity Demand While Hewitt Reports that material from our website for Employers Consider Phased Retirement to Ease Skills Shortage the last month including the What’s New items, the most • Enbridge Issues $500 Million of Long Term Debt important decision summaries and the new articles. This • TransCanada to Issue $1.0 Billion of Common Shares information is provided in a PDF format that can be • Enbridge Increases Stake in Enbridge Energy Partners printed, providing a document that can be reviewed when you • TD Bank Research Paper Assesses Greenhouse Gas Reduction Policy are away from your computer Options such as when you are 4 ALBERTA travelling or waiting for an appointment. This will allow • Direct Energy Regulated Services Files December 2008 Rates you to catch up on those items that you might have noticed • AUC Approves Revisions to ATCO Gas Schedule C Charges and Rural Pool when the alert came out but Connection Charges were unable to follow-up at the time. We trust you will find this • AUC Approves ATCO Gas Application for Approval of Rate Riders to Collect service useful, and as always, Customer Care and Billing Costs for Period 2003 to 2007 would welcome any comments • AUC Approves ATCO Gas Terms and Conditions of Service – Schedule C and suggestions you might have. • AUC Approves AltaGas Utilities’ Application to Adjust Rate Rider ‘E’ – Unaccounted-For Gas

• AUC Issues Decision With Respect to ATCO Gas 2008-2009 General Rate Application

• AUC Denies Russ Duncan Application to Recover Alberta Distribution System Costs Through NGTL Transmission by Others Service • AUC Issues Three Permits and Licences to ATCO Gas and Pipelines South

• AUC Denies City of Calgary Applications for Review of Decision 2006-098 and Utility Cost Order UCO 2006-064

• Alberta Government Advises that Natural Gas Price Triggers Rebate for November 2008

• AUC Approves AltaGas Compliance Filing With Respect to Directions Set 34 King Street E. Suite 620 Out in Decision 2008-103 Toronto, ON M5C 2X8 • ENMAX Advises that Calgary's Regulated Default Electricity Rate for Tel: (416)348-8883 December 2008 Will Be 12.18 Cents Per Kilowatt Hour Fax: 416-348-9930 Email: [email protected] • AUC Denies Request for Transfer of Power Plant Approval from Wind Power to Castle Rock Ridge LP On the Web, visit us at: • AUC Approves 2009 Interim Regulated Rate Option Non-energy Rates for http://www.cerise.info ENMAX Energy Corporation • AUC Agrees to Date of March 31, 2009 for AltaLink Refiling of Application With Respect to Updated TFO Terms and Conditions of Service • AUC Issues Nine Substation Permit and Licence Orders With Respect to Petro-Canada Oil Sands Inc • AUC Grants Petro-Canada Oil Sands Inc. Authorization to Construct a Double Circuit 144-kV Transmission Line in the Fort Hills ISD Area • AUC Grants Petro-Canada Oil Sands Inc. Industrial Systems Designation for Certain Facilities Associated With the Fort Hills Industrial Complex • AUC Grants Interim Approval to ATCO Electric Motion Seeking Confidential Treatment of the Establishment Audit • AESO Approves a New AESO Rider F Effective January 1, 2008 • AUC Confirms Alberta MSA Assessment of Specified Penalty to EPCOR PPA Management • AUC Issues Power Plant Approval No. U2008-196 and Connection Order U2008-197 for Prairie Home Wind Power Plant in the Wrentham Area • AUC Authorizes ATCO Electric to Alter and Operate Bridge Creek Substation 798S • AUC Approves a Regulated Rate Tariff 2007 Deferral Rider Schedule and Default Rate Tariff 2007 Deferral Rider Schedules for Direct Energy Regulated Services • AUC Releases Findings on AltaLink’s Updated Terms and Conditions • AUC Approves the Reorganization of TransAlta Corporation Group’s Corporate Structure • ATCO Midstream Announces Purchase of Assets in NWT • AUC Grants AltaLink Management Application to Issue is up to $150 Million of Medium Term Notes with a Term of up to 20 Years • Alberta Government Introduces Legislation to Implement New Royalty Framework • EPCOR Power L.P. and EPCOR Power Equity Ltd. Announce Closing of Morris Cogeneration LLC Acquisition 23 BRITISH COLUMBIA • BCUC Grants Terasen Fort Nelson Application for Approval to Amend its Schedule of Rates Effective January 1, 2009 for the Fort Nelson Service Area • NEB Approves Westcoast (Spectra Energy) South Peace Pipeline Project • Terasen Gas Launches Compressed Natural Gas Vehicle Program • BCUC Accepts Filing of Gas EDI Base Contract and Special Provisions for the Short Term Sale and Purchase of Natural Gas Between EOG Resources and Terasen Gas • BCUC Accepts for Filing Gas Supply Contracts Submitted by Pacific Northern Gas Ltd. • BCUC Accepts Filing of Gas EDI Base Contract and Special Provisions for the Short Term Sale and Purchase of Natural Gas between Nexen Marketing and Terasen Gas • BCUC Rules that Big White Gas Utility Should Continue to Operate Under its Existing Tariff Without Filing a 2008 Revenue Requirements Application • Spectra Energy's Pine River Phase III Project Comes Into Service

- ii - Cerise, Volume 7, Issue 11-November 2008 • British Columbia Investing $400,000 to Support Electrical Vehicle Technology • BCTC Files Ten Year Capital Plan with the BCUC • BCUC Agrees to Limited Reconsideration of Decision Granting FortisBC Approval for Lochrem Road Site for the Ellison Substation • BCUC Denies FortisBC Request for a CPCN for Its Advanced Metering Infrastructure Project • BCUC Denies FortisBC Application for a CPCN for Copper Conductor Replacement Project • BCUC Approves BC Hydro Application for a RIB Rate Exemption for Group of Customers Enrolled in RIB Control Group • B.C. Government Announces that David Emerson Will be Chair and CEO of BCTC • B.C. Government Sets GHG Targets for 2012 And 2016 • BC Government Signs Joint Declaration on Action to Reduce GHG Emissions During Governors’ Global Climate Summit in California • BC Government’s ICE Fund Backs Nexterra in its Supply of Biomass Gasification System to Kruger Products Paper Mill • BCTC Announces Departure of its President and CEO Jane Peverett 32 MANITOBA • MB Hydro Introduces Residential Solar Water Heating Program • Manitoba Hydro Board Accepts RFP Proposal for 300 MW Wind Farm at St. Joseph • Manitoba Board Issues Order Revising Certain Directives from Order 116/08 • Manitoba Government Announces $5-Million Project to Investigate Use of Carbon Dioxide to Enhance Oil Recovery 33 NEW BRUNSWICK • NB Regulator Issues Decision Concerning Proposed Changes to NBSO Open Access Transmission Tariff • NBSO Posts Report on Large Scale Wind Power in New Brunswick • NB Government Announces the Release of Strategic Environmental Assessment Report on Tidal Energy in Bay of Fundy Coastal Waters • NB Power Signs Memorandum of Understanding with Efficiency NB • New Brunswick Government to Invest Additional $6.3 Million into Energy Efficiency and Other Programs • New Brunswick System Operator Releases Annual Report for 2007-2008 38 NEWFOUNDLAND • Nfld PUB Approves 2009 Capital Budget Application Filed by Newfoundland Power 39 NORTHWEST TERRITORIES • NWT PUB Approves Application from Northland Utilities (Yellowknife) Limited for Approval for Changes to Existing Rider C • NWT PUB Approves Application from Northland Utilities (NWT) Limited for Approval for Changes to NTPC Shortfall Rider, Rider F • Northwest Territories Board Issues Decision With Respect to Phase II of Northland Utilities (Yellowknife) Ltd. 2008/2010 GRA - iii - Cerise, Volume 7, Issue 11-November 2008 • Northwest Territories Board Issues Decision With Respect to Phase II of Northland Utilities (NWT) Ltd. 2008/2010 GRA • Northwest Territories Board Approved Updated Refiling of Northwest Territories Power Corporation Phase 2 Application • Northwest Territories Board Releases Decision Concerning Northwest Territories Power Corporation Phase 1 GRA for Period April 1, 2006 to March 31, 2008 • Northwest Territories Board Issues Decision With Respect to Northland Utilities Limited 2008/2010 GRA • North West Territories Board Issues Decision for Northland Utilities (Yellowknife) Limited 2008/2010 GRA 46 NOVA SCOTIA • NEB and CNSOPB Agree to Partnership • Nova Scotia Board Approves Rate Application filed by Town of Lunenburg on Behalf of its Electric Utility • Emera Appoints Donald Pether to its Board of Directors 47 ONTARIO • OEB Issues Decision and Order for Joint Application by Chatham-Kent Hydro and Middlesex Power Distribution to Recover the Costs of Smart Meters • OEB Issues 2008 Electricity Distribution Rate Order for Erie Thames Powerlines Corporation • OEB Announces Further Consultation on Stretch Factor Rankings for 3rd Generation Incentive Regulation for Electricity Distributors • IESO Posts Its Submissions to the OEB With Respect to Kruger Energy Section 81 Proposal • OEB Posts November 2008’s Electricity Regulated Price Plan Variance Settlement Factor • OEB Issues 2008 Electricity Distribution Rate Order for Horizon Utilities Corporation • Kruger Energy Announces the Official Opening of its First Wind Farm in Ontario • OEB Issues Decision on 2008 Electricity Distribution Rate Application for Brant County Power • Ontario IESO Releases Fixed Global Adjustment Rate for November 2008 Distributor Billing • OPA Releases Its “2009 - 2011 Business Plan” • CEAA Announces Public Review Period on the EIS and Application for a Licence to Prepare a Site for the Proposed Bruce Power New Nuclear Power Plant Project • OEB Establishes Framework on Payment Levels for OPG Regulated Assets • Infrastructure Ontario Advises of Short Extension of Deadline for Nuclear Procurement Project Bid Submissions • Bruce Power Receives Boost in Plan for Life Extensions of Bruce A Units 3 and 4 • Ontario IESO Posts 2009 Fees Application • Ontario IESO Announces Estimated Global Adjustment for October, 2008 • Bruce Power Announces Intent to Conduct Environmental Assessment for - iv - Cerise, Volume 7, Issue 11-November 2008 Nuclear Generating Station Near Nanticoke But Ontario Government Not Supportive of Proposal • Ontario Task Force on Competitiveness, Productivity and Economic Progress Recommends Revenue Neutral Carbon Tax • Barrie Hydro and PowerStream Post Amalgamation Application and Notice 56 QUEBEC • The Régie Partially Approves Gaz Métro’s 2009 Rate Application, Supply Plan and Energy Efficiency Plan • Innergex Advises that Carlton Wind Farm Began Operations on November 22, 2008 • Hydro-Québec Gives SGL Canada $825 000 to Implement Energy Efficiency Projects • Hydro-Québec Gives Eka Chimie $678,000 to Implement Energy Efficiency Projects • Gaz Métro Reports Strong Results for its 2008 Fiscal Year 58 SASKATCHEWAN • Joint Report by NEB and Saskatchewan Reveals Potential for Years of Sustained Activity in Saskatchewan's Conventional Natural Gas Industry • CNSC Posts “Saskatchewan 2020 Clean energy New opportunity”, Bruce Power’s Report on Its Feasibility Study • Saskatchewan Government, Royal Dutch Shell and University of Regina Establish International CO2 Storage Assessment Centre 60 YUKON • Yukon Board Denies Yukon Energy Request for Interim Rate Rider U and Approves Rate Reduction for Most Rate Classes • Yukon Energy Announces Completion of Phase 1 of Carmacks-Stewart Line 60 UNITED STATES OF AMERICA • NRRI Releases Research Paper Entitled “Speculation in the Natural Gas Market: What It Is and What It Isn’t; When It’s Good and When It’s Bad” • NERC Releases its “2008/2009 Winter Reliability Assessment”, Indicating that Winter Electric Reliability Outlook is Generally Good • NYISO Forecasts Sufficient Electricity Supply for Winter 2008-2009 • NERC Releases Report on “Electric Industry Concerns on Reliability Impacts of Climate Change Initiatives • Midwest ISO Projects Region to Have Adequate Power to Meet Winter Demand • FERC Approves Incentives for Pepco’s Mid-Atlantic Grid Expansion • Spectra Energy Issues First Sustainability Report • NARUC Announces Appointments of its New President and Vice-Presidents • EIA Posts Updated “Short-Term Energy Outlook” • U.S. FERC Releases Its “2008 Report on Enforcement”

67 INTERNATIONAL • European Commission Adopts Revised Proposal for a Directive Setting up a Community Framework for Nuclear Safety • UK Government Launches “ACT ON CO2” People Power Challenge - v - Cerise, Volume 7, Issue 11-November 2008 Initiative • European Commission Issues Green Paper Entitled “Towards a Secure, Sustainable and Competitive European Energy Network” • U.K. Department of Energy and Climate Change Announces Enhancements to Existing Program to Address Fuel Poverty in Britain • European Commission Launches New Citizens' Energy Forum

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Copyright in all the material produced by CERISE for this newsletter is held either by CERISE or by the individual author. No reproduction of the material is authorized except with the consent of the holder of the copyright. Please contact Keith Bryan for permission to use this material. - vi - Cerise, Volume 7, Issue 11-November 2008 2005, with all provinces (except British CANADA Columbia) reporting declines. Encouragingly, General registration in electricity sector apprenticeship November 26, 2008 training programs increased by six per cent between 2003 and 2005. ESC Advises that Looming Worker Shortage Could Impact Industry's Ability to Meet The ESC also advises that retirement poses an Canada's Rising Electricity Demand While immediate challenge to the stability of the Hewitt Reports that Employers Consider electricity industry's human resources. The Phased Retirement to Ease Skills Shortage Council projects an annual retirement rate of 6.2 per cent by 2012, and the report shows that 28.8 Canada's Electricity Sector Council (“ESC” or per cent of the current electricity workforce is “the Council”) has released its 2008 workforce expected to retire within the next four years. planning report, "Powering Up the Future" which Electricity transmission faces the greatest reveals a critical shortage of engineers and challenge, and will see an increase in trades people, which, it says will have a retirements of over 750 per cent by 2009 and significant effect on the industry's support of more than 900 per cent by 2012. The ESC adds electrical energy in Canada. ESC says that the that its workforce development portfolio of electricity industry faces an immediate shortfall projects works to offset this labour loss by of 1,300 positions every year for the next three identifying best practices in Canada and around years, and must replace nearly 30 per cent of the world, and developing sector-specific online industry positions or approximately 25,000 tools such as templates and succession people within the next six years to meet planning processes to help organizations Canada's energy demands, currently rising by prepare for the radical shift in the workforce. one per cent each year. The announcement goes on to say that, in The ESC suggests that the electricity industry is recognition of the impending labour shortages unique from other industries in the educational which put the electricity sector at risk, the and training demands it makes of its workers, in workforce planning report recommends a that, at a minimum, its jobs require a high school number of important strategies to encourage diploma or completion of a four-year recruitment of foreign-trained workers and apprenticeship, and the vast majority of the traditionally under-employed groups such as electricity industry's positions need post- women, aboriginals, immigrants and visible secondary education. The Council says that if minorities. The ESC is targeting retirement the industry is to address these shortages in vacancies as opportunities for the industry to time through Canada's learning institutions and better support diversity through programs such immigration channels, it must act now. as its Foreign Credential Project and The ESC suggests that education is key to Connectivity Project. To further this effort, the increasing labour supply. The Council says that report urges industry and training institutions to the electricity industry offers its workers job develop targeted training courses for these security, competitive compensation and enjoys groups to help facilitate entry into the industry. excellent retention rates. However, the supply of Other key recommendations include the trained younger workers is declining and the development of a foreign credential recognition electricity sector faces increased competition for strategy to increase the integration of foreign their services as other industries face similar trained workers into the electricity sector, and demographic challenges. The report found focused marketing and promotional activities to enrolment in electrical engineering programs encourage youth and under-employed groups to decreased by 10 per cent between 2003 and consider a career in an electricity-related trade. - 1 - Cerise, Volume 7, Issue 11-November 2008 The Electricity Sector Council is an independent, implementing phased retirement programs, not-for-profit organization funded by the respondents indicated their motives are to Government of Canada with support from facilitate the transfer of key skills and knowledge participating businesses, labour organizations, to less experienced employees, ease the educators and stakeholder associations. The difficulty of replacing key skills, and to have the ESC provides support to 100,000 electricity and opportunity to use experienced employees in renewable energy workers by working with new roles or for special projects. industry employers and stakeholders to research Hewitt suggests that, in order to create effective and resolve human resource and workplace phased retirement programs, employers need development issues such as recruiting and to: retraining workers, facilitating school-to-work transitions and developing sector and career • Identify where the departure of those awareness strategies. approaching retirement will leave them with a skills shortage that is difficult to fill, In a somewhat related press release, Hewitt Associates (“Hewitt”) says that a survey it • Ascertain what type of arrangement would be conducted showed that almost three quarters of appealing to this group of older employees, employers view phased retirement programs as and an important element of their human resources • Determine how they can accommodate strategy over the next five years. Moreover, phased retirement, while meeting business factors such as the impact of the current objectives. financial crisis on retirement savings and a growing interest on the part of Baby Boomers in Hewitt notes that, in many cases, employers working past early retirement age may mean who already offer flexible work arrangements that older workers can be more easily convinced may not need to introduce special phased to stay on the job. retirement programs for older workers. Currently, the phased retirement programs most Hewitt says that phased retirement programs frequently offered by Canadian employers are allow employees nearing retirement to reduce year-round, part-time employment (provided by their work commitment, while still remaining 20 per cent of organizations) and work on active with the same employer. Hewitt says that special projects (provided by 15 per cent). older employees are being offered reduced workdays/workweeks, job sharing and flex time, Hewitt advises that, for some older workers, the while retirees may be rehired by their former ability to continue to accrue savings will be employer as part-time employees or consultants. enough to keep them on the job - perhaps even full-time. However, financial considerations The press release says that over half (52.5 per aside, employers realize that in order to cent) of the 171 survey respondents already encourage near-retirement employees to have a formal and/or informal phased retirement continue working, they have to enable them to program in place. Another 33 per cent reported make a valuable contribution to the success of that they do not currently offer phased the organization and give them interesting, retirement but are interested in establishing a challenging work to do. They must focus on program. Organizations in the United States engaging this group of employees, just as they express a similar interest: 47 per cent currently do others in the organization. offer phased retirement programs and almost 40 per cent more plan to do so, according to a November 20, 2008 survey conducted by Hewitt in June 2008. Enbridge Issues $500 Million of Long Term Hewitt reports that the impending mass exodus Debt of the Baby Boomers from the workforce has Enbridge Inc. (“Enbridge”) has announced that employers concerned about the vast amount of its wholly owned subsidiary Enbridge Pipelines knowledge and experience which will leave with Inc. (“EPI”) has placed with 30 institutional them. Hewitt says that when it asked investors a $300 million 10-year term debt organizations for their primary reasons for - 2 - Cerise, Volume 7, Issue 11-November 2008 issuance which carries a 6.62 % coupon. Partners L.P. ("Enbridge Partners" or "EEP") have announced that Enbridge has agreed to The announcement notes that this follows a subscribe for 16.25 million Class A common $200 million five-year term debt issuance by units of EEP at a price of US$30.76 per unit, or Enbridge Gas Distribution completed on approximately US$500 million in aggregate. The November 12, 2008. This debt carries a coupon units will be acquired by Enbridge's subsidiary, of 5.57% and was placed with 32 institutional Enbridge Energy Company, Inc., the general investors. partner of EEP, which will also contribute November 18, 2008 approximately US$10 million to maintain its TransCanada to Issue $1.0 Billion of 2.0% general partner interest. The Common Shares announcement says that the transaction has been approved by an independent committee of TransCanada Corporation (“TransCanada” or the Board of Directors of Enbridge Energy “the Corporation”) has advised that it has Management, L.L.C. on behalf of EEP. entered into an agreement with a syndicate of underwriters, led by RBC Capital Markets, BMO According to the announcement, Enbridge's Capital Markets, and TD Securities Inc. under overall ownership in EEP will increase from which they have agreed to purchase from approximately 15% to approximately 27% as a TransCanada and sell to the public 30,500,000 result of this transaction, which is expected to Common Shares. close on December 4, 2008. According to the announcement, the purchase November 12, 2008 price of $33.00 per Common Share will result in TD Bank Research Paper Assesses gross proceeds of approximately $1.0 billion, Greenhouse Gas Reduction Policy Options and the net proceeds of the offering will be used The TD Bank Financial Group (“TD”) says that a by TransCanada to partially fund capital projects paper entitled “Choosing Greenhouse Gas of the Corporation, including the Keystone Reduction Policies in Canada”, which was Pipeline System, for general corporate purposes prepared on its behalf by the Pembina Institute and to repay short-term indebtedness. (“PI”) and which identifies and assesses policies TransCanada says that the Common Shares will against a set of criteria to determine the most be offered to the public in Canada and the U.S. efficient and effective options, indicates that through the underwriters or their affiliates. The financial incentives, voluntary measures and Corporation has also granted the underwriters public information policies are not adequate to an option to purchase up to an additional reduce Canada's total national emissions on 4,575,000 Common Shares at a price of $33.00 their own. In preparing the paper, PI conducted per Common Share at any time up to 30 days a survey of existing studies and international after closing of the offering. experience. TD adds that its intent in releasing The announcement adds that the Common the paper is to provide policy makers with Shares will be issued by way of a prospectus concrete and comprehensive resources to supplement which will be filed with securities ensure they can develop climate policies that regulatory authorities in Canada and the U.S. work for both the environment and the economy. under TransCanada's short form base shelf TD says that it commissioned the paper prospectus dated July 2, 2008, which was because it believes that action to reduce previously filed with securities regulatory greenhouse gas (“GHG”) pollution in Canada is authorities across Canada and in the U.S. under being hampered by a lack of analysis on the the multi-jurisdictional disclosure system. most efficient policies from an economic and November 18, 2008 environmental perspective, which has led to a reign of confusion with various factions arguing Enbridge Increases Stake in Enbridge the relative merits of key policy options such as Energy Partners regulation, cap-and-trade and carbon taxation. Enbridge Inc. (“Enbridge”) and Enbridge Energy TD adds that the uncertainty around this vital - 3 - Cerise, Volume 7, Issue 11-November 2008 issue poses a serious cost as businesses have • The specific policies and price levels needed little idea how to factor future environmental to overcome market barriers that can prevent policies into their planning. consumers and businesses from taking up The paper says that Canadian governments cost-effective options to reduce emissions. must implement policy options at the more • An independent assessment of the mandatory end of the policy spectrum and that vulnerability of various Canadian industrial the right policy mix will necessarily span sectors to competitiveness impacts from numerous jurisdictions: no one government carbon pricing, and, if vulnerability is found, controls all the levers. the policies best suited to mitigate that The announcement provides the following vulnerability. summary of the three broad themes which ALBERTA emerged from the report: Natural Gas Strong consensus November 26, 2008 The review uncovered far more areas of consensus than of disagreement among Direct Energy Regulated Services Files experts. For instance, theory and practice December 2008 Rates confirm that reducing emissions in a cost- Direct Energy Regulated Services (“Direct effective way starts with a clear price signal that Energy” or “DERS”) has advised that it has filed reflects the costs of GHG pollution. with the Alberta Utilities Commission (“AUC” or Complementing that price signal with targeted “the Commission”) proposed regulated natural regulations and spending can increase its gas rates for December 2008. Upon approval, effectiveness, and governments have a number these rates will apply to customers who have not of proven policy options to choose from to do chosen a competitive supplier within the ATCO this. Gas North and South service territories. Ongoing debate North Service Territory Several recent announcements of emissions The North territory includes customers living in trading and carbon tax proposals have produced and north of the City of Red Deer. a heated “tax vs. trading” discussion in media and political circles in Canada. However, careful • For customers in the ATCO Gas North service assessment shows that the two approaches territory, the proposed December regulated have far more in common than their respective natural gas rate is increasing from the proponents tend to suggest. (An attachment November rate of $7.168 per GJ to $7.210 per from the report provides a detailed comparison.) GJ. Moreover, these two carbon pricing strategies • This rate reflects a market price for December are necessary but not sufficient. A supplies of approximately $6.92 per GJ as comprehensive suite of policies — so-called reported by the NGX, and incorporates an “silver buckshot” rather than a silver bullet — are adjustment of $0.29 per GJ for November and likely needed in addition to a carbon price signal prior months. in order to capture reasonably priced emission reduction opportunities which would otherwise • The typical residential gas bill for December go unrealized. based on an average 19 GJ of consumption would be approximately $178 in the North. Further research is required South Service Territory As governments move to implement climate policies in Canada, this paper has found several The South territory includes customers living areas where further research would be south of the City of Red Deer. beneficial. These areas include: • For customers in the ATCO Gas South service territory, the proposed December regulated

- 4 - Cerise, Volume 7, Issue 11-November 2008 natural gas rate is increasing from the Pool Connection Charge. November rate of $6.884 per GJ to $7.224 per In approving AG’s application, the AUC said that GJ. it found the increase in the Residential • This rate reflects a market price for December Reinstatement Charge (Outside of Normal supplies of approximately $6.92 per GJ as Business Hours) from $150 to $170 effective reported by the NGX, and incorporates an January 1, 2009, was as approved in Decision adjustment of $0.30 per GJ for November and 2006-075. The Commission said that it also prior months. found that the increase in the Rural Pool Connection Charge from $4,400/customer to • The typical residential gas bill for December $5,000/customer and the increase in the Urban based on an average 19 GJ of consumption Pool Connection Charge from $1,180/customer would be approximately $178 in the South. to $1,320/customer effective January 1, 2009 According to the Natural Gas Price Protection are both in accordance with Decision 2006-075 Regulation, government rebates are triggered reflecting “three times the net revenue.” The during the months of October through March AUC added that this update required no change when approved rates for two of the three major to Schedule C of the Terms and Conditions of regulated gas providers in Alberta exceed $5.50 Service. per GJ. Direct Energy has applied for rates that The Commission added that it agreed to AG’s exceed this threshold; therefore a Natural Gas proposal that Schedule C Charges and Rural Rebate of $1.50/GJ may be implemented for Pool Connection Charges implemented January December 2008. 1, 2009 should be reviewed and updated as November 25, 2008 necessary in the 2008-2009 GRA Phase II AUC Approves Revisions to ATCO Gas Application. Schedule C Charges and Rural Pool November 21, 2008 Connection Charges AUC Approves ATCO Gas Application for The Alberta Utilities Commission (“AUC” or “the Approval of Rate Riders to Collect Customer Commission”) has released Gas – Care and Billing Costs for Period 2003 to Miscellaneous Rates Order U2008-349 in which 2007 it grants Application No. 1593155 which was The Alberta Utilities Commission (“AUC” or “the registered by ATCO Gas (“AG”) on October 31, Commission”) has issued Decision 2008-117 in 2008 and which notified the Commission of which it approves, with some modifications an changes to AG’s Terms and Conditions of ATCO Gas (“AG”) application filed on Service – Schedule C and of the fact that September 19, 2008, requesting approval of Schedule C Charges and Rural Pool Connection interim refundable rates for ATCO Gas North Charges implemented January 1, 2009 will be (“AGN”) and ATCO Gas South (“AGS”) relating reviewed and updated as necessary in the 2008- to Customer Care and Billing (“CC&B”) costs for 2009 General Rate Application (“GRA”) Phase II the period 2003-2007 that were applied for in Application. Proceeding ID 32. The Commission reports that In its application, AG noted that Decision 2006- AG requested the rates to be effective 0752 approved a three-year phased-in November 1, 2008 to October 31, 2009, and adjustment to the Residential Reinstatement requested approval to include the following two Charge (Outside Normal Business Hours) with a new riders: proposed fee of $125 beginning on January 1, • Rider H (AGN) of 4.72% 2007, $150 beginning in January 1, 2008 and $170 on January 1, 2009. AG said that Decision • Rider K (AGS) of 5.08%. 2006-075 also approved the continuation of the In Decision 2008-117, the AUC noted that that “three times net revenue” methodology as the amounts outstanding are significant and may included in Schedule C” for the calculation of the attract up to $1.0 million annual interest for Rural Pool Connection Charge and the Urban customers and thus it would be in the public - 5 - Cerise, Volume 7, Issue 11-November 2008 interest to begin collection of these amounts increase in the Urban Pool Connection Charge now rather than accrue interest costs. To from $1,180/customer to $1,320/customer proactively balance and manage these effective January 1, 2009 were both in concerns, the Commission considered that it accordance with Decision 2006-075 reflecting would be appropriate to approve a portion of the “three times the net revenue.” This update applied for interim rates. requires no change to Schedule C of the Terms Based on its consideration of quantum and need and Conditions of Service. factors, and general public interest factors, the The AUC approved the change to Schedule C, AUC approved 50% of the requested interim effective January 1, 2009. rates. The Commission said that it typically The Commission agreed to AG’s proposal that considers changes that may result between Schedule C Charges and Rural Pool Connection interim and final rates will be reflected through Charges implemented January 1, 2009 should future credits or charges to customers. be reviewed and updated as necessary in the Therefore the AUC approved 50% of AG’s 2008-2009 General Rate Application (“GRA”) Interim Rate Riders effective December 1, 2008 Phase II Application. to remain in place on an interim basis until November 30, The AUC ordered that: 2008. • Schedule C, as set out in Appendix 1 attached to and forming part of this Order, is hereby The Commission approved the following interim fixed and approved as the rate to be applied to rate riders to be effective December 1, 2008 and the Residential Reinstatement Charge to remain in place until November 30, 2009: (Outside Normal Business Hours), effective • Rider H (AGN) of 2.36% January 1, 2009. • Rider K (AGS) of 2.54%. November 18, 2008 November 19, 2008 AUC Approves AltaGas Utilities’ Application to Adjust Rate Rider ‘E’ – Unaccounted-For AUC Approves ATCO Gas Terms and Gas Conditions of Service – Schedule C The Alberta Utilities Commission (“AUC” or “the The Alberta Utilities Commission (“AUC” or “the Commission”) has issued Miscellaneous Rates Commission”) has issued Gas – Miscellaneous Non-Routine Order U2008-327 in which it Rates Order U2008-349 in which it approves approves Application No. 1589732 from AltaGas Application No. 1593155 from ATCO Gas Utilities Inc. (“AUI”), which was registered on (“AG”), which was registered on October 31, October 7, 2008, and which sought approval to 2008, which notified the AUC of changes to adjust Rate Rider ‘E’ – Unaccounted-For Gas AG’s Terms and Conditions of Service – (“UFG”) from 0.74 percent to 0.82 percent Schedule C, and which in addition advised the effective December 1, 2008. Commission that “Schedule C Charges and Rural Pool Connection Charges implemented The Commission noted that the UFG rate in January 1, 2009 will be reviewed and updated Rider ‘E’ was determined in the same manner as necessary in the 2008-2009 GRA Phase II previously approved by Public Utilities Board Application.” Decision E90057, and also that no parties were opposed to the proposed UFG rate adjustment. The AUC found that the increase in the The AUC therefore found the amendments to be Residential Reinstatement Charge (Outside of in the public interest and approved the Normal Business Hours) from $150 to $170 adjustment to Rate Rider ‘E’ to 0.82 percent as effective January 1, 2009, is as approved in proposed by AUI. The adjusted Rider ‘E’ Decision 2006-075. replaces the rate approved by the Alberta The Commission found that the increase in the Energy and Utilities Board (“AEUB” or “the Rural Pool Connection Charge from Board”) in Order U2007-297. $4,400/customer to $5,000/customer and the - 6 - Cerise, Volume 7, Issue 11-November 2008 The Commission ordered that Rider ‘E’, as set directed AG to apply an occupational labour out in Schedule ‘A’ attached to and forming part inflation rate of 5.0% in 2009 to all appropriate of this Order, is hereby fixed and approved as amounts in the Application and update all the rate to be applied to all transportation end- corresponding tables in the refiling. The AUC user rates for the recovery of Unaccounted-For further directed AG in the refiling to apply a Gas, effective December 1, 2008. supervisory inflation rate of 4.5% in 2008 and 5.0% in 2009 to all appropriate labour November 18, 2008 categories in the refiling. AUC Issues Decision With Respect to ATCO Gas 2008-2009 General Rate Application • The Commission directed AG in its next GRA to provide a discussion of how it applies The Alberta Utilities Commission (“AUC” or “the inflation forecasts as noted above, and how Commission”) has issued Decision 2008-113 in these inflation forecasts are applied to projects which it sets out its findings and directions with with various time horizons. Further, to the respect to Application No. 1553052 (Proceeding extent that AG has double counted the second ID. 11), which was Phase I of the ATCO Gas year increase for two-year contracts, the AUC (“AG”) 2008-2009 General Rate Application directed AG in the refiling to remove these (“GRA”) for ATCO Gas North (“AGN”) and costs from the forecasts and clearly report ATCO Gas South (“AGS”). The AUC notes that these changes in the appropriate schedules. the application was initially filed on November 2, 2007 but, further to a directive from the Alberta • The Commission directed AG in the refiling to Energy and Utilities Board (“AEUB” or “the apply a contractor inflation rate of 10% for Board”) the process was suspended and AG 2008 and 5% for 2009 to all appropriate was instructed to submit the application in forecasts. January 2008 using a placeholder of the existing • The Commission directed AG to apply general 38 percent common equity in its 2008 and 2009 materials and supply inflation rate of 3.5% for revenue requirements until such time as the 2008 and 2009 to the appropriate amounts in Commission issued further direction on the the refilling. process to consider AG’s request for an increase to that common equity percentage for • Subject to its findings with respect to the test years in question. The AUC further Information Technology (“IT”) and Customer notes that AG filed its Application with the Care and Billing (“CC&B”) capital, the Commission on January 2, 2008 without Commission approved the 2008 Property changes, adjustments or alterations. Plant and Equipment (“PP&E”) opening balances, and directed AG in the refiling to In Decision 2008-113, the AUC set out its reflect these changes in its forecasts and findings, issued a number of directives and revenue requirement calculations. instructed AG to refile its 2008-2009 GRA to reflect the findings, conclusions and directions in • Finding that the 8% price reduction due to the this Decision by January 5, 2009 and, in that entry of two new contractors in Edmonton is refilling, to provide a summary which sets out a not a productivity improvement as suggested detailed reconciliation of its requested revenue by AG, the Commission directed AG to reflect requirement for 2008 and 2009 to the revenue the reduction in its refilling, highlighting the requirement resulting from the Commission’s change in the corresponding schedules. The determinations in the Decision. AUC also directed AG in its refilling to adjust the inflation factors used in forecasting costs Among the directives issued by the AUC were for urban mains replacement using the rates the following: of inflation approved by the Commission in • The Commission ruled that AG had not Section 5 of the Decision. demonstrated that a catch-up is required for • The Commission directed AG, in its refiling to the occupational labour category and as a adjust the inflation factors used in forecasting result, AG’s forecasted inflation rate of 7.50% unit costs for valve and vault replacements was not accepted by the Commission and it - 7 - Cerise, Volume 7, Issue 11-November 2008 using the rates of inflation approved by the full and part time positions. The AUC clarified Commission in Section 5 of the Decision that it was not addressing the specific number of Blue Flame Kitchen (“BFK”) staff to be • AG was directed in the refiling to reduce the included, nor the location where the staff will premium factor for the meter relocation and be employed. The Commission said it was replacement plan (“MRRP”) to 16.5% for the only stipulating the maximum amount that can test years and in forecasting the unit costs for be included in the revenue requirement for the the MRRP to use the inflation factor set out in test years. 28. In a related matter, the AUC Section 5 of the Decision. The Commission noted that the BFK does not report to a added that the inflation factors should be department under the President of AG, but applied based on the forecast mix of rather to a Vice President outside AG. The contractors and in-house crews. Commission said that this organizational • The AUC directed AG in the refiling to adjust arrangement raises a concern as to the BFK’s the inflation factors used in forecasting costs relationship to other parts of the ATCO for the Viking, North Edmonton, Ft. McMurray organization. The AUC directed AG in the and Airdrie operating centres using the rates refiling to address this concern demonstrating of inflation approved by the Commission in that the BFK’s duties are not performed for the Section 5 of this Decision. Given that the benefit of affiliated companies. If they are, North Edmonton OC is a current project for then the Commission expects that AG should 2008, the AUC agreed with AG that there will be able to show revenue for any work done for be no adjustment for inflation in 2008. others. • In the refilling, AG was directed to remove the • AG was directed to reduce its aircraft $5 million for the Rate 1 sample project. expenses in the refilling by $348,000 for 2008 and $375,000 for 2009. • The Commission directed AG to remove the contingency costs of $2,155,608 from the • Finding that a Citation V is more than NGSIS project. adequate and that the utility does not need a Citation X for its Alberta business, the • The Commission directed AG in the refiling to Commission directed AG to further reduce the use a 2008 debenture rate of 5.62% in revenue requirement associated with aircraft determining the 2008 long term debt rate and costs by $324,000 in 2008 and $279,000 in 6.25% for the 2009 rate. 2009 • In its next GRA, AG was directed to provide • With respect to the Corporate Office Supplies empirical data that will provide the & Corporate Secretary expenses, the Commission with a better understanding of the Commission directed AG to restate the differences in unit costs between the North expenses in the refiling using the approved and South and the reasons for those inflation rates since 2007 only. differences. • In the refilling, AG was directed to remove the • The Commission directed AG in the refilling to expenses related to the 2010 Winter adjust the O&M expense for 2008 and 2009 Olympics, forecast as $43,000 in 2008 and such that the addition of clerks is equal to five $639,000 in 2009. in each test year. • The Commission said that the existing Head • The Commission directed AG in the refiling to Office expenses and those permitted can be reduce the O&M for meter reading, Account increased over those in 2007 on the basis of 712, by $50,000 in 2008 and $150,000 in the inflation factor in Section 5. AG was 2009. directed to apply the approved inflation factor • AG was directed in the refilling to adjust the to re-estimate the test year expenses for Head O&M forecast for 2008 and 2009 to equal the Office. budget levels of 2007, adjusted for inflation only, i.e. $800,000 (2007) which included 12 - 8 - Cerise, Volume 7, Issue 11-November 2008 • AG was directed to participate in the process • While for the purposes of this application, the established by the ATCO Utilities for reviewing Commission accepted the use of two weather the corporate cost allocation methodology. stations for weather normalization for the test years, AG was directed to use six weather • AG was instructed to reduce the revenue stations for its next GRA and to fully identify its requirement in the South for the 2009 methodology and any incremental costs Transmission Operating expense by $241,164 related to preparing its forecast using the six and in the North by $338,700. weather stations. The AUC also directed AG • AG was directed to include both the to fully explain the circumstances of any “Financials Appl Host & Storage” item and the incremental costs which may be identified “Adabas-IMS License” item with the variable given that six weather stations were used for items to be evaluated during the Evergreen the response prepared to Direction 69 from Phase 1 proceeding where it will consider the Decision 2003-072. The Commission further City of Calgary’s recommendation to disallow instructed AG to arrange for a technical the “Adabas-IMS License”. meeting with interested parties regarding the technical aspects of the weather normalization • Due to the significant amount of capital process. The AUC also directed that the expenditures that have either occurred or are information shared and discussed at this forecast in the test years, the Commission technical meeting be included in its entirety in directed AG in its next GRA to file a full the application for the upcoming GRA. depreciation study which must include updates for capital activity as well as • The Commission also directed AG, in its next recommendations regarding the appropriate GRA, to provide a schedule in the format of depreciation parameters. the CG’s Table 8 – High Use Demand Forecast to assist with review of demand • Noting that, in its rebuttal evidence, AG forecast accuracy for high use customers. The committed to review alternative methods for schedule should include forecasts and actuals depreciating its leasehold improvement costs for the years 2007 through 2009, plus and this information will be filed as part of its forecasts for the GRA test years. next GRA, the Commission directed AG in its next GRA to provide the referenced study as • AG was instructed to, in its next GRA, to indicated in rebuttal evidence. investigate the cause or causes for the negative irrigation throughput amounts, and • In its next GRA, AG was directed to fully report the findings to the Commission. AG will comply with Direction from Decision 2006-004 also be required to recommend a cost and provide its best estimate of the retirement effective solution to address this issue. date for the CIS system, and to clearly identify the assumptions and rationale for the selected November 11, 2008 date. To the extent that AG has any AUC Denies Russ Duncan Application to preliminary information on alternatives to CIS, Recover Alberta Distribution System Costs the Commission directed AG in its next GRA Through NGTL Transmission by Others to file the information, including any available Service preliminary cost information. The Alberta Utilities Commission (“AUC” or “the • AG was instructed, in the refilling, to ensure Commission”) has issued Decision 2008-111 in and demonstrate that the working partners’ which it denies a March 1, 2007 application by 25% credit is appropriately reflected in the Mr. Russ Duncan requesting that NOVA Gas abandonment deferral account. Transmission Ltd. (“NGTL”) be directed to • The Commission directed AG, in the refilling, establish an Alberta Transportation By Others to use the Federal budgeted rates to (“TBO”) Service for the gas transportation costs determine income tax expense in its 2008- required by AltaGas Utilities Inc. (“AltaGas” or 2009 GRA. “AUI”) and ATCO Gas (“AG”) for gas delivery to their end users and the costs of Direct Energy - 9 - Cerise, Volume 7, Issue 11-November 2008 Regulated Services (“DERS”) for administration request made by Mr. Duncan in the Amended of gas transportation costs. In response to Application for an Alberta TBO. comments from other parties, Mr. Duncan later November 7, 2008 amended his application to include other Alberta gas distribution systems, such as Co-ops, AUC Issues Three Permits and Licences to municipal and First Nations distribution systems ATCO Gas and Pipelines South served by Gas Alberta (“Amended Application”). The Alberta Utilities Commission (“AUC” or “the According to the Commission, Mr. Duncan Commission”) has issued three permits and submitted that costs associated with his Licences in response to applications by ATCO proposal should be treated as flow through costs Gas and Pipelines Ltd. (South) (“AGPS”) and should be added to the other TBO flow seeking authorization for new pipeline through costs under the tolls of NGTL. Mr. construction. Duncan indicated that based on his figures, this AUC Gas Utility Pipeline Licence Addition Permit would change the referenced unit transportation / Licence No. 30475 costs of NGTL from $0.140 to $0.225 per thousand cubic feet (“MCF”). Mr. Duncan added The AUC has issued Gas Utility Pipeline Licence that the approximate cost of an Alberta TBO Addition Permit / Licence No. 30475 in which it would be $681,380,000. The AUC also reports approves Application No. 1592764 from AGPS that Mr. Duncan indicated that the rate of $0.140 which was registered on October 29, 2008, and applied to customers paying firm transportation which sought approval of new pipeline receipt (“FT-R”) and firm transportation delivery construction. Details of the construction (“FT-D”) rates for NGTL service. Mr. Duncan approved are set out in the Permit and Licence. also confirmed that the customers affected by AUC Gas Utility Pipeline Licence Addition Permit his proposal would be NGTL’s receipt and / Licence No. 12109 export delivery shippers. Mr. Duncan explained that with respect to the costs that would remain The Commission has issued Gas Utility Pipeline to be paid for by the distribution customers of Licence Addition Permit / Licence No. 12109 in AUI and AG as a result of his proposal, the end which it approves Application No. 1590727 from users would pay the items not associated with AGPS which was registered on October 15, transportation on their AG and AUI bills. 2008 and which sought approval of new pipeline construction. Details of the construction In denying the application, the AUC has approved are set out in the Permit and Licence. determined that Mr. Duncan’s TBO proposal is distinctly different from prior TBO approvals and AUC Gas Utility Pipeline Licence can not be supported by an application of the Addition/Amendment Permit / Licence No. 5341 factors and circumstances found significant by The AUC has issued Gas Utility Pipeline Licence the regulator in prior approvals. The Addition/Amendment Permit / Licence No. 5341 Commission noted that prior TBO approvals in which it approves Application No. 1590764 were in respect of transmission services and which was registered by AGPS on October 15, were proposed in response to competitive or 2008 and which sought approval of new pipeline market circumstances and resulted in some construction and a mapping route correction. benefit to those parties ultimately bearing the Details of the changes approved by the costs of the TBO. The AUC said that the Commission are set out in the Licence and Amended Application was unable to Permit. satisfactorily address the implications and costs November 5, 2008 of implementation, did not address jurisdictional difficulties, failed to garner support from any AUC Denies City of Calgary Applications for party and ultimately failed to persuade the Review of Decision 2006-098 and Utility Cost Commission that its adoption would be in the Order UCO 2006-064 public interest. In light of the foregoing reasons The Alberta Utilities Commission (“AUC” or “the and determinations, the Commission denies the Commission”) has issued Decision 2008-110 in - 10 - Cerise, Volume 7, Issue 11-November 2008 which it denies an application filed on December insofar as it relates to the Load Balancing 31, 2006 by the City of Calgary (“Calgary”) (“the Decision was denied. Application”), which sought a review and Similarly, with respect to the requested review of variance of the ATCO Pipelines Load Balancing the Cost Order, the AUC expressed the opinion Decision 2006-098 (“the Load Balancing that the Application had not established an Decision”) and a related Cost Order, UCO 2006- apprehension that the AEUB committed an error 064 (‘the Cost Order”). Calgary asserted that the of law, or jurisdiction, or fact, sufficient to raise a Alberta Energy and Utilities Board (“AEUB” or doubt as to the correctness of the Cost Order. “the Board”) had erred in law, or jurisdiction, or fact such as to raise a substantial doubt as to The Commission said that the preliminary the correctness of the Load Balancing Decision question required to be addressed by Section and of the Cost Order. In addition, Calgary 46(5) of the Rules as to whether the Cost Order submitted that the availability of new evidence or should be reviewed is answered in the negative the presence of a change in circumstances not and the Application insofar as it relates to the previously before the Board materially effected Cost Order was denied. the Load Balancing Decision. November 4, 2008 The Commission explains that the Decisions in Alberta Government Advises that Natural question related to ATCO Gas (“AG”) Gas Price Triggers Rebate for November Application No: 1411635 dealing with Phase 2, 2008 Part B of the Retailer Service and Gas Utilities Act Compliance process and were issued on The Government of Alberta has advised that, October 10, 2006 and December 1, 2006 under the Natural Gas Rebate program, the respectively. province will receive $1.50/GJ rebate in November 2008, which translates to The AUC advises that although it is by virtue of approximately $27 on the November gas bill. Section 80(3) of the Alberta Utilities Commission Act the appropriate party to decide on Calgary’s According to the announcement, rebates are application, the applicable Rules of Practice are triggered when two of the three regulated natural those that were in place at the time the gas companies charge regulated rates above Application was filed and therefore the Alberta $5.50/GJ. Most residential consumers will have Energy and Utilities Board Rules of Practice the rebate applied directly to their monthly gas A.R. 101/2001, as amended, are the governing bill. Large scale commercial or industrial Rules of Practice (“Rules”) with respect to the consumers, select agricultural producers, and Application. those who heat their homes with other fuels need to apply for rebates. In denying the request for a review of the Load Balancing Decision, the Commission said that, For most consumers, the Natural Gas Rebate in its opinion, the City of Calgary had not Program runs from October to March, which is established an apprehension that the AEUB had the timeframe when Alberta residences use committed an error of law, or jurisdiction, or fact, about 80 per cent of the total natural gas sufficient to raise a doubt as to the correctness consumed for the year. Rebate amounts of the Decision. The AUC went on to say that increase as the price of natural gas rises, with new facts or change in circumstances suggested the maximum cost of natural gas to most Alberta by Calgary do not raise a reasonable possibility consumers capped at $8.75/GJ. that they would lead the Commission to November 3, 2008 materially vary or rescind the Load Balancing Decision. AUC Approves AltaGas Compliance Filing With Respect to Directions Set Out in The Commission therefore concluded that the Decision 2008-103 preliminary question required to be addressed by Section 46(5) of the Rules as to whether the The Alberta Utilities Commission (“AUC” or “the Load Balancing Decision should be reviewed is Commission”) has released Gas – Compliance answered in the negative and the Application Filing Order U2008-324 in which it approves a - 11 - Cerise, Volume 7, Issue 11-November 2008 compliance filng submitted by AltaGas Utilities Electricity Inc. (“AUI” or “AltaGas”) on October 27, 2008, in November 28, 2008 compliance with directions issued in Decision 2008-103, “AltaGas Utilities Inc. 2007 Deficiency ENMAX Advises that Calgary's Regulated Rider, Interim Refundable Rates and Standard Default Electricity Rate for December 2008 Contribution – Rural Other” dated October 21, Will Be 12.18 Cents Per Kilowatt Hour 2008. ENMAX Corporation (“ENMAX”) has announced The Commission says that it is satisfied that that the default electricity rate for Calgary will be AUI’s filing complies with the directions issued in 12.18 cents per kilowatt hour (“kWh”), effective Decision 2008-103 and approves AUI’s 2007 December 1, 2008. This is an increase of 8.9 Deficiency Rider of 7.882% to recover a total of per cent from last month's rate of 10.81 cents $2,297,710 over the billing months of November per kilowatt hour. Consumers who have selected 2008 through February 2009, inclusive. a retailer and entered into a fixed price contract However, the AUC says that it is concerned with will not be affected by this price change. the extent of the variance between AUI’s November 28, 2008 estimated billed revenue of $32,667,812, approved as a placeholder in Decision 2008- AUC Denies Request for Transfer of Power 103, and AUI’s actual billed revenue of Plant Approval from Wind Power to Castle $29,152,826. Therefore, the Commission directs Rock Ridge LP AUI to provide a detailed explanation by Further to a letter of enquiry filed by Wind Power December 3, 2008 within its 2008/2009 GTA, of Inc. (“WPI”) on March 27, 2008, regarding a the factors that contributed to the significant proposed transfer of Power Plant Approval declines in its 2007 billed revenues which AUI U2007-74 for the Castle Rock Ridge Wind Plant, utilized in calculating its deficiency rider. currently held by WPI to Castle Rock Ridge The AUC says that it agrees to AUI’s suggested Limited Partnership (CRR LP), the Alberta change in the deadline for filing of its Utilities Commission (“AUC” or “the reconciliation application from February 28, Commission”) has issued Decision 2008-121 in 2009 to June 30, 2009 in order that the most which it denies the request. The Commission complete billing information would be available goes on to say that it would consider an for review. amended application by WPI, to transfer Power Plant Approval U2007-74 from Wind Power Inc. Further, the Commission confirms that AUI has to Enel Alberta Wind Inc., in its capacity as appropriately amended: general partner of the Castle Rock Ridge (a) its Rate Schedules to reflect the interim Limited Partnership. rates and the 2007 Deficiency Rider as The AUC reports that the original WPI project approved in Decision 2008-103 and the (known as the Castle Rock Ridge Wind Plant) Order; and was initially approved in early 2002, to be (b) its Natural Gas Utility Service Rules to located in an area north of Pincher Station and reflect the revision to AUI’s Standard south of the Old Man River. The original Contribution – Rural Other as approved in approval was for 56 ENERCON model E66 wind Decision 2008-103. The Commission has turbines, each rated at 1.8 MW. appended the revised Rates Schedules and Natural Gas Utility Service Rules to The Commission says that, since the original its Order. approval of the project, WPI has twice applied for, and received, regulatory approvals for modifications to the project. The first application for modification occurred in 2005, when WPI applied to install more modern wind turbines. Subsequently, in 2007, WPI applied for a second capacity increase due to new technologies developed by the turbine - 12 - Cerise, Volume 7, Issue 11-November 2008 manufacturer, which resulted in turbine The following table summarizes EEC’s request: increases from 2 MW to 2.3 MW. Also, a number of turbines were removed from the original 2008 2008 2009 2009 Final Final Interim Interim project. With these latest modifications, the Rates Rates Rates Rates project would have 50 turbines and a total installed capacity of 115 MW. However, WPI has Rate Class Admin Rider Admin Rider yet to start construction of the project due to Charge Charge insufficient transmission capacity out of the Residential $0.2373/ $0.0411/ $0.2373/ $0 Pincher Creek area. day day day In the Decision, the AUC notes that the Hydro Commercial $0.2316/ $0.0455/ $0.2316/ $0 and Electric Energy Act (“HEEA” or “the Act”) is day day day silent as to whether an LP may be considered a “person” for the purposes of holding an approval The Commission further reports that EEC under section 11 of that Act. However, the proposed the continuation of the 2009 interim Commission is satisfied that the legal status of RRO non-energy rates until such time as the an LP at common law is sufficiently limited to AUC has approved EEC’s 2009 RRO non- require that a general partner – which does have energy rates on a final basis. EEC has the status of a “person” - must hold the approval tentatively scheduled its 2009 RRO non-energy under section 11 of the HEEA on behalf of the rate application for April 2009. LP. The Commission finds that EEC is simply November 28, 2008 applying to continue with its AUC approved 2008 AUC Approves 2009 Interim Regulated Rate RRO non-energy rates, on an interim basis Option Non-energy Rates for ENMAX Energy commencing January 1, 2009. Corporation The Commission finds that EEC’s 2008 RRO The Alberta Utilities Commission (“AUC” or “the non-energy rates are suitable for use on an Commission”) has issued Interim Rates Order interim basis and therefore approves EEC’s U2008-362 in which it approves, for 2009 Interim RRO non-energy rates, as implementation on January 1, 2009, 2009 contained in Appendix A of this Order, for Interim Regulated Rate Option (“RRO”) Non- implementation on January 1, 2009. energy rates for ENMAX Energy Corporation The Commission directs EEC to apply for a true- (“EEC”). The Commission also directed EEC to up rider at the time that it receives approval for apply for a true-up rider at the time that it final 2009 RRO non-energy rates. receives approval for final 2009 RRO non- energy rates. The Commission orders that: The AUC reports that on November 6, 2008, it (1) ENMAX Energy Corporation’s 2009 Interim received an application from EEC requesting Regulated Rate Option Non-energy rates, as approval of 2009 Interim Regulated Rate Option contained in Appendix A of this Order, are (“RRO”) Non-energy rates. The Commission approved. advises that EEC applied for approval, effective (2) ENMAX Energy Corporation apply for a true- January 1, 2009, of its interim 2009 RRO non- up rider at the time that it receives approval for energy rates. EEC requested that the AUC final 2009 Regulated Rate Option Non-energy approve the continuation of EEC’s 2008 rates. approved final RRO non-energy rates, with the November 27, 2008 exception of its current RRO Rider, as the interim-refundable 2009 RRO non-energy rates. AUC Agrees to Date of March 31, 2009 for EEC noted that its current rider will end on AltaLink Refiling of Application With Respect December 31, 2008, and as such, the rider to Updated TFO Terms and Conditions of would not be a component of its requested 2009 Service interim tariff. Further to a November 17, 2008 filing by - 13 - Cerise, Volume 7, Issue 11-November 2008 AltaLink Management Ltd. (“AltaLink” or “AML”) consult with the TFOs for the purpose of which was made pursuant to a directive set out providing a comprehensive response to the in Decision 2008-108, issued by the Alberta Decision 2008-108 directions. Utilities Commission (“AUC” or “the November 25, 2008 Commission”) with respect to proposed Updated Transmission Facility Owner (“TFO”) Terms and AUC Issues Nine Substation Permit and Conditions of Service (“T&Cs”) for AML, the Licence Orders With Respect to Petro- AUC has issued Electric Rates Compliance Canada Oil Sands Inc Filing Order No. U2008-363 in which it approves In the context of Application No. 1571279, which a filing date of March 31, 2009 for AltaLink’s was registered by Petro-Canada Oil Sands Inc. Refiling Application. (“PCOSI”) on May 7, 2008, the Alberta Utilities The Commission notes that in Decision 2008- Commission (“AUC” or “the Commission”) has 108, among other things, it had directed issued Substation Permit and Licence Nos AltaLink, in consultation with the Alberta Electric U2008-321, U2008-322 and U2008-341 through System Operator (“AESO”) and other Alberta U2008-347. Details of each of these Orders, TFOs to refile the T&Cs to reflect the findings, which are each subject to specific conditions set conclusions and directions in the Decision. The out in the individual Orders, are as follows. AUC recognized that AltaLink and ATCO Substation Permit and Licence No. U2008-321 Electric had filed with the Commission General Tariff Applications (“GTAs”) which will occupy The Commission has issued Substation Permit significant resources of these parties. As a and Licence No. U2008-321 in which it grants result, the AUC said that it would like to receive approval to construct and operate a substation suggested dates from all parties in the designated as Intertie substation 585S. proceeding regarding the establishment of a Substation Permit and Licence No. U2008-322 deadline for the refiling directed in this Application. The AUC has issued Substation Permit and Licence No. U2008-322 in which it grants The Commission reports that on November 17, PCOSI approval to construct and operate a 2008, it received a letter from AltaLink regarding substation designated as Central Plant the recommended deadline for the Refiling substation. Application in which AML submitted that a number of regulatory proceedings are currently Substation Permit and Licence No. U2008-341 underway within Alberta which will require The Commission has issued Substation Permit substantial time and resources in order to satisfy and Licence No. U2008-34 in which it grants their requirements and timelines. AltaLink noted PCOSI approval to construct and operate a that Decision 2008-108 set out 18 directions for substation designated as Recycle Water Pond AltaLink and other TFOs to incorporate within substation. their T&Cs. AltaLink also noted that a direction Substation Permit and Licence No. U2008-342 for AltaLink to consult with the AESO and other TFOs with regard to policy development is a The AUC has issued Substation Permit and central aspect of that Decision. Licence No. U2008-342 in which it grants PCOSI approval to construct and operate a AltaLink submitted that as compliance with substation designated as Coarse Tailings Decision 2008-108 will require it to coordinate Booster Station 1 substation. input from the AESO and the TFOs, significant time and resources will be required before AML Substation Permit and Licence No. U2008-343 can prepare its Refiling Application pursuant to The Commission has issued Substation Permit Decision 2008-108. In light of these and Licence No. U2008-343 in which it grants considerations, AltaLink submitted that the PCOSI approval to construct and operate a deadline for its Refiling Application pursuant to substation designated as North Seepage Pond Decision 2008-108 should occur no sooner that substation. March 31, 2009, to permit AML to properly - 14 - Cerise, Volume 7, Issue 11-November 2008 Substation Permit and Licence No. U2008-344 November 25, 2008 The AUC has issued Substation Permit and AUC Grants Petro-Canada Oil Sands Inc. Licence No. U2008-344 in which it grants Industrial Systems Designation for Certain PCOSI approval to construct and operate a Facilities Associated With the Fort Hills substation designated as Coarse Tailings Industrial Complex Booster Station 2 substation. In the context of Application No. 1571279, which Substation Permit and Licence No. U2008-345 was registered on May 7, 2008 by Fort Hills Energy Corporation (“the Applicant”) on behalf of The Commission has issued Substation Permit Petro-Canada Oil Sands Inc. (“PCOSI”), the and Licence No. U2008-345 in which it grants Alberta Utilities Commission (“AUC” or “the PCOSI approval to construct and operate a Commission”) has issued Industrial System substation designated as South Seepage Pond Designation Order No. U2008-320 in which it substation. grants the Applicant approval to construct and Substation Permit and Licence No. U2008-346 operate Intertie substation 585S, Central Plant The AUC has issued Substation Permit and substation, double circuit 144-kV transmission Licence No. U2008-346 in which it grants lines 265PLTG20001 and 265PLTG20002, PCOSI approval to construct and operate a Industrial Systems Designation (“ISD”) for substation designated as OPP substation. electrical facilities within the Fort Hills Industrial Complex, and rules exempting from the Substation Permit and Licence No. U2008-347 operation of the Electric Utilities Act the electric The Commission has issued Substation Permit energy produced from, and consumed by, the and Licence No. U2008-347 in which it grants Industrial System. The AUC adds that an PCOSI approval to construct and operate a application for the 144-kV single circuit Tailings substation designated as Hydrotransport and OPP Loop and the Tank Farm and Pipeline Booster Station 1 substation. substation will be filed at a later date and that an amendment to this ISD order will be required to November 25, 2008 incorporate those facilities into the ISD. AUC Grants Petro-Canada Oil Sands Inc. The Order explains that PCOSI operates oil Authorization to Construct a Double Circuit sands mine and bitumen production facilities via 144-kV Transmission Line in the Fort Hills its Fort Hills Oil Sands industrial complex in the ISD Area Fort Hills area and, pursuant to Commission In the context Application No. 1571279, which Approval No. U2008-273, has approval to was registered by Petro-Canada Oil Sands Inc. construct and operate a new 130-MW power (“PCOSI”) on May 7, 2008, the Alberta Utilities plant and associated transmission and Commission (“AUC” or “the Commission”) has distribution facilities at the Fort Hills Oil Sands issued Transmission Line Permit and Licence industrial complex. No. U2008-323 in which it grants PCOSI November 25, 2008 approval to construct and operate a double circuit 144-kV transmission line designated as AUC Grants Interim Approval to ATCO 265PLTG20001 and 265PLTG20002 from Electric Motion Seeking Confidential Intertie substation 585S to Central Plant Treatment of the Establishment Audit substation within the Fort Hills Industrial System In the context of Application No. 1578371 Designation (“ISD”) area near the town of (Proceeding ID 86), the Alberta Utilities MacKay, Alberta. The Commission’s approval is Commission (“AUC” or “the Commission”) has subject to certain conditions set out in the Order. issued Order U2008-361 in which it says that it is prepared to grant, on an interim basis, a motion which was registered by ATCO Electric Ltd. (“AE”) on November 3, 2008 and which sought confidential treatment of the Establishment Audit which had been requested - 15 - Cerise, Volume 7, Issue 11-November 2008 through Information Requests AUC-AE 29, access to the Establishment Audit on IPCAA –AE 5(b) and IPCAA-AE 9(d). the understanding that they will execute and deliver to the Commission, the The AUC reports that in its Confidentiality Undertaking attached as Schedule B to Request, AE indicated that the Establishment the Order. On receipt of an executed Audit summarized certain aspects of Balfour Undertaking, the Commission shall send Beatty and United Group’s (“BBUGL Joint a copy of Establishment Audit to the Venture”) financial records, and that the party who has executed the Establishment Audit was prepared by an Undertaking. independent auditor to assist AE with its negotiation of a fair and equitable fee November 25, 2008 percentage (representing a “normal” profit AESO Approves a New AESO Rider F margin plus a contribution towards corporate Effective January 1, 2008 overhead). AE indicated that since private companies are not required to disclose financial In the context of Application No.1592737, which records to the public, the disclosure of Balfour was registered by the Alberta Electric System Beatty and United Group’s financial records Operator (“AESO”) on October 29, 2008, the would disadvantage and significantly harm the Alberta Utilities Commission (“AUC” or “the competitive position of these two companies. AE Commission”) has released Electric Rates – requested that the Commission grant Miscellaneous Order U2008-356 in which it confidential treatment in relation to this approves the AESO Balancing Pool Consumer document. Allocation Rider F as filed, effective from January 1 to December 31, 2009. The In granting its interim approval, the AUC directs Commission adds that it issued Notice of the parties to be prepared to speak to whether the AESO application on November 5, 2008 to all Establishment Audit should continue to be participants in the AESO’s General Tariff treated as confidential as a preliminary issue at Application (“GTA”) process but that no the commencement of the oral hearing. Parties Statements of Intention to Participate were should address the application of the test received. decision of the Supreme Court in Sierra Club of Canada v. Canada (Minister of Finance), [2002] The AUC reports that in the application, the S.C.J. No. 42 (“Sierra Club”) in their AESO indicated that on October 14, 2008, it had submissions. received notification from the Balancing Pool of an estimated annualized positive amount of The AUC further rules that, in the interim, the $389,844,650 to be incorporated into the use and disclosure of the Establishment Audit AESO’s rates and a request from the Balancing will be permitted on the following conditions: Pool that the amount be paid to AESO 1. The Establishment Audit shall be treated customers as a $6.50/MWh credit during 2009. as confidential for the purposes of The AESO noted that the annualized amount Proceeding ID 86 and as AE is in was similar in nature to the amount currently possession of the Establishment Audit, it being refunded to AESO customers through the shall immediately provide to the Balancing Pool Consumer Allocation Rider F Commission (to the attention of under the AESO’s 2008 tariff, approved as a Shannon Ramdin, Counsel), an $5.00/MWh credit effective from January 1 to electronic copy of the Establishment December 31, 2008. Citing the increase in the Audit. annualized amount for 2009, the AESO submitted that it had reviewed the basis for its 2. The Commission Panel assigned to allocation to AESO customers and that Rider F hear Proceeding ID 86 and Commission was to provide a $6.50/MWh credit to all Staff assigned to Proceeding ID 86 will Demand Transmission Service (“DTS”) and sign an Undertaking in the form Demand Opportunity Service (“DOS”) attached as Schedule A to the Order. customers, with the exceptions of the City of 3. Parties to Proceeding ID 86, will receive Medicine Hat and BC Hydro at Fort Nelson, for - 16 - Cerise, Volume 7, Issue 11-November 2008 consumption from January 1 through December November 13, 2008 31, 2009, inclusive. AUC Issues Power Plant Approval No. The Commission advises that it received no U2008-196 and Connection Order U2008-197 objections to the Application in response to its for Prairie Home Wind Power Plant in the Notice, and therefore considered the application Wrentham Area without further notice or process. The AUC said With respect to Prairie Home Wind Power Plant that, since Rider F essentially provides a (“the Power Plant”) in the Wrentham area, the mechanism whereby the AESO may pass on Alberta Utilities Commission (“AUC” or “the refunds or collections from the Balancing Pool, Commission”) has issued Power Plant Approval the Commission found that the request for a No. U2008-196 and Connection Order U2008- Balancing Pool Refund Rider F to provide a 197 in which it grants Application No.1568694 $6.50/MWh credit to all DTS and DOS which was registered on April 17, 2008 by customers, with the exception of the City of NaturEner Prairie Home 1 Energy Inc. (“the Medicine Hat and BC Hydro at Fort Nelson, for Applicant”). consumption from January 1 through December 31, 2009 inclusive, was reasonable and in the In Power Plant Approval No. U2008-196, the public interest. AUC notes that in the application, the Applicant advised the Commission that it had assumed November 20, 2008 ownership of the Power Plant and requested AUC Confirms Alberta MSA Assessment of approval to operate it and alter it by changing Specified Penalty to EPCOR PPA the style of turbines to be installed. The AUC’s Management approval was subject to certain conditions set out in the Order including the rescinding of In response to a May 9, 2008 application from Approval No. U2007-72. the Alberta Market Surveillance Administrator (“MSA”) seeking confirmation of a specified In Connection Order No. U2008-197, the penalty of $2,000 levied against EPCOR PPA Commission granted the Applicant permission to Management Inc. (“EPCOR”) for a breach of connect the Power Plant to the Alberta Independent System Operator (“ISO”) Rule 6.6 Interconnected Electric System (“AIES”) through which took place on November 29, 2007, with the electric distribution system of FortisAlberta respect to the operation of the generating unit Inc. known as Sundance 5 (“SD5”), the Alberta November 13, 2008 Utilities Commission (“AUC” or “the Commission”) has released Decision 2008-114 AUC Authorizes ATCO Electric to Alter and in which it confirms the penalty and directs that it Operate Bridge Creek Substation 798S be paid no later than 30 days from the date of The Alberta Utilities Commission (“AUC” or “the the Decision. Commission”) has issued Substation Permit and In granting the MSA’s application, the AUC Licence No. U2008-325 in which it grants found that EPCOR did not take sufficient steps Application No. 1592779 which was registered to prevent breaches of ISO Rule 6.6 and thus by ATCO Electric Ltd. (“AE”) on October 29, failed to make out the due diligence defence. 2008 and which sought approval to alter (“the The Commission said that EPCOR did not Alteration”) and operate the Bridge Creek exercise all reasonable care to avoid situations substation 798S. where generating units fail to comply with The Commission set out a number of conditions dispatch instructions, in that it did not implement in its Order, including the rescinding of the measures designed to monitor compliance with existing Permit and Licence No. U2007-002. such instructions. The AUC added that, as this is the first case of its type, there would be no order as to costs.

- 17 - Cerise, Volume 7, Issue 11-November 2008 November 11, 2008 accruals which more accurately reflects the actual bad debt write offs and it directed AUC Approves a Regulated Rate Tariff 2007 DERS to provide an update on the bad debt Deferral Rider Schedule and Default Rate accrual methodologies it employed in 2008 as Tariff 2007 Deferral Rider Schedules for part of its 2008 RRT and DRT non-energy Direct Energy Regulated Services deferral accounts application. In addition, the In response to Application No. 1570438, dated Commission directs DERS, as part of its 2008 May 1, 2008, the Alberta Utilities Commission RRT and DRT non-energy deferral accounts (“AUC” or “the Commission”) has issued application to provide a table that includes the Decision 2008-112 in which it approves a relevant data for 2008. Regulated Rate Tariff (“RRT”) 2007 Deferral Rider Schedule and a Default Rate Tariff • The AUC directed DERS to file the final (“DRT”) 2007 Deferral Rider Schedules for the Customer Care and Billing (“CC&B”) costs for period July 1, 2008 to December 31, 2008 for 2007 and 2008 once the CBS has been Direct Energy Regulated Services (“DERS”). completed and approved by the AUC. In approving the applied for rate schedules, the • The Commission directed DERS when filing AUC accepted DERS’ response to the directions the final CC&B costs to include all necessary set out in Decision 2007-084 and Decision 2007- adjustments to other deferral account 103 , although, in some instance, the components to true-up its DRT and RRT non- Commission issued further directions. Those energy deferral account balances. The AUC directions are as follows: added that the adjustments should include any differences between the amounts recovered • The AUC directed DERS to continue to report from the rate classes through the interim rate details of any material policy changes and riders approved in Order U2008-203 and this procedures which relate to bad debts and the Decision, and the final deferral account resulting actual dollar impact of such changes balances by rate class. in future non-energy deferral account applications. • Noting that DERS had requested ATCO I-Tek to determine the scope of work required and • Noting that it did not intend for DERS to the costs to implement the additional reporting undertake a costly comparison of utilities and requirements, the Commission directed DERS considers that the most meaningful when filing its next non-energy rate or deferral comparison would be to other Alberta RRT account balance application to include the and DRT participants, the Commission directs estimate and information regarding the DERS in its next non-energy deferral account additional rate class specific reporting. application to provide information and underlying data with respect to how DERS has November 6, 2008 determined an acceptable level of bad debt AUC Releases Findings on AltaLink’s supported by a detailed analysis which Updated Terms and Conditions compares DERS’ bad debt levels to other The Alberta Utilities Commission (“AUC” or “the RRT and DRT regulated utilities in Alberta. Commission”) has released Decision 2008-108 • Recognizing that the I-Tek costs for 2007 in which it sets out its findings with respect to a have yet to be determined through the September 28, 2007 application filed with the Collaborative Benchmark Study (“CBS”), the Alberta Energy and Utilities Board (“AEUB” or AUC directed DERS at the time of filing the “the Board”) by AltaLink Management Ltd. completed CBS, to provide information which (“AltaLink” or “AML”) respecting updated Terms clearly demonstrates to the Commission that and Conditions of Service (“T&Cs”) for Alberta customers have not paid twice for collection regulated Transmission Facility Owners costs. (“TFOs”) who provide transmission services to the Alberta Electric System Operator (“AESO”). • The AUC said that it expected DERS to adopt a new methodology for determining bad debt In the Decision, the AUC directed AltaLink, in - 18 - Cerise, Volume 7, Issue 11-November 2008 consultation with the AESO and other Alberta proposed T&Cs to reflect this requirement. TFOs, to refile the T&Cs to reflect the The Commission provided suggested Commission’s findings, conclusions and language. directions in the Decision. Recognizing that • The AUC also found that Article 3.1(b) of the AltaLink and ATCO Electric had filed General proposed T&Cs was inconsistent with the Tariff Applications (“GTAs”) which would occupy overall EUA statutory scheme and in particular significant resources of these parties, the with section 39(4) of the EUA. The Commission requested that all parties in this Commission said that Article 3.1(b), as proceeding send it suggested dates for the proposed, suggested that in the event that a establishment of a deadline for the refiling written notice of non-compliance with a directed in this Application. The AUC requested specific ISO Rule has been provided to the that these proposed dates be provided on or AESO by the TFO, the TFO is not obliged to before November 17, 2008. comply with the ISO Rule which is inconsistent Among the findings and direction of the with the EUA as a TFO has a duty to comply Commission were the following: with any ISO Rule that has been established except to the extent that doing so would not • AltaLink was directed to consult with the be consistent with section 39(4) of the EUA. AESO and other Alberta TFOs regarding the AltaLink was directed to revise Article 3.1(b) of establishment of a process and timeline for the proposed T&Cs to reflect this requirement ensuring that any mutual understandings and once again the Commission provided between the AESO and the TFOs set out in suggested language. the detailed subsections of Article 3.1 of the proposed T&Cs are reflected in applicable ISO • The AUC agreed that a TFO has a reasonable Rules and/or AESO business practice basis for concern about the AESO having the documents rather than in the T&Cs. AltaLink authority to direct it to operate its transmission was directed to provide its report on this facilities outside the parameters of Normal process and timeline in the refiling application. Operating Limits when contingency conditions are in effect. The Commission said that there • AltaLink was directed to include language is also a reasonable basis for a TFO to be clearly stating the paramountcy of the AESO’s concerned about the AESO having the rule making authority in Article 3.1 authority to direct the operation of immediately below the words “The TFO will transmission facilities outside of the provide and make available Transmission Emergency Operating Limits at any time. Such Services in accordance with these T&Cs”. The concerns notwithstanding, the AUC reiterated Commission provided potential language but its finding that a TFO does not have the said that the parties were free to develop their statutory authority to decline an operational own. direction from the AESO except in accordance • The AUC noted that Article 3.1 (a) of the T&Cs with section 39(4) of EUA. AltaLink was did not provide any role for the AESO in the directed to amend Article 3.1(d) to reflect this establishment of Normal and Emergency limitation or to remove the final sentence of Operating limits. The Commission said that, Article 3.1(d) at the time of the refiling. while the establishment of transmission facility The Commission said that it considered that operating limits should be initiated by the • referencing “Good Electric Operating Practice” TFOs rather than by the AESO, it is possible (“GEOP”) as a basis for a TFO to exercise that the AESO and the TFO may disagree on discretion to interrupt or curtail service in the levels of Normal and Emergency Article 3.1(e) (iii) affords discretion to a TFO to Operating Limits. The AUC further stated that interrupt or curtail service that goes beyond the TFO T&Cs must not bind the discretion of the limited set of conditions found in section the AESO beyond the limits of Electric Utilities 39(4) of the EUA. As a result, it directed Act (“EUA”) section 39(4). AltaLink was AltaLink to revise Article 3.1(e) (iii) to directed to revise Article 3.1(a) of the

- 19 - Cerise, Volume 7, Issue 11-November 2008 appropriately reflect section 39(4)(c) of the that any request to amend a Schedule to the EUA rather than GEOP in the refiling. T&Cs initiated by either the TFO or the AESO must be brought to the Commission for • The AUC stated that the discretion of the TFO consideration and directed AltaLink to revise to make decisions or take actions independent Article 17 to address this finding at the time of of ISO Rules does not exist except to the its refiling. extent provided for under section 39(4) of the EUA. The Commission found that certain • The AUC found that the matters set out in subsections of Article 3.1(g) of the proposed Schedule A are of an operational nature and T&Cs which are subject to the phrase “without should most appropriately be set out in ISO liability of any kind to the ISO” may be Rules rather than in the T&Cs and it directed inappropriate insofar as these provisions, by AltaLink to consult with the AESO and the removing any consequence for the TFO in other TFO’s regarding the establishment of an failing to comply with an ISO, reverts the appropriate process and timeline to articulate authority accorded to the AESO in the any matters addressed in Schedule A within legislative scheme back to the TFOs. AltaLink an ISO Rule, if necessary. The Commission was directed to amend the language in Article directed AltaLink to report on the appropriate 3.1(g) to reflect this finding. process and schedule for the possible transfer of Schedule A matters into one or more ISO • The AUC said that it considers it essential that Rules or at the time of the refiling. TFO expenditures and revenues arising from Article 3.1 Transmission Services and from • The AUC directed AltaLink to consult with the Article 3.2 Additional Services agreements be AESO and the other TFO’s regarding the properly categorized so that they may be establishment of an appropriate process and scrutinized by the Commission and interested timeline to articulate any matters addressed in parties in TFO or AESO tariff proceedings, as Schedule B within an ISO Rule, if necessary. applicable. The AUC directed AltaLink to The Commission directed AltaLink to report on include as part of Article 3.2 the additional the appropriate process and schedule for the words suggested by the Commission in its possible transfer of Schedule B matters into preamble to information request AUC.AML- one or more ISO Rules or at the time of the 004(b) or language to this effect at the time of refiling. its refiling. • The AUC found that the matters addressed in • AltaLink was directed to remove Article 11(c) Schedule C are either of an operational nature from the T&Cs at the time of its refiling. more appropriately suited to ISO Rules or, as is the case for subsections (3) and (4), • Noting that the EUA establishes a statutory unnecessary, and it directed AltaLink to remedy for market participants to object to a consult with the TFOs and the AESO for the new proposed ISO Rule (unless the proposed purposes of setting an appropriate process new ISO Rule is filed in accordance with the and schedule for dealing with Schedule C expedited filing process) or to complain about matters within ISO Rules and/or OPPs and to an existing ISO Rule, and that the dispute provide a report on such proposed process resolution process set out in the T&Cs must and schedule at the time of its refiling. be subject to any market participant’s statutory right to bring an objection or complaint before • The AUC found that to the extent that the the Commission, AltaLink was directed to second paragraph of Schedule C provides amend Article 9 to recognize this limitation at discretion to the TFO not to comply with an the time of its refiling. AESO OPP for reasons beyond the scope of EUA section 39(4), such discretion is • The AUC said that it was concerned by the unenforceable and cannot be relied upon by assumption within Article 17 that the AESO the TFO and it directed AltaLink to revise and the TFO can agree to amend the Schedule C to reflect this finding. schedules without the need for Commission approval of the amendment. The AUC said - 20 - Cerise, Volume 7, Issue 11-November 2008 • Citing a passage from subsection (3) from 101, 102 and 109 of the Public Utilities Schedule D of the T&Cs the Commission Act (“PUA”) following the completion of directed AltaLink to remove that passage at the transfer of TFO Assets from TAU to the time of the refiling. TEC and until such time as TEC merges with TAC, TAU and Keephills 3 GP Ltd. • Saying that any revenues that the TFO may to form Amalgamated TAC; receive from the AESO pursuant to subsection (4) of Schedule D should be treated as an 4. TA Gen is deemed to be subject to Additional Service and as such, any revenues sections 101, 102 and 109 of the PUA that the TFO may receive from the AESO following the completion of the transfer pursuant to Schedule D, subsection (4) must of TFO Assets from TAU to TEC and be disclosed at the time of the TFO’s GTA, the until such time as TA Gen may be Commission directed AltaLink to add language designated a “public utility” under the to Schedule D to reflect its findings at the time Designation Regulation; of its refiling and provided suggested 5. Effective as of the date of language for consideration. Amalgamation, section 101(2) of the • The Commission said that Schedule E serves PUA no longer applies to TA Gen no useful purpose within the T&Cs and directs except in respect of any transaction AltaLink to remove Schedule E from the TFOs undertaken by the TransAlta Generation and any associated references to Schedule Partnership, in respect of the TFO found elsewhere in the T&Cs at the time of its Assets. refiling. 6. Amalgamated TAC continues to be a General designated owner of a utility under the Designation Regulation; November 18, 2008 7. Effective as of the date of AUC Approves the Reorganization of Amalgamation, Section 101(2) of the TransAlta Corporation Group’s Corporate PUA no longer applies to Amalgamated Structure TAC, except in respect of any In response to Application 1587709 filed on transaction undertaken by Amalgamated September 22, 2008 by TransAlta Corporation TAC, as the Manager of the TransAlta (“TAC”), TransAlta Utilities Corporation (“TAU”), Generation Partnership, in respect of and TransAlta Generation Ltd. (“TA Gen”) the TFO Assets; (collectively, “the Applicants”) with the Alberta 8. Effective as of the dated of Utilities Commission (“AUC” or “the Amalgamation, Order C92057 is Commission”) seeking approval to reorganize rescinded and Amalgamated TAC is TransAlta Corporation Group’s (“TAC Group”) released from the Undertaking made by corporate structure, the AUC has issued TAC as of January 1, 1993 in Decision 2008-116 approving the application in connection with Order C92057. accordance with the terms set out in the Decision. 9. The Applicants file a copy of the Certificate of Amalgamation and The AUC ordered that: accompanying Articles of Amalgamation 1. The transfer of TFO Assets from TAU to with the Commission, the Indian Land TransAlta Energy Corporation (“TEC”), Registry and interested parties after the as the Manager of the TransAlta date of Amalgamation. Generation Partnership is approved; November 18, 2008 2. The merger and union of TAU, TAC, ATCO Midstream Announces Purchase of TEC and Keephills 3 GP Ltd. to form Assets in NWT Amalgamated TAC is approved; ATCO Midstream has announced the purchase 3. TEC is deemed to be subject to sections - 21 - Cerise, Volume 7, Issue 11-November 2008 of IPL Holdings Inc. (“IPLH”), a wholly owned The AUC reviewed the Application and found subsidiary of Enbridge Inc, which holds a one- the debt issue under consideration to be third interest in the Ikhil Joint Venture and one- necessary to finance assets that are used and third of the shares of Inuvik Gas Ltd. useful and in the public interest. The According to the announcement, the Ikhil Joint Commission added that the prudency of the Venture and Inuvik Gas represent the first terms of the final debt issue and interest rate natural gas development project north of the related to the issue could be reviewed during the Arctic Circle, dating back to 1999 when joint next GTA proceeding. venture partners, Inuvialuit Petroleum November 7, 2008 Corporation, AltaGas Utility Group Inc. and IPLH Alberta Government Introduces Legislation developed the Ikhil gas reservoir in the to Implement New Royalty Framework Northwest Territories. Today, assets include two producing wells, gas gathering and processing The Government of Alberta has announced the facilities as well as a 50 kilometre pipeline to the introduction of the Mines and Minerals (New town of Inuvik. Royalty Framework) Amendment Act, 2008 (“the Act”) which it says will enable the The announcement adds that Inuvik Gas is the implementation of regulations for a sliding scale sole distributor of natural gas to the town, of new, price sensitive royalties which will take serving more than 800 customers. effect with the January 2009 production month. November 18, 2008 The royalty scales take into account fluctuating commodity prices by providing increased returns AUC Grants AltaLink Management for Albertans when prices are high, while Application to Issue is up to $150 Million of offering lower royalty rates when prices are low Medium Term Notes with a Term of up to 20 to promote continued investment and Years development. The announcement says that the The Alberta Utilities Commission (“AUC” or “the Act will also give the province the tools to pursue Commission”) has issued Financing Non- new opportunities for value-added development Routine Order No. U2008-317 in which it by collecting bitumen or other products from oil approves Application No. 1587793 from AltaLink sands operators in lieu of cash royalties and to Management Ltd. (“AML”), in its capacity as the encourage new investment in shallow resource general partner of AltaLink L.P. (“ALP”), which pools. was registered on September 23, 2008, and which sought approval for: The Act will also give Cabinet the authority to pass regulations to strengthen the accountability a) an order of the Commission authorizing AML systems necessary to ensure complete and to cause ALP to issue up to $150 million timely reporting on royalties owed to the aggregate principal amount of medium-term province. This responds to recommendations notes having a term of up to 20 years and made by the Auditor General and by Peter having other terms currently expected to be as Valentine in his report, “Building Confidence: set out in the indicative term sheet attached as Improving Accountability and Transparency in Appendix “A” to the Application (the “Debt Alberta’s Royalty System”. Securities”), (ii) approving such issue as being made in accordance with law and (iii) approving The announcement advises that implementation the purposes of such issue; and of the New Royalty Framework requires amendments to the Mines and Minerals Act, and b) an order of the Commission authorizing AML, the enactment of seven regulations. Alberta as legal owner, and ALP, as beneficial owner, to Energy has also been required to make grant security to lenders in respect of the Debt significant changes to a number of specialized Securities, in the form of a first floating charge information technology applications to reflect the over the present and future property, assets and new royalty structures. undertaking of AML, as legal owner, and ALP, as beneficial owner.

- 22 - Cerise, Volume 7, Issue 11-November 2008 November 4, 2008 monthly for natural gas prices. Based on the energy payment formula, there is a small portion EPCOR Power L.P. and EPCOR Power Equity of energy costs that are not recovered through Ltd. Announce Closing of Morris the energy payments, and this non-recoverable Cogeneration LLC Acquisition amount fluctuates with the price of natural gas. EPCOR Power L.P. (“EPLP”) and EPCOR Most of this natural gas price exposure has been Power Equity Ltd. (“EPEL”), a subsidiary of hedged through 2011 and the Partnership is EPLP announce completion of the acquisition of considering adding additional natural gas Morris Cogeneration LLC from Diamond forward contracts past 2011 to further mitigate Generating Corporation and MIC Nebraska, Inc., this future price risk. both wholly-owned subsidiaries of Mitsubishi The announcement adds that the facility has a Corporation. The announcement notes that the power purchase agreement (“PPA”) with Exelon acquisition was previously announced on Generation Company, LLC covering 100 MW of September 11, 2008. It says that the acquisition electrical capacity. The annual capacity revenue closed on October 31, 2008 with a purchase earned under this contract has averaged just price of U.S. $72.7 million, after preliminary over U.S. $6 million per year, including bonus closing adjustments. The announcement payments for peak availability which exceeds 98 advises that the purchase price of the per cent. This PPA expires in April, 2011. The acquisition is being financed under the Partnership is evaluating opportunities to either Partnership's existing credit facilities. enter into new power purchase arrangements The announcement reports that the Morris with a third party, contract capacity into the facility, which began commercial operations in Pennsylvania, New Jersey, and Maryland November 1998, is a 177 megawatt (“MW”) (“PJM”) market or sell electricity on a merchant natural gas-fired cogeneration facility located on basis following the expiry of the existing PPA Equistar Chemicals LP's (“Equistar”) chemical term in 2011. plant in Morris, Illinois, near Chicago. The facility has three General Electric (“GE”) Frame 6B BRITISH COLUMBIA combustion turbine-generators, three Deltak Natural Gas supplementary fired heat recovery steam generators and one GE steam turbine generator November 26, 2008 and is located on 4.6 acres of land which is BCUC Grants Terasen Fort Nelson being leased from Equistar through 2023. The Application for Approval to Amend its announcement advises that Equistar has a right Schedule of Rates Effective January 1, 2009 to purchase the facility at fair market value at the for the Fort Nelson Service Area end of 2013, 2018 and 2023. It reports that the facility is a qualifying facility or "QF" under the Further to an amended application filed on Public Utility Regulatory Policies Act of 1978. October 30, 2008 by Terasen Gas Inc. (“TGI”) for approval to amend its schedule of rates The announcement says the facility has an effective January 1, 2009 for the Fort Nelson energy services agreement with Equistar Service Area (“Terasen Fort Nelson”), the British through 2023 providing for capacity and energy Columbia Utilities Commission (“BCUC” or “the payments for 100 per cent of Equistar's steam Commission”) has issued Order No. G-172-08 in needs and up to 77 MW of electricity. The which it approved Terasen Fort Nelson’s annual capacity payments from Equistar amended application subject to a recalculation consists of two payments, a non-escalating to reflect the 2009 allowed ROE determined by payment which expires in November, 2013, and the Generic Mechanism once issued by the a payment which escalates with materials and Commission. BCUC further directs Terasen Fort labour indices that runs through November, Nelson to file amended Gas Tariff Rate 2023. The non-escalating capacity payment is Schedules in accordance with the Order in a fixed at U.S. $8.3 million per year. In addition, timely manner. the facility earns energy payments based on electricity and steam delivered that is adjusted The Commission reports that the amended - 23 - Cerise, Volume 7, Issue 11-November 2008 application sought approval on a permanent The announcement explains that the South basis, effective January 1, 2009, to increase the Peace Pipeline will be linked to Westcoast's Rate Stabilization Adjustment Mechanism control room in Fort St. John, British Columbia. (“RSAM”) rate rider from $0.116/GJ by The NEB states that Westcoast also has a $0.120/GJ for a total rate rider of $0.236/GJ. comprehensive Emergency Management Plan The amended application also included a (“EMP”) which is updated annually and filed with revenue requirement increase of $377,000 for the Board, and an Operations Security Plan to the 2009 test year, effective January 1, 2009, help ensure the safety of the public and its resulting in an average 6.7 percent rate increase employees by maintaining the security of all its for all sales rate classes or a 36.0 percent facilities. The Pipeline will be incorporated into increase on a gross margin basis for all Westcoast's existing Security Plan. customers. The NEB noted that Westcoast effectively The Commission further reported that no identified potentially affected stakeholders and Intervenors or Interested Parties registered and Aboriginal people with an interest in the project no Intervenors provided comments by the and that consultation has been ongoing since October 10, 2008 deadline set by Order No. G- July 2007. The Board determined that impacts 144-08. on Aboriginal interests are likely to be minimal and that potential impacts will be appropriately November 19, 2008 mitigated. The NEB expects Westcoast to NEB Approves Westcoast (Spectra Energy) provide ongoing information to members of the South Peace Pipeline Project Kiskatinaw Pipeline Landowners Association, The National Energy Board (“NEB” or ‘the and interested landowners and residents, Board”) has approved an application from regarding Westcoast's programs to address Westcoast Energy Inc., carrying on business as issues associated with hydrogen sulphide (H2S). Spectra Energy Transmission, (“Westcoast”) to Westcoast committed to a Continuing Education construct the South Peace Pipeline Project (“the Program (“CEP”) to provide public awareness Project”). and education for landowners, residents and businesses which could be affected by a release The NEB explains that the proposed Project is from the Pipeline. an approximately 92 km extension of Westcoast's existing raw gas gathering system Along with the Reasons for Decision approving near Fort St. John, British Columbia, and that the project, the NEB also released the the new 508 mm (20 inch) diameter pipeline Environmental Screening Report (“ESR”) for the would carry gas from the area south of Fort St. Project, as required by the Canadian John and the Peace River northward to connect Environmental Assessment Act (“CEA Act”). to Westcoast's McMahon processing plant, in The Board advises that after a draft ESR was Taylor, British Columbia. The project, with an circulated for public comment on September 25, estimated construction value of $95 million, 2008, the final ESR concluded that with the would connect to either end of an existing implementation of Westcoast's environmental pipeline across the Peace River. protection procedures and mitigation measures, The Board advises that the Canadian Standards and the NEB's recommendations, the Project is Association (“CSA”) standard Z662-07 not likely to cause significant adverse establishes essential requirements and environmental impacts. minimum standards for the design, materials, The NEB issued Hearing Order GH-3-2008 on construction, operation, and maintenance of gas 12 March 2008 and held a public hearing in pipeline systems, and that the CSA standard Dawson Creek, British Columbia on 26 August has specific provisions for sour gas service 2008. pipelines. The NEB states that Westcoast committed to meet all applicable provisions in the standard.

- 24 - Cerise, Volume 7, Issue 11-November 2008 November 19, 2008 Gas Contracting Plan in Letter No. L-27-08, the British Columbia Utilities Commission (“BCUC” Terasen Gas Launches Compressed Natural or “the Commission”) has issued Order No. E- Gas Vehicle Program 21-08 in which it accepts for filing the executed Terasen Gas (“Terasen”) has announced a copy of the Gas Electronic Data Interchange Compressed Natural Gas Vehicle Program (“EDI”) Base Contract and Special Provisions for (“CNGV”) to promote clean, efficient natural gas the Short Term Sale and Purchase of Natural vehicles as an energy alternative in British Gas between EOG Resources Canada and Columbia’s transportation sector. The company Terasen Gas Inc. dated October 23, 2008 which says the program supports the B.C. had been submitted by Terasen Gas on Government’s Energy Plan and provides November 5, 2008. businesses with innovative energy solutions to reduce operating costs and greenhouse gas November 14, 2008 (“GHG”) emissions. BCUC Accepts for Filing Gas Supply Terasen is also announcing the first project Contracts Submitted by Pacific Northern Gas under the CNGV program, involving Terasen, Ltd. Euro Asia Transload and FuelMaker, which will The British Columbia Utilities Commission see the conversion of 100 forklifts from propane (“BCUC” or “the Commission”) has issued Order to natural gas. The $500,000 project includes No. E-19-08 in which it accepts for filing the gas the extension of the Terasen system to deliver contracts that were submitted on October 31, natural gas to a newly installed FuelMaker Corp. 2008 by Pacific Northern Gas Ltd. (“PNG”) for compression system at Euro Asia Transload’s approval of monthly and daily price premiums for Richmond and Burnaby warehouses and the gas supply arrangements which include installation of a FuelMaker Corp. compression seasonal, peaking and storage contracts. BCUC system to fuel each forklift. said that it had reviewed the PNG filing and is satisfied that the gas supply contracts are According to the announcement, approximately appropriate considering market prices at the 40 per cent of GHG emissions in B.C. come time the contracts were negotiated and the from the transportation sector. Annual Contracting Plan for 2008/2009. Under the new CNGV program, Terasen says it The Commission notes that it accepted the will support businesses by: 2008/2009 Annual Gas Contracting Plan under • continuing to invest in developments like the its Letter L-18-08 dated May 15, 2008. Forklift conversion project; November 14, 2008 • “bringing home” to B.C. the innovation in BCUC Accepts Filing of Gas EDI Base natural gas engine technology that B.C. Contract and Special Provisions for the businesses are already exporting to other Short Term Sale and Purchase of Natural countries; and Gas between Nexen Marketing and Terasen • strengthening its role as a central agency of Gas expertise for businesses looking to convert to Further to its acceptance of the Terasen Gas natural gas vehicles and fleets. Inc. (“Terasen Gas”) 2008/09 Midstream Annual November 14, 2008 Gas Contracting Plan in Letter No. L-27-08, the British Columbia Utilities Commission (“BCUC” BCUC Accepts Filing of Gas EDI Base or “the Commission”) has issued Order E-20-08 Contract and Special Provisions for the in which it accepts for filing the executed copy of Short Term Sale and Purchase of Natural the Gas Electronic Data Interchange (“EDI”) Gas Between EOG Resources and Terasen Base Contract and Special Provisions for the Gas Short Term Sale and Purchase of Natural Gas Further to its acceptance of the Terasen Gas between Nexen Marketing U.S.A. Inc. and Inc. (“Terasen Gas”) 2008/09 Midstream Annual Terasen Gas Inc., dated November 1, 2007,

- 25 - Cerise, Volume 7, Issue 11-November 2008 which was submitted by Terasen on November River Processing Plant, near Chetwynd, BC, and 5, 2008. includes 17 kilometres of new pipeline (parallel to existing lines), an additional 40 million cubic November 11, 2008 feet per day of gathering capacity, and BCUC Rules that Big White Gas Utility modifications at the Pine River facility to Should Continue to Operate Under its accommodate the increased delivery of gas. Existing Tariff Without Filing a 2008 Revenue

Requirements Application Electricity In response to a confidential letter filed on November 28, 2008 September 26, 2008 by Big White Gas Utility British Columbia Investing $400,000 to Ltd. (“BWGU”) containing its Financial Forecast Support Electrical Vehicle Technology for June 1, 2008 to May 31, 2009 and requests The Government of British Columbia has (1) that BWGU be allowed to continue to operate announced that it is investing nearly $400,000 to under its existing tariff without the requirement to support plug-in electric vehicles and related file a 2008 Revenue Requirements Application monitoring equipment around the province. (“RRA”) or 2009 RRA and, (2) should the British According to the announcement, there will be up Columbia Utilities Commission (“BCUC” or “the to 34 plug-in electric vehicles in operation, being Commission”) direct a filing of the 2009 RRA monitored in the province, and the initial vehicles that sets the filing date of the 2009 RRA to on or are four Toyota Prius converted to plug-in hybrid before October 15, 2009, the Commission has electric and two pickup trucks converted to plug- issued Order No. G-162-08 in which it finds that in battery electric. BWGU’s filing satisfies Directive No. 4 in Order G-98-08, the current rates are in the public The BC Government notes that the investment interest, and BWGU should continue to operate is part of a broader plug-in electric vehicle under its existing tariff without filing a 2008 program, and says that part of this program is Revenue Requirements Application. the plug-in electric transportation working group which includes the ministries of Energy, Mines BCUC notes that on May 29, 2008, it issued and Petroleum Resources, Transportation and Letter L-22-08 which stated that the Commission Infrastructure, Environment, and Labour and plans to direct BWGU to file by no later than Citizens’ Services, as well as the Climate Action April 30, 2009, its 2009 Revenue Requirements Secretariat, City of Vancouver, Green Fleets BC, (June 1, 2009 to May 31, 2010) (“2009 RRA”). BC Hydro, the British Columbia Transmission BCUC goes on to advise that subsequently, on Corporation (“BCTC”) and the University of June 19, 2008, the Commission issued Order G- Victoria’s Institute for Integrated Energy 98-08 with Directive No. 4 that BWGU was to file Systems. by September 30, 2008 a financial forecast for the June 1, 2008 to May 31, 2009 fiscal year According to the announcement, the working demonstrating that its current rates are group will: reasonable so that a filing of a 2008 Revenue 1. Complete technical studies on impacts Requirements Application (“2008 RRA”) would and opportunities for plug-in vehicles in not be required. the electricity system, using models and November 6, 2008 data collected from the program vehicles. Spectra Energy's Pine River Phase III Project Comes Into Service 2. Deliver a government-developed policy paper with public input that includes Spectra Energy has announced that it has policy recommendations related to plug- successfully completed expansion of its natural in electric transportation. gas gathering system in the Grizzly Valley area of north-eastern British Columbia. According to 3. Work with industry, educational the announcement, the project represents the institutions and other stakeholders to third phase of expansion connected to the Pine support the deployment of additional

- 26 - Cerise, Volume 7, Issue 11-November 2008 plug-in vehicles and related charging following eight years. The plan is filed for infrastructure throughout the province. approval with BCUC, the body responsible for 4. Work with local educational institutions regulating the province’s utilities. and industry to support local capacity in November 20, 2008 the plug-in electric transportation sector. BCUC Agrees to Limited Reconsideration of The announcement adds that the increased use Decision Granting FortisBC Approval for of plug-in electric vehicle technology is part of a Lochrem Road Site for the Ellison Substation broader sustainable energy strategy that will Further to a September 18, 2008 letter from the help B.C. reach its goal of curbing greenhouse Concerned Citizens of Quail Ridge and Lochrem gas (“GHG”) emissions by 33 per cent by 2020. Road (“CCQRLR”) and a September 23, 2008, In addition, plug-in electric vehicles support the letter from the Quail Ridge Residents province’s goal as outlined in the speech from Association (“QRRA”), each of which sough a the throne to reduce the carbon intensity of all review of the British Columbia Utilities passenger vehicles by 10 per cent by 2020. Commission (“BCUC” or “the Commission”) November 25, 2008 Order G-75-07 dated June 28, 2007 which granted a FortisBC Inc. (“FortisBC”) request for BCTC Files Ten Year Capital Plan with the approval for the Lochrem Road site for the BCUC Ellison Substation, BCUC has issued Order No. The British Columbia Transmission Corporation G-166-08 in which it grants a limited rehearing. (“BCTC”) has announced that it has filed its Ten The Commission has established a written Year Capital Plan with the BC Utilities hearing to reconsider the Decision, so as to Commission (“BCUC” or “the Commission”), address the initial question of whether the outlining $5.3 billion in expenditures. Noting that Ellison Substation, as proposed and approved at the transmission system is B.C.’s electricity the Lochrem Road site, will cause problems for highway powering virtually every home and the systems at the Kelowna Airport under the business in the province, the BCTC says that it terms specified in the Operating Agreement and continues to invest in improvements to the Statement of Work Agreement with NAV system to ensure electricity is delivered across CANADA (“the Agreements”) and, if problems the province, when and where it is needed. The are caused, the changes that will be needed to BCTC adds that significant investment is remedy the situation, and the cost of the required to maintain and expand the province’s changes. transmission system to secure the longterm electricity needs and to retain the ongoing BCUC further directed that by Monday, competitive advantage these assets provide to December 1, 2008, FortisBC will file an British Columbians. independent engineering Report (the “Report”) by a properly qualified individual or group that The new Capital Plan describes measures that reviews the siting and design of the Ellison the BCTC will take to enhance the transmission Substation as proposed and approved, relative system’s overall performance. These measures to the requirements of NAV CANADA as set out include replacing aging electrical equipment to in the Agreements, and which confirms that the ensure the safety and reliability of the system substation will comply with the requirements. If and building efficient new infrastructure to this confirmation cannot be provided, the Report supply the needs of communities. The BCTC will describe the changes to the substation that advises that it is also investing in new digital are needed to bring it into compliance, and the technologies to extend the life and enhance the estimated cost of these changes. capacity of B.C.’s transmission network. BCUC’s Reasons for Decision are included with The announcement advises that the BCTC’s the Order. The Commission has also F2010 – F2019 Capital Plan details capital established a timetable for the rehearing investment for the next two years and provides process. an outlook of potential investments for the

- 27 - Cerise, Volume 7, Issue 11-November 2008 November 13, 2008 Replacement Project. BCUC Denies FortisBC Request for a CPCN BCUC reports that the project consisted of the for Its Advanced Metering Infrastructure replacement of 85 percent of FortisBC’s No. 8, Project No. 6 and No. 90 MCM copper distribution The British Columbia Utilities Commission conductors with aluminum conductor steel (“BCUC” or “the Commission”) has released reinforced (“ACSR”) conductors; assessment of Order G-168-08 in which it denies a December poles for age and safety and replacement, 19, 2007 application from FortisBC Inc. subject to the assessment result; updates to the (“FortisBC”) seeking a Certificate of Public Geographic Information Systems Database; Convenience and Necessity (“CPCN”) for the standardization as per FortisBC existing Advanced Metering Infrastructure (“AMI”) Project standards for distribution lines; and disposal of (“the Project”). The Commission advises that it the replaced copper conductors through sale. will provide its rationale in a Decision which is to The project was expected to start in the first follow. quarter of 2009 and be completed by the fourth quarter of 2018, with estimated capital BCUC reports that the Project consists of expenditures of approximately $103 million, replacing FortisBC’s existing meters with AMI- including the cost of removals, over the ten-year enabled meters and installing AMI throughout life of the project. The net present value (“NPV”) FortisBC’s service territory, commencing in 2008 of the Project was estimated at approximately with completion by the end of 2010. FortisBC $59 million with an estimated NPV of Customer estimated that the Project would cost $31.3 Rate Impact at 0.15 percent. Although FortisBC million and would result in reduced operating was seeking approval of the Project, it was only costs and enhanced customer service, largely seeking expenditure approval out to 2010 of due to the remote meter reading capability of the $11.7 million, and proposed to seek further AMI-enabled meters. approval for expenditures beyond 2010 in its The Commission further reports that on March future Capital Expenditure Plans. 25, 2008, it postponed the timetable it had The Commission noted that no intervenors were established for the review of the application to opposed to the project. allow FortisBC to amend the application to include the additional functional enhancements In its Reasons for Decision, BCUC referenced of Home Area Network (“HAN”) capability to the PowerTech Report provided as Appendix A allow for in-home display units at some future to the FortisBC application and noted that: date, along with Validation, Estimation and • of the 12 conductor samples submitted for Editing (“VEE”) and hourly reading capability to analysis, six were of legacy copper conductor, the Meter Data Management Repository to the and six were of No’s 2, 3 and 4 non-legacy original AMI capability which added $6.0 million copper conductor, which are excluded from to the previously estimated cost of $31.3 million the scope of the Project. for a total estimated cost of $37.3 million. • the non-legacy samples included one with a November 11, 2008 failed hot tap connection, and two with BCUC Denies FortisBC Application for a un failed line splices; the balance were CPCN for Copper Conductor Replacement connection-free conductor wire samples, as Project were all of the legacy samples submitted. The British Columbia Utilities Commission • metallographic examination of the failed hot (“BCUC” or “the Commission”) has issued Order tap sample from non-legacy conductor G-165-08 and accompanying Reasons for confirmed the root cause of failure as Decision, in which it denies a June 27, 2008, annealing due to local resistance heating; FortisBC Inc. (“FortisBC”) application for a similar examination of the un-failed splice Certificate of Public Convenience and Necessity samples from non-legacy conductor confirmed (“CPCN”) for the Copper Conductor similar annealing local to the splices. physical

- 28 - Cerise, Volume 7, Issue 11-November 2008 testing of the non-legacy samples containing or “the Commission”) has issued Order No. G- connections confirmed that three inches 160-08 in which it approves an amended tariff distant from the connection, the properties of page for RS 1151. the conductor itself were unaffected. BCUC notes that, by Order G-124-08, dated • physical testing and metallographic August 28, 2008, it approved the existing RIB examination of both the connection-free rate structure commencing October 1, 2008. legacy and non-legacy conductor samples The Commission says that the RIB rate control confirmed that the material properties are group customers are to be recruited from the slightly below that of the nominal values currently participating Conservation Research dictated by the current standard (emphasis Initiative - Time of Use (“CRI TOU”) control added by the Commission). group customers and that the CRI TOU Pilot BCUC said that, in the absence of any evidence program is to end on October 31, 2008. The as to the nature and cause of the failures in the Order reports specifically that BC Hydro seeks legacy copper system, and given the expert an order which will amend Rate Schedule 1151 - opinion that the properties of both legacy and Exempt Residential Service (“RS 1151”) to allow non-legacy conductor material are unaffected customers enrolled in the RIB rate control group outside of any connection areas, and that those to continue to receive service under RS 1151 properties are only slightly below today’s after October 31, 2008. The Commission adds standard, the Commission Panel was unable to that, as one of several methods for measuring share FortisBC’s conclusion that replacement of the effectiveness of the RIB rate, BC Hydro all of the legacy copper conductor will mitigate plans to use a RIB rate control group as a the disproportionate occurrence of failure means of comparing the energy consumption statistically associated with the legacy system. patterns of residential customers on a flat rate to residential customers on the RIB rate. The Commission Panel said that it was further concerned that the accelerated replacement of General the legacy copper system as proposed in the November 26, 2008 Project would also result in the rate of pole replacement across the whole Fortis BC system B.C. Government Announces that David being materially, and potentially unnecessarily, Emerson Will be Chair and CEO of BCTC increased from its current level of 130/year by The Government of British Columbia has some or all of the 390 legacy system poles/year announced that former federal cabinet minister proposed to be replaced on average over the David Emerson will serve as the new executive ten year life of the Project. chair of the British Columbia Transmission For these reasons, the Commission Panel said Corporation (“BCTC”), presiding over the board that it could not conclude that the expense of directors and assuming the responsibilities of associated with the Project as submitted was the chief executive officer (“CEO”). The justified, and accordingly denied the application. announcement suggests that this new structure will allow for a smooth transition in the BCTC’s November 11, 2008 corporate leadership. BCUC Approves BC Hydro Application for a The announcement reports that Mr. Emerson RIB Rate Exemption for Group of Customers has served in numerous public and private Enrolled in RIB Control Group capacities, including several federal government Further to an October 20, 2008 application by cabinet portfolios. Prior to his retirement from the British Columbia Hydro and Power Authority elected office, he served as minister of foreign (“BC Hydro”) seeking approval of a residential affairs, as minister of international trade and inclining block (“RIB”) rate exemption for a group minister for the Pacific Gateway and the of residential customers enrolled in an RIB rate Vancouver-Whistler Olympics, and as minister of control group, effective November 1, 2008, the industry. David Emerson has also served as British Columbia Utilities Commission (“BCUC” deputy minister of finance and deputy minister to - 29 - Cerise, Volume 7, Issue 11-November 2008 the Premier in the government of British recommendations and implemented the Columbia. He was the first CEO of the following: Vancouver International Airport Authority, and • 2012 – six per cent below 2007 levels. This served as president and CEO of Canfor prior to target falls in the middle of the range being elected as a federal MP for Vancouver. recommended by the CAT and was achieved The announcement adds that Mr. Emerson has in 90 per cent of the model simulations. extensive experience from his service on • 2016 – 18 per cent below 2007 levels. This numerous corporate boards, including Telus, target is at the upper end of the range Terasen Gas and BC Ferries. He was the first recommended by the CAT and was achieved chair of the BC Progress Board, and has also in 95 per cent of the model simulations. served on the boards of the Canada West Foundation, the Forest Products Association of The government notes that the Climate Action Canada and the Canadian Council of Chief Plan, released in June, outlines initiatives that Executives. will take British Columbia approximately 73 per cent of the way to the 2020 target. The November 26, 2008 government is reviewing additional strategies B.C. Government Sets GHG Targets for 2012 put forward by the CAT in areas such as And 2016 emissions pricing, transportation, buildings, The B.C. Government reports that it has agriculture, forestry, and energy, to fill the reviewed and accepted the recommendations of remaining gap. the Climate Action Team (“CAT”) for interim The government advises that the 2012 and 2016 greenhouse gas (“GHG”) reduction targets, targets will be legally mandated, through establishing a GHG reduction target of six per regulation, by the end of 2008. cent below 2007 levels by 2012 and 18 per cent November 20, 2008 by 2016. BC Government Signs Joint Declaration on The announcement says that the B.C. Action to Reduce GHG Emissions During Government made a commitment to reduce Governors’ Global Climate Summit in GHG emissions by one-third by 2020 and that California the 2012 and 2016 targets will be used to guide and measure its progress towards the 2020 The Government of British Columbia has target and build on the economic opportunities announced that it has joined more than 8 U.S. to develop clean technology and green states and representatives from 11 countries in innovation in British Columbia. signing a joint declaration agreeing to pursue collaborative action to reduce greenhouse gas The government says that in November 2007, it (“GHG”) emissions and create opportunities to put into law British Columbia’s target of reducing grow green economies during the two-day GHG emissions by at least 33 per cent below Governors’ Global Climate Summit in California, 2007 levels by 2020 and 80 per cent by 2050 with the passing of the Greenhouse Gas The B.C. Government says that according to Reduction Targets Act. The Act requires that Deutsche Bank, which has just released a report realistic, economically viable interim targets for called “Economic Stimulus: The Case for Green 2012 and 2016 be set by the end of 2008. The Infrastructure, Energy Security and Green Jobs”, government established the CAT to recommend the world economic crisis can be addressed by the interim targets. aggressively investing in a low-carbon economy. The report says “a $100-billion investment in The government notes that the final CAT report clean energy and efficiency would result in two was released for public comment from August 6 million new jobs.” through October 6, 2008. After extensive feedback from industry and independent The announcement notes that the summit economic modelling to ensure the targets are featured discussions on monitoring and achievable, the government accepted the reporting of climate change emissions, reducing

- 30 - Cerise, Volume 7, Issue 11-November 2008 GHG emissions with sector-specific actions, a Corp. (“Nexterra”) in supplying a biomass report by government leaders on the global gasification system to Kruger Products Paper response to climate change and a commitment Mill (“Kruger”) in New Westminister. The to further action. announcement says that the alternative energy system will cut operating costs for Lower British Columbia’s actions to address climate Mainland industry and reduce greenhouse gas change and stimulate investment include: (“GHG”) emissions by 22,000 tonnes per year. • legislating GHG emission reductions of 33 per According to the announcement, Nexterra’s cent by 2020; direct fired biomass gasification system, the first • implementing tax cuts supported by a tax on of its kind in the pulp and paper industry, carbon emissions; converts locally sourced wood residue into clean-burning syngas to fire a boiler to produce • being the first province to join the Western heat for Kruger’s industrial process – Climate Initiative (“WCI”) and becoming a co- dramatically reducing the need to burn natural chair in the development of a cap-and-trade gas. The Kruger installation will produce 40,000 system that includes B.C.’s largest U.S. lbs/hour of process steam and displace trading partners; approximately 445,000 gigajoules (“GJs”) of • legislating the use of low-carbon fuels and natural gas annually. Displacing this amount of more fuel efficient vehicles; natural gas with syngas made from wood fuel will also lower Kruger’s energy costs by millions • investing in bio-energy and climate research; of dollars a year, making it less reliant on fossil and fuels. • implementing a new aggressive green building According to FPInnovations, part of a code to improve energy efficiency. consortium formed with Kruger and Nexterra, The government states that, in response to its advancements to Nexterra’s gasification Energy Plan, billions of dollars are currently technology make the switch from fossil fuels to being invested by independent power producers syngas an attractive option for many of North in renewable electricity projects in B.C., America’s pulp and paper mills and other employing workers in rural communities. The industrial sites. announcement adds that independent economic November 17, 2008 modelling estimates the province is 73 per cent of the way to meeting the 33 per cent 2020 BCTC Announces Departure of its President reduction target. and CEO Jane Peverett The announcement adds that aside from the The British Columbia Transmission Corporation summit in California, B.C. and California have (“BCTC”) has announced that on January 15, also partnered on a number of significant 2009, Jane Peverett, President and CEO, will climate-action initiatives in the past, which leave BCTC after almost six years to become a include signing memoranda of understanding full-time Corporate Director. (“MOU”) on Climate Action and on Ocean The announcement advises that in the near Protection. Additionally, both B.C. and California future, BCTC’s Board will initiate a search for a are active members of the Pacific Coast new President and CEO. In the interim, John Collaborative and the Western Climate Initiative. Irving, the company’s Vice-President and November 20, 2008 General Counsel, will assume the role of Acting CEO, effective January 16, 2009, while a search BC Government’s ICE Fund Backs Nexterra is conducted for Ms. Peverett’s permanent in its Supply of Biomass Gasification System successor. to Kruger Products Paper Mill The Government of British Columbia has announced that it is using its Innovative Clean Energy (“ICE”) Fund to support Nexterra Energy - 31 - Cerise, Volume 7, Issue 11-November 2008 MANITOBA Wind Farm Inc., owned by Babcock & Brown Canada ULC, to develop a 300 megawatt Electricity (“MW”) wind farm, the largest in Canada, at St. November 28, 2008 Joseph near Letellier in southern Manitoba. The MB Hydro Introduces Residential Solar Water announcement adds that the St. Joseph Heating Program proposal was the best of the over 84 proposals received in response to Manitoba Hydro’s RFP Manitoba Hydro (“MB Hydro”) has announced in 2007. the introduction of a new Residential Solar Water Heating Program. The program, The announcement notes that the project is developed with Natural Resources Canada subject to regulatory approvals and execution of (“NRCan”), is the latest addition to MB Hydro’s a power purchase agreement (“PPA”) with growing list of Power Smart programs. construction expected to start in 2009 and power deliveries starting as early as 2011. The exact According to the announcement, solar thermal schedule will depend upon the availability of hot water systems use solar collectors, typically materials and equipment for the wind turbines mounted on a roof, to absorb the sun's radiation and related transmission facilities. and transfer that energy into the home to preheat water entering the hot water tank. According to the announcement, the project is Systems can operate year round and typically worth over $800 million and will generate raise water temperatures by 4 to 10 degrees C, electricity from 130 turbines. It will result in $300 which in turn decreases the amount of energy million in operational expenditures, $70 million in required by the hot water tank. MB Hydro local landholder payments and $198 million in advises that participating homeowners in the provincial and municipal revenues over the life new program can expect savings between 30 to of the project. Environmental benefits include 60 per cent on their annual water heating costs. displacing 800,000 tonnes of greenhouse gas (“GHG”) emissions annually, the equivalent of In addition, MB Hydro says that the partnership taking 145,000 cars off the road. with NRCan allows the company to offer a $1200 rebate to participating customers. Other The announcement further advises that expenses, such as training and marketing costs, Manitoba Hydro will purchase wind-generated will be borne by MB Hydro. Financing through power as part of a proposed 25-year agreement the Power Smart Residential Loan is also with Babcock & Brown’s North American Energy available. Group which has interests in more than 20 wind farms across North America with an aggregate In the same press release, MB Hydro also value in excess of $3 billion. The group has mentions the creation of the first local Canadian worked closely on this project with local Solar Industries (“CSIA”) training course on the residents and Calgary-based wind developer new technology. Called Solar Thermal Domestic BowArk Energy. Hot Water Installer Training and Certification, the new course is designed to provide training November 10, 2008 on fundamentals and installation. The course will Manitoba Board Issues Order Revising also augment the development of the local solar Certain Directives from Order 116/08 industry and is planned to begin in January Further to requests from Manitoba Hydro (“MH”) 2009. for a Review and Variance of Order 116/08 and November 25, 2008 a request from the amalgamated intervention of Manitoba Hydro Board Accepts RFP Consumers’ Association of Canada (Manitoba) Proposal for 300 MW Wind Farm at St. Inc., the Manitoba Society of Seniors, and Joseph Winnipeg Harvest (“the Coalition”) for a Review and Variance of Orders 90/08 and 116/08, the The Government of Manitoba has announced Manitoba Public Utilities Board (“MPUB” or “the that the Board of Manitoba Hydro has accepted Board”) has Issued Order No. 150/08 in which, a request for proposals (“RFP”) from St. Joseph in response to the MH request, it reviews the - 32 - Cerise, Volume 7, Issue 11-November 2008 Directives from Orders 90/08 and 116/08 and re- enhanced oil project which will determine the states all of the Directives from Order 116/08, feasibility of recovering additional oil from the with revisions, but denies the Coalition’s Sinclair Field west of Virden by injecting and application. storing CO2 deep inside the earth. Manitoba has The MPUB advises that on September 18, 2008, participated in this experiment by offering royalty MH filed an application for a Review and relief to help offset initial start-up costs. If the Variance of Order 116/08, requesting the Board project is successful, this incentive will be more vary or set aside nineteen separate Directives than recovered by royalties on the additional oil provided in that Order. The Board says that in produced by the technique. considering MH’s request to vary or cancel The announcement reports that the project, nineteen of the thirty Directives in Order 116/08, located 30 kilometres southwest of Virden, will it has considered the submissions of parties determine if it is feasible to capture CO2 from which were Interveners at the GRA and MH’s large industrial emitters in Manitoba and inject response to those submissions. the CO2 in existing oil pools to increase oil The MPUB further reports that on October 15, recovery while storing the CO2 underground. 2008, the Coalition applied to the Board seeking The Government advises that the Koch Fertilizer an Order revising and varying Order 90/08 and Canada’s plant in Brandon is the source for the rolling back the 5% rate increase to 2.9%, at CO2, which is trucked to the Sinclair Field by least until such time as MH has presented, and Praxair and injected into the oil reservoir. the Board has approved, a low-income bill assistance program. The MPUB indicated that it NEW BRUNSWICK shared the Coalition’s stated concerns for low Electricity income Manitoba consumers, but for the reasons stated in its Order, it denied the November 28, 2008 Coalition’s application to Review and Vary Order NB Regulator Issues Decision Concerning 90/08 and 116/08. Proposed Changes to NBSO Open Access To reflect the decisions in its Order, the Board Transmission Tariff attached to its Order a complete listing of The New Brunswick Energy and Utilities Board Directives from Order 116/08, with revisions (“NB EUB” or “the Board”) has released its noted. decision with respect to a May 1, 2008 General application from the New Brunswick System Operator (“NBSO”) seeking approval of changes November 25, 2008 to its Open Access Transmission Tariff Manitoba Government Announces $5-Million (“OATT”). The Board notes that, pursuant to its Project to Investigate Use of Carbon Dioxide June 11 decision on a motion brought by the to Enhance Oil Recovery NBSO, Schedule 1 rate changes took effect on July 1, 2008. The Government of Manitoba has announced that a state-of-the-art, enhanced oil recovery The NB EUB reports that the NBSO applied for pilot project which has the potential to increase approval of changes to the rates for the following oil production and simultaneously reduce services: greenhouse gas (“GHG”) emissions is being • Revised rates for mandatory Ancillary Service tested in south-western Manitoba. The Schedule 1; Government suggests that by encouraging carbon dioxide (“CO2”) enhanced oil recovery, • Revised rates for mandatory Ancillary Service Manitoba may get the double benefit of Schedule 2; preventing CO2 from being released into the air • Revised rates for Capacity-Based Ancillary while extracting more oil from the ground. Services (“CBAS”) in Schedules 3, 5 and 6; The announcement congratulates Tundra Oil & Gas for launching the first Manitoba C02 - 33 - Cerise, Volume 7, Issue 11-November 2008 • Rates for a New Regulation and Frequency revenue requirement related to Schedule 1. Response Service to be charged to Wind The Board went on to direct that the NBSO Generators in Schedule 3(c). report each year on any use of the contingency amount in the previous year. The Board says that the NBSO also requested approval of a number of risk mitigation factors • The NBSO was ordered to file in January of which included an automatic escalation for each year, information which supports the Schedule 1 and 2 rates, an increase in the proposed annual revenue requirement for amount of its retained surplus and a cost of Schedule 2 and which provides verification service contingency. that the actual charges to the Transportation The NB EUB notes that a Settlement Agreement Customers, for Schedule 2 services in the which addressed the allocation of the 2007/2008 previous year, were calculated appropriately. surplus from the sale of CBAS services and a • The Board approved rates for Schedule 2, as methodology to distribute any surplus for filed on May 1, 2008 effective December 1, 2008/2009 was filed on June 19, 2008. Details 2008. of this agreement are set out in the Board’s • Finding that the change to the OATT did not Decision. clearly specify how the actual charge for each The NB EUB’s findings with respect to this Transmission Customer would be calculated application included the following: was not just and reasonable, the Board denied • The Board found that it had the authority to the change in methodology for Schedules 3, 5 approve the use of a mechanism for setting and 6 as requested by the NBSO. rates as proposed by the NBSO. • The NB EUB approved the rates for Schedule • The Board approved the rates for Schedule 1 3(a), 3(b), 5 and 6, as filed on May 1, 2008, that became effective on July 1, 2008, on a effective December 1, 2008. final basis. • The Board approved the initial rate of $0.25 • Noting that if must approve the NBSO’s per megawatt hour of Wind Energy effective revenue requirement on an annual basis, the April 1, 2009. It also approved, in principle, the Board established the type and format of escalation of the rate as proposed by the information that the NBSO must, at a NBSO. minimum, file in January of each year. The • Beginning in 2010, the NBSO was ordered to Board added that it would establish the file, as part of the review of the annual process which it will use to review the revenue requirement, information on the information and that the process will actual revenues, the actual expenses and the determine any additional information which the expected expenses for the 3(c) service. NBSO will be required to provide. • The Board directed the NBSO to provide, as • The NB PUB ordered the NBSO to have any part of the review for the 2010/2011 fiscal audited surplus or deficit reviewed by the year, information on whether or not there Board prior to any action being taken with should be a limit on the amount of wind power respect to that surplus or deficit. The regulator energy which will be eligible to receive 3(c) further ordered the NBSO to file its audited service. statements annually, as soon as they are available, together with an explanation of any • The Board denied the requested change to surplus or deficit for its Schedule 1,2, 3(a), the cap on self-supply of CBAS and ordered 3(b), 5 and 6 Services. that the currently approved cap of 90% was to remain in effect. • In order to deal with significant unanticipated legitimate expenses, the Board approved the • The NBSO was ordered to disburse the establishment of a contingency amount to be surplus for 2007/2008 and to treat any surplus included as part of the proposed annual or deficit for 2008/2009 in accordance with the Settlement Agreement. - 34 - Cerise, Volume 7, Issue 11-November 2008 • The NBSO was directed to develop and place reducing air pollution. on its website historical price information for According to the study, the reasons for these ancillary services that will provide an benefits are several: indication to Transmission Customers as to what the monthly charges may be in the • New Brunswick and the Maritimes Area have future. very good wind resources, yielding wind power capacity factors of up to 40 percent; • The Board directed the NBSO to file both the compensation review and the Ea Energy • The current fuel price level provides a strong Analysis report once they have been incentive to invest in technologies with low or completed. no fuel costs. Wind power generation in the Maritimes will mainly replace production from • The Board approved various aspects of the existing low efficiency oil or gas fired power wording for the OATT. plants in the region; • The NBSO was ordered to update the OATT • Carbon regulation and Renewable Portfolio to reflect all of the changes ordered in this Standards in the regions improve the decision and to file, by December 8, 2008, a competitiveness of wind power and provide copy of all pages in the OATT which have security of demand for wind power and other changed as a result of the Decision. non carbon emitting technologies; November 25, 2008 • Electricity demand is projected to continue to NBSO Posts Report on Large Scale Wind grow in the region in a situation where it is Power in New Brunswick difficult to find sites for new generation The New Brunswick System Operator (“NBSO”) capacity in New England, including coal power has posted on its website a report entitled: plants, nuclear power and wind power plants. “Large Scale Wind Power in New Brunswick - A The study states that, in order to maximise the regional scenario study towards 2025”, prepared value of wind power in the electricity market and for the NBSO and the Government of New to provide balancing power at reasonable costs, Brunswick by Ea Energy Analyses, a Danish a high level of cooperation between the markets company. in the Maritimes Area and the neighbouring The NBSO advises that the study examines systems of New England and Québec is large-scale wind power development in the essential. This applies to the day to day Maritimes Area in a regional context and operation of systems and markets as well as to examines how Danish experiences with long-term planning for new wind power capacity deployment of large amounts of wind power and new infrastructure. Further studies of load could be utilised in a Canadian context. The flows and the dynamic behaviour of the study indicates significant benefits to New electricity system will be needed as part of the Brunswick as well as neighbouring jurisdictions deployment process. However, the study from a deployment by 2025 of 5,500-7,500 MW indicates that, with increasing wind power of wind power capacity in the Maritimes Area, penetration, it will be economically attractive to including 3,000-4000 MW in New Brunswick, increase the transmission capacity between the 500-1,500 MW in Prince Edward Island and electricity systems within the Maritimes Area as 2,000-2,500 MW in Nova Scotia. The study well as to load centres in New England. reports that exploiting this potential for wind The report suggests that the following measures power will bring economic benefits to the are required in order to harvest the full benefits Maritimes provinces as well as New England, of a large-scale deployment of wind power: and Québec may profit from providing balancing • Preparing a comprehensive wind development power. Furthermore, wind power deployment will plan for New Brunswick (and the Maritimes), contribute to the security of supply of the region, including: will be part of a climate change strategy, and may bring benefits to the local environment by o long-term targets for wind power; - 35 - Cerise, Volume 7, Issue 11-November 2008 o proper physical planning to develop states, including developing a regional sites with good wind conditions; transmission expansion plan. A regional energy study could be one of the tools for o regulation ensuring that grid access is provided at reasonable costs not evolving a common understanding of the disfavouring wind power as a challenges and possibilities for the future fluctuating energy source; energy system in the north-eastern part of North America. o a strategy on how to harvest industrial benefits of large-scale wind power; November 19, 2008 and NB Government Announces the Release of Strategic Environmental Assessment Report o a strategy for incentives to invest in wind power, including a strategy for on Tidal Energy in Bay of Fundy Coastal local involvement and ownership. A Waters key question concerns what role the The Government of New Brunswick has provincial government, the utilities and announced the release of the Strategic electricity consumers of New Environmental Assessment (“SEA”) of In-Stream Brunswick should play with respect to Tidal Energy Generation Development in the stimulating investments in new wind province’s Bay of Fundy Coastal Waters, power capacity. Mechanisms whereby compiled and submitted by Barry Jones on electricity consumers and wind power behalf of the Marine Energy Working Group of developers share the risks and the Bay of Fundy Ecosystem Partnership benefits of the large investments (“BoFEP”). The SEA contains 19 required is recommended. recommendations to be considered if the province moves forward with developing in- • Revising existing market design and stream tidal energy in the Bay of Fundy, and the restructuring the market to allow for a higher recommendations are based on stakeholder level of competition and more efficient feedback and preliminary research. utilization of capacity within New Brunswick and across interconnectors. According to the announcement, the government has been looking into opportunities • Improving the integration of the electricity associated with in-stream tidal energy for a markets in the Maritimes and the neighbouring number of years. The government adds that it is systems of New England and Québec in order working on a formal response to the report's 19 to maximise the value of wind power in the recommendations; that the response will be a region and to provide balancing power. The collaborative effort by the departments of long term goal should be an efficient market Energy, Environment and Natural Resources, coupling between the markets or even a and will be released in the coming weeks. common electricity market. Background • Continuing the restructuring process for the electricity sector in New Brunswick, including In 2007, the New Brunswick and Nova Scotia the evolvement of a strong system operator governments announced that they would be able to integrate wind power into the system completing SEAs in relation to ocean energy in and engagement in comprehensive long-term the Bay of Fundy, with a specific focus on in- system planning together with research, stream tidal applications. The assessments development and demonstration activities. As included a background report, completed by part of this process, consideration should be Jacques Whitford in January 2008, which was given to establish a transmission system co-funded by the N.S. Department of Energy operator with ownership of the transmission and the Offshore Energy Environmental grid and interconnectors. Research Association on behalf of the Province of Nova Scotia. Stakeholder consultation was • Strengthening the efforts in developing energy also a component of the SEA, and a series of cooperation with neighbouring provinces and open house events was held in seven - 36 - Cerise, Volume 7, Issue 11-November 2008 communities along the New Brunswick side of $1.9 million, bringing the total to $16.7 million the bay in April 2008. per year); General • $2.5 million per year more for the low-income November 21, 2008 energy efficiency retrofit program shared by Social Development and Efficiency NB (in NB Power Signs Memorandum of addition to previous increases of $2.9 million, Understanding with Efficiency NB bringing the total to $9.7 million per year); New Brunswick Power (“NB Power”) has signed • $1 million in new funding for Efficiency NB, a Memorandum of Understanding (“MOU”) with which will create a new, $500 grant to Efficiency NB to further align energy efficiency encourage New Brunswickers to switch to an and conservation efforts. energy efficient heating system (in addition to According to the announcement, Efficiency NB previous increases of $9.8 million, bringing the was established to develop and deliver energy total to $12.6 million per year); and efficiency and conservation programs and • $500,000 for the Salvation Army's new Warm initiatives for all energy sources and to act as Hearts, Warm Homes program. the primary organization for the promotion of these programs in New Brunswick. NB Power is November 5, 2008 the largest provider of electricity in the province, New Brunswick System Operator Releases and as such, educates consumers on the Annual Report for 2007-2008 efficient use of its product to help them manage their electricity costs and protect the The New Brunswick System Operator (“NBSO”) environment. NB Power says that it will work has released its 2007/08 Annual Report. The with Efficiency NB to help customers get more NBSO notes that the need to reduce for their electricity dollar by helping them greenhouse gas (“GHG”) emissions and the maximize ways to conserve electricity. increased cost of fossil fuels have heightened the urgency of developing alternate sources of November 6, 2008 electricity which reduce harmful emissions and New Brunswick Government to Invest mitigate the impacts of rising fuel costs. Additional $6.3 Million into Energy Efficiency The NBSO suggests that New Brunswick is in a and Other Programs position to meet this challenge, advises the New Brunswick Government has announced province’s wind resources are estimated to be that it will invest an additional $6.3 million per equivalent to more than 43,000 MW of year in energy efficiency and other programs to electricity. The System Operator states that, with assist consumers in reducing and offsetting their currently available technology, up to 4,500 MW energy costs. According to the government, this of this energy is commercially viable, and that is over and above $25 million in previous figure is expected to grow as technology spending increases in this area, and $41 million improves. The NBSO says that combining this in energy tax reductions, which bring the total capability with the second nuclear reactor value of government's energy efficiency and proposed for Point Lepreau, New Brunswick has relief programs to $99.3 million per year, up from the potential to deliver over 5,500 MW of clean $27 million when the government took office. energy into the region’s electricity system which is more than enough to meet the province’s The new investments are: needs. The System Operator suggests that, at • $2.3 million per year more for Social this scale, wind and nuclear represent an Development's programs that provide benefits unprecedented opportunity for New Brunswick, to social assistance clients, residents of the Maritimes and New England to improve subsidized housing, and New Brunswickers environmental performance, secure their energy facing a winter hardship or emergency future and save billions of dollars in fuel costs situation (in addition to previous increases of under a “win-win” scenario which delivers benefits to all stakeholders. - 37 - Cerise, Volume 7, Issue 11-November 2008 The NBSO cautions, however, that new Generating Capacity expertise and large investments are required to pursue these opportunities and says that it is Source MW important to create “renewable – friendly” market rules and evolve the bulk electricity system to Oil 1251 attract the necessary capital and know-how. The System Operator suggests that it is encouraging Coal 514 that private sector firms are now investing in feasibility studies for expanded nuclear Natural Gas 353 generation and are already developing 400 MW Biomass 39 of wind generation to fulfill the province’s current Renewable Portfolio Standard. Hydro 893 The NBSO provides the following data with respect to the electricity system in New Nuclear 635 Brunswick: TOTAL 4226 Number of Interconnections 6 The System Operator explains that it is one of Interconnection Import 2,164 MW 17 Reliability Coordinators in North America. As Capacity Reliability Coordinator for the Maritimes Area, the NBSO is the authority responsible for the Interconnection Export 2,372 MW operation of the Bulk Power System in New Capacity Brunswick, Nova Scotia, Prince Edward Island, and a portion of north-eastern Maine. The NBSO Scheduled Energy Receipts 21,197 GWh is the Balancing Authority for New Brunswick, Prince Edward Island, and Northern Maine and Scheduled Transmission 511 GWh the transmission provider for New Brunswick. Losses The System Operator provides load following and regulation service to the system in order to Scheduled Energy Deliveries 20,686 GWh supply in-province customer load while maintaining scheduled flows on interconnections Value of Energy Transacted $1.2 Billion within established limits. These limits are set out (estimate based on the average in interconnection agreements with neighbouring Final Hourly Marginal Cost for system operators. the Year) NEWFOUNDLAND Transmission Lines 6,818 km Electricity Peak Demand (January 22, 3,078 MW November 12, 2008 2008) Nfld PUB Approves 2009 Capital Budget Application Filed by Newfoundland Power

The Newfoundland and Labrador Board of Commissioners of Public Utilities (“Nfld PUB” or “the Board”) has issued Board Order No. P. U. 27(2008) in which it approves the 2009 Capital

Budget Application filed by Newfoundland Power Inc. on July 11, 2008. In its application, Newfoundland Power requested that the Board make an Order: (i) approving its 2009 Capital Budget of - 38 - Cerise, Volume 7, Issue 11-November 2008 $61,571,000; NORTHWEST TERRITORIES (ii) approving 2009 leases in the amount of Electricity $11,000 per year; and November 25, 2008 (iii) fixing and determining its average rate NWT PUB Approves Application from base for 2007 in the amount of Northland Utilities (Yellowknife) Limited for $793,703,000. Approval for Changes to Existing Rider C In its Order, Nfld PUB ruled as follows: Further to the issuance by the Public Utilities • It approved Newfoundland Power’s capital Board of the Northwest Territories (“NWT PUB” purchases and construction projects in excess or “the Board”) of Decision 27-2008, dated of $50,000, as set out in Schedule A to this October 31, 2008, in which the Board approved Order. a net increase of $0.0125 per kilowatt hour (“kW.h”) to Northwest Territories Power • It approved the 2009 Capital Budget for Corporation’s (“NTPC”) purchase power rate, improvements and additions to Newfoundland the NWT PUB has issued Decision 30-2008 in Power’s property in an amount of which it approves a November 7, 2008, $61,571,000. application from Northland Utilities (Yellowknife) • It approved the 2009 leases of $11,000 per Limited (“Northland”) for an order to change the year, as set out in Schedule B to its Order. name of the existing NTPC Shortfall Rider, Rider C, which is intended to flow-through changes to • It fixed and determined the average rate base Northland’s purchase power costs resulting from for the year ending December 31, 2007 at changes to the power supply costs, adjusted for $793,703,000. line losses, to Rider F and to set Rider F, to • It ordered Newfoundland Power, unless $0.05010 / kW.h effective December 1, 2008, otherwise directed by the Board, to file an and set Rider F to $0.04951 / kW.h effective annual report to the Board on its 2009 capital June 1, 2009 upon collection of the forecast expenditures by March 1, 2010. under-collection. The Board adds that any further reconciliation of the Rider F balance will • It ordered Newfoundland Power, unless be done in a future application. otherwise directed by the Board, to provide, in conjunction with the 2010 Capital Budget The NWT PUB reports that Northland stated that Application, a status report on the 2009 capital it is forecasting a net under-collection balance of budget expenditures showing for each project: $49,122 for November 30, 2008, which is comprised of the actual over-collection balance (i) the approved budget for 2009; at October 31, 2008 of $133,627 and a forecast (ii) the expenditures prior to 2009; under-collection of $182,749 due to the 1-month (iii) the 2009 expenditures to the date of the lag in implementing this change. Northland application; proposed to collect this balance over 6-months from December 1, 2008 to May 31, 2009 by (iv) the remaining projected expenditures for increasing Rider F by $0.00059 / kW.h. 2009; November 24, 2008 (v) the variance between the projected total expenditures and the approved budget; NWT PUB Approves Application from and Northland Utilities (NWT) Limited for Approval for Changes to NTPC Shortfall (vi) an explanation of the variance. Rider, Rider F Further to the issuance by the Public Utilities Board of the Northwest Territories (“NWT PUB” or “the Board”) of Decision 27-2008, dated October 31, 2008, in which the Board approved a net increase of $0.010 per kilowatt hour - 39 - Cerise, Volume 7, Issue 11-November 2008 (“kW.h”) to Northwest Territories Power Northland Utilities (Yellowknife) Limited Corporation’s (“NTPC”) purchase power rate, (“Northland” or “NUL”) of its Phase 2 General the NWT PUB has issued Decision 31-2008 in Rate Application (“GRA”) for the 2008/2010 test which it approves a November 7, 2008, period to determine appropriate rates for NUL’s application from Northland Utilities (NWT) customers, the Public Utilities Board of the Limited (“Northland”) for an order to set the Northwest Territories (“NWT PUB” or “the NTPC Shortfall Rider, Rider F, which is intended Board”) has issued Decision 28-2008 in which it to flow-through changes to Northland’s purchase approves the application as modified by the power costs resulting from changes to the power settlement that NUL reached with the Town of supply costs, adjusted for line losses, to Hay River and the Hamlet of Fort Providence. $0.03200 / kW.h effective December 1, 2008, The Board directed NUL to refile the GRA to and set Rider F to $0.03981 / kW.h effective reflect the amendments with 30 days of its June 1, 2009 upon collection of the forecast Decision. under-collection. The Board adds that any November 4, 2008 further reconciliation of the Rider F balance will be done in a future application. Northwest Territories Board Approved Updated Refiling of Northwest Territories The NWT PUB reports that Northland stated that Power Corporation Phase 2 Application it is forecasting a net over-collection balance of $118,657 for November 30, 2008, which is Following the October 30, 2008 refiling by comprised of the actual over-collection balance Northwest Territories Power Corporation at October 31, 2008 of $117,095 and a forecast (“NTPC”) of its Phase 2 Application in response additional over-collection of $1,562 due to the 1- to directives set out in Decision 26-2008, the month lag in implementing this change. Northwest Territories Public Utilities Board Northland proposed to collect this balance over (“NWT PUB” or “the Board”) has released 6-months from December 1, 2008 to May 31, Decision 27-2008 in which it accepts updated 2009 by reducing Rider F by $0.00691/ kW.h. rate schedules and supporting material filed on October 31, 2008 by NTPC at the request of the November 21, 2008 Board. The NWT PUB advises that it asked for Northwest Territories Board Issues Decision the updated materials because, although the With Respect to Phase II of Northland method of allocating the deficiency in the initial Utilities (Yellowknife) Ltd. 2008/2010 GRA refiling was consistent with the Phase 2 In response to an April 2, 2008, filing by application, the Board found it to be inconsistent Northland Utilities (Yellowknife) Limited with the principle of spreading the burden of the (“Northland” or “NUL”) of its Phase 2 General shortfall rider deficiency equally across all Rate Application (“GRA”) for the 2008/2010 test communities and customers. period to determine appropriate rates for NUL’s The Board notes that, as part of the October 31, customers, the Public Utilities Board of the 2008 filing, NTPC provided updated fuel riders Northwest Territories (“NWT PUB” or “the reflecting updated fuel prices in response to Board”) has issued Decision 28-2008 in which it concerns expressed by the Hydro Communities approves the application as modified by the (“HC”). settlement that NUL reached with the City of The NWT PUB reported that NTPC noted the Yellowknife. The Board directed NUL to refile diesel fuel expenses respecting the Bluefish the GRA to reflect the amendments with 30 days Headgate project were capitalized in order to of its Decision. comply with Directives 5 and 6 from Decision November 21, 2008 26- 2008. NTPC considered this treatment to be inconsistent with directive 8 from Decision 17- Northwest Territories Board Issues Decision 2007 where the Board accepted the current With Respect to Phase II of Northland method of expensing diesel fuel expenses Utilities (NWT) Ltd. 2008/2010 GRA pending further review. However, NTPC In response to an April 2, 2008, filing by accepted the capitalization of diesel fuel - 40 - Cerise, Volume 7, Issue 11-November 2008 expenses as a one time adjustment pending a reduced 17-month collection period from thorough review of the mechanics of the November 1, 2008 to March 31, 2010 as Snare/Yellowknife Water Stabilization Fund at well as an update to the applicable the time of the next Phase 1 GRA. NTPC stated interest rate to October 27th, 2008. The pending this review, it will continue to charge NTPC is to continue to apply the 15% diesel generation to the water stabilization fund rate cap on the combined impacts of consistent with Directive 8 from Decision 17- adjustments to the base rates and the 2007. The NWT PUB considers the NTPC shortfall riders. proposal to continue to charge diesel generation 2. While maintaining the 15% cap on associated with other capital projects to the adjustments to base rates and the water stabilization fund consistent with Directive shortfall riders, the Board directs NTPC 8 from Decision 17-2007, to be acceptable, to apply a 20% total cap to the pending full review of the mechanics of the combined impact of adjustments to base Snare/Yellowknife Water Stabilization Fund. The rates, shortfall riders and stabilization Board accepts NTPC’s proposed capitalization fund riders. of fuel expenses respecting the Bluefish Headgate project in response to Directives 5 3. The Board directs the NTPC to design and 6 from Decision 26-2008. the stabilization fund riders to bring the fuel fund balances to $0 and the Snare November 3, 2008 water fund balance to its trigger amount Northwest Territories Board Releases by March 31, 2010. Decision Concerning Northwest Territories 4. The Board directs the NTPC to use an Power Corporation Phase 1 GRA for Period updated oil price and interest rate from April 1, 2006 to March 31, 2008 October 27, 2008 when designing the In response to a Phase 1 General Rate stabilization fund rate riders for Application (“GRA”) for the fiscal years April 1, implementation on November 1, 2008. 2006 to March 31, 2007 and April 1, 2007 to 5. The Board considers that the diesel fuel March 31, 2008 filed by the Northwest costs associated with the Bluefish Territories Power Corporation (“NTPC”) on generating station headgate project November 24, 2006, the Northwest Territories should be capitalized. The NTPC is Public Utilities Board (“NWT PUB” or “the directed to adjust the Snare/Yellowknife Board”) has released Decision 26-2008 in which Fuel Stabilization Fund balance and it sets out its findings and issues a number of rider accordingly. directives. In its Decision, the Board directs NTPC to implement the rate changes, as 6. The NTPC is directed to adjust the approved and directed in the Decision, on Snare/Yellowknife Water Stabilization November 1, 2008. The NWT PUB further Fund balance and rider to reflect directs NTPC to provide the Board and other capitalization of the diesel fuel costs parties by Oct. 30, 2008 with a working model, in associated with the Bluefish generating Excel format, of all Phase 2 GRA tables and station headgate project. schedules relating to the rate changes approved and directed by this Decision. The NTPC is also to provide the Board and other parties with an updated set of rate schedules. Among the directives set down by the NWT PUB are the following: 1. The Board directs the NTPC to apply the shortfall riders as calculated in Schedule B-3 of the Application subject to an adjustment to account for the - 41 - Cerise, Volume 7, Issue 11-November 2008 7. The Board directs the NTPC, in its next PUB directs NUL to provide to the Board and Phase 2 GRA, to consider the following interested parties a Phase 1 refiling reflecting table of revenue-to-cost ratios, in the findings and directions in this Decision within conjunction with other rate design 30 days of the release of the Board’s Phase 2 criteria, in setting the base rates. Decision. The NWT PUB further directs NUL to provide as part of the Phase 1 refiling a working model, in Excel format, of all GRA schedules Community Present Test Test Test relating to the establishment of rate base, return, /Customer Year 1 Year 2 Year 3 revenue requirement, revenues and revenue deficiencies and all relevant supporting schedules. Fort 51.7% 70% min 90% min 95% min Resolution Among the directions set down by the NWT PUB

in the Decision are the following: 1. The Board directs NUL to reflect the Jean Marie 69.2% 80% min 90% min 95% min 2007 actual plant closing balances in River the plant opening balances for 2008 in its Phase 1 refiling. Nahanni 75.2% 85% min 90% min 95% min Butte 2. The Board determines a common equity

ratio of 44% in conjunction with a return on equity of 9.1% for each of the years Fort 77.9% 85% min 90% min 95% min 2008, 2009 and 2010. NUL is directed to Simpson reflect the above determinations respecting capital structure and rate of return on common equity in its Phase I Wrigley 80.6% 90% min 95% min 95% min refiling Application. 3. In light of the Board’s determination on capital structure, the NWT PUB Dettah 85.9% 95% min 95% min 95% min considers NUL may need to raise new debt within the test period. The Board considers that it would be appropriate NUL(NWT) 130.2% 120% 110% 105% max max max for NUL to include any new debt at the cost rate for new debt approved for NUY in Decision 24-2008. NUL is accordingly directed to reflect this determination in its Phase I refiling application. The Board directs that in all other instances the results should be within the 95% to 105% range. 4. The Board directs that, in its Phase 1 refiling, NUL is to apply a 12% November 3, 2008 combined loss and station service cap Northwest Territories Board Issues Decision as a percentage of generation. With Respect to Northland Utilities Limited 5. The Board directs that, in its Phase 1 2008/2010 GRA refiling, NUL is to use the following In response to a General Rate Application inflation amounts for employees: (“GRA”) for the 2008/2010 test period filed on February 8, 2008 by Northland Utilities (NWT) • In-scope 11% in 2008, 5.25% in 2009 Limited (“Northland”, “NUL”), the Northwest and 5.25% in 2010 Territories Public Utilities Board (“NWT PUB” or • Out-of-Scope 10% in 2008, 5.25% in “the Board”) has released Decision 25-2008 in 2009 and 5.25% in 2010 which it sets out its findings and issues a 6. The Board directs that, in its Phase 1 number of directions. In its Decision, the NWT - 42 - Cerise, Volume 7, Issue 11-November 2008 refiling, NUL is to apply an inflation rate 2007, for the purposes of determining of 3.2% to operating materials and the lighting sales forecast for all supplies plus the non-affiliate and non- communities. NUL should reflect these contractor costs. directions in its refiling Application. 7. The Board directs NUL to limit the 12. The Board agrees with Fort Providence increase in the Oracle Financial that under the present rules, namely the expense to 3.2% for 2010 and reflect cash basis for pension, there is no need this finding in the refiling application. to hold in no cost capital the $168,000 8. NUL is directed to escalate the base previously collected from customers to billing charge using an inflation rate of fund pension and OPEB. NUL is, 5% over the 5 year period so that the therefore, directed to propose a method average of the rate over that period of returning the $168,000 to customers amounts to $1.72 and, to reflect this in its refiling application either through a change in the refiling of the application. reduction in the pension expense or, by way of an outright refund. 9. The Board directs that, in its Phase 1 refiling, NUL is to use a forecast cost for 13. The Board directs that, in its next Phase the current Phase 1 and 2 GRA that is 1 GRA, NUL is to compare the overall the greater of the following 2 options: fuel efficiency of each plant to the manufacturer’s rated engine efficiency (i) the $433,000 cost of the previous for each engine within that plant. If there GRA; or are significant discrepancies between (ii) an updated forecast cost of the the overall plant efficiency and the current Phase 1 and 2 GRA with individual rated engine efficiencies, NUL rates for NUL’s legal counsel is to provide an explanation and capped at $350/hr and the cost of potential solutions to improve plant capital expert capped at $270/hour. efficiency. If NUL proceeds with Option 2, 14. The Board directs that, in its next Phase then it will be expected to provide 1 GRA, NUL is to calculate forecast fuel supporting evidence and efficiencies using three years of data calculations. weighted 3 for the highest efficiency 10. NUL is directed to adjust its residential year, 2 for the middle efficiency year sales forecast for the test period to and 1 for the lowest efficiency year. reflect the three year average 15. The Board directs that, in its next Phase normalized Usage Per Customer 1 GRA, NUL is to give due weight to (“UPC”) from 2005 to 2007, for all earlier test year forecast fuel efficiencies communities, for purposes of the refiling when calculating the later test year application. For the community of Dory forecast fuel efficiencies. Point, because of the extremely low correlation between UPC and 16. The Board directs that, in its next Phase temperature, NUL is directed to use the 1 GRA, NUL is to provide separate 3-year average UPC including 2007 for analysis and discussions for losses and purposes of the refiling application. station service. 11. For the purposes of determining the 17. The Board directs that, in the next commercial sales forecast for all Phase 1 GRA, NUL is to include an communities, NUL is directed to use the examination of the pros and cons of three year average commercial UPC separating losses into its two including 2007. To be consistent, NUL is components (electrical losses and non- also directed to use the 3-year average electrical losses) which would allow the lighting usage per type of light including electrical losses to be forecast using the same method as for fuel efficiencies - 43 - Cerise, Volume 7, Issue 11-November 2008 while non-electrical losses could still be transmission line study as well as for the forecast using the 5-year rolling average project, with different levels of method. Government and report back to the Board by December 31, 2008. The 18. The Board directs that, in the next information should also be provided to Phase 1 GRA, NUL is to calculate interested parties. As part of the station service using the same December 31, 2008 report, NUL should procedure used for fuel efficiencies. also come forward with a proposal on Forecast station service is to be whether to proceed with the study of the calculated using 3 years of actual data transmission line option or any other with a weighting of “3” given to the option as a viable alternative to diesel lowest station service year, a weighting generation. The Board will make a of “2” given to the middle station service determination on the matter following year and a weighting of “1” given to the receipt of this information. highest station service year. 19. Consistent with its directions respecting November 3, 2008 fuel efficiencies, the Board directs that, North West Territories Board Issues Decision in its next Phase 1 GRA, NUL is to give for Northland Utilities (Yellowknife) Limited due weight to earlier test year station 2008/2010 GRA service forecasts when calculating the In response to a General Rate Application later test year station service forecasts. (“GRA”) for the 2008/2010 test period submitted 20. The Board directs that, within 90 days of on February 8, 2008, Northland Utilities the conclusion of the Phase 1 and (Yellowknife) Limited (“Northland” or “NUL”), the Phase 2 GRAs, NUL will file a cost claim Northwest Territories Public Utilities Board with the Board covering both Phase 1 (“NWT PUB” or “the Board”) has issued Decision and 2. 24-2008 in which it makes a number of findings and issues several directions. The NWT PUB 21. The Board directs NUL to include all directs NUL to provide to the Board and changes announced in any Federal interested parties a Phase 1 refiling reflecting and/or Territorial Budgets (i.e. related to the findings and directions in the Decision within corporate income tax and CCA rates) 30 days of the release of the Board’s Phase 2 impacting income tax expense in the Decision. The NWT PUB further requires NUL to income tax deferral account. provide as part of the Phase 1 refiling a working 22. The Board considers that a formal model, in Excel format, of all GRA schedules process as has been established before relating to the establishment of rate base, return, the Alberta Utilities Commission (“AUC”) revenue requirement, revenues and revenue should not be required for NUL at this deficiencies and all relevant supporting time. However, given the significance of schedules. the changes contemplated under IFRS, Among the directions set down by the NWT PUB the Board considers it important that it are the following: be kept fully informed of any material changes in NUL’s financial reporting as 1. The Board directs NUL to reflect the convergence towards IFRS proceeds. 2007 actual plant closing balances in The Board directs NUL to provide such the plant opening balances for 2008 in information to the Board and interveners its Phase 1 refiling. on an as needed basis consistent with 2. The Board determines a common equity the Board’s desire to be kept fully ratio of 43.5% in conjunction with a informed on developments respecting return on equity of 9.1% for each of the this matter. years 2008, 2009 and 2010. NUL is 23. The Board directs NUL to investigate directed to reflect the above the availability of funding for the determinations respecting capital - 44 - Cerise, Volume 7, Issue 11-November 2008 structure and rate of return on common deductions for income tax purposes for equity in its Phase I refiling Application. each of the test years, as part of the Phase I refiling. 3. The Board directs that, in its Phase 1 refiling, NUL is to incorporate debt rates 10. The Board directs NUL to adjust its of 5.51% for 2008, 6.32% for 2009 and residential sales forecast to reflect UPC 7.05% for 2010 into its cost of debt of 8183 kWh in 2008, 8118 kWh in 2009 calculation. and 8052 kWh in 2010 in its refiling Application. 4. The Board directs that, in its Phase 1 refiling, NUL is to use the following 11. The Board notes that by the end of inflation amounts for employees: 2010, NUL intends to have completed the AMR/meter conversion project. • In-scope 11% in 2008, 5.25% in 2009 Assuming that this upgrade in the and 5.25% in 2010 metering system would enable the • Out-of-Scope 10% in 2008, 5.25% in separation of non-technical losses from 2009 and 5.25% in 2010. the system loss calculation, the Board 5. The Board directs that, in its Phase 1 directs that, in the next Phase 1 GRA, refiling, NUL is to apply an inflation rate NUL is to include an examination of the of 3.2% to operating materials and pros and cons of separating losses into supplies. its two components (technical losses and non-technical losses) and, if 6. The Board directs NUL to limit the determined desirable to do so, to increase in the Oracle Financial calculate and include these two expense to 3.2% for 2010 and reflect components in its calculations for the this finding in the refiling application. next GRA. 7. NUL is directed to escalate the base 12. The Board directs that, within 90 days of billing charge using a rate of 5% over the conclusion of the Phase 1 and the 5 year period so that the average of Phase 2 GRAs, NUL will file a cost claim the rate over that period amounts to with the Board covering both Phase 1 $1.72 and, to reflect this change in the and 2. refiling of the application. 13. The Board directs NUL to include all 8. The Board directs that, in its Phase 1 changes announced in any Federal refiling, NUL is to use a forecast cost for and/or Territorial Budgets (i.e. related to the current Phase 1 and 2 GRA that is corporate income tax and CCA rates) the greater of the following 2 options: impacting income tax expense in the • the $238,000 cost of the previous income tax deferral account. GRA; or 14. The Board directs that NUL set up a • an updated forecast cost of the deferral account for Rainbow-type current Phase 1 and 2 GRA with rates deductions for the test period. for NUL’s legal counsel capped at 15. The Board directs NUL, in future $350/hr and the cost of capital expert proceedings, to provide explanations for capped at $270/hour. If NUL proceeds material variances between forecast and with Option 2, then it will be expected actual capitalized ES&G levels. to provide supporting evidence and 16. The Board considers that a formal calculations. process as has been established before 9. The Board directs NUL to capitalize pole the Alberta Utilities Commission (“AUC” test and treat expenditures for or “the Commission”) should not be accounting purposes and claim these required for NUL at this time. However, expenditures as Rainbow-Type given the significance of the changes

- 45 - Cerise, Volume 7, Issue 11-November 2008 contemplated under International behalf of its Electric Utility (the "Utility"), seeking Financial Reporting Standards (“IFRS”), approval of amendments to its Schedules of the Board considers it important that it Rates and Regulations. In its Decision, the be kept fully informed of any material Board approved: changes in NUL’s financial reporting as • the addition of a Domestic Service Time-of- convergence towards IFRS proceeds. Day Rate; The NWT PUB directs NUL to provide such information to the Board and • new charges as described in Regulation 6.10, interveners on an as needed basis 6.12, 6.13 and 6.14 pertaining to an increase consistent with the Board’s desire to be in Wiring Inspection fees; kept fully informed on developments • the charge under Regulation 6.11 to be respecting this matter. $107.00. and NOVA SCOTIA • changes in wording for Regulation 2.9, 2.10 Natural Gas and 2.11 pertaining to Service Changes. November 4, 2008 The Board notes that it did not receive any comments in favour of, or opposed to, the NEB and CNSOPB Agree to Partnership application and that no members of the public National Energy Board (“NEB”) and the Canada- spoke at the related hearing. Nova Scotia Offshore Petroleum Board General (“CNSOPB”) have announced the signing of a memorandum of understanding (“MOU”) which November 10, 2008 they say makes the regulation of pipelines more Emera Appoints Donald Pether to its Board efficient and effective. The announcement of Directors suggests that the MOU will ensure that the two Emera Inc. (“Emera”) has announced the regulators are able to continue the existing appointment of Don Pether, former Chair of the partnership in order to help them efficiently Board (and CEO) of Dofasco Inc., to its Board of implement flexible, goal-oriented regulation, Directors. foster innovation and make sound decisions in the public interest. Emera advises that, prior to his position as Chair, Mr. Pether, who joined Dofasco Inc. in The announcement advises that the 1970, was the President and Chief Executive construction, operation, decommissioning, Officer. The announcement reports that Mr. abandonment and removal of offshore pipelines Pether is currently Chair of the Board of the falls under the jurisdiction of both the NEB and Hamilton Health Sciences Foundation, is Vice- CNSOPB. The announcement says that the new Chair of the Board of Governors for McMaster agreement reduces regulatory overlap by setting University, and is Chair of the Board of the clear criteria for areas where cooperation can McMaster Innovation Park. Emera adds that Mr. occur, such as: data sharing, emergency Pether sits on the Council of Governors for the management, monitoring and enforcement, and Art Gallery of Hamilton and the Board of staff exchanges. Directors of Samuel Manu-Tech Inc. and is a Electricity former trustee of the Fording Canadian Coal November 4, 2008 Trust Board. Nova Scotia Board Approves Rate According to the announcement, Mr. Pether Application filed by Town of Lunenburg on holds a BSc. in Metallurgical Engineering from Behalf of its Electric Utility the University of Alberta and an Honorary Doctorate of Laws from McMaster University. The Nova Scotia Utility and Review Board (“NSUARB” or “the Board”) has issued Decision 2008 NSUARB 138 in which it approves an application from the Town of Lunenburg, filed on - 46 - Cerise, Volume 7, Issue 11-November 2008 ONTARIO Decision and Order added that, as a result, approval of that part of the Application would not Electricity affect the rates payable by the Applicants’ November 26, 2008 ratepayers at this time. OEB Issues Decision and Order for Joint The OEB said that the Applicants also requested Application by Chatham-Kent Hydro and approval of smart meter disposition riders of Middlesex Power Distribution to Recover the $0.78 per month for CKH and $0.77 per month Costs of Smart Meters for MPDC to take effect May 1, 2009 for the Under Board File No. EB-2008-0115, the 2009 rate year in order to recover the revenue Ontario Energy Board (“OEB” or “the Board”) requirement, for the 2009 rate year, related to has issued its Decision and Order on a joint costs for smart meters installed from May 1 to application by Chatham-Kent Hydro Inc. (“CKH”) December 31, 2007. The Board noted that, if and Middlesex Power Distribution Corp. approved, the May 1, 2009 disposition riders (“MPDC”) (“the Applicants”) for adjusted would increase the Applicants’ respective distribution rates to recover the costs of smart monthly charges for metered ratepayers by meters installed from May 1 to December 31, $0.23 in the case of CKH and by $0.68 in the 2007. The OEB advises that the new rates will case of MPDC. take effect November 1, 2008, but there is no In the interest of regulatory efficiency, the Board immediate rate impact for ratepayers served by said that it saw merit in considering the these distributors. Applicants’ request for approval of the In its Decision, the Board ruled in favour of a disposition riders to come into effect on May 1, request from the Applicants that certain 2009 and it approved the May 1, 2009 information be treated on a confidential basis. disposition riders as proposed by the Applicants, effective from May 1, 2009 until such time as the The OEB said that it was satisfied that the costs rates of the Applicants are rebased. that the Applicants sought to recover for smart meters installed from May 1, 2007 to December November 26, 2008 31, 2007 do not relate to functionality which OEB Issues 2008 Electricity Distribution Rate exceeds the minimum functionality adopted in O. Order for Erie Thames Powerlines Reg. 425/06 and it found that the costs were Corporation prudently incurred. The Board went on to approve, effective November 1, 2008, the Under Board File No. EB-2007-0928, and further disposition riders and the updated funding riders to a Decision and Order issued on October 27, proposed by the Applicants. 2008, the Ontario Energy Board (“OEB” or “the Board”) has issued a Rate Order for a 2008 The OEB also approved the accounting changes electricity distribution rate application for Erie as proposed by the Applicants to recognize the Thames Powerlines Corporation (“Erie approved smart meter costs in rate base and to Thames”). The OEB advises that the new partially dispose of the related balances in the distribution rates are effective May 1, 2008, but established deferral and variance accounts. will not be implemented until December 1, 2008. The Decision and Order notes that CKH’s According to the Board, as a result of this current Board-approved funding adder and Decision, the delivery portion of the bill disposition rider total to $2.42 and that the associated with the cost to distribute electricity proposed new funding adder and disposition will decrease by approximately 19% for Erie rider which the OEB was approving also sum to Thames’ residential customers. The total $2.42. Similarly, the Decision and Order said monthly bill for residential consumers paying the that for MPDC, the Board’s approval of the regulated price of electricity will decrease by proposed new funding adder and disposition approximately 7% from a bill issued between rider would not change the total increment on November 1 and November 30, 2008. the monthly service charge of metered customers, which remains at $2.58. The - 47 - Cerise, Volume 7, Issue 11-November 2008 November 21, 2008 comments received in its finalization of the Ontario electricity distributor efficiency ranking to OEB Announces Further Consultation on set the membership of the three distributor Stretch Factor Rankings for 3rd Generation groupings for stretch factor assignments for the Incentive Regulation for Electricity 2009 rate year. Distributors The OEB directs that written comments must be The Ontario Energy Board (“OEB” or “the filed by December 15, 2008. The Board’s letter Board”) has posted to its website a letter to all includes detailed filing instructions and participants in Consultation EB-2007-0673 and information on Cost Awards in respect of this all licensed electricity distributors in which it matter. advises of a further consultation on stretch factor rankings for 3rd generation incentive regulation November 19, 2008 (“IR”) for electricity distributors. IESO Posts Its Submissions to the OEB With The OEB notes that on September 17, 2008, it Respect to Kruger Energy Section 81 issued its “Supplemental Report of the Board on Proposal 3rd Generation Incentive Regulation for Further to a CERISE What’s New Alert of Ontario’s Electricity Distributors”, in which it November 29, 2007, the Ontario Independent stated its intention to undertake further work on Electricity System Operator (“IESO”) has posted the model it will use to assign stretch factors to to its website its reply submissions under distributors and to consult with stakeholders to Ontario Energy Board (“OEB” or “the Board”) identify whether it can improve the grouping File No. 2007-0691 with respect to an approach and further reduce the potential for application by Kruger Energy Inc. (“KEI”), misclassification in the two OM&A benchmarking Section 81 Proposal. evaluations. The Board advises that the purpose of this latest letter is to initiate that consultation. The IESO’s reply submission addresses the following issues: Further to its July 22, 2008 posting of the results of OM&A benchmarking evaluations prepared by • Issue 1: Whether the proposed substation the Pacific Economics Group (“PEG”) to divide could limit future access by other persons to electricity distributors into three efficiency the 230 kV lines between Chatham and “cohorts” supporting 3rd generation IR, the Lauzon Transformer Stations. Board advises that it has now posted a • Issue 2: Whether the proposed substation sensitivity analysis, prepared by PEG regarding could impose limits on the IESO operation of the efficiency cohorts, which address three the lines which could consequently restrict distributor characteristics. The OEB adds that an other persons. overview of its staff’s work in support of PEG’s analysis and of its staff’s proposal in relation to • Issue 3: The future operation of the the treatment of low voltage charges is set out in transformer station; in particular, what the an attachment to the Board’s letter. process would be for selecting generation projects for connection to the proposed The OEB is inviting participants to provide station. written comments on its staff’s overview and proposal as well as on the results of PEG’s • Issue 4: The future operation of the proposed sensitivity analysis. The Board says that, substation; in particular, whether the IESO specifically, it would be assisted by comments and Hydro One connection processes could on the following: be adversely affected. • What changes, if any, to the model arising In conclusion, the IESO states that it is from the attached sensitivity analysis should supportive of new or enhanced approaches for the OEB consider to further reduce the developing needed transmission facilities in potential for misclassification? Ontario; however, it strongly believes that such approaches should be consistent with and The Board says that it would consider written continue to promote fair and non-discriminatory - 48 - Cerise, Volume 7, Issue 11-November 2008 access to the IESO-controlled grid. The issue of year (1,000 kWh per month), and who chooses fair and non-discriminatory access by others to to leave the RPP, would receive a one-time the two transmission circuits should be credit of $19.11 while for a consumer who uses paramount to the OEB in determining whether less electricity, such as 750 kWh per month, the the impact of KEI’s proposal will adversely one-time credit would be $14.34. impact the development and maintenance of the The OEB advises that the updated factor was competitive electricity markets. As calculated using the positive net balance in the demonstrated, given the stated purpose and variance account (as of October 31st) of about $ function of the proposed transformer station, the 101.5 million, which is about $14.3 million lower IESO does not believe that KEI meets the than the positive balance at the end of requirements for an exemption from the need to September. The Board further advises that the obtain a transmitter license and in providing fair net variance balance incorporates estimates of and non-discriminatory access to the proposed the rebate from Ontario Power Generation transformer station. (“OPG”) - the difference between the revenue In addition, the IESO submits that, if approval is limit for some OPG generation facilities and the given by the Board, this should not be viewed as price they would have received in the wholesale an automatic allocation of any of the available spot market. transmission capacity on circuits C23Z and The OEB says that the principal contributing C24Z or grandfathering of any capacity rights on factor for the increase in the positive net balance these circuits for future use by KEI and/or its was that it included a credit of about 0.35 cents affiliate or other future connection customers. per kWh included in the RPP prices which went November 18, 2008 into effect on May 1 due to the need, over the next 12 months, to draw down the variance OEB Posts November 2008’s Electricity account balance which was a surplus at that Regulated Price Plan Variance Settlement time. Factor The Ontario Energy Board (“OEB” or “the November 14, 2008 Board”) has released an updated "Final RPP OEB Issues 2008 Electricity Distribution Rate Variance Settlement Factor" of -0.1593 cents Order for Horizon Utilities Corporation per kilowatt hour (“kWh”) which is to be used by Further to a Decision With Reasons issued on electricity distributors to calculate a one-time October 3, 2008 pursuant to Board File No. EB- credit for consumers who choose to stop 2007-0697, the Ontario Energy Board (“OEB” or purchasing electricity through the Regulated “the Board”) has issued a Rate Order for a Price Plan (“RPP”). The OEB notes that this Decision on a 2008 electricity distribution rate factor is updated on or around the 15th of each application for Horizon Utilities Corporation month and is based on the difference between (“Horizon”), in which it approves new distribution the amount RPP consumers paid for electricity rates which are effective May 1, 2008, but will (for the period from April 1, 2005 to August 31, not be implemented until December 1, 2008. 2008) and the actual amounts paid to generators to supply that electricity. The Board advises that, as a result of this Decision, the delivery portion of the bill The OEB says that this factor is to be used by associated with the cost to distribute electricity electricity distributors to calculate the final will decrease by approximately 17% for payment or credit for consumers who: (1) cancel Horizon’s residential customers. The total their utility account and move outside of the monthly bill for residential consumers paying the Province of Ontario; (2) switch to a retailer; (3) regulated price of electricity will decrease by have an interval meter and elect the spot market approximately 3.7% from a bill issued between pricing option; or (4) cease to remain eligible for May 1 and October 31, 2008. the RPP. According to the Board, based on the updated factor, a consumer who uses 12,000 kWh per - 49 - Cerise, Volume 7, Issue 11-November 2008 November 13, 2008 terminated the Regulatory Asset Recovery rate rider which had been approved for distributors in Kruger Energy Announces the Official 2006 to recover approved balances over a two- Opening of its First Wind Farm in Ontario year period. Kruger Energy has announced the official opening of the Port Alma Wind Farm in The OEB advises that, as a result of its Chatham-Kent, Ontario, with all 44 wind turbines Decision, the delivery portion of the bill at the Kruger Energy Port Alma Wind Farm now associated with the cost to distribute electricity operational. The company adds that the 101.2- will decrease by approximately 16.9% for Brant megawatt project, located on the north shore of County’s residential customers. The total Lake Erie, will generate over 300 gigawatt hours monthly bill for residential consumers paying the (“GWh”) of power per year. regulated price of electricity will decrease by approximately 4.6% from a bill issued between According to the announcement, Kruger Energy May 1 and October 31, 2008. The Port Alma Limited Partnership (“KEPA”) was announcement adds that a table of the selected by Ontario's Ministry of Energy in estimated bill impacts on residential consumers November 2005 as part of the Renewable for individual utilities that have had rate orders Energy Request for Proposals (“RFP”) II, to issued by the Board is available on its website. develop the Port Alma Wind Power Project. Under the terms of the contract, Kruger Energy November 7, 2008 will sell renewable energy to the Ontario Power Ontario IESO Releases Fixed Global Authority (“OPA”) for a period of 20 years. Adjustment Rate for November 2008 Under the Government of Canada's Distributor Billing ecoENERGY for Renewable Power program, The Ontario Independent Electricity System the wind power project will receive up to $31 Operator (“IESO”) is advising that the fixed million in funding over 10 years, and the one Global Adjustment (“GA”) rate for distributor cent per kilowatt hour ecoENERGY incentive will billing for November will be a charge of $7.80 / help to ensure that clean electricity generated at MWh. The System Operator advises that local the site can be delivered to Ontario consumers Distribution Companies (“LDCs”) should use this at competitive prices. figure to calculate the Provincial Benefit for those customers who are not on the Regulated November 12, 2008 Price Plan (“RPP”). OEB Issues Decision on 2008 Electricity Distribution Rate Application for Brant November 6, 2008 County Power OPA Releases Its “2009 - 2011 Business Under Board File No. EB-2008-0110, the Plan” Ontario Energy Board (“OEB” or “the Board”) The Ontario Power Authority (“OPA”) has has issued a Decision and Order approving released its “2009 – 2011 Business Plan”, and 2008 electricity distribution rates effective has outlined the most significant initiatives November 1, 2008 for Brant County Power Inc. planned for the 2009-2011 period. (Brant County). These initiatives are: The OEB reports that Brant County Power was • Developing revisions to the first Integrated one of the distributors identified to file a cost of Power System Plan (“IPSP1”), based on the service application, however it notified the Board September 2008 directive from the Minister of that it did not intend to file such an application. Energy and Infrastructure, and filing the The OEB advises that, in response to a revised plan with the Ontario Energy Board Direction from the Board, Brant County filed an (“OEB” or “the Board”). application for a change to one component of its distribution rates, the Retail Transmission • Undertaking consultation with First Nations Service rates which the Board in turn found just and Métis communities, and considering and reasonable. The OEB also says that it opportunities for partnership with Aboriginal - 50 - Cerise, Volume 7, Issue 11-November 2008 Peoples on generation and transmission standards and other updated knowledge, development in accordance with the including costs and operating performance of September 2008 directive from the Minister of current electricity system assets. Energy and Infrastructure. • Implementing internal strategies and tools • Supporting the implementation of specific critical to achieving the organization’s goals projects identified in IPSP1 and by directive, and deliverables, including a strategic including continuously looking for ways to communications approach in communities accelerate the implementation of cost-effective where vital electricity infrastructure is to be conservation and renewable resources and sited, a holistic talent management system, undertaking development work on key and information management tools and transmission projects designed to enable new capacity. renewable sources of energy to come into November 5, 2008 service. CEAA Announces Public Review Period on • Developing regional electricity plans, the EIS and Application for a Licence to particularly in areas of the province with Prepare a Site for the Proposed Bruce Power urgent and emerging electricity reliability New Nuclear Power Plant Project issues, and coordinating and supporting the implementation of integrated electricity The Canadian Environmental Assessment solutions to always include consideration of Agency (“CEAA” or “the Agency), the Canadian comprehensive conservation, renewable and Nuclear Safety Commission (“CNSC” or “the distributed generation solutions before Commission”) and the Joint Review Panel for considering other resource options. the proposed Bruce Power New Nuclear Power Plant Project (“The Joint Review Panel“) • Managing and settling an increasing volume together have announced the start of a six- and value of contracts for conservation and month public review period of the Environmental generation resources. Impact Statement (“EIS”) and complete • Verifying the results from an extensive application for a Licence to Prepare a Site filed portfolio of conservation programs to help by the proponent, Bruce Power Inc. (“the meet the targets for reductions in peak Project”). electricity demand, including the 2010 target The announcement explains that the EIS, which of 1,350 megawatts. is intended to inform regulators and members of • Championing a culture of conservation by the public about the Project, also provides coordinating and funding conservation information on the anticipated effects of the activities, identifying barriers to conservation Project on the environment. The EIS was and ways to overcome them, and reporting on prepared according to guidelines developed conservation progress and opportunities in jointly by the CEAA and the CNSC. The Ontario. guidelines also referred to the information the proponent was required to provide concerning • Procuring cleaner electricity generation the application for a Licence to Prepare a Site – resources to be in service by 2015. the first in a series of licences required • Developing ways to address barriers to the throughout the lifecycle of a new nuclear power development of economically sustainable plant. conservation, supply and transmission The Joint Review Panel has issued instructions • Continuing to update planning models and for the public review of the EIS and Licence assumptions, based upon the OPA’s most application, and advised that public comments current understanding of Ontario’s economic may be submitted at any time during the six- and energy outlook, customer and stakeholder month review period. The Panel will periodically expectations, technology innovation and issue requests for additional information from opportunity, regulatory requirements, reliability the proponent. Once the Panel has determined that the information requests have been - 51 - Cerise, Volume 7, Issue 11-November 2008 sufficiently responded to, and following the close • A reduction in the deemed equity ratio from of the public comment period, it will schedule the proposed level and announce the start of public hearings. • A reduction in the return on equity to 8.65% The CEAA explains that the Project is a from the proposed level of 10.5% proposal by Bruce Power Inc. for the site preparation, and the construction, operation, • An increase in the revenue attributable to the decommissioning and abandonment of up to Bruce nuclear station four new nuclear reactors at the existing Bruce • An increase in the revenue requirement due to Nuclear Site, located on the eastern shore of adjustments to the balances in various Lake Huron, north of Kincardine. The Project is deferral and variance accounts and an expected to generate approximately 4,000 adjustment to the proposed recovery period megawatts of electricity to the Ontario grid. for one account November 4, 2008 • A reduction in the level of mitigation to be OEB Establishes Framework on Payment provided by OPG. Levels for OPG Regulated Assets The OEB explains that OPG had applied for a In the context of Board File No. EB-2007-0905, fixed payment of 25% for nuclear generation the Ontario Energy Board (“OEB” or “the Board”) whether it produces electricity or not. In its has released its Decision With Reasons decision, the Board did not approve the fixed regarding Ontario Power Generation (“OPG”)’s payment proposal; rather it will compensate payment levels for the output of its regulated OPG on a ‘per megawatt hour’ basis for nuclear and hydroelectric generating assets. electricity. The OEB advises that, after reviewing the cost The OEB advises that OPG will be filing its draft proposals underlying OPG’s application for a order within 10 days for Board approval. Once total revenue requirement of $6,203.8 million for the OEB has approved that order, the Board will the 21 month period, it has decided there should be in a position to calculate the impact on be reductions in a number of areas including: consumer bills. nuclear operating costs, the return on equity, the The OEB notes that earlier this month, it debt/equity ratio, the treatment of nuclear included an allowance in electricity prices under liabilities and the treatment of revenues from the the Regulated Price Plan (“RPP”) to reflect Bruce nuclear station. The Board has directed about 50% of OPG’s original application. RPP OPG to file revised payment amounts reflecting prices may be adjusted by the Board on May 1, these changes, and advises that it estimates 2009 to reflect the difference between that 50% that the resulting impact will be an approximate allowance and the final approved payments, if 8.5% increase in the per megawatt hour necessary. (“MWh”) payment amounts. The Board says that for consumers who are not The following is a summary provided by the on the Regulated Price Plan, the new payment Board of the modifications that it has directed: amounts are expected to go into effect on • A reduction in Base OM&A for the Pickering A December 1, 2008. nuclear station November 4, 2008 • A reduction in nuclear advertising expense Infrastructure Ontario Advises of Short Extension of Deadline for Nuclear • An increase in the revenue attributable to Procurement Project Bid Submissions various activities in the hydroelectric business (segregated mode operation and water Citing in part continued volatility in global transactions) markets, Infrastructure Ontario (“IO”) has announced a short extension from the • A reduction in the revenue requirement related December 31 deadline for the submission of to the nuclear waste management and final bid proposals for the Nuclear Procurement decommissioning liabilities - 52 - Cerise, Volume 7, Issue 11-November 2008 Project saying that it will ask respondents to According to the announcement, when the 750 submit their proposals in early 2009. IO says megawatt unit was taken offline on September that the extension will allow respondents more 15 for its current maintenance program, crews time to assess appropriate risk sharing and had planned to shift more than 60 channels pricing terms - and issues raised from requests during the approximately two month outage. for additional information - to ensure the However, the program has been so successful provision of quality bids from vendors. IO adds that Bruce Power bumped its target to 98 that it is expected that the preferred vendor will channels, of which more than 80 have already be announced this spring but timing will remain been moved. somewhat flexible to ensure the best deal for Bruce Power advises that a recently completed Ontario ratepayers. boiler inspection program also allows it to extend The announcement notes that the project is the expected operating life of Bruce A Unit 4 to using an innovative approach by selecting a 2015. The company adds that it continues to nuclear vendor based on pre-established successfully advance its work on Units 1 and 2, commercial terms, including lifetime cost of and it expects that these units will be placed power, ability to deliver on schedule and level of back in commercial service in the first half of investment in Ontario. This approach requires 2010. extensive discussion with vendors to ensure that November 4, 2008 bids are well informed and in the best interests of Ontarians. Ontario IESO Posts 2009 Fees Application IO says that the Ontario Government announced The Ontario Independent Electricity System a two-phase competitive procurement process to Operator (“IESO”) has posted to its website its choose a preferred nuclear vendor last March. A 2009 Fees Application which it has submitted to commercial team, led by Infrastructure Ontario, the Ontario Energy Board (“OEB” or “the Board). is managing the procurement process. Team In its application, the IESO requests: members also include representatives from • Approval of its proposed 2009 revenue Bruce Power, Ontario Power Generation requirements of $130.3 million; (“OPG”), Ministry of Energy and Infrastructure and Ministry of Finance. A preferred vendor will • Approval of its proposed 2009 capital be chosen based on the evaluation outcome and expenditure envelope of $22.9 million for procurement process. A fairness monitor capital plans; continues to ensure all respondents are treated • Approval for the continuation of the $1,000.00 fairly throughout the Request for Proposals application fee; and (“RFP”) process. • Approval of a usage fee of $0.822 per November 4, 2008 megawatt hour (“MWh”) to be paid Bruce Power Receives Boost in Plan for Life commencing January 1, 2009. The IESO Extensions of Bruce A Units 3 and 4 usage fee is paid by all market participants on energy withdrawn from the System Operator Bruce Power has announced that its plan to add controlled grid including all scheduled exports. years to the operating life of Bruce A Unit 3 has If necessary, pending approval, the IESO received a significant boost thanks to the proposes to continue to charge the 2008 success of a complex maintenance program on usage fee ($0.799/MWh) to market the unit’s fuel channels. Known as West Shift, participants from January 1, 2009 until the end this program sees crews move fuel channels of the month in which Board approval is that have elongated over years of high received for the 2009 usage fee, and seeks temperatures, radiation and pressure back into authorization to charge market participants the their original position. To do that, each channel difference between the 2008 and 2009 usage must be cut free from the reactor, then pulled fee based on their allocated quantity of energy back and welded into place, which ultimately withdrawn for that period, directing such prolongs the reactor’s life. charges to market participants in the next - 53 - Cerise, Volume 7, Issue 11-November 2008 billing cycle following the month in which that November 3, 2008 approval is received. Bruce Power Announces Intent to Conduct In conjunction with these approvals, and Environmental Assessment for Nuclear pursuant to past treatment of accumulated Generating Station Near Nanticoke But operating surpluses approved by the OEB in Ontario Government Not Supportive of previous IESO fees submission proceedings, the Proposal IESO is also seeking authorization to rebate, in Bruce Power has announced that it will conduct 2009, the amount of the accumulated surplus in an Environmental Assessment (“EA”) with its deferral account in excess of $5.0 million. respect to a potential nuclear generating station The accumulated surplus is forecast to be $0.3 (“NGS”) near Nanticoke Ontario; however, in a million (total accumulated surplus is forecast at subsequent announcement, the Government of $5.3 million) as of the end of the fiscal year 2008 Ontario advises that it has not solicited the and it will be rebated to market participants Bruce Power proposal and it is not part of based on each market participant's allocated Ontario’s energy plan. quantity of energy withdrawn in 2008. The IESO is seeking approval to refund the final amount Bruce Power explains that the assessment, based on its audited financial statements as which could take nearly three years to complete, approved by the IESO Board for the fiscal year will examine the environmental and social 2008, and to direct the rebate to market impacts of building two reactors to generate participants in the next billing cycle following the between 2,000 and 3,000 megawatts of low- month in which the 2008 financial statements emissions electricity. The EA will also consider are approved. how other clean energy sources such as hydrogen, solar and wind could complement In the covering letter for the application, as in the nuclear in the area. previous year’s proceeding, the IESO requests that a draft issue list be posted for comment Bruce Power says that it will use the EA as a along with the Notice of Application. In the letter, planning tool to weigh the merits of building a the IESO also encloses a proposed draft issues clean energy hub on approximately 800 list which it says includes the central issues hectares within the Haldimand Industrial Park included in last year’s and previous years’ that it has optioned from US Steel Canada Inc. issues lists and also includes specific issues The EA will officially begin when a Project raised by the OEB panel in last year’s decision. Description and Site Preparation License are accepted by the Canadian Nuclear Safety As in recent years, the IESO requests that the Commission (“CNSC” or “the Commission”). OEB consider setting aside one or two days to hold an initial technical conference in lieu of Bruce Power advises that last June, both interrogatories to be followed shortly afterwards Haldimand and Norfolk councils unanimously by a settlement conference. If the Board’s passed resolutions supporting the launch of an schedule allows, the IESO requests that these EA into new nuclear. Bruce Power says that proceedings be scheduled before the end of the soon after, a poll conducted by Ipsos-Reid year. showed more than 80 per cent of residents were open to the EA planning process and that nearly November 3, 2008 two-thirds of people in the area support nuclear Ontario IESO Announces Estimated Global energy. Adjustment for October, 2008 Although Bruce Power says that Ontario’s The Ontario Independent Electricity System Minister of Human Resources and Skills Operator (“IESO”) has announced that the Development, Diane Finley, applauded Bruce estimated global adjustment (“GA”) rate for the Power’s decision, saying she strongly supports month of October is a charge of $7.93/MWh. the launching of an assessment for new nuclear The IESO further advises that the actual GA will build in her Haldimand-Norfolk riding, in a be on market participant settlement statements subsequent press release, the Government of 10 business days after the end of the month. Ontario says that it has not encouraged or - 54 - Cerise, Volume 7, Issue 11-November 2008 solicited such a proposal and is not looking to academic leaders, chaired by Roger Martin, build new nuclear facilities at Nanticoke. Dean of the Rotman School of Management, The Government of Ontario goes on to say that was established in 2001 to stimulate this course of action is speculative and is being businesses, governments, educational conducted by a private company. The institutions, and individuals to increase the pace Government says that its long-term energy plan of innovation and competitiveness, to ensure a includes renewing its nuclear fleet but at the continuing increase in the standard of living of same level it's been at for about 20 years. The Ontarians. plan seeks to ensure adequate baseload November 4, 2008 electricity supply while limiting the future use of Barrie Hydro and PowerStream Post nuclear power to today's installed capacity level Amalgamation Application and Notice of about 14,000 megawatts. PowerStream Inc. (“PowerStream”) and Barrie The government adds that it believes coal Hydro Distribution Inc. (“Barrie Hydro”) replacement should come from conservation (collectively “the Applicants”) have posted Notice and intensifying its reliance on renewable forms of a joint application to the Ontario Energy Board of energy, such as the sun, wind, water and (“OEB” or “the Board”) seeking leave to biomass. amalgamate with the amalgamated company In a related press release supportive of Bruce being referred to as “MergeCo”. The Power’s proposal, the Canadian Hydrogen amalgamation is referred to as the “Proposed Association (“CHA”) says that it will work with Transaction”. The Notice advises that the Bruce Power and representatives of the closing date of the Proposed Transaction is University of Waterloo and McMaster University December 31, 2008. to study the potential of building a clean energy The Applicants advise that if the Board grants hub at Nanticoke involving next generation leave to PowerStream and Barrie Hydro to nuclear, hydrogen, wind and solar. amalgamate, upon closing of the Proposed General Transaction, Barrie Hydro requests that its electricity distribution licence be cancelled. November 26, 2008 PowerStream has requested, that its distribution Ontario Task Force on Competitiveness, licence be amended to include in its service area Productivity and Economic Progress the area currently served by Barrie Hydro. Recommends Revenue Neutral Carbon Tax The announcement advises that PowerStream The Ontario Task Force on Competitiveness, owns, operates and manages assets associated Productivity and Economic Progress (“TFCPEP” with the distribution of electricity within the or “the Task Force”) has released its seventh geographic territory and municipal boundaries of annual report entitled: “Leaning into the Wind” the City of Vaughan, and the Towns of and among the new initiatives it recommends is Markham, Richmond Hill and Aurora, as that Ontario consider a carbon tax as part of its described in its electricity distribution licence approach to reducing greenhouse gases (ED-2004-0420). The announcement explains (“GHG”). The Task Force acknowledges that the that Barrie Hydro owns, operates and manages carbon tax was dealt a serious blow in the last assets associated with the distribution of federal election, but it says that if Ontario wants electricity within the geographic territory and to meet its national and provincial GHG municipal boundaries of the City of Barrie and reduction targets, it needs to consider a carbon the communities of Bradford, West Gwillimbury, tax. The Task Force adds that subsidies and Thornton, Alliston, Beeton, Tottenham and exhortations will not be enough and its proposal Penetanguishene, as described in its electricity is for consideration of a revenue neutral carbon distribution licence (ED-2002-0534). tax, which if implemented, would replace other taxes that work against Ontario’s prosperity. The announcement goes on to address many details and necessary actions related to the The Task Force, a group of industry and proposed transaction. - 55 - Cerise, Volume 7, Issue 11-November 2008 QUÉBEC financial products, as well as the proposed “ceiling” applicable to fixed price contracts; Natural Gas November 20, 2008 • Extended to September 30, 2010, the rate flexibility program for fuel-oil and dual-fuel The Régie Partially Approves Gaz Métro’s customers of all small and medium-power 2009 Rate Application, Supply Plan and customer classes (Rates D1, D3 and DM), Energy Efficiency Plan which had previously been extended to The Régie de l'énergie (“Régie”) has released September 30, 2009 by decision D-2007-116; decision D-2008-140, partially approving, with • Approved proposed changes to the some modifications, an application by the accounting method for accumulated vacation Société en commandite Gaz Métro’s (“Gaz pay; Métro”) to modify its 2009 rates and conditions. • Rejected the accounting method proposed for In its decision, the Régie also approved, with the annual amount payable by Gaz Métro to modifications, Gaz Métro’s 2009 supply plan, the the Agence de l’efficacité énergétique (“AEE”) application of its 2009 performance-based for energy efficiency programs that do not fall incentive mechanism (“PBM”), Gaz Métro’s 2009 within Gaz Métro’s 2009 DSM plan or its EEF energy efficiency plan (“DSM Plan”) and the programs; required budget for the Energy Efficiency Fund (“EEF”). • Ordered Gaz Métro to make changes to its rate application in compliance with the orders In its decision, the Régie: set out by the Régie in decision D-2008-140 • Approved the application of Gaz Métro’s and ordered Gaz Métro to submit its amended performance-based incentive mechanism evidence, its amended rate grid and its (“PBM”) for the 2009 fiscal year, in compliance amended Tariffs for 2009, at the latest by with decision D-2007-47, subject to the November 19, 2008 at noon (Eastern corrections to be made to Gaz Metro's Standard Time). evidence so as to comply with the current Background decision; On February 20, 2008, Gaz Métro filed an • Approved an average base capital cost of 7.68 application with the Régie for the approval of its % for 2008; 2009 rates, for the period from October 1, 2008 • Authorized a prospective capitalization rate of to September 30, 2009. 6.69% for Gaz Métro’s projected investment In its application, Gaz Métro also requested that projects in 2009, in compliance with its BT rate class (dual fuel energy rate) be parameters set out in decision D-97-25; delayed to September 30, 2010 for rate classes • Approved, with some changes, Gaz Métro’s D1, D3 and DM. Gaz Metro also sought the Supply plan for 2009; Régie’s approval of its 2009 supply plan, the elements that fall within the application of its • Approved a reduced budget of $3 million for performance-based mechanism (“PBM”) as well the Energy Efficiency Fund (“EEF”) to as the 2008-2009 budgets for its energy implement the Demand Side Management efficiency plan (“DSM Plan”) and Energy (“DSM” programs offered during the 2009 Efficiency Fund (“EEF”). fiscal year in compliance with the EEF’s action plan; Gaz Métro requested that the 2009 rate application be divided in two phases. Phase I • Approved changes proposed by Gaz Métro to pertained to proposed modifications to the its levelling account for weather variances; variance account for the cumulative cost of • Approved the total volumes for 2009 that fall natural gas supply and compressor fuel. within Gaz Métro’s program for derivative On June 6 2008, the Régie released Decision D- 2008-083 approving the elements included in - 56 - Cerise, Volume 7, Issue 11-November 2008 Phase 1 of Gaz Métro's 2008-2009 rate rendered. application. In that decision, the Régie also The Régie rendered the interim decision as it ordered Gaz Métro to prepare a detailed was not prepared to render a final decision explanatory document of the calculation method before Gaz Métro’s 2009 rates entered into force for the projected cost of service of natural gas on October 1, 2008. The Régie decision was supply and compression. The Régie also rendered in compliance with Article 34 of the Act abolished the variance threshold of 2 ¢/GJ which Respecting the Régie de l’énergie (“Act”). was included in the monthly adjustment of the natural gas supply and compression rate. Gaz Métro's full application carries docket number R-3662-2008. Phase II pertained to all other elements of Gaz Métro’s 2009 rate application including the 2009 Electricity supply plan as well as the application of the November 26, 2008 PBM approved by the Régie in decision D-2007- 47. Innergex Advises that Carlton Wind Farm Began Operations on November 22, 2008 More specifically, Phase II dealt with the request to delay the application of the dual fuel energy Innergex Renewable Energy Inc. ("Innergex") rates until September 30, 2010 for D1, D3 and advises that the Carleton wind farm, located in DM rate classes, which had already been the Province of Quebec was built on-time and on postponed until September 30, 2009 in budget, and commercial in-service occurred on compliance with decision D-2007-116. November 22, 2008. In Phase II, Gaz Métro also requested changes Innergex reports that the Carleton wind farm is to the levelling account pertaining to weather the third Cartier Wind Energy project built variations so as to take into account the impact following Hydro-Quebec Distribution (“HQD”)'s of wind. Modifications to the levelling account first call for tenders for wind energy. Innergex imply modifying the method used to evaluate the owns a 38% interest in the Carleton wind farm, gas volumes subject to the levelling procedure. which has secured a twenty-year power The latter is used to evaluate the gas volumes purchase agreement (“PPA”) with Hydro- that are subject to levelling as a result of Quebec (“HQ”) in respect of all the energy uncontrollable fluctuations of the “wind” generated by the facility. The Carleton wind farm component from one year to the next. is comprised of 73 wind turbines with 109.5 MW of total installed capacity, which should generate In Phase II, Gaz Métro also sought the Régie's over 340,000 MW-h of energy per year. approval for the average cost of capital on its rate base, its revenue requirement, the EEF and November 13, 2008 DSM budgets and expenditures related to its Hydro-Québec Gives SGL Canada $825 000 2009 investment projects. to Implement Energy Efficiency Projects Gaz Métro also sought the approval of the Hydro-Québec (“HQ”) announced that it had annual amount payable by Gaz Métro to the granted SGL Canada (“SGL”) over $825,000 for Agence de l’efficacité énergétique (“AEE”) for participating in one of Hydro-Québec energy efficiency programs that do not fall within Distribution’s (“HQD”) Demand Side Gaz Métro’s 2009 DSM plan or its EEF Management (“DSM”) programs for large programs as well as the proposed allocation by industry. customer class. SGL’s plant in Lachute, Quebec, received the On September 24, 2007, the Régie released financial support in order to carry out seven interim decision D-2008-122 regarding Gaz energy efficiency projects which were primarily Métro’s 2009 rate application. In that decision, aimed at reducing heat losses for the plant’s the Régie declared that Gaz Métro’s existing equipment. rates would continue to be applicable starting October 1, 2008 until the final decision regarding Combined, the seven energy efficiency projects the amended 2009 rate application was generated recurrent savings of over 11 million - 57 - Cerise, Volume 7, Issue 11-November 2008 KWh annually, which is roughly equivalent to the million, up $4.4 million over the average consumption of 660 households in previous fiscal year. Achieved rate of Quebec. return on deemed common equity is 10.37%, up 0.47% over the 2007 HQD estimates that, combined, its large power fiscal year; customers (5 MWh or more) have saved over one billion KWh and 80% of them have o Record number of new residential participated in HQ’s energy efficiency programs. sales: 6,305 new contracts signed in residential markets out of a total of General 9,083 new contracts, representing November 25, 2008 increases of 25% and 13% Hydro-Québec Gives Eka Chimie $678,000 to respectively over 2007 fiscal year. Implement Energy Efficiency Projects • Green Mountain Power Corporation (“GMP”): Hydro-Québec (“HQ”) has announced that it has o Favourable contribution of $11.8 granted Eka Chimie over $678,000 for million, before financing costs, for participating in one of Hydro-Quebec 2008 fiscal year. Distribution’s (“HQD”) Demand-Side Management (“DSM”) programs for large • Wind power projects: industry. o Firm 20-year electricity contracts HQ reports that Eka Chimie’s plant in Valleyfield, signed with Hydro-Québec Quebec, received the financial support in order Distribution, in partnership with to carry out three energy efficiency projects Boralex Inc. (Boralex), for wind power which were primarily improving the electrolysis projects totalling installed capacity of process used to make sodium chlorate. These 272 megawatts; and projects have made it possible to optimize the o Declaration of distribution of $0.31 per surface of electrodes and to improve contact unit, payable January 5, 2009 to between electrolysis cells. Combined, the seven Partners of record on December 15, energy efficiency projects generated recurrent 2008. savings of over 5 million KWh annually. SASKATCHEWAN HQ explains that Eka Chimie is a division of AkzoNobel, one of the main suppliers of Natural Gas bleaching chemicals, chemical products used to November 28, 2008 make paper as well as other systems for the pulp and paper industry internationally. Eka Joint Report by NEB and Saskatchewan Chimie also supplies specialty chemical Reveals Potential for Years of Sustained products to the pharmaceutical and electronic Activity in Saskatchewan's Conventional industries. Natural Gas Industry November 19, 2008 The National Energy Board (“NEB” or “the Board”) and the Saskatchewan Ministry of Gaz Métro Reports Strong Results for its Energy and Resources (“SMER”) have issued a 2008 Fiscal Year joint Energy Market Assessment revealing that Gaz Métro has reported strong results for its Saskatchewan has more than enough 2008 fiscal year ended September 30, 2008. conventional gas resources to maintain a high The company notes that its adjusted net income level of natural gas industry activity for many for the year is $153.3 million, which is $4.3 years. million over the previous year. Other highlights The announcement says that the assessment, of the fiscal year include: entitled “Saskatchewan's Ultimate Potential for • Distribution of natural gas in Quebec: Conventional Natural Gas”, shows that Saskatchewan's ultimate potential of marketable Contribution to net income of $125.3 o conventional natural gas resources is calculated - 58 - Cerise, Volume 7, Issue 11-November 2008 to be 297.4 billion cubic metres (109m(3)) or nuclear facility. Bruce Power estimates that a 10.6 trillion cubic feet. The NEB notes that this new plant would create 2,000 jobs during data, taken as of year-end 2004, represents a construction and 1,000 permanent jobs over 60 42 per cent increase from the last study in 1998. years of operation. About half of that volume has already been General produced; the remaining volume is 150.6 billion cubic metres (109m(3)) or 5.3 trillion cubic feet. November 7, 2008 The announcement explains that ultimate Saskatchewan Government, Royal Dutch potential is a science-based estimate of the total Shell and University of Regina Establish amount of conventional natural gas in an area. International CO2 Storage Assessment This includes gas produced to date, estimated Centre remaining proven reserves, and an estimate of The Government of Saskatchewan, Royal Dutch future discoveries. The majority of natural gas in Shell and the University of Regina have the province is non-associated which means it is announced a new international centre for the found in reservoirs where no crude oil is present. deployment and acceptance of Carbon Dioxide The current annual production of non-associated Capture and Storage (“CCS”). The natural gas in Saskatchewan is approximately announcement says that the new centre, known 6.9 billion cubic metres (109m(3)) or 245 billion as the International Performance Assessment cubic feet. Centre for Geologic Storage of CO2 (“IPAC- The assessment notes that shallow gas in CO2”), has been created through founding Saskatchewan's Milk River, Medicine Hat and investments of $5 million each from the Second White Specks formations shows 80 per Government of Saskatchewan and Shell. cent growth since the last study which focused Located at the University of Regina, the IPAC- primarily on deeper zones. New technology, CO2 will focus on key elements of the geological improved production practices, and higher storage of CO2: natural gas prices have pushed exploration into • Assessing proposed CCS projects around the areas once thought of as marginal or non- world and advising on the proper management economic. of technical issues and performance Electricity monitoring; November 28, 2008 • Informing stakeholders and the public about CCS from an independent, science-based CNSC Posts “Saskatchewan 2020 Clean perspective; energy New opportunity”, Bruce Power’s Report on Its Feasibility Study • Networking internationally to share and build The Canadian Nuclear Safety Commission on the findings of other research (“CNSC” or “the Commission”) has posted to its organizations. website a document entitled: “Saskatchewan The announcement suggests that broad 2020 Clean energy New opportunity” which is a acceptance of CCS technology requires that Bruce Power report on its feasibility study to IPAC-CO2 develop its credibility, objectivity and consider the role that nuclear power could play transparency. For that reason, the centre will in Saskatchewan. work internationally to allow the best expertise in In a related press release, Bruce Power the world to be brought to bear on the issue of suggests that nuclear energy could contribute geological storage of CO2. This expertise is 1,000 megawatts of electricity to found at the Universities of Regina, Calgary, Saskatchewan's generation mix by 2020. Alberta and Dalhousie, as well as in other According to the company, the feasibility study international organizations. To this end, IPAC- concluded that a region spanning from CO2 says that it has already begun discussions Lloydminster, including the Battlefords and with, among others, Imperial College, England, Prince Albert, was the most viable host for a the CO2CRC in Australia, and the Instituto do Meio Ambiente in Porto Alegre, Brazil. - 59 - Cerise, Volume 7, Issue 11-November 2008 A backgrounder providing more information footnote 1 in Board Order 2008-16. The footnote about IPAC-CO2 and its Acting Director, Dr. erroneously referenced the 2009 Forecast Malcolm Wilson of the University of Regina, is Revenues from Table 2.2 on page 2-16 of the attached to the press release. Application. The correct reference should be from Table 4-6 on page 4-14 of YEC’s 2008-09 YUKON General Rate Application using the $38,359.1 Electricity ($000s) total from the first column. This provides a 3.48% reduction through Rider J which applies November 27, 2008 only to Residential (Non-Government and Yukon Board Denies Yukon Energy Request Government), General Service (Non- for Interim Rate Rider U and Approves Rate Government and Government) and Lighting Reduction for Most Rate Classes customers. Wholesale customers are not affected by Rider J. The Yukon Utilities Board (“YUB” or “the Board”) has issued Board Order 2008-16 in which it November 26, 2008 denies an October 6, 2008 request from the Yukon Energy Announces Completion of Yukon Energy Corporation (“YEC”) for approval Phase 1 of Carmacks-Stewart Line of an Interim Refundable Rates Order for retail rate reductions (“Rider U”) commencing The Yukon Energy Corporation (“YEC”) has November 1, 2008 and amends Rider J by announced the completion of Phase 1 of the applying a 5.98% decrease to the base rates of Carmacks-Stewart transmission line. The all rate classes, except Rates 39 and 32, company says that construction of the line from effective December 1, 2008. Carmacks to Pelly Crossing with a spur to the Minto mine has allowed the mine to switch from The YUB notes that YEC’s original request was diesel generation to hydro, and that Pelly subsequently amended to December 1, 2008, Crossing will also switch to hydro within the next applicable only to first block rates where few days. YEC estimates that the project will feasible, without any rate rebalancing between reduce greenhouse gas (“GHG”) emissions by customer classes and that YEC also requested approximately 30,000 tonnes per year. that an increase in residential runoff rates be approved as part of an Interim Refundable According to the announcement, all parties Rates Order. contributed financially to the total cost of the transmission line with the Yukon government In rendering Decision 2008-16, the Board noted providing $10 million to the project. Sherwood that all interested parties support customers Copper contributed $7.2 million to the main line receiving the immediate benefits of higher sales and also covered the entire cost of the spur line arising from YEC’s interconnection of Minto to the Minto mine. The remaining costs were Explorations and that those parties also took the covered by the Yukon Energy Corporation and position that it is more appropriate to consider the Yukon Development Corporation. rate restructuring within the context of a Phase II proceeding. The Board said that it agrees with UNITED STATES OF AMERICA interested parties that alternative rate structures should be tested before implementation and that Natural Gas on an interim basis, Rider J is the best vehicle to November 12, 2008 flow through the benefits to retail customers. NRRI Releases Research Paper Entitled Subsequent to its release of Decision 2008-16, “Speculation in the Natural Gas Market: What the YUB released Decision 2008-17 in which it It Is and What It Isn’t; When It’s Good and advised that there was an error in the original When It’s Bad” decision and that the decrease should have The National Regulatory Research Institute instead been 3.48%. (“NRRI”) has released a research paper entitled In Decision 2008-17, the YUB advised that it had “Speculation in the Natural Gas Market: What It discovered an error in the formula set out in Is and What It Isn’t; When It’s Good and When - 60 - Cerise, Volume 7, Issue 11-November 2008 It’s Bad” which was prepared by its Director of use. Much of Canada, however, typically Natural Gas Research and Policy, Ken Costello. experiences peak demand for electricity during The paper advises that its major purpose is to the winter months due to electric heating. The address basic questions about speculation in report notes that the resource outlook in Canada commodity markets, especially the natural gas remains positive, with resource margins and oil markets. The paper notes that expected to improve from 14 percent last winter policymakers, analysts, and other market to 16 percent this winter. observers have expressed opinions on what The report also highlights several key factors effect increased speculation has had on that contribute to the favourable assessment for commodity markets. The paper further observes this winter: that these opinions diverge with different Mild Winter Weather Projected – According to implications for appropriate public policy and the U.S. National Oceanic and Atmospheric other actions the government might take with Administration (“NOAA”), winter weather is those who see speculation as almost always projected to be relatively mild, with much of the benign or beneficial to markets and society in central part of the continent expecting above general tending to advocate light-handed average temperatures. regulation of this market activity while sceptics of speculation who support more stringent Demand Response Increases – Approximately regulations, particularly in limiting speculative 28,000 MW of demand response is projected to positions to mitigate manipulation and a “bubble” be available across North America during the phenomenon. winter months, representing an increase of nearly 40 percent over last winter. As a result of The paper further observes that, although one this and the slowing economy, growth in common perception is that speculators engage demand for electricity has been limited to only in greedy, antisocial activities, such as market 0.5 percent in 2008 over last year, compared to manipulation, which allow them to accumulate the average annual growth of 1.75 percent over significant wealth at the expense of society; the past three years. where such instances have occurred, in almost every case, the culprit ultimately reaped financial Fuel Inventories and Availability Improves – ruin. Record levels of new natural gas pipeline and storage capacity in the U.S. have contributed to Electricity improved adequacy of the fuel supply and November 18, 2008 delivery system. Though current storage levels are below last year’s high, natural gas is NERC Releases its “2008/2009 Winter expected to be adequate for the winter. Coal Reliability Assessment”, Indicating that stocks are above average in both the East and Winter Electric Reliability Outlook is the West, with western utilities having an Generally Good average of approximately 20 additional days of The North American Electric Reliability burn on hand compared to last winter. Corporation (“NERC”) has posted its report Wind Generation Continues to Grow entitled: “2008/2009 Winter Reliability Significantly – Nameplate wind capacity is Assessment” on its website. According to the projected to grow by 6,000 MW or 27 percent report, the outlook for electric reliability in North over the winter months to a total of 28,500 MW America this winter is generally good, with NERC-wide. Texas will see the greatest generation and demand-side resources increase, with just under 4,000 MW scheduled expected to exceed target planning levels in all for completion by March 2009. The availability of regions. these resources at a time of peak demand still According to NERC, demand for electricity and requires further study, but is projected to range stress on the transmission system generally from 9 to 24 percent across North America. declines in North America during the winter months, primarily due to reduced air conditioning

- 61 - Cerise, Volume 7, Issue 11-November 2008 November 14, 2008 main source of home heating, while nearly 70 percent use air-conditioning. NYISO Forecasts Sufficient Electricity Supply for Winter 2008-2009 • The summer 2008 peak was 32,432 MW, set The New York Independent System Operator on June 9. New York’s all-time record peak (“NYISO”), says that New York State has was 33,939 MW, set on August 2, 2006. sufficient resources to serve the electricity needs November 10, 2008 of the 2008-2009 winter season. NYISO NERC Releases Report on “Electric Industry forecasts that New York’s winter peak usage will Concerns on Reliability Impacts of Climate reach 25,293 megawatts (“MW”) which is 272 Change Initiatives MW higher than the winter 2007-2008 peak of 25,021 MW that occurred on January 3, 2008. The North American Electric Reliability Corporation (“NERC”) has released its Special The NYISO advises that, with a total available Report on “Electric Industry Concerns on supply of 40,375 MW, New York has a capacity Reliability Impacts of Climate Change margin of 15,082 MW, or 37 percent. The Initiatives”. The report identifies several key System Operator adds that the New York State reliability issues associated with climate change Reliability Council (“NYSRC”), which develops initiatives that will need to be addressed as the reliability rules for compliance by the NYISO these policies progress: and its Market Participants, mandates a minimum margin of 15 percent. Broad-scale fuel switching from coal to natural gas — Coal-fired generation currently provides The NYISO reports that, while the upcoming approximately 50% of North America’s electric winter peak is expected to be higher than last capacity. Retirements of coal-fired plants over a winter’s peak, this winter’s forecast is 248 MW short timeline could result in the loss of less than the record winter peak of 25,541 MW generation needed to support the integrity of the set on December 20, 2004. bulk power system and thus severely impact According to the NYISO: reliability across the continent, especially in those regions heavily dependent on the fuel. • The forecasted peak for New York City is 7,860 MW. The total available supply from The broad-scale replacement and relocation of generators in New York City is expected to be generating plants from current coal sites to sites 10,085 MW, providing a capacity margin of that would be suitable for new or expanded 2,225 MW or 22 percent. New York City also natural gas-fired plants would require significant has an import capability in excess of 5,500 upgrades to existing transmission infrastructure. MW and a potential demand response of over Transmission infrastructure and planning 500 MW. mechanisms — The existing bulk transmission network is inadequate to reliably deliver power • The Long Island forecasted peak is 3,768 from new renewable resources to demand MW. The total available Long Island supply is centers. Innovative planning and operational expected to be 6,025 MW, providing a mechanisms will be needed as states and capacity margin of 2,257 MW or 37 percent. provinces attempt to deliver “clean energy” over Long Island also has an import capability in already heavily-loaded transmission lines to excess of 2,250 MW and over 150 MW of meet renewable portfolio standard requirements. potential demand response. Demand-side resources — Managing growing • New York’s electricity system experiences its demand will be critical to meeting both climate greatest demand during summer months due and reliability goals, making demand-side in large part to the power demands of air resources a critical component of the resource conditioning and cooling systems. According mix. Dispatchable demand response will be to the United States Energy Information particularly important as it adds needed system Administration (“EIA”), fewer than 7 percent of flexibility and supports the integration of new New York households rely on electricity as the variable generation such as wind power. - 62 - Cerise, Volume 7, Issue 11-November 2008 National climate change policy in the U.S. — A southern Maryland. The project would then decision on national climate change policy is cross under the Chesapeake Bay, traverse the needed in the U.S. to provide regulatory Delmarva Peninsula, cross the Delaware River certainty and support for industry action. Delay and end in Southern New Jersey. The MAPP on this important policy is negatively impacting project, to be placed into service by 2013, is both reliability and climate objectives. estimated to cost $1.05 billion; of which Pepco would be responsible for $950 million. November 4, 2008 FERC authorized for the project a 1.5 percent Midwest ISO Projects Region to Have return on equity (“ROE”) adder to the company’s Adequate Power to Meet Winter Demand existing 11.3 percent ROE which will result in an The Midwest Independent Transmission System overall ROE of 12.8 percent. FERC also Operator, Inc. (“MISO”) advises that its region authorized full recovery of construction work in will have sufficient generation capacity to meet progress and prudently incurred abandoned the expected winter peak power demand. The plant costs. The rates took effect Nov. 1, 2008. Midwest ISO’s winter evaluation is an annual review which examines the expected use of The project was identified in the PJM Regional power compared to the amount of generation Transmission Expansion Plan as a baseline available to meet the needs within the RTO’s project and has been approved by the PJM footprint. The just-completed final evaluation for Board of Managers. The project is expected to the winter of 2008/2009 estimates a peak net resolve 33 overloads on several interfaces in the demand of 79,362 megawatts (“MW”) within the Mid-Atlantic region and bring congestion relief footprint of the Midwest Energy Markets, 3.72 and reliability benefits to the Baltimore- percent below last winter’s 82,430 MW peak set Washington area. in the Midwest ISO Market footprint on January Pepco says the project will provide access to 24, 2008. more than 1,300 megawatts of renewable wind The MISO says that the projected reserve generation in the western portion of PJM and will margin for the winter of 2008/2009 is 33,366 be operated as a “smart grid” which provides MWs, or 42 percent of the coincident net internal operating efficiencies; minimizes sags, spikes demand, which exceeds the State Authorities’ and other disturbances; corrects problems with and the Planning Reserve Sharing Group’s minimal intervention by the grid operator; established minimum requirement of 11,507 or monitors and diagnoses the health and condition 14.5 percent. of equipment and predicts the malfunction or failure of a device to prevent it from occurring. November 4, 2008 The project is expected to save $113 million FERC Approves Incentives for Pepco’s Mid- annually to the Mid-Atlantic region, and $70 Atlantic Grid Expansion million annually for the entire PJM region if operated as an AC line. If the portion of the The U.S. Federal Energy Regulatory project crossing under the Chesapeake Bay is Commission (“FERC” or “the Commission”) has built as a 640 kV HVDC line, the annual savings approved a series of rate incentives for Pepco would be $174 million and $91 million, Holdings Inc.’s (“Pepco”) proposed 230-mile respectively, and reduce production costs by Mid-Atlantic Power Pathway (“MAPP”) project, a $58 million annually for the entire PJM region. major backbone transmission line from Virginia to New Jersey which would improve reliability in FERC regulations under Order No. 679 state the PJM Interconnection region. that projects seeking incentives must demonstrate that the facilities either ensure The announcement explains that the MAPP reliability or reduce the cost of delivered power project is a 500 kilovolt (“kV”), 230-mile by reducing transmission congestion. transmission line that would be built in segments, starting at Virginia Electric and Power Company’s Possum Point substation in Virginia and crossing over the Potomac River into - 63 - Cerise, Volume 7, Issue 11-November 2008 General Commissioner Tony Clark of North Dakota have been elected as First-Vice-President and November 26, 2008 Second-Vice-President respectively. Spectra Energy Issues First Sustainability The announcement reports that NARUC elected Report Commissioner Butler as its President at its 120th Spectra Energy has posted on its website its first Annual Convention in New Orleans. sustainability report, entitled: “Measuring Our Commissioner Butler, who will serve a one-year Performance, Extending Our Reach”, which term, succeeds President Marsha Smith of focuses on the company’s economic, Idaho, whose term expired on November 19, environmental and social performance during 2008. Both Commissioner Coen and 2007 and establishes a baseline for measuring Commissioner Clark, also elected by NARUC the company’s progress. members, will each serve one-year terms. The report outlines the company’s approach to NARUC explains that, as President, sustainability, which centers around four primary Commissioner Butler will provide general themes: oversight of the Association, which represents 1. operating in an ethically, fiscally and the State public service commissioners who socially responsible manner; regulate essential utility services such as 2. respecting and supporting local electricity, telecommunications, gas, water, and communities; transportation. In this role, Commissioner Butler 3. protecting the environment; and will serve as the Association’s primary voice, 4. delivering superior stakeholder value. leading NARUC before Congress, the courts, and administrative agencies. He will also be The report also conveys the foundation-setting responsible for designating members to the initiatives associated with supporting and NARUC Board of Directors and making other substantiating the company’s approach, from Association appointments as necessary. collecting and analyzing data and establishing metrics to formalizing commitments and setting According to NARUC, President Butler was first step goals for improvement. appointed to the New Jersey BPU in 1999, and has served on several NARUC committees, Additionally, the report identifies six areas of including as chair of the Ad Hoc Committee on focus for gauging performance: Climate Change, and the International Relations 1. Deliver superior economic returns; and Water committees. He currently serves on the advisory board of the Michigan State 2. Ensure strong corporate governance University Institute of Public Utilities, the New and business ethics; Mexico State University Center for Public 3. Operate responsibly, reliably and safely; Utilities’ Advisory Council and the advisory council to the University of Florida’s Public 4. Protect the environment; Utilities Research Center. Commissioner Butler 5. Value and energize employees; and received a Bachelor's degree in Modern 6. Support and engage local communities Languages and Political Science from Villanova University, and earned a Master's degree in November 20, 2008 International Relations from the Johns Hopkins NARUC Announces Appointments of its New University School of Advanced International President and Vice-Presidents Studies. The National Association of Regulatory Utility NARUC advises that First-Vice President Coen Commissioners (“NARUC” or “the Association”) was appointed to the Vermont Public Service has announced that New Jersey Board of Public Board (“PSB”) in June 1995 and subsequently Utilities (“BPU”) Commissioner Frederick F. reappointed for two successive terms. He is an Butler has been elected as its new President, active NARUC member, who has served on the and Commissioner David Coen of Vermont and Board of Directors, the Executive Committee and as Vice Chairman of the Consumer Affairs - 64 - Cerise, Volume 7, Issue 11-November 2008 Committee and Chairman of the National except for electric power, led by 4.1- and 3.2- Regulatory Research Institute’s Board of percent growth in the residential and commercial Directors. Prior to joining the PSB, First-Vice sectors, respectively. While very slight growth is President Coen served as President and CEO of expected in the residential and commercial Fishman’s Department Stores. He has held a sectors in 2009, the contracting economy is wide variety of community leadership positions, expected to cause a 2.2-percent decline in including serving on and/or chairing the boards industrial sector consumption next year. The of directors of the Vermont Business weakness in global economic growth could limit Roundtable, the Porter Medical Center, and the U.S. exports of natural-gas-intensive products Snelling Center for Government. and further reduce natural gas consumption by industrial consumers. NARUC advises that Second-Vice President Clark was elected to the North Dakota Public Production and Imports: Total U.S. marketed Service Commission (“PSC”) in 2000 and won natural gas production is expected to increase re-election in 2006. Within NARUC, by 6 percent in 2008 and by 2 percent in 2009. Commissioner Clark served as chairman of the Production activity from unconventional fields in Association’s Telecommunications Committee the States of Texas, Wyoming, and Oklahoma is from 2005-2008 and is a member of the Board expected to increase supply from the Lower-48 of Directors. Before his election to the PSC, non-GOM by almost 10 percent this year. While Second-Vice President Clark served in the North continued onshore production growth is Dakota Legislature from 1994-97. He holds expected in 2009, lower average prices and bachelors degrees from North Dakota State poor economic conditions are expected to limit University, and a Master’s degree in public the expansion of supplies to 1.9 percent. For administration from the University of North 2008, Federal GOM production is now expected Dakota. to decline by 14.8 percent as repairs to supply The announcement adds that Chairman Charles infrastructure continue, while 2009 growth of 2.7 Box of the Illinois Commerce Commission percent reflects the expectation of further (“ICC”) was unanimously confirmed as recovery and less shut-in production during the Treasurer by the NARUC Board of Directors, a 2009 hurricane season. position to which he was appointed in July. Strong global demand, supply constraints, and Chairman Box was appointed to the ICC in lower relative U.S. natural gas prices have all January 2006. Before that, he served 12 years, contributed to the decline in U.S. imports of from 1989-2001, as mayor of Rockford, Ill., liquefied natural gas (“LNG”), which are where he also served as the city’s Administrator expected to fall from 770 billion cubic feet (“Bcf”) and Legal Director. in 2007 to 350 Bcf in 2008, a reduction of 55 percent. LNG imports are expected to total November 13, 2008 about 410 Bcf in 2009. The limited natural gas EIA Posts Updated “Short-Term Energy storage facilities in LNG-consuming nations Outlook” outside of the United States could lead to higher The Energy Information Administration (“EIA”) of U.S. LNG import growth in 2009, particularly the U.S. Department of Energy (“DOE”) has during the storage injection season (April to released the November 2008 monthly update of September) as more global LNG capacity is its “Short-Term Energy Outlook”. The following brought online. is an edited version of the summary which the Inventories: On October 31, 2008, working EIA has provided: natural gas in storage was 3,405 Bcf. Current Natural Gas inventories are now 78 Bcf above the 5-year average (2003–2007) and 130 Bcf below the Consumption: Total natural gas consumption is level during the corresponding week last year. expected to increase by 1.1 percent in 2008 and fall by 0.2 percent in 2009. Consumption in Prices: The Henry Hub spot price averaged 2008 is projected to be higher in every sector $6.94 per Mcf in October, $0.94 per Mcf below the average spot price in September. The - 65 - Cerise, Volume 7, Issue 11-November 2008 slowing economy, continued growth in domestic advises that the report shows a rise in the natural gas production, and the significant number and quality of self-reports and an decline in oil prices have led to a dramatic shift increase in referrals from regional market in expectations for natural gas prices over the monitors, and provides information on forecast. Household heating expenditures this settlements which demonstrate the winter are expected to be slightly higher than Commission’s commitment to strengthening the last year due to the pass-through of some compliance programs of regulated companies. higher-priced natural gas that was put in storage The announcement advises that the purpose of earlier in the year to meet winter demand. the report is to provide information to both the Beyond the winter, the weak economy and regulated community and the public on how the continued growth in onshore natural gas FERC Office of Enforcement has conducted its production are expected to keep prices relatively enforcement program over the preceding fiscal low. On an annual basis, the Henry Hub spot year. The Commission adds that in May 2008 it price, which averaged $7.17 per Mcf in 2007, is instructed Enforcement staff to produce an expected to average $9.25 per Mcf in 2008 and annual statistical report at the end of each fiscal $6.82 per Mcf in 2009, $1.35 per Mcf lower than year; that order came after the well-received the forecast 2009 price in last month’s Outlook. release of FERC’s first report on enforcement Electricity activities at the November 2007 conference on enforcement policies. Consumption: The latter half of this summer was much cooler than the same period last year, FERC provides the following highlights from the especially in the upper Midwest and Northeast report: regions. As a result, residential electricity Settlements consumption is expected to fall 0.5 percent this year. The economic slowdown will impact Enforcement staff entered into seven settlement consumption in all sectors during 2009, agreements approved by the Commission for a particularly the industrial sector, which is now total of $19.95 million in total civil penalties. In expected to decline by 2.5 percent next year in two of those seven settlements, Enforcement contrast to the 0.2-percent decline projected in staff required that the companies establish last month’s Outlook. stronger, more effective compliance programs. Prices: The recent drop in power generation fuel Self-Reporting costs has caused some utilities to reconsider the The report tracks a doubling of self-reports of steep price increases announced this past compliance violations by regulated entities, from summer. However, fuel costs still remain high, 31 in 2007 to 68 in 2008, reflecting improved and it is unlikely that electricity rates for most compliance and auditing procedures on the part customers will fall significantly in the near term. of the industry and FERC’s frequently stated U.S. residential electricity prices are expected to intention to reduce or even eliminate penalties if increase by about 6.5 percent in both 2008 and violations are self-reported. 2009. Of the 68 self-reports for 2008, none have yet November 7, 2008 resulted in imposition of civil penalties. Staff U.S. FERC Releases Its “2008 Report on closed 25 of them after a review and without Enforcement” opening an investigation; three more were closed without penalties after investigation. To The U.S, Federal Energy Regulatory provide guidance to the industry, the report Commission (“FERC” or “the Commission”) has provides short, unnamed narratives about the released its “2008 Report on Enforcement” self-report cases closed with no actions and the which was prepared by the Staff of the reasons why. Commission’s Office of Enforcement. In an accompanying press release, FERC suggests The majority of self-reports involved the that the report demonstrates commitment to Commission’s natural gas pipeline capacity strengthening compliance. The Commission also release requirements. Standards of Conduct - 66 - Cerise, Volume 7, Issue 11-November 2008 violations, which involved a significant number of as financial audits and 21 which, among other 2007’s self-reports, were down considerably for things, addressed open access transmission 2008. That likely was due to the pending nature tariffs (“OATT”), interconnection rules, gas of FERC’s rulemaking that made major changes tariffs, website posting, standards of conduct to the Standards of Conduct. That rulemaking and Commission regulations. was finalized Oct. 16, 2008. These audits resulted in 156 recommendations Investigations for corrective action, and included $1 million in recoveries from accounting and billing In 2008, enforcement staff opened 48 adjustments and $8.7 million in reductions to investigations, compared with 35 in 2007. Staff utility plant. Staff also required implementation of closed 22 investigations in 2008, eight of which compliance plans to ensure regulated entities had findings of violations, and seven of which adhere to FERC policies and procedures. Staff had no violation findings. Seven other tracks all audit recommendations to ensure they investigations were concluded through are ultimately implemented. settlement, while eight were closed without pursuit of enforcement actions. As with the self- INTERNATIONAL reporting cases, the report provides guidance to the industry on investigations, with short, Electricity unnamed narratives about investigations closed November 26, 2008 with no action, and why. European Commission Adopts Revised The report also notes there are emerging trends Proposal for a Directive Setting up a on the investigation side. Among them is an Community Framework for Nuclear Safety increase, to 20, in investigations involving allegations of market manipulation. The report Responding to concerns for Europe-wide also notes there were more referrals from the binding safety legislation for the operation of market monitoring units of the regional market nuclear power plants, the European Commission operators, with 15 such referrals in 2008 (“EC” or “the Commission”) has announced the compared to two in 2007. adoption of a revised proposal for a Directive setting up a Community framework for nuclear Another trend is the rise in the number of safety. The Commission says that the new investigations into allegations that entities Directive defines basic obligations and general violated FERC regulations which require market- principles for the safety of nuclear installations in based rate power sellers to provide accurate, the European Union (“EU”) while enhancing the factual and complete information in role of national regulatory bodies. The communications with the Commission and the announcement adds that, while Member States FERC-approved regional market operators. will have a common reference framework for Most of these investigations involve allegations their respective national nuclear safety systems, that entities have provided inaccurate they will retain the right to apply more stringent information to FERC-approved market operators rules if required. in connection with bidding, scheduling or unit availability. The EC explains that the general objective of the proposal is to achieve, maintain and And finally, the report notes that 2008 marked continuously improve nuclear safety and its the first time Enforcement staff has opened regulation in the European Community and to investigations into allegations of violation of the enhance the role of the regulatory bodies. The reliability standards which took effect in June proposal’s scope of application is the design, 2007. siting, construction, maintenance, operation and Audits decommissioning of nuclear installations, for which consideration of safety is required under Enforcement staff completed 60 audits of public the legislative and regulatory framework of the utilities and natural gas pipeline and storage Member State concerned. The right of each companies in 2008, 39 of which were classified Member State to use nuclear energy or not in its - 67 - Cerise, Volume 7, Issue 11-November 2008 energy mix is recognised and fully respected. DECC advises that, under the Climate Change Act 2008, the UK will introduce five -yearly The proposal – which replaces and updates the 'carbon budgets' outlining how emissions targets one tabled in September 2004 – is based on the will be met, bring in plans on corporate reporting obligations of the Convention on Nuclear Safety for businesses, and eliminate free single use (CNS) and the International Atomic Energy carrier bags. The Energy Act 2008 underpins the Agency (“IAEA”) Safety Fundamentals. The High development of new civil nuclear power, the Level Group on Nuclear Safety and Waste expansion of renewables, and paves the way for Management (“ENSREG”) will become the focal new technologies such as carbon capture and point of cooperation between regulators and will storage (“CCS”) and smart meters. The Planning contribute to the continuous improvement of Act 2008 addresses energy efficiency in homes nuclear safety requirements, especially with and simplifies planning permission for all large respect to new reactors. The proposal foresees energy infrastructure projects. that the Commission shall present a report to the Council on progress made with the The announcement also suggests that in the implementation of this Directive, accompanied, if future, with the Planning Bill given Royal Assent, appropriate, by legislative proposals. the Government can begin to create the faster, fairer planning system that is need to reduce the General county’s fossil fuel addiction and build up a new November 28, 2008 generation of renewable energy infrastructure UK Government Launches “ACT ON CO2” sources like wind power. People Power Challenge Initiative November 26, 2008 The UK Government’s Department of Energy European Commission Issues Green Paper and Climate Change (“DECC”) has announced Entitled “Towards a Secure, Sustainable and the nationwide launch of its “ACT ON CO2” Competitive European Energy Network” People Power challenge where householders and drivers are being challenged to save energy Noting that there is a need for massive and cut their carbon emissions. investments in new energy networks across the European Union (“EU”), the European DECC reports that the challenge will follow Commission (“EC” or “the Commission”) has volunteers from Newcastle, Portsmouth and issued a Green Paper entitled “Towards a Birmingham as they attempt to reduce the Secure, Sustainable and Competitive European energy they use in their daily lives, with a Energy Network”. dedicated website tracking their progress, sharing their tips and comparing success The Commission says that energy supplies between the three cities. DECC notes that the depend on complex and often costly 'People Power' drive gives a renewed focus on infrastructure projects and that such projects are the individual; it links up energy consumption in needed for a wide range of reasons: to maintain the home with emissions on the road and offers current networks, to make new networks which solutions for maintaining a low carbon lifestyle. can transport alternative forms of energy, such as renewable energy, to link up different parts of The announcement adds that the launch of the the EU so that they can share a larger pool of campaign marks the passing of three major energy resources, to make it possible for local pieces of legislation - the Climate Change, communities or even single households to Energy and Planning Bills - which were all contribute electricity to the grid and to improve expected to receive Royal Assent on November the import and transmission networks for oil and 26, 2008. The announcement says that together, gas. The Green Paper includes a number of the three Acts will help facilitate the UK's examples of major EU network projects which transition to a low-carbon economy, deliver a the EU could promote. long-term, secure energy supply, and enshrine in law ambitious targets to reduce greenhouse gas (“GHG”) emissions by 80 per cent.

- 68 - Cerise, Volume 7, Issue 11-November 2008 November 25, 2008 Ofgem's probe. Ofgem has set industry a deadline of 1 December to respond. U.K. Department of Energy and Climate Change Announces Enhancements to DECC also announced the extension of the Existing Program to Address Fuel Poverty in Renewables Obligation from its current end date Britain of 2027 to at least 2037. The Renewables Obligation is the main financial support scheme The U.K. Department of Energy and Climate for large-scale generators of renewable Change (“DECC”) has announced changes to its electricity. The extension will ensure that “Warm Front” program which is the investors can plan with confidence for the future Government's major fuel poverty programme, so that over the next decade the market will providing home heating and energy efficiency continue to deliver the needed renewables improvements to vulnerable and low income projects. households. The announcement says that the Government will provide additional funding of The announcement suggests that this extension £100 million, and £50 million of existing will complement the introduction of a feed-in allocation will be spent a year sooner than tariff for small scale electricity and a renewable planned. The announcement also notes that heat incentive to reward households and since its introduction in 2000 Warm Front has businesses which generate renewable energy helped 1.8 million households, saving them an on site. average of £300 a year on energy bills. November 4, 2008 DECC also advises that the new funding will see European Commission Launches New it spend £400 million this year on fuel poverty Citizens' Energy Forum (including £50 million in new funding), £374 million next year (including new funding of £50 On October 28, 2008, the European Union million and £50 million brought forward) and (“EU”) opened, in London, the first ever meeting £200 million in the final year. of a new Citizens' Energy Forum, a platform designed to implement and enforce consumer The announcement says that the new funding rights on the energy market across the EU. The means that an additional 60,000 homes can aim of the forum is to tackle consumer problems benefit. This is in addition to the £910 million in and propose practical solutions so that current funding the Government has secured from EU-wide consumer rights exist in practice, not energy companies to make homes warmer and only on paper, and to improve regulatory more energy efficient. conditions in the retail markets. The Forum In another move to put downward pressure on brings together national consumer prices, the Government says that it has asked organisations, industry, national regulators, and the British energy regulator, Office of Gas and government authorities to work on key issues Electricity markets (“Ofgem”) to publish quarterly such as switching energy suppliers, user-friendly reports over the coming year showing the billing, smart metering or protecting vulnerable relationship between wholesale prices, groups. estimated hedged wholesale costs and average EU Consumer Commissioner, Meglena Kuneva, retail prices for gas and electricity. The suggests that high energy prices are one of the Government suggests that this will make it top issues of concern to European citizens and clearer when companies are passing the that EU wide efforts are needed to raise benefits of downward price changes through to standards on a range of issues from clear billing, their consumers and will ensure transparency to smart metering and switching suppliers so over future price changes. The first report will be that consumers have real choice, can reduce in February. consumption and get value for money. She says DECC reiterates the government's readiness to that the EU needs to watch the energy market consult on legislation to tackle unfair pricing carefully to take action against possible abuses differentials, if there is not a speedy and and needs to put protection for vulnerable satisfactory resolution to key issues identified in consumers at the top of the political agenda in - 69 - Cerise, Volume 7, Issue 11-November 2008 what will be a tough winter ahead. EU will continue to watch energy markets, and comprehensive market monitoring consumer EU Energy Commissioner Andris Piebalgs adds data - gathered by the European Commission – that the inclusion of consumer representatives indicating how gas and electricity markets are for the first time in such a forum will introduce a delivering for consumers, will feed into the work new dynamic and provide a meaningful voice for of the Forum. This data will be published consumers in the energy market. annually as part of a broader market monitoring The announcement explains that the Citizens’ analysis "The Consumer Markets Scoreboard." Energy Forum has been launched to help Member States will also report to the Forum on consumers by working to enforce their existing their monitoring of household prices, switching EU-wide rights and to provide them with clear, rates or complaints, a new power given to them straightforward information on what choices are under the Third Energy Package. available to them when it comes to buying their gas and electricity. The Forum will develop recommendations aimed at better implementation and enforcement of the rights of energy consumers, and better electricity and gas retail markets. According to the announcement, topics which will be discussed in the Citizens Energy Forum include: • Billing: a gas or electricity bill is the simplest and best indicator of energy consumption for the average consumer; the bills must be simple, accurate and allow comparisons between providers; • Energy efficiency: labels on the efficiency of energy-using appliances must be simple and clear; • Switching suppliers: switching must be easy, swift and free of charge; information on how to switch must be clear and accessible; • Smart metering: new technologies can help improve accuracy of bills, easier understanding of how much you pay, and enable companies to better advise consumers according to their consumption profile. • Protecting vulnerable consumers: people who depend on energy to survive must be protected; the forum will address questions such as: how to avoid disconnection for people using heart and breathing support or undergoing dialysis? How to deal with people who are in financial difficulties and cannot pay their energy bills? National authorities, consumer organisations and industry should work out solutions to this issue. The announcement advises that, in parallel, the - 70 - Cerise, Volume 7, Issue 11-November 2008