CERISE MONTHLY NEWSLETTER Volume 8, Issue 5 May 2009 INSIDE THIS ISSUE “WHAT IS NEW” (MAY ALERTS) 1 CANADA CEPA Survey Reveals Pipeline Companies Generally Have Positive Relations with Landowners NEB Releases Decision on Detailed Route Hearing for Enbridge Pipelines Alberta Clipper Expansion Project Dawn Gateway Pipeline Files Application with NEB NEB Receives Application for Groundbirch Pipeline Project NEB Releases Pipeline Survey Results for May 2009 Canadian Hydropower Association Announces the Appointment of Jacob Irving as President NEB Reports Canadian Consumers will see Lower Energy Prices this Summer NEB Says Pipeline Companies will be Required to Set Aside Funds for Abandonment PwC Survey Indicates that Responding to Climate Change and Other Regulatory Challenges is Top Concern Faced by Canadian Utilities Sector Government of Canada Celebrates ENERGY STAR Award Recipients Direct Energy Releases Results of Canadian Survey as to Motivations Impacting Reductions in Energy Use NEB Report Says Energy, Environment and Economy Increasingly Interconnected Government of Canada Launches $1-Billion Clean Energy Fund Government of Canada Appoints New Members to the National Round Table on the Environment and the Economy Canada’s Modernized Energy Efficiency Act Receives Royal Assent Enbridge Issues $400 Million of Long Term Debt NEB Releases Strategic Plan for 2009-2012 Greenpeace and European Renewable Energy Council Release Report Detailing Green Energy Scenario for Canada Spectra Energy Shareholders Vote in Favour of Management's Recommendation to Declassify Board of Directors Government of Canada Passes Amendments to the Energy Efficiency Act in the House of Commons About The CERISE Newsletter Welcome to the Monthly CERISE Newsletter, a service provided to you as CERISE subscribers. This document contains a compilation of material from our website for the last month including the What’s New items, the most important decision summaries and the new articles. This information is provided in a PDF format that can be printed, providing a document that can be reviewed when you are away from your computer such as when you are travelling or waiting for an appointment. This will allow you to catch up on those items that you might have noticed when the alert came out but were unable to follow-up at the time. We trust you will find this service useful, and as always, would welcome any comments and suggestions you might have. 34 King Street E. Suite 620 Toronto, ON M5C 2X8 Tel: (416)348-8883 Fax: 416-348-9930 Email: [email protected]On the Web, visit us at: http://www.cerise.info
Transcript
C E R IS E M O N TH L Y N E W S L E T T E R
Volume 8, Issue 5 May 2009
I N S I DE T HI S I S S UE
“WHAT IS NEW” (MAY ALERTS)
1 CANADA
CEPA Survey Reveals Pipeline Companies Generally Have PositiveRelations with Landowners
NEB Releases Decision on Detailed Route Hearing for Enbridge PipelinesAlberta Clipper Expansion Project
Dawn Gateway Pipeline Files Application with NEB
NEB Receives Application for Groundbirch Pipeline Project
NEB Releases Pipeline Survey Results for May 2009
Canadian Hydropower Association Announces the Appointment of JacobIrving as President
NEB Reports Canadian Consumers will see Lower Energy Prices thisSummer
NEB Says Pipeline Companies will be Required to Set Aside Funds forAbandonment
PwC Survey Indicates that Responding to Climate Change and OtherRegulatory Challenges is Top Concern Faced by Canadian Utilities Sector
Government of Canada Celebrates ENERGY STAR Award Recipients
Direct Energy Releases Results of Canadian Survey as to MotivationsImpacting Reductions in Energy Use
NEB Report Says Energy, Environment and Economy IncreasinglyInterconnected
Government of Canada Launches $1-Billion Clean Energy Fund
Government of Canada Appoints New Members to the National RoundTable on the Environment and the Economy
Canada’s Modernized Energy Efficiency Act Receives Royal Assent
Enbridge Issues $400 Million of Long Term Debt
NEB Releases Strategic Plan for 2009-2012
Greenpeace and European Renewable Energy Council Release ReportDetailing Green Energy Scenario for Canada
Spectra Energy Shareholders Vote in Favour of Management'sRecommendation to Declassify Board of Directors
Government of Canada Passes Amendments to the Energy Efficiency Act inthe House of Commons
About The CERISENewsletter
Welcome to the MonthlyCERISE Newsletter, a serviceprovided to you as CERISEsubscribers. This documentcontains a compilation ofmaterial from our website forthe last month including theWhat’s New items, the mostimportant decision summariesand the new articles. Thisinformation is provided in aPDF format that can beprinted, providing a documentthat can be reviewed when youare away from your computersuch as when you aretravelling or waiting for anappointment. This will allowyou to catch up on those itemsthat you might have noticedwhen the alert came out butwere unable to follow-up at thetime. We trust you will find thisservice useful, and as always,would welcome any commentsand suggestions you mighthave.
AUC to Request Authorization to Set Rates on the Ventures Pipeline
AUC Conditionally Grants ATCO Energy Solutions and ATCO Pipelines aTemporary Exemption from Their Inter-Affiliate Code of Conduct
AUC Approves AltaGas Default Rate Tariff Gas Charge for May 2009
AUC Approves AltaGas Utilities Third Party Transportation Rate for May2009
AUC Approves Direct Energy Regulated Services - South Default Rate TariffGas Charge for May 2009
AUC Approves Direct Energy Regulated Services - North Default Rate TariffGas Charge for May 2009
AUC Grants Approval for ATCO Pipelines to Negotiate Phase I of Its 2010-2012 General Rate Application
AUC Approves a Service Area Boundary Enlargement in City of Red Deerfor ENMAX Power Corporation
Canadian Hydro Acquires Windrise Prospect From EarthFirst Canada
AUC Issues Two Orders With Respect to Alteration of Edgerton Substation899S
AUC Issues Two Orders With Respect to Alteration of the Michichi Creek802S Substation
AUC Approves Withdrawal of Central Alberta Rural ElectrificationAssociation Micro-Generation Application
AUC Approves ENMAX Application for Approval of Enlargement of itsElectricity Distribution System
AUC Approves Application by City of Red Deer for Approval of theEnlargement of its Electricity Distribution System
AUC Approves EPCOR Application Concerning True-Up of Its TransmissionCharge Deferral Account for the Period Ending December 31, 2008
AUC Approves Glacier Power Application for Development and Constructionof a 100-MW Hydraulic Power Plant in Dunvegan Area
EPCOR to Launch Independent Power Generation Business
AUC Approves ENMAX’s Regulated Rate Tariff Electricity Charges for May2009
AUC Approves EPCOR Energy Alberta’s Regulated Rate Tariff ElectricEnergy Charges for May 2009
AESO Appoints New Vice-President Market Services
AESO Announces the Resignation of VP Corporate Communications WayneSt. Amour
TransAlta Announces $200 Million of Senior Notes Due 2014
TransAlta Reports Changes in its Major Maintenance Plans for 2009 and2010
AltaLink to Issue $100 Million in Medium-Term Notes
TransAlta Renews Normal Course Issuer Bid Program
Alberta Government Appoints Eric Newell as Chair to Manage ProvincialClimate Change Fund
22 BRITISH COLUMBIA
BCUC Grants Terasen Gas (Whistler) Request and Reverses Finding in
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Order G-35-09 Concerning Deferral of Conversion Costs
BCUC Grants PNG Utilities Commission Act Exemption for Tomslake GasDistribution System
BCUC Posts Decision and Order Concerning Terasen Gas (Whistler)Application for Approval to Amend Rate Schedules Effective January 1,2009
BCUC Approves Negotiated Settlement Agreement With Respect to 2009Revenue Requirements for the PNG-West Service Area
BCUC Approves Negotiated Settlement for PNG (N.E.) Ltd 2009 RevenueRequirements
BCUC Reminds Gas Marketers to Submit Their Price Information AsRequired by Commission Order No. G-9-09
Terasen Applies to BCUC to Sell LNG as Transportation Fuel
BCUC Grants Terasen Gas Whistler Application for Reconsideration ofDecrease in Conversion Costs
BCUC Approves Establishment by BC Hydro of a Regulatory Account forHome Purchase Offer Program
BCUC Approves Amendments to BC Hydro Tariff With Respect toCustomers Purchasing Power to Replace Power They have Sold
BCUC Reaffirms Disputed Aspects of Decision Approving BC Hydro F2009and F2010 Revenue Requirements Application
FortisBC Announces $105 Million Debenture Offering
BCUC Announces Levies for Recovery of Commission Costs for the 2009/10Fiscal Year
FortisBC Announces $300 Million Medium Term Note Debenture Program
32 NEW BRUNSWICK
NBEUB Approves Revised Market-Based Formula for Enbridge Gas NewBrunswick
New Brunswick Government to Review FERC Draft Impact EnvironmentalImpact Study for Downeast LNG Terminal Project
NB EUB Releases Consultant’s Report on Proposed 3% Increase in Ratesfor NB Power Distribution and Customer Service Corporation
New Brunswick Board Issues Decision on NBSO Revenue Requirement for2009-2010
Government of Canada Provides Funding for Kent Hills Wind Farm in NewBrunswick
35 NEWFOUNDLAND
Newfoundland Power Files for Rate Changes on July 1, 2009 and January 1,2010
Nfld PUB Approves Nfld Hydro’s Recovery of Costs of Burning 0.7% SulphurContent No. 6 Fuel Through Rate Stabilization Plan
Nfld PUB Approves Nfld Power’s Recovery of Demand ManagementIncentive Account Balance as of March 31, 2009
Nfld PUB Approves Nfld Hydro Application to Install Cold ReheatCondensate Drains and High-Pressure Heater Trip on Unit 2 at TheHolyrood Thermal Generating Station
Government of Newfoundland and Labrador Provides Update on 2008-2009Home Heating Rebate Program
36 NORTHWEST TERRITORIES
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NWT PUB Approves Adjustments to Northland Utilities (NWT) Limited RiderA for the Communities of Trout Lake and Wekweti
NWT PUB Accepts Northwest Territories Power Corporation Proposal toLeave Rate Stabilization Fund Riders Unchanged
NWT PUB Releases Findings With Respect to Customer ComplaintsConcerning Abnormally High Usage
39 NOVA SCOTIA
Nova Scotia Government Proposes Changes to the Pipeline Act
NS Power Invests $1 million Towards the Dredging of Sydney Harbour
NS Power Files Biomass Proposal with NSUARB
NS Power Advises that it has No Plans for 2010 Rate Increase
Nova Scotia Board Dismisses Appeal by Shaw Resources of a Decision ofthe Dispute Resolution Officer
41 ONTARIO
OEB Limits Extension of Franchise Agreement Between Natural ResourceGas Limited and the Town of Aylmer to Three Years
OEB Issues Decision with Reasons in Hydro One Transmission Proceeding
OEB Issues Update to Chapter 2 of the Filing Requirements forTransmission and Distribution Applications
OEB Issues Rate Order on 2009 Electricity Distribution Rates for Hydro OneRemote Communities
OEB Issues Rate Order on 2009 Electricity Distribution Rates for NorthernOntario Wires
Red Rock First Nation and OPG Sign Settlement Agreement
Moose Cree First Nation in Ontario Ratifies Amisk-Oo-Skow ComprehensiveAgreement
OEB Issues Rate Order on 2009 Electricity Distribution Rates for TorontoHydro-Electricity System Limited
OEB Advises that May's Electricity Regulated Price Plan VarianceSettlement Factor Is -0.1995 Cents per kWh
OEB Releases Decision Concerning New Distribution Rates for Hydro OneNetworks Effective May 1, 2009
Burlington Hydro Officially Launches GridSmartCity Partnership Program
OEB Approves Sale of Great Lakes Power Limited Distribution Assets toAffiliate and Issuance of a Distribution Licence to GLPD
OEB Releases Decision Respecting Lakeland Power Distribution ApplicationConcerning Rates and Other Charges for Electricity Distribution EffectiveMay 1, 2009
Ontario IESO Posts Fixed Global Adjustment Rate for May 2009 DistributorBilling and Estimated Global Adjustment for April, 2009
OEB Issues Rate Orders on 2009 Electricity Distribution Rates for EnWinUtilities Ltd. and COLLUS Power Corp.
OEB Issues Decision and Order Concerning 2009 Cost of ServiceApplication Filed by Hydro One Remote Communities Inc
Ontario Government Introduces Enabling Cap-And-Trade Legislation
Dan Santerre Appointed Director of Hydro One Remote Communities
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Ontario Announces Enhancements to Home Energy Savings Program
Toronto Hydro First Canadian Utility to Test Google PowerMeter Technology
Union Gas Offers Businesses New Incentives for Energy SavingTechnologies
Chatham-Kent Energy Announces Changes in the Role of President andCEO
Direct Energy Conservation Pilot Program Demonstrates that ConsumersCan Save up to 44 per cent Through Smart Home Technology
Government of Ontario Helps Schools Invest in Green Technology
OEB Grants Hydro One Networks Leave to Sell Certain Distribution Assetsto Haldimand County Hydro
OEB Varies its Decision in Respect of OPG’s Payments and Establishes aTax Loss Variance Account
Ontario Government to Introduce Legislation to Allow Workers From OtherProvinces and Territories to Maintain Certification in Ontario
Hydro Ottawa Credit Rating Upgraded by Dominion Bond Rating Service
OPG Appoints Tom Mitchell as President and CEO
Bruce Power Announces Appointment of Murray Elston as its VicePresident, Corporate Affairs
60 QUEBEC
Régie Approves Gazifère Application to Decouple Gas Transmission Rates
FERC Approves Funding Plan for Major International Transmission ProjectLinking Hydro-Quebec with ISO New England
NERC, NPCC and Régie Sign New Agreement Concerning the Reliability ofthe Bulk Power System in Québec
Régie Temporarily Approves HQD’s Request for New Deferral Account
Québec Government Launches the Romaine Hydroelectric Complex – theLargest Construction Project in Canada
Government of Québec Raises Maximum Price for Aboriginal andCommunity Wind Power Projects
Québec Government Announces Inauguration of New Hydro-QuébecTransÉnergie Facility for the Refurbishment of Transmission SystemBreakers
Hydro-Québec Launches Call for Tenders for 500 MW of Aboriginal andCommunity Projects Wind Power Produced in Québec
64 SASKATCHEWAN
SaskPower Undertakes Programs to Help Rural Residents Reduce Risk ofWorking Around Power Lines and Improve Productivity of FarmingOperations
Saskatchewan Government Provides More Financial Support forGeothermal Systems
65 UNITED STATES OF AMERICA
AGA Releases May 29, 2009 Edition of its "Natural Gas Market Indicators"
AGA Releases May 12, 2009 Edition of its “Natural Gas Market Indicators”
AGA Releases April 30, 2009 Edition of its "Natural Gas Market Indicators"
U.S. FERC Staff Release Final EIS for the Jordan Cove LNG Terminal andPacific Connector Gas Pipeline Project
NYISO Issues 2009 Comprehensive Reliability Plan
NYISO Anticipates Sufficient Electricity Supply for Summer 2009
CAISO Reports Healthy Energy Supply and Demand Forecast for Summer2009
NERC Says Reduced Electricity Demand Bolsters Reserve Marginsthroughout North America for the Coming Summer
NYISO Advises That Wholesale Electricity Prices Have Dropped Again
PJM Says that Region Ready for Hot Weather Power Demand
NERC’s Board of Trustees Approves Eight Revised Cyber SecurityStandards
California ISO Updates Five-Year Strategic Plan
U.S. EIA Posts May 2009 Edition of Its “Short-Term Energy Outlook”
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CEPA Survey Reveals Pipeline CompaniesGenerally Have Positive Relations withLandowners
The Canadian Energy Pipeline Association(“CEPA”) has announced that a surveyconducted on its behalf by Ipsos Reid indicatesthat, contrary to allegations from a small minorityof landowners and community activists, 83 percent of landowners have a favourable opinion ofthe energy pipeline company (companies)passing through their land.
CEPA says that, as part of the research, IpsosReid collected data from 884 landowners, thatcontacts were selected on a random basis andthat the survey provides detailed information onthe attitudes landowners have with CEPAmember companies and their pipelines.
CEPA reports that, overall, landowners providedvery high favourability ratings of the pipelinecompanies operating on their land. Surveyresults report that 81 per cent of landowners feelthe pipeline sector is doing a good job when itcomes to public safety and protection. Withregards to environmental matters, three quartersof landowners think pipeline companies do agood job at protecting the surroundings.
Other key findings include: 94 per cent oflandowners state that the pipeline industry isvery important to the Canadian economy; 83 percent of individuals have never had a problemwith a pipeline company and believe they arekept well informed about the physical locationsof pipelines.
May 15, 2009
NEB Releases Decision on Detailed RouteHearing for Enbridge Pipelines AlbertaClipper Expansion Project
In response to an application dated May 30,
2007 and further to its Reasons for Decision inOH-4-2007, the National Energy Board (“NEB”or “the Board”) has issued its Reasons forDecision in Docket # MH-3-2008 and has givenits approval for a detailed route for EnbridgePipelines Inc. (“Enbridge”) Alberta ClipperExpansion Project. The Board ruled that, subjectto certain provisions to accommodate theconcerns of landowners, the detailed routeproposed by Enbridge was the best possibleRoute.
The NEB notes that, on February 22, 2008, itissued the OH-4-2007 Reasons for Decisionapproving the Clipper Project and recommendedto the Governor in Council that a Certificate ofPublic Convenience and Necessity (“CPCN”) beissued subject to certain conditions. The Boardsays that Certificate OC-54 in respect of theClipper Project was approved by the Governor inCouncil on May 8, 2008.
The NEB explains that the Clipper Projectconsists of 1,078 kilometres (“km”) of new 914millimetre (36 inch) outside diameter oil pipelineand associated facilities between Enbridge'sHardisty, Alberta terminal and theCanada/United States border near Gretna,Manitoba. The associated facilities include newpump units at eight existing Enbridge pumpstations, one new pump station near Regina,Saskatchewan and receipt tankage, boosterpump units and other terminalling facilities at theHardisty terminal. The targeted in-service datefor the Clipper Project is July 1, 2010.
Approximately 89% of the Clipper pipeline isrouted alongside and contiguous to the existingEnbridge Mainline system (“Mainline”). Thisreflects Enbridge’s primary routing criterion ofparalleling the Mainline right-of-way (“RoW”) inorder to minimize the environmental and socio-economic impacts of the pipeline by minimizingboth the overall length of the pipeline and thelength of new RoW, which in turn minimizes thetotal area disturbed by the pipeline.
The NEB reports that it received 28 Letters of
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Opposition to the proposed Clipper detailedroute. Of these objections, 16 weresubsequently withdrawn and five were found notto meet the requirements of subsections 34(3)and (4) of the National Energy Board Act (“theAct”). The Board heard the remaining objectionsin three separate hearing files, as follows:
1. Douglas James Carlson oppositionrelating to Tract 2394.08 (SE 13-27-7W.3M).
2. Lyle Francis Denton, Florence MarionDenton, Westward Enterprises Inc.oppositions relating to Tract 2690.1(SW 35-16-20 W.2M) and JohnWesley Denton and Louis AlvinDenton oppositions to Tracts 2691.1and 2692.1 (SE 35-16-20 W.2M).
3. Dalerie Dawn Peterson oppositionrelating to Tract 2686.1 (LSD 1, 33-16-20 W.2M).
May 14, 2009
Dawn Gateway Pipeline Files Applicationwith NEB
Spectra Energy Corp and DTE PipelineCompany have announced that they have filedan application with the National Energy Board(“NEB” or “the Board”) seeking approval to ownand operate the Dawn Gateway Pipeline - aproposed new international pipeline betweenMichigan Consolidated Gas Company’s BelleRiver facility in Michigan and Union GasLimited’s Dawn Hub in Ontario. The proponentssay that this new international pipeline will play akey role in connecting Michigan storage andnew supplies coming into Michigan with theDawn Hub in Ontario and subsequently withdownstream markets in eastern Canada and theU.S. Northeast.
The announcement notes that the applicationfollows a successful open season conducted inthe fall of 2008 to gauge market interest in thepipeline. The open season resulted in bindingagreements for the sale of 280,000 Dth/d orapproximately 80 percent of the availablecapacity, and clearly demonstrated marketsupport for the project.
Dawn Gateway is a new joint venture owned bysubsidiaries of Spectra Energy Corp and DTE
Energy. The proposed pipeline project will haveinitial firm transportation capacity ofapproximately 360,000 Dth/d, will utilize acombination of new and existing pipelines and isscheduled to be in service for November 1,2010.
May 14, 2009
NEB Receives Application for GroundbirchPipeline Project
The National Energy Board (“NEB” or “theBoard”) has announced that, on April 30, 2009, itreceived an application from NOVA GasTransmission Ltd. (“NGTL”) for a certificate toconstruct and operate the Groundbirch Pipeline,which would connect the TransCanada AlbertaSystem to a source of sweet natural gas supplyfrom northeast British Columbia.
The Board reports that, if approved, theGroundbirch Pipeline would consist ofapproximately 77 km of 914-mm outsidediameter (or 36 in.) pipe and related facilities.The pipeline is proposed to extend from a newinterconnection on the Gordondale Lateral to anew meter station in the Groundbirch area innortheast B.C. (approximately 37 km west-northwest of Dawson Creek). The pipeline wouldhave the capability of transporting approximately46.9 106m3 (1.66 billion cubic feet) of naturalgas per day.
In total, about 7.5 km of the proposed extensionwould be built alongside existing pipeline,railway, and public highway rights-of-way(“ROW”). The remainder, or about 69.5 km, isprojected to be installed along new ROW.
The proposed Groundbirch Pipeline would be anextension of the TransCanada Alberta System,which is already regulated by the NEB. TheSystem comprises approximately 23 700 km ofpipeline and associated compression and otherfacilities located in Alberta.
The Board advises that it will announceprocedures for dealing with this application at alater date.
May 14, 2009
NEB Releases Pipeline Survey Results forMay 2009
The National Energy Board (“NEB” or “the
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Board”) has issued the results from its fifthannual survey which it conducts as a means toobtain direct feedback from the shippers ofmajor NEB-regulated pipeline companies on thequality of service provided by those pipelines.The Survey is also used to obtain feedback fromshippers on the Board's regulatory performancewith respect to tolls and tariffs.
The OEB reports that to conduct this year'sSurvey, it again used Inquisite, a web-basedsurvey tool, which was sent to shippers directlyvia e-mail under the header of the NationalEnergy Board. For each Survey received,shippers complete one response which reflectstheir company's corporate views on the servicesprovided by the pipeline being surveyed and onthe services provided by the Board.
The announcement advises that this year thereport has been expanded. While it is still asummary of the results in aggregate for all thecompanies surveyed, the aggregate resultsinclude the industry average and distribution ofresponses for each question in the Survey aswell as a five-year comparison of the aggregateresults for each question and a summary ofmajor themes. In addition, the Board will provideeach pipeline company and its shippers withdetailed company specific results including thepipeline company's average rating anddistribution of responses for each question aswell as the verbatim comments received fromshippers, with the names of the respondentsexcluded.
The NEB notes that this year, the Surveyparticipation rate increased. The Board says thatthe Survey was sent to 200 fewer shippers thanlast year as this year pipeline companies onlyincluded active shippers on their contactinformation lists. The overall response rateincreased to 38 per cent, up from last year's rateof 30 per cent.
The NEB also reports that overall satisfactionwith the pipeline services has increased sincethe last survey. The increase in satisfactionranges from one per cent (1%) to ten per cent(10%). The largest increase in satisfaction wasfound in question 1: "How satisfied are you withthe physical reliability of the pipeline company'soperations?" Four questions indicated adecrease in satisfaction and this was within a
range of a half per cent (1/2%) to one per cent(1%). The largest decrease was on thequestions regarding the Board framework andprocesses.
General
May 29, 2009
Canadian Hydropower AssociationAnnounces the Appointment of Jacob Irvingas President
The Board of Directors of the CanadianHydropower Association (“CHA” or “theAssociation”) has announced the appointment ofMr. Jacob Irving as President. The CHA saysMr. Irving has over 10 years of experience as anassociation manager and government relationsspecialist. He holds a BSSc. in Political Sciencefrom the University of Ottawa.
According to the CHA, most recently, Mr. Irvingwas Executive Director of the Oil SandsDevelopers Group (“OSDG”), where he acted asspokesperson for the association. He conductedmunicipal, provincial and federal governmentrelations, aboriginal relations, and otherstakeholder relations. Mr. Irving also worked ingovernment and in the petroleum energy sectorin Canada and overseas. From 1995 to 2000 hewas successively: Information Officer in theLibrary of Parliament in Ottawa, ProjectManager for the Western Cape ProvincialGovernment in Cape Town, South Africa andProject Manager with Foreign Affairs andInternational Trade/Industry Canada. From 2000until 2006 Mr. Irving managed government andpublic affairs in the private sector, first for BPCanada and later for Devon CanadaCorporation.
The CHA thanked outgoing president PierreFortin for his 10 years of service, and adds thathe will be serving as Special Advisor to theBoard of Directors until his departure at the endof June.
May 28, 2009
NEB Reports Canadian Consumers will seeLower Energy Prices this Summer
The National Energy Board (“NEB” or “theBoard”) has released its Summer Outlook inwhich it forecasted that Canadian consumers
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will enjoy lower energy prices this summer, asignificantly different energy picture from the onereleased last May.
The NEB reports that this time last year energyprices were on the rise, with crude oil hitting arecord high of US $147 per barrel, while naturalgas peaked at US $13/MMBtu in July. Howeverthe global economic downturn led to a dramaticdrop in prices over the fall and winter.
The Board forecasts that the current economicsituation, combined with the high inventories ofboth oil and natural gas, will continue to putdownward pressure on energy prices headinginto summer. The NEB is predicting crude oil totrade in the US $50 to $60 per barrel range, withnatural gas prices to average between US $3.20and $4.20/MMBtu over the summer.
The Board suggests that Canadians will find thatthe price of natural gas will not go as high as itdid last summer; however, companies mayrespond to the low prices by further cuttingproduction, which would mean a tighter energymarket in the medium to long term.
On the electricity side, new power generationcame on-line in several jurisdictions andtransmission capacity was expanded betweenOntario and Quebec and between NewBrunswick and the U.S. in 2008. As a result,electricity supply is projected to be adequate tomeet summer demand.
The Board reports that Canadian-Americanelectricity trade volumes reached record levelsin the summer of 2008, and are expected toremain strong this summer. Weaker economicconditions, however, may mean less demandfrom the industrial sector in the U.S. andCanada.
May 27, 2009
NEB Says Pipeline Companies will beRequired to Set Aside Funds forAbandonment
The National Energy Board (“NEB” or “theBoard”) has announced the adoption of a reporton the financial issues of pipeline abandonmentwhich will require companies to set aside fundsto cover future abandonment costs.
The Board advises that the Report and
Recommendations follows a January 2009hearing held by three NEB Board Members intothe financial matters of pipeline abandonment.By the Board's adoption of the report, all pipelinecompanies regulated under the NEB Act will berequired to comply with the report's frameworkand action plan. This calls for companies tosubmit estimates of funds needed forabandonment as well as proposals for how theywill collect and set aside those funds.
The Board advises that it will host a technicalconference this fall to discuss the assumptionswhich companies may use to help themdetermine the abandonment costs. The NEB'sgoal is to have companies begin setting asidefunds for abandonment no later than the end ofMay 2014. It is the Board's view that no pipelinesystem is likely to be abandoned in theforeseeable future and therefore there is time toensure the funding framework is established andimplemented in a manner that considers allparties' interests.
The NEB notes that the hearing and the reportare part of the Board's ongoing efforts toimprove understanding and dialogue betweencompanies, landowners and the Board throughthe Land Matters Consultation Initiative (“LMCI”).
May 27, 2009
PwC Survey Indicates that Responding toClimate Change and Other RegulatoryChallenges is Top Concern Faced byCanadian Utilities Sector
PricewaterhouseCoopers (“PwC”) reports that anew global survey from shows that 88% ofCanadian utility companies believe thatgreenhouse gas (“GHG”) regulations are thegreatest issue facing the industry in the next fiveyears. PwC further reports that
75% of Canadian respondents believe thatmajor sector issues include: regulatorychanges and development, the ageingworkforce, lack of transmission capacity andpressures to replace ageing assets.
Half of Canadian respondents report thatdiminished access to capital is having asignificant or major impact on their planningover the coming 12 months.
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Nearly two-thirds (63%) of Canadianrespondents viewed credit constraints as asignificant issue for the sector; however, utilitycompany executives expect these constraintsto improve as current financial conditionsease.
Asked if the economic recession would slowdown responses to climate change, 79% ofglobal respondents felt it would, with two-thirds of the 79% saying it would have a highor very high slowdown impact.
PwC says that Canadian utility companies reportthat the issue of managing GHGs is alreadyhaving a considerable impact on theiroperations, particularly on capital constructionplans and costs (63%). Most companies arereviewing their generation mix and only aquarter say that GHGs are having little impacton the fuel mix.
According to PwC, in Canada, regulatoryconcerns are regionally specific. In Ontario,concerns about the size and scale of investmentrequired in generation and transmissiondominate, with regulatory delays adding to costconcerns. In Alberta, much of the focus is ondelays in getting major transmission projectsmoving, in particular a new transmission linebetween Calgary and Edmonton.
Utility companies in the survey emphasize theimportance of greater clarity of climate changepolicy but express concern that the economicrecession is undermining the chances of aneffective response to climate change.
PwC explains that these findings are part of the“A World Beyond Recession, Utilities GlobalSurvey 2009”, which goes to the heart ofboardroom thinking of 65 leading powercompanies in 39 countries around the world.Key results of the global survey include:
Infrastructure investment needs remain high -the development of new generation capacityand the renewal of existing generation plantsis a priority area for most companies. 83% ofsurvey respondents say their companies areseeking to make medium to large investmentin new generation and 79% are seeking to dolikewise in transmission.
Worries about capital shortages arewidespread - there is considerable doubt onwhether investment will come forward in atimely manner to keep pace with futuredemand for power and climate change targets.Two thirds (67%) of survey respondents reportthat a shortage of capital is having a high orvery high impact on their activities. Two thirdscite problems in securing finance as a mediumor high barrier to project development.
Economic incentives needed to boostrenewables in the mix – nearly 60% ofrespondents feel that their renewable energyinvestment programs are being affected by thelack of clarity from governments on renewableenergy targets and financial support.Following a period of record high powerprices, only 28% of respondents believe thatunsubsidized renewable power can competecommercially against fossil fuel generation.
Worries that climate change action could slip -utility companies in the survey emphasize theimportance of greater clarity of climate changepolicy from governments but express concernthat the economic recession is underminingthe chances of an effective response toclimate change. 79% felt the economicrecession would slow down responses toclimate change with two thirds of these sayingit would have a high or very high slowdownimpact.
PwC says that, in the coming decade,technological innovation is seen as having themost new impact on energy efficiency, solarpower, combined heat and power (“CHP”),distributed generation and combustiblerenewable generation. Carbon capture andstorage (“CCS”) will be essential for the sector'slong-term contribution to the mitigation of climatechange and 83% of respondents from utilitycompanies in Europe, for example, report thattheir companies are evaluating CCS projects.
PwC reports that the current and futureimportance of technology is such that powerutility companies in the survey point toequipment and technology companies as aneven more significant competitive threat thandirect competition in the retail market by otherutility company rivals.
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PwC goes on to advise that, as well asinvestment in CCS, the survey highlights someof the major moves that companies are making:
moving upstream to secure gas supply andinvest in liquefied natural gas (“LNG”) supplychains;
horizontal expansion to increase presence inthe renewable energy or nuclear power field;
developing new technological capabilities toexploit new sources of power generation;
exploring a more flexible mix of distributedenergy supply and smart grid capabilities.
May 26, 2009
Government of Canada Celebrates ENERGYSTAR Award Recipients
The Natural Resources Canada (“NRCan”) hasannounced that it has awarded ten Canadianorganizations with the 2009 ENERGY STARMarket Transformation Awards, recognizing theiroutstanding efforts promoting energy-efficientproducts. These awards are part of additionalecoENERGY Efficiency awards recognizing bestpractices and innovation in energy efficiencyacross Canada.
The following are the ten ENERGY STAR 2009Market Transformation Award Winners:
1. Whirlpool Canada
2. Sears Canada Inc.
3. British Columbia Hydro and PowerAuthority (“BC Hydro”)
4. London Hydro
5. Modern
6. JELD-WEN Windows & Doors
7. One Change
8. BAZZ Inc.
9. British Columbia Ministry of Energy,Mines and Petroleum Resources
10.Hydro-Québec
May 26, 2009
Direct Energy Releases Results of CanadianSurvey as to Motivations ImpactingReductions in Energy Use
According to a recent survey of Canadianscommissioned by Direct Energy, almost half ofthe respondents (49%) have had adisagreement about the temperature in theirhome with almost twice as many Canadians(86%) saying they are motivated to make theirhomes energy efficient in order to save moneycompared to those (49%) who do so to helpsave the planet.
However, that motivation is not necessarilymatched by actions such as properly regulatingthe household temperature. In fact, Canadiansare more inclined to just leave the room (49%)or open a window (59%) than actually moderatethe temperature level when there is a disputeabout the temperature inside their homes.
Additional highlights of the survey include:
Younger age groups (18-34) are more likely tobe motivated to save the planet (66%), yetthey are the biggest offenders (56%) when itcomes to keeping the air conditioner on forhalf the day or more.
When it comes to thermo-spats, Quebecresidents are the least prone (43%), whilethose living in the Prairies (63%) are the mostlikely.
Residents of Alberta and Ontario aresimilar in how many of them disagreewith household members about thetemperature inside their home. 55% ofAlberta residents get into suchdisagreements, as do 46% ofOntarians
Households earning more than$100,000 a year report the highestrate (59%) of disagreements
Women are both more likely to lettheir thermo-spat escalate into anargument than men (23% vs. 17%)and more likely to opt to add orremove layers of clothing (82% vs.76%) or simply open a window (63%vs. 55%) rather than get into a
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disagreement about the temperature.
Residents of Manitoba and Saskatchewanhave the highest rates (12%) of leaving airconditioners on 100% of the time during thesummer.
The online survey was conducted by AngusReid Strategies on behalf of Direct Energy fromApril 23 to April 24, 2009. The survey wasconducted among a randomly-selected,representative sample of 1,006 adult Canadiansaged 18 and over who are members of theAngus Reid Forum online panel. The margin oferror for the overall sample is +/- 3.1%, 19 timesout of 20.
In its Canadian Energy Overview 2008 report,the National Energy Board (“NEB” or “theBoard”) says that the convergence of energyefficiency and conservation with renewableenergy policies continued to be a strong trend in2008. According to the Board, while theeconomy garnered significant headlines in thelatter half of 2008, the environment and theincreasing momentum on climate changeinitiatives were key influences on the Canadianenergy sector throughout the entire year.
The NEB says that several provincial andfederal policies aimed at energy demand wereproposed early in 2008 including the expansionof clean energy and renewable energystrategies and new standards for consumergoods. A proposed design of a comprehensiveregional cap-and-trade program to reducegreenhouse gases(“GHG”) was introduced bythe Western Climate Initiative (“WCI”). By theend of 2008, all provinces had some legislationfor climate change initiatives. Many of these newgovernment programs and policies shouldimpact consumer energy demand trends in thenext few years as Canadians factorenvironmental costs into purchasing decisions.
The Board notes that "going green" was also acommon theme in electricity generation.Investment in wind power has increased theenergy produced from this source by 265 percent from 2004. In 2008, Canada produced
about one per cent of Canada's total electricitydemand through wind. Canada's capacity roseby 34 per cent from 2007 levels making Canada16th in the world for wind generating capacity.Ontario led all other provinces with 782Megawatt (“MW”) of installed capacity followedby Quebec (532 MW) and Alberta (524 MW).Many wind projects that are currently underconstruction will soon be fully commissionedmeaning 2009 could exceed 2008 installationlevels.
The Board reports that the price of oil andnatural gas reached new highs only to falldramatically in the latter half of 2008. Due to thelow price and volatile financial markets, severalof the oil sands projects which earlier in the yearhad been promising, were either postponed orcancelled. Until the price of crude oil reboundsto levels which offer economic incentives,increases in production volumes and refiningcapacity may remain in doubt.
The NEB says that natural gas prices fell in thesecond half of 2008 due to the emergence ofunconventional resource plays in the UnitedStates. This created a supply glut which addedto the economic slowdown and reduceddemand. While natural gas production andexports declined, net export revenues were upsubstantially due to higher prices.
According to the NEB, approximately 16,300 oiland gas wells were drilled in 2008, which isabout 10 per cent below 2007 numbers. Albertatook the brunt of the decline with only 11,569wells drilled compared to the 14,001 in 2007.Despite the drop in well numbers, activity insome areas of the country increased.Saskatchewan saw an increase of 22 per centfrom 3,202 to 3,898 wells. Records for provincialrevenue generated by the sale of petroleumrights were set in British Columbia with theprovince earning $2.7 billion and Saskatchewanwith $1.1 billion.
May 21, 2009
Government of Canada Launches $1-BillionClean Energy Fund
Natural Resources Canada (“NRCan”) hasannounced the launch of the $1-billion CleanEnergy Fund including the investment of $850million in technology development and
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demonstration. This includes $650 million forlarge-scale carbon capture and storage (“CCS”)demonstration projects and $200 million forsmaller-scale demonstration projects ofrenewable and alternative energy technologies.
The announcement says that there will also be a$150-million research component, which willfund initiatives ranging from basic research topre-demonstration pilot projects of technologiesranging from next generation renewable andcleaner energy systems to new technologies toaddress environmental challenges in the oilsands such as water use and tailings. TheGovernment has issued an initial request forproposals for the small-scale demonstrationcomponent of the program.
NRCan says that in addition to advancing keyclean energy technologies in Canada,investments through the Clean Energy Fund willalso support Canada's work with the UnitedStates in building a cleaner energy economy forNorth America through the Canada–U.S. CleanEnergy Dialogue.
May 20, 2009
Government of Canada Appoints NewMembers to the National Round Table on theEnvironment and the Economy
Natural Resources Canada (“NRCan”) hasannounced the appointment of Ms. DianneCunningham, Mr. John V. Hachey, Mr. FranklinHoltforster and Ms. Leah C. Lawrence to theNational Round Table on the Environment andthe Economy (“NRTEE”) for a period of threeyears.
The roundtable undertakes research based onsound knowledge, advises governments andstakeholders on key issues and promotes bestpractices on sustainable development. Resultsof its research and discussions are disseminatedboth nationally and internationally.
May 19, 2009
Canada’s Modernized Energy Efficiency ActReceives Royal Assent
The Government of Canada has announced thatBill S-3, an act to amend the Energy EfficiencyAct (‘the Act”), is receiving Royal Assent on May15, 2009, and advises that the amendments to
the Act allow for energy efficiency standards tobe set for products which affect energyconsumption, including windows and doors, aswell as thermostats and other energy-systemcontrol devices.
The announcement explains that the amendedAct also allows for the development of futurestandards to reduce the amount of energyconsumed by televisions, microwaves, CDplayers and computers even when they areturned off.
May 14, 2009
Enbridge Issues $400 Million of Long TermDebt
Enbridge Inc. (“Enbridge“) has announced thecompletion of a $400 million 7-year term debtissuance in the Canadian debt capital markets.The issuance yields 5.18% and was placed withover 60 institutional investors.
Enbridge notes that the large over subscriptionto this offering further illustrates the ability of thecompany and its subsidiaries to successfullycomplete debt issuances at favourable termsand highlights investor confidence in Enbridge'sfinancial strength and growth outlook. Thecompany adds that it continues to enjoy stronginvestment grade credit ratings, supported by asound balance sheet.
Enbridge reports that it has a very substantialliquidity surplus, which provides it withconsiderable flexibility to take advantage ofattractive new opportunities. The announcementgoes on to say that Enbridge continues to carrya significant amount of unutilized credit facilities.After completing this issuance, committed creditfacilities for Enbridge and its subsidiaries totalled$6.7 billion of which $2.8 billion is either drawnor is allocated to backstop commercial paperprograms. The remaining $3.9 billion ofunutilized capacity is available to provide bridgefunding for capital programs prior to putting inplace permanent financing, or to accommodateadditional investment opportunities.
May 14, 2009
NEB Releases Strategic Plan for 2009-2012
The National Energy Board (“NEB” or “theBoard”) has released its Strategic Plan for 2009
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through 2012. The NEB notes that it reviews andupdates its Strategic Plan annually, with inputfrom its stakeholders.
The Board says that this Strategic Plan allows itto continue to meet its commitment of promotingsafety and security, environmental protectionand efficient energy infrastructure and marketsin the regulation of pipelines, energydevelopment and trade. The NEB gives as anexample its desire to continue working withindustry to ensure that oil and gas pipelinecompanies have programs and managementsystems to maintain and improve safety. TheBoard adds that it will be hosting a ComplianceForum in May 2009 to share key findings andtrends with stakeholders to promote continualimprovement.
The NEB notes that an important initiative fromlast year's Strategic Plan, its Land MattersConsultation Initiative (“LMCI”), is nearingcompletion. The Board says that among theresults of this initiative, through which it heardinput from landowners, industry and otherstakeholders across the country in 2008, is thatthe NEB now has a new Goal 4 in its StrategicPlan. The NEB goes on to say that, in thedevelopment of any energy infrastructureproject, the Board holds the expectation that the“rights and interests of those affected by NEB-regulated facilities and activities are respected”.The new Goal enables clarity and a systematicapproach to achieving this expected result for allinvolved.
May 12, 2009
Greenpeace and European RenewableEnergy Council Release Report DetailingGreen Energy Scenario for Canada
Greenpeace and the European RenewableEnergy Council (“EREC”) have announced therelease of a report entitled “Energy Revolution:A Sustainable Canada Energy Outlook” whichconcludes that available green energytechnology, if implemented immediately, canreduce carbon dioxide (“CO2”) emissions fromthe Canadian energy sector 45 per cent below1990 levels by 2020, and 82 per cent by 2050.
According to the announcement, the report,prepared by Greenpeace and based onmodeling by the German Aerospace Agency,
takes a comprehensive look at the latest inCanada-specific solutions for reducinggreenhouse gas (“GHG”) emissions whilemaintaining economic growth for the newcentury - without coal or nuclear power. Thereport concludes:
Efficiency measures would save Canadians$5.9 billion on their electricity bills in 2020;
By 2020, about 25 per cent of Canada’sprimary energy demand could be supplied byrenewable energy, rising to about 58 per centby 2050. Today, about 75 per cent ofCanada’s primary energy supply comes fromfossil fuels, and only 15 per cent fromrenewables;
Aggressive energy efficiency measures wouldreduce primary energy demand 50 per cent by2050;
Increased use of combined heat and power(“CHP”) would dramatically improve theefficiency of natural gas in the transition to asustainable energy system;
By 2020, over 80 per cent of electricity wouldbe produced from renewable energy sources,and by 2050, over 90 per cent;
Renewable energy would increase in finalenergy demand from 17 per cent in 2005 to 31per cent in 2020 and to 71 per cent in 2050;and
There would be aggressive efficiencyimprovements in the transport sector, withelectric vehicles playing an increasinglyimportant role from 2020 onwards.
May 11, 2009
Spectra Energy Shareholders Vote in Favourof Management's Recommendation toDeclassify Board of Directors
Spectra Energy Corp (“Spectra Energy”) hasannounced that, at the company’s annualmeeting held on May 7, 2009, its shareholdersvoted on and approved an amendment to thecompany’s Certificate of Incorporation toeliminate the classified board of directorsstructure.
According to the announcement, the proposedamendment, which was recently recommended
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by management and approved by thecompany’s board of directors, enhancescorporate governance policies and practices.The declassified board will become effectiveupon the filing of an amendment to thecompany’s Certificate of Incorporation with theDelaware Secretary of State. In future elections,directors will be elected to terms which expireeach year at the annual meeting ofshareholders.
Spectra Energy advises that shareholders alsoelected Gregory L. Ebel, Peter B. Hamilton andMichael E.J. Phelps as directors whose termswill expire in 2010, and ratified the selection ofDeloitte & Touche LLP as the company’sindependent registered public accounting firmfor the fiscal year ended December 31, 2009.
May 7, 2009
Government of Canada Passes Amendmentsto the Energy Efficiency Act in the House ofCommons
The Government of Canada has announced thatnew legislation has passed in the House ofCommons, allowing amendments to the EnergyEfficiency Act. The announcement says that withthis legislation, the federal government will havethe legislative authority to introducecomprehensive standards to regulate theamount of standby power consumed by manyproducts, such as computers, battery chargers,CD players and televisions, when they are not inuse. The announcement says that regulatingstandby power will reduce the averagehousehold’s electricity consumption by three tofive percent.
The announcement notes that theseamendments also allow for energy-efficiencystandards to be established for additionalproducts which affect energy consumption,including windows and doors, as well asthermostats and other energy-system controldevices.
A L B E R T A
Natural Gas
May 21, 2009
AUC to Request Authorization to Set Rateson the Ventures Pipeline
In response to Application No. 1453788originally filed by Suncor Energy Inc. (“Suncor”)on March 23, 2006, and further to Decision2006-105 which was upheld on appeal by theAlberta Court of Appeal in a Decision renderedon February 28, 2008, the Alberta UtilitiesCommission (“AUC” or “the Commission”) hasissued Decision 2009-065 in which it finds therates applicable to the pipeline held byTransCanada Pipeline Ventures LimitedPartnership (“Ventures Pipeline”) are unjust orunreasonable, unjustly discriminatory or undulypreferential, and expresses the view that it willseek an Order in Council authorizing it to setrates on the Ventures Pipeline. The Commissionadds that, upon receipt of an Order in Council,the Commission will set a process schedule forthe third stage, the rate regulation of theVentures Pipeline. The AUC also notes that therates in question were implemented by NOVAGas Transmission Ltd. (“NGTL”) andTransCanada Pipeline Ventures Ltd.(“Ventures”).
Among the conclusions made by theCommission in arriving at its findings were thefollowing:
Powers of the Commission and Non-Interference with the Contracts of the Parties:The Commission said that it did not acceptVentures main argument that “the sanctity ofvalid contracts gives rise to the presumption thatrates freely negotiated between parties, andrecorded in valid contracts, meet the just andreasonable standard and should not beinterfered with except in extraordinarycircumstances where there has been a cleardemonstration of serious harm to the publicinterest.” The AUC says that this argumentignores the legislative framework of the GasUtilities Act.
The Commission states that under the GasUtilities Act or Public Utilities Act, it generallysets the just and reasonable tolls or rates that
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regulated utilities may charge in Alberta. Even incases where the utility and its customersnegotiate tolls or rates in a negotiatedsettlement, the Commission must determine thatthe negotiated tolls or rates are in the publicinterest. The AUC expresses the view that arate, toll or charge freely negotiated is subject tochange if it is insufficient, excessive, unjust orunreasonable.
Time Period of Evidence to be Included in theInvestigation: The Commission found that, toinvestigate the reasonableness of the ratescharged to shippers on the Ventures Pipeline,the Commission had to consider not only the1997-1998 timeframe, when the originalcontracts were signed and underpinned theconstruction of the pipeline, but allcircumstances and contracts up to the close ofthe record in the instant proceeding.
Inter-Affiliate Relationship Between NGTL andVentures: The Commission noted that theevidence showed that NGTL owns 99.99percent of TransCanada Pipeline VenturesLimited Partnership, with NGTL being whollyowned by TransCanada PipeLines Limited. TheCommission found that the NGTL and VenturesPipeline acquisition discussions were morepredicated on maintaining shareholder value forTransCanada than pursuing a fair market valueor acquisition price for Ventures. TheCommission concurred with Suncor that keepingVentures whole was one and the same thing askeeping NGTL whole with respect to itsinvestment in the Ventures Pipeline. Further, theAUC said that the value that Venturesdetermined for the Ventures Pipeline assetsappeared to be inflated and inconsistent withwhat an arm’s length party would expect, whencompared to NGTL’s least cost alternative, Mr.Johnson’s assessment of the net present valueof the Suncor and Williams contracts and theVentures Pipeline, the threat of regulatedservice and bypass by NGTL, and the possibilitythat the Board/Commission might regulate theVentures system.
Are Rates Unjust or Unreasonable, UnjustlyDiscriminatory or Unduly Preferential?: TheCommission said that the evidence made itabundantly clear that the projected Venturesreturns were significantly higher than what a
regulated entity would receive.
Based on the investigation conducted in thisproceeding, the Commission finds that rates onthe Ventures Pipeline are unjust orunreasonable, unjustly discriminatory, or undulypreferential, and as a consequence the VenturesPipeline should be rate regulated.
May 7, 2009
AUC Conditionally Grants ATCO EnergySolutions and ATCO Pipelines a TemporaryExemption from Their Inter-Affiliate Code ofConduct
The Alberta Utilities Commission (“AUC” or “theCommission”) has issued Decision 2009-061 inwhich it grants, with some revisions, aDecember 22, 2008, application from ATCOPipelines (“AP”) requesting temporaryexemptions from certain provisions of their Inter-Affiliate Code of Conduct (“the Code”) withrespect to ATCO Energy Solutions Ltd. (“AES”).
The AUC finds that the circumstances inDecision 2007-0826 (“the ENMAX Decision”) aredistinguishable from the AP application. In theENMAX Decision, the applicant sought apermanent exemption while the exemptionssought in the AP application are of a temporarynature. Another key factor in the ENMAXDecision was the function performed by the non-regulated affiliates. Specifically, the exemptionssought related to some non-regulated affiliateswhich were engaged, directly or indirectly, in thecompetitive electricity markets. In the APapplication, AES is not operating in the retail gasmarket and is not involved in the natural gaspipeline business. In the Commission’s view,granting the exemptions would not bedetrimental to the interests of the Utilitycustomers.
The AUC said it was prepared to approve AP’stemporary exemptions. However, it was of theview that the requested exemption period untilDecember 31, 2009 was excessive. TheCommission found that a shorter period of timewould be adequate for AP to rectify its non-compliance with the Code. The AUC said that,as Mr. Myles has been in the dual role ofPresident of both AES and AEP since July 1,2008, the Commission expects AP to rectify itsnon-compliance with the Code by September 1,
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2009.
The AUC therefore approved AP’s request fortemporary exemptions to sections 3.1.3, 3.2.2,3.2.3 and 3.3.3 of the ATCO Group Inter-AffiliateCode of Conduct. The exemptions are to be ineffect until September 1, 2009. AP is directed toadvise the Commission when it has becomecompliant.
May 1, 2009
AUC Approves AltaGas Default Rate TariffGas Charge for May 2009
In response to Application No. 1605009 whichwas filed by AltaGas Utilities Inc. (“AltaGas”) onApril 24, 2009, the Alberta Utilities Commission(“AUC” or “the Commission”) has issuedDecision 2009-057 in which it approves a gascost recovery rate (“GCRR”) of $1.851 pergigajoule (“GJ”) for the AltaGas Default RateTariff (“DRT”) the month of May 2009.
The AUC says that its staff members havereviewed the application, and that it considersthat the proposed GCRR was determined inaccordance with the directions previously issuedto gas utilities by the AUC’s predecessor, theAlberta Energy and Utilities Board (“AEUB” or“the Board”), in Decision 2001-75, and, morespecifically to AltaGas, in Decision 2002-036.Consequently, the Commission approved forAltaGas the GCRR of $1.851/GJ, as set out inRate Rider “D”, which is to be applied to theenergy sold to all sales service rates unlessotherwise specified by specific contracts duringthe month of May 2009.
The AUC advises that, as directed in Decision2001-75, interested parties will be provided witha 30-day review period following the filing ofeach monthly GCRR in which to raise anyconcerns with the GCRR, price and volumeforecasts, and prior period reconciliations.
May 1, 2009
AUC Approves AltaGas Utilities Third PartyTransportation Rate for May 2009
In response to Application No. 1605010, whichwas filed on April 24, 2009 by AltaGas UtilitiesInc. (“AltaGas” or “AUI”), the Alberta UtilitiesCommission (“AUC” or “the Commission”) hasissued Decision 2009-058 in which it approves
AUI’s third party transportation rate (“TPTR”) of$0.210 per gigajoule (“GJ”) for the month of May2009.
The AUC advises that its staff members havereviewed the application, and that it considersthat the proposed TPTR was determined inaccordance with the method approved by theAUC’s predecessor, the Alberta Energy andUtilities Board (“AEUB” or “the Board”), inDecision 2007-079. Consequently, theCommission approved for AltaGas the TPTR of$0.210/GJ, which as set out in Rate Rider “G”, isto be applied to the energy delivered to defaultsupply and retail supply distribution servicecustomers during the month of May 2009.
The AUC explains that upstream transportationcosts currently recovered through the TPTRwere previously recovered through AltaGas’ gascost recovery rate (“GCRR”). Therefore, theCommission considers that, similar to thedirection provided to gas utilities for GCRRapplications in Decision 2001-75, interestedparties will be provided with a 30-day reviewperiod following the filing of each monthly TPTRin which to raise any concerns with thedetermination of the TPTR.
May 1, 2009
AUC Approves Direct Energy RegulatedServices - South Default Rate Tariff GasCharge for May 2009
In response to Application No. 1605007, whichwas filed on April 24, 2009, the Alberta UtilitiesCommission (“AUC” or “the Commission”) hasissued Decision 2009-056 in which itacknowledges the May 2009 gas cost flow-through rate (“GCFR”) for the Direct EnergyRegulated Services (“DERS”) Default Rate Tariff(“DRT”) in the ATCO Gas South service territory.
The AUC notes that In Order U2008-374, theCommission approved for DERS on an interimbasis, effective January 1, 2009, a return marginof $0.0223 per gigajoule (“GJ”). Unlike theGCFR, the return margin is not subject todeferral account treatment through DERS’sdeferred gas account but is to be recovered withthe GCFR through DERS’s Rate Rider “F”. Forthe month of May 2009, DERS included thefollowing amounts in setting Rider “F” forcustomers served in the ATCO Gas South
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service territory:
Component $/GJ
GCFR 3.038
Reasonable return margin(rounded)
0.023
Rider “F” 3.061
The AUC advises that its staff members havereviewed the application, and that it considersthat the proposed GCFR was determined inaccordance with the directions previously issuedto gas utilities by the AUC’s predecessor, theAlberta Energy and Utilities Board (“AEUB” or“the Board”), in Decision 2001-75, and morespecifically to ATCO Gas South in Decision2002-034, and to DERS in Decision 2003-106.
The Commission says that, as directed inDecision 2001-75, a 30-day review period wasprovided to interested parties following the filingof each monthly Gas Cost Recovery Rate(“GCRR”) in which parties could raise anyconcerns with the GCRR, price and volumeforecasts, and prior period reconciliations. AsDERS is the Default Supply Provider for ATCOGas, the 30-day review period is similarlyapplicable to the GCFRs requested by DERS.
May 1, 2009
AUC Approves Direct Energy RegulatedServices - North Default Rate Tariff GasCharge for May 2009
In response to Application No. 1605006 whichwas filed by Direct Energy Regulated Services(“DERS”) on April 24, 2009, the Alberta UtilitiesCommission (“AUC” or “the Commission”) hasissued Decision 2009-055 in which itacknowledges the May 2009 gas cost flow-through rate (“GCFR”) of $2.985 per gigajoule(“GJ”) in the Direct Energy Regulated ServicesDefault Rate Tariff (“DRT”) for Rates G1 and G3in the ATCO Gas North service territory.
The AUC notes that, in Order U2008-374, itapproved for DERS on an interim basis,effective January 1, 2009, a return margin of$0.0223/GJ. Unlike the GCFR, the return margin
is not subject to deferral account treatmentthrough DERS’s deferred gas account but is tobe recovered with the GCFR through DERS’sRate Rider “F”. For the month of May 2009,DERS included the following amounts in settingRider “F” for customers served in the ATCO GasNorth service territory:
Component $/GJ
GCFR 2.985
Reasonable returnmargin (rounded)
0.022
Rider “F” 3.007
The AUC advises that its staff members havereviewed the application, and it considers thatthe proposed GCFR was determined inaccordance with the directions previously issuedto gas utilities by the AUC’s predecessor, theAlberta Energy and Utilities Board (“AEUB” or“the Board”), in Decision 2001-75, and morespecifically to ATCO Gas North in Decision2002-035, and to DERS in Decision 2003-106.
The Commission says that, as directed inDecision 2001-75, a 30-day review period wasprovided to interested parties following the filingof each monthly Gas Cost Recovery Rate(“GCRR”) in which parties could raise anyconcerns with the GCRR, price and volumeforecasts, and prior period reconciliations. AsDERS is the Default Supply Provider for ATCOGas, the 30-day review period is similarlyapplicable to the GCFRs requested by DERS.
May 1, 2009
AUC Grants Approval for ATCO Pipelines toNegotiate Phase I of Its 2010-2012 GeneralRate Application
In response to Application No. 1604425, whichwas filed on January 29, 2009 by ATCO GasPipelines Limited (“AGPL”), the Alberta UtilitiesCommission (“AUC” or “the Commission”) hasreleased Decision 2009-051 in which it grantsAGPL approval to commence negotiations withits customers to settle AGPL’s revenuerequirement (General Rate Application (“GRA”)Phase I) for each of the years 2010, 2011 and2012, subject to the exclusion of certain
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specified issues. The issues currently before theCommission in other proceedings and whichAGPL is precluded from discussing during thenegotiations are the following:
1. The Competitive Pipeline Reviewproceeding (Application 1466609),
In order to allow the AUC to adequately examineAGPL’s revenue requirement for the 2010-2012test years, the Commission directed AGPL to filethe following information:
1. GRA for the 2010-2012 test years,including all supporting schedules(including 2008 actuals) beforecommencement of settlementdiscussions.
2. If a settlement is reached, AGPL isrequired to file a Settlement Brief whichprovides a detailed explanation of allissues settled and supportingschedules.
3. AGPL is directed to file a justification ofthe prudence of its actual 2008 and2009 capital expenditures to be includedin its opening balance for property,plant, and equipment (rate base). If asettlement is reached before AGPL’s2009 actuals are available, theCommission will not approve theopening balance for property, plant, andequipment in 2010 included within anysettlement that may be reached, inwhich case AGPL must justify theprudence of its 2009 capitalexpenditures to be included in its
opening balance for property, plant, andequipment in 2010 at its next GRAPhase I.
Electricity
May 27, 2009
AUC Approves a Service Area BoundaryEnlargement in City of Red Deer for ENMAXPower Corporation
The Alberta Utilities Commission (“AUC” or “theCommission”) has issued Distribution ServiceArea Approval No. U2009-207 in which it grantsApplication No. 1552134 which was registeredon December 19, 2007 by ENMAX PowerCorporation (“ENMAX” or “EPC”), in its role asthe operator of an electric distribution systemwithin the City of Red Deer, and which soughtapproval to operate that distribution systemfollowing an increase in the service area due toan expansion of the City Corporate Boundary byannexation.
The Commission’s approval was made subjectto certain conditions including the rescinding ofthe existing Approval No. U2005-375.
May 26, 2009
Canadian Hydro Acquires Windrise Prospectfrom EarthFirst Canada
Canadian Hydro Developers, Inc. (“CHD”) hasannounced confirmed the purchase of theWindrise Prospect (“Windrise”) from EarthFirstCanada Inc. for $250,000.
According to the announcement, the site islocated amongst a cluster of existing CHDoperations in southern Alberta, directly adjacentits Soderglen EcoPower Centre near FortMacleod, Alberta, where CHD has been workingon the development of the 50 MW SoderglenExpansion Wind Prospect. If built, Windriserepresents a minimum capacity generation of 99MW.
The announcement advises that thedevelopment of the site is dependent on aproposed 240 kV interconnection to the Albertagrid, which is expected to be in place in 2010,and that CHD is continuing to gather data andwork through the permitting process to prepareits application for provincial regulators.
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May 22, 2009
AUC Issues Two Orders With Respect toAlteration of Edgerton Substation 899S
The Alberta Utilities Commission (“AUC” or “theCommission”) has issued Need IdentificationDocument (“NID”) Approval No. U2009-201 andSubstation Permit and Licence No. U2009-202in which it approves, respectively, ApplicationNo. 1600791, which was registered by theAlberta Electric System Operator (“AESO”) onDecember 29, 2008, and Application No.1602273 which was registered on January 13,2009 by AltaLink Management Ltd. (“AML” or“AltaLink”).
NID Approval No. U2009-201 approves the NIDfiled by the AESO with respect to a transformerupgrade at Edgerton 899S substation.
In Substation Permit and Licence No. U2009-202, the Commission authorizes AML to alterand operate the Edgerton 899S substation. Theauthorization was given subject to certainconditions including the rescinding Permit andLicence No. U2002-543.
May 22, 2009
AUC Issues Two Orders With Respect toAlteration of the Michichi Creek 802SSubstation
The Alberta Utilities Commission (“AUC” or “theCommission”) has issued Need IdentificationDocument (“NID”) Approval No. U2009-196 andSubstation Permit and Licence No. U2009-197which, respectively, approve Application No.1604868, which was registered by the AlbertaElectric System Operator (“AESO”) on March 4,2009, and Application No. 1604882, which wasregistered on March 10, 2009 by ATCO ElectricLtd. (“AE”).
In NID Approval No. U2009-196, theCommission approved the NID filed by theAESO with respect to the addition of two 25-kVcircuit breakers at Michichi Creek 802Ssubstation.
Substation Permit and Licence No. U2009-197grants AE approval to alter and operate theMichichi Creek 802S substation. TheCommission’s approval was subject to certainconditions including the rescinding of Permit and
Licence No. U2007-153.
May 20, 2009
AUC Approves Withdrawal of Central AlbertaRural Electrification Association Micro-Generation Application
The Alberta Utilities Commission (“AUC” or “theCommission”) has issued Decision 2009-066 inwhich it grants a March 11, 2009 request fromCentral Alberta Rural Electrification AssociationLimited (“CAREA”) for approval to withdrawApplication No. 1604804 which it had submittedon February 13, 2009, asking the Commission torequire the proponents of a 2.4 kilowatt (“kW”)solar generation unit to pay, which CAREA hadcharacterized as extraordinary costs ofconnecting that facility to CAREA’s system.
CAREA desired to withdraw the applicationbecause the required equipment had alreadybeen installed and paid for after the generatingunit’s proponents has inadvertently knockeddown a tap pole which had been replacedinclusive of the required switch. The equipmentin question consisted of a 14.4 kilovolt switch.
The Commission found that the switch installedby CAREA is part of the standard equipmentthat is installed upon the replacement orinstallation of all new tap poles. TheCommission said that the reason for thisreplacement and repair falls outside the scope ofthe Micro-Generation Regulation. As such, theprocess in which CAREA carried out theinstallation of any equipment and the pricecharged for installation is outside the scope ofProceeding ID 163. Given the foregoing, theCommission found that Application No. 1604804was moot and no longer required. As such, theCommission granted the Withdrawal ofApplication submitted by CAREA.
May 19, 2009
AUC Approves ENMAX Application forApproval of Enlargement of its ElectricityDistribution System
The Alberta Utilities Commission (“AUC” or “theCommission”) has issued Decision 2009-063 inwhich it approves Application No. 1552134 fromENMAX Power Corporation (“EPC”) for theenlargement of EPC’s electric distributionsystem service area to include land recently
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annexed by the City of Calgary from theMunicipal District (“M.D.”) of Rocky View. TheAUC notes that the existing customers in thearea in question were previously served byFortisAlberta Inc. (“FAI”). The Commissionadvises that it will issue a Distribution ServiceArea Approval shortly after the issuance of theDecision.
The AUC says that it will defer providing anorder directing the compensation amount to bepaid to FAI in order to give EPC and FAI theopportunity to negotiate and present for approvalan agreement as to compensation to be paid. Ifthe parties are unable to agree, either party maybring forward an application to the Commissionrequesting that the Commission resolve theissue of compensation to be paid.
In approving the application, the AUC madecertain findings including the following:
Customer Service: The Commission found thatFAI's concerns with respect to customer servicedid not provide compelling reasons todemonstrate that the application is contrary tothe public interest.
Costs: The AUC noted that the cost tocustomers is approximately $1.4 million withthese costs consisting of about $150,000 forFAI’s reconfiguration, $800,000 for EPC’sreconfiguration, and a payment of $500,000from EPC to FAI to purchase the assets. TheBook Value of the assets is $400,000. TheCommission also noted EPC’s argument that theannexed lands are expected to be required forfuture subdivisions, in which case, as thedevelopment of subdivisions proceeds, theexisting facilities were likely to be altered orremoved anyway. The AUC added that, basedon 60 customers, $1.4 million represented$23,333 per transferred customer. However, this$1.4 million could be expected to be a muchsmaller cost per customer after the land wasdeveloped. The Commission said that the costsare of an incremental nature that, when spreadacross the EPC customer base, will have littleimpact on customers. The AUC went on to saythat it was not persuaded by FAI’s argument thatit will lose the opportunity to gain economies ofscale as the economies exist because the landsare becoming urban due to their location whichis now within the City. The Commission noted
that the public was not being deprived of theeconomies of scale as these economies willexist within the EPC system.
Harmonization of Boundaries: The AUC saysthat it gave consideration to the planningresponsibility of EPC under the ElectricityUtilities Act (“EUA”). The Commission found thatEPC should acquire service territory in advanceof the predicted growth of subdivisions for theCity of Calgary in order to facilitate the orderlydevelopment of electricity in Alberta.
May 19, 2009
AUC Approves Application by City of RedDeer for Approval of the Enlargement of itsElectricity Distribution System
The Alberta Utilities Commission (“AUC” or “theCommission”) has issued Decision 2009-062 inwhich it approves Application No. 1550523 fromthe City of Red Deer (“RD”) which soughtapproval for the enlargement of its electricdistribution system service area to include landrecently annexed from Red Deer County. TheCommission notes that FortisAlberta Inc. (“FAI”)currently provides service to the customers inthe area in question.
The AUC cautions that the approval will not takeeffect until:
the RD is prepared to serve the AnnexedCustomers;
the asset transfer is set to take place; and
the parties have reached an agreement withrespect to the payment of compensation andthe agreement has been approved by theCommission or absent such agreement, theCommission has issued its order for thepayment of compensation.
The AUC’s findings with respect to the issuesraised in the context of the application includedthe following:
Customer Service: In giving its approval, theCommission found that FAI's concerns withrespect to customer service did not providecompelling reasons to demonstrate that RD’sapplication was contrary to the public interest,noting that:
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RD’s three service area enlargements overthe past 10 years involved a total of 37 sitesand resulted in no customer servicecomplaints. The estimated 49 customersimpacted by the application were not asignificant increase in the number ofcustomers from the previous enlargements.As these enlargements were also in FAI’sservice territory, it was reasonable to concludethat there would be a similar ease of transitionfor this enlargement;
The Annexed Customers’ rates and terms andconditions of distribution service are regulatedby the City Council of RD. In the event that anissue might arise respecting the rates or termsand conditions, the Annexed Customers wouldhave recourse to the City Council;
Load settlement IDs and customerinformation/histories can be transferredwithout disruption to customers;
RD has committed to ensuring an orderly,economic and efficient transition incooperation with FAI.
Costs: The AUC found that there was notsufficient evidence to estimate the totalincremental cost to the public. The Commissionconsidered that the removal of 49 customers, inthe absence of evidence to the contrary, doesnot appear to impose a burden on the remainingFAI customers in Alberta. The AUC alsoconsidered that the onus was on FAI to provideevidence to convince the Commission that thecosts associated with the annexation werecontrary to the public interest. The Commissionfound that FAI has failed to provide compellingevidence as to deem the application contrary tothe public interest.
Harmonization of Boundaries: The AUC foundthat consideration of the public interest stronglyfavoured giving effect to the relevant legislationand the legislative scheme which suggestmunicipal service territories correspond to theboundaries of the municipalities. TheCommission added that the public interestreasons presented by FAI were not of asubstantial magnitude to outweigh the publicinterest factors favouring the application.
May 15, 2009
AUC Approves EPCOR ApplicationConcerning True-Up of Its TransmissionCharge Deferral Account for the PeriodEnding December 31, 2008
The Alberta Utilities Commission (“AUC” or “theCommission”) has issued Decision 2009-064 inwhich it approves Application No. 1604940(Proceeding I.D. 183) which was filed byEPCOR Distribution & Transmission Inc.(“EDTI”) on March 27, 2009 and which soughtapproval of Transmission Charge DeferralAccount System Access Service Rate Riders(“TCDA SAS Rate Riders”), to be in effect fromJune 1, 2009 to November 30, 2009. Theproposed TCDA SAS Rate Riders would allowEDTI to recover $17.971 million, whichrepresented the debit balance in itsTransmission Charge Deferral Account (“TCDA”)as at December 31, 2008.
EDTI provided the following informationconcerning the monthly TCDA true-up riderimpact for average use customers:
Rate Class Monthly TCDA True-Up Rider Impact
% increase
Residential 4.7
Small Commercial 5.2
MediumCommercial
5.6
Time of Use –Secondary
3.1
Time of Use – Direct 4.7
Time of Use –Primary
2.8
Security Lights – 70Watt to 400 Watt
1.5 – 2.5
Customer Specific 3.7
CST 4.0
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Small CommercialUnmetered
4.1 - 5.0
Specifically, the Commission’s findings includedthe following:
EDTI’s application was consistent with themethodology previously accepted in Decision2004-081.
The AUC reviewed EDTI’s calculation of theTCDA balance and approved the applied forTCDA balance of $17,970,979 as ofDecember 31, 2008.
The Commission noted that EDTI proposed tocollect the TCDA balance over a six monthperiod through a TCDA SAS Rate Rideramounting to 0.633 cents per kWh fornoninterval metered customers and 0.367cents per kWh for interval metered customers.EDTI had calculated that the increase for atypical residential customer amounts toapproximately 4.7% of the customer’s totalelectricity bill.
A six-month period is a reasonable amount oftime over which to collect the temporary TCDASAS Rate Riders.
The AUC reviewed EDTI’s calculation of theamount of the TCDA SAS Rate Riders andwas satisfied that both the level and form ofthe riders were appropriate based on EDTI’sestablished practice of refunding / collectingon a per kWh basis. Accordingly, theCommission approved the use of the TCDARate Riders as proposed by EDTI effectiveJune 1, 2009.
The Commission directed EDTI to account forany over-collection or under-collection of theapproved amount in its Transmission ChargeDeferral Account.
May 8, 2009
AUC Approves Glacier Power Application forDevelopment and Construction of a 100-MWHydraulic Power Plant in Dunvegan Area
In response to Application No. 1485454 whichwas registered by Glacier Power Ltd. (“Glacier”)on November 3, 2006, the Alberta UtilitiesCommission (“AUC” or “the Commission”) hasissued Hydro Development Approval No.
U2009-186 and Power Plant Approval No.U2009-187, which together, authorize Glacier toconstruct and operate a 100-MW HydroelectricPower Plant on the Peace River near Dunvegan,Alberta.
The first of these Orders notes that theDunvegan Hydro Development Act, whichauthorizes the Commission to make an order forthe construction and operation of the HydroDevelopment, came into force on April 20, 2009.
May 8, 2009
EPCOR to Launch Independent PowerGeneration Business
EPCOR Utilities Inc. (“EPCOR”) has announcedthat it plans to create Capital Power Corporation(“Capital Power”), an unregulated powergeneration company which will be permanentlyheadquartered in Edmonton. EPCOR adds thatit will continue to provide regulated powertransmission and distribution, water, andwastewater services to more than one millioncustomers in Western Canada, includingEdmonton.
According to the announcement, Capital Powerplans to develop and build power plants acrossNorth America and continue thecommercialization of near-zero emission powergeneration technologies, including IntegratedGasification Combined Cycle (“IGCC”) andAmine Scrubbing. EPCOR says that it mayeventually sell all or a substantial portion of itsownership interest, subject to market conditions,its requirements for capital and othercircumstances which may arise in the future,with proceeds from share sales to be reinvestedin EPCOR’s growing utility infrastructurebusinesses, including water, wastewater, powertransmission and power distribution.
The announcement notes that, as a first step,EPCOR is planning an Initial Public Offering(“IPO”) of common shares of Capital Powerrepresenting approximately 25% of the powergeneration business. A preliminary prospectusfor the offering is expected to be filed withsecurities regulators in Canada.
EPCOR states that its regulated power andwater customers will see no changes in serviceor costs as a result of this restructuring, and the
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City of Edmonton’s access to electricity remainssecured by long-term contracts.
The announcement goes on to say that EPCORExecutive Vice President and Chief OperatingOfficer, Brian Vaasjo, will be named Presidentand CEO of Capital Power. He will be joined atCapital Power by approximately 1,000 ofEPCOR’s 3,000 employees. Capital Power willbe governed by a majority independent Board ofDirectors.
Additionally, EPCOR anticipates that the closingof the IPO of Capital Power shares will becompleted in mid-2009, and has engaged TDSecurities Inc. and Goldman Sachs Canada Inc.to act as joint-bookrunners. Employees willmove to Capital Power at closing, with transitionarrangements in place between the companiesto ensure continuity of operations and services.
May 1, 2009
AUC Approves ENMAX’s Regulated RateTariff Electricity Charges for May 2009
In response to Application No. 1605008, whichwas filed on April 24, 2009, the Alberta UtilitiesCommission (“AUC” or “the Commission”) hasissued Decision 2009-054 in which itacknowledges the Regulated Rate Tariff (“RRT”)electricity energy charges for the month of May2009 for ENMAX Energy Corporation (“EEC” or“ENMAX”). Those charges are 7.855 cents perkilowatt hour (“kWh”) for both residential andcommercial customers.
The AUC advises that its staff members havereviewed the application, and that it accepts thatthe energy charges represent rates determinedin accordance with the ENMAX Energy PriceSetting Plan (“EPSP”) for 2006-2011 asamended and approved by the Commission inDecision 2008-091.
The AUC directs that if any affected partyobjects to the calculation of the energy charges,they should notify the Commission and ENMAXin a timely manner, and include the nature oftheir objection and the reason(s) why it shouldbe considered.
May 1, 2009
AUC Approves EPCOR Energy Alberta’sRegulated Rate Tariff Electric EnergyCharges for May 2009
In response to Application No. 1605002, whichwas filed on April 24, 2009, the Alberta UtilitiesCommission (“AUC” or ‘the Commission”) hasissued Decision No. 2009-053 in which itacknowledges the electric energy chargesapplicable for the month of May 2009 for theRegulated Rate Tariff (“RRT”) of EPCOR EnergyAlberta Inc. (“EEAI”). These rates are as follows:
EPCOR Distribution & Transmission Inc.(“EDTI”) Service Territory
Rate Class Cents per Kilowatt Hour
Residential 7.380
Small Commercial 7.380
Lighting 3.713
FortisAlberta Inc. (“FAI”) Service Territory
Rate Class Cents per Kilowatt Hour
Residential 7.373
Small Commercial 7.368
Lighting 4.073
Farm 7.497
Irrigation 6.927
Oil & Gas 7.242
The AUC advises that its staff members havereviewed the application, and that it accepts thatthe energy charges represent rates determinedin accordance with EEAI’s Energy Price SettingPlan (“EPSP”) for 2006-2011, including themonth-ahead portion and the Index SupportAgreement as approved in Order U2007-352. Inthis Order, the the AUC’s predecessor, theAlberta Energy and Utilities Board (“AEUB” or“the Board”) approved EEAI’s adjustment to its2006-2011 RRT EPSP Index SupportAgreement as agreed to by customer parties
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and the Advisor.
The AUC directs that if any affected partyobjects to the calculation of the energy charges,they should notify the Commission and EEAI ina timely manner, and include the nature of theirobjection and the reason(s) why it should beconsidered.
General
May 29, 2009
AESO Appoints New Vice-President MarketServices
The Alberta Electric System Operator (“AESO”)has announced that Kelly Gunsch will join theorganization effective June 22, 2009 in the roleof Vice-President Market Services reportingdirectly to Cliff Monar, Senior Vice-PresidentMarkets and Regulatory Services. Theannouncement says that Ms. Gunsch comes tothe AESO most recently from the CalgaryHomeless Foundation where she was ChiefStrategy Officer. Prior thereto, she heldprogressively more senior roles in RegulatoryAffairs, Corporate Development and Commercialand Portfolio Management and was the Vice-President of Commercial Operations atTransAlta. The announcement adds that Ms.Gunsch holds a bachelor of science and amasters in economics from the University ofCalgary.
The AESO says that Cheryl Terry, who hasserved as Interim Vice-President over the lastseveral months will work with Ms. Gunsch toensure a smooth transition and will remain withthe System Operator for the foreseeable futureas an advisor to help advance various market,process and policy initiatives within theorganization.
May 29, 2009
AESO Announces the Resignation of VPCorporate Communications Wayne St.Amour
The Alberta Electric System Operator (“AESO”)advises that its Vice-President CorporateCommunications Wayne St. Amour has resignedfrom the AESO effective May 31, 2009 and willbe moving to Nova Scotia in the next few weeks.
The announcement notes that in the past two
and a half years, and in the early days of theAESO, Mr. St. Amour was instrumental in thedevelopment of the AESO's Human Resources,Customer Services, Corporate Communicationsand Stakeholder Relations groups. Theannouncement adds that Mr. St. Amour’seducational background, expertise, knowledgeand network of relationships within the industrymade him a valued member of the executiveteam during his tenure at the System Operator.
The AESO reports that Nancy Arab will lead theCorporate Communications team.
May 27, 2009
TransAlta Announces $200 Million of SeniorNotes Due 2014
TransAlta Corporation (“TransAlta”) hasannounced it has priced an offering of $200million of 6.45 per cent senior notes due in 2014.The senior notes were priced at 99.823 per centfor yield to maturity of 6.49 per cent, and theyhave been rated BBB (stable) by Dominion BondRating Service (“DBRS”) and Standard & Poor’sRating Services. TransAlta says that the netproceeds from the offering will be used for debtrepayment, financing of the company’s long-term investment plan and for general corporatepurposes.
CIBC World Markets Inc. and Scotia Capital Inc.acted as joint lead agents and book-runners forthe offering.
May 22, 2009
TransAlta Reports Changes in its MajorMaintenance Plans for 2009 and 2010
TransAlta Corporation (“TransAlta”) hasannounced it would advance a majormaintenance outage on its 353 megawatt(“MW”) Sundance 3 facility from the secondquarter of 2010 into the second and thirdquarters of 2009.
The announcement says that advancement ofthe Sundance 3 major maintenance outagetakes advantage of the current low power pricesin Alberta, and allows TransAlta to optimize boththe scheduling of this work and the preventativemaintenance required in the short-term. Itsuggests that combining the Sundance 3 majormaintenance outage with work required this year
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will provide a benefit from reduced forcedoutages. To accommodate the Sundance 3major maintenance outage, the Sundance 5turnaround will now occur between the third andfourth quarters.
As a result of the change in schedule,TransAlta’s full year 2009 planned maintenancelost gigawatt hours (“GWh”) are expected toincrease by approximately 380 GWh.
From an availability perspective, TransAlta nowexpects Alberta Thermal to be between 81 - 83per cent for the full year. Overall fleet availabilityis now expected to be 87 - 89 per cent for thesame period.
Details of the 2009 planned maintenanceprogram are outlined below:
Coal Gas &Hydro
Total
Capitalized($millions)
$105 -110
$45 - 50 $150 -160
Expensed($millions)
$115 -125
$0 - 5 $115 -130
$220 -$235
$45 - 55 $265 -290
GWh lost 3,200 -3,300
200 - 225 3,400 -3,525
A quarterly breakdown of lost GWh fromplanned maintenance is as follows:
Fleet Q1 Q2 Q3 Q4
2009 PlannedMajorMaintenance(GWh)
~700 ~1,875 ~675 ~150
May 12, 2009
AltaLink to Issue $100 Million in Medium-Term Notes
AltaLink, L.P. (“AltaLink”) has announced thathas agreed to issue a principal amount of $100
million of additional Series 2008-1 Medium-TermNotes due May 29, 2018, through its $800million Medium-Term Notes program in anagency deal with Scotia Capital Inc., TDSecurities Inc., BMO Nesbitt Burns Inc., andRBC Dominion Securities Inc. Theannouncement says that the Series 2008-1Medium-Term Notes will pay an annual couponrate of 5.243% until maturity, and the distributionof this Series is scheduled to close on May 14,2009.
AltaLink states that the Medium-Term Notes aresecured by a first floating charge securityinterest in the present and future property andassets of the company. The Medium-TermNotes rank pari passu with all senior, securedindebtedness and have priority over all presentand future unsecured indebtedness and allsubordinated indebtedness. The net proceeds ofthe offering will be utilized to repay outstandingcommercial paper.
May 8, 2009
TransAlta Renews Normal Course Issuer BidProgram
TransAlta Corporation (“TransAlta”) hasannounced that it has received regulatoryapproval from the Toronto Stock Exchange(“TSX”) for the continuation of its normal courseissuer bid program.
TransAlta believes maintaining a balancedapproach to capital allocation enables thecompany to create consistent and stableshareholder value in a capital intensive,commodity-based industry. The company’s planincludes returning capital to shareholdersthrough dividends and share buybacks,investments in new capacity and portfoliooptimization. TransAlta says that it has approvalto purchase, for cancellation, up to 9,892,552 ofits common shares, representing 5 per cent ofits issued and outstanding shares which number197,851,056 as of April 30, 2009.
The announcement says that during the lasttwelve months, under its previous normal courseissuer bid, TransAlta repurchased 1,730,600common shares, representing approximately 0.9per cent of the company’s outstanding shares onApril 23, 2008, at an average price ofapproximately $35.60 per common share.
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TransAlta advises that its normal course issuerbid program will be effective from May 7, 2009and continue until May 6, 2010. Any purchaseswould be made on the open market through theTSX at the market price of such shares at thetime of acquisition. The company states thatdaily purchases cannot exceed 192,121common shares representing 25 percent of theaverage daily trading volume for the six calendarmonths prior to the date of approval of the bid bythe TSX, subject to block purchase exceptionsoutlined in the TSX rules. TransAlta adds thatits average daily trading volume during the lastsix calendar months was 768,482 commonshares.
May 7, 2009
Alberta Government Appoints Eric Newell asChair to Manage Provincial Climate ChangeFund
The Government of Alberta has appointed EricNewell to chair the province’s new ClimateChange and Emissions ManagementCorporation, an arms-length organization whichwill manage Alberta’s climate change fund. Thecorporation will invest money collected fromindustry into initiatives and projects whichsupport technologies to reduce greenhouse gas(“GHG”) emissions and improve the ability toadapt to climate change.
The announcement notes that Alberta is the onlyjurisdiction in North America which is operating amandatory reduction program for large industrialemitters. More than 6.5 million tonnes of GHGhave been reduced based on actions to date. Tocomply with reduction targets, a company maychoose to make facility improvements, purchaseAlberta-based carbon offset credits, or pay $15for each tonne over target into the ClimateChange and Emissions Management Fund,which currently holds $122.4 million.
The government advises that the Minister ofEnvironment will maintain responsibility forreceiving payments from industry andtransferring the dollars to the corporation, whichwill administer the fund, including soliciting andreviewing project submissions and makinginvestment decisions. It is expected thecorporation will begin accepting fundingproposals in the second half of fiscal 2009/10.
B R I T I S H C O L U M B I A
Natural Gas
May 20, 2009
BCUC Grants Terasen Gas (Whistler)Request and Reverses Finding in Order G-35-09 Concerning Deferral of ConversionCosts
In response to an April 17, 2009 application fromTerasen Gas (Whistler) (“Terasen Whistler” or“TGW”) seeking reconsideration of a finding inDirective 5 of Order G-35-09 disallowing $1.076million in deferrals of conversion costs, theBritish Columbia Utilities Commission (“BCUC”or “the Commission”) has issued Decision G-52-09 in which it grants the TGW request andreverses the finding in question. TheCommission directed that the following part of asentence on page 28 of the Decision:
“However, the Commission Panel directsTGW to reduce the amount deferred by$1.076 million being the amount of prioryears’ losses available for “carry back” atthe start of 2009.”
be struck out and replaced with:
“Commission Panel accepts TGW’srequest to defer amounts in respect ofconversion costs on a gross basis anddirects TGW to reduce the amountdeferred by $1.076 million being theamount of prior year’s losses available for“carry back” at the start of 2009.”
In seeking this change TGW stated that theevidence showed that it had taxable income inyears prior to 2009, and in 2009 it was projectedto incur a loss of $3.764 million for income taxpurposes that could be carried back and/orcarried forward. In the amendments to itsapplication, TGW carried back $1.076 million ofthe 2009 loss against taxable income of prioryears, which resulted in a $344.3 thousandincome tax refund being credited to customers insetting 2009 revenue requirements. Theremainder of the income tax loss would beapplied to reduce 2010 and 2011 income taxes.
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May 12, 2009
BCUC Grants PNG Utilities Commission ActExemption for Tomslake Gas DistributionSystem
The British Columbia Utilities Commission(“BCUC” or “the Commission”) has issued OrderNo. G-20-09 in which it sets out its findingsconcerning a March 26, 2009 application byPacific Northern Gas Ltd. (“PNG”) for approvalto implement a $12 per month fixed fee chargeto be applied to Tomslake B.C. customers whochoose the option to pay a monthly fixed feeinstead of an up-front lump sum contribution toobtain gas service from a new gas distributionsystem to be installed by Pacific Northern Gas(N.E.) Ltd. (“PNG (N.E.)”) Dawson Creek.
The BCUC ruled that subsection 45(2) of theUtilities Commission Act (“UCA”) does not applyin respect of the construction and operation ofthe Tomslake gas distribution system. TheCommission also said that having consideredthe information filed by PNG and in recognitionof the size of the investment required atTomslake in relation to the rate base of PNG(N.E.) as well as uncertainty about the cost ofthe system and the amount of customer load tobe realized, the BCUC has determined that PNGmust apply for a Certificate of PublicConvenience and Necessity (“CPCN”) for thisextension of its system. The Commission addedthat, when PNG files a CPCN application for theTomslake gas distribution system, it mustinclude detailed information about the designand costs estimate for the system, as well as thecustomers who have committed to take servicefrom PNG (N.E.) and their gas demand.
The Commission reports that PNG submitted inthe Application that it expects the number ofTomslake customers who would choose toconvert to gas service would be greatlyenhanced if the potential Tomslake customerswere provided with the option of paying a $12monthly fixed fee instead of a $1,752 one timelump sum contribution.
The BCUC notes that PNG estimates that thenew Tomslake distribution system will cost$2,636,516, and that contributions from thePeace River Regional District and EnCana GasMarketing (“EnCana”) will reduce the net cost to
$1,486,516. The Commission also notes that onMarch 26, 2009, PNG concurrently filed a copyof a Transaction Confirmation dated December8, 2008 which provided the terms and conditionsunder which EnCana has agreed to supply gasto PNG for redelivery to the residents ofTomslake, B.C.
May 11, 2009
BCUC Posts Decision and Order ConcerningTerasen Gas (Whistler) Application forApproval to Amend Rate Schedules EffectiveJanuary 1, 2009
The British Columbia Utilities Commission(“BCUC” or “the Commission”) has posted to itswebsite Order G-35-09 and concurrent Reasonsfor Decision in the matter of an October 3, 2008application by Terasen Gas (Whistler) Inc.(“Terasen Whistler” or “TGW”) which wasamended on November 21, 2008 and whichsought adjustments to TGW’s existing rateseffective January 1, 2009 and approval of aReturn on Equity (“ROE”) and Capital Structure.
The Commission advises that among the thingssought by Terasen Whistler in its applicationwere the following:
a permanent reduction to its total bundledvariable rates, inclusive of Rate Rider A of$1.537 per GJ from $25.459 per GJ to$23.922 per GJ effective January 1, 2009, anda revenue surplus forecast to be $1.149million for 2009 based on the current bundledrate including Rate Rider A. Terasen Whistleralso proposed to refund the differencebetween interim rates and permanent rates byway of a rate rider;
approval for the implementation of transitionaldeferral accounts for 2009;
that its allowed ROE be set at 75 basis pointsabove the benchmark low-risk utility and thatits capital structure for ratemaking purposesbe set at 60 percent debt and 40 percentcommon equity, effective January 1, 2009;and
approval for changes in certain accountingtreatments and continuation of certain deferralaccounts, and a proposal to harmonize itssystem extension and customer connectionpolicies with those of Terasen Gas Inc. (“TGI”)
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and Terasen Gas (Vancouver Island) Inc.(“TGVI”), effective January 1, 2009.
The BCUC noted that Commission Order G-172-06 directed Terasen Whistler to considerchanging to an unbundled rate structure as partof its next revenue requirements application. Inthis application, Terasen Whistler is requestingCommission approval for unbundling of rateswithin Terasen Whistler’s Gas Tariff and forcustomer billing purposes, to be effectiveJanuary 1, 2010, after the completion of theWhistler Pipeline and the conversion of thepropane system to natural gas.
Among the rulings and directives set out inOrder G-35-09 were the following:
The BCUC declined to approve as filed therequested permanent reduction to TerasenWhistler’s total bundled variable rates,inclusive of Rate Rider A of $1.537 per GJfrom $25.459 per GJ to $23.922 per GJeffective January 1, 2009, and a revenuesurplus forecast to be $1.149 million for 2009based on the current bundled rate includingRate Rider A;
The Commission Panel accepted the 2009forecast for new customer additions and useper customer; it also approved the 2009forecast plant additions of $2,190,800,capitalized overhead expenditures of$163,200, retirements of $18,000 anddepreciation expense of $501,200.
The Panel approved a list of certain deferralaccounts on the terms set out in the amendedapplication.
TGW was directed to charge all property taxesrelating to the Propane Plant in respect of theperiod after final conversion to the PropaneAsset Decommissioning deferral account andto include in its next revenue requirementapplication a report on whether followingdecommissioning of the propane plant thevariations in property taxes are expected to besignificant enough to warrant the retention ofthe deferral account.
The Commission Panel accepted TGW’srequest to defer amounts in respect ofconversion costs on a gross basis anddirected TGW to reduce the amount deferred
by $1.076 million being the amount of the prioryear’s losses available for “carry back” at thestart of 2009.
The inclusion of the maximum permissiblerecoverable cost for the Conversion Project at$6.231 million was approved.
TGW’s 2009 forecast mid-year rate base of$38,816,000 was accepted.
The Commission Panel accepted theforecasted revenues for TGW as set out inTGW’s application.
The Panel approved the following:
1. The management by TGI of the naturalgas supply requirements of TGW duringthe 2008-2009 gas contracting yeartogether with an allocation of the actualincurred cost of the natural gas volumesprovided to TGW, including midstreamcosts;
2. The continued management by TGI ofthe natural gas requirements of TGWfrom November 1, 2009 onwards, uponsubstantially the same terms as abovein (1);
3. The complete amalgamation of theTGW and TGI gas portfolios in 2010 asset out in the Application, including thediscontinuance of the requirement tosubmit a separate price riskmanagement and supplier contracts;and
4. TGW’s 2009 forecast cost of gas.
TGW was directed to establish unbundledrates upon the later of January 1, 2010 orcompletion of the Conversion Project.
The Commission Panel approved the costforecasts in the Application for:
1. Operations, maintenance andadministration;
2. Transportation charges; and
3. Cost of own use gas.
4. The forecast Income Tax refund of$344,000 and the forecast Property Taxin the Application.
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A capital structure comprised of 40 percentcommon equity and 60 percent debt wasapproved for TGW.
The ROE for TGW was established at 50basis points over the benchmark low-riskutility.
TGW’s request to recover any potentialdifference between interim rates andpermanent rates by way of a rate rider wasapproved.
The Commission Panel approved thefollowing:
1. TGW’s proposal to adopt an $85Application Fee for new installations anda $25 fee for existing installations;
2. TGW’s proposal to adopt the TGI andTGVI Service Line Cost Allowance of$1,535 (other than duplex) and $3,070(duplex);
3. TGW’s proposal to adopt the TGI-TGVIMain Extension (“MX”) Test;
4. TGW’s proposal to maintain aProfitability Index threshold of 1.0 foreach main extension and to evaluate theMX tests on an individual basis ratherthan on an aggregated basis; and
5. TGW’s proposal to provide incentives toinstall high efficiency gas appliances;
TGW’s proposed changes to its Tariff wereapproved.
Terasen Whistler was directed to refund thedifference between the 2009 interim ratesinclusive of Rate Rider A and the permanentrates with interest at the average prime rate ofTerasen Whistler’s principal bank as set out ina Commission Order which establishespermanent rates.
May 8, 2009
BCUC Approves Negotiated SettlementAgreement With Respect to 2009 RevenueRequirements for the PNG-West Service Area
The British Columbia Utilities Commission(“BCUC” or “the Commission”) has posted OrderNo. G-39-09 in which it approves a NegotiatedSettlement Agreement (“NSA”) with respect to
the 2009 revenue requirements for the PacificNorthern Gas (“PNG”) PNG-West service area.A copy of the NSA is attached to the Order. TheCommission also found a letter agreementbetween PNG and Merrill Lynch Commodities,Inc. to be in the public interest and approved it.In addition, BCUC issued the followingdirectives:
PNG was directed to file an amendedSummary of Rates and Bill Comparisonschedules based on the NSA.
PNG is to refund to customers the differencebetween permanent 2009 rates and theinterim rates with interest in accordance withCommission Order G-182-08.
Among the matters agreed to in the NSA werethe following:
A lump sum settlement allowance reduction of$120,000 is accepted by the parties with aportion allocated to PNG(N.E.). The NSAexplains that there are numerous cost ofservice items (such as labour costs, auditfees, director’s fees and consulting fees)which could have been addressed on a line byline basis but were grouped under a globalreduction to facilitate the settlementdiscussions.
Consistent with the Commission’s Decision onthe 2007 revenue requirements application,PNG agreed to include only one third of thecost of including executive bonuses inpensionable earnings in the 2009 cost ofservice. The reduction to the 2009 cost ofservice amounts to just under $25,000 beingtwo thirds of the estimated pension cost ofapproximately $37,000.
PNG agreed to reduce Account 721 –Administration budgeted costs by $30,580 forTravel Expenses and by $29,745 forEmployee Expenses for a total reduction toAccount 721 of $60,325 for 2009.
PNG agreed to reduce the budgeted 2009gasoline price from $1.426/litre to $1.10/litre.
PNG agreed to increase its 2009 forecast ofgas deliveries to the Conifex saw mill in FortSt. James (formerly owned by Pope & Talbot)from 38,120 GJ in the Updated Application to
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100,000 GJ under Negotiated SettlementProcess (“NSP”) 2009. This was due to thefact the saw mill commenced operating at thebeginning of March 2009 and was continuingto operate with one shift. Gas deliveries toConifex will be accounted for under theexisting Industrial Customer DeliveriesDeferral Account (“ICDDA”).
Subject to undertakings related to thePorpoise Harbour Crossing Replacement andthe Maintenance Management projects, theparties accepted the applied for 2009 capitaladditions budget.
The parties accepted PNG’s recommendationto draw down $900,000 of deferred incometaxes as a credit to income taxes payable in2009.
The parties acknowledged that PNG’srelatively small customer base made it difficultto be at the forefront of implementing DemandSide Management (“DSM”) programs in itsservice area. However, PNG will continue toactively participate in provincial governmentand industry working groups focusing onwhich DSM programs to implement throughoutthe province. PNG will focus its efforts ontargeting DSM programs which can help itslower income customers reduce their energyuse and costs. This is in recognition of theunique circumstances faced by customerswho may not be able to afford to purchasehigher efficiency natural gas appliances but atthe same time may have the greatest need toreduce their energy use to achievecorresponding cost savings.
The parties agreed a new deferral accountshould be implemented to record the costsincurred by PNG to implement InternationalFinancial Reporting Standards (“IFRS”) andagreed it should be set up as a rate basedeferral account.
The parties acknowledged that increasingcosts in the PNG-West division is having acorresponding impact on the level of sharedservices cost recovery by PNG-West from itswholly owned subsidiary PNG(N.E.). However,the parties continue to recognize the value toPNG(N.E.) of the economies of scale with alarger parent Company providing a number of
different services which would be more costlyto PNG(N.E.) if these services were obtainedby PNG(N.E.) on a standalone basis. PNGemphasized that it continues to seekopportunities to spread its overhead costsover other business ventures which wouldlessen the burden on PNG(N.E.). The pools ofcosts subject to allocation and the allocatorswere carefully reviewed again this year byCommission Staff. The parties agreed that aportion of the PNG-West NSP 2009 lump sumsettlement allowance reduction would bepassed through to PNG(N.E.) as a sharedservices cost reduction. The rationale is that itcould be assumed that much of the globalPNG-West settlement allowance related tocomponents of the administrative costs poolsubject to the time study allocator.Consequently, PNG’s shared service costrecoveries from PNG(N.E.) in 2009 will bereduced by 20.84 percent of the $120,000PNG-West NSP 2009 lump sum reduction.The PNG(N.E.) 2009 cost of service will bereduced accordingly.
The parties agreed to the continuation of theUnaccounted for Gas (“UAF”) volume deferralaccount. PNG is permitted to record all gasgains and the variance between zero percentand a loss of up to 1.0 percent in the UAFvolume deferral account without seekingfurther Commission approval of the deferral.PNG will be required to file an application withthe Commission to obtain approval to recordUAF losses above 1.0 percent in the UAFvolume deferral account. PNG’s UAF volumeforecast of zero percent for 2009 wasaccepted for the purposes of setting theCompany use gas cost recovery rate effectiveJanuary 1, 2009.
PNG will include in each annual revenuerequirements application a summary of thenumber of emergency calls it made during thecurrent year to the date of the application. Thesummary shall specify the average responsetime, the number of calls with a response timegreater than 40 minutes and any otherinformation PNG considers would be useful toparties reviewing these statistics.
The British Columbia Utilities Commission(“BCUC” or “the Commission”) has posted OrderG-40-09 in which it approves the NegotiatedSettlement concerning the 2009 revenuerequirements for Pacific Northern Gas (N.E.)Ltd. (“PNG(N.E.)”). A copy of the NegotiatedSettlement Agreement (“NSA”) is attached to theCommission’s Order. BCUC also issued thefollowing directives:
PNG (N.E.) was directed to file an amendedSummary of Rates and Bill Comparisonschedules based on the NSA.
PNG was directed to refund to customers thedifference between permanent 2009 rates andthe interim rates, with interest, in accordancewith Commission Order G-183-08.
Among the matters agreed to in the NSA werethe following:
The parties agreed that a portion of the PNG-West Negotiated Settlement Process (“NSP”)2009 lump sum settlement allowancereduction would be passed through toPNG(N.E.). The rationale is that it could beassumed that much of the global PNG Westsettlement allowances related to componentsof the administrative cost pool subject to thetime study allocator. Consequently, PNG’seffective shared service cost recoveries fromPNG(N.E.) in 2009 will be reduced by justover $25,000 (i.e. time study allocator of 20.84percent times PNG-West NSP 2009 lump sumsettlement allowance of $120,000). Inaddition, shared services costs will be reducedto the extent pooled costs are lower as aresult of the PNG-West NSP 2009 settlementagreement.
PNG agreed to reduce the budgeted 2009gasoline price from $1.426/litre to $1.10/litre.
The applied for 2009 capital additions budgetwas accepted by the parties with themodification that additions in the Fort St.John/Dawson Creek division for transportationequipment under Account 484 were to bereduced to reflect the agreement not toreplace Mobile Unit 335 in 2009.
The parties acknowledged that PNG(N.E.)’srelatively small customer base made it difficultto be at the forefront of implementing DemandSide Management (“DSM”) programs in itsservice area. However, PNG(N.E.) willcontinue to actively participate in provincialgovernment and industry working groupsfocusing on which DSM programs toimplement throughout the province.PNG(N.E.) will focus its efforts on targetingDSM programs which can help its lowerincome customers reduce their energy useand costs. This is in recognition of the uniquecircumstances faced by customers who maynot be able to afford to purchase higherefficiency natural gas appliances but at thesame time may have the greatest need toreduce their energy use to achievecorresponding cost savings.
The parties agreed that a new deferralaccount should be implemented to record thecosts incurred by PNG(N.E.) to implementInternational Financial Reporting Standards(“IFRS”) and agreed it should be set up as arate base deferral account.
The parties accepted the continuation of thepre-existing Industrial Customer DeliveriesDeferral Account (“ICDDA”) deferral accountsfor Fort St. John/ Dawson Creek (“FSJ/DC”)and Tumbler Ridge (“TR”).
PNG(N.E.) will include in each annual revenuerequirements application a summary of thenumber of emergency calls it made during thecurrent year to the date of the application. Thesummary will specify the average responsetime, the number of calls with a response timegreater than 40 minutes and any otherinformation PNG(N.E.) considers would beuseful to parties reviewing these statistics.
May 7, 2009
BCUC Reminds Gas Marketers to SubmitTheir Price Information As Required byCommission Order No. G-9-09
The British Columbia Utilities Commission(“BCUC” or “the Commission”) has issued LetterNo. L-30-09 in which it notes that Ag EnergyCooperative Ltd., MxEnergy (Canada) Ltd., andNexen Energy Solutions did not submit their
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rates for May 2009 for the Terasen Gas WebsitePrice Depository as required in CommissionOrder G-9-09. BCUC reminds those parties thatfollowing a hearing, they may have their GasMarketer Licence suspended for a period of timeif they do not submit their price information toTerasen Gas Inc. (TGI”). The Commission addsthat habitual non-compliance may result inlengthy suspension periods.
BCUC asks parties to note that CommissionOrder G-9-09 dated February 19, 2009 stated:
“Gas Marketers are to submit price datadirectly to TGI for the Market PriceDepository website at least one fullbusiness week prior to the end of eachmonth beginning March 24, 2009. Thisinformation is to be provided as acondition of maintaining a Gas MarketerLicence.”
May 7, 2009
Terasen Applies to BCUC to Sell LNG asTransportation Fuel
Terasen Gas (“Terasen”) has announced that ithas applied to the British Columbia UtilitiesCommission (“BCUC” or “the Commission”) forapproval to sell liquefied natural gas (“LNG”) asa transportation fuel source for fleet vehicles. Ifapproved, the proposed rate schedule will helpcustomers find solutions to managetransportation costs, reduce emissions, optimizeexisting company assets and support andadvance the provincial government’s EnergyPlan.
The announcement says that, as atransportation fuel, LNG will result inapproximately 20 per cent less carbon dioxide(“CO2”) and 50 per cent less nitrous oxideemissions than diesel. Using LNG as a fuelsource also provides cost savings to fleetoperators, as LNG is approximately 30 per centless expensive than diesel.
Terasen believes an approved rate schedule willprovide assurance of supply and sales costcertainty to fleet vehicle and LNG refuellingstation owner-operators, thereby enabling themarket to develop. LNG sales would originatefrom the company’s Tilbury LNG storage facilityin Delta, complementing its existing usage.
The announcement states that an approved rateschedule supports the B.C. government’sRequest for Expressions of Interest (“REI”) in anLNG Port Container Truck DemonstrationProgram at Port Metro Vancouver. Terasennotes that if its application is approved, it willalso support Wastech Service’s plan to convertits fleet to LNG trucks for hauling solid wastefrom Vancouver to Cache Creek’s landfill site,and that the refuelling stations could beestablished and operational within three months.
May 5, 2009
BCUC Grants Terasen Gas WhistlerApplication for Reconsideration of Decreasein Conversion Costs
In response to a letter dated April 17, 2009 fromTerasen Gas (Whistler) Inc. (“TGW”) requestinga reconsideration of the British Columbia UtilitiesCommission (“BCUC” or “the Commission”)’sdirection to TGW in the TGW 2009 RevenueRequirements and Return on Equity and CapitalStructure Decision to decrease the amount ofconversion costs by $1.076 million, theCommission has issued Letter No. L-29-09 inwhich it grants TGW’s request.
In this latest letter, BCUC advises that theCommission Panel finds that the April 17, 2009letter from TGW raises a valid concern regardingthe potential likelihood of an error in theDecision, which directs TGW to decrease theamount of conversion costs by $1.076 million.Accordingly, BCUC states that the CommissionPanel finds that TGW has been able toestablish, on a prima facie basis, that there is apotential likelihood of an error in fact or law inthe direction to TGW to decrease the amount ofconversion costs by $1.076 million.
The Commission Panel says that it concurs withTGW’s view that the ReconsiderationApplication is very limited in scope and that anabbreviated process is suitable for thedisposition of the Reconsideration Application.Therefore, the Panel has decided to proceeddirectly to the second phase of thereconsideration. The Commission Panel advisesthat, in this situation, submissions from TGWand the British Columbia Old Age Pensioners’Organization et al (“BCOAPO”) would not assistthe Panel in making a decision.
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Electricity
May 26, 2009
BCUC Approves Establishment by BC Hydroof a Regulatory Account for Home PurchaseOffer Program
Further to Order in Council No. 205 dated March12, 2009 wherein the Lieutenant Governor inCouncil made Direction No. 1 to the BritishColumbia Utilities Commission (“BCUC” or “theCommission”) requiring that the Commissionallow the British Columbia Hydro and PowerAuthority (“BC Hydro”) to establish a regulatoryaccount for the purposes of recovering from itsratepayers, in a subsequent period, the netHome Purchase Offer Program (“HPOP”) costswhich the utility incurs during its 2009 and 2010fiscal years, BCUC has issued Order No. G-55-09 in which it authorizes the establishment ofsuch an account (“the HPOP RegulatoryAccount”) inclusive of interest at BC Hydro’sweighted average cost of debt for its most recentfiscal year. The Commission further directs thatthe costs accumulated in the HPOP regulatoryaccount may be subject to a prudency reviewwhich will be performed along with the review ofBC Hydro’s next revenue requirementsapplication.
The Commission notes that BC Hydro estimatesthe net HPOP costs it will incur during F2009and F2010 to be approximately $8.2 million. Thetotal net HPOP costs are estimated to be around$23 million, based on estimated propertyacquisition costs of $62 million offset byestimated sales proceeds of $59 million, withadministration, finance and energy efficiencyimprovement costs estimated at $20 million.
May 7, 2009
BCUC Approves Amendments to BC HydroTariff With Respect to Customers PurchasingPower to Replace Power They have Sold
The British Columbia Utilities Commission(“BCUC” or “the Commission”) has releasedOrder No. G-48-09 and a concurrent Decision inwhich it approves, subject to certain conditionsand directions, an application by the BritishColumbia Hydro and Power Authority (“BCHydro”) for approval to amend section 2.1 of thePower Purchase Agreement (“PPA”) to clarify
that electricity purchased by FortisBC Inc.(“FortisBC”) under the PPA cannot be sold toFortisBC customers to replace electricity to besold by those customers.
In arriving at its findings, the Commission Panelexpressed the view that a more global solutionto the issue of reselling or “arbitrage” of powerwould be preferable and that a Commission“rule” or “regulation” might have been a viableway to proceed. However, in the end, the Paneldecided that the record in the proceeding andthe limited number of parties participating, didnot permit or support a more general solution orremedy. The Panel suggested that, as the powerexport market for BC generators and theiragents (BC Hydro, Powerex, FortisBC,Independent Power Producer (“IPP”) s, resellersand marketers etc.) matures, the Commission orthe Government may choose to establishguidelines, rules or regulations to deal with themarkets and to spell out the permitted roles andoperational rules which will be open to thevarious players province-wide.
Among the conditions and directives set out bythe Commission in the Decision were thefollowing:
The Commission Panel determined that it hadjurisdiction to consider the application.Further, it found that the provisions of the PPAdid not specifically address the kinds oftransactions now before it. Therefore, in theview of the Panel, the application did notinvolve “contractual interpretation” or“clarification” as was suggested by BC Hydro,but involves the setting of a “rate” within themeaning of the Utilities Commission Act (“theAct”).
The Panel found that the provisions ofsubsections 59(4)(a) and (b), and 59(5)(c) doprovide sufficient flexibility to found theCommission’s jurisdiction to order anamendment to a contract in the fact situationof this proceeding. The Panel further foundthat the current arrangement between BCHydro and FortisBC results in a rate whichcould result in undue discrimination orpreference within the meaning of subsection59(4)(b) and that the contract is therefore
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unjust or unreasonable within the meaning ofthe Act.
The Commission Panel was persuaded that arate allowing for the sale of power by self-generators, not in excess of their historicalloads, is unjust and unreasonable andtherefore contrary to the public interest. ThePanel expressed the view that the generalprinciples enunciated in Order G-38-01 oughtto be extended to customers of FortisBC.BCUC later added that it generally believedthat self-generators should be able to sell anyself-generated power which is not required bytheir base loads. The Panel decided that theremust be a simple definition of what constitutes“excess power” and it defined that term tomean power “net of load on a dynamic basis.”The Panel determined that any self-generators, as owners of the generationfacilities, should have the flexibility to reducedomestic load as they see fit in thecommercial circumstances at hand in order tooptimize the export of self-generated power.What would not be permitted is the supply ofembedded cost power to service the domesticload, at any time when the self-generator isselling power into the market.
The Panel directed BC Hydro, in consultationwith FortisBC, to identify and submit to theCommission an agreed methodology tomonitor “net of load” energy within 90 days ofthe date of the Decision.
The Panel made no determination as to thetreatment of any new or incrementalgeneration capacity added by self-generatorssaying that that issue can be dealt with in thefuture on a case by case basis.
BC Hydro was directed to provide a report tothe Commission which will summarize theterms and conditions of its contractualarrangements with any of its industrialcustomers with self-generation capacity whomay sell power on a basis which isinconsistent with the “net of load” concept asenunciated in the Decision.
The Panel directed that section 2.1 of the PPAbe amended to read as follows:
1. The electricity purchased under this
agreement is solely for the purpose ofsupplementing FortisBC’s resources toenable it to meet its service area loadrequirements and, shall not be exportedor stored, provided that nothingcontained herein shall prohibit FortisBCfrom storing its entitlement resources inits entitlement account pursuant to theCanal Plant Agreement; and
2. shall not be sold to any FortisBCcustomer when such customer is sellingself generated electricity which is not inexcess of its load.
The Panel added that the secondparagraph was to prevent FortisBC self-generating customers from purchasingpower at regulated embedded cost ratesand simultaneously selling an equivalentamount of power into available domesticand export markets.
With respect to a question from BC Hydrowhether FortisBC ought to be required toprovide, on its website or on an open accesssame-time information system (“OASIS”), itstransmission transactions, the Commissionrequested that FortisBC file a writtenstatement within 90 days of the date of theDecision as to its intentions to provide suchtransparency.
The British Columbia Utilities Commission(“BCUC” or “the Commission”) has issued OrderNo. G-46-09 in which, in response to an April 9,2009 request from the Joint Industry ElectricitySteering Committee (“JIESC”) that theCommission reconsider and reverse the part ofthe Decision accompanying Order G-16-09which approved the British Columbia Hydro andPower Authority (“BC Hydro”) fully recovering itsproposed operating costs in F2009, BCUC hasreaffirmed its original findings .
The Commission noted that, by letter dated April15, 2009, it had already declined to grant anassociated request from the JIESC that it clarify,and if necessary revise, the accounting
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treatment of the amortization of Demand-SideManagement (“DSM”) expenditures but thatBCUC had determined that the instant issueshould be allowed to proceed to the secondstage of the reconsideration process.
In the Reasons for Decision accompanyingOrder No. G-46-09, the Commission Panelnotes that in its Determination, in respect ofF2010, at the first paragraph on Page 221 of theDecision, is clear and unambiguous, and that it“directs BC Hydro to establish rates for F2010 inits compliance filing … that reflect its operatingcosts for that year …. at 97% of those applied-for …” BCUC says that the JIESC provides nobasis in its submissions or Reply to establishany error in that Determination.
BCUC goes on to rule that the rates establishedfor F2009 and F2010 reflect the revenuerequirements so determined by the Commission,and as such are not “unjust, unreasonable orunduly discriminatory”. Accordingly, BCUCdenied the JIESC’s application forreconsideration of the Decision on the basis thatthe Commission had erred.
General
May 29, 2009
FortisBC Announces $105 Million DebentureOffering
FortisBC Inc. (“FortisBC”) has announced that ithas priced an issue of $105 million medium termnote debentures under its shelf prospectus, andthe issue is expected to close on June 2, 2009.The syndicate for the issue was led by ScotiaCapital Inc. and includes CIBC World MarketsInc., HSBC Securities (Canada) Inc., NationalBank Financial Inc. and RBC DominionSecurities Inc.
According to the announcement, FortisBC plansto use the net proceeds for general corporatepurposes, including repayment of existingindebtedness and financing the company’scapital expenditure program and working capitalrequirements.
FortisBC advises that the debentures will bearinterest at a rate of 6.10% per annum, payablesemi-annually, and will mature on June 2, 2039.
May 28, 2009
BCUC Announces Levies for Recovery ofCommission Costs for the 2009/10 FiscalYear
The British Columbia Utilities Commission(“BCUC” or “the Commission”) has issued OrderNo. G-56-09 in which it sets out the amounts itwill be collecting quarterly from the parties itregulates in order to recover its operating costsfor the 2009/2010 fiscal year. BCUC explainsthat the current year’s levy of $0.0076391318per gigajoule (“GJ”), equivalent of energy soldfor the calendar year 2008 for recoveringCommission expenses is based on its 2009/10approved budget minus 2008/09 deferredrevenue and expected recoveries. That figure isthen divided by the total energy sales of theregulated energy utilities for calendar year 2008.BCUC adds that it will recover its expenses fromthe levy calculation on a quarterly basis and mayadjust the fourth quarter billing in order toaccount for additional revenues received orexpenses incurred during the fiscal year endingMarch 31, 2010. The final adjustment for theyear will occur commencing with the first quarterbilling in the following fiscal year of 2010/11.
The Commission notes that the recovery of itsapportioned costs to the Insurance Corporationof British Columbia (“ICBC”) and BritishColumbia Transmission Corporation (“BCTC”)requires a different method of cost recoveryrather than by way of a levy on energy sales.BCUC says that for ICBC and BCTC, theCommission has estimated the costs of theservice furnished, including its Commissioner,staff and apportioned administrative office costsfor 2009/10, and may adjust the last quarterlybilling to these companies.
In the Order, BCUC sets out the amountspayable by each utility, the upstream natural gasprocessors and intraprovincial oil pipelines andthe total estimated amount to be collected frommarketers.
May 19, 2009
FortisBC Announces $300 Million MediumTerm Note Debenture Program
FortisBC Inc. (“FortisBC”), an indirect whollyowned subsidiary of Fortis Inc., has announced
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that it has filed its inaugural preliminary shortform base shelf prospectus to establish aMedium Term Note Debenture Program (the“MTN Debentures”). FortisBC advises that, uponthe filing of the (final) short form base shelfprospectus (the “Shelf Prospectus”), it may, fromtime to time during the 25 month life of the ShelfProspectus, issue MTN Debentures in anaggregate principal amount of up to $300million.
FortisBC advises that it expects to enter into aDealer Agreement with certain affiliates of agroup of Canadian chartered banks inconnection with the MTN Debenture program.
N E W B R U N S W I C K
Natural Gas
May 29, 2009
NBEUB Approves Revised Market-BasedFormula for Enbridge Gas New Brunswick
The New Brunswick Energy and Utilities Board(“NBEUB” or “the Board”) has issued a Decisionin which it approves a revised market-basedformula for the setting of rates for Enbridge GasNew Brunswick (“EGNB”).
The NBEUB reports that, following a series oftechnical conferences which unsuccessfullyattempted to arrive at a new market-basedformula by consensus, and a directive from theBoard that it file a market-based formula byJanuary 26, 2009, EGNB submitted evidence inwhich it proposed a formula based on existingprinciples and methodology with somemodifications and clarifications. The proposedformula would calculate all numbers to fourdecimal places except in the case of the typicalannual natural gas consumption, which would becalculated to the nearest gigajoule (“GJ”). Ageneral description of that formula, which wasbased on the recommendations of Michael Ervinof MJ Ervin and Associates (“MJ Ervin”), is setout in the Board’s Decision.
The NBEUB notes that, while there wasdiscussion of the elements of the formula, noIntervenor challenged the method of calculatingthe formula. The Board also notes that noIntervenor provided any evidence to support anychanges to the formula nor provided an
alternative formula.
The NBEUB says that it had reviewed theevidence submitted by EGNB; found that it wasreasonable and accepted the formula asproposed by EGNB. The Board further acceptedthe use of Barchart.com for market informationand ordered that market information be collectedfrom this source unless otherwise approved bythe Board. The NBEUB said that these changeswould provide more transparency to thecalculation of rates as well as a moreappropriate balance between providing flexibilityto EGNB and predictability to the customer. Withrespect to Typical Annual Natural GasConsumption and Contract Demand, the Boardsaid it will require EGNB to file updated figuresand supporting data with each application for anincrease in the maximum rates or, in theabsence of an application, the information is tobe updated annually by July 31st for the 12months ending on June 30th. For the purpose ofRate Riders and Reinstatements, the mostrecent data, filed with the Board, on TypicalAnnual Natural Gas Consumption and ContractDemand is to be used.
Among the NBEUB’s other findings were thefollowing:
It accepted the use of 21 days of market datafor rate riders and rate reinstatements.
With respect to Rate Riders andReinstatements, the Board said that it willentertain requests from EGNB to vary the rateas calculated by the formula. The Boardcautioned that such a request will only begranted if it is convinced the variance is in thepublic interest. The NBEUB added that suchrequests should provide all of the normalinformation plus the rates being requested andthe rationale as to why the rate indicated bythe formula should not be used. The Boardalso added that it does not find it appropriateto allow third parties to request rate riders orrate reinstatements.
The Board ruled that it would not approve acap which would apply when establishing themaximum distribution rates, as such a limit orcap would be in conflict with the objectives ofthe market-based rates methodology.
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The NBEUB found that the benefits achievedby quarterly rate setting do not outweigh thebenefits of a rapid response to marketconditions. The Board said that it will continueto use the system of rate riders andreinstatements together with an adjustment tothe maximum distribution rates on an annualor less frequent basis.
May 21, 2009
New Brunswick Government to Review FERCDraft Impact Environmental Impact Study forDowneast LNG Terminal Project
Following the release by the staff of the U.S.Federal Energy Regulatory Commission(“FERC” or “the Commission”) of a draftEnvironmental Impact Study (“EIS”) for theDowneast liquefied natural gas (“LNG”) terminalproject, the Government of New Brunswick hasannounced that it will comprehensively reviewand assess the EIS and will also takeappropriate action as a formal intervener in theFERC proceeding.
The announcement says that the Commissionhas jurisdiction over the development of thisproject on United States soil and in UnitedStates waters. The Government adds that FERCstaff has recommended nearly 100 very seriousconditions be imposed on the project in theevent this project were ever to move forward.
New Brunswick also notes in the report thatthere is mention of resources or effects on theCanadian side of the border which are clearlybeyond the authority or jurisdiction of FERC.The announcement says that, for example,references to the application of the NewBrunswick Endangered Species Act, or anyother Canadian or provincial law, are misplaced.
The Government adds that it is involved in theFERC process in order to ensure that NewBrunswick's safety and security concerns, aswell as the environmental and economic impactsof these facilities on New Brunswick residentswho live along Passamaquoddy Bay, are notdismissed and are forcefully defended.
The announcement advises that the decision onLNG vessels transiting Head Harbour Passageand matters pertaining to Canadian territorialwaters is the exclusive jurisdiction of the
Government of Canada and is outside the FERCprocess.
Electricity
May 20, 2009
NB EUB Releases Consultant’s Report onProposed 3% Increase in Rates for NB PowerDistribution and Customer ServiceCorporation
In the context of a proceeding being carried outpursuant to a directive from the Minister ofEnergy, the New Brunswick Energy and UtilitiesBoard (“NB EUB” or “the Board”) has released areview conducted by the consulting firm, TeedSaunders Doyle and Co., (“TSDC”) of theevidence submitted by the NB PowerDistribution and Customer Service Corporation(“DISCO”) in support of its proposed 3%increase in rates. The Board’s Notice withrespect to the Minister’s directive was thesubject of a CERISE What’s New Alert datedApril 7, 2009.
In its report TSDC dealt with forecast purchasepower expense and the Petroleos de VenezuelaSA (“PDVSA”) Settlement Deferral Account.With respect to the former, TSDC said that,based on the review procedures conducted andthe results obtained, nothing came to itsattention that would cause it to believe thatDISCO’s forecast purchase power expense forthe fiscal year ended March 31, 2010 ismaterially misstated. It went on to further advisethat the amount forecast appeared to bereasonable and plausible based on these resultsof its work. TDSC noted that perhaps the mostcritical assumption made in preparing theforecasts was the back-in-service date ofOctober 1, 2009 for the Point LepreauGenerating Station (“PLGS”) and went on todiscuss the implications of a delay in that dateon the costs filed.
TSDC’s conclusions with respect to the PDVSASettlement Deferral Account were that all Boardorders had been properly implemented and thatthe review produced no evidence that wouldindicate that the assumptions used and themethodologies implemented were notreasonable. TSDC said that the levelized benefitincluded in the forecast for 2009/10 wasplausible in the circumstances.
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May 15, 2009
New Brunswick Board Issues Decision onNBSO Revenue Requirement for 2009-2010
The New Brunswick Energy and Utilities Board(“NB EUB” or “the Board”) has issued a Decisionin which it approves, with some adjustments, the2009-2010 revenue requirement for the NewBrunswick System Operator (“NBSO”).
The NB EUB says that, with respect to Schedule1 (Scheduling, System Control and DispatchService) the NBSO applied for a revenuerequirement in the amount of $10.265 millionwhereas the Board approved an amount of$10,234,000. The Board added that it woulddetermine the appropriate amount, on a finalbasis, after it has completed its review of theliability for costs arising from the unfundedpension liability for seconded employees.
For Schedule 2 (Reactive Supply and VoltageControl), the NBSO requested a revenuerequirement in the amount of $5.752 millionwhile the NB EUB approved, on an interimbasis, an amount of $5,703,000. The Boardwent on to say it would determine theappropriate amount on a final basis after it hascompleted its review of the base price inflationadjustment.
The NB EUB included in its Decision a schedulefor the continuation of the revenue requirementhearing to review the Unfunded Pension Liability(Schedule 1) and Escalation Clause (Schedule2).
The Board went on to direct the NBSO tomaintain detailed records on customer usageand payments for Schedule 1 and 2 services sothat any rebate necessary as a result of thereviews could be properly calculated.
Among the adjustments that the NB EUBdirected be made to the NBSO proposals werethe following:
Schedule 1
Labour and Benefits – The Board:
Approved funding for the 6 additional staffpositions;
Recognized the effect of the Governmentwage freeze initiative on the cost of living
increase for non-union employees andreduced the Labour and Benefits forecast by$6,000 and;
Denied the Public Intervenor’s request for astaff classification and compensation review.
Approved, on an interim basis, the amount of$215,000 for the unfunded pension liability;
Ordered the continuation of the hearing inorder to fully investigate the NBSO’sresponsibility to pay for the costs of theunfunded pension liability for secondedemployees and;
Will require the NBSO and Transco to attendand to argue the merits of the SecondmentAgreement, its ensuing liabilities and the basisfor determining how the liability wasdetermined.
Purchasing and Other Requirements - The NBEUB ordered the NBSO to develop a formalpurchasing policy including a process for use ofRequests for Proposals (“RFPs”) whereapplicable. The Board added that the policymust be available for review by parties in futurerevenue requirement reviews.
Schedule 2
Pricing for Grand Lake Generator - Noting thatthe NBSO could not explain why the price underthe Grand Lake Generator contract for megavoltage ampere resistance (“MVARs”) is$307/MVAR per month while other similarsuppliers were paid $207/MVAR per month, theBoard determined that the latter was theappropriate price and it directed that the revenuerequirement to be reduced by the amount of$48,733 to recognize the reduction in the rate tobe paid for MVARs.
Escalation of Base Prices – the Board said itwas not in a position to rule on theappropriateness of the escalation clause in theAncillary Services Contract since no review ofthat contract had been conducted. Noting that ahearing will be held in respect of the unfundedpension liability under Schedule 1, the Boardsaid it believed that arguments in respect of theescalation clause under Schedule 2 should alsobe heard at that time.
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May 12, 2009
Government of Canada Provides Funding forKent Hills Wind Farm in New Brunswick
Natural Resources Canada (“NRCan”) hasannounced that, through the ecoENERGY forRenewable Power Program, the Government ofCanada will invest $29 million in the Kent HillsWind Farm, New Brunswick’s first commercialwind farm.
According to the announcement, the 96megawatt (“MW”) Kent Hills Wind Farm islocated 30 kilometres from Moncton, in AlbertCounty. The wind farm will provideapproximately 290,000 megawatt hours (“MWh”)of electricity per year from its 32 turbines withthe electricity being sold to New BrunswickPower (“NB Power”).
N E W F O U N D L AN D
Electricity
May 29, 2009
Newfoundland Power Files for Rate Changeson July 1, 2009 and January 1, 2010
Newfoundland Power Inc. (“Nfld Power”) hasfiled two applications with the Newfoundland andLabrador Board of Commissioners of PublicUtilities (“Nfld PUB”) proposing changes toelectricity rates for its customers on July 1, 2009and January 1, 2010. If approved by the NfldPUB, the net impact of the proposed ratechanges will be an overall average decrease tocurrent electricity rates of approximately 0.5%.According to Nfld Power, the electricity rates inJanuary 2010 will be, on average, similar tothose in January 2009.
Proposed July 1, 2009 rate decrease
For July 1, 2009, Nfld Power is proposing anoverall average decrease to current electricityrates of 6.6%, and this proposed decreaseresults from the annual review of the RateStabilization Account (“RSA”). The RSAprovides for adjustment to electricity rates eachyear on July 1 to reflect the price and amount ofoil used by Newfoundland and Labrador Hydro(“Nfld Hydro”) in the generation of electricity.
Nfld Power expects that the Nfld PUB willconsider and rule on this application over the
next several weeks to allow an appropriate rateadjustment to be implemented on July 1, 2009.
Proposed January 1, 2010 rate increase
For January 1, 2010, Nfld Power is proposing anoverall average increase to current electricityrates of 6.1%, and this proposed increaseresults from a review of the company’s costsand customer rates which have been filed aspart of its 2010 General Rate Application(“GRA”).
Nfld Power explains that another driver behindthe GRA is the cost associated with the deliveryof electricity, a significant portion of which is theresult of connecting a growing number of newhomes to the electricity system and deliveringmore electricity to its customers. The otherprincipal cost driver relates to changes inaccounting practices for retirement costs.
Based on a detailed review of costs andcustomer usage patterns, in this GRA, NfldPower is proposing that the rate increase varyacross each of its customer categories. Theproposed average increase ranges from 4.1% to6.1% for commercial categories and 6.8% forresidential customers.
Nfld Power expects that its GRA will be subjectto a thorough public review by the Nfld PUB overthe coming months.
May 27, 2009
Nfld PUB Approves Nfld Hydro’s Recovery ofCosts of Burning 0.7% Sulphur Content No. 6Fuel Through Rate Stabilization Plan
The Newfoundland and Labrador Board ofCommissioners of Public Utilities (“Nfld PUB” or“the Board”) has issued Order No. P.U. 20(2009)in which it approves the recovery ofNewfoundland and Labrador Hydro’s (“NfldHydro” or “NLH”) costs of burning 0.7% sulphurcontent No. 6 fuel at the Holyrood ThermalGenerating Station through the operation of theRate Stabilization Plan (“RSP”) after March 31,2009. The Board further directs that the costs ofthe fuel must be calculated in accordance withthe usual operation of the RSP from March 31,2009.
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May 27, 2009
Nfld PUB Approves Nfld Power’s Recovery ofDemand Management Incentive AccountBalance as of March 31, 2009
In response to an application by NewfoundlandPower Inc. (“Nfld Power” or “NPI”) datedFebruary 27, 2009, the Newfoundland andLabrador Board of Commissioners of PublicUtilities (“Nfld PUB” or “the Board”) has issuedOrder No. P.U. 21(2009) in which it approvesthe disposition of the 2008 balance in theDemand Management Incentive (“DMI”) Accountas well as the related income tax effects bymeans of a credit in the amount of $641,336 tothe Rate Stabilization Account, as of March 31,2009.The Board notes that the amount of$641,336 consists of the 2008 DMI Accountbalance of $426,488 plus the related income taxeffects of $214,848.
May 11, 2009
Nfld PUB Approves Nfld Hydro Application toInstall Cold Reheat Condensate Drains andHigh-Pressure Heater Trip on Unit 2 at theHolyrood Thermal Generating Station
The Newfoundland and Labrador Board ofCommissioners of Public Utilities (“Nfld PUB” or“the Board”) has released Order No. P.U.19(2009) in which it grants an application byNewfoundland and Labrador Hydro (“NLH” or“Nfld Hydro”) for approval of an expenditure of$191,600 for the installation of cold reheatcondensate drains and high-pressure heater tripon Unit 2 at the Holyrood Thermal GeneratingStation.
General
May 11, 2009
Government of Newfoundland and LabradorProvides Update on 2008-2009 Home HeatingRebate Program
The Government of Newfoundland and Labradorhas issued and read in the House of Assemblyan update on its 2008-2009 Home HeatingRebate Program.
The government notes that this is the fifthconsecutive year it has provided assistance toindividuals and families associated with the highcost of heating their homes; that the program
has been expanded to include electricity, andthat the income threshold has been increased to$40,000 or less. The update adds thatapproximately 76,000 families are eligible for therebate, and advises that the rebate wasincreased for coastal Labrador communities dueto the high costs associated with home heatingfuel in that region.
The update explains that, under the program,eligible residents receive up to $300 in rebate forhouseholds which use heating oil, stove oil orpropane, up to $200 for households which useelectricity or wood, and up to $500 for thoseliving in coastal Labrador communities. Familieswith a net income up to $35,000 receive a fullrebate. The rebate gradually decreases asincome levels rise to $40,000, with no eligiblefamily receiving less than $100.
The government notes that approximately67,000 applications have been approved, with avalue of $15.3 million processed to date.
N O R T H W E S T T E R R I T O R I E S
Electricity
May 12, 2009
NWT PUB Approves Adjustments toNorthland Utilities (NWT) Limited Rider A forthe Communities of Trout Lake and Wekweti
The Public Utilities Board of the NorthwestTerritories (“NWT PUB” or “the Board”) hasissued Decision 12-2009 wherein it approves anApril 14, 2009 proposal by Northland Utilities(NWT) Limited (“NUL” or “Northland”) to adjustRider A for the communities of Trout Lake andWekweti.
The NWT PUB noted that NUL stated in itsapplication that it had completed its currentquarterly review of Rider A for each of the ratezones. Northland proposed that an exception tothe normal process be approved for the HayRiver, Fort Providence and Dory Point-Kakisarate zones, and thus proposed no changes tothe rider values up to July 1, 2009. NUL saidthat fuel costs are forecast to be lower thanthose used for the December 12, 2008 Rider Aapplication, and this permitted Northland toprovide an accelerated collection of anyoutstanding balances and bring the balances
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closer to zero than if the rate was re-adjusted tocollect over a 12-month period.
The Board said that NUL also stated that theactual fuel deliveries have occurred for TroutLake and Wekweti at lower prices than theGeneral Rate Application (“GRA”) approvedprices, and thus Northland forecasted asignificant over-collection balance by April 30,2010, using the process described above. NULexplained that the decrease in Wekweti is due,in part, to successful lobbying efforts which haveresulted in the cost of the ice road being coveredby the Government of the Northwest Territories(“GNWT”) as opposed to electrical consumers inWekweti. Northland proposed to reduce Rider Afor Trout Lake and Wekweti.
May 12, 2009
NWT PUB Accepts Northwest TerritoriesPower Corporation Proposal to Leave RateStabilization Fund Riders Unchanged
Further to Decision 26-2008, the Public UtilitiesBoard of the Northwest Territories (“NWT PUB”or “the Board”) has issued Decision 11-2009 inwhich it approves a February 20, 2009 proposalby Northwest Territories Power Corporation(“NTPC”) that no adjustment be made to any ofthe stabilization fund riders at this time and thatfuel prices, water availability and ridercollections be updated when NTPC files its nextstabilization fund. The NWT PUB reports that,although the fuel funds might not be projected toachieve zero balances by March 31, 2010, all ofthe funds are making progress towards thattarget. NTPC stated that it will be in a betterposition to propose adjustments to the fundsbased on actual winter resupply prices andupdated summer resupply price forecasts at thetime of its August 2009 application.
NTPC further noted that, with respect to theSnare/Yellowknife water stabilization fund, thebalance is expected to be slightly higher thanthe $3 million trigger by March 31, 2010. NTPCstated, at the current load levels, therequirement for diesel generation is dependentlargely on the water availability on the hydrosystem and NTPC would be in a better positionto forecast the water levels at the time of theAugust 2009 stabilization fund update filing,following the spring run-off period.
The NWT PUB said that, while world oil priceshad been in the $35-$45/barrel (US dollars)range earlier this winter, oil prices have nowincreased back into the $50-$55/barrel range.The Board suggested it is preferable for asmuch as possible of the outstanding fundbalances to be collected prior to furtherincreases in oil prices above the price (about$64/barrel) currently established in the rates.The Board expressed concerned about thepotential need for significant “keep up”collections on top of the current “catch up”components of the fund riders. It was theBoard’s view that decreases to the stabilizationfund riders at this time could hinder thecollection of the outstanding balances and makeit less likely that the stabilization fund balanceswill achieve the targets which have been set forMarch 31, 2010.
Therefore, the NWT PUB accepts the NTPCsuggestion that there be no changes to thestabilization fund riders until NTPC files its nextstabilization funds update with the Board byAugust 15th with potential changes to thestabilization fund riders for October 1st.
May 12, 2009
NWT PUB Releases Findings With Respect toCustomer Complaints ConcerningAbnormally High Usage
The Public Utilities Board of the NorthwestTerritories (“NWT PUB” or “the Board”) hasissued Decision 13-2009 in which it sets out itsfindings following a proceeding held in responseto formal and anecdotal complaints bycustomers of Northland Utilities (NWT) Limitedand Northland Utilities (Yellowknife) Limited(collectively “Northland” or “NUL”) with respectto abnormally high usage as compared tohistorical usage patterns.
Among the directives set down by the Boardwere the following:
Northland was directed, within 30 days of thedecision, to develop and submit for approval adocument to be given to customers, either asa result of a complaint or a process initiated byNUL, regarding high consumption issues. Thedocument should clearly outline the rights andresponsibilities of both the utility and the
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customer in an investigation process andshould at a minimum include the following:
Designated Northland person fordealing with customer concernsincluding contact information.
Explanation of the options available tothe customer, including associatedcosts, such as meter reread, meterchange and testing, voltagemeasurement and an on-site meetingwith NUL to review and discuss thecustomer’s historical and currentelectrical usage.
Explanation of the budget paymentplan to equalize electrical bills overthe year.
Explanation of what the customermight need to do to try to understandtheir electrical usage such asconducting an electrical inspection orinvestigating the possibility ofelectrical theft.
Contacts for outside organizations,such as the Arctic Energy Alliance,which are available to provideassistance to customers.
Contact information for the NWT PUB.
The Board directed NUL to reduce the $500threshold to $400.
The NWT PUB directed Northland, within 30days of the decision, to file with the Board aproposed standard or threshold, withsupporting rationale, upon whichcommunication with a customer would beinitiated quickly and automatically by NULafter an unusually high consumption meterreading to discuss the options available for thecustomer if further investigation is required.
The Board directed Northland to takereasonable steps to ensure that no customerreceives estimated bills more than once everyfour months in order to minimize customerimpacts.
The Board directed NUL to include oncustomer bills an explanation of the possibleimpacts of the reconciliation of estimated bills.
The Board directed Northland to limit billingcycles to a maximum of 32 days once AMR isin place.
The Board directed NUL to add a prominentbox to its bills identifying the customer’sconsumption for the month.
Northland was directed to calculate, and showin a prominent box on its bills, an overallelectrical cost per kilowatt hour (“kwh”) foreach customer’s bill which consists of all costsand credits divided by the total consumption.This calculation is to include the TPSP butexclude the GST.
The NWT PUB directed NUL, within 30 daysof the decision, to provide the Board with asample bill for approval which demonstrateshow NUL will comply with these directions onbill design.
The Board directed Northland to have billcalculators on its website by the end of May2009 for residential and general servicecustomers for each NUL community. Thesebill calculators should allow customers to inputa level of consumption to see in detail how thetotal cost of a bill is obtained. The customersare to be able to use these bill calculatorsdirectly on the NUL website as well as beprovided with links to downloadable billcalculators in Excel file format. The existenceof these calculators is to be prominently notedon customer bills. These bill calculators arealso to be updated quickly after any change inthe electrical rates with the effective date ofthe update noted in the calculators.
The NWT PUB directed Northland to reportback to the Board on its progress in providingin-home customer consumption monitoring byOct. 31, 2009.
The NWT PUB directed NUL to provide theBoard with an update on the issues of prepaidmetering and smart metering as part of thecustomer consumption monitoring report thathas been directed by Oct. 31, 2009.
The NWT PUB directed Northland to purchasean adaptor to allow 2 meters to be installedsequentially and to make this meterverification option available to customers. If
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justified by demand, the Board expects NUL topurchase additional adaptors.
Northland was directed to charge a customer$25 for the installation, use and removal of thesequential meter and adaptor. This fee wouldbe refundable if it is demonstrated that thecustomer’s meter is inaccurate. If the $25 feeis not consistent with cost recovery forinstallation, use and removal of the sequentialmeter and adaptor, NUL may apply to adjustthe fee level.
The NWT PUB directed Northland to test anydamaged meters which are removed if thosemeters are still capable of being tested and toprovide the customers with the results of thetesting.
The Board also set out adjustments which it saidmust be made to the bills of specific customers.
N O V A S C O T I A
Natural Gas
May 1, 2009
Nova Scotia Government Proposes Changesto the Pipeline Act
The Government of Nova Scotia has announcedthat it is proposing changes to the Pipeline Act(“the Act”) which will give the Nova Scotia Utilityand Review Board (“NSUARB” or “the Board”)broader power and more options to ensurecompliance.
The NSUARB has authority to regulate certainpipelines under the Pipeline Act. These changeswill expand the Board's authority around:
permit and licence applications;
monitoring and enforcing orders aroundpipelines and public safety.
The government says that if the amendmentsare passed, it will introduce draft regulations forpublic comment, likely in the fall.
The announcement adds that the Pipeline Actcovers Heritage Gas pipelines and the onshoreSable natural gas liquids line which runs fromGoldboro to the Strait area. The Act does notcover private gas lines in homes and businessesnor the Maritimes and Northeast pipeline.Private gas lines in homes are covered by the
Fuel Safety Act and the Maritimes and Northeastpipeline is regulated by the National EnergyBoard (“NEB”).
Electricity
May 14, 2009
NS Power Invests $1 million Towards theDredging of Sydney Harbour
Nova Scotia Power (“NS Power” or “NSPI”) hasannounced it will contribute $1 million toward theproposed dredging of Sydney Harbour whichwould deepen the shipping channel whichprovides access to the Ports of Sydney toapproximately 17 metres below normal low tide.
NS Power says that the investment will allow itto deliver coal to the area more efficiently, whichwill in turn lower its transportation costs andreduce the cost of electricity for its customers.
NSPI receives more than 1.5 million tonnes ofcoal annually through the International Coal Pierat Sydney Harbour. The coal accounts for about80 per cent of the fuel used to make electricity atthe Point Aconi and Lingan generating stations,which together produce 45 per cent of theelectricity used by Nova Scotians.
May 7, 2009
NS Power Files Biomass Proposal withNSUARB
Nova Scotia Power Inc. (“NS Power” or “NSPI”)has announced that it has applied to the NovaScotia Utility and Review Board (“NSUARB” or“the Board”) for approval of a Power PurchaseAgreement (“PPA”) for renewable energy frombiomass. The proposed project would involveNewPage Port Hawkesbury Corp. and Strait Bio-Gen, which would develop a 60 MW biomass-fuelled electrical generation facility, takingadvantage of existing infrastructure at theNewPage paper mill in Port Hawkesbury. Theannouncement adds that the energy from theproject would be sold to NS Power.
NS Power states that it has contracted with anumber of wind developers for renewableenergy, including 246 MW of wind power undercontract from independent power producers inNova Scotia. The company recently purchasedthe development rights for one of those projects,at Nuttby Mountain, near Truro.
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NS Power goes on to say that, together withNewPage and Strait Bio-Gen, it has applied tothe NSUARB for a review of the terms andconditions of the proposed arrangement. Theapplication requests confirmation from the Boardthat the project is a prudent means of assistingNS Power in meeting the province’s renewableenergy standard and lowering emissions. Theannouncement adds that a hearing is scheduledfor mid-June.
May 5, 2009
NS Power Advises that it has No Plans for2010 Rate Increase
Nova Scotia Power (“NS Power”) hasannounced that, based on current conditions, itdoes not plan to request any increase in baseelectricity rates for 2010.
NS Power advises that current world commodityprices provide reason for optimism that noupward adjustment in rates would occur in 2010through the new Fuel Adjustment Mechanism(“FAM”). Annual fuel adjustments occur in atransparent process before the Nova ScotiaUtility and Review Board (“NSUARB” or “theBoard”), but this happens separately fromchanges to base rates.
The company points out that the decision has noimpact on its commitment to improve reliabilitynoting that work on reliability initiatives is alreadyunder way.
General
May 29, 2009
Nova Scotia Board Dismisses Appeal byShaw Resources of a Decision of the DisputeResolution Officer
Under Docket 2009 NSUARB 70, the NovaScotia Utility and Review Board (“NSUARB” or“the Board”) has issued a Decision in which itdismisses an appeal by Shaw Resources(“Appellant” or “Shaw”) of a decision of theDispute Resolution Officer (“DRO”) to impose apenalty on Shaw under Nova Scotia PowerIncorporated (“Respondent” or “NSPI”)’sInterruptible Rider of the Large Industrial Tariff(“LIIR”).
The Decision explains that on December 2,2007, NSPI issued a request to Shaw to
interrupt power as per the LIIR to which Shawdid not comply and NSPI notified Shaw onJanuary 4, 2008 that the company was liable forthe penalty under LIIR. On March 17, 2008,Shaw contacted the DRO to appeal the penaltyas per the Board approved NSPI Regulations,and on April 27, 2008, the DRO issued hisdecision on and denied the appeal. Shaw thenappealed that decision to the Board on May 9,2008
The NSUARB says that the Appellant’s mainargument was that it did not receive thenotification to interrupt power and therefore itshould not be assessed the penalty under theLIIR. However, NSPI’s position was that thenotification to interrupt power was sent to Shawat the telephone numbers provided by Shaw orits service provider, therefore, NSPI does havethe right to assess the penalty under the LIIR.
The Board said that it considered the followingtwo questions to be the main issues of theappeal:
Did NSPI make the call on December 2, 2007to Shaw to interrupt power?
Did Shaw receive the call from NSPI to dropthe load on December 2, 2007?
With respect to the first question, the NSUARBnoted that no evidence was led by the Appellantwhy 11 of the 12 calls to drop load weresuccessfully sent and complied with, except theone made to Shaw. The Board further noted thatno evidence was led to say if there were anyunique or catastrophic failures in thecommunication system which would haveprevented calls to both the primary andsecondary numbers for Shaw. The Boardexpressed the opinion that there is insufficientevidence, to conclude that the NSPI interruptioncall was not made to Shaw, or its systemprovider, Carlow. The Board said that the totalityof the evidence is more consistent with theinterruption call being made than with thecontrary conclusion, and it found, on the balanceof the probabilities, that the calls were made byNSPI on December 2, 2007, to Shaw (Carlow).
As for the second question, the NSUARB saidthat it found that the Appellant had not met theburden of proof test on the balance ofprobabilities. Accordingly, the Board found that
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the calls were more likely to have been deliveredto Carlow than not, and added that why Carlowdid not act to drop the load for Shaw was notclear.
O N T AR I O
Natural Gas
May 6, 2009
OEB Limits Extension of FranchiseAgreement Between Natural Resource GasLimited and the Town of Aylmer to ThreeYears
The Ontario Energy Board (“OEB” or “theBoard”) has issued a Decision and Orderextending the franchise agreement betweenNatural Resource Gas Limited (“NRG”) and theTown of Aylmer by three years with thefranchise agreement due to expire on February27, 2012. In arriving at this ruling, the OEBfound in favour of the Town of Aylmer which hadbeen prepared to offer a term of three yearswhile NRG had requested a term of 20 years.The Board notes that the integrated GrainProcessors Cooperative (“IGPC”), the largestcustomer in the franchise area also opposed the20 year term.
In its Decision, the OEB noted that unusualcircumstances exist in this case that warrant aterm substantially less than a typical renewalterm in the Model Franchise Agreement. TheBoard cited concerns with NRG’s financialviability and quality of service, as reasons for itsDecision.
The OEB also ordered NRG:
to amend its security deposit policy to complywith procedures set out in Appendix B of theDecision and Order;
to file an application for new rates within sixmonths of this decision for rates to be effectiveOctober 1, 2010; and
to notify the Town of Aylmer of any regulatoryapplication or proceeding NRG brings beforethe Board.
Electricity
May 29, 2009
OEB Issues Decision with Reasons in HydroOne Transmission Proceeding
Pursuant to Board File No. EB-2008-0272, theOntario Energy Board (“OEB” or “the Board”)has issued its Decision with Reasons regardingHydro One Networks Inc. (“Hydro One”)’sapplication for approval of its transmissionrevenue requirement and rates for 2009 and2010. The Board notes that this Decision willimpact delivery rates for all electricity consumersin Ontario.
The OEB notes that Hydro One applied for arevenue requirement of $1,232.7 million for 2009and $1,341.0 million for 2010. The Boardreduced the operating revenue requirements ineach of those years by about $20 million,including reductions of $4 million relatedspecifically to compensation.
The OEB approved most of the projects and theassociated rate impacts proposed by HydroOne, which involved capital expenditurestotalling $897.2 million in 2009 and $854.9million in 2010, but it declined to approve about$180 million in development capital projects. Forthe purposes of 2010 rates the Board indicatedthat it will reconsider these projects if Hydro Oneprovides evidence supporting the projects by theend of November 2009.
The OEB also approved the disposition of threedeferral accounts which will result in an $18.3million reduction in rates over the period July2009 to December 2010.
The Board’s Decision for Hydro Onetransmission revenues will form part of thecalculation of the Uniform Ontario TransmissionRates, which include Ontario’s other transmitters(Great Lakes Power Limited, Five NationsEnergy Inc. and Canadian Niagara Power Inc.).The Uniform Transmission Rate proceeding willbegin shortly with the intent to implement newtransmission rates on July 1, 2009.
The following is an overview of some of theBoard’s findings in the Decision:
Current Economic Conditions: The OEB did notagree that it is appropriate to constrain the relief
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sought by utilities solely on the basis of currenteconomic conditions, agreeing with Hydro Onethat its spending programs are long-term innature and planning for their execution shouldnot be driven by economic cycles. The Boardadded that an adverse consequence of reducingthe applicant’s spending to match an economicdownturn would be to reduce the economicefficiency of asset optimization plans and tointroduce inappropriate volatility in spending.
Load Forecast: The OEB accepted Hydro One’sforecast for the purposes of setting rates, andalso said that it was satisfied with Hydro One’sresponse to the directive regarding a studycomparing weather normalizationmethodologies.
Export Revenues: The Board concluded that itwas appropriate to establish a variance accountto capture any difference between the forecastand actual revenues and that the account shouldbe symmetrical. As a result, the OEB found itunnecessary to adjust the forecast.
With respect to the Independent ElectricitySystem Operator (“IESO”) study of the exporttransmission tariff, focussing on arrangementswith other jurisdictions for an ExportTransmission Service with the intention ofeliminating the tariff, the Board said that it mightnot be necessary to wait for Hydro One’s 2011-2012 application to consider this matter anddirected Hydro One to put forward a proposalwithin 60 days of the release of the IESO study.
External Revenues:
Station Maintenance and Engineering andConstruction – The OEB commented that thiswas not an activity which Hydro One shouldbe incented to undertake, and given therequirements for internal work it was not anactivity which Hydro One should be activelypursuing. The Board made no change to theforecast revenues but determined thatratepayers’ interests were best protected byestablishing a variance account to ensure thatthe full extent of these revenues is to thebenefit of ratepayers while at the same timeprotecting Hydro One.
Secondary Land Use – the Board made nochange to the forecast revenues but directedthat a variance account be established.
Operating and Maintenance Expense (“OM&A”)
Overall OM&A – The OEB declined to make adisallowance based on trend projections, andsaid that, while trend projections are useful asa potential trigger for an examination ofchanging circumstances, they cannot be usedalone to justify a particular level of spending.
Sustaining OM&A – Although Hydro Oneproposed a total spending level of $226.5million in 2009 and $240.1 million in 2010, theBoard found that the evidence provided didnot support this level of expenditure anddisallowed $15 million of the proposedspending in each of the test years.
Development OM&A – The Board did notagree with the Intervenor submission thatdevelopment expenses should be considereddiscretionary and therefore not permitted in arecession but it did disallow the increase of$3.2 million proposed for the 2010 over 2009.
Shared Services and other OM&A - The Boardaccepted Hydro One’s submission on theanomaly which occurred in 2008 regarding theallocation of a portion of the GeneralCounsel’s costs. The OEB also accepted thethird party assessment that the allocation is inline with the methodology previously approvedby the Board.
Compensation – The OEB said that itdifferentiated between collective agreementcontracts from other goods and service relatedcontracts in the context of a review ofprudence. The Board said that it cannot relyon typical market forces to test the prudenceof entering into a collective agreement notingthat there is a single source supplier and thenature of the relationship cannot beconsidered to be arm’s length in the samemanner as stand alone independent goodsand service providers. Noting that there is nostandardized industry-wide method ofcapturing productivity data for comparisonpurposes, the OEB did not accept HydroOne’s claim, backed up by the Mercer Study,that its compensation costs which are overand above the median level of thecompensation paid by its comparators areoffset by its higher than median productivityranking among those same comparators. The
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Board said that there was no evidencesupporting the purported correlation of themegawatt hours (“MWh”) sold andproductivity, which was the performanceindicator that was the primary driver for HydroOne’s relatively high ranking. Concluding thatit was appropriate to disallow somecompensation costs because these costs aresubstantially above those of other comparablecompanies and the company has failed todemonstrate that productivity levels offset thissituation, the Board disallowed $4 million ineach of the test years saying this level ofadjustment goes some way toward aligningHydro One’s costs with other comparablecompanies. The Board went on to direct HydroOne to continue its key performance indicatordevelopment and to improve on its costallocation accounting processes with theobjective of being able to demonstrateimprovements in efficiency and the value fordollar associated with its compensation costs.
Property Taxes – The OEB rejected HydroOne’s claim that the 2% increase inassessments equates in a linear fashion to a2% increase in property taxes assumes that,on average, all other property valuesremained unchanged since the lastassessment. The Board disallowed 2% of theproposed property tax cost in each of the testyears or $1.2 million for 2009 and $1.3 millionfor 2010.
Capital Expenditures:
Hydro One’s Ability to Complete PlannedPrograms – The OEB noted that Hydro Onespent significantly less than it budgeted in2007 and in the first half of 2008 and thus thebudgeted expenditure levels for the test years,which were substantially higher than historicallevels, were beyond what an analysis of justthe recent historical experience would suggestwas achievable. However, the Board said itwas persuaded by Hydro One’s evidence thatthe new work methods explained in its WorkExecution Strategy, and specifically its plan tosubstantially increase the use of outsourcing,had increased Hydro One’s capacity tocomplete its planned work considerably.Accepting that any over collection resultingfrom capital expenditures being less than
budget would be short-term in nature becauserate base will be corrected in Hydro One’snext application, the Board said it would relyon its usual manner of testing and setting ratebase at the next cost of service proceedingand would not order that expenditures betracked in a variance account.
Sustaining Capital – Noting that the sustainingcapital program was not increasingsubstantially from 2008 to 2009, and findingthat the need for the15% increase in 2010related to Stations assets had been clearlydemonstrated, the Board said it was satisfiedthat Hydro One had substantiated the need forits proposed sustaining capital for both testyears.
Development Capital – The OEB found thatProjects D3, the installation of capacitor banksand D4, protection system modifications, werejustified on the basis of their relationship to theapproved Bruce to Milton Transmissionfacility. The Board approved Project D5, theunbundling of 500 kV circuits betweenClaireville and Cherrywood TransmissionStations and the cost consequences. TheBoard approved and allowed the costconsequences for Project D6, SVCreplacement at Lakehead TS, which involvesthe installation of a replacement 230kV SVC.On the basis of insufficient evidence, theBoard said that it would not approve ProjectsD7, D8, D9 and D10 which were intended toincrease transmission system capacity byreducing congestion. The Board added that itwould provide Hydro One with the opportunityto provide additional evidence on theseprojects for purposes of setting 2010 rates butsaid that such evidence should be filed nolater than November 30, 2009. The Board alsoapproved and accepted the costconsequences for Projects D23, D24, D25,D26, D27, which are customer loadconnection driven, but did not approveProjects D28 and D29 which were also loadconnection projects.
Cost of Capital:
Financial Data - The OEB found that it wasappropriate to use the cost of capitalparameters released by the Board in February
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2009, rather than using an update, forpurposes of establishing Hydro One’s cost ofcapital for 2009. For 2010, the Board said thatSeptember 2009 data should be used toupdate the cost of capital parameters.
Cost of Imbedded Long-Term Debt – TheBoard found that Hydro One should updatethe 2009 and 2010 average cost of embeddeddebt to reflect the cost of actual debt issued in2008.
Cost Rate for Deemed Component of Long-Term Debt - The OEB agreed withintervenors that it was not appropriate to applythe Board’s deemed long-term debt rate to thenotional or deemed long-term debt as the twoare quite separate concepts. The Boarddirected that Hydro One’s cost of capital beadjusted to use its weighted average cost ofembedded debt for purposes of determiningthe cost to be applied to the notional ordeemed long-term debt.
Treasury OM&A Costs – The Board made nospecific adjustment to this item.
Deferral/Variance Accounts:
Disposition and Continuation ofExisting Accounts - The OEB found itpreferable to dispose of the balancesin these accounts over an 18-monthperiod starting with the July 1, 2009implementation date for the new ratesand ending December 31, 2010.
Proposed New Accounts – The Boardapproved the establishment of theproposed Transmission System Codeand Cost Responsibility ChangesAccount. Although most intervenorsopposed the establishment of theIntegrated Power System Plan(“IPSP”) and Other PreliminaryPlanning Costs Account, the OEBapproved the account, noting thatHydro One’s activities are clearlydriven by current Ontario energypolicy and thus Hydro One itself is notthe driver behind the expenditures.
Cost Allocation: The Board accepted HydroOne’s current methodology in which nocosts are allocated to the 45 delivery points
located at a Network Station and did notrequire Hydro One at this point to carry outany further analysis on this matter.
Charge Determinants: With respect to theproposal from the Association of MajorPower Consumers of Ontario (“AMPCO”) foran alternative rate design under which afixed monthly network charge would becalculated for each customer based on thatcustomer’s demand during the hour of peakdemand during the 5 highest peak days ofthe previous year, the OEB directed HydroOne to come forward at its next applicationwith:
1. further analysis of AMPCO’s proposal;and,
2. a suitable proposal for implementationfor the Board’s consideration in theevent the Board decides to change thecharge determinant.
The OEB said that in its further analysis,Hydro One should address the variouscriticisms which have been made about theAMPCO’s analysis (and its expert’sanalysis) and should attempt to conductsome sensitivity analysis around thepotential impacts on commodity prices. TheBoard said that it also expected Hydro Oneto provide a comprehensive analysis of thetransmission rate impacts for customers aswell as an assessment of any potentialadverse impacts on local conditions due toload shifting.
May 28, 2009
OEB Issues Update to Chapter 2 of the FilingRequirements for Transmission andDistribution Applications
The Ontario Energy Board (“OEB” or “theBoard”) has posted to its website a letter toelectricity distributors and transmitters to whichwas attached an update of Chapter 2 of theBoard’s “Filing Requirements for Transmissionand Distribution Applications” (“the FilingRequirements”). This chapter outlines theinformation which the Board expects electricitytransmitters and distributors to file for cost ofservice rate applications, based on a forwardtest year. The OEB says it is advancing the
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updates to this Chapter to make it available tothose distributors filing applications in August2009 for 2010 rebasing. The Board adds that theremainder of the Filing Requirements will beupdated at a later date.
The OEB explains that, following two years ofcost of service reviews, a need to update thischapter of the Filing Requirements had beenidentified by both external and internalstakeholders in order to make this chapterclearer and more focused. It is the Board’sexpectation that the updated FilingRequirements will decrease the likelihood ofreceipt of incomplete applications and reducethe number of interrogatories. To that end, theOEB has included certain additional informationrequirements that it found helpful in its reviewsof cost of service applications in 2008 and 2009.
The Board says it has also updated its definitionof the typical residential customer for purposesof communicating bill impacts. Beginning in2010, the Board’s focus for a typical residentialcustomer will be at the 800 kWh consumptionlevel rather than the previous 1,000 kWh levelas this number more closely approximates themonthly consumption of a typical residentialcustomer.
The OEB also advises that, since the FilingRequirements were issued in November 2006, ithas reviewed certain policy matters andintroduced new guidelines in areas such assmart meters and cost allocation. These havebeen included in the update as well.
The Board clarifies that this update does notincorporate any adjustments to reflect potentialchanges arising from the Statement of the Chairof April 3, 2009 on ”Regulatory Framework forApproval of Investment in Infrastructure byElectricity Transmitters and Distributors” which isan ongoing initiative. There may also be theneed for updates related to other ongoingmatters such as the implementation of theGreen Energy Act 2009, the Low-income EnergyAssistance Program (“LEAP”) and others. Anysuch updates will be made as required.
May 27, 2009
OEB Issues Rate Order on 2009 ElectricityDistribution Rates for Hydro One RemoteCommunities
In the context of Board File No. EB-2008-0232,the Ontario Energy Board (“OEB” or “the Board”)has issued a Rate Order to reflect its April 30,2009 Decision on 2009 electricity distributionrates for Hydro One Remote Communities(“Hydro One Remotes”) effective May 1, 2009.
The Board advises that, as a result of this RateOrder, Hydro One Remotes bills will increase byapproximately $4.12 or 4.4% for its year roundresidential customers using 1,000 kWh permonth. In its application, Hydro One Remoteshad requested a distribution rate increase ofapproximately 4.4%.
The OEB says that Hydro One Remotesrequested a revenue requirement of $42.5million for the 2009 rate year. As a result of theBoard Decision, Hydro One Remotes willrecover a revenue requirement of $42.2M.
In its Decision, the OEB accepted Hydro OneRemotes’ proposals which included:
$30.9M of the revenue requirement will berecovered through the Rural or RemoteElectricity Protection Benefit and Charge.
Support for using renewable energy to supplyremote communities
Increased capital expenditures on dieselengines and the distribution system tomaintain the reliability and safety of thedistribution system.
May 27, 2009
OEB Issues Rate Order on 2009 ElectricityDistribution Rates for Northern Ontario Wires
Pursuant to Board File No. EB-2008-0238, theOntario Energy Board (“OEB” or “the Board”)has issued a Rate Order to reflect its April 22,2009 Decision and Order on 2009 electricitydistribution rates for Northern Ontario Wires Inc.(“Northern Ontario Wires”) effective May 1,2009.
The OEB advises that, as a result of this RateOrder, the delivery portion of the bill associatedwith the cost to distribute electricity will increase
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by approximately 15.8% or $5.75 for NorthernOntario Wires’ residential customers using 1,000kWh per month. In its application, NorthernOntario Wires had requested a distribution rateincrease of approximately 22.4%.
The Board reports that Northern Ontario Wiresrequested a revenue requirement of $2,890,752for the 2009 rate year. As a result of thisDecision, Northern Ontario Wires will recover arevenue requirement of $2,559,450.
The OEB says that in its Decision, it acceptedNorthern Ontario Wires’ proposals whichincluded:
Northern Ontario Wires’ capital expenditurespertaining to the purchases of specializedvehicles in excess of $220,000 in 2008; and
$200,000 for a building (in Kapuskasing) andfixtures and $80,000 in additions to poles andwires infrastructure.
The Board goes on to say that, during theproceeding, Northern Ontario Wires revised itsproposals to reflect the following:
Removal of $8,000 in operations,maintenance and administration (“OM&A”)costs for temporary staffing to assist withimplementing a new billing system; and
Removal of $81,000 in other interestexpenses associated with interest on VarianceAccounts, Truck Loan interest and interest onCustomer Deposits.
The Board adds that in its Decision, it reducedcertain requested amounts for OM&A costs suchas:
$10,000 out of a total requested amount of$20,000 for the early hiring and training of asuperintendent; and
$18,000 to remove that portion of therequested increase in OM&A that exceededthe wage inflation estimate of 3%.
May 27, 2009
Red Rock First Nation and OPG SignSettlement Agreement
The Red Rock First Nation (“RRFN”) andOntario Power Generation (“OPG”) haveannounced the signing of a final settlement
agreement which resolves past grievances fromthe impacts of OPG operations in the RRFNtraditional territory and the formal delivery of anapology to the community by OPG for thoseimpacts.
The parties suggest that this establishes thefoundation for a positive relationship goingforward between the RRFN and OPG. RRFN,together with other First Nations, and OPG haveestablished a framework for a mutuallybeneficial commercial relationship for a potentialhydro development.
The RRFN suggests that there are substantialhydroelectric opportunities in its homelands andthat the new agreement guarantees manybusiness, employment, environmental provisionsand financial benefits for its people.
May 22, 2009
Moose Cree First Nation in Ontario RatifiesAmisk-Oo-Skow Comprehensive Agreement
Ontario Power Generation (“OPG”) and theMoose Cree First Nation (“MCFN” or “theNation”) have announced that the MCFN ratifiedan agreement resolving past impacts on theNation and establishes the foundation for apositive relationship between the two parties.
May 17, 2009
OEB Issues Rate Order on 2009 ElectricityDistribution Rates for Toronto Hydro-Electricity System Limited
Under Board File No. EB-2009-0069 the OntarioEnergy Board (“OEB” or “the Board”) issued aRate Order to reflect its April Decision on 2009electricity distribution rates for Toronto Hydro-Electric System Limited (“Toronto Hydro”). Thenew rates are effective May 1, 2009. As a resultof this Decision and Rate Order, the deliveryportion of the bill associated with the cost todistribute electricity will increase byapproximately 1.7% or $0.72 for Toronto Hydroresidential customers using 1,000 kWh permonth.
In its Decision, the Board:
Authorized the implementation of electricitydistribution rates approved on May 15, 2008,which have been adjusted to reflect updated2009 Cost of Capital parameters,
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Reduced the requested level of debt costs byabout $800,000 or 0.2% due to the timing of anew debt issue,
Approved new rate rider credits for the 12-month period starting May 1, 2009 which willresult in a customer credit of about $0.83 permonth for a typical residential customer.
May 15, 2009
OEB Advises that May's Electricity RegulatedPrice Plan Variance Settlement Factor Is -0.1995 Cents per kWh
The Ontario Energy Board (“OEB” or “theBoard”) has released an updated variancesettlement factor which is to be used byelectricity distributors to calculate a one-timecredit for consumers who choose to stoppurchasing electricity through the RegulatedPrice Plan (“RPP”). This factor, called the “FinalRPP Variance Settlement Factor” is updated onthe OEB website on or around the 15th of eachmonth.
The Board says that this latest factor, -0.1995cents per kilowatt hour (“kWh”), is based on thedifference between the amount RPP consumerspaid for electricity (for the period from April 1,2005 to April 30, 2009) and the actual amountspaid to generators to supply that electricity.
This factor is to be used by electricity distributorsto calculate the final payment or credit forconsumers who: (1) cancel their utility accountand move outside of the Province of Ontario; (2)switch to a retailer; (3) have an interval meterand elect the spot market pricing option; or (4)cease to remain eligible for the RPP.
The OEB advises that a consumer who uses12,000 kWh per year (1,000 kWh per month),and who chooses to leave the RPP, wouldreceive a one-time credit of $23.94 based on theupdated factor. For a consumer who uses lesselectricity, such as 750 kWh per month, the one-time credit would be $17.96.
The announcement explains that, under theRPP, consumers are charged a regulated stableprice for the electricity they consume. That pricewas set by the Board based on a forecast of theexpected cost to supply RPP consumers. Whenthe RPP price differs from the amount actuallypaid to generators, the difference is tracked by
the Ontario Power Authority (“OPA”) in avariance account.
The OEB says that the updated factor wascalculated using the positive net balance in thevariance account (as of April 30, 2009) of about$126.4 million. The net variance balanceincorporates estimates of the rebate fromOntario Power Generation (“OPG”) – thedifference between the revenue limit for someOPG generation facilities and the price theywould have received in the wholesale spotmarket.
May 14, 2009
OEB Releases Decision Concerning NewDistribution Rates for Hydro One NetworksEffective May 1, 2009
Under Board File No. EB-2008-0187, theOntario Energy Board (“OEB” or “the Board”)has issued its Decision with respect todistribution rates and other charges for HydroOne Networks Inc. (“Hydro One”) effective May1, 2009.
The OEB advised that Hydro One is one of theelectricity distributors to have its rates adjustedfor 2009 on the basis of the 3rd GenerationIncentive Rate Mechanism (“3GIRM”) process.The Board goes on to say that Hydro Oneapplied for both the standard formulaicadjustment to distribution rates under the planas well as for an adjustment under theincremental capital module (“ICM”) provision ofthe plan. The OEB also notes that on March 26,2009, it declared Hydro Ones rates interim forMay 1, 2009.
The following is a summary of the findings of theBoard set out in the Decision:
The Price Cap Adjustment
The OEB characterized this part of Hydro One’sapplication as a fairly straightforward price capadjustment pursuant to the provisions of the3GIRM. This part also includes a Z-factoradjustment intended to return to ratepayers theirshare (50%) of recent reductions in income taxand capital tax rates, totalling $0.3 million. Thisadjustment is to be effected through the use of arate rider. This part also includes a revisedfunding adder for smart meters to $1.65 percustomer per month from the current level of
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$0.93.
The Board reports that no party was opposed tothis section of Hydro One’s application.Intervenors noted, and Hydro One agreed, thatan adjustment needed to be made to reflect theBoard’s March 2009 re-calculation of theinflation escalator to 2.3% from 2.1% used bythe Applicant, raising the escalator factor from0.98% to 1.18%.
Incremental Capital Module Application
The OEB noted that under its ICM frameworkunder 3GIRM, electricity distributors may applyfor unusual capital expenditure requirementswhich exceed a calculated threshold. The Boardreports that Hydro One’s 2008 depreciation of$188 million, the contribution of the price capmechanism of $42 million (before adjustment),the contribution from growth of $20 million, andthe 20% deadband of $38 million add to athreshold of $288 million. Hydro One’sapplication is for a total capital expenditure in2009 of $461 million. The OEB reports thatsubtracting the $288 million threshold amountfrom the $461 million total proposed capitalexpenditures in 2009 resulted in a requestedICM capital relief of $173 million. The associatedrevenue requirement relief was calculated at$21.3 million. The rate relief amount was 12.3%of the requested capital relief. During thehearing, there was general acceptance that the12.3% factor would apply to adjustments to therevenue requirement if there were anyadjustments to the requested capital amounts. Asubsequent adjustment to reflect an inflationfactor of 1.18% or 0.98% raised the threshold to$296 million, and correspondingly, lowers theproposed incremental capital requirement to$165 million. Using the 12.3% factor, the startingrevenue requirement relief was reduced to $20.3million.
One of the Board’s initial findings was to declineto dismiss the ICM application on the basis ofthe impact of the current economic climatefacing energy consumers. The Board said thatonce filed in accordance with the provisions ofthe legislation, applications are reviewed on theirmerit.
The OEB clarified that the purpose of the ICMmechanism was to deal with unforeseen large
increases in required capital spending which itsaid was not the case in the instant applicationand that therefore it could not consider HydroOne’s application under the ICM.
The Board went on to say that what was beforeit was, however, a request for rate relief whichgoes to a large degree to the distributor’s plan tocontinue to serve its existing customers in a safeand reliable manner. The OEB also noted thatHydro One's application was the first case inwhich the Board had considered a proposedincremental capital module and Hydro One didnot have the benefit of any case-specific Boarddecision for either Hydro One or any otherdistributor. The OEB said that Hydro One’smisinterpretation of the Board’s ICM plan did notinvalidate the substance of its application whichit filed in good faith. The Board further addedthat there was a relatively significant gapbetween Hydro One’s apparent capital needs in2009 and the available funding through rates forthese needs.
The OEB said that it was willing to approve rateadjustments for higher capital expenditures,subject to the employment of certain standardregulatory tools and practices in determiningappropriate adjustments to rate base andrevenue requirement and to safeguardratepayers.
Through the use of a calculation set out in theDecision, the Board reduced capitalexpenditures for which rate relief should beprovided to $99 million and, by employing the12.3% factor, the rate relief to $12.3 million.
In response to Intervenor suggestions as tocapital expenditures that should be eliminated,the Board said that it was its assessment thatthese matters were primarily a product of themanner in which the Hydro One had chosen toframe its application. The OEB said that theintervenors’ criticisms and concerns were validin that Hydro One’s filings did not satisfy manyof the Board’s requirements as set out in itsSupplementary Report. However, given theBoard’s case-specific approach of assessing therelief sought, the OEB does not make specificfindings on these matters. The Board added thatthe specific additions to rate base will be anopen question when Hydro One seeks to reflectthese expenditures upon rebasing. In that
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regard, the Hydro One was directed to establisha tracking account to track the differencesbetween its proposed capital and actualspending.
Hydro One was further directed to calculaterevised rate riders to reflect revenuerequirement relief of $12.1 million and to submitrevised rate schedules which reflect this findingas well as the Board’s findings with respect tothe adjustments arising from the application ofthe standard IRM process. Hydro One was alsodirected to file a draft rate order attaching theappropriate rate schedules as soon as possibleto give effect to the new rates on May 1, 2009.The Board said that, as the changes to the rateschedules will be mechanical in nature, it wouldreview the new rate schedules without the needfor submissions by the parties.
May 13, 2009
Burlington Hydro Officially LaunchesGridSmartCity Partnership Program
Burlington Hydro Electric Inc. (“BurlingtonHydro”), together with the Government ofOntario and City of Burlington, has announcedthe official launch of a GridSmartCity, whichbrings together a wide range of stakeholdersfrom industry to government to work together topromote the growth of smart grids.
The announcement states that the new programwill showcase how smart grids integrateelectricity production, delivery and consumptionto produce a more efficient, reliable andresponsive system which is better for theenvironment.
Burlington Hydro advises that partners ofGridSmartCity will collaborate on smart gridprojects to illustrate new technologies to helpfuel the growth of innovative green industries.Smart grid technologies, combined withadvanced communications and computeranalytics, will aid greater use of renewable'Green Energy' sources from the sun, wind anddevices such as electric vehicles.
In addition, the announcement advises thatGridSmartCity can assist consumers to learnmore about smart grids, time differentiatedprices and in-home energy management tools.
Background
The GridSmartCity initiative stems from recentdiscussions of senior members of Ontario'selectricity industry who formed a group calledthe “Ontario Smart Grid Forum”. The Forum'srecent report, “Enabling Tomorrow's ElectricitySystem”, recommended that distribution utilitiesundertake demonstration projects on smart gridtechnologies. GridSmartCity accelerates thisprocess by offering a platform for technologydevelopers and other interested firms tocombine all the major elements of a smart gridinto an integrated suite of projects, which willhelp to identify best practices, and new devicesand processes which will demonstrate the fullcapabilities of a smart grid.
May 12, 2009
OEB Approves Sale of Great Lakes PowerLimited Distribution Assets to Affiliate andIssuance of a Distribution Licence to GLPD
Under Board File Nos. EB-2009-0072, EB-2009-0073 and EB-2009-0075, the Ontario EnergyBoard (“OEB” or “the Board”) has issued aDecision and Order in which it approvesapplications dated March 6, 2009 from GreatLakes Power Limited (“GLPL”), Great LakesPower Distribution Inc. (“GLPD”) and GreatLakes Power Transmission Inc. (“GLPT”) onbehalf of Great Lakes Power Transmission LP(“GLPTLP”) (together, the "Applicants") whichsought, among other things, approval for GLPLto sell its distribution assets to GLPD and anelectricity distribution licence to GLPD.
In its Decision and Order, the OEB ruled that:
1. GLPL was granted leave to sell itsdistribution assets to GLPD.
2. The Board’s leave to sell Great LakesPower Limited’s distribution assets toGreat Lakes Power Distribution Inc. willexpire on December 31, 2009. If thetransaction has not been completed bythat date, a new application for leave willbe required in order for the transactionto proceed.
3. The application for an electricitydistribution licence by GLPD wasgranted, on the conditions contained inthe licence.
4. GLPL’s electricity distribution licence,
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ED-2008-0343, was cancelled.
5. GLPL’s electricity distribution rate order,EB-2007-0744, was transferred toGLPD, subject to any amendmentswhich may arise from GLPL’s appeal tothe Ontario Superior Court of Justice(Court File No. 610/08).
6. GLPT’s electricity transmission licence,ET-2002-0247, was amended to includeGLPTLP as operator.
7. GLPL’s electricity transmission licence,ET-2008-0342, was cancelled.
8. GLPL’s Customer Delivery PointPerformance Standards (EB-2006-0201)was transferred to GLPT.
9. GLPL’s Customer ConnectionProcedures (EB-2006-0200) wastransferred to GLPT.
May 11, 2009
OEB Releases Decision Respecting LakelandPower Distribution Application ConcerningRates and Other Charges for ElectricityDistribution Effective May 1, 2009
Under Board File No. EB-2008-0234, theOntario Energy Board (“OEB” or “the Board”)has issued a Decision and Order in which it setsout its findings with respect to a September 15,2008 application by Lakeland Power DistributionLtd. (“Lakeland”) seeking approval for changesto the rates it charges for electricity distributionto be effective May 1, 2009. Lakeland is thelicensed electricity distributor serving theMunicipalities of Bracebridge, Huntsville, Burk’sFalls, Magnetawan and Sundridge.
The OEB reports that, in its original application,Lakeland requested a revenue requirement of$5,672,375 for the 2009 test year to berecovered in distribution rates effective May 1,2009. The resulting requested rate increase wasestimated as a 17.9% increase over 2008 on thedelivery component of the bill for a residentialcustomer consuming 1,000 kWh per month.
The following aspects of Lakeland’s Applicationfor rates were accepted by all parties during anegotiated settlement process (“NSP”) and theresult was subsequently approved by the Board:
Asset Management
Service Reliability
Transformer Ownership Allowance.
Among the OEB’s findings on the other,contested, issues were the following:
Although the Board acknowledged that theremay be minor inaccuracies in the calculation,for the purposes of the instant application, theOEB accepted the applicant’s load forecastingmethodology noting that it had beenpreviously accepted by the Board assatisfactory. The OEB also accepted theLakeland’s statement that it expects toimprove its load forecasting methodology infuture cost of service rate applications bytaking into consideration comments made byparties in this application and in other cost ofservice rate applications. The Board went onto say that it disagreed with Energy Probe’ssuggested changes to the methodology,stating that many of them were impractical,given the current stage in the evolution ofdistribution load forecasting methodology inthe Province and without the benefit of asubstantial base of smart meter data.
Noting that vacation and statutory holidays aredirectly related to employee compensation,the Board found it reasonable that they beallocated in the same way as the hourstracked and allocated to the three companiesand it approved these costs. The OEB wenton to direct that in future applications,Lakeland should ensure that the allocation oflabour costs includes the costs for vacationand benefits to increase the accuracy intracking these costs.
Based on Lakeland’s acceptance of theIntervenor and Board staff submissions, theBoard found that the proposed expenses forRegulatory Costs ($26,000 per year) andElectrical Safety Authority Fees ($24,429) tobe reasonable. The Board also acceptedLakeland’s reply submissions regarding OfficeSupplies and Expenses and approves therequested amount ($94,496).
The OEB directed Lakeland to calculate thePayments in Lieu of Taxes (“PILs”) expenseusing the appropriate starting point and gross-
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up methodology found in the Board’s 2006application model and Handbook when itprepares its 2009 Draft Rate Order.
With Respect to Capital Cost Allowance(“CCA”), the OEB directed Lakeland to makethe appropriate changes in revenuerequirement and allowable deductions as aresult of the 2009 federal budget.
The Board accepted Lakeland’s proposedcapital expenditures for the 2008 and 2009Test Year of $974,788 and $1,685,160respectively.
The OEB found that Lakeland’s approach ofusing a 15% factor to derive its working capitalallowance was reasonable and said it wouldnot require Lakeland to prepare a lead-lagstudy for its next rebasing application. Inmaking this finding, the Board said it wasmindful that for a small working capitalrequirement, the cost of an individual study islikely to exceed any adjustment that mightresult. The OEB did direct Lakeland to updatethe cost of power used in calculating itsworking capital allowance to reflect the mostrecent cost of power forecast of $0.0672/kWhreleased by the Board on April 15, 2009.
Although it found that Energy Probe’srecommended depreciation amount was toolow, the OEB said that Lakeland had notprovided sufficient evidence to show that itsdepreciation claim of $970,000 was moreappropriate, or that it has used the standarddepreciation rates for assets added after2000. As a result, the Board deemed$900,000 as a reasonable estimate ofdepreciation expense for the 2009 Test Yearand directed Lakeland to provide updateddepreciation evidence, addressing the aboveconcerns, for the period from the 2000 yearend to the historic year in its next cost ofservice rate application.
The Board approved Lakeland’s request forcontinuation of the smart meter rate adder of$0.25 per month per metered customer addingthat it was understood that Lakeland will befiling a separate smart meter application at alater date.
The OEB accepted Lakeland’s proposedcapital structure and cost of capital noting thatit was consistent with Board policy and reflectsthe updated cost rates established by theBoard.
The OEB noted that Lakeland did not includeinterest derived from deferral and varianceaccounts (“DVA”) balances in its revenueoffset and agrees that the revenue offsetshould not include the interest income fromDVA. However the Board went on to say thatLakeland should include any interest incomenot associated with DVA in its revenue offset,and it directed Lakeland to update its 2009Revenue Offset forecast to include interestincome. The OEB further directed Lakeland toforecast its average balance in its sub-account4405 which is not associated with DVA, and touse an interest rate of 1.33% to calculate thiscomponent of the Revenue Offset.
The Board said that it found the intervenorarguments to be convincing with respect toLakeland’s Distribution Loss Factor (“DLF”)data. The OEB accepted the submissions ofall parties that the five-year average of SupplyFacilities Loss Factor (“SFLF”) wasappropriate, but found that Lakeland shoulduse the four-year average of DLF to removethe influence of the high value in the first year.The Board directed Lakeland to submit theresulting Transmission Loss Factors (“TLFs”)for primary and secondary-metered customersin its Draft Rate Order.
The OEB found that in its Draft Rate Order,Lakeland should provide an updated lowVoltage (“LV”) forecast based on the HydroOne LV rates approved in the EB-2007-0681proceeding, including the effect of HydroOne’s Rider # 4 at one-half of its annual value.The Board also directed Lakeland to ensurethat the updated LV cost is included in theforecast of working capital.
The OEB accepted Lakeland’s proposal forrevenue to cost ratios in 2009, except for theUnmetered Scattered Load (“USL”) class andthe General Service > 50 kW class.
The Board accepted Lakeland’s proposed ratedesign, and in particular its proposal tochange the General Service > 50 kW Monthly
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Service Charge and the volumetric rate (net ofthe Smart Meter and LV adders respectively)by a uniform percentage.
The OEB noted that Lakeland’s cost allocationresults for Un-metered Scattered Load may beoverly sensitive to a seemingly innocuousinput assumption in the model, and in thisinstance, the Board is inclined to rely on acomparison with the larger General Service <50 kW class. The OEB directed Lakeland tofile USL rates that will increase from thecurrently approved rates by the samepercentages as the corresponding GeneralService < 50 kW rates. Lakeland shall alsoprovide background information on therevenue to cost ratio of the USL class thatresults from such rates, using the model asadapted for its response to Board staffInterrogatory #31.
The Board set out the process by which costaward claims would be dealt with.
May 1, 2009
Ontario IESO Posts Fixed Global AdjustmentRate for May 2009 Distributor Billing andEstimated Global Adjustment for April, 2009
The Ontario Independent Electricity SystemOperator (“IESO”) advises that the fixed GlobalAdjustment (“GA”) rate for distributor billing forMay will be a charge of $39.80 / per megawatthour (“MWh”). The IESO says that localdistribution companies (“LDCs”) should use thisfigure to calculate the Provincial Benefit forthose customers who are not on the RegulatedPrice Plan (“RPP”), and that this new rate will beavailable for download from the preliminary dailyGA rate files on the IESO ftp site 10 businessdays after the May 1, 2009 trade date.
In a separate announcement, the IESO advisesthat the estimated global adjustment (“GA”) ratefor the month of April is a charge $37.87/ MWh.
May 1, 2009
OEB Issues Rate Orders on 2009 ElectricityDistribution Rates for EnWin Utilities Ltd.and COLLUS Power Corp.
The Ontario Energy Board (“OEB” or the“Board”) has issued rate orders to reflect itsdecisions and orders on 2009 electricity
distribution rates for EnWin Utilities Ltd.(“EnWin”), issued on April 9, 2009, and COLLUSPower Corporation (“COLLUS”), issued on April17, 2009. The new rates for both utilities areeffective May 1, 2009.
In the case of Enwin, the OEB indicates that asa result of this Decision and Rate Order, theportion of the bill associated with the cost todeliver electricity will increase by approximately5.8% or $2.25 per month for Enwin’s residentialcustomers using 1,000 kWh per month. In itsinitial application, EnWin requested an increaseof approximately 9.7%.
For COLLUS, the delivery portion of the billassociated with the cost to distribute electricitywill increase by approximately 5.1% or $1.85 forCOLLUS’ residential customers using 1,000kWh per month. In its application, COLLUS hadrequested a distribution rate increase ofapproximately 8.5%.
According to the Board, the delivery portionrepresents about one-third of the total bill.
May 1, 2009
OEB Issues Decision and Order Concerning2009 Cost of Service Application Filed byHydro One Remote Communities Inc.
The Ontario Energy Board (“OEB” or “theBoard”) has issued its Decision and Order withrespect to the 2009 cost of service applicationfiled by Hydro One Remote Communities Inc.(“Remotes”) seeking approval for changes to therates it charges for electricity distribution to beeffective May 1, 2009.
The OEB explains that Remotes is uniqueamong electricity distributors in many aspects ofits operation. It is an integrated generation anddistribution company licensed to generate anddistribute electricity within 20 isolatedcommunities in Northern Ontario. Remotesforecast a total of 3,411 customers in 2009. Itssystems are totally independent from theprovincial grid. Remotes is 100% debt-financedand operates as a break-even business. Thereis no return on equity available to its shareholderand any differential between revenues andexpenses is captured in the Rural and RemoteRate Protection (“RRRP”) variance account.
In its original application, Remotes had
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requested a revenue requirement of$45,236,000 to be recovered in new rateseffective May 1, 2009. In its Reply, Remotesagreed with a number of adjustments to itsapplication and revised its revenue requirementto $42,550,000, of which $14,655,000 isproposed to be recovered through customerrates and $27,895,000 is to be recovered fromRRRP. In 2006, the Board granted Remotes arevenue requirement of $31,551,000, of which$21,108,000 was to be recovered throughRRRP.
The OEB’s key findings are the following:
Rate Base And Capital Expenditures: Remotesforecast capital expenditures of $5,138,000 in2009. This is an increase of approximately 37%compared to 2007 actual capital expendituresand an increase of 67% over 2008 capitalexpenditures.
The Board said that it is satisfied that Remotes’capital spending plan is appropriate andachievable.
Meter Replacement: The OEB found thatRemotes’ proposal with respect to meterreplacement is appropriate. The Board notedthat the program differs from the Smart Meterprogram being implemented in other parts of theProvince (in that the meters will have reducedfunctionality) and therefore accepted that it is notnecessary for Remotes to conform to theBoard’s Smart Meter policies in relation to theseexpenditures.
Operating, Maintenance & AdministrativeExpenses (“O&MA”) Expenses: The OEB saidthat the increase in OM&A for 2009 with respectto 2006 Board-approved OM&A (the last set ofbase rates approved by the Board) is 7%.Remotes noted that neither Board staff nor theintervenors actively opposed the level of OM&Arequested for 2009.
The submissions from a group of intervenorswere related to the areas of development costsfor renewable generation and the RRRPgenerally.
The OEB said that it considered Remotes’proposal to be a reasonable interim approach ata time of rapid change in the legislative andpolicy environment. Remotes’ sole shareholder,
the government of Ontario, has introducedlegislation which places considerable emphasison the development of renewable energysources. The Board added that the legislationalso envisages an enhanced role for Aboriginalpeoples in the development of such resources.
The OEB found that the use of the avoided costof diesel as the pricing mechanism forrenewable projects as an interim measure isappropriate. It noted that there really is no otheryardstick which can be used at this time toassess appropriate pricing for these resources.The Board went on to say that the creation ofpartnerships with Aboriginal developers is anelement which needs to evolve in step with therest of the legislative and policy environment.According to the Board, Remotes’ approach isconsistent with such evolution. Therefore, theOEB accepted Remotes’ proposals.
Payments in Lieu of Taxes (“Pils”): Remotesindicated that it expects to incur a taxable loss of$4.8 million for the 2008 tax year. It anticipatedcarrying this amount forward and applying it toincome of future years. Remotes also indicatedthat amounts applied against future incomewould be recorded as a credit to its RRRPVariance Account. Consequently, Remotessubmitted that ratepayers will be held harmlessfrom the difference between the tax provision of$223,000 included in the 2009 Test Yearrevenue requirement and any income tax creditarising from a taxable loss that is actuallyincurred.
The OEB said it seems apparent that there is nogood rationale for the establishment of aprovision for PILs at any level for 2009. TheBoard found that while the mechanism proposedby Remotes would be expected to holdratepayers harmless should the provision not beneeded, it did not consider it appropriate tomake provision for a PILs liability which has noreasonable prospect of being realized.
Cost of Capital: The OEB noted that, consistentwith its Decision in RP-1998-0001, Remotes is100% debt financed and is not operated so as tomake a profit. Thus, Remotes’ capital structureconsists of 100% debt; 4% short-term debt and96% long-term debt.
Based on the Board’s February 24, 2009 update
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to the Cost of Capital Parameters, Remotesagreed to revise the short-term debt rate to1.33%.
According to the Board, Remotes’ long termdebt is composed of $23 million at an effectiverate of 5.60% payable to Hydro One Inc.reflecting debt issued by Hydro One Inc. to thirdparty public debt investors, and $6.9 million ofdeemed long-term debt.
The OEB noted that its update on Cost ofCapital Parameters revised the deemed long-term debt rate to 7.62%.
The OEB found that it was not appropriate toapply its deemed long-term debt rate to thenotional or deemed long-term debt. The two arequite separate concepts. The Board noted thatthe deemed long-term debt rate is intended toapply in the absence of an appropriate marketdetermined cost of debt, such as affiliate andvariable rate debt situations. For companies withembedded debt, it is the cost of this embeddeddebt which should be applied to any additionalnotional (or deemed) debt that is required tobalance the capital structure.
The OEB went on to say that Remote’s cost ofcapital will be adjusted to use its weightedaverage cost of embedded debt (5.60%) forpurposes of determining the cost to be appliedto the notional or deemed long-term debt. TheBoard found that this is consistent with thetreatment given to other local distributioncompanies (“LDCs”) which have undergonerebasing in 2008 and 2009.
Rate increases and the role of RRRP: Asdetailed in the introduction, Remotes hasapplied for a revenue requirement of$42,550,000, of which $14,655,000 is proposedto be recovered through customer rates and$27,895,000, or approximately 66%, is to berecovered from grid-connected customersthrough the RRRP subsidy.
The Nishnawbe Aski Nation (“NAN”) submittedthat Remotes was proposing an averageincrease of 4.4% and that the allowable rateincrease should be restricted to 2.0% for 2009rates. Remotes responded that the proposedincrease is based on the average 2008 increaseover 2007 distribution rates for Ontario LDCsapproved by the Board in 2008.
The OEB said that is satisfied that Remotes’proposal is appropriate. The increase to becollected from ratepayers is quite modest. Itnoted that other ratepayers in the province haveexperienced much more significant rateincreases in the last short period. The Boardsaid that it is mindful of ratepayers’ ability to paywhenever it sets rates. According to the Board, Itseems apparent in this case that the level ofincrease sought to be collected from Remotes’ratepayers is not excessive. The OEB addedthat it is also encouraged by the reduction inarrears reported by the utility in every year since2006.
Rural and Remote Protection (“RRRP”) VarianceAccount: Remotes was required to improvetransparency to also have the OM&A in theRRRP variance account broken down into eachof its sub-categories. Remotes was directed tofile a continuity schedule showing the balancesin the RRRP variance account and each sub-category within this variance account for eachyear from the time this account was lastdispositioned by the Board.
Interim Rates: The OEB found that Remotes’current rates for its service area should be madeinterim, effective May 1, 2009 pending theissuance of final rates for 2009.
General
May 28, 2009
Ontario Government Introduces EnablingCap-And-Trade Legislation
The Ontario Government has announced it isintroducing proposed Cap and Trade legislationwhich would, if passed, create the governmentauthority to set up a greenhouse gas (“GHG”)emissions trading system within the province.The government says the system is a form ofmarket regulation applied to GHGs produced byindustry, and is an effective way to reduce thethreat of climate change caused by carbonemissions.
The announcement advises that a discussionpaper, called "Moving Forward: A GreenhouseGas Cap-and-Trade System for Ontario", whichwill guide consultations over the summer onwhat Ontario's cap-and-trade model could looklike, is now available and is posted on the
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Environmental Registry under number 010-6740.
The government states that it anticipates a NorthAmerican cap-and-trade plan could be in placeas early as 2012, and that the creation of a cap-and-trade system for industry will help theprovince meet its climate change commitmentsto reduce GHG emissions by 6 per cent below1990 levels by 2014 and 15 per cent by 2020.
The announcement goes on to say that Ontariohas had months of discussions with nineindustrial sectors likely to be involved in cap andtrade; these sectors are base metal, cement,chemical, electricity, lime, natural gas,petroleum, pulp and paper, and steel, and thatenvironmental groups were also consulted.
According to the announcement, these sectorsrepresent about 40 per cent of Ontario's totalemissions in 2007. Electricity alone accounts for16 per cent (ref: Statistics Canada). Ontario andQuebec formed a working alliance on this issuein June 2008. Together they represent close to60 per cent of Canada's economy.
May 27, 2009
Dan Santerre Appointed Director of HydroOne Remote Communities
Hydro One has announced the appointment ofDan Santerre as Director of Hydro One RemoteCommunities Inc., which distributes electricity toremote communities in Northern Ontario.
Hydro One says that Mr. Santerre was formerlythe Distribution Superintendent of Lines,Northwest Region, of Hydro One Networks. Hehas 25 years of experience as a Hydro Oneemployee in Northwestern Ontario, and is wellacquainted with the challenges of servingnorthern and remote communities.
The announcement reports that Mr. Santerrewas born in Geraldton, Ontario, graduated fromGeraldton Composite High School and attendedthe University of North Dakota in Grand Forkswhere he graduated with a BA majoring inHistory. He joined Ontario Hydro in 1984 andhas worked in many roles during his career atOntario Hydro/Hydro One, including lineman,health and safety specialist, and most recentlyProvincial Lines Superintendent.
The announcement explains that Hydro OneRemote Communities Inc. operates 18 small,regulated generation and distribution systems in20 remote communities across Northern Ontariowhich are not connected to the provincialelectricity grid. Many of these communities areonly accessible via air transportation or winterroads.
May 26, 2009
Ontario Announces Enhancements to HomeEnergy Savings Program
The Government of Ontario has announced it isdoubling its investment in its Home EnergySavings Program resulting in enhancementswhich it says will increase rebates for changeslike fixing insulation in ceilings, foundations,basements, and crawl spaces as well asupgrading leaky windows and doors by 25percent or more.
Additional examples of program enhancementsinclude:
Provincial funding for solar domestic hot watersystems is increasing by 150 percent — to$1250, up from $500,
Home energy audits will soon be mandatory atthe point of sale (unless waived by the buyer)and can be transferred, allowing newhomeowners to take advantage of retrofitrebates.
The announcement notes that a home energyaudit is required in order to access the rebatesinvolved.
May 22, 2009
Toronto Hydro First Canadian Utility to TestGoogle PowerMeter Technology
Toronto Hydro-Electric System ("TorontoHydro") has announced that it is the firstCanadian utility to partner with Google to test apilot technology, Google PowerMeter, which is aGoogle gadget showing consumers theirpersonal electricity consumption on theirpersonal computer via their iGoogle home page.
Toronto Hydro says that the pilot is limited toselect group of customers and will last a fewmonths. Based on the results, it may makeGoogle PowerMeter available to all its
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customers.
The announcement notes that Toronto Hydrohas more than 611,000 smart meters installedacross the city of Toronto and has launchedTime-of-Use rates to the first 10,000 of itscustomers. It says that to fully take advantage oflower electricity rates, customers should shifttheir energy use to off-peak times like weekendsor evenings after 10 p.m. when electricity is only4.2 cents per kilowatt hour. Having informationreadily available can help customers quicklyidentify how much electricity they are using atspecific times of the day.
Toronto Hydro explains that, when ready,Google PowerMeter will complement the toolsalready available to many customers. It willprovide Toronto Hydro with another channel tointuitively educate customers on how to monitortheir electricity use and look for ways to shifttheir use to off-peak times. For example,customers will see their electricity usage at aglance on their iGoogle home page. If they wantmore detailed information, like how muchelectricity they are using on-peak, they can clickthrough to the Toronto Hydro.
The announcement notes that in addition tousing less electricity during peak times,customers will likely use less electricity in total.Studies show that providing access to ahousehold's personal energy information is likelyto result in savings between 5 to 15 per cent ona monthly bill.
May 22, 2009
Union Gas Offers Businesses New Incentivesfor Energy Saving Technologies
Union Gas has announced enhancements tofive of its EnerSmart program offerings designedto help businesses reduce energy use andoperating costs.
In this special program, Union Gas is offering itscommercial customers:
Free programmable thermostats: To reduceheating and cooling expenses by up to 10percent. Until August 31, 2009, Union Gaswill also provide a $40 incentive towards theinstallation of each new programmablethermostat unit.
Free pre-rinse spray nozzles for restaurants:To reduce water use and shave up to $950 offa business natural gas bill. This includes freedelivery and installation.
Free showerheads and aerators: To minimizeenergy used to heat water and save up to$100 a year on energy costs. This offer isavailable for multi-family and long-term carefacilities, schools, hotels, motels andrecreational commercial buildings andincludes free delivery.
$1,500 incentive on the installation of adestratification fan: High volume, low speedcommercial fans reduce heat loss through theceiling, ensure a consistent and comfortabletemperature and can reduce energy cost byup to 30 percent. Available until September30.
Up to $3,500 incentive on the installation of acondensing boiler: Save energy with up to 98percent thermal efficiency. Available untilSeptember 30.
May 22, 2009
Chatham-Kent Energy Announces Changesin the Role of President and CEO
Chatham-Kent Energy has announced that RayPayne, its President and Chief Executive Officer(“CEO”) since incorporation, will retire at the endof June and that Jim Hogan, its Chief FinancialOfficer (“CFO”), has been appointed as Mr.Payne’s successor.
The announcement reports that Mr.Payne hasbeen in the industry for more than 40 years andwas the General Manager of Wallaceburg Hydrofrom 1994 until the creation of the Municipality ofChatham-Kent in 1998, when he became theGeneral Manager of the Chatham-Kent PublicUtilities Commission, which includedresponsibilities for hydro power, water andwaste water. In 2000, he became the Presidentand CEO of Chatham-Kent Energy.
As CFO, Mr. Hogan has assisted in leading thefinancial, regulatory and customer servicefunctions.
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May 22, 2009
Direct Energy Conservation Pilot ProgramDemonstrates that Consumers Can Save upto 44 per cent Through Smart HomeTechnology
Direct Energy reports that the results from arecent pilot of the Direct Energy Smart HomeEnergy Conservation Program and researchproject in Milton, Ontario show dramatic savingsfor some participants, including up to 44 per centenergy savings during peak demand periods.
The announcement explains that the pilot wasconducted from July, 2007 to September 2008with 209 Milton Hydro households. The goal ofthe pilot was to not only test technology, but alsogain insights into consumer behaviours andmotivations for change. Participants were able tomonitor energy usage, and remotely control theirhome’s lighting and appliances with one easy-to-use web interface or a hand held device like aBlackberry. The portal and software, provided byLixar SRS, provide the ability for two waycommunication with the thermostat in real timeversus the alternative one way technologies.The program was developed in collaborationbetween Direct Energy, Milton Hydro, and Bellwith independent analysis by the University ofWaterloo.
According to the announcement, key highlightsfrom the pilot included:
The top 10 per cent of participants saved 16per cent off their electricity usage over 12months and saved 18 per cent off theirconsumption during peak periods.
A select group of participants saw savings of44 per cent during provincial demandresponse periods.
Consumers were motivated by dollar savingsand environmental benefits.
Larger homes saw the biggest impact onenergy savings.
Developed by Bell in partnership with Lixar SRS,the Smart Home Energy Conservation Solutionis a conservation demand management system.The solution provided participants with trendingand analysis, allowing them to monitor theirusage, and helped identify the high usage times
and devices to allow them to adjust theirbehaviour accordingly to conserve.
May 21, 2009
Government of Ontario Helps Schools Investin Green Technology
The Government of Ontario has announced thatit is investing $50 million for public schoolboards to reduce energy costs in schools byinstalling renewable energy technologies forheating, cooling or generating electricity.
The government says that this investment willbring a range of renewable technologies toschools, including:
small-scale wind projects to generateelectricity for use in schools,
solar photovoltaic to generate electricity solar thermal for heating (air or water),
and geothermal systems for heating and
cooling.
The announcement suggests that the use ofthese technologies will allow school boards tooff-set future operating costs, such as electricityand natural gas. As well, boards could sellelectricity to the grid through Feed-In Tariffs,which form part of the recently passed GreenEnergy Act. The investment will also createinteractive teaching opportunities for students bymaking schools living laboratories.
The Government reports that Ontario’selementary and secondary schools havesignificant energy costs, nearly half a billiondollars each year. The aim is to help schoolboards reduce those costs as well as reducegreenhouse gas (“GHG”) emissions, save onenergy demand and support more green jobs.
The government is expected to create acentralized procurement process to assistOntario’s 72 school boards in researchingtechnologies and selecting vendors as well asmaximizing the benefit of large volumepurchasing power. The funding will flow to theschool boards in the spring of 2010.
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May 20, 2009
OEB Grants Hydro One Networks Leave toSell Certain Distribution Assets to HaldimandCounty Hydro
Under Board File No. EB-2009-0136, theOntario Energy Board (“OEB” or “the Board”)has granted Hydro One Networks Inc. (“HydroOne Networks”) approval to sell certainelectricity distribution system assets toHaldimand County Hydro Inc. (“Haldimand”).The Board identifies the assets being sold in thetransaction as:
1. part of the Argyle F2 feeder involvingapproximately 6.6 km of 8 kV line. Thisline section includes conductors andassociated hardware; and
2. the single phase line along OnondagaTownline Road, between Greens Roadand Haldimand Road 54 comprised ofapproximately 2.8 km of one phase 4.8kV line. This line includes conductorsand associated hardware.
The Board notes that part of the Argyle F2feeder line section is currently used to supplycustomers of both Haldimand and Hydro OneNetworks.
The OEB reports that the application stated thatthe transaction would contribute towardimproved reliability and operational flexibility forHaldimand as the utility would be able to convertthe lines from 8 kV to 27.6 kV, thereby reducingelectrical losses. Ownership of these linesections would also enable Haldimand to reducethe sub transmission charges paid to Hydro OneNetworks. The application also stated that thetransaction would not adversely affect thesafety, reliability, quality of service, operationalflexibility, or economic efficiency of either theHydro One Networks or the Haldimand system.
The Board further advised that the sale price of$9,680 plus GST, represented the negotiatedcommercial value of the assets. The proposedtransaction also required that Haldimand pay thecosts for Hydro One Networks to eliminate itsneed for the Argyle F2 feeder. The estimatedcost of this work was $104,000. A JointAgreement of Sale, signed by both parties wasprovided as part of the application. The
application stated that there are no rate impactsto either party’s customers.
May 12, 2009
OEB Varies its Decision in Respect of OPG’sPayments and Establishes a Tax LossVariance Account
The Ontario Energy Board (“OEB” or “theBoard”) has issued a decision in which it grantsa motion filed by Ontario Power Generation Inc.(“OPG”) for a review and variance of the Board’sDecision with Reasons dated November 3,2008, file number EB-2007-0905 (“PaymentsDecision”).
The Motion sought a review and variance of thePayments Decision; an order for an oral hearingof the motion on the merits, or alternatively anoral hearing on the threshold question ofwhether the Motion raised a substantial questionas to the correctness of the Decision; and ifsuccessful, an order varying the PaymentsDecision, and establishing a variance account.
In its decision, the OEB said that the groundscited by OPG for the Motion were as follows:
1. the Board exceeded its jurisdiction byordering a revenue requirementreduction of $342 million withoutevidentiary or legal foundation,unlawfully depriving OPG of theopportunity to recover its approvedcosts and return on equity;
2. the Board erred in fact and in law infinding that there was no connectionbetween regulatory tax losses andOPG’s proposal to reduce its test periodrevenue requirement; and,
3. the Board’s analysis and disposition ofthe regulatory tax loss and mitigationissue was never advanced at thehearing, depriving OPG of theopportunity to respond to the Board’sapproach to the regulatory tax loss andmitigation issue.
The OEB said that it was satisfied that thegrounds put forward by OPG met the tests asset out in the Natural Gas Electricity InterfaceReview Decision (“NGEIR Review Decision”). Inthat Decision, the Board determined that the
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threshold question requires the motion to reviewto meet the following tests:
the grounds must raise a question as to thecorrectness of the order or decision;
the issues raised which challenge thecorrectness of the order or decision must besuch that a review based on those issuescould result in the Board deciding that thedecision should be varied, cancelled orsuspended;
there must be an identifiable error in thedecision as a review is not an opportunity for aparty to reargue the case;
in demonstrating that there is an error, theapplicant must be able to show that thefindings are contrary to the evidence whichwas before the panel, that the panel failed toaddress a material issue, that the panel madeinconsistent findings, or something of a similarnature;
it is not enough to argue that conflictingevidence should have been interpreteddifferently; and,
the alleged error must be material andrelevant to the outcome of the decision, andthat if the error is corrected, the reviewingpanel would change the outcome of thedecision.
The OEB said that OPG raised questionsregarding the correctness of the finding thatthere was no connection between the mitigationoffered by OPG and its regulatory tax losses,and the resultant ordering of certain revenuerequirement reductions. The Board added that itwas persuaded that those findings wereinconsistent with the evidence; that thoseinconsistent findings were material and relevantto the outcome of the decision; and that if variedor changed, those findings would change theoutcome of the decision.
In its decision, the OEB varied the PaymentsDecision in a manner that links the revenuerequirement reduction and regulatory tax losses,and ordered the establishment of a tax lossvariance account to record any variancebetween the tax loss mitigation amount whichhad underpinned the rate order for the test
period and the tax loss amount resulting fromthe re-analysis of the prior period tax returnsbased on the Board’s directions in the PaymentsDecision as to the re-calculation of those taxlosses.
The OEB determined that the clearance of thisaccount will be reviewed in OPG’s next paymentapplication hearing when a future panel of theBoard reviews the tax analysis ordered in thePayments Decision. The Board anticipated thatany issues related to tax calculations will bedealt with at the next payment amounts hearing.
May 6, 2009
Ontario Government to Introduce Legislationto Allow Workers from Other Provinces andTerritories to Maintain Certification inOntario
The Government of Ontario has announcedlegislation under which workers certified in anyCanadian province or territory would be eligiblefor the same certification in Ontario withoutadditional training or testing. The Governmentsays that, if passed, the Ontario Labour MobilityAct, 2009 would make it easier for workers tocommence employment without long delays,with a few exceptions to protect such things ashealth and safety and consumers. Ontario’sexceptions are currently under consideration.
The announcement notes that, earlier this year,all provinces and territories agreed to eliminatethe barriers that prevent certified workers frommoving between jurisdictions to work.
According to the announcement, approximately80 regulatory authorities and 300 occupations inOntario would benefit from labour mobilitylegislation.
May 5, 2009
Hydro Ottawa Credit Rating Upgraded byDominion Bond Rating Service
Hydro Ottawa is advising that the DominionBond Rating Service (“DBRS”) has upgraded itsrating on Hydro Ottawa Holding Inc.’s SeniorUnsecured Debt. The announcement says thatthe rating was upgraded to “A” from “A (low)”, onthe strength of the company’s financial andoperational performance, and confidenceregarding its ability to perform well in difficult
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economic conditions.
According to Hydro Ottawa, the DBRS report onthe upgrade states, “The rating upgrade reflectsthe Company’s strong financial profile which hasimproved over the past five years, itsconservative financial policies, and its strongoperational performance and low business risk.”Hydro Ottawa says that the rating agency furthernotes that it views the Company’s customer mixas being reasonably resilient in difficulteconomic times, and that the impact of thecurrent economic situation on the company’soperating performance should be negligible.
The announcement notes that DBRS lastchanged its rating of Hydro Ottawa inSeptember 2007, when it revised the trend onthe rating upward from “stable” to “positive”.
May 4, 2009
OPG Appoints Tom Mitchell as President andCEO
After considering both internal and externalcandidates, the Board of Directors of OntarioPower Generation (“OPG”) has named TomMitchell, who is currently OPG’s Chief NuclearOfficer, as President and CEO effective July 1,2009 following the retirement of Jim Hankinson.
The OPG Board also expressed theirappreciation of Mr. Hankinson’s efforts as aBoard member starting in 2003, and asPresident and CEO commencing in 2005, notingthat the company faced significant challengeswhen he took over.
May 4, 2009
Bruce Power Announces Appointment ofMurray Elston as its Vice President,Corporate Affairs
Bruce Power has announced that Murray Elston,the President of the Canadian NuclearAssociation (“CNA”), will join the company asVice President, Corporate Affairs, effective May19, 2009. Mr. Elston will guide all of BrucePower’s external communications, includinggovernment, community, investor and mediarelations.
The announcement advises that Mr. Elstonserved as a member of the Ontario legislaturefor Huron-Bruce from 1981 to 1994, holding a
number of positions, including Minister of Health,Chairman of the Management Board, Minister ofFinancial Institutions and Chairman of the PublicAccounts Committee.
Bruce Power mentions that Mr. Elston is agraduate of the University of Western Ontario,holding bachelor’s degrees in arts and law, andpractised law in Bruce County prior to hiselection. From Queen’s Park, he moved on toserve as President of Canada’s Research-Based Pharmaceutical Companies beforejoining the CNA in 2004.
The announcement adds that Mr. Elston is Chairof the Walkerton Clean Water Centre and serveson the boards of the University of OttawaInstitute of Mental Health Research, theCanadian Centre for Energy Information and theCanadian Nurses Foundation. He is a formermember of the Energreen Solutions Group andhas served as President of the Ontario InterlinkIndustrial Park and Chair of the Board ofDirectors of the University of Ottawa Institute ofMental Health Research and Energy DialogueGroup.
Q U É B E C
Natural Gas
May 27, 2009
Régie Approves Gazifère Application toDecouple Gas Transmission Rates
On May 27, 2009, the Régie de l'énergie(“Régie”) released a decision approving Phase 1of Gazifère Inc. (“Gazifère”)’s 2010 rateapplication, which dealt with Gazifère’s requestto decouple its gas transmission rates.
In Decision D-2009-067, the Régie approved therate structure and terms proposed by Gazifère.However, the Régie reserved its decisionpertaining to the start date of the new rates. TheRégie ordered Gazifère to propose a start datefor the new rates, which reflect the decoupling ofgas transmission costs, as soon as possible.The start date must also take into account theimplementation of Gazifère’s new CustomerInformation System (“CIS”), billing system.
Background
On March 13, 2009, Gazifère filed an applicationwith the Régie to decouple its gas transmission
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rates and close its accounting books for theperiod covering January 1, 2008 to December31, 2008. That same application also includedGazifère’s rate, supply plan and Demand-SideManagement (“DSM”) Plan application for 2010,all of which will come into effect on January 1,2010.
On March 25, 2009, the Régie released aprocedural order regarding Gazifère’sapplication, which was the subject of a CERISEWhat’s New Alert on March 30, 2009. Inprocedural order D-2009-032, the Régie orderedthat the application be divided into three phases.Phase 1 pertains to Gazifère’s application todecouple its gas transmission rate from itsdistribution rates as well as the withdrawal of theTransport-T credit granted to transmissioncustomers. Phase 2 would deal with Gazifère’sapplication to close its books for 2008. Phase 3will cover Gazifère’s 2010 rate application andsupply plan.
In compliance with the procedural order, a publichearing was not held for subjects dealt with inPhases 1 and 2 but will be held for Phase 3.
On May 26, 2009 the Régie rendered DecisionD-2009-067 in which it approved the elementsincluded in Phase 1 of Gazifère’s application.
Under the existing billing system, Gazifère billsall its customers for the cost of gas transmissionand distribution, which includes Enbridge GasDistribution (“EGD”) and Niagara Gas’transmission costs. Gazifère then credits its 42transmission service customers; of those, 4receive the service-T credit directly from theutility. The other 38 transmission servicecustomers receive the credit from theirrespective brokers.
Following changes to be made to its Rate 200and the implementation of its new billing system,EGD will bill Gazifère for the transmissionservice as a separate line-item and it willeliminate the service-T credit granted totransmission service customers. Gazifère mustthen decouple the price of transmission for all itsrates, in order to have the distribution andtransmission as separate line-items. Gazifèremust also eliminate the service-T credit grantedto its transmission service customers. Thechanges made will not have an impact on the
cost of natural gas paid by Gazifère under Rate200 nor will it have an impact on customers’bills.
Gazifère’s full application carries docket numberR-3692-2009.
Electricity
May 22, 2009
FERC Approves Funding Plan for MajorInternational Transmission Project LinkingHydro-Quebec with ISO New England
The Federal Energy Regulatory Commission(“FERC” or “the Commission”) has approved thefunding arrangement for a major transmissionproject linking Hydro-Quebec with ISO NewEngland (“ISO NE”) which would deliver low-costhydropower to consumers in the New Englandregion. The announcement adds that the projectis expected to reduce greenhouse gas (“GHG”)emissions by an estimated 4 to 6 million tons ofcarbon dioxide per year by displacing gas-firedgeneration in New England.
The Commission says that Northeast UtilitiesService Company, NSTAR Electric Companyand Hydro-Quebec TransEnergie (“HQT”) arecurrently negotiating a joint developmentagreement for the design, planning andconstruction of a 1,200 megawatt high voltagetransmission line that will cross over the U.S.-Canadian border and connect to ISO NE’sbackbone 345 kilovolt (“kV”) transmissionsystem. This expansion will make significantamounts of surplus hydropower available forexport to the United States.
The announcement reports that H.Q. EnergyServices (U.S.) Inc. is taking responsibility forany of the project’s risks, and agreed toparticipant funding for the project. Under aparticipant funding plan, the project costs will notbe included in the rates for transmission serviceunder ISO NE’s Open Access TransmissionTariff (“OATT”).
May 21, 2009
NERC, NPCC and Régie Sign New AgreementConcerning the Reliability of the Bulk PowerSystem in Québec
The North American Electric ReliabilityCorporation (“NERC”) and the Northeast Power
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Coordinating Council, Inc. (“NPCC”) haveannounced that they have signed a criticalagreement with the Régie de l’Énergie inQuébec (“Régie”), providing for the twoorganizations to assist the Régie in establishingmandatory reliability standards in Québec. Theannouncement adds that the agreement alsointroduces a compliance monitoring andenforcement program in the province.
NERC says that the agreement marks the latestmilestone in its efforts to ensure commonreliability standards are adopted and enforcedacross the interconnected bulk power system inNorth America. It adds that recent agreements inNew Brunswick and Saskatchewan have alsomarked progress in this area.
May 14, 2009
Régie Temporarily Approves HQD’s Requestfor New Deferral Account
On May 14, 2009, the Régie de l’énergie(“Régie”) released a decision, pursuant to anapplication from Hydro-Québec Distribution(“HQD”), in which it temporarily approved thecreation of a deferral account for revenuevariances associated with the application of theLoad Retention Rate, applicable to HQD’s large-power industrial customers. The new deferralaccount is applicable to variances starting May1, 2009.
However, in its decision D-2009-057, the Régiealso noted that the terms of the deferral accountand the inclusion of the new deferral accountbalance in HQD’s revenue requirement would beexamined in HQD’s next rate application.
Background
On May 1, 2009, HQD filed an application withthe Régie to create, as of May 1, 2009, adeferral account for revenue variancesassociated with the application of the LoadRetention Rate, applicable to HQD’s large-power industrial customers. HQD requested thatthe new deferral account bear interest at theauthorized rate on the rate base.
HQD argued that the current economic situationhas led to renewed interest in this rate and arate of this particular nature can only be fullyoperational with the creation of a deferralaccount in order to account for revenue
variances associated with its application.
HQD also specified that it would present thespecific terms for this account in its next rateapplication; therefore, a public hearing was notcarried out for this application.
The full application carries docket number R-3697-2009.
May 13, 2009
Québec Government Launches the RomaineHydroelectric Complex – the LargestConstruction Project in Canada
The Government of Québec has announced theofficial launch of construction on thehydroelectric complex on the Romaine in Havre-Saint-Pierre - the biggest construction project inCanada, which, when completed, will provideQuébec with an additional installed capacity of1550 megawatts (“MW”) and access to anadditional 8 terawatt-hour (“TWh”) of electrictyper year. The announcement advises that theconstruction of four hydroelectric plants on theRomaine will end in 2020, with the first powerslated to come on stream in 2014.
The announcement states that a joint federal-provincial review panel approved construction ofthe project after a rigorous and transparentenvironmental assessment process.
The announcement suggests that the project willgenerate economic spinoffs in the form ofcontracts and purchases of construction-relatedgoods and services valued at some $3.5 billionacross Québec, including around $1.3 billion forthe Côte-Nord, and that at the height ofconstruction, between 2012 and 2016, theproject will create over 2,000 jobs per year.
An attached backgrounder provides more detailsabout the project including the main steps in theapproval process and the start-up schedule.
May 4, 2009
Government of Québec Raises MaximumPrice for Aboriginal and Community WindPower Projects
The Government of Québec has announced thatit would proceed with an increase in themaximum price for community-based andindigenous wind power projects, as of April 30,2009. The maximum price is thereby increased
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from a maximum of 9.5¢ per kilowatt hour(“KWh”) to 12.5¢/KWh in 2009 dollars indexedannually at 100% of the consumer price index(“CPI”) or its equivalent.
The decision will make it possible for Hydro-Québec (“HQ”) to include the new maximumprice in its Call for Tenders C/T 2009-02 for thepurchase of two 250 megawatt (“MW“) blocks ofwind power produced by community-based andindigenous groups respectively.
The announcement indicates that the twotendering processes should generate $1.3 billionin investments and create some 4,200 new jobsin various regions in Québec. The wind farmswill enter into service starting in 2012.
HQ’s call for tenders falls within the Governmentof Québec’s 2006-2015 Energy Strategy,released in May 2006, which calls for thedevelopment of 4000 MW of wind power inQuébec by 2015.
May 6, 2009
Québec Government AnnouncesInauguration of New Hydro-QuébecTransÉnergie Facility for the Refurbishmentof Transmission System Breakers
On May 4, 2009, the Government of Québecannounced the opening of a new facility for therefurbishment of Hydro-Québec TransÉnergie(“HQT”)’s breakers at the Madawaskasubstation, in Dégelis.
The announcement stated that the project aimsto ensure the reliability and quality of thetransmission system and will contribute tomeeting HQT’s long-term operability objectives.
The Dégelis substation was selected due to theavailability of premises suitable for thecompletion of this type of work as well as itsfavourable location for the equipment that mustbe temporarily removed from the transmissionsystem to carry out the refurbishment work.Approximately one third of some 8,000 breakerswill be refurbished in the Baie-Comeau,Chibougameau, Dégelis, Trois-Rivières,Gatineau and Varennes facility.
According to the announcement, the new facilitywill create 11 new direct jobs in the Lower St-Lawrence region, in Québec.
May 4, 2009
Hydro-Québec Launches Call for Tenders for500 MW of Aboriginal and CommunityProjects Wind Power Produced in Québec
On April 30, 2009, Hydro-Québec Distribution(“HQD”) launched a Call for Tenders, C/T 2009-02, for the purchase of two separate 250megawatt (“MW”) blocks of wind power energyproduced in Québec, in order to meet the long-term electricity needs of its Québec customers.One of the energy blocks is designated toconsist of Aboriginal projects and the other ofcommunity projects. Each of the blocks will bedistributed as follows:
50 MW starting on December 1, 2012
100 MW starting on December 1, 2013
100 MW starting on December 1, 2014.
The maximum capacity for each individualproject is limited to 25 MW. The term of thecontracts is fixed at 20 years. The contracts aresubject to approval by the Régie de l’énergie(“Régie”).
Each project is also subject to minimum regionaland Québec content, divided as follows:
At least 60% of the overall costs of each windfarm must be incurred in Québec;
At least 30% of the cost of the windmills mustbe incurred in the Gaspésie- îles-de-la-Madeleine administrative region.
Background
HQD’s call for tenders was launched pursuant tothe Regulation respecting a 250 MW block ofwind energy from Aboriginal projects and theRegulation respecting a 250 MW block of windenergy from community projects, enacted onOctober 29, 2008. The Regulations wereamended on March 4, 2009 and April 29, 2009.
On April 30. 2009, the Government of Québecannounced that the maximum price foraboriginal and community-based wind powerprojects was increased from 9.5¢ per kilowatthour (“KWh”) to 11.5¢/KWh.
HQD has given the firm Deloitte Inc. themandate to assist it in the call for tendersprocess and act as its Official Representative.
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Deloitte Inc. must also advise HQD on theapplication of the Call for Tender and ContractAward Procedure.
S AS K A T C H E W A N
Electricity
May 11, 2009
SaskPower Undertakes Programs to HelpRural Residents Reduce Risk of WorkingAround Power Lines and ImproveProductivity of Farming Operations
SaskPower has announced that it is undertakingtwo programs to help Saskatchewan farmfamilies reduce the risk of working around powerlines and improve the productivity of farmingoperations. The two programs undertaken are:
the Farmyard Power Line Relocation Program;and
the Rural Electrical Distribution Program.
SaskPower says that under the reintroduction ofthe cost-sharing Farmyard Power LineRelocation Program, it will pay 75 per cent of thecost to bury or relocate overhead power lines infarmyards. Customers are responsible for theremaining 25 per cent, up to a maximumcontribution of $2000.
The company adds that customers will beplaced in the program in the order that theirapplications are paid and received. SaskPowernotes that it has a limited budget for the programfor each year, and that the budget will beestablished annually as part of the corporation’sbusiness planning process.
SaskPower points out that its second programfor rural Saskatchewan is a long-term strategy toimprove the existing overhead rural electricaldistribution system in the province. Existingoverhead lines in fields will be moved andreplaced with overhead lines in road allowances.Criteria for this program will be based on theneed to replace or upgrade aging infrastructure.Once the electrical distribution system has beenanalyzed and the priority list of infrastructureupgrades is developed, construction is expectedto begin in 2010.
General
May 27, 2009
Saskatchewan Government Provides MoreFinancial Support for Geothermal Systems
SaskPower has advised that the Government ofSaskatchewan has introduced a rebate programto encourage the use of geothermal heatingsystems within the provincial business sector.The announcement says that eligible businessescan receive a 15 per cent rebate on the cost ofinstalling a Canadian GeoExchange Coalition(“CGC”) certified geothermal heating and coolingsystem and the maximum rebate is $100,000.
According to SaskPower, financial support forresidential and farm customers wishing to installa geothermal system has also been enhanced.Interest rates for the Geothermal and Self-Generated Renewable Power Loan Programintroduced last fall, have been lowered. Byworking with TD Canada Trust, SaskPower willnow subsidize these loans by 3.5 per cent off ofTD’s fixed interest rate.
The announcement points out that thecommercial rebate program is funded bySaskPower and administered by theSaskatchewan Research Council (“SRC”). To beeligible for the rebate, projects must beprofessionally designed and installed by acertified member of the CGC.
SaskPower notes that it has approximately30,000 commercial customers, of which nearly2,500 use electric heat and will derive the mostbenefit from switching to a geothermal system.
Existing buildings currently heated by naturalgas are not eligible for the rebate. In a newbuilding, if there is access to natural gas, afeasibility study will be conducted to comparethe cost and environmental implications ofgeothermal, electricity and natural gas.SaskPower adds that it will assist with the costof those studies, funding up to 50 per cent of thefirst $5,000 and up to 25 per cent of theremaining costs.
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U N I T E D S T AT E S O F AM E R I C A
Natural Gas
May 29, 2009
AGA Releases May 29, 2009 Edition of its"Natural Gas Market Indicators"
The American Gas Association (“AGA”) hasreleased the May 29, 2009 edition of its “NaturalGas Market Indicators”. Among the AGA'sobservations are the following:
Natural Gas Pricing: Oil prices are beginning tofirm up, with both West Texas Intermediate andBrent trading above $62 per barrel as of lateMay. However, this firming is not reflected innatural gas markets. Henry Hub spot pricesremain in the $3.50 per MMBtu range. Spotprices, which began and ended May at around$3.50, touched the mid $4 mark in the middle ofthe month, their highest level since midFebruary, partially due to a few weeks of warmerthan normal weather. The futures market isstronger, with deliveries in 2010 priced in thehigh $5/low $6 range per MMBtu. Some analystsbelieve that the recent increase in spot priceswas due to liquids-driven increases andexcitement about possible economic turnaroundmore than underlying supply/demandfundamentals, which remain relatively weak.Others anticipate the July prompt month pricingto include a weather premium reflecting thepossibility of extreme heat or hurricane activity.
Underground Storage: Working gas inunderground storage had another stronginjection week, with overall volumes increasingby 106 Bcf compared to previous week’s revisedreport, in line with market consensus of a 110Bcf build. As of May 22, working gas in storagewas 2,213 Bcf, 524 Bcf higher than the sametime last year and 393 Bcf higher than the fiveyear average. Working gas in storage increasedin the East, West, and Producing regions. Largebuilds are becoming less and less surprising,since the most recent report marks 8 straightweeks of net storage increases.
Pipeline Imports and Exports: The U.S. remainsoversupplied with gas from domestic production,resulting in reduction on imports from Canada toan average of 5.4 Bcf per day in May, comparedto 6.4 Bcf per day last month and an average of
over 8 Bcf per day throughout 2008. The UnitedStates is sending some of its excess gas toMexico, with exports increasing to almost a fullBcf per day (0.9) on average this May,compared to 0.6 Bcf per day on average in Apriland 0.7 Bcf per day in May 2008.
May 13, 2009
AGA Releases May 12, 2009 Edition of its“Natural Gas Market Indicators”
The American Gas Association (“AGA”) hasreleased the May 12, 2009 edition of its “NaturalGas Market Indicators”. Among the AGA'sobservations are the following:
Natural Gas Pricing: The AGA notes that worldoil prices have increased to more than $58 perbarrel. At the same time, natural gas acquisitionprices have firmed in the $4.00-$4.50 per millionBritish Thermal Units (“MMBtu”) range for cashand prompt-month benchmarks at Henry Hubduring the past several weeks. Some analystsbelieve that, in contrast to this recent pricemovement, the current price activity is anupward technical correction to a sustained bearmarket and that prices may fall as the summerprogresses and when the continued supply-demand imbalance asserts itself.
Underground Storage: The AGA says thatunderground storage continues to sustain arobust level compared to last year and the five-year average. At 1,918 billion cubic feet (“Bcf”),inventories for the week ending May 1, 2009were 34.4 percent higher than in 2008 and 23.3percent higher than the five-year average.Beginning with the week ending April 3, 2009,each region of the country has demonstratedpositive net weekly storage builds as the netinjection season has progressed.
Pipeline Imports and Exports: U.S. gas supplyduring the first four months of 2009 is flat interms of domestic production with slightlygrowing LNG volumes. Pipeline imports fromCanada have declined. The Petroleum ServicesAssociation of Canada now expects the numberof oil and gas wells drilled in 2009 to be 41percent lower than the previous year (10,000compared to about 16,900 wells drilled andcompleted). In addition, pipeline imports fromCanada have fallen from an average of 7.9 Bcfper day in January 2009, to 6.3 Bcf per day
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during April. Daily import volumes for May havebeen below 6.0 Bcf. To the south, U.S. netexports to Mexico averaged about 0.7 Bcf perday during March 2009 but fell to under 0.6 Bcfper day for April.
May 6, 2009
AGA Releases April 30, 2009 Edition of its"Natural Gas Market Indicators"
The American Gas Association (“AGA”) hasreleased the April 30, 2009 edition of its “NaturalGas Market Indicators”. Among the AGA'sobservations are the following:
Natural Gas Pricing: Natural gas cash andprompt-month prices have been stable for thepast month (about $3.50 per million BritishThermal units (“MMBtu”)) while analysts debatemarket expectations for the summer. Manyanalysts agree on the solid domestic production,a strong underground storage position and anuptick in liquefied natural gas (“LNG”) imports onthe supply-side along with an economy which isnot ready to support a surge in large volumecustomer demand. The debate overexpectations for gas acquisition prices will likelybe overcome by actual events.
Underground Storage: Underground storageoperators have initiated the 2009 net injectionseason, and at 1,741 billion cubic feet (“Bcf”),the national working gas inventory is above thefive-year average and last year’s pace. For theweek ending April 17, 2009, working gas is 35.8percent above the volume from one year agoand 22.7 percent higher than the five yearaverage. AGA notes that only about 2.0 trillioncubic feet (“Tcf”) will be required to push storageto “full” over the next 185 days, and has doubtswhether some of the daily average requirementwill come in the form of LNG or not.
Pipeline Imports and Exports: Pipeline importsfrom Canada have fallen from an average of 7.9Bcf per day in January 2009, to 6.6 Bcf per dayduring the first three weeks of April. The 16.5percent decrease in pipeline imports originatingin Canada coincides with the falling U.S.demand requirements. To the south, U.S. netexports to Mexico averaged about 0.7 Bcf perday during March 2009 but have fallen to under0.6 Bcf per day for the first three weeks of April.
May 4, 2009
U.S. FERC Staff Release Final EIS for theJordan Cove LNG Terminal and PacificConnector Gas Pipeline Project
Pursuant to Docket Nos. CP07-444-000 andCP07-441-000 respectively, the staff of the U.S.Federal Energy Regulatory Commission(“FERC” or ‘the Commission”) have released thefinal Environmental Impact Statement (“EIS”) forthe Liquefied Natural Gas (“LNG”) importterminal proposed by Jordan Cove EnergyProject, LP (“Jordan Cove”), and the associatedsend out natural gas pipeline proposed byPacific Connector Gas Pipeline, LP (“PacificConnector”).
The Commission explains that Jordan Cove’sLNG terminal would be located on the bay sideof the North Spit of Coos Bay, about 7.5 milesup the exiting Coos Bay navigation channel, inCoos County, Oregon. Pacific Connector’sproposed 36-inch-diameter send out pipelinewould extend from Jordan Cove’s LNG terminalabout 234 miles southeast across Coos,Douglas, Jackson, and Klamath Counties,Oregon to a terminus near Malin, Oregon whereit would interconnect with the existing pipelinesystems of Gas Transmission NorthwestCorporation, Tuscarora Gas TransmissionCompany, and Pacific Gas and ElectricCompany.
FERC says that it concludes that constructionand operation of the Jordon Cove Energy(“JCE”) and Pacific Connector Gas Pipeline(“PCGP”) Project would result in some adverseenvironmental impacts. The Commission addsthat most of these impacts would be reduced toless-than-significant levels with theimplementation of the applicants’ proposedmitigation measures and the additionalmeasures recommend in the final EIS. FERCsays that the primary reasons for its decisionare:
The final engineering design for the LNGterminal would incorporate detailed seismicspecifications and other measures to mitigatethe impacts of earthquakes, and mitigationmeasures would be implemented along thepipeline route to address landslides and othergeological hazards;
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An engineering peer review process isrecommended to ensure compliance with allapplicable regulations, codes, designspecifications, and conditions of theCommission Order;
Jordan Cove would implement its project-specific Upland Erosion Control andRevegetation Plan and Wetland andWaterbody Construction and MitigationProcedures, and Pacific Connector wouldimplement its project-specific Erosion Controland Revegetation Plan which would minimizeimpacts on soils, water bodies, wetlands, andvegetation;
Jordan Cove and Pacific Connector wouldimplement various mitigation plans tocompensate for impacts on water bodies,wetlands, vegetation, and habitats;
Pacific Connector would continue to consultwith the Bureau of Land Management (“BLM”),(U.S.) Department of Agriculture ForestService (“USFS”),, and Bureau of Reclamation(“BOR”), to address impacts and mitigationmeasures on federal lands managed by theseagencies, and would incorporate project-specific design and mitigation measures intoPlans of Development for each affectedfederal land unit;
Completion of consultations with the U.S.Army Corps of Engineers (“COE”), CoastGuard, Fish and Wildlife Service (“FWS”),National Marine Fisheries Service, OregonDepartment of Land Conservation andDevelopment, Oregon Department ofEnvironmental Quality, Oregon Department ofState Lands, Oregon Department of Fish andWildlife, Oregon State Historic PreservationOffice, and other appropriate agencies andissuance of relevant permits andauthorizations would be completed beforeJordan Cove and Pacific Connector would beallowed to begin construction;
The proposed LNG terminal would meet thefederal safety regulations regarding thethermal radiation and flammable vapourdispersion exclusion zones, and appropriatesafety features would be incorporated into thedesign and operation of the LNG importterminal and LNG carriers;
An environmental inspection and mitigationmonitoring program would be implemented toensure compliance with all mitigationmeasures which become conditions of anyFERC authorization; and
Jordan Cove would have to implement the riskmitigation measures recommended by theCoast Guard in its Waterway Suitability Reportissued July 1, 2008.
The Commissioners advise that they will takeinto consideration the staff’s recommendationsand the final EIS when they make a decision onthe Project.
Electricity
May 25, 2009
NYISO Issues 2009 ComprehensiveReliability Plan
The Board of Directors of the New YorkIndependent System Operator (“NYISO”) hasapproved the 2009 Comprehensive ReliabilityPlan for New York’s bulk electricity grid.
The announcement advises that the ReliabilityPlan is the product of the ComprehensiveReliability Planning Process conducted by theNYISO to provide a blueprint for meeting thereliability needs of the state’s bulk electricity gridover a 10-year planning horizon.
The NYISO notes that, in January, it issued the2009 Reliability Needs Assessment, whichreported that New York State’s electric powerresources (generation, transmission, anddemand-side programs) are expected to meetthe state’s electricity reliability needs for the nextten years (2009-2018), assuming continuedprogress on planned resource additions.
According to the announcement, the NYISO’sfindings indicate that anticipated capacity supply(42,536 MW) will exceed the forecasted peakload (35,658 MW) by 994 MW in 2018, afterfactoring in the presently required 16.5%Installed Reserve Margin.
The primary factors influencing these findingsinclude reduction in peak load forecast due toprojected energy efficiency gains and slowereconomic growth; an increase in generationadditions and participation in demand-sidemanagement; and fewer planned retirements of
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generating facilities compared with the 2008reliability assessment.
However, the 2009 Comprehensive ReliabilityPlan does identify several risk scenarios thatcould adversely impact the current reliabilityassessment, including:
Power Plant Retirements -- Unexpectedretirement of significant generation facilitiescould create reliability concerns and requirenew resources in New York. For example, dueto its location in a constrained part of thesystem, retirement of one of the two IndianPoint nuclear power plant units would causean immediate violation of reliability standardsif other resources were not available toaddress the need.
Emerging Air Quality Standards --Implementation of new programs to controlsmog-causing emissions from fossil-fueledpower plants on high electric demand dayscould reduce the power available to meetpeak energy needs. For example, if 25% ofaffected units do not retrofit to meet theemission-control requirements, the availabilityof up to 3,125 MW of capacity would beaffected. In addition, there is uncertainty aboutthe long-term impacts of Clean Air InterstateRule (“CAIR”) on fossil generating units. In thenear term, these impacts are not expected todegrade reliability to unacceptable levels.
Greenhouse Gas (“GHG”) EmissionReductions -- The Regional Greenhouse GasInitiative (“RGGI”) program is not expected tohave adverse impacts on electric reliability inthe short term. However, if higher carbonallowance prices were to occur at the sametime as the spread between fossil fuels andother generation resource costs decreasesand as the cost of compliance with otherenvironmental programs increase, fossil-fueled units might experience strain onwhether, and the degree to which, they willcontinue to be able to operate. In addition, theRGGI market would be impacted by nationalcap and trade legislation, if enacted, as wellas by the current economic downturn.
The 2009 Reliability Plan also included severalrecommendations to address potential reliabilityconcerns:
Continued progress on initiatives to addressissues and concerns with voltage performanceon the bulk power system;
Urging the New York State Energy Plan,which is scheduled to be finalized in October2009, to call for the re-enactment of acomprehensive siting process for majorelectric generating facilities in the state;
Continued monitoring of the fuel diversity ofthe power supply system and changes to thefuel supply infrastructure; and
Continued participation in regional andinterregional planning efforts to maintainadequate models of its neighbouring systems’emergency assistance.
Another significant feature of the 2009 planningprocess cycle is that this plan will be the startingpoint for a new economic planning processcalled the Congestion Assessment andResource Integration Study (“CARIS”), which willcommence in the summer of 2009. The neweconomic planning process will examinecongestion on New York’s transmission systemand the relative costs and benefits of genericprojects to alleviate that congestion.
The NYISO’s newly expanded planning processwas developed in response to Order 890 of theU.S. Federal Energy Regulatory Commission(“FERC”). It integrates a local planning processfor each transmission owner with the existingreliability planning process and the CARIS intoan extended two-year planning cycle.
May 25, 2009
NYISO Anticipates Sufficient ElectricitySupply for Summer 2009
Noting that the economic downturn and energyefficiency initiatives are reducing demand, theNew York Independent System Operator(“NYISO”) is reporting that electricity supplies inNew York State should be adequate to meetexpected demand this summer.
The NYISO forecasts that New York’s summer2009 peak usage will reach 33,452 megawatts(“MW”). While the forecast is 3.1% (1,020 MW)higher than the 2008 summer peak of 32,432MW, it is 1.05% (357 MW) lower than the NYISOforecast for 2008 summer peak usage and
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1.40% (487 MW) lower than the record systempeak of 33,939 MW recorded on August 2, 2006.
The NYISO explains that extreme weather is thedominant factor when it comes to producing veryhigh demand for electricity and that heat waves,which cause increased power use by airconditioning and cooling systems, could producepeak loads this summer to rival those of recentyears. It says however, that overall electricityconsumption is trending lower as a result of theeconomic slowdown and New York State’svigorous energy efficiency initiatives.
The NYISO anticipates that installed generatingcapacity of 38,547 MW will be in place to meetprojected demand. Since March 2008, additionalgenerating capacity totalling 909 MW has beeninstalled, of which 569 MW is from wind power.Total wind power capacity in New York is now1,275 MW, of which 10% (or 127 MW) isassumed to be available during peak summerdemand periods. In addition, demand responseresources are available to provide over 2,000MW of load relief if necessary. Demandresponse programs provide incentives forelectricity customers to reduce their power useduring times of peak demand.
The longer-term usage trend anticipates slowergrowth in peak demand, as well as overallenergy use. Over the coming ten-year period,the NYISO expects peak demand to increase by0.68% annually, and overall energy use to growby 0.59%. The current forecasts are significantreductions from the NYISO’s 2008 estimates,which predicted an annual increase in peakdemand of 0.94% and increases in overallenergy use of 1.18% per year.
May 19, 2009
CAISO Reports Healthy Energy Supply andDemand Forecast for Summer 2009
The California Independent System OperatorCorporation (“California ISO” or “CAISO”) hasreleased its “2009 Summer Assessment”, whichshows a lower probability of encountering supplyissues this summer when compared to last year.CAISO notes that several factors shape thesummer 2009 assessment, such as newgeneration added since last summer which isexpected to more than offset drought-relatedreductions in hydroelectric production. In
addition, electricity demand and load growthremains down due to the economy. The reportalso indicates that energy imports should remainsufficient.
According to CAISO, the summer outlook showsnearly 1,500 megawatts (“MW”) of newgenerating capacity coming online by July and a3 percent reduction in peak demand due mainlyto the economic downturn. CAISO states thatpower imports into California can vary, butgenerally, an additional 1,000 MW is expectedthis summer compared to the forecast forimports last year. The new generation expectedthis summer includes nine power plants, two ofthem wind farms with a combined capacity of153 MW as well as a 2-MW photovoltaic (“PV”)solar plant. An estimated 22 MW of existinggeneration is scheduled to retire. CAISO notesthat it expects the dry year in 2009 could reducehydroelectric capacity by approximately 1,000MW.
CAISO advises that for the first time in manyyears, the situation in southern California issomewhat better than in northern Californiabecause of that region’s dependence onhydroelectricity. In addition to the newgeneration coming on line this year, CAISO saysthat it can now use another important toolquicker than in the past. Interruptible demandresponse programs refer to customers whoreduce their energy consumption under certainadverse conditions. CAISO explains that theseprograms are used to prevent reserves fromfalling below acceptable levels.
May 19, 2009
NERC Says Reduced Electricity DemandBolsters Reserve Margins throughout NorthAmerica for the Coming Summer
The North American Electric ReliabilityCorporation (“NERC”) has announced that theoutlook for electricity reliability for the comingsummer season is generally good in its annual2009 Summer Reliability Assessment, whichassesses the reliability of the North Americanbulk power system for the coming summerseason.
NERC states that the economic recession hascontributed to an overall reduction in theforecasted demand for electricity this summer,
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leading to higher reserve margins across NorthAmerica for the season. NERC stresses thatdespite this decline in demand, it is vital thatinfrastructure development continue in order tomaintain reliability for the coming years. This isespecially true for transmission infrastructure asnew variable resources like wind and solar aredeveloped.
Specific key findings, detailed in the report,include:
Economic Recession Drives Broad Decline inForecast Demand; Reserve Margins Increase— 2009 summer peak demand is projected tobe nearly 15 1 gigawatt (“GW”) (1.8 percent)lower than last year. Summer energy use(total electricity used over time) is alsoprojected to decline by over 30 Terawatt hours(“TWh”), trending towards 2006 summerlevels. Such year-over-year reduction inelectricity use is not uncommon, for example— industrial use of electricity has declined in10 of the past 60 years.
Coal and Natural Gas Fuel Forecasts AppearAdequate — Overall, U.S. fossil-fuelinventories, supply, and delivery capabilityappear adequate for the 2009 summerseason. Coal stockpiles are currently at nearly50 percent above average levels and naturalgas storage at 23 percent above averagelevels.
Nameplate Wind Capacity Grows by morethan 9,000 MW — Projected installednameplate wind capacity increased 45 percentfrom summer 2008 to nearly 30,000 MW totalin summer 2009. The need for transmissioninfrastructure to support these new resourcesis becoming evident, as regions integratingwind resources are projecting increasedtransmission congestion in the 2009 summer– particularly during off-peak periods.Nevertheless, integration of new windresources appears to be manageable for the2009 summer.
Demand Response Increasingly Contributesto Capacity — Demand response resourcesused to reduce peak demand during the 2009summer are projected to increase by eightpercent (more than 2,200 MW) from the 2008summer. The greatest rise in demand
response resources is seen in the NortheastPower Coordinating Council (“NPCC”) andReliabilityFirst (“RFC”) regions, where marketmechanisms have encouraged significantdevelopment in demand response programs inISO New England (“ISO NE”), New York ISO(“NYISO”), and PJM.
May 13, 2009
NYISO Advises that Wholesale ElectricityPrices Have Dropped Again
According to the New York Independent SystemOperator (“NYISO”), the prices of wholesaleelectric energy in New York State have droppedto their lowest level since 2002. The NYISOreports that the average price of wholesaleelectric energy in the state was $39.64 permegawatt-hour (“MWh”) in April — a 13% dropfrom prices in March and almost half theJanuary price of $73.28/MWh. The SystemOperator adds that the last time wholesaleelectric energy prices were this low was in May2002 when the average price was $37.44/MWh.
The NYISO suggested that the lower pricesprovide further evidence that New York’scompetitive markets are working as designed.The System Operator says that, while the latestdrop in energy prices is largely attributable tolower natural gas costs, New York also has amuch more efficient fleet of power plants today.Natural gas prices may go back up, but theefficiency improvements will not disappear.
The announcement adds that, as previouslyreported, the efficiency of fossil-fuelled powerplants in New York, as measured by the system-wide “heat rate,” has improved by 21% since theonset of competitive electricity markets in late1999. The heat rate is a measurement of howefficiently a generator uses heat energy. Theoperating cost of a fossil fuel/steam-drivenpower plant is a function of the unit’s heat rate.
The announcement explains most power plantsin New York burn fossil fuels to generate power,and their costs are highly influenced by theprices of natural gas and oil. The cost of naturalgas has dropped to $4.10 per million BritishThermal Units (“MMBtu”) in April, down from$5.00/MMBtu in March and $9.55/MMBtu inJanuary. Lower demand for electricity permits alarger proportion of electricity to be generated by
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more efficient and less costly facilities. Averagedaily electricity usage in New York State was400 gigawatt-hours per day (“GWh/day”) in April2009, down from last month (422 GWh/day inMarch 2009) and below last year’s levels (406GWh/day in April 2008).
May 7, 2009
PJM Says that Region Ready for Hot WeatherPower Demand
PJM Interconnection (“PJM”) says it expectsthere to be adequate resources to meetconsumers’ needs for electricity this summer inits region, which includes 13 states and theDistrict of Columbia, 51 million people and 20percent of the U.S. economy. The regulatoradds that, because of the recession, peakelectricity use in the PJM region is forecast to belower than the peak use last summer, and as theeconomy recovers, summer peak usage isforecast to grow at an average annual rate of 1.7percent.
PJM advises that transmission system upgradesand additions completed since last year alsohelp it to meet demand. However, the regulatoradds that in future years economic growth andrising demand for renewable energy willchallenge it and its members to add necessarytransmission lines and additional power supplyresources to keep electricity reliable.
PJM’s projected peak use of electricity for thesummer of 2009 is 1.4 percent lower than theweather-adjusted peak in 2008. The projectedweather-adjusted peak usage for 2009 is134,430 megawatts (“MW”) compared to aweather-adjusted 136,310 MW in 2008.
PJM says that it has 165,200 MW of powerresources to meet the demand for electricity.The available resources include a recordamount of emergency load management, 5,925MW. PJM explains that consumers in loadmanagement programs typically receive either aspecial rate or payments for stopping orreducing their use of electricity under emergencyconditions. The amount of emergency loadmanagement has grown about one-third sincelast year. It has grown five-fold since 2003.
The announcement indicates that this summer’sactual peak use could be higher or lower than
predicted if temperatures are higher or lowerthan normal. Because last summer was coolerthan normal, the actual recorded peak use ofelectricity (130,100 MW) was lower than theweather-adjusted amount used for planningpurposes. PJM adds that its all-time record useof electricity of 144,644 MW occurred in 2006.
May 6, 2009
NERC’s Board of Trustees Approves EightRevised Cyber Security Standards
The North American Electric ReliabilityCorporation (“NERC” or “the Corporation”) hasadvised that its Board of Trustees has approvedeight revised cyber security standards for theNorth American bulk power system. NERC saysthat this approval represents the completion ofphase one of its cyber security standardsrevision work plan, which was launched in July2008. The Corporation adds that work continueson phase two of the revision plan, with versionthree standards already under development.
The announcement states that the revisedstandards were passed by the electric industrywith an 88% approval rating, evidence of theindustry’s strong support for NERC’s standardsdevelopment process and the more stringentstandards. The standards are comprised ofapproximately 40 “good housekeeping”requirements designed to lay a solid foundationof sound security practices that, if properlyimplemented, will develop the capabilitiesneeded to secure critical infrastructure fromcyber security threats. Roughly half of thoserequirements were modified to clarify orstrengthen the standards in this initial, expeditedrevisions phase.
NERC mentions that the current revisions beginto address concerns raised by the FederalEnergy Regulatory Commission (“FERC”) in itsOrder No. 706, in which it conditionally approvedthe standards currently in effect. The revisionsnotably include the removal of the term“reasonable business judgment” from thestandards.
According to the announcement, entities foundin violation of the standards can be fined up to$1 million per day, per violation in the U.S., withother enforcement provisions in placethroughout much of Canada. Audits for
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compliance with 13 requirements in the cybersecurity standards currently in effect will beginon July 1, 2009.
May 4, 2009
California ISO Updates Five-Year StrategicPlan
As part of charting its course for 2009-2013while laying the foundation for renewableresource integration and smart grid technology,the California Independent Electricity SystemOperator (“CAISO” or “California ISO”) hasreleased an update of its Five-Year StrategicPlan titled “Smart Future”, reaffirming thedirection the organization is taking to adapt tostate and national economic forces, solveenergy supply and delivery challenges, as wellas manage workforce change.
CAISO advises that the plan’s objectivespromote excellence and transparency in gridand market operations with strategies to ensureopen and non-discriminatory grid access,enhance customer service and create value forCalifornians. A central tenant of the plan, whichthe ISO Board of Governors approved at itsMarch meeting, is the organization’scommitment to ambitious state, national andglobal objectives of reducing greenhouse gases(“GHG”) by welcoming in a new era of advancedtechnologies, such as the electrification ofautomobiles, renewable energy alternatives andenhanced grid functionality.
General
May 21, 2009
U.S. EIA Posts May 2009 Edition of Its“Short-Term Energy Outlook”
The Energy Information Administration (“EIA”) ofthe U.S. Department of Energy (“DOE”) hasreleased the May 2009 edition of its “Short-TermEnergy Outlook”. The EIA reports that energyprices rose in early May following reportssuggesting that the U.S. economy may havereached a turning point in the current recession,at least in some sectors. It cautions however,that near-term prices in the outlook remainsomewhat below market prices as of its releasedate given that prospects for a global economicturnaround remain highly uncertain. The EIAsays that its forecast is based on a
macroeconomic outlook that assumes the U.S.and global economies begin to stabilize in thecoming months and show signs of recovery latein 2009 and into 2010.
Among the things highlighted by the EIA is thatthe Henry Hub natural gas spot price isprojected to average $4.06 per thousand cubicfeet (“Mcf”) in 2009, down from an average of$9.13 per Mcf in 2008. Buoyed by modesteconomic growth next year, the price isexpected to increase to an average of about$5.21 per Mcf in 2010. The projected steepdecline in industrial output this year is expectedto reduce industrial natural gas consumption by8 percent, resulting in a 1.9-percent decrease intotal annual consumption of natural gas. Naturalgas consumption in the electric power sector,however, is projected to increase by 2.1 percentsince lower natural gas prices are expected toback out some coal consumption in this sector.
The other things noted in the Outlook were thefollowing:
Natural Gas
Consumption: Total natural gas consumption isprojected to decline by 1.9 percent in 2009 andthen increase slightly in 2010. Weak economicconditions leading to significantly lower naturalgas consumption in the industrial sector areexpected to be the main source of the dip in totalconsumption this year. The projected increasein natural gas use in the electric power sectoroffsets some of this decline. Lower relativenatural gas prices compared with coal,particularly in the Southeast, are expected toinduce higher utilization of natural-gas-firedelectric generation capacity in the near-term andlead to a consumption increase of 2.1 percent inthe electric power sector this year. Natural gasconsumption is expected to decline slightly inthe residential and commercial sectors this year.Similar to other fuels across the energy market,the outlook for natural gas consumption in 2010is highly contingent upon the timing and pace ofeconomic recovery. Under current assumptions,consumption growth in the electric power sectorand a slight recovery in the industrial sector areexpected to contribute to a small increase intotal consumption for the year, despite minorconsumption declines in the residential andcommercial sectors due to the expectation of 0.8
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percent fewer heating degree-days than theprevious year.
Production and Imports: Total U.S. marketednatural gas production is expected to decline by1.0 percent in 2009 and by 2.8 percent in 2010.As a result of poor economic conditions andlower natural gas prices, total working naturalgas rigs have declined by 54 percent since lastAugust. The erosion of drilling activity combinedwith production curtailments in response tocurrent and projected low prices and highinventory levels are expected to cause naturalgas production in the lower-48 non-Gulf ofMexico (“GOM”) to decrease by about 1.6percent in 2009. Conversely, marketedproduction from the Federal GOM is expected toincrease by 3.4 percent in 2009 due to the returnof facilities damaged by Hurricanes Gustav andIke as well as the start-up of new productionassociated with offshore oil projects. Despiteexpectations of higher prices next year, thelagged effects of the downturn in drilling thisyear and the natural decline in productivity fromexisting wells are expected to contribute to lowerproduction in both the lower-48 non-GOM andFederal GOM regions in 2010.
Expected weak natural gas demand in theliquefied natural gas (“LNG”)-consumingcountries of Asia and Europe, the startup of newliquefaction capacity, and limited natural gasstorage capacity in countries that typically relyon LNG are expected to increase the availabilityof LNG for the United States. U.S. LNG importsare expected to increase from 350 billion cubicfeet (“Bcf”) in 2008 to about 500 Bcf in 2009 and650 Bcf in 2010. However, there is significantuncertainty associated with the global LNGbalance. U.S. pipeline imports are expected todecline by about 7 percent in 2009 because ofthe impacts of suspended drilling programs anddeclining well productivity in Canada.
Inventories: On May 1, 2009, working naturalgas in storage was 1,918 Bcf. Currentinventories are now 362 Bcf above the 5-yearaverage (2004–2008), and 491 Bcf above thelevel during the corresponding week last year.The natural gas working inventory is projected topeak at about 3,635 Bcf at the end of October2009, exceeding the previous record of 3,565Bcf reported for the end of October 2007. Over
the past 10 years natural gas working inventoryhas typically reached a maximum level duringthe first 2 weeks of November, with the earliestseasonal peak reported the week endingOctober 20, 2006, and the latest peak the weekending November 30, 2001.
Prices: The Henry Hub spot price averaged$3.62 per Mcf in April, $0.46 per Mcf below theaverage spot price in March, as consumptionhas flagged amidst the drop in economic activity.No significant rise in average spot prices isexpected until cooler temperatures increase thedemand for space heating in the fall. While theseasonal boost in natural gas consumption isexpected to add some strength to prices, robuststorage levels are expected to limit anysignificant upward price movement through thewinter. However, as the expected improvementin the economy contributes to demand recoveryin 2010, sustained lower production levels couldlead to higher prices in the latter part of theforecast period. The Henry Hub spot price isexpected to average $4.06 per Mcf in 2009 and$5.21 per Mcf in 2010.
Electricity
Consumption: The drag on industrial retail salesof electricity as a result of the ongoing recessionis expected to decrease total electricityconsumption by 0.8 percent this year.Consumption is projected to return to a morenormal growth rate of 1.5 percent in 2010.
Prices: The increased cost of constructing newgeneration and transmission facilities has led torising residential retail electricity prices despitelower power generation fuel costs. As a result,residential electricity prices are projected toincrease by 4.4 percent in 2009. The lower fuelcosts are expected to be passed through toconsumers later in the year, slowing growth in2010 residential retail prices to 1.9 percent.
Generation: EIA’s preliminary estimates indicatethat power generation by natural-gas-fired plantsincreased by nearly 3 percent in February 2009from the same month last year while coalgeneration fell by about 14 percent. Thischange in the relative generation fuel mix maybe a response to the converging generationcosts for coal and natural gas. A similar patternis expected to continue during the rest of 2009,
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with natural gas generation increasing by 2.9percent and coal generation falling by 2.8percent.
Coal
Consumption: A decline in overall electricitygeneration, combined with projected increasesfrom natural gas, nuclear, and renewablegeneration (hydroelectric and wind) sources, areprojected to lead to a 2.3-percent decline in coalconsumption in the electric power sector. Anexpected increase in total electricity generationof 1.6 percent in 2010 is expected to lead to a1.4-percent increase in electric-power-sectorcoal consumption. Consumption in the coke-plant sector is expected to continue falling overthe forecast period.
Production: Production is expected to fall by 4.9percent in 2009 in response to lower totaldomestic coal consumption combined withexport declines. Production is projected toincrease by 1.0 percent in 2010 as domesticconsumption and exports increase with animproving economy.
Exports: Reductions in global coal demand areexpected to reduce U.S. coal exports by about12 million short tons, a 14-percent decrease, in2009 but an expected increase in global coaldemand is projected to result in a 15-percentincrease in exports in 2010.
Prices: The average delivered coal price to theelectric power sector increased by more than 17percent in 2008, to an average of $2.07 permillion Btu. Although record increases in spotprices (some well over 100 percent) for severaltypes of coal contributed to the increase in thecost of coal, spot market purchases make uponly a small portion of total coal consumed.Instead, a rise in transportation charges was theprimary reason for the cost increase last year.Despite declines in electricity demand and lowerfuel costs, the annual average delivered coalprice, which is primarily dictated by long-termcoal contracts, is projected to increase to $2.11per million Btu in 2009 since current deliveredprices were set when contracts were enteredinto during a period of high prices for all fuels ayear or more ago. The average delivered coalprice is expected to decline to $1.91 per millionBtu in 2010.
