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14052014 Council MINTown of Tillson burg Minutes of Council Meeting Date: Wednesday May 14, 2014 6:00PM Tillsonburg Community Cente Chair: Dave Beres : li jl MINUTES: Meeting for the Committee "Open Council" Review Access: e Public 0 Private ATTENDANCE Mayor Dave Beres Deputy Mayor Mark Renaud Councillor Marty Klein Councillor Brian Stephenson Councillor Mel Getty Councillor Chris Rosehart Staff: David Calder, CAO Donna Wilson, Town Clerk Darrell Eddington, Director of Finance Steve Lund, Director of Operations Rick Cox, Director of Parks & Recreation Services Jeff Bunn, Deputy Clerk ADOPTION OF AGENDA Resolution No.1: Moved By: Councillor Rosehart Seconded By: Councillor Getty THAT the Agenda as prepared for the Special Council Meeting of May 14, 2014, be adopted. MAYOR WELCOME PUBLIC MOMENT OF REFLECTION DISCLOSURE OF PECUNIARY INTEREST OR THE GENERAL NATURE THEREOF No disclosures of pecuniary interest were declared INFORMATION ITEMS 1. Tillsonburg Hydro Inc. Frequently Asked Questions CJ 051414 Page 1 MINUTES: Meeting for the Committee "Open Council" 2. Tillsonburg Hydro Inc. Timeline ldl PRESENTATIONS 3. Opening Remarks ~ Presented By: David Calder, CAO 4. Financial Information lJ) Presented By: Wayne Brett, Finance Regulatory Affairs Officer Wayne Brett provided a review of the financial statements for Tillsonburg Hydro Inc 2009-2014. 5. Tillsonburg Hydro Inc. Board of Directors I:Jl Phillip Esseltine, Chair of Tillson burg Hydro Inc., reviewed actions taken by the Board over the past five years. Other Board members spoke to the various options available to the shareholders of Tillson burg Hydro Inc. John Gilvesy, Board Member of Tillson burg Hydro Inc., reviewed various challenges facing the Board since the initial KPMG report in 2009, to the Board's latest recommendation to the shareholder. Mike Bossy, Board Member of Tillsonburg Hydro Inc., spoke to the financial inefficiencies of Tillsonburg Hydro Inc. Bryce Sibbick, Board Member of Tillsonburg Hydro Inc., noted that Tillsonburg Hydro currently does not have the appropriate staff to manage the company efficiently. DELEGATIONS 6. Delegations (1 0 minutes maximum per speaker) []} Lisa Gilvesy, Chair of the Development Committee, read a resolution from the Development Committee, urging Council to explore all options available for the sale, disposition, merger, and restructuring of Tillsonburg Hydro Inc. Dave Morris spoke in opposition to selling Tillsonburg Hydro Inc. Cam McKnight spoke in opposition to selling Tillsonburg Hydro Inc. Eddy Kunkel spoke in opposition to selling Tillsonburg Hydro Inc. Ron Osborne, shared how Ascent Group Inc. (St. Thomas Energy Inc.) can assist through the sale, mergers and acquisition of Tillson burg Hydro Inc. Shane Curtis, Tillsonburg Chamber of Commerce, urged Council to investigate all options available to Tillsonburg Hydro Inc. Jeff Pettit and Tyler Moore, from ERTH Corporation, spoke to the possibility of forming a possible business relationship between Tillsonburg Hydro Inc. and ERTH Corporation through merger. John Puhr spoke in opposition to selling Tillsonburg Hydro Inc. Page 2 MINUTES: Meeting for the Committee "Open Council" \ Peter Beechey spoke in opposition to selling Tillsonburg Hydro Inc. ! Will Hayhoe, President of Hayhoe Homes, spoke about how the decision made by this Council will ultimately affect investment in Tillsonburg. John Armstrong spoke in opposition to selling Tillsonburg Hydro Inc. Bryan Smith spoke in opposition to selling Tillsonburg Hydro Inc. NOTICE OF MOTION BY-LAWS Resolution No.2: Moved By: Deputy Mayor Renaud Seconded By: Councillor Klein THAT By-Law 3825, to Confirm the Proceedings of the Council Meeting of May 14, 2014, be read for a first and second time and this constitutes the first and second reading thereof. [] Resolution No.3: Moved By: Deputy Mayor Renaud Seconded By: Councillor Klein THAT By-Law 3825, to Confirm the Proceedings of the Council Meeting of May 14, 2014, be given third and final reading and the Mayor and Clerk be and are hereby authorized to sign the same, and place the Corporate Seal thereunto. CJ ADJOURNMENT Moved By: Councillor Klein THAT the meeting be adjourned at 8:27 PM "Carried" Approval Received: (0 of 1) Donna WilsonfTillsonburg (Thursday May 22, 2014 09:17AM) Town of Tillsonburg Page 3 Tillson burg Hydro Inc-Public Meeting-May 14, 2014 Frequently Asked Questions 1. Q. How much is the dividend from THI to the Town? A. The minimum annual dividend as noted In the Memorandum of Understanding and Direction (MOUD) payable to the Town is $150,000. The 5 year average dividend from 2009 to 2013 has been $190,000. 2. Q. What Is the profit that THI makes annually? A. The 5 year average net income after tax from 2008-2012 on a Canadian GAPP basis Is approximately $321,400. The 5 year average net income retained by THI after the payment of dividends is $131,400. 3. Q. How do revenues coming to the Town from THI in the amount of approximately $1,050,000 impact the tax base? A. Revenues coming to the Town from THI helps reduce the amount of taxes needed to be raised from property taxes but the funds provided by THI are raised through the distribution rates paid by hydro customers. 4. Q. What Is a virtual utility? A. It is a virtual utility meaning that there are no employees associated with the utility and that the utility owns the wires and poles and related transformer equipment. The municipality supplies the employees and the rest of the equipment and charges the actual cost back to THI through a Master Service Agreement (MSA). 5. Q. What is THI worth? A. Approximately $13 million but it would be dependent on what a willing buyer would pay. 6. Q. What is the $1,050,000 from THI to the Town for? A. This amount represents labour costs paid to the Town by THI of approximately $775,000, annual rent of $132,260 and an annual management fee of $140,000. 7. Q, lfTHI is currently paying $1,050,000 in labour and other costs to the Town is the THi customer paying for this on the monthly electrical bills? A. Yes 8. Q. What is the impact of merger or sale on staff? A. This would depend on who the buyer or merging partner may be and what the negotiated arrangement might be. In general, the skills and experience possessed by THI employees is high and would expect to be a major focus of any negotiations. 9. Q. How do residential, commercial and industrial rates in Tillsonburg compare to other municipalities? A. Please see Appendix A. 10. Q. What would become of any proceeds from a sale or merger? A. The shareholder, council, would have to determine the use of any proceeds. There has been suggestions made about developing an investment or management policy and putting the proceeds in a Trust of Legacy Fund • 0 0 0 Wasa&a (2m11 $Z82.96 so.-· $495.00 BD.3'Jt. $24617.08 129.S 10D.1" 12,046 Hydro 2000 Cprapaaed 20121 $294.60 !14.DK $728.40 1'18.1" $9.972.36 89.ll6 ga,.w 1,196 Lakeland $316.61 101.1K $641.«1 104.09ti $10,01B.30 II!M!C !J8.2t& 9,4!!1 iianrr-$1105.16 117M' $1186.28 112-M' $9,314.ZZ 8Z.6H 97.ul 4,155 WestCoiSt Hunm $1147.04 110.111& $683Jl4 110,7J' $10,030.68 B9.mt. $263,211&.84 77.2R 96.9J6 22,01)7 Oran11avllle SU9.5Z 1115.2K $639.72 llJ3,7J5 $8.770.68 71.896 ss.a tL256 North Bay $294.9& 94.2.96 $fiotiLiiO 105.256 $1,1Wi.!i0 85.3H 94.9" 29,754 aurllnRtan $306.12 87.7!1(, $&31.32 3.02.45' $9,444.84 83.896 94ml 64,339 Midland $329.52 1115.2H $550.32 89.2W. $9,617.96 85ft "·"" 6,914 Essex S2I5.ZO 94.2K $669.48 ~ $8,691MM 77.1H ma 28,1$ cambii-North Dllmfrlas $27S.OC BB.1w; $444.72 72.1K $12,31B.!I6 1119.1-" $351.266.80 :109.0S !I3.1J5 50,880 Rlclaau St.lJiwr. (prop1111d 2m2) $3110.24 !l!l.8K $1107.!16 985 $9,284.28 823" 92.2K 5,&28 C'entre Wel~qton $289.44 92M6 $567.72 !JUBE, $10,317.00 91.511i 92.0J' 1!1,196 ~erldlan $284.88 !lO.n $57a.72 9aJJJ6 $10,711.40 95.&" $300,!171.04 88.!1" 910K 112,!169 St.TIIornas $290.16 92.611 $581.00 915 $10,3111.14 ~ 91J* 2.154 Milton $912.80 99.8H $598.28 96.796 $11.<M6..80 74.11" $!104,822.40 89.4K 90.2R 29,1.42 ~h $3!0.&0 105.5H $482.110 78.2!16 $9,39UD 8!1.3" $28!1,051.44 ~e.ow; 87 ... 5o,250 Brantford $2.70.00 86.a5 $4SB.12 73..6'16 $13,337.42 100JIH 86.8H 37,654 Oshawa $21132 67.5H $4113.92 80.1" $11,346.54 100.6" $336,712.44 SBJnli 86.n6 ·52.710 IHv*o one Brampton $255.M 81.!H6 $587.40 95.2H $11.1114.14 76M6 $310.1189.68 91.1" 86.1" 134.228 Lllksfnmt $256.82 818 $469.20 76.1" $11.142.!10 98.8" 85.R 9,571 Tillsonbiii'IJ $281.16 8!J,n& $665.64 10'1 •• $11.65&.16 59.m& 115.6J5 &,700 Grtm&by $292.611 !13.4K $60&.72 98.4K $7,(161.76 62.6K 84.8 10,151 Powerstrelun $275.48 87.l!K $622.08 :IOO.!JK $11.524-20 10Z.ZK $151,1!91.5& 44.6K 89.7K 325,54ci welllnd $910.68 9!1.2% $506 • .t10 82.U& $8,346.48 14..DWo $2110,971.68 76.6K B3.DH 21,411 westarlo $272.40 87.11H $4711.114 76.ZK $9,593.70 85.~ ~ it770 CCLLUS 9271.20 86.&K $486.96 19-$9,288.24 82AG 8l.S'J& 15.533 Norl:lltlm Ontar!D Wlrea $34!1.56 2,09.796 $608.40 98.titli $4,2.4832 37M6 82.1lK &,026 Erla '1111111111 (201~) $2t1.24 93.11H $44a.28 71.!IJ6 $5.931.30 S2Mii I $355.501.92. 1D4a IIIIAKo 14,37.! I ICift&ltDn $289.08 92.3Wi $5!10.20 89.:5 $9,088.56 8ll.liK $~82,523.96 53.5K 78.!Hto 26.944 Peterborou&h $254.28 8l.2WI $574.80 9a.2H $10,2711.08 !I1.1K $164,217.48 48.Bi 18.G as au: Ottawa River $273.24 87.2tli $520.92 84.5S $&,!189.82 58.7K 7&.1" 10,4~ TlwnderBIY $237.24 7s.nc $5l&JJB B5.3S $6.11112.26 61.9fi 7.U" 49,508 E.t..K.I2Cl111 $209.40 66.8" $173.52 28.191i $19,7!8.28 121.8Wa 723H u.zos Hearst $2112.44 83JD6 SS98.84 64-B $7,585.32 67-'"G 71.8H 2,734 l!rdeiJrUs ·IWddlallc $285.00 91m& $938.16 !I4.Bi $4,892.5Z 43Mii $5l,040.8D 15.oH 51.0H 7,859 IH¥dro Hawb&Ourv $148.20 47.B $197.00 48.2S $5,79&.18 51A 49.0" 5,496 ·-· $31.!1.28 $616.78. --. -~11.174.45 $940.869.01 /··--. \ ; (_) Tillsonburg Hydro Inc. Timeline July 22, 2009-April, 2014 \ ) _ __.. ) 12-0ct-10 ( ~· 07-Mar-11 21-Jun-11 17-Jul-11 07-.Jul-11 18-0ct-11 21-Nov-11 20-Dec-11 17-Jan-12 21-Feb-12 08-Mar-12 26-Jun-12 Landfill Gas Generation to Produce Energy Marwood Invitation -Presentation on Solar Roof Top RoofTop Solar RFP RoofTop Solar At Application-Town FacUlties Dr.rfl: Investment Polley ERTH Corooration Presentation RoofTop Solar Fit Application-Town Facnltles- Business Plan Review Solar Investment Opportunity Solar Investment OooortunitY Market Valuation Update on Solar Investment Implications of either a Sale or Merger of Local Dlstlbution Company (LDCJ __ --- ( '\._) Presentation: James Nagle, Chief Operatlng Officer, Brantford Hydro Inc. & Brantford Generation Inc. Report: THI-Z011-Q3 RoofTop SOlar FIT Application-Town ofTIDsonburg Report: THI-2011-04 RoofTop Solar At Application -Town Fadlities -Bu Report: FIN THI-2011-Ql Draft Investment Polfcy Presentation: Ooeratlons of ERTH Report: THI-2011-04 RoofTop Solar Rt Application -Town Facilities -Business Plan Presentation: Cephas Panschow, Development COmmissioner Verbal Reoort Report: Market Valuation Report: Update on Solar Investment Report ':J 10 THAT THI pay the annual dividend at this time tD the Town of $150,000 plus the special dividend of $100,000 based on the forecastEd flnandal results of 2011. 11 THAT Report THI-2011-Q3 from the General Manager dated June 15Hl 2011 be received as lnfonnatlon. THAT report THI-201D-o4 from the General Manager dated July 12th, 2011 be received as infonnatlon; AND FURTHER RESOLVID THAT the Board approve that the roof 12 tDp solar project be pursued with the Town on the basis a 50% debenture and 50% cash contribution with THI being the owner of the solar installation, with the exception of the Spedal Events Centre and tD pursue altematlYe roof!Dps that would be suitable. THAT the Board receives Report FIN THI-2011-G1 Draft Investment Policy as infomnatlon; 13 THAT the Board aDDroVe the Investment oolicv. 14 THAT Tlllsonburg Hydro Inc. agree tD purcnase two mtcroFrr solar systems to be installed on the 18 Spruce St and 1 Library Lane municipal properties from the Town ofTIIIsonburg upon completion of the lnstallatlon and connection to the electridt.y grid and at the fair market value for the systems or $164,640 plus net HST· , FURTHER RESOLVE THAT through staff research this not be feasible then the system would be purchased direct by THI and the board wm be notlfled accordingly; AND FURTHER RESOLVE THAT this be subject tD the vendor completing a structural engineering review on the subject roofs oriol"to tne THAT the Board receive the Market Valuation report as lnfomnatlon; 15,16 RITHER THAT a condensed copy be forwarded to Town council foLUSe In Closed_5ession THATTIIIsonburg Hydro Inc. receive Update on SOlar Investment 17 as Information. 18 -------·-··-··-·· ----·--··-·· --·-·---·--------·-------· ·--· ' .. ----·--------- I '----· 19-Nov-13 18-Mar-14 GM Report The Consensus Accord ( --\_/ Hydro One BCP Public Meeting (COUnty of Brant) Report: A Report of ltle Consensus Accord -Taking the High Road -To Improve CUstomer Service In -the EIE!ctrldtv_Distrtbutlon Sector --------·--·····-····"""""""""'"" r"\, 0~/ 29 30 I I I ' } () Tillsonburg Hydro Inc. Timeline July 22, 2009-April, 2014 Appendix Set 1 (No.1-16) ~) \ ) 0 2013 27 Report: THI Disposition Analysis September 17, 2013 28 Impact to Town's Net levy if THI was sold -No employees transferred to new entity 29 County of Brant: Seeking Potential Buyers for Brant County Power Inc. 30 Report: A Report of the Consensus Accord -Taking the High Road -To Improve Customer Service in the Electricity Distribution Sector 31 Report: CAQ-14-04 Disposition Process of Tillsonburg Hydro Inc. Schedule A: Disposition Process Schedule B: Estimated transition Costs 32 Report: CAQ-14-07 Tillsonburg Hydro Inc. Public Information Meeting . ·. ,·_ ....... ·· ... · •••pperidiX·Set2;(No~.33~46) · '·'.·.' ' \ ·'. . , ,.· ........... .... ~ .. ··. -> . :· .·_.,;.· . '.Additional 'Resources : : .. .. ·.·· ..... .··:-.. .. . ' ...... ' ..... ' .. .. . . ' 33 Tillsonburg Hydro Inc. Rnancial Statements December 31, 2009 34 Tillsonburg Hydro Inc. Rnanclal Statements December 31, 2010 35 Tillsonburg Hydro Inc. Rnancial Statements \) December 31, 2011 36 Tillsonburg Hydro Inc. Financial Statements December 31, 2012 37 Tillsonburg Hydro Inc. Financial Statements December 31, 2013 38 Tillsonburg Hydro Inc. Financial Information 39 Tillsonburg Hydro Inc. Cost Increases 40 2014 Tillsonburg Hydro Inc. Labour Allocation 41 KPMG LOCs The landscape and options February 2014 42 EDA The Power to Deliver: Recommendations for the future of electricity distribution in Ontario 43 Renewing Ontario's Electricity Distribution Sector: Putting the Consumer Rrst -The Report of the Ontario Distribution Sector Review Panel 44 OEB "Yearbook" Web link: http://www.ontarioenergyboard.ca/OEB/Industry/Rules+and+Requirements/ Reporting+and+Record+Keeping+Requirements/Yearbook+of+Distrlbutors 45 AMO's Submission to the Ontario Distnbution Sector Panel July 2012 46 BDR Report: Evidence of Paula Zarnett on behalf of Essex Powerlines Corporation, Bluewater Power Distribution Corporation, and Niagara-On- The-Lake Hydro February 26, 2013 \ ) (-) DRAFT FOR DISCUSSION PURPOSES KPMGLLP 199 Bay Street, Suite 3300 Toronto, ON MSL 1B2 Strategic Review of Tillsonburg Hydro Inc. Apri130, 2009 \-j C) I. Introduction A. Background Tillsonburg Hydro Inc. ("THI" or the "Company") is an Ontario corporation that is wholly-owned by the Town of Tillsonburg ("Tillsonburg" or the "Town") and operates as a local distribution company (''LDC") that is regulated by the Ontario Energy Board ("OEB"). The primary focus and responsibility ofTHI is the delivery of electricity to customers and the maintenance of the power grid within Tillsonburg. The Company serves more than 6,600 customers located within a 24 square kilometre service territory. THl is governed by an independent board of directors, and owns all of the electricity lines and pole infrastructure required for the local distribution of electricity. THI operates under a Master Service Agreement with the Town of Tillsonburg, which owns and leases certain utility-related fixed assets (e.g. rolling stock, computers, and office equipment) to THI and supplies all personnel and related administrative services required by the Company. THl's primary goal is to provide its customers with a reliable and cost-effective power supply while maintaining a safe distribution system. The Company also has a mandate to improve the efficiency of the local power grid and to help customers reduce their energy consumption requirements. Working hand-in-hand with the Electricity Distributors Association of Ontario, the Ministry of Energy and the OEB, THl continues to implement programs and grid enhancements to achieve these objectives. B. Terms of Reference The Town of Tillsonburg and the Board of THI have engaged KPMG LLP to undertake an independent Strategic Review of THl. The Strategic Review is intended to provide a comprehensive analysis ofTHI that includes: a) A review offour strategic options available to Till including: Base Case: Maintain and operate the Company on a status quo basis; ii Expansion/Diversification: This option envisions the continuation ofTHI's traditional electricity distribution operations, plus expansion through the pursuit of complementary business opportunities such as LDC acquisitions, retail and/or power generation activities, and other ancillary joint venture opportunities; April30, 2009 Page 1 r) \ ) \,_-) '-) of Chartered Accowttants ("CICA"), and we have not otherwise verified the information we obtained or presented in this report. • KPMG has not and will not exercise any managerial or administrative authority, direction or control over the business affairs of THI. • This report is provided as of the date hereof and KPMG disclaims any wtdertaking or obligation to advise any person of any change in any fact or matter affecting the information provided in this report that may come or be brought to KPMG's attention after the date hereof. Without limiting the foregoing, in the event that there is a material change in any fact or matter affecting the content of this report after the date hereof, KPMG reserves the right to change, modify, or withdraw the report. • This report, together with all attachments, is being provided solely for the exclusive use of THI and/or the Town and may not be used or relied upon by any other party. Neither KPMG, its affiliates, nor its respective partners, directors, officers, employees, counsel or agents will have any liability to THI, the Town or any other parties resulting from the use of this report by them in making any decisions in respect ofTHI. • This report is private and confidential and is not intended for general circulation or publication, nor is to be reproduced or used for any purpose, other than to assist THI and/or the Town with the specific matters discussed herein, without our prior written permission in each specific instance. We will not assume any responsibility or liability for damages or losses incurred by THI or the Town, their respective officers, directors or councillors, or by any other parties as a result of the circulation, publication, reproduction or use of this report contrary to the provisions outlined herein. Any use which a party makes of this report, or any reliance on or decisions to be based on it, are the responsibility of such party. KPMG does not accept any responsibility for damages, if any, suffered by any party as a result of decisions made or actions taken based on the contents of this report. • KPMG International is a Swiss cooperative of which all KPMG firms are members. KPMG International provides no professional services to clients. Each member firm is a separate and independent legal entity and each describes itself as such. KPMG LLP, a limited liability partnership formed pursuant to the laws of Ontario, is the Canadian member firm ofKPMG International. E. Executive Summary THI serves more than 6,600 customers located within its 24 square kilometre service territory. THI's Vision is to deliver professional, cost--effective and environmentally responsible energy services to its stakeholders, that being its customer base within Tillsonburg, and to provide a reasonable economic return to the Town of Tillsonburg as the sole shareholder. One of THI's key values is to "satisfy its customer's energy April30, 2009 Page3 () __ ) The OEB is responsible for the regulation of the Ontario electricity generation, transmission and distribution sectors including regulating the rates charged by utilities operating in Ontario and setting performance obligations. The OEB regulatory process can be a major burden for smaller LDCs. During the past decade, the Ontario LDC sector has been consolidated into approximately 80 LDCs and Provincial policy makers have indicated that they would like to see further consolidation. We have not seen evidence that the Province is changing this position. The Province of Ontario introduced the Green Energy Act (''the Act") in February 2009, designed to promote growth of renewable energy, promotion of conservation as an alternative to expanding generation capacity and the development of a "smart" grid. Details of initiatives under the Green Energy Act will not be known with precision until further regulations are released. The Act is likely to promote further consolidations in that larger utilities will need to have the required critical mass to fulfill its requirements. Our analysis suggests the Base Case I Status Quo Option could be considered a Feasible Option, at least for the near term. Till appears to have a competent management team in place to manage the complexities of its business. THI has shown relatively good cost and service performance in the past, but this performance has started to deteriorate and will be under continued pressure as a result of its small size and lack of critical mass. We have some concerns over the long-nm viability of operating THI on a stand-alone basis. Our analysis of the Expand I Diversify Option suggests THI does not have sufficient financial resources to acquire another local LDC. Accordingly, we have interpreted this option as the pursuit of new business opportunities that are related to the electricity sector, but outside of THI's core distribution business. Our analysis suggests that this is not a Feasible Option for THI to pursue on its own in that the Company will still be hampered by its small relative size and lack of economies of scale in addressing regulatory burdens. Furthennore, THI does not appear to have the financial, technical and management resources necessary to participate in new business opportunities on a stand-alone basis. Given most power generation projects require a significant upfront capital investment as well as specialized technical skills, TID's limited financial resources will make it difficult for it to participate meaningfully in larger projects. It is likely that TID will need to hire specialized technical skills to operate any new ventures. Generating a satisfactory rate of return on any investments that are made will likely be accompanied by significant risk. There is an opportunity for Till to partner with other suppliers in the delivery of certain programs, particularly local conservation initiatives or the development of small-scale renewable power projects. THI's most logical role is to act as a bridge between external suppliers and local consumers. These smaller business opportunities are scalable and may provide some benefit to the local customer base. There is some risk, however, that even this limited role will be a distraction for management while leading to limited returns on investment. April 30, 2009 PageS ) II. Review ofTillsonburg Hydro Inc. A. Mission Statement I Vision In July 2008, representatives of senior management and the Board of Directors of THI participated in a one-day strategic planning workshop to brainstorm on the Strategic Vision of Tin. The moderator of the workshop, Fred J. Galloway ofF. J. Galloway Associates Inc., subsequently drafted a report entitled "The Strategic Plan -Environmental Scan Report" (the "Galloway Report'') dated July 2008. The Galloway Report identified the following Vision for THI -"to deliver professional, cost-effective and environmentally responsible energy services to our stakeholders." The two key stakeholders of TID are its customer base within Tillsonburg and the Town of Tillsonburg as the sole shareholder. The Galloway Report also identified the following Mission Statement for THI -"An energy services company committed to maximizing value to its customers and shareholder." We understand that both the Vision and Mission Statement were intended to be preliminary in nature, and required further discussion and refinement. The Galloway Report also articulated a series of eight values for THI, including seeking to "satisfy customers' energy needs with high quality, cost effective products and service excellence, and to provide the shareholder with a reasonable return on investment relative to its investment in infrastructure and risk." Since THI's customer base is essentially the same constituency as that of the shareholder, namely the residents of the Town of Tillsonburg, it is therefore critical to assess the strategic options under consideration from the perspective of how they advance the "energy and cost of service" interests of the residents of the community. The Galloway Report also identified and commented on the four strategic options for THI that are further discussed within this report. B. Organization 1. Corporate Organization THI was incorporated under the laws of Ontario on October 26, 2000 and its one issued and outstanding common share is owned by the Town of Tillsonburg. The incorporation of THI was undertaken in response to Bill 35 -The Energy Competition Act -which required, amongst other matters, that all Ontario municipalities transfer the assets and operations of their local electricity distribution operations into a legal corporation. A municipal bylaw enacted the transfer of most of the former Tillsonburg PUC electricity-related assets and operations into TIII on October 26, 2000. April 30, 2009 Page? \-} (~) \, __ ) \ ,_) Stakeholder interviews have suggested that the current organizational structure provides certain financial and operating benefits to the Town and THI. Specifically, the current personnel structure allows the Town to employ specialized personnel who can provide their services to several Town-managed operations. In addition, the Town charges a 5% mark-up above the cost of all services delivered to THI, thereby creating an annual $80,000 to $120,000 revenue stream that the Town uses to defray municipal property taxes. It should be noted that some stakeholders expressed concern over the potential for conflicts of interest to arise when Town employees represent multiple organizations. Some other challenges associated with the existing personnel structure include: • The workloads of financial and administrative staff at the Town appear to be strained by the specialized demands placed on them by THI, in addition to the demands of the Town and the PUC. This partly reflects the specialized nature of many of the tasks associated with running an LDC, and the need for staff to keep abreast of developments in the electricity sector and at the OEB. • Operation by the Town means that some THI staff have multiple responsibilities. This can result in confusion over work priorities and in balancing objectives across three organizations -1HI, the Town and the PUC. Conflicts of interest can arise. Some stakeholders suggested that by working for a single employer, staff would be more focussed and accountable to that organization. • The Town has tried to hire a Regulatory Affairs Manager to deal with OEB rate applications and other regulatory matters. One difficulty has been that salaries for LDC and regulatory specialist personnel are higher than can easily be accommodated within the municipal pay scale. We also note that there is a general shortage of capable regulatory personnel within the LDC sector, which generally accounts for the higher salaries. We understand from management that THI has had a mixed experience relying on other utilities and consultants for rate applications and other specialty assistance in the past. Due to resource constraints, this reliance on external experts is unlikely to change in the near term. The Town provides services to THI under a Master Services Agreement, and charges fees that are intended to recover its costs for both personnel, services and capital assets. The fees charged to THI include a 5% premium above direct operating cost as a management fee for the Town. The amount of annual cost recoveries is ftxed early in a calendar year for operating expenses (e.g. personnel, materials, rent, asset recovery costs), whereas capital expenditures charged to THI are flexible in amount and are based on the actual amount of time and related overhead costs incurred by the Town. It should be noted that charge-backs to THI are governed by the Affiliate Relationship Code, which generally requires that cost recoveries be limited to Fair Market Value. We have some concerns that the Town has not been recovering all of its costs in charges to THI. For example, we understand that the Town does not charge THI for depreciation and financing costs related to the use of certain capital assets such as office furniture, computers and related IT infrastructure. April 30, 2009 Page9 ) -n _) It should be noted that DDM Plastics, the Company's largest customer, will idle its 500,000 square foot production facility in Tillsonburg in May 2009 and intends to be closed for the indefmite future. It is hoped that DDM Plastics, a manufacturer of injected molded parts for the North American automotive industry, will recommence its operations once there is an improvement in the economy. The other large industrial customers ofTHI, particularly those in the automotive parts manufacturing industry, have similarly experienced a significant decline in their sales activity and have reduced their employment levels and their levels of power consumption. The decline in power consumption impacts the distribution revenues of Till, which are established based on the projected level of power consumption in a particular year. While the non~energy operating costs of THI are largely fixed, the revenues are dependent upon the amount of power constlmed in a given year. The Company purchases all of its power from Hydro One, which is delivered through transformer stations located just north of the Town. Due to the recent industrial plant closures and downsizings in recent months, the total amount of power consumption has declined by 15% during the first three months of 2009 compared to the same three month period in 2008. C. Operational Performance Based on stakeholder interviews, we understand that the physical distribution plant of THI is in a good state of repair. Since the late 1990's, THI has implemented a number of safety, maintenance and retrofit initiatives to ensure that all customers have a reliable and safe electricity system within the Town. In particular, the Town has gradually been converting its physical plant from a 4.16 kV system to a 27.6 kV system. THI management estimates that this conversion process is approximately 60% completed, with a full system~wide conversion to be completed within an additional 5 years. The conversion to a 27.6 kV system reduces the level of line losses and allows for the decommissioning of older substations. The Company owns and maintains approximately 151 kilometres of wire, consisting of 102 kilometres of overhead wire and 49 kilometres of underground connections. Till owns five substation properties throughout the Town. Three substation sites are currently in use, one substation site has been decommissioned and is currently used as a pole yard and storage area for a spare transformer that is used for parts, and a fifth substation site has been decommissioned and is vacant. The latter substation site could be liquidated if no longer required for 1HI purposes. THI does not own any other real properties, but leases its space requirements from the Town at two primary sites pursuant to the MSA as follows: • 200 Broadway Street, Second Floor -Town Hall facility which houses senior administrative personnel of THl (most of whom also allocate a portion of their time to Town and PUC matters). April 30, 2009 Page 11 () ) Exhibit 11-1 Comparative Analysis of Distribution Rates ~ ---------' -._--------- ------- -----. ----- ------- --- - --c-_:;;-~ -~-_;:--~~--~~---I -'.______ • -~ 1,000.0 kWh Brant County 11.27 2.25 405.24 0.7100 490.44 94.8% 1.0495 Brantrord 12.11 1.34 306.12 1.1900 448.92 86.8% 1.0420 Erie Thames 15.22 1.44 355.44 0.9200 466.84 90.1% 1.0427 Ha!di mand County 11.85 3.13 517.80 0.9000 625.80 121.0% 1.0585 Norfolk County 22.00 1.99 502.80 0.9800 620.40 120.0011. 1.0580 St. Thomes 12.02 1.57 332.64 1.0100 453.84 87.8% 1.0339 Woodl!lock 12.19 1 .92 376.68 0.9800 494.28 95.6% 1.0440 Simple AWTII!Ie 402.54 517.14 Note 1: DistriJutlon rates effective May 1, 2009 as approved by tile OEB In recent rate decisions. Note 2: Distrilutlon rates requested by Tillson burg Hydro in i1s most recent rate application before the OEB. If the rate application of THI is approved by the OEB, the annual distribution costs (including volwnetric transmission costs from Hydro One) of a residential customer of Till who purchases 1,000 kWh of power per month will be slightly higher than those of most other local LDCs, except for residential customers who are serviced by Haldimand County Hydro and Notfolk Power. Line loss is a measure of the percentage of power that is lost by an LDC's transmission grid. It is calculated as the difference between the amount of electricity that is purchased from Ontario Hydro and the amount of electricity sold to customers; divided by the amount of electricity sold to customers. TID has a line loss ratio that is comparable to other urban-based LDCs and better than that of LDCs that have a mix of urban and rural customers. D. Financial Position & Performance 1. Balance Sheet Position A summary of the balance sheet position of Till for the five years ended December 31, 2004 to 2008 is presented in the table below: April30, 2009 Page 13 1.0458 _) 6.00% on debt (pre-tax) and 8.40% on equity. Many, but not all, other Ontario LDCs have long-term debt obligations ranging from 40% to 60% of their total capital structure, with much of it structured as promissory notes payable to the municipal shareholder. This structure allows for tax-free interest payments equal to 6.00% (or greater) of the promissory note balance to flow to the municipal shareholder, whereas THI's return on the deemed debt component is generally limited to a range between 4.20% and 5.00% on an after-tax basis. While TID's ability to recapitalize its capital structure to include promissory notes payable to the Town is likely prohibited by the Municipal Act of Ontario, the Company could recapitalize its balance sheet by taking on traditional bank debt and using the cash borrowings to fund new investments or make a dividend payment to the Town. • The fixed assets of THI consist of distribution plant assets only, and exclude vehicles, IT systems, office equipment and similar moveable assets. These latter assets are owned by the Town and, accordingly, are not included in THI's rate base for rate application purposes. • THI has approximately $2.0 million of cash on hand at December 31, 2008. We understand that a considerable portion of this cash will be re-invested in the installation of smart meters ($1.0 million) and other capital projects in 2009 and 2010, and therefore is not necessarily surplus to TID's normal business needs. We also understand that the Town has budgeted a $100,000 dividend payment to the Town in 2009. In summary, TID has a solid balance sheet position as at December 31, 2008 that includes no long-term indebtedness and adequate cash reserves to fund immediate capital expenditure needs. 2. Income Statements Over the past five years the Company has generated only a modest level of profitability and a modest rate of return on investment A five year summary of the historical operating performance of THI for calendar years 2004 to 2008, as well as the budgeted operating performance for 2009, is outlined in the following table: April 30, 2009 Page 15 ' /) \_. • the lack of long-tenn debt in the capital structure of THI results in a reduction in the average rate of return on equity (i.e. 60% of total equity is permitted to generate a deemed rate of return equal to the after-tax cost of interest expense). The 2009 budget reflects a 30% increase in distribution revenues compared to calendar 2008 distribution revenues. This significant revenue increase is required in order for 1HI to recover its increased operating costs and to generate an after-tax profit of $532,000, which would imply a rate of return of approximately 6.13% on the average net book value of shareholder's equity. We understand that THI, through its rate application before the OEB, is seeking to realize the maximum allowable rate of return on its deemed capital structure. We Wlderstand the 2009 budget reflects the reduced power consumption levels of large industrial customers such as DDM Plastics, as well as the implementation of new distribution rates effective on or about May 1, 2009. It should be noted that the OEB rate application process is currently in progress, and that the outcome of this application is uncertain. C1Ulently, there are a number of challenges in assessing the future financial prospects of 1HI and, as a consequence, in assessing the fair market value of the Company. These challenges are as follows: • The Company is currently in the midst of a rate application, and the outcome of this application is uncertain. • 1HI's customer base has been buffeted by the recent economic downturn. The impact of the economic downturn is difficult to accurately project Management of THI is hopeful that the OEB will approve its current rate application, notwithstanding the significant requested increase in distribution revenues. 3. Rate Application Process We understand that, in THI's current amended rate application before the OEB, the Company has requested a significant increase in distribution rates to accommodate the large increases in projected OM&A expenses as well as the desire to generate after-tax profits consistent with OEB permitted rates of return. The size of the increase may pose challenges in the rate setting process. By their nature, requests for large rate increases draw more attention from OEB staff and intervenors. Key challenges in gaining approval for THI's rate application may be as follows: • The Town provides services to THI through a Master Services Agreement, and the pricing of these services will need to meet tests associated with the OEB 's Affiliate Relationship Code ("ARC"). • A large part of the rate increase is attributable to the overhaul of the Town's Customer Information System ("CIS"). The OEB may require additional evidence that this was the most cost-effective option for meeting new billing requirements associated with smart meters and timeMof~use pricing. • A significant portion of the increase in distribution rates is required to fund, over a number of years, certain regulatory costs such as the rate application costs April 30, 2009 Page 17 \-I () \ __ ) ) Exhibit 11-4 THI's Relative Size Ranking (#of Customers) LDC8 Ranked By ClldOmerBaee 300,000 ----..,.,.----~---...,....--...,....----,--~---:-:-:---:-~~ 250,000 200,000 I! " I a 150,000 '15 li .. E " z 100,000 !lO,OOO However, compared to other LDCs in the immediate area, THI is the smallest Exhibit 11-2 summarizes some key statistics for local LDCs. The financial data for 2007 has been taken from the OEB's 2007 Yearbook for Electricity Distributors. The exhibit below provides some additional benchmarking measures of 1HI against its local peers: April 30, 2009 Page 19 ) \ __ ~ ) increase in 2009 OM&A expense of about 30% compared to 2007 figures. This will significantly change its relative cost position. April 30, 2009 Page 21 J return on equity and a 6.00% pre-tax return on debt (in the case of THI). The capital structure for rate setting purposes is typically deemed to be 60% long- term debt and 40% equity. • Distribution rates in the three subsequent years are determined by indexing rates in the Base Year. Rates are indexed through an automatic adjustment mechanism that takes into account general price inflation and expected productivity improvements. • Distribution rates in the fourth year will again be reset based on expected operating costs in that year, as well as a return on invested capital. Distribution rates are therefore periodically reset to cover actual costs. Between rebasing years, however, the shareholders of an LDC are at risk if costs increase faster than provided for in the indexing mechanism. LDCs also have an incentive to reduce costs, since such savings will result in increased earnings during the years between rebasing. The OEB reserves the right to disallow certain costs during the rebasing process. This means that the OEB will not approve distribution rates to recover those costs from consumers if it feels that they are "imprudent'' or do not meet tests with respect to reasonableness. The OEB, for example, may disallow costs paid to a third party or an affiliate if it feels that they are above prevailing market prices. The OEB also regulates and monitors various other aspects of LDC operations -the accounting chart of accounts, conservation demand management requirements, operational metrics, customer deposit policies, etc. 2. The Affiliate Relationship Code The OEB's Affiliate Relationship Code ("ARC") sets parameters on the prices that can be charged to an LDC by affiliated entities. In particular, the ARC requires LDCs to prove that they will not pay any more than fair market value for any services provided to them by an affiliate. This measure is designed to protect electricity consumers. Oftentimes, a ''valid" tendering process can be used to demonstrate fair market value. The provisions of the ARC have implications for services provided to THI by the Town ofTillsonburg. Specifically, the cost recovery pricing mechanism or MSA for personnel, services, rent and use of capital assets has been and will continue to be subject to ongoing regulatory scrutiny. 3. Service Quality Standards The OEB provides standards with respect to the quality of service provided by an LDC. For example, it sets performance standards such as the telephone accessibility of customer service staff and it monitors power outages and other indicators of system reliability. These standards are consistent across Ontario and are designed to ensure that customers receive appropriate service on a timely basis. April 30, 2009 Page 23 2006 Electricity Distribution Rate process. It noted that differences could inhibit the LDC consolidation process. Relative to the early part of this decade, however, the pace of consolidation has slowed considerably and some of the most notable mergers have been between larger utilities (e.g. the recent PowerStream-Barrie Hydro merger). The current Transfer Tax exemption has not been successful to date in inducing significant additional merger activity. This heightens the probability that the Transfer Tax exemption will be re--introduced at some point in the future, in the event that it is not extended beyond the current October 16, 2009 deadline. C. The Green Energy Act The Province of Ontario introduced the Green Energy Act (''the Act") in February 2009. The Act is a major initiative that is designed to promote: • The growth of renewable energy in the Province, including wind, biomass and solar options. • Promotion of conservation as an alternative to expanding generation capacity. • Development of a "smart" grid, which envisages increased use of automation and communication technologies to facilitate real-time management of electricity load and integration oflocal energy sources. To enable these objectives, the Act provides the Minister of Energy with sweeping powers. The Minister can issue directives to government agencies, including the OEB and the Ontario Power Authority. The government has also limited the ability of municipalities to restrict renewable power projects through the use of local land use and zoning bylaws. To support the expansion of renewable power projects, the Green Energy Act provides for the implementation of "standard offer'' feed-in tariffs that will be provided to developers of small renewable power projects. These tariffs will provide price certainty to developers of small power projects, and will eliminate the costs and timing challenges of participating in the competitive procurement processes that have been used in the past. Feed-in tariffs should stimulate additional development of renewable power projects throughout the Province. Under the Act, distribution utilities will be given the power to directly own and operate small (under 10 MW) renewable power facilities or combined heat and power facilities. Up to now, LDCs have not been permitted to own such facilities directly, because of the separation of competitive and monopoly services that was imposed during the original industry restructuring process. The Act also gives municipalities the right to own such facilities directly, provided that they do not exceed 10 MW or another limit that may be set by regulation. As a benchmark comparator, 6 standard wind turbine units would generate the equivalent of approximately 9 MW of power. Details of many of the initiatives under the Green Energy Act will not be known with precision until further regulations are released. The Green Energy Act clearly favours small local sources of power generation as an alternative to large centralized April 30, 2009 Page 25 ·~_) IV. Review of Strategic Options A. Overview In this section, we discuss the four strategic options available to nn and the pros and cons associated with each option. As a general rule, we have tested each of the four strategic options against the criteria as to how they improve THI's ability to deliver on its mission statement, vision and core values as outlined in Section II of this report. In assessing the four strategic options, it is important to consider a number of key facts in respect of THI and the Ontario local electricity distribution industry that provide some context: • the Province continues to pursue further consolidation of Ontario LDCs; • the Company operates in a complex regulatory environment that continues to increase operating costs; • THI is a small LDC relative to other industry participants, with only 6,600 customers; • all management and employees are subcontracted from the Town pursuant to a MSA that offers both benefits and drawbacks; • the Company is awaiting an OEB decision on a rate application that seeks a 30% increase in total distnbution revenues; • certain manufacturing customers in Tillsonburg have reduced their energy consumption levels (and employment levels) in response to a weakened economy; • the Company's management team appears to be competent and capable of dealing with most regulatory matters; • a number of TRIM related employees are close to retirement age; • the Company appears to have limited management capacity to take on significant new projects; • the Company has no long-term debt and is fmancially stable to finance new projects such as the installation of smart meters; • a Transfer Tax exemption exists in respect of M&A transactions in the LDC industry that are substantially completed by October 16, 2009; • the Green Energy Act has recently been released and promotes investment in green energy power generation projects, amongst other business opportunities. In conclusion, the Ontario LDC sector continues to be challenged by rapid change and increased complexity in the industry. April 30, 2009 Page 27 () _) utility. KPMG is aware of a much larger LDC (with more than 10 times the number of customers) that budgeted a similar amount for its own recent rate application. On a per customer basis, the cost to this utility of submitting a rate application would thus be less than one-tenth of that incurred by THI. This highlights the very significant economies of scale associated with regulatory processes. However, it should be noted that: • TID's current rate application will have the 2009 year representing the Base Year for the IRM process (see Section III for details as to the rate-setting process). TID will not be required to submit a new rate application until2013. • The Town faces some financial risk with respect to the performance of TID over the period 2010 through 2012; in the event operating costs are greater than the approved rates, or there is a significant revenue shortfall, it will be difficult for THI to adjust those rates. • To the extent that costs can be built into distribution rates in the rebasing process, additional costs incurred by THI as a stand-alone utility should be recoverable from consumers in the longer-run. THI management indicated that the OEB has already asked for justification of the fees charged under the Management Services Agreement. In the past, THI has been able to avoid further investigation of these transfer prices by the OEB because its operating costs have been relatively low. However, this may become more of an issue in the future if the Town tries to significantly increase its level of cost recovery. Part of this increase relates to recovery of costs for a new billing system. The OEB may ask for evidence that such costs are no more than would be charged by a third- party service provider. In the future, Till will be faced with additional regulatory charges (e.g. IFRS conversion costs, smart meter integration costs) that will need to be allocated to its small customer base. These costs will further impact the sustainability of Till on a stand-alone basis. We understand that THI's current rate application, as amended on April14, 2009, is before the OEB and has undergone initial hearings with management and intervenors. Additional queries from the OEB are being answered in written format for submission back to the OEB in May 2009. Management of Till expects an OEB rate decision in June or July 2009; however, the outcome of the OEB's fmal decision in unknown. We also understand that any distribution rate increase will be implemented as soon as possible (likely June 1, 2009) and that the residents ofTillsonburg have been notified ofthe pending increase in local newspaper coverage in January 2009. It should be noted that THI's distribution rates represent only about 30% of the total electricity bill, so a 27.0% increase in distribution rates results in only a 9.0% increase in the total electricity bill. A summary of the advantages and disadvantages of the Status Quo I Base Case option is presented below: April 30, 2009 Page 29 ,\., I ._) looking at sharing setvices with other utilities and outsourcing certain support services where appropriate. In the event that the Status Quo is not sustainable in the long-run, there are strategic issues associated with whether an alternative strategic option such as a sale or merger is relatively more attractive now or at some time in the future. 2. Next Steps In the event the Town wishes to pursue the Status Quo option for THI, we suggest that it consider the following changes: • As shareholder, the Town should formally document its expectations with respect to the financial performance, dividend income, and business scope of 1HI. This can be provided through a "Shareholder's Declaration" or other similar document. This will provide Till's Board and management with a clear direction with respect to the utility. • Management should seek opportunities with other LDCs to share services in specialized areas such as preparing rate applications and other regulatory matters. Cost sharing initiatives should enable, to some extent, the ability to allocate operating costs over a larger customer base. Some co-operative efforts already exist amongst smaller LDCs in Ontario. • Management should actively look for opportunities to outsource support functions, where this can improve its overall cost and service performance. • The Town could consider selling a minority interest in Till in order to obtain specialized support and assistance from a larger and more experienced equity partner. Further discussion of this option is outlined under the Divestiture option. C. Expand I Diversify Option In our analysis of the expand I diversify option, we have ruled out the possibility of THI acquiring another LDC. There are no electricity utilities in the vicinity of Tillsonburg that are small enough to be acquired by THI without significant financial strain. Since Tillsonburg does not have sufficient financial resources to acquire another local LDC and expand its traditional electricity distribution operations, we have interpreted the expand and diversify option as the pursuit of new business opportunities that are related to the electricity sector, such as: • electricity generation (through wind power, photo-voltaic or solar power, hydro- electricity projects, co-generation projects) • retailing of energy • the provision of conservation and demand management programs • other business opportunities April 30, 2009 Page 31 (~} __ ) Exhibit IV-2 Summary of Expand I Diversify Option Advantages & Challenges Competitive Advantages Challenges • The Town is located near a major • transmission line, meaning that new generation projects will have relatively low costs of connection to The opportunities identified to date are all at the conceptual stage, formal business plans have not yet been developed. Additional planning to assess and quantify the potential new lines of business will be required and will take additional resources with an uncertain outcome. For example, the most recent Otter Valley hydro- electric power study was completed in the 1970's. the Ontario electricity grid. • There are large plots of open land available in the Tillsonburg area, some of which are owned by the Town. These plots could be used to generate solar power. • There is a river system nearby that offers the potential to develop run-of- the-river hydro-electric power that is environmentally friendly. • Wind resources in the region are relatively favourable for wind farms. • THI has the ability to borrow funds from a traditional lender in order to fmance any power generation projects that are pursued. These borrowings could range from $3 million to $5 million based on the Company's balance sheet position. April 30, 2009 • THI does not have in-house expertise in the field of renewable power generation and thus will either have to recruit staff or use external consultants to undertake the planning work noted in the first bullet above. Then, if business opportunities appear favourable, THI may have to hire additional staff to pursue them. This casts some doubt on Till's ability to be competitive in these new ventures relative to existing industry players. • Most energy-generation projects are capital intensive in nature. THI has limited capital resources. Due to its high debt load and low tolerance for financial risk, it is unlikely that the Town will provide funds for any significant green energy projects pursued by THI. • Most power projects are unlikely to provide an immediate cash return. • Due to limitations in transmission grid capacity in south-western Ontario, the OPA has recently imposed a moratorium on new connections in the region under the Renewable Energy Standard Offer Program (''RESOP"). Page 33 ) -0 \._) ._) 4. Issues Associated with Specific Businesses In this section, we comment on issues associated with particular lines of business. We note that, in the initial period of market restructuring, many distribution utilities set up competitive affiliates to pursue competitive lines of business outside of the electricity distribution business. To date, with the exception of some fibre-optic telecom businesses, the success rates and economic returns from these ventures have been low. Further, THI is a relatively small utility and will have greater difficulty in reaching economies of scale, in leveraging relationships with its existing customers, and building in-house expertise in the new business areas. Outlined below is an assessment of four potential lines of business: • Billing Services • Retail Energy • Conservation and Demand Management • Other Business Opportunities Billing Services Distribution utilities have historically been reluctant to rely on other utilities for their billing services. Accordingly, LDCs in Ontario have had limited success in marketing billing services to other utilities. We are familiar, for example, with one relatively large utility that made a major effort to market its billing services to smaller LDCs in the early part of this decade, but which later withdrew its marketing efforts in the face of very limited business growth. We understand that the Town currently provides billing and customer service to THI and water and waste-water billing services to customers of South Oxford County. The Town has already invested considerable funds in a new Harris billing system that enables it to provide these billing services. To date, there has been limited success in finding additional customers for these billing services. Retail Energy Retailers provide electricity consumers with fixed price contracts for power for periods of up to five years. This provides consumers with much more certainty regarding their future electricity costs than prices set by the Ontario Power Authority under its Regulated Price Plan ("RPP"), whereby prices are reset every six months to capture changes in current market prices. While prices offered by retailers are generally fixed over a contract term, they also tend to be much higher than those available under the RPP. Existing electricity retailers are very large players that can mount large advertising campaigns. They typically rely on highly-motivated direct sales staff who are compensated by commission. They also need sophisticated risk management processes to hedge their fixed price contracts with appropriate sources of supply. April 30, 2009 Page 35 ) -r) \ .· \ .. _) _) investment in a small-scale energy efficiency program that offers benefits to the customer base and a return on investment to the Company. We caution that before venturing into such expansionary projects, Till should ensure that any proposed product lines are technologically advanced and realistically offer economic benefits to the customer, that the Company has the requisite technical skills to enter into the business, and that sufficient demand exists to support a business case. The economic viability and returns of any such ventures should also be carefully analysed and documented in a properly developed business plan. A summary of the advantages and disadvantages of the Expand I Diversify option is presented below: April30,2009 Page 37 (} \ __ ) _) typically interested in the safe, efficient and cost-effective delivery of electricity. Expansion into new businesses may provide only limited benefits to customers, beyond the possibility that operating costs in the LDC may be reduced. The Town and THI should identify and codify their policy objectives (e.g. target rates of return) when pursuing competitive business opportunities outside of the traditional LDC business. 5. Conclusions On balance, we do not consider the expand I diversification option to be a Feasible Option for THI to pursue on its own. This option does not address the key issue facing THI, which is its small relative size and, accordingly, a lack of economies of scale in addressing regulatory burdens and investment in billing systems etc. Furthennore, most power generation projects require a significant upfront capital investment as well as specialized technical skills. THI has limited financial resources to participate meaningfully in larger projects, and may have to hire specialized technical skills to operate these ventures. Significant risk may also exist in terms of generating a satisfactory rate of return on any investments that are made. Further details of the Green Energy Act may reduce the level of financial risk. There is an opportunity for THI to partner with other suppliers in the delivery of certain programs, particularly local conservation initiatives or the development of small-scale renewable power projects. THI's most logical role is to act as a bridge between external suppliers and local consumers. These smaller business opportunities are scalable and may provide some benefit to the local customer base. There is some risk, however, that even this limited role will be a distraction for management while leading to limited returns on investment. D. Merger Option Under this option, Till would seek another company, likely another Ontario LDC, with which it could merge its operations. The merger process would result in the Town of Tillsonburg owning a percentage of the common shares of a larger LDC (''MergeCo"), and possibly receiving some cash as well. The key advantage of a merger is the ability to achieve cost synergies by sharing certain operating costs, capital expenditures, mte filing application costs etc. and by spreading these costs over a larger customer base. The biggest disadvantage is the loss of some control over local electricity distribution opemtions within Tillsonburg. In order to maximize operational synergies, it is better for two merger candidates to be located close to one another geographically. Furthermore, in order to have a meaningful ownership interest (i.e. 10% or greater) in the post-merger entity, the merger partners should be of somewhat similar size. For THI, the logical candidates for a merger would include the following proximate LDCs: • Brantford Power I Brant County Power (currently in merger discussions) • Erie Thames Powerlines April 30, 2009 Page 39 ) -n ' __ ... _) • the short and long-term impact on future LDC distribution rates (vs. stand-alone LDC) • the impact on current Town staffing levels I shared employees • the impact on the Town's financial returns from MergeCo (via dividends etc.) • the impact on local economic development initiatives • the long-term objective of investment in MergeCo (e.g. sell in another 5 or 10 years, further mergers that dilute ownership percentage etc.) • the views and opinions of Town residents The most recent two-year Transfer Tax exemption period that ended in October 2008 resulted in a few LDC mergers. The largest merger was the merger of PowerStream (Vaughan, Markham, Richmond Hill) and Barrie Hydro. Another proposed merger between Horizon Utilities (Hamilton/St. Catharines) with Guelph Hydro was aborted by the Town of Guelph in the late stages. In February 2009, Brantford Hydro and Brant County Hydro announced that they were exploring a merger of their operations. Other mergers may also be under review, but have not yet been publicly disclosed. A summary of the advantages and disadvantages of the merger option are outlined in the table below: April 30, 2009 Page41 _) Some key transitional issues that will need to be addressed are as follows (these could be pros or cons, depending on the merger partner selected and the terms of the deal that is negotiated): • The impact of a merger on the Town's current staff complement and common operations (e.g. water and wastewater billings, fleet maintenance, space utilization). • The ability to include/exclude certain Town-owned assets used by THI (billing system, vehicles, rental water heaters, sentinel lights, fibre assets) in the merger transaction. This would impact on the total value received for THI in a merger transaction. • The extent of an ongoing local service presence in Tillsonburg. It is likely that only an ongoing field service presence (e.g. linemen, maintenance personnel) would remain in Tillsonburg; however, the extent of a long-term presence of customer service and management personnel would need to be negotiated. The Town will need to protect its interests as a minority shareholder in MergeCo through an appropriate shareholder's agreement. 1. Conclusions Our view is that the merger option is a Feasible Option. However, this option should only be considered pursuant to a long-term vision or strategy for THI as it may be difficult to extract the Town from such an arrangement once it is entered into. The fact that the Town of Tillson burg would likely be a minority shareholder in any merger transaction significantly reduces the attractiveness of this option. The Town would lose direct control over decisions impacting on local electricity distribution. Furthermore, it is likely that the number of LDC employees working and residing in Tillsonburg, over the longer term, would be reduced to direct field service and maintenance personnel only. Conversely, the merger option does allow THI to better address its objective of sustainability by spreading OEB regulatory and other operational costs over a greater number of customers. This should result in lower distribution rates for customers over the longer-term, which is an objective of the THI. In theory, the level of service and reliability of electricity distribution within Tillsonburg should not decline under the merger option as the OEB sets various operational compliance levels that must be met by all LDCs. This is another key objective ofTHI. The Town's long-term objective of holding a minority equity position in MergeCo should also be considered carefully before entering into a merger transaction. The Town should establish the ultimate timing and exit strategy, if any, for its investment in shares of MergeCo prior to entering into a merger. Finally, it is imperative that the Town find a compatible merger partner with similar corporate values and visions. April 30, 2009 Page 43 \_) ) The presence of the OEB can provide the Town with some comfort that a purchaser of THI will not be allowed to significantly reduce service quality. Nevertheless, under a divestiture scenario, the Town would not have the same direct control of service quality and performance that it does now. Intervention by the OEB in the event that service standards slip under a new owner is unlikely to be immediate, and small decreases in quality may need to be tolerated without inducing a response. In order to maximize operational synergies, it is better for the purchaser of an LDC to be located close to Till geographically. For Till, the logical purchasers would include the following proximate LDCs: • Brantford Power I Brant County Power (currently in merger discussions) • Erie Thames Powerlines • St Thomas Energy • Woodstock Hydro Services • Norfolk Power Distribution • Haldimand County Hydro • Hydro One (which services the rural areas around Tiltsonburg) Other potentially acquisitive LDCs with cash resources may include Cambridge and North Dumfries Energy, Horizon Utilities and London Hydro. We have not investigated the prospects, financial constraints or merits of a purchase of THI by any of the specific candidates listed above. Such an analysis is beyond the scope of this assignment The process of undertaking a divestiture would include the following key steps, amongst others: • securing shareholder I Town of Tillsonburg approval to pursue a divestiture; • seeking out potential purchasers (via a formal or informal process); • negotiation of key business terms with prospective purchasers. Among the key issues to be negotiated are the purchase price for shares, the continuation of a local service centre I customer service presence in Tillsonburg, the harmonization of distribution rates, the transition of current THI-related employees and management, the transfer of other Town-owned hydro assets (e.g. fleet, billing systems), the allocation of transaction-related costs, ongoing purchaser support of local economic development initiatives etc.; • determination of the impact on local distribution rates, a review of potential synergies and dis-synergies, a review of the impact on the Town's existing operations I employees; • drafting of various legal documentation (sale agreements etc.); • securing fmal shareholder I Town of Tillsonburg approval of the divestiture. Public meetings in Tillsonburg would likely be held to obtain public input prior to Town Council's decision. The Board of Directors and the municipal April30, 2009 Page 45 _) Due to involvement with other LDCs, a utility partner would be in a much better position than the Town to provide support with respect to: • Preparation of rate applications and other regulatozy filings. • Support in developing conservation and demand management programs. • Other services specifically related to utility operations. A disadvantage of this option is that it may constrain the Town's ability to divest of THI in the future. The minority partner may require a right of first refusal in the event that the remainder of the Town's equity interest is put up for sale in the future. The minority shareholder may also require some assurances with respect to target returns, dividend payments, guaranteed exit prices etc. in order to protect its financial interests. (This may not be a significant disadvantage, since it may also help to protect the Town's ownership interest.) April 30, 2009 Page47 \ ....... )~ () _) • Loss of the 5% management fee received from Town-supplied personnel and services pursuant to theMSA. Some key transitional issues that will need to be addressed under the divestiture option are as follows: The impact of a sale on the Town's current staff complement and common operations (e.g. water and wastewater billings, fleet maintenance, space utilization). The ability to include/exclude certain Town-owned assets used by Till (billing system, vehicles, rental water heaters, sentinel lights, fibre assets) in the sale transaction. This would impact on the total proceeds received by the Town. The extent of an ongoing local service presence in Tillsonburg. It is likely that only an ongoing field service presence (e.g. linemen, maintenance personnel) would remain in Tillsonburg; however, the extent of a long-term presence of customer service and management personnel would need to be negotiated. 3. Estimated Fair Market Value of THI The fair market value of an LDC is driven by a number of factors. Among the more important factors are the dollar value of an LDC's rate base, the OEB·approved rates of return on debt and equity, the growth prospects within an LDC's underlying service area, the physical condition of distribution system assets, the extent to which an LDC's existing OEB-approved distribution rates achieve the maximum allowable rates of return, the competitiveness of current distribution rates vs. those of other LDCs, and the prospects of generating operating synergies through an acquisition I merger. Traditionally, a 10 to 20 year discounted cash flow valuation model is prepared to assess the fair market value of an LDC, complete with a review of various assumptions in respect of future growth prospects, capital expenditure requirements, rates of return etc. THI management has not prepared any long-term financial projections; furthermore, there is considerable uncertainty regarding the sbort·term financial prospects of THI due to uncertainty as to whether the OEB will approve the Company's current rate application. For purposes of this report, we have estimated the fair market value of TID based on the preliminary balance sheet as at December 31, 2008. As a regulated utility, TID can only generate a rate of return on its rate base, and the ability to generate significant excess profits is severely restricted. The range of fair market values for LDCs generally falls in a band that reflects a premium to the underlying net book value of the rate base. In the table below, we have estimated the fair market value of the shares of THI to fall in the approximate range of$10 million to $12 million as at December 31, 2008. This represents a fair market value range of $1,510 to $1,812 per customer. A fair Apri130, 2009 Page49 ) --C) ) it a financial return (e.g. annual dividends), the benefit of enhanced local economic development, reduced electricity rates, or opportunities for local employment As an investment, the Town should weigh the value and benefits of the ownership of THI against the value of the economic returns that could be generated from the cash proceeds that the Town would receive from a sale of the Company. In prior years, the Town has not received any financial return from its investment in THI. However, THI has budgeted the payment of a $100,000 dividend to the Town in 2009. The Company does not have a formal dividend policy in place; presumably THI intends to make ongoing dividend payments to its shareholder in the future. We understand that, if the OEB approves the current rate application, THI should be in a position to generate an after-tax return of approximately $532,000 in 2009. This represents an approximate 6.13% return on the Company's average rate base, which is approximated by the average net book value of shareholder's equity for the year. In the future, THI should be able to generate a similar rate of return on its rate base. We consider net income to be an appropriate measure of the economic or investment return of TID on a continued operational basis, as it provides the funding for dividend payments to the Town as well as for re-investment in growth-related opportunities (e.g. new customers, new capital expenditures etc.) that increase the market value of the utility. Conversely, a sale of THI should generate cash proceeds of between $10 million to $12 million. Assuming midpoint proceeds of $11 million (and no Transfer Tax liability), the Town of Tillsonburg could realize a guaranteed annual return of approximately $550,000 (i.e. 5.00% x $11 million) by paying off a portion of its $14 million in long-term debt. We understand that recent long-term borrowings of the Town have been priced at an interest rate of approximately 5.00%. Alternatively, investing the cash proceeds from a sale of THI in risk free 1 0-year Government of Canada bonds would generate approximately $322,000 in interest income per annum (i.e. based on a 2.93% yield as of April 22, 2009). In conclusion, if the current rate application is approved by the OEB along with its 30%+ increase in distribution revenues, THI will be in a position to generate an after- tax return of approximately $500,000 to $600,000 per annum. This return will fluctuate from year to year and may not be fully available to pay cash dividends to the Town. Alternatively, ifTHI is sold for estimated net proceeds of$11 million, the Town will realize notional interest savings of approximately $550,000 per year by reducing a corresponding amount of Town indebtedness, or a lower amount if the cash is simply invested in risk-free Government of Canada bonds. 5. Conclusions The sale option is clearly a Feasible Option and it results in the monetization of the Town's ownership interest in THI. Hence, it provides an immediate fmancial benefit to the Town. Furthermore, the Town would no longer be burdened by the financial risks and headaches of managing a complex regulated business. The Town must also consider the long-term direction of the Ontario LDC sector, and the Province's April 30, 2009 Page 51 (} ', . \_) V. Conclusions Compared to other LDCs in the immediate area, THI is the smallest in terms of customer base. Although its relative operating and financial performance has been satisfactory, its small size and lack of critical mass wiU make it difficult to continue that performance level into the future. Furthermore, it is likely that the Province will continue to pursue its policy direction of further LDC consolidation. Our analysis suggests the Base Case I Status Quo Option could be considered a Feasible Option, at least for the near term. We have some concerns over the long- run viability of operating THI on a stand-alone basis in the absence of entering into significant shared services arrangements. Our analysis of the Expand I Diversny Option suggests that THI does not have sufficient financial resources to acquire another local LDC. We have interpreted this option as the pursuit of new business opportunities that are related to the electricity sector. Our analysis suggests that this is not a Feasible Option for THI to pursue on its own due to the high investment in capital costs, the risk of limited economic returns, and the possible need to hire technical expertise. Our analysis suggests that the Merger Option is a Feasible Option. However, this option should only be considered pursuant to a long-term vision or strategy for THI as it may be difficult to extract the Town from such an arrangement once it is entered into. Our analysis suggests that the Sale Option is a Feasible Option and it results in the monetization of the Town's ownership interest in THI, providing an immediate financial benefit to the Town. The Town would no longer be burdened by the financial risks and headaches of managing a complex regulated business. This option may be an outcome of the Province's intention to continue industry consolidation over the next 5 to 10 years. April 30, 2009 Page 53 ) KPMGLLP 199 Bay Street, Suite 3300 Toronto, ON M5L IB2 I. Introduction A. Background Tillsonburg Hydro Inc. ("THI" or the "Company") is an Ontario corporation that is wholly-owned by the Town of Tillsonburg (''Tillsonburg'' or the ''Town") and operates as a local distribution company ("LDC") that is regulated by the Ontario Energy Board ("OEB"). The primary focus and responsibility of TID is the delivery of electricity to customers and the maintenance of the power grid within Tillsonburg. The Company serves more than 6,600 customers located wiqpn a 22 square kilometre service territory. ,;;+-'--+-. THI is governed by an independent board of director.~/~1o.wns all of the electricity lines and pole infrastructure required for the l~i!,l..~stribuq9~ of electricity. Till operates under a Master Service Agreement with The Town 'Gf'!,;J;ill.sonburg, which owns and leases certain utility-related fixed ~riCts (e.'g,rolling st~·computers, and office equipment) to THI and supplies all.,'~g~el· and related administrative services required by the Company. 'H b. THI's primary goal is to provide i~~!~w:p~.ers ~iJi'i~·reliable and cost-effective power supply while maintaining a safe tljstd~,.~ystein. The Company also has a mandate to improve the efficiency of tlieJocal''ft9\Ver grid and to help customers reduce their energy con~ptilp~!ffl. requ~wents. ' Working hand-in-hand with the Electricity Distributors .. 4{~ociati9h of Ontatw; the Ministry of Energy and the OEB, THI continues to implein:~~ .. ,PW~~~., ,a.rid. grid enhancements to achieve these objectives. . ':( :i:i!:;j:.~,~,~~4qL.~· •t•' B. Terrri'si~f Reteflnce· The Town of T~~~ ~d the Board of Till have engaged KPMG LLP to undertake an indepen&nt Strategic Review of THL The Strategic Review is intended to provide a comprehensive analysis of THI that includes: a) A review of four strategic options available to THI including: Base Case: Maintain and operate the Company on a status quo basis; ii Expansion/Diversification: This option envisions the continuation of Till's traditional electricity distribution operations, plus expansion through the pursuit of complementary business opportunities such as LOC acquisitions, retail and/or power generation activities, and other ancillary joint venture opportunities; iii Merger: Under this option, Till would be merged with one or more Ontario LDCs and the Town would receive cash and/or shares in the post-merger entity; and, April 30, 2009 Page 1 brought to KPMG' s attention after the date hereof. Without limiting the foregoing, in the event that there is a material change in any fact or matter affecting the content of this report after the date hereof, KPMG reserves the right to change, modify, or withdraw the report. • This report, together with all attachments, is being provided solely for the exclusive use of TID and/or the Town and may not be used or relied upon by any other party. Neither KPMG, its affiliates, nor its respective partners, directors, officers, employees, counsel or agents will have any liability to Till, the Town or any other parties resulting from the use of this report by them in making any decisions in respect of Till. • This report is private and confidential and is not intended for general circulation or publication, nor is to be reproduced or used for any purpose, other than to assist Till and/or the Town with the specific matters,4fiscussed herein, without our pri~r .~tten ~~ssion in each specific ins~:. We will not assume any responsibility or liability for damages or losses, tilcuq~ by Till or the Town, their respective officers, directors or councipg(sf,, or b}tt~y other parties as a result of the circulation, publication, reprod:petion or use of~~ r~port contrary to the provisions outlined herein. Any u~:~kich ~il'arty mwre.rbf this report, or any reliance on or decisions to be based on· ~~responsibility of such party. KPMG does not accept any responsibility fotlha,mages, if any, suffered by any party as a result of decisions made:or .actions tak~· based on the contents of this report. \:f.:i;jff:;1:Lfi;'!'' • KPMG International ~' .! ~'~Swiss co'Qperative~ of which all KPMG firms are members. KPMG Jrttem~~nal pro~e~ no professional services to clients. Each member fmn''iM~p·· and indel}endent legal entity and each describes itself as such. RY,:ryt:G 't~'ilHilitet!,'liability partnership formed pursuant to the laws of Ontamt; i~f'die Cailhliian member firm of KPMG International . . r{ ~tJ ~;/ E. Execut•~,e Suni1/natv 'r:!~. ,JT. Till serves more than~'§OO customers located within its 22 square kilometre service territory. Till's Vision'9.s to deliver professional, cost-effective and environmentally responsible energy services to its stakeholders, that being its customer base within Tillsonburg, and to provide a reasonable economic return to the Town of Tillsonburg as the sole shareholder. One of TID's key values is to "satisfy its customer's energy needs with high quality, cost effective products and service excellence, and to provide the shareholder with a reasonable return on investment relative to its investment in infrastructure and risk." Till is structured as a "virtual" company whereby only the distribution system assets (e.g. wires, poles, transformers, substations, substation lands and general distribution grid) are owned by the Company. The Town employs all of the personnel involved in managing and operating THI. Till is allocated the cost of approximately 18 FfE employees; approximately 10 of these individuals spend 90% + of their total time on Till matters. Although there may April 30, 2009 Page a / _) grid. Details of initiatives under the Green Energy Act will not be known with precision until further regulations are released The Act is likely to promote further consolidations in that larger utilities will need to have the required critical mass to fulfill its requirements. Our analysis suggests the Base Case I Status Quo Option could be considered a Feasible Option, at least for the near term. Till appears to have a competent management team in place to manage the complexities of its business. Tin has provided relatively good cost and service performance in the past; however, maintaining this performance level will be difficult as a result of Till's small size and lack of critical mass. We have some concerns over the long-run viability of operating TID on a stand-alone basis. Our analysis of the Expand I Diversify Option sugg~~ts TID does not have sufficient financial resources to acquire another local ~Accordingly, we have interpreted this option as the pursuit of new business ~AA~nities that are related to the electricity sector, but outside of TID's core distgbutidi,J.t:Rusiness. Our analysis suggests that this is not a Feasi"ble Option for 1'Hljo pursd~ pn its own in that the Company will still be hampered by its small,_¢1atiw. size and ~~~ .. of economies of scale in addressing regulatory burdens. Fu~or~; iTHI does .not appear to have the financial, technical and management reso~s~.ii.ecessary to participate in new business opportunities on a stand-alonp, ~asis. .. :; it;i, . Given most power generation projects ijij~~,~igrufl~r upfront capital investment as well as specialized technical skills, TW'~:iinu(«i:fmancial resources will make it difficult for it to participate, ~gfullyiP''larger~projects. It is likely that Till will need to hire specialized .f#Cbrii~ skills tojpperate any new ventures. Generating a satisfactory rate of ~ oniHmy invettnl.ents that are made will likely be accompanied by ~~:ig,~,~{q~~~nr;HH:i;f·'·· There is an oppariiuiicy~ TiJil-4Q .,partner with other suppliers in the delivery of certain prog11ams, particul@y lm~ai ·conservation initiatives or the development of small-scale renr\t~ble pow~Hpro.fects. TID's most logical role is to act.as a bridge between exterruil"'i'suppliers and local consumers. These smaller business opportunities are sc~}~d may provide some benefit to the local customer base. There is some risk, h~ever, that even this limited role will be a distraction for management while leading to limited returns on investment. Our analysis suggests that the Merger Option is a Feasible Option. However, this option should only be considered pursuant to a long-term vision or strategy for TID as it may be difficult to extract the Town from such an arrangement once it is entered into. The fact that the Town of Tillsonburg would likely be a minority shareholder in any merger transaction significantly reduces the attractiveness of this option. The Town would lose direct control over decisions impacting on local electricity distribution. Furthermore, it is likely that the number of LDC employees working and residing in Tillsonburg, over the longer term, would be reduced to direct field service and maintenance personnel only. April 30, 2009 Page5 i (J ' .. J II. Review ofTillsonburg Hydro Inc. A. Mission Statement I Vision fu July 2008, representatives of senior management and the Board of Directors of THI participated in a one-day strategic planning workshop to brainstorm on the Strategic Vision of Till. The moderator of the workshop, Fred J. Galloway of F. J. Galloway Associates fuc., subsequently drafted a report entitled ''The Strategic Plan -Environmental Scan Report'' (the "Galloway Report'') dated July 2008. The Galloway Report identified the following Vision,. :fqr THI -"to deliver professional, cost-effective and environmentally respoD.$1.ble energy services to our stakeholders." The two key stakeholders of TIU1a1'J1)~ customer base within Tillsonburg and the Town of Tillsonburg as the, ,s&t) s~older. The Galloway Report also identified the following Mission Sta,~nt' for 'I'Hi.t.#~<An energy services company committed to maximizing value mtf.~~ cu~mers ancfl~'iireholder." We understand that both the Vision and Missie)b Statement were intended to be preliminary in nature, and required further discus~fu~:tmd refmement. The Galloway Report also articula~Jjes of .• Values for Till, including seeking to "satisfy customers' energy n~dSi~J:M.gl?)J\iality, cost effective products and service excellence, and to provide ~~sharenplder with a reasonable return on investment relative to its inv~~~nt in i.n:f'tastrucrure and risk." _,+:· ''-!+-. ·~- Since Till's customet•~'H~ isl$s,sentiallyllthe same constituency as that of the shareholder, namely the res~gts 'dt:tl:!e:;J16\vn of Tillsonburg, it is therefore critical to assess the str~gldii~m~:ms' 1#,tper consideration from the perspective of how they advance the ·~~~rgy and-~~-of ~ce" interests of the residents of the community. The Gallow~~ ~P.rt also iij~tiff~ and commented on the four strategic options for Till that are furthet!l;liscusst;:d within this report. -~[!'~ B. Organ izatidn 1. Corporate Organization THI was incorporated under the laws of Ontario on October 26, 2000 and its one issued and outstanding common s.hare is. owned by the Town of Tillsonburg. The incorporation of THI was. undertaken in response to Bill 35 -The Energy Competition Act -which required, amongst other matters, that all Ontario municipalities transfer the assets and operations of their local electricity distribution operations into a legal corporation. A municipal bylaw enacted the transfer of most of the former Tillsonburg PUC electricity-related assets. and operations into THI on October 26, 2000. April30, 2009 Page? I (_) Stakeholder interviews have suggested that the current organizational structure provides certain financial and operating benefits to the Town and THL Specifically, the current personnel structure allows the Town to employ specialized personnel who can provide their services to several Town-managed operations. In addition, the Town charges a 5% mark-up above the cost of all services delivered to TID, thereby creating an annual $80,000 to $120,000 revenue stream that the Town uses to defray municipal property taxes. It should be noted that some stakeholders expressed concern over the potential for conflicts of interest to arise when Town employees represent multiple organizations. Some other challenges associated with the existing personnel structure include: • The workloads of financial and administrative staff at the Town appear to be strained by the specialized demands placed on them by Tin, in addition to the demands of the Town and the Water Department This partly reflects the specialized nature of many of the tasks associated witlu.lu.ming an LDC, and the need for staff to keep abreast of developments in ~lectrlcity sector and at the OEB. +)y 'i~in~:,, • Operation by the Town means that some T!IJ,~'have iiijil_Jjple responsibilities. This can result in confusion over work ,.Pi'loriti!'S and in bQlan:cing objectives across three organizations-THI, the Tow'rilmJ.d tti~:Water Depllrtment. Conflicts of interest can arise. Some stakeholders sti'ieied ihat by working for a single employer, staff would be more focu_ssed and aeci>.}mtable to that organization. • The ,:ro~ has tried to hire a ReJ~dcy:Mfairs -~ri~er to deal with OEB r~te applications and other regulatory ma'-'ers~'!.difficulty has been that salanes for LDC and regulatQcy; ,l!pecialist l¢rsonnei ·are higher than can easily be accommodated witfq~/'di({~cipal·p~y scale. We also note that there is a general shortage ofb~le~gulatory personnel within the LDC sector, which generally accoun~ for l'ii~Jwgbeti'~es. We understand from management that THI has ha~,IJi:lhlx~~,xpel:i~npe ~lymg on other utilities and consultants for rate applicaticms and oth¢~:. specmcy assistance in the past. Due to resource constraiii~s relian~ on eiternal experts is unlikely to change in the near term. ., Lh[t . f The Town provide~!~ts to TID under a Master Services Agreement, and charges fees that are intended cfO. recover its costs for both personnel, services and capital assets. The fees charged to THI include a 5% premium above direct operating cost as a management fee for the Town. The amount of annual cost recoveries is fixed early in a calendar year for operating expenses (e.g. personnel, materials, rent, asset recovery costs), whereas capital expenditures charged to THI are flexible in amount and are based on the actual amount of time and related overhead costs incurred by the Town. It should be noted that charge-backs to THI are governed by the Affiliate Relationship Code, which generally requires that cost recoveries be limited to Fair Market Value. We have some concerns that the Town has not been recovering all of its costs in charges to THI. For example, we understand that the Town does not charge THI for depreciation and financing costs related to the use of certain capital assets such as office furniture, computers and related IT infrastructure. April 30, 2009 Page9 ,. ) It should be noted that DDM Plastics, the Company's largest customer, will idle its 500,000 square foot production facility in Tillsonburg in May 2009 and intends to be closed for the indefinite future. It is hoped that DDM Plastics, a manufacturer of injected molded parts for the North American automotive industry, will recommence its operations once there is an improvement in the economy. The other large industrial customers of THI, particularly those in the automotive parts manufacturing industry, have similarly experienced a significant decline in their sales activity and have reduced their employment levels and their levels of power consumption. The decline in power consumption impacts the distribution revenues of Till, which are established based on the projected level of power consumption in a particular year. While the non-energy operating costs of Till are largely fixed, the revenues are dependent upon the amount of power consumed in a given year. The Company purchases all of its power from Hydro One, which is delivered through transformer stations located just north of the Town. Due t~ recent industrial plant closures and downsizings in recent months, the total ~nt of power consumption has declined by 15% during the first three months,;.~('~~~ compared to the same three month period in 2008. · "1 ~h. ;ft~~: .... . i; '"il;tu/ Operational Performance··,:q!:\ .. J:,,,, ,;;-c. ·::~*- Based on stakeholder interviews, we U'O,.~~~d thai'ilie~hysical distribution plant of TID is in a good state of repair. Sih~e'lq~:,,w,~ l~<J's, TID has implemented a number of safety, maintenance and retrQfitdhltU\tives to ensure that all customers have a reliable and safe el~epp~ty systerrl:]~ithin tile Town. In particular, the Town has gradually been conv¢ngl~hysical'pJap.t from a 4.16 kV system to a 27.6 kV system. Till manageoi~s · : '' that Ulls conversion process is approximately 60% completed, wjfu.. a fuii.t§Y ·~wjdl conversion to be completed within an additional 5 ye~y: Th~!:c()n\i~ipn ~o a 27.6 kV system reduces the level of line losses and all,'?~s for the d~~~i&ning of older substations . . :--~::. :1~1 .,.I· The Company oWits and mallitains approximately 151 kilometres of wire, consisting of 102 kilometres Clfp:verheJd wire and 49 kilometres of underground connections. :...l..i::... ..i..:·" THI owns five substa~'~~operties throughout the Town. Three substation sites are currently in use, one stlbstation site has been decommissioned and is currently used as a pole yard and storage area for a spare transformer that is used for parts, and a fifth substation site has been decommissioned and is vacant. The latter substation site could be liquidated if no longer required for THI purposes. THI does not own any other real properties, but leases its space requirements from the Town at two primary sites pursuant to the MSA as follows: • 200 Broadway Street, Second Floor -Town Hall facility which houses senior administrative personnel of TID (most of whom also allocate a portion of their time to Town and Water Department matters). • 10 Lisgar Avenue -Tillsonburg Customer Service Centre -which houses the majority of THI's personnel (e.g. linemen, customer service, finance and billing, etc.) and its vehicle fleet. April 30, 2009 Page 11 \ _) OM&A costs of $1,620,000. This represents an annual increase of approximately $73 per customer. • OM&A costs have increased at an annual rate of over 10% since those approved in the 2006 rate rebasing process. • There will be continued pressure on the OM&A costs of THI due to additional one-time regulatory and other costs such as the adoption of IFRS standards etc. Combined with increased capital spending for smart meters and an increase in Till's rate base, plus the Board's desire to generate the maximum permitted rate of return on Till's deemed capital structure, the proposed distribution revenues for 2009, if approved by the OEB, are expected to be approximately 30% higher than existing revenues. While 2009 industry-wide data will not be available for some time, our sense is that other LDCs are not requesting similar increases. Hence, the relative OM&A cost position of Till likely will deteriorate. ~- The following table provides a summary of the es~ted., distribution rates for residential customers of a number of comparable LDC,$~~c;ti.ve May 1, 2009, based on recently DEB-approved rate applications. The Qis~butl~rtr~es for Till are based on the most recent rate application which is still, ~i'e.tbe OEB) /!'he. pre-application distribution rates for TID are also shown at tb.tt;botto~.,of the tab1~WJ ' · Exhibitll·1 . . ... ,lftl;tf~~:··. Comparative Analysis of Dist1;16.in~.t1 Rat~· \''·~~~~-:i'']/ 40524 0.7100 490.44 94.9o/o 306.12 1.1900 448.92 86.9% 355.44 0.9200 465.84 90.2% 517.80 0.9000 625.80 121.1% 502.80 0.9800 620.40 120.1% 332.64 1.01 376.68 3 11 0.8800 Note 1: Distribution rates effective May 1, 2009 as approved by the OEB in recent rate decisions. Note 2: Distribution rates requested by Tillson burg Hydro In the most recent rate applcatlon before the OEB. Note 3: Distribution rates for Tillsonburg Hydro in 2008 before the currem OEB rate appfication. 1.0495 1.0420 1.0427 1.0565 1.0560 1 1.0422 If the rate application of TID is approved by the OEB, the annual distribution costs (including volumetric transmission costs from Hydro One) of a residential customer of TID who purchases 1,000 kWh of power per month will be slightly higher than those of most other local LDCs, except for residential customers who are serviced by April 30, 2009 Page 13 ) D. Financial Position & Performance 1. Balance Sheet Position A summary of the balance sheet position of THI for the five years ended December 31, 2004 to 2008 is presented in the table below: Exhibit 11-2 Five Year Summary of THI Balance Sheet Position Tlllaonburg Hydro Inc. Ballmce Sheet PosiUon ($DOG's) Assets Current Assets Cash and short-term lmestmenls ACCOl.llls receivable Due from related parties Income taxes receivable ln11B11tory Prepaid expenses Capital Assets Cost, net of contributions Accumulated amortization Deferred C05!S Regulatory Assets Long-Tenn Liabilities Customer deposits Regulatory &abilities Shareholde!'s Equity Common shares Contributed capital Retained earnings (deficit) Capital expenditures -gross Less: Contributions in aid of construction Net capital expenditures April 30, 2009 $ As at December 31 2004 2005 2006 2007 .i}r· ,,::;), 3,: /'·~::r~~~:? 2.: . {f ··:·;;. 39 .318 38ft r, ' 362 ,~:l. ;@ 277 3D . 4,085 11i'lL1:,(r6.1·~:·e~336_·_-_:._,l·~---.· .• ·, ... ·_,,, '"' "" ';:;~iY;~h. 12,239 13,042 (6,884) (7,124) 98 2,250 97 2,038 70 82 2,190 97 2,347 2,287 6,993 1,190 (833) 7,350 6,993 1,190 (763) 7,400 5,555 5,918 448 10,184 10,459 2,096 1,948 57 62 85 114 191 132 2,461 2,224 97 97 125 2,558 2,446 6,993 6,993 1,190 1,190 (557} (170) 7,626 8,013 $ 9,697 9,687 10,184 10,459 $ $ 925 (1,077) (152) 758 (168) 590 1,008 941 (276) (138) 732 803 2008 1,996 2,840 81 321 12 5,250 13,192 (7,584) 5,608 501 11,359 1,739 153 143 198 2,233 97 610 2,940 6,993 1,190 236 8,419 11,359 918 (769) 149 Page 15 (} Exhibit 11-3 Six Year Summary of THI Operating Performance Tlleonburg Hydro Inc. Summary of Operation Reaults ($ OOO's) Assets Revenue Powerre11111ue Cosl of power Gross maJgin on power Distrl:lullon reo.enue Retallsenke Other Expenses Ope!atlng and malnlenance Billing and collecdng Community relalions Genellll administration Depreciation Interest and finance charges Net Income befol8 taxes and other items Loss on disposal o1 assels Prior period adjustment Net Income before Income taxes Payments-In-lieu o1 taxes Net income Ooss) ·f:UL J' ~f";f" $ 15,661 15,661 1,534 11 73 1,618 549 327 462 365 13 1,716 (98) For the Year Ended December 31 2005 2006 2007 2008 17,913 17,913 1,731 11 115 1,857 16,316 18,970 18,318 18,970 2,320 2,504 16 17 134 133 2,470 2,654 ,;r'. 574 574 187 7.4% 7,820 4.95% 15,647 15,647 2,406 15 158 2,579 776 425 431 459 36 2,127 452 452 46 -2-8% 8,216 4_94% 2009 (Note 1) Budget 16,311 16,311 3,134 17 129 3,260 1,057 543 503 520 17 2,640 640 840 108 27.2% 8,685 6.13% We understand that the modest operating perfonnance and rates of return on investment achieved in prior years resulted from several factors as outlined below: • Relatively low distribution rates were locked-in for a number of years in the early 2000's and these did not allow the Company to generate a profit. This reflected the extension of earlier policies that were designed to eliminate an excess working capital balance; • the Town and Till were not actively pursuing a policy to maximize their return on investment in Till; rather, lower distribution rates were viewed as an economic development tool and a method of keeping customer power bills lower; • the Town and Board were not interested in generating interest and/or dividends for the Town. In fact, we understand that no dividends, interest payments or other direct investment returns have been paid to the Town since THI was incorporated in October 2000; and, April 30, 2009 Page 17 <).· \ . ) a Regulatory Affairs Manager ($100,000). These costs may also be questioned bytheOEB. In the event that the full rate increase is not approved by the OEB, then the Town may be required to absorb a portion of the costs disallowed, LDC earnings may be reduced, or services provided by Till may need to be cut back. These outcomes could reduce both the current fair market value of the utility and the fmancial earnings available under the status quo option. 2. Downturn in Economic Growth Based on discussions with management, we understand that consumption by 1HI's commercial and industrial customers has been adversely affected by the downturn in the global economy and by the significant decline in the North American automotive sector. A relatively large proportion of THI's industrial qu~omers are automotive parts suppliers. Another large customer supplies the No®"Aiherican housing sector and this company has also faced a business downwrn .. ~Pf:1 , -d·" !!.~ The economic downturn has made it difficult forll!'f'to pre~ an accurate forecast of sales volumes in the current rate setting pr~ss. AdditionaluiQI.Ulti,cipated declines in sales volumes could impair Till's earning(lfwer ~, next few')!elirs. Uncertainty over this issue may also impair the Company's '~pnlfiret value. · Conversely, the Town has experi~.moderat~lqp,ul~on growth over the past decade and this trend is expected to co~jp. the .fu~:' Tillsonburg is considered to offer an attractive quality of life ani hali~16®n,tbe'beneficiary of new residents, primarily seniors, who are QJ,ll'Chasing ''r~~itlenti.kV homes in Town. This modest population growth is ex~t~ift0!continue lgld will increase the size of THI. , ,, "·:' !; [:;;J;i!fc,,iiu; F' .1' •. E. Compptisbn !Agait!§.~~Peers in the OntariO LDC S~to_rr· . •:. .. . ·:~ .;: . '4tit ....• l Based on data for 2001': Tin ranked 59th out of 86 LDC's in Ontario in terms of the number of customers."' This placed THI near the bottom of the third-quartile of utilities in the Province. THI is thus clearly a relatively small LDC, but it is by no means the smallest. April 30, 2009 Page 19 \ __ ) I ,_) Exhibit 11-5 Comparative Benchmark Analysis of THI -~---------~ - -- --- > -' -------- --------___ .:....__ ___ -=: ~----~-~-----=---~-~- Total Brant County Brantford Erie Thames Haldmand County St. Thomas Woodstock Per Customer Brant County Brant lord Erie Thames Haldimand County St. Thomas Woodstoc 1,599 7,958 5,008 7,110 171 214 353 344 223 226 255 :•:;:,,2~ ($000s) 14,812 6,000 18,856 30,456 33,001 56,405 8,062 8,524 16,694 25,555 11,265 30,426 11,416 7,714 18,717 · , ~tliiz~B¥i.l1i¥.~6Biill 14,014 28,338 17,931 ($'s Per Customer) 1,962 854 849 2,019 1,520 1,177 1,470 1 176 1,242 1,434 1,424 ·:t~:: rj'::;I)!,J; i'Jlit'' Measured by number of q_Srofil~,rs. TID lit. less than half the number of customers of most other LDCs in the""local 'area. ~-.~..: ~ i·:l>.. Jt. ll :· Till also has a relatively lOW1~\le:lofi~~lf1Xed assets per customer. This is largely attributable to tq~!Jailit':~~ th~irf:ewn of'Tinsonburg owns many of the general (i.e. non-distribuq9.1i) assets ~i~ith utility operations; the Town owns the vehicle fleet and bilti~d compli~ sys&;ms. Most other utilities own these assets directly. Further, the Cotii~y operat#s out of premises owned by the Town rather than from a separate building1:~ec!rby the utility. Finally, Till operates a compact urban distribution system w1flpil Tillsonburg and does not have the high capital cost per customer associated with a rural customer base. Till has a relatively high equity value per customer. This results from the fact that, unlike other LDCs; THI has no long-term debt and therefore its capital structure consists entirely of equity. Until recently, TID has been reasonably successful in keeping its operating costs low. The Company's OM&A costs per customer in 2007 are less than the average for area utilities. This is all the more remarkable given TID's relatively small size. It appears that the utility's ability to share personnel and resources with the Town accounts for its favourable operating performance. Costs for Till, however, are now projected to increase substantially from 2007 levels. As noted earlier, Tillsonburg Hydro, in its current rate application, forecasts an increase in 2009 OM&A expense of about 30% compared to 2007 figures. This will significantly change its relative cost position. April 30, 2009 Page21 () \,) __ ) capital structure for rate setting purposes is typically deemed to be 60% long- term debt and 40% equity. • Distribution rates in the three subsequent years are determined by indexing rates in the Base Year. Rates are indexed through an automatic adjustment mechanism that takes into account general price inflation and expected productivity improvements. • Distribution rates in the fourth year will again be reset based on expected operating costs in that year, as well as a return on invested capital. Distribution rates are therefore periodically reset to cover actual costs. Between rebasing years, however, the shareholders of an LDC are at risk if costs increase faster than provided for in the indexing mechanism. LDCs also have an incentive to reduce costs, since such savings will result in increased earnings during the years between rebasing. ~ The OEB reserves the right to disallow certain costs ,~g'· the rebasing process. This means that the OEB will not approve distributJ.or~s to recover those costs from consumers if it feels that they are "impruden~· Or do n~w.eet tests with respect ~ f • ·~ . \ I : .~· ~ I to reasonableness. The OEB, for example, may.~ow costs'~!! to a third party or an affiliate if it feels that they are above pre':~~g m~~et prices. ':iJJ'' The OEB also regulates and monitors various ~~~! ~p~ts of LDc operations -the accounting chart of accounts, cons~rvation deili~ management requirements, operational metrics, customer deposit ~:e.i~~-' etc. ., 1t;;,,' 2. The Affiliate Relaffignship ~~%nli'' ' NJ·"' ... U.l: ~~ . The OEB' s Affiliate R.el@,onsb.l:P' Code ("UC") sets parameters on the prices that can be charged to an LDGPlY~~!l~,etltities. In particular, the ARC requires ux:s to prove t~:!.\l;~~~~ill ~il.'ay.any'Illore than .fair m:n-ket value for any sen?~s provtded to tt.¢1 by a~at#.t-, ;Fbis measure ts destgned to protect electricity consumers .. ..:6i);entim.es, a 1~id'}h~ndering process can be used to demonstrate fair market value. . 'Eij1 i h: t ' . iJ The provisions of t~C' have implications for services provided to Till by the Town of Tillsonburg. ~ifically, the cost recovery pricing mechanism or MSA for personnel, services, relit and use of capital assets has been and will continue to be subject to ongoing regulatory scrutiny. 3. Service Quality Standards The OEB provides standards with respect to the quality of service provided by an LDC. For example, it sets performance standards such as the telephone accessibility of customer service staff and it monitors power outages and other indicators of system reliability. These standards are consistent across Ontario and are designed to ensure that customers receive appropriate service on a timely basis. April30, 2009 Page23 (J Relative to the early part of this decade, however, the pace of consolidation has slowed considerably and some of the most notable mergers have been between larger utilities (e.g. the recent PowerStream-Barrie Hydro merger). The current Transfer Tax exemption has not been successful to date in inducing significant additional merger activity. This heightens the probability that the Transfer Tax exemption will be re-introduced at some point in the future, in the event that it is not extended beyond the current October 16, 2009 deadline. C. The Green Energy Act The Province of Ontario introduced the Green Energy Act ("the Act") in February 2009. The Act is a major initiative that is designed to promote: • The growth of renewable energy in the Province, incl1,1~ng wind, biomass and solar options. . .. jT·· .;J.: .. • Promotion of conservation as an alternative to exlPfi~g:generation capacity. •j. 'lJ> • Development of a "smart" grid, which envis~jrlcreasetil~ of automation and communication technologies to facilitat;j real-t.Qne manag~nt of electricity load and integration of local energy sourd~~ih. Jt·.," .7 To enable these objectives, the Act provides th~; ~ster of Energy with sweeping powers. The Minister can issue drrecuves to govetfunent agencies, including the OEB and the Ontario Power Authority';);:~e:j~pyernm~ibas also limited the ability of municipalities to restrict renewable P9W~t]tt(ij~ through the use of local land useandzoningbylaws. _,_i"':<.r;;. 'f( ,_._. To support the expa'9$f.9~ of ~ilewable jl9wer projects, the Green Energy Act provides for the implem~~9n.n91b';~~tlard offer" feed-in tariffs that will be provided to develQ~l.'S•!Qf sn:WJ:t.renewable power projects. These tariffs will provide price certainty ,«,fdevei~~i:s of~power projects, and will eliminate the costs and timing chalk~~ of partit~ng)h' the competitive procurement processes that have been used in thltJ!.ast. Fee'g-in tariffs should stimulate additional development of renewable power pr~j~s tqibughout the Province. ~ Ti~ Under the Act, distrioiifibn utilities will be given the power to directly own and operate small (under 10MW) renewable power facilities or combined heat and power facilities. Up to now, LDCs have not been permitted to own such facilities directly, because of the separation of competitive and monopoly services that was imposed during the original industry restructuring process. The Act also gives municipalities the right to own such facilities directly, provided that they do not exceed 10 MW or another limit that may be set by regulation. As a benchmark comparator, 6 standard wind turbine units would generate the equivalent of approximately 9 MW of power. Details of many of the initiatives under the Green Energy Act will not be known with precision until further regulations are released. The Green Energy Act clearly favours small local sources of power generation as an alternative to large centralized generating plants. Regulations governing to what extent LDCs can invest in power generation projects, as well as the mechanisms available to recover capital and operating costs, will need to be clarified before the economic merits of any project can be properly assessed. April 30, 2009 Page25 () ; \_~) IV. Review of Strategic Options A. Overview In this section, we discuss the four strategic options available to THI and the pros and cons associated with each option. As a general rule, we have tested each of the four strategic options against the criteria as to how they improve THI' s ability to deliver on its mission statement, vision and core values as outlined in Section II of this report. In assessing the four strategic options, it is important to c.po,~der a number of key facts. in respect of THI and the Ontario local electri~"dis'tribution industry that provtde some context: 1 ',. 'i :: :·. ~ r ,, ~ .. l -. • the Province continues to pursue further con~~on ofi~o LDCs; • the Company operates in a complex re~~ory,~nviro~t~:alat continues to increase operating costs; · -. '4+ .fl1"··c · · ·;;:n~·· • Till is a small LDC relative tq, ,~~er indusftt~~~cipants, with only 6,600 customers; ·;·p:H:;ll'i:,. ·"/·ii.J'. • all management and employees are~ub,9~ from the Town pursuant to a MSA that offers both b~R~W~ and ~acks; iv • the CompanyJs a~~'g ari~B decis1~HJ.. on a rate application that seeks a 30% increase in total ~.i~tri~),~r§~ffi;~f~1i, .1· • certain ma.tl,J!(iiD~. cfiSffitners in Tillsonburg have reduced their energy consumpqpn levels4(~d ~l6yment levels) in response to a weakened econoroy~'lh. 'f8; Y • the Compan:rs\!:managanent team appears to be competent and capable of dealing with mo~ory matters; • a number of THI-Ji~~ed employees are close to retirement age; • the Company appears to have limited management capacity to take on significant new projects; • the Company has no long-term debt and is financially stable to finance new projects such as the installation of smart meters; • a Transfer Tax: exemption exists in respect of M&A transactions in the LDC industry that are substantially completed by October 16, 2009; • the Green Energy Act has recently been released and promotes investment in green energy power generation projects, amongst other business opportunities. In conclusion, the Ontario LDC sector continues to be challenged by rapid change and increased complexity in the industry. Aprll30, 2009 Page27 (~) \. ) --./ a per customer basis, the cost to this utility of submitting a rate application would thus be less than one-tenth of that incurred by Till. This highlights the very significant economies of scale associated with regulatory processes. However, it should be noted that: • THI' s current rate application will have the 2009 year representing the Base Year for the IRM process (see Section ill for details as to the rate-setting process). THI will not be required to submit a new rate application until2013. • The Town faces some financial risk with respect to the performance of THI over the period 2010 through 2012; in the event operating costs are greater than the approved rates, or there is a significant revenue shortfall, it will be difficult for Tin to adjust those rates. • To the extent that costs can be built into distribution rates in the rebasing process, additional costs incurred by Till as a stand-alone utip...!¥-_.should be recoverable from consumers in the longer-run. . ~:t· ·· Till management indicated that the OEB ha8 alrea4)} ;~~~.for justification of the fees charged under the Management Services Ag¢e@ent. ifilth(1 past, THI has been able to avoid further investigation of these ~nsferjlrices by ~,PEB because its operating costs have been relatively low. -H6W.rverit1fPs may bei:ome more of an issue in the future if the Town tries to significari1J&:iri&elise its level of cost recovery. Part of this increase relates to recove.cy of costs f~ ~ew billing system. The OEB may ask for evidence that such costs ~·ifW. more th~d be charged by a third- party service provider. ·;kt.' ~~;!+;: ~\:ftt' '·· In the future, Till will ~!!~ with4,a(lditional regulatory charges (e.g. IFRS conversion costs, smart ~tef'i~gration ·@.sts) that will need to be allocated to its small customer base. Th~ costs will furt.lei impact the sustainability of Till on a stand-alone basis:, :CTH::: '· ··:n; ~'!l;::u;;::;u ::_:.r"' We understanqndilit~.UI'l'eti.~~ application, as amended on Aprill4, 2009, is before the QE].\,and has uli~gone, limtial hearings with management and intervenors. Additional · q~!! from Uie OEB are being answered in written format for submission back W":tp,l( O~jln May 2009. Management of Till expects an OEB rate decision in June or ~.l009; however, the outcome of the OEB's final decision in unknown. )F · We also understand that any distribution rate increase will be implemented as soon as possible (likely June 1, 2009) and that the residents ofTillsonburg have been notified of the pending increase in local newspaper coverage in January 2009. It should be noted that TID's distribution rates represent only about 30% of the total electricity bill, so a 27.0% increase in distribution rates results in only a 9.0% increase in the total electricity bill. A summary of the advantages and disadvantages of the Status Quo I Base Case option is presented below: April30, 2009 Page29 } () \_ )\ ) __ / looking at sharing services with other utilities and outsourcing certain support services where appropriate. In the event that the Status Quo is not sustainable in the long-run, there are strategic issues associated with whether an alternative strategic option such as a sale or merger is relatively more attractive now or at some time in the future. 2. Next Steps In the event the Town wishes to pursue the Status Quo option for Tin, we suggest that it consider the following changes: • As shareholder, the Town should formally document its expectations with respect to the fmancial performance, dividend income, and business scope of TID. This can be provided through a "Shareholder's Declaration" or other similar document. This will provide Till's Board and manag!!l,li6nt with a clear direction with respect to the utility. ~ • Management should seek opportunities with .,o~ '~~-to share services in specialized areas such as preparing rate appli,~ili! and o~regulatory matters. Cost sharing initiatives should enable, _tq 'some~_ extent, tl:le·j~ty to allocate operating costs over a larger customer b!IS~h SCL.iiie .. co-operative efforts already exist amongst smaller LDCs in Ontario. . "k(!.;,: - • Management should actively 10plf: J~r op~~-ities to outsource support functions, where this can improve it~b'Ver~.cost arlcfservice petformance. 1 y·:b<iO' • The Town could considf?f ~elling a 'D:JJnority 'XD.terest in THI in order to obtain · specialized support aijd1 " ' ' • ce frlipJ. a I.aiger and more experienced equity partner. Further disc[~_~ion qf;'this optid'ttJis outlined under the Divestiture option . . ·....:..:...:.:. ~ .t:.' -·:·;J~--:J·n;ri ! _: ... Jd!':j·.·. q~~ C. Expan~''rDi\(wsi~ption ~ 1/ ·······j q··· .;!·~.r..~~!!, ·: -~.l\ _y In our analysis :d~e expanij·t diversify option, we have ruled out the possibility of Till acquiring atio~ I..D€. There are no electricity utilities in the vicinity of Tillsonburg that are sm~W~ough to be acquired by Till without significant financial strain. Y Since Tillsonburg does not have sufficient financial resources to acquire another local LDC and expand its traditional electricity distribution operations, we have interpreted the expand and diversify option as the pursuit of new business opportunities that are related to the electricity sector, such as: • electricity generation (through wind power, photo-voltaic or solar power, hydro- electricity projects, co-generation projects) • retailing of energy • the provision of conservation and demand management programs • other business opportunities While each potential business offers its own unique issues, we will first address this option from a more generic perspective. April30, 2009 Page31 ,,---\ \ J --~ .. ·•· ) Exhibit IV-2 Summary of Expand I Diversify Option Advantages & Challenges Competitive Advantages Cballenges • The Town is located near a major • transmission line, meaning that new generation projects will have relatively low costs of connection to The opportunities identified to date are all at the conceptual stage, fonnal business plans have not yet been developed. Additional planning to assess and quantify the potential new lines of business will be required and will take additional resources with an uncertain outcome. For example, the most recent Otter Valley hydro- electric pow~r study was completed in the 197~'· the Ontario electricity grid • There are large plots of open land available in the Tillsonburg area, some of which are owned by the Town. These plots could be used to generate solar power. • There is a river system nearby that offers the potential to develop run-of- the-river hydro-electric power that is environmentally friendly. --~·h, • Tmf!6es~ve in-house expertise ~e fieiC:H1i:9~ ren. ewable power /gene.t:_ation andifi:q~-will either have ., dlho rii¢ruit staff'ift>r use external . """'' .. ,;.,,, ,. • Wind resources in the region are (:Qusllitalits to undertake the planning relatively favourable for wind farms. w~,q.oted in the first bullet above. 1., ·.j:l,. • Till has the ability to borrow fut:~; it 1 , Then;' lj :~f' business opportunities from a traditional lender in order 'to · · I; : ;~~,f~~ourable, Till may have to finance any power, r!,,~eneratiori4~ ' liiifl Md.itional staff to pursue the~ projects that are p!g'iiiled(:l~i. These .1 ~~ casts some do~~t m:' THI s borrowings could, J ~ge i_om $3 'i 1, , ability to be com~titive m .th~e million to $5 millio~"M~iQl'ktll.ti 1 .. ' ?ew ventures relative to extsting Company'~r~~~~··· • :;;;6~~i;"~: "'';1~:)/li ~?::c:r~2;'~~: Town will provide funds for any significant green energy projects pursued by TID. April 30, 2009 • Most power projects are unlikely to provide an immediate cash return. • Due to limitations in transmission grid cap~city in south-western Ontario, the OPA has recently imposed a moratorium on new connections in the region under the Renewable Energy Standard Offer Program ("RESOP''). Page 33 () 4. Issues Associated with Specific Businesses In this section, we comment on issues associated with particular lines of business. We note that, in the initial period of market restructuring, many distribution utilities set up competitive affiliates to pursue competitive lines of business outside of the electricity distribution business. To date, with the exception of some fibre-optic telecom businesses, the success rates and economic returns from these ventures have been low. Further, THI is a relatively small utility and will have greater difficulty in reaching economies of scale, in leveraging relationships with its existing customers, and building in-house expertise in the new business areas. Outlined below is an assessment of four potential lines of business: • Billing Services • Retail Energy 4k, ,, ~:· -;~ c~~1 h d:.-'.·;;~:;1~:;, . ~ ~ :·• i::, 1 'e; · .. ~:~:. ::.:[~:. :i ~-I ~ :;: ~-i -: i": ... ~:0~."-l "'"t-. Billing Services "~:l''·'· • Conservation and Demand Management • Other Business Opportunities Distribution utilities have historically~~ reluctan~fr~Y on other utilities for their billing services. Accordingly, LDCf 'Rti !QI:ltario b1ive had limited success in marketing billing services to other utilii:f~s. · :~~falniliar, for example, with one relatively large utility that,,~P,e a maj~'effort~fb market its billing services to smaller LDCs in the earl~part'~[ptis deca'.,e, ?ut which later withdrew its marketing efforts in the face of vecy~@.ited;J?ll:siness g!Q\'Vth. We understand that~!tJ'~~~iJHY!:Ptb~des billing and customer service to THI and water and~~l1e'~w. b1ill~~rvices to customers of South Oxford County. The Town h~eady inve~~ co~i&erable funds in a new Harris billing system that enables it tO~ pio~pe these oiil.ung services. To date, there has been limited success in finding additionahf~;tomer~tfor these billing services. ··!1J1l' Retail Energy ,. Retailers provide electricity consumers with fixed price contracts for power for periods of up to five years. This provides consumers with much more certainty regarding their future electricity costs than prices set by the Ontario Power Authority under its Regulated Price Plan ("RPP"), whereby prices are reset every six months to capture changes in current market prices. While prices offered by retailers are generally fixed over a contract term, they also tend to be much higher than those available under the RPP. Existing electricity retailers are very large players that can mount large advertising campaigns. They typically rely on highly-motivated direct sales staff who are compensated by commission. They also need sophisticated risk management processes to hedge their fixed price contracts with appropriate sources of supply. None of the major retailers is affiliated with a distribution utility, which suggests that the synergies between the two business sectors are low. April 30, 2009 Page 35 C) ) to enter into the business, and that sufficient demand exists to support a business case. The economic viability and returns of any such ventures should also be carefully analysed and documented in a properly developed business plan. A summary of the advantages and disadvantages of the Expand I Diversify option is presented below: April30,2009 Page 37 )) \__ __ _ _) Expansion into new businesses may provide only limited benefits to customers, beyond the possibility that operating costs in the LDC may be reduced. The Town and THI should identify and codify their policy objectives (e.g. target rates of return) when pmsuing competitive business opportunities outside of the traditional LDC business. 5. Conclusions On balance, we do not consider the expand I diversification option to be a Feasible Option for TID to pursue on its own. This option does not address the key issue facing THI, which is its small relative size and, accordingly, a lack of economies of scale in addressing regulatory burdens and investment in billing systems etc. Furthermore, most power generation projects require a significant upfront capital investment as well as specialized technical skills. Till hasJimi~ financial resomces to participate meaningfully in larger projects, and ~·· have to hire specialized technical skills to operate these ventures. Significa.t¥frlsk1~ also exist in terms of generating a satisfactory rate of return on any ~v~stments '~ are made. Further details of the Green Energy Act may reduce ~~velof fmanci'li.f'~.k .. . ·f:L .. \_ ·=;.:.t.Jl. There is an opportunity for THI to partner ''otJler.,,suppliers:"in the delivery of certain programs, particularly local conservatiolhij#tiatives or the development of small-scale renewable power projects,,.THI's most'l~gical role is to act as a bridge between external suppliers and l~;tcop.sumers~'These smaller business opportunities are scalable and may pro~lde·lJ9tii:Cf.JP~,g.e:fit to the local customer base. There is some risk, howeve~,,,that even~~ liniij:ea role will be a distraction for management while leadin_g lli H~ited re~ on investment. .:·!·]\ H.-: .) . D. Merger Qptfct~,Ji:l;:itln:in;:•'f,. ,:ff{;!i1,Jj!4#. ·~:;i-4..-" Under this g@Qn, THI wo.H.!d ~I( ·another company, likely another Ontario LDC, with which it 'c6p,I~ merge' t~.s operations. The merger process would result in the Town of Tillson~,ownit;ig a percentage of the common shares of a larger LDC ("MergeCo"), and p~l,¥Y receiving some cash as well. The key advantage of a merger is the ability ~.9 'achieve cost synergies by sharing certain operating costs, capital expenditmes, rate filing application costs etc. and by spreading these costs over a larger customer base. The biggest disadvantage is the loss of some control over local electricity distribution operations within Tillsonburg. In order to maximize operational synergies, it is better for two merger candidates to be located close to one another geographically. Fmthermore, in order to have a meaningful ownership interest (i.e. 10% or greater) in the post-merger entity, the merger partners should be of somewhat similar size. For THI, the logical candidates for a merger would include the following proximate LDCs: • Brantford Power I Brant County Power (currently in merger discussions) • Erie Thames Powerlines • StThomas Energy • Woodstock Hydro Services April30, 2009 Page39 \_) ) • the impact on the Town's financial returns from MergeCo (via dividends etc.) • the impact on local economic development initiatives • the long-term objective of investment in MergeCo (e.g. sell in another 5 or 10 years, further mergers that dilute ownership percentage etc.) • the views and opinions of Town residents The most recent two-year Transfer Tax exemption period that ended in October 2008 resulted in a few LDC mergers. The largest merger was the merger of PowerStrearn (V augban, Markham, Richmond Hill) and Barrie Hydro. Another proposed merger between Horizon Utilities (Hamilton/St Catharines) with Guelph Hydro was aborted by the Town of Guelph in the late stages. In February 2009, B~tford Hydro and Brant County Hydro announced that they were exploring a merger of their operations. Other mergers may also be under review, but have not yet been publicly disclosed. .44-, ~ j:) A summary of the advantages and disadvantages of tht(~ger option are outlined in the table below: ·-4 .,1~, April30, 2009 t 1 • ifL J~~· ·:_u_~_ ··''~'1r~,~"' 1-f~--tr '·n1 ]T:,. \:;:!i:'lU·!Li:.,:.i:>' ;·~:itF :.;_;_ ') ~ Ji·: 1:' '· i·~~i~h ~;l ::t"" Page41 _) Some key transitional issues that will need to be addressed are as follows (these could be pros or cons, depending on the merger partner selected and the terms of the deal that is negotiated): • The impact of a merger on the Town's current staff complement and common operations (e.g. water and wastewater billings, fleet maintenance, space utilization). • The ability to include/exclude certain Town-owned assets used by Till (billing system, vehicles, rental water heaters, sentinel lights, fibre assets) in the merger transaction. This would impact on the total value received for Till in a merger transaction. • The extent of an ongoing local service presence in Tillsonburg. It is likely that only an ongoing field service presence (e.g. linemen, maintenance personnel) would remain in Tillsonburg; however, the extent of!,l, long-term presence of customer service and management personnel would q~d to be negotiated. The Town will need to protect its interests as a n®orliM '[shareholder in MergeCo through an appropriate shareholder's agreement. ,1 .~--1+ftr~. J'~·-··+ft:;r i' • 1. Conclusions J~!L },, " :~.d ::~:·· Our view is that the merger option is a Feasiti~ti.on. However, this option should only be considered pursuant tn!l>a,J~ng-temi''\fisipn or strategy for Till as it may be difficult to extract the Town frriq:tl~h¢11::~. arrangfment once it is entered into. ... -"l+Yrr·· The fact that the Town of Till~~nburg ~<lW~f'lik~j~lb~ a minority shareholder in any merger transaction signifi_saittly~~uces t:Ii~ attractiveness of this option. The Town would lose direct con~~:pver #'cisions iri;tpacting on local electricity distribution. Furthermore, it is lik:eiy ~tp~til~·HfLDC employees working and residing in Ti~sonburg, OV~f;itb.~:i!~R~~~· wbilld be reduced to direct field service and mamtenance ~onnel ~-. ·+ft1,,.' Conversely;"'t~··~erger ~~n db~s allow THI to better address its objective of sustainability by·~~g ~ regulatory and other operational costs over a greater number of customd:~ T~' should result in lower distribution rates for customers over the longer-term, ~clt is an objective of the THI. In theory, the level of service and reliability of electricity distribution within Tillsonburg should not decline under the merger option as the OEB sets various operational compliance levels that must be met by all LDCs. This is another key objective ofTHI. The Town's long-term objective of holding a minority equity position in MergeCo should also be considered carefully before entering into a merger transaction. The Town should establish the ultimate timing and exit strategy, if any, for its investment in shares of MergeCo prior to entering into a merger. Finally, it is imperative that the Town find a compatible merger partner with similar corporate values and visions. If the merger option is selected as the Strategic Option for Till, the merger process as outlined above should be started immediately due to the time limitations imposed by the October 16, 2009 expiry of the Transfer Tax holiday. Aprll30, 2009 Page43 ) In order to maximize operational synergies, it is better for the purchaser of an LDC to be located close to Tin geographically. For THI, the logical purchasers would include the following proximate LDCs: • Brantford Power I Brant County Power (currently in merger discussions) • Erie Thames Powerlines • StThomas Energy • Woodstock Hydro Services • Norfolk Power Distribution • Haldimand County Hydro • Hydro One (which services the rural areas around Tillsonburg) Other potentially acquisitive LDCs with cash resources mnLinclude Cambridge and North Dumfries Energy, Horizon Utilities and London Jixtlfu .. , ~ We have not investigated the prospects, financial co~~~~,or merits of a purchase of Till by any of the specific candidates listed a~.~~ Such,~[M_alysis is beyond the scope of this assignment. ./' . 'iih .. ,. The process of undertaking a divestiture ·~~~. in:¢iMe the f~Jrowing key steps, ·1;1-:··, ,,. amongst others: .: l: L r-:·1• • securing shareholder I Town of TifJ~~Jlfg appx~W~~Jo' pursue a divestiture; \: . ~.:::~.)~··... ; !'" • seeking out potential purchasers (vi~..a foihla~';91; jnf'onnal process); ' "; 1-. )·l· ~-::·(i! • negotiation of key b~mC.s~#rms wiijf prospective purchasers. Among the key issues to be negoti~ are':me pure~ ,price for shares, the continuation of a local service centreT~ofi!.~'-\~riT,_i_<::e,ptJfsence in Tillsonburg, the harmonization of distributiot;~·;:M~~s. ~~Sitidri'' of current THI-related employees and managellleJ!,-t{tlie' ~er ·dl;~_sr Town-owned hydro assets (e.g. fleet, billing systems ),;#le allocatidn\w traq'Saction-related costs, ongoing purchaser support of local ec<>noQ,ijc develop~nt lliitiatives etc.; ''%.. +~~ • determination'of! IJ!.e i¥lPact on local distribution rates, a review of potential synergies and di~ergies, a review of the impact on the Town's existing operations I employees; • drafting of various legal documentation (sale agreements etc.); • securing final shareholder I Town of Tillsonburg approval of the divestiture. Public meetings in Tillsonburg would likely be held to obtain public input prior to Town Council's decision. The Board of Directors and the municipal shareholder(s) of the prospective purchaser would also need to approve the proposed transaction; • preparation of a joint MADD application for the OEB; and, • final OEB approval of the transaction. The creation of a steering committee is often employed as an approach to drive the divestiture process on a orderly and timely basis. Key issues for the Board I the Town to consider would include: April 30, 2009 Page45 () ) returns, dividend payments, guaranteed exit prices etc. in order to protect its fmancial interests. (This may not be a significant disadvantage, since it may also help to protect the Town's ownership interest.) -~. ;~! lU.:} ·:!~;:.: April 30, 2009 ;~h ;;.;: :'7 ~.:Jll-r .. :? Page47 I () \.) ,-·· personnel and services pursuant to I theMSA. Some key transitional issues that will need to be addressed under the divestiture option are as follows: The impact of a sale on the Town's current staff complement and common operations (e.g. water and wastewater billings, fleet maintenance, space utilization). The ability to include/exclude certain Town-owned assets used by THI (billing system, vehicles, rental water heaters, sentinel lights, fibre assets) in the sale transaction. This would impact on the total proceeds received by the Town. The extent of an ongoing local service presence in Tillsonburg. It is likely that only an ongoing field service presence (e.g. linemep;;Wfuaintenance personnel) would remain in Tillsonburg; however, the exte~~ a long-term presence of customer service and management personnel wo~d n~4it9 be negotiated. ·-l . :.~;:·- ::;;·:! ·; '~·-' ::-·:: t 3. Estimated Fair Market Value o,f:iTHI ~,. '·+:rl~y·' . ··!'::£..4. A;_;·.·=:,. _;:- The fair market value of an LDC is driven by a iil!mber of factors. Among the more important factors are the dollar value.q{ an LDC'sl~,base, the OEB-approved rates of return on debt and equity, the wg\\ltp,;r~rospectJ~:hin an LDC's underlying service area, the physical condition of di,stri.H~J.VY~m assets, the extent to which an LDC's existing OEB-appro,ved distriby!J,on rn~'kchieve the maximum allowable rates of return, the comp_Jtlti~~ss of c~nt distribution rates vs. those of other LDCs, and the prospa;t$[~f geti~ing o~g synergies through an acquisition I merger. ·;;:::;, ~ii:r;:H1,,,_.,,;;.· Traditionally, aJo:ita·!2Q:1y~~~~.;~~ cash flow valuation model is prepared to assess the f~ market y~e 6f:tan LDC, complete with a review of various assumptioni~~pect of ~e gr~wth prospects, capital expenditure requirements, rates of return ~, THI ~anagement has not prepared any long-term financial projections; furthe~, t,Jiere is considerable uncertainty regarding the short-term financial prospects of litf due to uncertainty as to whether the OEB will approve the Company's current rate" application. For purposes of this report, we have estimated the fair market value of TID based on its financial statements for the year ended December 31, 2008. As a regulated utility, THI can only generate a rate of return on its rate base, and the ability to generate significant excess profits is severely restricted. The range of fair market values for LDCs generally falls in a band that reflects a premium to the underlying net book value of the rate base. In the table below, we have estimated the fair market value of the shares of THI to fall in the approximate range of $10 million to $12 million as at December 31, 2008. This represents a fair market value range of $1,510 to $1,812 per customer. A fair market value in this range is not unusual for smaller LDCs as their investment in capital assets, represented by net book value, is generally considerably lower on a per customer basis than it is for LDCs in larger municipalities. April30, 2009 Page49 } (} ) As an investment, the Town should weigh the value and benefits of the ownership of THI against the value of the economic returns that could be generated from the cash proceeds that the Town would receive from a sale of the Company. In prior years, the Town has not received any financial return from its investment in THI except for the 5% management fee on purchased services. However, the Town has budgeted the receipt of a $100,000 dividend from THI in calendar 2009. It should be noted that THI does not have a formal dividend policy in place in respect of future dividend payments to its shareholder. We understand that, if the OEB approves the current rate application, THI should be in a position to generate an after-tax return of approximately $532,000 in 2009. This represents an approximate 6.13% return on the Company's average rate base, which is approximated by the average net book value of shareholder's equity for the year. In the future, Till should be able to generate a similar rate of return on its rate base. We consider net income to be an appropriate measure of tq.e.~onomic or investment return of THI on a continued operational basis, as it pro~ the funding for dividend payments to the Town as well as for re-investment .. pr '@'Qwth-related opportunities (e.g. ~~w customers, new capital expenditures eW.-+h.~t incrt~the market value of the utility. "1F · · ;.i, , Conversely, a sale of THI should generate e~,J£ro~ of be~~n $10 million to $12 million. Assuming midpoint proceeds of ~H' million (and no Transfer Tax liability), the Town of Tillsonburg c9:uld use the8eir~sh funds instead of incurring future borrowings; We understand ~~p.~t long:~'fm' borrowings of the Town have been priced at an interest rate of aPpio~\Y.~.OO%. Alternatively, investing the cash proceeds from a sale. of THI ittpsk fC~i>'iO-year Government of Canada bonds would generate a1?Pfti*ftv-~tely $34p,ooo m interest income per annum (i.e. based on a 3.09% yield:.;3~ pf Ap1f!• 30, 2009). , · ... ,::.~J:>J ... !"F::;tu~:~rq·:·.·· ..... ~:~~ In conclusion, if $,~: qp,veni~ applldatfon is approved by the OEB along with its 30%+ increase,jtidiStrl~n ret.fuw~s, THI will be in a position to generate an after- tax return Qf~:proximailiJi+ $509;000 to $600,000 per annum. This return will fluctuate from y¢~ to year ~d may not be fully available to pay cash dividends to the Town. Alteniii~Ve.ly, if,'fin is sold for estimated net proceeds of $11 million, the Town could realize '~;t:i~l interest savings of approximately $550,000 per year, over time, by reducin!f'tuture Town borrowings, or a lower amount if the cash is simply invested in risk-free Government of Canada bonds. 5. Conclusions The sale option is clearly a Feasible Option and it results in the monetization of the Town's ownership interest in Till. Hence, it provides an immediate financial benefit to the Town. Furthermore, the Town would no longer be burdened by the financial risks and heada,ches of managing a complex regulated business. The Town must also consider the long-term direction of the Ontario LDC sector, and the Province's intention to support industry consolidation. Perhaps the selection of the divestiture option is simply a matter of timing -not now, but 5 or I 0 years into the future. The major disadvantages of the sale option are as follows: April 30, 2009 Page 51 \ ) _) v. Conclusions Compared to other LDCs in the immediate area, TID is the smallest in terms of customer base. Although its relative operating and financial performance has been satisfactory, its small size and lack of critical mass will make it difficult to continue that performance level into the future. Furthermore, it is likely that the Province will continue to pursue its policy direction of further LDC consolidation. Our analysis suggests the Base Case I Status Quo Option could be considered a Feasible Option, at least for the near term. We have some concerns over the long- run viability of operating Till on a stand-alone basis in the absence of entering into significant shared services arrangements. ..i..L_ Our analysis of the Expand I Diversify Option su~C(S~~· tilat Till does not have sufficient financial resources to acquire another local ~'! , We have inte1preted this option as the pursuit of new business opportunities i,at ~lated to the electricity sector. Our analysis suggests that this is not a ~-le Opti(j~r Till to pursue on its own due to the high investment in capi,W: costs-., the risk d£.lJiillited economic returns, and the possible need to hire technical' elP!'lrQ,seL · -~::·~ H:· Our analysis suggests that the Merg~r Option is ~ble Option. However, this option should only be considered pur~, to a long~~ vision or strategy for THl as it may be difficult to extract the ToWi;i, frdttiisuch an fuangement once it is entered into. .,. ,r··~;'~!ir' Our analysis suggests thl!!.{fiits* Optio~is a Fe~ble Option and it results in the monetization of the T6WP,~ s oW,hership i~terest in THI, providing an immediate financial benefit to the T6~p,.rTT11D.~V.J;~wfi would no longer be burdened by the financial risks an,~ netti¥!f.J,les''O~wanaging a complex regulated business. This option may be an outcome o:f'"tl~~LPro~'s intention to continue industry consolidation o=~nexi~~c~~· /' j~. April30, 2009 Page 53 I (} Attachment 3 \~) () · __ ) I lJJ c r ~ LL3·rr:_:,cc, 3e "' ------------------------------------------------------------------ Establishing right to connect for renewable energy projects on the transmission and distribution systems Implementing a smart power grid in Ontario, makiDgit easier to connect renewable energy generation to the system Fostering a culture of conservation by assisting consumers, government, schools and industry to transition to lower and more efficient energy use Establishing a streamlined approvals process, and provide service guarantees renewable energy projects Creating an attractive feed- in-tariff regime that will rates Setting procurement targets for domestic content by technology (currently under negotiation) f) 1 l 11g --: 11~ tn;:..,s~ Ue te" ------------------------------------------------------------------- Proposed Feed-in-Tariff Rates Technology SolarPV Rooftop Ground Mounted Proposed size ttanches :!>lOkW 10-lOOkW Proposed ¢/kWh 80.2 71.3 100-500 kW 63.5 > 500kW 53.9 :!>lOMW 44.3 Adjustments 9% price reduction triggered when 100 MW contracted As of March 12, 2009 09/04/2014 2 09/04/2014 (} ~ 1 J ;:--~ n c~ --.; . c r r 1 ,) :: ) p 1 c" ------------------------------------------------------ Feed-in-Tariff Contract Lengths Country Wind Hydro Biomass France 15 20 15 Gennany 20 20 20 Ontario 20 20 20 Portugal 12 12 Spain (2007)* >15 ),\:::~:;~~f, >:<1 ;_: .. ,:·· ·.'"·· "<. _-,::.:";:.··\':d >25 >20 Lo.oger contracts reduce the iDitial price 3 L: 1lcl1 ~ cJ E' U ~ 'i •: C ' -:: ~ • ,. ' ------------------------------------------------------ 4 09/04/2014 :),,rid r ;1 t'J3111"S': Jct.s· ---------------------- Tillsonburg's Value Proposition Can't -Suitable topography -Total of 352 acres (142 ha) available (only 4 owners) -No significant development -Just south of Hwy 3 -Competitively priced land -Strong local capabilities -Oxford is already home to one solar farm with more planned =• ,_I I ·~· I l q =~ 1_ 3 : 1 C ::_-, ~J J r, { ~ C I ---------------------- 6 ' ___ ) C>•IIC. ,,q UL.~I' 3 ,, :ldi :.:1 -------------------- ArntjenSolar Prqposal • Provided proposal for the Town of Tillsonburg that included the installation of 1 02 DEGER7000nt solar trackers on a portion of the Vanderhaeghe lands • Under proposed Bi11150, Municipalities and Electrical Utilities would be allowed to own and operate renewable energy generating facilities • These initiatives are eligible for Infrastructure Ontario loans 09/04/2014 8 i () ..... _ .. / \) . \ _ _) Attachment 4 ; I \ () \._) / \ -___j Table of Contents 1 INTRODUCfiON ...................•...•..................•..•.......•....................................•........•...•....•...........•••.. 1 2 VISION ..........................•...•..•...... , •..•...............................................•..•.....•.....•...............................•••. 2 3 MISSION STATEMENT ................................................................................................................... z 4 PRINCIPLES AND V ALUES ••••••••.•.•••••••••.••••••.•.•••••••••..••••••.••••••••••••••••••••••••••••••••••••••••••••••••••••••••••• 3 5 AREAS OF EFFORT •••••.••.••••••••••••.•.•• ~ ............................................................................................... 4 6 IMPLEMENTATION .•••.••.••••••••..•....••...........••.....••••.•••.••••••.••••••••••••.....•...•••••.......•.•....•...••.•...••.••• 10 6.1 llfPI.BIENTATION CHARTS """'"'"'""'"'"'""""""""""'"'""'""""""""""'"""'"""''""'""""""""'""""""""''""'"'10 8.2 S7RATEGIC PLA.N REviEw PRocEss .................................................................................. -............................................... 14 Tillsonburg Hydro Inc. STRATEGIC PLAN Table of Contents i ) (_) ") \ / 2 VISION A Vision is like a horizon. It is a point in the future that galvanizes the focus and energy of all stakeholders to move in the same direction. Like a horizon, it constantly moves, and as such, a vision needs to adapt to its environment but continues to provide a constant point of focus and direction. The following Vision was developed several years ago by THI and was affirmed at the 2009 Strategic Planning Workshop. To deliver professional, cost effective and environmentally responsible energy services to our stakeholders. Some of the key perspectives within the Vision are as follows: 3 • Professional, cost-effective and environmentally responsible -represents the three focal points that guide and direct the decisions of THI. Its programs, services and operations will be professionally delivered, be cost-effective in support of the customers and the shareholder, and will be environmentally responsible, both to the natural and the community environments of Tillsonburg. • Our stakeholders-as a public utility, THI serves 6,600 customers, has a single shareholder and is an integral member of the broader community, ranging from the benefits of community investment to supporting economic development. MISSION STATEMENT A Mission statement profiles to the reader, the essence and essentials of an organization, in terms of its focus and what it does. In application terms, every strategic and operational decision THI undertakes needs to be aligned with its Mission. If a decision comes before the Board of Directors or staff that is not aligned with the Mission, a question needs to be asked as to why a decision would be made that does not support or is consistent with the Mission Statement, or is it time for the Mission Statement to be re~ evaluated. The following Mission Statement was developed for THI and was affirmed with some amendments at the 2009 Strategic Planning Workshop. An innovative energy services company committed to maximizing value to Its customers and shareholders. lillsonburg Hydro Inc. STRATEGIC PLAN Page2 \ / (J The following Principles and Values were developed previously and have been affirmed with some formatting amendments at the Strategic Planning Workshop. • Satisfying customer energy needs with high quality, cost~ective products and service excellence; • Providing the shareholder with a reasonable return on investment relative to Its Investment in infrastructure and risk; • Creating an atmosphere for employees that promotes empowerment and commitment to the THI Vision. • Promoting safe and efficient practices in the supply, delivery and use of energy; • Supporting a cleaner and healthier environment through a proactive, positive approach to its environmental and conservation responsibilities. • Supporting initiatives that improve the social and economic well-being and enhance the quality of life in Tillsonburg; • Focusing on posHive outcomes and responsible leadership, responsiveness to customer needs and continuous improvement In all operational areas; • Compliance wHh our regulatory partners. 5 AREAS OF EFFORT Areas of Effort identify the strategic priorities and actions the organization will undertake over the next three years to achieve its Vision and Mission. Based on the results of the Environmental Scan Report, the KPMG study and the ongoing work of the Board Directors and management, four Areas of Effort have been identified to form the basis for moving THI forward progressively within the complex regulatory environment in which it operates. lillsonburg Hydro Inc. STRATEGIC PLAN Page4 (} • Undertake an internal governance development process involving: o Develop a governance model based on policy governance principles with a single employee directed by the Board. o Prepare a governance policy to direct the governance practices of the Board of Directors ofTHI; o Amend the current THI by-laws to ensure alignment between the governance policy and the by-laws; o Develop executive limitations to define the authorities to act for the General Manager with a policy governance approach; o Undertake deliberations with respect to Director term limits as a means to facilitate Board succession; o Pursue other governance policy additions and enhancements. Area of Effort No. 3 To undertake an organizational capacity analysis related to securing the senior management and administrative services needs of THI. aligned with the requirements that emerge from Area of Effort No. 1 -Strategic Business Plan. /-) \.~ Area of Effort No. 4 ,.. ) "-- To undertake a communications and branding strategy that focuses on: • A branding logo and core messaging strategy for THI; • An on-going communications program to customers, staff and the community; • Separated website and email addresses for THI; • Develop a community investment policy for THI related to monetary and non-monetary donations, gifts and related contributions to community organizations and causes. Tillsonburg Hydro Inc. STRATEGIC PLAN Page6 " \ .. ...-- Figure 2 Strategic Business Plan Process Inputs [ October 2009 to January 2010 J ( --'0 Business Plan Development Program and Service Opportunities Analysis Potentials and Risk Assessment Organizational Capacity Requirements Capital Cost Requirements Multi-Year Pro Forma Develop ROI and Other Performance Targets I Measures Implementation Plan Staging, Review Periods, etc. I Febru&IY and March 2010 ~ ,r--. '.-.__J~./ THI Board Decision Point Recommend to the THI Board • Proceed for one to two years, or • Initiate Merger and I or Sale or Lease of Assets investigations [ . Man:h I April 2010 I Tillsonburg Hydro Inc. STRATEBIC PLAN Page a __________ , ______________ . ---------------·-· -------------------· () \_) -__ ) Town and THI, with all employees being employees of the Town and the Town providing all administrative services. Some of the senior leadership of THI is at a 30% or less allocation level. Questions have emerged as to whether a full time strategic and operational leader is required, or whether other models may prevail that would support the growth and diversification strategy within the selected business model. What is apparent, is that the actual management and administrative services sourcing model cannot be fully identified until the Strategic Business Plan is developed and approved. Therefore, these two Areas of Effort are highly aligned. The organizational capacity consideration, which involves the management and administrative services considerations, needs to become a component of the overall Strategic Business Plan as it represents the capacity to implement that Business Plan. The fourth Area of Effort involves a communications and branding strategy for THI. This has been discussed for a period of time. At this point, the corporation has little self-identification in the community as it is totally engaged within the Town structure. Questions around a separate website and email addresses, logos on buildings and vehicles, communication strategies to stakeholders, and an overall branding plan involving a logo and core messages needs to be undertaken. This Area of Effort will also have to align with the selected business model as it will be in part, one of the implementation tools of what emerges from the Strategic Business Plan. 6 IMPLEMENTATION 6.1 IMPLEMENTATION CHARTS The following charts outline the implementation frameworks for the four Areas of Effort. They provide an overview of the responsibilities, timelines, integration, etc. The fundamental implementation strategy will be as follows: • The Board of Directors, meeting as Committee of the Whole will give direction and approvals in regards to the strategic business model, the organization capacity Area of Effort and the communications and branding initiative. All these materials and recommendations will be developed by management. • The governance Area of Effort will be undertaken by a sub-committee of the Board. It will undertake the research and develop recommendations that will be brought back to the Board for their consideration. Tillsonburg Hydro Inc. STRATEGIC PLAN Page 10 ( ' ~- OBJECTIVES Area Of EffOrt No; 2 2.1 Participate in the soon to emerge shareholder agreement 2.2 Undertake an internal governance development process Area of -E:fforfNo. 3 ··. -----··--·····-··--·-··-------- ( ~ -~ .. ' ~I '~~_/ Reporting Approval Priority Project Tasks Dates Requirements Ranking Lead/Team mm /dd /yr To undei'take.atw() le'lel.gbvemlar-ce Initiative; Board Chair 1. Review Draft Fall2009 Board 2. Recommend Content A Board 1. Committee Formed Fall2009 Board Chair Committee Chair 2. Develop Work January 201 o Committee Chair Program B 3. Research topics January to Committee Chair March 2010 4. Develop & Present April2010 Board Recommendations li§i:::;1£n:~~~~~i1~~····· B General Manager 1. Integrate with Area of I January I Board Effort 1 February 201 0 -------------···--····· ··········· Tillsonburg Hydro lnc. STRATEGIC PLAN Page 12 0 6.2 STRATEGIC PLAN REviEW PROCESS The following review format for the Strategic Plan is recommended for Board of Director implementation: • Quarterly, the General Manager should undertake a presentation for the Board on the progress being made for the Strategic Plan. This should include tasks completed, challenges that have emerged, key amendments in the implementation plan and other considerations. • Annually, the Board should assign a two hour block oftime to review the Strategic Plan, to recast the implementation plan in regards to dropping a year and adding a year in order to keep it dynamic and current. • Every three years, the Board of Directors should undertake a more comprehensive review of the Plan that could include an environmental scan and other activities to ensure the continuing alignment of the Strategic Plan with the evolution of the operating environment. lillsonburg Hydro Inc. STRATEGIC PLAN Page 14 () ~--) TILLSON BURG HYDRO INC. Board Governance Workshop Tuesday, February 9, 2010 Board Governance Workshop Agenda February 9, 2010 • Welcome and Introduction • Session Overview • Governance Areas of Effort and Framework • Governance Presentation • Governance Policy Framework Discussion o Principles D Roles o Polley Focus o Terms Limits 1:1 Other Components • Organization Leadership Models and Discussion • Next Steps • Recap • Adjournment 09/04/2014 1 0 r. Guiding Principles (Governance): • The Board Shall: o Supervise the management of the business and affairs of the Corporation; o Shall avoid any conflict of interest, act honestly and in good faith; o Initiate strategic improvement projects that will enhance the profile of the Corporation and the Town. • The Town Shall: o Encourage and support the Board and staff in their endeavours; o Receive a reasonable annual return on its investment in the form of a cash dividend (7.0 Dividend Policy). )\'):(,,:,··'' Business Activities: • Any business activities as may be permitted by the OEB Act, and as authorized by the Board: o Compliance with all applicable laws; o Operate in a manner that consider community values and to the extent possible Town practices and policy; o Act in a safe and environmentally responsible manner; I:l Employ commercially prudent business practices; o Have regard to the fact that the Town is a municipal corporation. 09/04/2014 3 n \~) ·~_) GOVERNANCE SCOPE • Principal means for establishing the direction setting and accountabilities for organized groups; • Determines how an organization assigns decision-making authority and accountabilities; • A concept applied to all sectors of society-private, non-profit and public. GOVERNANCE TOOLS Legal/ Statutory • Corporations Act: ~ Non-profit; ~ Non-profit I charitable. • Objects of Incorporation; • Constitution and By-laws; • Memorandum of Understanding and Direction 09/04/2014 5 _) BOARD ACCOUNTABILITY QUESTION • What is the accountability of a Board of Directors in governing an organization, related to tfle models and techniques that it uses: ).>. To define and direct what is to be achieved by the organization; )l> To ensure that these achievements I outcomes are being realized within regulatory and statutory requirements, sound fiscal practices, tile Shareholder's Agreement (MOUD) and the efficient use of available resources. GOVERNANCE POLICY • Governance Policy and Executive Limitations -Represents the collective processes, procedures and practices the Board of Directors utilizes to govern; • A Board Policy - A statement by the Board that directs the General Manager as to the Board's intents; and the outcomes and monitoring that the Board wishes achieved on a specific topic. • Operational Procedures -Represents the collective plans, strategies and actions of the General Manager used to implement the Board's approved policies directions and priorities. 09/04/2014 7 () ,_) !':. FROM BY-LAW GOVERNANCE TO A GOVERNANCE POLICY • Ability of a Board to outline more comprehensively its governance requirements and practices; • Develops a more direct and focused accountability framework for the Board of Directors and for the General Manager . BOARD EVALUTAION OF CURRENT GOVERNANCE MODEL • What are the strengths of the current governance model? • What are the concerns, issues, weaknesses of the current governance model? • What do you think, using examples, is a • Board decision? • Management decision? 09/04/2014 9 ~-) 1 • GOVERNANCE POLICY DISCUSSION POINTS • Principles and Model • Committee Structure • Agenda structure and focus -strategic or operational • Term Limits • Other Considerations Option A Board of Directors General Manager I Contracted Part Time I I H Board Support Contracted Operations Contracted Support lead and Customer Services H Strateclc PlannJne Laad I I ~ Operations and Delivery Plllnnillll Contnn:ti!CI Staff Contracted Staff u Regulatory Affairs 09/04/2014 J J _I I 11 I (). Attachment 6 . \ ',,,./ ( '-._..- Elecsar Engln••rlnB ca. Ud. P.._oollly: D. lilooh,P.Iing. Step 1 Review Praposal .r- '0 Desc:rlptlon Tlllaonburg Hrdro Inc. Estimate for Revised Scope of Work for Hydraulic Power on Big Otter Creek Project I Senior I Drafting I Manager Engineer Oilier I Pollutach (lml) (hra) (lml) Olhar Coats Dlsburumanta --oil obiioi-;;·e.;;;~""on;;;.lriiir.:.:s;ii ott;;; creek & .. -.. J . a .. :_~ ~=~[et~=~~t~~~::~:r-.:~: 40 80 4o 100 ... :· .. ·::··1~;;;.~·:·"- Cost par Phase Totall 32 160 0 1 OD I S800 I I $42,812 I Step 41Evaluate Lalla Usgar Mlcroproject I I Slep siFinanclal Modeling and Business Plan II S1ep& 118port and Prase-'!'~---- a) Draft Report b) Presentation l'nljact Manager Senior Engineering Dialling I Other Pollu\ech Other Costs Contingency IC•natata'!illtl ...... : 2010Prklea ------ Aa af Ju!y 10.2010 HSTwlll~~pptwo l...llbGUr priDed tar normal hours ltlls eatlmale wild tgr3D diNS fram dille CJf iiiW Meanburg Edmdltft 1.».8 ................ ---·-·-·------· I 40 Totall 0 40 0 I Total 0 o I 0 16 40 40 __ 16 16 Total 32. S& 40 Tolal Estlmat.o 96 @ 344 @ 40 @ 116 @ SubtDtal Tolal Etitlmaled Cost Holel, Food & T"'""""rtatlan 0 $0 Sli.72ol $10,000 0 $10,000 $11,0001 ___ ,., _ _ , ______ ----------· ---;;e-·--.:zoo .. -1TI1>.400km@$0.60 115 $21111 $18 348 $95,866 $135 $12,960 $130 $44,720 $70 $2,800 $130 $15,060 $75.560 $12,600 $88,060 10% $6806 lTIIPI , .... .~, ; j ~ -...._./ March 15, 201C Rev.1 31tii201G DATE: TO: FROM: SUBJECT: Report April 8, 20 10 Board of Directors-Tillsonburg Hydro Inc. S. T.Lund, P.Eng., General Manager Hydraulic Turbine Feasibility-Summary of Engineering Couultant Costs RECOMMENDATION: REPORT NO: TBI 2010-01 That ''Report THI 2010-01 from the General Manager dated April 8th, 2010 be received as information." PURPOSE To report back to the board on engineering costs to date regarding the Hydraulic feasibility of Lake Lisgar and the . ~--) Big Otter as part of the strategic plan focused on Growth/Diversification. \____, ·-. ___,. ) IDS TORY The Tillsonburg Hydro Inc. Board of Directors approved at the December 15th, 2009 board meeting the following resolution: 8. Renewable Enemy Options Feasibility Review Presented By: General Manager S.Lund reported. When the Chair, F. lewis and S.Lund met, they also reviewed the proposal from Elecsar. The price has been reduced from $29,000 to $27,000. They came up with a list of exclusions and responses. B.Sibbick noted concerns with associated noise being an issue with neighbours in that area, and a potential OMB hearing. flow. S.Lund to get some preliminary information regarding noise, etc. B.Sibbick also asked if there are ways to generate more water in Lake lisgar, to increase the CORPORATE OFFICE 10 Lisgar Avenue, Tillsonburg, Ontario, N4G 5A5, Telephone# (519) 842-9200, Fax# (519) 842-9431 Web: www.tillsonburg.ca \ } C) ... ..._ .. ~ ) \ __ ) ,) Attachment 8 \ N 0 N } 0 \) __ ) Confidential Report DATE; September lOth. 201 0 TO: Board ofDireetors-TiUsonburg Hydro Inc. FROM: S.T .Lund, P .Eng.. General Manager SUBJECT: Strategis; Bwsinep Plan-Update REPORT NO: THI 1018-81 RECOMMENDATION: That "Report Tllll010-01 from the General.Moager dated September lOth, 2010 be received"; And further that "the proposal eontllined thereio be implemented." PURPOSE To report back to the board on all update of the TIII Strategic PJan. HISTQRY The Tillsonbw-g Hydro Inc. Board reviewed report THI2009-0 l from the General Manager at their September 2009 board meeting regarding the Strategic Business Plan prepared by F J.Galloway and Associates dated July 20, 2009 which identified four areas of effort as follows: I. Pursue a Strategic Business Model focused on Alternative No. 2 -Growth Diversification 2. Undertake a two-level governance initiative (Shareholder Agreement/Document). 3. Organizational Capacity Analysis to meet requirements of Area of Effort No.1. 4. Undertake a Communications and Br~ding Strategy. DISCUSSION Area of effort No. 1-Strategie Bllliness Model-Growth Diverslflgtlon requires the following; The General Manager reported back to the Board the results from the Growth Diversification RFP at the March 2010 board meeting. The Tin Steering committee had decided rather than doing a general report on renewable energy options. the Lake Lisgar/ Big Otter Creek hydraulic turbine feasibility study would be more worthwhile exploring due to smaller associated costs to implement. The Elecsar Engineering proposal from Samia was reviewed at the boards March 2010 board meeting, however, this issue was tabled as more information was requested. CORPORATE OFFICE 10 Lisgar Avenue, Tillsonburg. Ontario, N4G SAS, Telephone# (519) 842-9200, Fax# (519) 842-9431 Web: www.tillsonburg.ca \_) ) Area ofEft'ort No.4 w Undertake a Communieations and Branding Strategy. This area has been proceeding all year. Red Bam Design group has been retained to assist and develop the following; · 1. Development of.Corporate Identity-Research name development supporting the mandate ofTHJ. 2. Focus Group Session with staff and Rate groups -this will provide staff and customers to assess name options and provide valuable feedback in the decision making process. 3. Corporate Value Statement Development-Creation of a tag line and value statement that defines corporate identity and informs public awareness. 2 weeks. 4. Logo Design -creation of the visual elements of the selected corporate identity supporting mandate of THI.I-includes producin& supplying logo in various file formats along with brand standards guide. 4 Weeks. 5. Stationary package and internal signage -Creation of standard stationary package including internal signage from the customer service centre. 2 weeks. Flye Year Financial and Capital Plan In addition to the strategic plan. we continue to progress on our voltage conversion program over the next 1 0 years to eliminate the remaining 3 municipal substations which in turn reduce line loss and distribution costs. This wotk is being carried out as a result of the due diligence study report prepared by Elecsar Engineering in 1999 for the commission. Typically we spend in the $S-600k range on voltage conversion program annually. So far we have saved in the range of$300k per year due to reduced line and transformer losses. Our smart metering project is on track for full implementation of time of use rates in July 2011. The smart meters are expected to be installed by year end 2010 and system testing scheduled for the first half of20 11. Next StePS 1. Assemble the StraiEgic Plan subcommittee to review the next steps for the renewable energy study. 2. Prepare an Energy Feasibility report that can be reviewed by a subcommittee of Tin to consist of the President, GM, Chair and Vice-Chair and a director for January 31 •t, 2011. 3. Prepare a Strategic Business Plan to be presented that can be used move Alternative No.2 forward for the March 2011 board meeting. 4. Continue to proceed with the governance committee to review and prepare bylaw lA for Board approval with a report back for the November 2010 board meeting. S. Continue with the Branding Subcommittee work expected to take 4 months total with reports back as each step completed. CORPORATE OFFICE 10 Lisgar Avemue, Tillsonburg. Ontario, N40 5A5, Telephone# (519) 842-9200, Pax# (519) 842-9431 Web: www.tillsonburg.ca ) 0 _) Marwood Metal Fabrication 1 0 KW Solar Projects All Three Projects Went On Line August 7,2010 •Installation ••• •••• ••••• •••• ••••• •••• •••• • • ••• •••• ••••• •••• ••••«~ ••• @ ••so @ 0 • The installations were managed through N//ERGY Solutions. • The panels and racking were constructed on the roofs by Grassmere Construction. • The Electrical installation was completed by Marwood. • The projects took 4 weeks to complete. 09/04/2014 1 0 35 Town line Road \ __ ) 101 Townline Road : __ _) ••• •••• ••••• •••• ••••o •••• ••se ••• •••• ••••• •••• ••••e •••• ••• 0 e G 09/04/2014 I I 3 \ J () \__) KW Produced Per Month 35 Townline Rd. Aug. amounts are 75% July amounts are 25o/o 1600------------------------ 1400~----------------------- 120n~---------------- 1000 400 200 0 Aug./10 Nov./10 Feb./11 May./11 Revenue per Month 35 Townline Rd. Aug. amounts are 75% July amounts are 25% 1800~---------------------=~~ 1400~------------------------~ 1200~--------------------~--~ 1000~~=-~~-=~~~=-~~--~ 800 600 400 200 0 Aug./10 Nov./10 Feb./11 May./11 ••• •••• ••••• •••• • •••• ... ., ••• 4!1 0 0 ••• •••• ••••• • ••• •••• 0 •••• •••o 0 $ llil Rev. $ Iii Target 09/0412014 5 () '~_) , _ _) Solar Issues/Problems ••• •••• ••••• •••• ••••• •••o •••e e e • One day we had a bad wind storm and at 1 01 Town line Rd. six panels were broken. • The same storm one of the clamps moved causing a row of panels to lay down at 35 Townline Rd. • Working with EI/NERGY and Canadian Solar we had new panels within a few days and were back up and running. Broken Panels ••• •••• ••••• •••• •••• (j) •••• •••eo • El 09/04/2014 7 \ ) 0 \ __ ) ~--_) 09/04/2014 9 (] '·~ ... _J • Thank-you • Questions -__ ) ••• •••• ••••• •••• ••••e •••~t ••o& • 0 09/04/2014 11 (-\ \ ) DATE: TO: FROM: SUBJECT: Report Board of Directors-Tillsonburg Hydro Inc. S.T.Lund, P.Eng., General Manager Roof Top Solar FIT Application-Town Facilities RECOMMENDATION: REPORT NO: THI 2011-03 That "Report THI 2011-03 from the General Manager dated June 15th, 1011 be received as information." PURPOSE To update the Till board with regards to a potential Growth Strategy opportunity related to the OPA FIT program \~~) and the Town ofTillsonburg. ,_.) HISTORY The Till Strategic Plan Area of Opportunity Number 2 -Growth Strategy is a business plan item for 2011. As outlined in the General Managers previous reports. Staff is currently reviewing opportunities under the FIT program and the THI corporate structure (i.e. holding company overseeing Wires Co. and Generation Co.). DISCUSSION The President and General Manager have been in discussions with the Town Economic Development Commissioner and assisting in the review of the Towns roof top solar RFP that closed recently. As a result of that review it is apparent that a growth opportunity for Till could exist with a ROI in the range of 5-10%. Staff is currently exploring the advantages of Till becoming involved in a Build/Own/Operate roof top solar project that the town has recently applied for a 20 year solar FIT contract (capacity allocation exempt). Higher rates of return will be realized if the estimated 2.8M capital costs of the proposed roof top solar installations on town facilities are up fronted vs. leasing. This could ultimately involve Till assuming the OPA contract and solar infrastructure provide a solid business case can be developed. Staff will be working on preparing a business case for the board to review, subject to receiving a FIT contract offer, for presentation to the board in the near future. CORPORATE OFFICE 10 Lisgar Avenue, Tillsonburg, Ontario, N4G 5A5, Telephone# (519) 842-9200, Fax# (519) 842-9431 Web: www.tillsonburg.ca \ j DATE: TO: FROM: SUBJECT: Tillson burg Hydro Inc. Report July 12thth, 2011 Board of Directors -Tillsonburg Hydro Inc. S.T.Lund, P.Eng., General Manager RoofTop Solar FIT Application-Town Facilities-Business Plan Review REPORT NO: THI 2011-04 RECOMMENDATION: That "Report TID 2011-04 from the General Manager dated July 12th, 2011 be received as information." And further that " the board approve the roof top solar project be pursued with the Town on the basis a 50% debenture and 50% cash contribution with Tm being the owner of the solar installation." \_ __ ) PURPOSE To update the THI board with regards to business plan models related to the solar roof top Growth Strategy opportunity related to the OPA FIT program and the Town of Tillsonburg. HISTORY The THl Strategic Plan Area of Opportunity Number 2 -Growth Strategy is a business plan item for 2011. As outlined in the General Managers previous reports. Staff is currently reviewing opportunities under the FIT program and the Till corporate structure (i.e. holding company overseeing Wires Co. and Generation Co.). Report THI2011-03 was presented to the board at the June2011 meeting and a follow business plan regarding a potential FIT contract for solar roof top was discussed. DISCUSSION The project is defined as 513MW of rooftop solar panels to be placed on the Tillsonburg Community Centre, Customer Service Centre, Special Event Centre, Librruy and Public Works buildings. Project revenue must be secured from the Ontario Power Authority (OPA) via the MicroFIT and FIT programs. The projected capital cost is $2.68M for the project excluding maintenance (approx. $25,000 EST.). The President, General Manager and Treasurer have met to explore various financing and tax implications of the proposed $2.68M solar roof top FIT project. Options include borrowing from Infrastructure Ontario the proposed capital funds in the amounts of 0, 50%, 75% and 100% the project. The assumed borrowing rate is 4.09%.The after tax scenarios were also reviewed for the same borrowing scenarios. CORPORATE OFFICE 10 Lisgar Avenue, Tillsonburg, Ontario, N4G 5A5, Telephone# (519) 842-9200, Fax# (519) 842-9431 Web: www.tillsonburg.ca \ I Development and Communication Services 2011 (-\ __________________________ ...._ __ _ \. 1 ,) DCS 12-01 Report -Additional Information on Solar Investment Opportunity DATE: JANUARY 9, 2011 TO: KELLEY COULTER, CAO FROM: STEVE LUND, GENERAL MANAGER CEPHAS PANSCHOW, DEVELOPMENT COMMISSIONER '· SUBJECT: ADDITIONAL INFORMATION ON SOLAR INVESTMENT OPPORTUNITY RECOMMENDATION ""That the Town of Tillsonburg agree in principal to allowing the placement of two microFIT solar systems purchased by Tillsonburg Hydro Inc on the 18 Spruce St and 1 Library Lane municipal properties subject to entering into a Memorandum Of Understanding with Tillsonurg Hydro Inc at a later date; That staff be authorized to enter into microFIT contract with the Ontario Power Authority to enable connection to the hydro electricity grid; and, That bylaws be brought forward in this regard at the next meeting of Council" PURPOSE 1. The purpose of this report is to provide Council with the additional information provided to the Tillsonburg Hydro Inc (THI) Board of Directors and to seek approval for the Town of Tillsonburg enter into a Memorandum of Understanding with TIIIsonburg Hydro Inc enabling the purchase of two solar systems by THI for installation on two municipally owned rooftops. \ I Development and Communication Services 2011 7. In terms of question four, staff have revised the four quotations received for the purchase of solar systems such that the installed DC capacity is the approximately the same for each project, I.e. all projects are between 512 to 513.5 KW DC: ARISE Tech Bright Power Sol cap Soler a Energy/KW Energies Power Logic Location Waterloo Toronto Tillsonbu rg/Brussels Toronto Established 1996 2009 2008 1985 Years Solar 15 2 10 20 Experience Installed Capacity 512.4 KW 513.5 KW 512.6 513 (DC} Installed Capacity 450 KW 450 KW 450 KW 450KW (AC} Average 629,289 629,450 540,000 551,347 Energy /Year( KWH) Panel Efficiency 15.8% N/A 14.2% N/A Weight of 3.5 to 10 3.3 4 3-5 system(lbs/SF) Total Cost $2,072,209 $2 695 744 $2 419 850 $2,293,110 Cost/Watt (DC) $4.04 $5;25 $4.72 $4.47 Total Revenue $8,585,849 $9,02 7,_6666 $7 050 162 $7 920,645 Net Revenue $6,513,640 $6 331 922 $4 630 312 $5,627,535 Simple Payback 4.83 5.97 6.86 5.79 (years) Annual Average $429,292 $451,383 $352,508 $396,032 Revenue Gross ROI _(Simple]_ 20.7% 16.7% 14.6% 17.3% *ROI calculation is not net present value, but rather, a simple cash on cash calculation () \_ ____ --- ,_) Development and Communication Services 2011 12.Upon first review it appeared that the Town must own both the solar system and the Ontario Power Authority contract In order to comply with this rule change. Staff have investigated this further and have been advised by a number of solar installers, including Solera Energies, that the Town can continue to own the contract, but THI would own the solar system capital equipment. 13.Under this scenario, THI would pay for the solar system purchase and installation directly and then enter into a Memorandum of Understanding with the Town of Tlllsonburg that enables them to place the systems on the Town's properties. The Town would agree to provide the use of the rooftops free of charge possibly in exchange for future dividend payments. 14.Revenue payments from the Ontario Power Authority can be designated to go into any account by the owner of the contract, which in this case is the Town of Tlllsonburg. THI would then receive all the revenue generated by the systems. 15.Staff are recommending that we proceed under this scenario and that the Memorandum of Understanding and the contract with the Ontario Power Authority be brought back at the January 23, 2012 meeting for review and approval. 16.Based on the continued strong showing of Solera, staff are maintaining their recommendation to select Solera Energies as the systems Integrator for the two microFIT projects. FINANCIAL IMPACT /FUNDING SOURCE 17.The projects would be funded by THI in 2012. ALTERNATIVES 18.There are two alternatives to the recommended motion: a. The Town could borrow the funds from THI in order to finance the long term ownership of the solar systems Internal Rate of Return (IRR) i. Although this would generate revenue for the Town of Tlllsonburg (through revenue) and THI (interest payments), staff are not recommending this course of action as the interest payments to THI and other related costs result in a IRR that is close to or Jess than zero (see revised IRR calculations below) ARISE Tech Bright Power Solcap Solera Energy/KW Energies Power Logic -1.7% 0.3% <0 -0.4% Attachment 13 , __ ) \ J 0 The results were analyzed and was determined the Internal Rate of Return (IRR) for borrowing to the 75% and 100% capital amounts were greater than the FIT contract term of 20 years and were not considered further in the business planning exercise. The 500/o borrow before tax scenario of the capital cost of2.68 million will generate an IRR of0.08 and a Return on investment (ROI) of 1.14 or $3.069M. The after tax considemtions reduce the IRR to 0.03 with a ROI of0.39 or $1.048M. While TID is not in a position to fully the project the base case was reviewed or comparison purposes. A fully up front funded project with no borrowing costs will generate and IRR of0.12 or ROI of 1.67 or $4.465M. The after tax consideration results in an IRR of0.07 and a ROI of0.90 or $2.429M. Given our current cash flow requirements we recommend funding no more than 50% of the capital costs. Assumptions -The preceding business case is subject to receiving a FIT /MicroFIT contmct(s) offer from the OP A and a review of tax implications by our tax accountant Rick Scrimgeour. CORPORATE OFFICE 10 Lisgar Avenue, Tillsonburg, Ontario, N4G 5A5, Telephone# (519) 842-9200, Fax# (519) 842-9431 Web: www.tillsonburg.ca 0 I. Governing Authority Legality 1111sonburg Hydro Inc. {llii) Investma1t Policy The investment program shall be operated in conformance with federal, provincial, and other legal requirements. THI is regulated by the Ontario Energy Board (OEB). Given that THI provides a service to customers and that THI is fully accountable to the OEB and rate payers in any and all decisions it makes, it is expected that a prudent, careful, due diligent and limited risk tolerance approach be followed by THI. II. Scope This policy applies to the Investment of all surplus funds. 1. Pooling of Funds THI will consolidate surplus cash balances to maximize investment earnings and to Increase effidencles with regard to investment pridng, safekeeping and administration. III. General Objectives The primary objectives, in priority order, of investrnent activities shall be safety, liquidity, and yield: 1. Safety Safety of principal is the foremost objective of the investment program. Investments shall be undertaken in a manner that seeks to ensure the preservation of capital in the overall portfolio. The objective will be to mitigate credit risk and interest rate risk. a. Credit Risk THI will minimize credit risk, which is the risk of loss due to the failure of the security issuer or backer, by: • Umlting Investments to GIC's, Certificates of Deposit and other nominal risk investments. • Pre-qualifying the financial institutions and any other broker/dealers, intermediaries, and advisers with which THI will do business. b. Interest Rate Risk THI will minimize interest rate risk, which is the risk that the market value of securities In the portfolio will fall due to changes in market interest rates, by: • Structuring the investments so that they mature to meet cash requirements for ongoing operations, thereby avoiding the need to sell investments on the open market prior to maturity • Investing operating funds primarily In shorter-term securities, interest bearing bank account, money market mutual funds, or similar investment pools. 2. Uquidlty Investments shall remain suffidently liquid to meet all operating requirements that may be reasonably anticipated. The current monthly cash flow requirement pertaining to IESO is approximately $1.5 million which must be maintained, at a minimum, to meet the monthly IESO obligation. 0 __ ) V. Authorized Financial Institutions 1. Authorized Rnancial Institutions A list will be maintained of financial Institutions authorized to provide investment services. That list currently is TO Canada Trust and can be changed or updated with Board approval. VI. Safekeeping and Custody 1. Delivery vs. Payment All trades of marketable securities will be executed by delivery vs. payment to ensure that securities are deposited in an eligible financial institution prior to the release of funds. 2. Safekeeping Securities will be held by an independent third-party custodian selected by the entity as evidenced by safekeeping receipts in THI's name. 3. Internal Controls The investment officer shall establish a system of internal controls. The internal controls shall be reviewed by the independent auditor. The controls shall be designed to prevent the loss of funds arising from fraud, employee error, misrepresentation by third parties, unantidpated changes in financial markets, or imprudent actions by employees and officers. VII. Suitable and Authorized Investments 1. InvesbnentTypes The following investments will be permitted by this policy: • Treasury obligations which carry the full faith and credit guarantee of the Canadian government and are considered to be the most secure instruments available; • Certificates of deposit and other evidences of deposit at financial institutions, including THI's current bank account, • Bankers' acceptances; • Money market mutual funds whose portfolios consist only of dollar-denominated securities. VIII. Investment Parameters 1. Diversification It is the policy of THI to diversify its invesbnent portfolios. To eliminate risk of loss resulting from the over-concentration of assets In a specific maturity, issuer, or dass of securities, all cash and cash equivalent assets in all funds shall be diversified by maturity, issuer, and class of security. The following diversification limitations shall be imposed on the portfolio: • Maturity: No more than SO percent of the portfolio may be invested beyond 12 months. • Default risk: No more than SO percent of the overall portfolio may be invested in the securities of a single issuer, except for securities of the Canadian Treasury. No more than 100 percent of the portfolio may be invested in each of the following categories of securities: a) Commercial paper, b) Negotiable certificates of deposit, c) Bankers' acceptances, d) Any other obligation that does not bear the full faith and credit of the ' ; CJ Attachment 14 0 Development and Communication Services 2011 3. With respect to the first question, the following is a comparison of a lease versus a purchase transaction for all five municipal properties using the figures provided by Sclera Energies: Lease Purchase Revenue $1108,890 $7,920,645 Cost 0* $2,293 110* Net Revenue (20 years} $1,108,890 $5,627,535 Net Revenue/Year $55 445 $281,377 *Note: Any structural costs would be the same for either scenario so they are not rncluded for ease of comparison 4. With respect to written confirmation by the solar company that they can complete and connect the project by the February 26, 2012 deadline, Sclera Energies has indicated that they are willing to provide confirmation in writing that they can complete the project by the deadline assuming they are given the green light right away and there are no major structural issues with the rooftops. 5. With respect to written confirmation that the price quoted includes an engineering report on the structural integrity of the rooftops, Sclera Energies has confirmed that this engineering report is included in their price. 6. In terms of rooftop replacement, the Operating & Maintenance includes moving small sections of an array if a roof leak needs to be addressed. However, the complete removal of an array is not included and could be negotiated on a time and materials basis. _) Development and Communication Services 2011 8. The below table summarizes the costs to purchase two 10 KW (AC) systems from the four companies: ARISE Bright Power Sol cap Solera Energy/KW Energies Power Logic Installed Capacity 25 25.85 25.85 25.85 (DC) Installed Capacity 20 20 20 20 (AC) Average 30,605 29/050 24,000 28,788 Energy /Year(KWH) Total Cost* $142,540 $135,712.5 $134,000 $144 760 Cost/Watt (DC) $5.70 $5.25 $5.18 $5.60 Total Revenue $449,085 $465,962 $360,404 . $461 767 Net Revenue $306,545 $330,250 $226,404 $317,007 Annual Average $22,454 $23/298 $18,020 $23,088 Revenue Simple Payback 6.35 5.83 7.4 6.27 (years) Gross ROI (Simple) 15.8% 17.2% 13% 15.9% 9. The Internal Rate of Return for these projects has been revised to reflect updated tax treatment of the project: ARISE Tech Bright Power So leap Sol era Energy/KW Energies Power Logic Internal Rate 7.1% 8.2% 3.9% 8.2% of Return (IRR) IRR-After 5.8% 6.8% 3.0% 6.8% Taxes lO.Based on the continued strong showing of Solera, staff are maintaining their recommendation to select Sclera Energies as the systems integrator for the two microfiT projects. FINANCIAL IMPACT /FUNDING SOURCE U.The projects would be funded by THI in 2012. ) (J Attachment 15 i \ ' f j - ) Table 2: Sale/Merger Comparators LDC Comparators Customers Shareholder Per Market Price Per Market Equity Customer Customer Premium Clinton 1,639 $492,000 $300 Dutton 586 $243,072 $415 $311,000 $531 28% Terrace Bay 938 $802,566 $855 $1,000,000 $1,066 25% West Perth 2,049 $1,471,093 $718 $3,200,000 $1,562 117% West Nipissing 3,101 -$42,469 -$14 $2,000,000 $645 n/a Wellington Electric 1,657 $331,163 $200 Middlesex Power 7,859 $4,691,742 $597 $9,100,000 $1,158 194% Callus Power 15,553 $10,781,975 $694 $29,000,000 $1,864 269% Aurora Hydro 16,039 $16,041,328 $1,000 $35,000,000 $2,182 218% Barrie Power 69,628 $60,466,613 $868 $111,166,613 $1,596 184% Toronto Hydro 700,368 $893,496,884 $1,275 $1,080,000,000 $1,542 Tillsonburg Hydro F/S Dec. 31, 2010 6,729 $8,788,856 $1,306 * Coli us Merger-Based on 50% sale of shares valued at $14.5M and price to be confirmed ** Barrie Power Merger-Assume Equity sale plus $25 Dividend plus 25. 7M hike in dividends over 10 years *** Toronto Hydro-Based on Proposed 10% sale of Toronto Hydro Scenario Assumptions: No. Customers and Shareholder Equity based on OEB information prior to sale/merger, Merger sale price based on google reports, newspaper articles and LDC reports. Table 2 is a chart of an analysis completed by the General Manager of recent sales and mergers in the sector. The LDCs selected give the board a survey of the market and the market conditions. For added convenience, the current book value of shareholder equity for THI, as of December 31, 2010 is highlighted at the bottom of Table 2. Table 2 demonstrates that the market rate per customer has fluctuated materially from a low of $531 to a high of $2,182 per customer. In reflecting on Table 1 and Table 2, the value ofTHI ranges from $8,788,856 (no premium on the asset base) to a high of $12,806,802. On a per customer basis the value is from $1,306 to $1 ,903 per customer. In addition, a transfer tax holiday for the shareholder continues to remain in force for municipal electricity property. Further, a number of the Shareholder activities are intertwined with the THI Corporation. Although operations are distinct and separate, should the asset be merged or sold, a number of operating costs would hit the taxation levy. The best sale/merger option would involve a complete acceptance ofTHI staff complement or a partial sale where the Town continues to provide services under the MSA. The potential financial impact of this risk would average $100,000 per employee for approximately 12 direct employees. A compensating factor would be the sale of equipment held by the shareholder in the execution of the Master Servicing Agreement. 200 Broadway, Tillsonburg, Ontario, N4G 5A7, Telephone# (519) 842-6428, Fax# (519) 842-9431 Web: www.town.tillsonburg.on .. ca 21% \ ) (} \ __ ) 1 , _ _/ Exhibit IV-6 Calculation of the Market Value of THI l!stfmall!d loiMbt Value of Tlllnnburg Hydro All at December 31, 2006 (lOOO's) Low Hill!! Mi!!Jl!!lnt Fbad asse1s, net $ 5,608 5,608 Allowance !of~ capital ~.§H g&§!! Asaet rate base 8,291 8,297 Muliple 1.20 1.40 &,956 11,616 Addltlonalassals (iabllllies) 122 122 Estimated llllllllet value (Nates 1 $ 1!!,078 11,738 10,808 Eelimatsd markehalue (rounded) 10,000 12.000 11,000 Numb8f of CUSI01118lll 6,!!gg 6,622 §.622 Market vaU. par custrlmer ($'&) $ 1,!!10 1,§12 1,661 NGie 1: Sane addilicnalvalue Ia avaiable in certain LOC-relaled assets owned by tte Town of Tlisonbur1j and chaqjed baol< to THI. ThtG lnorementalv'*"' inclldes whlcles, compu1er and olfice aqulpment, and bUillg •1'818m•· The estimated value for Tm as presented above is generally consistent with the market values that have been paid for similar-sized Ontario lDCs with comparable balance sheets, customer levels and operations. h should be noted that the lack of long-term debt in Till is captured within the value of its sh&res. It should be noted that the calculated valuation range for rm assumes !bat tbe OED will approve a considerable portion of the distribution rate increase requested in its pending rate application, or that a prospective buyer will be able to re-apply for new distribution rates following an acquisition of Tin. Proceeds in addition to the range estimated above could be realized if certain Town- owned assets used by Tin (e.g. the billing system, vehicles, minor equipment, rental water heaters, sentinel lights, fibre assets) are also included in the sale transaction. 4. Economic Analysts of Rates of Retum From the Town's perspective, Tm represents a municipally-owned asset or investment that should provide the Town and its residents wilh a tangible return -be it a financial return (e.g. annual dividends), the benefit of enhanced local economic development, reduced. electricity rates, or opportunities for local employment- April30, 2009 Page 50 () • The decision is irrevocable. The Town will unlikely be able to bny back its utility in tbe future. • The sale will disrupt the eltisting operational arrangements with the Town. Costs at the Town may increase because of tbe loss of shared overheads and staffing. • The Town wiD no longer have control over the local distribution of electricity. This would be no different than the Town's current lack of control over the delivery of other utilities, such as natural gas or telephone services. If the divestiture option is selected as the Strategic Option for THI, the divestiture process should be started immediately due to the time limitations imposed by the October 16, 2009 expiry of the Transfer Talt holiday. Aprll 30, 2009 Page 52 Tillson burg Hydro Inc. Timeline July 22, 2009-April, 2014 Appendix Set 2 (No.17-32) \ j c__) 2013 27 Report: THI Disposition Analysis Se_pte_!Tlber 17, 2013 28 Impact to Town's Net levy if TI-ll was sold -No employees transferred to new entity 29 County of Brant: Seeking Potential Buyers for Brant County Power Inc. 30 Report: A Report of the Consensus Accord -Taking the High Road -To Improve Customer Service in the Electricity_ Distribution Sector 31 Report: CAQ..l4-04 Disposition Process of lillsonburg Hydro Inc. Schedule A: Disposition Process Schedule B: Estimated transition Costs 32 Report: CAQ-14-07 Tlllsonburg Hydro Inc. Public Information Meeting 33 lillsonburg Hydro Inc. Financial Statements December 34 lillsonburg Hydro Inc. Financial Statements December 2010 35 lillsonburg Hydro Inc. Financial Statements December 2011 36 lillsonburg Hydro Inc. Financial Statements 2012 37 lillsonburg Hydro Inc. Financial Statements December 2013 42 EDA The Power to Deliver: Recommendations for the future of electricity distribution in Ontario 43 Renewing Ontario's Electricity Distribution Sector: Putting the Consumer Rrst-The of the Ontario Distribution Sector Review Panel 44 OEB "Yearbook" Web link: http:/fwww.ontarioenergyboard.ca/OEB/Industry/Rules+and+Requirements/ 2012 46 BDR Report: Evidence of Paula Zamett on behalf of Essex Powerllnes Corporation, Bluewater Power Distribution Corporation, and Niagara-On- The-Lake 26 20 .) Development and Communication Services 2012 REPORT-UPDATE ON SOLAR INVESTMENT DATE: MARCH 8, 2012 TO: BOARD OF DIRECTORS, TILLSONBURG HYDRO INC FROM: STEVE LUND, GENERAL MANAGER CEPHAS PANSCHOW, DEVELOPMENT COMMISSIONER SUBJECT: UPDATE ON SOLAR INVESTMENT RECOMMENDAnON "That this report be received for information purposes" PURPOSE 1. The purpose of this report is to provide a real time update to the Tillsonburg Hydro Inc {THI) Board of Directors on the status of the solar investment opportunity. HISTORY & DISCUSSION 2. At their December 20, 2011 meeting, the THI Board of Directors approved the following motion: RESOLVE THAT Tillsonburg Hydro Inc agree to purchase two microFtTsolar systems to be installed on the 18 Spruce Stand 1 Ubrary Lane municipal properties from the Town of Tiffsonburg upon completion of the installatioin and connection to the electricity grid and at the fair market value for the systems or $164,640 plus net HST; Further RESOLVE THAT through staff research this not be feasible then the system would be purchased direct by THI and the board be notified accordingly; AND FURTHER RESOLVE THAT this be subject to the vendor completing a structural engineering review on the subject roofs prior to the installation. 3. The $164,640 referenced in the above motion was based on the original proposal for a 29.4 KiloWatt (KW) Direct Current (DC) system whereas the December 20, 2011 report provided the costs for a 25.85 KW DC system, which decreased to $134,400 based on the purchase of a 24 KW DC system. \ i () Development and Communication Services 2012 B. It is important to note that while Sclera had indicated there may be an issue with purchasing the exact components listed in the most recent proposal due to supply shortages, they did not mention the change in the panel supplier until this meeting. 9. Sclera recommended the purchase of Heliene solar panels over Canadian Solar and Symphony (OSM) based on the extensive European manufacturing experience, long standing Canadian facility (in Sault Ste Marie), the higher power density of the panels, and their textured glass technology. These characteristics offered significant benefits over the other two panels. 10.The Heliene panels were more efficient than the previously proposed panels; however, less panels were used and the difference is summarized as follows: Heliene (Current) Other (Previous) Difference Number of panels 96 110 -14 Wattage/ panel 250 w 235 w +15 W/panel Total Wattage 24,000 25,850 -1,850 (DC) _} 11.Aithough the Heliene panels are more efficient, fourteen less panels were used, \_ _ _.-which results in overall lower energy and revenue generation potential. 12.Staff have investigated the reason for the provision of a slightly smaller solar system and have been 'advised that this was due to technical limitations relating to the electrical grid and the inverter size (inverters are the unit that converts the DC power generated by solar panels into the AC power required by the grid). 13.0nce Sclera had completed their on-site inspection it was determined that the power service available was three phase instead of single phase. This meant that the original inverters included in the proposal were not suitable and another inverter was required. The new inverter did not permit the same level of oversizing with respect to the DC wattages; hence, the 25.85 KW DC wattage was reduced to 24 KW DC. 14.Solera did not provide information as to the supply chain risk due to the tight timeline nor the impact the change in technology would have on the generation potential, which meant that staff were not aware of the impact related to this change in technology. 15.Solera has been focused on providing a 10 KW AC system that provided slightly higher DC peak generation potential and believe that they have provided the Town with a suitable solution notwithstanding the impact the smaller system will have on the Town's proforma for the project. 16.This limitation would have affected all of the proposals submitted by the various companies. () ') \ __ __ ) Development and Communication Services 2012 22.Based on the revised Internal Rate of Return (IRR) calculations, the Solera IRR is now approximately equivalent to the Arise IRR but lower than the Bright IRR of 8.2%/6.8%. However the selection committee had serious concerns regarding Bright Power's record of limited installs in Ontario versus Solera's 20 years of experience at the time their proposals were reviewed on Aprll1, 2011. Given the capacity limitation of 24kW, one would expect that Bright Power's IRR would decline as well and narrow the gap between them and Solera. 23.Staff are currently investigating a work around solution that would enable the addition of eight panels to the two systems (four per system), which would result in a total DC wattage of 26 KW and revenues in keeping with the projections from the December 20, 2011 report. 24.In addition to this, staff have reviewed the assumptions for the project with Solera Energies and they Indicated that the revenue estimates provided are conservative. In fact, they are estimating that the current 24 KW DC system could actually produce $437,982 in revenue versus the $461,767 for the 25.85 KW DC system above, which is an increase $9,079 over the lifetime of the project. This reduces the revenue shortfall from $32,864 to $23,785 ($1,189 per year). This information has not been included in the current IRR calculations. FINANCIAL IMPACT /FUNDING SOURCE 25.THI was originally anticipating total revenue of $23,088 per year from the two solar systems and, based on the smaller systems installed, can now expect total revenue of $21,445 per year, which is a reduction of $1,643. If the solar system can produce more energy, this gap can be narrowed by an additional $454 per year resulting in gross revenue of $21,899 per year. 26.This report, with the exception of the IRR calculations, has not been reviewed by the Director of Finance due to timing. PREPARED BY: Cephas Panschow, BA, MAES, Development Commissioner March 5, 2012 APPROVED BY: Kelley Coulter, Chief Administrative Officer I I , '· ) Report to the Hydro Board June 26, 2012 · CONFIDENTIAL Members of the THI Board: During the Board meeting of May 15, the President was given direction to provide a report to the Board as part of the Annual General Meeting on the implications of either a Sale or Merger of the Local Distribution Company (LDC). A Valuation report was reviewed as part of the February 21 Board meeting. It was reported based on recent sales transactions ·and mergers that the range of value for THI is between $8,788,856 and $12,806,802 or $1,306 to $1,900 per customer. The Corporation of THI has virtually no debt servicing obligations. Prl.or to reviewing the scenarios available to the Board, a brief review of the financial health of THI Is warranted. Essex Power Lines completed a review of Small, Medium and Large local distribution companies. A copy of the report Is attached (Append!~ A). THI Is part of the Small LDCs element. Further, for the convenience of the Board Table 1. summarizes the findings of Essex Power against the audited fiscal year end for THI. Appendices B and C provide a detailed summary of THis performance for 2008·1011. It Is worth noting with the OEB yearbook results THI outperformed the small LDC element in 2008, 2010, and 2011 on a Net Income basis. . . . The following analysis Is timely given the sector review that is underway. The Electrical Distribution Authority has been working to look at the sector and appropriate number of LDCs. As reported In the Essex Power Lines summary the market has 81 Independent WCs. The province has been questioning whether or not this is an appropriate size. The market Is in the middle of a self review and this may affect the valuation .should the Board recommend disposition to the Shareholder. TABLE 1 Element Average THI 2011 Small LDCs Audited F/S Customers 7.929 6,729 Distribution Revenue 4,253,995 3 165.997 Expenses (3 83,179) (2,866 912) Net Income 370,816 233,393 Net Income per Customer 37.28 34.68 ···-··~-. Net Income% 7.90% 7.37% Note: Small <20,000 customers (44 LDCs Mpresented Dai:B averaged between 2008 trnd 20l0(Source OEB E/ectr/dty Distributor Yearbooks) r] and two (2) Customer Service Representatives and one {1) billing support \.. · representative. _) The Shareholder's direct labour costs would reduce by ($132,000) with the reduction In a reduction in local locates for Bell, Rogers, Banner Installation. As well the Street lights and Traffic light work would be contracted out. Anally the positions that perform the service of Asset Management and Field Customer Service works would no longer be required. Indirect labour consists of the lost absorption of positions like the Director of Operations, Director of Finance, Finance Staff, Dispatchers, Fleet Services and Engineering. Given the different skill set requirements of these positions it is challenging to reduce employees from the organization. The financial burden to the tax levy In this scenario is $285,788 per annum. Indirect labour costs can be reduced In the areas where no allocattol') would be necessary with the sale of the THI Corporation as the duties could be redeployed to other positions In the organization. The annual levy savings is ($121,000). The physical fleet costs with the sale ofTHI are relatively straightforward. In the absence of recent transactions In the market; proceeds equivalent to the net book value (NBV) are assumed for a savings of $380,000 with the long term debt charges of $267,000. These costs are assumed to be funded from the proceeds of the sale-and would not be a hit to the levy. The financial impact of the revenue from the Master Servicing Agreement is assumed to be eliminated for $140,000. The operational costs that would be required to be absorbe_d through the taxation levy is the revenue impact of lost contributions to building rent for the Customer Service Centre, Postage equipment, engineering, IT services, tree trimming and street light repairs. In total, the projected Impact on taxation of these Items is $307,600. In summary the Impact of Scenario 1 is a draw-down on net financial proceeds of $405,000 to be Incurred In the year of sale/merger only. The financial hit to the taxation levy Is projected at $325,788 (1% on taxation levy Is $121,000 In 2012). The water system users would be Impacted by $41,600 through the loss of efficiencies in the Harris software. The Town would need to Investigate the ability to utilize the miscellaneous billing module under the Great Plains Software. n \.' ' -. ..-1 trimming and street light repairs. In total project Impact on taxation of these Items Is $307,600. In summary the Impact of Scenario 2 Is a draw-down on net financial proce.eds of $647,060 will be incurred in the year of sale/merger only. The financial hit to the taxation levy re~alns at a projected $325,788 (1% on taxation levy Is $120,000 in 2012). The water system users would continue to fund an impact of $33,600 through the loss of efl'lclencies In the Harris software •. Scenario 3: THI Sold/Merged no Employees transferred to new entity, water /wastewater transferred to County Scenario 3 assumes no employees are transferred to the new corporate entity and that the water and wastewater system maintenance would transfer to the County of Oxford operations. With this scenario the one-time settlement costs are $576,504 for notice and severance with $110,000 for outplacement services at $5,000 per employee. The costs are derived with the assumption that twenty-two (22) employees are impacted with a minimum 8 weeks working notice period and the length of service for severance. could be up to 26 weeks. The balance of the costs associated with Scenario 3 mirror those of Scenario 1 and 2 with the exception of Indirect labour. The Shareholder's direct labour costs would reduce by ($132,000) with the reduction In a reduction in local locates for Bell, Rogers, Banner Installation. As well the Street lights and Traffic light work would be contracted out. Finally the positions that perform the service of Asset Management and Aeld Customer Service works would no longer be required. Indirect labour consists of the lost absorption of positions like the Director of o·perattons, Director of Finance, Finance Staff, Dispatchers, Fleet, Water Customer Service and Engineering. Given the different skill set requirements a move these positions it Is challenging to reduce employees from the organization. The financial burden to the tax levy would be an additional $406,902 given the lost efficiencies of the water and wastewater system. Indirect labour costs can be reduced In the areas where no allocation would be necessary with the disposal of the THI Corporation as the duties could be redeployed to other positions In the organization. The annual levy savings is ($121,000). _() \ __ ) _) The Impact on the Town Hall operations Is Ignored In this scenario. A minimum of 50% of the capacity of the 10 Lisgar Customer Service Centre would become . available for alternative use. The potential impact on economic development Initiatives has not been considered. Further any impact on the R.apidFlbre project or 3rd party subdivision connections are assumed to not be impacted by the sale. From a community perspective, any costs associated with the installation of banners, Christmas wreaths, flower baskets are not included in this calculation. The costs are unknown. This Is an Issue for the shareholder to assess on whether it becomes a service within the Town Public Works department -this is ·a viable alternative with the appropriate training. I . I I I (J _) REQUEST FOR PROPOSALS Town of Tillsonburg and TiUsonburg Hydro Inc., 200 Broadway, 2rul Floor TUisonburg, ON N4G SA 7 Email: keoulter@tillsonburg.ca REQUEST FOR PROPOSALS for PROFESSIONAL AND CONSULTING SERVICES To Conduct an Organizational and Operational Review of the Town of Tillson burg SUBMISSION DATE December 14, 2012 CLOSING LOCATION: Office of the CAO Town of Tillson burg 200 Broadway, 2nd Floor Tillsonburg, ON N4G 5A7 Attn: Kelley Coulter Chief Administrative Officer T (519) 688-3009 E kcoulter@tillsonburg.ca ': AVAILABILITY OF LABOUR AND ESCALATION ............................................................. 24 j ()CORRECTION OF DEFECTS ................................................................................................... 24 .... ~·-~AX ISSUES ............................................................................................................................... 25 LOBBYIN"G ................................................................................................................................ 25 ENVIRONMENTAL .................................................................................................................. 25 CONFLICT OF INTEREST ........................................................................................................ 26 CONTRACT PROVISIONS BY REFERENCE ......................................................................... 26 ADDENDA ................................................................................................................................. 26 VEN])QR' S RESPONSIBILITIES ............................................................................................. 27 IN"SURANCE .............................................................................................................................. 27 WORKPLACE SAFETY AND INSURANCE BOARD ............................................................ 28 MUNICIPAL FREEDOM OF INFORMATION & PROTECTION OF PRIVACY ACT ........ 28 COMPLIANCE WITII LAWS ...... ; ............................................................................................ 28 CONDITIONS ............................................................................................................................. 29 GENERAL .................................................................................................................................. 29 / \ __ ) )may change depending on the comments received from the consultant in the course of or r ~llowing its overview but presently the requested departments are: the Town's Operations \ 'Uepartment (Hydro, Water/Wastewater, Engineering, Fleet, Roads) and the Finance Department (Costing, Finance, Billing, Taxation, Payroll, HR) (herein referred to as the "Departments") in order to develop recommendations on changes that will improve the efficiency and effectiveness of service delivery by the Departments. Project Objectives: 1. To provide a broad-brush summary of the strengths and weaknesses of the overall organizational structure, operating procedures and systems of the Town/TID Master Servicing Agreement. 2. To review the current organizational structure of the Departments highlighted above, current procedures and systems, and the resources allocated to the Departments, with regard to the operational requirements and objectives that have been assigned to the procedures and systems, and allocated resources, of similar departments in other communities comparable to Tillsonburg across . Ontario, with emphasis placed on identifying those who are regarded as employing best practices. 5. To recommend practical, achievable and realistic revisions/adjustments to the overall organizational structure, which may include: a) clarify roles, responsibilities and authority of management staff; b) eliminate duplication and overlap of responsibilities within the Town as well as the Departments and between other Town departments; c) improve the utilization of technological solutions to the service delivery model; d) improve the delivery time and quality of services provided by the Departments; e) improve communications within and between the Departments and other Town departments; and / C.) • relations with other Town departments including documenting extent and nature of interaction; • services including suggestions/comments for improving quality of services provided, cost-saving initiatives and on-time delivery; • suggest priority items that would increase the Town-THI's efficiency and/or cost effectiveness. 5. Analyze the results of the consultant's consultations whether in the form of interviews, questionnaires or both to identify: • significant patterns and trends in perceptions regarding the current level of services provided, organization structure, reporting relationships, and position functions; • any duplication/overlap of effort within the Town as well as within the Departments and with departments; -· 1. The consultant shall recommend a proposed organizational structure based on fmdings and present clear recommendations on changes that will improve the effectiveness and efficiency of operations. 2. The consultant shall prepare a draft final report and review project fmdings and proposed recommendations (including detailed implementation and/or phasing plans) with the Chief Administrative Officer and the rest of the Project Team, prior to finalizing the report. 3. The consultant shall present a written fmal report summarizing the results of the organizational and operational review incorporating fmdings, conclusions, and recommendations and deliver 12 copies to the Town by December 15, 2012. In addition, the consultant shall provide all presentations, materials and fmal report in an ' ) electronic form acceptable to the Town (for example pdt). \ ) ( ~-yroposal: / The Town requires prospective consultants to submit three (3) copies of a proposal in hard copy and one (1) electronic copy (pdf format) to conduct the organizational and operational review as set out herein. The proposal shall include: __ ) • an overview of the proposed methodology • names of the key personnel to be assigned with resumes outlining qualifications and experience • relevant experience of key personnel and the firm in conducting organizational and operational reviews of the nature set out herein references who can COMPLETION DATE: May 15, 2013 THE CORPORATION OF THE TOWN OF TILLSONBURG Professional and Consulting Services to Conduct an Organizational and Operational Review of the Town of Tillsonburg FORM OF PROPOSAL TOTAL AMOUNT: $ ______ _ Harmonized Sales Tax shall be extra. N~OFCOMPANY: ________________________________________ ___ ADDRESS: ________________________________________________ __ ACCEPTANCE AGREEMENT ACCEPTED ON BEHALF OF THE CORPORATION OF THE TOWN OF TILLSONBURG, THIS __ DAY OF ______ __....; 2012. MAYOR TOWN CLERK /,) j () INFORMATION AND INSTRUCTIONS 1. PURPOSE: This Request for Proposal states the instruction for submitting proposals and the procedure by which the Vendor will be selected. 2. DEFINITIONS: Hereinafter, each company receiving this Request for Proposals is referred to as a "Vendor" and/or "Proponenf' and/or "Company'', a Vendor's proposal in response to this Request for Proposals is referred to as a "Proposal" and the Town of Tillsonburg shall hereinafter be referred to as the "Town." 3. ISSUING OFFICE: Office of the Chief Administrative Officer Town of Tillsonburg ON The Town of Tillsonburg will not accept submission of any Proposals after the Closing Time on the Closing Date. 5. PROPOSAL SUBMISSION: There shall be one (1) proposal package marked original and three (3) proposal packages marked complete copy (including a digital copy if required). Proposal packages shall be delivered in a sealed envelope, with the proponent's company name, Proposal Number clearly stated on the label provided with this document. Faxed or electronic replies will not be a.:cepted. Vendors may not make modifications to their Proposals after the closing date and time except as may be allowed by the Town. The Town may reproduce any of the Vendor's Proposals and supporting documents for internal use. The Town will not be obligated in any way by the Vendor's Proposal. The Town will not return any of the Vendor's Proposals or supporting documents to the Vendor. them in making their Proposals and fixing prices. 0 Vendors must satisfy themselves in all respects as to the risks and obligations to be undertaken by them. If a Vendor discovers any inconsistency, discrepancy, ambiguity, errors, or omissions in this Request for Proposals, it must notify the Town's CAO, who may, if necessary, send written addenda to all Proponents. · The Town may, at any time, make and stipulate changes to this Request for Proposals. The Town may provide additional information, clarification or modification by written addenda All addenda shall be incorporated into and become part of this Request for Proposals. The Town shall not be bound by oral or other information, explanations or clarifications not contained in written addenda. 9. CLARIFICATION OF PROPOSALSNERIFICATION OF INFORMATION \_-) The Town may verify any Proponent's statement or claim by whatever means the Town deems appropriate, including contacting·references other than those offered by the Proponent. The Town may reject any Proponent's statement or claim if, in the judgment of the Town, the statement or claim is unwarranted or not credible. The Proponent shall cooperate with the Town in its attempt to verify any such statement or claim. 10. SELECTION PROCESS: ) Because the Town bases any decision to award a contract on the Proposals submitted, Vendors should include all requirements, terms and conditions it may have in their Proposal, and should not assume that any opportunity will exist to add such matters after the Proposal is submitted. The Town reserves the right, at its sole discretion, to negotiate with any Vendor as it sees fit, or with another Vendor or Vendors concurrently. In no event will the Town be required to offer any modified terms to any other Vendor. The Town shall incur no liability to any other Vendor as a result of such negotiations or modifications. The Town shall have the right to negotiate with each and every Proponent the terms and conditions of their Proposal, the details of the contract and the inclusion or exclusion of all or any portion of the I (J 14. / ) ... ___ ___ Following the evaluation, the Town reserves the right to accept or reject any and all Proposals or accept the Proposal which it deems the most advantageous to it notwithstanding the scoring of each of the Proposals and has the right to reject any or all Proposals, including specifically any Proposal whose weighting in any one particular category may be unacceptable even though it is weighting in other categories is superior to other Proposals, which could include a Proposal whose financial or cost component is significantly in excess of the obligations the Town is prepared to undertake and the Town reserves the right to disqualify any Proposal which scores poorly in any category, as determined by the Town in its sole discretion. The successful Proponent agrees to indemnify and hold harmless the Town and Till, their respective Directors, Officers, Employees and Agents from and against all suits, judgements, claims, demands, expenses, actions, causes of action and losses (including, without limitation reasonable legal expenses and any claim for lien made pursuant to the Construction Lien Act), and for any and all liability for damages to property and injury to persons (including death), and for any incidental, indirect, special or consequential damages or any loss of use, revenue or profit as a result of or arising out of or in relation to the performance by the Vendor under or any breach of the terms of the Agreement by the Vendor or arising from or relating to the RFP including the Vendor's own default, negligence or misconduct, or those of its employees, servants, agents and contractors. The Contractor will also provide as part of the Agreement an indemnity and any waivers of claim to the Town similar to that provided by the Town to its funding entities. RFP OVERRIDES STANDARD TERMS AND CONDITIONS The terms of this RFP and the Agreement reached pursuant to this RFP with the Proponent supersede the contents of any and all standard terms and conditions contained in the documentation from the Proponent, including those contained in or on the reverse of purchase orders, order verifications, sales receipts or other standard documentation supplied by either the Proponent or any equipment suppliers to the Proponent. '18. c_) 19. PRINCIP ALIREPLACEMENT The Proponent acknowledges that any principals and/or key personnel, workers, consultants or contractors identified in the Schedule for whom an hourly rate has been provided, may not be replaced during the term of this contract without the prior written consent of the Town. EXTRAS The contract is contemplated of being inclusive of all Work, including due to any unforeseen or unknown conditions in the price quoted. To the extent, however, that any extras are authorized by the Town, in addition to this contract, then the price which is extra, shall be agreed upon between the Proponent and the Town in advance and if not, if so ordered by the Town, shall be performed at the hourly rates set out in the Schedule attached hereto. The Proponent shall not proceed with any Work unless an agreement has been reached on the price of such extra work and/or the method of determining the cost and price of such extra Work. 20. PURCHASING BYMLAW Unless progress payments or alternative payment terms are specifically agreed to under the terms of the RFP and any Proposal, as accepted by the Town, the contract price shall be invoiced after delivery and acceptance and testing of the services and/or deliverables and payable thirty (30) days from the later of such date and the date of receipt of invoice. Any alternative payment terms, including the cost thereof, to the Town and its financing parties, will be considered as an element of valuation in the fmancial evaluation of any proposals. As funding is provided primarily from the federal and provincial governments under contracts with the entities administering federal/provincial infrastructure projects, including Industry Canada, any funding and payments thereunder will be subject to the requirements of such program and contracts with the Town. The Town shall have the right to withhold from any sum otherwise payable to the Vendor such amount as may be sufficient to remedy any defect or deficiency in the Work, pending correction of the same. r __ ) All hourly rates set out for individuals or persons or by position in the Schedule attached (if applicable) to this RFP and the response to this RFP shall be firm and binding for the term of this contract. \27. j C) OCCUPATIONAL HEALTH AND SAFETY EMPLOYER OBLIGATIONS By entering into this Agreement, the Consultant acknowledges its responsibility to meet all of the employer obligations under the Occupational Health and Safety Act (OHS Act) and shall ensure that all work is carried out in accordance with the OHS Act and all applicable regulations. This includes, but is not limited to, the duties to: provide a safe workplace; provide information and educate workers on workplace hazards; appoint a competent supervisor; prepare and provide a health and safety policy, implement a comprehensive health and safety program to support the policy and take every reasonable precaution to protect the safety of workers. COMPETENT SUPERVISORS The Consultant shall ensure an adequate number of supervisors are provided and they all satisfy the definition of "competent" as prescribed in the OHS Act. OHS REPORTS/NOTIFICATIONS The Consultant is responsible for all costs associated with workplace accidents and all premiums or assessments owing to the Workplace Safety and Insurance Board (WSffi), or insurance company. Upon award of the assignment and as requested by the Town during the term of the contract, the Consultant shall furnish evidence of coverage for themselves, their employees, subcontractors and subcontractor's employees under the Workplace Safety and Insurance Act or insurance policy. The Town may withhold payment of such sums of money sufficient to cover any default of the Consultant to the wsm or insurance company for premiwns or assessments and any costs arising from an accident for income replacement, medical aid or rehabilitation. GENERAL DUTY CLAUSE The Consultant shall take all reasonable precautions to meet the requirements for the protection of workers set out in the OHS Act and the regulations made under it. OHS PLAN REQUIREMENTS (, __ ) The Consultant shall be required to have in place a health and safety policy and to implement a comprehensive health and safety program to support the policy. The successful consultant will be required to develop an OHS Plan for this assignment, which must address: \ ) 0 Each Proponent, by submitting a Proposal, agrees that: a) In the event that any or all of the Proposals are rejected or disqualified for any reason, proper or improper, or the Project or selection process is modified, suspended or cancelled for any reason, neither the Town or its member municipalities, employees, officers, directors or representatives will be liable under any circumstance for any claim, damages, losses, cost, reimbursement or compensation to any person or entity whatsoever arising out of this Proposal, including, but not limited to the cost of preparation of the Proposal, loss of anticipated profits, loss of opportunity and any other matter; b) The Proponent hereby waives any claim for loss of profits or loss of opportunity if the Proposal is rejected or disqualified or the Proponent is not successful in the selection process for any reason whatsoever; and c) The Proponent acknowledges that in evaluating the Proposals, the Town and its advisors are seeking a Proposal satisfactory to the Town and under no obligation to the Proponent to do anything other than bona fide consider all Proposals. In the event that the Town shall be in default under this RFP or the Agreement, or shall be negligent in the performance of its duties under this RFP the Agreement, or shall be in default of · to the then in 30. NOTICES/ACCEPTANCE 31. _) The placing in the mail to the address given in his/her submission or delivery of a notice of award to a Proponent shall constitute notice of acceptance of contract. This acceptance shall be conditional on the Proponent providing all documentation, insurance, bonding, security and certifications as required by the RFP within ten (I 0) working days of the date that the notice of award is placed in the mail or delivered to the bidder. The Proponent shall forthwith, within ten (10) working days of receipt thereof, execute the Agreement in the form prepared by the Town and incorporating the terms and conditions of this RFP and such other terms and conditions as the Town shall reasonably require. CONTRACT CANCELLATION The Town shall have the right, which may be exercised from time to time to cancel any uncompleted or unperformed portion of the work or part thereof without cause or fault. In the event of such cancellation, the Town shall pay to the Company the cost and expenses by the Company in performing that portion of the work completed up until the date of cancellation. The Town may: I \ 34. j 35. 36. ._) TAX ISSUES The Proponent is solely responsible for obtaining and relying on tax advice from its own advisors and experts, including obtaining any advance interpretations and rulings from CRA relative to this RFP and the Agreement which it feels are appropriate (including in relation to the supplying of funds, any financial structure and any tax consequences). LOBBYING In order to ensure fairness to all Proponents, the Town must endeavour to prevent unfair advantage created by lobbying. Therefore, the Town reserves the right to disqualify, at any time and at its sole discretion, any Proponent engaging in lobbying in connection with a competitive bidding process between a date that is no later than the date of issue of the RFP and the date of signing of a contract between the Town and the Successful Proponent(s). The Town may disqualify a Proponent at any time in the procurement process, including after the selection process has been completed. Lobbying may include any activity that the Town, in its sole discretion, determines has or may give an unfair advantage to one Proponent relative to other Proponents. Without limiting the foregoing, lobbying may include: f. Verbal or written communication with or to any member of the RFP Evaluation and Selection Committee other than those identified as contacts in this RFP. g. Direct or indirect requests by the Bidder to any person, organization or group to provide a written or verbal expression of support not required by this competitive bidding process to any member of the Evaluation and Selection Team or Council. h. Verbal or written communication with or to media organizations. i. Direct or indirect offers of gifts of any kind or value to any Town representative or personnel. ENVIRONMENTAL The Proponent shall be responsible in respect of all environmental matters including compliance with any and all environmental laws, rules, regulations, statutes, and orders of any governmental or regulatory body or authority having jurisdiction in connection with this RFP, the Agreement and the construction and delivery of the Work and the operation of any fibre optic network or other facilities after its construction, including any environmental liabilities, any clean-up obligations, any fines, penalties or interest resulting from any condition of the Work, properties or the facilities, whether pre-existing, known or unknown, disclosed or undisclosed or which occur after the date of the Agreement. a) If a Vendor discovers any inconsistency, discrepancy, ambiguity, errors, or omissions in this Request for Proposals, it must notify the Town's Purchasing Supervisor, who may, if necessary, send written addenda to all Vendors. b) The deadline for questions/answers relating to this RFP is January 15,2012. c) When it becomes necessary to revise, delete, substitute or add to the bid documents after release, the Purchasing Supervisor will issue an addendum. d) A copy of each addendum shall be forwarded by fax and/or mail, by the Purchasing Supervisor or her designate, to all vendors registered on the distribution list. e) Addendum sent by fax is accompanied by a "Verification of Receipf' document to be retUrned promptly by fax to the Purchasing Supervisor. This is for the Vendors' protection. f) All Vendors must acknowledge addendum by attaching a signed copy of this addendum to their respective bid documents. Failure to do so may result in rejection of the bid. j) Any Addenda, if required, will only be issued to those Vendors who have pre-registered as a bid taker. VENDOR'S RESPONSffiiLITIES: 40. INSURANCE: ) The successful Vendor shall in effect and maintain for the period of the Project at is own expense with insurers acceptable to the Town all necessary insurance considered appropriate for a prudent contractor undertaking a project similar to this Project including such of the following types of insurance as the Town may elect: a) Commercial General Liability Insurance in the joint names of the Vendor and the Town with limits of not less than Five Million ($5,000,000.00) Dollars inclusive per occurrence for bodily injury, death and damage to property, including loss of use thereof, with a property damage ; () applicable and in any way affect the work, and no plea of misunderstanding will be considered on account of ignorance thereof. Vendors shall carefully examine and study all of the documentation in order to satisfy themselves by examination as to all conditions affecting the scope of work to fulfill the contract CONDITIONS: GENERAL: 1. TAXES: Harmonized Sales Tax is applicable, but shall not be included in the bid amount. 2. WITHDRAWAL PROCEDURE: a. Proposals may only be withdrawn prior to the closing date upon providing a written request. b. The Vendor who has submitted a response may request that the Proposal be withdrawn. Adjustments or corrections to a Proposal already submitted will not be allowed. The •• if the made by f. Withdrawal requests received after the Proposal closing will not be allowed. 3. SUB-CONTRACTORING: The successful Vendor will not, without the written consent of the Town, make any assignment or any subcontract for the execution of any goods and services hereby proposed. 4. FACSIMILE/ELECTRONIC BIDS: All bids must be signed and sealed originals. Faxed or electronic bids will not be accepted. 5. PROPOSAL PRICES: a. Bid prices must be valid for 90 days after the proposal closing date stated herein. b. In the event of any discrepancy between the unit price and the extension(s), the unit price shall govern. c. The total price and payment is to be shown and made in Canadian Funds. c_) ) '"'--./ f _) which are then remaining in the possession of the Town of Tillsonburg on account of this Proposal, and to any court of competent jurisdiction as monies paid on behalf of the Vendor. ~ 1 (_) Henley lntamatlonalln~: · · / ) Fa~ruary 5, 2013 PropOsal: To Provide a Val~ation of Tillsonburg Hydro. Inc. . . . . I. Henley Internatioli81 Inc.'s Experience in the Valuation of Eleetrieity Distribution Companies · Henley l~temational. Inc .. h~ bf.en i:actively irivolved in .th$ eJectrlcftY .distribution ~inels since the beginning Of the restructuring of the OntariO electricity market Dr. l.awrBnce Murphy of Henley was the Chairman of the Retail Technical Panel of the Market Design Committee, which recommended the system of codes \Aihich was'ultimately accepted by the Ontario l;nergy Board {0~) as the bas~ for the ~u~ry system f~r ttl~ Ontario retail market He also eat on OEB task forces which develOped the detailed design for performance-based regulation, the basis for the current Electricity Distribution Rate Handbook. Henley has Worked with over thirty .dlstrib~.on compani", ass~.ng th&m wittl ~he transition from commission to incorporation, adVising On recapltalization,·unde'rtaklng valuations of dh;,triblgion compan-. and related ~ine&$es, negotia:ting the sale Of . .· t - - -. -. . t distribution C.ompanles, advising on niergei's and d~loplng busi~ess plans. ·· · ~. . . . . Henley prepared the valuation for and helped negQ1iale .the first sale of a distributiQn company (Thorold Hydro) approved bY the. OEB aft~r the implementation Of thei Energy Co-:npetltlon Act, 1998 and was Involved in the development of the only lease of a dlstrlb.utlon company tt:tat has been approved bY,~ OE;B (Port Colbome Hydro). In addition Henley hai undertaken valuation•: for anti has •lated ·in thEt n~atlon of the sale of nurneroui distribution companies. Th8Se haw rarlged from carhpan.f~s as large as Richmond Hill Hydro, the second largest sale to date, to Stirling-RawdOri Hydro, one of the smallest l,lliiiUes sold. Henley has proylded .~nancl~l advice (in many cases- including valu~ons) for distributiOn "Cotripan!ea or municipalities in the. Niagara . Peninsula hich.idrng Gri~by Hydi'O, H.amlltoo: fl}tdro,· Niagara Falls Hydro;·Niagai'IH)n- the-Lake Hyd·ro, Pelham PUC, Port Colboi'ne Hydro, Thorold HYdro, Pen·weSt: Power · and Weiland Hydro. · Other utjl~ for whlct) Henley ha• provided advice. e~ on. ~half of tha u~lity" Qr t~ munlclpai. ~haretn)lder·anc:J"agaln MOIJTtf!llY r&qu,ri_nsf.a valu,atl~ arid often partlCipati.on i~ the negOtiation of a ·Sale include Aurora Hydro,· Bracebr'idge Hydro, BrantfOt'd Hydro, Brighton Hydro, Burtington Hydro, Campbellford-5eymour PUC, Clinton Hydro, Cobourg PUC, Colborne PUC, Enwin Powerline$, G~avenhurst Hydro," Guelph Hydro, Lakeland _Hydro, ~iddlesex Power ~.ribution.~ni~!W.·f,(oifo.lk Powe.r; Oakville Hydro, Oshawa.PUC Networks, p~·souncl Hydro, Q~inte West Hy'dro, Ramara Hydro, · · Richmond-Hill Hydl:b, $ern~ (:iydto1 ·seugogHydra, S~m-f1ydro, Veridian . Connections; West Perth PoWer Inc., Wh~churcli-Stoi.df\iille Hydro and Woodstock Hydro. · · · · · · · .• ·.· In ~everal ca&es the Vfi!UatiOn of a utilitY included· the valuation of affiUilted OOn-reguJated companies. "These comr;Janies were typicallY in the energy -~c:ee or the poWer . . . . .. generation businesses: Henley has also Worked with oompanies engaged in the energy Henley International Inc. 1 . I i .( () ) the authority to regulate I;;DCs;-To fulfill thiS mandate· the OEB uses the framework established in the Electricity Distribution Rate Handbook and related guidelines on incentiVE!· regulation.· Henley's approach to the cash floY.r·valuatioi'1 of a distribution compa.ny begins with detailed projections of utility_ revenues. This Is done by rate class using volu~ proj&ctions arid aisodated rateS ·by rate ClaSs. Tlie 'OEB's approach to rate regulation Involves the establishment ·of base 'rate$ .uaing a· full· Cost of service application and then rebasing periodically. ~during· the interim-Years are detennined by the OEB's Incentive RegulatiQn procedures. THI h&Sfllecf$·coat of service appiK.ation for 2013 rates Which_ will' set base rites fOr the 'utilitY. For -~e interim years between rebaslng the OEB's 3nt Generation Incentive RegUlation Meeliiattisrri (IRM) in normally used to project rates. However, in October of 2012 the OEB made available its report entiUed Renewed • · Regulatory Fral')'lework for Electricity Distributors. In it ttJe OE~. indicates that it will continue.to use the overall ~ulatory framework that-is cul'reiitly iii place but Intends to introduce some important changes. These wili have 'to be take~-into consideration. · . ' . . . ... : .. ~ ' . ' . . . ,: ···: : : .. The basis for the valuation will be the financial results for 2012, and the rate application for 2013. The valuation will be as at the .end of 2012. Henley's proprietary valuation model allows the projection~ to be CC!flpleted expedillously \IIIith a focus on the . underlying· assumptions ·and the interPr"etation ·of th'e:results: Variations in assumptions can provide a range for the valuation results. It is anticipated that THI's submissions to the OEB will provide all the infonnation that is required for the valuation. However, any a~ltlonal required information will be obtained from the THI. 2 Transaction--based Approach Henley maintains a record of transactions Involving the sale of electricity distribution companies. This Information is used to establish benchmaJt multiples. Benchmark· -- multiples that are commonly used by investors are premium on book value and cost per customer among others. The results of applying these benchmarks will be compared to · the cash flow approach. The use of benchmarks when the utilities have significantly different structures can be very misleading. Care must be taken in selectiilg appropriate comparators for the utility. · These activities will provide the infonnation necessary to arrive at a fair market value for the utility. Ill. Work Plan and DeDverables For the purpose of providing an indication of the time.taken to complete the project the folloWing schedule assumes a start date of May 1. The actual start date could be any date after February 20, _2013. Activities Period May 1-May5 Assembly and review of data required for completion. of· the valuation. During this period contact with the THI and possibly the OEB and other data sources may be necessary to provide missing information. May6-May 13 Initialization of valuation models to reflect company financial information. Henley International Inc. · 3 I l l I I J. ("-) ~-. VI. Conflicts of Interest Henley is not aware of any conflicts of interest that would prevent It from completing this p~~ . . . . . ,. . ' · .. \,_) Henley International Inc. . 5 .I I ·\ __ ) .• '. I I l' ! : . I • • ' I i . i ·~_) . ·. .... ' . . . . \ ' . .' : . . ' : . CoSt Prop6sal 7" PartS (V~luatiori · · .. ·.Phasel ... · .. .... .. .... . · ... · · · .. · · .... · ... · · . . . . -. . . . . . . . . . . . · · : :As. ·~~cif~s~riar .a~is~ ~e\1~·d$fSta~~:You·r ~~d·tO:~m~·· ... . ... :vah.~e .t6rtrnde~.v~:pc~y/~~e·.$ive -~:k89.P ~· ~ th~ ~ ...... · ...... r)Os$it~ia :i~~-'cic)cis!Stertt With' ~igh 'piOf.t(?mil:~n.~rdS anclto~ .. -... : . . .-· .... ·. · . q~lit'i $~~M~ ... ·Inim~ .. ~u~ m tl1is.-enQ&ge~; ~MG· Win. ... : . · · ·: .. · · ·.:Cieliv$r'yaiQe~:·q~erigag~rT1~nt.Wril-~.effi.~ient. effeciwe and well-.· .. · . . · .. · · · . · i:()Qrriin~t~·v® ·Wii b9 ... intorme~ .. Of.·<lur.Progress.·~· $p ·m tn-e ·: · .. -~Y .. ~~ci.r~$iVe .. &litiY·.~fi~.®·of'a.hY.~;iner~no··issu~/ .. ·. · · · .. : · ... -: . . . : . . .' .... · . :' . -. -. . . . . . . : . . . . . _· . . . . . : .· .· . . · ... we ~m~.-~~i~~~·~t~.~ ~·~-~~~·~siij~~~nt ~ett upon·~ .... .. : .. : work.p.laitin·~.tedmt~i ~·~.bett7,;oa: · : : .... . : .. · · · '... · ... · · :: :· · . : ·~·~e~l.f~:~r:& baSed ~~·tlie ~l!~.tJr~~ serv{~~fOpps~ ~d ~ .. : · ... : : . ~iKiinil.ot ~r ~i~ma~~ we.wiu·C:OJ:tfum ·til~ seop& and c~etE.ili> with vOt! · . · · .. d!i~ tris~s-iriti81 ldoic.of1 ~~fna.~~d·di~ion: A..tte·en~gem~~"· :. ·. · . · .. . . : ;~~: ~hl:iuld-~.Of ~ ~~ Cha~·~affect.bur esti~tSS;·~.if. tt.e·~ · . · . ·. ·.Of' u,e .e~·ni.18 diri~t.fRin ·th8t eStimated. ~·~u d~tiss·th'ase:m.~tters With ..... · : :yq~ be~ .. i~~-·{la(~~ .. QQn~~: ~ oui~~e !&.~than ~ted, we .. . : ..... ~-~~·~· ~ .. ~'·'.~~dl~~: .... .' .. · ... :' ........ : . :' .... : ·. ·. '.: ..... · · ... : . . . .: : :···... . ....... . . : .' . 041:-¢:~~et.axpeniles; ~udi!lg vavel:e,o$t&;willbe Chargedto you at.i::ost to 8 . . . . . .. : : mJ?tirtn.i~ upset Ji~ of $4oci.for. tlie. Part' B Pt;ase: pUr-.fEi~$i~~ ·~11 ro.uiirie . . : -· ~ · ·:. · / adfn_~-8Xp.n.8'sti~ aS lor(; iuSt:B~~-tel8~8 CaiiS ... photocaP·ies. fax chargeS. . . .. mileai3e; pi;Mj,;.g:~_f,port&j~ and.d.eflvi.v 'a~ ~mi.~trStlve.~~ ~l'l!lEI~.. . ..... . . . . ..-_. : : . . . . . . . : ... -. . . : . . . . _· _· . . . . .' . . . . . . . . .-· .. . ': 4.' 0 ·.' : . J~. : 4 .. : ... . .... 10 .. ... . . . .. . . . . . . . - - . - . . . * : : : : ·~ .· . . .. :·, .... : rviE)th.odotb·gy ... ~ .... Pa _r{ -s·_. N ~tu.atiorr· .. :. · .. · · · ... :· .. · and..:Tra.n .. sa·cti·or1af .. ls·s't1esr·· .: .... ·> ... · ... ·· ... : •• : •• :: • • • * • • • • : • • . : • . . • • • • • · ill~~·.~~;~~, .. ~~s~~·-~~.apP~a~ .. ~~d ~ro~d ~rk .. ~lao ~-· .. · · ·hOW~ ate going .!Q·ex~e--the va~en ~se of.~ proJect.· . · .... · we ha\tf). sPebffi~uv id8n~ the .t;meiin~; · irifo.l'fOation ·. · ' .. · · · . ·. · · re~i~~. rnaiOr ~tSstdnes al,d·~werdbles· ttiat .. Wilf be':.·. . .. : .... . ~i-~r~ .~~ .. Par-t.ot~-~-P.to~ ·. : .. · :·: ... =: ... · ·/ /. · : · · · .. ··. · · · ... ·. ·. OU~-~~~-~~e~~~~-~~~d~·~··f~r-~~~~~·each .. f~d·o~:· · · · · .. ~-~~~~$.ri~~~t~c. U.:.iit)ie·~.and~~s'qlrtlined.intlle.AFP ... : · .: . · · The .. toaloiM~o·s8ctln pioVide ~:brieta-/ptiQrret ~h·~~~ ~n~ ~g ~fated.. . · · : .· ~.......... ... . . .. .. .. .. . . . . . . . .. -~~:yall18tf()n_ot~i·.-.. . ....... . : N..e ~ Co~rrient'~n:Sper.ffic As~ts of THJ . · · . . . .. ~.3: et?(r;rher.t.on.T~onar R!SJcs and .lssi.les .. · · · . ....s.;.i; Final RePOit·~ ~~t!Q~:·; :' : .' : : .. ,· 'Pii~~t.1:· v~··atnu .. ' ·. . .:_:·_.. . .. . . .. ... : ••• :·.:. • •• _,_. -~-•••• •• -•• • •• • • ••' • * :· ... . . . We Will ~ II wluaoon·of Till aS at~ cu~ent -~ ~ upon diseussioils wif;h : ..... . manageiy\~nt ~~ 1t r&iti8W ~ wri~·financial ah<J ~I infotm8tion in .r8Spect .. · _:Qf THf. · We.will Utilize.the folic;Wing va~·on ~-· ,·. · . · _.· :· . . . . : .. · . . · . · · · '1.~.' .. ~:~.-~~~:.-.~.MG'.~~·~-~~:th.·ta;r·~~--~j~ ~-:. · ·:· .... · _.·: , THI .. ri~. ~t:' Its· pfQ)eci~cr futJ,Ire: ~miriQ~·a~ ~-fiows. · ~thar .Wi~h .. ·s · · ... .. ' . eon&ider$tiQ(t of·itS u.rld~iOQ.f&te.~ ancr'<iper~ and ~ahcial'ris~ .. ·: . : .·. . . ; . . . . . . . . . . . . . . . . .. . . . we· ~il_.utili~ ma·.-gament~ fi~~al P,fOie.ci;ons_ari~ tor strategic plari,·for.T~I.::: .. . an~Dab.l~; m de:terininlng ~ fii~ ~rkef ja~ Of th~ l:DC: . : . : · · : . . · . .· . . ~·win.~ ·j~~Oriarrt .to· i~~ .... ~rri~i~.wnh .. ~p&Ct·i~.:fu~re.etistom.;r.:· · . gr~, cuStOmer u~e; eaPJial·~iQJ8ridit1Jre!l:and rnlld·fi!~()r:S rn·~ fln.~n~l · . . ~Oils-. Th~·~meters.wilr' inflUence .required eapjtal!fpendlr:ig aod.' . .. . . . Se~ rev&~:.· : . . ..... : . :. : : .. : . . . . . . ::: . . . ... 2 •. · ~-T~~-~·~·MUiti~.'~~:·KPMG . .Mifvall!'etHI .. . · : . · tMBed ~ com~ pnces·~tt mu!tipl~ Pa~ for other LOCs wltnin 01)tario i~ .... receirt'~i's. using int~tiordnatts'publiCtV'~ta~~{ .· .. ·:. : .. : . . . . . . . . . . . . . ..... o~'r val~tion wiu' als~ ~ b· fair .rh~kef yaJr,le of·~ny.~gu,lated.·t)~~sa~: . . (e.g. ~r~~ ope!'llio~s, green' !'(lergy initlatiws, ·water lieaters}·that may be... . . . . . · .em~V(ithiliTi-11~.: . · ·_.. . ' . . . . ·. ·.. . ·.... . .... We~!· prepare a dftlft.~lulltiOO .re~rt Of THI. and dis'cu~·the d.etBHs and.: ... · · · . cor.iclitsiOJis With tt:i~· Pr~je(it·i~m-before finanzing·out valuatiorr.report. . . . . . . . . : . . . . . .' -. . . . . . . -.. : . . .. : : . . . . . . . ... . . . ... -. . ., . . . . . . . · . . . . . . . . ·. -.. Attachment 22 \~) () Report on Valuation Results Tillsonburg Hydro Inc. 1. Overview of Valuation Methodology In the preparation of this report Henley has relied primarily on the discounted cash flow (DCF) approach to company valuation. This is generally recognized as the theoretically sound approach by academics and valuation professionals. It views enterprises as providers of a stream of cash over time. The present value of this cash flow is the value of the enterprise. Of course, this stream of cash is uncertain and this uncertainty must be taken into consideration. This is done by using a discount factor that suitably adjusts for the risk associated with the predicted cash flows. The discount rate applicable to electricity distribution companies in Ontario is developed in considerable detail as part of the Ontario Energy Board's (OEB) regulatory process. The DCF approach involves the preparation of detailed projections of all the factors that affect cash flow, based on various assumptions. In some cases the degree of uncertainty related to these assumptions is quite high in which case it is deemed preferable to rely on actual data or very short term forecasts and use multiples applied to selected performance indicators to arrive at a value. These multipliers, as is the case with benchmark transactions, are normally derived from transactions involving similar companies. Since the restructuring of the Ontario electricity market was initiated the number of electricity distribution companies (EDCs) has fallen from over 300 to the 75 currently listed in the OEB' s 2011 Yearbook of electricity distributors. Henley has assembled information on over 40 acquisitions ofEDC's which provides a basis for the development of valuation benchmarks that are commonly used. However, it should be kept in mind that EDCs differ in terms of customer density, age of assets, operational efficiency and other features. These differences can lead to significant variations in the benchmarks from company to company. While the DCF approach is the basis for the valuations undertaken here, benchmarks will be used for comparison purposes. In the case ofEDCs the regulatory environment plays a critical role, affecting most aspects of utility operation. Henley's EDC valuation model attempts to capture all of the major features of this regulatory framework from a valuation point of view. The focus is on cash flows rather than the accounting treatment of transactions. The overall process is described in the Appendix. The regulatory environment bears most directly on the determination of the rate base, rates, capital structure and the returns to capital employed. The model uses this information and additional assumptions regarding inflation, sales growth and productivity performance to develop projections of elements ofthe company's income and cash flow statements. In fact the projections are carried out in the context of integrated pro forma fmancial statements over the period 2013-2036. Operating costs and investment spending are affected by growth in the utility's customer base and energy sales as well as inflation and productivity improvements. The cost of the Henley International Inc. Page 1 (} Chart 2 shows comparative operating ratios for the EDC benchmark and for THI again over the period for which the OEB has provided data 2005 -2011. Over the period THI' s OM&A costs relative to distribution revenues have been about 25% higher. .. ) 80 70 60 50 40 30 20 10 0 CHART2 % Average Operating Ratio 2005 -2011 (OM&A/Distribution Revenues} 67.7 EDCAverage THI A second significant factor in the underperformance of ROE has been the use of capital. As indicated above Till has chosen to fmance investment spending almost entirely with equity capital. This has prevented it from taking advantage of the tax and leveraging advantages of the use of debt as prescribed by the OEB in its capital structure guidelines. Graph 3 shows the relative use of debt by the EDC benchmark and by THI over the period 2005 -2011. so 40 30 20 10 0 CHART3 LTD/Total Capital (Average 2005-2011) EDCAverage Henley International Inc. 12.4 THJ Page 3 \ ()· ) growth rate thereafter. This implies a long-term growth rate of three quarters of one percent. The nwnber of customers in the OS < 50 kW class fell between 2007 and 2008 but has increased at a slow but steady rate since then. THI' s recent Cost of Service (COS) rate application with the OEB forecasts a modest increase in customer count to 2013. This trend is expected to continue over the forecast period. Consumption per customer fell between 2008 and 2009 but then increased from 2009 to 2011. It is projected to remain constant over the forecast period. The result is that energy consumption grows at the customer growth rate of slightly over one half percent per year. The number of customers in the GS > 50kW to 499 kW increased from 2007 to 2009 and then decreased to 2011. The COS keeps the customer count constant to 2013. In the longer term this forecast has customer count growing very slowly. Improvements in energy efficiency stopped in 2009 and have reversed somewhat since then. Consumption per customer is assumed to remain constant in the longer term. The long-tenn growth for energy consumption for this class is slightly below one half of one percent per year. The number of customers in the GS > 500 kW to 1,499 kW class was constant from 2007 to 2011. However, energy demand experienced a drop in 2007-2009. It rebounded somewhat in 2010 and has been stable since then. The COS provided for no growth in this class to 2013. In the longer term a forecast of one quarter of one percent per year is assumed. In the GS > 1,500 kW class the number of customers has been halved from 4 to 2 since 2007. The COS projects the customer count remains at 2 to 2013. This is projected to remain the same over the long term with energy growth at a rate of slightly under one half percent per year. Electricity Rates The OEB's rate order is the basis for 2012 rates and for 2013 the projected rates in Till's COS are used. For the following years the OEB's 4th Generation Incentive Regulation (401R) as described in its Renewed Regulatory Framework for Electricity Distributors, October 2012 is followed. This is much the same as 3GIR with respect to the determination of rates for the interim years between rebasing. However, it uses a five- year rebasing period. So in the case ofTHI rates are rebased again in 2018 and then every five years thereafter. Inflation/Productivity Improvement These affect price increases in the years between rebasing under 4GIR as well as cost items such as OM&A, capital spending and the cost of power. It is assumed that inflation proceeds at an average annual rate of 2.25% and productivity improvements used for 40IR average 1.12% per year. This includes the stretch factor assigned to THI. Henley International Inc. PageS J'\ l,_ .. J cost of capital parameters over the past four years is used to detennine rates of return to capital over time. \_) Initial values The basis for the fmancial projections is the financial statements for 2011. The fmancials for 2012 are projected using partial information available and the approved rates for the year. Forecast period The forecast period is 2013 to 2036. However, because of incomplete information, some variables are estimated for 2012 and so effectively the forecast is for 2012 to 2036. The valuation is as at the end of 2012. The residual value is based on the cash flow for the last year of the forecast period. 4. Valuation Results Two valuation results are derived. The first is the enterprise valuation which provides the value of the company. The second is the equity valuation which provides the value ofthe equity investment in the company. The first is based on estimates of the cash flows to both types of capital, debt and equity. The second is derived as the enterprise value less the market value of debt outstanding. As mentioned above the projections are derived in the framework of pro forma fmancial statements using the assumptions just described. (See the Appendix for financial projections). Enterprise value Rate base (Est 2013) Premium on rate base (%) Cash and Working capital Value less working capital NBVFA Premium on NBVF A (%) Benchmark premium (%) Long-term debt Equity value Book value of equity Premium on book equity (%) Exhibit l Valuation Results ($Millions) 11.9 9.5 25.3 3.1 8.8 6.4 37.5 37.1 1.0 10.9 8.9 22.6 The value of the free cash flow discounted at the weighted average cost of capital is $10.4 million. Adding back estimated cash balances at the end of2012 yields a total enterprise value $11.9 million. This represents about a 25% premium on the estimated Henley International Inc. Page7 \ (j~ '~-.· ') ~-- _) THI valuation Comparator average Range of values THI valuation/customer 37.5 Purchase Price/ Customer $1,855 $1,333-2,363 $1,748 Looking at the information from previous transactions the average premium on NBVF A is 3 7% but the range of values is quite broad. Generally speaking the premium paid tends to be higher for larger utilities. Factors that might have had a bearing on the premium actually paid include the age of the assets, the density of the customer base and the potential for economies of operation. Uncertainty regarding the regulatory environment probably also affected the prices buyers were prepared to pay. The potential for operating synergies was an incentive for utility acquisitions. Initially it was expected that there would be a five-year gap between rebasing periods, ample time to realize advantages from improved efficiency. The eventual restriction of this period to three years limited this potential somewhat. However, the OEB's proposal in the report cited above to move to a 5-year rebasing cycle will reverse this restriction. In any case this broad range makes it very difficult to use any particular number as a benchmark for a prospective acquisition or sale. Another common benchmark is the price paid per customer. The average price paid for the ten cases examined was $1,855/customer but again there was a very wide range in individual cases. As in the case ofthe previous benchmark, the price paid per customer is generally higher for larger utilities. The valuation puts THI in the middle of the range for the ten. Since there is no trading in shares of an Ontario EDC it is not possible to observe a market assessment ofEDC value directly. However, there are companies whose major businesses are in regulated areas of the Canadian economy and it is instructive to look at multiples derived from market assessments. In particular we looked at TransCanada Corp., Enbridge Inc., Transalta Corp., Emera Inc. and Fortis Inc. Each of these companies has significant components of their business in unregulated fields but they are generally thought to be primarily regulated utilities. Yahoo Finance Canada provides financial information in each of these companies including an estimated enterprise value (EV). Using this plus information on the market value of the companies' debt we can determine their equity value (EQV) and valuation multiples related to these concepts of value. Exhibit 3 summarizes these measures. Henley Internationallnc. Page9 I ( J variability is limited by the fact that prices and the rate base will be rebased regularly. So, for example, if OM&A costs prove to be higher than in the base case, the divergence cannot persist for more than four years when the rebasing of rates will take this into consideration (provided of course that the cost increase is warranted which is the assumption here). __ ) When considering EDCs there are four principal variables that typically cause deviations from the base case. These are sales volumes, OM&A costs, capital spending and the discount rate used. In THI' s case sales volumes are not likely to change radically but a no-growth scenario was considered. In addition sensitivities are considered for OM&A, capital spending cost of capital parameters and the discount rate. In the first case it is assumed that THI does not realize any productivity improvement so OM&A costs increase at the rate of inflation. The negative impact on enterprise value of this change is partially offset by rebasing every five years where higher operating costs are built into rates. In the second case capital spending is assumed to start from the higher level predicted in the COS with result that capex is 25% higher on average over the forecast period. Again the negative impact on valuation of this reduction in free cash flow is partially offset by increases in the rate base every five years when rates are rebased. Finally, a reduction in the discount rate of one half percent is introduced with no other offsetting factors. This latter sensitivity is not based on a change in OEB capital cost parameters but rather on potential variations in the perceived cost of capital by potential purchasers ofthe utility. There are no offsetting influences. Base Case No Growth HigherOM&A Higher Capex Lower Discount rate Exhibit 5 Sensitivity Results Enterprise Value($ Millions) Ent. Value Difference Diff/1 o/o Change $11.9 11.7 11.3 11.5 12.8 -0.2 -0.6 -0.4 +0.9 -33k -66k -20k +128k The changes in the enterprise value are shown in Exhibit 5 in absolute values and then as the amount of change for each per cent change in the control variable. So, for example, in the no-growth case the last column in Exhibit 5 shows the change in value per l% change in average sales volume over the forecast period relative to the base case. Changes in the discount rate (a drop in the discount rate is shown here) have the highest impact on enterprise value, largely because there is no offsetting influence as there is for all other sensitivities. Higher OM&A costs have the next greatest impact but part of the increase in costs is absorbed in a lower tax liability. As mentioned earlier the influence on enterprise value is also offset by rebasing. These are followed by no growth and higher capital spending. Higher capex, impacts directly on cash flow but it also increases the rate base but with a lag. The effect of the automatic adjustments through regulation is to stabilize the enterprise value of the company. Henley International Inc. Page 11 \ 6. Supplementary Questions Proponents may have additional requests for infonnation which are submitted to the legal agent. A time period is established for the submission of questions. 7. Submission of Binding Offers A format is established for the submission of binding offers. The shareholder is free to accept or reject binding offers, to negotiate a definitive agreement with one or more proponents or to reject all binding offers. The RFP should be drafted to provide the Municipality with the maximum flexibility on how it wishes to proceed. 8. Interviews with Selected Proponents Based on the binding offers the shareholder may choose to interview selected proponents to clarify bids are to explore improvements in bids. 9. Selection and Announcement of Successful Proponent Assuming that one of the proposals is acceptable to the shareholder, that proposal is formally accepted and the negotiation of a definitive transaction agreement, based on the draft sale-purchase agreement, commences. This step ends with the Municipal Council and the purchaser signing the Share-Purchase Agreement. 10. MAADS Application The shareholder and the successful proponent jointly prepare an application for approval \.~) of the transaction by the Ontario Energy Board. / _) 11. Closing Transaction When all the conditions precedent are met, including the OEB approval, the transaction and definitive agreements are closed completing the transaction. Merger Option The merger option is a more customized, lengthier and generally more expensive process in which each party will bear its own transactions costs. Many elements of the process are similar to the sale process but there are important differences. 1. Selection of a Legal Agent The management of the process of merger of an EDC is somewhat more complicated than a sale and requires considerable experience with previous cases. 2. Open or Closed Process Like the sale process, the merger process may be either an open or closed process. In the case of a closed process the Council will have determined the candidate or candidates beforehand and carries out negotiations with no public announcement. 3. Public or Private Participation Assuming it is an open process the Council must stiU decide if it wants to identify potential merger candidates beforehand or open the process to others that may respond to Henley International Inc. Page 13 APPENDIX _) Henley International Inc. Page 15 0"1!121 2;1 z1 183,871,1.22 184;694.,628 185;664,577 186;493;1113 .2,25 . 2.25 2.26 2.25 -_1,,12 1.12 1.12 ) Henley International Inc. Page 17 ;' ( ~) "-) ) Report Title: Report No.: Author: Meeting Type: Council Date: Attachments: RECOMMENDATION: STAFF REPOR,T DEPARTMENT THI Resolution -Request to Shareholder to Authorize the Board of Tillson burg Hydro to Investigate the Divestiture of Tillson burg Hydro Inc. CAO CL-08 David Calder, CAO IN-CAMERA COUNCIL MEETING MAY 13,2013 Resolve that Council in accordance with clause 5.0 of the Memorandum of Understanding and Direction, dated January 19, 2010 between the Town and THI, authorizes the Board of Directors of THI to proceed with the investigation of a potential merger or sail of THI. EXECUTIVE SUMMARY At its meeting of April 16, 2013, the Board of Directors of the Tillsonburg Hydro Inc., passed the following resolution. Moved By: Councillor Klein Seconded By: Board Member Bossy RESOLVE THAT the Board of Directors of the Tillson burg Hydro Inc., (THI) consider it to be in the best interest of the THI and the Town of TIIIsonburg (Town) as its sole shareholder to investigate an (A) Merger Or (B) Sale of THI and in accordance with clause 5.0 of the Memorandum of Understanding and Direction, dated January 19, 2010 between the Town and THI which states the Board, in the spirit of the agreement, is to seek the approval of the Town prior to the Board undertaking or causing to undertake, authorizing or approving the entering into discussions regarding potential merger, amalgamation, or divestiture ofTHI; AND THAT the Board of Directors of THI obtain approval of the Town as the sole shareholder to investigate a potential merger or sale of THI; AND THAT the Board of Directors of THI obtain a report from staff on a process and i ( -, \} Estimating Transactions Costs The level of transactions costs related to sale of an electricity distribution company (LDC) depends upon a number of factors. To begin with it depends upon whether a single LDC is being sold or its holding company along with other subsidiaries. Assuming we are talking about just the LDC and that the LDC is small, say less than 10,000 customers the cost can still vary considerably depending upon the complexity of the sale. Some important factors are the following: • Number of proponents -many interested parties prepared to request a copy of the RFP increases the costs • Communications requirements of the shareholder-if Council wants to stay closely involved with weekly face-to-face meetings on progress the cost increases • Preparation of data-staff of the utility and municipality can substantially cut down on the cost of organizing and providing information for the Data Room which is critical for the proponents to undertake their due diligence • Preferred bid -the quicker a preferred bid is identified and the smoother the negotiations leading to a signed sale-purchase agreement the lower the costs; this requires quick and effective processing of the submitted bids With these various caveats I can provide the following estimates prepared jointly by Henley and Borden, Ladner, Gervais, (BLG) the most experienced legal advisor in the field and a firm with whom I have worked on over thirty occasions, including the recent Norflolk Power-Hydro One transaction. Small LDC Share Sale -Restricted Bid Process/Full Involvement of LDC Staff -very limited bid process (pre-identify small number of bidders (3)); -LDC staff is relied upon to conduct a comprehensive search and to produce due diligence materials -no public stakeholdering ( no community open houses, etc) -no affiliate transactions included -negotiating legal agreements -preparing MAAD application -uncontested OEB process (no opposing intervenors at OEB hearing to approve the transaction) Professional Fee Range for legal fees-$100,00 to $150,000 Professional Fee Range for financial advisory fees $20,000-30,000 Small LDC Share Sale-Expansive Bid Process/ Larger Number of Legal Issues to be Managed -bid process is open and competitive (many bidders potentially like in Norfolk) -BLG oversight in due diligence process to ensure all documentation is properly produced and posted -receiving/addressing questions from proponents -arranging for bidder site visits i CJ Attachment 24 . _) ) 0 Part of the THI strategic plan adopted in 2009 identified four options which included sale, merger, growth and do nothing options. Growth Ootjon (Other Options) THI started the growth option review In October 2009 which included a RFP to investigate Renewable Energy in order to generate revenue for the shareholder. A RFP was completed however the full scope of the RFP was not fully commissioned as one of the responders suggested looking at micro hydroelectric project through kinetic turbines in the Big Otter River. A pre-liminary feasibility study concluded the ROI on this type of project was not satisfactory resulting in any further action on this item or continuance of the Renewable Energy growth study. In order to fully explore the Regulated and Non-Regulated growth options a consultant report would be required on a value based RFP process estimated to cost $75-100,000. This study could look at market opportunities and partnerships to create growth and revenue. Sale Ootion The THI board recently retained Henley International and Associates to determine the value of THI based on a cash flow analysis approach (see attached report from Henley International dated March 22, 2013). The report summarized the enterprise value at $11.9M. 1} Most recent transactions have been at the rate of 1.3 times the book value. On this basis, "---THI could expect a nominal value of $15.5M ($2275/customer). __ ) The recent sale of Norfolk Power to Hydro One equates to a market value price of 2.24 · times book value ($3,900 per customer). If this sale price were applied to the sale of THI then one would expect a market value of $26.6M. On this basis, the sale value of THI is estimated between $15.5-26.6 M. (Interestingly, back in 1999 Hydro One was reported offering bids as high as $5,000 customer which would place value of THI at $34M). In addition, Henley International has provided information related to a sale process in terms of legal and consultant fees. The values are based on a Small LDC Share sale Restricted Process ($180,000) vs. an Expansive Process ($380,000) (See attached information sheet provided by Henley International Inc.). The estimated costs are based on assumptions of staff involvement, OEB approval, legal and consultant involvement. Based on the required expertise it is suggested the latter of the costs should be expected. In the Norfolk sale the purchaser covered the transaction costs up to a limit. If the process becomes lengthy and protracted then the vendor (THI) would pick up these extra costs. 2 D President ._) Similarly, costs to manage a Merger process would be based on a restricted process vs. and expansive process and the level of staff, legal and consultant involvement and subject to OEB approval. The major steps in a LDC merger as identified by Henley International Inc. March 22, 2013report are as follows: 1. Selection of Legal agent. 2. Open or closed process. 3. Public or Private Participation 4. Confidentiality Agreement. 5. Business Case for the Merger. 6. Preparation of the Merger Documents. 7. Selection and Announcement of Successful proponent. 8. MAADS Application. 9. Closing Transaction including OEB approval. Next steps At the May 2013 meeting limited board discussion suggested a sub-committee of THI may be appropriate to investigate the strategic options which would be a good idea as this process will be somewhat lengthy and time consuming. In addition, our solicitor, Aird and Berlis has offered to present to our board further information at an upcoming meeting free of charge regarding our options. They have experience in Mergers and Acquisitions of Utilities in Ontario. FINANCIAL IMPACT/FUNDING SOURCE N/A APPROVALS General Manager Name/Signature Treasurer Name/Signature S.T.Lund, P.Eng. DATE:12June,2013 DATE: 4 President I () Estimating Transactions Costs The level of transactions costs related to sale of an electricity distribution company (LDC) depends upon a number of factors. To begin with it depends upon whether a single LDC is being sold or its holding company along with other subsidiaries. Assuming we are talking about just the LDC and that the LDC is small, say less than 10,000 customers the cost can still vary considerably depending upon the complexity of the sale. Some important factors are the following: • Number of proponents -many interested parties prepared to request a copy of the RFP increases the costs • Communications requirements of the shareholder-if Council wants to stay closely involved with weekly face-to-face meetings on progress the cost increases • Preparation of data -staff of the utility and municipality can substantially cut down on the cost of organizing and providing information for the Data Room which is critical for the proponents to undertake their due diligence • Preferred bid -the quicker a preferred bid is identified and the smoother the negotiations leading to a signed sale-purchase agreement the lower the costs; this requires quick and effective processing of the submitted bids With these various caveats I can provide the following estimates prepared jointly by Henley and Borden, Ladner, ~ervais, (BLG) the most experienced legal advisor in the field and a firm with whom I have worked on over thirty occasions, including the recent Norflolk Power-Hydro One transaction. Small LDC Share Sale-Restricted Bid Process/Full Involvement of LDC Staff -very limited bid process (pre-identify small number of bidders (3)); -lDC staff is relied upon to conduct a comprehensive search and to produce due diligence materials -no public stakeholdering ( no community open houses, etc) -no affiliate transactions included -negotiating legal agreements -preparing MAAD application -uncontested OEB process (no opposing intervenors at OEB hearing to approve the transaction) Professional Fee Range for legal fees-$100,00 to $150,000 Professional Fee Range for financial advisory fees $20,000-30,000 Small LDC Share Sale-Expansive Bid Process/ Larger Number of Legal Issues to be Managed -bid process is open and competitive (many bidders potentially like in Norfolk) -BLG oversight in due diligence process to ensure all documentation is properly produced and posted -receiving/addressing questions from proponents · · ) -arranging for bidder site visits j () Attachment 26 ) ·--' \ I rj \ .. ~ \_) II. Background A. Corporatization of LDC's: • The Electricity Act 1998 1. Sole shareholder 2. Multiple shareholder 3. Outright sale B. Consolidation of the LDC Sector 1. Transfer Tax Holidays 2. Regulatory burden 3. Financial payout 4. Economies of Scale II. Background (cont'd) C. Distribution Sector Report 1. Consolidation: Means vs. Ends 2. Whowins? 3. The wrong tools: "Top down" vs. incentives through rates 4. Ministerial back~pedal D. Recent Transactions 1. Callus/Power Stream 2. Norfolk/Hydro One 3 4 2 I (J 'J Merger IV. Regulatory and Financial Considerations 1. MAADs Application 2. Rate harmonization 3. Deemed Debt/Equity Ratio 4. Third party debt FeaiiJJe&'lssue&: 1. Bhan>haldersAgreement 2. VotD""'Is 3. A-lonolv- 4 . .-.-ordlvfdenllll 5. lndopendenco of l!oard 6. Rigltlto-"'ldirec!ors 7. RestliollonsonSaleof ShaJB!IdiiUIIon 8. Equlyvs. Oobl 7 8 4 \ j (_) '.J VI. Transaction Steps A Board and Council approval of process B. Valuation C. RFEI (optional) D. RFP E. Evaluate Proposals F. Select Preferred Bidder(s) G. Negotiate Definitive Agreements H. Board and Council approval of Agreements I. Execute Agreements J. OEB MAADs Application K. Closing L. Implementation VII. Conclusions A. Create process that considers all factors B. Take into account financial and political factors C. Community buy-in to process and ongoing communications is vital D. Avoid "crisis~~ mentality 11 12 6 ' \ ; c._) Attachment 27 \ ) C) of a merger or sale, for the most part will Impact the shareholder, being the Town of Tillsonburg, It Is Important to be aware of such costs In order to understand the full financial Impact on the shareholder of any recommendation by the board of directors. The Town of Tmsonburg Is in a unique situation due to the purchase of services structure of THI from the Town of Tillsonburg through a Master Service Agreement and the supply of labour and equipment by the shareholder to the utility on a cost recovery basis. The Board of Directors also discussed seeking an agent/advisor to guide the shareholder through the sale or merger process. A review of the profession~! assistance required to execute a sale or merger will be addressed In this report. · REASQNS FOR REVJEWII'JG A SALE OR MERGER Over th~ course of the last number of months, staff have heard numerous discussions about why a sale or merger might be pursued at this point" In time. Subsequently, as Board members know, the County of Brant has gone to the market to seek buyers for Brant County Power. In reviewing the material the County of Brant posted on their web site, staff cannot help but see the parallels to the Tlllsonburg Hydro· Inc. discussion. The major trigger points for a sale of by the County of Brant seem to have been the following: • Maintaining competitive electricity rates for customers· while continuing to provide a system that Is safe and reliable; • Increasing regulatory and service demands for local · electricity distribution companies; · · • The conclusions of the Ontario Distribution Sector Review Panel which recognized the need for a more efficient electrical distribution models and recommended consolidation of LDCS. It should be noted, that similar to discussion by the THI shareholder, the Brant County Council put some emphasis as part of their decision making on the potential income streams that could come from reinvestment of proceeds for use In offsetting infrastructure .·I ~. . CON$ULTADON/COHMUNICATION Regardless of which method of divestiture Is ultimately dedded upon, the management of the process of a sale or merger of an LDC is a complex one that requires the skills of an experienced agent and financial advisor. As the Board Is well aware, the capacity to. drive this process or the expertise required does not exist within THI or the Town of Tlllsonburg. As such, in order to get the best results, a legal agent who has experience in negotiating successful transactions and has a broad connection with potential bidders Is desirable. It should be noted that in the case of a sale, most transaction costs, which includes the cost of legal .and flna·nclal experts, can be recovered to some degree from the purchaser. A merger proposition does not provide for the ability to recoup transaction related costs as e~ch party to the merger wlll be responsible for their own costs. Members of the Board will recall that Henley International Inc. prepared a "Rep·ott on , · ·) Valuation Results" for the THI asset. This Is an important step toward dedslon making D Page216 CAO { \ · would be expected that the County would place the service with another service provider \_. .. J for cost effective reasons. 'j \_ __ j The following cost analysis, presented for discussion purposes, is staff's best estimate of known costs and the estimated ftnanclallmpact to the Town. The following needs to be noted: · · • The costs are at a point In time and will Increase for at least the employee tennination compensation related expenses as time moves on. • The tax Implications of a sale occulTing are beyond the scope of this report. • The risks inherent with any sale In terms of the market valuation of the Balance Sheet vers!JS the book valuation are not considered. • A sale and merger are considered synonymous. Under a merger, the operational efficiencies can only be realized If the service delivery is executed from the host corporation and not from THI. • The potential annual return to the Town from the invested sale/merger proceeds Is not considered. • All larger known contracts have been analyzed/reviewed for nnancial Impact on terminatioh or on sale. For example, .the Hams software contract was reviewed and confirmed that the contract requires 60 days cancellation notice at no penalty or additional cost. · • Audit costs for the town have been assumed as flat or unchanged as a result of a change in the buslne~s model. • The impact on_ the Town operations Is ignored although there would be . substantial available capacity at the 10 Usgar Street Customer Service Centre. • The potential Impact on economic development initiatives Is not considered. • Any costs associated with the Installation of banners, Christmas wreaths and flower baskets are unknown and not considered In this calculation. With regard to termination In Ontario, an employee's compensation entitlements are based on three (3) components: I) statutory notice, II) statutory severance pay, and ill) common law notice. . · i Statutory Notice Is required under the Employment Standards Act, 2000. An employee's entitlement Is based on their completed length of ser\tlce with the organization to a maximum of eight (8) weeks. Notice can be provided as working notice or pay in lieu of notice. Statutory severance Pay Is the second legislated component of entitlement as per the Employment standards Act, 2000; however, specific criteria must be met In order for an employee to be entitled to this amount. The employee must have been with the organization for more than five (5) years, and the organization must have a payroll that exceeds 2.5 million dollars per year. This component Is also based on an employ~e's completed length of service with the organization up to a maximum of twenty-six (26) weeks. Severance pay must be paid in one lump sum upon termination of employment. The third component of an employee's entltletnent is Common Law Notice. This amount Is not provided through Employment Standards Act, but rather through the Ontario courts In / ) which they have previously awarded employees compensation above and beyond the D Page4/6 CAO \ i () \ \, )) ,') In order to be prepared for any transaction of the magnitude that Is envisioned In a possible sale of THI, It has been suggested by other entitles that have gone. through a sale of an asset as valuable as a utility Is to ensure that in advance of any proceeds coming to the sh.areholder, that an Investment PQI!cy specific to the use of the proceeds from any sale of the THI asset be established. It Is better to have a policy discussion well In advance of the receipt of any proceeds. As noted previously In this report, Finance staff has reviewed the various costs that the Town as shareholder may Incur as a result of the sale of THI. It is Important to understand these costs In order to negotiate a sal~ and to ensure any proceeds through the sale process be used to cover any disentanglement costs such as severance, contractual obligations, etc. APPROVALS Author Date: Name/Signature David Calder September 9,. 2013 Director Date: Name/Signature Darrell Eddington September 9, 2013 Finance Date: Name/Signature Darrell Eddington September 9, 20:13 D Page6/6 CAO . I I , ) (}, · .. -' 6. SVPIJlemontary Questions . . ' \ ProPonents may have additional requests for information whk:h arc 8libmitted to the legal ageat. A time period is established for the submill&ion of questlOD&. 7. Submission ofBindiug Oifers . A founat is established for the submission of binc:tins offers. Tbe abarebolder is free to aoeept or rojeot binding otftn, to nego1iate a defblltlve aareement with one or more propmeot& or 1o ·reject all binding offers. The RFP should be drafted to provide the Municipality with the maximum fleDDillty on how it wishes to proceed. 8. Interviews with Selected Proponents . Based on the binding offcn tho shareholder may choose to interview seleoted propments to clarify bids arc to explore ~ants in bids. · 9. Selocti.on and Ann0Uileel11eat of s~ Proponom A118l1Dl,ing 1fJat one of the proposals is acceptable to tho lhamboldet~ that proposal it formally accepted mel the nqotiatiou of a definitive transaatlon agreement. based on 1he draft saJe._purcbase apemen~. commfiDOel. This step ends with the Mtmicipal Counoil and the purchaser signing the Sharo-Purohase Agreement. 10. MAADS Application . The shareholder and the successfW. pr~t jointly prepare 1111 application for approval of tho tnlllsaction by Cbc Ontario BneraY· Board. 11. aosiag Transaction · · When all the conditions ~ are • iDc1udins the OBB approval. 1be 11an8acrtion and definitive agreements aNi closed completing the transaCtion. MeiJer Opt1o• Tho mqer option ls a more cuatmdzed, leqthier and generally more expensiw process in which each party will bear its own tranaactiODS costs. Many elemeDts oftho progoss_are similar to the sale process but there are important~ 1. Selection of aLepl Apnt Tho management of ~ procesa of JDel'8'll' of an BDC is llODl8What more complicated than a B8le and teqUirea CODfiderable experience witb. previous oa&eB. 1. Qpen or Closed Process Lib tbD sale process, tho IDeiJI'I' procasa may be either an open or closed procC118. In the ease of a closed process ihe Council will have detemriDecl the cencii~ or candidates bet'onlhand and carries out DqJOtiations with no public ann0\1tlCC!IMill 3. Public or Private Participation Assumin& it is an open process tbe Council must &tiD decide if it wants to identify potential merger c:aactidates boforehand or open the prOcess. to others that !MY respond to Henley Intematlonallm:. Page13 ._) ___ -------·--------··-·---·-·------·- 65 I \ _) Estimating Transactions Costs The level of transactions costs related to sale of an electricity distribution company (LDC) depends upon a number of factors. To beRin with It depends upon whether a sinale LDC is bein& sold or-its holding company alona with other subsidiaries. Assuming we are talldn& about just the LDC and that the LDC is small, say less than ~0,000 customers the cost can still vary · considerably depending upon the complexity of the sale. Some Important factors are the following: • Number of proponents -many interested parties prepared to request a copy of the RFP increases the costs · • Communications requirements ofthe shareholder-if council wants to stay closely involved with weekly face-to-face m~etlngs on progress the cost Increases • Preparation of data-staff of the utility and municipality can substantially cut down on . the cost of orpnlzlng and providing lnformat!on forth' Data Room which is critical for the proponents to undertake their due diligence . • Preferred bid -the quicker a preferred bid is identified and the smoother the nesotiatlons leading to a slsned sale-purchase agreement the lower the costs; this requires quick and effective processlna of the submitted bids With these various caveats I can provide the following estimates prepared jointly by Henley and Borden, Ladner, Gervais, (BLG) the most experienced legal advisor In the field and a firm with whom I have worked on over thirty occasions, indudlng the recent Norflolk Power-Hydro One transaCtion. Small LDC Share Sale-Restricted Bid Process/Full Involvement of LDC Staff -very limited bid process (pre-Identify small number of bidders (3)); . -LDC staff is relied upon to conduct a comprehensive search and to produce due diligence materials · · -no public stakeholdering ( no community open houses, etc) -no affiliate transactions lnduded ·negotiating legal agreements -preparing MAAD application -uncontested OEB proces$ (no opposin8 intervenors at OEB hearing to approve the transaction) Professional Fee Range for legal fees-$100,00 to $150,000 Professional Fee Range for financial advisory fees $20,000-30,000 small LDC Share Sale-Expansive Bid Process/ l,amer Number of Legllssues to be Managed -bid process Is open and competitive (many bidders potentially like In Norfolk) -BLG oversight In due diligence process to ensure all documentation is properly produced and posted ..recelvlnsfaddressing questions from proponents -arranging for bidder site visits \ J (-) . ' "' ) Attachment 28 ) (J '·-···· 'J Attachment 29 -0. ,_,j Two significant reports released in 2012 on the future of the Electricity Distribution Sector; both of these reports were reviewed by County of Brant Council. ~\ j BACKGROUND -OF 2 ~ -..('-. ' \.._,_..,.... -----··--·----...... ·······-------··--------·---·----------·-··-.. ------.--.. ---·--·------------------- Upon presentation of the staff report, Council requested a further report on "future options for the County's Local Distribution Company". ~ BACKGROUND -~\ -----------------·-·-···-----------------···-·--·-·-·-·---·---·-·---·----------·-·--............................... ----------·---·-·--------·-·---·--·-·-· ------·--------... -........................ . Council weighed each option against the following criteria: ,-...f'""-- \......../ 1. The impact on Brant County Power's customers (rates, service, performance) 2. The impact on Brant County Power staff (employees, collective agreements, local presence) 3. The impact on the citizens/taxpayers of the County of Brant (financial return, capital investment, future commercial/industry risks) ~"'\ _,) BACKGROUND ~' ···-·-·~·--·~-- Council directed that proposals for potential buyers of Brant County Power Inc. be solicited. Further, Council resolved that proposals be considered based on the proponent's willingness to make commitments as follows ..• /'"'-~ ,-, 1~\ '..,/, ) MOVING FORWARD ,....-.__, '-... -~··-·-···--·~ ... ·--·-------·---······-------···----·--··--~·--·-···-····. . -.-·-·-..... -·-··---·---- Potential Transaction Partner proposals will be considered which have a: Good track record and commitment to worker safety and public safety. ~·. C::\ --"' / MOVING FORWARD \. '-- Potential Transaction Partner proposals will be considered which: Commit to continue to invest capital in electrical distribution infrastructure within the County of Brant service area . . ~ )::::::\ ) MOVING FORWARD ··~ ----.. -·-·-·---··----··-·-----·-------------------·----- Potential Transaction Partner proposals will be considered which: Commit to_ support the County of Brant community through involvement in local activities and events. r-0 -------·· ,r'\ }~.I / ~--·-··-···' .. ··-· . MOVING FORWARD ~ ., ---------------·--·-·--·--··----·····-····--------············------·-···-··-·-----·-····-------------------------------------------- Potential Transaction Partner proposals will be considered which: Commit to competitive electricity distribution rates for the customers of Brant County Power Inc., including, but not limited to, provisions to maintain distribution rates at comparable levels to what would be charged if the utility remained under municipal ownership, and provisions on managing rate harmonization. ~' ___. ... ·0 / --~---·. ---·· ·······-···· ... --··-· --·-··--·-··------·-- MOVING FORWARD ~ ----------~-·-··· .... ---~--·····-···--·-·------- The Request for Proposals (RFP) that is being developed to solicit potential buyers for Brant County Power Inc. will specify that the County is seeking proposals that make these commitments. The RFP could also include other conditions arising from matters raised during these public information sessions. ~··. ____ / 0) / MOVING FORWARD ~ '- Taking the High Road - To Improve Customer Service in the Electricity Distribution Sector September 12,2013 Background Paper l_) Background Paper CONTENTS Executive Summary ................................................................................................................................. 3 Introduction ............................................................................................................................................. 4 What is all the fuss about? ....................................................................................................................... 5 The Bigger Picture: Where consensus exists ......................................................................................... 18 Alternatives ........................................................................................................................................... 32 Advantages of the Local LDC ................................................................................................................ 34 Recommendations and Considerations .................................................................................................. 35 Appendix A: Consensus Accord Survey Results .................................................................................... 39 Acknowledgements The Accord would like to acknowledge the support and guidance of the Steering Committee formed for this report and in particular, the dedication and leadership of the Chair and Vice Chair of the committee. In addition, the Accord thanks MNP LLP and the team of Craig Sabine, Daniel Bida and Sarah Keyes, who provided extensive consulting and technical advisory assistance in development of the report and its analysis. Responsibility for the final product and its conclusions is reserved to The Consensus Accord alone and should not be assigned to any reviewer or other external party. September 12, 2013 Page 12 Background Paper Figure 1 : 2011 Average Monthly Residential and Commercial Delivery Cost per Customer by LDC Size Range1 . $50.00 $45.00 $40.00 $35.00 $30.00 $25.00 $20.00 $15.00 $10.00 $5.00 $- small(< 12,500) Medium {12.S00to 150.000) Large Extra-large (150,000 to (>500,000) 500,000) $250.00 .---------- $150.00 $100.00 $50.00 $- SmaU(< 12,500) Medium l.aflll! Eldra-lall!e (12,500 to (150,000 to pSOO,OOO) 150,000) 500.0001 This report builds a case that dismisses forced or widespread consolidation as the only solutions that lead to optimization in the sector. Our recommendations incorporate flexibility, taking into consideration a variety of unique industry factors and providing a series of tools that will lead to enhanced efficiency· and service through cooperative organizations between utilities, a streamlining of regulatory agencies and their activities and voluntary consolidations. There are numerous specific examples of successful actions that have occurred to date, where efficiencies and synergies have been obtained without formal consolidation or M&A activity. '--) Our overall recommendations include the following: 1. Development of Facilitative Policy ~To incant strong business-based merger activity and remove simple barriers to increase the flexibility for innovative solutions to enhanced efficiency for all LDCs. 2. Localized Long-Term Energy Planning -Includes LDCs and their local communities. 3. Focus on Regulatory Efficiency-Promotes improvement of mechanisms to deliver sector-wide efficiencies and minimize the costs of regulation. 4. Voluntary Consolidation and Collaboration -Suitable in some instances where clear benefits and a strong business case exists, including amalgamation of Hydro One distribution assets. Our conclusion is that a "one size fits all" approach to consolidate the existing 75 LDCs into 8 to 12 regional distributors simply does not make good business or socioeconomic sense in an electricity market as diversified as Ontario. Ultimately, we believe that mass consolidation into 8 to 12 regional distributors is not the answer. The recommendations provided in this report can achieve the same goals of cost efficiency, enhanced service, and focus on the customer, as those contained in the Sector Panel Review Report, without requiring formal consolidation. / .· __ ) / 1 Your Electricity Utility, Ontario Energy Board. 2012. September 12, 2013 Page 14 Background Paper \ \ :) THE DISTRIBUTION SECTOR PANEL REPORT / _) Prior to the release of the DSRP, a comprehensive six-month sector-consultation process was conducted. The report aims to represent, broadly, the input and outlook of various market participants, although at times, it seems to overlook balanced comment from LDCs of all sizes and operational models. The DSRP describes the criticality of the electricity sector as a building block of a strong economy and proposes that aggressive consolidation of Ontario's distribution utilities will lead to substantial cost efficiencies, enhancing our competitiveness as an economy. The following section discusses some of the findings and recommendations of the DSRP in detail and presents alternative analyses that suggest differing and/or conflicting conclusions. Our analysis demonstrates that the DSRP interpreted data to over-simplify operating assumptions and exaggerate the cost savings of consolidation. Transparent application of publicly available sector data results in very different conclusions to those found in the DSRP. These conclusions have been demonstrated by numerous analysts, academics and market participants over time and we are again demonstrating the dynamic nature of the distribution sector in the sections that follow. We believe that Medium-sized utilities, and in many cases, Small utilities, can be as competitive and efficient in their operations as Extra-Large ones. Furthermore, Small utilities can often have lower costs and provide the highest levels of customer service and responsiveness. This report explores a number of DSRP inconsistencies and elements of speculation that are unclear or questionable, including interpretation of cost efficiencies (OM&A), customer pricing, performance and reliability, labour costs and historical merger results. This section also presents some key findings from the DSRP that are important for consideration and those that will allow all LDCs, regardless of size, to improve service and enhance the customer experience. DSRP Critical Review In reviewing the DSRP, there are a number of inconsistencies identified in the document that warrant further discussion and analysis in order to garner a complete picture of the distribution sector. The discussions that follow have been developed based on the principal objectives of consumer focus, enhanced effiCiencies and preparation for the future. It is believed that further analysis of DSRP conclusions reveals a tremendous amount of systematic uncertainty, which will inhibit the effectiveness of holistic and prescriptive policy action as the Panel has recommended. The DSRP has recommended the consolidation of Ontario LDCs into 8 to 12 regional distributors that are large enough to deliver improved efficiency and enhanced customer focus, while at the same time maintaining connections with local communities. The fundamental recommendations suggests that there should be 2 regional distributors to serve the north (one in northeast and one in northwest), leaving 6 to 10 regional distributors in southern Ontario. Per the DSRP, any new regional distributor in southern Ontario should have a minimum of 400,000 customers. Toronto Hydro, with an existing customer base in excess of 700,000, is recommended to be one of the 8 to 12 regional distributors, as it has already consolidated with a number of smaller local LDCs in the past. A "one size fits all" mindset is counterintuitive when considering the goal of putting the customer first. In such a diversified market as Ontario, carte blanche approaches can often lead to adverse effects for many. The analysis performed below serves to identify the inconsistencies within the DSRP and shed light on some of the core issues that exist, if an unsophisticated consolidation of Ontario's LDCs were to be carried out. A particular emphasis has been placed on the number of customers and the relevant costs incurred per customer. Cost comparisons identify problems in the interpretation of data analyzed by the DSRP and the final recommendations of the Panel. September 12, 2013 Page 16 ,. _ _) Background Paper Figure 2: 2011 Average Monthly Residential Delivery Cost per Customer by LDC Size Range3 $50.00 $45.00 $40.00 $35.00 $30.00 $25.00 $20.00 $15.00 $10.00 $5.00 $- Small (< 12,500) Medium (12,500 to 150,000) Large (150,000 to 500,000) $44.20 Extra-Large (>500,000) Figure 3: 2011 Average Monthly Commercial Delivery Cost per Customer by LDC Size Range4 $250.00 $200.00 $150.00 $100.00 $50.00 $- OM&A Costs Small(< 12,500) Medium (12,500 to 150,000) Large (150,000 to 500,000) $211.69 Extra-Large (>500,000) The DSRP identified Operational, Maintenance and Administration (OM&A) costs as a key metric to consider. OM&A costs are a substantial component of operating a utility company and these costs are passed onto the customers through delivery costs charged on monthly electricity bills. Using OM&A cost per customer as a proxy, the DSRP hypothesizes that customers of smaller LDCs pay more for their service than customers of "optimally" sized LDCs, defined as a utility with a minimum of 400,000 customers in the DSRP. However, the analysis in Figures 2 and 3 above shows this to be a flawed 3 1bid. 4 1bid. September 12, 2013 Page 18 Background Paper \ , ') Figure 4: 2011 Average Monthly Commercial Delivery Cost per Customer by LDC Size6 ' / ( ) OM&A Cost per Customer $~.00 .------------------------------------------------- $195.00 $190.00 $185.00 $180.00 $175.00 $170.00 Between 100,000 to 150,000 Customers Between 150,000 to 5(]0,000 Customers The DSRP recommendation for mandatory consolidation of Ontario LDCs to 8 to 12 regional distributors is not supported by an analysis of reduced OM &A costs. It is therefore questionable to assume that consolidation of smaller and mid-sized utilities, with any other larger Ontario utility, will have an immediate net OM&A cost benefit that consistently applies to customers. Figure 5: Annual OM&A Cost per Customer by LDC Size Range7 $350 $300 $250 $200 $150 $100 $50 $- Small (<12,500) Medium (12,500 Large (150,000 Toronto Hydro Industry Average to 150,000) to 500,000) (>500,000) As a measure of the actual costs paid by the customer, OM&A costs should also be considered carefully for artificial adjustment or veiled application. In comparing Figs. 2, 3 and 5, an inconsistency is identified in the data. If OM&A costs are truly passed on to the customer in the delivery charges on their monthly electricity bills, Fig. 5 would correlate directly to Figs. 2 and 3. The primary reason this alignment does not exist is due to the fact that OM&A is a function of the utility's capitalization policy, which is strictly an accounting policy choice without any cash consideration. Larger utilities have more aggressive capitalization policies than smaller utilities. For example, Toronto Hydro has a capitalization policy for all borrowing costs on construction-in-progress assets (called "Allowance for Funds Used During construction" or "AFUDC"). In 2012, approximately $2.3 million was removed from interest expenses and 6 2011 Yearbook of Electricity Distributors, Ontario Energy Board. 2012. 7 2011 Yearbook of Electricity Distributors, Ontario Energy Board_ 2012_ September 12, 2013 Page 110 \ } C1 ) Background Paper delivery models, unavoidable because of expanded service territory and a greater diversity of customer type. As an example, Hydro Ottawa has attempted for years to purchase the assets and territory of approximate 47,000 Hydro One customers embedded in their service territory. The case is clear, Hydro Ottawa provides less costly service with higher reliability10. However, the service areas have not been transferred or sold and those customers continue to pay higher rates than their neighbours. We believe it is important to assess the existing metrics and determine whether, and how much, consolidation will benefit the customer in terms of reliability and responsiveness. Is consolidation and sector disruption worth the expected changes to reliability and responsiveness? Fig. 6 represents the average total hours of system interruption for all of Ontario's LDCs during 2011 based on their size. The figure clearly shows that the highest system interruption hours are incurred by Extra-Large Utilities, which calls into question the potential reliability of utilities in Ontario of the DSRP's proposed size. The ability of larger consolidated LDCs to be as responsive as the local LDCs that currently serve Ontario's communities is questionable. Larger utilities spread across rural areas will face the same challenges in maintaining the system as today's currently geographically diverse Extra Large utilities. Fig. 6 also shows a narrow margin in performance between Small, Medium and Large LDCs. It therefore seems egregious to consider fundamental and disruptive changes to the sector for the upside of less than one hour of saved interruption time. All of the other benefits that local utilities provide their customers likely outweigh the potential for small and unproven improvements in reliability indices. In a more likely scenario, if the DSRP recommendation were to be implemented, the industry average of total hours of system interruption is just as likely to increase due to reduced local control over distribution assets resulting from the elimination of local LDCs. The data below is inconclusive given that the largest utilities have the highest outage ratings. Figure 6: System Average Interruption Duration Index (SAlOl) by LDC Size Range11•12 20.00 14.47 15.00 10.00 5.00 Small & Medlum (Up to 150,000 customers) Large (150,000 to 500,000) Extra-Large (>500,000) Industry Average Fig. 7 represents the average frequency of system service interruption for all of Ontario's LDCs during 2011 based on their size. Similar to the above, Fig. 7 demonstrates that the highest average frequency of service interruption is incurred at the Extra-Large Utilities, which again calls into question the impact of consolidation on the reliability to customers on the whole. If the DSRP recommendation were to be implemented, the industry average of total frequency of system interruption will likely increase due to reduced local control over distribution assets resulting from the elimination of local LDCs. In the case of 10 Ottawa Citizen, Rural Hydro Customers Stuck with Hydro One Indefinitely, Hydro Ottawa Says, June 26,2013 11 2011 Yearbook of Electricity Distributors, Ontario Energy Board. 2012. 12 Within the Large category, there are no LDCs with a customer base in excess of 400,000. September 12, 2013 Page 112 ) C.) \.) ) Background Paper Economies of Scale: Historical Consolidations The DSRP assumes consolidation could result in net sector-wide cost savings of $1.2 billion. We believe that cost savings are likely. However, it is unclear and unlikely that consolidation and forced M&A would lead to results on such a scale. It is critical to consider historical examples of consolidations and their actual financial results with an objective eye. In determining whether consolidation is the ideal solution to capitalize on efficiencies, it is worthwhile examining historical results and lessons learned. In benchmarking against actual historical examples, a more definitive conclusion can be reached on the overall cost impact to the customer. The following analysis explores the total actual annual OM&A costs per customer, as a result of past LDC consolidations using the best publicly available data. This is in contrast to relying on an assumptions-based projected total cost savings figure over a ten year period, as performed in the DSRP. Several economic studies have concluded that few real welfare gains have emerged from previous efforts to consolidate LDCs in Ontario. According to Cronin and Motluck (2007), research undertaken for the OEB found little or no evidence of cost savings as the utility size increased, challenging the norm of larger always being better. More recent research has also found that no economies of scale are typically realized by distribution utilities and some economists have actually found diseconomies beyond a certain moderate size 16• The largest distribution utilities in the province have historically operated on higher OM&A costs per customer and lower productivity rates when compared to smaller municipal electric utilities and restructured municipally-owned LDCs. The following sections demonstrate that quantitative evidence does not support the claims that OM&A costs per customer have been reduced through consolidation or merger activity in the Ontario sector. These analyses focus on two specific Ontario utilities (Utility A and Utility B), both in the Large LDC size category presently and both having completed several mergers/amalgamations in the province in the past. On a per-customer basis (levelizing costs to a common factor), trends for Utility A and Utility B (or their precursor LDCs) show no substantial improvement from pre-amalgamation conditions (see Fig. 9 below). During the 1993-2005 period when the cost base of both Utility A and Utility B had grown through amalgamation, the average cost per customer had increased over 17% and 5%, respectively. Interestingly, this is by far a long enough operating and change management time period to begin harvesting the expected cost synergies of merger. Since 2003, cost improvements have been made; however, the cost per customer was still higher in 2005 than under the service of various pre- amalgamated LDCs. Figure 9: Utility A and Utility B Costs Trends (1993-2005)17 Utility A: 1993 1997 2003 2004 2005 Customers 75,608 81,765 90,867 93,634 100,802 OM&A $ 11,316,996 $ 11,466,935 $ 21,490,194 $ 19,772,029 $ 17,620,658 --------------·-'$""" 149.7 OM&A Per Customer $ 140.2 $ 236.5 $ 211.2 $ 174.8 Utility B: 1993 1997 2003 2004 2005 ·-·-·--Customers OM&A 116,758 134,219 190,201 197,141 203,749 OM&A Per Customer ~" 188.9 $ 151.4 $ 174.0 $ 183.2 $ 197.7 Nota: Augmented from 2007 study , How Effecttve af8 M&As m Dtstributran? Eva/uatmg the Govemmenfs Po/rcy of Usmg Mergers and Amalgamations to Drive Effrciencies into Ontario's LDCs 16 How Effective are M&As in Distribution? Evaluating the Government's Polley of Using Mergers and Amalgamations to Drive Efficiencies into Ontario's LDCs. Cronin, Frank J and S.A. Motluck. 2007. 17 1bld. September 12, 2013 Page 114 Background Paper ) (-} Figure 11: 2012 Labour Rates19•20 \__) ) Hourly Rates for Powerline Maintenance Worker $45.00 .-----------------------------.-,~....,---- $40.00 ~-------~~~---~~~---jijiiiiliil $35.00 +-----c~-ro--------== $30.00 +--- $25.00 +--- $20.00 +---- $15.00 +--- $10.00 +--- $5.00 +--- $0.00 +--- Small (<12,500) Medium (12,500 to 100,000) Large (100,000 to 500,000) Extra-Large (>500,000) In some amalgamation scenarios, any efficiency gains for larger LDC customers will be at the cost of the smaller LDC customers. As a result of a merger, the smaller LDC customer would begin to absorb the higher cost of labour due to CBAs already in place. Increasing responsibilities and service areas may also lead to higher compensation requirements, while jobs would be added at centralized locations to complete the shared workload, further increasing the costs of employee compensation after mergers. Staffing reductions combined with more limiting CBA agreements are likely to lead to lowered customer service standards and lower amounts of maintenance and capital work completions. Integration and transfer costs of merging systems/processes, as well as increased training costs will add to the overall cost/risk paradigm. Lastly, an important potential risk is the limited direct access of the municipality to the corporate distribution entity, which helps to ensure customer service and company performance on behalf of customers and community in less densely populated regions of the province. Our experience suggests that labour costs, as a potential source of reduced administration expenses in a merger, could result in reduced service rather than gained efficiency. Each circumstance is subject to unique situational restrictions. Once again, a one-size-fits-all approach cannot hold true in a utility market as diversified as Ontario. Investments in Innovation The DSRP presupposes that Ontario's Small and Medium LDCs do not typically invest as often in innovation compared to the Large LDCs. It is thought that their investments tend to focus on maintenance and upkeep instead. While large R&D, innovation and change investments are important, it is also critical to carefully determine their necessity, impact and timing. These investments do not always yield the expected returns (or benefits to the customer) especially if the innovations do not tum out to perform as well as originally forecasted, or if their implementation is not executed well. Ontario's Small and Medium LDCs have shown a strong ability to maintain the strength of their distribution systems as evidenced by their better than sector average performance on Reliability and Responsiveness indices, in spite of at times, more challenging conditions, particularly in Northern Ontario. The investments being made by these utilities are working and customers are garnering the benefrts. In 19 Compensation, Wages, Benefits. EB-2012-0031 (Hydro One). Ontario Energy Board. 2012. 20 North Bay Hydro rates comparisons September 12, 2013 Page 116 \ ) (J \_) Background Paper The DSRP recommendation to remove red tape and other barriers, as a way of fast tracking merger activities, is also supported. If voluntary mergers that make clear business sense are to occur, inhibiting barriers need to be removed in order to encourage LDCs (and their shareholders) to take advantage of any potential long-term benefits that could be captured from merging. In addition to these points, the process used to gather data and opinions was a strength of the report's methodology-it was open and encouraged various stakeholder groups to participate. Nothing precluded relevant stakeholders from submitting opinions and perspectives on the current and fUture state of the sector. Looking forward, continued inclusiveness, consensus building and regional involvement in mapping out the objectives and approaches of the sector should be encouraged from the top down. THE BIGGER PICTURE: WHERE CONSENSUS EXISTS Differences of opinion aside, there are a number of electricity sector facts that cannot be contested. This section offers overwhelming consensus and insight from numerous studies and sources that all point toward several areas within the energy sector, but outside the distribution business, that can be shored up immediately to create cost efficiencies that are much more impactful for consumers. First and foremost, we believe a lot of undue focus is being placed on the distribution sector in hopes of alleviating price pressures generated more broadly within Ontario's electricity sector and with no linkage to distribution utilities at all. It is generally accepted that the distribution component of customer bills makes up between 20% and 25% of the total, while the supply component makes of 50%. The exact portion changes over time, as the wholesale costs of electricity change, electricity commodity rates and policy adjustments leading to uplifts and other charges change, and as natural economic productivity leads to reduced overall consumption per unit of output. Some studies find the distribution portion to be more than 20%, while others find it less. Generally, the 20% range is by and large acceptable for analytic purposes. Therefore, up to 80% of the electricity bill is outside of the control of LDCs, no matter the size (See Fig. 12 below). In each area critical to the functioning of the electricity sector (including generation and market mechanisms, transmission, regulation and policy) there has been just as much, if not more, debate and contention as in the distribution sector. D. N. Dewees, professor of the Economics Department at the University of Toronto, points out in his March 2012 paper for Sustainable Prosperity Policy and Research Network, that since 1966, inflation-adjusted electricity prices show steady increases with a few periods of significant cost jumps. Although inflation represents much of the overall increase, leaving an average of only 1.42% annual growth, it has become clear that Ontario is no longer a "cheap" electricity jurisdiction as it once was. Our prices are similar or higher than those jurisdictions that surround us, which has led to decreased economic competitiveness on the whole21. ) 21 D.N. Dewees, 2012. What is Happening to Ontario Electricity Prices, Sustainable Prosperity Backgrounder. September 12, 2013 Page 118 \ ) ( ) Background Paper Our assessment of the market shows that a far greater consensus exists on the following key areas of focus for the sector (beyond distribution) and for policy makers going forward. Well-developed stakeholder consultation and planning can have greater impact on customer bills and the competitiveness of the economy, if emphasis were placed on these critical areas: 1. Commodity Supply and Market Inefficiencies. 2. The Components of the Global Adjustment Mechanism. 3. Streamlining the Regulatory Frameworks. 4. Streamlining and Enhancing the Transparency of Provincial Agencies. 5. Negative Implications of the Green Energy Act. Commodity Supply and Market Inefficiencies The long history of supply (generation) costs driving increases in electricity bills is well documented. As previously noted, the overall inflation-adjusted growth rate of the total consumer electricity price has been relatively low for over 50 years, at 1.42% on an annual average basis. This figure tells us that the diverse and continually enriched value of electricity and its application in the economy, versus the average growth in electricity prices, is actually a great story of success for the province. The overall landscape of electricity prices across Canada from 1996 to 2007 (most recent year with data available from Statistics Canada) shows that the annual average revenue per kilowatt hour has been steadily increasing. See Fig. 13 below. Ontario has experienced steeper annual growth over the time horizon studied when compared to the other regions of Canada. \_) Figure 13: Annual Average Revenue per kWh in Nominal Dollars23,24 .) -Maritimes -ontario 4.00 -j------------------------~ ---Prairies -Aiberta/BC 2.00 +---------------------- 0.00 +--.-------,-------r-------., .. --. ···---,--------·· r·-, ·· --·· .-·· · ' · -· .---·· "··r-· ·· ---, 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 At times, the relatively modest growth rate in overall electricity price is interrupted by spurts of larger increases and volatility. We postulate that it is these growth spurts that have ultimately led to the declines 23 Statistics Canada. 2009. Electric Power Generation, Transmission and Distribution. Table 4-Residential and agriculture sales of electric power, 2003 to 2007. Catalogue No. 57-202-X. 2013. 24 Statistics Canada. 2002. Electric Power Generation, Transmission and Distribution. Table 4-Residential and agriculture sales of electric power, 2003 to 2007. Catalogue No. 57-202-XIB. 2013. September 12, 2013 Page 120 ) Background Paper effects, as inflation and other market forces act to increase prices at the same time as artificially low prices, held for long periods of time, get adjusted to reality. We are currently seeing the impacts of convergences like this in the market. By the later part of the 2000s, the lack of reliable and steady investment in the sector led to the need for further policy interventions that would secure new supply. New supply was needed to replace aging fleets of power plants, implement the coal phase-out and support the Green Energy Act (and its Feed-In Tariff for renewable generation). The costs to consumers for these investments, through long-term power- purchase contracts, is above the historic costs of electricity supply and often far above current wholesale market rates. Other policy actions between 2009 and 2011 moved to cancel contracts made with developers of gas-fired generation facilities in Mississauga and Oakville. These decisions have added further costs for Ontarians to absorb, with little or no benefit. These costs have been estimated to be $600 million by the OPA and Auditor General to $1.2 billion by energy critic Tom Adams. Another study completed by Power Advisory LLC for the Canadian Wind Energy Association, calculates that costs to the typical consumer have increased by 30% before application of the Clean Energy Benefif6 between 2009 and 2012. Of concern, is that 50% of the total increase is related to supply costs. The increase in commodity costs is attributable to several sources including those described in Fig. 15 below. Figure 15: Recent Increases in Consumer Bills ($1k.Wh)27 2009 .2012 :c Delivery (i11cludit\g Tx) :;J Increased Taxes o Increased Reiiew.able SuP!>Iv qosts m h)~:reased Nuclear, Coal and Gas S(!pply Co'sts • Total Historic Cost In addition to these supply side factors, line loss (defined as the electricity lost as it is transmitted through wires and transformers), can also contribute meaningfully to the cost of power borne by customers. Ontario's distribution system losses have averaged over 4% in recent years. New equipment and technology, currently available on the market, has been shown to reduce the loss to less than 3%. This type of improvement can have direct and immediate benefits to customer bills, as less of the power purchased by LDCs is lost arriving to our homes and businesses and direct blll item charges (line loss factor) is reduced. Recognizing these line loss reductions as conservation, based on the improved 26 The Clean Energy Benefit was Implemented to artificially reduce the price impacts of recent policy decisions, including the GEA. 27 Power Advisory LLC for CanWea. Customer Bill Impacts of Generation Sources in Ontario. 2013 September 12, 2013 Page 122 Background Paper ( ) Figure 16: Recent Increases in Consumer Bills ($/kWh)28 ') 100 r------------------------- .. ' -2.0 10 L_ ____________________________________ _ ·-·-·Average HOEP ($/MWh)=AverageGA (${MWhl"-Total Average Monthly Cost The GA largely represents the difference between the total payments made to all contracted generation, rate regulated generation facilities and conservation programs, and the total market revenue captured through the HOEP. These costs include the elements noted in the figure below. With the GA costs associates with supply making up a much larger portion of the overall commodity price (70% on July 3rd 2013) we must start to question the resources being consumed managing the wholesale market functions and maintaining the necessary infrastructure. Wholesale market costs are yet another cost absorbed by ratepayers, while the perceived benefit is currently very low. 28 1ndependent Electric System Operator. 2013 Market Data. September 12, 2013 Page 124 \ ) (_) Background Paper process is meant to foster these investments, with the proper cost controls, the process may not be working as it is meant to, even if the spirit and intention to do so exists. The regulatory costs borne by Ontario utilities, and ultimately by consumers, grew by 24% in the last 3 years ending in 2010, as represented by the below table, published by the EDA This increase is largely attributed to increased scrutiny by the OEB and the increased costs associated with intervenors. All in, it is costing Ontario's electricity customers close to a quarter of a billion dollars a year to regulate and administer the sector. 31 Some focus should be placed on streamlining these agencies and the regulatory process to get costs in line with the potential benefit to the end consumer-which, if left unchanged, will continue to rise over time.32 Figure 18: Regulatory Costs Incurred by LDCs33 OEB License Fee and Cost Assessments $14.6 ESACost LDC Costs for Regulatory Compliance $29.8 : . . . ~ 1 • ~ ~ ~~ -~ I '-. ) Negative Implications of the Green Energy Act The 2013 report of the Fraser Institute, Environmental and Economic Consequences of Ontario's Green Energy Act, outlines a number of analyses that present weaknesses of the GEA plan. According to the report, there is considerable uncertainty if the GEA will lead to the expected environmental benefits suggested. Although we believe in the spirit of the GEA and intentions of developing a world leading renewable energy sector in Ontario, the Fraser Report serves to pinpoint alternative policy solutions that will drive market establishment, technology commercialization and real environmental benefits at costs the ratepayers and taxpayers of the province can support. Inefficiencies of the GEA are leading to market losses in the amount of $200 million annually, a figure supported by the Auditor General34. The report and the Auditor General have also uncovered the following: 1. $1.3 to $1.7 billion in new grid spending associated with supporting the GEA objectives. 2. $1.1 billion to fund the Clean Energy Benefit on an annual basis. 3. $2.7 billion in renewable energy contracts equaling prices approximately 89% above prevailing market rates. Savings Possible from Repositioning Retailers A significant area of contention is the use of electricity retailers in Ontario and the related costs to the residential and small customer of entering into fixed price contracts. As seen in Fig. 19, two scenarios have been developed: Analysis A compares the difference in the monthly electricity bills between an LDC and a retailer for a customer living in a given location in Ontario and Analysis B compares the current cost 31 1bid. 32 1bid. 33 1bid. 34 Fraser Institute. 2013 September 12,2013 Page 126 ) Background Paper consistent with the 15% cost savings assumption of the DSRP. The analysis shows that the customer will save approximately 5% on their monthly electricity bill if OM&A cost savings from consolidation are as high as 15%, assuming reduction in delivery charges. As noted, the level of savings expected in the DSRP is aggressive and may not be the case in practice, as demonstrated from the historical examples discussed previously in this report. In comparing the two analyses, it is clear that the customer could experience significant cost savings on their monthly electricity bill if the province were to reposition retailers in the Ontario market. In the current state, the LDCs and customer base in Ontario are bearing variable costs of retailers in the form of the billing function, collections and worst of all, expenses related to bad debt. These costs were raised in Westario Power Inc's most recent rates application, where it was found the costs of the utility supporting retailers have been steadily increasing over time and were brought into question. Consolidation..cJerived benefits impact such a small portion of the total bill and limited pricing reductions may actually be possible through mandatory consolidation. However, retailer rates have been extremely uncompetitive with RPP rates over time and adjustments to these long-term contracts could have considerable benefits for small consumers. Additional costs associated with retailers and absorbed by LDCs (and their customers} only compound the overall burden of retailers in the market. The sector should consider alternatives that mitigate or remove the cost risks of retailers and/or remove the operating cost burden of retailers to utilities. In addition to these analyses, the Electricity Distributors Association (EDA) released a report in 2012, The Power to Deliver: A Six Point Plan for the Future of Electricity Distribution in Ontario, which considered the cost savings for the customer, associated with curtailment of electricity retailers. The findings of the EDA report were consistent with the analyses in Fig. 19. According to the EDA, "approximately 15 per cent of the Province's customers are currently signed up with a retailer-the result being, that they are paying 35 per cent to 65 per cent more than customers of LDCs (as identified by Ontario's Auditor General). Phasing out the role of electricity retailers for residential customers will save the electricity system (primarily customers) approximately $260-mi//ion. Additionally, LOGs and customers will benefit from reduced costs related to billing settlement processes, collections on defaults, and reduced need for regulatory oversight. Most importantly, almost 700, 000 residential electricity customers will see the price they pay for power decrease dramatically. 35" When we look at retailers in the marketplace, it is not only the financial cost considerations that impact the customer-there are other associated costs. When putting the customer first, we should also consider their personal experiences with the electricity retailers in Ontario. The EDA stated that more than 70% of complaint calls to the DEB are related to retailer practices, including door-to-door sales and the provision of potentially misleading information to customers36. The issue here is simple: the electricity retailers are selling contracts on the basis of the customer saving money on their electricity bills, which is clearly not the case in the analysis performed in Figure 19. Based on the above discussion and analysis, there are a number of ways that electricity retailers can be repositioned to achieve cost savings for customers. First of all, retailers are currently not including the global adjustment in their electricity prices presented to the customer at the time of signing the contract. It is only when the customer receives their bill from the LDC, which performs the billing function for the retailers in the current state, that they can see the global adjustment charges, which are substantial. It is recommended that retailers are required by the OEB to include the global adjustment in their contract prices to show customers the true cost of their monthly electricity. Secondly, retailers are currently not a& "The Power to Deliver: A Six Point Plan for the Future of Electricity Distribution in Ontario", Electricity Distributors Assoclation. 2012. 36 Ibid. September 12, 2013 Page 128 Background Paper of the existing relationship and the common shareholder, transaction and transition costs would be far lower in comparison to merging with a neighboring LDC. In addition to cost savings, customers would see a benefit in the way they interact with the utilities-they would receive one bill, clearly explaining consumption and rates for each service, and be able to call one number if there are any questions. This improved clarity will save additional phone calls for both the customer and the utility. By efficiently combining activities from more than one type of service, overall costs are reduced. Examples of utilities that are currently managed as a combined entity, or multi-utilities, exist in the United States and Ontario. It is common in the US to see utilities providing electricity, gas, water and wastewater services, street lighting and energy conservation programs. Examples include larger investor owned utilities such as San Diego Gas and Electric, Avista Utilities and Ameren Illinois. Utilities Kingston is a prime example in Ontario. The company has been providing electricity, gas, fiber optics and water and waste-water services for the municipality since 2000, under one affiliate. It estimates that it saves a combined total of $1.9 million each year through sharing overhead costs, equipment, metering/billing services and engaging in joint construction projects. 38 These examples are not the norm; however, through a change in the legislation, more utilities and municipalities will pursue a multi-utility model in order to realize the above benefits to operating costs and customer service. Broaden the use of Shared Services between LDCs to Find Cost Efficiencies Shared services are commonly used internally to provide functions and resources used by multiple departments, thereby reducing redundancies and improving cost efficiencies within the organization. Evolving this concept further by sharing services between multiple local distribution companies would add further savings for both ratepayers and shareholders. Evidence of successful collaborations already exist in the Ontario market, as innovative Small and Medium LDCs have cooperated to take advantage of common billing systems, bulk purchasing and general knowledge sharing, among other functions and services. Through these sometimes informal collaborations, one LDC has estimated that it now saves about 10% off its annual equipment purchases as a result of its participation in bulk purchasing programs. Another success story is summarized in the case below: During the installation of smart meters in the province and development of the MDM/R integration, Small and Medium sized LDCs met the province-wide requirements on time and on budgetary costs much lower by comparison to larger LDCs. This demonstrates that Small and Medium LDCs are just as and sometime more efficient and productive than their large counterparts when implementing innovative top down provincial solutions. The OEB has also recognized many from the Small and Medium LDC community for their efforts in maintain excellent cost- per-meter installations in account reconciliations. Through more formal collaborations, the impact of creating "internal" service providers for the broader sector could mean cost savings to each and every member of the collaboration. Certainly, an amount of local expertise will continue to be needed, but the same level of spending at each LDC will not be required in order to maintain the high service standards that are the norm for Small and Medium LDCs. / _) 38 lbid. September 12, 2013 Page [30 Background Paper \ , \ and the utility, could be saved. The Accord is encouraged by recent actions undertaken by the OEB to \ ... J pursue an in-depth inquiry into the role and costlbenefrt of intervenors in regulatory matters. Voluntary Consolidation of Neighbouring LDCs with Relevant Absorption of Hydro One Assets Forced consolidation, as recommended by the DSRP, would create pressure on Ontario's Small and Medium LDCs to merge, even if does not does it make good business sense. In the broader economy and in the electricity sector, most mergers and amalgamations have not been successful at increasing shareholder value41, while considerable questions can be raised on their ability to create cost efficiencies as well. What does make good business sense is to have contiguous, shoulder-to-shoulder utilities, able to serve all customers within a particular region, without having pockets of customers being served by Hydro One. Many Ontarians are currently able to point to a friend or family member who lives "around the comer'', is served by Hydro One instead of the local LDC, and pays more for electricity each month. Putting the Hydro One assets on the table for amalgamation would accomplish numerous goals for the Province- specifically, it could realize cash through the divestment, while also creating contiguous utilities that take advantage of the obvious efficiencies that come from operating a whole and fulsome service territory. The total number of LDCs would decline, potentially reducing the cost to regulate the sector. Planning decisions would be much more integrated and holistic, also providing benefits to the local economy, environment and ratepayers. By encouraging the distribution sector to merge where it makes good business sense, while allowing consolidation of logical assets and customers, Ontario's ratepayers would directly benefit from the likely savings. With the appropriate support, the market could identify and harvest value in a range of merger activity, -J with good business as a guiding principle. These mergers would be successful when the appropriate "-·--organizational alignment is in place, and change management plans are executed, yielding the greatest possible synergies. Mass-mergers with an aim to reduce the quantity of LDCs in Ontario five-fold, will likely end in diffiCult transitions and far less of the $1.2 billion in estimated cost savings being actually achieved. In voluntary and fundamentally sound mergers, the risk of failed integration is dramatically reduced, as are the transaction and transition costs, ultimately absorbed by ratepayers. ALTERNATIVES Consolidation is not the only way to achieve cost savings or scale. Numerous collaborations over the years have led to not only cost savings, but innovation, new expanded opportunities and new revenue stream as well. Some of these past collaborations are mentioned by the DSRP. Through co-operative or non-profrt business models, many of Ontario's Small and Medium LDCs have, in some form or another, benefitted from collaborating with each other, while incurring minimal transaction or transition costs without giving up local control and direct community interaction. Collaborative service elements have included group buying of equipment and services, regulatory filing support, billing, COM program management, common conditions of service, industry research, and others. These accomplishments have been achieved through open and trusting relationships among utilities with common values. Two often-discussed examples in the Ontario market include Cornerstone Hydro Electric Concepts (CHEC) and Utility Collaborative Services (UCS). Established in 2000 and 2005, respectively, both collaborations share in common a membership that includes only Small and Medium LDCs-those 41 Becker-Biease, J, L.Goldberg and F Kaen. 2008. "Mergers and Acquisitions as a Response to the Deregulation of the Electric Power Industry: Value Creation or Value Destruction?" Journal of Regulatory Economics September 12, 2013 Page 132 Background Paper \\ ADVANTAGES OF THE LOCALLDC /) The local LDC provides substantial value to the community it serves, so new alternative efficiency strategies require consideration of the advantages of the local LDC, particularly when considering the DSRP's recommendation to consolidate the existing 75 LDCs in Ontario down to 8 to 12 regional distributors. In putting the customer first, it is not only the monthly electricity bill that needs to be considered, there are a number of important considerations for the customer to bear in mind: 1. Higher levels of service and responsiveness. 2. Community access to decision makers. 3. Greater focus on the community in decision making and in overall economic effectiveness. 4. Local jobs and economic activity. 5. Community involvement in long-term regional energy planning. Higher Levels of Service and Responsiveness The DSRP noted a fundamental necessity of all utility serviced customers: "All electricity customers should be able to access immediate and responsive service from their LDC, whether it is a large utility or a small one". It is the quality of service and the level of responsiveness that drives the customer's direct experience with their electric utility. As discussed earlier in this report, it was noted that the smaller, community-based utilities are considered by many to be more responsive and reliable to their customers when compared with larger ones. In comparing local LDCs to Hydro One (the largest utility in Ontario), it is clear that the SAID!, SAIFI and CAIDJ metrics demonstrate that smaller LDCs have higher levels of service and responsiveness around interruptions. The value in these metrics is not to be understated. Ultimately, the customer deserves cost effective electricity with reliable and responsive service from their LDC. This is one of the major advantages of a locally operated utility. Community Access to Decision Makers Another advantage of the local LDC is the community access to key decision makers within the utility. Smaller communities place significant value on having their viewpoints heard by those who can influence outcomes. Individual ratepayers have the opportunity to provide their input into the decisions that ultimately affect their monthly electricity bills and their overall experience with their electric utility. Often, under local control, citizens have an avenue to drive business policy through their local representatives, who make up councils in direct influence of the utility. Locally-based LDCs give customers and their communities the ability to have their voice heard by key individuals from their utility. This enables the community messages to be escalated to a higher-level where decisions are made. First hand interaction often creates greater impact as the consumer voice is directly heard and incorporated into decision making. In the case of larger utilities, such as Toronto Hydro or Hydro One, the customer is sometimes limited to virtual communication with utility managers due to the widespread physical location of coverage and multiple layers of administration. As a result, the customer experience may be significantly diminished. In putting the customer first, it is critical to give the customer a voice. Greater Focus on the Community in Decision Making and Economic Effectiveness Individuals who are decision makers at the local LDCs are also community members. In this sense, there is increased incentive for the decision makers at local LDCs to stimulate the local economy wherever possible. This includes hiring locally, purchasing locally and investing in the local community. There is a September 12, 2013 Page 134 Background Paper ) () RECOMMENDATIONS Development of Facilitative Policy to lncent Strong Business .. Based Merger Activity and Remove Simple Barriers to Increase the Flexibility for Innovative Solutions to Enhanced Efficiency for LDCs Numerous studies and researchers, in addition to the DSRP and the authors of this report, have pointed out that certain specific barriers exist which are inhibiting the sector from taking advantage of opportunities for efficiency improvements. Many municipalities continue to operate the water utility as a distinct entity from the electric utility, despite owning both. While some of the efficiencies that could be captured are being achieved through shared services like combined billing, there are additional efficiencies that could be captured through horizontal consolidation at the local level. Removing regulatory restrictions around the nature of LDC operations to allow for municipally-owned LDCs to merge services such as water and street lighting, for example, into their organizations would allow them to take advantage of economies of scope, and pass on cost savings to customers for these services and electricity. In addition, the 33% transfer tax and departure tax (imposed on municipally owned utilities when more than 10% is owned by a private sector investor, forcing them to lose tax exempt status) have often been pointed to as impediments to consolidation activity in the sector. The removal of these taxes would facilitate the kind of smart, broadly beneficial investments and mergers that could potentially drive overall sector efficiencies and create a level playing field for all parties. Localized Long .. Term Energy Planning that Includes Local Distribution Companies and Their Local Communities The benefits of taking a local, community-based approach have been demonstrated in the discussion above on the advantages of a local LDC. We recommend that provincial long-term energy planning takes a localized focus in order to address the unique circumstances of each diverse region of Ontario. We believe that a critical aspect to putting the customer first requires giving the customer a voice. It is important to involve the local communities in planning discussions that will ultimately affect their experience with their utility. In fostering community involvement in long-term energy planning, the advantages of a local LDC cannot be understated. Access to key decision makers within the local utilities is an important requirement. It is recommended that local utilities hold an annual meeting for their customers and the community they serve to enable an open forum for discussions of existing issues and inefficiencies, as well as their thoughts on the future of the electricity sector in Ontario. Focus on Regulatory Efficiency to Promote Improvement of Mechanisms to Deliver Sector-Wide Efficiencies and Minimize Costs of Regulation As discussed earlier in this report, within a typical residential electricity bill, 20% of the costs are within the LDC's control and 80% of the costs are outside of the LDC's control. In both cases, we believe there are efficiencies to be obtained that ultimately represent cost savings to the customer upon implementation. Firstly, we recommend that LDC's are permitted to increase the scope of their operations through I ) horizontal consolidation at the local level. The potential efficiencies to be gained include cost savings from September 12, 2013 Page 136 ) \, .. ) / ) Background Paper believe this process will involve investing time and resources into feasibility studies and due diligence, including using historical examples to identify potential best practices and those to avoid as well. This will enable more carefully thought-out and informed business decisions. Ultimately, the province and the consumer will benefit from this approach. Furthermore, we strongly believe that all Ontario LDCs should enter into discussions with each other to explore opportunities for collaboration, without formally merging. The Small and Medium utilities may be able to achieve synergies at the core of their business (for example, through regular knowledge-sharing and development of industry best practices) and cost efficiencies (for example, through common billing systems or shared purchasing of equipment and other necessary supplies). Cooperation among utilities will spark creativity and innovation without placing undue pressure (and incurring transaction and transition costs) on the LDCs to consolidate. Ultimately, the use of cooperation and shared services between utilities will present a more immediate benefrt to the customer in terms of reduced costs and improved service. September 12, 2013 Page 138 Attachment 31 .) \ __ ) I () _ _) would have an opportunity to have their proposal evaluated and considered by the shareholder. It should be pointed out that all negotiations would obviously be confidential due to the sensitivity of such information as employee details, financial information, any outstanding litigation issues, etcetera. REASONS FOR DISPOSITION OF TILLSQNBURG HYDRO INC. As Council is aware, there has been an Initiative in the Province of Ontario through the work of the Distribution Sector Review Panel to consolidate the number of Local Distribution Companies (LDC's) in order to obtain sector efficiencies. A number of municipalities that own LDC's have initiate the sale of such assets for a variety of reasons. The County of Brant for example has gone to the market to seek buyers for Brant County Power. The major decision points for a sale by the County of Brant seem to have been challenges facing the LDC in the following areas: • Maintaining competitive electricity rates for customers while continuing to provide a system that is safe and reliable; • Increasing regulatory and service demands for local electricity distribution companies; • The conclusions of the Ontario Distribution Sector Review Panel which recognized the need for a more efficient electrical distribution model and recommended consolidation of LDCs. It should also be noted that Brant County Council put some emphasis as part of their decision making on the potential income streams that could come from reinvestment of proceeds for use In offsetting infrastructure costs. Council is also aware that Norfolk Power is finalzing its sale to Hydro One and the City of Woodstock is moving forward on the sale of their LDC as well. These are just a couple of other examples where municipally owned LDC's are being consolidated with larger entitles. CONSULIADON/COMMUNIQTION Regardless of whether a sale, merger or other model of divestiture is ultimately decided upon based on responses to a Request for Proposal (RFP), the management of the process of a sale or merger of an LDC is a complex one that requires the skills of an experienced agent and financial advisor. As the Council is well aware, the capacity to drive this process or the expertise required does not exist within THI or the Town of Tlllsonburg. As such, in order to get the best results, a legal agent who has experience in negotiating successful transactions and has a broad connection with potential bidders is desirable. It should be noted that in the case of a sale, most transaction costs, which includes the cost of legal and financial experts, may be recovered to some degree from the purchaser. A merger proposition does not provide for the ability to recoup transaction related costs as each party to the merger will be responsible for their own costs. D Page2/3 CAO i C) \_) Schedule 'A' Disposition Process-Sale or Merger of TIIIsonburg Hydro Inc. Sale Option 1. Selection of Legal Agent The management ofthe process of a sale of a Local Distribution Company (LDC) can be a complicated one and should engage the skills of an experienced legal agent and financial advisor. An experienced legal agent is one that has overseen successful transactions and has a familiarity with potential bidders. 2. Preparation of Bid Documents The bid documents consist of a detailed Request for Proposal (RFP) to purchase the LDC which would outline the steps involved and may include a draft sale-purchase agreement. 3. Solicitation Process The municipal council as the shareholder has some decisions to make regarding the process. a. Will the process be public or private? In a public process the legal agent is instructed to commence a public process where any qualified entity may submit a proposal. For a private process Council predetermines those entities with whom it is wanting to negotiate with. b. Will the process be open or closed? In an open process a solicitation process is supplemented by direct contact with qualified entities. In a closed process parties are contacted directly in confidence with a public announcement made at the end of the process when an agreement has been reached. 4. Confidentiality Agreement and the RFP All prospective proponents are required to execute a Confidentiality and Non-disclosure agreement and to provide a deposit to qualify and receive the RFP and any additional confidential and sensitive information (employee details, outstanding litigation, environmental issues, financial details, etc) 5. Site Visit and Data Room Those qualified to receive the RFP and confidential information may be invited to attend a scheduled tour ofthe LDC site. Access is also given to a data room containing due diligence material which is usually hosted on a special web site. ) () _) 4. Confidentiality Agreement Same as a sale with the addition of the shareholder having to sign a confidentiality agreement as well as the proponent due to the fact that the proponent will be sharing some of their confidential information during any merger discussions. 5. Business Case for the Merger In the case of a merger, the shareholder will have to identify the source and magnitude of the benefits of a merger and any related costs. This may differ from merger proponent to merger proponent. This can be a lengthy step in the merger process. 6. Preparation of Merger Documents Agreements can be complicated and time consuming to draft. This step will require negotiations and understanding of conditions by all parties in order to come to agreement. 7. Selection and Announcement of Successful Proponent If there is an acceptable proposal successfully negotiated a definitive transaction agreement is required. A public announcement can then be communicated. 8. Merger, Acquisition, Amalgamations and Divestitures (MAADS) Application Same as a sale. 9. Closing Transaction Same as a sale. Note: The steps as outline have been compiled from information provided by individuals with experience in such divestiture processes. ' (_) _) Option 2-SmalllDC Share Sale-Expansive Bid Process/Larger Number of Legal Issues to be managed • Based on an open and competitive bid process produdng many potential bidders; • Legal representatives oversee due diligence process to ensure all documentation is available and posted to data room; • Legal receives and addresses questions from proponents; • Arrange all bidder site visits; • Meets with Municipal Council and assists with decision making process; • Need for communication strategy; • Negotiation of legal agreements; • Preparation of MAAD application; • Represents shareholder at OEB; • Closing of transaction and preparation of all required documentation. Professional Fee Range for legal-$150,000 to $350,000 Professional Fee Range for financial advisor-$25,000 to $40,000 Note: The process and figures provided in this schedule were compiled from information provided by an individual experienced in the sale process of LDC's. () Report Title: Report No.: Author: Meeting Type: Council Date: Attachments: RECOMMENDATION; STAFF REPORT DEPARTMENT Tlllsonburg Hydro Inc. Public Information Meeting CAO 14-07 David Calder COUNCIL MEETING MARCH 24, 2014 DRAFT SPECIAL PUBLIC MEETING AGENDA That Council direct staff to schedule a Public Information Meeting to provide the information to the public as outlined in Report CAO 14-07 , Tillsonburg Hydro Inc. Public Information Meeting. \_) And that stakeholders be given the opportunity to provide input to Council regarding the options for sale, merger, acquisition or status quo of Tillsonburg Hydro Inc. EXECUTIVE SUMMARY At its meeting of February 27, 2014, Council adopted the following resolution: RESOLVED THAT a vote on proposed resolution #4 be deferred pending a public meeting to provide information to receive input from the public; FURTHER RESOLVE THAT Mr. Calder, CAO, develops a format and reports back at the Council Meeting of March 24th, 2014. The purpose of this report is to provide a format for a public meeting for Council's consideration. CONSULTATION/COMMUNICATION Staff has discussed the format of a public meeting with THI staff and the Board of Directors of THI in order to determine the type of information to be provided as part of a public meeting. As a result, attached as Schedule A is a proposed special public meeting agenda. In addition, the following information could also be provided in advance of the public meeting. KPMG report presented at the OGRA conference, KPMG report presented to the THI Board of Directors, Report of the Consensus Accord Committee, Report of the Ontario Distribution· j () Tillsonburg Hydro Inc. Timeline July 22, 2009-April, 2014 Appendix Set 3 (No.33-46) '_) 27 28 29 30 31 32 33 34 35 ,) '-··-· 36 37 43 44 .·_) 2013 Report: THI Disposition Analysis September 17, 2013 Impact to Town's Net levy If THI was sold -No employees transferred to new entity County of Brant: Seeking Potential Buyers for Brant County Power Inc. Report: A Report of the Consensus Accord -Taking the High Road -To Improve Customer Service in the Electricity Distribution Sector Report: CA0-14-04 Disposition Process of lillsonburg Hydro Inc. Schedule A: Disposition Process Schedule B: Estimated transition Costs Report: CAQ-1 4-071illsonburg Hydro Inc. Public Information Meeting Tillsonburg Hydro Inc. Flnandal Statements December Tillsonburg Hydro Inc. Financial Statements December 3 2010 Tillsonburg Hydro Inc. Financial Statements 2011 Tillsonburg Hydro Inc. Financial Statements December 2012 Tillsonburg Hydro Inc. Financial Statements December 2013 ) 0 ) _ __/ ·----------~----------- .. -·~ .... TILLSONBURG HYDRO INC. FINANCIAL STATEMENTS DECEMBER 3~.~~09 \ j 0 i") \ ___ / : __ ) ..... ···-·----··-·-·--··-·------·-----------~---. ··········--···----- TJLLSQNBURQ HYDRO INC. STATEMENT OF FINANCIAl, POSITION PECEMBER 31. 2009 (with comparative balances as at December 31, 2008) 2009 ASSETS Current Cash s 891,931 Accounts receivable 2,926,997 Due from related parties (note 10) 114,001 Income taxes receivable 56,581 Inventory 320,024 Prepaid expenses l~2Qa Capital -(note 4) 4,323,zaz Cost 14,120.413 Less accumulated amortization {8,1a§,al2) 5,984.741 Other assets Deferred costs (note 6) 88,336 Regulatory assets (note 5) 351,731 440,067 Total assets $ 10.748,545 LIABILmES AND SHAREHOLDER'S EQUITY Current Accounts payable and accrued liabilities $ 1,869,569 CUstomer deposits 149,543 Deposits in aid of construction 151,080 Due to related parties (note 10) 2,170,192 Long term Customer deposits 92,189 Other liabilities Regulatory liabilities (note 5) Total liabilities 2.262.381 Shareholder's Equity Common shares {note 7) 6,992,565 Contributed capital 1,190,387 Accumulated net eamings -Statement 2 303,2j2 8.486,164 Total liabilities and shareholde..-s equity $ 10.748,545 On behalf of the Board: Statement 1 2008 $ 1,995,841 2,839,931 81,366 321,043 l2.al9 §,250,500 13,191,435 a.sll3,7al> 5,6i.}7,§7~ 500,757 500.757 $ 11.358.931 $ 1,738,801 153,235 143,032 198,~99 2,233,567 96,778 609.967 2.94Q.312 6,992,565 1,190,387 235,§27 8.418,619 $ 11,35§.931 The accompanying notes are an integral part of this financial statement. -------··-·-··-·-···· I Statemen!a 0 IILYIQtiiLIIm HYDB.O INC. SIATEMEffi gF OPERA]]ONS fOB THE YEAR !;tiDED DE~EMBER ~1. agga (with comparative balances for the year ended December 31, 2008) Financial Plan Actual Actual 2009 2009 2008 Power service General $ 8,522,000 $ 9,680,637 $ 10,166,476 Residential 2,399,000 2,413,589 2,276,4n Streetlight 17,000 9,883 53,799 Wholesale and transmission charges 2.95Q.OOO 3.069.954 3.149.917 13,888,000 15,174,063 15,646,669 Cost of power (13.888.000) 15.174.063 15.64§.669 Gross margin on power Distribution revenue Distribution service 2,713,000 2,709,942 2,405,624 ,>-) Retail service 15,000 11,288 14,843 Other 98.QQQ 103.591 13QA53 \.,/ 2.826.000 2.824.821 2.550.920 Net non-utility activities (note 9) 2.000 26.834 27.974 Expenditures Operating and maintenance 1,039,721 1,039,723 ns.128 Billing and COllecting 425,604 434,918 424,963 General administration 419,469 370,579 415,523 Regulatory expenses {note 6) 59,327 . 250,494 15,151 Amortization (note 1) 627,660 551,911 459,467 Interest and finance charges 20.000 14.844 36.176 2.591.781 2.662,469 2;127.408 Net operating revenue 236.219 189.186 451.48§ Provision for corporate taxes (note 8) 39.00Q 21,641 45,iM8 Net earnings for the year $ j9Z.2j9 s 167.545 $ 405.838 i l I I The accompanying notes are an Integral part of this financial statement I ~-) i I I () TILLSONBURG HYQRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31.2009 Tillsonburg Hydro Inc. was incorporated In Ontario on October 26, 2000 to distribute electrical power in accordance with Section 144 of the Electricity Act. 1998. 1. Significant accounting oollc!es The Corporation's financial statements have been prepared in accordance with Canadian generally accepted accounting principles as amended by principles specifically prescribed by the Ontario Energy board for rate regulated businesses in the "Accounting Procedures Handbook for Electric Distribution Utilities". In February 2008, the Canadian Accounting Standards Board (ACsB) confirmed that the use of International Financial Reporting Standards (IFRS) for financial statement presentation will be required for year ends beginning on or after January 1, 2011 for pubHcly accountable enterprises. IFRS will replace Canada's current generally accepted accounting principles for those enterprises which include Tillsonburg Hydro Inc. The Corporation Is currently evaluating the impact of the transition to I FRS on its financial statements. Basis of Accounting () \__ _ These financial statements have been prepared using the accrual basis of accounting. The accrual basis of accounting recognizes revenue as it becomes available and measurable. Expenditures are recognized as they are incurred and measurable as a result of the receipt of goods or services and the creation of a legal obligation to pay. / ., ',. ____ ) Accounts receivable Accounts receivable are shown net of an allowance for doubtful accounts of $48,068 (2008 -$21,680 ). . Inventories Inventory consists of repair parts, supplies and material held for future capital expansion and maintenance activities and is valued at the lower of cost and replacement value. Cost is determined using weighted averages of direct costs. Caoital assets and amortization Capital assets included property, plant and equipment These assets are valued at acquisition cost less accumulated amortization. Amortization is provided on the straight line basis using the following rates, which are designed to reflect the approximate economic life of each class of asset: Substation equipment Distribution lines and transformers Distribution meters Computer hardware Computer software 25years 25years 25years 2years 2 years ;() .( \ .· I ) '---··' ---------~-.. ---------·~----- TILLSONBURG HYDRO INC. NOJES TO FINANCIAL STATEMENTS DECEMBER 31. 2009 2. Rate setting and lndustrv regulation The Ontario Energy Board Act (1998} (the Act) gave the Ontario Energy Board (OEB) increased powers and responsibilities to regulate the electricity Industry on Ontario. These powers and responsibilities include the ability to approve or fix rates for the transmission and distribution of electricity, the ability to provide continued rate protection for rural and remote electricity consumers and the responsibility for ensuring the distribution companies fulfil obligations to connect and service customers. The Act provides for a competitive market in the sale of eJectricity In addition to the regulation of the monopoly electricity delivery system in Ontario. The OEB has regulatory authority over the electricity delivery sector. The Act sets out the Board's powers to issue a distribution license, which must be obtained by any person owning or operating a distribution system under the Act. The Act allows the Board to prescribe license requirements and conditions to electricity distributors, which they Include such considerations as specified accounting records, regulatory accoun1ing principles, separation of accounts for separate businesses and filing requirements for rate setting purposes. With the commencement of the open market, the company purchases electricity from the ~ndependent Electricity System Operator (IESO), at spot market rates and charges Its customers unbundled rates. The unbundled rates include the actual cost of generation and transmission of electricity and an approved rate for electricity distribution. The cost of generation, transmission and other charges such as connection and debt retirement are collected by Tillsonburg Hydro Inc. and remitted to the IESO. The company retains the distribution charge on the customer hydro Invoices. The OEB has the general power to include or exclude costs, revenues, losses or gains In the rates of a specific period, resulting in a change in the timing of accounting recognition from that which would have applied In an unregulated company. Such change In timing gives rise to the recognition of regulatory assets and liabilities. The company's regulatory assets represent certain amounts receivable from future customers and costs that have been deferred for accounting purposes because it Is probable that they will be recovered on future rates. In addition, the company has recorded regulatory liabilities, which will represent amounts for expenses incurred in different periods than would be the case had the company been unregulated. Specific regulatory assets and liabilities are disclosed In note 5. The Corporation's approved distribution rates include components for the recovery of distribution expenses, regulatory assets and liabilities, payments in lieu of corporate income taxes, and a rate of return on capital assets. 3. Financial instruments The fair value of cash, accoun1s and income taxes receivable, due from (to) related parties, accounts payable and accrued liabilities and customer deposits Is approximately equal to their carrying value given their short-term maturity date. ; 1n ! ' .· \,_) . ) "-·-" --------·-·-------------· ------·-----~-------------------. ·------· . . ' DLLSONBURG HYDRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31. 2009 5. Reaulatorv assets and liabilities continued Starting in 2006, rates included an amount to fund a smart meter conversion program. The amount the Corporation collects In rates is deferred to offset the costs of the conversion program. During 2009, the Corporation has incurred costs for implementation of the smart meter program. It Is anticipated this project will be completed in 2010. The total cost of the project is estimated at $1,275,000 and will be funded by long-term debt. The retail service variance accounts represent the difference between the amount charged by the IESO based on the settlement invoice and the amount billed to customers using the OEB approved rates. The disposition of these amounts Is expected to be reflected in future rate adjustments. The balance in the recovery of regulatory assets represents the amount that the OEB has considered In prior applications and set a rate for recovery. Regulatory asset amounts included in approved accounts that were recognized after December 31, 2004 have been reviewed by the OEB regulatory auditors for the period ending December 31, 2007. The company continually assesses the likelihood of recovery of each of it's regulatory assets and liabilities into the setting of future rates. If, at some future date, the company judges that it Is no longer probable that the OEB will include a regulatory asset or liability in future rates, the appropriate carrying amount will be reflected in results of operations in the period that the assessment is made. 6. Deferred costs and regulatory expenses The Corporation Incurred costs to prepare and file a rate rebasfng application. At December 31, 2008, the Corporation deferred $216,647. During 2009, a further $111,969 was expended. The Ontario Energy Board provide approval to recover $106,000 of these costs through rates over a four year period. Regulatory expenses of $250,494 In 2009 reflect the expense of the unrecoverable rate application costs, amortization of the approved costs, and OEB annual assessment and cost awards. In addition, at December 31, 2008, the Corporation deferred costs incurred to replace the customer infonnation and billing software of $284,110. During 2009, a further $24,065 was expended to complete the conversion and the full cost was capitalized and Is being amortized over a two year period. 7. Share capjtal The share capital of the Corporation consists of the following: Authorized -Unlimited common shares -Unlimited number of Class A shares -non-voting, non-cumulative redeemable 2009 2008 Issued - 1 voting common share ' $ 6.gg2.565 $ 6.992.565 0 ·--·-··---···--· ---····-···----~----- TILLSQNBURG H)'DRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31. 2009 12. Litigation and contingent liabilities -----------·. Class actions were commenced against the Consumers Gas Company in 1994 and against Toronto Hydro as the proposed representative defendant for all Ontario Municipal Electric Utilities in 1998. Both actions claimed restitution for unjust enrichment arising from the late payment penalties levied on overdue utility bills by the defendant nullities. On April 24, 2004, the Supreme Court of Canada rendered lfs judgment regarding defences raised by Consumers Gas. With respect to the unjust enrichment claim, the Court held that the rate orders of the Ontario Energy Board contravened the Criminal Code, which is Federal legislation and this is paramount to Provincial legislation and the Ontario Energy Board Act. This Court also ruled that an order for repayment of monies collected would not occur before the issuance of the statement of claim In 1994. The Electric Distributors Association and Toronto Hydro jointly engaged legal counsel to represent the interests of the LOCs In the class action litigation. In 2010, an offer to settle was received arid accepted by LOCs, subject to court approval. The Corporation's share of the proposed settlement of $30,083 (2008 -$75,000) has been accrued in these financial statements. 13. Comparative balances Certain comparative balances have been reclassified to conform with the current year's presentation. I I I I •I i : J .() ~-) TILLSONBURG HYDRO INC. FINANCIAL STATEMENTS DECEMBER 31, 2010 1--~-"'-"'""''''-···----· --~-·••---•---------~~----' I ·i .I ! ' 0 · __ ,l'.i ' ~:-) TILLSONBURG HYQRO INC. STATEMENT OF FINANCIAL POSITION DECEMBER 31. 2010 (with comparative balances as at December 31, 2009) 2010 ASSETS Current Cash $ 2,957,459 Accounts receivable 2,462,098 Due from related parties (note 11) Income taxes receivable (note 9) Inventory 343,563 Prepaid expenses §§,flQO 5,820,020 Capital -(note 4) Cost 14,71-9,785 Less accumulated amortization ca. 1aa.oao> s.S3Q,Z55 Other assets Deferred costs (note 6) 125,906 Regulatory assets (note 5) 862,270 980,176 Totala&&ets $ 12.738.951 LIABILITIES AND SHAREHOLDER'S EQUITY Current Accounts payable and accrued liabilities Income taxes payable (note 9) Customer deposits Current portion of long term debt (note 7) Deposits in aid of construction Due to related parties (note 11) Long term Customer deposits Bank loan (note 7) Total liabilities Shareholder's Equity Common shares (note 8) Contributed capital Accumulated net earnings -Statement 2 Total liabilities and shareholder's equity On behalf of the Board: __________ _ $ $ 2,048,676 65,220 234,393 103,141 69,547 11Z,§3Z 2.638.614 153,073 1,158,408 1,311,481 3.950.095 6,992,565 1,190,387 605,904 8.Z88,856 12,738,951 Statement 1 2009 $ 891,931 2,926,997 114,001 56,581 320,024 14,2Q3 4,323.737 14,120.413 £8,la~.§72) 5.aa~.Z~1 88,336 ~l.Z31 440.067 $ 1 o.z 48.545 $ 1,869,569 149,543 151,080 2.170.192 92,189 92,189 2.262.381 6,992,565 . 1, 190,381-...... -~-------·-- ag3,212 8.486,164 $ 10,748.54§ The accompanying notes are an integral part of this financial statement. Statement3 ·! () TILLSONBUBG HYDRO INC. STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31. 2010 i (with comparative balances for the year ended December 31, 2009) .I j 2010 2009 Power service General $ 9,454,099 $ 9,680,637 Residential 2,854,249 2,413,589 Streetlight 9,883 Wholesale and transmission charges 3.Q89.182 3.069.954 15,397,530 15,174,063 ! Cost of power 15.397.530 15.174.063 " :j Gross margin on power ., Distribution revenue "I I Distribution service 3,172,213 2,709,942 Retail service 15,286 11,288 Other 197,079 H~3.591 (~) 3,384.578 2,824.821 Net non-utility activities (note 10) 17 791 26.834 I Expenses I Operating and maintenance 1,082,028 1,039,723 I Billing and collecting 484,560 434,918 i General administration 549,520 370,579 I Regulatory expenses (note 6) 86,673 250,494 I 1 Amortization (note 1) 653,359 551,911 I I ., Interest and finance charges 10,049 14.844 ·I 2,866.189 2,662.469 1 Net operating revenue 536.180 189.186 Provision for corporate taxes (note 9) 83,488 21.641 Net earnings for the year $ 452.692 $ :I§I.545 : ; The accompanying notes are an integral part of these financial statements. ; ., ' '! ! "i ' () DLLSONBURG HYDRO INC. NOTES TO FINANCIAL STATEMENTS PECEMBER 31. 2010. Tillsonburg Hydro Inc. was incorporated in Ontario on October 26, 2000 to distribute electrical power in accordance with Section 144 of the Electricity Act, 1998. 1. Significant accounting Policies The Corporation's financial statements have been prepared in accordance with Canadian generally accepted accounting principles as amended by principles specifically prescribed by the Ontario Energy board for rate regulated businesses in the "Accounting Procedures Handbook for Electric Distribution Utilities". In February 2008, the canadian Accounting Standards Board (AcSB) confirmed that the use of International Financial Reporting Standards (I FRS} for financial statement presentation will be required for year ends beginning on or after January 1, 2011 for publicly accountable enterprises. IFRS will replace canada's current generally accepted accounting principles for those enterprises which include Tillsonburg Hydro Inc. The Corporation is currently evaluating the impact of the transition to I FRS on its financial statements. During 2010, the AcSB granted an optional one year deferral for IFRS adoption for entities subject to rate regulation. The Corporation has decided to elect the optional one year deferral of Its adoption of IFRS. The Corporation continues to monitor the impact of the transition to IFRS. Basis of accounting These financial statements have been prepared using the accrual basis of accounting. The accrual basis of accounting recognizes revenue as it becomes available and measurable. Expenses are recognized as ·they are incurred and measurable as a result of the receipt of goods or services and the creation of a legal obligation to pay. Revenue recognition Service revenue is recorded on the basis of regular meter readings and estimates of customer usage since the last meter reading to the end of the year. Estimated customer usage from the last billing date to the end of the year, is included in revenue. Accounts receivable Accounts receivable are shown net of an allowance for doubtful accounts of $46,012 (2009 -$48,068 ). lnventorv Inventory consists of repair parts, supplies and material held for future capital expansion and maintenance activities and is valued at the lower of cost and replacement value. Cost is determined using weighted averages of direct costs. Due to the nature of the inventory, no overhead costs are allocated. r) \ .. ·· . ! ·j ·'i i .I ___ ) TILLSONBURG HYDRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31. 2010 1. Significant accounting oolicies continued Use of estimates The preparation of financial statements in conformity with Canadian generally accepted accounting principles requires management to make certain estimates and assumptions that affect reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Such estimates are periodically reviewed and any adjustments necessary are reported in earnings in the period in which they become known. Actual results could differ from these estimates. 2. Rate setting and Industry reaulation The Ontario Energy Board Act (1998} (the Act) gave the Ontario Energy Board (OEB) increased powers and responsibilities to regulate the electricity industry on Ontario. These powers and responsibilities include the ability to approve or fix rates for the transmission and distribution of electricity, the ability to provide continued rate protection for rural and remote electricity consumers and the responsibility for ensuring the distribution companies fulfil obligations to connect and service customers. The Act provides for a competitive market in the sale of electricity in addition to the regulation of the monopoly electricity delivery system in Ontario. The OEB has regulatory authority over the electricity delivery sector. The Act sets out the Board's powers to issue a distribution license, which must be obtained by any person owning or operating a distribution system under the Act. The Act allows the ·Board to prescribe license requirements and conditions to electricity distributors, which they include such considerations as specified accounting records, regulatory accounting principles, separation of accounts for separate businesses and filing requirements for rate setting purposes. With the commencement of the open market, the company purchases electricity from the Independent Electricity System Operator (IESO), at spot market rates and charges its customers unbundled rates. The unbundled rates include the actual cost of generation and transmission of electricity and an approved rate for electricity distribution. The cost of generation, transmission and other charges such as connection and debt retirement are collected by Tillsonburg Hydro Inc. and remitted to the IESO. The company retains the distribution charge on the customer hydro Invoices. The OEB has the general power to include or exclude costs, revenues, losses or gains in the rates of a specific period, resulting In a change In the timing of accounting recognition from that which would have applied in an unregulated company. Such change in timing gives rise to the recognition of regulatory assets and liabilities. The company's regulatory assets represent certain amounts receivable from future customers and costs that have been deferred for accounting purposes because it Is probable that they will be recovered on future rates. In addition, the company has recorded regulatory liabilities, which Will represent amounts for expenses incurred in different periods than would be the case had the company been unregulated. Specific regulatory assets and liabilities are disclosed in note 5. The Corporation's approved distribution rates include components for the recovery of distribution expenses, regulatory assets and liabilities, payments in lieu of corporate income taxes, and a rate of return on capital assets. 0 ., . I I .I II ;) \ __ . ; I l .! I ; i : __ ) .I TILLSONBURG tm)RO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31. 2010 5. Reaulatorv assets and liabilities continued Starting in 2006, rates Included an amount to fund a smart meter conversion program. The amount the Corporation collects in rates is deferred to offset the costs of the conversion program. The project was completed in 2010 and was funded by long term debt as described in note 7. The retail service variance accounts represent the difference between the amount charged by the IESO based on the setUement invoice and the amount billed to customers using the OEB approved rates. The disposition of these amounts Is expected to be reflected in Mure rate adjustments. The balance in the recovery of regulatory assets represents the amount that the OEB has considered In prior applications and set a rate for recovery. Regulatory asset amounts included in approved accounts that were recognized after December 31, 2004 have been reviewed by the OEB regulatory auditors for the .period ending December 31, 2007 . The company continually assesses the likelihood of recovery of each of It's regulatory assets and liabilities into "the setting of future rates. If, at some future date, the company judges that it is no longer probable that the OEB will Include a regulatory asset or liability in future rates, the appropriate carrying amount will be reflected in results of operations in the period that the assessment is made. 6. Deferred costs and regylatory exoenses The Corporation incurred costs to prepare and file a rate rebaslng application. The Ontario Energy Board provided approval to recover $106,000 of these costs through rates over a four year period commencing in 2009. The amortization of these costs is recorded in regulatory expenses. As at December 31, 2010, the deferred costs related to this application are $61,840. In addHion, the Corporation has deferred costs related to adjustments to the retail settlement variances and harmonized tax savings of $64,066. · 7. Long-term debt The Corporation incurred long-term financing for the smart meter program during the year. The bank loan is repayable over 10 years, and bears interest at 4.53%, and has the option of a 10% prepayment each year. The loan is secured by a general security agreement. Principal repayments over the next five years are as follows: 2011 2012 2013 2014 2015 $103,141 $107,763 $112,895 $118,117 $113,032 . ~----·-··-:;·-···-···-·-·-··-------~---------- ;-, \, _____ ) (_) 12. Prudential support DLLSONBURG HVDRQ INC. NOTES TO FINANCIAL STATEMENTS PECEMBER 31. 2010 Ti!lsonburg Hydro Inc. has posted a letter of credit with the Independent Electricity System Operator (IESO) In the amount of$ 956,406 (2009 -$956,406). The IESO is responsible for ensuring that prudential support is posted by all market participants to satisfy their prudential support and obligation and, therefore, mitigate the impact of an event of default by a market participant on the rest of the market. -····-. ----· .. ---·-····---· .. ----·-· .. , -~: .. ~-. -~--------·······----··--·-·-.. --. .,~ ... -.... ···-~ --~....,..-;--··-----.--------------... --· ·---··-··· ---... .. () .. ) ....... __ _., . DLLSONBURG HYDRO INC. FINANCIAL STATEMENTS DECEMBER 31.2011 ) () (~) DLLSONBURG HYDRO INC. STATEMENT OF FINANCIAL POSIDON DECEMBER 31. 2011 (with comparative balances as at December 31, 2010) current cash Accounts receivable Due from related parties (note 11) Income taXes receivable (note 9) Inventory Prepaid expenses Capital-(note 4) Cost Less accumulated amortization Other assets Deferred costs (note 6) Regulatory assets (note 5) Total assets ASSETS $ 1,818,658 2,752,906 314,253 40,104 425,714 1Q.336 5.361.971 15,368,250 (9,385,Z32) 5,982,518 35,344 ~~.~1a 574.763 $ 1l.&l9~52 UABILITIES .AND SHAREHOLDER'S EQUITY Current Accounts payable and accrued· liabilities Income taxes payable (note 9) Customer deposits Current portion of long term debt (note 7) Deposits in aid of construction Due to related parties (note 11) $ 1,790,923 86,233 113,975 65,549 2,056.680 ·Long term Customer deposits Bank loan (note 7) Total liabilities Shareholder's Eq ulty Common shares (note 8) Contributed capital Accumulated net eamings -Statement 2 172,890 917,433 1.090.323 3,147.003 6,992,565 1,190,387 589,297 a.1Z2.2~s Statement 1 201.0 $ 2,957,459 2,462,098 343,563 56,900 5.82Q.020 14,719,786 !a,7m!,Q3:l > 5,93Q,Z55 125,906 a§2,2ZQ 988,176 $ j~.Z3I.Ifi1 $ 2,048,676 65,220 234,393 103,141 69,547 :1:17,637 2,638,614 153,073 :1.158,408 1,3:11,481 3,950,095 6,992,565 1,190,387 §05,90~ a.zaa.a~ Total liabilities and shareholder's equity $ 11.919.252 $ 12.Z38,Q51 '~ ) On behalf of the Board: --·-The acco_m_p_a_n_yl-ng_n_o_tes-a-re_a_n_l_nt_eg_ra_l_part of this financial statement ) (--} \ . --) \. •• J Statement4 TlbLSON§URG !:fii}RO IN~. STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECr:;MBiiiB. 31• 2013 (with comparative balances for the year ended December 31, 2012) 2013 2012 Operating activities Comprehensive Income for the year (Statement 3) $ 546,693 $ 724,026 Charges not involving cash Amortization 356,191 255,020 Net change In non-cash working capital balances related to operations (A) (644,497) (9,670) 258.387 969,376 Investing activities Deferred contributions In aid of construction (143,658) (49,488) Capital asset acquisitions (net of dispositions) (1 ,524,859) (502,348) Non-utility capital asset disposls (acquisitions) 11,463 (136,9§§) (1 .657,054} (688,801) Financing activities Regulatory assets 742,015 302,097 Customer deposits-long term 12,394 41,996 Debt (119,254) (118,242) Deferred costs 91,582 (56,238) Return of contributed capital (note 1 0) (200,000) Dividends paid (30Q,QQO) (1§0,0QQ) 226.737 19,613 Change in cash during the year (1 '171 ,930) 300,188 Cash and short-term investments, beginning of year 2,118.846 1,818.658 Cash and short-term Investments, end of year $ 9461916 $ 2,11§,846 (A) Consists of changes in accounts receivable, inventory, prepaid expenses, current customer deposits, due from (to) related parties and accounts payable and accrued liabilities. The accompanying notes are an integral part of these financial statements. ,.. '\ ) TILLSONBURG HYDRO INC. STATEMENT OF RETAINED EARNINGS FOR THE YEAR ENDED DECEMBER 31. 2013 (with comparative balances for the year ended December 31, 2012) Retained earnings, beginning of year Comprehensive income for the year -Statement 3 Dividends Retained earnings, end of year . 2013 $ 1,163,323 546,693 (300.000) $ 1.410.016 Statement 2 2012 $ 589,297 724,026 (150.000) $ 1.:1§3.323 The accompanying notes are an integral part of these financial statements. I () /-) INDEPENDENT AUDITOR'S REPORT To the Shareholder and Board of Directors: I have audited the accompanying financial statements of Tillsonburg Hydro Inc., which comprise the statement of financial position as at December 31, 2013, December 31, 2012 and January 1, 2012, and the statements of retained earnings, comprehensive income and cash flows for the years ended December 31, 2013 and December 31, 2012, and a summary of significant accounting policies and other explanatory information. Management's Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of these financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error. Auditor's Responsibility My responsibility is to express an opinion on these financial statements based on my audit. I conducted my audit in accordance with Canadian generally accepted audit standards. Those standards require that I comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating overall presentation of the financial statements. I believe that the audit evidence I have obtained is sufficient and appropriate to provide a basis for my audit opinion. Opinion In my opinion, the financial statements present fairly, in all material respects, the financial position of Tillsonburg Hydro Inc. as at December 31, 2013, December 31, 2012 and January 1, 2012, and its financial performance and its cash flows for the year then ended in accordance with International Financial Reporting Standards. April15,2014 London, Canada LICENSED PUBLIC ACCOUNTANT Attachment 37 '--) \.. __ _ -__ ) 8. Share caoital TILLSONBURG HYDRO lNC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31.2012 The share capital of the Corporation consists of the following: Authorized -Unlimited common shares -Unlimite.~ number of Cla$s A shares-non-voting, nb.ri-cumulative redeemable 2012 Issued .,. 1 voting common share $ 6,992.565 9. Payments In lieu of coroorate income taxes 2011 $ 6.992.565 As a regulated Lines Distribution Corporation, Tillsonburg Hydro Inc. is required to rem!t payments in lieu of corporate income taxes as follows: 2012 Income taxes -current $ 67,477 lhcotne taxes -prior year's adjustment 67,47_7 $ $ 2 011 67,471 18,086 S5,557 Payments in lieu of corporate income taxes are calculated on the net operating revenues, adjusted for timing differences arising on differences betweem amortization of cc;tpital assets for tax purposes. The applicable rates for the year ending December 31, 2012 are 15.5% (2011 -15.5%) c.ombined federal and provincial rates on the first $500,000. 10. Net non'"utility activities Ontario Power Authority funded Conservation and Demand Management programs are not regulated by the OEB and therefore, are classified as non-utility activities. Consequently, these net revenues are not recognized for rate-setting purposes. In addition, during 2012, the Corporation purchased solar powered equipment Which is not regulated by the OE1;3. These assets are being amortized over their useful lives an<;l are shown as non-regulatory capital assets. The net revenue generated from these assets is recorded in the non- utility activities. () ( __ ) 3. Financial instruments TILLSONBURG HYDRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31. 2012 The fa_ir value of ~sh, accounts and income taxes receivable, due from (to) related parties, acco~nts paya~le .and _-accrued liabilities and customer deposits is approximately equal to their carry1ng value g1ven the1r shorHerm maturity date. 4. .Capital assets The value of property, plant and equipment as at year end are as follows: Substation land $ 11,520 Substation equipment 404,210 Distribution system 17,929,014 Computer hardware 11,532 Computer software 296;643 18,652,919 Contributions in aid of co·nstruction (2,838,082) Accumul~ted Amortization $ (340,151) (9,967,824) (1, ,532) C296,643) 10,616, 1.50) 710,652 $ Net 2012 11,520 64,059 7,961 '190 8,036,769 (2,127,4~0} $ Net 2 011 11,520 63,516 8;091,Ei56 8,166,594 (2,.184,Q76} $15,814,837 $ (9,905,498) $ 5.909,339 $ 5,982,518 (~) 5, Regulatory assets ~11cl li_f:lbilities The folli::;>wing e.xpEtnSE1!s (r~coveries) may be considered by the Ontario Energy Board in future rate applications and accordiligly have been deferred tmtil such time as direction is provided by the 683. 201.2 2011 Deferred costs: Deferred payment in lieu of corporate income taxes $ (185,2&1) Miscelle}n·eous deferrals $ 13,773 (35,380) Smart meters 895,510 1,049;943 909,283 829,282 Retail settlement variances (613,408) (533, 164) RecoVery of regulatory assets {58,553) 243,301 Total regulatory (liabilities) asset~ $ g37,322 $ 539,419 The deterred payment iri lieu of corporate income taxes represents the accumulated ciifference in the approved estimate of taxes to be paid and the actual taxes paid to December 31 i 2005. The estimate of taxes tq be paid was approved by the OEB a.nd was recovered as part of the company's( ) service revenue requirement hi the related years. The true up has been recorded as pe!rt qf d~fe_rred',, ... payments in lieu oftaxes and reduced income. The OEB ruled that the $185,281 plus 2012 interest of $723, be disposed on a final basis in the 2012 Distribution Rate Order. . iiLLSONBURG HYDRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31. 2012 1. Significant accounting policies continued Capital assets and amortization Capital assets included property, plant and equipment. These assets are valued at acquisition cost less accumulated amortization. Amortization is provided on the straight line basis using the folloWing rate:s, which are designed to reflect the approximate economic life of each class of asset: Substation equipment Distribution lines and transformer$ Computer hardware ComputE?r soJtwC)re Deposit in aid of construction 25 years 25 years 2 y~ars 2 years Depos.its in aid of oom;truction are require9 contributions re~ived from ovtside sources used to finance additions to property, plant and equipment. These deposits are deferred until expended on the intended capftal project. Amounts exp.ended are transferred to a contra-asset account and amortized at an equivaient rate to that !1Sed for the deprecir;ltion of the rel.ated property, plant and equipment. Unspent amounts are refunded. Payment in lieu of corporate income taxes The company provides for payments in lieu of corporate income taxes using the taxes p:ayable method. Under the taxes payable method, no provisions are made for the future income taxes as a result of temporary differences between the tax basis of assets and liabilities and their carrying amounts for accounting purposes. When unrecorded future income taxes become payable, it is expected that they will be included in the rates c;~pproved by the OEB and recovered from the customers of Tillsonburg Hydro Inc. Regulatory policies Tillsonburg Hydro Inc, has adopted the fallowing policie~, as prescribed by the Ontario Energy Board (OEB) for rate-regulated enterprises. The policies have resulted in accounting treatments differing from Canadian 9erterally accepted accounting principles (GAAP) for enterprises operating on a non-regulated environment: · 1. Various regulatory costs have been deferred in accordance with crfteria set out iD the OEB's AGcounting Procedures handbook. In the absence of such regulation, their costs would have been expensed When incurred under Canadian GAAP. 2. The company has deferred certain retail settlement variance amounts under the provisions of Article 490 in the OEB's Accounting Procedures handbook. 3. The company provides fqr payments In lleu of corporate income taxes relating to its regUlated business using the t.axes payable method as directed by the OEB. () () i __ Statement 4 TILLSONBURG HYDRO INC. lr., -\ .. STATEMENT OF CHANGES IN FINANCIAL POSITION ) ' ' FOR THE YEAR ENDED DECEMBER 31 I 2012 (with comp~rative balance$ for the y~ar ended December 31, 201 0) 2012 2011 Operating activities Net earnings for the year (Statement 3) Charges not involving cash · Amortiz.ation · Net change in non-cash working capital balances related to operations (A} lnvestir:~g activities Contributions in aid of construction Capital asset acquisitions (net of dispositions) Non-utllity ~~pital asset a~quisttions Financing activities Re,gulatory asse~s Customer deposits-long term Debt Deferred costs Dividends paid Change in cash during the year Cash. beginning of year Cash; end of year $ $ 347,183 $ 233,393 526,614 596,701 (~l.27Q) Cl,273,520) 864.127 (443.426) 55.,761 17,2,793 (502,348) (821,257) (1~§,965) . (583,.!552) (648.464) 302,097 90,562 41,996 19,8•17 (118,242) (230, 141} (S6·,238) 322,8-51 (150,000) {250,000) . 19,613 {46,911) 300,188 {1,138,801) 1.818;658 2,957,459 2,118,846 $ 1,818,658 (A) Consists of changes in accounts receivable, ihventory, prepaid expenses, current customer deposits, due frpm (tQ) related parties and accounts payable and accrued liabilities. The accompanying notes are an integral part of these financial statements. () ( ) '-... _ ..• TILLSONBURG HYDRO INC. STATEMENT OF RETAJNED EARNINGS FO.R THE YEAR ENDED DECEMBER31. 2012. (with Gompar.ative bal~nce~ for the year ended De.c$mber 31, 2011) 2012 Accumulated net ~arnings; beginning of year $ 589,297 Net earnings for the year-Statement 3 $47,183 Dividends (150.000) Accumulated net earnings, end of year $ 786.480 Statement 2 2011 $ 605,904 23$,393 (250,000} $ 589,297 The accompanying notes are an integral part of these financial statements. () SCRIMGEO COMPANY INDEPENDENT AUDITOR'S REPORT To the Shareholder and Board of Directors: I have audited the accompanying financial statements of Tillsonburg Hydro Inc., which comprise the statement of financial por;;ition as ~t Dec;ember 31, .2012 and the stat~ments of retained E'!~rning.s, operations ·ahd changes in financial position for the year then ended, and a summary of significant accounting policies and other explanatory information. Management's Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of these financial statements in accordance with Canadian generally accepted accountiQg principles. aml far such internal control as management determines Is necessary to enable the preparation of financial statements that are free from material misstatemeAt, whether due to fraud or error. Auditor's Responsibility My responsibility .is to express an op1nron on these financial statements based on my audit. conducted my audit in accordance with Canadian gen~raHy accepted audit standan;!s. Those standards require that I comply with ethical requirements and plan arid perform the audit to o'btain reasonal:)le assurance about whether the financial statements are free from material misstatement. An auditinvolves performing procedures to obtain audit evidence about the amounts and disclosures in() the financial statements. The procedures selected depend on the auditor's judgment, including the as.sessment df the ri~ks· of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation ofthe financial statements in order to design audit procedures that are appropriate iri the Circumstances, but not for the purpose of expressing an opinion on the effectiVeness of the entity's internal control. An audi~ al~o in~ludes evaluating the appropriat~ne~s of accoi,Jnting policies U!:ied and the reasonableness of accounting estimates made by management, as well as evaluating overall presentation of the financial statements. I believe that the audit evidence I have obtained is sufficient and appropriate to provide a basis for my audit opinion. Opinion In my opinion, the financial statements present fairly, in all material respects, the financial position of the Corporation as at December 31, 2012 and its financial performance and its cash flows for the year then ended in accordance with canadian gen'erally accepted accounting prinCiples. June 18, 2013 Landon, Canada Ackmqww' · ~· LICENSED PUBLIC ACCOUNTANT Suite950, 495 Ridunond Street London, Ontario N6A SA9 • Phone: 519-672-6811 Fax: 519-672-9757 () .· \ . __ _) Attachment 36 8. Share capital DLL$0NBYRG HYDRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31. 2011 The share capital of the Corporation consists of the following; Authorized -Unlimited common shares -Unlimited number of aass .A shares -non-voting, nooQ!mulative redeemable tl.1.1 Issued - 1 voting common share $ 6.992.565 9. Pavments In lieu of income taxes $ 6.9Q2.566 As a regulated Lines Distribution Corporation, Tillsonburg Hydro Inc. Is required to remit payments in fieu of income taxes as follows: 2Jl11 2010 Income taxes -current $ 67,471 $ 89,489 Income taxes-prior year's adjustment 18.086 (6.001) $ 85,557 $ 8~.488 Payments in lieu of income taxes are calculated on the net operating revenues, adjusted for timing differences arising on differences between amortization of capital assets for tax purposes. The applicable rates for the year ending December 31, 2011 are .15.5% (2010 -15.5%) combined federal and provincial rates on the first $500,000. 10. Net non-utility actMties Ontario Power Authority funded Conservation and Demand Management programs are not regulated by the OEB and therefore, are classified as non-utility activities. Consequently, these net revenues are not recognized for rate-setting purposes. · 11 . Belated party transactions Banking and accounting activities are administered by the Town of Tillsonburg on behalf of Tillsonburg Hydro Inc. Amounts due from (to) related parties represent the net working capital position between the Town and the Corporation. A Master Service Agreement, which was updated in 2009, governs the financial relationship between the Corporation and the Town of TIIIsonburg. These financial statements reflect this Agreement. This Agreement was updated subsequent to year end for the years ending December 31, 2012 and forward. (_) ( __ ) ,,. 3. Financial instruments DLLSONBURG HYDRQ INC. NOTES TO ANANCIAL STATEMENTS QECEMBER 31. 2011 The fair value· of cash, accounts and income taxes receivable, due from (to) related parties, accounts payable and accrued liabilities and customer deposits Is approximately equal to their carrying value given their short-tenn maturity date. 4. Caoital assets The value of property, plant and equipment as at year end are as follows: Accumulated Net Net Cost Amortization !JlU 1ll1l Substation land $ 11,520 $ $ 11,520 $ 11,520 Substation equipment 400,152 (336,636) 63,516 64,946 Distribution system 17,430,724 (9,339, 166) 8,091,558 7,896,366 Computer hardware 11,532 (11 ,532) 2,883 Computer softWare 296.643 (296,6~) 74,j60 18,150,571 (9,983,9n) 8,166,594 8,049,875 Contributions in aid of construction (2,782.321) 598,245 (2.184,07Ei) C2.119.12Q) $:15.368,250 $ (9.385.732) $ 5.982,518 $ 5,93Q,Z~~ 5. Reaulatory assets and liabilities The following expenses (recoveries) may be considered by the Ontario Energy Board in future rate applications and accordingly have been deferred until such time as direction is provided by the OEB. 2011 il.1Jl . Deferred costs: Deferred PILs $ (185,281) $ (63,358) Miscellaneous deferrals (35,380) (63,604) Smart meters l.Q~.i4a B!U.Z~ 829,282 864,813 Retail settlement variances (533,164) 106,691 Recovery of regulatory assets 243,301 (109.234) Total regulatory (llablltles) assets ~ ~a.~ls $ §§Z.~ZD The deferred payment in lieu of taxes represents the accumulated difference in the approved estimate of taxes to be paid and the actual taxes paid to December 31. 2005. The estimate of taxes to be paid was approved by the OEB and was recovered as part of the company's service revenue requirement in the related years. The true up has been recorded as part of deferred payments in lieu of taxes and reduced Income. The OEB ruled that the $185,281 plus 2012 interest of $723. be disposed on a final basis in the 2012 Distribution Rate Order. () () " DLL§ONBURG lffl)RQ INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31. 2011 1. Significant accounting poHcies continued capital assets and amortization capital assets Included property, plant and equipment. These assets are valued at acquisition cost less accumulated amortization. Amortization is provided on the straight line basis using the following rates, which are designed to reflect the approximate economic life of each class of asset Substation equipment Distribution lines and transformers Distribution meters Computer hardware Computer software DeoosH in aid of construction 25 years 25 years 25 years 2-years 2years Deposits in aid of construction are required contributions received from outside sourcet:~ used to finance additions to property, plant and eqlipment. These deposits are deferred until expended on the intended capital project. Amounts expended are transferred to a contra-asset account and amortized at an equivalent rate to that used for the depreciation of the related property, plant and equipment Unspent amounts are refunded. Payment In lieu of corporate income taxes The company provides for payments in lieu of corporate Income taxes using the taxes payable method. .Under. the taxes payable method, no provisions are made for the future income taxes as a result of temporary differences between the tax· basis of assets and liabilities and their carrying amounts for accounting purposes. When unrecorded future income taxes become payable, it is expected that they will be included In the rates approved by the OEB and recovered from the customers of Tillsonburg Hydro Inc. Reaulatory oolicies TIJisonburg Hydro Inc. has adopted the following policies, as prescribed by the Ontario Energy Board (OEB) for rate-regulated enterprises. The policies have resulted in accotJnting treatments differing from Canadian generally accepted accounting principles (GAAP) for enterprises operating on a non-regulated environment: 1. Various regulatory costs have been deferred in accordance with criteria set out in the OEB's Accounting Procedures handbook. In the abSence of such regulation. their costs would have been expensed when Incurred under Canadian GAAP. 2. The company has deferred certain retail settlement variance amounts under the provisions of Article 490 in the OEB's Accounting Procedures handbook. 3. The company provides for payments in lieu of corporate income taxes relating to Its regulated () business using the taxes payable method as directed by the OEB. (._ .J TILLSONBUBG HYDRO INC. STATEMENT OF CHANGES IN FINANCIAL pOSITION FOR THE YEAR ENDED DECEMBER 31. 2011 (with comparative balances for the year ended December 31, 2010) ll1.1 Operating activities Net earnings for the year (Statement 3) $ 233,393 Charges not invoMng cash Amortization 596,701 Net change in non-cash working capital balances related to operations (A) (l.~~.~2Q) ' (443.426) Investing activities Contributions In aid of construction 172,793 Capital asset acquisitions (net of disposHions) (821,257) (648.464) Ananclng activities Regulatory assets 90,562 Customer deposits-long term 19,817 Debt (~0.141) Deferred costs 322,851 DMdends paid ~tMlQQ) (46.911) Change In cash during the year {1,138,801) Cash, beginning of year 2,957,459 Cash, end of year $ 1.818,658 statement4 $ 452,692 653,359 fl~4.§Z§ 2.040.5U 90,325 (689,698) C599,373) (510,539) 60,884 1,261,549 (37,570) u~.oog> ~24.324 2,065,528 891,931 $ 2.957~~0 (A) Consists of changes in accounts receivable, inventory, prepaid expenses, current customer deposits, due from (to) related parties and accounts payable and accrued liabilities. The accompanying notes are an integral part of these financial statements. i nl (~) ( ) ,, ___ / _) 1. Reporting entitv TILLSONBURG HYDRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31.2013 Tillsonburg Hydro Inc. was incorporated in Ontario on October 26, 2000 to distribute electrical power to the residents of the Town of TIIIsonburg in accordance with Section 144 of the Electricity Act, 1998. The Corporation operates under a licence issued by the Ontario Energy Board ("OEB"). The Corporation Is regulated by the OEB and adjustments to the Corporation's distribution and power rates require OEB approval. The address of the Corporation's registered office is 200 Broadway Street, Suite 204, Tillson burg, Ontario. 2. Basis of presentation The Corporation's financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as adopted by the International Accounting Standards Board ("IASB") and interpretations as issued by the International Financial Reporting Interpretations Committee ("IF RIC") of the lAS B. These are the Corporation's first financial statements prepared in accordance with IFRS. In prior years, the Corporation prepared its financial statements in accordance with Canadian Generally Accepted Accounting Principles ("Canadian GAAP"). The Corporation has restated its opening Statement of Financial Position at January 1, 2012, Its IFRS transition date, by applying I FRS retrospectively, except with regard to specific items, in respect of with IFRS 1: First-time Adoption of I FRS either, prohibits or modifies the retrospective application of I FRS. An explanation of how the transition to IFRS has affected the reported financial position, financial performance and cash flows of the Corporation is provided in note 15. Approval of the financial statements The financial statements were approved by the Board of Directors on Apri115, 2014. Basis of measurement The financial statements have been prepared on the historical cost basis. These financial statements have been prepared using the accrual basis of accounting. The accrual basis of accounting recognizes revenue as it becomes available and measurable. Expenses are recognized as they are incurred and measurable as a result of the receipt of goods or services and the creation of a legal obligation to pay. Functional and presentation currency These financial statements are presented in Canadian dollars, which is the Corporation's functional currency. ) TILLSONBURG HYDRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31.2013 2. Basis of presentation continued Rate setting and industry regulation With the commencement of the open market, the Corporation purchases electricity from the Independent Electricity System Operator (IESO), at spot market rates and charges its customers unbundled rates. The unbundled rates include the actual cost of generation and transmission of electricity and an approved rate for electricity distribution. The cost of generation, transmission and other charges such as connection and debt retirement are collected by Tillsonburg Hydro Inc. and remitted to the IESO. The Corporation retains the distribution charge on the customer hydro Invoices. The OEB has the general power to include or exclude costs, revenues, losses or gains in the rates of a specific period, resulting In a change in the timing of accounting recognition from that which would have applied in an unregulated Corporation. Such change in timing gives rise to the recognition of regulatory assets and liabilities. The Corporation's regulatory assets represent certain amounts receivable from future customers and costs that have been deferred for accounting purposes because It is probable that they will be recovered on future rates. In addition, the Corporation has recorded regulatory liabilities, which will represent amounts for expenses incurred in different periods than would be the case had the Corporation been unregulated. Specific regulatory assets and liabilities are disclosed in note 6. The Corporation's approved distribution rates include components for the recovery of distribution expenses, regulatory assets and liabilities, payments in lieu of corporate income taxes, and a rate of return on capital assets. On December 12, 2011, the Corporation submitted an application to the OEB under the incentive regulation mechanism (IRM) seeking approval to change its 2012 Electricity Distribution Rates. On April12, 2012, the Corporation received a Decision from the OEB that approved changes to the rates that the corporation charges for electricity distribution, to be effective May 1, 2012. On November 8, 20.12, the Corporation submitted a Cost of Service rate application to the OEB for 2013 Electricity Distribution Rates. On April11, 2013, the Corporation received a Decision from the OEB that approved changes to the rates that the Corporation charges for electricity distribution, to be effective May 1, 2013. _) TILLSONBURG HYDRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER31. 2013 3. Significant accounting policies continued Property. plant and equipment Property, plant and equipment are measured at cost or deemed cost established on the transition date. Cost includes expenditures that are directly attributable to the acquisition of the asset. The cost of self-constructed assets includes the cost of materials and direct labour and any other costs directly attributable to bringing the asset to a working condition for its intended use. Parts of an Item of property, plant and equipment that have different useful lives are accounted for as separate items (major components) of property, plant and equipment. Amortization is recognized in profit or loss on a straight-line basis over the estimated useful life of each part or component of property, plant and equipment. Land is not depreciated. The estimated useful lives are as follows: Distribution station equipment Poles, towers and fixtures Overhead conductors Overhead devices Underground conduit Underground conductors and devices Transformers Services -overhead Services -underground Distribution meters Smart meters Computer hardware COmputer software 40 years 50 years 60 years 40 years 50 years 30 years 40 years 50 years 40 years 25 years 15 years 5 years 5 years Depreciation methods, useful lives and residual values are reviewed at each reporting date. Impairment Property, plant and equipment assets with finite lives are tested for recoverability whenever events or changes in circumstances indicate a possible impairment. Any impairment is recognized in comprehensive income when the asset's carrying value exceeds its estimated recoverable amount. An impairment charge may be reversed only if there is objective evidence that a change in the estimate used to determine the asset's recoverable amount since the last impairment was recognized is warranted. A reversal of an impairment charge is recognized immediately in comprehensive income. after such a reversal, the depreciation charge, where relevant, is adjusted in future periods on a systematic basis over the assefs remaining useful life. (_) \__ _ _) _) 4. Financial instruments TILLSONBURG HYPRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31. 2013 The fair value of cash, accounts and income taxes receivable, due from (to) related parties, accounts payable and accrued liabilities and customer deposits is approximately equal to their carrying value given their short-term maturity date. Exposure to market risk, credit risk, and liquidly risk arises in the normal course of the Corporation's business. Market risk refers primarily to risk of loss that results from changes in commodity prices, foreign exchange rates and interest rates. The Corporation does not have market risk due to the flow through nature of its energy purchases and costs. The Corporation does not have foreign exchange risk. The Corporation minimizes interest rate by issuing long-term fixed rate debt Financial assets create credit risk if customers fail to discharge an obligation, causing a financial loss. The Corporation's distribution revenue is earned on a broad base of customers principally located in Tillsonburg, with no single customer that accounts for revenue or accounts receivable balance in excess of 1 0% of the respective balance. The Corporation invests in short-term investments which are not considered a credit risk. Liquidly risk is the risk that the Corporation will not be able to meet its financial obligations as they become due. Short-term liquidity is expected to be sufficient to fund normal operating requirements. 5. Property. plant and eauipment The value of property, plant and equipment as at year end are as follows: Accumulated Net Nat Cost Amortization 2013 2012 Substation land $ 11,520 $ $ 11,520 $ 11,520 Substation equipment 404,210 (340,592) 63,618 65,602 Distribution system 18,865,971 (9,557,799) 9,308,172 8,336,491 Computer hardware 19,886 (13,704) 6,182 Computer software §56,125 {363,336) 192,789 $19,857,712 $10,275,431) $ 9.582.281 $ ~.413,613 I C_) TILLSONBURG HYDRO INC. NOTES TO FINANCIAL STATEMENTS pECEMBER 31.2013 7. Deferred costs and regulatory expenses The Corporation incurred costs to prepare and file a rate rebasing application. The Ontario Energy Board provided approval to recover $106,000 of these costs through rates over a four year period commencing in 2009. The amortization of these costs is recorded in regulatory expenses. The final disposition of these costs occurred In 2013. In addition, the Corporation expensed its costs related to the 2013 rate rebasing application in 2013 of $82,733. These costs are induded in regulatory expenses. 8. Long-term debt The Corporation incurred long-term financing for the smart meter program. The bank loan is repayable over 1 0 years, and bears interest at 4.53%, and has the option of a 1 0% prepayment each year. The loan is secured by a general security agreement. Principal repayments over the next five years are as follows: 2014 $124,no $130,541 $136,571 $142,895 $149,505 2015 2016 2017 2018 9. Deferred contributions Deferred customer contributions in aid of construction or acquisition of property, plant and equipment is as follows: Deferred contributions received Less: Amount recognized as distribution revenue Deferred contributions, and of year 1 0. Share capital 2013 $ 2,757,152 (773.380) $-1.983.772 2012 $ 2,838,082 (710.652) $ 2.127.430 The share capital of the Corporation consists of the following: Authorized -Unlimited common shares -Unlimited number of Class A shares -non-voting, non-cumulative redeemable 2013 2012 Issued - 1 voting common share $ 6.992.565 $ 6.992.565 During the year the Corporation returned $200,000 of the contributed capital to its shareholder. \,_) 14. Prudential support T!LLSONBURG HYDRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31.2013 Tillsonburg Hydro Inc. has posted a letter of credit with the Independent Electricity System Operator (!ESO) in the amount of$ 956,406 (2012-$956,406). The IESO is responsible for ensuring that prudential support is posted by all market participants to satisfy their prudential support and obligation and, therefore, mitigate the impact of an event of default by a market participant on the rest of the market. 15. Explanation of transition to !FRS The Corporation has elected under IFRS 1 to use the carrying value of property, plant and equipment as the deemed cost at the date of the transition. Therefore, there has been no change to property, plant and equipment at January 1, 2012. In accordance with I FRS, the Corporation has revised its accounting policy to address the component accounting requirements for property, plant and equipment. The standard requires more rigorous accounting for significant components of property, plant and equipment than is required under Canadian GAAP. As part of the componentization exercise, the useful lives of the various components were determined and the amortization has been recorded from January 1, 2012 using the new useful lives. This had the effect of increasing property, plant and equipment net book value by $376,843 on December 31, 2012, and decreasing depreciation expense by $376,643 for the year ended December 31, 2012. In addition, to componentization, !FRS contains different definitions of costs eligible for capitalization. As a result, the Corporation has reviewed the amounts of overhead and related costs capitalized to property, plant and equipment in 2012 and have determined that no adjustment is required. !FRS 14, Regulatory Deferred Accounts, permits a Corporation which is a first-time adopter of IFRS to continue to account for regulatory deferral account balances In accordance with its previous GAAP, both on initial adoption of IFRS and in subsequent financial statements. Regulatory deferral account balances, and movement in them, are presented separately in the Statement of Financial Position and Statement of Comprehensive Income. Deferred contributions at January 1, 2012, of $2,184,077, have been reclassified from a credit offsetting property, plant and equipment to a long-term liability. The amortization of these contributions for the year ending December 31, 2012 of $57,874 has been reclassified from depreciation to distribution revenue for the year ending December 31, 2012. There is no effect of these changes on the comprehensive income for the year. The Statement of Cash Flows for the year ending December 31, 2012, has been adjusted for the change In amortization from the componentization of property, plant and equipment of $346,843 and the reallocation of the amortization of the deferred capital contributions of $57,87 4. ,r \,....._---""'' -\ _ _:j Tillsonburg Hydro Inc. -Financial Information 2009. 2010. 2011. 2012. (CdnGAAP) (CdnGAAP) (CdnGAAP) (CdnGAAPl Total Assets $ 10,453,412 $ 12,656,022 $ 11,919,253 $ 12,253,959 Shareholder's Equity $ 8,486,169 $ 8,788,860 $ 8,n2,254 $ 8,969,437 capital Additions $ 1,020,825 $ 689,698 $ 821,257 $ 502,348 Total Customers 6,738 6,700 6,745 6,782 Distribution Income $ 2,811,436 $ 3,326,724 $ 3,089,744 $ 3,173,144 Other Income $ 41,438 $ 85,336 $ 96,119 $ 133,973 Expenses $ 2,663,688 $ 2,875,880 $ 2,866,911 $ 2,892,457 Income Taxes $ 21,641 $ 83488 $ 85,557 $ 61,4n Net Income AfterTax $ 167,545 $ 452,692 $ 233,395 $ 347,183 CUrrent Ratio (Current Assets/CUrrent uabilities) 2.15 2.24 2.61 2.59 Return on Assets (Net Income/Total Assets) 1.60% 3.58% 1.96% 2.83% Return on Equlty(Net Income/Total Equity) 1.97% 5.15% 2.66% 3.87% ---- * Ontario Energy Board Yearbook ** 2013 Audited Rnanclal Statements prepared using International Financial Reporting Standards ··-·-----~----------~-----------------------------------·--------------·------~--------------· Z01Z** (lnt'l FRS) $ 14,758,232 $ $ 9,346,275 $ $ 502,348 $ 6,782 $ 3,307,971 $ $ 133,973 $ $ 2,650,441 $ $ 61,4n $ $ 724,026 $ 2.59 4.91% 7.75% 2013** (lnt'l FRS) 15,296,537 $ 9,392,968 $ 1,524,859 $ 6,892 3,996,600 $ 25,929 $ 3,406,952 $ 68,874 $ 546,693 $ 2.22 3.57% 5.!mll r-·, J ·--J Z014Budpt (lnt'l FRS) 12,717,272 I 9,259,390' 750,214 6,892 3,342,768 141,300 2,940,569 39,848 503,651 2.54 3.96% 5.44% I 0 Attachment 39 __ ) '--·· W11511pi20UI $282.96 !10-DO $495.00 80.3% Hydro 2000 [proposed 20121 $:l94.60 94.01: $728.40 11B.1J5 Lakeland $316.68 101.1% $641.40 104Jm Renfrew $!D5.16 97.4" $686.28 U1.3K WestCoast Huron $347.04 110.8% $683.04 110.~ On~npvllle $329.52 105.2% $639.72 :l03.7% North Bay $Z94.96 9IL2fi $648..60 105.3i Burltns!xm $306.12 97.7'J'o $631.32 102.A" Mdland $329.52 105.2% $550.32 89.2illi Essax $295.20 94.~ $669.48 1DB.S5 Cllmbrldp Nanll Dumfries $276.00 88.1% $444.72 72.1" Rideau St. !awr. (praposad 2D12l $300.24 95.81Hi $607.56 ~ Centre Wellington $289M 92.41Hi $567.72 92JM Verldlan $284.88 !lll.!lilli $573..72 M.DK St. Thomas $290.16 92.6" $561.00 9UJK Mli!Dn $!12.60 99.8illi $596.28 96.1!6 Guelph $33D.60 105.5illi $482.o40 78.2'J6 Brantfonl $270.00 86.:5 $45:1.72 7!1 .... Oshawa $21132 67.5illi $49:1.92 80.1" Hydro OnS Brampum $255.24 81.5" $587.40 !15.:5 Lakefront $256.32 81.8" $469.20 76.1!11i !TIIIsa nbura $281.16 89.nli $665.64 11l7.9illi Grlmaby $292.68 !13.4" $60&.72 98.4" Powenltream $273.48 87.3illi $622.08 100.9% Wi!!lland $310.68 99~ $506.oll0 82.B Westarlo $272.40 87mfi $470.04 7ti.2illi cou.us $271.20 86.6% $486.9& 79.0" Northem Ontario Wires $343.56 109.7" $608.40 98-Erie Thames (2011} $291.24 93mfi $443.28 71.!IK l<lnastan $289.08 92.395 $5!0.20 89.2" Peterborough $254.28 ~ $574.80 93.2illi Ottiiwii River $273.2.4 87.2% $520.92 84.5!Hi ThunderBav $237.Z4 75.7illi $52&.08 85.3" E.L.K. (2011) $209.40 66-$173.52 28.1" Hearst $262A4 83.8illi $396.84 64.3" Entesrus • Middlesex $285.00 91.DK $338.16 54.8!Hi Hydro $148.20 47.3" $297.00 48.2!Hi [AIIEIIAQ $313.28 $616.78 $14.617.0S $9,372.36 $1D.083.90 $9.314.:!2 $10.0!10.68 $8,770.68 $9,616.50 $9,444.84 $9,1!87.96 $8.690.94 $12,D.!I& $9,284.28 $10,317.00 $10,781.40 $10,981.74 $8,446.80 $9,391.50 $11_337.42 $11,346.54 $11.614.14 $11,142.!10 $6,656.16 $7,1161.76 $11,524.20 $8,!146.48 $!1,!593. 70 $9,288.24 $4,243.32 $5,931.30 $9,0118.56 $10,276.o& $6,389.112 $6,982.26 $1:1,736.28 $7,585.32 $4,892.52 $5,796.18 $11,274.45 129.6% 83.1% 89.4" BU'Jii 89m6 77.8illi 85.3" 83.8" 85.91Hi 77.1" 10!1.1" 82.3" 91.5" 958 92.1" 74.9illi 83.3" 101J.&96 101J.&96 76.4" 911.6 59.0!11i 62.6" 102.2" 74.0" 115.1" 82.4" 31-S ~ 80.6" 9Ll" 5ti.7% 61.9" 121.8" 675 43.4" 51A!Hi / / \ .I '---./ $263,286.84 $351,286.80 $300,977.04 $304,622AO $283,051.44 $396.712.44 $310,669.68 $151,891.5& $260,977.68 $355,501.92 $182,523.9& $164,217.48 $51,040.80 $340,859.01 CJ'--" 100.1" 12,046 98.""' !,1!16 ~ 9,439 97.1" 4,155 77..2% 96oft 22,007 95.6W 11,256 94.m£ 23,754 94-"' 64,319 93 ... 6,914 93.35 28,183 103.DK 93.1" 50,890 92.2illi 5,818 9~ 19,196 ll8.3illi 92.0Wi 112,569 91.9illi 2.754 89-"'6 90.291i 29,142 u.mc 87.5" 50,250 86.8illi :17,654 98.ni 86.7illi -52,710 91.1" 86.1" 134.Z2B 858 9,571' 85.6" 6,Mili 84.8% 10,151 44.&!Hi 83.7ifli 325.,540 76.6" U.OJ6 21,411 82.8% 3770 82.6% 15.5:13 82.0J6 6,026 104.3" 80.4" 14,373 53.5" 78.9" 26,91J4 48.2" 78.4!Hi 35,012 7&.1!Hi lD,475 74.3" 49,508 72.3!16 11,205 7l..U. 2,7:14 15.~ 5l.Oilli 7,859 49.0" 5,496 ---............. '--·-··---·-·--·----------- \. .. ...__ .. / Haldlmand Caunty $25S.SO $328.76 $73.26 28.1'J6 Halton Huts $190.38 $21.7.25 $26.87 14.Hii Festival-Main $168.66 $206.34 $37.68 22.3'Jti CNP Fort Erle/Ea5tam $273.68 $352.44 $78.76 2B.8'Jti Norfolc $21z.n $2£65 $50.93 a• Sioux Loakaut $372.99 $426.09 $53.10 14.2'Jti OOLLUS $19559 $275.69 $110..10 41.0'Jti Woodstock $21.2.38 $243.45 $31.08 1A.Ii'J6 lnnlsfll $195.28 $267.36 $72.08 36.~ ErleThaml!li $319.1)4 $310.93 -$8.11 -2.5'Jti Or! lila $Z61151 $329.28 $60.78 22.6'J6 Wallilill $147.:13 $1.82.89 $3Ui5 24.29' A11111ma $641.0S $749.56 $10BA7 16.9'111 Orangeville $17S.1S $23S.OS $&9.92 34.2'l6 OttawaRIINII' $186.70 $221.99 $35.29 :18.9'Jti Grlmsby $160.35 $177.89 $17.54 10.9'l6 Brant County $356.90 $361.27 $4.37 1.Z'Jti Lilla!front $188.30 $224.26 $!15.96 19.1'Jti Lakeland $216.53 $312.58 $96.05 44A'l6 CNP Pon Calbome $432.95 $388.19 -$44.76 -~.3'Jti Nlaeara-CIII-the-Lake $182.64 $228.52 $45.89 25,1'Jti Entegrus-Mldlie5ex $244.48 $217.46 -$27.01 ·11.0% Mldl;lnd $2.54.24 $271.67 $17A3 6$ nJ lsonbUil& $215.9JI $330.22 $114.29 52.9'Jti centre Welllnstan $234.34 $285.14 $5G.80 ZL~ Northern Ontario Wlras $259.23 $341.29 $82.06 3L'"' Rideau St. Lawrence $229.27 $286.42 $57.15 249K Kenora $206.88 $309.90 $103.02 49Jl'l6 Hydro Hawkesbury $1AO.DS $160.73 $20.68 14.8" Renfrew $172.53 $250.57 $78.03 45.2" Huron $373.54 $351.48 -$22.05 -5.9')1; ~allln&ton Nonh $277B4 $352.24 $74.40 26.8" PanySound $306.09 $359.27 $53.18 17A" St.Tho1118S $197.94 $2111.22 $12.28 6.2'Jti HI!III!St $213.80 $299.76 $85.96 40.~ l:mbrun $198.84 $242.10 $43.86 22.1" Hydro2000 $264.06 $249.oll5 -$14.60 -5.5" WSSHJEDA.VI!RAGE $219.70 $29032 $7o.G2 32.1" SIMIUAIIRAG! $229.18 $269.84 $40.66 17.7% $1,416 $1,657 $1,274 S1M8 $1,559 $1,712 $l,179 $3,282 $1,897 $2,608 $1,1184 $1,644 $667 $857 $1,1!19 $1,3!17 $1,3.81 $1,537 $:1..148 $1,245 $:1..219 51.197 $775 $732 $4,280 $6,071 $U76 $1.246 $824 $780 $1.123 $1,114 $1,986 $2.027 $2_160 $1,139 $3.399 $1.475 $ti95 $3.319 $2,536 $2,515 $9U Si.IDI $810 $1,573 $828 $&85 $2_149 $1,007 $579 $578 $S99 $709 $3.195 $1,315 $387 $35fi $1192 $1,0116 $1,1)42 $1,()97 $776 $1,326 $1,432 $1,140 $3.202 $1,142 $384 $287 $3.107 $982 $324 $373 $2,017 $2,5.54 $1,274 $1,4!14 r. 'v $241 $174 $153 $1,103 $711 -$239 $1!11 $198 $355 $97 -$23 -$43 $2_791 -$a0 -$44 -$9 $41 -$21 $76 $624 -$21 $193 $762 $57 -$142 -$1 $109 $120 -$a1 $94 $55 $549 -$293 -$60 -$97 -$125 $49 $537 $221 .r\ ·J 17mtl 20,97l 13.7'J6 20,79C 9.8'Jti 19,5751 so a 19,196 37.5'16 18,911(1 -12.7'Jti 16,419 .28.696 15,533 16.5'l6 15.o74 30.1'!6 14,707 8.5'!6 14,373 -1.9'Jti 12,862 -5-S'Jti ll,046 41.9'1' 11.612 -2A'Jti :1:1,256 -5AH io.475 .0.8'!6 20.151 2..1% 9,667 -1-9,571 SA'Jti 9,439 89.7'Jti 9,1&9 ~-7,882 21.2'lti 7- 94.1')6 6,914 &.8'Jfi 6,100 ·12A'J6 6,463 ~.Di 6,026 18.2" 5,818 lO.Bi 5,5801 ..a.DWi 5,4961 95" 4,~ 5.3'Xo 3,~ 10.8'Xo 3,6131 ·20A" 3,377 -5.0" 2,754 -25.2" z.~ -11.3% 1,958 15,1'lti 3.196 26.6'J6 I 17.3'16 I ( ,.----.\ ' 2014 TH~bour Allocation \"-.../ ~.-J~ .,.._rtment/ lob Title Diinld: Labour ChaiJ• Indirect Labour Charp• ... IMt Finance CAO 0.00% 15.77% Director of Rnance 0.00% 20.57% Rnance Reg. Affairs Manager 0.00% 100.00% Deputy Treasun!lr 0.00% 18.99% Senior Cost/Budget Analyst 0.00% 1.80% AlP & AIR Coordinator 0.00% 15.77% HR Manager 0.00% 15.77% CLERK 0.00% 8.44% Cylll:mnar SarvJc:w CUstomer Service Manager -50% of FTE 0.00% 59.24% Billing Support Clerk 0.00% 65.24% Billing Support Clerk 0.00% 81.22% CUstomer 5ervlce COOrdinator 0.00% 24.79% customer service Representative 0.00% 32.29% CUstomer Service Representative 0.00% 35.86% Billing SUpport Clerk 0.00% 83.33% utility Revenue Coordinator O.OOo/a 81.08% Bra Rwarl;rll8nt Fire communicator 0.00% 10.80% Fire Communicator 0.00% 10.80% Fire CommuniCator 0.00% 10.80% Fire Communicator 0.00% 10.80% OparatiQPidmln Director of Operations 0.00% 25.50% Operation utility Manager 0.00% 50.00% Enalnoering · Engineering Manager 0.00% 20.00% Operations Technologist 0.00% 20.00% Operations Technologist 0.00% 20.00% Asset Management 0.00% 25.00% C:\~1111111\Hydn>\2014 THILabor Alocatillll 0110412014 ·----............. -----------------------·--···------------------- \ ) () ) Attachment 41 Introductions/Context Background: A Brief History of LDCs in Ontario • Origins • Recent Developments Current Landscape Potential Options for Municipal Shareholders Key considerations • Stakeholders • Market and Valuation • Regulatory/Tax • Transaction Strategy/ Arrangements Examples Conclusions @ 2013 KPMG, a Canadian limited liability partnership, is part of tile KPMG International network. KPMG International is a Swiss cooperative. All rights reserved. The KPMG logo and name are trademarks of KPMG lntematlonal. 1906: Genesis of Local electrical Distribution Companies (LDCs) • Ontario Government establishes Hydro Electric Power Corporation (eventually becoming Ontario Hydro) to manage electricity transmission from Niagara Falls to LDCs. 1923 -1998: LDCs proliferate • Over 390 LDCs with Ontario Hydro providing the generation and transmission of electricity to all LDCs. • The LDC evolution in Ontario was and is unique in Canada. No other province has more than a few municipally-owned distribution utilities. 1996: Recommendation to create large LDCs • Macdonald Committee review of structure and recommendation to merge municipally-owned LDCs along with Ontario Hydro's rural distribution system to create large LDCs @ 2013 KPMG, a Canadian limited llabQity partnership, is part of the KPMG International network. KPMG lntemational is a Swiss coopera1iVe. All rights reserved. The KPMG logo and name are trademarks of KPMG International. 3 .......... _, ___ , __ Regulatory Pressures: • OEB productivity standards/ rate containment expectations -that are increasingly difficult to meet with LDC status quo/non scaled structure. • OEB policy review-to determine what changes are needed to encourage operational improvements and remove any disincentives for consolidation and generally to encourage LDC transactions Scale Service Platform Expectations: • Scale increasingly seen as key -to achieve efficient operating platforms and deploy technology and service standards that meet customer expectations of improved services, as well as regulator expectations of rate containment and productivity. Identified Savings Expectations: • Opportunities to combine and achieve synergies -in operating, maintenance and administrative costs (OMA) as well as in capital programs, are being considered within the current structure of the 80 Provincial LDCs • Provincial Government's continued interest -to explore ways to motivate LDCs to achieve the $1.2 billion (1 0 to 15%) savings identified in 2012 December Distribution Sector Panel Report. While not forcing consolidation, Government announced in April 2013 that they· will look to the sector to voluntarily deliver the identified savings © 2013 KPMG, a canadian limited liability partnership, is part of the KPMG International network. KPMG International is a Swiss cooperative. All rights reserved. The KPMG logo and name are trademarks of KPMG International. --......... ·--··· ·····-·····--···---------------.. ----- 5 -·--·--·-·-·····------------------ Attribute Then @ 2013 KPMG, a canadian limited liabifil:y partnership, Is part of the KPMG International network. KPMG International is a Swiss cooperative. All rights reserved. The KPMG logo and name are trade.marks of KPMG International. 7 ----··----···---···-······-······-·----·-· ------- Key factors to consider in determining the optimal strategy Key Considerations 1. Industry Context • What are the industry movements at government and provincial level and how do they impact municipal owners in the short and long term • What is the regulatory, technological and labour environment 5. Transaction Strategy/Arrangements • What investors may be interested and what would they need? • Would others value synergies? and can these be factored in? • What tactics can be used to maximize value? 2. Stakeholder position and views • What's the current position of the key stakeholders (Ratepayers; Taxpayers, Employees/employment base; Municipal shareholders) and what are their any limits on what options they would consider • Need for immediate cash vs. future stream of dividends 3. Market Considerations • What are others doing and how would this impact? • What are the growth rates and the future of the rate base? • What are the market prices being paid and what is investor demand? (e.g. Norfolk) 4. Tax and Regulatory Regime • Implication of transfer tax PILS, departure tax, and alternative structures on potential bidders and valuations • MADD @ 2013 KPMG, a Canadian limited liability partnership, is part of the KPMG International network. KPMG International is a Swiss cooperative. All rights reserved. The KPMG logo and name are trademarks of KPMG International. ····~·---·-·-··-------··--·----·· 9 The market related to current valuations and future potential activity need to be considered Recent M&A Activity Synergies Support M&A • One initial sale, generated significant and aggressive competition with high value premium. Previously there had been few sales, with mergers being the preferred model to retain interest (PowerStream/EnsourceNeridian) • Various municipalities and municipal entities exploring options; In addition to Hydro One, many medium size municipally owned players offer consolidation/merger opportunities • Expectation that through consolidation, savings in administration and OM&A will benefit ratepayers • Anticipated savings of 1 Oo/o-20% on a case by case basis can be achieved, however KPMG analysis suggests there may be additional benefits depending on acquirer • Strong interest by institutional and strategic investors in LDCs that offer scale and add-on investment opportunities-threshold investment interests and current tax barriers limit participation • A merger with adjacent utilities or others could present scale that would attract private capital to the combined entity as a future option • Analysis on options related to a stand-alone merger or merger with financial partner would need to consider scale, governance, strategic rationale and appetite in advance of entertaining further discussions • Current high level of interests generating high returns that may not be sustainable in long term • Hydro One's offer of 1.70x rate base for Norfolk Hydro (1.60x adjusted) is creating a precedent and expectations for future transaction valuations in the market @ 2013 KPMG, a canadian limited liability partnership, is part of the KPMG International network. KPMG International is a SWiss cooperative. All tights reserved. The KPMG logo and name are trademarks of KPMG International. ··-·-·---------·-·-··-······-······-··--·-------- 11 ·------·· ··-·'. Regulatory Considerations • "MAADs" Application • The Ontario Energy Board Act requires that any person acquiring an LDC must file an application with the Ontario Energy Board • The test to be applied by the OEB is the "no harm'' test: "whether the transaction would have an adverse effect" when considering the following factors: • Protect the interests of consumers with respect to price and the adequacy, reliability and quality of electric service; and • To promote economic efficiency and cost effectiveness and to facilitate a financially viable electricity industry © 2013 KPMG, a Canadian limited Uabllity partnership, is part of the KPMG International network. KPMG International is a Swiss cooperative. All rights reserved. The KPMG logo and name are trademarks of KPMG International. 13 ---------·-----····--··----------------------------------------·-· -·---------------- Typically additional three to six month time frame Evaluate Proposals/Final Negotiations • Shortlist investors (3-5) • Solicit binding offer • Enter into exclusivity with preferred partner • Negotiate terms of definitive agreements • Manage due diligence and transaction process to execution of definitive agreement s Approvals and Implementation • Board and Council Approval • OEB MAADs application • Closing • Implementation © 2013 KPMG, a Canadian limited liability partnership, is part of the KPMG International network. KPMG lntematlonal Is a SWiss cooperative. Am rights reserved. The KPMG logo and name are trademarks of KPMG tltemational. 15 ----------------------------·-------------------------- Structure: Acquisitions to date have typically involved a purchase of a minority interest in a municipally-owned LDC (given tax implications) Subsequent Interests: • In exchange for the purchase price, the selling municipality transfers the proportional ownership of the acquired interest in its LDC to the ac.quirer's shareholders. • Residual LDC control and operation of assets are typically subject to minority shareholder and veto rights. Examples: • Enersource @2013 KPMG, a canadian limited liability partnership, Is part of the KPMG International network. KPMG lntemalional is a Swiss cooperative. All rights reserved. The KPMG logo and name are trademarks of KPMG International . .. ---·---·---------------·····~·-···-···---~--····-···~~-~-~~-~- 17 Structure: involves combining the operations and assets with a partner aimed at equalizing interests in the combined entity, while accessing services from a larger scale platform. Subsequent Interests: • The shareholders of the smaller LDC, receive proceeds for a share of their LDC with the larger LDC taking a corresponding ownership interest to their relative contributions in the merged utility. • Control and operation of purchased assets and employees are shared, but with access to leverage services provided from a larger scale platform . • Shared values establish requirements around rates and retentions of staff, services and facilities Examples: • Town of Collingwood and PowerStream's Strategic Partnership in Callus PowerStream @ 2013 KPMG, a Canadian limited liability partnership, Is part of the KPMG International network. KPMG lntemalional Is a Swiss cooperative. All rights reserved. The KPMG logo and name are trademarks of KPMG lntemational. ................. ---·----·-------· _________ .............................. --.-----· 19 The LDC operating landscape has become more complicated and the risk profile of municipal ownership has increased • Municipal LDC owners should review their risk appetite and evaluate the ongoing value proposition of their current ownership in light of the increasingly complicated/risky landscape There are a number of options for municipal owners of LDC's to explore that should be evaluated and reconciled with municipal priorities to make an informed decision. • "Beware" of the big cheque and "be aware" of other considerations • A number of these options have been profiled here today with perspectives shared by peers Once a decision has been made-a supporting transaction strategy and arrangements can be developed to realize the desired values. • Key process elements have been reviewed along with a timeline to illustrate the steps and level of commitment e 2013 KPMG, a Canadian limited liability partnership, is part of the KPMG International network. KPMG International is a Swiss cooperative. AU rights reserved. The KPMG logo and name are trademarks of KPMG International. ---------······-···-··· ..... , ..... ··-··· ----~-----... 21 -----····-.......... _. _______________ _ (~) Reprsantlag Onbrio's ElectridiJ lliltrilorlm \ .. ) FOR IMMEDIATE RELEASE August 8, 2012 Electricity Distributors Association offers Six Point Plan to save Ontario electricity customers more than half a billion dollars annually Allowing distributors to offer more utility services, curtailing electricity retailers' activities with residential customers, promoting voluntary mergers of utilities and improving industry regulation are key recommendations to the Ontario Distribution Sector Review Panel. TORONTO-The Electricity Distributors Association (EDA) met with the Ontario Distribution Sector Review Panel to outline a six point plan that will save Ontario electricity consumers more than $540- million each year. The Association's 150-page submission details how Ontario can realize the full potential of Its electricity distribution system and achieve efficiencies that will ultimately benefit customers and communities. "Our submission details how, with the right changes, the government could reduce customer bills by close to five per cent and improve the distribution system in Ontario at the same time," says Max Cananzi, Chair of the EDA. "LDCs can deliver more than just electricity-by growing and delivering more services to their communities, they can be even more efficient which will lead to savings for customers." The EDA's six point plan examines all aspects of the distribution sector including operations, ownership, regulation and new and emerging technologies to find ways to make the sector more efficient. "There are definitely savings to be had through mergers and amalgamations if done correctly-we estimate about $50-million worth-but it doesn't end there, H says Charlie Macaluso, President and Chief Executive Officer of the ED A. "We dug deeper and identified greater and more significant savings of nearly a half a billion dollars that could come from improved regulation, a keener focus on the customer and encouraging distributors to grow." Capturing the $54Q-million per year in savings will depend on whether the government will make the following changes in the electricity distribution industry: 1. Allow LDCs to manage water and waste-water services-$180-million 2. Permit LDCs to carry out street light maintenance work In their communities-$15-million 3. Let LDCs take the lead In designing and developing conservation and demand management programs that make sense for their customers and communities instead of today's centrally planned, one-size-fits-all programs-$2D-million 4. Improve industry regulations-$15-million 5. Curtail energy retailers in the residential sector-$260-million 6. Promote the voluntary mergers of LDCs-$50-million The full EDA submission, Power to Deliver: Recommendations for the Future of Electricity Distribution in Ontario is available on the Association's website at www.eda-on.ca. ) ,_) Attachment 42 Table of Contents Foreword ............................................................................................................................................. iii Guide for Readers ................................................................................................................................. v Acknowledgements ............................................................................................................................. vi Executive Summary .............................................................................................................................. 1 Introduction and Background ............................................................................................................... 9 A. History of LDC Evolution in Ontario ......................................................................................... 9 B. Distribution Sector Contributions to Ontario's Economy ....................................................... 11 C. lpsos Reid Survey ................................................................................................................... 12 The Challenges Facing Distribution .................................................................................................... 15 A. Infrastructure Investment ...................................................................................................... 16 B. New and Emerging Technologies ........................................................................................... 17 C. Conservation and Demand Management .............................................................................. 25 D. Renewable and Distributed Generation ................................................................................ 26 E. Costs ...................................................................................................................................... 26 F. Regulation and Government Policy ....................................................................................... 28 G. Human Resources .................................................................................................................. 28 H. Breakdown of the Bill ............................................................................................................. 3D Efficiency Opportunities ..................................................................................................................... 31 A. Efficiencies Through Regulatory Streamlining ........................................................................ 33 B. Efficiencies From Scale and Contiguity ................................................................................... 37 C. Efficiencies From Reducing Regulatory Constraints on Scope of Operations ......................... 44 D. Changes to the COM Framework ........................................................................................... so E. Efficiencies Through Curtailment of Electricity Retailers ....................................................... 59 F. Estimates of Potential Efficiency Gains .................................................................................. 61 ••• ••• ••• 0 0 0 Foreword The Electricity Distributors Association (EDA) is pleased to submit this proposal -a series of recommendations that address increasing the efficiency of Local Distribution Companies (LDCs}. Our proposal is not submitted in isolation. We understand and appreciate that the Government of Ontario and its energy agencies are in the midst of a benchmarking study and in one case, a merger of two Important organizations with provincial mandates-the Independent Electricity System Operator (IESO) and the Ontario Power Authority (OPA). The EDA and our members applaud these activities, the goal of which is to create better value for electricity consumers. These consumers are the customers of our members, and our members' focus is on providing customer value every day. We are pleased to put forward the system-wide recommendations to further this value. The Ontario Distribution Sector Review Panel (Panel} has a mandate to: "Provide advice and make recommendations to the Minister of Energy regarding issues related to Ontario's electricity distribution sector and distribution models, including opportunities for consolidating distributors". The EOA supports the work of this Panel-in fact we called for such a review in November 2011 in our paper titled Electricity is the Answer. Our province's dependence on reliable electrical power continues only to grow, and our ability to continue to meet demand and maintain reliability is paramount. The goal of creating a more efficient electricity system in Ontario, as a whole, is valid. That drive for efficiency, however, must never place reliability at risk. Our submission to the Panel, The Power to Deliver, is very much a proposal that addresses many issues facing Ontario's electricity sector. This paper demonstrates that Ontario's outdated regulatory model has become a significant barrier in the ability of our members to grow and make the kind of long-term investments that are critical to renewing our infrastructure. You will also read that our local members have been addressing Canada's so-called "Innovation Gap" for decades, as each of our members develop and test new ideas that, once successfully implemented on a local basis, are often taken as best practice across our entire industry. Indeed, the seventy-five member LDCs that serve the province are a broad well of Innovation, and one that needs only the freedom to create and test to develop more system-wide tools for efficiency. Since 1998, the number of electricity distributors has dropped from more than three hundred to today's number of seventy-five. Every year, some of our members determine-voluntarily-that it is in the best interests of their customers and their shareholders to merge with another member. So the central question for the Panel, we suggest, is not whether consolidation is necessary, but whether the heart of any recommendation the Panel may make should benefit Ontario's more than 12-million electricity consumers. • ••• ••• ••• () () '-- Guide for Readers The Proposal before you is a significant document. There is a great deal of information within it and this information is presented as the basis for well-considered recommendations as well as a series of options on how to best implement them. Fully two-thirds of the document is made up of Appendices. In the Appendices you will find the details of much of the information presented in the document. The data referenced in this document is current as of 2010, except where more recent data is available and in which case is specifically noted. Also, the Panel had several specific questions for the EDA. The questions and our responses are included In Appendix A for ease of reference. Section 1 of the proposal provides the reader with background information on how Ontario's LDCs came to be, what our members are responsible for, and a summary of their current attitudes as it relates to the Panel's mandate. Section 2, The Challenges Facing Distribution, is analysis of the current regulatory, policy, and implementation issues, concerns, and opportunities that our members are working with as well as outlining the implications the present situation has on the end goal-increased LDC efficiency. Section 3 provides the reader details of how the EDA believes that new efficiencies in electricity distribution can be achieved. These recommendations fall into the categories economies of scale, economies of scope, the development and delivery of COM programs, and an overall reform of the regulatory process. Section 4 outlines several implementation options for these recommendations, all of which are founded upon creating measureable cost savings for Ontario's electricity customers. • •• ••• ••• 0 PCL XL error Subsystem:xlpaint () Error: Input Stream EOF Operator: BezierRelPath Position: 131692 () ( ) "--- Background Paper {"\ ----------------------:L,_) The Consensus Accord September 12,2013 Sometimes in the course of public events, it becomes clear that responsible people have two choices: They can either complain, shriek, and kick dirt on ideas put forth by their government or by others, or, they can take the "High Road" and instead offer suggestions and solutions they believe make more sense, thereby seeking to build bridges and "Consensus'' to move things forward. The latter choice is what spawned this effort. This document was created as a result of thirty-eight (38) small-to medium-sized Local Distribution Companies (representing approximately 600,000 customers) coming together to analyze and discuss the recommendations and findings of The Report of the Ontario Sector Review Panel, "Renewing Ontario's Electricity Distribution Sector: Putting the Customer First". The combined industry wisdom and experience of the group has led to a set of alternatives, insights and objectives with the goal of guiding the development and optimization of the Electricity Sector in Ontario -for the benefit of consumers. We challenge many of the assumptions put forth in the Sector Panel Review Report, but more importantly, we offer tangible alternatives that could, and we believe would, move the industry forward along a customer-centric path. We submit these ideas respectfully, hopefully, and certainly in the expectation that they will open the doors to a discussion which will lead to a better vision for tomorrow's Ontario Electrical Distribution System. Respectfully submitted, The Consensus Accord· BlUewater Power Distribution Corporation lnnisfil Hydro Dls1ribution Systems Rideau St Lawrence Distribution Inc. Brant County Power Inc. Urn !ted Sioux Lookout Hydro Inc. Centre Wellington Hydro Ltd. Lakefront Utilities Inc. St. Thomas Energy Inc. Chapleau Public Utilities Corporation Lakeland Power Distribution Ud. Tlllsonburg Hydro Inc. Cornerstone Hydro Electric Concepts Inc. Midland Power Utility C01poratlon Wasaga Distribution Inc. (CHEC) Milton Hydro Distribution Inc. Wslland Hydr~Eiecfrlc: System Corp. Cooperative Hydro Ernbrun Inc. Newmarket-Tay Power Distribution Wsl&ngton North Power Inc. Erie Thames Powerllnes Corporation Ltd. Westarlo Power Inc. Essex Powerlines Corporation Niagara-on-the-Lake Hydro Inc. Whitby Hydro Electric Corporation Fort Frances Power Corporation North Bay Hydro Distribution Limited WOodstock Hydro Services Inc. Greater Sudbury Hydro Inc. Northern Ontario Wires Inc. Haldimand County Hydro Inc. orangeville Hydro Linltecl Hearst Power Distribution Company OrRiia Power DIStribution Corporation Limited Ottawa River Power Corporation Hydro 2000 Inc. Parry Sound Power Corporation HYdro Hawkesbury Inc. PUC Distribution Inc. September 12, 2013 Page 11 0 \ J Background Paper '\ ------------------------~_) EXECUTIVE SUMMARY A collaboration of forty Ontario-based local distribution companies {LDCs) are collectively and cooperatively exploring alternative options to mandatory electricity distribution sector consolidation, as was recommended in the Report of the Ontario Distribution Sector Review Panel, "Renewing Ontario's Electricity Distribution Sector: Putting the Customer First". The combined industry wisdom and experience of the group has supported development of this report that analyzes the recommendations and findings of the Sector Review Panel and presents a set of alternative assumptions, insights and objectives with Which to guide the development and optimization of the electricity sector in Ontario. The report and its authors support a number of key concepts, which are believed to provide a more pragmatic, actionable and customer-focused guide for enhancement of the distribution sector. The Group supports several recent announcements related to consolidation, including avoidance of mandatory policy measures and themes that rely on voluntary business practices to "bend the cost curve". The report also questions some of the fundamental assumptions of the Sector Review Panel Report and brings forward three key messages as follows: • The Group strongly believes that municipally-owned and local LDCs are customer focused and consistently conduct business in the best interests of the customer. The advantages of the local LDC are discussed in this paper and demonstrate their core focus of putting the customer first, consistent with the primary objective ofthe sector paners recommendations. • The Group contends that the Sector Panel Review Report is flawed. The net efficiency gains In the distribution sector postulated through mega-mergers are unclear, distorted by real barriers (such as what to do with Hydro One's asset in contiguous utility regions) and inherently risky. The level of cost savings, as reported by the panel are not transparent and based on indefinite analysis. The Group supports the Minister of Energy's recent announcement that rejects the notion of mandatory consolidation of the sector within two years. • The Group provides recommendations that are based on factual data and result in real cost savings for the customer. The recommendations of the Group can provide real benefits while avoiding the significant transaction and transition costs associated with mandatory consolidation. As a key set of sector stakeholders, we question the value in mass consolidation and ask-is it worth the risk? Is it worth the risk to fundamentally shift the distribution sector and give up the clear benefrts that local utilities offer their communities? Is It worth the risk for the chance at some percentage of unproven cost savings claimed by proponents of consolidation? Is it worth the risk of increases to customer bills, and is it worth the risk to draw focus away from where real savings for ratepayers can be harvested in the industry? We propose instead to maintain the principal objectives of consumer focus, enhanced efficiencies and preparation for the Mure, but also to look for alternative options, where consensus and cooperation can be garnered to nurture a new elecbicity distribution sector that all Ontarians can be proud of. The analysis performed in this report covers a qualitative and quantitative review of the strengths and weaknesses found In the Sector Review Panel report, as well as an examination of the provincial electricity sector. The Group's approach is grounded In the same principles ofthe Sector Panel Review Report to guide the findings and recommendations offered. Fig. 1 shows that small and medium utilities deliver distribution services at rates nearty 25% more competitive to Ontario consumers, in comparison with larger utilities. September 12, 2013 Page 13 (J (_ __ ) ................................................................ s.a.ck•g•ro•u•oo--Pa•pe .. r ........ ~~~~ INTRODUCTION In December 2012, a blue-ribbon panel mandated by the Government of Ontario to investigate the electricity distribution sector released its highly anticipated report, Renewing Ontario's Electricity Distribution Sector: Putting the Customer First. The Distribution Sector Review Panel Report (DSRP) summarized a variety of analyses and set out a number of recommendations, much of which have been highly contentious across the Ontario economy and with its consumers. The finding that consolidation, or amalgamation, of the province's 751ocal distribution companies (LDCs) being the only viable solution to reduce costs and stabifize rates, does not hold strong from all perspectives. The argument that bigger- scale utilities set a better path to enter the future of the electricity Industry Is flawed (or that bigger Is always better in the first place). Of course, all parties have their own biases. Each particular lens that is applied can change analytical findings considerably in an industry as complex and dynamic as the electricity production and delivery Industry. Therefore, these issues should be discussed more broadly and policy should guide the desired results through the creation of positive environments for sector participants to clearly see the optimal paths forward and make business decisions without prescriptive intervention. We believe the Intentions and spirit of the DSRP to be genuine, but there is simply no comprehensive evidence suggesting that consolidating the sector Is best for the consumer. Since the DSRP's release, discussions have not led to consensus on the strategic or tactical directions the sector should take. History has shown us it is therefore likely that prescriptive sector policy will inevitably fail. This report endeavours to change the conversation. Developed by a group of 40 LDCs, the Consensus Accord has leveraged the combined knowledge and wisdom of distribution sector leaders from across the province. Appendix A to this report summarizes a survey conducted to set the context for our analysis and identifies the key issues that the Accord believes pertinent. Our report offers a comprehensive set of analyses that counter those found in the DSRP, while recognizing the merits of the Electricity Distributors Association's Six Point Plan, published in August of 2012. The analyses included here, apply transparent data and methodology. Our findings support further exploration of best pradices and look towards alternative solutions that can be effective In producing cost efficiency without losing robust customer service and local economic activity, while encouraging mergers where appropriate. Our report references the following customer size ranges based on the number of customers serviced by an LDC: Small Utilities Medium Utilities Large Utilities Extra-Large Utilities Less than 12,500 customers 12,500 to 150,000 customers 150,000 to 500,000 customers Greater than 500,000 customers The customer size ranges above are intended to be akin to the ranges used by the sector panel in the DSRP for comparability purposes. However, we have elected to extend the upper limit of the Medium Utilities group from 100,000 customers to 150,000 customers for the purposes of this report. Data will demonstrate that utilities with a customer base around 100,000 customers tend to exhibit the charaderistics of more medium sized LDCs, of which there are a large number of in Ontario. It is believed that many of these characteristics are positive and beneficial for the customer. More often, the medium sized group (including those LDCs up to 150,000 customers) performs more effectively for the consumer in operations and cost management than larger LDCs. We believe the adjusted categorization gives a clearer picture of the various customer bases and their corresponding metrics. All references to LDC sizes throughout this report are based on the above thresholds to maintain a level of consistency and comparability across the analyses. September 12, 2013 Page 15 () ( ) '\. .. _,,. Background Paper -·) ---------------------......-.-:(_ Cost of Delivery Comoarison The fundamental objective of the DSRP is to put the customer first when considering the Mure of the Ontario elecbicity distribution sector. This includes ensuring that the customers are not shouldering the burden of ineffiCiencies in the marketplace, over which they have no control. A key component in the cost to the customer is the delivery charges, which include a customer-service charge (monthly flat fee varying by LDC) and variable distribution/ transmission charges based on kWh consumed (adjusted for the LDC loss factor). Delivery cost per customer is a key metric and subject to regulation by the OEB (i.e. fixed rates for electricity charges)-this is the only significant component of the monthly electricity bill that varies by LDC. Other elements of the bill are by and large uniform from one customer to the next within the same class. In Figs. 2 and 3, an analysis of the delivery charges has been performed to allow for comparability of a cross-section of representative LDCs by size, using the OEB website for standard monthly usage levels. In the Extra-Large category, only Toronto Hydro has been used in the analysis (i.e. excluded Hydro One for the same reasons noted above and consistent with the DSRP). For residential customers in Fig. 2, the analysis has been performed assuming a customer who uses 800 kWh per month and whose pattern of electricity use is 64% off-peak, 18% mid-peak and 18% on-peak. For commercial customers in Rg. 3, the analysis has been performed assuming a customer who uses 6,500 kWh per month with the same pattern of electricity use.2 In Figs. 2 and 3 below, It Is apparent that both the average residential delivery cost per customer and average commercial delivery cost per customer are highest in the Extra-Large Utilities category. In fact, there is a linear correlation between the size of the utility (in terms of number of customers) and the average delivery cost per customer on monthly electricity bills. Therefore, it is entirely unclear why any customer should support consolidation of Ontario LDCs into utilities with 400,000 customers or more. The data suggest that this will be highly unlikely to reduce the controllable delivery costs to the customer. It appears the opposite Is true-the larger the LDC, the higher the monthly costs per customer. In particular, Toronto Hydro has the highest monthly residential and commercial delivery costs per customer, which indicates that If the DSRP recommendations were to be implemented, a number of customers may actually see an increase in their monthly electricity bills as a result. 2 Your Electricity Utllfty, Ontario Energy Board. 2012. September 12, 2013 Page 17 (J ................................................................ e.a.ck•g•~•u•n•d•Pa•~ .. r ........ ~r~ conclusion. While It Is important to acknowledge OM&A cost as a key element of the industry, we also caution against the generic notion that OM&A costs are optimized as utility sizes Increase. In determining the OM&A costs per customer in Fig. 5, the 75 existing Ontario LDCs have been categorized Into size ranges based on the total number of customers, consistent with the ranges described in the introduction. Hydro One has been excluded from the Extra-Large UtiUtles categol}' in this case, due to its unique set of circumstances, with higher costs being driven by the low overall customer density of Its service territories and customers spread out over a wider and more diVerse geographic area. This is consistent with the exclusion of Hydro One from the OM&A cost per customer analysis in Figure 6 of the DSRP report5. Conversely, it is worth questioning why the DSRP also excluded Toronto Hydro from its OM&A costs per customer analysis, whereby it concluded that a linear relationship exists between LDC size and OM&A costs (le, the larger the LDC, the lower the OM&A costs per customer}. Given that part of the overall recommendation in the DSRP Is that Toronto Hydro remains unchanged as one of the 8 to 12 consolidated regional distributors, it brings into question the legitimacy of the OM&A of the analysis. Toronto Hydro is one of the higher cost utilities in the province (as demonstrated by a simple OM&A analysis). To "put the customerfirsr, it is critical to make evaluations including Toronto Hydro in the Extfa..Large Utilities category and assess whether the recommendation put forth ln the DSRP will truly reduce costs to the customer in the long-term. Toronto Hydro Is after all, a Large-sized utRity within the recommended size range of the DSRP and has evolved from past amalgamations, which should make an Interesting case study. Fig. 5 shows that the current annual OM&A costs per customer do not follow the general rule Identified in the DSRP. The industry average for OM&A cost per customer was approximately $292 in 2011; however, Toronto Hydro's adual OM&A costs per customer exceeds the industry average by $36 (or 12%) annually. While it Is fair to state that Small utilities generally have a higher average OM&A cost per customer tll8n the industry average, the OM&A cost per customer is only $2 (or less than 1 %) higher than Toronto Hydro's, which has over 700,000 customers. Therefore, we conclude that there Is no decisive evidence of a lineer relationship between LDC size and OM&A costs. The Medium and large LDCs have far lower annual OM&A costs than the Industry average and this is where the majority of Ontario LDCs can be categorized. Our analysis also finds that within a grouping of some of the largest Ontario LDCs besides Toronto Hydro, the OM&A costs of the 41argest, are on average higher than the next 31argest, which serve about 100,000 customers. Rg. 4 below demonstrates that the optimal size does not align with the DSRP recommendation and that a critical mass falls somewhere closer to the size of a much more diverse set of LDCs near 100,000 customers. 5 Renewing Ontario's ElectriCity DistributiOn Sector. Putting the Customer First, Repor1 of 1he OntariO Distribution Sector ReView Panel. 2012. September 12, 2013 Page 19 () I ) '-~.--.1 ................................................................ Ba .. ck•gro .. u•oo--~.~ .. r ......... (~ capitalized into intangible and construction-In-progress assets8• Smaller utilities do not have this flexibility as they do not have the customer base to justify such massive capital expenditures on construction-in- progress assets, which is a key requirement of capitalization under the reporting requirements set out by the OEB. This accounts for the discrepancy between Figs. 2, 3 and 5. The OEB has recognized the need to review whether OM&A in Its current form Is appropriate and is considering changing the OM &A metric within the Renewed Regulatory Framework for Electricity Disbibutors (RRFE). A key component of the RRFE Is the Modified International Financial Reporting Standards (MIFRS}, which dictates how the financial statements are prepared for the Ontario utilities. The OEB Is currently In the process of revising how recoverable depreciation rates are determined in order to make costs in the Industry more comparable. Until these revisions have been achieved, the comparison of costs across utilities in the province Is Inadequate due to the Impact of capitalization and depreciation policies on the financial reporting by the utilities. These policies vary widely and will often distort comparisons as some LDCs may capitalize less of their administrative expenses, thereby driving up OM&A indices. Another consideration affecting OM&A costs as an adequate measure is due to the fact that many of the Small utilities in Ontario are located in Canadian Shield regions or other difficult terrain. Similar to Hydro One, these utilities have a unique set of operating circumstances: low overall customer density of service territories, customers spread out over a wider and more diverse geographic area, and volatile environmental conditions. In Shield regions, construction and maintenance is more difficult and requires more specialized distribution equipment and materials. Therefore, in excluding Hydro One from the OM&A analysis, it further supports that these Small utilities share these exceptional circumstances, which makes it difficult to noiTT1BIIze and compare their OM&A costs to their counterparties located throughout the rest of the province. In a 2013 benchmarking study prepared for the OEB, it was acknowledged that utilities operating In the Canadian Shield are subject to a unique set of geographical circumstances that inevitably results in higher OM&A costs than utilities in any other region ofthe province9• This further supports that the OEB recognizes this as a key contributor to the higher OM&A costs and as a result, It is difficult and misleading to compare OM&A costs per customer for utilities located In northern Ontario to the other utilities in the province. Reliability & Responsiveness An important consideration for customers Is the reliability and responsiveness rnetrics of the utllhles that serve them -essentially how often outages occur and how long they last. The DSRP notes that smaller utilities are less responsive. Figs. 6 and 7 show these important performance Indicators by LDC size. With careful evaluation, the data disputes the DSRP findings and recommendations. All Ontario LDCs have been included in our analysis; specifically, Hydro One is included in the Extra- Large category. In considering reliability and responsiveness, one must understand the potential reality that faces 8 to 12 regional Ontario LDCs under a consolidated scenario. some of these hypothetical utilities would face the same unique and understandably difficult set of circumstances faced by Hydro One - a low overall customer density spread out over a wide service area with difficult geographic and environmental conditions. Achieving 8 to 12 shoulder-to-shoulder utilities In Ontario would mean that the current operational challenges of Hydro One and other larger widespread utilities will be transferred to most of the consolidated utilities that would exist. More customers will be immediately impacted by the higher cost- 8 2012 Annual Report, Toronto Hydro. Accessed in 2013. 9 Third Generation Incentive RegJJiatfon Stretch Factor Updates for 2013, Report for the Ontario Energy Board. Power System Englneeling, Inc. November 27, 2012. september 12, 2013 Page 111 / ') \_.- I ) \ __ _./ Background Paper ('\ -------------------------------------\ ) SAIFI, there is even less variability in the data and therefore, less room tor improvement. Industry restructuring over a difference of 30 minutes in a total of 8,760 total hours of highly reliable services seems illogical. · It is worthwhile to note that many of the large utilities and consequently those that have undergone prior merger activity are located in some of Ontario's fastest growing regions. These are generally the cities and communities with the most recently developed and newest Infrastructure, such as Markham, Mlsslssauga, Durham Region and the Grand River Area. Correspondingly, it is logical to assume that these utilities would experience fewer and shorter-duration system interruptions due to the newer and more technologically advanced Infrastructure In place. Fig. 8 presents several of the upper and single tier growth municipalities as identmed in the government's Places to Grow growth plan strategy13 and their corresponding utilities services. The diversity within regional systems, as evidenced by these SAID! and SAIFI indices, often makes comparison of Small and Medium LDCs to some of Ontario's larger LDCs, just as poor a comparison as using older and/or rural service utilities such as Toronto Hydro and Hydro One. However, once again we see the Small & Medium and Large-sized utilities outperforming. Figure 7: System Average Interruption Frequency Index (SAIFI) by LDC Size Range14•15 4.00 3.00 2.00 1.00 Small & Medium (Up to 150,000 customers) Large (150,000 to 500,000) Extra-Large (>500,000) Figure 8: High Growth Regions and Reliability Performance 2011 14 Region of Durham Verldian Large Region of York Powerstream Large City ofToronto: Toronto Hydro Extra Large Region of Peel Enersource Large of Hamilton Horizon Utilities Industry Average 2.05 1.00 1.48 1.54 1.74 The above figures articulate why it is critical that not only quantitative operational and financial metrics be considered, but also qualitative metrlcs that Indicate the customer's experience with their utility and the spinoff impacts of consolidation on utility operations. It is difficult to embrace that consolidation of Ontario LDCs will improve the reliability and responsiveness metrics experienced by all, or even the majority of customers In Ontario, given the current mixture of performance of Ontario's largest utilities. 13 Places to Grow, Ministry of Infrastructure. 2013. Website 14 2011 Yearbook of Electricity Distributors, Ontario Energy Board. 2012. 15 Within the Large ca1egory, there are r10 LDCs with a customer base in excess of 400,000. September 12, 2013 Page 113 (') 1... ___ .. Background Paper OM&A cost per customer trends for Utility A are clearly increasing over the time horizons studied in Fig. 10. During the estabfishment of Utility A, through consolidation, mergers & acquisitions, consistent cost efficiency is not demonstrated. The annual OM&A cost per customer are volatile for both Utility A and UtOity B. According to this data, Utility B's OM&A cost per customer has remained relatively flat over time,. although costs are higher now than during pre-merger conditions prior to 2002 and the level of cost reduction is not stable or consistent with claims made in the DSRP that consolidation leads to 15% to 20% efficiency gains in OM&A. It is, therefore, difficult to conclude that substantial OM&A efficiencies have been experienced during these tlmeframes. Figure 10: OM&A Costs per C~tomer for Utility A an~ Utility B (2005 to 2011) 18 Utility A OM&A Costs Per Customer $190.00 $185.00 $180.00 $175.00 $170.00 $165.00 $160.00 $155.00 $150.00 /\ ../ \ ,... \ I \I • ,.__,__ ... Utility B OM&A Costs Per Customer $195.00 $190.00 $185.00 $180.00 $175.00 $170.00 $165.00 $160.00 $155.00 2005 2006 2007 2008 2009 2010 2011 2005 2006 2007 2008 2009 2010 2011 Higher-Cost Service Providers The DSRP Identifies employee labour costs as a component of the administration portion of OM&A costs. Based on the DSRP analysis, administrative labour would appear to be the most significant component of cost and a differentiator in the market between Small and Large LDCs as it relates to OM&A per customer. Correspondingly, an analysis Is performed below to determine If the labour costs are higher in Small, community-based utilities vs. Extra-Large, widespread utilities (such as Hydro One Networks or Toronto Hydro). An immediate challenge to cost containment, where larger utilities acquire or amalgamate with smaller community-based utilities, especially in the case of Hydro One Networks, will be the higher labour costs that these entities are subject to. In fact, Section 69 of the Ontario Labour Rights Act states that if consolidation were to occur and be viewed as a sale of businesses, the new entity is bound by the higher cost collective bargaining agreements (CBAs) of existing trade unions of either business In the merging of assets. For example, Rg. 11 below demonstrates the up to 31% difference ($30.58 vs. $40.26) between the Small LDC hourly labour cost and the Extra-Large LDC hourly labour cost per power line maintenance worker. It is therefore beyond the control of merging utilities to limited labour cost Increases and would be driven by labour laws more than strategic or sound business decision making. 16 2005-2011 Yearbooks of Electricity Distributors, Ontario Energy Board. 2012. September 12,2013 Page 115 () ................................................................... aa .. ~.g.rou_.oo .. P.ape._r ........ ~r--) add111on, careful strategic investments in Innovation are being made where it makes sense for the customer. Large LDCs are not the only leaders in innovation. A straightforward example of the ability of smaller LDCs with respect to innovation is the recent smart meter rollout, where all of the Province's LDCs were required to Install smart meters and begin charging customers time-of-use rates. Just like the authors of the DSRP stated, pundits at the time claimed that the Small and Medium LDCs would not be able to complete the roll out on budget and that the leverage of the systems would be poor. At the time, the same sector followers used their theory as further support for the argument to consolidate the sector. Ironically, no one was questioning the ability of the Large LDCs to complete the task and we now know various shortcomings have been evident. In the end, the Small and Medium LDCs took the natural step of working together (28 of them joined London Hydro to purchase smart meters as a collective) and at the time of this report's release, all of their customers are being charged time-of-use rates. One LDC even enhanced the network development and innovation by working together with the local municipality to install a town-wide wireless network in concert with smart meters. In contrast, multiple Large and Extra Large LDCs required substantial project extensions and were unable to charge all of their customers time-of-use rates within the province's mandated timeframes. Strengths of the Report It is important to recognize that the DSRP and the process undertaken to develop the report, included some clear strengths, important intentions and made a number of sound recommendations. The emphasis on putting the customer first is a value held by all of Ontario's Small and Medium LDCs. We encourage this concept as being central to future decision making and believe It will have a positive impact on both policy and planning outcomes. Community-based LDCs have always made decisions and implemented strategies that enhance results for the customer; they will continue to do so as the baseline for doing business in their communities. The advantages of contiguous LDCs is well articulated in the report, particularly with regards to the duplication that comes from Hydro One's operations centres existing within another LDC's service territory. Putting the puzzle pieces together, creating holistic service territories and eliminating the duplication will cause direct benefits for the municipal LDC's and Hydro One's ratepayers. To paraphrase the authors, fewer boundaries will mean better planning and utilization of assets. Allowing and/or incenting mechanisms that move Hydro One assets and customers over to municipal utilities, where it ultimately benefits the customer, will result in larger customer bases and have immediate and positive rate impacts as municipal utility rates are adopted by fanner Hydro One customers. The larger fragmented utility will also be able to focus on serving Its rural territories without addressing problems in pockets of service territory nested within areas already serviced by municipal utiDties. The discussion of the LDC of the future and th~ new world of electricity Is also one of the strengths of the DSRP. Considerable change is occurring in the sector as a result of the ongoing innovations in communications technology and shifting of customer behaviour. The authors are astute to recognize that some LDCs find it hard to be innovative in the current regulatory environment -specifically pointing to an OEB decision to prevent Guelph Hydro from recovering the costs of a plot program for electric vehicles. "The expectations and requirements of the LDCs and the OEB need to be aligned if innovation is to be encouraged in Ontario's distribution sector." Therefore, public policy and consumer behavior must drive the needs of utilities to develop and innovate. If the customer need Is present, the regulator will be better equipped to approve investments that support a customer or societal demand. The demand must be clear and the regulatory policy must be aligned With the specific goals to further encourage the innovative requirements of future generations and technologies. September 12, 2013 Page 117 (__) r ) \_ J .............................................................. aa.c.k.gro .. uoo .. h .. ~--------~-) Figure 12: Components of a Typical Residential Electricity Bill ·~l·~~iff-~me~, ·-tJliU )li:~~.j:~t~!)i:~ll.,~-~~ m~~~t,~-~r~ II :t:liait~fiilia'@ll ii!J!!~~i,i'~f!#tO~;!I'j~sP.·~~ L,I:!C' • Baaed an a monthly canaumptlon araoo kWh reflecting prices as a! February 2013 lara reprasentatlve uliliy oustomor As an industry, Small and Medium-sized LDCs can accept that they must be part of the solution, and continue to evolve for the benefit of Ontario ratepayers. We believe we are acting on these objectives and continually strive for improvement and innovation. As noted above, Ontario has always experienced real price Increases. Drivers of growth have been fairly evenly distributed between generation, transmission and distribution costs22• Although each element has grown at similar rates, the overall proportion of generation related costs indicates that more opportunities for ratepayer savings can be harvested with focus on the commodity supply and market design {51%), taxation {12%}, debt retirement (5%) and potentially regulatory (6%). It therefore seems logical to place as much, or more, emphasis and oversight on other aspects of the electricity system, particularly supply, where greater efficiencies, productivity, savings and ultimately value, can be captured. The DSRP Itself, states that the "province's distribution sector has been able to avoid a fot of attention from consumers because local distribution costs encompass a small proportion of a typical electricity bilf'. Although the comment on proportion Is true, the notion of lack of attention is not. The diverse nature of the LDC sector and the local connection is exactly why consumer interaction occurs at a local level. LDCs garner significant attention within the communities that they serve. Secondly, as far back as 1996, the Macdonald Committee released A Framework for Competttfon, a report on the electricity sector in which substantial evaluation of the distribution sector was carried out and recommended upon. The Macdonald Report, similar to the current DSRP, recommended a series of consolidations within the sector to result in shoulder-to-shoulder utilities. Although many municipal electric utilities of the day were subsequently merged with Hydro One and others, no mandatory consolidations were legislated. Furthermore, the results achieved by Hydro One and its merged LDCs are far from clear or encouraging. From a savings-to-customers point of view, Hydro One has provided little upside for the customers they have acquired. Hydro One urban customers pay significantly higher rates than neighbouring customers served by the locallDC. In many cases these neighbouring customers are literally across the street, yet they can pay up to 25% more for the distribution service. This is an extreme example of a system that does not support the best decisions for customers, yet Is easily rectifiable. 22 1bid. September 12,2013 Page 119 () ................................................................ Ba .. ck•g•ro•u•oo--~.~.......... ("~ in competitiveness of Ontario's electricity sector. The growth spurts can be seen in Figs. 14 and 15 and are often related to policy activity or Investment choices. These factors will be accounted for in following sections. Fig. 14 below demonstrates the natural productivity of energy use in the economy; this is a key observation because the natural decline In electricity consumption per unit of economic activity actually mutes the degree to which price Increases, driven by supply, impact our bills. Put another way, we are getting much better at using electricity as an economy. Therefore, even though the supply portion of the overall price for electricity is by far the largest and growth rates for each portion of the bnl have been comparable, growth In generation costs are counteracted by natural productivity. The counteractive effect leads to slower growth in absolute resources spent on our electricity supply as we use less overall. This Is troubling because it also means we are leaking away the energy efficiency gaits we create. It should be noted that the productivity argument bears more strongly on the electricity supply that it does on distribution. Electricity supply tends to be more heavily weighted toward variable costs, which are of course impacted more strongly by consumption levels, while distribution costs are typically more fixed In nature. It is clear that attention should be focused on the root causes of the price growth spurts that have occurred over time, and these are nearly always associated with supply-side policy and changes to the market structure and commodity pricing environment. Figure 14: Generation Cost Increase vs. Electricity Productivity 199P 1995. ~ ~1 ,~OP~' 2~0 ~ 20QS 200.6 2Q07 •ilOOI{ 2{)09 ZOUI ~(i.ll --LeveiitoiiEiectrlcitvio~•fiHil!'ili~ g~'o~} -~·&en.niiGnc...fGrawtlt·j·/IIWi\! Figure 14 demonslrates that the amount of electricity consumed per unit of economic output (GOP) has declined since 1990 by over 40%. At the same lime, consumer eleCtricity bills have been Increasing. A 70% rise in generation costs is a main driver. Through the mid 1970s and again in the early 1990s, capital costs and overruns from building out the province's backbone nuclear generation fleet led to large increases in average electricity prices as they were rolled into consumer pricing and Into the approximately $20.9 billion In stranded debt ofthe former Ontario Hydro, an expense ratepayers continue to absorb25• By the time the industry began restructuring In 1998, costs of supply were again on the rise. At market opening in 2002, acute price Increases and volatility led to a set of policy measures enacted to manage impacts on customer bills and provide subsequent relief from high growth. Key to the story is that Ontario's electricity system has always been influenced by significant policy Intervention and debate. The spinoff consequences of these interventions led to artificially-depressed prices, hiding the true costs of electricity, discouraging ongoing investment in the province's system by the private sector and increasing the debt levels that inevitably must be paid down by future consumers (either ratepayers or taxpayers). These factors eventually have compounding 25 Ontario Auditor General, "2011 Annual Report of the Office of the Auditor General of Ontario," 2011, p, 122 September 12, 2013 Page 121 () i !... ... _ \ ) ........................................................... BK* ... ~ ... oo.~ .. ~.r------~(~ efficiency of the electricity system, and allowing utilities to recover the associated costs of system improvements would allow customers across the province to save. This section has discussed a number of supply cost increases largely driven by legacy policy interventions. It is too late to rectify past decision-making; however, as we look to the future we believe it is in the interest of the province and Its consumers that the collective knowledge, experience and intellect of the industry, and its oversight agencies, focus efforts on the following: 1. Through the Long-term Energy Planning process, enhance the precision of supply recommendations and take all reasonable actions to reduce risk In the Province's generation system planning. 2. Leveraging the work of the Global Adjustment (GA) and HOEP Reviews, ensure the future of the wholesale electricity market sends appropriate pricing signals to make operational and investment decisions, while gradually removing the barriers caused by the GA. 3. Implement regional planning and institute infrastructure zoning principals to avoid future project cancellations. 4. Investment in new equipment and technology to reduce line losses, and allowances for utilities to recover these costs. Components of the Global Adjustment Mechanism Since 2005, the long-term Impacts of policy interventions and new supply arrangements with the province have materialized as part of the Global Adjustment (GA) mechanism on customer bills. The GA is a catch- all customer cost category outside the control of the LDC sector and largely reflects the costs of provincially contracted generation and Its distortion to the supply market. Today, the GA represents the greatest portion of the total real costs to supply the grid with electricity (greater that the amount supplied in the marketplace), diminishing the economic principles on which the wholesale-power market was designed. Ag. 16 below demonstrates the growth in GA costs and their impact on the total cost of supply for consumers. In the past four years, the average annual GA cost increase has been 32%. These cost increases are particularly worrisome, given broader market signals that would indicate commodity prices should be declining, as a result of the sustained depression of demand In Ontario and historically low North American natural gas prices, which tend to drive marginal electricity prices. September 12, 2013 Page 123 r·---~.) I I .I 1 ) Background Paper ,--"\ ------------------------------------------( ) Figure 17: Global Adjustment Components29 OH> U!:~C i::,~;:~~~~~~~;~;f,:~t~ ,· .. :~~~~_,G,~~ ~ ~-~:~ -. -. y ~ .:·· OPG'f;. COal-"reB Gs5 . ~" ' '!o '> ~ ;.,.-,;v~'~-:-:-::. = ' Carrying forward from the GA Review process (IESO SE-1 06), we propose striving towards adoption of the second recommendation of the 2011 Electricity Mar1c:et Forum and reconnect supply and demand through tighter integration of the supply mix and commodity pricing. Following the key guiding principles of the GA Review, considering administrative complexity, fairness and equality of GA allocation and impacts on market efficiency, adopt restructuring options for the GA and market rules to more appropriately recover costs of supply. Streamlining the Regulatory Process To date, the regulatory cost burden for the distribution sector has been significant. The OEB's foced costs typically represent over $32 million annually to ratepayers, while compliance requirements for utilities lead to substantial variable cost burdens of filing cost of service applications and responding to intervenors. We believe the RRFE will assist in streamlining the process for LDCs of all sizes. We propose to continue working closely with the Board and the Ministry to find further efficiencies in similar spirit of the RRFE. Similarly, we suggest that costs of intervenors could be substantially reduced wHh the appropriate controls and screening to reduce the costs associated with their involvement in ratemaklng. The intervenor process is an important one to ensure fairness of investment and equity of rates; however, a streamlined process that allows for more precise articulation of noteworthy input requires greater oversight and better screening of participants. Those selected should provide only the greatest value to the ratepayer, while transparently and concisely providing input to the Board. Streamlining and Enhancing the Transparency of Provincial Agencies Currently, the OEB regulates the costs and operations of Ontario's LDCs, In addition to nearly every other aspect of the electricity system, including planning (OPA), the Implementation of govemment energy policy (Ministry of Energy), large aspects of generaUon (OPG, non-UtiHty generators, OPA) and transmission (IESO) of electrlcHy. According to many of Ontario's LDCs, this process has potentially created disincentiVes tor innovation and investment in key infrastructure, and has resulted in increased costs for the end consumer, when It was meant to control or even decrease costs. 30 While the regulatory 29 Navlgant ConsuHing Ltd. Global Adjustment Review Part 1: Options Identification. 2013 30 "The Power to Deliver: A Six Point Plan for the Future of Electricity Distribution In Ontario", Electricity Distributors Association. 2012. September 12, 2013 Page 125 (_) ) --------------------------------Ba-ck•g•ro•u•nc:1-Pa•pe-r----.:(-J of the same LOG for the same customer as Analysis A with the proposed cost savings from consolidation, as projected by the DSRP. This comparison is for illustrative purposes only, as we strongly doubt that the 15% OM&A savings from consolidation projected in the DSRP is achievable In the majority of cases. Ultimately, the purpose of Fig. 19 Is to identify that repositioning retailers In the Ontario electricity market can be optimized to achieve greater cost savings to the customer than consolidation. A discussion of the proposed recommendations in relation to repositioning electricity retailers in Ontario follows the analysis of Fig. 19 below. Figure 19: Average Size LDC vs. Retailer Cost Comparison Alii~ a · Coml!l!d!gn !l!: LDC!!! 1!1!!11![ I CUstomer Lives in Same Location Average Size LDC in ontario Retailer Dlff!$1 Dlff!"l Electricity Charges $ 69.67 $ 132.33 $ 62.66 90% Delivery Charges $ 40.85 $ 40.85 $ 0% Regulatory Charges $ 4.90 $ 4.65 -$ 0.25 -5% Debt Retirement Charge $ 5.60 $ 5.60 $ 096 subtotal of Monthly Electricity 111 $ 121.02 $ 183.43 $ 62.41 52% Add: HST (1396) $ 15.73 $ 23.85 $ 8.11 52% Total of Monthly Electricity Bill $ 136.75 $ 207.28 $ 70.52 5296 Less: Ontario Clean Energy Benefit (1096 off) $ (13.68) $ (20.73! ·$ 7.05 52% Final Monthlv Electrldty 8111 $ 123.08 $ 186.55 $ 63.47 52% Average Size lOC In Ontario· After Averap Size !DC In ConsoRdatlon and OM&A AnaiWJ!!I B • Coml!!!~n gf Unconsolidated Ontario -CUrrent Cost smncs o1 15" vs. Consoldated LDC Landscape Realized Dlff!$1 Dlff ("I Electricity Charges $ 69.67 $ 69.67 $ 0% Delivery Charges $ 40.85 $ 34.72 -$ 6.13 -15% Regulatory Charges $ 4.90 $ 4.90 $ 0% Debt Retirement Charge $ 5.60 $ 5.60 $ 0% Subtotal of Monthly Electricity Bll $ 121.02 $ 114.89 ·$ 6.13 ·5% Add: HST (13%) $ 15.73 $ 14.94 -$ 0.80 -5% Total of Monthly Electrlc:ltv Bill $ 136.75 $ 129.83 -$ 6.92 ·5% Less: Omarlo Clean Energy Benefit (10'!6 off) $ (13.68) $ (12.98) $ 0.69 ·5% Final Monthly Electricity Bll $ 123.08 $ 116.85 ·$ 6.23 ·5% In Analysis A, the comparison is performed between an average size local LDC and a comparable retailer by customer number, for a household In a given location in Ontario. The analysis shows that the customer pays approximately 52% more on their monthly electricHy bills under contract with a Retailer than a customer with the same usage habits in the same town. In Analysis B, the comparison is performed to assess the impact of a 15% OM&A cost savings passed down to the customer as a resuH of consolidation. The cost savings for consolidation has been performed September 12, 2013 Page 127 (') ,, -··,.. ) --------------------------------Ba-ck•gro-u.nd-Pa•per-----:t~J perfonnlng their own billing and collections functions; the LOG Is responsible for this function. As a result, the LDC spends a significant amount of time and money on billings, collections and ultimately, writing off bad debts associated with unpaid retailer customer bills. If it is believed that there remains a place for Electricity Retailers In the marketplace, it is recommended that the retailers perform their own billing and collections functions, which would reduce the OM&A costs to the LDC and require the retailers to focus on signing electricity contracts with creditworthy customers. In the event that retaH customers default on their bills, it should be the responsibility of the retailer to perform the collections and corresponding bad debt wrlte-offs for defunct customer accounts, not the LOG. The recommendations noted above create real cost savings for the LOG. These savings should not be disregarded as they can benefit customers immediately, rather than over the 10 year period of the recommended consolidation plan as identified in the DSRP report. We believe that If retailers are required to include the global adjustment In their prices and perform their own billing and collection functions, the LDCs Will save a greater percentage of OM&A costs on an annual basis, when compared to consolidation, without incurring any of the transition and transactlon costs and while still maintaining the advantages of the local utility for the customer. WHERE CONTROL EXISTS FOR LDCS Wrthin the 20% of the electricity bill that can be attributed to the distribution sector, focusing on the following areas could yield improvements to service levels while maintaining or reducing costs to the end consumer: 1. Allow LOGs to Increase the scope of their operations. 2. Broaden the use of shared services between LOGs to find cost efficiencies. 3. Streamline the OEB Intervenor process. 4. Voluntary consolidation of neighbouring LDCs, beginning with relevant absorption of Hydro One assets. Allow LDCs to Increase the Scope of their Operations In the not-so-distant past, a number of electricity distributors operated as public utility commissions, which provided multiple services-such as water and street lighting. As part of the move towards a competitive electricity market In the 1990s, the delivery of electricity was separated from other services. While it made sense at the time, this deregulated model has been largely abandoned and new themes dominate the Industry. Wrth increasing amounts of new technology and many new services available, new possibilities for economies of scope have emerged. 37 Many municipalities continue to operate the water utility as a distinct entity from the electric utility, despite owning both. While some of the efficiencies that could be captured are being achieved through shared services like combined billing, there are additional efficiencies that could be captured through horizontal consolidation at the local level. Savings will accrue for customers on the water and power side as a result of having a single, combined database and IT system, the potential to eliminate redundancies in administration, operations and customer service, and through Integrated management and planning for capital projects. If there Is appeal in consolidating electric utilities to capture cost-side savings, why would there not be appeal in consolidating across utilities to more effectively use resources and the customer relationship? As a result 37 1bid. September 12, 2013 Page J29 (_) --------------------------------Ba-ckg-ro•u•nd-Pa•per------:() Further exploration Is needed by the Individual players in the market regarding what services in particular could be shared at a more centralized level, in order to reduce OM&A costs while still maintaining current service standards. Several utilities are working towards formalizing Initiatives that will produce clear and Immediately quantifiable savings. It is evident from both historical evidence and academic literature that there are distinct benefits that can be captured through co-operation that do not require consolidation on a larger scale, as suggested by the DSRP. Through the use of co-operatives and buying groups, among other creative solutions, efficiencies could be realized without incurring significant transaction and transition costs. Streamline the OEB Intervenor Process As part of the current rate filing process with the OEB, Intervenors are interested groups or individuals who participate actively by submitting evidence, arguments or Interrogatories (written questions) or by cross--examining a witness or witnesses at an oral hearing. Intervenors are free to participate and submit arguments that question and often reMe the utility's cost projections and general outlook, thereby making a case for lower rates or smaller rate increases than applied for by the LDC. Intervenors ma}t Include customers and other affected individuals, consumer and trade associations, environmental and regional interest groups, and other public interest groups.39 We propose that this process be streamlined to reduce the amount of time needed to review and approve each rate filing, and therefore the cost of the entire process for the utility, the OEB and ultimately, ratepayers. Enhancement of the Intervenor approvals process would Increase regulatory effectiveness and efficiency. Using best practice, the OEB could use a scorecard system and set of Indicators to ensure the appropriateness and avoidance of intervenor costs. This process may be further enhanced for smaller LDC hearings, where community focus is already heightened. Both Direct and indirect interrogatory costs per customer must be fair and necessary to be value added to the customer. Currently, the eligibility requirements for becoming an Intervenor eligible to recover costs are not overiy onerous. Essentially, any individual or organization outside of the government (municipal, provincial or federal) and companies operating in the sector can act as an Intervenor (and recover the associated costs}, if they can show they represent ratepayers, the public interest or are an affected landowner. This, as you might expect, represents quite a large group of individuals and organizations. Correspondingly, we recommend the following: • streamlining the regulatory requirements of the OEB and right-sizing them to the size of the LDCs on a case by case basis, which will help limit the need for Intervenors. • Putting in place a stronger screening process to ensure Intervenors are bringing value to the hearings, and not just using them as a lobbying platform. This could Include an Intervenor checldlst and a set of evaluation criteria to pre-qualify the matter each could intervene on, and eliminate those who should not have Intervenor status. • Implementing a system of criteria that defines the amount of time Intervenors have to debate, based on the size and/or complexity of the case and Its reach in terms of impact. • Intervenors identify the people they represent and demonstrate that those people acknowledge and approve their representation.40 By raising the eligibility standard for cost recovery of what is 'in the public's Interest', a portion of the approximately $4 million that's spent each year on Intervenors, In addition to the time spent by the OEB 39 "Participating In a Hearing" Ontario Energy Boalfl. Date published: 2012-0B-07. Date accessed: 2013-06-20. <http:/lwww.ontarloenergyboard.ca/OEB/lndustry/Regulatory+Proceedings/Hearlngs/Partlclpatlng+ln+a+Hearlng> ~0 'The Power to Deliver: A Six Point Plan for the Future of Electricity Distribution In Ontario", Electricity Distributors Association. 2012. September 12, 2013 Page 131 () Background Paper /-\ ----------------------------~ ... ) utilities that seek the benefits of scaling up certain activities while working together to further the growth of the sector. Another even broader example of collaboration Includes the utilities Standards Forum (USF). USF represents the combined efforts of 50 utilities of all sizes and services members with approximately 2 million customers. While these collaborations provide real services to their membership, a key benefit of the relationship is the knOWledge sharing that occurs on an ongoing basis and formally at periodic meetings and functions. Members pay annual dues and usage fees to cover the cost of running the collaboration, and benefit from reduced costs for services and equipment and from the Increased awareness of the latest Industry developments and sharing of best practices among peers facing similar challenges. Looking south of the border also offers some good examples of how Ontario's Small and Medium LDCs could benefit from collaboration without consolidation -the National Rural Electric Co-operative Association (NRECA). NRECA represents over 900 rural electric co-operatives (mainly distributors) and provides members with industry research, political advocacy and lobbying, education and training, management consulting, pension plan administration, executive search, management of the national co- op brand (Touchstone Energy}, development and administration of youth trades and international development programs, and the publishing of an Industry magazine. All of this is done for the benefit of the members, who do not necessarily need to build these skills and capacities internally. Local value is maintained, while the shared benefits of scaled operations are captured for ratepayers and shareholders. Keys to success lie in the collective trust of the group and their shared values. Each member is committed to collaboration as a way of growing their bottom line and their local impact. While consolidating would formally bring organizations together, the benefits to the bottom line and/or the local community are not proven-often the value allocated to the lawyers and advisors that help to consummate the deal (projected, together With transition costs, to be $500 million over 10 years by the DSRP) is greater than the benefits that shareholders and/or ratepayers will gain collectively. September 12, 2013 Page 133 () \.··~ ... ~ . c_J --------------------------------Ba-ck•g•ro•u•nd_Pa_pe_r _____ --J stronger connection between the local LDC and the community in which it operates. This translates to a more significant consideration of the impacts of decisions made at the utility-level on the local community. Local Jobs and Economic Activity Smaller communities benefit more significantly from the jobs created and maintained by their local LDC compared to larger, more widespread LDCs. For example, Algoma Power Inc. has a total of62 full time employees serving a total population of 16,78942• The percentage of the total population employed by Algoma Power Is 0.36%. Toronto Hydro has a total of 1,740 full time employees serving a total population of 2.5 mlllion43• The percentage of the total population employed by Toronto Hydro is 0.070AI. Algoma Power on a per capita basis therefore creates five times as many jobs for the population it serves. In creating and maintaining a higher percentage of local jobs, the community's economic activity Is stimulated through Increased local spending. Community Involvement in Long*terrn Regional Energy Planning Local LDC decision makers are not only hearing first-hand what their customers and their communities have to say about the future ofthe electricity sector in Ontario; decision makers are taking these real messages from their customers Into consideration in determining the future direction ofthe utility. In addition, the local LDCs are representing their communities when discussing the long-term energy plans with the OEB. This approach is becoming more and more important to the future of the entire energy sector, evidenced by the Minister of Energy's May 30th, 2013 announcement indicating the adaptation of poliCies to better Include the meet the needs of communities. Energy planners and developers are to work directly with municipalities to Identify appropriate actions and locations for development. As discussed previously, the local community is a keyfocusforthe LDCs. The voice of the community Will contribute not only to existing energy issues, but also with long-term planning with regulators and policymakers. 422011 Yearbook of Electricity Distributors, Ontario Energy Board. 2012. <131bld, September 12, 2013 Page 135 (~) ( _ _) ................................................................ Ba .. ck.~ ... oo .. Pa.~ ........ ~~-) a single, combined billing system, elimination of redundancies In administration, operations and customer service, integrated capital management and an improved customer experience in their interactions with the utilities. In 1this sense, we believe the Mlnistl)' and the OEB should focus their regulate!)' efforts on reducing the 8'0% of costs outside of the LDC's control to create more significant cost savings for customers in the long-term. Secondly, we recommend that the OEB streamlines the intervenor process to achieve cost savings associated With the current intervenor costs incurred by the utilities. In order to achieve these cost savings, there needs to be a reduction in the amount oftime required for each rate filing. Our recommendation includes the following aspects: (1) streamline the regulatory requirements by th'e OEB and adapt these requirements on a case-by-case basis depending on the size of the utility; (2) Implement a stronger screening process for intervenors to ensure they are bringing value to the hearings; and (3) Implement a system of criteria that limits the amount of time spent on Intervenors during hearings. Thirdly, we recommend streamlining and enhancing the transparency of provincial agencies. This Includes taking a closer look at the regulatory costs borne by the Ontario utilities (and ultimately passed down to the customers on their monthly electricity bills) to consider where cost savings could be achieved through the elimination of redundancies in regulatory activities performed across the various provincial agencies. Rnally, we recommend considering the repositioning of retailers in the Ontario electricity sector to achieve significant cost savings for all customers. As noted in Fig. 19, the monthly electricity bills of customers in contracts with electricity retailers are between 35% to 65% higher than the monthly electricity bills of customers subject to time-of-use pricing with their utilities. It is recommended that retailers are required by the OEB to include the global adjustment In their contract prices to show customers the true cost of their monthly electricity. In addition, It is recommended that retailers perform their own billing and collections functions, Which reduces the costs of bad debts currently absorbed by the LDCs. In implementing these two recommendations to reposition retailers, significant cost savings can be achieved for the LDCs. These savings will be passed onto the customer in the form of reduce OM&A costs at the LDC level. Voluntary Consolidation and Collaboration, Where Clear Benefits and a Strong Business Case Exists, Including Amalgamation of Hydro One Distribution Assets There is no clearly definable and uniform minimum customer base that creates the opUmal situation for net benefits to the customer. Each LDC in Ontario faces a set of unique circumstances, including opportunities and challenges relative to their geographical location, the population being served and the overall regulatory framework. As With all businesses, there are situations where logical synergies exist and there are others where none can be found. Correspondingly, we do not agree with the widespread consolidation recommendation of the DSRP; however, we recognize and believe in many of the DSRP's underlying principles regarding mergers including putting the customer first, the need for shoulder-to- shoulder, whole boundaries in Ontario, the need for increased efficiencies and the need for removal of blockades preventing mergers and acquisitions when they make good business sense for the province. As such, we recommend encouraging voluntary mergers in order to move toward creating shoulder-to- shoulder utiHties across Ontario, but only where good business cases can be made. In this sense, we mean that mergers and acquisitions should only be pursued if there are real efficiency gains to be realized that would ultimately benefit the customer and the shareholders. This includes merging the pockets of Hydro One customers with the local LDCs that currently serve surrounding terrttory. We September 12, 2013 Page 137 C) Background Paper APPENDIX A: SURVEY OF KEY SECTOR ISSUES AND ACTIONS THAT WILL DIRECTLY BENEFIT CUSTOMERS Participation 72%-R..,_.Rtle ---------------------------------------- . . ' '1•'· Where Should the Province. Focus for Real Savings Cont'ct ..... Top 5 Action ltenis 1. ~0!/lh~ 2' _._.I!SO,CI'A,OI!! 4. -~~lriduiby frompolbii.Jl(lleleU&. hllo-liami1or.tioty I. DNnsatttlb'EB .6. ChaDtn;alheG~IAdjus~~nent ----------------------------·------------. :.~ ------------- Our Benefits to the Cornmu.,~ we ~. Serve Whatlsthevalu•addltlonoflllelocal LDC? 1. HlgharfaVatt3fHRolcaand --2. ~aa;&taPdlidai~n 3. ==:nr~ly &mono~ 4. Lqca!J;IIInt.n~e.c;a.,_~ a. ~motv:aman~n .llm81tml .......... _ -·------. ------------------------- • 1 1 •r~ Where Should the Province Focus for ~eal Savings TheAa:ordliellaYMihat80% of the Ill OUt!lldA LDC Contrcills !'lkirtlm~ · ·· · · · · • l. -~Moo:hlllillm 2. Co-""Pi>!Yendrull!al ~~~-s. 1\oi!~!o!YCosto 4. TooMon)'F!IO~•- -------. --------------------' -'• . What Can The Accord Do? 20%~the.CustomerBIIIIslnColttroloftheLDe,WhereShouldWe Focus: •t;;..t-=.=t.~--Si=="-" -------~--. ~ September 12, 2013 Page 139 (-) CJ ('"') . \.··~- ) I .. ) \. __ j Preface Ontario has developed a prosperous and diversified economy over the past century. This has permitted the province to enjoy a high :standard of living combined with quality health care, education and other public services. This would not have been possible without efficient and cost-effective infrastructure, ranging from roads and transit systems to the provision of electricity. Investment in cost-effective infrastructure also improves Ontario's competitiveness with other jurisdictions in North America and around the world. In its most recent annual report, the Ontario government's Task Force on Competitiveness, Productivity and Economic Progress said Ontario has great strengths economically and has achieved solid economic results. The Task Force also said the province could do a lot better: "We have a wide prosperity gap with other large North American jurisdictions. The source of this gap is our inability to be as innovative as we could be in our economic fife. 111 Electricity is a critical building block not just of Ontario's standard of living, but also of its ability to compete economically. In a highly competitive world, it is vital that electricity be delivered in the most efficient and cost-effective manner. That is why the Ontario government appointed the Ontario Distribution Sector Review Panel (Panel) to review the province's local distribution companies (LDCs2). In order to ensure that Ontario's LDCs deliver power at the lowest possible cost and contribute to a strong economic future, the government3 asked the Panel to look at whether a restructured distribution system could lead to price stability, a more efficient and reliable system configuration, as well as fairness and value for money. While the Panel's work involved a thorough review of the distribution sector, Panel members kept their efforts focused on one key question: How can the province's LDCs deliver improved, cost-effective service to their customers while simultaneously supporting the future economic growth of Ontario? Panel members recognized that their key responsibility was not to rearrange the pieces to deal with the issues of today, but to make sure the province's electricity distribution system puts its customers first, so that Ontario can prosper a decade from now and beyond. The Panel members heard from close to 85 stakeholders including LDCs, associations, consumer groups, unions, municipalities, government ministries and agencies, financial and investment organizations and individuals from across the province. The Panel found that most presenters and submitters agreed that significant change is required if all the province's LDCs are to adopt the technological innovations that will enhance the safety and reliability of the electricity system, reduce its operating cost, and enable a renewed focus on the customer. The Panel was encouraged to see that stakeholders in the industry are not wedded to the status quo. The Panel has also determined that Ontario's electricity distribution system will require significant additional resources if it is to replace aging equipment and provide new services. The current structure of electricity distribution is a barrier to this required investment and needs to be changed. Ontario's distribution system got started when community and business leaders realized in the early 1900's that the economic well-being of their towns and cities depended on having electricity readily available at an affordable cost. The province faces a similar challenge today. In order to ensure the . future well-being of Ontarians, the electricity distribution system must be able to adapt to the coming j technological and economic challenges. This is the most significant test the distribution system has faced in one hundred years. Failure to meet the challenge will mean a diminished future for the people of Ontario. 1 Task Force on Competitiveness, Productivity and Economic Progress. "Prospects for Ontario's Prosperity," November 2011, p. 4. ' Industry jargon provides a wealth of synonyms for a local distribution company (LDC): distributor, local or electricity distributor, utility, local utility, distribution company and so on. Though there has been an attempt to limit the number of times this occurs, please treat any such uses as mmpletely interchangeable. 1 In this report, unless otherwise spedfied, references to 'government' and 'province' are taken to mean the Government of Ontario and the province of Ontario respectively. -Keml P1111wtr Dhtribullon C•mpmJ LfmltH iSChlpl .. u~ll.c UtllitinCarp. Chapter 1 The Imperfect World -How We Got Here Ontario's electricity distribution system is a product of its history. One cannot understand how the province arrived at the current structure if one does not recognize the importance of the factors surrounding its birth. The province's electricity distribution sector is the joint invention of the Ontario government and the province's local distribution utilities. It was created in the early 1900's under pressure from business leaders and politicians in Toronto, Kitchener, London and other communities who understood that their communities needed an affordable supply of electricity in order to prosper.4 The towns and cities in Ontario at the beginning of the 1900's also knew they needed an assured supply of this new source of energy. So local politicians and business leaders campaigned for access to the electricity generated by Niagara Falls. The pressure grew to such an extent that in 1906 the Ontario government created the Hydro-Electric Power Corporation (HEPC) to transmit power from the Falls.5 HEPC and its successor Ontario Hydro established the generation and transmission facilities that supplied electricity to generations of Ontarians. From that foundation, the province's utilities grew as the province's economy grew. At one point in 1923, Ontario had 393 different utilities supplying electricity to customers.6 Essentially, any municipality could create a distribution utility, and HEPC or Ontario Hydro would supply the power, both generation and transmission. This was basically the state of affairs until1996, when a provincially appointed committee led by the Hon. DonaldS. Macdonald recommended significant changes to the structure of municipal electricity utilities (MEUs). The Macdonald Committee7 recommended that Ontario's 307 remaining MEUs be merged with the distribution systems then operated by Ontario Hydro to create shoulder-to-shoulder distribution utilities along regional and county lines. A shoulder-to-shoulder distribution system would have resulted in a smaller number of utilities with contiguous boundaries, and no distributors embedded inside another distributor's territory. The 1996 report, ':4 Framework for Competition," also proposed that Ontario Hydro be broken up into separate generation and transmission companies. 8 Two-and-a-half years later, the Ontario legislature passed the Energy Competition Act (ECA), putting into place a number of the recommendations of the Macdonald Committee. The ECA created a new company for generating electricity {Ontario Power Generation) and another to take over Ontario Hydro's transmission and distribution assets (Hydro One Inc.). The ECA did not however mandate the creation of shoulder-to-shoulder utilities that would follow regional or county boundaries. While the ECA did confirm that municipal governments owned the electricity utilities, it required that they be transformed into business corporations under the Ontario Business Corporations Act (OBCA), a departure from the past when local commissions were the norm. • N.B. Freeman, "The Politics of Power: Ontario Hydro and its Government, 1906·1995, 1996," Universrry ofloronto Press. p. 10-13. ' Ibid., p. 31. • "Sir Adam Beck," Dictional)' of Canadian Biography Online. Accessed October 2012. See: http:/fbiographi.ca/009004-119.01·e.php?id_nbr=7790 7 Formally referred to as the Advisory Committee on Competition in Ontario's Electricity System. 8 Advisory Committee on Competition In Ontario's Electricity System, "A Framework for Competition: The Report of the Advisory Committee on Competition in Ontario's Electricity System to the Ontario Minister of Environment and Energy," May 1996. See Summal)' of Recommendations. • The median-sized LDC in Ontario has 19,885 customers. • The average-sized LDC has 65,394 customers. The fact that the median is so far below the average shows that there is a preponderance of small LDCs in Ontario. Hydro One Inc. put it this way in its submission: "When compared against other Canadian jurisdictions, Ontario has almost twice as many LDCs ... as all of the remaining provinces combined."14 1,400,000 1,100,000 1,000,000 5 J 8011,000 600,000 400,000 200,000 • • • o o I I Llll 11111111111111111111 Figure 2: Total Customers by LDC in 2011 Source: Based on 2011 Ontario Energy Board Yearbook of Electricity Distributors Data 14 Quoted from Hydro One Inc.'s official submission to the Panel. 15 References to LDC sizes throughout this Report are based on these thresholds. OWnership Variation also exists in the ownership of LDCs, but to a much lesser extent. Ontario's provincial and municipal governments own the vast majority of the province's distribution utilities. The Ontario government owns Hydro One Inc., which in tum owns three distribution utilities: Hydro One Networks, Hydro One Brampton, and Hydro One Remote Communities. Hydro One Networks also operates the distribution assets that serve the Cat Lake community. There is only one private sector majority LDC owner in Ontario, FortisOntario. FortisOntario owns 100% of three smaller utilities in different parts of the province: Algoma Power; Canadian Niagara Power, which serves customers in Port Colborne, Gananoque and Fort Erie; and Cornwall Electric. However, FortisOntario and two investment firms also hold minority interests in a number of other LDCs. FortisOntario owns 10% of Westario Power, which serves communities in Bruce, Grey and Huron counties, as well as 10% of Rideau St Lawrence Distribution and Grimsby Power. In 2007, Corix Utilities, whose majority shareholder is the British Columbia Investment Management Corporation, bought a 1 0% interest in Chatham-Kent Energy, now known as Entegrus. A number of pension plans have found electricity distributors to be very attractive investments, as the stable rates-of-return they earn from a regulated industry are ideal for their portfolio. In 2001, Borealis Infrastructure, the infrastructure investment arm of the Ontario Municipal Employees Retirement System (OMERS), bought a 10% stake in Enersource, which serves customers in MississaugaY Michael Nobrega, the President and CEO of OMERS, has said that the pension plan would like to increase its investment in Enersource, and invest in other larger utilities in the province, but the existing transfer tax imposes a financial penalty to do so.1&,l9 The rest of Ontario's LDCs are either wholly owned by one of the province's municipalities, or jointly owned by a number of municipalities. The municipal ownership of LDCs makes itself felt in a number of ways. Municipal councillors are often appointed to the Boards of the local utility and municipal governments frequently use the dividends they receive to help pay for municipal services and capital projects. How others Do It If Ontario was to set out to establish a new electricity distribution system from scratch, it is highly doubtful that it would choose to replicate the current structure. The arrangement of Ontario's distribution system cannot be found anywhere else in Canada. Many other provinces have only a single electricity distributor that is part of a vertically integrated utility handling both the transmission and the distribution of electricity. Figure 4: Electricity Distributor Sizes -International Comparisons 11 According to Borealis' website. Accessed November 2012. See: http:f/www.borealis.ca/eng_enersource.htm "A provincial tax of as much as 33% is payable when a munidpally-owned LDC transfers or sells assets to a private investor. When the Ontario government gave municipalities ownership of their ME Us. they were provided with a source of income and the potential to realize significant profits should they sell their utilities. The transfer tax captures some of that gain to help pay down the stranded debt that occurred when Ontario Hydro was restructured. 19 Quoted from OMERS' meeting with the Panel. The province's distribution sector has been able to avoid a lot of attention from consumers because local distribution costs encompass a smaller proportion of a typical electricity bill. The Panel believes however that there are efficiencies to be found that will ease future costs to consumers. Data show that there have been significant increases in the OM&A costs of the distribution sector. The OM&A expenses for utilities increased by more than 42% between 2005 and 2011. During the same time the number of customers served by LDCs saw an increase of just 7% and inflation was just 11.6%.21 Moreover, when compared to municipalities, LDCs' OM &A costs increased by 36% between 2005 and 2010, while the total operating costs of municipalities increased by just 26%.22 The increase in OM &A expenses was not spread evenly throughout the sector. When one looks closer at individual LDCs, it is clear that OM&A costs per customer are generally higher for smaller LDCs. As Fig. 6 and Fig. 7 shows, OM &A costs follow a general rule: the larger the LDC. the lower the OM &A costs per customer. 23 350 • Administration • Maintenance 300 • Operation 250 .. I 200 j l ... 150 100 50 0 SmaD Mnlum Larp Figure 6: OM&A Costs per Customer for Small, Medium and Large LDCs Source: Ontario Energy Board, 2011 Yearbook of Electricity Distributors Data 21 OM&A and customer analysis based on Ontario Energy Board Yearbook of Electricity Distributors from the years 2005 to 2011, inclusive, op. cit. Inflation analysis based on seasonally adjusted Total Consumer Price Index, taken from The Bank of Canada website. Accessed October 2012. See: http://WWIIII.bankofcanada.ca/rates/price-indexes/cpi/ 22 Municipal cost increases based on Provincial Multi-Year Financial Information Return Review. Accessed November 2012. See: http://csconramp.mah.gov.on.ca/fir/Welcome.htm "The OM&A costs of the two largest utilities in Ontario, Hydro One Networks and Toronto Hydro, are excluded from the charts in Fig. 6 and Fig. 7 because of their unique circumstances. Hydro One Networks has higher costs because its low overall customer density is spread out over a wide service area. Toronto Hydro also has unique cost pressures. tls aging assets have to serve a dense urban core that has the highest growth rate in multi-residential buildings in North America. charges in the standard operating and capital costs reported to the OEB, leading to understated OM&A totals, though they do ultimately pass these transformation and low voltage distribution costs on to their customers through a separate recovery mechanism. Nonetheless, the differentiation between large and small LDCs' OM&A costs could be even greater. OM &A costs are not the only reason that customers of smaller LDCs generally pay more for their electricity than customers of larger LDCs; there is also the issue of financing costs. Smaller LDCs usually have to pay more to raise money and attract investment. As Fig. 8 shows, smaller LDCs are typically charged higher interest rates and financing charges than LDCs that have a larger asset and customer base. Larger LDCs generally have access to a wider variety of capital markets, and benefit from the best terms and lowest debt costs. These lower financing costs are passed on to their customers. 8% 7% 6% • -= 5% .. t: f 4% Cll .... . E 3% 2% 1% 0 Extra Large LDC Large LDC Medium LDC Small LDC Figure 8: Average Financing Costs of Long-Term Debt by LDC Size This difference in financing costs will become only more significant in the future. Utilities will need billions of dollars in additional investment to transform themselves into modern LDCs that use up-to- date technology and offer higher levels of service to their customers. This investment will be more easily secured by larger LDCs. Currently, LDCs can turn to Infrastructure Ontario (10) for loans. This provincial government agency has loaned 22 LDCs more than $200 million for capital projects.24 1t charges LDCs between 3.2% and 3.3% for a 15-year loan. 25 There seems to be little public policy rationale for a government adding to its debt load for this purpose, when private financing is available. 24 Infrastructure Ontario • October 2012. 25 Infrastructure Ontario website. Acmsed November 2012. See: http:/lwww.inframuctureontario.cafTemplates/RateForm.aspx?ekfrm=2147483942&sector=ldc Approximately half of these service areas, including Guelph, Peterborough, Kingston, Amprior and Kapuskasing, have a Hydro One Networks operations centre as well as an operations centre for one or more LDCs within their boundaries. Regulatory Efficiency The OEB assumed responsibility for regulating the province's distribution utilities in 1998. One of its roles is to protect consumers by setting just and reasonable rates while providing reasonable financial returns for the industry. The OEB's operating budget for 2012/2013 is $34.97 million dollars.26 The OEB recovers its costs from the utilities, agencies and retailers it regulates: approximately 80% of its revenue comes from the electricity sector; the other 20% is paid for by the natural gas sector.27 The OEB's operating costs, which are ultimately born by the consumer, are higher than they need be because of the fragmented nature of Ontario's distribution sector. The large number of LDCs in Ontario requires more OEB resources to monitor their operations and adjudicate their rate applications than would · otherwise be the case. A review of the cost of regulation indicates that customers of small LDCs tend to pay more for the regulation of their utilities than customers of large LDCs. According to a 2011 report by Ontario's Auditor General, the cost of filing a full Cost of Service (COS) rate application for many small and mid-sized LDCs , ranges from $100,000 to $250,000.28 While the cost of filing a COS application for larger LDCs can be ; as much as $1 million or more, 29 the cost per customer is actually much lower because of their larger customer base. The Auditor General's report noted that the cost of regulatory scrutiny can consequently be as high as $40 per customer for smaller utilities, while it shrinks to about $1 per customer for the largest utilities.30 Workforce The province's distribution workforce is "greying/' and the wave of retirements expected over the coming decade threatens to cause a shortage of skilled labour in the province's LDCs. Ontario's LDCs employ a little over 10,200 people.31 In 2008, a study for The Electricity Sector Council of Canada estimated that about 45% of the electricity distributors' employees across Canada were between the ages of 45 and 54, putting many of them now, four years later, on the edge of retirement.32 According to this 2008 study the situation appears most critical for the highly skilled trades that are crucial to the safe and reliable operation of the electricity grid: 53% of power system operators across the electricity system were aged 45 to 54 years; 42% of power line workers were also in that age group; 74% of their managers and supervisors were 45 years of age or older.33 16 Ontario Energy Board, "2012·2015 Business Plan," August 2012, p. 24. Accessed October 2012. See: http://www.ontarioenergyboard.ca/OEBI_Documents/Corporate/OEB_Business_plan_2012-2015.pdf 17 Ontario Auditor General, "2011 Annual Report of the Office of the Auditor General of Ontario," 2011, p. 67. 1JI Ibid., p. 69. 19 Ibid., p. 76. 30 Ibid. " OEB-November 2012. 12 The Electricity Sector Council of Canada, "Powering up the Future: 2008 Labour Market Information Study," 2008, p. 57. 11 Ibid., p. 58-61. \ Chapter 2 The New World of Electricity Around the world, dramatic changes are occurring to the way people generate and use electricity. Electricity distributors are having to rethink how they do business in order to stay ahead of the curve. For decades, LDCs were relatively passive players in the electricity sector, delivering electricity that was generated elsewhere. They have been the brokers of a one--way flow of energy. The electricity would be produced at a central generation station using hydroelectric, coal, or nuclear energy, where it would then be transmitted, often over long distances, to local communities and then distributed to customers. Jurisdictions everywhere are changing how they generate electricity and how they use it. Instead of mega-projects, they are building smaller-scale distributed generation closer to where the energy will be consumed. In order to reduce the greenhouse gas (GHG) emissions that come from the use of carbon- based fuels, industrialized nations everywhere are turning their minds towards new uses for electricity, such as emission-free electric vehicles. Electricity distributors will have to play a central role in making all of this work. This promises to be a far more complex and sophisticated role than Ontario's LDCs are used to currently. At the same time, many countries are facing a second challenge: they have 'to replace the aging and outmoded infrastructure they use to distribute electricity. This cannot be done on a simple like-- for-like replacement. Electro-mechanical switches that were once the backbone of the transmission and distribution systems are going the way of the typewriter. The future for electricity distribution is computerized and data-driven. If this were the recording industry, it would be like jumping from LPs to digital MP3 files. Just as this new digital world shook up telephone companies and led to the creation of new consumer services, the advent of computerized switching and digital data in electricity distribution will present challenges for LDCs. Some of the larger ones, such as Hydro One Networks, Horizon Utilities and PowerStream have already taken advantage of the new technology to develop new services for customers. Others are in danger of being left behind. The investment needed to transform the province's current electricity distribution system into one that uses modern technology to provide new customer services will cost billions of dollars. This investment is critical to ensuring the preservation of and the future economic prosperity of sustainable communities throughout Ontario. With every challenge, there is an opportunity. The world of electricity is changing, and Ontario has the chance to harness these changes so that they enhance the province's economic competiveness and the quality of life of its people. This cannot be done without a modern, high-tech distribution system. Ontario now has the opportunity to ensure that all utilities in the province are equipped to meet these future challenges and deliver the future to the electricity consumer as efficiently as possible. Ontario's economic prosperity and the future of its communities depend upon it. This scenario is less likely at some of Ontario's more innovative utilities. PowerStream for instance, which serves about 333,000 customers in York Region and Simcoe County, is one of the leaders in engineering computerized intelligence into the distribution network. Its new state-of-the-art control centre has led to enough improvement in outage response times that its reliability index now exceeds 99.99%. Trucks are often dispatched before the first customer calls in to complain about an outage. This is just the first step in Ontario. As the government's Long Term Energy Plan described it, "we are moving toward a modem, smart electricity system that will help consumers have greater control over their energy usage-even when they're not at home ... and make it easier for consumers to produce their own power. '135 Smart Hotnes The first phase of this new world for energy consumers is occurring in the home. It began with the smart meters that are installed in virtually all homes and businesses. Following this, many homeowners applied for and received microFIT contracts that allowed them to install solar panels and wind turbines to feed electricity back into the grid. Next, manufacturers developed stand-alone modules that allow homeowners to turn off lights and small appliances using a smart phone app. The same app can connect with a home thermostat, allowing homeowners to raise or lower the temperature on their furnace or central air conditioner. Figure 11: Smart Home Illustration Source: Hydro One Networks 35 Ontario Ministry of Energy, "Ontario's Long-Term Energy Plan: Building Our Clean Energy Future," 2010, Queen's Printer for Ontario, p. 3. plants. Distributed generation includes other "close-to-load" technologies, such as combined heat and power (CHP) and district energy, which are expected to increasingly provide an alternative to the conventional generation/transmission/distribution paradigm. Further off, but still expected, are improvements in energy storage. Wide-scale storage will fundamentally change the economics of electricity production, as it will allow the stockpiling of energy that previously had to be consumed as soon as it was produced. High engineering and construction costs currently stand in the way of extensive adoption of energy storage, but technologies are improving. Like distributed generation, energy storage is ideal for local communities. Changing Customer Relationships Generation and consumption are not the only things that are changing in the energy world; so is the energy consumer. It used to be said that people just wanted the certainty that lights would go on when they turned on the switch. This is no longer the case. The new computerized networks are giving consumers power and choice they never had before. Instead of being passive consumers, many want to have increased control over the electricity they use. A recent study has shown there is a new emerging diversity of consumers with different needs and profiles. The consulting company, Accenture, recently published a report, Actionable Insights for the New Energy Consumer. Accenture proposes that there are now four broad types of electricity consumers:37 • Consumers who want predictability, with a consistent, stable bill. • Consumers who want the lowest possible price. • Consumers who use the latest technology to control their consumption. • Consumers who were willing to pay more for renewable energy. Accenture suggests these last two consumer groups, the "Save Time" and "Save the Planet" customers will grow in importance over time, as they are found more often in the 18 to 34 age groups. As Accenture points out "more than ever, consumers are seeking added value, personal connection and products and services that align with their lifestyles -all of which go beyond the traditional energy experience. 1138 New electricity consumers take the same approach to energy that they take to everything else they buy. They are demanding more from the products and services they purchase. If they are not satisfied, they will go elsewhere. Tomorrow's LDCs must adapt to increased competition from other service providers such as telephone and cable companies if they hope to satisfy changing customer desires. They must master the new technologies and ways of doing business if they hope to survive as important players in the energy world. There is a new era of electrification looming, and LDCs have to adapt, not just for their own sakes, but for their customers' benefit as well. LDCs need to be an active contributor to an electricity system that will enhance the future competiveness of the provincial economy, and provide a firm foundation for sustainable communities. 31 Accenture. "Actionable Insights for the New Energy Consumer," 2012, p. 20. Accessed November 2012. See: http://www.accenture.com/SiteCollectionDocuments/PDF/Accenture-Adionable-lnsights-New-Energy-Consumer.PDF 38 Ibid., p. 3. \ • Hydro One Networks has a Geographic Information System (GIS) that gives it data on the location of all of the poles, transformers and equipment on its distribution network. It has used this information to build a smart-phone app that not only tells customers the location of a power outage, but how many people are affected, whether crews are on site, and when power will be restored. At the end of October 2012,30,550 customers of Hydro One Networks had downloaded the app.40 • Horizon Utilities, serving Hamilton and St. Catherines, has pioneered efforts in "energy mapping." In a pilot project with the Ontario Power Authority (OPA), it is combining customer data from smart meters with information obtained from the Municipal Property Assessment Corporation on a home's size, date of construction, energy type, air conditioning, and whether it has a finished basement and a swimming pool.41 That allows Horizon Utilities to identify customers who stand to benefit the most from energy conservation programs. The aim is to develop a best practice that any LDC in Ontario can adopt.42 The Drive for Effidency As Chapter 1 has shown, the distribution sector has plenty of room to moderate its costs for delivering electricity. Some smaller utllities have realized this and have developed ways to increase their efficiency that do not involve consolidation. The Cornerstone Hydro Electric Concepts Association (CHEC) is a group of 12 LDCs scattered from Prescott in eastern Ontario to Goderich in the west, and north to Huntsville. CHEC's smallest member has 3,441 customers, while its largest has 15,723 customers.43 Members of the CHEC Group have reduced their costs by jointly developing conservation and demand management ; (CDM) programs, sharing regulatory costs, and jointly purchasing smart meters and consulting services. While the CHEC Group has achieved savings, the co-operative model is not stable enough to be used as a template for the transformation of the distribution sector. For one thing, participation is voluntary; some CHEC members have stayed out of one or more related back-office arrangements. This reduces the potential cost savings. Secondly, CHEC's largest member. Callus Power. has entered into a partnership with PowerStream, to get the advantages that come from linking with a larger, innovative utility. There has been another more commonly seen method for increasing efficiency, and that is through the merger or acquisition of nearby utilities. The evidence shows that these consolidations have resulted in significant cost savings and efficiencies:44 • Veridian Connections, 1999: Veridian was created though the consolidation of the three neighbouring distribution utilities in Pickering, Ajax and Clarington. In the first three years of operation, Veri dian reportedly achieved savings of 13% in OM&A expenses. • PowerStream, 2004: PowerStream was created in 2004 with the voluntary merger of the distribution utilities of Markham and Vaughan and the acquisition of Richmond Hill's LDC. That consolidation brought about $6.9 million in annual cost savings • Veridian Connections' purchase of Scugog and Gravenhurst Hydro, 2005: As a result of the acquisition, the total cost of operating, maintaining and administering the combined utility decreased from $21.1 million to $18.8 million, an 11% reduction. This works out to savings of almost $40 per customer per year. "As of October 31 2012. Source: Hydro One Networks. 41 In developing this pilot, Horizon Utilities has followed the Ontario Information and Privacy Commissioner's approach of "Privacy by Design." For more on "Privacy by Design," see http://privacybydesign.ca/ 42 Horizon Utilities -November 2012. 4' Based on: Ontario Energy Board, "20 11 Yearbook of Electricity Distributors," op. cit. 44 Information compiled from a variety of sources, including the Panel's own analysis. on the fair market value of those assets. While the transfer tax does serve an important function of protecting payments made by distributors in lieu of taxes (PILs), it is also a major deterrent for private sector investment in the sector. Innovation The mantra for modern business is "Innovate or Die." In its 2011 annual report, the Ontario government's Task Force on Competitiveness, Productivity and Economic Progress said improving innovation has to be the province's priority for the coming decade: "When economists observe that productivity in Canada and Ontario is lagging, they are seeing the results of a sub-standard innovation record among our businesses. "49 The Smart Grid is just the beginning of what can be done with the digital sensing that will soon be the backbone of all distribution networks. Similar computerized intelligence is already being transferred to the home, allowing a thermostat, for instance, to sense when a family has left the home and reduce the level of heating or air-conditioning in order to save money. A number of LDCs say it can be difficult to be innovative in the current regulatory environment. They cite a recent OEB decision that prevented Guelph Hydro from recovering the costs of a pilot program for electric vehicles, or the costs of including additional technology in its smart meters to enhance communication with in-home displays and appliances. 5° While the OEB said it might allow the recovery of the additional smart meter costs in the future, the decision has persuaded many LDCs that innovation is too risky. The expectations and requirements of the LDCs and the OEB need to be aligned if innovation is to be encouraged in Ontario's distribution sector. Contiguity The results of previous consolidations have shown that a reduction in the number of utilities can result in significant cost savings. It is important to acknowledge however that the consolidations of the past may understate the extent of possible savings in the future. That is because many of the consolidations were accomplished by amalgamating two utilities that were distances apart and did not have any adjoining boundaries. Four of the five examples of consolidations cited in this chapter did not eliminate any boundaries. The existing boundaries were maintained; only the administration and operations were merged. Additional savings can be achieved when the boundaries themselves are erased, consolidating neighbouring utilities into one new larger LDC with one contiguous boundary. Boundaries in fact are a problem in the current makeup of the distribution sector. There are too many of them. Boundaries are an obstacle because they inhibit the efficient use of capital and resources. With fewer boundaries between utilities, they would be able to install new switches and sub-stations so that they serve a wider area. In addition, physical plants can be rationalized, eliminating the need for multiple control rooms in favour of one advanced system control centre with computerized monitoring and controls. There will also be fewer instances of the oft-heard complaint that crews from one LDC must pass through another LDC's service area in order to attend to its own customers, requiring trucks to drive further than what ought to be necessary-a clear example of inefficiency. Fewer boundaries and fewer LDCs will also mean better planning. Currently there is a perverse incentive for a utility to build up its own capital base, rather than share equipment owned by another utility. 49 Task Force on Competitiveness, Productivity and Economic Progress, op. cit., p. 12. 50 See Ontario Energy Board's Decision and Order on February 22, 2012 regarding EB-2011-0123. Chapter 4 The Vision A new world of electricity distribution is emerging, and it will look a lot different from what Ontarians see today. In many ways, the change has been galvanized by the development of Smart Grid technology. The digital nature of modern electricity distribution has now made its way into the sensors and controls that are part of the II Smart Home. II The next steps will include the adoption of electric vehicles, the spread of energy storage and an increase in distributed energy. Over the next decade, Ontarians will be changing the way they generate, manage and consume electricity. This presents a big challenge for the province's LDCs, the biggest challenge many have ever faced. Ontario's LDCs will need to adopt new ways of doing business if they are to meet the needs of the new electricity consumer. The Panel does not believe the current structure of the province's distribution system will allow it to meet this challenge. The LDC of the future must have a stronger balance sheet, and the capacity to adopt new technology and offer advanced services in a cost-effective manner. This requires "shoulder-to- \ shoulder, robust, we/1-resourced, and efficient LDCs," to borrow a phrase from the Electricity Distributors ! Association (EDA).52 The Panel is supporting consolldation not as an end, but as a means to an end. The current fragmented nature of Ontario's electricity distribution system, with its large number of small distributors, is a barrier to the innovation that is needed in the sector, and that its customers deserve. It is also an obstacle in the way of the most cost-effective delivery of electricity. The Panel agrees with what The Conference Board of Canada said in its 2012 report, Needed: A Comprehensive Growth Strategy for Ontario: " ... Ontario firms and organisations will have to step up their own commitments to strengthen productivity growth and competiveness,. They can enhance their commitment to research and development in the province and work to build an innovation culture within organizations of all sizes and types, one that places high value on new ideas and constant refinements to products and process. "53 There is a strong consensus in the industry that consolidating the province's LDCs will not only encourage innovation but also result in a less costly and more efficient delivery of electricity. This is the view of the Ontario Energy Association: " ... now is the ideal time for the Ontario government to move decisively to eliminate costly inefficiencies in the LDC sector to the benefit of ratepayers, and unlock the value of each company for its shareholder. Rationalization of LDCs would bring economic benefit to all Ontarians - especially important given the province's fiscal challenges and the broader economic landscape. "54 A number of electricity customers share this opinion. In its presentation, the Retail Council of Canada (Council) said the current distribution system "causes extra administrative costs for retailers in multiple service areas, costs that have no return on investment. •-ss The Council also said it "increases the cost 52 Electricity Distributors Association, "The Power to Deliver: Recommendations for the future of electricity distribution in Ontario," August 2012, p. 5. 51 G. Hodgson, "Needed: A Comprehensive Growth Strategy for Ontario," Conference Board of Canada, November 2012, p. 4. 5' Ontario Energy Association, "Ontario Distribution Sector Review Panel Submission, • July 2012, Cover Letter. " Quoted from the Retail Council of Canada's official submission to the Panel. "Ibid. As noted in Chapter 1, the structure of the electricity distribution sector in Ontario is unique. No other jurisdiction in Canada has the number or share of small LDCs that are evident in Ontario's distribution sector. While there was a general understanding that the status quo was no longer appropriate, there was also a surprising amount of agreement on what should replace the currently fragmented distribution system: a dramatically reduced number of LDCs. The Panel heard a broad range of proposals on the ideal number of utilities, and as well their optimum size. One stakeholder suggested that only one distribution utility was needed to serve the entire province. Others suggested there should be 6 to 7 lDCs, each with 500,000 to 800,000 customers apiece. Another participant felt Ontario should have 8 regional distributors centered on an urban hub, each with at least 500,000 customers and a rate base of at least $1 billion. In the end, Panel members agreed with this general direction. So it is recommending the consolidation of Ontario LDCs into 8 to 12 regional distributors that are large enough to deliver improved efficiency and enhanced customer focus, while at the same time maintaining connections with local communities.65 The Panel's recommendations will not apply to all LDCs in Ontario. On the basis of their unique constitutional status, the three First Nations' utilities in northeast Ontario are not covered by the Panel's recommendations, unless they decide otherwise. The three non-rate regulated utilities in Ontario. Cornwall Electric, Dubreuil Lumber, and the assets serving the Cat Lake community will also be exempt unless they choose to join in. Cornwall Electric is exempt because it buys its electricity , from Quebec; Dubreuil because it operates mainly on private property; and the distribution assets that serve the Cat Lake community are exempt because they are under the control of Hydro One Networks under an interim electricity distribution licence. Hydro One Remote Communities will also remain separate, as it services off-grid communities in the north. The new regional distributor will be anchored by one or more urban centres and will have to provide service to customers in its territory regardless of the costs of service. Northern Ontario needs to be treated differently because of the smaller number of customers spread out over longer distances. There should be two regional distributors in the north, one serving the northeast part of Ontario, and the other serving the northwest This would leave the rest of the province to be served by between 6 and 10 regional distributors. Of the existing LDCs, the Panel expects only one, Toronto Hydro, will remain unchanged as it is already large enough and has contiguous boundaries. It can thus be considered as one of the 6 to 1 0 regional distributors in southern Ontario. Each new regional distributor in southern Ontario should have a minimum of 400,000 customers. The Panel feels that the existing LDCs should be encouraged to voluntarily merge their distribution assets and create the new regional distributors within two years. While there was intense consolidation and sale activity in the years immediately following the passage of the ECA, the situation has been relatively stagnant in recent years. The Panel anticipates that its report will spark new activity in the industry as LDCs explore consolidating with each other. Since consolidation is a proven method to curb costs, ensure the broadest adoption of technological innovation and make the necessary funding available at the lowest price, inaction is not in the best interests of the consumers or the province. 65 Texts in bold face are summaries of the Panel's recommendations. The formal recommendations can be found in Chapter 6. The recommendation to merge and not sell Hydro One Networks' distribution assets is in line with a recommendation from the Drummond Commission: UDo not partially or fully divest any or all of the province's government business enterprises-Ontario Lottery and Gaming Corporation, Uquor Control Board of Ontario, Ontario Power Generation and Hydro One-unless the net long-term benefit to Ontario is considerable and can be clearly demonstrated through comprehensive analysis. '168 Cost Savings and Benefits The Panel is convinced that consolidating the applicable rate-regulated LDCs into a smaller number of considerably larger utilities will significantly curb costs and generate benefits for the industry. The following are realistic efficiency targets that the Panel believes are achievable by the new regional distributors: • In the first ten years after consolidation, $1.7 billion in costs at net present value can be removed from the electricity distribution sector.69 After allowing for $500 million in transaction and transition costs, it is expected that cost savings of $1.2 billion at net present value would be achieved across the sector over the first ten years for the benefit of customers and shareholders. This would be equivalent to approximately $70 per year for every electricity customer by the end of the tenth year. • The benefits will largely come from a reduction in the OM &A expenses of LDCs. Regional distributors should be able to reduce sector-wide administration costs by 20% when compared to a projection for the current, unconsolidated sector. Efforts to increase administrative efficiency should focus on customer care, billing and collections, facilities and facilities maintenance and administrative salaries and expenses. • Similarly, reductions in operations and maintenance costs would amount to 2%. Benefits accrue from curbing operating expenses, the number of service and control centres, and supervision and engineering costs. • Consolidation will allow LDCs to avoid $1.3 billion in infrastructure investment over the first ten years resulting in a 5% reduction in depreciation and return on capital when compared to the continuation of the status quo-worth over $300 million in present terms. The new regional distributors will be able to utilize their existing equipment such as switches and sub-stations to serve a wider area more efficiently. In addition, duplicate service and control centres can be eliminated. There will also be improved economies of scale for facilities and transportation, and for advanced computer software such as customer information systems. Fig. 13 and Fig. 14 illustrate the source and timeframe for costs savings in the ten years following consolidation versus a projection of the status quo. The savings will continue to increase beyond ten years, with relatively more of the savings accruing from avoided infrastructure investments and the resulting reductions in the regulated asset base over time. Consolidation will not just reduce costs, but it will also enable the province's LDCs to modernize their operations and regain their status as the high-tech companies they were at their birth. • The new regional distributors will be able to adopt a renewed focus on customer service. This can include modern operation centres that offer 24n customer service throughout the province and enhance reliability using Smart Grid technology. '" Ibid., p. 407. "" Assumed annual discount rate of 6%. • Larger distribution utilities will have the resources and capacity to deal with the impending changes in electricity generation and consumption, including distributed generation, energy storage and electric vehicles. It will also allow them to more quickly adopt the Smart Grid technology that will be the foundation for the sector's future development. • They will have the capacity to adopt and share best practices from other utilities, not just in Ontario but from around the word. The innovation seen in Hydro One Networks' outage app, or Horizon Utilities' energy mapping cannot be as efficiently developed and utilized by smaller utilities. • Larger, betteHesourced distributors will be able to use enhanced asset management methods to focus replacement or upgrades on assets most at risk. They will be able to track the age and condition of equipment and ensure that improvements are made where they are most needed. This will increase reliability and reduce the risk of power outages. • Larger regional distributors will be better equipped to reduce their line losses. Right now distributors lose about 4% of the energy they purchase due to technical matters and theft.7° Technical line losses are caused primarily by magnetic losses in transformers and by the electrical resistance inherent to sending lower-voltage electricity over long distances. Line loss has historically been higher for smaller LDCs with older equipment than for larger newer ones, and this cost is passed on directly to consumers. • Regional Planning will be easier. As noted previously, the OEB's Renewed Regulatory Framework for Electricity concludes that LDCs will be expected to file evidence in rate and leave to construct proceedings that demonstrates that regional issues have been appropriately considered and, where applicable, addressed in the utility's capital budget or infrastructure investment proposal. After consolidation, a lot of the work of planning the optimal investment in infrastructure at the lowest possible cost will be done as a matter of routine by the new regional distributor. • Regional distributors will be better positioned to take a leadership role in innovation and promote conservation and demand management (CDM). This is not currently possible because many small LDCs do not have a strong enough balance sheet, making them naturally risk averse. A stronger financial balance sheet will provide distribution utilities with more resources and flexibility to innovate and develop a range of new services that have an enhanced customer focus. • There will be savings in regulatory costs. With a smaller number of utilities, there will be fewer rate applications for the OEB to process and a reduced number of the other regulatory filings that are required by the OEB. Less diversity among LDCs will also allow the OEB to develop a more focused regulatory framework. These changes will have two benefits: It will allow the OEB to streamline operations and reduce its cost of regulation, thus saving customers money; and since the per customer cost of regulatory filings is less for large utilities than small ones, consumers will receive a second, more immediate benefit. • Financing costs will be lower. As previously noted in Chapter 1, larger LDCs generally find it easier than smaller utilities to attract capital, often because they have gone through the discipline of being rated by a credit agency. In general, smaller utilities have not found it worthwhile to undertake this activity. The cost of capital will be increasingly important in the future, as the electricity distribution sector requires billions of dollars of additional infrastructure investment to renew and transform its distribution networks. 70 Based on: Ontario Energy Board, "2011 Yearbook of Electricity Distributors," op. cit. Transition Advisor Even though the Panel believes substantial consolidation can be achieved voluntarily within two years, it also feels immediate action must be taken if this is to succeed. Therefore, the Panel is recommending that the government appoint a Transition Advisor to monitor the process of consolidation. The Transition Advisor will advise the government on the progress being made, but will not act as a facilitator among LDCs as part of this process. Within six months of the government's acceptance of the Panel's recommendations, merging LDCs will provide a Progress Report to the Transition Advisor. The Progress Report will indude evidence of an agreement among the merging LDCs, such as a Memorandum of Understanding, committing them to work towards consolidation within the two-year time frame. After receiving a Progress Report. the Transition Advisor may advise LDCs of any conflicts that would inhibit the achievement of the Panel's vision for the sector, such as mergers that may not result in efficient, contiguous regions. or that may result in stranded service territories. LDCs may then submit a revised Progress Report based on further negotiations before the end of the initial six months. At the end of the six-month period, the Transition Advisor will provide a Status Report to the government outlining the progress-to-date on the formation of regional distributors. • The Transition Advisor will provide advice on the formation of contiguous and shoulder-to-shoulder regional distributors. • The Transition Advisor will notify the government of mergers that may not result in efficient contiguous regions as envisioned In Chapter 4, or that may result in stranded service territories. • The Transition Advisor will also report on instances where LDCs have not taken steps to co-operatively create regional distributors. After consideration of the Status Report, if any of the proposed regional distributors need more time to finalize their voluntary agreements. the government may permit them up to three additional months to finish their work. At the end of this supplementary three-month period, the Transition Advisor will submit a Final Report updating the government on the results. Where it is dear, after consideration of the Transition Advisor's Status Report, or in the event that the government has sanctioned an additional 3 months, the Final Report, that formation of regional distributors cannot be completed through voluntary means, the Panel recommends that the government introduce legislation at that time to ensure consolidation Is successfully completed. from the sale of buildings or property that were no longer required by the new utility. The Panel feels the money should stay in the distribution system. Any shareholder gains from the disposal of excess utility assets prior to the merger are expected to be reinvested in the regional distributor to strengthen the system, and not used for dividends or other non-electricity purposes. Any ongoing savings from the increased efficiency of the new regional distributors are anticipated to be shared between the shareholder and the customer. As the Panel has heard from many stakeholders that significant capital investment will be required over the coming years, the Panel expects that much of the savings accruing to the shareholder will be reinvested in the electricity distribution system. Many utilities in Ontario have subsidiaries or nonwregulated affiliates that provide services beyond the regulated poles and wires business of electricity distribution. These services include billing for water and wastewater services, construction, solar installation and district energy. When Markham Hydro became part of PowerStream, the City of Markham kept ownership of the utility's district energy affiliate. Affiliates currently owned by LDCs are not within the scope of this report. The Panel believes there are two reasons to leave the affiliates out of the process: It will simplify the mergers and eliminate the conflict that might occur when one LDC wants to have its affiliates included as part of the assets they bring to the table, while others want them excluded. Secondly, the Panel feels the consolidations that will create the new regional electricity businesses will take the full and uninterrupted attention of the new regional electricity distributors' managers, and that they should not be distracted by any unregulated business affairs. Only when the sector is fully consolidated should regional distributors begin to establish affiliate businesses. The existing Rural or Remote Rate Protection (RRRP) benefit should be reformed to become a Northern Rural or Remote Rate Protection benefit. Under RRRP. all electricity customers in Ontario pay a small charge to cushion the highwcost of electricity distribution for hard to serve rural or remote customers. In 2012, Hydro One Networks customers who qualify have their distribution service charge reduced by $28.50 a month. The Panel believes the RRRP will no longer be needed in southern Ontario because unlike the present situation, the contiguous, shoulderwtDwshoulder regional distributors will have a mix of both urban and rural customers, allowing them to balance urban and rural rates within each region. This change is not expected to affect customers of First Nations' LDCs, Hydro One Remotes Communities, or qualifying customers in areas of northern Ontario currently covered by the RRRP. Investments and Gover•nce The Panel feels that a lot of potential benefits of consolidation could be unleashed by making changes to the governance and management of the province's LDCs. Strengthening managerial capacity was one of the recommendations of the Ontario government's Task Force on Competitiveness, Productivity and Economic Progress. "Strong Management is important for sizing up competitive challenges and threats, assessing consumer behaviour for business opportunities, putting in place the necessary resources and capabilities, and building skills and talents in the organization. "72 Since 1998, distribution utilities have been incorporated under the OBCA. The Panel feels it is time to treat the province's LDCs as the commercial enterprises they are; this will require municipal shareholders to adopt best practices in the stewardship of the LDC assets in order to ensure strong operating performance. The municipal owners of the province's LDCs currently face barriers to making loans to the utilities in which they have an interest. This is a deviation from accepted practice, whereby shareholders of a corporation are responsible for ensuring it is adequately capitalized. The Panel believes the distribution sector should be treated the same as other corporations in Ontario. and 72 Task Force on Competitiveness, Productivity and Economic Progress, op. cit., p. 41. Chapter 6 Recommendations Regional Distributors The 73 LDCs that are the focus of this report should be consolidated into 8 to 12 larger regional distributors that are large enough to deliver improved efficiency and enhanced customer focus, while at the same time maintaining a strong connection with their local communities. There should be two regional distributors to serve the north, one serving the northeast part of Ontario, and the other serving the northwest, leaving 6 to 1 0 regional distributors in southern Ontario. Any new regional distributor in southern Ontario should have a minimum of 400,000 customers. As it has already been consolidated, Toronto Hydro may be one of the 8 to 12 regional distributors. The three rate-regulated First Nations' utilities, and the three utilities that are not rate-regulated (Dubreuil Lumber, Cornwall Electric, and Hydro One Networks lncJCat Lake Power Community) will be exempt from this consolidation, unless they decide they want to join in. Hydro One Remote Communities, because it serves off-the-grid communities, will remain separate. The new regional distributors must have boundaries that are contiguous and stand shoulder-to-shoulder. Boundaries should follow the existing structure and architecture of the distribution system, and take into account the existing Hydro One Networks service areas. Consolidation should be completed within two years of the Government's acceptance of the recommendations of this report. Hydro One There should be no across-the-board sale of Hydro One Networks' distribution assets. The creation of the new system of regional distributors will be facilitated by the merger of Hydro One Networks' assets with those of the other existing distributors. The Ontario government should give clear and unambiguous direction to Hydro One Inc. to lead and engage in the discussion of the merger of its distribution assets with the appropriate interested utilities. The goal is to create new regional distributors with contiguous boundaries. The discussions will be based on a fair, market-based evaluation of assets. The owners of the current LDCs will get shares in the new regional distributors they voluntarily create in proportion to the valuation of the assets they contributed. LDCs that are amalgamated through mandatory mechanisms will have their assets valued at book value. Ontario Government The government should appoint a Transition Advisor to oversee the consolidation process. The Transition Advisor will advise the government on the progress of achieving complete consolidation. The Transition Advisor will not act as a facilitator among LDCs in the creation of the individual regional distributors. Cost Savings The Panel anticipates that any funds from the disposal of excess utility assets would be re-invested in the regional distributors in order to strengthen the system, and not used for dividends or other non-electricity purposes. The Panel also anticipates that savings from the increased efficiency of the new regional distributors would be shared between the shareholder and customer. Given the requirement for significant capital investments, it is expected that much of the savings accruing to the shareholder will be reinvested in the electricity distribution system. Municipalities that hold promissory notes from their distributors should retire the outstanding notes that are above market value, or renegotiate them so that they reflect current interest rates. Governance Restrictions that prevent municipal governments from making loans to the distributors in which they have an interest should be removed. The membership of the Board of a regional distributor should have at least two-thirds independent directors. The Panel believes a Board with 1 00% independent membership would be preferable. The Boards should be adequately sized to have directors with an appropriate range of skills and experience, and be populated on the basis of directors' qualifications to meet the management and oversight requirements of an electricity distribution utility. Utilities should ensure that their Board members have adequate training in governance and the roles of Boards, and represent an appropriate range of skills and experience. Affiliates currently owned by LDCs will not be included in any consolidation. Appendix 1 List of Maps, Charts and Graphs Fig. 1 LDC Service Areas in Ontario Page 2 Fig. 2 Total Customers by LDC in 2011 Page 7 Fig. 3 Veridian Connections Service Areas Page 8 Fig. 4 Electricity Distributor Sizes -International Comparisons Page 9 Fig. 5 Components of a Typical Residential Electricity Bill in Ontario Page 10 Fig. 6 OM&A Costs per Customer for Small, Medium and Large LDCs Page 11 Fig. 7 OM&A Costs per Customer by LDC Size Page 12 Fig. 8 Average Financing Costs of Long-Term Debt by LDC Size Page 13 Fig. 9 Capital and OM&A Costs per Customer by LDC Page 14 Fig. 10 Smart Grid Illustration Page 18 Fig. 11 Smart Home Illustration Page 19 Fig. 12 Illustration of 8 Regional Distributors Page 30 Fig. 13 Estimated Benefits from LDC Consolidation (First 1 0 Years) Page 32 Fig. 14 Breakdown of $1.7 Billion (Net Present Value) in Cost Savings Page 32 Fig. 15 Timeline for Consolidation Illustration Page 36 • Ministry of Labour • Ministry of Municipal Affairs & Housing • Northeast Utilities Group • Oakville Hydro Corporation • Ontario Chamber of Commerce • Ontario Energy Association • Ontario Energy Board • Ontario Financing Authority • Ontario Municipal Employees Retirement System • Ontario Power Authority • Oshawa PUC Networks Inc. • Peterborough Distribution Inc. • Power Workers' Union • PowerStream Inc. • RBC Capital Markets • Retail Council of Canada • School Energy Coalition • Simui/UtilityPULSE • The Common Voice Northwest Energy Task Force • The Federation of Northern Ontario Municipalities • The Northwestern Ontario Municipal Association • The Society of Energy Professionals • Toronto Hydro-Electric System Limited • Town of Collingwood • Town of Fort Frances • Town of Niagara-on-the-Lake • Township of North Dumfries • Utilities Kingston/Kingston Hydro Corporation • Utilities Standards Forum • Utility Collaborative Services Inc. • Veridian Connections lnc.Neridian Corporation • Whitby Hydro Electric Corporation Individuals • Donald Carmichael • Gerhard Langematz • John McNeil • Parker Gallant • Private Citizen • Private Citizen • Private Citizen other • Anonymous Submitter MicroFm Ontario residents are able to develop a very small or "micro" renewable electricity generation project (1 0 kilowatts or less in size) on their properties. Under the microFIT Program, they are paid a guaranteed price for all the electricity they produce for at least 20 years. Municipal Elecb'icity Utility (MEU): An infrequently used term for a LDC which faded from usage after 1998, when MEU's were converted into corporations under the OBCA. The term is still used in some legislation to describe LDCs. Ontario Power Authority (OPA): An Ontario government agency that assesses the long-term adequacy of electricity resources in Ontario, plans and procures electricity supply, and coordinates province-wide conservation efforts. Operations. Maintenance and Administration (OM&A): The cost of operating, maintaining and providing the back-office administration of a business. OM&A expenses typically include salaries and equipment required to provide regulated services and maintain a state of good repair. Payments in Lieu of Taxes (PILs): In Ontario, electricity utilities that are at least 90% publicly- owned are exempt from corporate taxes. Instead they pay Plls to the Ontario Electricity Financial Corporation (OEFC). PILs which replicate federal and provincial corporate taxes and property taxes payable by private sector companies, are used to help pay down the stranded debt of the former Ontario Hydro. Peak Demand: Peak demand, peak load or on-peak are terms describing a period in which electricity is expected to be provided for a sustained period at a significantly higher than average supply level. Rate Setting: The OEB sets an LDC's rates to enable the LDC to recover the forecasted costs which it will prudently incur to provide regulated services. Once every four years, an LDC undergoes a comprehensive Cost of Service (CoS) application where the OEB uses one year forecasted cost and revenue information submitted by the LDC to determine a base revenue requirement and the "base" rates that are set to recover that revenue requirement. In the intervening years, as part of the Incentive Regulation Mechanism (IRM) those base rates are adjusted annually according to an DEB-approved formula that includes components for inflation and the OEB's expectations of efficiency and productivity gains. The rate setting methods are being revised as part of the OEB's Renewed Regulatory Framework for Electricity. Rural or Remote Rate Protedion (RRRP): Rural or Remote Rate Protection was established by the Ontario government to keep distribution rates in rural and remote parts of the province at levels similar to those paid by the rest of the province. The cost of the RRRP benefit is recovered through a regulated charge on all Ontario electricity customers approved by the OEB. In 2012, this charge was set at 0.11 ~/kWh. Scale of Operations: The size of an LDC's customer base and service area. A large utility has a larger scale of operations than a small one. Scope of Operations: The extent to which an LDC also owns and operates other utility-like services. An LDC that also provides natural gas and water and wastewater services has a larger scope of operations than a utility that restricts its operations to electricity distribution. • 'I'} • 0 () ( ) '·~ The Province should work with the utilities to determine a payment per kW/kWh and m3 of savings delivered through COM and DSM, respectively and then allow utilities and other players in the marketplace to develop their own innovative programs. There is still a need for program development and research and development by a central agency such as the OPA. OPA programs provide a helpful default for those utilities with limited capacity and have the opportunity to pursue non-conventional approaches such as human resource capacity building and novel technologies. However, the OPA must streamline its lengthy approvals process, move beyond its narrow focus on electricity demand and stop wasting time on technical benchmarks and standards development divorced from market realities. The OPA should be allowed to continue to provide COM programs as a default for LDCs and to pursue non-conventional approaches such as human resource capacity building and novel technologies. However, the OPA must streamline its lengthy approvals process and move beyond its narrow focus on electricity demand to more efficiently take advantage of the huge conservation opportunity available. AMO is pleased that the OPA is now considering COM programming that looks beyond technology-focused pilots and electricity demand reduction to the crucial goal of developing staff capacity. Like many other customer groups, the municipal sector's main challenge in accessing utility incentive programs is a lack of capacity and qualified staff to take advantage of these opportunities. We believe current CDM efforts could be enhanced by a one-window approach to programs, municipal account managers at the utility level and financial support for energy efficiency service providers to service the municipal and other key consumer sectors. As previously discussed, current electricity pricing is also an obstacle to achieving more CDM. Rate mitigation efforts through subsidies such as the Ontario Clean Energy Benefit (OCEB) only mask the true cost of power and act as a disincentive to conservation. Electricity pricing must be made more transparent to the consumer to align the role of price in signaling consumption and conservation. Customers are confused by their energy bills, especially those municipalities which have multiple bill Page 32of35 . ' ' (.) A New Conservation Framework is Required The Province needs to move beyond talk to true leadership by making our homes, buildings and industries the most energy efficient in the world. A new conservation framework is required. In a comprehensive review of state conservation governance schemes, the International Energy Association (lEA) concluded that the ideal COM and DSM framework: • Confers sufficient authority to implement EE policies and programs; • Builds political consensus on EE goals and strategy; • Creates effective partnerships for policy development and implementation; • Assigns responsibility and create accountability; • Mobilises resources needed for EE policy implementation; and • Establishes a means to oversee results. 16 (-· ·) Clearly, while the Province was off to a good start in many of these areas the current "'-~ (_) system has too many agencies involved, suffers from competing objectives and has been overwhelmed by a focus on renewable energy generation-all of which threaten to undo the political consensus and effective partnerships that have been built to date. The regulatory agencies have also been too focused at maintaining 'arbitrary divisions' between electricity, natural gas and other types of energy conservation programs to the point that they are creating inefficiencies. Energy systems are just that, it is not a series of silos. A new conservation framework should be designed to achieve the maximum cost- effective COM and DSM, over long time periods. It should enable innovation, improvement and learning in program design and delivery. It should promote the development of local capacity to design and deliver COM and OSM in Ontario. It requires a combination of technology development, market mechanisms and government policies that can influence the actions of all consumers. Better conservation 16 1nternational Energy Agency, Energy Efficiency Governance, Paris: 2010. Page 30of35 n () ( ' \ ) '-~ strategic investments of public money because they commonly leverage $2-3 for every dollar spent while making our air cleaner and reducing environmental impact. AMO has consistently supported these objectives through our policy positions and program delivery through our subsidiary, Local Authority Services Limited (LAS). We believe conservation should be the first priority in terms of not just supply options but overall energy policy design and system planning. COM Should be the First Priority The energy we stop wasting is the cheapest and most readily available energy source there is. For example, the cost of saving electricity is 76-94% lower than the cost of new nuclear energy. Conservation and Demand Management (COM) also helps avoid the construction of new, expensive and often unpopular energy supply projects and has many other system benefrts. Reduced use of carbon-based fuels would make urban air more breathable. COM has a multiplier effect in terms of system benefits as a unit of energy saved at the consumer level cascades into multiple units of energy saved at the source. COM also creates well-paid, local jobs that cannot be outsourced. In terms of primary delivery agents, the L TEP recognized that the Green Energy and Green Economy Act tasked LOCs with being the "face of conservation" by assigning conservation targets which they must meet as a condition of their licence via a combination of province-wide and local incentive programs. LOCs are well suited to deliver COM programs because they have existing relationships with their customers, they are very knowledgeable and trusted sources of energy information and they can provide financial incentives. The Current System is Broken Despite its ambitious targets, the Province is proposing to spend six times more on electricity supply ($75.4 billion) than on energy efficiency ($12 billion) in the LTEP. Worse, in the alphabet soup that is Ontario's current energy regulatory environment, the Ontario Energy Board (OEB) has completely undermined existing efforts by utilities to meet the targets provided to them in November 2010. Page 28of35 () ( )' \ __ , The Panel could recommend that the OEB and LDCs work together to reform the current common performance standards. The OEB should refine and enforce efficiency, reliability and service standards as this benefits all consumers. Outliers should be given clear expectations and reasonable time periods to achieve required improvements. The OEB has commenced this exercise11 by looking at incentive regulation, benchmarking and service quality standards in other jurisdictions and AMO is pleased that it is considering an "outcome-based approach with multi-year rate-setting". More work needs to be done in this area-the OEB should separate considerations of Operational, Maintenance and Administrative (OM&A) Costs to focus more on reducing administrative costs and new utility outputs that measure how LDCs connect renewable energy projects, incent innovative conservation initiatives and operationalize the smart grid should be developed. The transfer tax should be eliminated in order to create benefit for municipal taxpayers and ratepayers. The Electricity Act imposes a 33% Transfer Tax on any sale of assets owned by a municipal LDC, payable to the Ontario Electricity Financial Corporation (OEFC). The OEFC uses proceeds from this tax, along with other revenue sources, to pay off the stranded Ontario Hydro debt. Eliminating the transfer tax barrier will deliver greater options and flexibility to municipal governments. Some municipalities will choose to expand their local hydro companies and generate new revenue and shareholder benefits while others may choose to sell part or all of their LDC for own source revenue purposes. Conservation Until recently, Ontario has had a tradition of offering low, subsidized prices for electricity with less focus on the vast potential of conservation and demand management (CDM) programs. The broad array of our natural resources, our growing population, our climate and geography push us towards above-average energy consumption. As a result, 11 Ontario Energy Board, Staff Discussion Paper on Defining & Measuring Performance of Electricity Transmitters & Distributors EB-2010-0379, Toronto: 2010. Page26of35 0 The inclusion of Hydro One's rural territories with more urban areas held by other LDCs would result in lower costs and efficiencies through better economics of scale and by eliminating redundant assets, equipment and personnel. This would also allow Hydro One to focus on the transmission build-outs required in the near future. The inclusion of Hydro One's rural territories with more urban municipally-owned LDCs would result in lower costs and more efficiency through considerable economies of scale and scope by eliminating redundant assets, equipment and personnel. The sale of Hydro One distribution assets at reasonable prices determined by an independent evaluation will result in efficient regional LDCs that will be able to provide benefrts to all customers through reasonable rates and enhanced service. To enable true Shoulder to Shoulder utilities investment, outside investors will be required, but we would prefer that majority ownership of LDCs remain within the public sector. The combination of democratic, local oversight and market-based discipline from such firms would be ideal for owners and ratepayers alike. (-) The continued exclusion of the private sector from the LDC sector has reduced the \__, (_) options for capital-raising, prevented monetization of municipal value and may be a deterrent to additional consolidation and efficiency in the sector. Another concern is the fact that permissible debt is capped at 60% and the industry currently sits at approximately 55% overall. 9 However, private capital is not a silver bullet and in no way are we suggesting that an ownership transfer occur from public to private hands-the majority equity share of LDCs should remain publically owned. Some consolidation proponents argue that the private sector will impose the discipline of a bottom-line profit motive to hold management's feet to the fire but this is based on the two false assumptions that the private sector performs better and the public sector does not have any external sources of discipline. Numerous studies have confirmed that there is no "statistically significant difference in the operation of distribution electric utilities based 9 Figures provided by the Electricity Distributors Association (EDA) based on long-term debt and equity for the distribution industry from 2005 to 2010. Page 24of35 C) ( ) \.__, Comparison of LDCs by Size Data from OEB Yearbooks 2008-10 Small LDCs Medium lDCs Large LDCS Hydro One <20,000 customers 20,001--99,999 >100,000 Avg Number of Customers 7,929 41,162 262,386 1,194,683 %of Ontario Electridty Consumers 7.43 24 43.7 24.87 Number of LDCs 44 28 9 1 Avg Revenue Per customer $ 494.80 $ 439.72 $ 497.76 $ 893.66 Avg O&M per Customer $ 301.87 $ 202.91 $ 194.94 $ 423.45 Avg Net Income per Customer $ 37.28 $ 6L53 $ 74.42 $ 130.99 Avg New Capital Spent per Customers s 1,157.05 $ 180.15 $ 181.06 $ 343.87 Power & Distribution Revenue s 17,529,641.10 $ 104,029,496.63 s n7,299,346.91 $ _3,100,883,045.11 Expenses operating $ 382,198.82 $ 2,234,993.68 $ 14,393,833.90 $ 72,037,434.47 maintenance $ 515,354.22 $ 1,622,087.84 $ 9,sn,97t.86 $ 227,837,441.74 administrative $ 1,428,640.65 $ 5,211,87L 76 s 31,497,208.66 $ 206,179,217.02 TotaiO&M&A $ 2,326,193.70 $ 9,068,953.28 $ 55,769,014.42 $ 506,054,093.23 A caution here-not all small LDCs are underperforming and in fact an LDC by LDC examination reveals that many small LDCs outperform much larger ones. AMO suggests the real opportunity here is to develop a framework where these smaller LDCs can expand by acquiring areas currently within Hydro One's distribution service territory. The data clearly shows that Hydro One remains an outlier in terms of poor performance. While a certain amount of Hydro One's poor performance is due to the vast distances it must service including many areas with very few customers, that is not the full story. Hydro One has some of the highest salaries in the Ontario public sector, even though they are running businesses that do not face normal competition or the pressure for results that comes from having to meet shareholders' expectations. There are also numerous instances of redundant infrastructure in the Province where Hydro One has assets in the same neighbourhood or even on the same street as a municipal LDC. Hydro One faces substantial investment requirements in the near future related to several planned transmission projects. Transmission is Hydro One's core business. AMO suggests that Hydro One's distribution assets should be independently valued and put up for sale to municipal LDCs with a right of first refusal. Proceeds from this sale could go to help Hydro One fund its transmission builds and refurbishments. Page22 of35 (~) ( ) \.__ __ best value to its ratepayers and shareholders. If the desired outcome of this exercise is to create more efficient and effective entrepreneurial energy companies then surely this would be a good place to start. Voluntary alliances and sharing of services should be incented whenever possible. More must be done to encourage specialization. There are great synergies and service sharing on the unregulated side of the business-this should be allowed on the regulated side as well. Current OEB policies which are a barrier to realizing efficiencies must be eliminated. Principles to Guide Consolidation As mentioned AMO has its doubts that significant financial savings can be realized from consolidation of LDCs and some of our members are opposed to this initiative. Efficiencies can be achieved by looking at the entire system. However, if the government is going to pursue consolidation and views the current conditions as being inadequate in terms of pushing LDCs towards consolidation and other efficiencies. AMO offers some caution on how it proceeds. The following principles may help guide the Panel to offer recommendations to the Minister of Energy. We were pleased with the frank and wide-ranging discussion we had with the Panel at our initial meeting and are confident that it will interpret its mandate widely. In developing this submission, we have been guided by the belief that the efficiency of a given LDC must be balanced with its effectiveness, its service to its customers, as well as its contributions to the overall energy system and the community that is serves. Page 20of35 () area of electricity? Indeed, if anything, LDCs should be protected as they are looking after the best interests of their community instead of strictly adhering to the bottom line. We are also unconvinced of the benefits of LDC consolidation given a review of past experiences in this area "indicates that few real welfare gains have emerged from the costly effort by the Ontario Government and the Regulator to reduce the number of distribution utilities in the Province.'ra Given that the Panel is focused on seeking out all sorts of possible efficiencies beyond just merely conventional consolidation approaches, it is worthwhile to point out the benefrts of shared services at this point. Shared Services Since the Panel has been tasked with conducting an analysis of the current system to determine what financial advantages and savings could be realized, we believe it is worthwhile briefly pointing out current examples of successful coordinated procurement and administration between and amongst LDCs. A quick scan of the current LDC () environment reveals that several initiatives are underway, sometime involving groups of up to 48 LDCs in the following areas: (__) • billing services shared by multiple electricity distributors • billing services shared by various services (e.g., electricity, water and sewage) • joint development of ESA standards • shared services based on meter technology • joint procurement of products and services • shared services arrangements for regulatory filings • sharing 'locates' services • delivery of CDM programs • collaboration and aid during natural disasters. 8 Frank Cronin and Stephen Motluk, "How Effective are M&As in Distribution? Evaluating the Government's Policy of Using Mergers and Amalgamations to Drive Efficiencies into Ontario's LDCs," The Electricity Jouma/2007, 60-68. Page 18of35 0 Municipal governments must be invited to participate in the planning of smart grid infrastructure. Current system planning is also inefficient because the existing regulatory environment prevents electric and gas utilities from working together on synergistic projects. The OPA is only interested in reducing electricity demand and the primary regulator and other agencies have swung the pendulum too far towards excessive rules at the expense of people who actually get things done. Energy planning and programming must be holistic and one that all includes types of fuel sources and all supply options with a priority on conservation. The Ministry of Energy must build upon the L TEP to produce a true energy plan that is based on all forms of energy and not just electricity. AMO supports moving to more integrated, longer term planning that eliminates the inefficient wall between electricity, natural gas and other sources of energy. A growing number of Ontario municipalities have also decided to implement district energy (DE) systems to meet their thermal (~) energy needs and environmental goals. DE systems, especially Combined Heat and Power facilities, are very efficient because they utilize multiple energy sources, including what are often waste products. District energy systems currently exist in Cornwall, Hamilton, London, Markham, Ottawa, Sudbury and Toronto and could be established in many additional communities across Ontario if investors can accept long pay-back periods. LDCs and gas utilities not only have experience with the technologies involved, but are also more willing to accept long pay-back periods than most private lenders. Unfortunately, the current regulatory framework focuses on conventional energy forms and systems. ( ) \ __ The Ontario Energy Board Act should be amended to allow LDCs and gas utilities to expand their mandates to become rate-regulated electricity and district energy utilities and rate-regulated natural gas and district energy utilities. Page 16 of35 () \ ___ ) welcome development if the OEB can obtain the objective identified in the letter-" an improved and streamlined regulatory process that leverages regulatory best practices and is tailored to the Board's legislative requirements and operating environment"-and does not merely tinker around the edges of its currently overly labourious, time consuming and costly process. Another way to enhance the efficiencies of LDCs is to enable them to expand the scope of their business. To fully realize the business opportunities that will bring value to customers and shareholders alike, LDCs need a regulatory model that builds efficiencies for utilities. The regulatory model should shift from focusing on LDC ability to deliver traditional services to customers to one that provides electricity distributors the flexibility and freedom to effectively expand these services to support and empower customers to manage their electricity consumption through conservation and renewable energy programs. Currently, many LDCs have very entrepreneurial and innovative business offerings in their unregulated affiliate companies. They have evolved from the old "poles and wires" PUC model into an integrated energy company that offers many different services to not only customers in their service area but to other areas in the Province and sometimes to the U.S. and overseas markets. The numerous regulatory restrictions on the main holding companies prevent them from moving into areas where natural synergies may exist. Further, the expense of establishing an affiliate is another obstacle to some LDCs from expanding their operations. LDCs should be allowed to provide street lighting maintenance and other services in a competitive market with other providers. The Ontario Energy Board (OEB) should enable increased flexibility in internal firm structure and operation AMO has been pushing for a regulatory remedy to deem streetlight maintenance as a permissible LDC activity under section 71 of the DEB Act since 2010. Allowing LDCs to conduct street lighting services to their municipalities will give municipalities the choice to use their own LDC for street lighting services or consider other options. Presently, that choice does not exist. We believe this regulatory change will provide legislative and regulatory clarity, promote public safety, and increase cost effectiveness for municipal shareholders and ratepayers alike. Page 10of35 () Transmission or Distribution? Northwestern Ontario Needs an Infrastructure Upgrade to Tap Into a Better Economic Future The transmission in the Northwest Region (apart from the 230 kV line that at this point serves primarily as a conduit line running between the Manitoba boarder and points east of Wawa) takes place typically at 115kV delivering power to step-down transformers of customers. • It is essential to appreciate that the transmission system in place covers only the lower one third of the land mass of the Northwest Region. • The remaining two thirds of the land mass of the Northwest Region have no access to power supplied by transmission. It is also essential to appreciate the lack of security in the transmission system that does exist in the Northwest Region. The 115kV lines are virtually all long radial circuits running extensive distances of between 200 km and 500 km through remote areas of Crown Land. Permanent fauHs in these transmission lines result, several times a year, in blackouts that are often measured in days rather than hours. Moreover, transmission line management during electrical storms requires the temporary suppression of transmission in the locality of a storm. The absence of two line supply throughout most of the Northwest Region, outside the City of Thunder Bay, leaves industrial customers and LDCs of smaller communities with little security in power supply. There are several power lines in the Northwest that are classified as distribution lines in terms of voltage but are much longer than many classified as transmission lines elsewhere in the Province. These radial lines are vulnerable to weather, natural disasters and even traffic accidents. Permanent faults in these distribution lines result, several times a year, in blackouts that are often measured in days rather than hours. Many local leaders feel that local LDCs could be more responsive than Hydro One in servicing these areas. As the Northwest is on the threshold of massive investments in mining, requiring significant construction and operation of infrastructure -from roads to telecommunications, to rail to electrical transmission or distribution. This is at the same time as two-thirds of the region's land mass has no transmission infrastructure and remote First Nations must rely on expensive and dirty diesel generation. These people are citizens of Ontario and should have the same access to electricity as do all other citizens and should not be asked to bear a higher cost to make those connections. Page 14of35 () of the directives, an OEB-approved plan and details on the L TEP assumptions points to the continuing lack of transparency. AMO agrees with the Environmental Commissioner of Ontario that "a more nimble approach with attention to localized load growth and closer alignment of conservation targets with annual results and demand growth would better serve the Province".4 A better approach is needed for system planning to allow electric utilities to figure out how to best connect significant amounts of renewable energy generation at the distribution level and to allow gas utilities to plan for district energy plants or better yet to allow both to participate in truly integrated community energy system planning. The current regional planning approach "entails joint planning between distributors and transmitters in relation to distributor connections to the transmission system (to) share information regarding distributor connection issues, and identify optimal connection solutions among alternatives involving transmission and distribution investments. "5 The OEB paper also states that regional planning may facilitate the "desirable outcome" of integrating land use planning and electricity infrastructure planning exercises, whereas the OPA admits that "while there are some () commonalities across regions, each is unique in terms of its electricity requirements, anticipated growth, economic development potential, age and configuration of existing infrastructure, resource and demand management opportunities and community acceptance of proposed solutions."6 Despite the desired outcome of finally integrating land use and energy planning and the realization that each region has unique circumstances, and the goal of aligning with local initiatives such as Community Energy Plans, Official Plans and other municipal planning considerations, municipal governments have not been invited to participate in this exercise. 4 Environmental Commissioner of Ontario, Restoring Balance: A Review of the First Three Years of the Green Energy Act. Annual Energy Conservation Progress Report -Volume One: Toronto, 2011. 5 Ontario Energy Board, Discussion Paper: Regulatory Framework for Regional Planning for Electricity Infrastructure (EB-2011-0043) Toronto: 2011. 6 Ontario Power Authority, The OPA's Regional Planning Process, Toronto: February 2012. Page 12of35 \ () (_) 300 35 $ 3 250 30 200 1ft 25 u 9 -~ 150 'CI)o j en E t: = 20 .2 2 ~ 100 II: 8 en Cll Ill 15 c Cll so s:a. iiC 11.1 a:l 11.1 0 0 10 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 -+-Number of LDCs (Left axis) ~OEB Expenditures $, Million (Right axis) A more efficient and cost-effective regulatory framework that achieves provincial policy objectives is possible. The costs of regulation must be balanced with the benefrts to customers and the amount of regulation should be proportionate to the intended policy outcome. As shareholders of local distribution companies (LDCs) municipal governments have also been indirectly burdened by interveners driving up compliance costs-often in rate applications where individual interveners have no actual members or where their members are completely unaware of their intervention. The intervener process, which appears to benefit a cadre of energy lawyers instead of ratepayers, is a good place to start. Page 8 of35 () energy market is used to dispatch generation efficiently and to produce price signals that coordinate the actions of the many diverse participants. Central procurement and regulated prices are used to ensure that key government energy policy objectives are achieved. As a result of these swings in policy direction, we are now left with a confused marketplace governed by a veritable alphabet soup of regulators and other agencies including Hydro One, Ontario Power Generation (OPG), Ontario Power Authority (OPA), Independent Electricity System Operator (IESO), Electrical Safety Authority (ESA), Ontario Electricity Financial Corporation (OEFC), and the Ontario Energy Board (OEB). While the current Bi/175 An Act to amend the Electricity Act, 1998 to amalgamate the Independent Electricity System Operator and the Ontario Power Authority is a good start in terms of reducing the number of agencies involved in the sector much more needs to be done to streamline the current regulatory process. There is overlap in the various functions of Ontario's energy agencies. The OPA, Ministry of Energy, and the IESO all do some form of power system planning; the OPA, Infrastructure Ontario, and the Ontario Electricity Financing Corporation (OEFC) all procure generation projects and/or manage procurement contracts; and the OPA, IESO and OEB either administer or regulate different conservation programs. Streamlining these agencies' mandates by removing duplication and creating an easier-to-navigate system can result in cost savings and better outcomes for all market participants. More also needs to be done to educate the public about the important decisions facing utilities and other power system planners. AMO agrees with the Drummond Report in this area: The Province must coordinate a comprehensive, proactive electricity education strategy across sector participants that at a minimum covers generation, imports/exports, what drives electricity prices, the roles and responsibilities of the various entities operating in the electricity sector; and the evolving role of the electricity ratepayer in the smart grid paradigm. Page 6of35 () "-_- procurement, co-ordinated administration, and/or re-assessment of service area boundaries, as well as any combination of solutions". AMO continues to apply a triple bottom line approach to its analysis of pertinent policy issues. In its broadest sense, the triple bottom line concept captures the spectrum of values that organizations must embrace-economic, environmental and social. Triple bottom line means expanding the traditional working framework to use financial outcomes as well as environmental and social performance to resu~ in decisions that will: • Lead to greater physical, cultural and financial access and equity in service delivery and activities • Use fewer natural resources • Promote and maintain economic development and growth in a sustainable manner. The triple bottom line is ideally suited to energy policy analysis since energy policy is about ensuring that our environment can support our society, economy and way of life not just now, but well into the future. This same triple bottom line approach guides our response to the Panel's search for efficiencies in the energy sector. AMO realizes that to the outside observer the 78 LDCs of various sizes appears to be inefficient. There are also a number of new pressures facing LDCs including: financing challenges for building or refurbishing old distribution infrastructure; increased customer demands; new products and services such as Smart Meters, Electric Vehicles and the Smart Grid. All of these pressures require increased capacity and greater access to private equity capital. Municipal governments, especially those that govern single-industry towns, are very well aware that reliable and affordable energy is essential for attracting business and investment to our Province. We too are struggling with fewer resources and are doing our utmost to find as many efficiencies as possible. AMO offers this submission to the Panel to help it make the best recommendations possible not just for municipal ~._ _ _) governments, but for energy ratepayers and all Ontario citizens. Page 4of35 ' n Table of Contents Introduction 3 Govemance and Regulatory Reform 5 System Planning 11 Consolidation 17 Shared Services 18 Principles to Guide Consolidation 20 Conservation 26 CDM Should be the First Priority 28 The CuTTent System is Broken 28 A New Conservation Framework is Required 30 The Role of the Municipal Sector 33 Conclusion 35 r-~) \__~ Page 2 of35 C) Attachment 45 () \ ___ ) ') 0 Attachment 44 .. . . ., \ 0 formats from different utilities. Furthermore, the recent increases in the global adjustment mechanism (GAM) have often meant that customers are paying more money for less energy, at a time when the hourly price is quite low. The Province should reform energy pricing policy to ensure bills clearly reward behaviour that yields an absolute reduction in energy demand. The Role of the Municipal Sector Municipal electrical consumption accounts for more than 4% of the total provincial consumption. The municipal sector is a very significant component of the broader public sector as municipalities consume well over 6.6 billion kilowatt-hours per year (or 6.6 terawatt-hours). In terms of costs, the sector spends over $1 billion a year on energy (including over $700 million on electricity) and energy costs are general between the third to fifth largest item in the annual budget of a municipality (where it is tracked as such). IESO/AMO Research indicates that the sector has the potential to reduce its consumption from 12% to 15% using a combination of energy efficiency measures and demand response activities. The municipal sector is doing its part to reduce energy consumption through energy efficiency projects and energy planning and will continue to do so as it grapples with multiple competing demands on its revenue. Energy conservation plans are good public policy because they help municipalities reduce costs and environmental impacts while enhancing existing asset management initiatives. The planning requirement under the Energy Conservation and Demand Management Plans Regulation (397/11) of the Green Energy Act will help municipalities gain better control of their energy consumption, but the plan and its implementation requires investments. AMO's subsidiary, LAS, is working to develop a number of support programs to assist those that lack the internal capacity to move forward with this important work. LAS delivers programs and services to 320 municipalities and 20 broader public sector entities (primarily school boards) including a number of valuable programs and products designed to help municipalities save money, energy and the natural environment \ ___ ) through our Energy Services Division. Page 33of35 n .. / It enhances municipal autonomy and is synergetic with other provincial policy objectives, including local job creation and energy conservation. The amendments to the regulation will be of benefit to municipalities that are currently interested in energy efficiency and renewable energy projects. Conclusion Ontario's energy system is becoming and must continue to become cleaner, more responsive and more efficient. Past periods of great risk have prompted Ontario to mobilize its wealth, skills, leadership, natural resources and entrepreneurial spirit to overcome great challenges. Time and again, we have emerged from crises better and stronger. Ontario has before it an historic opportunity to make and incent strategic investments in key infrastructure projects and new technologies to revolutionize our rather archaic and cumbersome energy system to place the province at the forefront of the new, greener economy. AMO has set out a number of recommendations in this paper based on the belief that the efficiency of a given LDC must be balanced with its effectiveness, as well as its contributions to the overall energy system and the community that is serves. This guiding principle, our collective experience, and an examination of data available to us led to the conclusions that: (1) regulatory and governance reform would yield far greater savings than mere consolidation, (2) efficiency gains from merging municipal LDCs are dwarfed by the potential that exists within Hydro One, and (3) that any consolidation that occurs must be voluntary and driven by business principles. AMO believes that if we stick to these guiding principles we can capitalize on the synchronicity between sound energy system planning and economic health to tap the productivity of our people, invest wisely, and restore Ontario's technological leadership. Page 35 of35 Updated February 27,2014 EB-2013-0196/ 0187 I 0198 EVIDENCE OF PAULA ZARNETT ON BEHALF OF ESSEX POWERLINES CORPORATION, BLUEWATER POWER DISTRIBUTION CORPORATION, AND NIAGARA-ON-THE-LAKE HYDRO In the Matter of Application by Hydro One Inc. EB-2013-0196 Application by Norfolk Power Inc. EB-2013-0187 Application by Hvdro One Networks Inc. EB-2013-0198 Before the Ontario Energy Board February 26, 2013 BDR 34 King Street East Suite 1000 Toronto, ON M5C 2X8 416-214-4848 phone 416-214-1643/ax , __ ) i ) EXECUfiVE SUMMARY Introduction and Scope Evidence of Paula Zamett on behalf ofEBN EB-2013-0196, EB-2013-0187, EB-2013-0198 Before the Ontario Energy Board February 26, 2014 I Updated February 27, 2014 Page2 If the Board approves the applications in the proceeding, HONI will acquire NPDI and partially integrate it with the operation ofHONI. NPDI customers will receive the benefit of a 1% reduction relative to 2012 base electricity rates, which reduced rates, if approved, will remain frozen in effect for five years. As with all similar applications, the Board must be satisfied that no harm results to customers in terms of the factors identified in the Board's objectives. EBN has intervened, and requested BDR to: ) Review evidence as to cost structures to detennine whether they are likely to increase or decrease as a result of the intended transaction; ) To comment on non-fmanciaJ impacts, such as quaJity of service; and ) To consider and comment on whether the purchase price is set at a level that would create a financial burden on the acquiring utility; and ) To develop and present a possible scenario for estimation of the impacts of harmonization of rates, once the proposed rate freeze period expires. To carry out the assignment, BDR has reviewed the evidence filed in this proceeding and other information in the public domain, evaluated that evidence and drawn conclusions based on its experience in the electricity sector and in the capital markets sector. In reviewing the information, BDR considered whether it was internally consistent, and aJso whether it was consistent with other information available to BDR about business in the electricity sector in Ontario. Conclusions Operating and Capital Expenditure Costs With regard to operations and capitaJ, it is BDR's conclusion that the Applicants have not demonstrated any changes likely to produce reductions in operations direct staffing, vehicles, or facility costs that flow from the transaction. Furthermore, the 2012 Statistical Yearbook shows that average OM&A per customer for HONI was $439.77 per customer as compared with $333.43 per customer for . NPDI. In HONI's response to EBN Interrogatory 13, they claim that the appropriate comparative figure is lower because only costs allocated to urban and medium density customers should be considered, and go further to say that on average, there will be lower costs than HONI's average to serve NPDI's southern Ontario distribution territory. No analysis has been provided to support this statement, and it is noted that HONI has not provided information as to which of its density classes are appropriate to NPDI customers. There is thus no evidence that HONI can achieve a lower ( ) Evidence of Paula Zamett on behalf ofEBN EB-2013-01%, EB-2013-0187, EB-2013-0198 Before the Ontario Energy Board February 26,2014/ Updated February 27, 2014 Page4 Based on information found in the public domain, it appears that financing rates through Infrastructure Ontario are below the rates that HONI has recently obtained, for loans of similar term. Therefore, by removing accessibility to a less costly source of debt, the transaction increases the cost structure ofNPDI and creates a harm to the customers. Furthermore, even ifHONI can provide funding at a reduced cost, it has not made any commitment that it will assume and re-finance NPDI's debt in order to do so. BDR concludes that the Applicants have not supported their claim that lower costs of debt are a certain benefit of the transaction, both because NPDI can and has already obtained cost effective debt capital from Infrastructure Ontario, and because there has been no commitment that Hydro One will refinance the higher~ cost debt assumed in the transaction. Even if Hydro One,s costs of capital could be shown to be significantly lower today (for which there is no evidence), there is no evidence that this will continue into the future, when its cost of capital may be impacted both by increasing demands for bo"owing to fund infrastructure and by the effects of having bo"owed to fund the premiums of acquisition which may or may not be repaid to the shareholder through cost efficiencies. Non~ financial impacts on customers, such as quality of service With regard to Service Quality, BDR has concluded that information from public sources provides a basis for concern that NPDI customers may experience a decline in levels of service with HONL This information has not been countered by evidence from the Applicants. Based on the Service Quality Indicators (SQis) reported by HONI In the 2012 Statistical Yearbook, the overall standard of service by HONI for reliability and emergency response is lower than the standard of service of NPDL There is no evidence that HONI plans to maintain the historic local service levels in its service to NPDI customers. If HONI allows the level of service to deteriorate to the levels that it maintains for its legacy customers, the NPDI customers wiU be harmed by the transaction. Creation of a financial burden on the acquiring utility The premium that Hydro One proposes to pay for NPDI is significantly higher than the levels at which LDCs were able to achieve transactions historically. As indicated, there is cause to be concerned that the additional premium will not be recovered for the shareholder through savings gained before the rates are rebased. Hydro One is proposing to extend its credit for acquisitions at the same time that significant funds are needed for investment in the distribution and transmission systems. The Applicants have not provided any information to show that the excess premiums ( ) 1 Evidence of Paula Zarnett on behalf ofEBN EB-2013-01%, EB-2013..0187, EB-2013-0198 Before the Ontario Energy Board February 26, 2014 I Updated February 27,2014 Page6 INTRODUCTION AND PuRPoSE OF THE REPOR'I' This evidence is being filed with the Ontario Energy Board ("OEB" or "Board") on behalf of Essex Powerlines Corporation, Bluewater Power Distribution Corporation, and Niagara-on-the-Lake Hydro (together "EBN'') in the matter of applications filed by Hydro One Networks Inc. ("HONf') and Norfolk Power Distribution Inc. (''NPDI"), both licensed electricity distributors, and Hydro One Inc. (''Hydro One"), HONI's parent company (together the "Applicants"), on April26, 2013 and subsequently amended. The applications, as clarified by the Applicants in January, 2014 and set out by the Board at page 2 of its Decision and Order and Procedural Order No. 8 dated January 24,2014, are as follows: "1. an application by Hydro One for leave to purchase all of the issued and outstanding shares ofNorfolk Power Inc. under section 86(2)(b) of the Act; 2. an application by NPDI seeking to include a rate rider in the 2013 Ontario Energy Board approved rate schedule ofNPDI to give effect to a 1% reduction relative to 2012 base electricity delivery rates (exclusive of rate riders) under section 78 of the Act; 3. an application by NPDI for leave to transfer its distribution system to HONI under section 86(1)(a) ofthe Act; and 4. an application by NPDI for leave to transfer/assign its electricity distribution licence and rate order to HONI under section 18 of the Act." EBN has intervened in these applications, stating as its concern that the "no harm" test has not been satisfied, and, along with other parties, submitted interrogatories intended to compel disclosure from the Applicants of additional information regarding impact of the transaction on consumer rates and impact of the purchase price on consumers, and on the efficiency and cost-competitiveness of the industry as a whole. The Board, in its January 24,2014 Decision and Order and Procedural Order No.8, at pages 4, 5 and 6, defmed its interest in the information to be provided as follows: ''Therefore, in applying the ''no harm" test, it is appropriate for the Board to assess the cost structures which will be introduced as a result of the transfer ofNPDI's distribution system and associated licence to HONI in comparison to the cost structures underpin NPDI's current rates. A downward impact on the entities' cost structures would tend to decrease rates, whereas an upward impact on the entities' cost structures would tend to increase rates. This will occur regardless of whether rate harmonization is ultimately sought. I () \__j ( ) Evidence of Paula Zamett on behalf ofEBN EB-2013-0196, EB-2013-0187, EB-2013-0198 Before the Ontario Energy Board February 26, 2014/UpdatedFebruary 27,2014 Page8 The report therefore consists of three parts. In section 2, information as to cost structures is reviewed. In section 3, the issue of fmancing and the competitive market for LDC mergers and acquisitions is addressed, with a view to drawing conclusions about the potential financial burden on the proposed acquirer in this transaction and in transactions that may be expected to follow. In section 4, a computation is presented to estimate the impacts on the bills ofNPDI customers what would result from harmonization with HONI rates, once the proposed five-year freeze at reduced rates bas expired. 2 CosT STRUCTURES OF HONI AND NPDI 2.1 Conceptual Overview This portion of the analysis is intended to draw on filed and other public information in order assess whether such information supports a conclusion as to whether aggregate future cost structures ofHONI and NPDI will increase or decrease as a result of the proposed transaction. For clarity, it is BDR's view that only changes that result from the proposed transaction should be considered in the "no harm" test. For example, if certain cost efficiencies that are planned following the transaction would otherwise have been achieved or achievable by the acquired LDC on a stand-alone basis (i.e. if no transaction takes place), then these should not be considered as net benefits of the transaction. Furthermore, it is possible, depending on the circumstances of an individual LDC, that existing arrangements creating synergies or cost efficiencies before the transaction will be lost as a result of the transaction. For example, if an LDC shares resources with its municipal shareholder (for example, shared billing of electricity and water), and thereby reduces costs to the electricity ratepayer, these reductions may be lost when the LDC is acquired and transitions to the billing system of the acquiring LDC. Similarly, benefits of synergies with affiliates or through joint action consortia may be lost. If this is the case, then in our view it is the net effect that should be considered. While the evidence filed by the Applicants in this case points from time to time to the conclusions of the Sector Review Panel to the effect that productivity gains are generally expected from LDC consolidation 1, it is not necessarily true that a specific proposed merger or acquisition will produce cost efficiencies or produce them in any specific timeframe. Therefore each specific transaction proposal should, in our view, be assessed on its individual merits and not accepted merely because there is a general consensus in favour of consolidation. Since only the Applicants have access to the detailed internal information and plans that should be gathered and developed in connection with the proposed transaction, 1 For example, in Exhibit I Tab 5 Schedule 20 Page 1 of2 / ) Evidence ofPaula Zarnett on behalf ofEBN EB-2013-0196, EB-2013-0187, EB-2013-0198 Before the Ontario Energy Board February 26,2014 I Updated February 27, 2014 Page 10 the PEG methodology evaluates distributor efficiency by comparing actual cost results with the results predicted by the model. The analysis ranked NPDI 31st of 73 Ontario LDCs, with a value of -4.8%, where negative values indicate a level of cost below the predicted value (i.e. relatively more efficient). While any LDC can theoretically become more efficient, and the regulatory regime is structured to provide incentive for them to do so, by this measure NPDI is a relatively efficient LDC, when its business conditions, especially its relatively low density customer distribution and large rural service territory, are taken into account. We can therefore assume that very significant reductions in the cost of service to NPDI, if they can be achieved, must come from specifically identified changes in the way business would be carried on following the acquisition. We have therefore reviewed the evidence and considered whether a specific cost reduction plan has been identified, and if so, whether the elements appear to be (a) internally consistent; and (b) consistent with what experienced industry professionals understand as the typical manner in which Ontario LDCs do business. 2.3 Applicants' Evidence as to Specific Benefits Available from the Transaction For the convenience of the Board and all parties, these comments are organized consistent with the Applicants' high-level categorization of savings opportunities, as set out in Exhibit I Tab 2 Schedule 2. 2.3.1 Local.Atea Operating and Capital Savings Resulting from a More Efficient Distribution System due to the Elimination of an Artificial Electrical Border (i.e. Benefits from Contiguity) In setting out how they expect efficiencies to be achieved from contiguity, the Applicants say: Specific to NPDI, Hydro One has an operating centre located less than 2 km from the NPDI operating centre. Hydro One crews travel the same roads and drive by the same facilities as the existing line crews from NPDL Every day staff in the Hydro One Field Business Centre in Dundas answer calls from local businesses and customers for operational services within the area of Norfolk County served by Hydro One. NPDI has customer service representatives that carry out similar functions for their neighbouring customers within Norfolk County. Rationalizing these functions over a larger service area will yield efficiency savings. "5 This statement conveys the impression that redundancies in the resources for field activities (bases of operation, number of staff, vehicles and equipment) will be a source of significant cost reductions following the proposed transaction. However, the transaction will not reduce the major cost drivers, which are number of customers, 5 Exhibit I Tab 2 Schedule 2 Page 5 of 8 ) Evidence ofPaula Zamett on behalf ofEBN EB-2013-0196, EB-2013-0187, EB-2013-0198 Before the Ontario Energy Board February26, 2014/UpdatedFebruary27, 2014 Page 12 is proposing capital spending reductions in the range of$1.5 to $2 million annually). In the October 25, 2013, the Applicants refused to answer as to the amount of capital spending in NPDI, as the rates would be lowered and frozen 7• As a result, the scenarios are the only information provided by the Applicants as to the proposed differences in capital expenditures that they are claiming as benefits of the transaction, despite the efforts of EBN to obtain further information through interrogatories. No asset condition assessment or other detailed review has been provided to satisfy the Board and parties that the planned level of capital spending is adequate to maintain the quality of service to consumers. In the absence of any explanation from the Applicants, BDR considered the possible reasons why HONI's forecast of capital expenditure might be lower than the capital expenditure plan ofNPDI's management. One possible reason is that HONI expects it can deliver the same capital programs planned by NPDI while incurring significantly lower costs. However, HONI has not offered this as an explanation, or provided any evidence that HONI is a more cost efficient constructor than NPDI. The other possible explanation for the lower HONI capital expenditure scenarios is that HONI plans to postpone or cancel specific projects that NPDI had planned to implement. Any management can postpone or cancel a capital project, and NPDI's management could, on a stand-alone basis, have reduced its capital program if they were prepared to live with any consequences in terms of reliability or future costs. Therefore in our view, a reduced capital program is not a cost saving related to the transaction, unless it can be shown that the transaction offered an alternative that would achieve the required result at lower cost. No evidence has been filed to show that the capital expenditure reductions reflect the achievement of system improvements as a direct result of the transaction. If the capital expenditure reductions are in fact not related to either of these possible explanations, then the situation is simply that HONI has a different opinion of the necessary level of capital level expenditures than NPDI's management No evidence has been provided as to the review process that HONI carried out to determine the needed level of capital expenditures, or which if any specific projects can prudently be cancelled or postponed. If the capital project being postponed or cancelled are in fact necessary projects, this may result in negative effects on customers, including reduction in reliability and/or higher costs in the future, and cost reductions could not be considered as a saving or benefit. HONI has not offered any proof that the reduced capital expenditure program constitutes a "saving" (i.e. that it meets the needs of customers for reliable supply at a reduced cost). Until rates are rebased, a reduction in capital expenditures from planned levels provides no benefit to customers, while resulting reductions in service quality or future cost increases resulting from deferral of needed projects can create harm to customers. 7 Exhibit I Tab 5 Schedule 2. ( ) Evidence of Paula Zarnett on behalf ofEBN EB-2013-0196, EB-2013-0187, EB-2013-0198 Before the Ontario Energy Board February26, 2014/UpdatedFebruary 27,2014 Page 14 We then reviewed the evidence to fmd more specific examples of functions where it is not apparent that the level of work needed to manage, plan and operate what is now NPDI would diminish, at least in the first several years following the transaction. Function Reference and Conclusion CDM At Exhibit I, Tab 1, Schedule 6, the Applicants state that CDM targets for NPDI "will remain separate". While some implementation cost savings should reasonably be expected to be realized, assuming that the activities can be fully integrated with those ofHONI, this approach will result in continued separate costs related to administration, monitoring and verification, and compliance reporting related to CDM. Corporate costs It has not been stated by the Applicants that following the transaction, HONI would plan to wind up NPDI as a corporation. In that case, there would be continued costs for all corporate compliance filings, financial statement preparation, independent audits, tax returns, etc. 'Ihe Applicants state that there would be a reduction of$70,000 in costs now incurred to maintain NPDI's board of directors, but have not stated how requirements for independent directors would continue to be met at no cost. Accounting and As long as NPDI continues to exist separately, it would require Service Level separate accounts. If the intent is to administer and manage Agreements NPDI, and to provide professional services to it with HONI staff (as we understand from Exhibit I, Tab 2, Schedule 2) the provisions of the Affiliate Relationships Code ("ARC") would require service level agreements to be prepared and administered, and, in the case of "shared corporate services" as defined by the ARC, charges to be made by HONI to NPDI on the basis of fully allocated cost, determined by a reasonable method. This involves, if not an incremental level of effort from current accounting and administrative functions, at least a significant level of effort into the future. The evidence indicates that NPDI costs will continue to be tracked separately from HONI's "legacy'' accounts; that a separate sub-account will be created to track LRAM, and that USGAAP will be adopted. Taxation The evidence at Exhibit I, Tab 3, Schedule 16 suggests that a small business tax credit valued at $33,000 would be lost on acquisition by HONI. System Planning There is no explicit evidence stating how the work of system and Design, planning and design, development of maintenance plans, etc. Management of would be carried out within HONI at the same staffmg levels that System are adequate in the status quo case. Section 2.2 above quotes r· \ J Compliance Evidence of Paula Zamett on behalf ofEBN EB-2013-0196, EB-2013-0187, EB-2013-0198 Before the Ontario Energy Board February 26, 2014 I Updated February 27, 2014 PaTEe 16 there will be a saving in the normal costs that an LDC incurs to prepare, ftle, support and implement the results of its annual rate changes under an IR.M regime. However there would be a continuing need for approval of rate riders and other adjustments, which would entail filings with the Board. We have not found in the evidence any reference to the effort required for on-going compliance requirements, such as the filing of RRR data, audits, etc., but in our view it is reasonable to assume that there would be such costs, and that they would be incremental to HONI's status-quo resource requirements. Based on the foregoing analysis, which is general and qualitative given the absence of detailed evidence as to the costs involved and the plans to address them, BDR has drawn the conclusion that the Applicants' savings estimate is overstated, and that such benefits which may be achievable would not be achieved immediately. Furthermore, if HONI is in fact able to eliminate 30 positions within NPDI, while maintaining its own level ofFTEs at levels determined for its legacy service territory and customers, it suggests that HONI's resources are above the efficient levels to serve the legacy service territory and customers. It is noted that HONI appears to be pursuing other LDC acquisitions. Therefore, even ifNPDI, an LDC of 19,000 customers, could be operated by HONI without complement additions, this could not be true for an indefinite number of additional acquisitions. If another LDC is acquired, and results in additions of staff in HONI, both of the acquired LDCs must be considered to be incremental in the economic sense, and contribute to the need for staff, since HONI could alternatively have acquired the other LDC first, and then NPDI, resulting in the acquisition ofNPDI being the trigger for staff additions. 2.3.3 Savings due to lower financing costs HONI claims in its evidence that an important benefit to be realized by the acquisition is the more competitive financing costs that it and its parent can obtain from the capital markets by virtue of size, as compared with small LDCs. However, no specific facts or analysis has been presented to substantiate: (a) that similar levels of interest rates to those available to HONI would not be available to an LDC, and that NPDI has not obtained capital for similar terms at similar rates; (b) that if the transaction takes place, NPDI would in fact receive the benefit of any reductions in fmancing costs; or \ ) ( Evidence ofPaula Zarnett on behalf ofEBN EB-2013-0196, EB-2013-0187, EB-2013-0198 Before the Ontario Energy Board February 26, 2014/ Updated February 27, 2014 Page 18 BDR concludes that the Applicants have not supported their claim that lower costs of debt are a certain benefit of the transaction, both because NPDI can and has already obtained cost effective debt capital from Infrastructure Ontario, and because there has been no commitment that Hydro One wiU refinance the higher- cost debt assumed in the transaction. Even if Hydro One's costs of capital could be shown to be signifreantly lower today (which has in fact not been demonstrated), there is no evidence that this wiU continue into the future, when its cost of capital may be impacted both by increasing demands for bo"owing to fund infrastructure and by the effects of having bo"owed to fund the premiums of acquisition which may or may not be repaid to the shareholder through cost efficiencies. 2.4 Service Quality The applicants have not provided any specific evidence as to how and to what extent there will be an impact on the service quality to NPDI customers following the transaction, except that they say at Exhibit I Tab 2 Schedule 2 Page 4 of 8 that HONI will be able to provide extended hours of call centre service and a smart phone application for real time updates on outage restoration. However, there is no evidence offered that extended call centre hours would be a sufficient service improvement if customers are not satisfied with the timing and accuracy of their bills or the method of handling payments. According to the attached media articles dated February 4, 2014, the Ontario Ombudsman is investigating complaints from HONI customers about delayed bills, incorrect bills, estimated bills, huge and unexpected withdrawals from their bank accounts, and difficulty addressing these issues through HONI's call centre. These indications that NPDI customers may experience lower levels of service with HONI are of additional concern given HONI's evidence that it will not be adding to current staff complement in order to render timely and accurate bills to 19,000 customers, to resolve any errors that occur, and to talk to these customers on the telephone. Nor is there any evidence that customers would be satisfied with updates on their smart phones if there is a deterioration in time taken to restore service, or an increase in the number of outages. HONI has not presented evidence that it can meet the standards of restoration that NPDI customers are accustomed to, or that it will maintain the standards of reliability (SAIDI, SAIFI, CAIDI) that now prevail in NPDI's service territory. The Unit SQR tab of the Board's 2012 Electricity Yearbook 10 reports that NPDI in 2012 responded to emergencies in its rural areas within the required two hours 100% 10 Obtained in MS Excel form from the Board's website as 2012 _Electricity_ Yearbook_ excel.xls Evidence of Paula Zamett on behalf ofEBN EB·2013·0196, EB·2013·0187, EB·2013.0198 Before the Ontario Energy Board February 26,2014 I Updated February 27,2014 Page20 3 THE ONTARio LDC M&A "MARKET" 3.1 Issue Context A key factor in the assessment of the purchase prices in corporate acquisition transactions paid is the premium over overall book value (which approximates Rate Base). Purchase prices in excess of overall approved rate base are costs for the shareholder account as the Board does not permit such costs to be included in utility Revenue Requirements at any time (including cost of service applications at re-basing periods). The costs therefore cannot be passed directly to consumers through regulated rates, and it is therefore investors who take the risk associated with recovery of premiums through savings realized during the period allowed before such savings are re-allocated to customers through the rebasing process. Nonetheless, if excessive borrowing lowers the credit status ofLDC owners and thus raises the cost of borrowing, this will be a negative impact to ratepayers as long as the Board approves third party "market" interest in the revenue requirement. Furthermore, the Board has a mandate to assure a financially viable industry, able to obtain resources to develop and sustain sector infrastructure at reasonable cost. If premiums paid for acquisitions cannot be recovered in reasonable timeframes through savings, the credit of the industry as a whole may suffer. It is also, in our view, important to note that the Board's regulatory provisions, which put shareholders at risk for the cost of premiums on acquisition, protect the public effectively in the context investor-owned utilities whose equity is provided by private capital. Hydro One and the municipal utilities of Ontario are public sector entities, meaning that taxpayers and municipal ratepayers are at risk if Hydro One or municipal utilities make excessive or imprudent investments in acquisitions. If Hydro One continues a practice of offering high premiums for acquisition, municipal utilities may choose to compete with high offers of their own and thereby create difficulties for their shareholders and customers through reductions in financing capability for rate base investment and/or higher interest costs. 3.2 History of Recent Transactions and Premiums The Ontario Merger and Acquisition market for distribution companies in its ''modem" form (following the re-structuring of the electricity industry over the 1998/1999 period) began with the acquisition by Hydro One of some 88 local distribution companies in the first phase which ended at the end of2001 (with the implementation of the PILS regime). The Table below is representative of transactions in which government owned utilities purchased 100% interests in LDC's. It indicates that the average premium \ ~ .. _) / ) Evidence of Paula Zamett on behalf ofEBN EB-2013-0196, EB-2013-0187, EB-2013-0198 Before the Ontario Energy Board February 26, 2014/UpdatedFebruary 27,2014 Page22 The comparable figures for the acquisition ofNPDI by Hydro One are 1.63 for the ratio of Enterprise price to book value, and 2.50 for the ratio of Equity price to book value. The above data (and more recent possible transactions) suggest that substantial risk transfers are taking place between one set of rate-payers/taxpayers and another set of rate-payers. This analysis is made in the context that municipalities, which are the shareholders of almost all of the non-HONI electricity distribution in Ontario, are governed by strict legislated rules as to the types of businesses they can enter and the level of risk they can assume. 3.3 Ability of Purchaser to Fund a High Premium Transaction As of September 30,2013, Hydro One reports total assets in excess of$21 billion. Hydro One also reported debt of about $8.5 billion. In terms of asset allocation, Hydro One has about $12 billion in transmission assets and about $9 billion in distribution assets. Hydro One has substantial funding needs in the context of its capital spending program for its legacy system. It is also imperative that Hydro One maintain its current credit ratings so as to minimize its cost of capital in the interests ofboth its customers (ratepayers) and its owners (tax-payers). Although the proposed acquisition ofNPDI involves Hydro One paying a substantial premium, in dollar terms the magnitude of the premium is only about $40 million, which is not large as a fraction of Hydro One's total capital structure or debt levels. However it appears that Hydro One now has a strategic plan to acquire multiple utilities (especially in Central and Southern Ontario). Therefore, while it is clear that the current transaction alone would not be sufficient to impair Hydro One's credit, the Applicants have not provided any basis for confidence that an aggressive program of acquisitions will not, at some point, be detrimental both to customers and to the public. Since the issue is the aggregate total of acquisitions, and not an individual acquisition, the NPDI customers acquired now (and the legacy HONI customers) could be harmed by a series of high premium acquisitions that take place after this transaction. ( ) Evidence ofPaula Zamett on behalf ofEBN EB-2013-0196, EB-2013-0187, EB-2013-0198 Before the Ontario Energy Board February 26, 2014/ Updated February 27, 2014 Page24 Applicants. The Applicants have not proposed any specific plan for rates to NPDI customers at the expiration of the freeze. It is possible that by 2019 an entirely different rate proposal may be brought forward by HONI. However, we believe that HONI's custom IR Filing (EB-2013-0416) is the best indication available at present of the potential rate classes into which NDPI ratepayers will be harmonized. The following table shows the impacts of a transition for NPDI's customers to HONI rates, assuming: )> that the distribution rates approved by the Board for NPDI in its Revised Rate Order dated May 24, 2012 in EB-2011-0272 are reduced by 1% and applied unchanged until2019; and l> that HONI's rates for 2019 as applied for in EB-2013-0416, Exhibit Gl, Tab 4, Schedule 2, Attachment 5 are approved and would then apply.13 It is important to note, that although NPDI has a service territory that includes rural areas, unlike HONI it has no density rates. For the analysis, it was not possible to incorporate an estimate of the number ofNPDI customers that would transition to each ofHONI's UR, R1 and R2 rates, as HONI has said it is unable to provide a breakdown. BDR reviewed EB-20 13-0416 Exhibit G l, which at Tab 2 Schedule l provides the density related criteria for each class, but does not have the information to make an independent determination as to how many (if any) NPDI customers would-qualify for the UR (i.e. lowest) rate. The analysis has assumed a residential customer with monthly consumption of 750 kWh per month, and a General Service customer with monthly consumption of 7500 kWh (for example, a customer with demand of2S kW and a load factor of 41%. The analysis includes only distribution rates, excluding any rate riders or adders or other adjustments that may apply at the time. On this basis, an NPDI residential customer would experience a l 0% decrease in distribution charges if transitioning to HONI' s UR rate; however the customer would receive an increase of 42% if assigned to R1, and a 238% increase if assigned to R2. A general service customer transitioning from NPDI's rate to HONI' s UGe or GSe rate would receive an increase of62% or 218% respectively on this basis. These changes do not include the higher commodity charges each NPDI customer will face due to HONI' s higher line losses. 13 The 2019 HONI rates are those proposed in its EB-2013-0416 recent multi-year custom IR filing and have not been considered or approved by the Board. This includes any proposed changes to the revenue-to-cost ratios and/or the density of the customer classes. ) ( ) ( \ Evidence ofPaula Zametton behalfofEBN EB·2013·0196, EB·2013·0187, EB·2013·0198 Before the Ontario Energy Board February 26, 2014 /Updated February 27, 2014 Page26 Small General Service Norfolk Base 2012 Rates GS<50kW Fixed GS<50kW Variable Rates Bill Change$ Bill Chang-e % Norfolk Base Reduced by 1% 49.74 0.0155 GS<50kW Fixed 49.2426 GS<50kWVariable 0.015345 Assumed Typical Consumption, kWhiMonth 7500 Monthly Disrlbution Bill without Riders or Adders S 164.33 HONI 2019 Gse Fixed 32.47 ~ariable 0.06532 Monthly Distribution Bill without Rid&rs or Adders 522.37 S 358.04 218% HONI2019 Uge Fixed Variable Monthly Diaribution Bill without Riders or Adders 27.82 0.03184 266.62 $ 102.29 62% ~----------------------------------------m This table sets out the approved line losses for NPDI and HONI. The rate impacts identified in the comparison of distribution charges do not reflect the levels of line losses in the two LDCs. Assuming that HONI's line losses are applied to NPDI's customers on harmonization, the customers will face increases in the amounts that they pay for generated electricity and for transmission services as a result, in addition to increases in the distribution charges. 5 Comparison of Loss Factors, NPDI and HONI NPDI-all classes 1.0564 HONI Residential Urban 1.078 Medium Density 1.085 Low Density 1.092 Urban General Service Energy 1.092 Other General Service Energy 1.092 ) ___ _,..· ( ) Evidence ofPaula Zamett on behalf ofEBN EB-2013-0196, EB-2013-0187, EB-2013-0198 Before the Ontario Energy Board February 26,2014 I Updated February 27, 2014 Page28 Selected projects illustrating her experience and expertise in analyzing cost information related to the operation of electricity distributors include: };-a study on behalf of the Toronto Hydro-Electric System Ltd. to allocate the costs of service to customers who are individually metered suites in multi-unit residential buildings (2010-2011). };-For the City ofEdmundston/Energy Edmundston-a business plan and cost forecast reflecting acquisition of distribution service territory and new supply contracts with NB Power » Numerous studies to support the allocation of shared costs and to develop transfer pricing in support of regulated revenue requirements. Selected projects illustrating her experience in analysis of the impacts of LDC mergers and acquisitions include: };-Markham Hydro Distribution Ine. and Town of Markham -Due diligence services in support of amalgamation with Hydro Vaughan Distribution Inc. to form PowerStream Inc. » City of Guelph -independent advisor to the City with regard to fairness of ownership proportion in proposed merger; analysis of ownership options, including development of financial projections in support of valuation > Analysis and support to the City ofEdmundston/Energy Edmundston in support of its negotiation to acquire 3,000 customers from the contiguous service territory of New Brunswick Power With regard to rates and rate design, Paula has a decade of direct experience designing rates for all customer classes for Toronto Hydro, and before joining Toronto Hydro, performed rate analysis and design functions for gas utilities in ' Manitoba, Albert and British Columbia. As a consultant, she has performed rate design studies for electricity, steam and water. She participated on behalf of a client in the Ontario Energy Board's stakeholder processes regarding cost allocation for electricity distribution service, and was an instructor in cost allocation and rate design (advanced) at CAMPUT's annual utility regulation course in 2006, 2007 and 2008. She has testified before the regulators in Ontario, New Brunswick, Prince Edward Island and British Columbia, and has been accepted as an expert in cost allocation by the Ontario Energy Board.14 Formerly a manager at Toronto Hydro with responsibilities in customer service, CDM, business project analysis and rate designs, Paula is knowledgeable in the 14 EB-2010-0142, Transcript dated March 29, 2011, page 20. \ __ ) ( ) Evidence ofPaula Zarnett on behalf ofEBN EB-2013-0196, EB-2013-0187, EB-2013-0198 Before the Ontario Energy Board February 26,2014/ Updated February 27, 2014 Page30 (d) Specific Information and Documents Relied on in Preparing the Evidence BDR reviewed the record in this proceeding, with particular emphasis on revised interrogatory responses filed on February 10,2014, as well as information publicly available from the Board's website and infonnation from other public sources. Sources are footnoted in the body of the report. No proprietary or confidential information was obtained or relied on. (e) Points of Agreement and Disagreement with other Expert's Evidence Not applicable. 17162337.3 '-.._ ._./ 2019 Rate Design A B c D=A-C AllOcated Mise Revenue Number of GWh kWs Revenue Customers Cost Revenue fram Rates UR 218,777 1.9118 -$ 95,308.404 $ 89482887 4.520.949 IS 90,785,455 Rl 46 189 5.101 -$ 344989,1133 $ 325.43&899 12,691,159 $ 132.298.313 R2 346,430 4.719 -IS 818,452250 $ 827128359 16 015.559 I S 61111.436,692 sea...,ol 148.083 428 -I S 107 793,630 $ 109,746.488 3,028674 I f 104,754,955 GSe 94827 2.109 -$ 179.2:!2,549 $ 178506435 4 l231 s 174,679 618 GSd 8,483 2.396 8162219 L:[_ 169.S94.e86 $ 548555 2,531.257 IS 167,483,407 UGe 17,974 588 -$ 24.872,399 $ 25.592,334 $ B51.9l21S 24.220,467 UGd 1,929 1,042 2, 415 IS 35,034.472 s 36,594,857 I$ 411.984 I$ 34,622A88 S1_!.gt 15,074 127 -'$ 15.079,008 $ 16404,291 321 46 14 757.062 SenLAI 29.411 22 -$ _6,217 571 $ 8.520.956 IS 3050,055 $ s 167.516 USL 5,628 26 -$ 3,807,248 I$ 33900831$ 104.467 $ 3 502778 DGen 1,909 26 255.585 $ 8,515,952 I $ 9.Q50.529 $ 180,300 $ 8,335,8!52 ST 835 15,673 28,874.041 $ 67,679,971 $ 5!!,474 479 IS 954764 $ 56 925208 Total 1,337,709 34,242 40,174,261 $1,665,975,848 $1,688,975,MB $49,016,278 $1,616,959,671 ------( Filed: February 26, 2013 EB-2013-0196 I 0187 I 0198 BDR Report Attachments Rate Design E F=AIB G HcB"G RIC Target 2018 Rallo 2019 Tolal revenue RIC from RIC tobe Rallo the Ratio collected CAM 1.06 1.07 1.02 I$ 91272,545 I=H-A Shift In Revenue 4,033869 1.06 1.06 1-02 331947,877 s 13041888 1198 0.98 0.99 s 821 792,982· 6.340.712 0.98 0.98 1199 I $ 108.812.155 1,018,526 1.01 1.00 1.00 IIJ 179~ 849 -0.98 0.96 1199 $ 1 37742 61 078 0.98 0.97 0.99 s 26374854 502.2115 0.98 0.96 0.99 $ 36283436 1,248,11611 0.98 0.98 0.99 $ 15.273.285 s 194.277 0.96 0.96 0.99 $ 8448490 $ 230919 1.06 1.06 1.02 $ 3457,884 5 149.381 0.91 0.94 0.99 $ 8,973.559 $ 457607 0.98 0.97 0.99 .!_ 58,988 678 s 1.088,708 $1,665,975,848 $ (II Phase-In Complete J~IID K '-"J-K.C % .----....._.._._ Flied: 2013--12-19 EB-2013-0418 Exhibit G1-4-2 AIIBCIIment5 Pagelaf1 Change In Fixed Revenue Ravenue from Volumetric Volumetric %Fixed Charge fromFiud Volumetric Charga Charge "::'e ($/monlh) Charge Charge (¢lkWII) (SikW) Revenue 1'111118 -4% 19.57 51,377965 35,373,530 .77. 59% -4% 27.19 154,6~3 164,683,288 3-227 48% 1% 81.74 339 788 5 265991119 &.837 !511% 1% 31.55 55.292.445 50A91,036 11JJ10 52% 0% 32..47 36947944 137731674 6.532 21% 4% , ... 94 8 $. 811,313 241 uaa 20.253 5% 2% 27JJ2 5 999.564 $ 18723188 3.184 24% 4% 111.74 $ 2.585 963 I $ 33.2115.491 1.183 11.848 7% 1% 11.03 s 306156 14.845.183 11.526 2% 4% S.B3 $ 1,3!52,426 $ 4.D48.007 111.1144 25% -4% 37.47 s 2.520,878 $ 732742 2.172 78% 5% 285.88 s 6651.237 s 242.022 8.&71 6.772 76% 2% 1 053.88 $ 1ll,li83,777 ' 47450,137 0.303 1.643 18% s 6711,3111,935 $ IM0,808, 738 Total Rev I 1,818,95!1,171 Mise Rev $ 49,016,278 Total Rev Req $ 1,185,975,9411 ~~1:0'::::::.· $ 1,5119,3011.970 3.0366% i \ ) ( ) ( ) Filed: February 26, 2013 EB-2013-0196/ 0187 I 0198 BDR Report Attachments Norfolk Power Distribution Inc. EB-2011-Gm l!xhibit 5 Tab I ScheduleZ Pap6of6 Filed; August ze, :zou Ombud probing Hydro One billing practices I Ontario I News I Toronto Sun 404'ftal Property Assessment Corporation (MPAC), an~ said the "anaemic" response ofHydro One reminds him of the SllRMINN 41 REIMPACCESS priority on putlil~~~ruary 26, 2013 , .. EB-2013-0196/ 0187 I 0198 h.mer Kathleen Wynne said the Ontario government iJJII~~hl'rlltatimbudsman to resolve the issues with \_ ~JRJIJI6NOM $0.99/MONTH* 'Certain conditions apply "I afililiktbOGINhat Hydro One is already aware that there are problems and they are working to ameliorate the situation," Wynne said. Hydro One president and CEO Carmine Marcello wrote an open letter to more than 1.3 million customers Tuesday in which he said the company transitioned to a new billing system last May to provide an improved level of service. "Like other companies who have changed large, complicated billing systems in recent years, we have experienced some challenges in this conversion," Marcello said. "We know that approximately three per cent of our customers have received estimated bills for too long and about another two per cent have gone for more than 90 days without receiving a bill. ''While the vast majority of our customers continue to receive normal bills, some of our customers have not had a positive experience." Marcello said Hydro One is taking aggressive steps to fix these problems. Progressive Conservative MPP Vic Fedeli said the Ontario government would have known about these concerns for years. "Hydro One issues are the number one complaint that I receive in my office," Fedeli said. NDP Leader Andrea Horwath said she has also been pressing for action because the electricity system is not meeting the needs of citizens. "This investigation, I hope, will help get to the bottom of why these bills are so out of whack," she said. -~ ( ) bttp:Uwww.torontosun.com/2014/02/04/ombud.sman-to-probe-hydro-one-billing-practices Page2of4 2/25/2014 \ ') ( ) Ombudsman to probe Hydro One's 'baffling' billing practices Filed: February 26, 2013 EB-2013-0196/ 0187 I 0198 Page2 of3 Jim and Lynn Ellis from Southgate TdmBJ:Iif'~tCMit~told the Star they know exactly what Marin is talking about After complaining in May about not getting bills, more than six months later they received a notice that they owed $3,477.57, due by Dec. 3. Two weeks later another arrived for $1,097.27. Jim Ellis said his normal bill is $200 to $300 a month. "I don't think we were treated very well by the system at all," he said, noting that whenever he tried to get answers he would have to deal with a different person at the Hydro One call centre. Ellis said a Hydro One executive, who finally called at one point to apologize, told him there were "tens of thousands (of customers) in the same boat." "I'm angry that it's a monopoly and you can't seem to get (anywhere) with it," he said. "If there was an alternative, we'd be checking it out." Marin noted that complaints about Hydro One to his office have more than doubled since the fiscal year 2011-2012 when 232 complaints were received, which then grew to 328 in 2012-2013 and jumped to 600 between Aprill, 2013 and now. "This all points to a systemic problem that warrants an in-depth investigation by my special ombudsman's response team," he said, noting that the probe should take about nine months. Toronto resident Jim MacLean, who owns a cottage north of Huntsville, said Hydro One installed a smart metre two years ago at his cottage and the provincially-owned utility has never once used it because there is no reliable cell connection. "Why would they even put them in if they can't use it," he said, noting that he keep getting bills "estimating" what his power consumption is. Baccega Rosa acknowledged there "are areas where the meters can't communicate-the actual infrastructure is just not there" but insists Hydro One hopes to eventually hook them up. She said that ofHydro One's customers, 3.2 per cent are still receiving frequent estimated bills. Another 2 per cent haven't received any bill at all for more then 90 days. Marin said part of his office investigation is to look at the transparency and reliability of the billing system. "We are hearing from the public that they are quite prepared to be socially re-engineered as electrical trained seals doing their laundry at certain times to avoid excessive billing but on the other hand they want to be able to understand their billing, they want accuracy in their billing," he said. The ombudsman said a common complaint from customers is that they don't get bills for months and months and "suddenly because they have direct withdrawal from the bank account, they wake http://www.thestar.com/news/canada/201 4/02/04/ontarjo ombudsman to investigate hyd ... 2/25/2014 The Globe and Mail: Hydro One to face major investigation as billing complaints mount Page 1 of2 Filed: February 26, 2013 EB-2013-0196/ 0187/0198 BDR Report Attachments Convert Flies Dovvnload • February 4, 2014 Hydro One to face major investigation as billing complaints mount By Adrian Morrow Complaints against the electricity giant have more than doubled in the last two years A rapidly rising number of complaints about shoddy billing practices and poor customer service at Hydro One has prompted a major review of the Crown corporation. While the ombudsman's investigation is expected to focus on accusations the agency overcharged hundreds of people -in at least one case by tens of millions of dollars-it will also probe how and why customers have trouble getting problems fixed after bringing them to Hydro's attention. The transmission company is only the latest Ontario electrical organization to come under fire, after an audit that revealed generous pensions and big bonuses at Ontario Power Generation late last year. "With Hydro One, it takes two, three, four calls, a couple of weeks, and then we don't get straightforward answers. We get the runaround," Ombudsman Andre Marin said at Queen's Park Tuesday. "lfs like wrestling with a slippery pig.• The agency responded that many of its delays dealing with customer complaints are the resuH of switching to a new billing system last May. The changeover entailed setting up an entirely new computer platform, and Hydro One is still working out the bugs, said Laura Cooke, vice-president of corporation relations. "The glitches that we expected to be able to resolve in a timely manner are taking much longer to resolve from a technology standpoint," she said. "As a result, it's taken longer for us to manage or resolve certain customer complaints." Some customers charge that Hydro One sends them an "estimated" total on their bill, but won't explain how the estimates are arrived at, Mr. Marin said. In some situations, smart meters fail to give accurate readings because of interference from trees and hills. In other cases, he said, the utility stops billing a customer for a long period of time, then suddenly withdraws thousands of dollars from their bank account in one go. In one extreme situation, which The Globe and Mail first revealed last month, Hydro mistakenly charged Beaver Valley Ski Club for $36-million. For Raymond and Judy Muldoon, retirees who live in the countryside near Sydenham, Ont., the trouble started innocuously enough. Last May, they noticed Hydro One was charging them $20.87 for a sentinel light, a device they did not actually have. They told Hydro One about it. E-mails show it took the entire summer-and several reminders - for the utility to remove the charge from their bills. And nine months after their initial complaint, Mr. Muldoon said, they f ) are still waiting to be reimbursed. "I'm thinking: 'Corne on, guys, you can do better than this,' " he said in an interview. http:ljliceuse.icQpyriibtnet/userlviewFreeUse.act?fujd=MTc5MDA4Mzc%3D 2/25/2014 Ontario ombudsman to probe Hydro One's use of smart meters Filed: February 26, 2013 EB-2013-0196/ 0187/0198 \)) Ontario ombudsman tdDf>fcmt!'~ One's use of smart meters BY MATTHEW PEARSON, OTTAWA CITIZEN FEBRUARY 3, 2014 Page 1 of3 Ontario ombudsman Andre Marin is putting Hydro One's billing practices and tlme-of-use smart meters under his microscope, the Citizen has learned. Photograph by: James Park, ottawa Citizen OTTAWA-Ontario ombudsman Andre Marin is putting Hydro One's billing practices and time-of-use smart meters under his microscope, the Citizen has learned. Marin is expected to announce Tuesday that his office's next high-profile Investigation will focus on the hydro utility .. Time-of-use pricing coupled with so-called smart meters is supposed to give customers more control over their monthly electricity bill. Smart meters are meant to record how much electricity is used and when, typically hourly, then send the information automatically to Hydro One through a wireless communications network. But that's not always happening. The meters have caused huge billing headaches for some customers in rural areas because many of .r ) the machines cannot transmit billing data properly to utility hubs. Hilly topography and tall trees interfere with the signals. http:Uwww.ottawacitizen.com/stot:y print.html?id=9465092&sponsor= 2125/2014 )) \. __ -- Ontario ombudsman to probe Hydro One's use of smart meters Filed: February 26, 2013 Page 3 of3 A spokeswoman for Energy Minister Bo~e~R~JP~ i~~~6Rd§9 she wouldn't "pre-empt the BDR Report AttFichments ombudsman," but noted Hydro One introduced a new billing system last year that has caused a "small number" of Hydro One customers to experience sub-par service. "Hydro One has been working to address outstanding issues as quickly and efficiently as possible," said Beckie Codd-Downey in an email. "They have made a lot of progress in the past few months. Delivering value to energy consumers is a priority for our government." With files from Hugh Adami © Copyright (c) The ottawa CHizen http://www.otta.wacitizen.com/stol'L!'J'int.htrnl?id::::9465092&sponsor-2/25/2014 ( ) MPP Randy Hillier says Hydro One probe provides vindication to frustrated customers Page2 of3 Filed: February 26, 2013 Time-of-use pricing, coupled with so-cau~-~lih9r1~W,1~~6~8§ed to give customers more control over their monthly electricity bill. Smart m!=l~.§ ~~8t~:,W¥iN~~~a how much electricity is used and when, then send the information to Hydro One through a wireless communications network. But that doesn't always happen. The meters have caused huge billing headaches for some customers in rural areas because many of the machines cannot transmit billing data properly to utility hubs. That means bills are based on estimates and often arrive irregularly, resulting in customers receiving bills with outstanding balances in the thousands of dollars. Hillier said he first met with Hydro One and the Ministry of Energy about the problems with smart meters in 2011. Since then, his office has fielded more and more complaints about what he calls "administrative and technical problems" at Hydro One. Hillier said the investigation provides vindication for the hundreds of people who have registered complaints. "Dealing with government can be a very agonizingly slow, drawn out and frustrating process, and many people lose faith because of the slowness and the complexities of it. This, he said, shows that "yes, you should speak out, and you will be heard." In a release, Marin's office said complaints about Hydro One to the ombudsman have risen steadily in recent years. The office has received more than 600 complaints since April1, up from 328 in the 2012- 13 fiscal year and 232 the year before. Marin said his office has experienced "stonewalling" from Hydro One in trying to help Ontarians resolve problems with their bills. "Our experience reflects what we are hearing from people across the province, and it Is alarming. Many of those who have contacted us are in vulnerable situations and say they have faced significant financial hardship and stress because of their dealings with Hydro One," he said In a release. Hydro One admitted it was not providing adequate customer service, which it contracted out to call centre operator Vertex, and said It would provide more training for the Vertex staff who answer the Hydro One phones. "We know that the level of service we've been providing to customers is not acceptable," said Hydro One spokeswoman Tiziana Baccega Rosa. "It's not what they deserve, and it's not what we want to give them." The Ministry of Energy also admitted Hydro One had problems with customer service, and promised full co-operation with the ombudsman's investigation. Marin's office said the investigation will be completed within nine months, after which he will produce a report with recommendations. http://www,ott.awacitjzep.com/stozy print.htrnl?jd=9469574&sponsoF 2/25/2014 ( ) Hydro One probe by ombudsman gets 2,500 more complaints Lokalee-Trusted Review ... Page 1 of2 Filed: February 26, 2013 DON'T MISS SnowstDrm blankels 13,C.'s SOU!tl Coost EB-2013-0196/ 0187 I 0198 BDR Report Attachments webacoM LOKAlEE THENATIONAL CANADA *Home 1 amalia 1 Hydro One probe by ombudsman gets 2.500 more complaints Hydro One probe by ombudsman gets 2,500 more complaints Ontario ombudsman Andre Marin says the complaints continUe to mount against Kydro One. Slr¥:e Ontario's ombudsman announced an hwesligelion into Hydro One's billing ~eliteS and rustomer senlioe lllst week, his office has ret;J;ve;l ;almost 2,500 more complaints. With the total now at 3,100, Ontario's ombudsman has told his followers on Twitter not to despair. Andre Mann said his staff Is meeting weekly with the utility In an effort to sort out lnclvldual cases- tustomers who have had issues 111nging from no bills for monlhs, to unus..ally steep bills. n ontario Ombudsman ®OnLOmbudsman FoUow We now have weekly meetings w/OpHydroOne to move the individual cases along. Don't despair, we'll get you thru this. 5:24 PM -11 Feb 2014 In some cases, Mann Sllld, customers' houses burned down and they continued to receive hydro bHis. As for the number of complaints, Marin said tltey continue to riSe. Prior to the Investigation, Ma~n said he had about 650. N Ontario Ombudsman @Ont_Ombudsman Most bizarre @HydroOne complaints? Those whose houses bmnt down. Completely. And they still were having actual use bills. 5:56PM -11 Feb 2014 Follow TECHNOLOGY & SCIENCE AR1S & ENTERTAINMENT Popular Cillgary mom guilty of InfantiCide for lea In dumpster l'bwrnbot 27, W-3 Tom Daley announces he's dating man lleCelnl>er 2, 2013 Paul Willker's dealh ~Bfl<s g~ef, shod< media llldlnbor 1, 201.3 Egypt 'anti-protest' law [mils publlt gatt -25,2013 Cilnada's students sUpping in math and : OS::Ofinds llea!mber 3, 2013 February 2014 January 2014 December 2013 November 201.3 CATEGORIES Arts 8! Entertainment Business Cilnada Health POlitics Technology &. Science TiieNd1.1011d1 Top Stories World RECENT POSTS Opponents slam Trudeau over Ukraine CBC/Pado-Canada se!S Cilnadlan Olyr viewership mark Well, she's HIUary arnton, and they're Macdonald Why Vladimir Putln can1 afford to loot over Ukraine U.K. pollee arrest 4 on suspldon ol Sy flerrorism Doli51S of sludents killed In Nlgl!rlan t sthool attack Mexico's cartels: The aminal organize behind the drug war Uganda tabloid publishes 1op' homoss Ukraine votss to try Yanukovych In IN Criminal court Why Hillary Clnton could bUIV the Ret presidential field http:/lnews.lokalee.com/bydro-one-probe-by-ombudsmau-~ets-2500-more-complaints/ 2125/2014 )) Filed: February 26, 2013 Ontario Ombudsman launches ~d~03f.§Hi Ui'Vi~sfi\1fft.ton · · -··~DR Report Att~ll'!hrnAriif~r Dave Reaney checks smart meter Joarme Schnurr, CTV Ottawa Publiahod Tuesday, February 4, 2014 3:07PM EST Last Updeted Tuesday, Fabruary4, 2014 5:09PM EST Page 1 of2 Ontario's ombudsman has launched an Investigation into Hydro One after hundreds of complaints to his office. CTV Ottawa hightighted many of these storieS of people close to bankruptcy, unable to pay their utility biD. Andre Marin decided to launch his investigation after years of trying to resolve hundreds of complaints on an Individual basis. He says deaUng with Hydro One has been extremely difficult, like trying to catch a slippery pig. Davld Baker knew there was something wrong wlth his smart meter. He's been heating his house near Prescott only with wood and couldn't understand why his hydro bill was so high. "I have energy efficient everything in the house," said Baker In an earlier CTV story from December. RELATED STORIES Christina!> Is back on for Smiths Falls famRy Sm~hs Falls family cancsls Chrlslmas to payhydm Prescott family pulls the plug on Hydro One The Bakers weren't the only Hydro One customers complaining about high bills. Hundreds of them turned to Ontario's Ombudsman for help after getting nowhere with the utility company. "Stories of huge unexplained catch-up biUs, multiple bills or estimated bills with no rhyme or reason," said Andre Marin at a news conference this momlng in Toronto. The ombudsman has now launched a fun Investigation. He says It's not about the prloe of electricity but about billing and oommurjcation problems; problems his own offioe has experienced fii"Slhand. "Sometimes lfs like wrestling with a slippery pig, • says Marin, "that's why my heart goes out lo the average citizens who try to take on the Golath that is Hydro One." The ombudsman says COillliaints to his office about Hydro One have continued to mount. They more than doubled In the last year to 600. Most of those complaints were about bHis being wrong or excessively high. Dave Reaney was one of those customers trying to get answers from Hydro One. He works in heating and cooling and knows the Industry. He knew his bill for $2800 over a 2()(kjay period was way out of line. "Their billing was completely erroneous," says Reaney, "thay were bilting me three times what my actual consumption was." He says he fought Hydro One and won. David Baker is still fighting but hoping the ombudsman will help hundreds of customers like him struggling to just to pay their utility bill. "It was in 2005 when I started complaining," said Baker today, "and here it is 2014 and yeah Ills frustrating but I'm glad finally somebody listened." Reaney welcomes the ombudsman's investigation but says is much deeper Investigation Is needed . ., think It should be a criminal investigation at this point," says a frustrated Reaney, "I think the ombudsman is a good step but I think there's been some criminal activity and fraud, period." bttp://ouawa.ctynews.ca/ontario-ombudsrnan-launches-hydro-one-inyestigation-1. 1670529 2/25/2014 ( ) Report ofPilafiG ~~'Liarch, LLC EB-2013-0196/ 0187/0198 BDR Report Attachments EMPIRICAL RESEARCH IN SUPPORT OF INCENTIVE RATE SETTING IN ONTARIO: REPORT TO THE ONTARIO ENERGY BOARD May 2013 BDR ';) PAULA ZARNETI Filed: February26, 2013 EB-2013-0196/ 0187/0198 BDR Report Attachments · l . . ) ~'·./ Paula Zarnett has 30 years broadly based experience in utility customer service, customer research, rates, and regulation. Following a series of rate specialist positions in both the electricity and natural gas sectors, she was promoted to the position of Manager of Marketing and Energy Management at Toronto Hydro. There, her responsibilities included all rate and regulatory issues, customer research including load research and forecasting, and customer program design with a focus on conservation and demand management. She was responsible for establishment of the utility's Key Account group, which focused on assessing and meeting the service needs of the utility's largest customers. During her career at Toronto Hydro, Paula carried out rate-related customer research, including questionnaire and interview research to select residential customers for a time of use rate pilot program, and to select commercial-industrial customers for load research. For two years, she led an organization- wide program of performance improvement, which included implementation of employee surveys as to overall employment satisfaction and satisfaction with the services provided by other departments (i.e. as internal customers). In her consulting practice, Paula provides a variety of advisory and analytical services to clients facing the challenges of both traditional and restructured energy markets, with a focus on issues impacted by regulatory policy and process. Her work includes business case and project feasibility analysis, cost allocations and pricing designs, energy sector mergers and acquisitions, and expert testimony before regulators. She is a skilled hands-on analyst, experienced in handling large data sets. She has performed assignments for clients in North America, China, Ghana, and Barbados. SELECTED EXPERIENCE BY SUBJECT AREA (INCLUDES PROJECTS UNDERTAKEN AS A CONSULTANT, AND IN lHE COURSE OF RESPONSIDILITIES WITIDN ORGANIZATIONS} Rate Designs and Pricing Studies IGPC Ethanol Inc.-supported the intervention of this industrial consumer in the rate application of its gas supplier, Natural Resource Gas Rogers Cable and Communi~ations Inc. -representation at Ontario Energy Board staff consultation process with regard to rate designs for Ontario's electric distribution utilities; development of policy and position documents, attendance at stakeholder meetings, analysis in support of positions on rate design for General Service classification and unmetered scattered loads; distribution cost allocation stakeholder process and 2006 distribution rate handbook. City of Markham (Ontario)-recommendations for restructuring water and wastewater rates ) -/ PAULA ZARNETT Page3 Testimony before Regulators Filed: February 26, 2013 EB-2013-0196 I 0187 I 0198 BDR Report Attael'lrnents Toronto Hydro -development of all customer rate designs, implementation strategy, and preparation of annual submissions for approval of the rates. Managed a team of specialists in the preparation of associated detailed studies, load forecasts and load research. ORAL: Toronto Hydro-Eieetrie System -Testified before the Ontario Energy Board in support of the allocated costs of service to customers that are individually metered suites in multi-unit residential buildings. Saint John Energy -Testified before the New Brunswick Public Utilities Board in support of intervention in the Cost Allocation and Rate Design application of New BrtmSWick Power Distribution and Customer Service Corp. ICG Utilities -coordinated preparation of applications, supporting materials, and other aspects of regulatory process for regional gas utility managements, as member of a head office specialist team; provided expert technical services in rate design, cost allocation, and working capital allowance determination (lead-lag); testified in three hearings before British Columbia regulator on the subject oflead-Iag studies. Rogers Cable and Communication Inc. -Testified before Ontario Energy Board in support of consensus for treatment of certain umnetered electricity loads in the development of guidelines for electricity distribution rates. WRITTEN: Greater Sudbury Hydro -study to allocate costs of services purchased from affiliate Bluewater Power -study to allocate costs of services provided to and purchased from affiliates Kingston Hydro -study to review transfer pricing methodologies and allocation of shared costs for services provided by non-regulated affiliates. FortisOntario -Three studies to allocate corporate and shared costs among regulated and non-regulated affiliates EnWin Utilities-study to allocate corporate and shared costs among corporate affiliates Ontario Power Authority -model development and analysis in support of evaluation of a potential generation, transmission and demand response alternatives in York Region; report in support of generation alternative to the Ontario Energy Board. I I I I I I I I I I I I I I I ! \ l I I I C) PAULA ZARNETT PageS Business and Strategic Planning, Mergers and Acquisitions Filed: February 26, 2013 EB-2013-0196/ 0187/ 0198 City 'aPii~$ Edmundston -business plan reflecting acquisition of distribution service territory and new supply contracts with NBPower City of Edmundston/Energy Edmundston -analysis and strategic support in negotiation of contracts with NB Power for: • Acquisition of 3,000 customers within the territorial boundaries of the City ofEdmundston • Purchase of wholesale electricity supply • Sale of output of the City's hydro generators; and • Sale of a portfolio of rental water heaters. City of Sault Ste. Marie -review of municipally-owned electricity distribution company with regard to ownership options, capital structure and financing. Brantford Power -facilitation of strategic plannirig session for Board of Directors. Orillia Power -facilitation of strategic planning session for Board of Directors and key staff Oakville Hydro-facilitation of regulatory strategic plan Burlington Hydro Inc. -advisory services and analysis in connection with bid to acquire a local distribution utility. Markham Hydro Distribution Inc. and Town of Markham -Due diligence services in support of amalgamation with Hydro Vaughan Distribution Inc. to form PowerStream Inc. City of Guelph -independent advisor to the City with regard to fairness of ownership proportion in proposed merger; analysis of ownership options Township of King -advice to municipality staff with regard to potential construction of a peaking generator in response to a contract award from Ontario Power Authority. This assignment included design, implementation and analysis of a web-based survey to determine attitudes of residents to the project. Hydro Ottawa Holdings Inc. -as part of a larger project to provide strategic advice on four business units, provided financial modeling for valuation of Energy Ottawa Generation. Town of Markham, City of Vaughan and City of Barrie -analysis, due diligence and advisory services in evaluation of potential investment in the solar business ofPowerStream Inc. PUC Distribution Inc. -advisory services and analysis in connection with certain issues of new assets and affiliate relationships PAULA ZARNETT Pa e 7 )) 1995-1998 ( )' \ 1993-1995 1986-1992 1984-1986 1981-1984 1979-1981 Degrees and Designations Professional Association Continuing Professional Development Teaching and Training, Industry Committees February, 2014 Filed: February 26, 2013 EB-2013-0196/ 0187/0198 Toro ~. Marketing and Energy Management (responsible for demand management programs, customer rates, water heating programs, key account services, emergency telephone response, customer and load research and special projects) Toronto Hydro -Special Assistant to the General Manager (responsible for organizational performance improvement initiatives) Toronto Hydro -Supervisor ofRates and Cost Analysis Toronto Hydro -Senior Rate Analyst ICG Utilities Ltd. -Coordinator, Rate Administration H. Zinder & Associates Canada Ltd., Senior Analyst EDUCATIONAL AND PROFESSIONAL QUALIFICATIONS Society of Management Accountants of Manitoba, CMA University of Calgary, Masters ofBusiness Administration (Finance) University of Toronto, Bachelor of Arts (Hon), Anthropology Society of Management Accountants of Manitoba Queens University School of Business, Marketing Program Queens University School of Business, Sales Management Program Society of Management Accountants of Canada-Customer Profitability Analysis Society of Management Accountants of Canada-Strategic Cost Management Society of Management Accountants-Auditing I PROFESSIONAL INVOLVEMENT Instructor in Cost Allocation and Rate Design for Annual Energy Regulation Course, CAMPUT (Canadian Association of Members of Public Utility Tribunals) 2006,2007, 2008. Member and present Vice-Chair, Electricity Distributors Association Commercial Members Steering Committee (2007 to present) Member-Ontario Energy Board Cost Allocation Working Group (2003 and 2005-6) Member-Ontario Energy Board Working Group on Cost Allocation for Unmetered Electricity Loads (20 12-20 13) Member -Municipal Electric Association Cost of Service Sub- Committee (1986-1988) JOHN A. MCNEIL Page2 ~') HydroOne \ . -_) ( ) Hydro One and Northwestern Ontario LDCs(Zone 7) Hydro One Markham Oakville Hydro Orangeville Hydro Power Stream PUC Distribution (Sault Ste Marie) Thunder Bay Hydro Filed: February 26, 2013 EB-2013-0196/ 0187/0198 Advismf~~6fi~~g various "consolidation" options which might be available both specifically to Hydro One and generally as part of an overall policy which the Province might adopt. Facilitated a feasibility study for the potential amalgamation of the distribution utilities in Northwestern Ontario. The project included assessment of synergies, evaluation of impacts on shareholder values and identification and analysis of potential challenges and potential barriers. In the 1999/2000 timeframe, Mr. McNeil had a series of contracts with Hydro One involving advisory services on a wide range of confidential projects relating to M & A, cost of capital, valuation, capital markets and regulatory matters. Publicly announced assignments include the acquisition of Brampton Hydro for $260 million. Led the team which has advised advised Markham re a number of matters relating to their investment in PowerStream including the assessment of its position as a major shareholder of PowerStream in relation to merger discussions with Barrie Hydro. The transaction closed on January 1, 2009 Retained as an advisor to complete a Strategic Options Study. Valuation in the context of a possible sale and valuation re merger with a number of different utilities including Centre Wellington Hydro Valuation ofCOLLUS as part of an acquisition of up to 50% equity interest Transaction closed in mid-2012. Advised the City with respect to a comprehensive assessment of its options re its electric distribution utility. Retained as an advisor to complete a Strategic Options Study Retained as an advisor to complete a Strategic Options Study ) TILLSONBURG HYDRO INC. FINANCIAL STATEMENTS DECEMBER 31.2013 Statement 1 TILLSONBURG HYDRO INC. STATEMENT OF FINANCIAL POSITION DECEMBER 31 1 2013 (with comparative balances as at December 31, 2012 and January 1, 2012) December 31 January 1 2013 2012 2012 ASSETS Current Cash and short-term investments $ 946,916 $ 2,118,846 $ 1,818,658 Accounts receivable 4,208,733 3,316,181 2,752,906 Due from related parties (note 13) 61,991 314,253 Income taxes receivable (note 11) 40,104 Inventory 283,079 442,491 425,714 ! Prepaid expenses 94,88~ 8,080 10,336 5,595,602 5,885,598 5,361,971 ! Property, plant and equipment (note 5) . i Cost 19,857,712 18,652,919 18,150,571 Less accumulated amortization (10,275,431) (10,239,306) (9,983,976) ~.582,281 8,413,613 8,166,59Q Other assets Deferred costs (note 7) 91,582 35,344 Regulatory assets (note 6) 237,322 539,419 Non-utility capital assets (note 12) 118,65~ 130,117 118,654 459,021 574,763 Total assets $ 15.296.537 $ 14.758.232 $ 14.103.329 LIABILITIES AND SHAREHOLDER'S EQUITY Current Accounts payable and accrued liabilities $ 2,362,883 $ 1,600,996 $ 1,856,472 Customer deposits 31,029 69,726 86,233 Current portion of long term debt (note 8) 124,770 119,254 113,975 Due to related parties (note 13) 485,753 2,518,682 2,275,729 2,056,680 Long term Customer deposits 227,280 214,886 172,890 Deferred contributions (note 9) 1,983,772 2,127,430 2,184,077 Bank loan (note 8) 669,142 7~3,9:12 917,433 2,880,19~ 3,136,228 3,274,400 Other liabilities Regulatory liabilities (note 6) 504,693 Total liabilities 5.903.569 5.411.957 5.331.080 Shareholder's Equity Common shares (note 1 0) 6,992,565 6,992,565 6,992,565 Contributed capital (note 1 0) 990,387 1,190,387 1,190,387 Retained earnings -Statement 2 1,410,012 1,163,323 589,297 9,392,966 9,346,275 8,772,249 Total liabilities and shareholder's equity $ 15.296.537 $ 14.758.232 $ 14.103.329 On behalf of the Board: The accompanying notes are an integral part of these financial statements. Statement 3 TILLSONBURG HYDRO INC. STATEMENT OF COMPREHENSIVE INCOME FOR THE YEAR ENDED DECEMBER 31 1 2013 (with comparative balances for the year ended December 31, 2012) 2013 2012 Electricity revenue $ 20,128,436 $ 17,676,325 Cost of power 20.128.436 17.676.325 Gross margin on power Distribution revenue Distribution service (note 6) 3,855,742 3,140,613 Retail service 10,955 13,754 Other 12~UlQ3 1l2~.604 3,996,600 3,307,971 Net non-utility activities (note 12) 25,919 133,973 Expenses Operating and maintenance (note 6) 1,358,137 908,064 Billing and collecting 643,690 665,721 General administration 767,320 715,580 Regulatory expenses (note 7) 209,417 53,114 Amortization (note 3 and 15) 356_,191 255,020 Interest and finance charges 72,197 52,942 3.406,952 2,650.441 Net operating revenue 615,567 791,503 Provision for payment in lieu of corporate taxes (note 11) 68,874 67 477 Comprehensive income for the year $ 546.693 $ 724.026 The accompanying notes are an integral part of these financial statements. • j ... 1. Reporting entity TILLSONBURG HYDRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31.2013 Tilfsonburg Hydro Inc. was incorporated in Ontario on October 26, 2000 to distribute electrical power to the residents of the Town of Tillsonburg in accordance with Section 144 of the Electricity Act, 1998. The Corporation operates under a licence issued by the Ontario Energy Board ("OEB"). The Corporation is regulated by the OEB and adjustments to the Corporation's distribution and power rates require OEB approval. The address of the Corporation's registered office is 200 Broadway Street, 2nd Floor, Tilfsonburg, Ontario. 2. Basis of presentation The Corporation's financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as adopted by the International Accounting Standards Board ("IASB") and interpretations as issued by the International Financial Reporting Interpretations Committee {"IFRIC") of the IASB. These are the Corporation's first financial statements prepared in accordance with IFRS. In prior years, the Corporation prepared its financial statements in accordance with Canadian Generally Accepted Accounting Principles ("Canadian GAAP"). The Corporation has restated its opening Statement of Financial Position at January 1, 2012, its I FRS transition date, by applying I FRS retrospectively, except with regard to specific items, in respect of with I FRS 1: First-time Adoption of IFRS either, prohibits or modifies the retrospective application of IFRS. An explanation of how the transition to IFRS has affected the reported financial position, financial performance and cash flows of the Corporation is provided in note 15. Approval of the financial statements The financial statements were approved by the Board of Directors on Apri115, 2014. Basis of measurement The financial statements have been prepared on the historical cost basis. These financial statements have been prepared using the accrual basis of accounting. The accrual basis of accounting recognizes revenue as it becomes available and measurable. Expenses are recognized as they are incurred and measurable as a result of the receipt of goods or services and the creation of a legal obligation to pay. Functional and presentation currency These financial statements are presented in Canadian dollars, which is the Corporation's functional currency . TILLSONBURG HYDRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31.2013 2. Basis of presentation continued Rate setting and industry regulation · ! With the commencement of the open market, the Corporation purchases electricity from the Independent Electricity System Operator (IESO), at spot market rates and charges its customers unbundled rates. The unbundled rates include the actual cost of generation and transmission of electricity and an approved rate for electricity distribution. The cost of generation, transmission and other charges such as connection and debt retirement are collected by Tillsonburg Hydro Inc. and remitted to the IESO. The Corporation retains the distribution charge on the customer hydro invoices. The OEB has the general power to include or exclude costs, revenues, losses or gains in the rates of a specific period, resulting in a change in the timing of accounting recognition from that which would have applied in an unregulated Corporation. Such change in timing gives rise to the recognition of regulatory assets and liabilities. The Corporation's regulatory assets represent certain amounts receivable from future customers and costs that have been deferred for accounting purposes because it is probable that they will be recovered on future rates. In addition, the Corporation has recorded regulatory liabilities, which will represent amounts for expenses incurred in different periods than would be the case had the Corporation been unregulated. Specific regulatory assets and liabilities are disclosed in note 6. The Corporation's approved distribution rates include components for the recovery of distribution expenses, regulatory assets and liabilities, payments in lieu of corporate income taxes, and a rate of return on capital assets. On December 12, 2011, the Corporation submitted an application to the OEB under the incentive regulation mechanism (IRM) seeking approval to change its 2012 Electricity Distribution Rates. On April 12, 2012, the Corporation received a Decision from the OEB that approved changes to the rates that the corporation charges for electricity distribution, to be effective May 1, 2012. On November 8, 2012, the Corporation submitted a Cost of Service rate application to the OEB for 2013 Electricity Distribution Rates. On April 11, 2013, the Corporation received a Decision from the OEB that approved changes to the rates that the Corporation charges for electricity distribution, to be effective May 1, 2013. TILLSONBURG HYDRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31.2013 3. Significant accounting policies continued Property. plant and equipment Property, plant and equipment are measured at cost or deemed cost established on the transition date. Cost includes expenditures that are directly attributable to the acquisition of the asset. The cost of self-constructed assets includes the cost of materials and direct labour and any other costs directly attributable to bringing the asset to a working condition for its intended use. Parts of an item of property, plant and equipment that have different useful lives are accounted for as separate items (major components) of property, plant and equipment. Amortization is recognized in profit or loss on a straight-line basis over the estimated useful life of each part or component of property, plant and equipment. Land is not depreciated. The estimated useful lives are as follows: Distribution station equipment Poles, towers and fixtures Overhead conductors Overhead devices Underground conduit Underground conductors and devices Transformers Services -overhead Services -underground Distribution meters Smart meters Computer hardware Computer software 40 years 50 years 60 years 40 years 50 years 30 years 40 years 50 years 40 years 25 years 15 years 5 years 5 years Depreciation methods, useful lives and residual values are reviewed at each reporting date. Impairment Property, plant and equipment assets with finite lives are tested for recoverability whenever events or changes in circumstances indicate a possible impairment. Any impairment is recognized in comprehensive income when the asset's carrying value exceeds its estimated recoverable amount. An impairment charge may be reversed only if there is objective evidence that a change in the estimate used to determine the asset's recoverable amount since the last impairment was recognized is warranted. A reversal of an impairment charge is recognized immediately in comprehensive income. after such a reversal, the depreciation charge, where relevant, is adjusted in future periods on a systematic basis over the asset's remaining useful life. 4. Financial instruments TILLSONBURG HYDRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31.2013 The fair value of cash, accounts and income taxes receivable, due from (to) related parties, accounts payable and accrued liabilities and customer deposits is approximately equal to their carrying value given their short-term maturity date. Exposure to market risk, credit risk, and liquidly risk arises in the normal course of the Corporation's business. Market risk refers primarily to risk of loss that results from changes in commodity prices, foreign exchange rates and interest rates. The Corporation does not have market risk due to the flow through nature of its energy purchases and costs. The Corporation does not have foreign exchange risk. The Corporation minimizes interest rate by issuing long-term fixed rate debt. Financial assets create credit risk if customers fail to discharge an obligation, causing a financial loss. The Corporation's distribution revenue is earned on a broad base of customers principally located in Tillsonburg, with no single customer that accounts for revenue or accounts receivable balance in excess of 1 0% of the respective balance. The Corporation invests in short-term investments which are not considered a credit risk. Liquidly risk is the risk that the Corporation will not be able to meet its financial obligations as they become due. Short-term liquidity is expected to be sufficient to fund normal operating requirements. 5. Property. plant and equipment The value of property, plant and equipment as at year end are as follows: Accumulated Net Net Cost Amortization 2013 2012 Substation land $ 11,520 $ $ 11,520 $ 11,520 Substation equipment 404,210 (340,592) 63,618 65,602 Distribution system 18,865,971 (9,557,799) 9,308,172 8,336,491 Computer hardware 19,886 (13,704) 6,182 Computer software 556,125 (363,336) 192,789 $19,857,712 $10,275.431) $ 9,582.281 $ 8,413,613 i ! TILLSONBURG HYDRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31.2013 7. Deferred costs and regulatory expenses The Corporation incurred costs to prepare and file a rate rebasing application. The Ontario Energy Board provided approval to recover $106,000 of these costs through rates over a four year period commencing in 2009. The amortization of these costs is recorded in regulatory expenses. The final disposition of these costs occurred in 2013. In addition, the Corporation expensed its costs related to the 2013 rate rebasing application in 2013 of $82,733. These costs are included in regulatory expenses. 8. Long-term debt The Corporation incurred long-term financing for the smart meter program. The bank loan is repayable over 10 years, and bears interest at 4.53%, and has the option of a 10% prepayment each year. The loan is secured by a general security agreement. Principal repayments over the next five years are as follows: 2014 $124,770 $130,541 $136,571 $142,895 $149,505 2015 2016 2017 2018 9. Deferred contributions Deferred customer contributions in aid of construction or acquisition of property, plant and equipment is as follows: Deferred contributions received Less: Amount recognized as distribution revenue Deferred contributions, end of year 10. Share capital 2013 $ 2,757,152 (773.380) $ 1.983.772 2012 $ 2,838,082 (710.652) $ 2.127.430 The share capital of the Corporation consists of the following: Authorized -Unlimited common shares -Unlimited number of Class A shares-non-voting, non-cumulative redeemable 2013 2012 Issued - 1 voting common share $ 6.992.565 $ 6.992.565 During the year the Corporation returned $200,000 of the contributed capital to its shareholder. 14. Prudential support TILLSONBURG HYDRO INC. NOTES TO FINANCIAL STATEMENTS DECEMBER 31.2013 Tillsonburg Hydro Inc. has posted a letter of credit with the Independent Electricity System Operator (IESO) in the amount of$ 956,406 (2012-$956,406). The IESO is responsible for ensuring that prudential support is posted by all market participants to satisfy their prudential support and obligation and, therefore, mitigate the impact of an event of default by a market participant on the rest of the market. 15. Explanation of transition to I FRS The Corporation has elected under IFRS 1 to use the carrying value of property, plant and equipment as the deemed cost at the date of the transition. Therefore, there has been no change to property, plant and equipment at January 1, 2012. In accordance with I FRS, the Corporation has revised its accounting policy to address the component accounting requirements for property, plant and equipment. The standard requires more rigorous accounting for significant components of property, plant and equipment than is required under Canadian GAAP. As part of the componentization exercise, the useful lives of the various components were determined and the amortization has been recorded from January 1, 2012 using the new useful lives. This had the effect of increasing property, plant and equipment net book value by $376,843 on December 31, 2012, and decreasing depreciation expense by $376,843 for the year ended December 31, 2012. In addition, to componentization, IFRS contains different definitions of costs eligible for capitalization. As a result, the Corporation has reviewed the amounts of overhead and related costs capitalized to property, plant and equipment in 2012 and have determined that no adjustment is required. IFRS 14, Regulatory Deferred Accounts, permits a Corporation which is a first-time adopter of IFRS to continue to account for regulatory deferral account balances in accordance with its previous GAAP, both on initial adoption of IFRS and in subsequent financial statements. Regulatory deferral account balances, and movement in them, are presented separately in the Statement of Financial Position and Statement of Comprehensive Income. Deferred contributions at January 1, 2012, of $2,184,077, have been reclassified from a credit offsetting property, plant and equipment to a long-term liability. The amortization of these contributions for the year ending December 31, 2012 of $57,874 has been reclassified from depreciation to distribution revenue for the year ending December 31, 2012. There is no effect of these changes on the comprehensive income for the year. The Statement of Cash Flows for the year ending December 31, 2012, has been adjusted for the change in amortization from the componentization of property, plant and equipment of $346,843 and the reallocation of the amortization of the deferred capital contributions of $57,874. SPE~KERS>REGISTRAR .. sped~l· f!t~ti.F!g::.~£:¢<»ll·•idl •• Wec;tnesday, :MayJ4, 20'14 · '· ....... · · .•.. · ..•. · .. · · .... ··. : ; : Tillspnburg Cprnmunity.·· Centre {ltions1ALicji~qrh:~rn),.45 .. ITJ'ar'~Y: ~y:~.,·:J(~II$9ri'p~rgi.!QN······· nus61'11)org Hydro Inc:; Potilic lntor*"at:ior1~ M~e~~·l1!1 · ·. ·· ·· < ··. Date Received Requestor Organization 10-Apr-14 23-Apr-14 28-Apr-14 30-Apr-14 01-May-14 01-May-14 02-May-14 07-May-14 08-May-14 09-May-14 09-May-14 Lisa Gilvesy, Chair, Development Committee Dave Morris Max Adam Cam McKnight Eddy Kunkel Ron Osborne (CEO) John Armstrong Suzanne Renken (CEO) Development Committee Jeff Pettit (President & CEO) Tyler Moore (Executive Vice-President) Ascent Group Inc. (St. Thomas Energy Inc.) Tillsonburg Chamber of Commerce ERTH Corporation ERTH Corporation THE CORPORATION OF THE TOWN OF TILLSONBURG BY -LAW NUMBER 3825 BEING A BY-LAW to confirm the proceedings of Council at its meetings held on the 14th day of May, 2014 WHEREAS Section 5 (1) of the Municipal Act, 2001, as amended, provides that the powers of a municipal corporation shall be exercised by its council; AND WHEREAS Section 5 (3) of the Municipal Act, 2001, as amended, provides that municipal powers shall be exercised by by-law; AND WHEREAS it is deemed expedient that the proceedings of the Council of the Town of Tillson burg at this meeting be confirmed and adopted by by-law; NOW THEREFORE THE MUNICIPAL COUNCIL OF THE CORPORATION OF THE TOWN OF TILLSON BURG ENACTS AS FOLLOWS: 1. All actions of the Council of The Corporation of the Town of Tillsonburg at its special meeting and regular meeting held on May 14, 2014, with respect to every report, motion, by-law, or other action passed and taken by the Council, including the exercise of natural person powers, are hereby adopted, ratified and confirmed as if all such proceedings were expressly embodied in this or a separate by-law. 2. The Mayor and Clerk are authorized and directed to do all the things necessary to give effect to the action of the Council of The Corporation of the Town of Tillsonburg referred to in the preceding section. 3. The Mayor and the Clerk are authorized and directed to execute all documents necessary in that behalf and to affix thereto the seal of The Corporation of the Town of Tillsonburg. 4. This by-law shall come into full force and effect on the day of passing. READ A FIRST AND SECOND TIME THIS 141h DAY OF MAY, 2014. READ A THIRD AND FINAL TIME AND PASSED THIS 14"' DAY OF MAY '2014. MAYOR -Dave Beres TOWN CLERK-Donna Wilson THE CORPORATION OF THE TOWN OF TILLSONBURG BY -LAW NUMBER 3825 BEING A BY -LAW to confirm the proceedings of Council at its meetings held on the 14th day of May, 2014 WHEREAS Section 5 (1) of the Municipal Act, 2001, as amended, provides that the powers of a municipal corporation shall be exercised by its council; AND WHEREAS Section 5 (3) of the Municipal Act, 2001, as amended, provides that municipal powers shall be exercised by by-law; AND WHEREAS it is deemed expedient that the proceedings of the Council of the Town of Tillsonburg at this meeting be confirmed and adopted by by-law; NOW THEREFORE THE MUNICIPAL COUNCIL OF THE CORPORATION OF THE TOWN OF TILLSONBURG ENACTS AS FOLLOWS: 1. All actions of the Council of The Corporation of the Town of Tillson burg at its special meeting and regular meeting held on May 14, 2014, with respect to every report, motion, by-law, or other action passed and taken by the Council, including the exercise of natural person powers, are hereby adopted, ratified and confirmed as if all such proceedings were expressly embodied in this or a separate by-law. 2. The Mayor and Clerk are authorized and directed to do all the things necessary to give effect to the action of the Council of The Corporation of the Town of Tillsonburg referred to in the preceding section. 3. The Mayor and the Clerk are authorized and directed to execute all documents necessary in that behalf and to affix thereto the seal of The Corporation of the Town of Tillson burg. 4. This by-law shall come into full force and effect on the day of passing. READ A FIRST AND SECOND TIME THIS 141h DAY OF MAY, 2014. READ A THIRD AND FINAL TIME AND PASSED THIS 14111 DAY OF MAY '2014. MAYOR -Dave Beres TOWN CLERK-Donna Wilson UTILITIES Looking beyond··· April 2, 2014 David Calder Chief Administrative Officer Town of Tillsonburg 200 Broadway, 2nd Floor Tillsonburg ON N4G 5A7 Re: Public Meeting on Tillsonburg Hydro Dear Mr. Calder: Vice President, Business Development Horizon Utilities Corporation 55 John St. North, Hamilton ON L8R 3M8 Tel: 905.317.4780 Cell: 905.531.4232 neil.freeman@horizonutilities.com www.horizonutilities.com I am writing to you to request an opportunity for Horizon Utilities, the local distribution company owned by the cities of Hamilton and St. Catharines, to address the upcoming public meeting on the future of Tillsonburg Hydro. As I am sure you are aware, the environment in which local distribution companies operate is undergoing significant changes and will continue to evolve over the years to come. These changes have provided significant challenges to local utilities. Horizon Utilities' focus is continuously directed to ensuring that our utility business makes our communities better places to live and work. We have been recognized for our industry leadership on contributing to the sustainability of the communities we serve. As a company, we pride ourselves on both our successful performance -low customer rates, low operating costs, excellent customer service, and strong shareholder dividends -and being a great place to work for our employees. I would appreciate an opportunity to present to your public meeting on how Tillsonburg Hydro might best continue to serve its customers and municipal shareholder in the future. I look forward to hearing from you . Neil Freeman Vice President, Business Development May 13,2014 Town ofTillsonburg Tillson burg Town Council 200 Broadway, Tillsonburg, ON TILLSONBTTR£' W& llJrmg mimi 'U Tillsonburg BIA Re: Disposition ofTillsonburg Hydro Dear Mayor Beres & Town Council, It is with regret that we cannot be in attendance at the special meeting. Our Board will be in a Strategic Planning meeting with the Ontario Ministry of Agriculture, Food and Rural Affairs. On behalf of the Tillsonburg Downtown Business Improvement Area (Tillsonburg BIA), I would like to inform all persons involved in the decision of either selling or keeping Tillsonburg Hydro Inc. (THI) of the effects their decision will have on Tillsonburg's core shopping area. • Loss of businesses due to increased rates for hydro and services • Loss of the installation of Christmas lights and decorations on the main street and the side streets respectively, in the Downtown core • Loss of services and hydro to our Electronic Bulletin Board signage • Loss of the installation of lights on the Christmas tree in the Sears Parkette • Loss of service for the illumination of the trees on Broadway • Loss of service to fix outdoor electrical outlets beside trees • Loss of the installation of banners announcing upcoming events as well as seasonal banners -ie. Canada Day flags, Turtlefest banners, Shop Tillsonburg Banners • Loss of maintenance and installation of electrical units for special events in the downtown-ie. Clock Tower outlets for special events such as the New Year's Eve fireworks • Loss of installation/removal of decorative hanging baskets both in the summer and in the winter • Loss of installation and current partnerships in planning upgrade of repeaters on the traffic lights to improve Wi-fi reception in the Downtown • Loss of support for Special Events in the Downtown ie. Turtlefest, New Year's Eve P.O. Box 192, Stn. Main Tillsonburg, ON. N4G 4H5 The Tillsonburg BIA and the Town ofTillsonburg has a Memorandum of Understanding (MOU) that works for both parties and their budgets. Assuming the sale of THI, if the BIA were to continue with the above Beautifications projects on an ongoing basis they would have to hire a bucket tluck and staff to execute the above installations and services annually. This will in turn cost a phenomenal amount of money to the town since the costs are currently being covered by the THI budget. Having our own services at hand has been as asset to our Downtown and has been crucial in the Downtown's ongoing Revitalization plan. Thousands of dollars in savings will be lost and many of these programs may no longer continue. In closing, the Tillsonburg BIA expects that our concerns are taken into consideration when a decision is made on the fate of THI. Warm Regards, ~~ Virginia Armstrong J Executive Director, Downtown Tillsonburg BIA 20 Oxford St., Tillsonburg, ON N4G 1G2 \ Presentation to Tillsonburg Council May 14th, 2014 In 1999, Tillsonburg Council of the day had a decision to make ...... whether to sell, merge or retain the assets of the former Tillsonburg Public Utility Commission which was about to be disbanded under the Provincial Electricity Act. Council felt it was in the best interests of the Community to retain control of the Electrical Distribution in Tillsonburg to maintain excellent Customer Service; competitive Hydro Rates provide efficient operations and utilize the utility as an economic driver for Tillson burg. THI was established as a Business Corporation with a Board of Directors appointed by the Shareholder represented by Council. But uniquely it was a Virtual Company without employees. It would contract with the Town under a Master Service Agreement. With this the Town would provide Management, Linesman, technicians, customer service and billing staff as well office and building space. Also provided by the Town was rolling stock-trucks. For this the Town receives an annual payment including a Management Fee. This was about 2. 7 million dollars in 2013. THI received some of the Assets of the previous PUC including Lines, Poles, related inventory, Transformer Stations including the land they were on. The Town retained the balance. Unlike other Line Distribution Companies, Tillsonburg Hydro is in effect merged with the Municipality to benefit from the sharing of costs. As well, the County of Oxford contracts with the Town to provide Water and Sewer operational and billing services including Customer Service within the Town of Tillson burg. This is a unique arrangement which results in ONE STOP Shopping for the Customer at the CUSTOMER SERVICE CENTRE. Town Council is again being asked to make a Decision on the control of Hydro in the Town of Tillson burg. The argument for selling or merging appears to be made on the basis of how much THI can be sold for. It would appear that the valuation reports could put it around Fifteen Million. However, let's look at what THI is currently contributing financially to the Town of Tillson burg. \ If we look at Exhibit 28 provided by the Town which shows the impact on the ) Town Taxes ifTHI was sold we see two bottom line figures. An Initial Year Cost and an annual cost. The Initial Year cost of $1,659.937 represents costs to the Town which will have to be deducted from the Sale Proceeds. What aren't identified here are the additional costs of the disposition of THI which are in the $300,000 to $400,000 range to carry out the process ... lawyers, consultants, etc .. So ifTHI was sold for $15,000,000, the Town might only net $13,000,000. More importantly the Town is benefitting on an annual basis as shown by $908,475 by having THI. Your municipal taxes are currently being reduced by this amount. And in fact in 2013, this amount would have been in excess of a million dollars because the dividend paid to the Town by THI was not $150,000 as shown but $300,000. This million would represent about 8 percent of the Municipal Tax Levy If THI is sold the taxpayers of the Town will have to make up the lost revenue that THI is currently contributing to the Town ..... in 2013 this was in excess of$ 1 million dollars. Some would say that we will have the proceeds of the sale of THI. Let's look at that. If the net proceeds are 13 million, one million each year would have to be used to compensate for the loss THI is contributing to the Town .... this will last for maybe 15 years with interest earned on. After that taxes will have to be raised by one million dollars each year. Or if the 13 million is invested at today's interest rates, this would have a return of $400000 ..... a shortfall of $600,000 each year resulting in a Municipal Tax Increase of 5%. What should also be noted is that the Town is restricted by the Municipal Act in how it can invest its money ..... basically government secured funds such as GICs which currently return less than 3 percent. What aren't as apparent on this Impact sheet are the Loss of Water and Sewer Billing and Customer Service. If Hydro is sold or merged, the Town will lose the capability of continuing Water and Sewer Billing and Customer Service .... this will revert back to the County. I would further suggest that all Water and Sewer \ operations will follow. This will result in the loss of the One Stop Shopping at the Town's Customer Service Centre. Financially disposing of THI does not make financial sense. Nor does it make sense from a customer service point of view. The difference today's Council find itself from the 1999 Council is it has 14 years of successful operations of THI to rely on in making its decision. THI is a profitable company with a solid balance sheet and relatively little debt. It has invested its earnings by replacing low voltage lines and eliminating a number of transformer stations thus reducing line loss which reflects in lower Hydro Rates. It was one of the first LDCs to install Smart Metres which incidentally have the capability of also transmitting water meter information if this can be worked out with the County. Through its business arrangements with the Town, Tillson burg Hydro has enjoyed cost sharing which has allowed its customers to have some of the lowest hydro Rates in the province. Your Worship and Members of Council. Thank you for the opportunity of making this presentation. I hope it shows that the right decision is to not sell or merge Tillson burg Hydro. Instead I would suggest that we need to get back on track creating an environment where Tillsonburg Hydro can thrive in a work environment which emphasizes excellence and innovation to the benefit of the Tillsonburg Hydro Customer h • r1z UTILITIES Looking beyond··· April2, 2014 David Calder Chief Administrative Officer Town of Tillsonburg 200 Broadway, 2nd Floor Tillson burg ON N4G 5A 7 Re: Public Meeting on Til/sonburg Hydro Dear Mr. Calder: Vice President, Business Development Horizon Utilities Corporation 55 John St. North, Hamilton ON L8R 3M8 Tel: 905.317.4780 Cell: 905.531.4232 neil.freeman@horizonutilities.com www.horizonutilities.com I am writing to you to request an opportunity for Horizon Utilities, the local distribution company owned by the cities of Hamilton and St. Catharines, to address the upcoming public meeting on the future of Tillson burg Hydro. As I am sure you are aware, the environment in which local distribution companies operate is undergoing significant changes and will continue to evolve over the years to come. These changes have provided significant challenges to local utilities. Horizon Utilities' focus is continuously directed to ensuring that our utility business makes our communities better places to live and work. We have been recognized for our industry leadership on contributing to the sustainability of the communities we serve. As a company, we pride ourselves on both our successful performance -low customer rates, low operating costs, excellent customer service, and strong shareholder dividends -and being a great place to work for our employees. I would appreciate an opportunity to present to your public meeting on how Tillsonburg Hydro might best continue to serve its customers and municipal shareholder in the future. I look forward to hearing from you. Neil Freeman Vice President, Business Development ) / / / / I Public Meeting May 14, 2014 6:00 p.m. If you require assistance, please speak with the Deputy Clerk. Ordersrof the Day: CALL TO ORDER ADOPTION OF AGENDA Proposed Resolution No.1: AGENDA Town of Tillsonburg Special Coundl Meeting on Wednesday, May 14, 2014 6:00PM Tillson burg Community Centre (Won's Auditorium) Chair: Dave Beres THAT the Agenda as prepared for the Special Council Meeting of May 14, 2014, be adopted. MAYOR WELCOME PUBLIC MOMENT OF REFLECTION DISCLOSURE OF PECUNIARY INTEREST OR THE GENERAL NATURE THEREOF 5/14/14 1 / ) Tlllsonburg Hydro Inc. -Financial Information 2009 2010 2011 2012 2Dll OM &A Per Customer*" s 278.17 s 330.22 s 329.73 s 3~2.().1 s 376.23 (see note 1 below) Dividends Paid Lo $ 100,000 s 150,000 $ 250,000 $ 150,000 $ 300,000 Shareholder (Town ofTillsonburg) Return of Capir;:~l Paid to Shareholder $ 200,000 MSAfee s 136,305 s 140,000 s 140,000 s 140,000 s 140,000 Rent s 91,900 s 90,144 s 90,144 s 132,634 s 132,620 Indirect labour s 471,696 s 538,512 s 608,808 s 703,456 s 755,614 • OM&A pet customer Is derived by summing Operations, Maintenance and Administration Com and dividing by Total Customers This figure is derived consistently for all local Distribution Com ponies ldcntlficd in the OEB Yearbook of Distributors 2013 OM &A Per Customer Calcul.,tion excludes the effect of the Smi1rt Meter Dispo~ltlon one-time entry Orders•of the O~y: INFORMATION ITEMS AGENDA Town of liillsonburg Special Coundl Meeting on Wednesday, May 14, 2014 6:00PM Tillsonburg.CommunitY,_ Cetitre (lllon's Auditorium) Chair: I Dave Beres 1. Tillsonburg Hydro Inc. Frequently Asked Questions Gil 2. Tillsonburg Hydro Inc. Timeline Gl PRESENTATIONS 2014 Budsot $ 380.99 $ 150,000 s 140,000 s 132,620 s n5,173 3. Opening Remarks Gll Presented By: David Calder, CAO 4. Financial Information Gi) Presented By: Wayne Brett, Finance Regulatory Affairs Officer 5. Tillsonburg Hydro Inc. Board of Directors Gll 5/14/14 3 Impact to Town's Net levy lfllfl was sold -No employees transferred to new entity Costs{Savll1&') One:tlme C..sts/ISoylnpl l!lillal..Ynr: AmuallftY HR Notice and:>ever.~noe 05tlmated costs s 1.322,000 $ . Outplacement (newftem) 110,000 . Debt o/s -principal repayment 227,937 Sales of Fleet uniUatNBV (330 634) Cost of Fleet unlu at NBV 330,634 Mulll~lem[Com/lSavl!!l•l iW1zu. Direct labour & benefits no lonaer absorbed In tholovy (noYI) (61,789) Indirect labour dlarged to THI, would be ab<orl>•d by Town 31B,146 ~lrtii2DII 'iiSI Fleet rovonue charges 19,392 Building reot revenue 1om (from THI and Water) 219,360 Posta go oqulpment rental 3,366 £!tlmated outsouttint of Tree trimming 100.000 Estimated olll:source of Streetlights 20.000 THI MSA Manogement Fee 140.000 THIDivldl!lld 150.000 lnvti1ment rctvm on proceeds not known Total COSIS/(Savlnp) s 1,659,937 s 908,475 Members of the public who are not on this list but wish to speak will have the opportunity to do so after the last speaker on the registrar. All speakers have a MAXIMUM of 10 minutes to speak. 5/14/14 5 ut Ascent and St. Thomas Energy ~ Ascent Group of Companies are wholly owned by the City of St. Thomas ~ Ascent owns St. Thomas Energy Inc. (regulated entity) and Ascent Energy Services Inc. (affiliate) , History spans over 1 00 years ( 1906) Acquiring businesses since 2007 Delivered upwards of $10 million in dividends and interest to the City since 2000 One of the largest medium/high voltage electrical companies in SW Ontario 2.6 million hours worked without a lost time accident Growth Strategy-$5 million in annual dividends plus interest by 2018 Shareholder benefits through dividends from regulated and affiliated entities honesty attitude respect teamwork TIRsonburg Hydro -Pubflc Meeting St. Thomasenergyinc. W•r• Your L«d Powu Dirlribuior ~ 16,690 customers (14,828 residential; 1,862 commercial) ,. 95% Customer Service ranking > Lowest rates of the "many" offering options for utilities St. Thomas POI'IIlrS!roam 5121.78 $122.53 OEB 2014 RATES-800 kwh Residential Entogrus Tilson burg 5127.02 S128.56 ErioThames 5129.43 H~IOOne Brampton $122.17 a division or Asctnt ~roOne Urban $141.47 Historically in top 5 international utilities as per the Canadian Electrical Association survey for reliability .. Water and sewer billing services for City Offer all standard OPA programs to customers Support community programs honest)' attitude respect teamwork Tmsonburg Hydro -Public Meeting Slide3 Hydro One Medil.ln 5157.00 Slide4 5/14/14 7 ~~~~- nities for Tillsonburg and Ascent * Shareholder Commwlity -; ~PriCe i Cash & EqWty OptionS i . Shared Service Options ! KnownEnlity · AhadyHire · ·~GUarantee Known Entity No Emj>loymOnt LOss 1 rack Record between our Communities Profit Sharing Partial Acquisition Merger Community Focus l.a.vRates HighReliabiity Custon\ei,c.ie Community Focus honesty attitude respect teamwork I Able to SUpport Water Biling '·'Allie to Invest in lnfras1rudute Abiity to Scale lnve;tment Cash & Equity OptionS Industry Expemse Shar<d Service Options Abletoln,.stinlnfrastructure AsAhove Still Own Utility i Shared Ownerchip (%) As Ahove ': :DMdeildo from Utility and Coq>etitive Entity Still Own Utility :Shan!dSeMceOption. Tillsonburg Hydro -Public Meeting • Subject to City of St. Thomas Council Approval You're not alone No Impact Relocation Guarantee No Employment loss Profit Sharing Slide7 ,. Ascent and St. Thomas Energy are known entities with a proven track record on service, reliability, low rates and community focus ~ Ascent is prepared to engage in discussions with Tillsonburg to come up with the best solution for our Customers, our Shareholders, our Community and our Staff. honesty attitude respect teamwork Tilis<>nburg Hydro -Pubr.c Meeting SlideS 5/14/14 9 E RTH CORPORATION Lt1lu' Hurcn1 L_ . .'<'""'/=~··-··1 ~J; ~ ERIE THAMES 5/14/14 11 2000 2010 • Aylmer PUC • Clinton Power • Beachville PUC • West Perth Power • Belmont PUC • Ingersoll PUC • Norwich PUC • Port Stanley PUC • Zorra PUC • Tavistock PUC One share • One vote per municipality 5/14/14 13 5/14/14 --J a: LLJi 3: C) C- ERIE THAMES Your Home Town Utility LOCAL Control • Employment • Involvement 15 5/14/14 Hydro Inc. 17 Orders of the Day: DELEGATIONS AGENDA Town of Tillsonburg Special Coundl Meeting on Wednesday, May 14, 2014 6:00PM Tillsonburg Community Centre (lion's Auditorium} Chair: Dave Beres 6. Delegations (1 0 minutes maximum per speaker) NOTICE OF MOTION BY-LAWS Prooosed Resolution No.2: HAT By-law ~5. to Confirm the Proceedings of the Council Meeting of May 14, 2014, be read for a first and second time and this constitutes the first and second reading thereof. ..J Proposed Resolution No.3: HAT By-Law 3825, to Confirm the Proceedings of the Council Meeting of May 14, 2014, be given third aod final reading and the Mayor and Clerk be and are hereby uthorized to sign the same, and plaoa the Corporate Seal thereunto . .J ADJOURNMENT Public Meeting May 14, 2014 6:00 p.m. If you require assistance, please speak with the Deputy Clerk. 5/14/14 19 COUNCIL RESOLUTION AGENDA ITEM NO.: Date: May 14, 2014 RESOLUTION NO.: --=2 __ MOVED BY: /~ SECONDED BY: --~..:::::::::=::::::::..::~·==::::::=--- THAT By-Law 3825, to Confirm the Proceedings of the Council Meeting of May 14, 2014, be read for a first and second time and this constitutes the first and second reading thereof. D Carried Recorded Vote D Defeated D Deferred Tabled COUNCIL RESOLUTION AGENDA ITEM NO.: __ Date: May 14, 2014 RESOLUTION NO.: 3 J_ <"~ MOVEDBY: ~ SECONDED BY: -~__:::=:s;:z::~===----- THAT By-Law 3825, to Confirm the Proceedings of the Council Meeting of May 14, 2014, be given third and final reading and the Mayor and Clerk be and are hereby authorized to sign the same, and place the Corporate Seal thereunto. m Carried D Recorded Vote D Defeated D Deferred Town Council 10 Lisgar Avenue Tillsonburg Ontario N4G SAS March 19,2014 Re: {(Dining table" Discussion on {(Disposition" Tillsonburg Hydro Members of Council Thank you for the opportunity to voice my opinion on this matter It has always been my opinion, this was the intent of our founding forefathers to resolve issues, In this manner. PROBLEM-Identify in writing, who wants the change, why? SOLUTION-discuss with all persons concerned, is change necessary, why? ACTION TAKEN-by administration if any? If program is not broken, don't fix it, if you can show me a better way I will listen and consider change. We should always learn from past history and ask ourselves some questions? -Is bigger always better? NO -Would I prefer to go to China to get the answers to my questions? NO -Or go down to our local municipal office? YES -Who is better equipped to give us reliable answers? Local talent -Do I enjoy using a 1-800 #talking to an iron lady NO I prefer people (I enjoyed Cam McKnights quip about horses) sometimes we should talk back -Dave Morris brought it to our attention if passed as written it would have approved courses of action including closed negotiations in an open RFP for a variety of options including sale or merger of THI.(this has been deferred) -McKnight said council has both the right and responsibility to deliberate and make major decisions on a wide range of services and assets. Those are all things council should look at, but they need to let the public know and give the public opportunity for input on those issues. The group's present also indicated, Said Mr. Morris, concern council did not have access to all pertinent information, Page 2 of 2 And we are all shareholders, Horton. Apart from a combined public request for that form of information and input, participants also wished to bring forward what in their opinion, is their version of pertinent information on both Tillsonburg Hydro financial and community impact. Tillsonburg hydro was born out of a Provincial mandated turnover of local public utilities, said Morris, CAO for a council of the day, options, sale, amalgamation or retention. The decision at that time was retain. Good choice That's where we find ourselves now said Mr. Morris. Tillson burg hydro has ran efficiently for years. That's more than I can say for Ontario Hydro. That corporation has been mismanaged for years. When someone was finally held accountable, they were permitted to resign and paid a tremendous severance package. In my humble opinion that is (/rewarding mismanagement." That is one of our biggest problems today that practice should be reviewed. With the Provincial debt at $263.5 billion I don't know how they can be an encouragement to anyone, that should tell us bigger is certainly not better, the status quo look pretty good to me. If Mr. Morris figures can be confirmed $900.000.00 per year would be a real asset to the Town and to the taxpayer, why would we want to sell this source of income. Plus Mr. McKnight points out there is roughly another $1,000.000.00 of salaries and potential economic impact related to Tillson burg Hydro Inc. senior staff. Linemen, customer service rep. That means jobs in our community. Big brother who supplies everything except what is needed, our federal government, $618.8 billion in debt, is big really better? Need I say more. We should learn from passed history. I like the Horton quip about the golden goose, but it's so true. Dave Morris has it right, it doesn't make sense. This is an excellent report by the Tillson burg News. People should pay attention. A fan of Tillsonburg Ray Andress Tillsonburg Ontario ; happen t;,-, he one pfth.; n~tHl}" Pandand donatnr~~ past and p-resent, and s-tili lli'VC~ !\1y na;me is George GHvocsy\ Gyulv~-zi} and r fl-'iVe rived in thi~ ~cmm.uniry r{--.r 7Q years plus ... ~tl my r-=1at1~·es still h\~c iu d1e TiHsnnburg an .. ~ e. cc-~r. for my grru.lJ.i~Ji1 \Vho lh ~s in Lt..lldirn, n1y grandd ... ughtcr ~~vho i~ a poii(:'(! officer in Toton .o snd !1 nepl'lCV/ "\Vh J h; ~1 architect live~ rn Europi:, TI1af h1story of my ·amily i;; v.::H koovm to l)'.Jople in the area .. The arrgumenl ff·om the LHwn Ct,uns~iors is th-._t the thing. that fi~ry_p~ru:d \vere· flOJ Oli Ut) 'tA~arch"', .... \.s one uf d1 m-ny donors 1r !3 rid to fhc to\vn a.rld as d~·!Ciop0r tv~ h;.;d t•J ~~)nate 5~~1 of the land teL the tOV'Tl. We tr1 ~a to ci\ ,;. cash in Heu of hmd. ThL;; ..,. a:rranr:eiDent to most dcv-el--:•pers was prelerrcd becaus .... -'''e controlled our ~urr(rundin(n~. Cournet even obJected to us nami~ thi: cxrr-a 6,.8 a·:res.. Vv'c: 'v~u1i.t-d to name the. Par: Gyuh e~u~ in honor of rny lalhcr. Vf~ vtould prefer that i fHH~ toi'Nn ·was getting rid )[Parkland 1hat th1: pr~c~:::-ds be Jiven tn c arity~ not 10 redu(·e th~ d~ht ':if the to\VIt . .. ~ ti b ~~ines~ l -et~s.on the ~.:st '\\~ay b) get out 01" debt is tq cut speudirtg .. There i~JnanJ:· __ \Y-$lJ;~s of Q.oin2 ttdss: ).hc:r..; are ruany qualified busines::-, peoplt m the ommu.1"f.ity ilia \Voujd grtr "Jy ·· clp th~+ l0'\"\11 in doing rf1is. T b+.::li ~ve that moS1 people \Vt;Hiid do hL free of chaff!e and ~\··otlid be gJarl tr' l1e1p. I am tlP~l:Jlc:a to an.' question~ tllat the town may h~tvc .. !Jla.t I \Vill tf"":' to ~n.s·r;eJ ) tc1 rh~ best ufrnv a.hilitv. . • 7 EO&E " HAYHOE™ -·HOMES·- Pc.rfornumce CommuJJilies h1c. '\:--------------------------------------------------------------------------' May 14,2014 Town ofTillsonburg I 0 Lis gar Ave. Tillsonburg, ON N4G 5A5 Attn: Council ofthe Town ofTillsonburg Re: Tillsonburg Residential Developments and Electrical Distribution System Expansions I appreciate the opportunity to provide comment on the future ofTillsonburg Hydro Inc. (THI). My comments concern the role of the "Local Distribution Company" and Electrical Distribution System expansions. Introduction and Background In 2012 the Town ofTillsonburg hosted several Target Tillsonburg symposiums to gather information from local realtors, home builders and residential land developers. Our understanding is that the Town ofTillsonburg recognizes the need to foster growth and the Town was reaching out to stakeholders requesting input into how the Town could be more competitive and how to market the Town of Tillsonburg to attract residents to this community. In 2013 Hayhoe Homes completed the servicing of 52 residential lots on Colin Avenue. We had several meetings with staff ofTHI and appeared before Council on several occasions to present concerns about the underfunded contribution initially proposed by THI. We have experience in residential land development in other municipalities and with other LDCs. In early 2014 we were notified that THI had revisited the economic evaluation model and the OEB regulations and on May 8, 20 14 we met again with staff of THI. We understand a written communication is forthcoming from THI to explain how THI will evaluate future distribution system expansions. The Future and the Role of the Local Distribution Company for future Electrical Expansions The Town of Tillson burg is committed to growth and we are also interested in exploring future residential development in the Town ofTillsonburg. The policies of the Local Distribution Company (LDC) have an impact on the future growth of Tillsonburg. The impact of the merger or sale ofTHI on future electrical expansions should be carefully considered at time of negotiation. As a developer we offer several specific recommendations: I. Policies and Inputs of the LDC used in the Economic Evaluation Model should be determined and communicated to the development community. We request that any changes be reviewed with local developers in advance. Surprises and uncertainty discourages investment. We need to know our costs to complete a thorough review prior to investing in the Town ofTillsonburg. 1 BARRIE BOULEVARD, ST. THOMAS, ONTARIO N5P 4B9 TEL. (519) 633-2050 FAX: (519) 633-2037 '-- TOWN OF TILLSON BURG Public Meeting for May 14, 2014 Record of Attendance NAME ADDRESS PHONE E-MAIL (Please Print) {Including Postal Code) ·\Sv7 OV\ SVV\\JL 70 G laVIvt ~) £w-eoj.~0 5l4 -4-.$b bv1G.f:.VV\,+Q) Q \{ # l lA.)-c9b~c. ~L f{:l7D or-.wJ .. ne+ { \ Page 1 Notice of Collection Correspondence intended for Committee and/or Council is generally received as public information, subject to the Municipal Freedom of Information and Protection of Privacy Act and will be part of the public record. AUDITORIUM ~ pe--e-~ (A_,\_ ~-e_ e____ +\ ~~. Stage P~wer: One dedicated 15 amp circuit ~Mired directly to the panel and two receptacles on the opposite side of the st age wired in series. There is a 30 am p stove plug near the electrical panel. Date of Event: Organization Name: W (J-~~~/IY Centre island ?.7"w x 16' 1 r®l ~ 9' high STAGE Contact Name: Function Type: Meeting Set-Up Time: Event Time: Attendance # 21' deep STAIRS 36'----· 54' ........................................................................................................... L.l _ ____::C&~\A:u~uc..~.., l..l...~_p +-...:..CA_c.....:~~-\-~C\.-._Cf-._·_-~1 ~ ~IV' ,L!:....:..J 3 ~(A (@'· 0() ~- Bar Area: Auditorium CS::> Coat Check: ~ ~ Coffee Urn Ice -Add'l cost Additional Instructions: lophp · f \ o ~ -c'*:o• .S L.l C..(.("-. p ro ~L..u~' 13' Entrance 70"w x 81"h 40' 40' 70' ......................................................................................................... . TCC Staff Sound Check performed by: _____________ (please print) Representative Approving Sound Check: (please print) ·-----------··--·~----. Screen on sta:)e Automated control 12'w x lO'h 4 carts available Tables 8' x 30"w Tables Round 5'diameter Coat Racks 3 -48" X 62"h 1-36" X 62"h To: "Brent McKay" <academyofmusiccentre1@rogers.com>, Cc: Bee: Subject: Re: May 14,2014 Quote Brent, The Town would like you to proceed with the set up and operation of the Special Council Meeting at the Community Centre, Auditorium on Wednesday May 14, 2014. Please confirm that you will have the complete set up done by approximately 4:30p.m. that day as I expect Council and the public will start to come in around 5:00 p.m. Please confirm, Donna Wilson Town Clerk Town of Tillson burg 200 Broadway, 2nd Floor, Suite 204 Tillsonburg, ON N4G 5A7 Phone: 519-688-3009 Ext. 3224 www.tillsonburg.ca www.DiscoverTillsonburg.ca www. F acebook.com!Ti llsonburgON Individuals who submit letters and other information to Council should be aware that any personal information contained within their communications may become part of the public record and may be made available to the public through the Council Agenda process. ---:c--:--=--=--=-----=c------c----··-------"Brent McKa}'_" ___ Hi Donna I met with Mr Batt Thursday at the c ... From: To: Date: Subject: Hi Donna "Brent McKay" <academyofmusiccentre1 @rogers.com> "Donna Wilson!Tillsonburg" <DEWilson@tillsonburg.ca>, 04/25/14 12:00 PM May 14,2014 Quote 04/25/201412:00:19 PM I met with Mr Batt Thursday at the community centre to review what is available. The following is a list of Town owned equipment for your information. Lap top Projector screen Projector PA system Wireless microphone Podium I would need to bring the following items 14-25' 'XLR to XLR mic cables ,, 2 -adapter cables 12 -microphones 12 -table top microphone stands 1 -24 channel mixing board 1 -operator The total cost for the rental of the equipment and an operator will be $ 258.00 plus HST. Thanking you for this opportunity to quote Brent McKay Academy of Music/Music Centre 20 Brock Street East Tillsonburg, Ontario 519-842-7811 Office 519-688-8263 Cell Hi Donna May 14,2014 Quote Brent McKay to: Donna Wilson/Tillsonburg 04/25/14 12:00 PM Hide Details From: "Brent McKay" <academyofmusiccentre 1 @rogers.com> To: "Donna Wilson/Tillsonburg" <DEWilson@tillsonburg.ca>, Page 1 of 1 I met with Mr Batt Thursday at the community centre to review what is available. The following is a list of Town owned equipment for your information. Lap top Projector screen Projector PA system Wireless microphone Podium I would need to bring the following items 14 -25' 'XLR to XLR mic cables 2 -adapter cables , 12 -microphones 12-table top microphone stands 1 -24 channel mixing board 1 -operator The total cost for the rental of the equipment and an operator will be $ 258.00 plus HST. Thanking you for this opportunity to quote Brent McKay Academy ofMusic/Music Centre 20 Brock Street East Tillsonburg, Ontario 519-842-7811 Office 519-688-8263 Cell file:// /C:/U sers/DEWilson/ AppData/Local/Temp/notesD39658/~web6416.htm 4/25114 ~ARMtiR Pw-~ ) ARMOR Pro Aud10 Ltd. 76 Bysham Park Dr. Woodstock, ON CANADA N4T 1R2 Phone: (519) 421-3214 Fax: (519) 539-1956 E-mail: mike@armorpro.com Web Site: www.armorpro.com BILL TO: Town of Tillsonburg 200 Broadway, 2nd Floor, Suite 204 Tillsonburg ON N4G 5A7 (519) 688-3009 Ext. P.O. NUMBER SHIP VIA Pickup PART NUMBER DESCRIPTION RENTAL Rental Charges F.O.B. Woodstock ) P.A. Sytem with 2 main speakers and 2 monitor speakers, 13 microphones, power amplifier, mixer and all required cables and stands. RENTAL Rental Charges Delay speakers with all cables, stands, and electronic delay We will bring these items but will only use and bill if required due to overflow audiance. RENTAL Rental Charges 6000 lumen projector with stand and all required cables. LAB3 Delivery, Setup & Pickup Labour Charges includes all labour and transportation for delivery, setup operation and load out for the event GST Number 13386 0197 Page 1 of 1 Quote DATE April 14, 2014 NUMBER 0000002635 CUSTOMER NO. TOWfiL SHIP TO: Town of Tillsonburg 200 Broadway, 2nd Floor, Suite 204 Tillsonburg ON N4G 5A7 (519) 688-3009 Ext. SALESPERSON DATE ORDER NUMBER 14-Apr-14 TERMS Due on Receipt QUANTITY REQ. UNIT PRICE 300.00000 65.00000 160.00000 500.00000 NET AMOUNT FREIGHT H.S.T. 0000002635 EXTENDED PRICE 300.00 65.00 160.00 500.00 1,025.00 133.25 TOTAL DUE $1,158.25 .._ __ ..;...._...-.~ \ ) Event Production Rental Quotation 1 Live Event Solutions is subject to the availability of equipment and personnel upon confirmation. To request a confirmation please return a signed copy of this by e-mail with written authorization. In order to secure a booking a Purchase Order number or Credit Card number with the expiry date, and cardholder name may be required. than 72 hours prior to the event date and time stated on this quotation may be billed in full or in part to cover any and all expenses CanC<'!IIatiorls made less than 24 hours prior to the event date and time stated on this quotation will be billed in full. Transportation costs will be adjusted to cover any requests made by the client or persons in charge during the set up, operation, or dismantling of Date: 7 Colleen Pepper Marketing & Partnerships Officer Development & Communication Services Town of Tillson burg 200 Broadway, 2nd Floor, Suite 204 Tillsonburg, ON N4G 5A7 Phone: 519-688-3009 Ext. 3231 London Inc. AV QUOTATION Staging for Public Meeting on May 14, 2014, Tillsonburg Community Center QTY DESCRIPTION 1 Fastfold screen, 6'x 8' or 7' x 10' space permitting Rear projection surface 1 4500 lumen XGA projector, short lens 1 Display laptop, wireless remote control 1 Wireless mic and stand for audience Q&A 12 Conference Table mics, Council members 1 8-Channel audio mixer *4 Powered speakers & stands * Not required if in house PA system available 3 AV Tech delivery, set up and operate PRICE $125.00 $150.00 $50.00 $50.00 $275.00 $35.00 $200.00 $200.00 Please do not hesitate to contact me with any questions or if I can be of any assistance. Video Works London Kevin Suzuki F R E E MAN AUDIO VISUAL CANADA 3 VICTORIA Fax (250J381-0680 Tel. (778 410-2522 WINNIPEG Fax (204J775-6312 Tel. (204 775-6198 QUEBEC Fax (418J683-5843 Tel. (418 687-9055 04/02/2014 VANCOUVER Fax (604J255-0225 Tel. (604 255-1151 HAMILTON Fax (888J886-5328 Tel. (905 524-2414 FREDERICTON Fax (506J452-Q805 Tel. (506 459-1117 I BILLING ADDRESS I ADRESSE DE FACTURATIONj TOWN OF TILLSONBURG Dev & Communication Services 200 Broadway Street 2nd Floor, Suite 204 Tillsonburg, ON, CAN, N4G 5A7 WHISTLER Fax (604J938-3411 Tel. (604 932-3357 LONDON Fax (519J668-0019 Tel. (519 668-7745 SAINT JOHN Fax (506) 452-0805 Tel. (506) 459-1117 AVC ORDER DATE CON'!' ACT P.O. NUMBER ESTIMATE & RESERVATION AGREEMENT EDMONTON Fax (780J489-8698 Tel. (780 454-8840 TORONTO Fax (905J361>-0274 Tel. (905 361>-9200 MONCTON Fax (506J452-0805 Tel. (506 459-1117 CALGARY Fax (403J235-1564 Tel. ( 403 235-1563 OTIAWA Fax (613J521>-0850 Tel. (613 526-3121 HALIFAX Fax (902J468-9656 Tel. (902 468-4485 DEVIS ET RESERVATION 21270 /1 B. ESTIMATE SASKATOON Fax (306J652-4799 Tel. (306 665-7874 MONTREAL Fax (514J631-6727 Tel. (514 631-1821 NEWFOUNDLAND Fax (902J468-9656 Tel. (902 468-4485 haywood -Apr 02, 2014 09:35 I SHIPPING ADDRESS I ADRESSE D'EXECUTIONI TILLSONBURG COMMUNITY CENTRE 45 Hardy Avenue Tillsonburg, Ontario DELIVERY DATE AND TIME DELIVERY VIA DATE ET HEURE DE LIVRAISON -1 J:!VRAISON VIA 05/14/2014 14:00 FREEMAN STARTING DATE AND TIME RENTAL PERIOD DATE ET HEURE DE DEPART ·-lf ERIODE DE LOCATION 05/14/2014 18:00 1 DAY ENDING DATE AND TIME PICKUP VIA I •DATE DE COMMANDE ·-NO. DE BON DE COMMANDE DATE ET HEURE DE TERMINAISON CUEILLETTE VIA -· -04/02/2014 Ms. Colleen Pepper 05/14/2014 20:00 FREEMAN CUSTOMER NUMBER NE TELEPHONE NUMBER FACSIMILE NUMBER PICKUP/RETURN DATE AND TIME PST NUMERO DE CLIENT VENDEUR NUMERO DE TELEPHONE NUMERO DE TELECOI'IEUR . -DATE ET HEURE DE CtJEILLETTE/RETOUR TVF' C76583 CH (519} 688-3009 05/14/2014 20:00 =~~QUANT. DESCRJ.PTION ~ I PRICE J TOTAL '.:Jt. f>ERIODE PRIX ***\iiStl~LS -I?RE>JECliiO~t·• 1. 0 E>AY 550.00 550.00 .00 70171 1 LAPTOP 17 2.3G W7 OFF2010 W/S 1. 00 DAY 150.00 150.00 ***AUDIO*** 61547 1 1.00 DAY 40.00 62415 1 1.00 IDA¥ 100.00 ** COUI'i'JCIIUSilii\FF MICIROPIHONES ** 61547 12 COI'i'JPEJREilJCE MICROPIHONE 12" 1.00 IDJ.\iY:' 40.00 61033 12 TABLE STAND FOR CONFERENCE MIC 1.00 DAY .00 * * * T ED * * * .· .·c. .· '<> PROVINCIAL SALES TAX (PST) AND GOODS AND SERVICE TAX (GST) WILL BE CHARGED IN ACCORDANCE WITH THE LEGISLATION OF I I I THE PROVINCE WHERE MEETING IS HELD. (SEE THE FOLLOWING PAGE) TOTAL LA T AXE DE VENTE PROVINCIALE (TVP) ET LA T AXE SUR LES PRODUITS ET SERVICES (TPS) SERONT APPLIQUEE$ EN VERTU DE LA ' "'I DE LA PROVINCE OU LA CONFERENCE A LIEU. (VOIR A LA PAGE SUIVANTE) 1l ASE RESERVE EQUIPMENT AND PERSONNEL AS QUOTED ABOVE SUBJECT TO THE CONDITIONS ON THE GST I TPS : R105164933 t'OLLOWING PAGE. QST I TVQ : 1002036904 VEUILLEZ RESERVER L'EQUIPEMENT ET LE PERSONNEL REQUIS POUR LA PRESENTE SOUMISSION, AUX CONDITIONS MENTIONNEES A LA PAGE SUIV ANTE. I I APPROVED BY I APPROUVE PAR DATE: PER/PAR DATE: F R E E MAN AUDIO VISUAL CANADA VICTORIA Fax (250) 381-0680 Tel. (778) 410-2522 WINNIPEG Fax (204) 775-6312 Tel. (204) 775-6198 QUEBEC Fax (418) 683-5843 Tel. (418) 687-9055 VANCOUVER Fax (604) 255-0225 Tel. (604)255-1151 HAMILTON Fax (888) 886-5328 Tel. (905) 524-2414 FREDERICTON Fax (506) 452-0805 Tel. (506) 459-1117 WHISTLER Fax (604)936-3411 Tel. (604) 932-3357 LONDON Fax (519) 666-0019 Tel. (519) 666-7745 SAINT JOHN Fax (506) 452-0805 Tel. (506) 459-1117 EDMONTON Fax (780) 489-8698 Tel. (780) 454-8840 TORONTO Fax (905) 366-0274 Tel. (905) 366-9200 MONCTON Fax (506) 452-0805 Tel. (506)459-1117 CALGARY Fax (403) 235-1564 Tel. (403) 235-1563 OTTAWA Fax (613) 526-0850 Tel. (613) 526-3121 HALIFAX Fax (902) 466-9656 Tel. (902) 466-4485 ESTIMATE & RESERVATION AGREEMENT DEVIS ET RESERVATION 21270/2 B.ESTIMATE SASKATOON Fax (306) 652-4799 Tel. (306) 665-7874 MONTREAL Fax (514) 631-6727 Tel. (514) 631-1821 NEWFOUNDLAND Fax (902) 466-9656 Tel. (902) 466-4485 3 04/02/2014 AVC heywood ·Apr 02, 2014 09:35 I BILLING ADDRESS I ADRESSE DE FACTURATIONj TOWN OF TILLSONBURG Dev & Communication Services 200 Broadway Street 2nd Floor, Suite 204 Tillsonburg, ON, CAN, N4G SA? ORDER DATE CONTACT DATE DE COMMANDE 1- 04/02/2014 Ms. Colleen Pepper CUSTOMER NUMBER AlE TELEPHONE NUMBER NUMERO DE CLIENT VENDEUR NUMERO DE TELEPHONE C76583 CH (519) 688-3009 . - P.O. NUMBER NO. DE BON DE COMMANDE FACSIMILE NUMBER NUMERO DE TELECOPIEUR I SHIPPING ADDRESS I ADRESSE D'EXECUTIONI TILLSONBURG COMMUNITY CENTRE 45 Hardy Avenue Tillsonburg, Ontario DELIVERY DATE AND TIME DELIVERY VIA DATE ET HEURE DE LIVRAISON LIVRAISON VIA -05/14/2014 14:00 FREEMAN STARTING DATE AND TIME RENTAL PERIOD DATE ET HEURE DE DEPART PERIODE DE LOCATION - 05/14/2014 18:00 1 DAY ENDING DATE AND TIME PICKUP VIA DATE ET HEURE DE TERMINAl SON CUEIULETTE VIA 05/14/2014 20:00 FREEMAN PICKUP/RETURN DATE AND TIME PST . Q_~HEURE DE CUEIULETTEJ~ TVP 05/14/2014 20:00 - - PRODUCT~~~ DESCRIPTION TERM J PRICE J TOTAL .~ CODEDEFRODU QUANT. PERIODE 1'RIX ** AI!J91ENCE Q&A MICROPHONES ** ~1511 2 SHURE SM-58 MICROPHONE 1.00 DAY 30.00 1005 2 FILOOR STAND FOR MICROPHONE 1.00 DNY .00 ** MIXING/PA SY TEM ** 67130 1 2 SPEAKER TANNOY V15 SOUND SYSTEM 1. 00 DAY 400.00 1245 1 16+4 CH MIDAS VENICE 240 MIXER 00 61812 1 GRAPHIC EQUALIZER .00 61320 2 liANNOY V15 POWERED SPEAKER .00 61326 2 SPEAKER STAND .00 63228 2 100' AC SINGLE I!JGROl!JND CABLE .00 63253 2 1 00' XLR TO XLR CABLE .00 31589 1 12 X 4 CHJXNNEt 2€>0' AUDIO SNAKE .00 ***ESTIMA liED LABO R*** 2 SERVICE REP TRAVEUSETUP 03:00 HOU 1 TECH SERVICE REP OPERATE 02:00 HOUR 2 TECirl SERVICE REP DISMANTL..E/TiRAVEt. 02:30 HOILJR ***liRANS PORT A TION*** 1 IDEI:..IV,ER¥ & PICKI!JI? EACH 100.00 * * * TO BE CONTINUED * * * ,,;_ PROVINCIAL SALES TAX (PST) AND GOODS AND SERVICE TAX (GST} WILL BE CHARGED IN ACCORDANCE WITH THE LEGISLATION OF I I I THE PROVINCE WHERE MEETING IS HELD. (SEE THE FOLLOWING PAGE) TOTAL LA TAXE DE VENTE PROVINCIALE (TVP) ET LA TAXE SURLES PRODUITS ET SERVICES (TPS) SERONT APPLIQUEE$ EN VERTU DE LA • '1 DE LA PROVINCE OU LA CONFERENCE A LIEU. (VOIR A LA PAGE SUIVANTE) 'ASE RESERVE EQUIPMENT AND PERSONNEL AS QUOTED ABOVE SUBJECT TO THE CONDITIONS ON THE GST I TPS : R105164933 t<'OLLOWING PAGE. QST I TVQ: 1002036904 VEUILLEZ RESERVER L'EQUIPEMENT ET LE PERSONNEL REQUIS POUR LA PRESENTE SOUMISSION, AUX CONDITIONS MENTIONNEES A LA PAGE SUIVANTE. I I APPROVED BY I APPROUVE PAR DATE: PER/PAR DATE: F R E E MAN AUDIO VI S UAL CANADA 3 VICTORIA Fax (250) 381-0680 Tel. (778) 410-2522 WINNIPEG Fax (204) 775-6312 Tel. (204) 775-6198 QUEBEC Fax (418) 683-5843 Tel. (418) 687-9055 04/02/2014 VANCOUVER Fax (604) 255-0225 Tel. (604) 255-1151 HAMILTON Fax (888) 886-5328 Tel. (905) 524-2414 FREDERICTON Fax (506) 452-0805 Tel. (506)459-1117 I BILLING ADDRESS I ADRESSE DE FACTURATIONj TOWN OF TILLSONBURG Dev & Communication Services 200 Broadway Street 2nd Floor, Suite 204 Tillsonburg, ON, CAN, N4G 5A7 WHISTLER Fax (604) 938-3411 Tel. (604) 932-3357 LONDON Fax (519) 668-0019 Tel. (519) 668-7745 SAINT JOHN Fax (506) 452-0805 Tel. (506) 459-1117 AVC ORDER DATE CONTACT P.O. NUMBER EDMONTON Fax (780) 489-8698 Tel. (780) 454-8840 TORONTO Fax (905) 368-0274 Tel. (905) 368-9200 MONCTON Fax (506) 452-0805 Tel. (506)459-1117 CALGARY Fax (403) 235-1564 Tel. (403) 235-1563 OTIAWA Fax (613) 528-0850 Tel. (613) 526-3121 HALIFAX Fax (902) 468-9656 Tel. (902) 468-4485 ESTIMATE & RESERVATION AGREEMENT DEVIS ET RESERVATION 21270 /3 B.ESTIMATE SASKATOON Fax (306) 652-4799 Tel. (306) 665-7874 MONTREAL Fax (514) 631-6727 Tel. (514) 631-1821 NEWFOUNDLAND Fax (902) 468-9656 Tel. (902) 468-4485 haywood-Apr 02, 2014 09:35 I SHIPPING ADDRESS I ADRESSE D'EXECUTIONj TILLSONBURG COMMUNITY CENTRE 45 Hardy Avenue Tillsonburg, Ontario DELIVERY DATE AND TIME DELIVERY VIA DATE ET HEURE DE LIVRAISON LIVRAISON VIA 05/14/2014 14:00 FREEMAN STARTING DATE AND TIME RENTAL PERIOD DATE ET HEURE DE DEPART PERIODE DE LOCATION - 05/14/2014 18:00 1 DAY ENDING DATE AND TIME PICKUP VIA - DATE DE COMMANDE , _ --NO. DE BON DE COMMANDE DATE ET HEURE DE TERMINAISON CUEILLETTE VIA ,-J 04/02/2014 Ms. Colleen Pepper 05/14/2014 20:00 FREEMAN CUSTOMER NUMBER NE TELEPHONE NUMBER FACSIMILE NUMBER PICKUP/RETURN DATE AND TIME PST NUMERO DE CLIENT VENDEUR NUMERO DE TELEPHONE ·-~0 DE TELECOP.JEUR.. DATE ET HEURE DE CUEILILETTE/RETOUR TVP C76583 CH (519) 688-3009 05/14/2014 20:00 =~~~QUANT. DESCRIPTION TERM J PRICE I. TOTAL PERIODE PRIX }{Oj,'EJS )-• -TAXBS -ARE EXTRA AND ~ARE NOT INCLUDED ON THIS~ -BST.l.MATB I EQUIPMENT 1,780.00 CABLES & CONSUMABLES 89.00 LABOUR 806.00 DELIVERY PICKUP 100.00 " PROVINCIAL SALES TAX (PST) AND GOODS AND SERVICE TAX (GST) WILL BE CHARGED IN ACCORDANCE WITH THE LEGISLATION OF I , $2,77s.oo 1 THE PROVINCE WHERE MEETING IS HELD. (SEE THE FOLLOWING PAGE) TOTAL LA TAXE DE VENTE PROVINCIALE (TVP) ET LA TAXE SURLES PRODUITS ET SERVICES (TPS) SERONT APPLIQUEE$ EN VERTU DE LA --. DE LA PROVINCE OU LA CONFERENCE A LIEU. (VOIR A LA PAGE SUIVANTE) ,EASE RESERVE EQUIPMENT AND PERSONNEL AS QUOTED ABOVE SUBJECT TO THE CONDITIONS ON THE GST I TPS: R105164933 i<OLLOWING PAGE. QST I TVQ : 1002036904 VEUILLEZ RESERVER L'EQUIPEMENT ET LE PERSONNEL REQUIS POUR LA PRESENTE SOUMISSION, AUX CONDITIONS MENTIONNEES A LA PAGE SUIV ANTE. I I APPROVED BY I APPROUVE PAR DATE: PER/ PAR DATE: Town of Tillson burg 200 Broadway Suite 204 Tillsonburg, Ontario N4G 5A7 519-688-3009 ext. 3231 12 PowerPoint Remote?? 2 Mixer w/ Audio Snake 750W Powered Speakers w/Stands 4.00 hrs 2.00 hrs Schedule: Events Inc. Suite J5 265 Lawrence Ave. Kitchener, ON, N2M 5R1 2 Techs x 2hrs 2 Techs x 1hr Arrive on site to set: 4pm Rehearsal I Run Through: Event Ends: TBD Set Complete by: 6pm Event Begins: 6pm Dismantle & Remove: TBD $270.00 $250.00 $85.00 $20.00 $125.00 $40.00 $15.00 $150.00 $75.00 'lhis quotation is subject to the availability of equipment and personnel upon confirmation of acceptance. Order will be confirmed on receipt of signed estimate or e-mailed authorization along with Purchase Order number or credit card number, expiry date, security v- code and cardholder name. Cancellations made less than 72 hours prior to the date and times stated on this quotation may be billed in full or in part to cover any and all expenses incurred. Cancellations made less than 24 hours prior to the date and times stated on this quotation will be billed in full. Labour and Transportation cost will be adjusted to cover any requests made by the client or persons in charge during the set up, operation, or dismantling of an event. Client Signature Confirmation Date SPEAKERS REGISTRAR Public Meeting Wednesday, May 14, 2014 Tillsonburg Community Centre (Lion's Auditorium), 45 Hardy Ave., Tillsonburg, ON Tillsonbur H dro Inc. Public Information Meetin \-j>::' .l...l..)iH ~ -t \ \\\JeS~T As of 1:15 pm on May 14, 2014