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Veridian Connections EB-2009-0140

Response to Vulnerable Energy Consumers Coalition Interrogatories January 11, 2010

1. Ref: Exhibit 1 / Tab 1 / Schedule 10 The Application states “All of the power that Veridian distributes is acquired from Hydro One’s system. Some supply points are located at Hydro One Transformer Stations and others at the distribution voltage level. Due to Veridian’s diverse and non-contiguous service areas there are a large number and variety of supply points, however, the bulk of the power is received at 44 kV.” Request

(a) Please confirm that all of the contiguous and non-contiguous service areas of Veridian Connections Inc. (Veridian) receive supply from Hydro One Distribution) for 2010

(b) If not please indicate which service areas are supplied directly from hydro one transmission

(c) Please provide details of all the supply arrangements. Response: (a) Veridian confirms that all service areas are supplied from Hydro One Distribution for

2010. (b) N/A. (c) Exh. 1/Tab 1/Sch 1/Att 1 provides a schematic of how each service area is connected

and at what voltages.

Veridian Connections EB-2009-0140

Response to Vulnerable Energy Consumers Coalition Interrogatories January 11, 2010

2. Ref: Exhibit 1 / Tab 2 / Schedule 1 / Page 16 The Application States “Veridian proposes that the 2010 base revenue requirement be assigned to the two rate zones in the same proportions used to establish its 2006 Board approved distribution rates. The allocations used at that time were 94.04% to Veridian_Main and 5.96% to Veridian Gravenhurst. For the 2010 test year, the resulting apportionment of base revenue requirement is:

Veridian Main - $45,059,625 Veridian Gravenhurst - $2,855,757

Request

(a) Provide a continuity schedule that shows starting in 2006, the components of and total base distribution revenue requirement for Main and Gravenhurst

(b) Calculate the % of the DRR for each service area and compare this to the Board Approved percentages and proposed 2010 allocations of Main - $45,059,625 and Gravenhurst - $2,855,757

Response: (a) The information required to provide a continuity schedule that starts in 2006 showing

the components of and total base distribution revenue requirement for Main and Gravenhurst is not available. Please see Exhibit 6, Tab 2, Schedule 1 for further details.

(b) Please see the response to Board Staff interrogatory #38.

Veridian ConnectionsEB-2009-0140

Response to Vulnerable Energy Consumers Coalition InterrogatoriesJanuary 11, 2010

3. Ref: Exhibit 1 / Tab 2 / Schedule 4Exhibit 1 / Tab 2 / Schedule 5

Request

(a) Please provide an electronic copy of Exhibit.1 Tab 2 Schedules 4 and 5 -Revenue Requirement Work Form Model.

(b) Why was the model not run for the Main and Gravenhurst Service areas separately based on the inputs (ratebase etc) approved by the Board in 2006 as updated?

(c) What is the plan to harmonize rates for Main and Gravenhurst in terms of timing?

(d) Explain why separate accounting and determination of the Revenue Requirements for Main and Gravenhurst areas should not be maintained during the transition?

Response:

Exhibit 1, Tab 2, Schedules 4 and 5-Revenue Requirement Work Form Model havebeen revised as a result of Veridian’s Application Update. This interrogatory has been answered on the basis of the updated values.

(a) An updated electronic version of the Revenue Requirement Work Form Model has been filed as part of Veridian’s Application Update.

(b) Veridian ran the model for the 2010 Test Year only based on its interpretation of the Minimum Filing Requirements.

(c) Veridian’s plan for harmonization of the Main and Gravenhurst rate zones has not yet been determined.

(d) Please see Exhibit 6, Tab2, Schedule 1.



4. Ref: Exhibit 1 / Tab 1 / Schedule 10Exhibit 2 / Tab 1 / Schedule 2

Request

Does Veridian or Hydro One Networks own the transformer stations that step down the power supplied down from 230 kW & 115 kW to primary distribution voltage in the 12 service areas?

Response:

Veridian does not own any Transformer Stations (TS). All such stations involved in the supply to Veridian are owned by Hydro One.



5. Ref: Exhibit 2 / Tab 10 / Schedule 1 / Page 1 / Table 1

Request

(a) What is the source of the $0.0672 per kWh, value used for the Cost of Power?

(b) Are any of Veridian’s retail customers registered as Market Participants and billed directly for commodity costs by the IESO?

(c) If the response to part (b) is yes, what is their forecast use for 2009 and 2010 and has it been excluded from the calculation of the commodity cost used to determine the working capital allowance?

(d) Please confirm that over 50% of Veridian’s sales are non – RPP customers • Estimate an average commodity cost for all sales based on the weighted average of the RPP and non-RPP costs.• Re-estimate the Total Commodity cost for 2009 and 2010.

Response:

(a) Please see Exhibit 2, Tab 10, Schedule 2, page 1, lines 18-21.

(b) No.

(c) Not applicable.

(d) In response to Energy Probe interrogatory #10, Veridian has calculated that in the VCI_Main rate zone in 2008, the non RPP kWh as a percentage of total kWh was 50.06%. In the VCI_Gravenhurst rate zone in 2008, the non RPP kWh as a percentage of total kWh was 35.7%.Using the RPP pricing and non RPP pricing proxies provided by Energy Probe in their interrogatory #10, Veridian calculates an average commodity cost for all sales based on the weighted average of the RPP and non-RPP costs as follows:

VCI_Main ($0.05820*0.5006) + ($0.06215*0.494) = $.060151VCI_Gravenhurst ($0.05820*0.357) + ($0.06215*0.643) = $0.06074

The re-estimated total commodity costs for 2009 and 2010 are as follows:

Rate Zone 2009 2010VCI_Main 149,496,225 150,103,755VCI_Gravenhurst 5,986,996 5,993,841Total 155,483,221 156,097,596



6. Ref: Exhibit 2 / Tab 2 / Schedule 3 / Table 1

Request

(a) Please provide a schedule that provides details of the total capital additions in each year 2006-2010 using the same major spending categories as set out in Exhibit 2, Tab 2, Schedule 3 Table 1, but indicate the main asset categories- poles transformers etc and the US of A accounts associated with each category.

(b) Provide an explanation of the increase in development capital in 2010.

(c) Explain the reduction in sustainment capital in 2010 relative to the need to upgrade the networks.

Response:

(a) The information requested is contained in the tables on the following pages.



VECC IR #6 (a)2006-2010 Capital Additions by Spending Category by Asset Group by G/L Account No. –Pg. 1/4

Note: The amount of Veridian’s forecast capital expenditures for the 2010 Test Year has changed as a result of Veridian’s application update. This interrogatory has been answered on the basis of the updated values.

Type of Spending Asset Group OEB# 2006 2007 2008 2009 2010

Development $15,794,541 $9,141,477 $13,813,529 $8,156,500 $14,575,500

DS $497,377 $43,415 $1,860,534 $0 $5,025,000

1820 $497,377 $43,415 $1,860,534 - $5,025,000

Line Transformers $2,985,708 $1,319,086 $2,440,163 $1,340,800 $1,548,000

1850 $2,985,708 $1,319,086 $2,440,163 $1,340,800 $1,548,000

Poles, Wires $7,488,025 $5,147,499 $10,132,723 $5,594,300 $6,904,500

1830 $789,293 $944,305 $1,858,843 $1,324,700 $3,277,500

1835 $955,723 $1,018,921 $1,907,027 $1,303,400 $1,770,000

1840 $1,678,747 $1,130,096 $2,959,180 $1,057,300 $635,000

1845 $4,064,262 $2,054,178 $3,407,674 $1,908,900 $1,222,000

Services and Meters $4,517,500 $2,577,022 -$1,487,812 $1,221,400 $1,098,000

1855 $3,449,909 $2,198,151 $1,992,288 $865,400 $548,000

1860 $1,067,590 $378,871 -$3,480,101 $356,000 $509,000

1940 - - - - $41,000

Smart Meters $260,370 $21,882 $867,353 $0 $0

1555 - - $864,371 - -

1860 $260,370 $21,882 $918 - -

1861 - - $2,063 - -

TS Primary >50 $45,561 $32,572 $568 $0 $0

1815 $45,561 $32,572 $568 - -





Sustainment $4,929,012 $6,938,481 $6,086,451 $6,713,000 $5,082,000

DS $652,068 $216,405 $533,003 $2,030,000 $345,000

1820 $652,068 $216,405 $533,003 $2,030,000 $345,000

Line Transformers $973,287 $2,960,760 $1,519,570 $272,000 $580,000

1850 $973,287 $2,960,760 $1,519,570 $272,000 $580,000

Other Distribution Assets $82,878 $251,707 $249,484 $545,000 $345,000

1980 $82,878 $251,707 $249,484 $545,000 $345,000

Poles, Wires $3,208,571 $3,047,737 $3,227,000 $3,703,000 $3,507,000

1830 $837,801 $1,380,244 $877,695 $688,000 $1,220,000

1835 $1,739,021 $1,290,171 $1,580,884 $2,328,000 $1,225,000

1840 $57,682 $64,350 $9,230 $175,000 $75,000

1845 $574,067 $312,972 $759,191 $512,000 $987,000

Services and Meters $12,207 $461,871 $557,394 $145,000 $305,000

1855 $12,090 $461,871 $557,394 $145,000 $305,000

1860 $117 - - - -

Land and Buildings $0 $0 $0 $18,000 $0

1800 - - - $18,000 -





Fleet $664,561 $1,602,221 $828,037 $1,310,000 $1,770,000

Equipment $664,561 $1,602,221 $828,037 $1,310,000 $1,770,0001930 $664,561 $1,602,221 $828,037 $1,310,000 $1,770,000

Facilities $50,889 $616,431 $528,504 $1,140,500 $6,150,000Equipment $15,620 $197,122 $183,691 $170,000 $790,518

1915 $15,620 $197,122 $183,691 $170,000 $790,518General Plant $8,372 $404,825 $341,800 $970,500 $5,359,482

1908 $5,184 $404,825 $329,785 $703,500 $5,289,4821910 $3,188 - $12,016 $267,000 $70,000

Services and Meters $26,897 $0 $3,013 $0 $0

1865 $26,897 - $3,013 - -Land and Buildings $0 $14,484 $0 $0 $0

1905 - $14,484 - - -





IT $770,836 $2,283,637 $2,431,948 $2,453,800 $1,598,100

Equipment $15,143 $14,941 $120,594 $0 $0

1915 - $14,941 $120,594 - -

1955 $15,143 - - - -

IT Assets $749,194 $2,254,659 $2,310,835 $2,218,800 $1,398,100

1920 $23,939 $321,395 $311,815 $901,000 $563,100

1925 $725,254 $1,933,264 $1,999,019 $1,317,800 $835,000

Other Distribution Assets $6,499 $776 $0 $235,000 $200,000

1960 $6,499 - - - -

1990 - $776 - $235,000 $200,000

Smart Meters $0 $13,262 $519 $0 $0

1920 - $4,340 $519 - -

1925 - $8,922 - - -

Miscellaneous/Tools $237,302 $337,923 $245,612 $102,900 $95,000

Equipment $95,543 $56,833 $117,939 $102,900 $95,000

1935 $409 - - - -

1940 $85,901 $56,833 $117,355 $102,900 $95,000

1945 $7,397 - $584 - -

1955 $1,836 - - - -

Other Distribution Assets $78,589 $84,946 $127,673 $0 $0

1960 - $24,177 $8,693 - -

1990 $78,589 $60,769 $118,980 - -

Services and Meters $63,170 $196,144 $0 $0 $0

1865 $63,170 $196,144 - - -

Grand Total $22,447,141 $20,920,171 $23,934,081 $19,876,700 $29,270,600

.(b) Development capital covers all spending associated directly or indirectly with the

addition of new customers to the system, the physical extension of the grid, and the enhancement of the grid’s capacity to serve load. This category is very dependent on new customer activity, however spending is not directly proportional to new customer activity in any given year, since new grid assets are not sized only for the moment. It is noted that the terms Development and Sustainment are only terms applied after projects are placed into the capital program as a way of grouping expenditures, and to some extent can be arbitrary. For example, an aged substation being reconstructed for improved performance as well as increased capacity to supply load satisfies the concept of sustainment (“the re-investment in existing assets to maintain their ongoing usefulness, safety, and necessary length of life for the proper functioning of



the grid”) and also development (“the enhancement of the grid’s capacity to serve load”).

As discussed in Ex. 2/2/2, rapid customer growth in recent years has created a built up demand within Veridian’s system for increased capacity and reliability based spending. This spending is often costly since it involves the purchase of major pieces of equipment such as large power transformers and high voltage substation switchgear. For example, in 2010 Veridian has three large projects for substation improvement and capacity increases (Applecroft, First Street, and Liberty North) which alone account for some $5M in spending. Veridian expects this type of spending to continue for several years. In 2010 there is also an abnormally large line relocation project (Highway 7, Brock Rd x Lakeridge Road, Pickering) at $2.4M. This type of project would typically be classed as sustainment, however in this case it has been grouped among the development projects since the new relocated line will have significantly greater capacity than the existing line, dictated by system needs. There were no such projects in 2009.

(c) As noted above, the reduction in the number and total cost of projects grouped under the term sustainment does not indicate a reduction in spending on upgrading the network. Much of the so called development spending will result in the replacement of an existing older asset with a larger better new one. This is perhaps a somewhat unique feature of Veridian’s service areas and grid – in many cases assets in need of sustainment spending will not be simply replaced like for like but will in fact be rebuilt to significantly greater specifications due to ongoing growth, and will be called development. This is in part due to the fact that much of Veridian’s service area cannot be considered fully mature, in the sense that Veridian can reasonably expect to see further long customer term growth within many existing community areas due to in-fill and re-development activity.

Please refer also to the response to VECC Interrogatory #8.



7. Ref: Exhibit 2 / Tab 3 / Schedule 1 / Page 6Exhibit 2 / Tab 5 / Schedule 1

The Application States :”Veridian’s knowledge of the overall general condition of its assets, and of the conditionof any specific asset, is based on the cumulative information collected from the routineand iterative inspection and testing programs which have been and continue to beconducted. With the increasing rigour and diligence being assigned to these inspection

and testing activities in the bridge and coming years, and with the greatly enhanced ability to mine the data being collected as a result of the maturing of the GIS, the newfeatures of the OMS, and the plans to develop an AMP, Veridian is confident of its abilityto effectively manage its assets. Veridian considered the merits and costs of engaging anindependent assessment of its asset condition to provide a base from which to build newmanagement programs with an AMP. This step was viewed as not being cost effective,

[Emphasis added]

Request

(a) Since Veridian retained Hatch Acres to prepare a 10 Year Planning Study for theAjax/Pickering Areas what additional ACAs and Capital Plans have been prepared? Provide the latest reports.

(b) In lieu of an external Asset Condition/Management Review what does Veridian use to provide direction to priorities for its Sustaining capital program? Please discuss.

(c) Provide a copy of any internal management reports that provide an overview of asset condition and required asset replacement investments over the current and forward rate years.

(d) For regulatory purposes the “gold standard” is an external ACA. Explain why Veridian apparently rejects this approach?

Response:

(a) Veridian has developed two projects in response to the Hatch Acres 10 Year Planning Study for Whitby TS and the Applecroft conversion. Details concerning those projects can be found in Ex 2, Tab 5, Sch 1 on pages 1,16,19,21 for the Whitby TS related projects and Ex 2 Tab 5, Sch 1 page 24 for the project details related to the Applecroft Substation Conversion. Longer term capital spending requirements related to the Hatch Acres study have been discussed for key capital investments within the planning horizon as described in Exhibit 2 Tab 5 Sch 6 page 3. No additional Capital Plans or ACA plans have been prepared at this time.



(b) Rather than incurring the additional expense of having an external party review all of its operating assets, Veridian focuses its resources on plant that needs attention and on areas of known concern in order to sustain the efficiency and reliability of its distribution system cost effectively. Feeder analysis, testing programs, service disruption tracking and routine and iterative inspections are used to identify areas that require closer scrutiny, remedial maintenance or replacement.

(c) Veridian does not prepare asset overview reports as plant in need of maintenance or replacement is reported on an individual basis as part of the annual inspection processes. Any malfunctioning or poorly performing assets are dealt with individually within the annual budgeting process either as an immediate concern in the current budget or as a future expenditure in a subsequent budget. Once Veridian’sGIS system is fully populated, overall asset condition and life cycle analysis will be more readily available at minimal effort and cost.

(d) As stated in the referenced evidence, Veridian’s approach to asset management is to enhance its inspection processes, data management approach, and asset condition records, and then focus on systems and processes to mine that data in the most efficient and effective way. This approach of using system knowledge and enhancing that with the increased use of the GIS and related analysis systems will ensure higher quality service without the added and duplicate cost of an external ACA. Veridian considers the current system to be working efficiently, and has not experienced worker or public safety related issues, nor has it experienced customer or area reliability concerns that have not been dealt with efficiently and cost effectively. Therefore, Veridian believes it cannot justify the costs of an external ACA. Veridian’s view is that such costs may be appropriate when a utility has neither the skills, resources, nor the immediate or near future time to properly understand its ownsystem, which is not the case. Veridian believes it would be imprudent to conduct such an independent assessment when in-house capital and OM&A costs have already been established or forecast for the same purpose, and when there is no evidence that current processes are materially inadequate. While an external ACA would provide a second opinion, Veridian sees no compelling issue to suggest that such is necessary.



8. Ref: Exhibit 2 / Tab 3 / Schedule 1 / Page 11

Reliability: Outage information is currently manually recorded, at all levels of the system using existing recording devices. By late 2009 Veridian’s new Operations ManagementSystem will replace the manual system with an automated software application which

will improve the accuracy and efficiency of this function. Both processes are capable ofgenerating reliability indices and outage reports for the whole system and eventually forany point in the system down to customer level. The new system will help Veridian operational staff to identify and correct incidences of poor operating performance.

Request

(a) Provide Reliability data CAIDI, SAIDI, SAIFI from 2006 actual to 2010 forecast, if possible by service area.

(b) Discuss trends in reliability indices and relate these to the sustaining capital investment programs.

Response:

(a) The chart below is for 2006 to 2009 (to November 30) reliability statistics that include: Veridian total, Veridian without Gravenhurst, and Gravenhurst. Gravenhurst is the only area that is separated in our reporting process.

VERIDIAN INCL GRAVENHURST

2006 2007 2008 2009 SAIFI 2.76 1.81 2.41 2.45

SAIDI 2.54 1.93 2.36 4.04

CAIDI 0.94 1.07 0.98 1.65

VERIDIAN W/O GRAVENHURST

2006 2007 2008 2009 SAIFI 2.72 1.84 2.18 2.27

SAIDI 1.9 1.5 1.68 2.5

CAIDI 0.7 0.82 0.77 1.1



GRAVENHURST

2006 2007 2008 2009 SAIFI 2.12 1.36 6.45 5.05

SAIDI 10.3 9.43 14.11 30.74

CAIDI 4.85 6.95 2.19 6.09

An accurate forecast of reliability is not possible given the number and complexity of events that affect a distribution system’s reliability statistics.

(b) Please refer to the discussion on reliability in our response to Board Staff

Interrogatory #12. As shown in the graphs in part f) of this referenced response, while the average system outage frequency shows a relatively flat trend over the past 5 years, the average outage duration shows a negative rising trend. At an overview level, this correlates with Veridian’s experience that while there are not more outages occurring, outages in recent years have become larger (involving more asset damage and more customers at one time) and more time consuming to restore.

Veridian has noted an increase in the amount and severity of inclement weather in the last years, and this is a factor that has contributed most significantly to the average outage duration. Overhead and underground plant continues to age, and in certain areas where the average age proceeds beyond 60-75% of rated life, the plant, while continuing to perform safely and adequately, can reasonably be expected to begin to contribute more to outages as a result of natural failures in minor components and a general greater susceptibility to adverse conditions.

Given this background, the capital plans for 2010 and forward reflect a general slowing in development-based (non-discretionary work being done to address customer needs) construction, and a general increase in asset management based construction (work being committed to address plant needs). Much of Veridian’s capital investment in past years has not contributed to a reduction in potential outage causes, since it has resulted in plant extensions and additions. In contrast, Veridian’s plans now will result in an increase in the relative amount of capital investment that directly reduces potential outage causes,through rebuilding, renewal, and betterment of line and substation assets. This activity is not confined to Sustainment work. For example many of the projects in the Development category, listed there because they primarily produce an asset that adds a new main supply feature or that is of a larger capacity, do however significantly and directly result in newer and better performing assets than those they replace. This will reduce or eliminate contributors to outages, and strengthen the system’s ability to withstand disturbances.



9. Ref: Exhibit 2 / Tab 5 / Schedule 1 / Pages 1-39Exhibit 2 / Tab 2 / Schedule 3 / Pages 1-5

Request

(a) Identify any new/changed charges included in the Conditions of Service and provide Explain the rationale for the changes.

(b) Provide more information on forecast revenues recovered from these charges in the 2010 test year compared to 2009 bridge year.

Response:

(a) Veridian’s Conditions of Service document was last updated with an effective date of October 1, 2007.

Please see the response to Board Staff interrogatory number 7 for a summary of all rates and charges referenced in Veridian’s current Conditions of Service. The only new charge introduced as part of the October 2007 update was for the reconnection of services that had previously been disconnected at a property owner or operator’srequest due to a change in tenancy or occupancy. This charge is referenced under section 2.1.7 of the Conditions of Service.

When a tenant vacates a property, Veridian’s practice is to transfer the account to the landlord until such time that a new tenant contracts for service. The change to the Conditions of Service that provides for a charge for reconnection of services following a change in tenancy was introduced to give landlords the option of service disconnection between tenancies.

Charges for service reconnections following changes in tenancy have not been applied to date. Veridian has proposed a specific service charge for this service as part of its 2010 rate application. Details are provided at Exhibit 3/Tab 8/Schedule 2/pages 1 & 2.

(b) See response to Board Staff interrogatory number 7.



10. Ref: Exhibit 2 / Tab 5 / Schedule 2 / Pages 39-40

Veridian has approximately 28,000 wood poles within its distribution system. Detailed pole inspections have not been performed since 2003 due to the very high number of false negative inspection and test reports. Since that time only a routine visual check has been performed on a three year cycle.

Request

(a) Provide a schedule that shows the history and projection of # wood pole replacements 2006-2015 and associated costs. Provide the Percentage of poles replaced in each year.

(b) Provide data on the # pole failures 2006-2009

(c) Please explain the reason for increase in the Pole Replacement spending from 2009 ($378,000) to 2010 ($500,000). Relate the spending to #defective poles as a result of visual inspections.

(d) Does Veridian have a plan to visually inspect its poles starting with the oldest? If not why not.

Response:

(a) The table below is an update and expansion to the table shown in Ex. 2/5/2/pg. 40 and reflects actual 2009 information. The significant increase in the number of distribution pole replacements in 2009 (over the planned number previously filed) is a result of extensive pole damage experienced during high wind and tornado events of August 2009, details and costs of which were unknown at the time of filing. The unusually high cost of 2006 44 kV pole replacements is an anomaly and is due to the associated extensive work performed on attachments during the replacement work. Veridian is unable to estimate with any accuracy the pole replacement numbers beyond 2011, and 2011 is a rule of thumb projection only.

2006 2007 2008Poles Amount Poles Amount Poles Amount

44kV Pole Replacements 2 $115,000 12 $158,100 14 $120,500

Distribution Pole Replacements 71 $490,300

103 $524,400 93 $695,300

TOTALS

73 $605,300

115 $682,500

107 $815,800% of Total Poles Replaced (28,000 poles total) 0.26% 0.41% 0.38%



2009 2010 proposed 2011 proposedPoles Amount Poles Amount Poles Amount

44kV Pole Replacements 10 192,400 18 $150,000.00 18 $150,000.00

Distribution Pole Replacements

121 585,300 84 $350,000.00 84 $350,000.00

TOTALS

131 $777,800

102 $500,000.00

102 $500,000.00% of Total Poles Replaced (28,000 poles total) 0.47% 0.36% 0.36%

(b) Veridian has not experienced any pole failures due to inherent or internal defect. All poles that have broken have failed due to external influences – predominantly violent wind and related conductor/guy damage, falling trees, or vehicular accident. 2007 through 2009 replacements are almost all due to wind and trees. The numbers listed here are pole replacements not related to an inspect/test activity:

2006 2007 2008 2009Quantity of Broken Poles 24 95 62 94

(c) As set out in the response to (a) above, the pole replacement cost in 2009 was $777,800. Therefore, pole-replacement spending is expected to decrease by $277,800 in 2010.

(d) Veridian’s inspection plans are based on area maps that divide all parts of the service area into 3 year cycles. All poles in an identified map area are inspected in each cycle. This is in part due to the fact that pole age data has not been available in a ready geographic format, but more significantly this ensures a full inspection of polesand related assets along a line or road, at a frequency and in a manner in keeping with good utility practice. This is also the most time and resource efficient method. Pole deterioration is also not necessarily related to age, but includes other factors such as ground conditions, environment, and amount and size of attachments.




For 2010 there is $400,000 spending associated with the elimination of Long Term Load Transfers.

Request

(a) Given the date for elimination of LT Load transfers is 2014 Provide a projection of planned expenditures for 2009-2014.

(b) Please describe the projects involved and why the approach selected (i.e. choice of

(c) What is the year to date spending for 2009 and the projected total for 2009?

(d) What are number of new customers connected in 2008, 2009 and 2010 and what is the associated capital spending? Where is this included in each year’s reported spending?

Response:

(a) Even though the required date to complete the elimination of LT Load transfers (LTLTs) is 2014, Veridian has planned to start meeting its obligation to the requirement prior to that year to take early advantage of system expansion and system loop benefits resulting from line extensions that are associated with this work. Currently, conservative projections for 2011 and 2013 are $300,000 and $200,000.

(b) The 2010 work planned for this objective is described in Ex. 2/5/2/Pg. 43-44. More specifically, the 4 sub-projects to completed in 2010 are:

i. Lakeridge Road Line Extension – Phase 2, extend 1-ph 16.0 kV line for approximately 0.8 km north Conc. 10, Pickering, $75,000 - to meet load growth in the area and connect 4 customers.

ii. Lakeshore Boulevard/Riley Road, Newcastle – extend 3-ph 27.6 kV line 0.7 km to interconnect existing radial line sections, $149,000 - to establish a loop supply connection for improved reliability and for planned voltage conversion work and connect 8 customers.

iii. Metcalf/Riley/Farrow Road, Newcastle – extend 3-ph 27.6 kV line across Hwy 401and interconnect existing radial line sections, $100,000 - for loop supply and for planned area voltage conversion program and connect 7 customers.



iv. Conc. Road 10 & Brock Road, Pickering - extend low voltage overhead line,

0.1 km, $1,000 – to establish consistency in ownership and maintenance responsibility of a service and connect 1 customer.

(c) One LTLT elimination project was completed in 2009 and minor engineering work (approx. $7,000) has been undertaken on some others. A project “Lakeridge Road Line Extension - Phase 1, Conc. 9 x Conc. 10, 0.8 km 1-phase 16.0 kV, $68,000”, was advanced from 2010 into 2009 in order to economize construction costs enabled by related work by Bell Canada.

(d) Veridian’s interpretation of this question is that the request is for the number of newcustomers connected in 2008, 2009 and 2010 which are associated with LTLTs. There were 0 in 2008, 1 in 2009, and will be 20 in 2010 with the completion of the 4 projects. The associated spending for 2009 is $75,000, and for 2010 is $325,000. This yearly spend is included in the GL accounts for line transformers (1850), and poles and wires (1830, 1835 and 1840, 1845).




This project involves replacing approximately 0.5 km of backyard (rear lot) primaryoverhead pole lines in the Bay Ridges area of the City of Pickering to front lot primaryunderground lines.

Request

(a) Why is the Bay Ridges area unique in requiring replacement of overhead with underground service?

(b) What is the condition of the BR overhead and when would it be scheduled for replacement/ upgrade?

(c) Has Veridian experienced higher than usual customer complaints about the BR overhead service and its maintenance. Please provide details.

(d) What is the specific cost/benefit of this type of project?

(e) If applied to the rest of the franchise what would be the likely cost of similar conversions.

Response:

(a) The Bay Ridges community in Pickering is a residential area built using rear-lot overhead distribution methods typical of the 1960’s and 1970’s. Veridian has several communities similar to this in its service areas with the largest areas being in Pickering, Ajax, and Belleville. Veridian has not yet assembled its system condition knowledge into an overall “rear-lot” service area assessment plan, but the Bay Ridges area specifically was identified since some period of time as problematic due to tree interference, outages, public safety concerns, and access difficulties. The plant was deemed in need of replacement and beyond simple maintenance. The existing construction could be replaced in a like-for like approach as would be the norm for and-of-life overhead. However the same identified problems of tree interference, routine and emergent equipment replacement access, trouble call response, trouble shooting, and public safety concerns associated overhead lines in mature residential backyards would continue to recur. It was deemed prudent to consider eliminating, or at least mitigating, these recurring issues when it was time to replace this type of construction. Conversion of rear-lot overhead to “on street” underground is a common utility practice. Public opposition precludes the installation of new overhead lines on the street in such areas. Bay Ridges is the first area selected to complete thistype of conversion.



(b) The rear-lot wood poles, transformers, and conductors in the Bay Ridges area is of 1960’s construction. The back yards are now heavily treed and tree trimming that would be considered adequate by normal line clearing standards is not possible due to public opposition. Thus much of the plant is at constant risk of tree induced outages.This equipment is mostly original save for specific items that have been replaced over the years due to upgrade or failure. For the most part, the plant is at or near normal end-of-life. Poles appear aged, overhead conductor insulation is degraded and in some cases quite unsightly since it is coming off, and many transformers appear rusted. Failures and outages are occurring due to conductor to conductor contact, as well as tree interference. The condition of the plant is such that failures and resultant outages are expected to increase as the equipment deteriorates further.

(c) Customer complaints have been received concerning the outages encountered and the reliability of the supply in this area, as well as about the condition of the wires. Maintenance and operational difficulties are routinely encountered during routine maintenance activities and trouble call responses. Detailed information on these complaints has not been collected.

(d) A detailed cost/benefit analysis has not been prepared as this work is considered to be the only viable option. The overall benefit is a reliable long term solution with increased service reliability for customers, reduced maintenance costs for tree trimming, and reduced operating costs for trouble call responses. Capital costs will be lower when future replacements or upgrades are required. Currently, all backyard work must be completed manually as there is no vehicle access, causing higher labour costs. Converting the backyard overhead supply to front yard underground supply eliminates the public safety issue as much as possible.

(e) An initial conservative estimate would be between $5M and $10M. As noted above a complete survey and report on this issue has not been prepared. Areas nominated for remedial re-servicing will be generated through the normal site specific problem and needs process discussed in Ex. 2/3/1. At the moment, it is expected that spending on such activities would be managed at under $500k in any year, if and when identified.




The Application States:The results of the PCB testing will identify exactly which units must be replaced andresult in transformer replacement costs in 2010. The capital estimate for this project isbased on Veridian replacing 1% of the transformers being sampled, or 24 units in total.

Request

(a)Please describe the testing program and results to date.

(b)Describe how this project relates to the proposed Z-Factor Accounting Treatment of 2009 PCB Testing Costs.

(c)Provide a summary of the testing and remediation program 2009-2010 and beyond.

Response:

(a) In order to comply with recent PCB regulations changes, Veridian entered into a contract to survey and sample oil as necessary in select pad mounted and vault style transformers. The contractor was directed to transformers manufactured in 1985 or earlier. 2400 transformers were identified, and all have been inspected, oil samples drawn when appropriate, and are laboratory analysis continues. To date 5transformers have been identified as meeting the requirements for immediate attention, and a further 33 appear suspect and results are being further analyzed. Veridian anticipates that the 2010 capital allowance for this work will be sufficient to meet obligations.

(b) This project represents the second phase of Veridian’s multi-year PCB compliance initiative. The first phase was completed in 2009 and focused on the identification and remediation of pad mount and vault style transformers with PCB concentrations of greater than 500 ppm, as required by federal government regulations. The second phase will commence with this project in 2010 and will shift the focus to PCB testing and remediation work for transformers with PCB concentrations of greater than 50 ppm.

Please see the response to Board Staff interrogatory number 52 for an explanation of the rationale for handling PCB compliance costs in the manner proposed.

(c) The 2009 program is described in a) above. In 2010, Veridian will enter into the next phase of transformer oil sampling and test overhead transformers. 2010 activity will provide the information necessary to identify which pole-mount transformers require replacement due PCB concentrations greater than 50 ppm. It is projected that 50% of



the pole-mount transformers requiring replacement will be completed in 2011 and the final 50% in 2012. The pole-mount transformer testing and replacement program will be handled similar to the pad mount and vault transformer program in 2009/2010, whereby the sampling/testing costs will be treated as an operational expense and the replacement transformer costs as a capital expense. These costs have been built into the appropriate budgets for 2010-12.

Also in 2010, Veridian will commence remediation work related to pad mount and vault transformers having PCB concentrations of 50 ppm or higher. The survey and analysis work completed to date has identified no more than 33 pad mount and vault transformers requiring replacement as part of this second phase of Veridian’s PCB compliance initiative. It is projected that replacement activity for all PCB contaminated pad mount and vault transformers will be complete by the end of 2012.



14. Ref: Exhibit 2 / Tab 5 / Schedule 6 / Pages 2-3Exhibit 9 / Tab 4 / Schedule 6

The Application States:Within this Application and in accordance with the Board’s Smart Meter Funding andCost Recovery Guideline (G-2008-0002), Veridian is proposing disposition of the Smart

Meter Variance Account 1555 for amounts recorded to December 31, 2008. Through the disposition of the variance account, smart meter related capital investments would be transferred to rate base as of January 1st, 2010, resulting in a net increase to rate base of $6.679M.

Request

(a) Does the amount to be closed to ratebase include carrying costs?

(b) Has here been an independent review of the amounts to be charged to ratepayers?

(c) Provide details of the average unit meter costs (procurement and installation) for each of the residential and GS<50 kw classes. Compare to the aggregate cost of $260.00 shown in Exhibit 9 Tab 4, Schedule 6 Attachment 1.

(d) Has Veridian tracked the AMCD costs separately for Residential and GS<50 kw classes. If so provide a copy of the costs for each class that are to be disposed of in this application. If not explain.

(e) Has Veridian tracked the other Capital and Operating costs by class? If so provide a copy of the costs for each class that are to be disposed of in this application. If not explain.

Response:

(a) No amounts to be closed to rate base include carrying costs.

(b) The amounts recorded to variance accounts 1555 and 1556 and the calculation of the revenue requirement resulting from Veridian’s smart metering activities have been reviewed by Veridian’s external auditors.



(c) In preparing the response for this interrogatory, some errors were found in Exhibit 9 Tab 4 Schedule 6 Attachment 1, smart meter funding adder calculation. An updated version of the calculation is attached.

The corrected calculation of the “Per Meter Cost Split” is provided below.

Per Meter Cost Split: Per Meter Installed Investment % of InvestSmart meter including installation 137.63$ 36,392 5,008,678$ 70%Computer Hardware Costs 3.09$ 107,261 331,934$ 5%Computer Software Costs -$ 107,261 -$ 0%Tools & Equipment -$ 107,261 -$ 0%Other Equipment -$ 107,261 -$ 0%Smart meter incremental operating expenses 16.66$ 107,261 1,786,556$ 25%

Total Smart Meter Costs per meter 157.38$ 7,127,168$ 100%

Note on per meter cost calculations:1) Smart meter including installation - 2009 & 2010 estimated costs for total of 2009 & 2010 forecast installs2) All other costs - calculated as 2009 & 2010 estimated costs for total of all units installed as they support all meters not just the forecast 2009 & 2010 meters installed

As well, a revised version of Appendix 2-S – Smart Meters is attached.

Veridian understands the request to be to compare the average unit meter costs (procurement and installation) as calculated from the amounts to be transferred to rate base through the smart meter variance account disposition (totalling $6.679M on a NBV basis) to the average unit meter costs forecast in 2009 and 2010, restated in the table above.

Firstly, it should be noted, that incremental operating expenses of $16.66 per meter are included in the calculation above and should be deducted for the purposes of comparing average unit meter costs for procurement and installation. On this basis, the forecast average unit meter cost for procurement and installation, including capital costs for hardware and software, is $140.72.

The following table values are extracted from Appendix 2-S and provide the calculation of the average unit meter capital costs for procurement and installation of smart meters and related hardware and software for the amounts to be transferred to rate base.



Meters Insta l led Capi tal Costs

2006 - 46,179 2007 34,609 4,604,472 2008 36,260 3,168,497

70,869 7,819,148

Average Unit Meter Cost 110.33$

Veridian is unable to provide an average per unit meter cost by rate class as not all capital costs were tracked separately by rate class.

Higher forecasted average per meter unit costs in 2009 and 2010 are expected as Veridian will begin its installation of smart metering within the Gravenhurst service area in 2010. The Gravenhurst service area presents unique challenges due to the topography and geography and higher unit costs are expected as a result.

(d) Veridian has not tracked the AMCD costs separately for residential and GS < 50 kW classes. Veridian is not aware of any Board issued accounting guidelines ordirections requiring separate tracking of AMCD costs by rate class.

(e) Veridian has not tracked the other Capital and Operating costs by class. Veridian is not aware of any Board issued accounting guidelines or directions requiring separate tracking of these costs by rate class.



15. Ref: Exhibit 2 / Tab 12 / Schedule 1 Exhibit 2 / Tab 12 / Schedule 2

The application states:In 2006 Veridian took on the Gravenhurst system, a low density high exposuredistribution system located in a well forested and difficult access area. Frequent summer and winter storms were experienced each year thereafter, creating large and lengthy outages. The result has been a significant drop in Veridian’s overall reliability performance.

Request

(a) Please expand the SAIDI, SAIFI and CAIDI elements of the table in Schedule 1, for 2009 YTD and forecast 2010

(b) Breakdown the reliability indices (SAIDI, SAIFI, CAIDI) 2006-2009 and forecast 2010 between Main and Gravenhurst.

(c) Provide more detail on the plan to improve reliability values for both Main and Gravenhurst.

Response:

(a) and (b)

Please refer to the response to VECC Interrogatory #8.

(c)

Veridian does not have a stand-alone reliability improvement plan. Rather, Veridian’s reliability improvement goals are embedded in the routine and annual activities around Capital and O & M. Both Veridian’s Capital plans and ongoing Maintenance plans include significant considerations for reliability improvement.

One of the five drivers of capital investments cited in Ex 2/3/1/Pg 6-7 is Performance, which includes among others projects geared specifically at improving reliability. A Capital Plan without attention to this driver is deemed incomplete.

Veridian relies on an analysis of outage information Ex 2/3/1/Pg 10 to identify parts of the delivery system that are performing below expectations as well as aid in identifying other specific problem issues that could be targeted by an investment in new or refurbished plant. This type of analysis will be enhanced through the Outage Management System now underway.



The current Capital Investment Selection Criteria Ex 2/11/1/Pg. 6-7 includes a reliability test “Reliability – to what extent does the project impact the power system reliability and customer service?” and this assigns increased weighting to potential projects that will generate improvements.

The Operations programs Ex 4/4/2 include a number of cases where inspection activity has been increased from previous levels, in order to among other things reduce the chances of equipment failure due to undetected incipient problems.

The Maintenance programs Ex 4/4/3 include a number of cases where cost increase have been reflected due to additional work or more detailed scope of work standards, again aimed at preventing equipment failures. In addition vegetation management cost increases are noted due to additional and more thorough tree trimming activity being undertaken and planned.

In part to support a greater emphasis on reliability improvement, there are staff additions in Planning, Maintenance Management, and Supervision Ex 4/4/3 etc. that are included in 2009 and in 2010 plans, to add another degree of focus and thoroughness.

Please refer to Board Staff Interrogatory #12 for specific Capital projects, in the 2009 activity and in the 2010 plan, which feature reliability improvement as a feature or main purpose.



16. Ref: Exhibit 3 / Tab 2 / Schedule 1 / Attachment 1Exhibit 3 / Tab 2 / Schedule 1 / Attachment 2

Request

(a) For 2010 please provide a schedule setting out the revenue by class for Veridian -Main – where for each class the rates are net of the LV charge/adder and the revenues are reported both before and after the transformer allowance.

(b) For 2010 please provide a schedule setting out the revenue by class for Veridian -Gravenhurst – where for each class the rates are net of the LV charge/adder and the revenues are reported both before and after the transformer allowance.

(c) Please reconcile the results for parts (a) and (b) with the revenues by class reported at Exhibit 7/Tab 3/Schedule 2, Attachment 1.

Response:

Veridian’s 2010 projected distribution revenues have changed as a result of Veridian’s application update. The values in Appendix 2-P (Exhibit 7, Tab 3, Schedule 2, Attachment 1) have also changed and an updated Appendix 2-P is provided as Attachment 1.This interrogatory has been answered on the basis of the updated values.

(a) , (b) and (c) Please see Attachment 2 for the requested schedules and the reconciliation.

Revised Appendix 2-P - Veridian_GravenhurstCost Allocation Revenue to Cost Ratio (%)

Customer ClassFrom Cost Allocation

Model

Revised Transformer Ownership Allowance

Proposed for Test Year

Board Target Range

Residential - Urban 106.22% 106.80% 106.80% 85-115Residential - Suburban 61.10% 61.52% 61.96% 85-115Residential - Seasonal 84.67% 85.37% 87.34% 85-115GS < 50 kW 138.93% 139.35% 139.07% 80-120GS > 50 kW 185.12% 179.05% 186.65% 80-180Sentinel Lighting 14.25% 14.37% 15.57% 70-120Street Lighting 81.17% 81.29% 82.42% 70-120

Test Year Revenue Impacts

Customer ClassTest Year Revenue at

Existing Rates

Test Year Revenue

Assuming Current Revenue to Cost

Ratios

Test Year Revenue

Assuming Proposed

Revenue to Cost

Residential - Urban 787,288$ 908,798$ 908,798$ Residential - Suburban 281,336$ 324,758$ 332,262$ Residential - Seasonal 733,445$ 846,645$ 846,645$ GS < 50 kW 338,924$ 391,233$ 388,349$ GS > 50 kW 313,682$ 362,095$ 356,685$ Sentinel Lighting 513$ 592$ 1,420$ Street Lighting 4,962$ 5,728$ 5,728$

Total 2,460,150$ 2,839,849$ 2,839,887$ Note: Differences due to rounding

Revised Appendix 2-P - Veridian_MainCost Allocation Revenue to Cost Ratio (%)

Customer ClassFrom Cost Allocation

Model

Revised Transformer Ownership Allowance

Proposed for Test Year

Board Target Range

Residential 97.73 99.90 98.50 85-115GS < 50 kW 110.53 113.83 114.78 85-115GS > 50 kW 105.22 99.01 99.22 85-115Intermediate 83.12 61.52 81.41 80-120Large Use 81.74 62.81 87.73 80-180Sentinel Lighting 38.93 40.39 72.68 70-120Street Lighting 68.48 71.70 74.96 70-120Unmetered Scattered Load 86.91 88.02 97.42 80-120

Test Year Revenue Impacts

Customer ClassTest Year Revenue at

Existing Rates

Test Year Revenue

Assuming Current

Revenue to Cost Ratios

Test Year Revenue

Assuming Proposed

Revenue to Cost Ratios

Residential 25,856,142$ 27,969,756$ 28,078,876$ GS < 50 kW 6,170,920$ 6,675,363$ 6,430,037$ GS > 50 kW 7,951,573$ 8,601,575$ 8,601,575$ Intermediate 175,570$ 189,922$ 203,879$ Large Use 709,883$ 767,912$ 842,402$ Sentinel Lighting 162,541$ 175,828$ 183,715$ Street Lighting 30,435$ 32,922$ 47,049$ Unmetered Scattered Load 365,470$ 395,346$ 421,201$

Total 41,422,533$ 44,808,623$ 44,808,736$ Note: Differences due to rounding

Veridian_VECC IRR_16 Part a and b

VCI_Main ‐ 2010 Projected Distribution RevenueRevenues by Class from

Fixed Charge Variable Charge Revised Appendix 2‐PCustomer Class Name Rate Volume Revenue Rate Volume Revenue Total Revenue Transf. Allow Net RevenuesResidential $11.38 1,156,440 13,160,287 $0.0161 927,385,803 14,930,911 28,091,199 0 28,091,199 28,078,876General Service Less Than 50 kW $14.08 93,096 1,310,792 $0.0174 294,966,007 5,132,409 6,443,200 0 6,443,200 6,430,037General Service 50 to 2,999 kW $138.20 12,456 1,721,419 $3.1015 2,408,247 7,469,178 9,190,597 (589,045) 8,601,552 8,601,575General Service 3,000 to 4,999 kW $5,333.07 24 127,994 $1.4789 86,111 127,350 255,343 (51,461) 203,882 203,879Large Use $8,011.37 60 480,682 $1.7581 311,685 547,973 1,028,656 (186,266) 842,390 842,402Unmetered Scattered Load $7.68 10,500 80,640 $0.0190 5,413,534 102,857 183,497 0 183,497 183,715Sentinel Lighting $2.92 8,760 25,579 $9.1086 2,353 21,433 47,012 0 47,012 47,049Street Lighting $0.67 324,540 217,442 $3.7366 54,601 204,022 421,464 0 421,464 421,201

TOTAL 1,605,876 17,124,835 1,230,628,341 28,536,133 45,660,968 (826,772) 44,834,196 44,808,736 Difference (25,461)

Differences due to rounding

VCI_Gravenhurst ‐ 2010 Projected Distribution RevenueRevenues by Class from

Fixed Charge Variable Charge Revised Appendix 2‐PCustomer Class Name Rate Volume Revenue Rate Volume Revenue Total Revenue Transf. Allow Net RevenuesResidential Urban Year‐Round $10.22 35,820 366,080 $0.0198 27,397,075 542,462 908,542 0 908,542 908,798Residential Suburban Year‐Round $14.96 9,084 135,897 $0.0208 9,458,013 196,727 332,623 0 332,623 332,262Residential Suburban Seasonal $27.19 19,104 519,438 $0.0336 9,730,721 326,952 846,390 0 846,390 846,645General Service Less Than 50 kW $11.78 8,724 102,769 $0.0201 14,769,007 296,857 399,626 (11,457) 388,169 388,349General Service 50 to 4,999 kW $110.62 600 66,372 $4.2266 68,687 290,312 356,684 0 356,684 356,685Sentinel Lighting $1.62 636 1,030 $3.0873 127 392 1,422 0 1,422 1,420Street Lighting $0.44 11,364 5,000 $0.4330 1,664 721 5,721 0 5,721 5,728

TOTAL 85,332 1,196,586 61,425,294 1,654,423 2,851,009 (11,457) 2,839,552 2,839,887 Difference 335

Differences due to rounding




Request

(a) Please update Table 1 to include the four month period Jul 09-Oct 09.

(b) What is the basis for the kWh/kW forecast provided for the Large User and Intermediate classes for 2009 and 2010?

Response:

(a) Please see response to Board Staff Interrogatory #15, part (a).

(b) Please see Exhibit 3, Tab 7, Schedule 3 pages 10 and 11 – entitled Non-Weather Sensitive Classes and Customer Connection Forecast.



18. Ref: Exhibit 3 / Tab 6 / Schedule 1

Request

(a) Please provide a schedule setting out the actual customer count, by class, for the most recent month in 2009 that data is available.

(b) Given that the growth in GS>50 customers has exceed that for the GS<50class in recent years (i.e., 2007 and 2008), why is it reasonable to assume no growth in the GS>50 customer count for 2009 or 2010?

Response:

(a) Please see the response to Board Staff Interrogatory #19.

(b) While the growth in GS > 50 customer has exceeded that for the GS < 50 class in 2007 and 2008 on a percentage basis, it has not exceeded it in actual average number of connections. The table below uses values from Exhibit 3, Tab 6, Schedule 1, Table 6 to calculate the increase in average connections over the period referenced for the referenced classes.

2006 2007 2008

GS < 50 kW 7,565 7,604 7,655 39 51 Increase in Average

GS > 50 kW 1,012 1,020 1,038 8 18 Increase in Average

While some number of new connections of GS > 50 kW customers is expected within the bridge and test years, the number of accounts reclassified from GS > 50 kW to GS < 50 kW due to Veridian’s annual customer classification review is expected to offset the number of new connections and result in flat customer counts for this class.

In response to Board Staff interrogatory #19, Veridian provides the 2009 YTD (as of Nov 30th, 2009) customer counts by rate class. A decline can be seen in counts for the GS > 50 kW in the Main rate zone. The annual average (Dec 3008 to Nov 2009) was 1,022 and the actual customer count as of November 30th, 2009 was 1,003. This decrease was due to a number of GS > 50 kW customers being reclassified as GS < 50 kW customers during Veridian’s annual classification review. In this review, the past 12 months of demand billings are reviewed for all GS > 50 kW accounts to determine if the monthly kW demand values are sufficiently high to continue to meet the criteria of GS > 50 kW classification. In July 2009, 61 accounts were reclassified from GS > 50 kW to GS < 50 kW. This is due to overestimation of projected demand



by newly established customers and from falling demand of existing customers, likely due to reduced production volumes attributable to the poor economic conditions. Veridian forecasts this trend to continue in 2010.




Request

(a) Is the recent negative growth in Residential-Seasonal accounts the result of accounts in this class being transferred the Residential class? If so, are the transfers generally to the Residential-Suburban class?

(b) Please confirm that the expected sales to the two new customer have been grossed up for losses for purposes of Table 6. What loss factor value was used?

Response:

(a) Veridian does not have sufficient detailed information on the recent negative growth in Residential-Seasonal accounts to confirm that this is due to accounts being transferred to the Residential class or the Residential-Suburban. Veridian does confirm that this could be a possibility should those customers in the Residential-Seasonal class change their residence status to designating their once seasonal premise to be their principal residence and as such qualify for designation as a Residential-Year Round customer.

(b) Veridian has attempted to interpret the question given the provided reference but has not been successful. The evidence reference does not contain a Table 6. Table 6 is within Exhibit 3, Tab 6, Schedule 1, but Veridian is unable to interpret the reference to ‘two new customer’ or ‘sales’ as Table 6 provides information on average annual customer connections for VCI_Main, not sales.



20. Ref: Exhibit 3 / Tab 7 / Schedule 1 Exhibit 3 / Tab 7 / Schedule 2

Request

Please explain how the weather normalized use per customer values were determined for the Veridian_Main and Verdian_Gravenhurst service areas for the weather sensitive customer classes.

Response:

Weather normalized use per customer is derived by dividing annual weather normalized use by annual number of customers.




Request

(a) With respect to Section 2.1, is Pearson Airport the closest weather station for which Environment Canada publishes monthly data? If not, why was Pearson airport used?

(b) With respect to Section 2.2, please provide the employment outlook from the Ontario Ministry of Finance’s Fall Outlook and update the forecast for 2009 and 2010.

(c) With respect to Section 2.3, please confirm that the methodology used by ERA to determine weather normal use by customer class will require that the actual loads for non-weather sensitive classes also be adjusted in order that the sum of the weather normalized load by class equal the total weather normalized load. I

(d) With respect to Section 2.3, please recalculate the weather normalized use for the Residential, GS<50 and GS>50 classes for 2003 to 2008 using an approach where the total predicted weather normal purchases net of purchases required for non-weather sensitive classes is used and the shares based only on the relative proportion of load attributable to each weather sensitive class? Using these results, please also re-do Table 14.

(e) With respect to Section 2.3, please confirm whether the 2009 and 2010 forecast values for each class are based on: i) the 2008 percentages shown times the total forecast reported in Table 7 and discrepancies will be due to rounding error or ii).the 2008 percentages shown times the forecast total reported in Table 7 and then reduced by losses. If the later, what loss factor was used for each class?

(f) Given the material change in the unemployment forecasts for 2009 and 2010, relative to history (Table 2), why is it reasonable to assume that the share of sales to residential will be the same in 2009 and 2010 as it was in 2008 as opposed to being somewhat higher (as commercial/industrial use falls off reflecting the lower employment levels)?

(g) With respect to Table 12 in Section 2.3, 2008 normalized retail use is 1.74% higher than actual. However, per Table 7, weather normalized wholesale kWh are 1.94% higher than actual. Please reconcile.

(h) With respect to Table 14, Section 2.4, please comment on the reasonableness of the resulting 2009 and 2010 “normalized” average use values for Residential, GS<50 and GS>50 classes given the values for the preceding years.



(i) Please prepare an alternative forecast for 2009 and 2010 for the Veridian_Main Residential class where average use per customer in each year reflects the observed trend in average use over the 2003-2008 period as shown in Table 14.

(j) Please provide a schedule that sets out the average weather normal use per customer for each Veridian_Main customer class as determined by Hydro One Networks for the OEB’s CAIF.

(k) With respect to Section 3.3, please provide Sheet I6 from Gravenhurst’s 2006 CAIF and reconcile any differences between the loss factors reported here by customer class with those used in Table 20.

(l) Please repeat part (d) for Veridian_Gravenhurst and, using the results, provide a revised version of Table 26.

(m)Please provide a schedule that sets out the average weather normal use per customer for each Veridian_Gravenhurst customer class as determined by Hydro One Networks for the OEB’s CAIF.

(n) Given that the customer count for the various Veridian_Gravenhurst customer classes is forecast to grow at different rates in 2009 and 2010, why is it reasonable to use the 2008 shares to determine the sales by class in 209 and 2010?

(o) With respect to Table 26, Section 3.5, please comment on the reasonableness of the resulting 2009 and 2010 “normalized” average use values for Residential, GS<50 and GS>50 classes given the values for the preceding years.

Response:

(a) Veridian observes that in order to calculate degree days, daily weather data must be available. It is possible that there is an Environment Canada weather station that is closer than Pearson Airport. However, it is likely that the prevailing weather would be materially different from that observed at Pearson. For Belleville, Trenton would be closer than Pearson and has daily observations and history. However, on a population weighted basis, Pearson is closer to the larger number of customers in the Veridian Main service area. Pearson Airport has decades of daily weather observations with very few missing observations and is widely used to describe weather observations for the GTA and environs. Many smaller Environment Canada weather stations have limited historical data or significant missing observations. For these reasons, Pearson Airport was chosen. Veridian also notes that Hydro One used Toronto Pearson as the weather station used for the OEB’s CAIF.

(b) The Ontario Ministry of Finance Fall Outlook projects employment to decline by -2.6 per cent in 2009 and grow by 0.6 per cent in 2010. This is virtually identical to



forecast used in Veridian’s application (-2.6 per cent and 0.4 per cent, respectively). This is not a material difference, so Veridian has not updated the forecast. Attached are the relevant schedules from the Ontario Ministry of Finance Fall Outlook.

(c) No, the methodology used by ERA to determine weather normal use by customer class does not require that the actual loads for non-weather sensitive classes also be adjusted.

(d) To comply with this request, Veridian has developed a monthly data series called “weather sensitive wholesale load” or “WSL”. WSL is defined as monthly wholesale purchases less monthly intermediate, large user, street light, sentinel light and USL kWh. Intermediate and large user customers are interval metered and therefore their monthly kWh reflects monthly consumption. For the purpose of answering this interrogatory, Veridian has assumed that monthly street lighting, sentinel lighting and USL kWh is one-twelfth of the annual consumption in the relevant year. All class specific kWh is exclusive of distribution losses.

Using monthly WSL as defined above and the identical explanatory variables and time period as the regression equation displayed in Table 3 of Section 2.3, the following regression equation results:

Model 1:OLS using observations 2002:05-2008:12 (T = 80)"Dependent variable: WSLkWh

coefficient t-ratio p-valueconst -102,226,386.0 -5.47 5.69E-07HDD 81,465.7 28.42 6.71E-42CDD 321,299.8 23.43 3.04E-36Peakdays 1,454,946.2 2.84 0.005809FTE_Ont 41,871.6 14.65 1.05E-23

R-squared 0.92555496 Adjusted R-squared 0.921585F(4, 75) 233.1136581 P-value(F) 1.76E-41rho 0.02106627 Durbin-Watson 1.936056

This results in the following weather normalized consumption (historical and forecast) using the identical assumptions for economic growth.



Actual Annual ConsumptionYear WSL %chg Residential %chg share GS<50 %chg share GS>50 %chg share2003 2,084,630,307 827,059,131 39.7% 276,521,722 13.3% 964,152,305 46.3%2004 2,116,244,270 1.5% 831,017,028 0.5% 39.3% 281,226,049 1.7% 13.3% 942,013,909 -2.3% 44.5%2005 2,237,132,134 5.7% 906,779,281 9.1% 40.5% 283,135,116 0.7% 12.7% 1,005,862,450 6.8% 45.0%2006 2,251,019,752 0.6% 883,724,953 -2.5% 39.3% 294,123,554 3.9% 13.1% 983,029,977 -2.3% 43.7%2007 2,284,454,160 1.5% 915,566,674 3.6% 40.1% 291,605,781 -0.9% 12.8% 966,922,043 -1.6% 42.3%2008 2,274,172,944 -0.5% 931,097,742 1.7% 40.9% 296,146,633 1.6% 13.0% 931,775,076 -3.6% 41.0%

Weather Normal ConsumptionYear WSL %chg Residential %chg share GS<50 %chg share GS>50 %chg share2003 2,099,156,317 832,822,200 39.7% 278,448,566 13.3% 970,870,659 46.3%2004 2,159,459,553 2.9% 847,987,015 1.8% 39.3% 286,968,894 3.1% 13.3% 961,250,535 -1.0% 44.5%2005 2,188,258,992 1.3% 886,969,476 4.6% 40.5% 276,949,651 -3.5% 12.7% 983,888,040 2.4% 45.0%2006 2,241,795,965 2.4% 880,103,799 -0.8% 39.3% 292,918,352 5.8% 13.1% 979,001,910 -0.5% 43.7%2007 2,274,778,010 1.5% 911,688,653 3.6% 40.1% 290,370,641 -0.9% 12.8% 962,826,499 -1.7% 42.3%2008 2,297,750,931 1.0% 940,751,102 3.2% 40.9% 299,216,998 3.0% 13.0% 941,435,458 -2.2% 41.0%2009 2,225,156,199 -3.2% 911,029,180 -3.2% 40.9% 289,763,590 -3.2% 13.0% 911,691,915 -3.2% 41.0%2010 2,235,808,341 0.5% 915,390,407 0.5% 40.9% 291,150,730 0.5% 13.0% 916,056,315 0.5% 41.0%

From the above results, Table 14 from Section 2.4 is restated for the weather sensitive classes (residential, GS<50 kW, GS>50 kW).

Average Use Per CustomerActual

Year Residential GS<50 GS>502003 10,016 38,080 1,002,6722004 9,990 39,275 968,2372005 10,451 38,005 1,009,9022006 9,763 38,882 971,8542007 9,864 38,349 947,8852008 9,854 38,687 897,520

Normalized & Forecast Use Per Customer

Year Residential GS<50 GS>502003 10,086 38,345 1,009,6582004 10,194 40,077 988,0092005 10,222 37,174 987,8392006 9,723 38,723 967,8712007 9,823 38,186 943,8702008 9,956 39,088 906,8252009 9,533 37,602 878,1752010 9,499 37,531 882,379



(e) The 2009 and 2010 forecast values are based on 2008 class shares, as indicated in Section 2.3. The percentages shown in Table 8, rounded to 3 digits, are presented for information only in order to provide the reader with a snapshot of the relative importance of each class and the trend over time. For calculation purposes, the actual class share should be used. For example, in 2008 the residential class share would be the actual residential throughput in 2008 divided by the actual wholesale throughput in 2008. Calculated in this way, there is no discrepancy. No loss factor adjustment is made as no distribution losses are included in the class throughput. See response to Board Staff IR 14 for a detailed example.

(f) The year 2008 was chosen as it was the most recent year available. At the time the load forecast was prepared, only the first quarter of residential class kWh billing was available. It was Veridian’s view that choosing an alternative value for the class share that was not based on historical performance would be perceived as arbitrary by the Board and intervenors. As the load forecast report indicates, it would be preferable to develop class specific weather normalized forecast equations. However, the quarterly billing cycle in Veridian Main precluded this approach.

(g) Table 12 in Section 2.3 refers to average annual customer connections for VCI Main. Veridian assumes VECC is referring to Table 13. Please reference the table below. Veridian calculates that on both a retail and wholesale basis, normalized consumption is 1.94% higher than actual in 2008. Veridian suspects that VECC inadvertently included non-normalized retail classes in its examination of retail kWh.

From Table 13

Normalized 2008 Residential 949,155,6922008 GS<50 301,890,1782008 GS>50 949,846,163

2008 Normalized Retail 2,200,892,033

Actual 2008 Residential 931,097,7422008 GS<50 296,146,6332008 GS>50 931,775,076

2008 Actual Retail 2,159,019,451

Normalized vs Actual 1.0194

From Table 7



Normalized 2008 Wholesale 2,575,788,571

Actual 2008 Wholesale 2,526,783,479

Normalized vs Actual 1.0194

(h) Please see response to Energy Probe IR 15.

(i) As requested, Veridian has calculated average use per customer for 2009 and 2010 for the Veridian Main residential class based on the observed trend in average use over the 2003-2008 period as shown in Table 14. Using these data points, the following linear trend function is fitted: y = -52.029x + 10176. We have then used the forecast number of customers as displayed in Table 12 to calculate the forecast class volumes for 2009 and 2010. Results are displayed in the table below.

From Table 14T Year Residential Normalized Use Per Cust trend1 2003 10,075 10,1242 2004 10,208 10,0723 2005 10,175 10,0204 2006 9,626 9,9685 2007 9,834 9,9166 2008 10,045 9,8647 2009 9,8128 2010 9,760

Residential Forecast for VCI Main, 2009 & 2010Based on above trending of NAC methodology

Year Cust #s kWh2009 95,570 937,707,3552010 96,370 940,542,748

Veridian would like to note that the above methodology ignores any forward looking economic trends. Therefore, forecast future economic fluctuations (downwards or upwards) are not reflected in this forecast methodology.

(j) The following table sets out weather normalized average use per customer as calculated from Hydro One Networks analysis for the OEB’s CAIF.

Monthly kWh by class (with actual weather) TOTAL1 2004 Retail2 Implied Loss1 Residential class 905,108,916 831,017,028 1.0892 Street lighting 17,342,522 13,636,431 1.2723 Sentinel lighting 216,478 825,096 0.2624 General service <50kW 321,940,535 281,226,049 1.1455 General service >50kW 956,396,447 942,013,909 1.015



6 Intermediate Use 20,551,009 19,667,919 1.0457 Large Use 222,045,561 184,659,451 1.2028 USL 6,376,103 4,887,715 1.305

Monthly kWh by class (with normalized weather) TOTAL1 2004 Retail3 2004 Avg Cust retail "NAC"1 Residential class 911,101,396 836,518,966 83,188 10,056 2 Street lighting 17,342,522 13,636,431 22,599 603 3 Sentinel lighting 216,478 825,096 784 1,052 4 General service <50kW 325,285,928 284,148,363 7,160 39,686 5 General service >50kW 965,985,090 951,458,356 973 977,861 6 Intermediate Use 20,551,009 19,667,919 2 9,833,960 7 Large Use 222,045,561 184,659,451 5 36,931,890 8 USL 6,376,103 4,887,715 747 6,543

1 per Hydro One analysis2retail kWh by class for VCI Main3 calculated using impled loss factor

(k) Sheet I6 from Gravenhurst’s 2006 CAIF is provided as an attachment. The loss factor reported in sheet I6 (1.0835) is derived from the 2006 EDR which is a three year average (2002, 2003, and 2004) as can be seen from “Schedule 10-5: Determination of Loss Adjustment Factors” from Gravenhurst Hydro Inc.’s 2006 Distribution Rate Application (also provided as an attachment). Table 20 provides “implied loss factors” by class calculated by dividing the 2004 weather actual class kWh consumption reported by Hydro One by the 2004 retail kWh class sales as recorded by the utility.

(l) The only non-weather sensitive load in Gravenhurst is street lighting and sentinel lighting. The consumption of these classes accounts for approximately 0.6% of total wholesale purchases (0.636% in 2008), which is less than the random error of the OLS regression model. Recalculating consumption as requested will not result in any material difference; therefore, Veridian has not recalculated on this basis.

(m) This appears in Table 20 of Exhibit 3, Tab 7, Schedule 3.

(n) Please see response to part (f).

(o) Please see response to response to Energy Probe IR 16.



22. Ref: Exhibit 3 / Tab 8 / Schedule 1 / Page 1Exhibit 3 / Tab 8 / Schedule 3 / Page 3

Request

Please provide a more detailed breakdown regarding the sources of Other Income and Deductions for the years 2007-2010 such that the reasons for the year over year changes are more readily apparent.

Response:

Please see the response to Board Staff Interrogatory #20.




Request

Is Veridian proposing to introduce any new service charge or change the “rate” for any existing service charges? If so, please identify and provide the supporting rationale, including cost analysis.

Response:

As set out at Exhibit 3, Tab 8, Schedule 2, page 1, Veridian proposes that its menu of specific service charges be augmented by the addition of two charges under the category of ‘Customer Administration’. The two charges are for Disconnect/Reconnect at meter –during regular hours and for Disconnect/Reconnect at meter – after regular hours. Veridian’s current menu of specific service charges includes these two charges under the category of ‘Non-Payment of Account’.

The supporting rationale for the new charges is provided at Exhibit 3, Tab 8, Schedule 2, pages 1 and 2.Veridian is proposing the standard amount for these specific service charges as stipulated in the Board’s 2006 Electricity Distribution Rate Handbook.



24. Ref: Exhibit 3 / Tab 8 / Other RevenuesExhibit 3 / Tab 8 / Appendix D

The reference states:Shared services to Veridian Corporation will continue and the associated revenue is forecast at $229,000. Full details of corporate cost allocation methodologies are outlined at Exhibit 4, Tab 6, Schedule 5.

Request

(a) Indicate which line(s) of Appendix D include the outbound services to Veridian Corporation.

(b) Confirm the services are provided at Veridian Connections fully allocated cost.

(c) Provide a sample of the calculation of the fully allocated cost for a service provided to Veridian Corporation.

Response:

(a) The outbound services to Veridian Corporation are included in the line “Other Income and Expenses”.

(b) Confirmed.

(c) Please see the response to Energy Probe Interrogatory #32.




Request

(a) Provide a version of Table 2 that incorporates the Cost per kilowatt hour distributed

(b) Benchmark the OM&A costs shown in Table 2 as amended, to the Data shown on the Boards Web site http://www.oeb.gov.on.ca/OEB/_Documents/EB-2006-0268/Comparison_of_Distributors_with_2007_data.xls

(c) Update the data for 2008.

(d) Discuss Veridian’s trends and Position in the Cohort.

Response:

(a)2006 Board Approved

2006 Actual

2007 Actual

2008 Actual

2009 Forecast

2010 Forecast

Total OM&A Expenses ('000s) $ 19,734 $ 19,413 $ 17,629 $ 19,589 $ 20,029 $ 22,399 Customer Count 101,865 107,231 109,225 110,861 112,042 113,216Kilowatt Hours Distributed ('000s) 2,419,475 2,532,414 2,547,644 2,501,314 2,455,988 2,465,704

OM&A Cost/Customer $ 193.73 $ 181.04 $ 161.40 $ 176.70 $ 178.76 $ 197.84 OM&A Cost/ Customer % Change -6.5% -10.8% 9.5% 1.2% 10.7%

OM&A Cost/kWh 0.00816 0.00767 0.00692 0.00783 0.00816 0.00908 OM&A Cost/ kWh % Change -6.0% -9.7% 13.2% 4.1% 11.4%

OM&A Cost/Customer % change-2006 Board Approved to 2010 Forecast 2.1%Annual Increase in Costs per Customer-2006 Board Approved to 2010 0.35%

OM&A / kWh % change-2006 Board Approved to 2010 Forecast 11.4%Annual Increase in Costs per kWh -2006 Board Approved to 2010 1.90%(Note: Based on 6 years as 2006 Board Approved is 2004 Actuals)

www.oeb.gov.on.ca/OEB/_Documents/EB-2006-

http://www.oeb.gov.on.ca/OEB/_Documents/EB-2006-

http://www.oeb.gov.on.ca/OEB/_Documents/EB-2006-0268/Comparison_of_Distributors_with_2007_data.xls



(b) Veridian has added its actual 2008 and forecast 2009/2010 costs to the spreadsheet at the web-link provided, and has calculated three year average cost data using these new data. A copy of the modified table is provided as Attachment 1.

(c) Data for 2008 have been included in Attachment 1, per the response to (b) above.

(d) Veridian’s projected OM&A costs of $198 per customer in the test year compares favourably to the 2005-07 group average cost of $214 per customer. This favourable comparison is understated as the costs of other cohort members have been trending up, and the group average cost is likely to increase as the comparison is updated with more recent cost data.

The following table provides a comparison of recent cost trends for distributors within Veridian’s peer group, using data from the Board’s website. The general upward trend in Veridian’s costs appears consistent with those of peer group members.

Comparison of Ontario Electricity Distributors Costs (EB-2006-0268)Peer Groups per PEG Report

Total OM&A per Customer

Average Average Forecast ForecastLDC 2008-2010 2007-2009 2010 2009 2008 2007 2006 2005

Small Northern Low UndergroundingWest Nipissing Energy Services Ltd. $135 $160 $184 $63Renfrew Hydro Inc. $204 $231 $209 $171Fort Frances Power Corporation $276 $296 $269 $261Espanola Regional Hydro Distribution Corporation $280 $300 $302 $237Northern Ontario Wires Inc. $282 $302 $282 $262Parry Sound Power Corporation $306 $306 $311 $302Sioux Lookout Hydro Inc. $389 $414 $381 $373Atikokan Hydro Inc. $399 $444 $379 $373Chapleau Public Utilities Corporation $415 $482 $373 $389Great Lakes Power Limited $693 $714 $690 $674

Group Average $338

Small Northern Medium Undergrounding Ottawa River Power Corporation $205 $226 $200 $188Kenora Hydro Electric Corporation Ltd. $224 $248 $214 $209Hearst Power Distribution Company Limited $229 $240 $233 $214Lakeland Power Distribution Ltd. $231 $226 $253 $215

Group Average $222

Mid-Size Northern North Bay Hydro Distribution Limited $221 $219 $249 $196PUC Distribution Inc $222 $239 $210 $216

Average 2006-2008

Average 2005-2007

PUC Distribution Inc. $222 $239 $210 $216Thunder Bay Hydro Electricity Distribution Inc. $223 $241 $219 $210Greater Sudbury Hydro Inc. $263 $365 $213 $210

Group Average $232

Large Northern Hydro One Networks Inc. $357 $413 $351 $309

Small Southern Low & Medium Undergrounding Hydro Hawkesbury Inc. $141 $144 $134 $144Lakefront Utilities Inc. $204 $212 $206 $193Hydro 2000 Inc. $212 $201 $192 $243Rideau St. Lawrence Distribution Inc. $233 $239 $230 $231Dutton Hydro Limited $250 N/A $233 $266Clinton Power Corporation $284 $333 $296 $224Wellington North Power Inc. $287 $289 $295 $276Brant County Power Inc. $293 $173 $365 $342Grand Valley Energy Inc. $325 $323 $356 $295Eastern Ontario Power (CNP) $380 $371 $415 $356Port Colborne (CNP) $462 $490 $452 $443

Group Average $279

Small Southern Medium-High Undergrounding Middlesex Power Distribution Corporation $212 $202 $208 $226Tillsonburg Hydro Inc. $236 $246 $246 $217West Perth Power Inc. $237 $262 N/A $213Newbury Power Inc. $255 $299 $251 $215Midland Power Utility Corporation $261 $263 $272 $249West Coast Huron Energy Inc. $350 $306 $374 $371




Average 2006-2008

Average 2005-2007

Group Average $259

Small Southern Medium-High Undergrounding with Rapid Growth Grimsby Power Incorporated $162 $169 $154 $162Orangeville Hydro Limited $181 $192 $174 $175Cooperative Hydro Embrun Inc. $202 $210 $197 $199Niagara-on-the-Lake Hydro Inc. $207 $227 $205 $189Centre Wellington Hydro Ltd. $239 $242 $238 $238

Group Average $198

Mid-Size Southern Low & Medium Undergrounding Innisfil Hydro Distribution Systems Limited $211 $225 $210 $198Norfolk Power Distribution Inc. $229 $255 $217 $215Peninsula West Utilities Limited $260 $203 $276 $301Orillia Power Distribution Corporation $271 $281 $262 $270Haldimand County Hydro Inc. $293 $346 $273 $260Fort Erie (CNP) $297 $323 $298 $269

Group Average $260

Mid-Size Southern Medium-High Undergrounding E.L.K. Energy Inc. $155 $182 $171 $113Wasaga Distribution Inc. $157 $159 $159 $152Chatham-Kent Hydro Inc. $162 $164 $161 $162

$ $ $Peterborough Distribution Incorporated $181 $192 $186 $166Festival Hydro Inc. $182 $185 $189 $171Welland Hydro-Electric System Corp. $183 $209 $162 $178Kingston Electricity Distribution Limited $189 $182 $181 $204Westario Power Inc. $203 $196 $205 $206COLLUS Power Corp. $211 $225 $220 $187St. Thomas Energy Inc. $216 $214 $229 $205Essex Powerlines Corporation $221 $206 $222 $236Woodstock Hydro Services Inc. $223 $228 $223 $218Niagara Falls Hydro Inc. $247 $255 $245 $240Bluewater Power Distribution Corporation $261 $256 $270 $258Erie Thames Powerlines Corporation $329 $356 $308 $324

Group Average $208

Large City Southern Medium-High Undergrounding Hydro Ottawa Limited $150 $155 $161 $135Veridian Connections Inc. $184 $173 $175 $174 $198 $179 $177 $163 $185 $176Toronto Hydro-Electric System Limited $236 $247 $228 $233ENWIN Powerlines Ltd. $294 $359 $263 $259

Group Average $214

Large City Southern High Undergrounding Hydro One Brampton Networks Inc. $130 $129 $136 $127Horizon Utilities Corporation $161 $165 $147 $170London Hydro Inc. $166 $175 $168 $156PowerStream Inc. $180 $182 $169 $190Enersource Hydro Mississauga Inc. $237 $249 $235 $229

Group Average $175




Average 2006-2008

Average 2005-2007

Mid-Size GTA Medium-High Undergrounding Barrie Hydro Distribution Inc. $121 $124 $124 $115Kitchener-Wilmot Hydro Inc. $145 $149 $148 $139Cambridge and North Dumfries Hydro Inc. $158 $172 $148 $154Oshawa PUC Networks Inc. $163 $172 $159 $158Guelph Hydro Electric Systems Inc. $172 $213 $149 $154Waterloo North Hydro Inc. $179 $179 $182 $177Newmarket - Tay Power Distribution Ltd. $189 $186 $189 $192Oakville Hydro Electricity Distribution Inc. $196 $189 $202 $198Burlington Hydro Inc. $196 $206 $199 $185Brantford Power Inc. $197 $217 $175 $199Milton Hydro Distribution Inc. $201 $198 $198 $208Whitby Hydro Electric Corporation $206 $214 $205 $200Halton Hills Hydro Inc. $220 $220 $241 $198

Group Average $180

Total Average $237




Request

(a) With respect to the cost driver Table 3, please breakdown the Employee Costs contribution for each year as between: (i) staff increases (headcount and FTEs) and (ii) inflation .and increases in costs per employee.

(b) what were the annual contracted costs for tree trimming service in 2006-2008 along with the projected costs for 2009 and 2010.

(c) Please provide a schedule that compares the tree trimming cost for 2007 and 2010 and explain the variance in terms of inflation, scope of work performed, etc.

(d) Do Veridian’s residential customers have an option of equal monthly (i.e. budget) billing? If not, why not?

Response:

(a) Employee Costs related to (i) staff increases are in the row identified as “Increased Staffing Requirements” within Table 3. Employee costs related to (ii) inflation and increases and in costs per employee are in the row identified as “Inflation, Wage Adjustments and Other” within Table 3.

(b) Awarded or Projected Contract costs for cyclical tree trimming as follows:

Year 2006 2007 2008 2009 proj 2010 projContract costs

$287,119 $287,379 $295,000 $535,700 $595,900

This table includes only the planned or cyclical line clearing programs in Veridian’s districts. Reactive spending due to trouble calls or customer calls are not included in the above table.

(c) As is readily seen from the table in Part (b), costs are substantially different from 2007 costs to projected 2010 costs. For the areas in the Ajax, Brock, Belleville and Clarington Districts scheduled for line clearing activities in 2010, there is some increase in the scope of the work since the areas due for trimming have a greater amount of line exposed to trees and/or are more heavily treed (larger and thicker vegetation). All work is/will be done by contract, and all work is awarded via an RFP process. The current RFP included three bidders, and the lowest bid was accepted for each district. The average contract labour rate increased from $107.29 per hour in 2007 to $150.00 per hour for 2010. The contract rate alone represents approximately 40% of the total increase for the work to be performed in these three districts. For the



Gravenhurst District, contracted work for 2007 was only based on a preliminary and limited restart of tree trimming in this area. Veridian was hampered in setting out a vegetation management plan by a lack of area information, compounded by the considerable variation in terrain and working conditions which made estimating by deemed average costs impossible. The 2007 contract was used to set some base line cost determinants. There had been little to no regular vegetation management done in previous years, and it was clear that there is a need to accelerate the pace of line clearing efforts in this area to achieve improved reliability and minimize storm damage. 2007 contract costs for Gravenhurst were approximately $54,600, and due solely to scope of work this is being increased to $180,000 in 2010 and forward in a continuing effort to re-establish proper and safe vegetation clearances. Veridian anticipates this level of spending through the IRM period.

(d) Veridian customers have the option of participating in a monthly equal payment plan.




Request

(a) Please confirm that Veridian’s application includes provisions for LEAP contributions and staffing costs.

(b) Provide details of these costs.

(c) Given the Board’s September 28, 2009 update regarding the Low Income Energy Assistance Program initiative, are the budgeted LEAP amounts required for 2010? If yes, then explain why?

Response:

(a) Confirmed.

(b) Details regarding provisions for “LEAP Emergency Financial Assistance for Bill Payment” in the test year are provided in the response to Board Staff interrogatory number 33.

The increased staffing levels required to accommodate LEAP and related proposed changes to customer service standards are explained at Exhibit 4/Tab 5/Schedule 4/Page 9. An increase of 2.5 FTEEs is required. The test year costs will be $160k.

(c) Yes, the proposed amounts are still required for 2010.

While the Board’s September 28th 2009 letter announced that it would not proceed to implement new support programs for low-income energy consumers in advance of a ministerial decision, it also explains that it will proceed with the process of amending codes to bring into force new customer service rules that will benefit all customers, including low-income customers. Details of the proposed changes in customer service rules are laid out in the “Board’s Notice of Revised Proposal to Amend Codes” as issued under proceeding EB-2007-07223 on October 1st 2009.

The proposed changes contemplated by the Board’s notice are comprehensive and will have significant impacts on Veridian’s business operations. Veridian has summarized the changes in the table appended as Attachment 1. The table also identifies the areas of Veridian’s business operations that will be affected by the changes.

Summary and Impacts of Proposed Code AmendmentsCustomer Service, Customer Reclassification and Management of Customer Commodity Non-Payment RiskEB-2007-0722

On-going/One timeCode Amendt DetailsDSC Sect 2.4.20A Security Deposit

LDC must permit a Residential customer to pay security deposit in equal installments over a period of 6 months √ √ √where a new security deposit is required due to LDC applying the existing deposit against amounts owing. On-going

2.4.22A LDC shall conduct a review of the customer's security deposit in the calendar year in which the anniversary of √ √the 1st instalment occurs and thereafter as otherwise required by the Code. On-going

2.4.23A For purposes of Section 2.4.23, where a Residential customer has paid a security deposit in instalments, the √ √ √customer shall not be entitled to request a review of the deposit until 12 months after the first instalment was paid.

2.4.25A Despite Section 2.4.25 where a Residential electricity customer is required to adjust the security deposit upwards √ √ √LDC shall permit the customer to pay the adjustment amount in equal instalment over a period of at least 6 months. On-going

2.4.26A LDC shall not issue a disconnection notice to a Residential customer for non payment unless the LDC has first √ √applied any security deposit held on account for the customer against any amounts owing at the time and thesecurity deposit was insufficient to cover the total amount owing. On-going

2.4.26B Where LDC applies all or part of security deposit to offset amounts owing by a Residential customer to offset √ √amounts owing under Sec. 2.4.26A, the LDC may request that the customer repay the amount of the securitydeposit that was applied. LDC shall allow customer to repay security deposit over at least 6 months. On-going

Code Amendt DetailsDSC Sect 2.6 Bill Issuance and Payment

2.6.1 LDC must include the date bill printed on each bill issued to customer On-going √ √2.6.2 Except as otherwise permitted by the DSC, LDC shall not treat a bill as issued to a customer √ √ √

as unpaid and shall not impose any ODI or other charges associated with non-paymentuntil the applicable minimum payment period set out in Section 2.6.3 has elapsed. One time

2.6.3 For the purposes of Section 2.6.2, the minimum payment period shall be 16 days from the date √ √ √on which the bill was issued to the customer. (LDC may provide a longer payment period,however, must be documented in Conditions of Service)

2.6.4 For the purposed of Section 2.6.3, a bill will be deemed to have been issued to a customer: √ √(a) if sent by mail, on the 3rd day after the date on which the bill was printed by LDC One time √ √ √ √(b) if made available over the internet, on the date on which the e-mail was sent to customer notifying √ √ √ √

bill is available for viewing over the internet (c) if sent by e-mail, on the date on which the e-mail is sent, or (d) if sent by more than one of the methods above, on whichever date of deemed issuance occurs last. √ √ √ √

2.6.5 LDC shall apply the following rules for the purposes of determining the date on which payment of a bill √ √ √has been received from a customer:

(a) if paid by mail, 3 days prior to the date on which the LDC receives the payment On-going √ √ √(b) if paid at a financial institution or electronically, on the date on which the payment is acknowledged √ √ √

Code Amendt DetailsDSC Sect 2.6 Bill Issuance and Payment (cont'd)

or recorded by the customer's financial institution. On-going2.6.6 Where the LDC has issued a disconnection notice to a Residential customer for non payment, the √ √

LDC shall permit the customer to pay all amounts that are overdue for payment by Credit Card issuedby a financial institution.

2.6.7 Where a bill issued to a Residential customer includes charges for goods or services other than √ √ √electricity charges, the LDC shall allocate any payment made, first to the electricity charges and then,apply remaining fund to the charges for other goods or services.

2.6.7.1 Section 2.6.7 does not apply to existing joint billing agreements until the renewal date of the agreement, √ √or 2 years, whichever comes earlier, and thereafter the provisions of Section 2.6.7 are deemed applicable. One time

2.6.7.2 Where payment of a bill referred to in Sections 2.6.7/2.6.7.1 is sufficient to cover the electricity charges √ √ √LDC shall not apply ODI charges, issue a disconnection notice or disconnect electricity supply.

2.6.7.3 For the purposes of this section, "Electricity charges" are: (a) charges that appear under the sub-headings "Electricity, Delivery, Regulatory Charges and Debt √

Retirement" as described in Ontario Regulation 275/04 (Information on Invoices to Low-Volume Consumersof Electricity) made under the Act, and all applicable taxes on these charges

(b) where applicable, charges labeled "Provincial Benefit" as described in Ontario Regulation 429/04 √(Adj Under Sect 25:33 of the Act) made under the Electricity Act and all applicable taxes on these charges

(c) Board approved ODI fees, specific service charges and such other charges and applicable taxes associated √ √ √with the consumption of electricity as may be required by law to be included on the bill issued to the customeror as may be designated by the Board for the purposes of this section but not including security deposit.

2.6.8 For the purposed of Section 2.6, LDC shall apply the following rules relating to computation of time:

ImpactCIS Vendor

Bill Print Provider

Revision Impact

Billing Credit Call Centre Finance Reg


On-going/One timeImpact

CIS VendorBill Print Provider

Revision Impact

Billing Credit Call Centre Finance Reg(a) where there is reference to a number of days between 2 events the days shall be counted by excluding On-going √ √ √

the day on which the 1st event happens, and including the day on which the 2nd event happens(b) where the time for doing an act expires on a day that is not a business day, the act may be done on the √ √ √ √ √

next business day(c) where an act other than payment by a customer occurs on a day that is not a business day, it shall be √ √ √ √ √ √

deemed to have occurred on the next business day(d) where the act, other than payment by a customer occurs after 5:00 p.m. it shall be deemed to have occurred √ √ √ √ √ √

on the next business day(e) receipt of payment by a customer is effective on the date that the payment is made, including payments √ √ √ √ √

made after 5:00 p.m.Code Amendt Details

DSC Sect 2.7 Arrears Management Programs2.7.1 LDC shall make available to any Residential electricity customer who is unable to pay their electricity On-going √ √ √

charges, as defined in Section 2.6.7.3 the opportunity to enter into an Arrears Payment Agreement with the LDC. The Arrears Payment Agreement shall include, at a minimum, the terms and conditions below:

2.7.1.1 Before entering into an Arrears Payment Agreement under Section 2.7, LDC shall apply any security deposit √ √Code Amendt Details

DSC Sect 2.7 Arrears Management Programs(cont'd)against any electricity charges owing at the time.

2.7.1.2 As part of the Arrears Payment Agreement, LDC may require that the customer pay down up to 15% of the On-going √ √electricity charge arrears accumulated, inclusive of any applicable ODI, but excluding other service chargeswhen entering into the Arrears Management Program.

2.7.2 The Arrears Payment Agreement referred to in Section 2.7.1 shall allow the Residential Electricity Customer √ √ √to pay all remaining electricity charges that are then overdue for payment after applying the down payment referred to in Section 2.7.1.1 including all electricity-related service charges that have accrued to the date ofthe agreement, over the following periods:

(a) A period of at least 5 months, where the total amount of the electricity charges remaining overdue for payment √ √ √is less that twice the customer's average monthly bill amount

(b) A period of at least 10 months, where the total amount of the electricity charges remaining overdue for paymentis equal to or exceeds the customer's average monthly billing amount.

2.7.3 For the purposes of Section 2.7.2. the customer's average monthly billing amount shall be calculated by taking √ √ √the aggregate of the total electricity charges billed to the customer in the preceding 12 months and dividingthat value by 12. If the customer has less than 12 months, the average monthly billing amount shall be areasonable estimate made by the LDC. "Electricity Charges" has the same meaning as in Section 2.6.7.3.

2.7.4 Where the customer defaults on more than one occasion in making a payment in accordance with an Arrears √ √Payment Agreement or on a current electricity charge billing, the LDC may cancel the Arrears PaymentAgreement

2.7.4.1 If LDC cancels an Arrears Payment Agreement pursuant to Section 2.7.4, LDC must give written notice of √ √cancellation to the customer and to any 3rd party designated by the customer under Section 4.2.2.2 at least10 days before the effective date of the cancellation.

2.7.4.2 If customer makes payment of all amounts due pursuant to the Arrears Payment Agreement as of the cancellation √date referred to in Section 2.7.4.1 and makes payment on or before the cancellation date, the LDC shall reinstatethe Arrears Payment Agreement.

Code Amendt DetailsDSC Sect 2.8 Opening and Closing of Accounts

2.8.1 When LDC opens an account in the name of a person at the request of a 3rd party, LDC shall within 15 days On-going √ √ √ √of opening the account send a letter to the person advising of the opening of the account and requesting that the person agrees to be the named customer. If LDC does not receive confirmation within 15 days of the letter, theLDC shall advise the 3rd party that the account will not be set up as requested.

2.8.1.1 The LDC is not required to send a letter advising of the opening of the account where the request to open √ √the account is made in writing by the person's solicitor or person in possession of a valid Power of Attorney forthe person.

2.8.2 When LDC opens an account in the name of a person at the request of a 3rd party the LDC shall not hold the √ √3rd party responsible for any charges unless the person has agreed in writing to being the customer of LCDin relation to the property.

Code Amendt DetailsDSC Sect 2.8 Opening and Closing of Accounts (cont'd)

2.83 Despite any other provision of this Code with exception of the parties mentioned in Section 2.8.1.1 where a On-going √ √ √ √LDC receives a request to close or transfer an account in relation to a rental unit in a Residential Complex as




Revision Impact

Billing Credit Call Centre Finance Regdefined in the Residential Tenancies Act, 2006 or another residential property, the LDC shall not seek to recover any charges for the service provided to that rental unit or residential property after closure of the accountfrom any person, including the landlord for the residential complex or a new owner unless the person hasagreed in writing to assume responsibility for those charges.

2.8.4 For the purposes of Section 2.8 the requirement for agreement in writing includes agreements in electronic √ √form in accordance with the Electronic Commerce Act, 2000.

Code Amendt DetailsDSC Sect 4.2.2 Disconnection for Non-payment

LDC that intends to disconnect pursuant to Section 31 of the Electricity Act 1998, the property for non payment One timeshall send or deliver a disconnection notice to the customer that contains, at minimum the following information

(a) the amount that is overdue including ODI and other charges associated with non payment √ √(b) the earliest and latest dates on which disconnection may occur √ √(c) amount of any reconnection charges that may apply is disconnection occurs including where more than one √ √

charge has been approved by the Board and the circumstances in which each charge is payable(d) any action that the customer may take to avoid disconnection and the deadline for taking such action √ √(e) if a local Vital Service By-law is in effect that applies to the customer's property, whether the LDC has provided √ √

the required notification to the municipality(f) that a Board prescribed Arrears Management Program is available to all Residential customer, and that other √ √

voluntary bill payment, disconnection and financial assistance may be available, and contact information for theLDC where the customer can obtain further information about available financial assistance.

(g) the date on which the disconnection notice was printed by the distributor √ √4.2.2.2 LDC shall at the written request of a Residential customer, send a copy of any disconnection notice issued to On going

the customer for non-payment to a 3rd party designated by the customer for that purpose provided that therequest is made no later than the last day of the applicable minimum notice period set out in Section 4.2.3 In such a case:

(a) LDC must notify 3rd party that the 3rd party is not unless otherwise agreed with the LDC, responsible for the √ √payment of any charges for the provision of electricity service in relation to the customer's property, and

(b) Rules set out in Sections 2.6.4 and 2.6.8 shall apply, with such modification as the context may require for √ √the purposes of determine the date of receipt of the disconnection notice by the 3rd party.

4.2.2.3 A disconnection notice issued for non-payment shall expire on the date that is 11 days from the last day of On going √ √the applicable minimum notice period referred to in Section 4.2.3, determined in accordance with the rules setout in Section 2.6.8. LDC may not thereafter disconnect the property of the customer for non-payment unlessthe LDC issued a new disconnection notice in accordance with Section 4.2.2.

4.2.2.4 LDC must make reasonable efforts to contact, in person, or by telephone, a customer to whom the LDC has √ √issued a disconnection notice for non-payment prior to the earliest date on which disconnection for non-payment

Code Amendt DetailsDSC Sect 4.2.2 Disconnection for Non-payment (cont'd)

may occur as set out in the disconnection notice.4.2.2.5 In multi-unit bulk metered Residential building, LDC must post copy of the disconnection notice in a conspicuous On going √ √

place on or in the building promptly after issuance of the notice.4.2.2.6 LDC must suspend disconnection for a period of 21 days, from the date of notification by a Registered Charity, √ √

Government Agency, or Social Services Agency, that may be assessing a Residential Customer for determiningeligibility to receive bill payment assistance provided such notification is made 14 days form the date on whichthe disconnection notice is received by the customer. Where a Residential customer has requested prior to theissuance of the disconnection notice that the LDC also provide a copy of any disconnection notice to a 3rd partythe LDC shall suspend any disconnection action for a period 21 days from the date of notification by the 3rd party that they are attempting to arrange assistance with the bill payment, provided that such notification is made within 14 days for the date on which the disconnection notice is received by the customer.

4.2.2.7 Upon notification by a registered charity, government agency or social service agency that a customer is not √ √eligible to receive bill payment assistance, or if another 3rd party who was considering the provision of billassistance decides not to proceed, the LDC may disconnect the customer in accordance with Section 4.2.2.3and 4.2.3.

4.2.3 An LDC shall not disconnect a customer for non payment until the following minimum notice periods have elapsed:

(a) 60 days from the date on which the disconnection notice is received by the customer, in the case of a Residential √ √customer that has provided the LDC with documentation from a physician confirming that disconnection poses arisk of significant effects on the physical health of the customer or any dependant family member residing withthe customer.

(b) 14 days from the date on which the disconnection notice is received by a Residential customer or √ √(c) 10 days from the date on which the disconnection notice is received by the customer in all other cases √ √




Revision Impact

Billing Credit Call Centre Finance Reg4.2.3.1 For the purposes of Section 4.2.3:

(a) Where a disconnection notice is sent by mail, the disconnection notice shall be deemed to have been received √ √by the customer on the 3rd business day after the date on which the notice was printed by the LDC

(b) Where the disconnection notice is delivered by personal service, the disconnection notice shall be deemed to have √ √been received by the date of delivery

(c) Where a disconnect notice is delivered by being posted on the customer's property, the disconnection notice √ √shall be deemed to have been received by the customer on the date of such posting

(d) "Spouse" has the meaning given to it in Section 29 of the Family Law Act. √ (e) "Dependant family member" means a "dependant" as defined in Section 29 of the Family Law Act, and also √

includes a grandparent who, based on need, is financially dependant on the customer and,(f) The LDC shall apply the rules relating to the computation of time set out in Section 2.6.8. √

Code Amendt DetailsDSC Sect 6.1.2.1 Management of Customer Accounts

Nothing in Section 6.1.2 shall be construed as permitting an LDC to recover or to seek to recover charges for On going √ √ √ √a service provided to a property from any person other than a person that has agreed in writing to being thecustomer of the LDC in relation to the property or that has greed in writing to assume responsibility for thosecharges.

6.1.2.2 For the purposes of Section 6.1.2.1, the requirement for agreement in writing includes agreements in electronic √ √ √ √form in accordance with the Electronic Commerce Act, 2000.

6.1.2.3 Section 6.1.2.1 applies to all agreements entered into after the effective date of these amendments, and is not √ √ √ √intended to void or cancel any binding agreements for service existing as of the effective date of these amendments

Code Amendt DetailsDSC Sect 7.10 Reconnection Standards

7.10.1 Where an LDC has disconnected the property for non-payment, the LDC shall reconnect the service within On going √2 business days, as defined in Section 2.6.8 of the date on which the customer:

(a) Makes payment in full of the amount overdue for payment as specified in the disconnection notice or √(b) Enters into an Arrears Payment Agreement with the LDC as referred to in Section 2.7 √ √

7.10.2 This service quality requirement must be met 85% of the time on a yearly basisCode Amendt Details

7.2.5 (RSC) Equal Payment PlansAn LCD that provides distributor consolidated billing for a Residential customer shall bill the customer on the On going √basis of an equal monthly payment plan if so requested by the customer or the retailer. The equal monthlypayment plan shall comply with the requirements set out in the Standard Supply Service Code.If the LDC offers an equal payment or billing plan to a class of non-residential customer, the LDC shall whenproviding distributor consolidated billing for a non residential customer within that class, bill the non residentialcustomer on the basis of that equal payment or billing plan if so requested by the customer or retailer.

2.6.2(SSSC) LDC shall offer an equal monthly payment plan option to all Residential customer receiving SS service. The equalmonthly payment plan option shall meet the following minimum requirements:

(a) LDC may refuse to provide an Equal Monthly Payment Plan option to a customer that is in arrears on payment to the √ √LDC for electricity charges, as defined in the DSC and that has not entered into an Arrears Payment Agreement withthe LDC as referred to in DSC.

(b) LDC may require a Residential Customer on Equal Monthly Payment Plan to agree to pre-authorized automatic √ √monthly payment withdrawals from the customer's bank account if the billing cycle of the LDC is less than monthly.

(c) Despite any other provisions of this Code or of any other code issued by OEB, the equal payment plan option isoffered to Residential electricity customer shall provide for the customer to make equalized payments on a monthly √ √basis and shall make provision for the customer to select from at least two dates for the automated withdrawal fromthe customer's bank account.

(d) LDC may issue its bill to a Residential customer on a monthly equal payment plan on a monthly, bi-monthly or √ √quarterly basis.

(e) Subject to paragraph (f), the equal monthly payment plan shall provide for annual reconciliation of the plan as follows: √ √Code Amendt Details

7.2.5 (RSC) Equal Payment Plansi) Customer may join the equal payment plan at any time during the calendar year, LDC is only required to reconcile all On going √ √ √ √

of its EPP customers once during the calendar year and not on the 12th month anniversary of joining the plan.ii) In the first year of EPP where a customer has been on the plan for less than 12 months reconciliation may be earlier √ √ √

than 12th month anniversary, as a result of Subsection i)iii) LDC only required to reconcile EPP customers on an annual basis, must review EPP quarterly, or semi-annually and √ √ √

adjust the EPP amount in the event of changes in the customers consumption.iv) Where annual reconciliation indicates that funds are owing to the customer in an amount less than the customer's √ √ √




Revision Impact

Billing Credit Call Centre Finance Regaverage monthly billed amount, LDC shall credit the amount to the customer's account.

v) Where annual reconciliation indicates that funds are owing to the customer in an amount that is equal to or exceeds √ √ √ the customer's average monthly billing, the LDC shall credit the amount to the customer's account and advise the customer that the customer may contact LDC within 10 days of the date of bill to request refund of the overpaymentby cheque instead and the LDC shall make payment within 11 days of the customers request.

vi) Where annual reconciliation demonstrates that funds are owing by the customer in an amount that is less than the √ √ √customer's average monthly billing, the LDC may collect the full amount owed by a corresponding charge on the billissued to the customer in the 12th month of EPP plan, and

vii) Where annual reconciliation demonstrates that funds are owing by the customer in an amount that is equal to or √ √ √exceeds the customer's average monthly billing, the LDC shall roll over the balance due to the following year's EPP and recover the balance over the first 11 months of the following years EPP and,

(f) Where customer leaves the EPP for any reason, the LDC shall conduct a reconciliation and shall include any funds √ √ √owing by or to the customer as a charge or credit on the next regularly scheduled bill issued to the customer.

2.6.2A(a) Customer's average monthly billing amount shall be calculated by taking the aggregate of the total electricity charges √ √ √ √

billed to the customer in the preceding 12 months and dividing that value by 12. If the customer have been receivingservice from LDC for less than 12 months, the customer's average monthly billing amount shall be based on a reasonable estimate by LDC. For the purposes of this Section, "Electricity Charges" has the same meaning as inSection 2.6.7.3 of the DSC, and

(b) Where a Residential customer requests EPP, the EPP monthly payment amount all include all "Electricity Charges" √ √ √as defined in Section 2.6.7.3 of DSC

Code Amendt Details7.7.1 (RSC) Correction of Billing Errors

The following rules apply to billing errors in which Measurement Canada has not become involved in the dispute: On going √ √ √Where an LDC has overbilled a customer or retailer by an amount that is equal to or exceeds the customer's orretailer's average monthly billing amount (determined in accordance with Section 7.7.5) the LDC shall within10 days of discovery of the error, notify the customer/retailer of the over billing and advise that customer/retailermay elect to have the full credit applied to the account, or repaid in full by cheque within 11 days of requestingpayment by cheque. Where no cheque has been requested by customer/retailer within 10 days of notificationof the error by LDC the LDC may credit the full amount to the account.

Code Amendt Details7.7.1 (RSC) Correction of Billing Errors (cont'd)

7.7.2 Where an LDC has over billed a customer/retailer by an amount that is less than the customer/retailer's average On going √ √monthly billing amount, determined in accordance with Section 7.7.5 the LDC shall credit the account in thenext regularly scheduled bill issued to customer/retailer.

7.7.3 If there are outstanding arrears on the customers/retailer's account, the LDC is not required to repay the √ √over-billed amount but may apply it to the arrears on the customer/retailer's account and credit or repaythe remaining balance.

7.7.4 Where LDC have under billed a customer who in not responsible for the error, the LDC shall allow the customer √ √ √ √to pay the under billed amount in equal installments over a period equal to the duration of the billing error.

7.7.5 For the purposes of Sections 7.7.1 and 7.7.2 the customer/retailers average monthly billing amount shall be √ √ √ √calculated by taking the aggregate of the total electricity charges billed to customer/retailer in the preceding12 months and dividing that value by 12. If the customer has been receiving service for less than 12 months, theamount shall be calculated on a reasonable estimate. For the purposes of this section "Electricity Charges" hasthe same meaning as in Section 2.6.7.3 of the DSC.

7.7.6 Where LDC has under billed a customer/retailer who is responsible for the error, whether by way of tampering, √ √ √willful damage, unauthorized energy use or other unlawful action the LDC may require payment of the full amountunder billed by means of a corresponding charge on the next regular scheduled bill issued to customer/retailer.

7.7.7 Where LDC has under billed a customer/retailer the maximum period of under billing of which the LDC isentitled to be paid is 2 years. Where LDC have over billed customer/retailer, the maximum period of over billing √for which customer/retailer is entitled to be repaid is 2 years.

7.7.8 LDC may charge interest on under billed amounts only where the customer/retailer was responsible for the error. √ √ √Such interest shall be equal to the prime rate charges by the LDC's bank.

7.7.9 LDC that has over billed a customer/retailer and the billing error is not the result of LDC's standard documented √ √ √billing practices, shall pay interest on the amount credited or repaid to the customer/retailer equal to prime ratecharges by the LDC's bank.

7.7.10 The entity billing a customer, whether LDC or retailer is responsible for advising the customer of any meter √error and of his/her rights and obligations under the Electricity and Gas Inspection Act(Canada). The billingparty is also responsible for subsequently settling actual payment differences with the customer as described above.

7.7.11 The provisions of Section 7.7 do not apply where the LDC has over billed or under billed a customer/retailer but √




Revision Impact

Billing Credit Call Centre Finance Regissues a corrected bill prior to the due date of the original erroneous bill.




Request

(a) Please confirm the increase in total headcount from 2006 to 2008 is approximately 6.6% per year and from 2008 to 2010 is approximately 13.1% per year.

(b) Please explain the key changes in the Applicant’s operations that have driven these changes.

(c) Benchmark the Employees (FTE) and total Compensation to the number of customers and the load distributed from 2006-2010(forecast).

Response:

(a) Veridian confirms that the increase in total headcount from 2006 to 2008 is approximately 6.6% per year and from 2008 to 2010 is 13.1% per year, both calculated on non-compounded basis.

(b) Veridian identifies key changes that explain the growth in employee headcount at Exhibit 4 Tab 5 Schedule 2, page 1 through 12.



(c) The Benchmark table of Employees (FTE), total compensation, and load distributed from 2006 to 2010 (forecast) follows:

.2006 VCI + Affiliates 2007 2008 (Actual)

2009 (Projected)

2010 (Forecast)

Number of Employees (FTEs including Part-Time)

Total 164.7 174.5 186.5 205.2 235.5Total Compensation (Salary, Wages & Benefits)

Total * $14,413,923 $15,008,693 $17,032,754 $18,429,263 $21,330,886

Customers

Total

107,231 109,225 110,861 112,043 112,937

Load Distributed (MWh)

Total

2,419,475

2,532,414

2,501,314

2,455,988

2,465,704

Employee Index

Customers per Employee

651

626

594

546

480

kwh per Employee

14,690,194

14,512,401

13,411,871

11,968,752

10,470,081

Compensation Index

Compensation per Customer $134 $137 $154 $164 $189

Compensation per Mwh $5.96 $5.93 $6.81 $7.50 $8.65

* 2008 Compensation amended for error detected in pre-filed evidence. See response to Board Staffinterrogatory 25 c)




Request

(a) Update the Employee hiring Schedule for 2009 Actuals and 2010 forecast. Show the new numbers and totals alongside the original plan.

(b) Estimate the change in total compensation from the original plan to the actual 2009 and forecast 2010.

Response:

(a) See appended schedule that compares the Bridge and Test Year Hiring Schedule as filed at Exhibit 4/Tab 5/Schedule 8/Page 1/Table 1 with Veridian’s estimate forecast hiring schedule for 2010.

(b) Actual 2009 compensation is estimated to be $656,000 less than the 2009 plan.Forecast 2010 total compensation as at January 6, 2010 is $79,000 less than the forecast 2010 total compensation as filed within the pre-filed evidence.

Table 1: Bridge and Test Year Hiring Schedule:(as filed in pre‐filed evidence) (as revised January 6, 2010)

Planned 2009 HiresQ1 2009 Q2 2009 Q3 2009 Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2009 Q2 2009 Q3 2009 Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010

Accounting Analyst 1 1 1 1

Accounting Associate

1 1 1 1

Administration Clerk

1 1 1 1

Adminitrative Assistant

-1 -1 -1 -1

AMI Settlement Data Supervisor 1 1

11

Apprentice Lineperson

4 1 1 2 4 1 1 2

Corporate Planning Analyst

1 1 1 1

Corporate Plng Supervisor

1 1 1 1

Corporate Secretary 1 1 1 1

Customer Care Associate FT

1 1 1 1

Customer Care Associate PT

-0.4 -1 0.6 -0.4 -1 0.6

Customer Care Associate PT

1 1 1 1

Customer Care Rep. (Full time)

6 1 3 1 1 5 1 4

Customer Care Rep. (Part time)

1.8 1.8 1.8 1.8

Engineering Supervisor

1 1 1

Engineering Technician

5 3 2 5 3 2

Executive Assistant 1 1 1 1

Field Supervisor 2 1 1 2 1 1Financial Analyst 1 1 1 1Financial Reporting Analyst

1 1 1 1

GIS Technician 2 2 2 2IFRS Contract 0 1 -1 0 1 -1

Actual 2009 HiresNo. of HiresPosition

No. of Hires

No. of Hires by Hire Date Planned No. of Hires by Hire Date Planned No. of Hires by Hire Date

Table 1: Bridge and Test Year Hiring Schedule:(as filed in pre‐filed evidence) (as revised January 6, 2010)

Planned 2009 HiresQ1 2009 Q2 2009 Q3 2009 Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2009 Q2 2009 Q3 2009 Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010

Actual 2009 HiresNo. of HiresPosition

No. of Hires

No. of Hires by Hire Date Planned No. of Hires by Hire Date Planned No. of Hires by Hire Date

Inspector 1 1 1 1IT Analyst 1 1 1 1Key Accounts Representative

1 1 1 1

Lineperson 3 2 1 3 1 2Manager, Grid Operations

1 1 1 1

Manager, Northern District

-1 -1 -1 -1

Manager, Planning & Maintenance

1 1 1 1

Meter Technician 2 1 1 2 2Meter Technician Apprentice

1 1 1 1

Metering Clerk 1 1 1 1Operations Supervisor

1 1 1 1

Project Engineer 0 1 -1 0 1 -1Public Relations Representative

2 2 2 1 1

Settlements Analyst 1 1 1 1

Substation Technician

1 1 1 1

System Operations Technician

1 1 1 1

System Operator Apprentice

2 2 2 2

Co-op Line Apprentices

3 3 -3 3

Total Hires 50.4 5 3 22.6 5.8 8 0 6 0 53.4 5 6 5 3.6 20.8 5 7 0




The Application States:With the 2009 elimination of shared services with its energy services affiliate and the establishment of a new lease for office and storage space at 5 Mill Street, Port Hope, shared services in the 2010 test year will be restricted to:

The provision of executive management, financial and property management services to Veridian Corporation, and;

The sublease of office and storage space from Veridian Corporation at the following locations:

a. 459 Sidney Street, Bellevilleb. 1465 Pickering Parkway, Pickering

Request

(a) Please provide a copy of the 2010 Affiliate Services Agreement(s) between Veridian Networks and Veridian Corporation.

(b) What happens to costs and cost allocation if the separation of Veridian Energy Services is not accomplished by the beginning of the 2010 rate year?

(c) Provide a Copy (or Summary of the results) of the 2009 Time study that is the basis of 2010 allocations between Veridian Networks and Veridian Corporation.

Response:

(a) Veridian has not yet executed 2010 Affiliate Service Agreements.

(b) For the reasons explained in response to SEC Interrogatory number 3, Veridian plans to renew its Transitional Services Agreement with Veridian Energy Inc. for the first three months of 2010. Veridian submits that due to the transitional nature of these cost transfers, they should not be taken into consideration for the purpose of establishing its test year distribution revenue requirement.



(c) The following table shows summary results for the staff that completed the 2009 time study. The time study was not completed for the President & CEO. The study results for the Executive Assistant to the President & CEO were used as a proxy. The time study was also not completed for the position of Executive Assistant to the Executive Vice President & CFO, Corporate Services. The study results for the Executive Vice-President and CFO, Corporate Services were used as a proxy for this allocation, with an added 5% to reflect additional work volumes related to services to the Board of Veridian Corporation.

Summary Results of Time Study

%age of Time Allocated to VC

Executive Assistant to President & CEO 10.60%Executive Vice-President and CFO, Corporate Services 4.48%

Financial Supervisor 7.29%Accounting Analyst 7.00%Accounting Clerk 8.90%

Facilities Administrator 20.24%Facilities Assistant 8.61%



31. Ref: Exhibit 4 / Tab 6 / Schedule 5 / Attachment 1 / Appendix 2M

The Appendix indicates the following affiliate transactions in 2010:

2010 Veridian Connections to Veridian Corporation Governance, Financial and FacilitiesServices Fully allocated Cost $228,838 Range of 5 - 25% of various FTEs as per Service Agreement

2010 Veridian Corporation to Veridian Connections Leased Office & Storage Space Fully allocated Cost $374,376 By square footage of each rented premise

Request

Confirm that these are the only Services and reconcile the costs to Schedule A of the Service Level Agreements for 2010 (requested in previous IR)

Response:

Veridian confirms that these are the only services planned for exchange with Veridian Corporation during 2010. As explained in the response to VECC interrogatory 30:

• additional services will be provided to Veridian Energy Inc. on a transitional basis; and,

• the 2010 Affiliate Service Agreements have not yet been executed

Copies of the draft transfer pricing schedules for the 2010 Affiliate Service Agreements with Veridian Corporation are attached.

The total monthly charge from Veridian Corporation to Veridian Connections Inc. for the sublease of office and storage space will be $31,197.90 ($2,500 + $24,066.67 + $4,631.25) for an annual cost of $374,375.

The total monthly charge by Veridian Connections Inc. to Veridian Corporation for shared corporate services will be $17,151 for an annual cost of $205,812. The $228,838 amount referenced in Exhibit 4/Tab 6/Schedule 5/Attachment 1/Appendix 2M is in error, as it reflected a full year of shared costs related to the new Corporate Secretary and the Executive Assistant to the Corporate Secretary. These positions are scheduled to be filled mid-year 2010.



Attachments:

Veridian Connections to Veridian Corporation Services_2010

Veridian Corporation to Veridian Connections Services_2010

Schedule “A”

DESCRIPTION OF SERVICES AND PRICES

Veridian Connections Inc. services to Veridian Corporation

January 1st to December 31st 2010

Transfer pricing:

Description Price

Governance services, financial services related to the assessment of investment opportunities, preparation of financial statements, accounts payable administration, and general bookkeeping, and;

Property management and facilities maintenance services related to Veridian Corporation’s leased property located at 1465 Pickering Parkway, Pickering.

Flat Fee of $17,151 monthly, based on fully allocated labour costs related to the following full-time equivalent (FTE) time allocations:

Position Allocation (FTE)

Annualized Charge

President & CEO .10 $48,418Executive Assistant to President & CEO

.10 19,469

Executive Vice President & CFO, Corporate Services

.05 18,598

Executive Assistant to Executive Vice President & CFO, Corporate Services

.10 15,652

Corporate Secretary * .10 15,200Executive Assistant to Corporate Secretary *

.10 7,826

Financial Supervisor .10 17,067Accounting Analyst .10 11,243Accounting Clerk .10 9,785Facilities Administrator .25 37,777Facilities Assistant .25 4,777

Total Annual Charges: $205,812

*Annualized charges reflect the planned mid-year hire of the Corporate Secretary and the Executive Assistant to the Corporate Secretary

Schedule “A”

DESCRIPTION OF SERVICES AND PRICES

Veridian Corporation services to Veridian Connections Inc.

January 1st to December 31st 2010

Transfer pricing:

Description Price

Sublease of office and storage space at:§ 459 Sidney Street, Belleville§ 1465 Pickering Parkway, Pickering (Suite

200), and:§ 1465 Pickering Parkway, Pickering (Suite

102)

Notes:1) The sublease of space in Belleville is on a

‘net’ basis. The sub-tenant is directly responsible for operating expenses, insurance and real estate taxes as applicable.

2) The sublease rate for the space in Pickering is comprised of $14.75 per square foot base rent and $9.00 per square foot additional rent. The additional rent amount covering operating expenses, insurance and real estate taxes will be reconciled to actual costs once annually.

LocationRentable

Area (ft2)

Annual Lease Rate

per ft2

Monthly Charge

459 Sidney St., Belleville - - $2,5001465 Pickering Parkway,

Pickering (Suite 200) 12,160 $23.75 $24,066.67

1465 Pickering Parkway, Pickering (Suite 102)

2,340 $23.75 $4,631.25

All sublease costs are based on the pass through of Veridian Corporation actual head lease costs, with no margin or mark-up.




Veridian requires an additional $21,000,000 of long-term debt to finance capital projects. This additional debt will be provided by parent company, Veridian Corporation. The $21,000,000 debt instrument will be filed with the Board upon approval and execution by the parties. It will have a term of ten years. Similar to the notes payable to its municipal shareholders, the Veridian Corporation debt is proposed to have a variable interest rate that will match Ontario Energy Board’s deemed long-term debt rate each year during the term of the instrument.

Request

Has Veridian contacted Infrastructure Ontario to determine if any or all of the $21 million can be borrowed on more favorable terms? If Not why not. If yes provide details of the discussions.

Response:

(a) Please see the Veridian Financing Strategy appended to the response to Energy Probe Interrogatory #39 for a description of the process involved with renewing the Second Amended and Restated Promissory notes.




In accordance with the Cost of Capital Report’s treatment of “new” and “variable” debt,Veridian expects that its cost of debt for rate-making purposes will be based on theBoard’s 2010 deemed long-term debt rate. Veridian has used the 2009 deemed long-term debt rate of 7.62% as a placeholder in this pre-filed evidence. However, Veridian understands that this rate will be replaced by the 2010 deemed long-term debt rate and that the Board is currently reviewing the cost of capital.

Request

(a) Has Veridian assessed the impact of the Boards New Cost Of Capital Report on its Debt Costs for 2010? Provide an update to Table 1 that shows the projected changes in the cost of Debt

(b) Reconcile the amount owed under promissory note-- is it 21,322,000 as the evidence indicates or 31,000,000 as the note indicates?

(c) If Veridian wanted to pay off the $21,322,000 promissory note, is it able to do so without the agreement of shareholder? If no, what agreements are required and why?

(d) Are there any impediments to Veridian borrowing from a third party such as Infrastructure Ontario or a commercial bank? For example, would it require the “guarantee” or “permission” of its shareholders to undertake such borrowing?

(e) If the response to part (c) is yes, is there any reason to expect these impediments would prevent it from undertaking 3rd party borrowing? For example, if a “guarantee” was required from the shareholders, is there any reason to expect such a guarantee could not/would not be provided?

Response:

(a) Veridian believes that its proposed use of the deemed debt rate is consistent with the Board’s new cost of capital report.

(b) The $30 million Term Promissory Note issued on June 1, 2007 and owing to parent company Veridian Corporation provides for quarterly blended principal and interest payments. The principal outstanding on the loan as at December 31, 2009, after deducting principal payments made since 2007, will be $21.322 million.

(c) Veridian is unable to pay off the $21,322,000 promissory note without the agreement of the noteholder and shareholder, Veridian Corporation. An agreement would need to be reached with Veridian Corporation to repay the note as the note does not contain a provision for early repayment.



(d) Please see the Veridian Financing Strategy appended to the response to Energy Probe interrogatory #39.

(e) Not applicable. The answer to (c) is no.




The Application states:Veridian has used the latest S.T. debt value, 1.33% as established by the Board for May 1, 2009 implementation dates. Veridian understands that this rate will be replaced with the 2010 rate approved by the Board.

Request

Provide an update to the cost of capital based on the Boards change in the ST interest rate in the latest Cost of Capital Report.

Response:

Veridian is unable to estimate the cost of capital based on the Boards changes in the latest Cost of Capital Report. Veridian understands that the short-term rate will be established by the Board by averaging short-term debt issuances over 3-month Bankers’ Acceptance rates. Veridian does not track or keep data on average Bankers’ Acceptance rates.



35. Ref: Exhibit 5 / Tab 2 / Schedule 3 / Page 1 / Attachment 1

The application states:Veridian Connections Inc. proposes that the Return on Equity rate should be the value as established by the Ontario Energy Board for Cost of Service Applications. This application uses the latest value, 8.01% as established by the Board for May 1, 2009 implementation dates. Veridian understands that this rate will be replaced with the 2010 rate.

Request

(a) Provide an update to Exhibit 5 Tab 2 Schedule 3 Attachment 1 Page 2 that reflects the projected changes to Cost of Capital arising from The Board’s latest Cost of Capital Report.

(b) Provide an estimate of the revised Return on rate base and impact on the as filed 2010 Distribution Revenue Requirement and Revenue Deficiency.

Response:

The amount of Veridian’s 2010 rate base and revenue requirement for the 2010 Test Year has changed as a result of Veridian’s Application Update. This interrogatory has been answered on the basis of the updated values.

(a) Veridian provides as Attachment 1, an update to Exhibit 5 Tab 2, Schedule 3, Attachment 1, page 2 that reflects the projected changes to Cost of Capital arising from the Board’s latest Cost of Capital Report. Veridian has used the most recent information available for calculation of all components of the cost of capital as follows;

• ROE – 9.75% - As per the value published in the referenced report.• Deemed Debt Rate – 7.62 % - Veridian has not updated its proposed cost of

debt from that originally filed. No value for the deemed debt rate was published in the referenced report and Veridian is unable to calculate an estimate of an updated debt rate as it does not have access to the referenced sources of information.

Veridian notes that the any changes in total cost of capital provided in this response are not representative of the total changes or impacts anticipated by the Board’s referenced report as Veridian’s proposed long term debt rate was based on the Board’s deemed debt rate. Veridian used the 2009 deemed debt rate of 7.62% as a placeholder, however Veridian expects that the 2010 deemed debt rate will be lower than 7.62%.



(b) Please see responses to Schools Energy Coalition Interrogatories 8 and 34.

Update to Exhibit 5, Tab 2, Schedule 3, Attachment 1, Page 2Based on ROE of 9.75%Capitalization and Cost of Capital

Particulars Cost Rate Return Cost Rate Return Cost Rate Return(%) ($000) (%) ($000) (%) ($000) (%) ($000) (%) ($000) (%) ($000)

Long Term Debt Veridian Main 53.5% 88,541 6.83% 6,046 56.0% 98,394 7.06% 6,949 56.0% 105,098 7.11% 7,471 Veridian Gravenhurst Total Long Term Debt 53.5% 88,541 6.83% 6,046 56.0% 98,394 7.06% 6,949 56.0% 105,098 7.11% 7,471 Short Term Debt Veridian Main 4.0% 6,620 4.47% 296 4.0% 7,028 1.33% 93 4.0% 7,507 1.33% 100 Veridian Gravenhurst Total Short Term Debt 4.0% 6,620 4.47% 296 4.0% 7,028 1.33% 93 4.0% 7,507 1.33% 100 Total Debt 57.5% 95,161 6.66% 6,342 60.0% 105,422 6.68% 7,042 60.0% 112,605 6.72% 7,571

P f d Sh

Bridge Year Test Year2008 2009 2010

Capitalization Ratio Capitalization Ratio Capitalization Ratio

Preferred Shares Veridian Main 0.0% - - - Veridian Gravenhurst Total Preferred SharesCommon Equity Veridian Main 42.5% 70,336 8.57% 6,028 40.0% 70,281 8.01% 5,630 40.0% 75,070 9.75% 7,319 Veridian Gravenhurst Total Common Equity 42.5% 70,336 8.57% 6,028 40.0% 70,281 8.01% 5,630 40.0% 75,070 9.75% 7,319 Total Equity 42.5% 70,336 8.57% 6,028 40.0% 70,281 8.01% 5,630 40.0% 75,070 9.75% 7,319

Total Debt and Equity 100% 165,497 7.47% 12,370 100.0% 175,704 7.21% 12,672 100.0% 187,676 7.93% 14,890



36. Ref: Exhibit 6 / Tab 1 / Schedule 1 / Table 3Exhibit 6 / Tab 1 / Schedule 2 / Page 1 / Table 1

Request

(a) Update Table 3 to reflect the current projections for cost of capital in 2010

(b) Update Table 1 in the second reference to reflect updated cost of capital

(c) Provide a schedule that sets out the derivation of 2010 Revenues at 2009 Rates by customer class (per Reference (ii)). Please provide the rates and volumes used and confirm that the rates are net of transformer ownership allowances (where applicable), smart meter adders and SSS Administration charges.

Response:

(a) Please see the response to School Energy Coalition interrogatory #34.

(b) Veridian’s interpretation of the reference is Exhibit 6, Tab 1, Schedule 2, Page 1, Table 1 – 2010 Distribution Revenue at Current Rates. Based on this interpretation, Veridian believes the values in this table would be unchanged by current projections for cost of capital in 2010 as the calculation uses 2010 forecasted volumes and customer counts and 2009 rates – all of which are unaffected by 2010 cost of capital values.

(c) For VCI_Main, please see Exhibit 10, Tab 1, Schedule 1, Attachment 3, page 40. For VCI_Gravenhurst, please see Exhibit 10, Tab 1, Schedule 1, Attachment 4, page 40. All volumes and rates are provided in the above references. Veridian confirms that the rates are net of transformer ownership allowances, smart meter adders and SSS Administration charges.




The Application States:Veridian proposes that the 2010 Base Revenue Requirement be apportioned to the two5 rate zones in the same proportion as the 2006 Approved Base Revenue Requirement for 6 the rate zones.

Request

(a) Provide a version of Table 1 for the 2010 test year.

(b) Compare the % of 2010 Revenue requirement allocated to Main and Gravenhurst to that provided in response to VECC IR#2 b).

(c) Explain any material differences between the calculated and proposed revenue requirement allocations.

Response:

Veridian’s 2010 Service Revenue Requirement and 2010 Revenue Offsets have changed as a result of Veridian’s application update. This interrogatory has been answered on the basis of the updated values.

(a) Veridian would like to note that the statement above is incorrect. The correct statement is “Veridian proposes that the 2010 Base Revenue Requirement be apportioned to the two rate zones in the same proportion as the 2006 Approved Base Revenue Requirement for the rate zones.”

As explained in Exhibit 6, Tab 2, Schedule 1 and Schedule 2, the 2010 Service Revenue Requirement and Revenue Offsets have not been apportioned to the rate zones as the various components of these amounts are available only a single entity basis.

On this basis, Veridian has attempted to complete a version of Table 1 for the 2010 Test Year. Rate zone specific information such as LV charges and transformer allowances has been provided. The calculation of Total ‘2010 Base Revenue Requirement’ using this methodology has then been apportioned to the rate zones using the proposed ratio of 94.04% for VCI_Main and 5.96% for VCI_Gravenhurst, rather than percentages being calculated. No other percentages can be calculated as the 2010 Service Revenue Requirement and Revenue Offsets are not apportioned, but rather calculated on a single entity basis.



Total VCI_Main VCI_Gravenhurst2010 Service Revenue Requirement

$51,866,572 Not Available Not Available

Less: Revenue Offsets

$4,218,100 Not Available Not Available

Less: LV Charges $1,664,268 $1,422,560 $241,708Add: Transformer Allowance

$838,229 $826,772 $11,457

2010 Base Revenue Requirement

46,822,433 $44,031,816 $2,790,617

%age of Total 94.04% 5.96%

It should be noted that 2010 Base Revenue Requirement calculated on this basis will be lower than Veridian’s proposed 2010 Base Revenue Requirement as this methodology incorrectly deducts LV charges which are not included in the 2010 Service Revenue Requirement as was the case in the 2006 Revenue Requirement calculation.

(b) No calculation was performed in response to VECC IR#2 b), rather a reference to the response to the Board Staff interrogatory 38 was provided.

(c) As no percentages have been calculated in the 2010 version of Table 1, no comparison between calculated and proposed revenue requirement allocations can be made. Please see response to Board Staff interrogatory 38 where the results between an alternative methodology considered by Veridian and the proposed revenue requirement apportionment methodology are compared.




Request

(a) Please provide full electronic copies of the Cost Allocation Models VM-2010 and VG-2010.

(b) Please confirm whether Models VM-2010 and VG-2010 also included the Adjustment #1 (correction for transformer ownership allowance) and Adjustment #2 (as applicable for 2010).

(c) If the response to part (b) is that Adjustments #1 and #2 were not included in the 2010 Models, please provide revised 2010 runs for both the Main and Gravenhurst service areas with these two adjustments included.

Response:

(a) Full electronic copies of the Cost Allocation Models VM-2010 and VG-2010 are attached.

(b) Confirmed.

(c) Not Applicable.

DOCSTOR: 1842591\1

Attachments 1 and 2

(Note: These attachments are being e-mailed to you– the files are too large be to included here)




Request

(a) With respect to Attachment 3, page 14 (lines 13-16) – please confirm whether it was the Total Revenue or the Distribution Revenue by class that was scaled up. If it was the Total Revenue by class, please recalculate the revenue to cost ratios based on an approach that scales the Distribution Revenue by class.

(b) With respect to Attachment 1 (page 2) and Attachment 3 (page 14), please confirm that for Veridian-Main the revenues based on 2006 rates and 2010 load were scaled down (as opposed to up as suggested by the text) in order to produce a total revenue to cost ratio of 100%.

(c) Please provide the full electronic copies of Cost Allocation Runs VM-2006C2 and VG-2006C.

Response:

(a) - It was Total Revenue by class that was scaled.

Customer Class VM-2006C2 VM-2010 VM-2010re-calculated

Board Target Range

Residential 99.33 98.04 98.11 85-115GS < 50 kW 117.56 120.71 120.50 85-115GS > 50 kW 98.79 98.47 98.39 85-115Intermediate 61.53 74.21 74.08 80-120Large Use 62.84 80.65 80.49 80-180Sentinel Lighting

40.1 42.74 42.81 70-120

Street Lighting 71.29 72.54 72.41 70-120USL 87.42 96.97 97.10 80-120

(b) - Given that the unique circumstances around Veridian's integration of Gravenhurst, expenses are based on 2004 costs, and revenues are based on projected 2010 loads. This has resulted in a scaling down in order to produce a total revenue to cost ratio of 100%.

(c) Full electronic copies are provided in Attachment 1.

DOCSTOR: 1842587\1

Attachments 1 and 2

(Note: These attachments are being e-mailed to you– the files are too large be to included here)




Request

(a) Given the inability of Veridian to do a Cost Allocation by service areas based on 2010 costs and the fact that 2010 costs are not tracked by service area but rather apportioned based on the 2006 approved revenue requirement for each, does Veridian consider its cost allocation results for 2010 to be as robust and accurate as those prepared for 2006. • If yes, please explain why.• If no, please comment as to why the target ranges established by the Board

for revenue to ratios based on the 2006 CA filings should apply to Veridian in 2010.

(b) For Veridian-Main, the Applicant is proposing to increase the revenue to cost ratio for the residential class even though the current ratio is well within the Board’s target range. The Applicant is also proposing to increase the ratios for the Large Use and Intermediate classes to values above the lower boundary of the Board’s target range for each class. Please explain why such changes are considered to be consistent with the Board’s Report per EB-2007-0667 and the Board’s finding in other cost of service Applications where the ratios were adjusted only as required to more each customer class to the boundary of the Board’s ranges.

(c) Please explain why for Veridian-Main the Application includes specific proposals for 2011 revenue to cost ratio adjustments (page 2); while for Veridian-Gravenhurst no approval is sought for the 2011 revenue to cost ratios (page 4).

Response:

(a) No. The 2010 Veridian Cost Allocation Model utilizes a proxy method that provides the most appropriate assessment of the 2010 revenue to cost ratios given available data. Veridian does not consider it to be appropriate to deviate from the Board-approved target ranges for revenue to cost ratios. The existing ranges explicitly recognize the high degree of imprecision inherent in the revenue to cost calculations of Ontario LDCs in general. There is no reason to believe that Veridian’s cost allocation results are not consistent with the accuracy of other Ontario LDCs’ cost allocation results, given the myriad of factors affecting the accuracy of calculated revenue to cost ratios.

(b) Veridian has proposed rates that it considers to be just and reasonable. The changes in the revenue to cost ratios are consistent with all Board directives. Changes in revenue



to cost ratios that increase equity by moving class revenue to cost ratios toward 100% without causing rate shock are consistent with all Board directives.

(c) Veridian is not seeking approval for any 2011 revenue to cost ratio adjustments within its 2010 Cost of Service rate application. The 2011-2013 adjustments proposed for both rate zones is indicative only and Veridian will seek approval of these adjustments in future applications.



41. Ref: Exhibit 6 / Tab 1 / Schedule 2 / Page 1Exhibit 7 / Tab 3 / Schedule 2 / Attachment 1 / Page 1Exhibit 10 / Tab 1 / Schedule 1 / Attachment 3 / Page 40Exhibit 10 / Tab 1 / Schedule 1 / Attachment 4 / Page 40

Request

(a) The first two references report different 2010 revenues for Veridian-Main based on existing rates. Please reconcile.

(b) Please re-do the schedule in the third reference so that the revenues (at existing rates) reported for each customer class are net of the LV rate adder and the transformer ownership allowance.

(c) Please reconcile any differences between the result (by customer class) presented in response to part (b) and those set out in Reference (ii) – page 1.

(d) Please re-do the schedule in the fourth reference so that the revenues (at existing rates) reported for each customer class are net of the LV rate adder and the transformer ownership allowance.

(e) Please reconcile any differences between the result (by customer class) presented in response to part (d) and those set out in Reference (ii) – page 2.

Response:

(a) The calculation of and values for the Test Year Revenue at Existing Rates in Exhibit 7, Tab 3, Schedule 2, Attachment 1, page 1 of $41,422,533 can be found at Exhibit 10, Tab 1, Schedule 1, Attachment 3, page 43.The amount in Exhibit 6, Tab 1, Schedule 2, Page 1, Table 1 of $41,430,742 is incorrect and is overstated by $8,209. The calculation of and values for this amount can be found at Exhibit 10, Tab 1, Schedule 1, Attachment 3, page 40. The difference is due to the incorrect use of the 2009 value of the LV charges embedded in 2009 distribution rates in this calculation.

(b) Please see Exhibit 10, Tab1, Schedule 1, Attachment 3, page 43.

(c) Please see the response to part (a).

(d) Please see Exhibit 10, Tab 1, Schedule 1, Attachment 4, page 43.

(e) There are no differences.



42. Ref: Exhibit 6 / Tab 2 / Schedule 2 / Pages 2-3Exhibit 7 / Tab 3 / Schedule 2 / Attachment 1Exhibit 8 / Tab 1 / Schedule 1

Request

(a) Please confirm whether the 2010 revenue requirement apportioned to Veridian-Main and Veridian-Gravenhurst in Reference (i) includes an adjustment for the transformer ownership allowance.

(b) If the response to part (a) is yes, please explain why when the May 2009 Filing Guidelines directed that it be excluded.

(c) If the response to part (a) is no, please explain why the percentages used to determine the split between the two service area (Reference (i)) were based on the 2006 revenue requirement for each service area adjusted to include the transformer ownership allowance as a cost.

Response:

(a) Veridian’s 2010 Revenue Requirement has changed as a result of Veridian’s application update. The details of the application update have been filed concurrent with interrogatory responses. This interrogatory has been answered on the basis of the updated value of Veridian’s 2010 Revenue Requirement. The methodology for apportionment of the 2010 revenue requirement has not been changed as a result of the application update.

The 2010 revenue requirement apportioned to Veridian_Main and Veridian_Gravenhurst in Reference (i) does not include an adjustment for the transformer ownership allowance.

(b) Not applicable.

(c) Veridian did not consider the difference in methodologies between the calculation and allocation of the 2006 Base Revenue Requirement as per the Board issued 2006 EDR Model and the direction provided in the May 2009 Filing Guidelines as it relates to the required revision to the cost allocation model for treatment of the transformer allowance. Veridian proposes that the direction within the May 2009 Filing Guidelines is specific to allocation to classes and is not applicable to Veridian’s allocation of revenue requirements to rate zones, for which the May 2009 Filing Guidelines provide no direction. Veridian has followed the May 2009 Filing Guidelines specific treatment of transformer allowance as it relates to the cost allocation model.



43. Ref: Exhibit 8 / Tab 2 / Schedule 1 / Veridian_Main

Request

(a) Did the variable rates used to determine the fixed/variable percentages set out in Table 1 exclude the LV rate adder and allow for the transformer discount where appropriate?

(b) Please provide a schedule that sets out the 2010 fixed and variable revenues by customer class based on existing rates and the resulting fixed/variable percentages where the variable rates used exclude the LV rate adder and variable revenues are reduced by the transformer allowance as applicable.

(c) Please confirm that the Board’s EB-2007-0667 Guideline (page 12) sets the upper limit for the MSC at 120% of avoided costs plus the allocated customer costs (i.e., Minimum System plus PLCC Adjustment). Based on this definition, if Veridian-Main’s fixed charges were set so as to maintain the fixed/variable percentages determined in part (b) would any of the resulting monthly service charges exceed the Board’s upper limit?

Response:

(a) No variable rate was used to determine the fixed/variable percentages set out in Table 1. The methodology for determining the fixed/variable percentages was to set the fixed rate with the primary purpose of maintaining existing fixed/variable revenue splits by customer class while setting the absolute value of the fixed rate at no higher than the Monthly Service charge ceiling as calculated in the 2010 Main Cost Allocation Model (VM-2010).

(b) The requested schedule is attached.

(c) In the Report of the Board on Application of Cost Allocation for Electricity Distributors (EB-2007-0667), it is stated that “The Methodology set a ceiling for the MSC based on the avoided costs plus the allocated customer costs. The Discussion Paper proposed that the ceiling for the MSC be 120% of this level.” It goes on to say, “The Board considers it to be inappropriate to make significant changes to the ceiling for the MSC at this time, given the number of issues that remain to be examined.” And also states “In the interim, the Board does not expect distributors to make changes to the MSC that result in a charge that is greater than the ceiling as defined in the Methodology for the MSC. Distributors that are currently above this value are not required to make changes to their current MSC to bring it to or below this level at this time.” Veridian does not interpret the above statements in the Report of the Board to



be a guideline which “sets the upper limit for the MSC at 120% of avoided costs plus the allocated customer costs (i.e., Minimum System plus PLCC Adjustment).

Yes, the resulting monthly service charges would exceed the ceiling as defined in the Methodology for the MSC for the GS > 50 kW, Intermediate and Large Use classes.

Veridian Connections Inc.- VCI Main (ED-2002-0503)

2010 PROJECTED DISTRIBUTION REVENUE AT EXISTING RATES

Customer Class Name Total Less: LV Pass-thru Less: Trans Allow Adjusted Total Fixed Fixed % Adjusted Variable Variable %Residential 26,598,051$ (741,909)$ 25,856,142$ 12,223,571$ 47.28% 13,632,571$ 52.72%General Service Less Than 50 kW 6,406,893$ (235,973)$ 6,170,920$ 1,274,484$ 20.65% 4,896,436$ 79.35%General Service 50 to 2,999 kW 9,416,510$ (876,843)$ (588,094)$ 7,951,573$ 1,656,897$ 20.84% 6,294,676$ 79.16%General Service 3,000 to 4,999 kW 266,718$ (39,482)$ (51,667)$ 175,570$ 127,976$ 72.89% 47,594$ 27.11%Large Use 1,020,726$ (123,832)$ (187,011)$ 709,883$ 480,638$ 67.71% 229,244$ 32.29%Unmetered Scattered Load 166,872$ (4,331)$ 162,541$ 72,135$ 44.38% 90,406$ 55.62%Sentinel Lighting 30,965$ (531)$ 30,435$ 16,732$ 54.98% 13,703$ 45.02%Street Lighting 379,099$ (13,628)$ 365,470$ 191,479$ 52.39% 173,992$ 47.61%

Gross Revenue 44,285,833$ (2,036,528)$ (826,772)$ 41,422,533$ 16,043,912$ 25,378,621$



44. Ref: Exhibit 8 / Tab 2 / Schedule 2 / Veridian_Gravenhurst

Request

(a) Did the variable rates used to determine the fixed/variable percentages set out in Table 1 exclude the LV rate adder and allow for the transformer discount where appropriate?

(b) Please provide a schedule that sets out the 2010 fixed and variable revenues by customer class based on existing rates and the resulting fixed/variable percentages where the variable rates used exclude the LV rate adder and variable revenues are reduced by the transformer allowance as applicable.

(c) Please confirm that the Board’s EB-2007-0667 Guideline (page 12) sets the upper limit for the MSC at 120% of avoided costs plus the allocated customer costs (i.e., Minimum System plus PLCC Adjustment). Based on this definition, if Veridian-Gravenhurst’s fixed charges were set so as to maintain the fixed/variable percentages determined in part (b) would any of the resulting monthly service charges exceed the Board’s upper limit?

(d) Why is it appropriate to increase the monthly service charge for GS>50 to the maximum of the Board’s range as opposed to just moving to the lower bound of the range?

Response:

(a) No variable rate was used to determine the fixed/variable percentages set out in Table 1. The methodology for determining the fixed/variable percentages was to set the fixed rate with the primary purpose of maintaining existing fixed/variable revenue splits by customer class while setting the absolute value of the fixed rate at no higher than the Monthly Service charge ceiling as calculated in the 2010 Gravenhurst Cost Allocation Model (VG-2010) and addressing any significant anomalies within the existing revenue splits.

(b) The requested schedule is attached.

(c) Please see the response to VECC Interrogatory #43 part c). No, none of the resulting monthly service charges would exceed the ceiling as defined in the Methodology for the MSC.

(d) Moving the monthly service charge for the GS> 50 kW class just to the lower bound of the range i.e. $67.34, would set the fixed/variable percentages at 9.53% fixed and 90.47% variable. Veridian proposes that these levels would vary materially from the



average fixed/variable split of the rest of the rate classes in the VCI_Main rate zone. The average fixed percentage for the balance of the rate classes is 49.58%.

Even moving the monthly service charge to $110.62 still sets the fixed percentage (15.67%) at a rate much lower than the average, but does not conform to the Methodology as described in the Report of the Board.

Veridian Connections - Response to VECC Interrogatory # 44 - Part b

Veridian Connections Inc.- VCI Gravenhurst (ED-2002-0503)

2010 PROJECTED DISTRIBUTION REVENUE AT EXISTING RATES

Customer Class Name Total Less: LV Pass-thru Less: Trans Allow Adjusted Total Fixed Fixed % Adjusted Variable Variable %Residential Urban Year-Round 861,260$ (73,972)$ 787,288$ 318,798 40.49% 468,490 59.51%Residential Suburban Year-Round 306,873$ (25,537)$ 281,336$ 115,821 41.17% 165,515 58.83%Residential Suburban Seasonal 758,745$ (25,300)$ 733,445$ 450,281 61.39% 283,164 38.61%General Service Less Than 50 kW 374,369$ (35,446)$ 338,924$ 87,851 25.92% 251,073 74.08%General Service 50 to 4,999 kW 390,309$ (65,170)$ (11,457)$ 313,682$ 13,602 4.34% 300,080 95.66%Sentinel Lighting 609$ (96)$ 513$ 413 80.57% 100 19.43%Street Lighting 6,150$ (1,187)$ 4,962$ 4,432 89.31% 530 10.69%

Gross Revenue 2,698,316$ (226,708)$ (11,457)$ 2,460,150$ 991,198$ 1,468,952$



45. Ref: Exhibit 8 / Tab 1 / Schedule 1 / Page 1Exhibit 8 / Tab 3 / Schedule 1Exhibit 8 / Tab 3 / Schedule 2

Request

Please confirm that the differences between the revenue requirements by customer class (for both Veridian-Main and Veridian-Gravenhurst) reported in the two references are due to the cost of the transformer allowance being included in the class revenue requirements in Reference (ii).

Response:

Confirmed.




Request

What is the basis for Veridian’s assumption that the LV rates adders will not be revised/updated during the IRM period?

Response:

Veridian has made no assumption that LV rates adders would not be revised/updated during the IRM period, rather it has attempted to calculate a rate to be effective May 1st, 2010 so that it would not be necessary to revise or adjust the LV rates adders during the IRM period, thus providing stability in the LV rate.

Prior to 2010, LV charges were recovered as a component of base distribution rates, rather than a separately calculated rate adder. No formal processes under 2nd Generation IRM existed for adjusting the recovery of LV charges through base distribution rates.




Request

(a) For Veridian-Main (Attachment 1), please provide the bill impacts for a Residential customer using:• 500 kWh per month• 250 kWh per month• 100 kWh per month

(b) For Veridian Gravenhurst (Attachment 2), please provide the bill impacts for a Residential Urban customer using::• 500 kWh per month• 250 kWh per month• 100 kWh per month

(c) For Veridian Gravenhurst (Attachment 2), please provide the bill impacts for a Residential Suburban customer using::• 500 kWh per month• 250 kWh per month• 100 kWh per month

(d) For Veridian Gravenhurst (Attachment 2), please provide the bill impacts for a Residential Suburban Season customer using::• 500 kWh per month• 250 kWh per month• 100 kWh per month

(e) Based on the most recent 12 months billing data, please provide a schedule that includes the following information regarding Veridian-Gravenhurst’s Residential Urban customers:• Total number of customers using less than 100 kWh per month• Total number of customers using between 100 and 250 kWh per month.• Total number of customers using between 250 and 500 kWh per month• Overall total number of customers.

(f) Based on the most recent 12 months billing data, please provide a schedule that includes the following information regarding Veridian-Gravenhurst’s Residential Suburban customers:• Total number of customers using less than 100 kWh per month • Total number of customers using between 100 and 250 kWh per month. • Total number of customers using between 250 and 500 kWh per month• Overall total number of customers.



(g) Based on the most recent 12 months billing data, please provide a schedule that includes the following information regarding Veridian-Gravenhurst’s Residential Suburban Seasonal customers:• Total number of customers using less than 100 kWh per month • Total number of customers using between 100 and 250 kWh per month. • Total number of customers using between 250 and 500 kWh per month • Overall total number of customers.

Response:

Veridian’s proposed Tariff of Rates and Charges has changed as a result of Veridian’s Application Update. This interrogatory has been answered on the basis of the updated rates and bill impacts.

(a) The bill impact summary provided at Exhibit 8, Tab 7, Schedule 2, Attachment 1 has been updated to reflect the changes due to Veridian’s application update and includes the requested bill impacts for a Residential customer using 500 kWh, 250 and 100 kWh per month. It is provided as Attachment 1.

(b) (c) and (d) The bill impact summary provided at Exhibit 8, Tab 7, Schedule 2, Attachment 2 has been updated to reflect the changes due to Veridian’s application update and includes the requested bill impacts for Residential Urban, Residential Suburban and Residential Seasonal customers using 500 kWh, 250 and 100 kWh per month. It is provided as Attachment 2.

(e), (f) and (g)

The table below provides the information requested in parts e, f and g.

Residential Urban

Residential Suburban

Residential Seasonal

Less than 100 kWh per mo 121 31 264Between 100 - 250 kWh per mo 181 30 444Between 250 - 500 kWh per mo 659 87 370

Overall Total Number As of November 30th, 2009 3,023 751 1603

l 50 to 2 999 kW 435 000 1 480 $191 95 ($1 655 76) (16 3%) ($1 656 06) (3 8%)

Veriidan_VECC_IRR 47‐Attachment 1Updated Bill Impact Summary ‐ Veridian Main

Volume RPP Distribution Charges Delivery Sub-total Total BillCustomer Class Name

kWh kWRate Class $ change % change $ change % change $ change % change

Residential 800 0 Summer $2.65 11.2% ($0.95) (3.1%) ($0.95) (1.0%)1,000 0 Summer $2.89 10.8% ($1.61) (4.6%) ($1.61) (1.4%)1,500 0 Summer $3.49 10.1% ($3.26) (6.9%) ($3.27) (2.0%)2,000 0 Summer $4.09 9.7% ($4.91) (8.3%) ($4.91) (2.2%)5,000 0 Summer $7.69 8.7% ($14.81) (11.3%) ($14.82) (2.7%)800 0 n/a $2.65 11.2% $0.57 1.9% $0.57 0.6%500 0 Summer $2.29 12.0% $0.04 0.2% $0.04 0.1%250 0 Summer $1.99 13.1% $0.86 5.0% $0.86 0.1%100 0 Summer $1.81 14.1% $1.36 9.9% $1.36 0.1%

General Service Less Than 50 kW 1,000 0 Non‐res. $1.77 5.6% ($2.83) (7.2%) ($2.83) (2.4%)2,000 0 Non‐res. $2.27 4.6% ($6.93) (10.7%) ($6.93) (3.1%)

10,000 0 Non‐res. $6.27 3.3% ($39.73) (15.0%) ($39.73) (3.7%)35,000 0 Non‐res. $18.77 3.0% ($142.23) (16.0%) ($142.25) (3.8%)25,000 0 Non‐res. $13.77 3.1% ($101.23) (15.8%) ($101.26) (3.7%)2,000 0 Non‐res. $2.27 4.6% ($6.93) (10.7%) ($6.93) (3.1%)25,000 0 n/a $13.77 3.1% ($53.73) (8.4%) ($53.76) (2.1%)

General Service 50 to 2 999 kWGenera Service , 435,000 1 480 n/a, n/a $191 95. 3 9%3.9% ($1 655, .76) (16 3%) ($1 656 06) (3 8%). , . .100,000 500 n/a $68.86 3.9% ($644.59) (18.4%) ($644.66) (5.7%)40,000 100 n/a $18.62 4.1% ($86.07) (10.6%) ($86.09) (2.2%)

General Service 3,000 to 4,999 kW 1,750,000 4,000 n/a $556.01 4.7% ($3,182.19) (11.7%) ($3,183.36) (2.0%)Large Use 4,200,000 6,800 n/a $2,016.45 10.2% ($7,227.27) (15.7%) ($4,404.03) (1.2%)Unmetered Scattered Load 800 0 Non‐res. $2.49 11.9% ($1.11) (4.1%) ($1.11) (1.3%)Sentinel Lighting 180 1 Non‐res. $2.62 53.0% $1.78 29.4% $1.78 9.2%Street Lighting 180 1 Non‐res. $0.31 13.5% ($0.50) (14.4%) ($0.50) (3.0%)Note: RPP Rate Class of "n/a" indicates Non-RPP customers subject to the Global Adjustment Rate Rider

Veridian_VECC IRR_47 ‐ Attachment 2 Application Update ‐ Revised VCI_Gravenhurst Bill Impact Summary

Volume RPP Distribution Charges Delivery Sub-total Total BillCustomer Class Name

kWh kWRate Class $ change % change $ change % change $ change % change

Residential Urban Year‐Round 800 0 Summer $4.52 17.7% $7.02 20.4% $7.77 7.9%

1,000 0 Summer $5.10 17.3% $8.24 20.3% $9.18 7.6%

1,500 0 Summer $6.55 16.7% $11.24 20.0% $12.64 7.0%

2,000 0 Summer $8.00 16.3% $14.26 19.9% $16.12 6.8%

5,000 0 Summer $16.70 15.4% $32.36 19.7% $37.02 6.3%

800 0 n/a $4.52 17.7% $7.28 21.1% $7.97 8.1%

500 0 Summer $3.65 18.7% $5.21 20.7% $5.62 8.9%

250 0 Summer $2.93 20.1% $3.71 21.3% $3.92 10.8%

100 0 Summer $2.49 21.4% $2.79 21.9% $2.87 14.1%Residential Suburban Year‐Round 800 0 Summer $5.89 19.9% $8.39 21.7% $9.14 9.0%

1,000 0 Summer $6.59 19.6% $9.73 21.7% $10.67 8.5%

1,500 0 Summer $8.34 19.0% $13.03 21.5% $14.43 7.8%

2,000 0 Summer $10.09 18.7% $16.35 21.4% $18.21 7.5%

5,000 0 Summer $20.59 18.0% $36.25 21.3% $40.91 6.9%

800 0 n/a $5.89 19.9% $8.65 22.4% $9.34 9.1%

500 0 Summer $4.84 20.5% $6.40 21.9% $6.81 10.1%

250 0 Summer $3.97 21.4% $4.75 22.2% $4.96 12.3%

100 0 Summer $3.44 22.2% $3.74 22.5% $3.82 15.8%

R id ti l S b b S lResidential Suburban Seasonal800 0 Summer $8.42 17.0% $11.16 19.0% $11.91 9.8%

1,000 0 Summer $9.40 16.8% $12.84 19.1% $13.78 9.3%

1,500 0 Summer $11.85 16.5% $16.99 19.2% $18.39 8.7%

2,000 0 Summer $14.30 16.3% $21.16 19.2% $23.02 8.3%

5,000 0 Summer $29.00 15.9% $46.16 19.3% $50.82 7.7%

800 0 n/a $8.42 17.0% $11.42 19.5% $12.11 9.9%

500 0 Summer $6.95 17.3% $8.66 18.9% $9.07 10.8%

250 0 Summer $5.73 17.8% $6.59 18.8% $6.80 12.6%

100 0 Summer $4.99 18.2% $5.32 18.6% $5.40 14.9%General Service Less Than 50 1,000 0 Non‐res. $5.89 19.5% $9.02 22.4% $9.96 8.3%

2,000 0 Non‐res. $9.19 18.5% $15.42 22.1% $17.28 7.4%

35,000 0 Non‐res. $118.09 17.1% $227.28 21.8% $259.90 6.4%

25,000 0 Non‐res. $85.09 17.2% $163.07 21.8% $186.36 6.4%

75,000 0 Non‐res. $250.09 17.1% $484.05 21.8% $553.92 6.4%

25,000 0 n/a $85.09 17.2% $171.09 22.8% $192.69 7.0%General Service 50 to 4,999 kW 435,000 1,480 n/a ($368.79) (4.5%) $1,588.33 11.6% $1,964.08 4.0%

100,000 500 n/a ($65.77) (2.4%) $580.36 12.5% $666.74 5.3%

40,000 100 n/a $57.91 10.1% $193.55 20.5% $228.10 5.5%Sentinel Lighting 180 1 Non‐res. $3.26 >100% $4.20 82.9% $4.35 23.2%Street Lighting 180 1 Non‐res. $0.18 12.9% $1.23 29.0% $1.38 7.7%Note: RPP Rate Class of "n/a" indicates Non-RPP customers subject to the Global Adjustment Rate Rider




The Application indicates In accordance with the Z-factor guidelines contained within Chapter 3 of the Board’s Filing Requirements for Transmission and Distribution Applications (dated July 22, 2009), Veridian provides notice to the Board as part of this application, that it will record its 2009 PCB testing cost amounts in account 1572, Extraordinary Event Costs, and will seek recovery of these amounts at the time of a future rate application.

Request

Why is the PCB Extraordinary Cost deferral account required rather than simply tracking PCB remediation costs and including ¼ of the prior years expenses in rates or alternatively using a variance account to record the difference in rates and actual cost. Please explain

Response:

Veridian would be amenable to these suggestions, subject to Board approval.



49. Ref: Exhibit 9 / Tab 2 / Schedule 1Exhibit 9 / Tab 4 / Schedule 4 / Attachment 1

The application indicates:• a $6.6 M increase in rate base representing the net book value of Smart Meter

capital assets as of December 31, 2008

• a rate rider of $0.54 per month for all metered customers to recover the undercollection of incremental revenue requirement associated with Smart Metercapital investments and operating expenses to December 31, 2008. The rider to be effective for a period of one year, from May 1, 2010 to April 30, 2011.

Request

Reconcile the balances to be disposed of with the balance of Smart Meter Related Fixed Assets Net Book Value of: $6,644,822 used for calculation of the 2010 Smart Meter Rate Adder.

Response:

Please see the response to Board Staff Interrogatory #55.




Preamble: The Application states: Meter installation in Gravenhurst will be completed in 2010 (5,359 residential, 710 GS < 50kW). In addition, approximately 4,777 GS < 50kW in the remainder of Veridian’s service territory will be left to complete in 2010.

Request

(a) Provide Support/details of the 2009-2011 Residential Class SM Unit costs (procurement and installation)

(b) Provide Support/details of the 2009-2011 Residential Class SM AMI, communications and back office costs (procurement and installation)

(c) Provide Support/details of the 2009-2011 Commercial Class SM Unit costs (procurement and installation)

(d) Provide Support/details of the 2009-2011 Commercial Class SM Unit costs (procurement and installation)

Response

(a) Veridian understands this request to be to provide a calculation of the SM capital unit costs for the residential class for its forecast smart metering activities (procurement and installation) during 2009-2010.

Veridian is unable to provide a class specific SM unit meter cost as not all capital costs have been tracked separately by rate class.

In its pre-filed evidence, at Exhibit 9, Tab 4, Schedule 6, Attachment 1, Veridian provides an estimated SM unit cost of $260. In preparing the response for VECC interrogatory #14, some errors were found in Exhibit 9 Tab 4 Schedule 6 Attachment 1, smart meter funding adder calculation. An updated version of the calculation is attached.The corrected calculation of the “Per Meter Cost Split” is provided below.

The revised average (residential and GS < 50 kW) SM capital unit cost for the forecast SM installations in 2009 and 2010 is $137.63 as stated in the table below.



Per Meter Cost Split: Per Meter Installed Investment % of InvestSmart meter including installation 137.63$ 36,392 5,008,678$ 70%Computer Hardware Costs 3.09$ 107,261 331,934$ 5%Computer Software Costs -$ 107,261 -$ 0%Tools & Equipment -$ 107,261 -$ 0%Other Equipment -$ 107,261 -$ 0%Smart meter incremental operating expenses 16.66$ 107,261 1,786,556$ 25%

Total Smart Meter Costs per meter 157.38$ 7,127,168$ 100%

Note on per meter cost calculations:1) Smart meter including installation - 2009 & 2010 estimated costs for total of 2009 & 2010 forecast installs2) All other costs - calculated as 2009 & 2010 estimated costs for total of all units installed as they support all meters not just the forecast 2009 & 2010 meters installed

(b) The SM AMI, communications and back office costs(listed in the table above as Computer Hardware Costs and Computer Software costs) in the preceding table contain single costs that support both classes, therefore we are unable to provide a breakdown by class. The forecast investment in these systems will support all smart meters already installed as well as those forecast to be installed in 2009 and 2010. The per unit cost is $3.09.

(c) See response to a) above.

(d) This appears to be a duplicate of c) above.



51. Ref: Exhibit 9 / Tab 4 / Schedule 6 / Attachment 2 / Appendix 2-S

Request

(a) Provide a schedule that gives a breakdown of the AMCD Capital Costs shown in lines 1.1.1-1.5.6 between the Residential and GS<50kw and other classes.

(b) Provide a breakdown of the O&M costs shown at lines 2.1.1-2.5 between the Residential and GS<50kw and other classes.

Response:

(a) The requested schedule has been provided as Attachment 1. Some capital costs such as computer hardware and software are for investments that pertain to both the Residential and GS < 50 kW classes and have not been tracked separately by class.

(b) Generally, operating costs are common costs that are not class specific. These costs have not been tracked separately by class, therefore a breakdown of the O&M costs shown at lines 2.1.1-2.5 between the Residential and GS<50kw and other classes is not available.

Veridian_VECC IRR_51 ‐ Attachment 1

Capital Costs

2009 Residential 2009 GS<50 Total 2009 Forecast 2010 Residential 2010 GS<50 Total 2010 Forecast Grand Total

1.1.1 Smart Meter 1,741,576$ 220,000$ 1,961,576$ 713,474$ 1,097,400$ 1,810,874$ 3,772,450$ may include new meters and modules, etc.

1.1.2 Installation Cost 240,821$ 41,250$ 282,071$ 275,900$ 205,763$ 481,663$ 763,734$ may include socket kits plus shipping, labour, benefits, vehicle, etc.

1.1.3a Workforce Automation Hardware ‐$ ‐$ ‐$ may include fieldworker handhelds, barcode hardware, etc.

1.1.3b Workforce Automation Software ‐$ ‐$ ‐$ may include fieldworker handhelds, barcode hardware, etc.

Total Advanced Metering Communication Device (AMCD) 1,982,397$ 261,250.00$ 2,243,647$ 989,375$ 1,303,163$ 2,292,537$ 4,536,184$

1.2 ADVANCED METERING REGIONAL COLLECTOR (AMRC) (includes LAN)

1.2.1 Collectors 227,800$ 207,195$ 434,995$

1.2.2 Repeaters ‐$ 2,280$ 2,280$

1.2.3 Installation 6,700$ 28,518$ 35,218$ may include upgrades to collectors for AMCC integration

Total Advanced Metering Regional Collector (AMRC) (includes LAN) 234,500$ 237,993$ 472,493$

1.3 ADVANCED METERING CONTROL COMPUTER (AMCC)

1.3.1 Computer Hardware 150,058$ 41,147$ 191,205$

1.3.2 Computer Software ‐$ ‐$ ‐$

1.3.3 Computer Software Licence & Installation (includes hardware & software) ‐$ ‐$ ‐$ may include installation and licensing fees, capitalized labour for installation

Total Advanced Metering Control Computer (AMCC) 150,058$ 41,147$ 191,205$

1.4 WIDE AREA NETWORK (WAN)1.4.1 Hardware (modems) ‐$ ‐$ ‐$

1.4.2 Configuration license fees ‐$ ‐$ ‐$ May include project management, configuration, testing and verification

Total Wide Area Network (WAN) ‐$ ‐$ ‐$

1.5 OTHER AMI CAPITAL COSTS RELATED TO MINIMUM FUNCTIONALITY1.5.1 Customer equipment (including repair of damaged equipment) ‐$ ‐$ ‐$

1.5.2 AMI Interface to CIS ‐$ ‐$ ‐$

1.5.3 Professional Fees ‐$ ‐$ ‐$

1.5.4 Integration ‐$ ‐$ ‐$

1.5.5 Program Management ‐$ ‐$ ‐$

1.5.6 Other AMI Capital 140,729$ ‐$ 140,729$

Total Other AMI Capital Costs Related To Minimum Functionality 140,729$ ‐$ 140,729$

Total Capital Costs 2,768,934$ 2,571,678$ 5,340,612$




Request

(a) Based on the rate class split in capital and operating costs provided in the response to VECC IR#2 parts a, and b, provide a schedule that shows the amount to be recovered (including carrying costs) and the May 2010 onward SM Adder by rate class and compare this to the aggregate $1.14 per month per metered customer.

(b) Provide extension of the Table in appendix 2-S into 2011 and if required 2012.

Response:

(a) Veridian is unable to resolve the reference given in the interrogatory. VECC IR#2 parts a and b reference Exhibit 1, Tab 2, Schedule 1, page 16 and pertain to the proposed apportionment of revenue requirement between VCI_Main and VCI_Gravenhurst, rather than any ‘rate class split’ information. As Veridian cannot resolve the reference of ‘rate class split’, it cannot provide the requested schedule.

(b) Veridian forecasts completion of its smart metering activities in 2010 so there would be no forecast costs in 2011 or 2012.




Request

(a) Provide a cash flow projection showing SM rate adder revenue and SM expenditures by Month for each class for the 2009, 2010 and 2011 rate years.

(b) Is Veridian recording its Smart Meter Costs by class in the smart meter variance accounts 1555 and 1556? If not why not.

Response:

(a) A cash flow projection as requested is provided as Attachment 1.

(b) Veridian is not recording Smart Meter cost by class in the smart meter variance accounts 1555 and 1556. Some costs are common or related to all classes and cannot be directly allocated to specific rate classes. Veridian is not aware of any Board issued accounting guidelines or directions requiring separate tracking of costs by rate class.

Veridian_VECC IRR_53 ‐ Attachment 1

2009 Smart Meter Cashflow Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2009 TotalSmart Meter Rate Adder RevenueResidential 68,266 81,922 73,750 66,091 83,644 72,883 70,653 80,814 75,414 63,526 86,066 74,821 897,851 GS<50 5,210 6,780 6,852 4,633 7,088 6,361 5,668 6,956 6,137 5,468 7,205 6,214 74,572 GS>50 788 714 841 693 797 779 820 742 756 762 742 767 9,201 Intermediate 0 3 1 2 1 2 1 2 2 1 2 1 18 Large Use 4 4 3 4 4 4 4 4 4 4 3 4 44 Total Adder Revenue 74,268 89,422 81,448 71,422 91,533 80,028 77,146 88,517 82,314 69,762 94,018 81,807 981,686

Smart Meter Capital Costs 49,759 411,250 261,789 364,475 485,503 423,803 406,616 185,809 387,017 380,753 198,384 85,022 3,640,180 Smart Meter Operating Costs 21,946 35,714 136,148 83,342 51,387 10,917 202,245 34,530 142,347 64,207 79,884 34,236 896,903

Net Cashflow 2,564 (357,543) (316,489) (376,395) (445,357) (354,692) (531,715) (131,822) (447,050) (375,198) (184,250) (37,451) (3,555,397)

2010 Smart Meter Cashflow Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2010 TotalSmart Meter Rate Adder RevenueResidential 74,242 74,291 74,341 74,391 101,974 102,043 102,112 102,181 102,250 102,320 102,390 102,468 1,115,003 GS<50 6,160 6,163 6,167 6,171 8,458 8,463 8,468 8,473 8,478 8,483 8,488 8,497 92,469 GS>50 794 758 758 758 1,038 1,038 1,040 1,040 1,040 1,040 1,040 1,040 11,383 Intermediate 1 1 1 1 2 2 2 2 2 2 2 2 22 Large Use 4 4 4 4 5 5 5 5 5 5 5 5 55 Total Smart Meter Rate Adder Revenue 81,201 81,218 81,271 81,324 111,477 111,551 111,627 111,701 111,775 111,850 111,925 112,012 1,218,932

Smart Meter Capital Costs 68,017 85,022 102,026 136,035 238,061 238,061 229,558 229,558 127,532 119,030 102,026 25,506 1,700,432 Smart Meter Operating Costs 90,995 72,605 72,605 72,605 72,605 72,605 72,605 72,605 72,605 72,605 72,605 72,605 889,653

Net Cashflow (77,811) (76,409) (93,360) (127,316) (199,189) (199,115) (190,537) (190,463) (88,363) (79,786) (62,706) 13,900 (1,371,154)