2010 01 22 BC Hydro IRES 2 to BCUC and INTV · ExhibitB13,pp.58,59;ExhibitB5BCOAPOIR1.34.3...

B-7

ylapierr

LGS RD

��

ERICA�M.�HAMILTON�COMMISSION�SECRETARY�

[email protected]�web�site:�http://www.bcuc.com�

��

SIXTH�FLOOR,�900�HOWE�STREET,�BOX�250�VANCOUVER,�B.C.��CANADA��V6Z�2N3�

TELEPHONE:��(604)��660�4700�BC�TOLL�FREE:��1�800�663�1385�

FACSIMILE:��(604)��660�1102�

Log�No.�31137�

BCH�LGS/GenCor/A�6_IR�No2�to�BCH�

VIA�EMAIL�[email protected]� December�21,�2009��

� BC�HYDRO��LGS�RATE��EXHIBIT�A�6�

�Ms.�Joanna�Sofield�Chief�Regulatory�Officer�British�Columbia�Hydro�and�Power�Authority�333�Dunsmuir�Street�Vancouver,�BC��V6B�5R3��Dear�Ms.�Sofield:��

Re:��British�Columbia�Hydro�and�Power�Authority�Project�No.�3698573/Order�G�125�09�

��Large�General�Service�Rate�Application��Pursuant�to�Appendix�A�of�Commission�Order�G�156�09,�enclosed�please�find�Commission�Information�Request�No.�2.��In�accordance�with�the�Regulatory�Timetable,�please�respond�by�Friday,�January�22,�2010.��Please�file�your�response�in�accordance�with�the�British�Columbia�Utilities�Commission�Document�Filing�Protocol.�� Yours�truly,�� Original�signed�by:�� Erica�M.�Hamilton�EC/ac�Enclosure�cc:� Registered�Intervenors�� (Via�Email:��BCH�LGSR�RI)��

�REQUESTOR�NAME:�British�Columbia�Utilities�Commission�INFORMATION�REQUEST�ROUND�NO:�2�TO:�BRITISH�COLUMBIA�HYDRO�&�POWER�AUTHORITY�DATE:�December�21,�2009�PROJECT�NO:�3698573�APPLICATION�NAME:�Large�General�Service�(“LGS”)�Rate�Application�_____________________________________________________________________________________�

1.0 Reference:� Estimates�of�Conservation�Exhibit�B�1�3,�pp.�5�8,�5�9;�Exhibit�B�5�BCOAPO�IR�1.34.3�

The�estimated�conservation�in�GWh�as�presented�in�the�December�7,�2009�ERRATA�are:�

� F2011� F2012� F2013� F2014� F2015� F2016�

MGS�(GWh)� 6� 44� 81� 132� 196� 271�

%�of�MGS�Sales�� 4.8� �

LGS�(GWh)� 131� 474� 853� 1083� 1296� �

%�of�LGS�Sales�� 12.7� �

�

1.1 Please�confirm�the�data�in�the�table�above�and�provide�information�to�the�blank�cells.��Please�state�explicitly�whether�the�%�of�sales�estimates�are�based�on�forecasted�sales�before�DSM�with�rate�impact�or�forecasted�sales�before�DSM�without�rate�impact.�

1.2 Please�replicate�the�table�above�based�on�the�following�variations:�

1.2.1 The�initial�HBLs�based�on�(a)�2007,�2008�and�2009�3�year�monthly�rolling�average�with�the�remaining�years�calculated�as�described�in�Section�1.7.2.1�in�the�Application,�and�(b)�one�year�2009�monthly�rolling�rate�going�forward;�holding�all�other�variables�constant.�

1.2.2 Segmentation�of�the�ELGS�at:�(a)�500�kW,�(b)�1,000�kW,�and�(c)�100�kW;�holding�all�other�variables�constant.�

1.2.3 The�Price�Limit�Band�is�based�on�up�to:�(a)�10%�of�baseline,�(b)�15%�of�baseline,�and�(c)�30%�of�baseline;�holding�all�other�variables�constant.�

1.2.4 The�flattening�of�rate�structure�for�MGS:�(a)�over�a�five�year�period�and�(b)�over�a�four�year�period;�holding�all�other�variables�constant.��Please�state�explicitly�the�threshold�assumptions.�

1.3 Please�provide�a�comparison�of�the�respective�bill�impacts�as�a�result�of�the�varied�assumptions�in�the�above�IRs.�

�

BC�Hydro�Large�General�Service�Rate�Application� 1� Commission�Information�Request�No.�2�


2.0 Reference:� Forecast�Energy�Exhibit�B�5,�BCUC�IR�1.12.2;�BCUC�IR�1.1.3.1�pp.�3,�4�Conservation�as�a�Percentage�of�Energy�

The�response�to�IR�1.12.2�provides�the�forecast�energy�in�GWh�for�the�years�F2011�to�F2015�for�MGS�and�LGS�respectively.�

2.1 Please�reconcile�the�total�MGS�and�LGS�forecast�energy�sales�in�IR�1.12.2�with�the�ELGS�forecast�sales�for�the�same�period�presented�in�Response�to�IR�1.1.3.1�pages�3�and�4.�

3.0 Reference:� Load�Forecast�Exhibit�B�5.�BCUC�IR�1.1.2�and�IR�1.1.3.1�

BCUC�IR�1.1.2�asked�for�the�source�document�of�the�load�forecasts�and�Tables�A4.1�to�A4.10.��The�Response�explains�that�the�August�2009�Load�Forecast�is�a�short�term�update�of�the�energy�forecasts�only,�and�that�high�and�low�scenarios�were�not�developed.�

3.1 Is�there�a�document,�other�than�the�output�tables,�that�constitutes�the�August�2009�Load�Forecast�Update?��If�so,�please�provide�the�document�that�constitutes�the�August�2009�load�forecast�update.��If�there�is�no�document�at�BC�Hydro�that�records�the�changes�in�energy�forecasts,�please�provide�detailed�explanation�to�the�August�Short�Term�Update�from�the�2008�LTAP�Evidentiary�Update.�

3.2 Please�explain�the�basis�of�percentage�used�(28.4%:71.6%)�in�the�splitting�of�the�ELGS�class�to�MGS�and�LGS�and�why�it�is�different�from�the�information�contained�in�the�‘Active�Account�Summary’�in�Table�B�1�(Exhibit�B�1,�Appendix�B).�

3.2.1 Will�the�MGS�and�LGS�split�remain�constant�over�the�years�for�modeling�purposes?��Please�explain�the�basis�of�assumption.�

3.3 The�Response�to�BCUC�IR�1.1.2�refers�to�the�data�in�Appendix�Q�as�the�data�used�in�modeling.��Please�repeat�Table�Q�1�(i.e.,�after�DSM�and�after�rate�impacts),�by�rate�class�(summing�to�the�total�integrated�system�load)�with�general�service�disaggregated�to�small,�medium�and�large,�for�each�year�from�2009�to�2015.�

3.3.1 Since�an�annual�adjustment�to�the�Part�1�energy�rate�is�proposed�in�the�Application,�please�comment�if�the�Short�Term�Update�to�the�Annual�Load�Forecast�will�be�done�regularly�for�the�specific�purpose�of�the�setting�of�LGS�Part�1�rate.�

4.0 Reference:� Two�Part�Rate�Structure�and�Price�Limit�Bands�Exhibit�B�5,�BCSEA�1.1.1;�Exhibit�B�1�p.�3�22�Scenario�3�and�Scenario�9,�pp.�6�and�12�of�18�

Scenarios�3�and�9�are�two�substantially�similar�scenarios:�(a)�consumption�at�133%�above�HBL;�and�(b)�outside�Price�Limit�Band.�

4.1 The�energy�charge�calculated�for�Scenario�3�results�in�the�4,000�kWh�outside�PLB�being�charged�Part�2�Tier�2�energy�rate�at�4.45�¢/kWh.��The�energy�charge�calculated�for�Scenario�9�results�in�the�1,000�kWh�outside�PBL�being�charged�Part�2�Tier�1�rate�at�9.26�¢/kWh.��Please�explain�the�difference�in�their�treatment�and�please�explain�the�price�signals�created�by�this�different�treatment.�


5.0 Reference:� Heritage�Contract�Exhibit�B�5,�BCUC�IR�1.2.2;�Exhibit�B�1,�p.�4�11�Treatment�of�New�Customers�

The�preamble�to�IR�1.2.2�is�“Please�contrast�this�treatment�for�new�customers�with�that�of�(1)�MGS�and�SGS�new�customers;�(2)�new�residential�customers�and,�(3)�new�TSR�(Rate�Schedule�1823)�customers.�Please�explain�in�each�case�why�the�differing�treatments�are�appropriate.”�

5.1 The�response�to�IR�1.2.1�mentioned�that�the�BC�Hydro�proposed�exposure�to�marginal�cost�was�prompted�by�customer�concerns.��Is�this�the�only�reason�for�creating�a�different�treatment�for�new�customers?��If�not,�please�modify�the�answer�to�explain�fully�why�in�each�case�different�treatments�are�appropriate.�

5.2 The�Direct�Testimony�of�Dr.�Orans�explains�that�his�recommendation�of�LRMC�based�rate�for�10�per�cent�reflects�the�fact�that�existing�accounts�will�have�between�0�and�20�per�cent�of�their�total�usage�exposed�to�the�LRMC�based�rate.��Is�10�per�cent�an�average�of�major�site�types?��Is�there�wide�variation�among�site�types?�

6.0 Reference:� Part�2�Energy�Rate�Exhibit�B�5,�BCUC�IR�1.4.2;�JIESC�IR�1.5.3;�BCOAPO�1.37.4�Long�Run�Marginal�Cost�

In�this�Application,�the�estimated�annual�conservation�for�F2015�is�1,492�GWh�as�a�result�of�ELGS�rate�re�structuring.��The�estimated�annual�conservation�for�F2015�in�the�2008�LTAP�proceeding�was�350�GWh.�

6.1 Was�the�12¢/kWh�also�used�in�the�ELGS�conservation�analysis�in�the�2008�LTAP?��If�not,�how�much�of�the�differential�in�estimated�conservation�can�be�attributed�to�the�LRMC�assumed�in�the�model.�

7.0 Reference:� Default�and�Mandatory�Rate�Exhibit�B�5,�BCUC�IR�1.6.2.1;�BCUC�IR�1.6.3;�BCUC�IR�1.25.2;�BCOAPO�IR�1.25.1;�CEC�IR�1.40.3�Control�Group�

7.1 In�BC�Hydro’s�response�to�BCUC�IR�1.6.3�discussing�rate�options,�it�states�that�“The�control�group�participants�typically�are�selected�from�a�group�of�volunteers�for�the�rate�option,�but�are�kept�on�the�default�rate�for�a�period�of�time�before�being�allowed�to�take�service�on�the�option”.��Please�comment�if�this�statement�also�describes�ratepayers�currently�on�Rate�Schedules�1151,�1161�(Exempt�Residential�Service).�

7.2 Please�compare�and�contrast�the�Exempt�Residential�Service�control�group�as�approved�by�Commission�Order�G�150�08�with�the�proposed�control�group�in�this�Application�e.g.,�bill�guarantee,�incentive,�sampling,�mandatory�nature,�etc.�

7.3 In�BC�Hydro’s�response�to�BCUC�IR�1.6.2.1,�it�states�that�the�Commission�is�the�sole�judge�as�to�whether�a�rate�is�unduly�discriminatory.��Due�to�the�absence�of�evidence�from�other�utilities�(Response�to�BCUC�IR�1.25.2),�can�BC�Hydro�present�evidence�to�support�that�the�creation�of�the�mandatory�control�group�mandatory�is�not�discriminatory�other�than�the�evidence�that�the�control�group�is�important�for�research�purposes?�


7.4 In�Response�to�BCOAPO�IR�1.25.1,�BC�Hydro�states�that�it�intends�to�create�control�groups�that�would�reflect�the�characteristics�of�each�class.��Please�provide�more�details,�for�example,�will�it�be�random�sampling,�if�so,�how�does�random�sampling�retain�the�characteristics�of�each�class?��If�not,�how�does�one�avoid�bias?�

7.5 In�Response�to�CEC�IR�1.40.2,�BC�Hydro�states�that�it�expects�the�sample�sizes�of�200�for�treatment�and�control�groups�will�provide�acceptable�margins�of�error�for�the�analysis.��Please�provide�the�confidence�levels�for�both�the�projected�18,000�MGS�accounts�and�the�projected�5,000�LGS�accounts.�

8.0 Reference:� Rate�Structure�Exhibit�B�5,�BCUC�IR�1.10.1�Part�1�LGS�Rate�

The�response�states�that�flattening�the�Part�1�rates�would�create�additional�bill�impacts�for�LGS�accounts�without�significantly�improving�the�price�signal�or�customer�understanding�of�the�price�signal,�and�with�minimal�conservation�impact.��

8.1 What�are�the�merits�of�maintaining�the�tier�1�and�tier�2�ratio�at�2.0783?��Would�resetting�the�ratio�(i.e.�moving�towards�a�flat�rate)�over�the�years�affect�conservation?�

8.2 Please�provide�empirical�evidence�that�flattening�Part�1�rates�would�(a)�create�additional�bill�impacts�for�LGS�accounts,�and�(b)�has�minimal�conservation�impact.�

8.3 The�response�refers�to�Figure�3�1�which�illustrates�that�the�LGS�customers�see�a�declining�average�electricity�rate.��Please�confirm�that�the�average�electricity�rate�shown�in�Figure�3�1�is�based�on�total�monthly�bill�of�energy,�demand�and�basic�charge.�

8.3.1 If�confirmed,�will�BC�Hydro�be�able�to�use�the�same�justification�if�costs�are�considered�only�on�a�rate�per�kWh�basis?�

8.4 Why�would�flattening�the�Part�1�rates�not�result�in�improving�price�signals�and�having�customers�better�understand�the�price�signals?�

9.0 Reference:� DSM�Expenditures�Exhibit�B�5,�BCUC�IR�1.11.2;�Exhibit�B�1�3,�p.�2�7;�Exhibit�B�5,�p.�3�11�Implementation�Costs�

9.1 Please�compare�the�implementation�costs�to�launch�the�MGS�and�LGS�through�F2013�at�$4.6�million�with�the�costs�associated�with�the�implementation�and�administration�of�the�TSR�and�the�RIB�rate.�

10.0 Reference:� Bill�Impacts�Exhibit�B�5,�BCUC�IR�1.17.3;�BCUC�IR�17.5;�CEC�1.20.4;�CEC�IR�1.25.4�

In�the�Response�to�BCUC�IR�1.17.3,�BC�Hydro�describes�the�10%�bill�impact�threshold�and�discusses�the�acceptability�of�bill�impact�based�on�a�consideration�of�various�factors,�including,�amongst�others,�cumulative�bill�impacts�and�the�absolute�dollar�value�of�a�bill�impact.��BC�Hydro’s�response�has�not�addressed�whether�there�is�a�limit�on�cumulative�impact�which�was�the�question�in�the�IR.�

10.1 Please�provide�a�table�similar�to�response�to�IR�CEC�1.25.4�for�LGS�accounts.�


10.2 For�the��150kW�accounts,�please�list:�

10.2.1 The�top�25�accounts�impacted�from�both�the�negative�and�positive�impact�range�(in�percentage�terms�for�F2011)�and�provide�their�respective�bill�impacts�in�absolute�dollar�values.�

10.2.2 The�top�25�accounts�impacted�in�dollar�values�from�both�the�negative�and�positive�range�for�F2011�and�provide�their�respective�bill�impacts�in�percentage�terms.�

10.3 Please�provide�the�cumulative�impact�from�F2011�to�F2015�for�the�impacted�LGS�accounts�in�the�previous�two�IRs.�

10.4 For�the�<�150�kW�accounts,�please�list:�

10.4.1 The�top�25�accounts�impacted�from�both�the�negative�and�positive�impact�range�(in�percentage�terms�for�F2011)�and�provide�their�respective�bill�impacts�in�absolute�dollar�values.�

10.4.2 The�top�25�accounts�impacted�in�dollar�values�from�both�the�negative�and�positive�range�for�F2011�and�provide�their�respective�bill�impacts�in�percentage�terms.�

10.5 Please�provide�the�cumulative�impact�from�F2011�to�F2016�for�the�impacted�MGS�accounts�in�the�previous�two�IRs.�

10.6 Please�provide�the�reference�in�the�Application�regarding�dollar�impact�analysis.�

11.0 Reference:� Average�Electricity�Rate�Exhibit�B�5,�BCUC�IR�1.21.1�

11.1 Please�recalculate�Figure�3�4�at�load�factors�ranging�from�10%�to�75%�in�5%�increments�and�use�kWh�as�the�x�axis�for�each�of�the�following:�

11.1.1 Customers�using�35�kW�






12.0 Reference:� Two�part�Rate�Threshold�Exhibit�B�5,�BCUC�IR�1.21.2�

12.1 Please�repeat�the�table�in�Response�to�BCUC�IR�1.21.2�at�a�threshold�of�(a)�500�kW�and�(b)�1000�kW.�


13.0 Reference:� Billing�Baseline�Loads�Exhibit�B�5,�BCUC�IR�1.23.1.1�

13.1 Please�comment�if�the�methodology�for�determining�BBLs�in�other�billing�processes�(e.g.,�Step�1�block�for�RIB�rate)�has�encounter�any�significant�difficulties�in�customer�understanding�and�acceptance.��If�so,�please�describe�the�difficulties�and�how�they�are�resolved.�

14.0 Reference:� HBL�Exhibit�B�5,�BCUC�IR�1.22.1;�BC�Ferries�IR�1.3.1�Three�Year�Rolling�Averages�

14.1 Please�confirm�if�F2010�YTD�(August�2009)�means�that�it�has�six�months�of�data.��If�not,�please�provide�the�number�of�months.�

14.1.1 Since�the�data�for�F2010�for�the�table�‘Average�ELGS�Monthly�kWh�per�Account’�is�monthly�average,�does�it�mean�that�the�full�year�F2010�figure�could�be�higher�or�lower�that�50,416?�

14.1.2 Is�the�data�for�F2010�for�the�table�‘Average�ELGS�Annual�kWh�per�Account’�on�an�annualized�basis?��If�not,�please�provide�the�annualized�figure.�

14.2 BC�Hydro�response�to�BC�Ferries�IR�1.3.1�states�that�“establishing�initial�baselines�using�the�average�of�calendar�2005,�2006�and�2007�results�in�54�percent�of�accounts�having�a�higher�initial�HBL�than�using�F2009�to�set�initial�baselines”.�

14.2.1 Are�only�a�handful�of�accounts�responsible�for�the�9.0%�decline�in�F2008�from�the�F2005�F2007�three�year�average?�

14.2.2 The�frequency�distribution�of�energy�sales�for�F2009�are�shown�in�the�Response�to�BCUC�IR�1.12.1,�can�BC�Hydro�provide�more�details�as�to�which�group�of�accounts�compose�of�the�biggest�decline�in�average�monthly�sales�indicated�in�the�Response�to�BC�Ferries�IR�1.3.1�?�

15.0 Reference:� 2008�FACOS�Exhibit�B�5�BCUC�IR�1.38.1;�BCOAPO�IR�1.11.1�Segmentation�

15.1 Please�provide�the�Fully�Allocated�Cost�of�Service�(FACOS)�Study�that�Dr.�Orans�relied�on�in�Appendix�J�to�explore�segmentation.�

16.0 Reference:� LGS�Bill�Volatility�Exhibit�B�5,�BCUC�IR�1.42.3�Anomalies�

16.1 Please�provide�details�as�to�the�percentage�of�customers�who�will�receive�anomaly�adjustments�to�baselines.�

17.0 Reference:� Models�Methodologies�and�Compliance�Filings�Exhibit�B�5,�BCUC�IR�1.48.2�

17.1 In�addition�to�the�spreadsheet�models�in�the�response�to�BCUC�IR�1.30.1�and�Sections�6.1�and�


6.2�in�Appendix�N�on�Compliance�Filing,�please�include�any�additional�information�that�would�bolster�BC�Hydro’s�case�and�would�be�helpful�for�the�Commission�Panel�to�demonstrate�what�are�being�approved�in�the�Order�as�a�result�of�this�Application?�

British Columbia Utilities CommissionInformation Request No. 2.1.1 Dated: December 21, 2009British Columbia Hydro & Power Authority Response issued January 22, 2010

Page 1 of 1

British Columbia Hydro & Power Authority Large General Service Rate Application

Exhibit:B-7

1.0 Reference: Estimates of Conservation Exhibit B-1-3, pp. 5-8, 5-9; Exhibit B-5 BCOAPO IR 1.34.3

The estimated conservation in GWh as presented in the December 7, 2009 ERRATA are:

F2011 F2012 F2013 F2014 F2015 F2016

MGS (GWh) 6 44 81 132 196 271

% of MGS Sales 4.8

LGS (GWh) 131 474 853 1083 1296

% of LGS Sales 12.7

2.1.1 Please confirm the data in the table above and provide information to the blank cells. Please state explicitly whether the % of sales estimates are based on forecasted sales before DSM with rate impact or forecasted sales before DSM without rate impact.

RESPONSE:

The sales estimates shown in the table below, and in the response to BCUC IR 1.12.2, are based on a load forecast net of both “rate impact” and DSM. That is, they are net of an assumed demand response to revenue requirement rate changes, programs, codes and standards, and an assumed conservation rate structure.

The table below shows the percentages for all years that were modelled.

F2011 F2012 F2013 F2014 F2015 F2016

MGS (GWh) 6 44 81 132 196 271

% of MGS Sales 0.6 1.1 2.0 3.3 4.8 6.7

LGS (GWh) 131 474 853 1083 1296 Not Modelled

% of LGS Sales 5.1 4.7 8.5 10.8 12.7 Not Modelled


Page 1 of 2


Exhibit:B-7



F2011 F2012 F2013 F2014 F2015 F2016

MGS (GWh) 6 44 81 132 196 271

% of MGS Sales 4.8

LGS (GWh) 131 474 853 1083 1296

% of LGS Sales 12.7

2.1.2 Please replicate the table above based on the following variations:

RESPONSE:

BC Hydro received a number of questions from the BCUC and intervenors asking to modify the proposed MGS and LGS rate designs and display the results in varying formats. To respond to these queries, BC Hydro has created two comprehensive matrices for MGS and LGS proposals that not only look at the impact of varying design elements on conservation estimates, but also include prices, bill impacts, Part 1 rate adjustments, and bill volatility. The two matrices are attached to this IR response.

BC Hydro’s qualitative observations from its consideration of the different modifications to the proposed rate designs are as follows.

In response to BCUC IR 2.1.2.1 BC Hydro modelled the use of an initial three-year baseline based on the most recent consumption history, and an initial single year baseline also based on the most recent consumption history. Bill volatility distributions and conservation estimates for each of these scenarios, and BC Hydro’s initial baseline proposal, are all fairly similar.

Resegmenting the LGS and MGS classes to break at 100 kW, 120 kW, or 140 kW, which is analyzed in response to BCUC IR 2.1.2.2, results in very little change to the bill impact distribution for MGS customers or the bill volatility expected for LGS customers. Other things being equal, lower kW segment breakpoints lead to more expected conservation. Resegmenting the LGS and MGS classes to break at 500 kW or 1,000 kW creates more MGS customers with relatively large dollar bill impacts. This also decreases the expected amount of conservation in the LGS class and from the ELGS class overall.


Page 2 of 2


Exhibit:B-7

For the LGS class, wider Price Limit Bands result in more bill volatility, as shown in BC Hydro’s response to BCUC IR 2.1.2.3. There is a corresponding increase in expected conservation caused by a wider band, but a portion of the conservation is mitigated by the minimum energy charge feature of BC Hydro’s proposed LGS design.

Finally, as shown in BC Hydro’s Application in Table M-10 (MGS Design Alternatives), flattening the MGS rate structure is expected to produce a modest amount of conservation over time. Although an “immediately flat” design would increase expected conservation compared to BC Hydro’s proposal, it would also cause immediate bill impacts of more than 50 per cent for some customers. A shorter transition period than proposed by BC Hydro will result in higher bill impacts and higher amounts of expected conservation (please refer to Table M-3).

MG

S R

ate

Mat

rix

Year

Tier-1

Tier-2

Tier-3

Tier-1

Tier-2

MGS Net Conservation

CorrespondingLGS Scenario if applicable

LGS Net Conservation

Total Net Conservation

F11

18.0

7

-4.

40

8.

45

8.

53

4.

25

9.

78%

/ 10

.36%

/ 12

.41%

$62

/ $1,

686

/ $6,

101

12.6

3%0%

70.5

1%6

131

137

F12

18.7

4

-4.

57

8.

76

8.

68

4.

68

1.

87%

/ 3.

11%

/ 7.

44%

$14

/ $64

8 / $

4,02

97.

70%

0%70

.49%

4447

451

8F1

320

.01

-

4.88

9.36

9.02

5.45

3.82

% /

5.83

% /

12.5

6%$2

9 / $

1,23

6 / $

7,32

112

.80%

0%70

.49%

8185

393

4F1

421

.41

-

5.22

10.0

1

9.26

6.50

2.78

% /

5.61

% /

14.5

8%$2

3 / $

1,36

3 / $

9,52

415

.02%

0%70

.49%

132

1,08

31,

215

F15

22.6

1

-5.

51

10

.57

9.

27

7.

75

0.

11%

/ 3.

72%

/ 14

.36%

$5 /

$1,1

60 /

$10,

683

15.5

8%0%

70.4

9%19

61,

296

1,49

2F1

624

.11

-

5.87

11.2

7

9.29

9.29

0.28

% /

4.40

% /

15.5

5%$7

/ $1

,456

/ $1

3,23

416

.63%

0%70

.50%

271

3.11

% /

5.51

% /

12.8

2%$2

3 / $

1,25

8 / $

8,48

272

93,

836

4,29

5B

CU

C 2

.2.1

.2F1

118

.07

-

4.40

8.45

8.49

4.32

9.27

% /

10.2

% /

13.4

9%$5

9 / $

1,68

6 / $

6,60

713

.63%

1.8%

70.4

9%7

131

138

F12

18.7

4

-4.

57

8.

76

8.

55

4.

92

0.

73%

/ 2.

74%

/ 9.

67%

$7 /

$649

/ $5

,258

9.70

%2.

3%70

.49%

5847

453

2F1

320

.01

-

4.88

9.36

8.71

5.98

1.94

% /

5.20

% /

15.7

8%$1

7 / $

1,23

6 / $

9,41

715

.80%

2.6%

70.4

9%11

285

396

4F1

421

.41

-

5.22

10.0

1

8.82

7.28

1.24

% /

5.05

% /

16.4

3%$1

3 / $

1,36

3 / $

11,3

3216

.52%

0.3%

70.5

0%17

71,

083

1,26

0F1

522

.61

-

5.51

10.5

7

8.72

8.72

-1.1

% /

3.24

% /

15.0

4%-$

162

/ $1,

160

/ $12

,033

15.5

8%0.

0%70

.50%

251

1,29

61,

546

F16

24.1

1

-5.

87

11

.27

9.

29

9.

29

6.

63%

/ 6.

63%

/ 6.

77%

$48

/ $1,

456

/ $6,

245

7.63

%0.

0%70

.50%

271

3.12

% /

5.51

% /

12.8

6%-$

3 / $

1,25

8 / $

8,48

287

53,

836

4,44

0B

CU

C 2

.2.1

.2F1

118

.07

-

4.40

8.45

8.45

4.39

8.75

% /

10.0

4% /

14.5

7%$5

6 / $

1,68

6 / $

7,11

314

.63%

6.1%

70.4

9%8

131

139

F12

18.7

4

-4.

57

8.

76

8.

42

5.

14

-0

.28%

/ 2.

41%

/ 11

.6%

-$39

/ $6

48 /

$6,3

4211

.70%

6.4%

70.4

9%71

474

545

F13

20.0

1

-4.

88

9.

36

8.

47

6.

40

0.

62%

/ 4.

74%

/ 17

.77%

$8 /

$1,2

36 /

$10,

863

17.8

0%5.

8%70

.50%

136

853

989

F14

21.4

1

-5.

22

10

.01

8.

26

8.

26

-2

.48%

/ 3.

74%

/ 21

.41%

-$35

2 / $

1,36

3 / $

15,3

5221

.52%

6.2%

70.5

0%23

21,

083

1,31

5F1

522

.61

-

5.51

10.5

7

8.72

8.72

5.58

% /

5.58

% /

5.7%

$38

/ $1,

160

/ $4,

977

15.5

8%0.

0%70

.50%

251

1,29

61,

546

F16

24.1

1

-5.

87

11

.27

9.

29

9.

29

6.

63%

/ 6.

63%

/ 6.

77%

$48

/ $1,

456

/ $6,

245

7.63

%0.

0%70

.50%

271

3.14

% /

5.52

% /

12.9

7%-$

40 /

$1,2

58 /

$8,4

8296

93,

836

4,53

5B

CU

C 2

.1.2

.2F1

118

.07

-

4.40

8.45

8.54

4.28

9.97

% /

10.4

4% /

12.6

3%$6

3 / $

1,47

2 / $

4,89

512

.63%

0%70

.61%

414

815

3F1

218

.74

-

4.57

8.76

8.74

4.76

2.37

% /

3.3%

/ 7.

61%

$17

/ $56

6 / $

3,32

17.

70%

0%70

.61%

3153

756

9F1

320

.01

-

4.88

9.36

9.15

5.61

4.67

% /

6.15

% /

12.7

4%$3

5 / $

1,07

9 / $

5,98

712

.80%

0%70

.61%

5896

41,

022

F14

21.4

1

-5.

22

10

.01

9.

51

6.

80

3.

94%

/ 6.

05%

/ 14

.99%

$32

/ $1,

189

/ $7,

942

15.0

2%0%

70.6

2%96

1,22

41,

320

F15

22.6

1

-5.

51

10

.57

9.

64

8.

32

1.

35%

/ 4.

21%

/ 15

.51%

$14

/ $1,

013

/ $9,

451

15.5

8%0%

70.6

3%14

61,

465

1,61

0F1

624

.11

-

5.87

11.2

7

9.91

9.91

2.84

% /

5.35

% /

14.4

4%$2

5 / $

1,27

1 / $

10,1

6316

.63%

0%70

.64%

194

4.19

% /

5.92

% /

12.9

9%$3

1 / $

1,09

8 / $

6,96

053

04,

338

4,67

3F1

118

.07

-

4.40

8.45

8.54

4.26

9.91

% /

10.4

2% /

12.6

3%$6

3 / $

1,56

7 / $

5,87

812

.63%

0%70

.41%

514

114

6F1

218

.74

-

4.57

8.76

8.73

4.70

2.22

% /

3.25

% /

7.68

%$1

6 / $

603

/ $4,

027

7.70

%0%

70.3

9%36

511

547

F13

20.0

1

-4.

88

9.

36

9.

12

5.

48

4.

47%

/ 6.

08%

/ 12

.77%

$33

/ $1,

149

/ $7,

206

12.8

0%0%

70.3

9%66

916

982

F14

21.4

1

-5.

22

10

.01

9.

45

6.

54

3.

69%

/ 5.

96%

/ 14

.93%

$30

/ $1,

266

/ $9,

501

15.0

2%0%

70.3

9%10

81,

163

1,27

1F1

522

.61

-

5.51

10.5

7

9.54

7.89

0.94

% /

4.06

% /

15.5

4%$1

1 / $

1,07

8 / $

11,3

6715

.58%

0%70

.40%

163

1,39

21,

554

F16

24.1

1

-5.

87

11

.27

9.

63

9.

63

0.

97%

/ 4.

71%

/ 17

.25%

$12

/ $1,

353

/ $14

,578

16.6

3%0.

01%

70.4

0%23

13.

70%

/ 5.

75%

/ 13

.47%

$28

/ $1,

169

/ $8,

760

609

4,12

24,

500

F11

18.0

7

-4.

40

8.

45

8.

53

4.

26

9.

77%

/ 10

.36%

/ 12

.59%

$62

/ $1,

649

/ $5,

946

12.6

3%0%

70.4

5%6

135

140

F12

18.7

4

-4.

57

8.

76

8.

69

4.

70

1.

93%

/ 3.

14%

/ 7.

6%$1

5 / $

634

/ $3,

983

7.70

%0%

70.4

3%42

488

530

F13

20.0

1

-4.

88

9.

36

9.

03

5.

48

3.

98%

/ 5.

89%

/ 12

.71%

$30

/ $1,

209

/ $7,

167

12.8

0%0%

70.4

3%78

874

952

F14

21.4

1

-5.

22

10

.01

9.

30

6.

56

2.

92%

/ 5.

67%

/ 14

.94%

$24

/ $1,

333

/ $9,

494

15.0

2%0%

70.4

3%12

71,

111

1,23

8F1

522

.61

-

5.51

10.5

7

9.28

7.93

-0.1

6% /

3.64

% /

15.5

3%-$

25 /

$1,1

35 /

$11,

345

15.5

8%0%

70.4

3%19

31,

328

1,52

1F1

624

.11

-

5.87

11.2

7

9.39

9.39

1.26

% /

4.76

% /

14.6

7%$1

4 / $

1,42

4 / $

12,3

8116

.63%

0%70

.43%

259

3.28

% /

5.58

% /

13.0

1%$2

0 / $

1,23

1 / $

8,38

670

53,

936

4,38

2

Estim

ated

Con

serv

atio

n (G

Wh

unle

ss o

ther

wis

e no

ted)

Com

men

ts

LGS

0

% of accounts in excess of BC Hydro's Proposed bill impact

threshold

Bill Impact Thresholds

LGS

17

MGS 2

flatte

n ra

te s

truct

ure

for M

GS

ov

er a

four

-yea

r per

iod

flatte

n ra

te s

truct

ure

for M

GS

ov

er a

five

-yea

r per

iod

MGS 1 MGS 5

MG

S s

egm

enta

tion

of g

reat

er

than

or e

qual

to 3

5kW

to

belo

w 1

40kW

Min

/Avg

./Max

Bill

Impa

ctIn

clud

ing

CA

RC

Rel

ativ

e to

Pre

viou

s Ye

ar ($

)

Scenario #

IR R

efer

ence

.

Des

ign

Obj

ectiv

e an

d A

ssum

ptio

ns

Basic Charge(¢/day)

Dem

and

Rat

e ($

/kW

) E

nerg

y R

ate

(¢/k

Wh)

Min

/Avg

./Max

Bill

Impa

ct

Incl

udin

g C

AR

C R

elat

ive

to P

revi

ous

Year

(%)

% Accounts Pay Less

LGS

0

MGS 0

Bas

e C

ase

BC

H P

ropo

sal

LGS

16

LGS

15

LGS

0

MG

S s

egm

enta

tion

of g

reat

er

than

or e

qual

to 3

5kW

to

belo

w 1

20kW

MGS 4

MG

S s

egm

enta

tion

of g

reat

er

than

or e

qual

to 3

5kW

to

belo

w 1

00kW

MGS 3

Ave

rage

% a

nd $

; G

Wh

Sum

Ave

rage

% a

nd $

; G

Wh

Sum

Ave

rage

% a

nd $

; G

Wh

Sum

Ave

rage

% a

nd $

; G

Wh

Sum

Ave

rage

% a

nd $

; G

Wh

Sum

Ave

rage

% a

nd $

; G

Wh

Sum

��

��

� ��

MG

S R

ate

Mat

rix

Year

Tier-1

Tier-2

Tier-3

Tier-1

Tier-2


CorrespondingLGS Scenario if applicable



Estim

ated

Con

serv

atio

n (G

Wh

unle

ss o

ther

wis

e no

ted)

Com

men

ts

% of accounts in excess of BC Hydro's Proposed bill impact

threshold

Bill Impact Thresholds

Min

/Avg

./Max

Bill

Impa

ctIn

clud

ing

CA

RC

Rel

ativ

e to

Pre

viou

s Ye

ar ($

)

Scenario #

IR R

efer

ence

.

Des

ign

Obj

ectiv

e an

d A

ssum

ptio

ns Basic Charge

(¢/day)

Dem

and

Rat

e ($

/kW

) E

nerg

y R

ate

(¢/k

Wh)

Min

/Avg

./Max

Bill

Impa

ct

Incl

udin

g C

AR

C R

elat

ive

to P

revi

ous

Year

(%)

% Accounts Pay Less

BC

UC

2.1

.2.2

F11

18.0

7

-4.

40

8.

45

8.

45

4.

23

8.

82%

/ 9.

87%

/ 12

.61%

$57

/ $2,

482

/ $21

,979

12.6

3%0%

75.8

5%11

8091

F12

18.7

4

-4.

57

8.

76

8.

45

4.

60

0.

03%

/ 2.

15%

/ 7.

54%

$3 /

$955

/ $1

4,36

97.

70%

0%75

.77%

7828

936

7F1

320

.01

-

4.88

9.36

8.51

5.27

0.67

% /

4.19

% /

12.7

8%$9

/ $1

,820

/ $2

6,18

512

.80%

0%75

.76%

141

518

659

F14

21.4

1

-5.

22

10

.01

8.

33

6.

17

-2

.02%

/ 3.

16%

/ 14

.88%

-$28

8 / $

2,00

6 / $

34,3

7915

.02%

0%75

.75%

228

657

885

F15

22.6

1

-5.

51

10

.57

7.

67

7.

29

-7

.89%

/ -0

.18%

/ 15

.58%

-$1,

138

/ $1,

708

/ $41

,357

15.5

8%0%

75.7

5%34

278

41,

126

F16

24.1

1

-5.

87

11

.27

7.

94

7.

94

3.

53%

/ 5.

31%

/ 8.

47%

$25

/ $2,

143

/ $26

,088

16.6

3%0%

75.7

6%39

40.

52%

/ 4.

08%

/ 11

.98%

-$22

2 / $

1,85

2 / $

27,3

931,

194

2,32

83,

129

BC

UC

2.1

.2.2

F11

18.0

7

-4.

40

8.

45

8.

40

4.

23

8.

20%

/ 9.

51%

/ 12

.56%

$53

/ $2,

916

/ $41

,743

12.6

3%0%

78.2

8%14

5569

F12

18.7

4

-4.

57

8.

76

8.

28

4.

61

-1

.44%

/ 1.

33%

/ 7.

62%

-$20

4 / $

1,12

2 / $

27,9

867.

70%

0%78

.13%

9820

029

8F1

320

.01

-

4.88

9.36

8.13

5.29

-1.7

5% /

2.86

% /

12.7

8%-$

243

/ $2,

138

/ $50

,568

12.8

0%0%

78.0

8%17

835

853

7F1

421

.41

-

5.22

10.0

1

7.64

6.21

-5.9

9% /

1.05

% /

14.9

5%-$

838

/ $2,

357

/ $66

,420

15.0

2%0%

78.0

9%28

845

474

3F1

522

.61

-

5.51

10.5

7

7.07

7.07

-7.3

6% /

-0.3

% /

12.0

4%-$

974

/ $2,

007

/ $61

,384

15.5

8%0%

78.0

8%39

354

293

5F1

624

.11

-

5.87

11.2

7

7.54

7.54

6.62

% /

6.62

% /

6.8%

$40

/ $2,

517

/ $38

,682

16.6

3%0%

78.0

9%43

2-0

.29%

/ 3.

51%

/ 11

.13%

-$36

1 / $

2,17

6 / $

47,7

971,

404

1,61

02,

582

LGS

19

LGS

18

MG

S s

egm

enta

tion

of g

reat

er

than

or e

qual

to 3

5kW

to

belo

w 1

000k

W

MGS 7MGS 6

MG

S s

egm

enta

tion

of g

reat

er

than

or e

qual

to 3

5kW

to

belo

w 5

00kW

Ave

rage

% a

nd $

; G

Wh

Sum

Ave

rage

% a

nd $

; G

Wh

Sum

��

��

� ��

LGS

Rat

e M

atrix

Year

Tier-1

Tier-2

Tier-3

Tier-1

Tier-2

LRMC based Price

% Change

Dollar Change (millions)

Pric

eLi

mit

Ban

ds

Initi

al H

BL

Bas

isC

Y050

607?

Yes/

No

# of Bills Adjusted per

Year

Threshold


Cor

resp

ondi

ngM

GS

Scen

ario

if

appl

icab

le



F11

18.0

60

4.40

8.44

8.58

4.13

7.02

-0.0

6%(0

.3)

$

-40.

27%

/ 0.

00%

/ 8.

86%

131

6

13

7

F12

18.7

20

4.56

8.75

8.90

4.28

6.91

-0.0

5%(0

.2)

$

-38.

47%

/ -0

.01%

/ 8.

05%

474

44

51

8

F13

19.9

80

4.87

9.34

9.49

4.56

9.66

-0.2

2%(1

.1)

$

-50.

88%

/ -0

.18%

/ 16

.46%

853

81

93

4

F14

21.3

80

5.21

9.99

10.1

4

4.88

11.5

4

-0

.38%

(2.0

)$

-5

4.40

% /

-0.3

3% /

21.7

3%1,

083

132

1,21

5

F1

522

.56

05.

50

10

.55

10

.69

5.

14

13

.38

-0.5

9%(3

.4)

$

-58.

59%

/ -0

.62%

/ 26

.68%

1,29

6

19

6

1,

492

% A

vera

ge; $

Sum

-0.2

6%(7

.0)

$

-48.

52%

/ -0

.23%

/ 16

.36%

3,83

6

458

4,

295

BC

UC

2.1

.2.1

aF1

118

.06

04.

40

8.

44

8.

52

4.

10

7.

02

-0

.92%

(4.0

)$

-1

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% /

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8

128

F1

218

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04.

56

8.

75

8.

84

4.

25

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1

44

505

F1

319

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87

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34

9.

40

4.

52

9.

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13

2

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209

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60

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9

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Ave

rage

; $ S

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3,76

7

452

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219

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2.1

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118

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49

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801

81

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F14

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2.2.

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118

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40

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19

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02

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131

6

13

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8.75

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1

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515

F1

319

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87

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56

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60

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844

81

92

5

F14

21.3

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0.

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1,06

9

13

2

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201

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22.5

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5

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8

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253

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Ave

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; $ S

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40

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58

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133

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28

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91

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503

F1

319

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34

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48

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56

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81

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421

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99

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13

2

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180

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60

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5

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8

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rage

; $ S

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C

EC

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6

138

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218

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44

52

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1,08

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9

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218

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91

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44

52

2

F13

19.9

80

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89%

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856

81

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21.3

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10

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1,30

1

19

6

1,

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vera

ge; $

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3,85

6

458

4,

314

CE

C 2

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cF1

118

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40

8.

44

8.

59

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13

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02

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25%

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96%

132

6

13

8

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18.7

20

4.56

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8.91

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3$

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% /

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9

44

523

F1

319

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04.

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34

9.

49

4.

57

9.

66

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)$

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16.5

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7

81

938

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421

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99

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1,08

8

13

2

1,

220

F15

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60

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5

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0

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858

45

8

4,31

6

655

MG

S 0

Estim

ated

Con

serv

atio

n (G

Wh)

LGS 7LGS 6LGS 5LGS 4Scenario #

Min

/Avg

./Max

Vol

atili

ty

Impa

ct R

elat

ive

to C

urre

nt

Stru

ctur

e (%

)

Ene

rgy

Rat

e (c

ents

/kW

h)IR

Ref

eren

ce.

Des

ign

Obj

ectiv

e an

d A

ssum

ptio

ns

Basic Charge(¢/day)

Dem

and

Rat

e ($

/kW

) P

art-1

Rat

e A

dj

Ano

mal

y A

dj

80:1

20Y

es50

%

80:1

20

No

(Ave

rage

9/20

06 -

8/20

09)

LGS 3LGS 2LGS 0 LGS 1

6 an

omal

y ad

just

men

ts p

er

year

allo

wed

(50%

ano

mal

y th

resh

old)

4 an

omal

y ad

just

men

ts p

er

year

allo

wed

(50%

ano

mal

y th

resh

old)

Pro

pose

d D

esig

n (w

ith

appl

icat

ion

of a

nom

aly

rule

to

initi

al b

asel

ine

to m

atch

LG

S

6 to

14)

Max

of p

ropo

sed

or 2

007-

2009

initi

al b

asel

ine

2009

HB

L

Pro

pose

d D

esig

n (w

/ few

er

acco

unts

to m

atch

LG

S 1

to

3)

2007

-200

9 H

BL

Pro

pose

d D

esig

n

600 -- 813

50%

80:1

20N

o(9

/200

8 -

8/20

09)

-- 813

50%

80:1

20

No

(Lar

ger o

f av

erag

e of

9/

2006

- 8/

2009

or

CY

0506

07)

529 -- 813

50%

80:1

20Y

es77

5 -- 813

50%

80:1

20Y

es87

1 -- 894

50%

80:1

20Y

es12

68 --12

8850

%

80:1

20Y

es14

72 --14

8750

%

MG

S 0

MG

S 0

MG

S 0

MG

S 0

MG

S 0

MG

S 0

MG

S 0

Com

men

ts

This

sce

nario

shi

fts $

21 M

via

Par

t 1 ra

te

adju

stm

ents

ove

r 5 y

ears

to th

e m

ore

stab

le

acco

unts

, rel

ativ

e to

LG

S 4

.

This

sce

nario

is b

ased

on

an a

djus

ted

data

set a

s ex

plai

ned

furth

er in

BC

UC

IR

2.1.

2.1

and

shou

ld b

e th

e ba

sis

of

com

pario

ns fo

r sce

nario

s LG

S 1

to 3

.

This

sce

nario

incl

udes

app

licat

ion

of th

e an

omal

y ru

le fo

r the

initi

al H

BL

calc

ulat

ion

as e

xpla

ined

furth

er in

CE

C IR

2.3

.1 a

nd

shou

ld b

e th

e ba

sis

of c

ompa

rions

fro

scen

ario

s LG

S 6

to 1

4.

��

��

� ��

LGS

Rat

e M

atrix

Year

Tier-1

Tier-2

Tier-3

Tier-1

Tier-2

LRMC based Price

% Change


Pric

eLi

mit

Ban

ds

Initi

al H

BL

Bas

isC

Y050

607?

Yes/

No


Year

Threshold


Cor

resp

ondi

ngM

GS

Scen

ario

if

appl

icab

le



Estim

ated

Con

serv

atio

n (G

Wh)

Scenario #

Min

/Avg

./Max

Vol

atili

ty

Impa

ct R

elat

ive

to C

urre

nt

Stru

ctur

e (%

)

Ene

rgy

Rat

e (c

ents

/kW

h)IR

Ref

eren

ce.

Des

ign

Obj

ectiv

e an

d A

ssum

ptio

nsBasic Charge

(¢/day)

Dem

and

Rat

e ($

/kW

) P

art-1

Rat

e A

dj

Ano

mal

y A

dj

Com

men

ts

CE

C 2

.3.2

aF1

118

.06

04.

40

8.

44

8.

59

4.

13

7.

02

-0

.01%

(0.1

)$

-4

1.25

% /

0.00

% /

8.90

%13

1

6

137

F1

218

.72

04.

56

8.

75

8.

90

4.

28

6.

91

-0

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(0.0

)$

-4

0.31

% /

0.00

% /

8.09

%47

6

44

520

F1

319

.98

04.

87

9.

34

9.

49

4.

56

9.

66

-0

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(1.1

)$

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0.89

% /

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7% /

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7%85

4

81

934

F1

421

.38

05.

21

9.

99

10

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4.

88

11

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7%(2

.0)

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40%

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1,08

4

13

2

1,

216

F15

22.5

60

5.50

10.5

5

10.6

8

5.14

13.3

8

-0

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(3.5

)$

-5

8.50

% /

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1% /

26.6

7%1,

295

196

1,49

1

%

Ave

rage

; $ S

um; G

Wh

Sum

-0.2

4%(6

.6)

$

-49.

07%

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3,84

0

458

4,

298

CE

C 2

.3.2

bF1

118

.06

04.

40

8.

44

8.

59

4.

13

7.

02

-0

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(0.0

)$

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1.25

% /

0.00

% /

8.90

%13

1

6

137

F1

218

.72

04.

56

8.

75

8.

90

4.

28

6.

91

-0

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0.31

% /

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1% /

8.09

%47

6

44

520

F1

319

.98

04.

87

9.

34

9.

49

4.

56

9.

66

-0

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)$

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0.89

% /

-0.1

7% /

16.4

7%85

4

81

935

F1

421

.38

05.

21

9.

99

10

.14

4.

88

11

.54

-0.3

7%(2

.0)

$

-54.

40%

/ -0

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/ 21

.74%

1,08

4

13

2

1,

216

F15

22.5

60

5.50

10.5

5

10.6

8

5.14

13.3

8

-0

.61%

(3.5

)$

-5

8.50

% /

-0.6

3% /

26.6

7%1,

296

196

1,49

2

%

Ave

rage

; $ S

um; G

Wh

Sum

-0.2

4%(6

.6)

$

-49.

07%

/ -0

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/ 16

.37%

3,84

2

458

4,

300

CE

C 2

.3.2

cF1

118

.06

04.

40

8.

44

8.

59

4.

13

7.

02

0.

00%

(0.0

)$

-4

1.24

% /

0.00

% /

8.91

%13

1

6

137

F1

218

.72

04.

56

8.

75

8.

90

4.

28

6.

91

0.

00%

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)$

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0.30

% /

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8.09

%47

6

44

520

F1

319

.98

04.

87

9.

34

9.

49

4.

57

9.

66

-0

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0.89

% /

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16.4

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4

81

935

F1

421

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05.

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9.

99

10

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4.

88

11

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40%

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1,08

5

13

2

1,

217

F15

22.5

60

5.50

10.5

5

10.6

9

5.14

13.3

8

-0

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(3.3

)$

-5

8.48

% /

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3% /

26.6

8%1,

297

196

1,49

2

%

Ave

rage

; $ S

um; G

Wh

Sum

-0.2

3%(6

.2)

$

-49.

06%

/ -0

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/ 16

.38%

3,84

3

458

4,

302

CE

C 2

.3.2

dF1

118

.06

04.

40

8.

44

8.

59

4.

13

7.

02

0.

01%

0.0

$

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12%

/ 0.

00%

/ 8.

92%

132

6

13

8

F12

18.7

20

4.56

8.75

8.90

4.28

6.91

0.01

%0.

1$

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0.61

% /

-0.0

1% /

8.10

%47

7

44

520

F1

319

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421

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6

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vera

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6

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477

44

52

1

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80

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855

81

93

6

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44

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1

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138

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122

37

8

4,50

0

1128 --

1170

470 -- 526

MG

S 0

MG

S 0

LGS 12LGS 11 LGS 14LGS 13LGS 8

80:1

20Y

es

LGS 10LGS 9

40%

ano

mal

y th

resh

old

(2

anom

aly

adju

stm

ents

per

ye

ar a

llow

ed)

35%

ano

mal

y th

resh

old

(2

anom

aly

adju

stm

ents

per

ye

ar a

llow

ed)

30%

ano

mal

y th

resh

old

(2

anom

aly

adju

stm

ents

per

ye

ar a

llow

ed)

80:1

20Y

es

LGS 15

Seg

men

t at 1

00 k

W80

:120

Yes

1378 --

1451

50%

MG

S 3

LGS 16

Seg

men

t at 1

20 k

W80

:120

Yes

50%

60%

ano

mal

y th

resh

old

(2

anom

aly

adju

stm

ents

per

ye

ar a

llow

ed)

55%

ano

mal

y th

resh

old

(2

anom

aly

adju

stm

ents

per

ye

ar a

llow

ed)

Pro

pose

d D

esig

n (w

ith 5

0%

anom

aly

thre

shol

d an

d 2

anom

aly

adju

stm

ents

per

ye

ar a

llow

ed to

mat

ch L

GS

8 -

11 a

nd L

GS

13

- 14)

45%

ano

mal

y th

resh

old

(2

anom

aly

adju

stm

ents

per

ye

ar a

llow

ed)

30%

80:1

20Y

es54

4 -- 585

35%

624 -- 676

40%

80:1

20Y

es73

8 -- 771

45%

80:1

20Y

es87

1 -- 894

50%

80:1

20Y

es10

31 --10

5055

%

80:1

20Y

es12

37 --12

6360

%

MG

S 0

MG

S 0

MG

S 0

MG

S 0

MG

S 0

MG

S 4

The

Sce

nario

LG

S 1

2 is

iden

tical

to

Sce

nario

LG

S 5

.

~3,0

00 a

dditi

onal

LG

S A

ccou

nts.

Ple

ase

see

the

resp

onse

to B

CO

AP

O IR

1.3

0.4

rega

rdin

g im

plem

enta

tion

prac

tical

ity.

~1,5

00 a

dditi

onal

LG

S A

ccou

nts.

Ple

ase

see

the

resp

onse

to B

CO

AP

O IR

1.3

0.4

rega

rdin

g im

plem

enta

tion

prac

tical

ity.

��

��

� ��

LGS

Rat

e M

atrix

Year

Tier-1

Tier-2

Tier-3

Tier-1

Tier-2

LRMC based Price

% Change


Pric

eLi

mit

Ban

ds

Initi

al H

BL

Bas

isC

Y050

607?

Yes/

No


Year

Threshold


Cor

resp

ondi

ngM

GS

Scen

ario

if

appl

icab

le



Estim

ated

Con

serv

atio

n (G

Wh)

Scenario #

Min

/Avg

./Max

Vol

atili

ty

Impa

ct R

elat

ive

to C

urre

nt

Stru

ctur

e (%

)

Ene

rgy

Rat

e (c

ents

/kW

h)IR

Ref

eren

ce.

Des

ign

Obj

ectiv

e an

d A

ssum

ptio

nsBasic Charge

(¢/day)

Dem

and

Rat

e ($

/kW

) P

art-1

Rat

e A

dj

Ano

mal

y A

dj

Com

men

ts

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13

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02

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/ 0.

01%

/ 8.

91%

135

6

14

0

F12

18.7

20

4.56

8.75

8.90

4.28

6.91

0.01

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0$

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0.61

% /

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% /

8.10

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8

42

530

F1

319

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87

9.

34

9.

49

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57

9.

66

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78

952

F1

421

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99

10

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11

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1

12

7

1,

238

F15

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60

5.50

10.5

5

10.6

9

5.14

13.3

8

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8.30

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26.7

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328

193

1,52

1

%

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rage

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Wh

Sum

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.9)

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3,93

6

446

4,

382

BC

UC

2.1

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aF1

118

.06

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40

8.

44

8.

59

4.

13

7.

02

0.

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80%

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79%

80

11

91

F12

18.7

20

4.56

8.75

8.91

4.29

6.91

0.10

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3$

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7.42

% /

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9

78

367

F1

319

.98

04.

87

9.

34

9.

49

4.

56

9.

66

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)$

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1.83

% /

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7% /

16.4

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8

141

659

F1

421

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05.

21

9.

99

10

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4.

87

11

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1%(1

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$

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12%

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657

22

8

88

5

F15

22.5

60

5.50

10.5

5

10.6

5

5.13

13.3

8

-0

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(2.9

)$

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5.69

% /

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26.4

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4

342

1,12

6

%

Ave

rage

; $ S

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Wh

Sum

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5%(4

.1)

$

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77%

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2,32

8

801

3,

129

BC

UC

2.1

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bF1

118

.06

04.

40

8.

44

8.

59

4.

13

7.

02

0.

09%

0.2

$

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81%

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11%

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76%

55

14

69

F12

18.7

20

4.56

8.75

8.91

4.28

6.91

0.09

%0.

2$

-1

7.43

% /

0.10

% /

7.99

%20

0

98

298

F1

319

.98

04.

87

9.

34

9.

47

4.

56

9.

66

-0

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)$

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6.77

% /

0.10

% /

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8

178

537

F1

421

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05.

21

9.

99

10

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4.

86

11

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4%(1

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16%

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454

28

8

74

3

F15

22.5

60

5.50

10.5

5

10.6

1

5.10

13.3

8

-1

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(3.3

)$

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9.08

% /

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2% /

25.2

7%54

2

393

935

%

Ave

rage

; $ S

um; G

Wh

Sum

-0.4

8%(5

.2)

$

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05%

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07%

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1,61

0

972

2,

582

BC

UC

2.1

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aF1

118

.06

04.

40

8.

44

8.

58

4.

13

7.

02

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)$

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2.56

% /

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5.19

%11

3

6

119

F1

218

.72

04.

56

8.

75

8.

90

4.

28

6.

91

-0

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(0.1

)$

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0.57

% /

-0.0

4% /

4.73

%41

1

44

455

F1

319

.98

04.

87

9.

34

9.

49

4.

57

9.

66

-0

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(0.6

)$

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3.39

% /

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9.09

%70

1

81

782

F1

421

.38

05.

21

9.

99

10

.15

4.

89

11.5

4

-0

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)$

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1.01

% /

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7% /

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9

132

1,01

2

F1

522

.56

05.

50

10

.55

10

.72

5.

16

13

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-0.1

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78%

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1,02

7

19

6

1,

222

% A

vera

ge; $

Sum

; GW

h Su

m-0

.09%

(2.4

)$

-3

8.66

% /

-0.1

9% /

9.09

%3,

131

45

8

3,58

9

B

CU

C 2

.1.2

.3b

F11

18.0

60

4.40

8.44

8.59

4.13

7.02

0.00

%(0

.0)

$

-33.

81%

/ -0

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/ 7.

31%

126

6

13

2

F12

18.7

20

4.56

8.75

8.90

4.28

6.91

0.00

%(0

.0)

$

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84%

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/ 6.

67%

457

44

50

1

F13

19.9

80

4.87

9.34

9.49

4.57

9.66

-0.1

4%(0

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$

-49.

47%

/ -0

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/ 13

.06%

805

81

88

6

F14

21.3

80

5.21

9.99

10.1

5

4.88

11.5

4

-0

.20%

(1.1

)$

-5

4.40

% /

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9% /

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7%1,

017

132

1,14

9

F1

522

.56

05.

50

10

.55

10

.71

5.

15

13

.38

-0.2

3%(1

.3)

$

-57.

42%

/ -0

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/ 20

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1,20

5

19

6

1,

400

% A

vera

ge; $

Sum

; GW

h Su

m-0

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(3.1

)$

-4

5.19

% /

-0.1

9% /

12.9

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A IR

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��

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� ��

LGS

Rat

e M

atrix

Year

Tier-1

Tier-2

Tier-3

Tier-1

Tier-2

LRMC based Price

% Change


Pric

eLi

mit

Ban

ds

Initi

al H

BL

Bas

isC

Y050

607?

Yes/

No


Year

Threshold


Cor

resp

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Scen

ario

if

appl

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Estim

ated

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serv

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BC

UC

2.8

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r bill

impa

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is

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LGS 26

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British Columbia Utilities CommissionInformation Request No. 2.1.2.1 Dated: December 21, 2009British Columbia Hydro & Power Authority Response issued January 22, 2010

Page 1 of 3


Exhibit:B-7


The estimated conservation in GWh as presented in the December 7, 2009 ERRATA are: F2011 F2012 F2013 F2014 F2015 F2016 MGS (GWh) 6 44 81 132 196 271 % of MGS Sales 4.8 LGS (GWh) 131 474 853 1083 1296 % of LGS Sales 12.7


2.1.2.1 The initial HBLs based on (a) 2007, 2008 and 2009 3-year monthly rolling average with the remaining years calculated as described in Section 1.7.2.1 in the Application, and (b) one-year 2009 monthly rolling rate going forward; holding all other variables constant.

RESPONSE:

Please refer to Tables 1 to 3 below, each of which corresponds to a scenario shown in the response to BCUC IR 2.1.2. Given that the proposed MGS rate does not depend on a baseline, only the LGS portion of the above table is reproduced below. Volatility impact distributions reflecting the same requested variations are also shown in Tables 4 through 6.

Please note that because not all data is available yet for 2009, the most recent 12 months of available data were used. Therefore, the baseline corresponding to part (a) of the question uses data from September 2006 to August 2009, and the baseline corresponding to part (b) of the question, uses data from September 2008 to August 2009.

Each of the following tables also corresponds to scenarios shown in the response to BCUC IR 2.1.2 as indicated.

Table 1: Estimated Conservation for the Proposed LGS Design (Scenario LGS 4)

F2011 F2012 F2013 F2014 F2015 LGS (GWh) 127 460 824 1048 1253 % of LGS Sales 4.9% 4.7% 8.5% 10.9% 12.8%


Page 2 of 3


Exhibit:B-7

Table 2: Estimated Conservation for a 9/2006Through 8/2009 Initial Baseline (Scenario LGS 1)


Table 3: Estimated Conservation for a 9/2008Through 8/2009 Initial Baseline (Scenario LGS 2)


Note that in order to model the relative effect of different initial baselines BC Hydro adjusted the billing data to make the different years comparable. Scenarios LGS 1, 2, and 4 are based on the adjusted data; Scenario LGS 0 is not.

Table 4: Volatility Impacts for the Proposed LGS Design (Scenario LGS 4)

FY2011 FY2012 FY2013 FY2014 FY2015below 30% - - 7 52 136

-30% to -25% - - 25 51 82 -25% to -20% - - 43 81 141 -20% to -15% 11 6 102 169 211 -15% to -10% 70 55 220 266 320

-10% to -5% 298 258 511 576 601 -5% to 0% 1,916 1,958 1,387 1,109 864 0% to 5% 2,323 2,372 1,559 1,201 946

5% to 10% 318 225 711 761 686 10% to 15% - - 280 403 517 15% to 20% - - 14 165 285 20% to 25% - - - 9 123 25% to 30% - - - - 6 30% to 35% - - - - - 35% to 40% - - - - - 40% to 45% - - - - - 45% to 50% - - - - -

50% and above - - - - -


Page 3 of 3


Exhibit:B-7

Table 5: Volatility Impacts for a 9/2006 Through 8/2009 Initial Baseline (Scenario LGS 1)


-30% to -25% - - 11 33 82 -25% to -20% - - 29 59 141 -20% to -15% 1 1 43 124 211 -15% to -10% 11 7 157 252 320

-10% to -5% 123 97 532 625 601 -5% to 0% 2,833 2,747 1,814 1,366 863 0% to 5% 1,910 1,990 1,636 1,303 947


50% and above - - - - -

Table 6: Volatility Impacts for a 9/2008 Through 8/2009 Initial Baseline (Scenario LGS 2)


-30% to -25% 1 - 12 33 82 -25% to -20% - 1 29 67 141 -20% to -15% 24 3 64 133 211 -15% to -10% 83 52 193 302 320

-10% to -5% 381 271 645 759 601 -5% to 0% 2,041 2,246 1,706 1,285 864 0% to 5% 2,064 2,147 1,487 1,234 946

5% to 10% 343 153 581 615 686 10% to 15% - - 137 310 517 15% to 20% - - - 74 285 20% to 25% - - - - 123 25% to 30% - - - - 6 30% to 35% - - - - - 35% to 40% - - - - - 40% to 45% - - - - - 45% to 50% - - - - -

50% and above - - - - -


Page 1 of 13


Exhibit:B-7



F2011 F2012 F2013 F2014 F2015 F2016

MGS (GWh) 6 44 81 132 196 271

% of MGS Sales 4.8

LGS (GWh) 131 474 853 1083 1296

% of LGS Sales 12.7


2.1.2.2 Segmentation of the ELGS at: (a) 500 kW, (b) 1,000 kW, and (c) 100 kW; holding all other variables constant.

RESPONSE:

Please refer to the following tables, each of which corresponds to a scenario shown in the response to BCUC IR 2.1.2.

ELGS Segmentation @ 100 kW (Scenario MGS 3 and LGS 15)

F2011 F2012 F2013 F2014 F2015 F2016

35kW � MGS < 100kW (GWh) 4 31 58 96 146 194

% of MGS Sales 0.6% 1.1% 2.1% 3.5% 5.2% 7.0%

100kW � LGS (GWh) 148 537 964 1224 1465

% of LGS Sales 5.0% 4.8% 8.6% 10.9% 12.9%


Page 2 of 13


Exhibit:B-7


F2011 F2012 F2013 F2014 F2015 F2016

35kW � MGS < 120kW (GWh) 5 36 66 108 163 231

% of MGS Sales 0.6% 1.1% 2.0% 3.3% 4.9% 6.9%

120kW � LGS (GWh) 141 511 916 1163 1392

% of LGS Sales 4.9% 4.7% 8.5% 10.9% 12.8%


F2011 F2012 F2013 F2014 F2015 F2016

35kW � MGS < 140kW (GWh) 6 42 78 127 193 259

% of MGS Sales 0.6% 1.1% 2.1% 3.4% 5.1% 6.8%

140kW � LGS (GWh) 135 488 874 1111 1328

% of LGS Sales 4.9% 4.7% 8.5% 10.8% 12.8%

ELGS Breakpoint @ 500 kW (Scenario MGS 6 and LGS 18)

F2011 F2012 F2013 F2014 F2015 F2016

35kW � MGS < 500kW (GWh) 11 78 141 228 342 394

% of MGS Sales 0.6% 1.0% 1.8% 2.9% 4.3% 4.9%

500kW � LGS (GWh) 80 289 518 657 784

% of LGS Sales 4.9% 4.7% 8.4% 10.7% 12.6%


Page 3 of 13


Exhibit:B-7

ELGS Breakpoint @ 1000 kW (Scenario MGS 7 and LGS 19)

F2011 F2012 F2013 F2014 F2015 F2016

35kW � MGS < 1,000kW (GWh) 14 98 178 288 393 432

% of MGS Sales 0.6% 1.0% 1.8% 2.9% 3.9% 4.3%

1,000kW � LGS (GWh) 55 200 358 454 542

% of LGS Sales 4.9% 4.7% 8.5% 10.8% 12.6%

The following tables show the corresponding bill impacts for the MGS customers and bill volatility for the LGS customers under each of the 5 segmentation cases above.


Page 4 of 13


Exhibit:B-7

Table 1: MGS Bill Impacts for a Segmentation of Customers with Demand Equal to or Greater Than 35kW and Less than 100 kW (Scenario MGS 3

# Percentile # Percentile # Percentile # Percentile # Percentile # Percentile17 - 1816.6 - 17

16 - 16.6 0 100.00%15.6 - 16 0 100.00%

15 - 15.6 2 100.00% 0 100.00%

14 - 15 15 100.00% 31 99.98% 2 100.0%13 - 14 71 99.89% 76 99.76% 53 100.0%12.8 - 13 34 99.4% 32 99.2% 21 99.6%

12.6 - 12.8 2 100.00% 29 99.1% 22 99.0% 27 99.5%

12 - 12.6 148 100.0% 12 99.98% 146 98.9% 128 98.8% 149 99.3%11 - 12 2379 99.0% 119 99.90% 398 97.9% 293 97.9% 363 98.2%10.63 - 11 1683 82.4% 103 99.1% 192 95.1% 154 95.9% 203 95.7%

9 - 10.63 10110 70.6% 1033 98.3% 1245 93.7% 872 94.8% 1195 94.3%8 - 9 1142 91.0% 899 84.8% 690 88.7% 848 85.9%7.7 - 8 372 82.9% 295 78.4% 207 83.9% 256 80.0%

7 - 7.7 20 100.00% 1000 80.3% 800 76.3% 482 82.4% 679 78.2%

6.8 - 7 23 99.86% 356 73.2% 275 70.6% 145 79.0% 222 73.4%

6.6 - 6.8 27 99.7% 291 70.6% 191 68.7% 134 78.0% 170 71.8%

5.6 - 6.6 614 99.5% 2027 68.6% 1391 67.3% 916 77.1% 1142 70.7%

5 - 5.6 763 95.2% 1976 54.2% 935 57.4% 540 70.7% 663 62.6%3.7 - 5 2704 89.8% 5658 40.2% 7130 50.8% 1290 66.9% 1962 58.0%

3 - 3.7 2096 70.6% 781 57.8% 3156 44.3%2 - 3 7889 55.8% 1839 52.3% 3161 22.1%1 - 2 5626 39.4% 0 0.0%0 - 1(5) - 0(10) - (5)

15.0%

12.8%

7.70%

12.8%

10.6%

F2014 Accounts

3.70%

6.8%

7.0%

5.6%

6.6%

15.6%

F2015 Accounts F2016 Accounts

16.6%

Annual Bill Increase

%

F2011 Accounts F2012 Accounts F2013 Accounts


Page 5 of 13


Exhibit:B-7

Table 2: LGS Volatility Impacts for a Segmentation of Customers with Demand Equal to or Greater Than 100kW (Scenario LGS 15)

FY2011 FY2012 FY2013 FY2014 FY2015below 30% 2 1 12 68 180

-30% to -25% - 1 30 67 124 -25% to -20% - - 61 122 218 -20% to -15% 17 9 141 246 323 -15% to -10% 87 71 332 442 548 -10% to -5% 429 366 846 944 941

-5% to 0% 3,166 3,237 2,350 1,853 1,502 0% to 5% 3,861 3,905 2,577 2,036 1,592

5% to 10% 474 343 1,125 1,228 1,162 10% to 15% - - 415 632 806 15% to 20% - - 18 232 440 20% to 25% - - - 12 161 25% to 30% - - - - 6 30% to 35% - - - - - 35% to 40% - - - - - 40% to 45% - - - - - 45% to 50% - - - - -

50% and above - - - - -


Page 6 of 13


Exhibit:B-7

Table 3: MGS Bill Impacts for a Segmentation of Customers with Demand Equal to or Greater Than 35kW and Less than 120 kW (Scenario MGS 4)

# Percentile # Percentile # Percentile # Percentile # Percentile # Percentile17 - 18 1 100.00%16.6 - 17 0 99.99%

16 - 16.6 0 99.99%15.6 - 16 9 99.99%

15 - 15.6 1 100.00% 30 99.99%

14 - 15 1 100.00% 6 99.99% 167 99.7%13 - 14 44 99.99% 74 99.96% 268 98.7%12.8 - 13 34 99.7% 36 99.5% 75 97.0%

12.6 - 12.8 1 100.00% 35 99.5% 28 99.3% 78 96.5%

12 - 12.6 120 100.0% 0 99.99% 152 99.3% 130 99.1% 257 96.0%11 - 12 2693 99.2% 107 99.99% 441 98.3% 351 98.3% 539 94.4%10.63 - 11 1883 82.3% 100 99.3% 199 95.5% 153 96.0% 207 91.0%

9 - 10.63 11169 70.4% 1145 98.7% 1416 94.2% 947 95.1% 1210 89.7%8 - 9 1311 91.3% 1138 85.1% 804 89.1% 791 82.0%7.7 - 8 492 82.9% 327 77.8% 270 84.0% 210 77.0%

7 - 7.7 4 100.00% 1069 79.8% 819 75.7% 602 82.3% 511 75.7%

6.8 - 7 17 99.97% 395 72.9% 309 70.4% 198 78.5% 175 72.5%

6.6 - 6.8 28 99.9% 330 70.4% 219 68.4% 149 77.2% 152 71.4%

5.6 - 6.6 698 99.7% 2234 68.3% 1566 67.0% 930 76.3% 935 70.4%

5 - 5.6 839 95.2% 1758 54.0% 967 56.9% 607 70.4% 532 64.5%3.7 - 5 3050 89.9% 6667 42.7% 7731 50.7% 1432 66.6% 1245 61.1%

3 - 3.7 2289 70.4% 163 1.0% 814 57.5% 722 53.2%2 - 3 8736 55.8% 1595 52.3% 1579 48.7%1 - 2 5280 42.2% 5625 38.7%0 - 1 1395 8.8% 493 3.1%(5) - 0(10) - (5)


%


6.6%

15.6%


16.6%

3.70%

6.8%

7.0%

5.6%

15.0%

12.8%

7.70%

12.6%

10.6%

F2014 Accounts


Page 7 of 13


Exhibit:B-7

Table 4: LGS Bill Volatility for a Segmentation of Customers with Demand Equal to or Greater Than 120kW (Scenario LGS 16)


-30% to -25% - 1 28 60 106 -25% to -20% - - 57 102 188 -20% to -15% 16 8 120 218 278 -15% to -10% 82 66 286 362 446

-10% to -5% 367 315 695 773 781 -5% to 0% 2,580 2,637 1,888 1,493 1,186 0% to 5% 3,141 3,191 2,089 1,631 1,283

5% to 10% 419 302 942 1,024 949 10% to 15% - - 367 535 671 15% to 20% - - 18 207 374 20% to 25% - - - 12 150 25% to 30% - - - - 6 30% to 35% - - - - - 35% to 40% - - - - - 40% to 45% - - - - - 45% to 50% - - - - -

50% and above - - - - -


Page 8 of 13


Exhibit:B-7



16 - 16.615.6 - 16

15 - 15.6 1 100.00%

14 - 15 15 100.00% 35 99.99% 8 100.0%13 - 14 135 99.91% 168 99.79% 127 99.95%12.8 - 13 54 99.1% 45 98.8% 53 99.2%

12.6 - 12.8 1 100.00% 46 98.8% 41 98.5% 55 98.9%

12 - 12.6 228 100.0% 10 99.99% 231 98.5% 203 98.3% 244 98.6%11 - 12 2941 98.7% 209 99.93% 583 97.1% 444 97.1% 596 97.1%10.63 - 11 1846 81.3% 165 98.7% 247 93.6% 210 94.5% 248 93.6%

9 - 10.63 11949 70.4% 1343 97.7% 1390 92.1% 1009 93.2% 1317 92.1%8 - 9 1310 89.6% 1100 83.8% 785 87.2% 1001 84.3%7.7 - 8 467 81.8% 356 77.1% 227 82.6% 311 78.4%

7 - 7.7 21 100.00% 1096 79.0% 761 75.0% 584 81.2% 683 76.6%

6.8 - 7 50 99.87% 335 72.4% 243 70.4% 207 77.8% 206 72.5%

6.6 - 6.8 53 99.6% 264 70.4% 195 69.0% 131 76.6% 153 71.3%

5.6 - 6.6 935 99.3% 2065 68.9% 1460 67.8% 907 75.8% 1100 70.4%

5 - 5.6 902 93.7% 1316 56.5% 849 59.0% 516 70.4% 675 63.9%3.7 - 5 2992 88.3% 8110 48.6% 2551 53.9% 1324 67.4% 1504 59.9%

3 - 3.7 2106 70.4% 4380 38.6% 734 59.5% 947 51.0%2 - 3 6503 57.8% 2043 12.3% 1129 55.2% 2076 45.4%1 - 2 3182 19.0% 1602 48.5% 5605 33.1%0 - 1 4008 39.0%(5) - 0 2584 15.3%(10) - (5)

F2014 Accounts

5.6%

6.6%

15.6%

15.0%

12.8%

7.70%

12.6%

10.6%

3.70%

6.8%

7.0%


%

F2011 Accounts F2012 Accounts F2013 Accounts F2015 Accounts F2016 Accounts

16.6%


Page 9 of 13


Exhibit:B-7



-30% to -25% - 1 28 53 96 -25% to -20% - - 49 95 162 -20% to -15% 15 8 111 195 243 -15% to -10% 74 61 254 306 367

-10% to -5% 327 287 580 646 663 -5% to 0% 2,163 2,204 1,569 1,254 988 0% to 5% 2,662 2,712 1,775 1,368 1,077


50% and above - - - - -


Page 10 of 13


Exhibit:B-7



16 - 16.615.6 - 16

15 - 15.6 1 100.00%

14 - 15 7 100.00% 95 99.99%13 - 14 352 99.97% 402 99.55%12.8 - 13 107 98.3% 97 97.7%

12.6 - 12.8 1 100.00% 90 97.8% 95 97.2%

12 - 12.6 594 100.0% 11 99.99% 448 97.4% 369 96.8%11 - 12 3180 97.2% 552 99.94% 737 95.2% 584 95.0%10.63 - 11 1401 82.4% 303 97.3% 280 91.7% 226 92.3%

9 - 10.63 10439 75.8% 1669 95.9% 1375 90.4% 1095 91.2%8 - 9 5815 27.1% 1143 88.0% 840 83.8% 625 86.1% 582 100.0%7.7 - 8 354 82.5% 288 79.8% 198 83.2% 969 97.3%

7 - 7.7 14 100.00% 856 80.9% 577 78.5% 458 82.3% 2339 92.7%

6.8 - 7 112 99.93% 223 76.8% 176 75.7% 142 80.1% 762 81.8%

6.6 - 6.8 152 99.4% 191 75.8% 147 74.9% 113 79.4% 521 78.2%

5.6 - 6.6 1410 98.7% 1442 74.8% 988 74.2% 681 78.9% 3622 75.8%

5 - 5.6 1008 92.0% 858 68.0% 642 69.5% 382 75.7% 1990 58.8%3.7 - 5 2436 87.3% 2029 63.9% 1383 66.4% 875 73.9% 7118 49.5%

3 - 3.7 1507 75.7% 1302 54.3% 706 59.9% 558 69.8% 3453 16.2%2 - 3 2512 68.6% 2185 48.1% 1187 56.5% 734 67.2%1 - 2 3251 56.7% 3896 37.8% 1314 50.9% 769 63.8%0 - 1 8751 41.4% 4069 19.3% 1507 44.6% 700 60.2%(5) - 0 7868 37.4% 4537 56.9%(10) - (5) 7604 35.6%


%


6.6%

15.6%


16.6%

3.70%

6.8%

7.0%

5.6%

15.0%

12.8%

7.70%

12.6%

10.6%

F2014 Accounts


Page 11 of 13


Exhibit:B-7



-30% to -25% - - 9 18 30 -25% to -20% - - 15 27 32 -20% to -15% 6 3 36 47 58 -15% to -10% 22 19 58 67 75

-10% to -5% 91 83 120 120 133 -5% to 0% 421 427 299 249 189 0% to 5% 534 546 344 269 203


50% and above - - - - -


Page 12 of 13


Exhibit:B-7



16 - 16.615.6 - 16

15 - 15.6

14 - 15 93 100.00%13 - 14 581 99.57%12.8 - 13 123 96.9%

12.6 - 12.8 2 100.00% 104 96.3%

12 - 12.6 850 100.0% 104 99.99% 419 95.8% 1 100.0%11 - 12 2821 96.2% 776 99.51% 670 93.9% 291 100.0%10.63 - 11 1135 83.4% 305 96.0% 217 90.8% 308 98.7%

9 - 10.63 6960 78.3% 1457 94.6% 1171 89.8% 1370 97.3%8 - 9 10365 46.8% 983 87.9% 708 84.4% 834 91.1%7.7 - 8 291 83.3% 199 81.2% 277 87.3%

7 - 7.7 174 100.00% 637 82.0% 478 80.3% 589 86.0%

6.8 - 7 224 99.20% 220 79.1% 150 78.0% 170 83.3% 1 100.0%

6.6 - 6.8 232 98.2% 165 78.1% 129 77.4% 146 82.6% 1993 100.0%

5.6 - 6.6 1371 97.1% 1055 77.3% 735 76.8% 852 81.9% 20063 91.0%

5 - 5.6 816 90.8% 629 72.5% 399 73.4% 491 78.0%3.7 - 5 1975 87.1% 1529 69.6% 994 71.5% 1018 75.8%

3 - 3.7 1101 78.1% 919 62.6% 598 67.0% 578 71.2%2 - 3 1837 73.0% 1281 58.3% 857 64.2% 897 68.6%1 - 2 2106 64.6% 1572 52.5% 852 60.3% 919 64.5%0 - 1 2599 55.0% 1857 45.2% 835 56.3% 887 60.3%(5) - 0 9410 43.1% 7993 36.7% 6650 52.5% 5308 56.3%(10) - (5) 4744 21.9% 7102 32.2%

F2014 Accounts

5.6%

6.6%

15.6%

15.0%

12.8%

7.70%

12.6%

10.6%

3.70%

6.8%

7.0%


%

F2011 Accounts F2012 Accounts F2013 Accounts F2015 Accounts F2016 Accounts

16.6%


Page 13 of 13


Exhibit:B-7


FY2011 FY2012 FY2013 FY2014 FY2015below 30% - - - 3 8

-30% to -25% - - 3 3 6 -25% to -20% - - 2 7 17 -20% to -15% 2 1 8 21 30 -15% to -10% 7 6 29 33 23

-10% to -5% 35 30 49 40 44 -5% to 0% 157 162 118 100 88 0% to 5% 227 231 135 113 88


50% and above - - - - -


Page 1 of 4


Exhibit:B-7


The estimated conservation in GWh as presented in the December 7, 2009 ERRATA are: F2011 F2012 F2013 F2014 F2015 F2016 MGS (GWh) 6 44 81 132 196 271 % of MGS Sales 4.8 LGS (GWh) 131 474 853 1083 1296 % of LGS Sales 12.7


2.1.2.3 The Price Limit Band is based on up to: (a) 10% of baseline, (b) 15% of baseline, and (c) 30% of baseline; holding all other variables constant.

RESPONSE:

Please see the following tables, each of which corresponds to a scenario shown in the response to BCUC IR 2.1.2. Tables 1 through 3 below replicate the referenced table with the three Price Limit Bands requested. Since BC Hydro’s proposed MGS rate does not utilize a Price Limit Band, only the LGS portion of the above table is reproduced.

The response is supplemented with three bill volatility distributions shown in Tables 4 through 6 that correspond to each of the Price Limit Band cases.

Table 1: Estimated Conservation for a 90:110 Price Limit Band (Scenario LGS 20)





Page 2 of 4


Exhibit:B-7



Table 4: Bill Volatility for a 90:110 Price Limit Band (Scenario LGS 20)


-30% to -25% - - - 1 15 -25% to -20% 1 1 1 14 50 -20% to -15% 1 1 14 69 212 -15% to -10% 1 1 147 338 442

-10% to -5% 178 128 637 695 667 -5% to 0% 2,249 2,280 1,616 1,305 1,068 0% to 5% 2,761 2,717 1,983 1,531 1,222

5% to 10% 4 - 713 1,041 1,053 10% to 15% - - - 101 441 15% to 20% - - - - - 20% to 25% - - - - - 25% to 30% - - - - - 30% to 35% - - - - - 35% to 40% - - - - - 40% to 45% - - - - - 45% to 50% - - - - -

50% and above - - - - -


Page 3 of 4


Exhibit:B-7



-30% to -25% 1 - 3 32 77 -25% to -20% - 1 28 78 142 -20% to -15% 1 1 88 172 224 -15% to -10% 40 23 228 311 372

-10% to -5% 292 245 580 614 605 -5% to 0% 2,071 2,118 1,481 1,193 966 0% to 5% 2,595 2,626 1,716 1,335 1,054

5% to 10% 195 115 845 882 841 10% to 15% - - 141 430 576 15% to 20% - - - 37 247 20% to 25% - - - - 9 25% to 30% - - - - - 30% to 35% - - - - - 35% to 40% - - - - - 40% to 45% - - - - - 45% to 50% - - - - -

50% and above - - - - -


Page 4 of 4


Exhibit:B-7



-30% to -25% 1 - 42 62 116 -25% to -20% 20 12 53 97 144 -20% to -15% 33 33 113 176 233 -15% to -10% 76 65 235 301 352 -10% to -5% 307 277 527 617 658

-5% to 0% 1,932 1,967 1,444 1,153 890 0% to 5% 2,369 2,398 1,510 1,160 901

5% to 10% 433 370 687 712 642 10% to 15% 22 6 313 368 454 15% to 20% - - 129 218 280 20% to 25% - - 12 109 182 25% to 30% - - - 20 84 30% to 35% - - - - 39 35% to 40% - - - - 2 40% to 45% - - - - - 45% to 50% - - - - -

50% and above - - - - -


Page 1 of 2


Exhibit:B-7



F2011 F2012 F2013 F2014 F2015 F2016

MGS (GWh) 6 44 81 132 196 271

% of MGS Sales 4.8

LGS (GWh) 131 474 853 1083 1296

% of LGS Sales 12.7


2.1.2.4 The flattening of rate structure for MGS: (a) over a five-year period and (b) over a four-year period; holding all other variables constant. Please state explicitly the threshold assumptions.

RESPONSE:

Please refer to the following tables, each of which corresponds to a scenario shown in the response to BCUC IR 2.1.2. (Scenarios MGS 1 and MGS 2).

Five-Year Period F2011 F2012 F2013 F2014 F2015 F2016

MGS (GWh) 7 58 112 177 251 271

% of MGS Sales 0.2% 1.4% 2.8% 4.4% 6.2% 6.7%

Four-Year Period F2011 F2012 F2013 F2014 F2015 F2016

MGS (GWh) 8 71 136 232 251 271

% of MGS Sales 0.2% 1.8% 3.4% 5.8% 6.2% 6.7%


Page 2 of 2


Exhibit:B-7

Flattening the rate structure over a shorter time period than proposed in the application will result in more conservation in the transitioning years, but will also result in higher bill impacts. Per-year bill impact thresholds are increased to reflect a shorter flattening period. In both cases threshold levels are increased above CARC each year, consistent with BC Hydro’s phase-in proposal.

The specific threshold levels are 3 per cent, 6 per cent, 9 per cent, 9.5 per cent and 10 per cent above CARC for the five-year period; and 4 per cent, 8 per cent, 11 per cent and 14.5 per cent for the four-year period example. These levels were selected for modeling purposes only to allow a response to this information request, and do not represent a recommendation by BC Hydro.


Page 1 of 1


Exhibit:B-7



F2011 F2012 F2013 F2014 F2015 F2016

MGS (GWh) 6 44 81 132 196 271

% of MGS Sales 4.8

LGS (GWh) 131 474 853 1083 1296

% of LGS Sales 12.7

2.1.3 Please provide a comparison of the respective bill impacts as a result of the varied assumptions in the above IRs.

RESPONSE:

Please refer to the response to BCUC IR 2.1.2.


Page 1 of 1


Exhibit:B-7

2.0 Reference: Forecast Energy Exhibit B-5, BCUC IR 1.12.2; BCUC IR 1.1.3.1 pp. 3, 4 Conservation as a Percentage of Energy

The response to IR 1.12.2 provides the forecast energy in GWh for the years F2011 to F2015 for MGS and LGS respectively.

2.2.1 Please reconcile the total MGS and LGS forecast energy sales in IR 1.12.2 with the ELGS forecast sales for the same period presented in Response to IR 1.1.3.1 pages 3 and 4.

RESPONSE:

The forecasts shown in the response to BCUC IR 1.1.3.1 are “with rate impacts”, meaning they are net of the demand response to revenue requirement rate changes. They are “before DSM”, meaning they are before any demand response to programs, codes and standards, or assumed conservation rate structures.

The forecasts shown in Response to BCUC IR 1.12.2 are “with rate impacts” and with DSM, meaning they are net of the demand response to revenue requirement rate changes, programs, codes and standards, and assumed conservation rate structures.


Page 1 of 1


Exhibit:B-7

3.0 Reference: Load Forecast Exhibit B-5. BCUC IR 1.1.2 and IR 1.1.3.1

BCUC IR 1.1.2 asked for the source document of the load forecasts and Tables A4.1 to A4.10. The Response explains that the August 2009 Load Forecast is a short-term update of the energy forecasts only, and that high and low scenarios were not developed.

2.3.1 Is there a document, other than the output tables, that constitutes the August 2009 Load Forecast Update? If so, please provide the document that constitutes the August 2009 load forecast update. If there is no document at BC Hydro that records the changes in energy forecasts, please provide detailed explanation to the August Short Term Update from the 2008 LTAP Evidentiary Update.

RESPONSE:

There is no single document that contains the August 2009 load forecast because the August forecast is a short-term update. The August 2009 load forecast was developed generally with the same methodology and similar sources of inputs used in the load forecast contained in the 2008 LTAP Evidentiary Update. Please refer to the response to BCUC IR 2.3.3.1.

The differences between the August 2009 load forecast and the forecast used in the 2008 LTAP Evidentiary Update are due to updates to the forecasting models for historical sales and economic drivers. The table below shows the annual growth rates of the economic drivers used to develop the August 2009 forecast and the forecast contained in the 2008 LTAP Evidentiary Update.

2008 AUGUST 2008 AUGUST 2008 AUGUST 2008 AUGUSTLTAP EU 2009 LTAP EU 2009 LTAP EU 2009 LTAP EU 2009

Residential Residential Employment Employment Real Real Retail RetailAccounts Accounts ANNUAL ANNUAL GDP GDP Sales SalesANNUAL ANNUAL GROWTH GROWTH ANNUAL ANNUAL ANNUAL ANNUALGROWTH GROWTH GROWTH GROWTH GROWTH GROWTH

% % % % % % % %2009 1.5% 1.1% 0.6% -2.5% 1.8% -2.5% 4.0% -7.1%2010 1.4% 1.2% 1.3% 1.2% 3.3% 3.4% 5.0% 4.0%2011 1.4% 1.4% 1.5% 2.5% 2.8% 3.5% 5.3% 5.7%2012 1.4% 1.4% 1.1% 2.5% 2.7% 3.7% 5.2% 6.6%2013 1.3% 1.4% 1.0% 1.5% 2.2% 3.5% 4.9% 5.5%2014 1.3% 1.3% 0.7% 1.1% 2.0% 2.2% 4.1% 4.0%2015 1.3% 1.3% 0.8% 0.8% 1.9% 1.9% 4.0% 4.2%

Note: Residential account growth rates are for fiscal years while all remaining growth rates are for calendar years.


Page 1 of 1


Exhibit:B-7



2.3.2 Please explain the basis of percentage used (28.4%:71.6%) in the splitting of the ELGS class to MGS and LGS and why it is different from the information contained in the ‘Active Account Summary’ in Table B-1 (Exhibit B-1, Appendix B).

RESPONSE:

The percentage split between the MGS and LGS classes referred to in the question is based on the datasets used to model MGS and LGS rates; those datasets were adjusted to eliminate accounts with partial billing data in the fiscal year. Appendix B, Table B-1 uses a dataset of active accounts in F2008 and does not eliminate accounts with partial billing history.


Page 1 of 1


Exhibit:B-7



2.3.2 Please explain the basis of percentage used (28.4%:71.6%) in the splitting of the ELGS class to MGS and LGS and why it is different from the information contained in the ‘Active Account Summary’ in Table B-1 (Exhibit B-1, Appendix B).

2.3.2.1 Will the MGS and LGS split remain constant over the years for modeling purposes? Please explain the basis of assumption.

RESPONSE:

BC Hydro is not entirely clear on what information is being sought in this information request. The modelling done by BC Hydro and described in this application provides an indication of the pricing, conservation, bill impacts and bill volatility that the proposed rate structures would yield for a number of years in the future, based on assumptions that seem reasonable at this time. BC Hydro does not anticipate modelling the rate structures again, in any comprehensive fashion, if and when they are approved. It follows that there will be no MGS/LGS split, assumed or otherwise, for future modelling purposes.

However, under BC Hydro's proposals it would be making annual pricing adjustments to the LGS Part 1 energy rates, and the MGS energy rates, in accordance with BCUC orders arising from this proceeding. Because under BC Hydro's proposals those pricing adjustments would be made pursuant to previous BCUC orders, no relief would be sought, which is why BC Hydro refers to such filings as compliance filings.

BC Hydro's proposed annual pricing adjustments would be based on revenue requirement rate changes and load forecasts that would have already been approved , or for which approval is pending, for the year in regard to which the compliance filing is being made, exactly in the same manner that BC Hydro makes its RIB price adjustment filings, as well as historical datasets for the MGS and LGS class. The split between MGS and LGS used for these annual filings will be different in the future, as BC Hydro will use the most recent datasets of billing history to determine revenue neutral rates. Please also refer to the response to BCOAPO IR 2.9.1 regarding the proposed annual pricing adjustments.


Page 1 of 1


Exhibit:B-7



2.3.3 The Response to BCUC IR 1.1.2 refers to the data in Appendix Q as the data used in modeling. Please repeat Table Q-1 (i.e., after DSM and after rate impacts), by rate class (summing to the total integrated system load) with general service disaggregated to small, medium and large, for each year from 2009 to 2015.

RESPONSE:

Please refer to the table below.

2008 LTAP Forecast (GWh) 2009 Updated Forecast (GWh) FiscalYear

SGSLoadForecast

ELGSLoadForecast

MGSportionof ELGS Forecast

LGSPortionof ELGS Forecast

SGSLoad

ELGSLoadForecast

MGSportionof ELGS Forecast

LGSportionof ELGS Forecast

2010 3,972 14,649 4,160 10,489 3,776 14,118 4,003 10,115 2011 3,975 14,854 4,219 10,635 3,737 14,307 4,057 10,250 2012 3,959 14,973 4,252 10,721 3,570 14,123 4,004 10,119 2013 3,961 15,113 4,292 10,821 3,490 14,076 3,991 10,085 2014 3,943 15,156 4,304 10,852 3,411 14,034 3,979 10,055 2015 3,916 15,213 4,320 10,893 3,363 14,248 4,040 10,208

All estimates in the above table are net of both “rate impacts” and DSM, and thus are net of both the demand response from revenue requirement rate changes, programs, codes and standards, and assumed conservation rate structures.

Estimates in the last two columns correspond to row 34 in Table N-2, page 6 of 17, and row 51 in Table O-2, page 9 of 23, in the Application.


Page 1 of 1


Exhibit:B-7



2.3.3 The Response to BCUC IR 1.1.2 refers to the data in Appendix Q as the data used in modeling. Please repeat Table Q-1 (i.e., after DSM and after rate impacts), by rate class (summing to the total integrated system load) with general service disaggregated to small, medium and large, for each year from 2009 to 2015.

2.3.3.1 Since an annual adjustment to the Part 1 energy rate is proposed in the Application, please comment if the Short Term Update to the Annual Load Forecast will be done regularly for the specific purpose of the setting of LGS Part 1 rate.

RESPONSE:

Please refer to the responses to BCOAPO IR 2.9.1 and BCUC IR 2.3.2.1 regarding the proposed annual price adjustments.

The August 2009 load forecast update was used for the purpose of the Application simply because it reflected the most recent internally approved load information that was available to BC Hydro. This forecast was used in the August 2009 update of the Service Plan, this application, and will be used in the F2011 RRA. Please also see the response to BCUC IR 2.3.1 regarding the August 2009 load forecast.

Because the annual forecast Part 1 price adjustment is a compliance filing BC Hydro would use the most current BCUC approved load forecast.


Page 1 of 1


Exhibit:B-7

4.0 Reference: Two Part Rate Structure and Price Limit Bands Exhibit B-5, BCSEA 1.1.1; Exhibit B-1 p. 3-22 Scenario 3 and Scenario 9, pp. 6 and 12 of 18

Scenarios 3 and 9 are two substantially similar scenarios: (a) consumption at 133% above HBL; and (b) outside Price Limit Band.

2.4.1 The energy charge calculated for Scenario 3 results in the 4,000 kWh outside PLB being charged Part 2 Tier 2 energy rate at 4.45 ¢/kWh. The energy charge calculated for Scenario 9 results in the 1,000 kWh outside PBL being charged Part 2 Tier 1 rate at 9.26 ¢/kWh. Please explain the difference in their treatment and please explain the price signals created by this different treatment.

RESPONSE:

In both Scenario 3 and Scenario 9, actual consumption exceeds both the HBL and the upper Price Limit Band. Thus, the marginal rate seen by the account in each scenario is the applicable Part 1 energy rate (the Tier 2 energy rate of 4.45 ¢/kWh in Scenario 3; the Tier 1 energy rate of 9.26 ¢/kWh in Scenario 9). The different rates charged for marginal energy consumption reflect the historical energy consumption in Scenarios 3 and Scenario 9 being above and below the 14,800 threshold, respectively.

This difference in marginal price signals for accounts in different consumption situations does not constitute unduly discriminatory treatment. It is true that there is a discontinuous marginal price incentive across consumption levels under the proposed LGS rate structure and for any two-part structure with either Price Limit Bands or minimum energy charges. More generally, however, there will be discontinuities in marginal incentives in any block rate structure including the ELGS rate structure, the RIB rate, and the TSR stepped rate.

As a result of the proposed LGS Price Limit Bands and the relatively small percentage of LGS accounts that consume below the 14,800 KWh threshold, very few LGS accounts are expected to see the Tier 1 energy rate as their marginal price signal. They account for about one per cent of bills and about 0.1 per cent of load, and are shown as Scenarios 6, 9 and 13 in the response to BCSEA IR 1.1.1. Please also refer to the response to BCSEA IR 2.5.1.


Page 1 of 1


Exhibit:B-7

5.0 Reference: Heritage Contract Exhibit B-5, BCUC IR 1.2.2; Exhibit B-1, p. 4-11 Treatment of New Customers

The preamble to IR 1.2.2 is “Please contrast this treatment for new customers with that of (1) MGS and SGS new customers; (2) new residential customers and, (3) new TSR (Rate Schedule 1823) customers. Please explain in each case why the differing treatments are appropriate.”

2.5.1 The response to IR 1.2.1 mentioned that the BC Hydro proposed exposure to marginal cost was prompted by customer concerns. Is this the only reason for creating a different treatment for new customers? If not, please modify the answer to explain fully why in each case different treatments are appropriate.

RESPONSE:

In the absence of express concerns from existing customers, BC Hydro would not have proposed a design that exposed new customers to any LRMC-based pricing in the first year.

As noted, the TSR stepped rate provides no exposure to LRMC-based pricing for new customers, while the RIB rate does provide such exposure for customers whose consumption exceeds the Step-1 Threshold. These features of these rate structures were approved by the BCUC without any discussion on whether new customers should be treated consistently between classes. Given that the default rate structures in each case are quite different, and given the different procedural history of each rate structure, BC Hydro believes that the different treatment between the TSR stepped rate and the RIB rate is not inappropriate.

Similarly, the proposed LGS rate structure is different from both the RIB rate and the TSR stepped rate, and already has a unique procedural history, and there is no reason that it should expose new customers to LRMC-based pricing in either the manner of the TSR stepped rate or the RIB rate.


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Exhibit:B-7

5.0 Reference: Heritage Contract Exhibit B-5, BCUC IR 1.2.2; Exhibit B-1, p. 4-11 Treatment of New Customers

The preamble to IR 1.2.2 is “Please contrast this treatment for new customers with that of (1) MGS and SGS new customers; (2) new residential customers and, (3) new TSR (Rate Schedule 1823) customers. Please explain in each case why the differing treatments are appropriate.”

2.5.2 The Direct Testimony of Dr. Orans explains that his recommendation of LRMC-based rate for 10 per cent reflects the fact that existing accounts will have between 0 and 20 per cent of their total usage exposed to the LRMC-based rate. Is 10 per cent an average of major site types? Is there wide variation among site types?

RESPONSE:

The percent of total usage exposed to the LRMC-based rate depends upon the proposed rate design, baseline consumption, and actual consumption. Under BC Hydro’s proposal, customers with usage outside of the Price Limit Bands do not see the LRMC-based rate as their marginal rate.

Assuming an F050607 baseline and F08 actual consumption, among customers with usage within the Price Limit Bands, the average percentage of total usage exposed to LRMC is 0.3 per cent. This reflects the fact that this class of customers has had a very small average annual energy growth rate. Among customers with increased consumption relative to their baseline, the average percentage of total usage exposed to LRMC is 7.1 per cent; the following table provides a breakdown by Conservation Potential Review (CPR) site type of customers with increasing consumption.


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Exhibit:B-7

CPR_designationAverage Usage

Increase (%)Agriculture 7.5%Chemical - Other 8.5%Coal Mining 8.6%Educational Services 7.7%Food & Beverages 7.6%Food Retail 4.8%Health Services 7.8%Heavy Manufacturing 8.5%Hotels 6.6%Industrial - Other 8.3%Public School 7.2%Light Manufacturing 7.9%Metal Mining 7.8%Municipal Pumping 7.9%Non-Food Retail 6.3%Nursing Home 8.1%Offices 6.7%Other 6.8%Other Commercial 7.0%Public Hospital 6.0%Residential 7.8%Restaurant 7.2%Transportation 7.8%University/College 7.3%Warehouses 6.8%Wood - Lumber 8.1%Wood - Other 8.0%Wood - Panel 7.0%


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Exhibit:B-7

6.0 Reference: Part 2 Energy Rate Exhibit B-5, BCUC IR 1.4.2; JIESC IR 1.5.3; BCOAPO 1.37.4 Long Run Marginal Cost

In this Application, the estimated annual conservation for F2015 is 1,492 GWh as a result of ELGS rate re-structuring. The estimated annual conservation for F2015 in the 2008 LTAP proceeding was 350 GWh.

2.6.1 Was the 12¢/kWh also used in the ELGS conservation analysis in the 2008 LTAP? If not, how much of the differential in estimated conservation can be attributed to the LRMC assumed in the model.

RESPONSE:

The 2008 LTAP load forecast net of DSM assumed fixed threshold, inclining block structures for the ELGS class, one for service at primary voltage and one for service at secondary voltage. The higher tier 2 rates were assumed to be 10.5 cents/kWh and 9.3 cents/kWh, respectively, in F2020.Thus the difference in estimated conservation arises from both the different designs (and the degree to which consumption is exposed to the marginal rate) and the different marginal rates.


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Exhibit:B-7

7.0 Reference: Default and Mandatory Rate Exhibit B-5, BCUC IR 1.6.2.1; BCUC IR 1.6.3; BCUC IR 1.25.2; BCOAPO IR 1.25.1; CEC IR 1.40.3 Control Group

2.7.1 In BC Hydro’s response to BCUC IR 1.6.3 discussing rate options, it states that “The control group participants typically are selected from a group of volunteers for the rate option, but are kept on the default rate for a period of time before being allowed to take service on the option”. Please comment if this statement also describes ratepayers currently on Rate Schedules 1151, 1161 (Exempt Residential Service).

RESPONSE:

The statement does not completely describe ratepayers currently on Rate Schedules 1151, 1161 – Exempt Residential Service (RS 1151, 1161). In addition to those customers that participate in the RIB rate control group, these rate schedules also include farms and those residential customers taking service in Rate Zone IB (Bella Bella).

The customers on the RIB rate control group are customers who originally volunteered for BC Hydro’s Conservation Research Initiative (CRI) pilot and who remained on the flat residential rate as a control group for the pilot. When the RIB rate was approved, BC Hydro also received approval to keep those CRI customers on the flat exempt rate as a control group for the RIB rate.

In the case of the RIB rate the default rate is the RIB rate, and the exempt flat rate is the non-default rate, as opposed to the typical case described in the response to BCUC IR 1.6.3. If a customer is no longer enrolled in the RIB rate control group, they would be placed on the default RIB rate.


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2.7.2 Please compare and contrast the Exempt Residential Service control group as approved by Commission Order G-150-08 with the proposed control group in this Application e.g., bill guarantee, incentive, sampling, mandatory nature, etc.

RESPONSE:

BC Hydro notes that BCUC Order No. G-124-08 approved the exempt residential service control group, not BCUC Order No. G-150-08 as noted in the information request.

The table below provides a comparison between the proposed ELGS control group and the RIB control group receiving service under RS 1151, 1161.

ELGS Control Groups RIB Control Group

Bill guarantee (note 1) No NoIncentive (note 1) No NoSampling Stratified Customers volunteered for

enrolment in the CRI pilot, but enrolled customers were then randomly assigned to control or treatment groups

Mandatory Yes No Geographically defined No YesCustomer types All types are potentially

eligible for inclusion Single family dwellings only

Note 1: When customers originally applied to become volunteers in the CRI program, they were given an incentive and a bill guarantee. Neither of these inducements were offered to those CRI customers who remained on RS 1151 or 1161.

The advantages of the ELGS control groups, relative to the RIB control group, are their mandatory nature and random selection.


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2.7.3 In BC Hydro’s response to BCUC IR 1.6.2.1, it states that the Commission is the sole judge as to whether a rate is unduly discriminatory. Due to the absence of evidence from other utilities (Response to BCUC IR 1.25.2), can BC Hydro present evidence to support that the creation of the mandatory control group mandatory is not discriminatory other than the evidence that the control group is important for research purposes?

RESPONSE:

This information request presumably seeks a basis upon which the BCUC can be comfortable that its approval of mandatory, exempt control groups would not be unduly discriminatory and therefore not unlawful.

As set out in the referenced information request response, it is a question of fact over which the BCUC has exclusive jurisdiction whether a rate is unduly discriminatory (section 59(4) of the UCA), subject only to the views of the Court of Appeal with leave (section 101 of the UCA), or upon a stated case (section 104 of the UCA). Because the issue is a question of fact, over which the BCUC has exclusive jurisdiction, it can be said with reasonable certainty that the Court of Appeal would be unlikely to set aside as unlawful a BCUC order approving the creation of a mandatory, exempt control group.

BC Hydro has reviewed the jurisprudence, and decisions of other public utility regulators, and has not found a case where the lawfulness of an exempt, mandatory control group has been considered. The only case that BC Hydro has found that touches on the issue is Illinois Commerce Commission v. Commonwealth Edison Co., 1998 Ill. PUC Lexis 360 (Illinois Commerce Commission, hereinafter referred to as Illinois). The issue in the case was whether a pilot program was unduly discriminatory insofar as it was not available to all customers who might benefit from it, but rather only those who met prescribed eligibility criteria. It was not about the lawfulness of a mandatory, exempt control group, and the underlying statutory regime was similar but not identical to the statutory regime currently in place in British Columbia. Nevertheless, the following summary may be of assistance to the BCUC.


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Exhibit:B-7

In Illinois, the Commonwealth Edison Co. ("ComEd") filed a new experimental tariff entitled Rider CB. Rider CB provided for a voluntary pilot program of consolidated billing systems. It allowed a participating entity having multiple geographically dispersed premises to receive a single bill covering electricity consumption at many of its premises as if they all were a single premise. Two groups of customers were eligible to participate in the pilot program: (i) retail trade businesses having, among other things, at least 5 sites; and (ii) school districts having, among other things, 820 premises. While there were no guarantees of a discount for any customer participating in the pilot program, the rate structure was designed to provide an estimated typical participant with a 5 per cent savings if the customer agreed to participate.

In response to the Illinois Commission’s questions, "What is the reason for having an experimental rather than a general new tariff? Should Rider CB be made a non-experimental tariff that is available to all customers who have multiple locations under common ownership, management, or association and elect to receive consolidated billing?", ComEd stated that it reasonably and prudently formulated Rider CB as an experimental or pilot tariff rather than as a general tariff and that submitting Rider CB as a general tariff would have been irresponsible. "Rider CB constitutes an innovative and unprecedented combined test of methods for aggregation, AMR metering, and new communications and billing systems and technologies. Because a program of this sort has never been implemented or even piloted before and because the technologies and systems are largely untested, it would be all too easy for a utility or a utility regulator to make mistakes - in rate design, in the selection of technology and in the basic systems to monitor customer energy use."

The position of the Illinois Commission's Staff was that it was appropriate for ComEd to offer Rider CB to a limited number of customers because the ComEd needed to develop the systems required to implement Rider CB before considering expanding the Rider. Staff further argued that ComEd could gain useful experience by offering the tariff to a limited number of customers. Staff also stated that ComEd's difficulties in implementing Rider CB to date supported its decision to limit the tariff to two sub-classes of customers. Illinois Commission Staff also submitted that ComEd's opportunity to gain information from the program justified a temporary rate difference.

Certain participants in the hearing argued that Rider CB's narrow eligibility requirements were unlawfully discriminatory pursuant to section 9-241 of Illinois' Public Utilities Act. They submitted that the Rider CB should be provided on a non-experimental basis to all customers who have multiple locations under common ownership, management or association, and who elect to receive consolidated billing. They argued that in its Order in Docket 95-0435, the Illinois Commission held that an experimental or pilot program may offer different charges for different customers for a limited period of time without violating


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Exhibit:B-7

Section 9-241. They went on to say that "Since Rider CB is an open-ended experiment the tariff does not meet the standard the [Illinois] Commission established in Docket 95-0435."

With respect to the indefinite time frame of the experimental tariff, the Illinois Commission Staff proposed that ComEd file certain periodic reports with the Illinois Commission.

As to "unreasonable discrimination", one of the participants recognized that not all rate discrimination is illegal. "Discrimination is only illegal if there is no rational basis for the difference in rates. The test to be applied in determining whether rate discrimination has resulted is whether the differential treatment is reasonable and not arbitrary."

The Illinois Commission found that ComEd had demonstrated that it created the eligibility limitations for Rider CB based on just and reasonable factors. ComEd witnesses testified that ComEd formulated the eligibility criteria for Rider CB to provide for an easily defined class, an adequate sample of meter types and installations, and geographically dispersed premises, to avoid intra-industry inequities, and to produce a pilot program of a size and scope that was administratively and technologically manageable and resulted in a prudent level of financial risk to ComEd. The Illinois Commission noted that ComEd did not oppose complying with the Staff's recommendation regarding reporting requirements.

The Illinois Commission also found that Rider CB was not unreasonably discriminatory under the plain language and long-established standards under Section 9-241. In Docket 95-0435, the Illinois Commission considered and rejected an intervener's contention that pilot programs violated Section 9-241 on similar grounds. The Illinois Commission concluded, in that case, "that the pilot programs should not be rejected as unreasonable or unduly discriminatory. Implementation of pilot programs offering different charges and services for a limited period does not impose unreasonable differences in contravention of Section 9-241. Section 9-241 provides that the Illinois Commission may approve differences in charges based on "the amount used, the time when used, the purposes for which used”, and other relevant factors. The Illinois Commission anticipates that the information to be produced by the programs will be beneficial to the public, not just CILCO. This benefit is a relevant factor that justifies allowance of the pilot programs."

The Illinois Commission wrote the following at paragraph 74: "Pilot programs such as this are commonly used throughout the utility industry to test both new technologies and new billing concepts. Pilot programs approved by this Commission typically have highly restrictive eligibility criteria, in many cases far more limited than those of Rider CB. Intervenors' desire to participate in the pilot


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Exhibit:B-7

program is not evidence of unjust or unreasonable discrimination under S. 9-241. Nor is the fact that participants may ultimately benefit by participating. Were this true, any pilot program could be charged with discrimination, because pilot programs by their nature are limited."

The Illinois Commission found that the pilot would produce valuable experience and information for ComEd, the Illinois Commission, the industry and the ratepayers. The Illinois Commission also found that the pilot had not yet reached the level of technological certainty and reliability necessary for a prudent general expansion of the experimental tariff and that the expansion would not further, but rather would hinder, achievement of the pilot program's objectives and discourage other pilot programs.


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Exhibit:B-7


2.7.4 In Response to BCOAPO IR 1.25.1, BC Hydro states that it intends to create control groups that would reflect the characteristics of each class. Please provide more details, for example, will it be random sampling, if so, how does random sampling retain the characteristics of each class? If not, how does one avoid bias?

RESPONSE:

BC Hydro intends to use stratified randomized sampling to determine a control group for each of the LGS and MGS rate classes. A separate control group will be drawn from each of these two customer groups. Randomization is used to eliminate bias from the sampling. Stratification is used to increase the efficiency of the analysis.


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Exhibit:B-7


2.7.5 In Response to CEC IR 1.40.2, BC Hydro states that it expects the sample sizes of 200 for treatment and control groups will provide acceptable margins of error for the analysis. Please provide the confidence levels for both the projected 18,000 MGS accounts and the projected 5,000 LGS accounts.

RESPONSE:

In its response to CEC IR 1.40.1, BC Hydro estimated a confidence level of +/-7 per cent for a sample size of 200 out of a population of 6,000. This was a high level, conservative estimate. Providing more accurate estimates of confidence levels (whether for BC Hydro’s proposed control groups or for larger control groups) requires an estimate of the coefficient of variation for energy savings which BC Hydro does not have. However, BC Hydro believes, based on its review of other studies and its experience with the TSR stepped rate and the CRI, that a control sample of 200 MGS and of 200 LGS customers is sufficiently large to provide a statistically valid energy savings analysis.


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Exhibit:B-7

8.0 Reference: Rate Structure Exhibit B-5, BCUC IR 1.10.1 Part 1 LGS Rate

The response states that flattening the Part 1 rates would create additional bill impacts for LGS accounts without significantly improving the price signal or customer understanding of the price signal, and with minimal conservation impact.

2.8.1 What are the merits of maintaining the tier 1 and tier 2 ratio at 2.0783? Would resetting the ratio (i.e. moving towards a flat rate) over the years affect conservation?

RESPONSE:

The merits of maintaining the Tier 1 and Tier 2 ratio at 2.0783 is that customers that continue to consume at their HBL levels would see bills that are comparable to what they would have experienced absent rate restructuring. By contrast, flattening the Tier 1 and Tier 2 energy rates, and thus changing the ratio, would increase the bills for the larger energy consumers in the LGS class and lower the bills for the smaller energy consumers in the LGS class.

Conservation is modeled as being driven by the customer’s marginal rate. For the majority of LGS customers that marginal rate is the LRMC-based Part 2 rate so the Tier 1 and Tier 2 rates would not affect the conservation estimates for those customers. However, for some customers with billing usage that falls outside of the Price Limit Bands, their marginal rate could be Tier 1 or Tier 2, so their conservation estimates could change with modified ratios.


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Exhibit:B-7



2.8.2 Please provide empirical evidence that flattening Part 1 rates would (a) create additional bill impacts for LGS accounts, and (b) has minimal conservation impact.

RESPONSE:

The bill impacts for a two-part rate with a flat Part 1 energy rate are shown in Table 1 below. The CARC increase is at 10 - 11 per cent in F2011 and 3 – 4 per cent in F2012. The lines in the table are approximately BC Hydro’s bill impact threshold from its MGS rate proposal. The flat Part 1 energy rate would result in 680 accounts exceeding the bill impact threshold in F2011. After the energy rates are set as flat in F2011, the bill impacts in the subsequent years would essentially be CARC.

In comparison, BC Hydro’s two-part rate proposal has bill impacts each year (including F2011) that are essentially CARC. Note that bill impacts are not to be confused with volatility impacts. Bill impacts show the effect of changing the rates, assuming no change in consumption. Volatility impacts layer on the impact of having actual consumption that differs from an account’s HBL.


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Exhibit:B-7

Table 1 Bill Impacts for Two-Part Rate with a Flat Part 1 Energy Rate

Table 2 shows that the net conservation estimate for the two-part energy rate with a flat Part 1 energy rate is the same as for BC Hydro’s proposal.

FY2011 FY201220% and above - -

19% to 20% - -18% to 19% 9 -17% to 18% 63 -16% to 17% 116 -15% to 16% 145 -14% to 15% 166 -13% to 14% 181 -12% to 13% 183 -11% to 12% 209 -10% to 11% 181 -9% to 10% 181 -

8% to 9% 174 -7% to 8% 202 -6% to 7% 187 -5% to 6% 182 -4% to 5% 180 -3% to 4% 173 4,6342% to 3% 183 -1% to 2% 176 -0% to 1% 172 -

-1% to 0% 147 --2% to -1% 150 --3% to -2% 130 --4% to -3% 152 --5% to -4% 94 --6% to -5% 98 --7% to -6% 87 --8% to -7% 75 --9% to -8% 70 -

-10% to -9% 69 --11% to -10% 58 --12% to -11% 58 --13% to -12% 43 --14% to -13% 37 --15% to -14% 26 --16% to -15% 28 --17% to -16% 36 --18% to -17% 25 --19% to -18% 27 --20% to -19% 21 --21% to -20% 20 --22% to -21% 18 --23% to -22% 16 --24% to -23% 14 -

below -24% 72 -


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Exhibit:B-7

Table 2 Conservation (GWh)

F2011 F2012 F2013 F2104 F2015 Flat Part 1

Energy 133 483 863 1095 1310

BC Hydro Proposal

131 474 853 1083 1296


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Exhibit:B-7



2.8.3 The response refers to Figure 3-1 which illustrates that the LGS customers see a declining average electricity rate. Please confirm that the average electricity rate shown in Figure 3-1 is based on total monthly bill of energy, demand and basic charge.

RESPONSE:

BC Hydro assumes that the question meant to refer to Figure 3-4. BC Hydro confirms that Figure 3-4 is based on total monthly bill of energy, demand and basic charges.


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Exhibit:B-7



2.8.3 The response refers to Figure 3-1 which illustrates that the LGS customers see a declining average electricity rate. Please confirm that the average electricity rate shown in Figure 3-1 is based on total monthly bill of energy, demand and basic charge.

2.8.3.1 If confirmed, will BC Hydro be able to use the same justification if costs are considered only on a rate per kWh basis?

RESPONSE:

BC Hydro assumes that the phrase “rate per kWh basis” refers to a case where only the impacts of the energy rates are included in the analysis. Since the average cost of energy declines with increased usage, the justification that the flattening of the Part 1 rates would create additional bill impacts for LGS accounts would also apply if considered only on an energy basis.


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2.8.4 Why would flattening the Part 1 rates not result in improving price signals and having customers better understand the price signals?

RESPONSE:

Under BC Hydro's two-part rate proposal, LGS accounts with consumption changes within 20 per cent of their baseline usage would see a price signal equal to the incremental cost reflected in the Part 2 LRMC-based rate. The price-induced conservation effect is driven by the rate difference between the Part 2 LRMC-based rate and the marginal rate under the existing declining block design. Under this calculation, flattened Part 1 energy rates would not affect the conservation price signal for these LGS accounts.

For the small subset of accounts with usage outside of the Price Limit Bands, flattening the Part 1 rates could raise their marginal rate. This would provide a higher, and therefore “better” price signal than the existing declining block rate structure for those accounts that have usage in Tier 2.

BC Hydro believes that a flattened Part 1 energy rate would not significantly increase customer understanding of the two-part rate because BC Hydro’s proposal uses the current ELGS rates as the basis for the Part 1 rates. As customers are already familiar with the current ELGS rates, education efforts under BC Hydro’s proposed rate structure could focus on the Part 2 LRMC-based rate. With a flattened Part 1 rate, customers would need to be educated on both the Part 1 and Part 2 portions of the rate.


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Exhibit:B-7

9.0 Reference: DSM Expenditures Exhibit B-5, BCUC IR 1.11.2; Exhibit B-1-3, p. 2-7; Exhibit B-5, p. 3-11 Implementation Costs

2.9.1 Please compare the implementation costs to launch the MGS and LGS through F2013 at $4.6 million with the costs associated with the implementation and administration of the TSR and the RIB rate.

RESPONSE:

The table below compares the implementation costs identified for the launch of the LGS and MGS rates with similar costs for the RIB rate and TSR stepped rate. The estimates are for incremental implementation and initial customer support costs for activities consistent with those included in the LGS and MGS estimate and do not reflect ongoing administration costs.

Rate Class Implementation Cost ($ million)

Fiscal Years

Large & Medium General Service 4.6 F2010 – F2013

Residential Inclining Block 4.1 F2009 – F2010

Transmission Service Rate 1.9 F2006 – F2008


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Exhibit:B-7

10.0 Reference: Bill Impacts Exhibit B-5, BCUC IR 1.17.3; BCUC IR 17.5; CEC 1.20.4; CEC IR 1.25.4

2.10.0 In the Response to BCUC IR 1.17.3, BC Hydro describes the 10% bill impact threshold and discusses the acceptability of bill impact based on a consideration of various factors, including, amongst others, cumulative bill impacts and the absolute dollar value of a bill impact. BC Hydro’s response has not addressed whether there is a limit on cumulative impact which was the question in the IR.

RESPONSE:

Respectfully, BC Hydro outlined its bill impact threshold and additional factors that the BCUC could consider in determining if bill impacts arising from rate restructuring are acceptable, in its response to BCUC IR 1.1.7.3. BC Hydro has not in the past and does not currently propose a cumulative bill impact threshold, nor has the BCUC endorsed one.

Similarly, BC Hydro has never proposed a dollar value bill impact threshold, nor has one been endorsed by the BCUC. However, section 3.1.3 of Appendix M contains information regarding changes in MGS customers’ average electricity rates, and changes in F2016 monthly bills at different demand levels in Table M-5, as a result of the proposed MGS rate structure.


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Exhibit:B-7


In the Response to BCUC IR 1.17.3, BC Hydro describes the 10% bill impact threshold and discusses the acceptability of bill impact based on a consideration of various factors, including, amongst others, cumulative bill impacts and the absolute dollar value of a bill impact. BC Hydro’s response has not addressed whether there is a limit on cumulative impact which was the question in the IR.

2.10.1 Please provide a table similar to response to IR CEC 1.25.4 for LGS accounts.

RESPONSE:

The response to CEC IR 1.25.4 shows an 11 segment distribution of MGS customer bill impact percentages relative to their F2010 annual bill. BC Hydro refers to bill impacts as the change in an account’s annual bill relative to the prior year’s bill, assuming no change in usage. The bill impacts for F2011 relative to F2010, and the cumulative bill impacts for F2015 relative to F2010, are shown in Table 1 below.

Table 1 uses BC Hydro’s rate design subset of accounts. The total number of accounts is lower than the load forecast calibrated total, but this does not affect the distribution of the accounts shown in the table.

Table 1 Distribution of Cumulative Bill Impacts for LGS Accounts (Including changes due to CARC, but no usage change)

BillIncrease

Range (%) F2011 F2012 F2013 F2014 F2015 36 to 40 0 0 0 0 4634 32 to 36 0 0 0 0 0 28 to 32 0 0 0 4634 0 24 to 28 0 0 0 0 0 20 to 24 0 0 4634 0 0 16 to 20 0 0 0 0 0 12 to 16 0 4634 0 0 0 8 to 12 4634 0 0 0 0 4 to 8 0 0 0 0 0 0 to 4 0 0 0 0 0

BC Hydro has also presented volatility impacts in its Application. Volatility impacts show the bill changes that could result from changes in consumption interacting with the


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Exhibit:B-7

proposed two-part rate structure. Table 2 shows the bill increase distribution from incorporating changes in consumption into the analysis. Note that the values in the table are not the same as volatility impacts modelled in the Application, because the values in the table are expressed relative to F2010 bills, while volatility impacts in the Application are expressed relative to the bills that customers would have otherwise received under ELGS rates.

Table 2 Distribution of Impacts Relative to F2010 for LGS Accounts (Including changes due to CARC, and usage changes)

Bill Increase Range (%) F2011 F2012 F2013 F2014 F2015

60 to 70 0 0 0 0 79 50 to 60 0 0 0 32 634 40 to 50 0 0 0 690 1410 30 to 40 0 0 560 1975 1501 20 to 30 0 188 2676 1399 614 10 to 20 2918 4104 1138 376 242 0 to 10 1650 333 205 115 105 -10 to 0 65 8 52 44 43 -20 to -10 1 1 3 3 7 Below -20 1 1 1 1 0


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Exhibit:B-7



2.10.2 For the �150kW accounts, please list:

2.10.2.1 The top 25 accounts impacted from both the negative and positive impact range (in percentage terms for F2011) and provide their respective bill impacts in absolute dollar values.

RESPONSE:

BC Hydro has consistently referred to bill impacts as the change in an account’s annual bill relative to the prior year’s bill, assuming no change in usage. The bill impacts for F2011 relative to F2010 and the cumulative bill impacts for F2015 relative to F2010 are shown in Table 1 below.


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Exhibit:B-7

Table 1 Bill impacts for LGS customers receiving top and lowest F2011 percentage impacts – Including changes due to CARC

Top F2011 % Impacts Cumulative Impacts Lowest F2011 % Impacts Cumulative Impacts

% IncreaseAnnual $ Increase % Increase

2011 to 2015 $ Increase % Increase

Annual $ Increase % Increase

2011 to 2015 $

Increase

1 10.91% 2,826$ 39.43% 10,215$ 10.56% 6,167$ 38.16% 22,293$ 2 10.84% 3,972$ 39.19% 14,356$ 10.56% 5,721$ 38.16% 20,682$ 3 10.83% 3,722$ 39.16% 13,452$ 10.56% 5,550$ 38.16% 20,064$ 4 10.82% 1,546$ 39.12% 5,589$ 10.56% 5,646$ 38.16% 20,410$ 5 10.82% 5,259$ 39.11% 19,009$ 10.56% 5,575$ 38.16% 20,154$ 6 10.82% 2,430$ 39.11% 8,782$ 10.56% 5,327$ 38.16% 19,256$ 7 10.80% 32,901$ 39.05% 118,921$ 10.56% 5,611$ 38.16% 20,283$ 8 10.80% 7,868$ 39.02% 28,438$ 10.56% 5,386$ 38.16% 19,470$ 9 10.79% 34,571$ 39.01% 124,955$ 10.56% 7,369$ 38.16% 26,637$

10 10.79% 1,605$ 39.00% 5,803$ 10.56% 6,113$ 38.16% 22,097$ 11 10.79% 6,338$ 38.99% 22,910$ 10.56% 6,496$ 38.16% 23,482$ 12 10.79% 11,666$ 38.99% 42,166$ 10.56% 5,466$ 38.16% 19,758$ 13 10.79% 10,104$ 38.98% 36,520$ 10.56% 5,932$ 38.16% 21,445$ 14 10.78% 4,526$ 38.98% 16,359$ 10.56% 5,978$ 38.16% 21,611$ 15 10.78% 6,246$ 38.96% 22,575$ 10.56% 5,349$ 38.16% 19,336$ 16 10.77% 7,237$ 38.94% 26,158$ 10.56% 5,246$ 38.16% 18,964$ 17 10.77% 8,799$ 38.93% 31,803$ 10.56% 5,923$ 38.16% 21,410$ 18 10.77% 5,504$ 38.92% 19,894$ 10.56% 5,733$ 38.16% 20,724$ 19 10.77% 10,376$ 38.92% 37,504$ 10.56% 6,170$ 38.16% 22,305$ 20 10.77% 6,054$ 38.92% 21,883$ 10.56% 5,436$ 38.16% 19,652$ 21 10.77% 8,101$ 38.91% 29,282$ 10.56% 6,182$ 38.16% 22,348$ 22 10.77% 14,011$ 38.91% 50,643$ 10.56% 7,238$ 38.16% 26,164$ 23 10.76% 13,441$ 38.90% 48,582$ 10.56% 5,853$ 38.16% 21,156$ 24 10.76% 8,756$ 38.90% 31,650$ 10.56% 5,483$ 38.16% 19,819$ 25 10.76% 10,955$ 38.90% 39,597$ 10.56% 5,807$ 38.16% 20,990$

BC Hydro has also presented volatility impacts in its Application. Volatility impacts show the bill changes that could result from changes in consumption interacting with the proposed two-part rate structure. Table 2 shows the bill increases that result from incorporating changes in consumption into the analysis. Note that the values in the table are not the same as volatility impacts as modelled in the Application, because the values in the table are expressed relative to F2010 bills, while volatility impacts in the Application are expressed relative to the bills that customers would have otherwise received under ELGS rates.


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Exhibit:B-7

Table 2 Rate structure and usage change impacts for LGS customers receiving top and lowest F2011 percentage impacts – Including changes due to CARC


%Increase

Annual $ Increase

2015 over 2010 % Increase

2015 over 2010 $

Increase % IncreaseAnnual $ Increase


2015 over 2010 $

Increase

1 19.55% 10,598$ 63% 34,010$ -31.49% (10,264)$ -19% (6,186)$ 2 19.45% 14,393$ 63% 46,548$ -19.79% (19,119)$ -5% (4,455)$ 3 19.39% 56,970$ 62% 182,650$ -8.63% (3,194)$ 1% 328$ 4 19.36% 116,228$ 61% 366,135$ -7.21% (11,880)$ 1% 1,222$ 5 19.28% 15,728$ 59% 48,367$ -7.20% (2,582)$ -18% (6,380)$ 6 19.23% 92,656$ 64% 306,052$ -6.64% (2,480)$ 2% 860$ 7 19.23% 20,660$ 63% 68,070$ -6.29% (4,400)$ -5% (3,741)$ 8 19.21% 32,364$ 63% 105,963$ -6.25% (4,511)$ -2% (1,588)$ 9 19.10% 8,343$ 59% 25,860$ -5.99% (7,188)$ -7% (8,701)$

10 19.06% 44,702$ 62% 145,858$ -5.49% (2,253)$ -14% (5,838)$ 11 19.01% 36,284$ 61% 115,948$ -4.90% (4,317)$ -6% (5,563)$ 12 18.93% 7,405$ 61% 23,794$ -4.79% (3,595)$ -11% (8,490)$ 13 18.90% 14,221$ 60% 44,822$ -4.64% (21,085)$ 15% 66,737$ 14 18.89% 13,758$ 57% 41,483$ -4.38% (2,312)$ -9% (4,918)$ 15 18.70% 12,117$ 58% 37,803$ -4.37% (1,365)$ -5% (1,615)$ 16 18.70% 10,775$ 58% 33,425$ -4.26% (1,776)$ -9% (3,788)$ 17 18.63% 12,246$ 62% 40,591$ -4.24% (18,016)$ 5% 19,839$ 18 18.62% 77,504$ 58% 243,518$ -4.23% (1,520)$ -4% (1,411)$ 19 18.57% 8,342$ 55% 24,624$ -4.17% (2,505)$ -6% (3,858)$ 20 18.56% 13,315$ 61% 43,945$ -4.13% (1,885)$ -9% (4,188)$ 21 18.55% 41,410$ 62% 138,692$ -4.12% (2,500)$ -3% (1,602)$ 22 18.47% 12,843$ 61% 42,270$ -3.92% (2,011)$ -10% (4,952)$ 23 18.46% 30,024$ 57% 92,361$ -3.76% (3,310)$ -1% (1,089)$ 24 18.45% 13,134$ 60% 42,605$ -3.76% (811)$ -8% (1,801)$ 25 18.44% 18,677$ 65% 65,871$ -3.65% (4,801)$ -2% (2,113)$


Page 1 of 3


Exhibit:B-7



2.10.2 For the �150kW accounts, please list:

2.10.2.2 The top 25 accounts impacted in dollar values from both the negative and positive range for F2011 and provide their respective bill impacts in percentage terms.

RESPONSE:

BC Hydro has consistently referred to bill impacts as the change in an account’s annual bill relative to the prior year’s bill, assuming no change in usage. The bill impacts for F2011 relative to F2010 and the cumulative bill impacts for F2015 relative to F2010 are shown in Table 1 below.


Page 2 of 3


Exhibit:B-7

Table 1 Bill impacts for LGS customers receiving top and lowest F2011 dollar impacts – Including changes due to CARC

Top F2011 $ Impacts Cumulative Impacts Lowest F2011 $ Impacts Cumulative Impacts


2011 to 2015 $

Increase%

IncreaseAnnual $ Increase % Increase


1 269,322$ 10.7% 973,531$ 38.5% 431$ 10.6% 1,560$ 38.2%2 260,455$ 10.6% 941,488$ 38.5% 444$ 10.6% 1,604$ 38.2%3 257,175$ 10.7% 929,627$ 38.5% 587$ 10.6% 2,123$ 38.2%4 222,320$ 10.6% 803,641$ 38.5% 604$ 10.6% 2,183$ 38.2%5 196,275$ 10.6% 709,492$ 38.5% 642$ 10.6% 2,321$ 38.2%6 191,378$ 10.7% 691,784$ 38.5% 696$ 10.6% 2,517$ 38.2%7 190,771$ 10.6% 689,594$ 38.5% 705$ 10.6% 2,549$ 38.2%8 186,327$ 10.7% 673,526$ 38.5% 719$ 10.6% 2,600$ 38.2%9 180,197$ 10.7% 651,367$ 38.5% 720$ 10.6% 2,602$ 38.2%

10 176,192$ 10.7% 636,892$ 38.5% 784$ 10.6% 2,833$ 38.2%11 173,585$ 10.7% 627,466$ 38.5% 820$ 10.6% 2,965$ 38.2%12 171,918$ 10.7% 621,435$ 38.6% 897$ 10.6% 3,243$ 38.2%13 170,929$ 10.7% 617,863$ 38.6% 919$ 10.6% 3,320$ 38.2%14 164,382$ 10.7% 594,200$ 38.5% 970$ 10.6% 3,508$ 38.2%15 163,023$ 10.7% 589,284$ 38.6% 1,032$ 10.6% 3,728$ 38.2%16 160,638$ 10.7% 580,667$ 38.5% 1,045$ 10.6% 3,777$ 38.2%17 157,286$ 10.7% 568,551$ 38.5% 1,056$ 10.6% 3,816$ 38.2%18 154,223$ 10.7% 557,476$ 38.5% 1,085$ 10.7% 3,921$ 38.5%19 152,323$ 10.7% 550,605$ 38.6% 1,111$ 10.6% 4,018$ 38.2%20 149,246$ 10.7% 539,482$ 38.6% 1,113$ 10.6% 4,024$ 38.2%21 140,976$ 10.6% 509,595$ 38.5% 1,124$ 10.6% 4,064$ 38.2%22 128,696$ 10.7% 465,202$ 38.6% 1,141$ 10.6% 4,123$ 38.5%23 128,008$ 10.7% 462,717$ 38.6% 1,150$ 10.6% 4,158$ 38.2%24 124,616$ 10.7% 450,456$ 38.5% 1,177$ 10.6% 4,256$ 38.2%25 123,334$ 10.7% 445,824$ 38.5% 1,183$ 10.6% 4,276$ 38.2%

BC Hydro has also presented volatility impacts in its Application. Volatility impacts show the bill changes that could result from changes in consumption interacting with the proposed two-part rate structure. Table 2 shows the bill increases that result from incorporating changes in consumption into the analysis. Note that the values in the table are not the same as volatility impacts as modelled in the Application, because the values in the table are expressed relative to F2010 bills, while volatility impacts in the Application are expressed relative to the bills that customers would have otherwise received under ELGS rates.


Page 3 of 3


Exhibit:B-7

Table 2 Rate structure and usage change impacts for LGS customers receiving top and lowest F2011 dollar impacts – Including changes due to CARC

Top F2011 $ Impacts Cumulative Impacts Lowest F2011 $ Impacts Cumulative Impacts


2015 over 2010 $

Increase



2015 over 2010 $

Increase


1 306,163$ 12.7% 1,144,225$ 47.4% (21,085)$ -4.6% 66,737$ 14.7%2 304,977$ 17.0% 1,153,846$ 64.4% (19,119)$ -19.8% (4,455)$ -4.6%3 284,555$ 11.6% 1,046,716$ 42.8% (18,016)$ -4.2% 19,839$ 4.7%4 250,859$ 12.0% 976,445$ 46.7% (11,880)$ -7.2% 1,222$ 0.7%5 236,100$ 13.5% 913,345$ 52.2% (10,264)$ -31.5% (6,186)$ -19.0%6 224,104$ 15.7% 710,234$ 49.8% (9,329)$ -1.2% (3,605)$ -0.5%7 208,371$ 13.6% 795,057$ 52.0% (7,188)$ -6.0% (8,701)$ -7.3%8 208,244$ 14.1% 743,939$ 50.4% (6,538)$ -3.5% 18,946$ 10.3%9 194,623$ 11.8% 753,039$ 45.5% (5,689)$ -1.8% 19,080$ 6.0%

10 189,284$ 10.5% 746,832$ 41.6% (5,504)$ -2.6% (2,883)$ -1.4%11 172,453$ 9.4% 685,640$ 37.2% (4,801)$ -3.7% (2,113)$ -1.6%12 171,285$ 11.4% 618,098$ 41.0% (4,511)$ -6.2% (1,588)$ -2.2%13 168,029$ 6.6% 675,607$ 26.7% (4,400)$ -6.3% (3,741)$ -5.3%14 161,864$ 10.5% 615,658$ 39.9% (4,317)$ -4.9% (5,563)$ -6.3%15 157,388$ 9.8% 656,393$ 40.7% (3,799)$ -2.9% (7,371)$ -5.6%16 144,197$ 12.8% 542,186$ 48.1% (3,595)$ -4.8% (8,490)$ -11.3%17 143,791$ 14.7% 520,452$ 53.4% (3,310)$ -3.8% (1,089)$ -1.2%18 142,840$ 8.8% 517,738$ 31.8% (3,194)$ -8.6% 328$ 0.9%19 137,272$ 11.7% 478,339$ 40.9% (3,133)$ -1.5% 11,397$ 5.4%20 135,242$ 16.5% 509,744$ 62.4% (2,904)$ -1.5% (3,619)$ -1.9%21 131,910$ 12.1% 482,562$ 44.3% (2,582)$ -7.2% (6,380)$ -17.8%22 131,463$ 14.5% 416,612$ 46.0% (2,505)$ -4.2% (3,858)$ -6.4%23 131,355$ 15.0% 462,589$ 52.7% (2,500)$ -4.1% (1,602)$ -2.6%24 131,275$ 16.3% 493,292$ 61.2% (2,480)$ -6.6% 860$ 2.3%25 130,714$ 9.0% 465,171$ 32.2% (2,312)$ -4.4% (4,918)$ -9.3%


Page 1 of 1


Exhibit:B-7



2.10.3 Please provide the cumulative impact from F2011 to F2015 for the impacted LGS accounts in the previous two IRs.

RESPONSE:

Please refer to the response to BCUC IRs 2.10.2.1 and 2.10.2.2.


Page 1 of 2


Exhibit:B-7



2.10.4 For the < 150 kW accounts, please list:

2.10.4.1 The top 25 accounts impacted from both the negative and positive impact range (in percentage terms for F2011) and provide their respective bill impacts in absolute dollar values.

RESPONSE: Please refer to the F2011 bill impacts, relative to F2010 bill impacts, in the table below. The 25 accounts with the minimum percentage bill impacts all receive a 9.8 percent bill increase because this is the modelled increase applied to the Tier 1 rate.

Note that the 9.8 per cent increase is less than the assumed CARC in F2011 of 10.6 per cent that these accounts would otherwise have seen if the ELGS rate structure had remained in place.


Page 2 of 2


Exhibit:B-7

Top F2011 % Impacts Lowest F2011 % Impacts


Annual $ Increase

1 12.4% 5,777$ 9.8% 1,062$ 2 12.4% 6,033$ 9.8% 1,133$ 3 12.3% 6,101$ 9.8% 1,134$ 4 12.3% 5,416$ 9.8% 1,211$ 5 12.3% 5,869$ 9.8% 1,144$ 6 12.3% 5,924$ 9.8% 1,144$ 7 12.3% 5,737$ 9.8% 1,218$ 8 12.3% 5,820$ 9.8% 1,075$ 9 12.3% 5,672$ 9.8% 1,079$

10 12.3% 5,759$ 9.8% 1,152$ 11 12.3% 5,791$ 9.8% 1,082$ 12 12.3% 5,836$ 9.8% 1,156$ 13 12.3% 5,903$ 9.8% 1,164$ 14 12.3% 5,382$ 9.8% 1,277$ 15 12.2% 5,668$ 9.8% 1,170$ 16 12.2% 5,501$ 9.8% 1,098$ 17 12.2% 5,646$ 9.8% 1,177$ 18 12.2% 5,554$ 9.8% 1,109$ 19 12.2% 5,415$ 9.8% 1,193$ 20 12.2% 5,543$ 9.8% 1,126$ 21 12.2% 5,599$ 9.8% 1,149$ 22 12.2% 5,479$ 9.8% 1,155$ 23 12.2% 5,387$ 9.8% 1,163$ 24 12.2% 5,539$ 9.8% 1,165$ 25 12.2% 4,975$ 9.8% 1,247$


Page 1 of 2


Exhibit:B-7



2.10.4 For the < 150 kW accounts, please list:

2.10.4.2 The top 25 accounts impacted in dollar values from both the negative and positive range for F2011 and provide their respective bill impacts in percentage terms.

RESPONSE:

Please refer to the F2011 bill impacts, relative to F2010 bill impacts, in the table below. In this case the 25 accounts with the largest and smallest dollar increase are shown.

BC Hydro notes that the assumed F2011 CARC is 10.6 per cent.


Page 2 of 2


Exhibit:B-7

Top F2011 $ Impacts Lowest F2011 $ ImpactsAnnual $ Increase % Increase


1 6,101$ 12.3% 127$ 10.0%2 6,033$ 12.4% 119$ 9.8%3 5,924$ 12.3% 115$ 9.8%4 5,903$ 12.3% 115$ 9.9%5 5,869$ 12.3% 113$ 9.9%6 5,836$ 12.3% 112$ 9.8%7 5,820$ 12.3% 109$ 10.0%8 5,791$ 12.3% 107$ 10.0%9 5,777$ 12.4% 106$ 10.3%

10 5,759$ 12.3% 97$ 9.9%11 5,737$ 12.3% 94$ 10.0%12 5,672$ 12.3% 93$ 9.8%13 5,668$ 12.2% 89$ 10.0%14 5,646$ 12.2% 88$ 9.9%15 5,599$ 12.2% 87$ 9.9%16 5,554$ 12.2% 84$ 9.8%17 5,543$ 12.2% 82$ 9.9%18 5,539$ 12.2% 80$ 9.8%19 5,504$ 12.2% 75$ 9.9%20 5,501$ 12.2% 73$ 10.1%21 5,479$ 12.2% 69$ 9.9%22 5,436$ 12.2% 68$ 9.9%23 5,416$ 12.3% 67$ 10.2%24 5,415$ 12.2% 63$ 9.9%25 5,410$ 12.2% 62$ 9.9%


Page 1 of 3


Exhibit:B-7



2.10.5 Please provide the cumulative impact from F2011 to F2016 for the impacted MGS accounts in the previous two IRs.

RESPONSE:

Refer to the tables below for the F2011 and cumulative F2011 to F2016 bill impacts in both percentage and dollar form over the forecast period.


Page 2 of 3


Exhibit:B-7

Table 1 Accounts with highest and lowest F2011 percentage bill impacts





2011 to 2016 $ Increase

1 12.41% 5,777$ 106% 49,251$ 9.78% 1,062$ 20% 2,152$

2 12.38% 6,033$ 103% 50,167$ 9.78% 1,133$ 20% 2,297$

3 12.32% 6,101$ 103% 50,892$ 9.78% 1,134$ 20% 2,298$

4 12.30% 5,416$ 100% 44,193$ 9.78% 1,211$ 20% 2,455$

5 12.29% 5,869$ 102% 48,567$ 9.78% 1,144$ 20% 2,319$

6 12.29% 5,924$ 102% 48,998$ 9.78% 1,144$ 20% 2,319$

7 12.28% 5,737$ 102% 47,436$ 9.78% 1,218$ 20% 2,468$

8 12.28% 5,820$ 101% 48,087$ 9.78% 1,075$ 20% 2,178$

9 12.28% 5,672$ 101% 46,845$ 9.78% 1,079$ 20% 2,187$

10 12.28% 5,759$ 101% 47,528$ 9.78% 1,152$ 20% 2,335$

11 12.27% 5,791$ 101% 47,774$ 9.78% 1,082$ 20% 2,193$

12 12.27% 5,836$ 101% 48,121$ 9.78% 1,156$ 20% 2,342$

13 12.27% 5,903$ 101% 48,661$ 9.78% 1,164$ 20% 2,359$ 14 12.25% 5,382$ 100% 44,147$ 9.78% 1,277$ 20% 2,589$

15 12.25% 5,668$ 100% 46,434$ 9.78% 1,170$ 20% 2,371$

16 12.24% 5,501$ 100% 44,952$ 9.78% 1,098$ 20% 2,225$

17 12.23% 5,646$ 100% 46,123$ 9.78% 1,177$ 20% 2,386$

18 12.23% 5,554$ 100% 45,340$ 9.78% 1,109$ 20% 2,248$

19 12.22% 5,415$ 100% 44,136$ 9.78% 1,193$ 20% 2,417$

20 12.22% 5,543$ 100% 45,167$ 9.78% 1,126$ 20% 2,281$

21 12.22% 5,599$ 99% 45,539$ 9.78% 1,149$ 20% 2,328$

22 12.21% 5,479$ 99% 44,525$ 9.78% 1,155$ 20% 2,340$

23 12.21% 5,387$ 99% 43,777$ 9.78% 1,163$ 20% 2,355$

24 12.21% 5,539$ 99% 44,973$ 9.78% 1,165$ 20% 2,360$ 25 12.21% 4,975$ 97% 39,697$ 9.78% 1,247$ 20% 2,524$


Page 3 of 3


Exhibit:B-7

Table 2 Accounts with highest and lowest F2011 $ bill impacts

Top F2011 $ Impacts Cumulative Impacts Lowest F2011 $ Impacts Cumulative ImpactsAnnual $ Increase % Increase




1 6,101$ 12.3% 50,892$ 102.8% 127$ 10.0% 342$ 26.9%

2 6,033$ 12.4% 50,167$ 103.0% 119$ 9.8% 258$ 21.2%

3 5,924$ 12.3% 48,998$ 101.6% 115$ 9.8% 256$ 21.9%

4 5,903$ 12.3% 48,661$ 101.2% 115$ 9.9% 266$ 22.8%

5 5,869$ 12.3% 48,567$ 101.7% 113$ 9.9% 276$ 24.1%

6 5,836$ 12.3% 48,121$ 101.2% 112$ 9.8% 247$ 21.6%

7 5,820$ 12.3% 48,087$ 101.5% 109$ 10.0% 295$ 27.1%

8 5,791$ 12.3% 47,774$ 101.3% 107$ 10.0% 287$ 26.9%

9 5,777$ 12.4% 49,251$ 105.8% 106$ 10.3% 390$ 38.0%

10 5,759$ 12.3% 47,528$ 101.3% 97$ 9.9% 223$ 22.6%

11 5,737$ 12.3% 47,436$ 101.6% 94$ 10.0% 250$ 26.7%

12 5,672$ 12.3% 46,845$ 101.4% 93$ 9.8% 203$ 21.6%

13 5,668$ 12.2% 46,434$ 100.3% 89$ 10.0% 227$ 25.4%14 5,646$ 12.2% 46,123$ 100.0% 88$ 9.9% 223$ 25.2%

15 5,599$ 12.2% 45,539$ 99.4% 87$ 9.9% 206$ 23.3%

16 5,554$ 12.2% 45,340$ 99.8% 84$ 9.8% 187$ 21.9%

17 5,543$ 12.2% 45,167$ 99.6% 82$ 9.9% 185$ 22.1%

18 5,539$ 12.2% 44,973$ 99.1% 80$ 9.8% 177$ 21.9%

19 5,504$ 12.2% 44,581$ 98.8% 75$ 9.9% 173$ 22.9%

20 5,501$ 12.2% 44,952$ 100.0% 73$ 10.1% 210$ 28.8%

21 5,479$ 12.2% 44,525$ 99.3% 69$ 9.9% 157$ 22.5%

22 5,436$ 12.2% 44,008$ 98.7% 68$ 9.9% 158$ 23.1%

23 5,416$ 12.3% 44,193$ 100.3% 67$ 10.2% 218$ 33.5%

24 5,415$ 12.2% 44,136$ 99.6% 63$ 9.9% 151$ 23.7%25 5,410$ 12.2% 43,389$ 97.5% 62$ 9.9% 141$ 22.3%


Page 1 of 1


Exhibit:B-7



2.10.6 Please provide the reference in the Application regarding dollar impact analysis.

RESPONSE:



Page 1 of 8


Exhibit:B-7

11.0 Reference: Average Electricity Rate Exhibit B-5, BCUC IR 1.21.1

2.11.1 Please recalculate Figure 3-4 at load factors ranging from 10% to 75% in 5% increments and use kWh as the x-axis for each of the following:

� Customers using 35 kW





RESPONSE:

Each chart below plots the relationship between the average rate and monthly energy use for a single load factor as described in the request.

Note that the line is an approximation of the rate function. The lines have been created by calculating the average rates for more than 40 usage levels, and then drawing a straight line to connect those points. An exact line would require the use of an infinite number of data points.


Page 2 of 8


Exhibit:B-7

70kW

35kW

150kW

250kW1,000kW

2,000kW

$0.040$0.050$0.060$0.070$0.080$0.090$0.100$0.110$0.120$0.130$0.140

1,000 10,000 100,000 1,000,000

Monthly Energy (kWh, log scale)

Ave

rage

Rat

e ($

/kW

h)

.

Load Factor: 10%

70kW

35kW

150kW

250kW1,000kW

2,000kW

$0.040

$0.050

$0.060

$0.070

$0.080

$0.090

$0.100

1,000 10,000 100,000 1,000,000


Ave

rage

Rat

e ($

/kW

h)

.

Load Factor: 15%


Page 3 of 8


Exhibit:B-7

70kW

35kW 150kW

250kW1,000kW

2,000kW

$0.040$0.045$0.050$0.055$0.060$0.065$0.070$0.075$0.080$0.085$0.090

1,000 10,000 100,000 1,000,000


Ave

rage

Rat

e ($

/kW

h)

.

Load Factor: 20%

70kW

35kW

150kW

250kW1,000kW

2,000kW

$0.040$0.045$0.050$0.055$0.060$0.065$0.070$0.075$0.080$0.085

1,000 10,000 100,000 1,000,000


Ave

rage

Rat

e ($

/kW

h)

. Load Factor: 25%


Page 4 of 8


Exhibit:B-7

70kW

35kW

150kW

250kW1,000kW

2,000kW

$0.040

$0.045$0.050

$0.055$0.060

$0.065

$0.070$0.075

$0.080

1,000 10,000 100,000 1,000,000 10,000,000


Ave

rage

Rat

e ($

/kW

h)

. Load Factor: 30%

70kW35kW

150kW

250kW1,000kW

2,000kW

$0.040

$0.045$0.050

$0.055$0.060

$0.065

$0.070$0.075

$0.080

1,000 10,000 100,000 1,000,000 10,000,000


Ave

rage

Rat

e ($

/kW

h)

. Load Factor: 35%


Page 5 of 8


Exhibit:B-7

70kW

35kW

150kW

250kW1,000kW

2,000kW

$0.040

$0.045

$0.050

$0.055

$0.060

$0.065

$0.070

$0.075

1,000 10,000 100,000 1,000,000 10,000,000


Ave

rage

Rat

e ($

/kW

h)

. Load Factor: 40%

70kW

35kW

150kW

250kW1,000kW

2,000kW

$0.040

$0.045

$0.050

$0.055

$0.060

$0.065

$0.070

$0.075

1,000 10,000 100,000 1,000,000 10,000,000


Ave

rage

Rat

e ($

/kW

h)

. Load Factor: 45%


Page 6 of 8


Exhibit:B-7

70kW

35kW

150kW

250kW1,000kW

2,000kW

$0.040

$0.045

$0.050

$0.055

$0.060

$0.065

$0.070

$0.075

1,000 10,000 100,000 1,000,000 10,000,000


Ave

rage

Rat

e ($

/kW

h)

. Load Factor: 50%

70kW

35kW

150kW

250kW1,000kW

2,000kW

$0.040

$0.045

$0.050

$0.055

$0.060

$0.065

$0.070

$0.075

1,000 10,000 100,000 1,000,000 10,000,000


Ave

rage

Rat

e ($

/kW

h)

. Load Factor: 55%


Page 7 of 8


Exhibit:B-7

70kW

35kW

150kW

250kW1,000kW

2,000kW

$0.040

$0.045

$0.050

$0.055

$0.060

$0.065

$0.070

1,000 10,000 100,000 1,000,000 10,000,000


Ave

rage

Rat

e ($

/kW

h)

. Load Factor: 60%

70kW

35kW

150kW

250kW1,000kW

2,000kW

$0.040

$0.045

$0.050

$0.055

$0.060

$0.065

$0.070

1,000 10,000 100,000 1,000,000 10,000,000


Ave

rage

Rat

e ($

/kW

h)

. Load Factor: 65%


Page 8 of 8


Exhibit:B-7

70kW

35kW

150kW

250kW1,000kW

2,000kW

$0.040

$0.045

$0.050

$0.055

$0.060

$0.065

1,000 10,000 100,000 1,000,000 10,000,000


Ave

rage

Rat

e ($

/kW

h)

. Load Factor: 70%

70kW

35kW

150kW

250kW1,000kW

2,000kW

$0.040

$0.045

$0.050

$0.055

$0.060

$0.065

1,000 10,000 100,000 1,000,000 10,000,000


Ave

rage

Rat

e ($

/kW

h)

. Load Factor: 75%


Page 1 of 1


Exhibit:B-7

12.0 Reference: Two-part Rate Threshold Exhibit B-5, BCUC IR 1.21.2

2.12.1 Please repeat the table in Response to BCUC IR 1.21.2 at a threshold of (a) 500 kW and (b) 1000 kW.

RESPONSE:

The tables below show BC Hydro estimates of the net conservation expected for the MGS and LGS classes between F2011 and F2015 using segmentations between LGS and MGS of 500 kW and 1,000 kW. All values shown are in GWh.

Fiscal Year MGS LGS Total MGS LGS Total2011 6 131 137 11 80 91 2012 44 474 518 78 289 367 2013 81 853 934 141 518 659 2014 132 1,083 1,215 228 657 885 2015 196 1,296 1,492 342 784 1,126

Rates with 500 kW SegmentationBC Hydro Application

Fiscal Year MGS LGS Total MGS LGS Total2011 6 131 137 14 55 69 2012 44 474 518 98 200 298 2013 81 853 934 178 358 537 2014 132 1,083 1,215 288 454 743 2015 196 1,296 1,492 393 542 935

Rates with 1000 kW SegmentationBC Hydro Application

Note that this information is also shown in the response to BCUC IR 2.1.2.2, and is shown in Scenarios LGS 18 and 19 in the response to BCUC IR 2.1.2.


Page 1 of 1


Exhibit:B-7

13.0 Reference: Billing Baseline Loads Exhibit B-5, BCUC IR 1.23.1.1

2.13.1 Please comment if the methodology for determining BBLs in other billing processes (e.g., Step-1 block for RIB rate) has encounter any significant difficulties in customer understanding and acceptance. If so, please describe the difficulties and how they are resolved.

RESPONSE:

Billing Baselines (BBLs) are unique to the proposed LGS rate.

However, as noted in the response to BCUC IR 1.23.1.1, BC Hydro currently calculates daily amounts in numerous billing situations. For example, the proposed BBL methodology is the calculation required when a rate change or a tax change occurs in the middle of a billing period. In this situation, BC Hydro calculates the daily consumption for the billing period and apportions this daily amount to the appropriate number of days before or after the change. In a similar manner, customers’ billing periods will typically straddle more than one calendar month and the HBLs for the calendar months involved will have to be appropriately apportioned to create the BBL for that billing period.

As noted above, the daily amount calculation is a common practice at BC Hydro as well as other utilities. BC Hydro has not encountered any significant difficulties in customer understanding and acceptance of daily amount calculations.


Page 1 of 1


Exhibit:B-7

14.0 Reference: HBL Exhibit B-5, BCUC IR 1.22.1; BC Ferries IR 1.3.1 Three Year Rolling Averages

2.14.1 Please confirm if F2010 YTD (August 2009) means that it has six months of data. If not, please provide the number of months.

RESPONSE:

Values in the rows labeled “F2010 YTD (August 2009)” are based on the most recent F2010 data available at the time the IR response was completed. Most accounts had at least five months of data in the calculation of the average consumption (April 2009 to August 2009 inclusive).


Page 1 of 1


Exhibit:B-7



2.14.1.1 Since the data for F2010 for the table ‘Average ELGS Monthly kWh per Account’ is monthly average, does it mean that the full year F2010 figure could be higher or lower that 50,416?

RESPONSE:

Yes.


Page 1 of 1


Exhibit:B-7



2.14.1.2 Is the data for F2010 for the table ‘Average ELGS Annual kWh per Account’ on an annualized basis? If not, please provide the annualized figure.

RESPONSE:

The F2010 YTD annual consumption figures presented in the response to BCUC IR 1.22.1 are based on a linear extrapolation of the average monthly consumption F2010 YTD data. The annualized figure, shaped by monthly load, is 52,446 kWh/month (629,352 kWh /year).


Page 1 of 1


Exhibit:B-7


2.14.2 BC Hydro response to BC Ferries IR 1.3.1 states that “establishing initial baselines using the average of calendar 2005, 2006 and 2007 results in 54 percent of accounts having a higher initial HBL than using F2009 to set initial baselines”.

2.14.2.1 Are only a handful of accounts responsible for the 9.0% decline in F2008 from the F2005-F2007 three-year average?

RESPONSE:

The F2008 average kWh per account in the response to BCUC IR 1.22.1 was based on billing data that was unadjusted for partial billing history. Using that billing data overstates the decline in F2008 consumption.

Using billing data that is adjusted for partial billing history, the F2008 average kWh per account differs from the average F2005 to F2007 consumption by -2 per cent, which is substantially lower than the 9 per cent decline shown in the response to BCUC IR 1.22.1.

In this case, an errata to BCUC IR 1.22.1 has been issued, and the revised tables are as follows:

Average Monthly kWh per account Year >= 150 kW < 150 kW TotalF2005 160,700 19,001 54,768F2006 161,428 19,002 54,472F2007 160,935 19,163 54,135F2008 159,112 19,240 53,491F2009 154,091 19,081 52,144F2010 YTD (August 2009) 149,326 18,004 50,416

Average Annual KWh per account Year >= 150 kW < 150 kW TotalF2005 1,928,404 228,009 657,221 F2006 1,937,141 228,029 653,660 F2007 1,931,223 229,957 649,622 F2008 1,909,343 230,878 641,893 F2009 1,849,093 228,966 625,725 F2010 YTD (August 2009) 1,791,918 216,048 604,993


Page 1 of 2


Exhibit:B-7


2.14.2 BC Hydro response to BC Ferries IR 1.3.1 states that “establishing initial baselines using the average of calendar 2005, 2006 and 2007 results in 54 percent of accounts having a higher initial HBL than using F2009 to set initial baselines”.

2.14.2.2 The frequency distribution of energy sales for F2009 are shown in the Response to BCUC IR 1.12.1, can BC Hydro provide more details as to which group of accounts compose of the biggest decline in average monthly sales indicated in the Response to BC Ferries IR 1.3.1 ?

RESPONSE:

Please refer to the following table for some characteristics of the 100 accounts with the largest percentage decline in usage between the proposed initial baseline (average of calendar 2005 to 2007) and F2009 compared to the proposed LGS class, by site type.


Page 2 of 2


Exhibit:B-7

100 accounts with largest % decline in kWh LGS class

Site Types

Number of

accounts

Largest %

declinefor a

singleaccount

Average % decline for

topaccounts

% of all LGS accounts

Average % change in

kWh

Chemical - Other 3 -52% -48% 1.5% -5%

Food & Beverages 4 -73% -47% 4.9% 2%

Health Services 1 -42% -42% 0.6% 2%

Heavy Manufacturing 7 -98% -62% 5.3% -2%

Hotels 1 -41% -41% 4.8% 3%

Industrial - Other 2 -55% -48% 4.3% 3%

Light Manufacturing 13 -92% -52% 5.0% 0%

Municipal Pumping 2 -67% -62% 2.5% 0%

Non-Food Retail 4 -78% -53% 9.3% -3%

Offices 10 -75% -46% 16.7% 0%

Other Commercial 4 -73% -52% 8.4% 1%

Public School 2 -80% -64% 6.2% -1%

Transportation 2 -76% -59% 3.8% 4%

Warehouses 3 -59% -45% 3.2% 3%

Wood - Lumber 16 -90% -56% 2.1% -16%

Wood - Other 22 -88% -54% 4.0% -11%

Wood - Panel 4 -75% -52% 0.3% -20%

Total 100 83%*

* Does not add to 100 per cent due to other site types not represented in the “100 accounts …” column.

The sample used for this specific IR response is based on accounts with complete billing data for F2007, F2008, F2009, and F2010 YTD (total of 4396 accounts).


Page 1 of 1


Exhibit:B-7

15.0 Reference: 2008 FACOS Exhibit B-5 BCUC IR 1.38.1; BCOAPO IR 1.11.1 Segmentation

2.15.1 Please provide the Fully Allocated Cost of Service (FACOS) Study that Dr. Orans relied on in Appendix J to explore segmentation.

RESPONSE:

Attached is the F2008 FACOS study that was used by Dr. Orans for his analysis in Appendix J.

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Page 1 of 1


Exhibit:B-7

16.0 Reference: LGS Bill Volatility Exhibit B-5, BCUC IR 1.42.3 Anomalies

2.16.1 Please provide details as to the percentage of customers who will receive anomaly adjustments to baselines.

RESPONSE:

BC Hydro estimates that two per cent of bills or about 15 per cent of LGS accounts would receive anomaly adjustments per year.


Page 1 of 1


Exhibit:B-7

17.0 Reference: Models Methodologies and Compliance Filings Exhibit B-5, BCUC IR 1.48.2

2.17.1 In addition to the spreadsheet models in the response to BCUC IR 1.30.1 and Sections 6.1 and 6.2 in Appendix N on Compliance Filing, please include any additional information that would bolster BC Hydro’s case and would be helpful for the Commission Panel to demonstrate what are being approved in the Order as a result of this Application?

RESPONSE:

In the absence of a specific question or concern, BC Hydro is unable to provide more information that would bolster its case, or allow for a more specific draft order.

Since the 2007 RDA decision BC Hydro has made significant investments in developing its internal rate design resources and in retaining external rate design expertise. A great deal of that investment has been deployed in this LGS application. In BC Hydro's view the result is an application that represents a high-water mark in British Columbia for rate design applications in terms of innovation; quantitative modelling; and implementation detail.

Regarding modelling and implementation detail, BC Hydro submits that no rate design application has been filed with the BCUC that is as comprehensive as the LGS Rate Application. None of BC Hydro's RIB, TSR, 2007 RDA, or Real-Time Pricing rate applications have come close to providing as much information as this application on how a proposed rate design would work, and affect BC Hydro and its customers; conversely, the elements of those applications that were approved through BCUC orders were approved by orders with a similar degree of specificity as the draft orders attached at Appendices R, S and T. A good example is BCUC Order No. G-130-07, regarding the 2007 RDA, attached.

SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, B.C. V6Z 2N3 CANADA

web site: http://www.bcuc.com

TELEPHONE: (604) 660-4700 BC TOLL FREE: 1-800-663-1385

FACSIMILE: (604) 660-1102

…/2

BRITISH COLUMBIAUTILITIES COMMISSION

ORDER NUMBER G-130-07

IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473

and

An Application by British Columbia Hydro and Power Authority 2007 Rate Design (“2007 RDA”) Phase I

BEFORE: A.J. Pullman, Panel Chair R.J. Milbourne, Commissioner October 26, 2007 L.A. O’Hara, Commissioner

O R D E R WHEREAS:

A. British Columbia Hydro and Power Authority (“BC Hydro”) filed on March 15, 2007, pursuant to the Utilities Commission Act (“the Act”) and Commission Order No. G-148-06, the 2007 Rate Design Application (“Application”) to update BC Hydro’s rates and terms and conditions of service; and

B. The Application addresses rate rebalancing, rate restructuring, changes to the E-Plus rates, General Service rates, and amendments to its Terms and Conditions of Service, including the distribution extension policy. On May 8, 2007, the Commission established an oral public hearing process for the review of the Application by Order No. G-50-07 (Exhibit A-4); and

C. Central Coast Power Corporation (“CCPC”) is an Independent Power Producer (“IPP”) in the Non-Integrated Area (“NIA”) whose Energy Purchase Contract with BC Hydro was the subject of Information Requests and a motion by a Registered Intervenor, the Heiltsuk Tribal Council/Shearwater Marine Ltd. (“Heiltsuk”). On July 3, 2007, the Commission issued Commission Letter No. L-57-07 to inform all Parties that the Commission would hear the motion from Heiltsuk immediately following the Opening Statement of the Panel Chair; and

D. The Commission Panel Hearing Issues List was issued on July 6, 2007 (Exhibit A-23). Items No. 6 and 7 on the Issues List related to “NIA – Zone II rates” and the “Bella Bella NIA” and were identified in the cover letter as subject to the Commission Panel’s determination on the motions then before the Panel; and

E. By letter dated July 6, 2007, BC Hydro submitted its compliance filings on interruptible rates to IPPs serving Zone II customers for the period commencing July 1, 2007 and ending June 30, 2008 (Exhibit A2-3); and

F. The public hearing commenced on July 9, 2007 in Vancouver; and

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…/3



G. By letter dated July 11, 2007, BC Hydro filed with the Commission a proposal that the F2006 Zone II Special Contract rate of $0.1769 per kWh effective June 1, 2006 continue for the contract year beginning June 1, 2007 on an interim (refundable) basis (Exhibit B-37); and

H. By letters dated July 16, 2007, Heiltsuk filed two complaints with the Commission. One complaint was made pursuant to Commission Order No. G-30-02 and another complaint was made pursuant to Section 25 of the Act (respectively Exhibit C23-14 and Exhibit C23-15); and

I. On July 17, 2007, the Commission Panel made the determination that the Application would be heard in three phases. Phase I would cover the issues in Items No. 1 to 5 of the Issues List; Phase II would cover issues in Items No. 6 and 7 of the Issues List; and Phase III would cover the BC Hydro Special Contract rates (T8: 1331-1333 and T10: 1646-1648). The Commission Panel’s determinations were set out in Commission Order No. G-84-07 dated July 27, 2007 (Exhibit A-25) and Commission Order No. G-97-07 dated August 20, 2007 (Exhibit A-30); and

J. Subject to the filing of certain outstanding information requests, the evidentiary phase of Phase I of the proceeding closed on July 19, 2007. The Panel Chair established a schedule for final argument which provided that BC Hydro file its Final Argument on August 3, 2007, Intervenors file their Arguments on August 17, 2007, and BC Hydro file its Reply Argument on August 24, 2007; and

K. On September 19, 2007 the Commission issued interim Order No. G-111-07 regarding FACOS and Rate Schedules to ensure that the Rate Schedules resulting from its Decision can be in place by April 1, 2008; and

L. The Commission Panel has reviewed the evidence and arguments submitted for this proceeding, and issues its Decision with respect to the Phase I issues.

NOW THEREFORE the Commission for the Reasons stated in the Decision issued concurrently with this Order, orders that:

1. The Commission interim orders that are the subject matter of Order No. G-111-07 are confirmed as final.

2. BC Hydro comply with all the directives of the Commission in the Decision, including those directives that are the subject matter of Order No. G-111-07.

3. BC Hydro’s proposed changes to its Residential Rate Schedules identified in Section 4.1.4 of the Decision are approved.

4. BC Hydro’s rebalancing proposal and the resultant proposed increase of one percent and a decrease of 5.2 percent to BC Hydro’s Residential and Small General Service Rate Schedules, respectively are denied.

5. BC Hydro’s application to amend Rate Schedules 1105, 1205, 1206 and 1207 to restrict transfer of service is approved. The application to otherwise amend Rate Schedules 1105, 1205, 1206 and 1207 is denied.

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3

Orders/G-130-07_BCH_2007RD Phase 1 Decision



6. BC Hydro’s proposal to eliminate Rate Schedules 1222 and 1223 is approved.

7. BC Hydro’s proposed changes in respect of the Basic Charge and minimum charge on the Small General Service rate is approved.

8. BC Hydro’s proposal to create Rate Schedule 1402 is approved.

9. BC Hydro’s proposal to increase the rates to its Irrigation customers is denied.

10. BC Hydro’s proposal to eliminate Rate Schedules 1761 and 1770 is approved.

11. BC Hydro’s proposed SET policy is not approved. The allocation methodology to be applied to the SET policy is 65 percent demand/35 percent customer based on 20 years using BC Hydro’s nominal weighted average cost of capital of 8 percent. BC Hydro is to recalculate its allowance levels in Table 5-1 of the Decision and file the recalculated allowance levels within 60 days of this Order issued concurrently with the Decision.

12. BC Hydro’s proposal to charge the customer the lower of the extension charge under its existing SET Policy and the above extension policy from April 1, 2008 until June 30, 2008, is approved.

13. BC Hydro’s proposed Service Connection Charge Schedule is approved.

14. Subject to paragraphs 11, 12 and 13 of this Order, BC Hydro’s proposed changes to the Terms and Conditions of its Electric Tariff identified in Section 5 of the Decision are approved.

DATED at the City of Vancouver, in the Province of British Columbia, this 26th day of October 2007.

BY ORDER

Original signed by:

A.J. Pullman Panel Chair

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Dec 21st, 2009

To: Ms. Joanna Sofield Chief Regulator Officer BC Hydro 333 Dunsmuir St. Vancouver BC V6B 5R3

Information request #2 As an Intervener in the British Columbia Hydro and Power Authority Project No. 3698573/Order G-125-09 Large General Service Rate Application BC Ferries submits the following; Chapter 2 Direct Testimony of Lisa Coltart.

1.2.1 Why is there no inclusion for reduced rates for off peak demand and consumption?

REF 1.2.1BC Hydro's proposals do not provide for off-peak rates because BC Hydro does not currently meter ELGS customers on an interval basis that would allow such rates to be charged or enforced. With the advent of smart metering in the next few years, it is likely that such rate designs will be developed. In the meantime, BC Hydro believes that it must proceed with the development of energy conservation rates for its ELGS customers, for the reasons set out in the Direct Testimony of Lisa Coltart, section 2.2 of the Application.

Are you stating it is technically impossible at this time to introduce interval metering to ELGS customers due to a lack of available metering systems? We believe this would be a false statement and that BC Hydro is simply choosing to exclude this provision at this time. With the proposed schedule for implementation of the new rate structure, the metering replacement process could be progressing adequately to allow for this inclusion prior to 2010/2011. We ask that interval metering with reduced rates for off peak usage be added to this application and that the off peak rate directly reflect the actual value of that power as determined by BC Hydro. This will encourage the shifting of load to off peak where possible and cost effective.

REF 1.7.2.13.) a- We have been introducing new vessels into service in the last couple of years and encouraging the use of shore power (BC Hydro provided power.) to reduce fuel consumption and to reduce harmful emissions. This has resulted in our overall load being at its highest level historically. “Historical Baselines” (HBLs) should be based on the most recent and/or highest years of consumption. If particular years are being used (2005 to 2007) based on specific industry preferences due to those years having their highest consumption, then all customers “Historical Baselines” should be determined using the 3 years with their highest consumption. One customer should not be penalized for the benefit of another.

b- Could a variance process be included for unusual circumstances where load and consumption change dramatically throughout the year?

RESPONSE:

C8-3� BC�HYDRO��

��LGS�RATE��EXHIBIT��

Generally, BC Hydro agrees that the most appropriate method for establishing an account’s baseline is one based on an average of historical consumption from the most recent three years, and this is a key element of BC Hydro’s proposed LGS rate (described in Chapter 3, A22, pages 3-18 through 3-20). However, during the consultation process, a common customer concern raised was that early-year baselines would be low as a result of the current economic downturn, and not be representative of accounts’ normal operating levels. Please see Appendix F (pages 11 through 18 of 20) for a summary of customer feedback on the LGS rate during consultation. Therefore, in direct response to customer concerns BC Hydro’s application recommends using a pre-recessionary time period to establish initial year HBLs as a transitional feature of the design. The selection of calendar 2005, 2006 and 2007, versus a more recent period, is expected to result in higher initial HBLs for the majority of customers. This is estimated shown by the following statistics, where F2009 was used as a proxy for more recent consumption data: Establishing initial baselines using the average of calendar 2005, 2006 and 2007 results in 54 per cent of accounts having a higher initial HBL than using F2009 to set initial baselines; and The combined total of all HBLs across the class calculated using the average of calendar 2005, 2006 and 2007 are about 3.5 per cent higher than what the total would be using F2009 data as the basis. Regardless of time period used to establish HBLs, LGS Part 1 rates would be adjusted to account for revenue differences between class-aggregated HBLs and forecast load, to maintain revenue neutrality. To the extent customers could choose their initial HBLs BC Hydro would earn lower revenues, requiring larger increases to the Part 1 energy rate.

Regardless of the 2005 to 2007 data resulting in 54% of accounts having higher baselines one customer should not be penalized for the benefit of another. We ask that the 2007, 08, 09, and possibly 2010 data be included in the initial baseline calculation for BC Ferries accounts as this is the most up to date energy consumption data and suggest this method would be the least prejudicial to all customers. If data from 2005 to 2007 is to be used it would follow that data for the baseline should always remain 2 to 3 years out of date to support this rational, not just a one time deal to appease selected customers.

1.20.5 During the customer consultations, has the ability to aggregate ELGS accounts for the purpose of calculating HBLs been raised? Will BC Hydro propose that customers who hold more than one LGS account be allowed to aggregate HBLs?

RESPONSE: Yes, the ability to aggregate ELGS accounts for the purpose of calculating HBLs was raised during customer consultations. No, BC Hydro is not proposing that customers who hold more than one LGS account be allowed to aggregate their HBLs. Based on BC Hydro’s review, there does not appear to be sufficient DSM or self generation opportunities evident at this time that might arise from an aggregation option to justify the system and process changes that would be required to accommodate an “automated” system solution. As well, BC Hydro feels that allowing aggregation introduces the opportunity for

customers to self-select an aggregated HBL that will minimize their exposure to the LRMC-based Part 2 rate. BC Hydro does not intend that the amount of LRMC-based Part 2 energy should be at the discretion of the customer. Finally, LGS account aggregation is not feasible or practical from a metering and billing perspective. Current metering and read date practices for LGS customers are not able to support aggregation. All LGS accounts are not currently required to have advanced meters (unlike transmission customers). BC Hydro is uncertain whether and at what cost its systems could accommodate an “automated” solution for account aggregation.

As per your response above, aggregating accounts would not allow the customer to self-select an aggregated HBL unless BC Hydro was to design that possibility into the rate structure process. Where aggregating would benefit BC Ferries Services Inc. is to allow our large loads (Ships) to move from one account to another without a large cost implication as our overall power consumption would not change. This should be a fairly simple capability for a computerized accounting and invoicing system.

Doug Peabody Energy Manager, Terminal Maintenance British Columbia Ferries Services Inc.

Tel: (250) 756-5716 Cell: (250) 756-5716 Fax: (250) 753-1186 Mail to: [email protected]

BC FerriesInformation Request No. 2.1.1 Dated: December 21, 2009British Columbia Hydro & Power Authority Response issued January 22, 2010

Page 1 of 1


Exhibit:B-7

2.1.0 REF 1.2.1

Why is there no inclusion for reduced rates for off peak demand and consumption?

BC Hydro's proposals do not provide for off-peak rates because BC Hydro does not currently meter ELGS customers on an interval basis that would allow such rates to be charged or enforced. With the advent of smart metering in the next few years, it is likely that such rate designs will be developed. In the meantime, BC Hydro believes that it must proceed with the development of energy conservation rates for its ELGS customers, for the reasons set out in the Direct Testimony of Lisa Coltart, section 2.2 of the Application.

2.1.1 Are you stating it is technically impossible at this time to introduce interval metering to ELGS customers due to a lack of available metering systems? We believe this would be a false statement and that BC Hydro is simply choosing to exclude this provision at this time. With the proposed schedule for implementation of the new rate structure, the metering replacement process could be progressing adequately to allow for this inclusion prior to 2010/2011. We ask that interval metering with reduced rates for off peak usage be added to this application and that the off peak rate directly reflect the actual value of that power as determined by BC Hydro. This will encourage the shifting of load to off peak where possible and cost effective.

RESPONSE:

The focus of BC Hydro’s LGS rate application is on restructuring default rates for ELGS customers with the main objective of encouraging energy conservation. Time-differentiated rates have a different focus - encouraging customers to shift consumption to off-peak periods.

BC Hydro plans to apply to the BCUC for time-differentiated rates in the future to complement default conservation rates, following thorough rate design and customer consultation efforts. The implementation of time-differentiated rates also requires as a prerequisite that advanced metering infrastructure and meter data management systems be in place and fully operational. Based on current timelines related to these activities, BC Hydro expects to file a time-differentiated rate application in the fall of 2012.


Page 1 of 2


Exhibit:B-7

2.2.0 REF 1.7.2.1

a- We have been introducing new vessels into service in the last couple of years and encouraging the use of shore power (BC Hydro provided power.) to reduce fuel consumption and to reduce harmful emissions. This has resulted in our overall load being at its highest level historically. “Historical Baselines” (HBLs) should be based on the most recent and/or highest years of consumption. If particular years are being used (2005 to 2007) based on specific industry preferences due to those years having their highest consumption, then all customers “Historical Baselines” should be determined using the 3 years with their highest consumption. One customer should not be penalized for the benefit of another.

b- Could a variance process be included for unusual circumstances where load and consumption change dramatically throughout the year?

RESPONSE: Generally, BC Hydro agrees that the most appropriate method for establishing an account’s baseline is one based on an average of historical consumption from the most recent three years, and this is a key element of BC Hydro’s proposed LGS rate (described in Chapter 3, A22, pages 3-18 through 3-20). However, during the consultation process, a common customer concern raised was that early-year baselines would be low as a result of the current economic downturn, and not be representative of accounts’ normal operating levels. Please see Appendix F(pages 11 through 18 of 20) for a summary of customer feedback on the LGS rate during consultation. Therefore, in direct response to customer concerns BC Hydro’s application recommends using a pre-recessionary time period to establish initial year HBLs as a transitional feature of the design. he selection of calendar 2005, 2006 and 2007, versus a more recent period, is expected to result in higher initial HBLs for the majority of customers. This is estimated shown by the following statistics, where F2009 was used as a proxy for more recent consumption data: Establishing initial baselines using the average of calendar 2005, 2006 and 2007 results in 54 per cent of accounts having a higher initial HBL than using F2009 to set initial baselines; and The combined total of all HBLs across the class calculated using the average of calendar 2005, 2006 and 2007 are about 3.5 per cent higher than what the total would be using F2009 data as the basis. Regardless of time period used to establish HBLs, LGS Part 1 rates would be adjusted to account for revenue differences between class-aggregated HBLs and forecast load, to maintain revenue neutrality. To the extent customers could choose their initial HBLs BC Hydro would earn lower revenues, requiring larger increases to the Part 1 energy rate.

2.2.1 Regardless of the 2005 to 2007 data resulting in 54% of accounts having higher baselines one customer should not be penalized for the benefit of another. We ask that the 2007, 08, 09, and possibly 2010


Page 2 of 2


Exhibit:B-7

data be included in the initial baseline calculation for BC Ferries accounts as this is the most up to date energy consumption data and suggest this method would be the least prejudicial to all customers. If data from 2005 to 2007 is to be used it would follow that data for the baseline should always remain 2 to 3 years out of date to support this rational, not just a one time deal to appease selected customers.

RESPONSE:

BC Hydro did not propose to establish initial baselines via the method suggested in this information request because of the higher level of potential adjustment to Part 1 rates that would necessarily accompany it.

However, for the BCUC’s consideration, BC Hydro has included this rate design scenario (Scenario LGS 3) in its response to BCUC IR 2.1.2. Scenario LGS 3 would provide each LGS account that has adequate history with a formulaic initial year HBL that is the higher of either the three-year average of calendar 2005 to 2007 (BC Hydro’s proposed method for establishing initial HBLs) or a more recent three-year average. In all cases, initial year HBLs would still transition to a three-year rolling average method as proposed by BC Hydro in A33 of Sylvia von Minden’s testimony (pages 3-29 and 3-30 of the Application).

If the initial HBLs were to be established as modelled in Scenario LGS 3, BC Hydro estimates that Part 1 rates would be increased by about 1.5 per cent in F2011 relative to BC Hydro’s proposal (Scenario LGS 4).

BC Hydro’s proposed method to establish initial HBLs, using calendar 2005 to 2007 historical data, was based on broad feedback provided by customers during consultation regarding concerns about the impacts of the economic downturn, not feedback from a selected group of customers. BC Hydro’s proposed method does not have HBLs that remain “2 to 3 years out of date”; rather, BC Hydro proposes that initial HBLs transition to three-year rolling average HBLs.


Page 1 of 3


Exhibit:B-7

2.3.0 During the customer consultations, has the ability to aggregate ELGS accounts for the purpose of calculating HBLs been raised? Will BC Hydro propose that customers who hold more than one LGS account be allowed to aggregate HBLs?

RESPONSE: Yes, the ability to aggregate ELGS accounts for the purpose of calculating HBLs was raised during customer consultations. No, BC Hydro is not proposing that customers who hold more than one LGS account be allowed to aggregate their HBLs. Based on BC Hydro’s review, there does not appear to be sufficient DSM or self generation opportunities evident at this time that might arise from an aggregation option to justify the system and process changes that would be required to accommodate an “automated” system solution. As well, BC Hydro feels that allowing aggregation introduces the opportunity for customers to self-select an aggregated HBL that will minimize their exposure to the LRMC-based Part 2 rate. BC Hydro does not intend that the amount of LRMC-based Part 2 energy should be at the discretion of the customer. Finally, LGS account aggregation is not feasible or practical from a metering and billing perspective. Current metering and read date practices for LGS customers are not able to support aggregation. All LGS accounts are not currently required to have advanced meters (unlike transmission customers). BC Hydro is uncertain whether and at what cost its systems could accommodate an “automated” solution for account aggregation.

2.3.1 As per your response above, aggregating accounts would not allow the customer to self-select an aggregated HBL unless BC Hydro was to design that possibility into the rate structure process. Where aggregating would benefit BC Ferries Services Inc. is to allow our large loads (Ships) to move from one account to another without a large cost implication as our overall power consumption would not change. This should be a fairly simple capability for a computerized accounting and invoicing system.

RESPONSE:

As outlined in this information request, account aggregation would introduce the opportunity for customers to self-select an aggregated HBL that would arbitrage the difference between the LRMC-based and the Part 1 rates with no change in consumption. This would have revenue implications for BC Hydro and could shift costs to other customers. An example is shown below. In this instance aggregation would yield a financial advantage for the customer despite no change in consumption.


Page 2 of 3


Exhibit:B-7

Site 1 Site 2 Site 3 Total

HBL - MWh 100 100 100 300Actual Use - MWh 60 100 140 300

Change in consumption (40) 0 40 0

Part 2 (Credit)/Charge @ LRMC-based rate (20) 0 20 0Part 2 (Credit)/Charge @ Tier 1 or Tier 2 Energy rate (20) 0 20 0

With no aggregation, the total Part 2 (Credit)/Charge = 0

---------------------------------------------------------------------------------------------------------------------

Site 1 Site 2 Site 3 Total

HBL - MWh 100 100 100 300Actual Use - MWh 60 100 140 300

Change in consumption (40) 0 40 0

Part 2 (Credit)/Charge @ LRMC-based rate (40) 0 20 (20)Part 2 (Credit)/Charge @ Tier 1 or Tier 2 Energy rate 0 0 20 20

Total Part 2 (Credit)/Charge = Credit for 20 units at LRMC-based rate plus charge for 20 units at Part 1 rate… which is the same mathematically as:Total Part 2 (Credit)/Charge = Credit for 20 units at difference between LRMC-based rate and Part 1 rate

Aggregated

The following conclusions can be drawn from this example:

� The existence of Price Limit Bands creates an arbitrage opportunity for customers if account HBL aggregation were allowed.

o Aggregation would encourage customers to shift load to exceed the Price Limit Bands in order to achieve a financial benefit, even if there is no change in the overall consumption;

o Conversely, aggregation could work to customers’ detriment if aggregated accounts have increased consumption;

o Where customers cannot shift their loads to exceed the Price Limit Bands, there is no incentive to aggregate.


Page 3 of 3


Exhibit:B-7

If customers were allowed to rearrange the number of accounts included in their aggregation on an annual basis as is allowed in the TSR stepped rate, the opportunity for arbitrage increases significantly. Each year customers could move volume to accounts outside of the aggregation and therefore would be limited to an LRMC-based rate on just the first 20 per cent of the increase from baseline while receiving a LRMC-based credit for all reduced volume on the aggregated accounts.

Please also refer to BC Hydro’s response to JIESC IR 2.7.1 regarding the billing and system changes that would be required to allow account aggregation.

1

INFORMATION REQUEST: Round 2

TO: BC Hydro

APPLICATION: Large General Service Rate Application

FROM: BCOAPO et al.

DATE: December 22, 2009

________________________________________________________________

Question #1

Reference: BCUC 1.1.2; 1.1.3.1 and 1.1.3.2

1.1 Please confirm that the “With Rate Impact” forecasts are those prepared as part of the August 2009 Update.

1.2 Do the “With Rate Impact” projections include any impacts from rate design or just demand response due to revenue requirement rate changes?

1.3 If any rate design impacts were included, please confirm that the impacts been removed for purposes of modelling the implications of the current LGSR proposal.

Question #2

Reference: BCUC 1.2.2

2.1 Please respond to initial question’s request for an explanation as to “why the differing treatments are appropriate”.

Question #3


3.1 Is it BCH’s intent to use the price from the F2006 Call as the basis for the residential step 2 rate and the transmission tier 2 energy rate over the same 2011-2013 period? If not, why not?



2

Question #4


4.1 Please explain what is meant by the statement that “the majority of LGS accounts effectively see a flat average rate”. Also, please indicate the percentage of LGS accounts this entails and the percentage of LGS volumes (MWh) captured by these accounts.

Question #5


5.1 The response states that HBLs will be updated, at minimum, two times per year. Please explain why BCH is not proposing to standardize the frequency at which HBLs are updated.

5.2 Won’t updating HBLs to values other than those used when setting the rates for the year in question increase revenue variability?

Question #6


6.1 Please confirm that the unit cost quoted is just BCH’s unit cost for implementing the ELGS restructuring and does not include either a) the cost of Power Smart programs customers may participate in to achieve the savings or b) the costs customers may incur to achieve the savings.

Question #7

Reference: BCUC 1.42.2 and BCOAPO 1.2.1Application, page 1-16

7.1 Why is the potential “benefit” of an symmetric Anomaly Rule measured in terms of increased revenue to the class? Isn’t the objective/benefit to determine a more reasonable and typical baseline?

7.2 What is the lost revenue and lost conservation from the application of the proposed Anomaly rule?

3

Question #8

Reference: BCOAPO 1.21.1

8.1 The intent of the original question was to obtain the definition and source for the inflation measure that would be used (e.g., Is it BC inflation or Canada inflation? Is it CPI or some other measure? Is it forecast and, if so, what source?). Please provide a revised response.

Question #9

Reference: BCOAPO 1.22.4 and BCOPAO 1.23.1

9.1 Assuming the HBLs are adjusted in April of a given year, please explain fully what historical data (i.e., which months for the previous/current year) will be used in the calculation, when the calculation will actually be done and whether application of the revised HBLs will require adjusting previous bills (e.g. for the first few months after April 1st).

Question #10

Reference: BCOAPO 1.24.1 and 1.29.2

10.1 The referenced interrogatory response in BCOAPO 1.24.1 does not address the question of whether or not demand charges impact energy consumption/conservation. Please address this issue which is also raised in the last sentence in the response to BCOAPO 1.29.2.

Question #11

Reference: BCOAPO 1.34.2

11.1 Please confirm that the referenced response should be BCUC IR 1.27.4.

11.2 The first paragraph of the response suggests that elasticity increases as price increases. Does BCH/Dr. Orans have any evidence that this is the case?

4

Question #12

Reference: BCOAPO 1.36.3 and 1.35.2

12.1 Please confirm that, for modelling purposes, BCH has determined the revenue required from the MGS class by escalating the existing ELGS rates by the CARC adjustment. However, once the rate is “flattened”, it is BCH’s plan to determine future MGS rates simply by applying the CARC to the MGS rates.

Question #13

Reference: CEC 1.2.7

13.1 Please provide the requested bill variance for the example given, except assume that the energy use is 53,000 kWh per month. For purposes of the comparison, please compare the MGS bill with the following three LGS bill calculations:

• The 53,000 kWh is equivalent to the customer’s HBL• The 53,000 kWh is 10% above the customer’s HBL• The 53,000 kWh is 10% below the customer’s HBL.

Question #14


14.1 The examples provided only calculate the energy charges. Please confirm that, in each case, there would also be demand charges which would be calculated based on the customer’s monthly peak demand using the Part 1 demand rates and would be subject to the minimum demand provisions.

Question #15

Reference: CEC 1.26.2 and 1.26.3

15.1 Would two customers with the same energy but different demand levels impose the same costs on BCH? In the response please address from the perspective of both incremental and embedded costs.

5

Question #16


16.1 What is the basis for BCH’s view that energy charges elicit more conservation than the equivalent demand charges?

16.2 Please explain the view that increased emphasis on energy charges would increase bill volatility.

Question #17


17.1 The response states that demand is less volatile than energy consumption. Does this mean that increased emphasis on demand charges would decrease bill volatility? If so, why wasn’t an increased emphasis on demand charges considered as one of the potential ways (per Application, page 3-21) to reduce bill impact volatility?

BCOAPO et al.Information Request No. 2.1.1 Dated: December 18, 2009British Columbia Hydro & Power Authority Response issued January 22, 2010

Page 1 of 1


Exhibit:B-7

1.0 Reference: BCUC 1.1.2; 1.1.3.1 and 1.1.3.2

2.1.1 Please confirm that the “With Rate Impact” forecasts are those prepared as part of the August 2009 Update.

RESPONSE:

Confirmed.


Page 1 of 1


Exhibit:B-7


2.1.2 Do the “With Rate Impact” projections include any impacts from rate design or just demand response due to revenue requirement rate changes?

RESPONSE:

The “With Rate Impact” forecasts are net of the demand response to revenue requirement rate changes. Forecasts that are net of DSM, or “with DSM”, are net of energy savings from programs, codes and standards and assumed conservation rate structures. It follows that “With Rate Impact” forecasts may or may not be net of a demand response due to an assumed change in rate structure, depending on whether it is net of DSM.


Page 1 of 1


Exhibit:B-7


2.1.3 If any rate design impacts were included, please confirm that the impacts been removed for purposes of modelling the implications of the current LGSR proposal.

RESPONSE:

Not confirmed. The conservation estimates are based on load forecasts net of “rate impact” (demand response to revenue requirement changes) and net of DSM (demand response to programs, codes and standards, and assumed conservation rate structures). The result is a more conservative (i.e., lower) conservation estimates than if the demand response to assumed conservation rate structures was added back in to the load forecast.


Page 1 of 1


Exhibit:B-7

2.0 Reference: BCUC 1.2.2

2.2.1 Please respond to initial question’s request for an explanation as to “why the differing treatments are appropriate”.

RESPONSE:



Page 1 of 1


Exhibit:B-7


2.3.1 Is it BCH’s intent to use the price from the F2006 Call as the basis for the residential step 2 rate and the transmission tier 2 energy rate over the same 2011-2013 period? If not, why not?

RESPONSE:

Future bases for establishing the marginal energy prices under the RIB rate or the TSR stepped rate- whether or not these rates will remain based on the F2006 CFT or whether they would be adjusted for inflation similar to BC Hydro’s proposal under the LGS rate, or otherwise adjusted- will depend upon whether there is a basis for a new LRMC of new energy supply during the period and upon the BCUC’s decision regarding BC Hydro’s LGS proposal. Please also refer to the responses to CEC IRs 1.10.1 and 1.10.2, and JIESC IR 2.6.1.


Page 1 of 1


Exhibit:B-7


2.4.1 Please explain what is meant by the statement that “the majority of LGS accounts effectively see a flat average rate”. Also, please indicate the percentage of LGS accounts this entails and the percentage of LGS volumes (MWh) captured by these accounts.

RESPONSE:

The average electric rate is the demand, energy and basic charges divided by the kWh consumption. Figure 3-4 shows that smaller customers that have a 48 per cent monthly load factor, would see their average rate decline as they increase their demand and energy usage up to 150 kW (note that since the graph is for a constant 48 per cent load factor, as peak demand increases on the graph from left to right, the consumption would also increase). The decline in the average rate occurs because of the declining ELGS energy rate structure. As small accounts use more, they will use more at the lower Tier 2 rate, and their average rate energy declines.

In contrast, once a customer exceeds 150 kW in demand, Figure 3-4 shows that the average rate no longer declines as demand and energy usage increase. The average rate essentially flattens out because of the tier 3 demand rate that becomes effective at 150 kW of demand. The tier 3 demand rate is far higher than the tier 2 demand rate. Therefore as customers have higher demand and higher energy usage, the increase in their demand charges offsets the low Tier 2 energy rate. The net effect is that the average rate no longer declines with customer size, and basically becomes flat.

Because LGS customers are all above 150 kW, they would all fall into this “flat” portion of Figure 3-4. The statement that “the majority of LGS accounts effectively see a flat average rate” merely references this fact. BC Hydro qualifies the statement with the term “majority” because for some of the smallest and lowest load factor LGS customers, their average rate will not follow the same pattern shown in Figure 3-4.

BC Hydro has not created a formal definition of “flat average rate”, because the use of the term “flat average rate” was simply meant to contrast the average rate pattern for large LGS accounts as opposed to the smaller MGS accounts. Therefore BC Hydro cannot calculate percentages of LGS accounts and volumes that see a relatively flat average rate.


Page 1 of 1


Exhibit:B-7


2.5.1 The response states that HBLs will be updated, at minimum, two times per year. Please explain why BCH is not proposing to standardize the frequency at which HBLs are updated.

RESPONSE:

Please refer to the response to BCOAPO IR 2.9.1.


Page 1 of 1


Exhibit:B-7


2.5.2 Won’t updating HBLs to values other than those used when setting the rates for the year in question increase revenue variability?

RESPONSE:

Yes, there is a revenue effect from setting prices on the basis of HBLs other than those used for billing. Please also refer to the response to BCOAPO IR 2.9.1.


Page 1 of 1


Exhibit:B-7


2.6.1 Please confirm that the unit cost quoted is just BCH’s unit cost for implementing the ELGS restructuring and does not include either a) the cost of Power Smart programs customers may participate in to achieve the savings or b) the costs customers may incur to achieve the savings.

RESPONSE:

Confirmed.


Page 1 of 1


Exhibit:B-7

7.0 Reference: BCUC 1.42.2 and BCOAPO 1.2.1Application, page 1-16

2.7.1 Why is the potential “benefit” of an symmetric Anomaly Rule measured in terms of increased revenue to the class? Isn’t the objective/benefit to determine a more reasonable and typical baseline?

RESPONSE:

Increased revenue to the class is the modelled outcome when applying a symmetric anomaly rule versus the proposed (asymmetric) anomaly rule. Since the LGS rates are calculated to be revenue neutral, having an asymmetric anomaly rule results in collecting slightly less revenue than otherwise would have been collected without an anomaly rule.

Historical baselines are simply a measure of historical consumption. Therefore, BC Hydro is not trying to determine a more reasonable and typical baseline in the abstract. A number of trade-offs were considered in the development of the baseline proposal of a monthly, three year average rolling baseline including the frequency of reset and different preferences of accounts that are conserving versus growing; the delivery of the price signal on a monthly or annual basis, and the potential impact on cash flows, among others. BC Hydro acknowledges that any manner of calculating HBLs is bound to benefit some and disadvantage others (Chapter 3, A21). Please refer to Appendix K – Baseline Determination for further background on baseline determination considerations.


Page 1 of 1


Exhibit:B-7

7.0 Reference: BCUC 1.42.2 and BCOAPO 1.2.1Application, page 1-16

2.7.2 What is the lost revenue and lost conservation from the application of the proposed Anomaly rule?

RESPONSE:

The revenue and conservation impacts from the proposed Anomaly Rule are very small. Please refer to Appendix L, Tables L-8, L-18 and L-19.


Page 1 of 1


Exhibit:B-7

8.0 Reference: BCOAPO 1.21.1

2.8.1 The intent of the original question was to obtain the definition and source for the inflation measure that would be used (e.g., Is it BC inflation or Canada inflation? Is it CPI or some other measure? Is it forecast and, if so, what source?). Please provide a revised response.

RESPONSE:

Inflation rates for F2007, F2008, and F2009 are actual annual Canadian inflation rates published by the Bank of Canada. Inflation rates for F2010 and F2011 are forecast inflation rates provided by Treasury Board of British Columbia.


Page 1 of 3


Exhibit:B-7

9.0 Reference: BCOAPO 1.22.4 and BCOPAO 1.23.1

2.9.1 Assuming the HBLs are adjusted in April of a given year, please explain fully what historical data (i.e., which months for the previous/current year) will be used in the calculation, when the calculation will actually be done and whether application of the revised HBLs will require adjusting previous bills (e.g. for the first few months after April 1st).

RESPONSE:

HBLs are the average of the three most recent previous year’s months of consumption, subject to the anomaly rule. There would be no adjustments made to customer HBLs once established. Please refer to the revised response to BC Ferries IR 1.4.1, included in the January 22, 2010 errata filing.

This IR response describes the datasets that would be used for two different purposes: 1) HBL determination; and 2) annual compliance filings to determine the Part 1 rate adjustment.

Figure 1 – Customer HBL Determination for June 2015 (F2016)

June 2013

F12 F13 F14 F15 F16F11

BC Hydro cannot provide a full year of HBLsimmediately following the end of a month.

June 2012

June 2014

June 2015

Billing Month

June HBL = Average of June consumption from previous three years

2 - 3mths

9 to 1Month(s)

HBLs will be communicated in advance of billing.


Page 2 of 3


Exhibit:B-7

Figure 2 – Annual Compliance Filing for F2016

3mths

3mths

HBL Sample Datasets Consumption Sample Dataset

X

F12 F13 F14 F15 F16F11

Scaled by same scale factor as F2014

consumption sample dataset

Scaled to F16 forecast

X

Compliance filing of rates, prior to start of fiscal year

Data extraction, processing

F2016 rates in effect

1) Customer HBL determination

Customer HBLs for any particular month, excluding HBLs upon implementation, will be determined following the methodology illustrated in Figure 1 above. In this example, the June 2015 HBL is calculated as an average of the consumption in June 2012, 2013 and 2014.

Customers will be notified of their HBLs in advance of the billing month. As indicated in Figure 1, BC Hydro will be able to provide HBL notification about nine months in advance of billing. It is not possible to provide HBLs 12 months into the future because data for the later months will not yet be available from the billing system. In the example shown, a customer’s HBL for June 2015 would be known and communicated sometime after October 2014.

It is BC Hydro’s intention to standardize the method and frequency of notifying LGS customers of their HBLs well in advance of a billing period. Options to make the information available online are being considered.

2) Annual compliance filing to determine Part 1 rate adjustment

The annual compliance filing is a completely separate process from determining customer HBLs. Figure 2 illustrates the information used for calculating the Part 1 rate adjustment in regard to the compliance filing. As illustrated, there is a difference between the HBLs used for the basis of billing customers and the “HBLs” used for the compliance filing to determine the Part 1 rate adjustment. Two issues prevent using the most recent billing datasets for calculating the Part 1 rate adjustment:


Page 3 of 3


Exhibit:B-7

1. the Part 1 rate adjustment will be calculated in advance of the start of the fiscal year and a full set of fiscal billing data is not available; and

2. two different sets of sample data that don’t overlap are needed: a sample for consumption and a sample for HBLs.

In the example above, both datasets are scaled using the same ratio of the F2016 forecast to the F2014 consumption. The proposed methodology helps to minimize the revenue variability that could arise from using different HBL values for billing purposes and Part 1 rate adjustment purposes.


Page 1 of 1


Exhibit:B-7

10.0 Reference: BCOAPO 1.24.1 and 1.29.2

2.10.1 The referenced interrogatory response in BCOAPO 1.24.1 does not address the question of whether or not demand charges impact energy consumption/conservation. Please address this issue which is also raised in the last sentence in the response to BCOAPO 1.29.2.

RESPONSE:

Although BC Hydro does incorporate the incremental costs of demand charges in its estimates of conservation, for most ELGS customers, the level of demand charges has a more significant impact on their bills than on their consumption and therefore their conservation.

Regarding the last sentence in response to BCOAPO IR 1.29.2, economists will argue that where there must be deviations between prices and incremental costs, economic efficiency is best served when those deviations are minimized for the pricing components that, like energy, have a comparatively larger price elasticity.


Page 1 of 1


Exhibit:B-7


2.11.1 Please confirm that the referenced response should be BCUC IR 1.27.4.

RESPONSE:

Confirmed.


Page 1 of 1


Exhibit:B-7


2.11.2 The first paragraph of the response suggests that elasticity increases as price increases. Does BCH/Dr. Orans have any evidence that this is the case?

RESPONSE:

Intuition suggests that when energy cost is a relatively large share of a customer's total cost, the customer is likely more price-sensitive than when the energy cost share is relatively small. The customer's relatively large energy cost share can be attributable to the customer being a relatively large user or the energy price being relatively high.

Unfortunately, as previously described in response to BCOAPO IR 1.34.2, the electricity demand literature does not offer clear evidence on the relationship between price elasticity and price level.1

1 For example, a Rand study's state-level price elasticity estimates for commercial

customers do not correlate with the state-level electricity rates, refer to Bernstein M. and J. Griffin (2005) “Regional Differences in the Price-Elasticity of Demand for Energy,” (available at http://RAND.org/pubs/technical_reports/2005/RAND_TR292.pdf), pages 81-82.


Page 1 of 1


Exhibit:B-7

12.0 Reference: BCOAPO 1.36.3 and 1.35.2

2.12.1 Please confirm that, for modelling purposes, BCH has determined the revenue required from the MGS class by escalating the existing ELGS rates by the CARC adjustment. However, once the rate is “flattened”, it is BCH’s plan to determine future MGS rates simply by applying the CARC to the MGS rates.

RESPONSE:

BC Hydro has modeled the MGS revenue requirement by escalating the existing revenues at existing rates for the MGS accounts by the CARC. This is slightly different from escalating the existing rates by CARC because BC Hydro is not proposing to change the existing discount provided for primary metering.

BC Hydro has no proposal at this time for MGS rate design past F2016.


Page 1 of 1


Exhibit:B-7

13.0 Reference: CEC 1.2.7

2.13.1 Please provide the requested bill variance for the example given, except assume that the energy use is 53,000 kWh per month. For purposes of the comparison, please compare the MGS bill with the following three LGS bill calculations:

� The 53,000 kWh is equivalent to the customer’s HBL

� The 53,000 kWh is 10% above the customer’s HBL

� The 53,000 kWh is 10% below the customer’s HBL.

RESPONSE:

MGS

LGS - Monthly consumption

10% above HBL*

LGS - Monthly consumption equals HBL*

LGS - Monthly consumption

10% below HBL*

ModelledYear

Monthly Consumption

(kWh)

Monthly Energy Charge

HBL(kWh)


HBL(kWh)


HBL(kWh)


F11 53,000 $2,749 48,182 $2,843 53,000 $2,710 58,889 $2,548

F12 53,000 $2,968 48,182 $2,977 53,000 $2,854 58,889 $2,705

F13 53,000 $3,335 48,182 $3,310 53,000 $3,070 58,889 $2,778

F14 53,000 $3,796 48,182 $3,632 53,000 $3,316 58,889 $2,930

F15 53,000 $4,311 48,182 $3,924 53,000 $3,529 58,889 $3,047

* For the purpose of this IR response, the HBL is fixed each year and does not update moving forward. If the HBLs were updated in accordance with BC Hydro’s proposal the monthly LGS energy charges would all be the same in F2014 and F2015.


Page 1 of 1


Exhibit:B-7


2.14.1 The examples provided only calculate the energy charges. Please confirm that, in each case, there would also be demand charges which would be calculated based on the customer’s monthly peak demand using the Part 1 demand rates and would be subject to the minimum demand provisions.

RESPONSE:

BC Hydro assumes the intended reference was BCSEA IR 1.1.1.

Confirmed. Customers will also pay demand charges and they will be subject to minimum demand provisions.


Page 1 of 1


Exhibit:B-7

15.0 Reference: CEC 1.26.2 and 1.26.3

2.15.1 Would two customers with the same energy but different demand levels impose the same costs on BCH? In the response please address from the perspective of both incremental and embedded costs.

RESPONSE:

There is not sufficient information provided in the question to provide a definitive answer. If the customers’ maximum demands are comparable and occur at times other than the system peak hours, or the class peak hours, then the costs could be the same from an incremental or embedded cost basis. If the demands are different enough to require differing meters, service drops, or upstream facilities, then the embedded costs could be different. If the demands are different enough that the line losses imposed by the customers are different (despite the metered energy being the same), then the incremental and embedded costs could be different. If one customer is located in a capacity constrained area and the other is in an area with capacity surplus, then their incremental costs could be different, regardless of demand size. These are just a few examples of potential differences in costs.


Page 1 of 1


Exhibit:B-7


2.16.1 What is the basis for BCH’s view that energy charges elicit more conservation than the equivalent demand charges?

RESPONSE:

Because energy charges apply to a consumer’s consumption during all hours and demand charges only apply to the consumption during a single hour, where the customer has maximum demand, energy charges are a more consistent and powerful incentive to induce conservation than demand charges.

That said, customers do reduce their kW demands in response to rising demand charges. However, such kW demand responses do not lead to substantial energy conservation. For example, in the critical peak pricing program implemented in California, customers reduced energy consumption during the few critical peak hours with high prices, but did not reduce their overall consumption due to increased consumption in the remaining non-critical hours with lower prices.

Please also refer to the response to BCOAPO IR 2.10.1.


Page 1 of 1


Exhibit:B-7


2.16.2 Please explain the view that increased emphasis on energy charges would increase bill volatility.

RESPONSE:

The variation in monthly, seasonal and annual energy consumption is greater than billing demand for the ELGS customers. Hence, increased emphasis on using energy charges for revenue collection will increase bill and revenue volatility.


Page 1 of 1


Exhibit:B-7


2.17.1 The response states that demand is less volatile than energy consumption. Does this mean that increased emphasis on demand charges would decrease bill volatility? If so, why wasn’t an increased emphasis on demand charges considered as one of the potential ways (per Application, page 3-21) to reduce bill impact volatility?

RESPONSE:

Yes, increasing demand charges relative to energy charges would generally decrease bill volatility for ELGS customers. However, this option was not adopted because it would decrease energy charges, making the ELGS rate structure less economically efficient, with weaker conservation signals, and it would shift costs in the class.

1

REQUESTOR NAME: B.C. Sustainable Energy Association and Sierra Club British Columbia INFORMATION REQUEST ROUND NO: 2 TO: BRITISH COLUMBIA HYDRO & POWER AUTHORITY DATE: December 21, 2009PROJECT NO: 3698573 APPLICATION NAME: Large General Service Rate Application ____________________________________________________________________________

1.0 Reference: Exhibit B-5, BC Hydro response to BCSEA IR 1.2.6, Exhibit B-1 Revised Table 3-6; B-1, Appendix L, Footnote 1, concept of “Two-Part Rate”

BCSEA-SCBC were concerned that Figure 3-6 did not accurately show the LGS proposal. BCSEA IR 1.2.6 asked for a revised version of Figure 3-6 showing credits below the x-axis and showing the correct shading for charges above the x-axis.

The Response refers to Revised Figure 3-6 which is described as increasing clarity regarding the LGS rate structure.

Revised Figure 3-6 fails to show the credits below the x-axis. In addition, with respect, Revised Figure 3-6 appears to confirm that neither the original Figure 3-6 nor the Revised Figure 3-6 reflects accurately the actual LGS proposal.

Revised Figure 3-6 states:

“Part 1 Charge = Baseline X Existing Rate” and “Part 2 Credit/Charge = (Consumption –Baseline) X LRMC Rate”. [underline added]

This concept is a reiteration of footnote 1 of Appendix L, in which the “two-part energy rate design” is defined as follows:

A two-part design computes an account's monthly total energy bill as the sum of (1) the part-1 bill equal to the account's baseline (based on the account's historic consumption) at the part-1 energy rates; and (2) the part-2 bill equal to the account's billing consumption deviation (= billing kWh - baseline kWh) at the part-2 rate. … [underline added]

1.1 Please confirm that “Part 2 Credit/Charge = (Consumption – Baseline) X LRMC Rate” in Revised Figure 3-6 is a description of a “Basic Design” and is not an accurate description of the proposed LGS rate design with Price Limit Band as set out in the draft tariff pages (Appendix T) and the 15 scenarios provided by BC Hydro’s B-5 response to BCSEA IR 1.1.1.

1.2 Is the following accurate? The proposed LGS rate design has two stages, but the two stages are not the same as Part 1 and Part 2. The first stage is to determine a charge for the customer’s HBL (“HBL Charge”). This stage uses only the Part 1 rates (Tier 1 and Tier 2). The second stage is to determine the amount of an additional charge or a credit, depending on whether the customer’s actual consumption is greater than or less than the HBL. In the second stage, both the Part 2 rates and, where applicable, the Part 1 rates are used.

1.3 Please confirm that Revised Figure 3-6 showing the “Credit” confined to the Part 2



2

LRMC rate and the area between 80% and 100% of HBL is inaccurate because in the Appendix T proposal the Credit includes not only a credit at the Part 2 rate for deviation of actual consumption from HBL between 80% and 100% of HBL but also a credit at Part 1 rates where actual consumption is less than 80% of HBL.

1.4 Please provide three figures illustrating the determination of the LGS customer bill as follows:

1.4.1 A figure showing the first stage, in which a charge is made for the HBL according to the Part 1-Tier 1 rate and the Part 1-Tier 2 rate, with shading under the price curve to show the size of the HBL charge.

1.4.2 A figure showing the first stage as above, plus the second stage where the customer’s monthly actual consumption exceeds the HBL, showing the additionalcharge for actual between 100% and 120% of HBL at the Part 2 LRMC and the Part 1-Tier 2 rate for actual above 120% of HBL, with shading (differentiated from the first stage charge) to show the size of the second stage additional charge.

1.4.3 A figure showing the first stage as above, plus the second stage where the customer’s monthly actual consumption is below the HBL, showing the credit for actual between 100% and 80% of HBL at the Part 2 LRMC and the credit at Part 1-Tier 2 and Part 1-Tier 1 rates for actual less than 80% of HBL, below the x-axis, with shading (differentiated from both the HBL-charge and the second-stage additional charge).

2.0 Reference: Exhibit B-5, BC Hydro response to BCSEA IR 1.1.1, p.1 of 18

2.1 Please provide a revised version of the table on p.1 of 18 with an explanation of what it is. Please confirm whether the actual and HBL figures are monthly or yearly. Please indicate where the HBL figures come from (i.e., on what basis are they chosen).


3.1 Please confirm, or otherwise explain, that the graph titled “Marginal Rate vs Test year consumption” on p.2 of 18 is more accurately described as “Test month”.


4.1 Please provide a revised version of the table on p.3 of 18 showing the heading of the third column as “Test Month kWh” (if that is accurate, or otherwise explain).


The table describes Scenarios 1 and 2 as “Most common” (the text says Scenarios 1 and 2 are about 73% of bills based on F2008 billing data [p.2 of 18]) and Scenarios 3 to 15 as “Less common.” The intention is to quantify the distribution of the other 15 scenarios.

5.1 Please provide a revised version of the table on p.3 of 18 showing two additional columns for number of customers and kWh of energy. Please specify if this is for a particular month of the test year, or an average of the 12 months within the test year.

3

6.0 Reference: Exhibit B-5, BC Hydro response to BCSEA IR 1.1.1, pages 4 to 18; response to BCSEA IR 1.2.6

In response to BCSEA IR 1.1.1, BC Hydro provides “sample energy charge calculations for 15 different combinations of actual consumption and HBLs,” with tables and graphs.

The graphs do not show the first stage HBL charge at Part 1 rates. They show the second stage energy credit above the x-axis. And they label the second stage energy credit as “Part 2 Energy Credit” (though the credit is not limited to Part 2, as discussed above).

The intention is to create a graphic representation of the calculation of a monthly bill under the proposed LGS rate design, including both the first and second stage, with appropriate inclusion of the Part 1-Tier 1 rate, the Part 1-Tier 2 rate and the Part 2 LRMC rate, both as charges (positive rates) and credits (negative rates).

6.1 Please provide revised versions of the graphs for Scenarios 1 to 15 (with unchanged copies of the tables) showing: (a) shading of the HBL Energy Charge, and where appropriate (b) shading of the “actual-greater-than-HBL charge” or (c) shading of the “actual-is-less-than-HBL credit” below the x-axis.

7.0 Reference: Exhibit B-5, BC Hydro response to BCSEA IR 1.1.3 and BCSEA IR 1.1.1, p.18 of 18

BCSEA IR 1.1.3 asked for the formula for determining the circumstances in which the Minimum Energy Charge will be applicable. The response refers to Scenario 15 on p.18 of the response to BCSEA IR 1.1.1, which provides a sample calculation of one hypothetical instance in which the Minimum Energy Charge would be applicable.

7.1 Please provide the formula for determining the circumstances in which the Minimum Energy Charge will be applicable. Alternatively, please explain why would it not be possible to solve the general bill formula for MEC approaching zero.


BCSEA IR 1.1.4 asks “Assuming that the Minimum Energy Charge will be applicable where there are various combinations of the size of the HBL, the deviation of actual from HBL, and the ratio of LRMC to the combination of Tier 1 and Tier 2 rates, please provide a graph, if possible, that illustrates the boundary between the Minimum Energy Charge being applicable and not being applicable.”

The response says that “The Minimum Energy Charge applies only when the average energy rate in a Billing Period is less than the minimum energy rate” and refers to Scenario 15. This does not respond to IR 1.1.4.

The intention is to learn more about the factors that influence the applicability (or not) of the Minimum Energy Charge.

8.1 Please discuss the premise of BCSEA IR 1.1.4. Is it correct that the MEC will be applicable where there are various combinations of the size of the HBL, the deviation of actual from HBL, and the ratio of LRMC to the combination of Tier 1 and Tier 2 rates?

4

Are there any other factors that influence whether the MEC will be applicable or not?

8.2 Please provide a two dimensional graph of the main influences on the applicability of the MEC, making and specifying reasonable assumptions regarding the most appropriate other parameters to hold constant.

9.0 Reference: Exhibit B-5, BC Hydro response to BCSEA IR 1.2.7

BSCEA IR 1.2.7 asked for a flowchart demonstrating the calculation of an LGS customer’s bill for a given billing period. The Response refers to the examples provided in B-5 BCSEA 1.1.1 and does not provide a flowchart.

9.1 Please provide a flowchart demonstrating the calculation of an LGS customer’s bill for a given billing period where (a) the customer has an HBL and (b) the customer does not have an HBL.

10.0 Reference: Exhibit B-1, Chapter 3; Appendix L “LGS Bill Volatility”

10.1 Where the “bill volatility” metric used in Appendix L and referenced in Chapter 3 is used to support a statement that a subject rate design (for example, a Basic Two-Part with 70:130 Price Limit Band shown in Table L-3) would result in maximum “Volatility Impacts (relative to current structure)” of 37.8%, does that mean that this customer’s annual bill would be 37.8% higher than its historical three-year average annual bill, or 37.8% higher than its annual bill in the test year would have been if consumption in the test year was billed according to the existing rate design?

11.0 Reference: Exhibit B-1, Chapter 4, p.4-10; Exhibit B-1, Appendix K, Baseline Determination; Exhibit B-5, BCUC IR 1.27.3; CEC IR 1.4.4; CEC IR 1.4.5

Dr. Orans states:

”Using a three-year rolling average of historic consumption to determine an account’s baseline smoothes out year-to-year usage fluctuations and can better reflect an account’s long-term consumption trend than a baseline based on a single year of billing data. The three-year average method also has regulatory precedent in British Columbia; …” [p.4-10]

And:

“the three-year rolling average calculation of monthly baselines provides a formulaic way to balance the competing interests of customers who are conserving or whose usage is declining, and whose usage is increasing;” [p.4-15]

In Exhibit B-5, BCUC IR 1.27.3, BC Hydro states:

“…The three-year rolling-average baseline does a good job of addressing bill volatility. A rolling baseline with more years could provide a stronger conservation incentive, but would also increase the timeframe over which incremental energy consumption above baseline is exposed to LRMC. If the three-year rolling average is judged to provide too weak a conservation incentive, the baseline period could be lengthened.”

In Exhibit B-5, CEC IR 1.4.4, BC Hydro states:

5

“… A five-year rolling average baseline definition was also considered as a way to provide additional conservation incentives. Ultimately, BC Hydro believed that the three-year rolling average baseline definition provided a sufficiently strong incentive for new conservation investments, while balancing the interests of existing customers.”

11.1 What would be the effect on net conservation and on bill volatility of using a five-year rolling average instead of a three-year rolling average, other aspects of the rate design being as proposed? An eight-year rolling average?

12.0 Reference: Exhibit B-1, Appendix L, section 4 Price Limit Band; Table L-3

The bill volatility of various Price Limit Bands is shown in Appendix L. A broader Price Limit Band has a larger conservation outcome but larger bill volatility.

12.1 Please confirm that changing to a 70% to 130% Price Limit Band from an 80% to 120% Price Limit Band, other things being equal, would yield 1,510 GWh – 1,393 GWh = 117 GWh additional Net Conservation.

12.2 For what reasons did BC Hydro select an 80% to 120% Price Limit Band instead of, say, a 70% to 130% Price Limit Band?

12.3 Please provide a version of Table L-3 showing Scenarios 70:140 Price Limit Band, 60:160 Price Limit Band, and 50:200 Price Limit Band.

13.0 Reference: Exhibit B-5, BC Hydro response to BCUC IR 1.27.3

13.1 Please explain why Hydro believes that the conservation effect of the LGS rate design is independent of the resetting of the HBL.

14.0 Reference: Exhibit B-1, Appendix P, Conservation Estimating Methodology

14.1 If a customer is aware that a housekeeping measure that reduces energy use by three kWh in year one (with no continuing reductions in subsequent years) reduces its bill by three kWh times the LRMC for the current year, but results in the HBL being adjusted downward one kWh in each of the following three years, resulting in one additional kWh in each year being priced at the LRMC rather than the Tier 2 energy rate, would the customer evaluate the dollar savings as 3 kWh x LRMC – (LRMC – Tier 2 rate) × (1/(1+r) + 1/(1+r)2 + 1/(1+r)3), where r is the customer’s discount rate, and assuming no CARC?

14.2 If the LRMC is 12¢/kWh, the Tier 2 rate is 3.7¢/kWh, and the customer’s discount rate is 10%, and assuming no CARC, please show the calculation of the customer’s net present value per kWh of a 3 kWh conservation measure in year one.

14.3 Should the customer’s NPV per kWh of conservation in year one be treated as the price signal for estimating the conservation effect of the rate design? If not, why not? How does this compare with the logic described in Appendix P, which uses an LRMC-based marginal price signal? What conservation longevity assumptions are associated with the elasticity figure used in Appendix P?

6

End of document

B.C. Sustainable Energy Association and Sierra Club British ColumbiaInformation Request No. 2.1.1 Dated: December 21, 2009British Columbia Hydro & Power Authority Response issued January 22, 2010

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Exhibit:B-7






“Part 1 Charge = Baseline X Existing Rate” and “Part 2 Credit/Charge = (Consumption – Baseline) X LRMC Rate”.


A two-part design computes an account's monthly total energy bill as the sum of (1) the part-1 bill equal to the account's baseline (based on the account's historic consumption) at the part-1 energy rates; and (2) the part-2 bill equal to the account's billing consumption deviation (= billing kWh - baseline kWh) at the part-2 rate. …

2.1.1 Please confirm that “Part 2 Credit/Charge = (Consumption – Baseline) X LRMC Rate” in Revised Figure 3-6 is a description of a “Basic Design” and is not an accurate description of the proposed LGS rate design with Price Limit Band as set out in the draft tariff pages (Appendix T) and the 15 scenarios provided by BC Hydro’s B-5 response to BCSEA IR 1.1.1.

RESPONSE:

Figure 3-6 does not fully illustrate all nuances of the proposed LGS rate design, nor was it intended to.

The scenarios provided in the response to BCSEA IR 1.1.1 should be referenced for detailed examples of how the energy portion of an LGS bill would be determined. Please also refer to the response to BCSEA IR 2.1.2.


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Exhibit:B-7









2.1.2 Is the following accurate? The proposed LGS rate design has two stages, but the two stages are not the same as Part 1 and Part 2. The first stage is to determine a charge for the customer’s HBL (“HBL Charge”). This stage uses only the Part 1 rates (Tier 1 and Tier 2). The second stage is to determine the amount of an additional charge or a credit, depending on whether the customer’s actual consumption is greater than or less than the HBL. In the second stage, both the Part 2 rates and, where applicable, the Part 1 rates are used.

RESPONSE:

BC Hydro acknowledges some inconsistencies in language usage. However, BC Hydro is hesitant to use the new terms introduced in this information request.

BC Hydro agrees to the following:

The proposed LGS rate design has two parts. The first part determines a charge for the customer’s baseline consumption, and uses only the Part 1 rates (in Appendix T revised,


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Exhibit:B-7

these are called ‘Tier 1 price’ and ‘Tier 2 price’; in the response to BCSEA IR 1.1.1 these are called ‘Tier 1 energy rate’ and ‘Tier 2 energy rate’). The second part determines the amount of an additional charge or a credit, depending on whether the customer’s actual consumption is greater than or less than their baseline consumption. In calculating the second part, three possible rates are used: the Part 2 LRMC-based energy rate (in Appendix T, revised, this is called ‘marginal cost based energy rate’; in the response to BCSEA IR 1.1.1 this is called ‘LRMC-based energy rate’) and, where applicable, the Tier 2 energy rate and the Tier 1 energy rate.

BC Hydro notes that the 15 detailed scenarios in the response to BCSEA IR 1.1.1 provide clear illustrations of which and how prices would be used in energy charge calculations under the LGS rate structure. BC Hydro has simplified the language in these 15 scenarios to reflect the fact that there are three possible rates (or prices) used in calculating the Part 1 and Part 2 energy charges under the LGS rate structure: a Tier 1 energy rate, a Tier 2 energy rate, and an LRMC-based energy rate.

The calculation of the Part 1 baseline energy charge uses as many as two rates:

� the Tier 1 energy rate; and

� the Tier 2 energy rate.

The calculation of the Part 2 energy credit/charge uses as many as three rates:

� the LRMC-based energy rate;

� the Tier 1 energy rate; and

� the Tier 2 energy rate.


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Exhibit:B-7









2.1.3 Please confirm that Revised Figure 3-6 showing the “Credit” confined to the Part 2 LRMC rate and the area between 80% and 100% of HBL is inaccurate because in the Appendix T proposal the Credit includes not only a credit at the Part 2 rate for deviation of actual consumption from HBL between 80% and 100% of HBL but also a credit at Part 1 rates where actual consumption is less than 80% of HBL.

RESPONSE:

Please refer to the response to BCSEA IR 2.1.1.

B.C. Sustainable Energy Association and Sierra Club British ColumbiaInformation Request No. 2.1.4.1 Dated: December 21, 2009British Columbia Hydro & Power Authority Response issued January 22, 2010

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Exhibit:B-7









2.1.4 Please provide three figures illustrating the determination of the LGS customer bill as follows:

2.1.4.1 A figure showing the first stage, in which a charge is made for the HBL according to the Part 1-Tier 1 rate and the Part 1- Tier 2 rate, with shading under the price curve to show the size of the HBL charge.

RESPONSE:



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Exhibit:B-7










2.1.4.2 A figure showing the first stage as above, plus the second stage where the customer’s monthly actual consumption exceeds the HBL, showing the additional charge for actual between 100% and 120% of HBL at the Part 2 LRMC and the Part 1-Tier 2 rate for actual above 120% of HBL, with shading (differentiated from the first stage charge) to show the size of the second stage additional charge.

RESPONSE:



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Exhibit:B-7

1.0 Reference: \ Exhibit B-5, BC Hydro response to BCSEA IR 1.2.6, Exhibit B-1 Revised Table 3-6; B-1, Appendix L, Footnote 1, concept of “Two-Part Rate”









2.1.4.3 A figure showing the first stage as above, plus the second stage where the customer’s monthly actual consumption is below the HBL, showing the credit for actual between 100% and 80% of HBL at the Part 2 LRMC and the credit at Part 1- Tier 2 and Part 1-Tier 1 rates for actual less than 80% of HBL, below the x-axis, with shading (differentiated from both the HBL-charge and the second-stage additional charge).

RESPONSE:



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Exhibit:B-7


2.2.1 Please provide a revised version of the table on p.1 of 18 with an explanation of what it is. Please confirm whether the actual and HBL figures are monthly or yearly. Please indicate where the HBL figures come from (i.e., on what basis are they chosen).

RESPONSE:

The table on page 1 of 18 in the response to BCSEA IR 1.1.1 shows the F2011 marginal rates for an LGS customer with an assumed baseline of 160,000 kWh per month under various actual consumption situations (160,000 kWh is the average monthly consumption for an LGS customer). The average monthly kWh is calculated based on F2008 consumption data in BC Hydro’s rates model.

Actual monthly consumption relative to an assumed HBL of 160,000 kWh

Marginal Energy Rate in F2011

Actual consumption is > 160,000 kWh and less than or equal to 120% of HBL (192,000 kWh)

9.42 cents/kWh (LRMC based Energy Rate)

Actual consumption is greater than 120% of HBL (192,000 kWh)

4.45 cents/kWh (Tier 2 Energy Rate)

Actual consumption is < 160,000 kWh and greater than or equal to 80% of HBL (128,000 kWh)

9.42 cents/kWh (LRMC based Energy Rate)

Actual consumption is less than 80% of HBL (128,000 kWh) and greater than 14,800 kWh


Actual consumption is less than 80% of HBL (128,000 kWh) and less than 14,800 kWh



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Exhibit:B-7


2.3.1 Please confirm, or otherwise explain, that the graph titled “Marginal Rate vs Test year consumption” on p.2 of 18 is more accurately described as “Test month”.

RESPONSE:

The words “test year” generally refer to the particular fiscal period for which pricing, conservation, or other elements or effects of a rate design are modelled. In the figure on page 2 of 18, in the response to BCSEA IR 1.1.1, “test year” indicates that the location of the curve relative to the y-axis varies from test year to test year. That is, the energy rates and consumption vary from year to year. In the table on page 3 of 18, in the response to BCSEA IR 1.1.1, “test year kWh” refers to the assumed monthly consumption for a particular test year.


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Exhibit:B-7


2.4.1 Please provide a revised version of the table on p.3 of 18 showing the heading of the third column as “Test Month kWh” (if that is accurate, or otherwise explain).

RESPONSE:

Please refer to the responses to BCSEA IRs 2.3.1 and 2.6.1.


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Exhibit:B-7


The table describes Scenarios 1 and 2 as “Most common” (the text says Scenarios 1 and 2 are about 73% of bills based on F2008 billing data [p.2 of 18]) and Scenarios 3 to 15 as “Less common.” The intention is to quantify the distribution of the other 15 scenarios.

2.5.1 Please provide a revised version of the table on p.3 of 18 showing two additional columns for number of customers and kWh of energy. Please specify if this is for a particular month of the test year, or an average of the 12 months within the test year.

RESPONSE:

The 73 per cent figure referred to in the response to BCSEA IR 1.1.1 was based on the F2008 dataset unadjusted for partial billing history. To respond to this IR, it was necessary to use the F2008 data set adjusted to remove accounts with partial billing history. On the basis of the adjusted data set, scenarios 1 and 2 account for about 86 per cent of the bills. Please refer to the table below.

HBL above or below

14,800 kWh threshold

Actual kWh above or below

14,800 kWh threshold

Scenario Actual kWh Above or Below from HBL

above below above below

Accounts (%)

Bills(%)

kWh(%)

1 Above; Within Price limit band x x 78.4 44.0 48.31

2 Below; Within Price limit band x x 75.3 41.8 42.05 3 Above; Outside Price limit band x x 16.0 6.9 6.38 4 Below; Outside Price limit band x x 9.0 4.0 3.03

5 and 7 Above; Outside Price limit band x x 0.8 0.3 0.05 6 and 13 Below; Outside Price limit band x x 1.1 0.4 0.03

8 Above; Within Price limit band x x 0.3 0.2 0.01 9 Above; Outside Price limit band x x 1.0 0.4 0.02 10 Above; Within Price limit band x x 2.4 0.8 0.05 11 Below; Within Price limit band x x 0.3 0.1 0.01 12 Below; Within Price limit band x x 2.3 0.9 0.05 14 Below; Outside Price limit band 1.0 0.4 0.01

Total, Scenarios 1 to 14 100 100 15 Number of bills with anomaly adjustments About 2


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Exhibit:B-7

6.0 Reference: Exhibit B-5, BC Hydro response to BCSEA IR 1.1.1, pages 4 to 18; response to BCSEA IR 1.2.6

In response to BCSEA IR 1.1.1, BC Hydro provides “sample energy charge calculations for 15 different combinations of actual consumption and HBLs,” with tables and graphs.

The graphs do not show the first stage HBL charge at Part 1 rates. They show the second stage energy credit above the x-axis. And they label the second stage energy credit as “Part 2 Energy Credit” (though the credit is not limited to Part 2, as discussed above).

The intention is to create a graphic representation of the calculation of a monthly bill under the proposed LGS rate design, including both the first and second stage, with appropriate inclusion of the Part 1-Tier 1 rate, the Part 1-Tier 2 rate and the Part 2 LRMC rate, both as charges (positive rates) and credits (negative rates).

2.6.1 Please provide revised versions of the graphs for Scenarios 1 to 15 (with unchanged copies of the tables) showing: (a) shading of the HBL Energy Charge, and where appropriate (b) shading of the “actual-greater-than-HBL charge” or (c) shading of the “actual-is-less-than-HBL credit” below the x-axis.

RESPONSE:

In its first round information requests the BCSEA raised questions as to how BC Hydro's proposed LGS rate structure would work and be billed. To make it clear how the rate would work under all possible scenarios of historical load and billed load relative to the existing 14,800-kWh threshold BC Hydro provided a comprehensive response to BCSEA IR 1.1.1. BC Hydro also reviewed some of the figures and explanations it used to describe the proposal, and in consequence made some errata filings that specifically responded to questions raised by the BCSEA.

This current information request does not evidence any indication of misunderstanding or uncertainty; instead it indicates only a desire by BCSEA that BC Hydro should describe the LGS proposal in a way that BCSEA prefers. With respect, this is not a proper purpose of an information request, and BC Hydro declines to respond.


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Exhibit:B-7


BCSEA IR 1.1.3 asked for the formula for determining the circumstances in which the Minimum Energy Charge will be applicable. The response refers to Scenario 15 on p.18 of the response to BCSEA IR 1.1.1, which provides a sample calculation of one hypothetical instance in which the Minimum Energy Charge would be applicable.

2.7.1 Please provide the formula for determining the circumstances in which the Minimum Energy Charge will be applicable. Alternatively, please explain why would it not be possible to solve the general bill formula for MEC approaching zero.

RESPONSE:

There is no single mathematical formula to determine if the Minimum Energy Charge is applicable.

The Minimum Energy Charge will always be greater than zero.


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Exhibit:B-7





2.8.1 Please discuss the premise of BCSEA IR 1.1.4. Is it correct that the MEC will be applicable where there are various combinations of the size of the HBL, the deviation of actual from HBL, and the ratio of LRMC to the combination of Tier 1 and Tier 2 rates? Are there any other factors that influence whether the MEC will be applicable or not?

RESPONSE:

Whether the Minimum Energy Charge applies depends on the variables that are used to calculate a bill under the proposed LGS rate structure. The key ones are HBL, actual consumption, Tier 1 rate, Tier 2 rate, LRMC-based rate and minimum energy rate. Because these variables are different for each customer, multiple circumstances exist where the Minimum Energy Charge is triggered. In general, as the difference between the LRMC based rate and the minimum energy rate increases, the magnitude of consumption reduction from the HBL needed to trigger the Minimum Energy Charge decreases.

For a typical LGS customer with a HBL consumption at 160,000 kWh / month, the Minimum Energy Charge would apply when the actual consumption is as follows, using the modelled rates for each fiscal year:


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Exhibit:B-7

Actual Consumption where Minimum Energy Charge Applies (kWh)

% Energy Reduction from HBL

(160,000kWh/month) F2011 17,500 89% F2012 13,500 92% F2013 54,500 66% F2014 76,000 53% F2015 97,000 39%


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Exhibit:B-7





2.8.2 Please provide a two dimensional graph of the main influences on the applicability of the MEC, making and specifying reasonable assumptions regarding the most appropriate other parameters to hold constant.

RESPONSE:

Please refer to the responses to BCSEA IRs 2.8.1 and 2.6.1.


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Exhibit:B-7

9.0 Reference: Exhibit B-5, BC Hydro response to BCSEA IR 1.2.7

BSCEA IR 1.2.7 asked for a flowchart demonstrating the calculation of an LGS customer’s bill for a given billing period. The Response refers to the examples provided in B-5 BCSEA 1.1.1 and does not provide a flowchart.

2.9.1 Please provide a flowchart demonstrating the calculation of an LGS customer’s bill for a given billing period where (a) the customer has an HBL and (b) the customer does not have an HBL.

RESPONSE:



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Exhibit:B-7

10.0 Reference: Exhibit B-1, Chapter 3; Appendix L “LGS Bill Volatility”

2.10.1 Where the “bill volatility” metric used in Appendix L and referenced in Chapter 3 is used to support a statement that a subject rate design (for example, a Basic Two-Part with 70:130 Price Limit Band shown in Table L-3) would result in maximum “Volatility Impacts (relative to current structure)” of 37.8%, does that mean that this customer’s annual bill would be 37.8% higher than its historical three-year average annual bill, or 37.8% higher than its annual bill in the test year would have been if consumption in the test year was billed according to the existing rate design?

RESPONSE:

“Bill impact” refers to the total change in an account’s bill as a result of implementing a new rate structure and holding account consumption constant. The LGS rate structure by definition creates minimal bill impacts, because its Part 1 rates are virtually the same as the energy rates under the ELGS rate structure.

In contrast with bill impact analysis, “bill volatility” refers to the change in an account’s bill as a result of changes in consumption under an assumed rate structure.

In this application BC Hydro measures bill volatility as an account’s total bill given a change in consumption, under the proposed LGS rate structure, relative to the bill that an account would have received under the ELGS rate, and excluding the effect of CARC.

In Table L-3, the maximum bill volatility under a 70:130 Price Limit Band is 37.8 per cent. This single most volatile LGS account’s annual bill for its F2011 consumption would be 37.8 per cent higher under the LGS design (given an HBL based on F2005 – F2007 historical consumption) than its annual bill would be if F2011 consumption was billed under the ELGS rate design, given a 35.8 per cent increase in consumption over an F2005 – F2007 HBL.


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Exhibit:B-7

11.0 Reference: Exhibit B-1, Chapter 4, p.4-10; Exhibit B-1, Appendix K, Baseline Determination; Exhibit B-5, BCUC IR 1.27.3; CEC IR 1.4.4; CEC IR 1.4.5

Dr. Orans states:

”Using a three-year rolling average of historic consumption to determine an account’s baseline smoothes out year-to-year usage fluctuations and can better reflect an account’s long-term consumption trend than a baseline based on a single year of billing data. The three-year average method also has regulatory precedent in British Columbia; …” [p.4-10]

And:

“the three-year rolling average calculation of monthly baselines provides a formulaic way to balance the competing interests of customers who are conserving or whose usage is declining, and whose usage is increasing;” [p.4-15]

In Exhibit B-5, BCUC IR 1.27.3, BC Hydro states:

“…The three-year rolling-average baseline does a good job of addressing bill volatility. A rolling baseline with more years could provide a stronger conservation incentive, but would also increase the timeframe over which incremental energy consumption above baseline is exposed to LRMC. If the three-year rolling average is judged to provide too weak a conservation incentive, the baseline period could be lengthened.”

In Exhibit B-5, CEC IR 1.4.4, BC Hydro states:

“… A five-year rolling average baseline definition was also considered as a way to provide additional conservation incentives. Ultimately, BC Hydro believed that the three-year rolling average baseline definition provided a sufficiently strong incentive for new conservation investments, while balancing the interests of existing customers.”

2.11.1 What would be the effect on net conservation and on bill volatility of using a five-year rolling average instead of a three-year rolling average, other aspects of the rate design being as proposed? An eight-year rolling average?

RESPONSE:

The methodology BC Hydro uses to provide estimates of conservation is completed for a single year, using price elasticity estimates for a single year, and is therefore not


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Exhibit:B-7

sensitive to the multi-year effect of the baseline definition. Rate forecasts for each year are then converted to a forecast of annual conservation.

BC Hydro believes that a longer rolling average baseline period could provide a stronger conservation signal than a shorter one. However, BC Hydro has not developed separate conservation estimates for these different baseline definitions, as BC Hydro’s rates model for estimating savings does not take this function into account. Even if BC Hydro had an estimate of potential conservation savings related to these different baselines, to determine the net impact on BC Hydro’s overall DSM plan savings, BC Hydro would need to consider these estimates in the context of other DSM initiatives (e.g., DSM related codes and standards and Power Smart initiatives).

Increasing the length of the period of the rolling average will decrease bill volatility but BC Hydro does not have sufficient data to quantify this.


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Exhibit:B-7



2.12.1 Please confirm that changing to a 70% to 130% Price Limit Band from an 80% to 120% Price Limit Band, other things being equal, would yield 1,510 GWh – 1,393 GWh = 117 GWh additional Net Conservation.

RESPONSE:

Not confirmed.


Changing the Price Limit Bands to 70:130 from 80:120, all else being equal, would yield 1,566 GWh – 1,296 GWh = 270 GWh additional conservation in F2015 (refer to Scenarios LGS 22 and LGS 0).

Note that the 1,510 GWh conservation quoted in the question above is for a generic two-part design with a 70:130 Price Limit Band and does not reflect the impacts of the phase-in to LRMC, anomaly adjustment, and initial baseline proposal.


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Exhibit:B-7



2.12.2 For what reasons did BC Hydro select an 80% to 120% Price Limit Band instead of, say, a 70% to 130% Price Limit Band?

RESPONSE:

In selecting the Price Limit Band, BC Hydro’s goal was to balance the sometimes conflicting goals of maximizing conservation, while minimizing bill volatility and promoting customer understanding and acceptance of the proposed rate design. Wider Price Limit Bands increase both conservation and customer understanding at the expense of increased bill volatility.

In BC Hydro’s opinion, compared to an 80:120 Price Limit Band design, the increased bill volatility resulting from a 70:130 Price Limit Band outweighs the benefits of higher conservation and increased customer understanding. BC Hydro believes the 80:120 Price Limit Band appropriately balances conservation, bill volatility, and customer understanding goals.


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Exhibit:B-7



2.12.3 Please provide a version of Table L-3 showing Scenarios 70:140 Price Limit Band, 60:160 Price Limit Band, and 50:200 Price Limit Band.

RESPONSE:

Please refer to the tables below, each of which corresponds to a scenario shown in the response to BCUC IR 2.1.2.

The first table shows the bill volatility impacts, net conservation, percent of bills with consumption outside of the Price Limit Bands, and percent of bills at the minimum energy rate for the three different Price Limit Band scenarios requested. Aside from the changing Price Limit Bands, and except as noted n the following paragraph, all assumptions and data are consistent with BC Hydro’s proposed LGS design. Tables 2 - 4 show the bill volatility distribution for the three scenarios.

To respond to this information request BC Hydro modified its rate model to automatically calculate zero net conservation for all bills that are at the Minimum Energy Charge. This modification was not needed for BC Hydro’s filed scenarios because BC Hydro’s Price Limit Bands almost always limited the amount of conservation credit received to keep bills from hitting the Minimum Energy Charge. In other words, the smaller Price Limit Bands studied by BC Hydro would automatically reset the conservation price signal to the lower Tier 1 or Tier 2 energy prices, and thereby limit both the net conservation and conservation incentives for those bills.

The Price Limit Bands in this data request, however, are so wide that they would result in a significant number of bills seeing the Minimum Energy Charge while still being within the Price Limit Bands. Indeed, in some cases, the percentage of bills at the minimum energy rate exceeds the percentage of bills outside of the Price Limit Band. The rate model modification described above prevents the model from attributing any conservation to those accounts that are subject to the Minimum Energy Charge.


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Exhibit:B-7

Scenario Year

NetConserva

tion

BillsOutside

PriceLimit Band

Bills at Min. Energy Rate

Min % Avg % Max % GWh % %FY2011 -45.89% 0.02% 15.14% 144 4.80% 0.28%FY2012 -46.77% 0.01% 13.61% 545 4.81% 0.22%FY2013 -50.88% -0.25% 25.53% 1004 6.57% 1.20%FY2014 -60.27% -0.48% 33.86% 1299 7.31% 2.29%FY2015 -68.17% -0.84% 42.82% 1594 8.84% 3.80%

Mean or Sum -54.39% -0.31% 26.19% 4585 6.47% 1.56%FY2011 -46.01% 0.00% 18.71% 146 2.48% 0.49%FY2012 -47.68% 0.00% 16.49% 551 2.49% 0.38%FY2013 -57.47% -0.28% 33.70% 1016 3.61% 1.76%FY2014 -65.31% -0.50% 43.47% 1316 4.05% 2.77%FY2015 -70.93% -0.84% 51.39% 1621 5.01% 4.24%

Mean or Sum -57.48% -0.32% 32.75% 4649 3.53% 1.93%FY2011 -46.01% -0.02% 23.22% 147 1.29% 0.64%FY2012 -47.68% -0.01% 22.74% 554 1.29% 0.50%FY2013 -60.75% -0.29% 44.08% 1023 1.86% 1.91%FY2014 -67.44% -0.50% 56.12% 1326 2.18% 2.93%FY2015 -71.22% -0.81% 69.57% 1634 2.74% 4.39%

Mean or Sum -58.62% -0.33% 43.15% 4684 1.87% 2.07%

Volatility Impacts (relative to current structure)

60:160 price limit band



Table 1: Volatility Impacts for a 70:140 Price Limit Band (scenario LGS 23)


-30% to -25% 1 - 41 65 115 -25% to -20% 20 12 56 95 151 -20% to -15% 34 33 116 187 247 -15% to -10% 81 65 239 302 380 -10% to -5% 311 278 553 640 668

-5% to 0% 1,993 2,031 1,485 1,186 906 0% to 5% 2,272 2,299 1,442 1,113 857

5% to 10% 422 376 648 659 600 10% to 15% 61 32 271 346 422 15% to 20% 1 - 167 196 243 20% to 25% - - 45 128 165 25% to 30% - - 2 58 111 30% to 35% - - - 15 70 35% to 40% - - - - 28 40% to 45% - - - - 7 45% to 50% - - - - -

50% and above - - - - -


Page 3 of 3


Exhibit:B-7



-30% to -25% 12 4 40 65 115 -25% to -20% 17 20 64 107 157 -20% to -15% 35 30 113 181 268 -15% to -10% 92 80 241 319 393 -10% to -5% 305 267 590 659 699

-5% to 0% 2,002 2,036 1,497 1,211 912 0% to 5% 2,228 2,255 1,403 1,076 835

5% to 10% 390 359 591 624 547 10% to 15% 95 69 256 299 379 15% to 20% 15 8 138 176 230 20% to 25% - - 84 115 135 25% to 30% - - 32 81 89 30% to 35% - - 6 47 96 35% to 40% - - - 16 54 40% to 45% - - - 3 30 45% to 50% - - - - 15

50% and above - - - - 4



-30% to -25% 15 8 35 66 121 -25% to -20% 17 18 64 113 161 -20% to -15% 39 31 119 188 274 -15% to -10% 92 86 245 331 417 -10% to -5% 308 262 617 689 725

-5% to 0% 2,023 2,050 1,520 1,213 919 0% to 5% 2,192 2,232 1,368 1,052 806

5% to 10% 379 341 560 594 510 10% to 15% 89 68 242 283 362 15% to 20% 33 27 124 157 204 20% to 25% 4 2 81 102 133 25% to 30% - - 33 74 78 30% to 35% - - 20 54 82 35% to 40% - - 15 23 51 40% to 45% - - 4 19 35 45% to 50% - - - 12 39

50% and above - - - 9 36


Page 1 of 1


Exhibit:B-7

13.0 Reference: Exhibit B-5, BC Hydro response to BCUC IR 1.27.3

2.13.1 Please explain why Hydro believes that the conservation effect of the LGS rate design is independent of the resetting of the HBL.

RESPONSE:



Page 1 of 1


Exhibit:B-7


2.14.1 If a customer is aware that a housekeeping measure that reduces energy use by three kWh in year one (with no continuing reductions in subsequent years) reduces its bill by three kWh times the LRMC for the current year, but results in the HBL being adjusted downward one kWh in each of the following three years, resulting in one additional kWh in each year being priced at the LRMC rather than the Tier 2 energy rate, would the customer evaluate the dollar savings as 3 kWh x LRMC – (LRMC – Tier 2 rate) × (1/(1+r) + 1/(1+r)2 + 1/(1+r)3), where r is the customer’s discount rate, and assuming no CARC?

RESPONSE:

Yes. This example also assumes:

1) No phase-in of LRMC;

2) The 3 kWh reduction is within the Price Limit Band;

3) The Minimum Energy Charge does not apply;

4) All ELGS energy applicable to baseline quantities is billed at Tier 2;

5) The housekeeping measure has a capital cost of zero; and

6) All kWh savings take place at the beginning of each year.


Page 1 of 1


Exhibit:B-7


2.14.2 If the LRMC is 12¢/kWh, the Tier 2 rate is 3.7¢/kWh, and the customer’s discount rate is 10%, and assuming no CARC, please show the calculation of the customer’s net present value per kWh of a 3 kWh conservation measure in year one.

RESPONSE:

Assuming the 3 kWh reduction is within the Price Limit Band; the Minimum Energy Charge does not apply; there is no CARC: the customer’s real discount rate is 10 per cent; and all kWh savings take place at the beginning of each year, then the formula provided in BCSEA IR 2.14.1 can be used to calculate the NPV per kWh of savings versus what the customer would have paid under the current design with no usage change. The result of this calculation is 5.1 cents per kWh of savings. The calculation is provided below.

Formula Year 1 Year 2 Year 3 Year 4Year 5

& BeyondA Baseline kWh x (x+x+x-3)/3 = x-1 x-1 x-1 xB Actual usage kWh x-3 x x x xC = 3.7 * A Bill for Baseline Usage (cents) 3.7 * x 3.7 * (x-1) 3.7 * (x-1) 3.7 * (x-1) 3.7 * xD = 12 * (B - A) Bill for Incremental Usage (cents) 12 * <3> 12 * 1 12 * 1 12 * 1 0E = 3.7 * x Bill with no usage change (cents) 3.7 * x 3.7 * x 3.7 * x 3.7 * x 3.7 * xF = C + D - E Bill change (cents) <36> 12 - 3.7 12 - 3.7 12 - 3.7 0

G kWh Savings 3 0 0 0 0H Discount Factor (1 + 0.1) ^ 0 (1 + 0.1) ^ 1 (1 + 0.1) ^ 2 (1 + 0.1) ^ 3 (1 + 0.1) ^ 4

I = F / H PV of Bill Change (cents) -36 7.5 6.9 6.2 - J = SUM ( I ) Sum PV Bill Change (cents) (15.4) K = sum (G / H) NPV kWh 3.0 L = J / K NPV Bill Change / NPV kWh (cents/kWh) (5.1)


Page 1 of 1


Exhibit:B-7


2.14.3 Should the customer’s NPV per kWh of conservation in year one be treated as the price signal for estimating the conservation effect of the rate design? If not, why not? How does this compare with the logic described in Appendix P, which uses an LRMC-based marginal price signal? What conservation longevity assumptions are associated with the elasticity figure used in Appendix P?

RESPONSE:

The conservation price signal is the customer’s marginal price of energy in a given month. As demonstrated below, in certain circumstances, this can be equal to the customer’s NPV of bill savings per kWh of conservation. The correct way to evaluate the marginal price signal is on a monthly basis, without discounting, per the logic described in Appendix P, which uses an LRMC-based price signal when a customer’s consumption is within the Price Limit Band. The expected conservation impact over one year is the sum of the 12-monthly conservation calculations.

Under the proposed design, a customer can conserve up to 20 per cent of its baseline usage and receive credit at LRMC for this conservation. Assuming the customer does so, the NPV per kWh of conservation is equal to LRMC. For example, assuming all conservation occurs at year end, and assuming the customer’s discount rate equals R:

PV bill savings = 12 months X .2 X HBL X LRMC / (1+R) PV kWh saved = .2 X HBL X 12 months / (1+R) PV bill savings / PV kWh saved = LRMC

If a customer conserves more than 20 per cent of its baseline in some months and less than 20 per cent of its baseline in some months, its PV bill savings / PV kWh saved will be less than LRMC. In this case, the NPV per kWh conservation is not equal to the marginal rate seen by the customer in any month in the given year and therefore should not be used to produce a conservation estimate.

The elasticity assumption described in Appendix P is intended to be used to calculate rate-induced behavioural conservation impacts for a 1-year period. It is not a long-run elasticity for calculating program- or standards-induced conservation. There is no specific longevity period associated with the elasticity assumption described in Appendix P.

Commercial Energy Consumers Association of British ColumbiaInformation Request No. 2.1.1 Dated: December 21, 2009British Columbia Hydro & Power Authority Response issued January 22, 2010

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Exhibit:B-7

1.0 Reference: Exhibit B-5, CEC 1.6.2

2.1.1 Given that this issue is a concern for BC Hydro on an ongoing basis, would BC Hydro consider allowing initial LGS HBLs to be established on the higher of the 2005, 2006, 2007 period or the 2007, 2008, 2009 period?

RESPONSE:

Please refer to the responses to BC Ferries IR 2.2.1, PPI IR 2.1.1, and Scenario LGS 3 in the response to BCUC IR 2.1.2.


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Exhibit:B-7

2.0 Reference: Exhibit B-5, BCUC 1.42.4, CEC 1.7.1 and 1.7.2 and 1.7.3 and 1.7.4

2.2.1 Would BC Hydro agree that there could be other anomalous events, which could affect the implementation of the HBL from the customer’s point of view?

RESPONSE:

Consistent with other elements of the LGS rate, BC Hydro is proposing a formulaic approach to dealing with atypical consumption periods and their impact on HBLs. Using a formulaic approach means BC Hydro is not adjusting for a specific event and does not need to know the reason behind the exceptionally low consumption or to judge whether it was caused by the type of event that justifies an HBL adjustment. Please also refer to the response BCUC IR 1.42.1.

BC Hydro is trying to accommodate as many customers as possible with the LGS proposal which requires making the rate and its administration as formulaic as possible, without allowing for unique customer circumstances. This is why BC Hydro believes the anomaly rule must remain formulaic.

As discussed further in the response to BCUC IR 1.42.3, the anomaly rule is designed to address short-lived anomalous events that do not happen regularly. Approximately 2 per cent of bills are impacted when the anomaly rule is limited to two months. Allowing for more anomaly adjustments may benefit individual customers but has the potential to increase the Part 1 rate adjustment, which impacts all customers.

Modelling indicates that the impact to the Part 1 rate adjustment as a result of increasing the number of anomaly adjustments is minimal. Over the F2011 to F2015 period, a $5.5 million decrease to Part 1 rates is required for revenue neutrality with two anomaly adjustments per year versus a $4.2 million decrease to Part 1 rates with four anomaly adjustments per year. As a result of increasing the number of adjustments allowed from two per year to four per year, an additional $1.3 million would need to be collected from the entire class over a five-year period.

Please also refer to the response to CEC IR 2.3.1.


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Exhibit:B-7


2.2.2 Would BC Hydro agree that revenue is not lost but that revenue is not collected as a consequence of underestimating the HBL because of anomalies, which may be part of the business context but for which the customer would not expect to be paying a premium for conservation and efficiency?

RESPONSE:

BC Hydro’s proposed Anomaly Rule adjusts individual customer baselines to exclude abnormally low consumption months from the HBL calculation. The result in most cases is a higher HBL, less exposure to the higher LRMC-based rates and less revenue than would otherwise be the case. BC Hydro proposes that the lost revenue be made up by the proposed Part 1 price adjustment.

Modelling has shown the Anomaly Rule to have minimal impact on the Part 1 rate adjustment.

BC Hydro does not see any part of the proposed anomaly rule or rate structure providing a premium to customers. All elements proposed rate structure are cost-based.


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Exhibit:B-7


2.2.3 Such an example might be when customers are moved out of a building for a period of time to upgrade the facilities and install new conservation and efficiency equipment. The limits on the anomaly rules would seem to limit the rate designs ability to address infrequent and significant changes in load. Would BC Hydro see some flexibility on this issue as possible?

RESPONSE:

Please refer to the responses to CEC IRs 2.2.1 and 2.3.1.


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Exhibit:B-7


2.2.4 Does this certainty derive from the sequencing of anomaly recognition being applied to the first instance and then the second instance in order?

RESPONSE:

Yes, sequencing of the anomaly recognition rule allows BC Hydro to avoid recalculating customer HBLs and the billing adjustments that would result.

There would be no technical implementation barriers to recognizing a third anomaly in sequence.


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Exhibit:B-7


2.2.5 What issues would be involved to recognize a third anomaly in sequence?

RESPONSE:

Please refer to the response to CEC IR 2.2.4.


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Exhibit:B-7


2.3.1 Please show the same table as L-8 for anomaly adjustments allowing 2 (current BCH proposal), 4, 6 events per year.

RESPONSE:

To accurately respond to this question, BC Hydro has expanded its modeling of anomalies to capture the impact of an anomaly adjustment on both an account’s initial and ongoing HBL. For the Application and for the preparation of the first round of IR responses, BC Hydro’s modeling of anomalies reflected how anomalous future use would modify baselines, without consideration of the impact of the rule on an account’s initial baseline. This simplified modeling approach results in a slightly lowered estimate of initial HBLs and an insignificant underestimate of the revenues required to be collected from Part 1 energy adjustments under BC Hydro’s proposed anomaly rule. While this underestimate is immaterial for BC Hydro’s proposal, BC Hydro has adjusted its modelling to be responsive to this information request.

The following tables replicate Table L-8 and capture volatility impacts, net conservation, percent of bills with consumption outside of the Price Limit Bands, and percent of bills at the minimum energy rate for three different anomaly scenarios using the modified anomaly rule model described above. Aside from the changing maximum number of anomalies allowed, every variable remains the same as in BC Hydro’s proposed LGS design.

The three scenarios under the Scenario heading in the table below correspond to Scenarios LGS 5, LGS 6, and LGS 7, respectively, in the matrix attached to the response to BCUC IR 2.1.2.


Page 2 of 4


Exhibit:B-7

Table 1: Comparison of Anomaly Rule Scenarios (Scenarios LGS 5 through LGS 7)

Scenario Year

Net Conserva

tion

BillsOutside

Price Limit Band


Min % Avg % Max % GWh % %FY2011 -42.12% 0.00% 8.92% 132 11.59% 0.12%FY2012 -40.61% -0.01% 8.10% 477 11.63% 0.08%FY2013 -50.89% -0.18% 16.49% 855 15.30% 0.37%FY2014 -54.40% -0.35% 21.77% 1086 16.61% 0.70%FY2015 -58.29% -0.63% 26.72% 1298 19.45% 1.62%

Mean or Sum -49.26% -0.23% 16.40% 3848 14.91% 0.58%FY2011 -42.25% 0.00% 8.95% 132 11.23% 0.13%FY2012 -41.55% -0.01% 8.13% 478 11.26% 0.10%FY2013 -50.89% -0.19% 16.52% 856 15.08% 0.39%FY2014 -54.40% -0.35% 21.81% 1088 16.38% 0.71%FY2015 -59.70% -0.64% 26.77% 1301 19.21% 1.63%


Mean or Sum -49.86% -0.24% 16.45% 3858 14.50% 0.60%

6 anomaly adjustments per

year allowed (50% anomaly

threshold)

4 anomaly adjustments per

year allowed (50% anomaly

threshold)

Proposed Design (with application of

anomaly rule to initial baseline)



Page 3 of 4


Exhibit:B-7

Table 2: Volatility Impacts for a Baseline with 2 Anomalies Granted: Scenario LGS 5


-30% to -25% - 1 28 52 93 -25% to -20% - - 49 91 153 -20% to -15% 15 8 108 184 220 -15% to -10% 74 61 238 282 345

-10% to -5% 314 273 541 603 623 -5% to 0% 1,990 2,038 1,440 1,146 894 0% to 5% 2,449 2,496 1,626 1,256 987


50% and above - - - - -



-30% to -25% - 1 26 53 93 -25% to -20% 1 - 50 93 154 -20% to -15% 16 9 108 178 217 -15% to -10% 72 61 237 286 350

-10% to -5% 314 276 545 602 612 -5% to 0% 1,974 2,015 1,435 1,148 905 0% to 5% 2,482 2,529 1,627 1,255 984


50% and above - - - - -


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Exhibit:B-7



-30% to -25% - 1 28 52 93 -25% to -20% 1 - 49 95 153 -20% to -15% 16 9 109 174 219 -15% to -10% 72 61 237 290 348

-10% to -5% 314 275 545 596 610 -5% to 0% 1,974 2,010 1,436 1,155 903 0% to 5% 2,486 2,538 1,631 1,257 994


50% and above - - - - -


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Exhibit:B-7


2.3.2 Please show the same table as L-8 for anomaly adjustments allowing anomalies to be identified at 60%, 55%, 50%, 45%, 40%, 35% and 30% of the HBL.

RESPONSE:

The following tables capture volatility impacts, net conservation, percent of bills with consumption outside of the Price Limit Bands, and percent of bills at the minimum energy rate for three different anomaly scenarios using the expanded anomaly rule model described in the response to CEC IR 2.3.1. Aside from the changing maximum number of anomalies allowed, every variable remains the same as in BC Hydro’s proposed LGS design. Tables 2-8 show bill volatility distributions for the scenarios.

The scenarios in the tables below correspond to Scenarios LGS 8, LGS 9, LGS 10, LGS 11, LGS 12, LGS 13, and LGS 14, which respectively identify anomalies at 30 per cent, 35 per cent, 40 per cent 45 per cent, 50 per cent, 55 per cent, 60 per cent, in response to BCUC IR 2.1.2.


Page 2 of 6


Exhibit:B-7

Table 1: Comparison of Anomaly Rule Scenarios (Scenarios LGS 8 Through LGS 14)

Scenario Year

Net Conserva

tion

BillsOutside

PriceLimit Band


Min % Avg % Max % GWh % %FY2011 -41.25% 0.00% 8.90% 131 11.82% 0.12%FY2012 -40.31% 0.00% 8.09% 476 11.84% 0.09%FY2013 -50.89% -0.17% 16.47% 854 15.46% 0.36%FY2014 -54.40% -0.33% 21.74% 1084 16.78% 0.68%FY2015 -58.50% -0.61% 26.67% 1295 19.66% 1.62%







Mean or Sum -48.78% -0.24% 16.44% 3853 14.79% 0.58%

60% anomaly threshold (2 anomaly adjustments per year

allowed)


allowed)

Proposed Design (with 50% anomaly

threshold and 2 anomaly adjustments

per year allowed)


allowed)


allowed)


allowed)


allowed)



Page 3 of 6


Exhibit:B-7

Table 2: Volatility Impacts for a Baseline with Anomalies Identified at 30%: Scenario LGS 8


-30% to -25% - 1 28 56 92 -25% to -20% - - 51 90 147 -20% to -15% 13 7 107 179 223 -15% to -10% 72 62 235 287 348

-10% to -5% 317 275 544 599 622 -5% to 0% 1,999 2,043 1,442 1,159 900 0% to 5% 2,438 2,483 1,621 1,231 974


50% and above - - - - -


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Exhibit:B-7



-30% to -25% - 1 29 56 92 -25% to -20% - - 50 89 149 -20% to -15% 13 7 107 180 224 -15% to -10% 72 62 237 287 346

-10% to -5% 320 273 542 597 624 -5% to 0% 1,995 2,042 1,442 1,160 899 0% to 5% 2,441 2,487 1,623 1,233 974


50% and above - - - - -



-30% to -25% - 1 28 54 90 -25% to -20% - - 50 89 151 -20% to -15% 15 8 107 180 222 -15% to -10% 72 61 239 286 345

-10% to -5% 318 273 537 604 626 -5% to 0% 1,994 2,042 1,443 1,152 900 0% to 5% 2,443 2,489 1,625 1,239 973


50% and above - - - - -


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Exhibit:B-7



-30% to -25% - 1 28 54 92 -25% to -20% - - 50 90 150 -20% to -15% 16 8 108 180 223 -15% to -10% 71 61 239 284 344

-10% to -5% 314 273 536 604 630 -5% to 0% 1,997 2,038 1,442 1,152 893 0% to 5% 2,442 2,496 1,624 1,245 979


50% and above - - - - -



-30% to -25% - 1 28 52 93 -25% to -20% - - 49 91 153 -20% to -15% 15 8 108 184 220 -15% to -10% 74 61 238 282 345

-10% to -5% 314 273 541 603 623 -5% to 0% 1,990 2,038 1,440 1,146 894 0% to 5% 2,449 2,496 1,626 1,256 987


50% and above - - - - -


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Exhibit:B-7



-30% to -25% - 1 28 53 94 -25% to -20% - - 49 88 155 -20% to -15% 16 9 108 189 217 -15% to -10% 73 60 243 279 346

-10% to -5% 312 276 541 602 619 -5% to 0% 1,989 2,029 1,435 1,147 898 0% to 5% 2,456 2,504 1,627 1,256 986


50% and above - - - - -



-30% to -25% - 1 29 53 89 -25% to -20% - - 49 89 159 -20% to -15% 17 9 107 189 216 -15% to -10% 74 61 242 278 344

-10% to -5% 308 275 543 596 609 -5% to 0% 1,981 2,025 1,436 1,158 905 0% to 5% 2,467 2,513 1,624 1,247 996


50% and above - - - - -


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Exhibit:B-7


2.4.1 Please provide an analysis of the conservation results for the LGS rate class for breakpoint thresholds between the MGS and LGS classes that add 100, 200, 300, 500, 1000, 1500 and 2000 accounts to the LGS by moving breakpoint from the 150 KW toward 100 KW. Please show the LGS conservation and the MGS conservation under these scenarios.

RESPONSE:

Please refer to the responses to BCUC IRs 2.1.2 and 2.1.2.2, and the following scenarios:

(1) Scenario LGS 15 at a breakpoint of 100 kW, adding about 3,000 more accounts to the LGS class (corresponding MGS scenario is Scenario MGS 3).

(2) Scenario LGS 16 at a breakpoint of 120 kW, adding about 1,500 more accounts to the LGS class (corresponding MGS scenario is Scenario MGS 4).

(3) Scenario LGS 17 at a breakpoint of 140 kW, adding about 500 more accounts to the LGS class (corresponding MGS scenario is Scenario MGS 5).

The accounts enumerated in this response are from the data sets adjusted to remove partial billing history.

BC Hydro has provided more information than was requested in BCUC IR 2.1.2.2 to provide additional data points to show the trends if additional accounts moved from MGS to LGS, and vice versa; that information substantially responds to this information request.


Page 1 of 1


Exhibit:B-7


2.4.2 Please provide an analysis of the conservation results for the LGS class for breakpoints between the MGS and LGS classes that deduct 100, 200, 300, 500, 1000, 1500 and 2000 accounts. (Please show the LGS and MGS conservation under these scenarios)

RESPONSE:

Please refer to the responses to BCUC IR 2.1.2 and CEC IR 2.4.1and the following scenarios:

(1) Scenario LGS 18 at a breakpoint of 500 kW (corresponding MGS scenario is Scenario MGS 6), leaving about 1,000 accounts in the LGS class.

(2) Scenario LGS 19 at a breakpoint of 1,000 kW (corresponding MGS scenario is Scenario MGS 7), leaving about 500 accounts in the LGS class.


Page 1 of 1


Exhibit:B-7


2.5.1 Would it be true that the difference between the savings in 1 and 2 above would appear as reductions to the LTRIF. If so, could BC Hydro please provide the differences by year?

RESPONSE:

The impact on the long term rate increase forecast is uncertain. Energy conservation will decrease BC Hydro’s energy purchase costs. However, it will also reduce revenues. The long term rate increase forecast will only generally be reduced if the reduction in costs exceeds the reduction in revenues. To the extent the LGS rate (and revenues) are matched with the marginal cost of new supply, the effect on the LTRIF may be small in the long run.

Generically, the two-part rate structure is designed to minimize the differences between BC Hydro’s revenues and incremental costs as customers change their consumption.


Page 1 of 5


Exhibit:B-7


2.6.1 Could BC Hydro please provide the same phase in graphs provided in response to CEC 1.24.1, but instead with the flattened demand charge included?

RESPONSE:

The graphs below show average rates for 1) the current rate structure, 2) BC Hydro’s proposed rates, 3) the rate alternative with increased basic charge, and 4) the rate alternative with the flattened demand charge. Each graph assumes a load factor of 46 per cent.

Note that the prior plots used data points of 35, 50, 70, 90, 110, 130, and 150 kW. The plots in this data response use 32 data points per series to increase the precision of the plots. In particular, these plots calculate the average rate for each demand from 35 kW to 50 kW, allowing these plots to more accurately show the increase and descent of the average rate over this range.


Page 2 of 5


Exhibit:B-7

0.060

0.065

0.070

0.075

0.080

0.085

0.090

0.095

35 55 75 95 115 135

Maximum Monthly Demand (kW)

Aver

age

Ele

ctric

ity R

ate

($/k

Wh)

Current Rate Structure Proposed Rate

Increased Basic Charge Flattened Demand Charge

FY2011 Average Rate Comparison

c

0.060

0.065

0.070

0.075

0.080

0.085

0.090

0.095

35 55 75 95 115 135


Ave

rage

Ele

ctri

city

Rat

e ($

/kW

h)

Current Rate Structure Proposed RateIncreased Basic Charge Flattened Demand Charge


c


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Exhibit:B-7

0.060

0.065

0.070

0.075

0.080

0.085

0.090

0.095

0.100

0.105

35 55 75 95 115 135


Aver

age

Ele

ctric

ity R

ate

($/k

Wh)




c


Page 4 of 5


Exhibit:B-7

0.060

0.065

0.070

0.075

0.080

0.085

0.090

0.095

0.100

0.105

0.110

35 55 75 95 115 135


Aver

age

Ele

ctric

ity R

ate

($/k

Wh)




c

0.060

0.070

0.080

0.090

0.100

0.110

0.120

35 55 75 95 115 135


Ave

rage

Ele

ctri

city

Rat

e ($

/kW

h)

Current Rate Structure Proposed RateIncreased Basic Charge Flattened Demand Charge


c


Page 5 of 5


Exhibit:B-7

0.060

0.070

0.080

0.090

0.100

0.110

0.120

0.130

35 55 75 95 115 135


Aver

age

Ele

ctric

ity R

ate

($/k

Wh)




c


Page 1 of 1


Exhibit:B-7


2.6.2 Would there be a conservation effect if the demand charge were rolled into the energy charge for the MGS?

RESPONSE:

Yes, since the forecasted level of conservation is driven by the change in a customer’s marginal rate, rolling the demand charge into the energy charge could have an impact on conservation. The impact would depend on how much of the demand charge was rolled into the Tier 1 energy charge, versus Tier 2 energy charge. Also, the conservation would be affected by how much of a customer’s usage was previously billed at the tier 3 demand charge. The higher the exposure to the tier 3 demand charge, the more bill reduction the customer would see from the elimination of the demand charge. This bill reduction would dampen or possibly override the stronger conservation signal provided by higher energy charges.

Without a specific rate design, BC Hydro cannot forecast the conservation effect of a demand charge being rolled into the energy charge.


Page 1 of 1


Exhibit:B-7


2.6.3 Is the conservation effect determined on the total bill change or on the energy charge bill impact?

RESPONSE:

The conservation effect is determined by the change in the account’s marginal rate. The marginal rate is composed of both the marginal energy rate and the marginal demand rate for the account. The marginal rate represents how an account’s bill would change for a 1 kWh change in usage and associated change in monthly peak demand. The conservation analysis assumes that an account’s monthly load factor would not change.


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Exhibit:B-7


2.7.1 Please show the same analysis as is provided in response to this question for the top 10, 20, 30, 40, 100, 200, 300, 500, 1000, 2000, 3000 and 5000 MGS accounts.

RESPONSE:

The response to CEC IR 1.25.1 shows the maximum annual bill impact and the maximum cumulative bill impacts due to rate restructuring. The maximum impacts would be the same for the top 10, 20, 30, 40, 100, 200, 300, 500, 1,000, 2,000, 3,000, and 5,000 accounts.

However, the average bill impacts would change as the number of MGS accounts included in the “top” group changes. Shown below are the average bill impacts for the top 10, 20, 30, 40, 100, 200, 300, 500,1,000, 2,000, 3,000, and 5,000 accounts. The “top” accounts are determined by their bill increase in each year, so the members of each top group could vary slightly from year to year. The bill increases are relative to each account’s annual bill from the prior year. The average is calculated as the average of each account’s annual bill increase percentage (i.e., the average is not weighted by sales or dollars).


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Exhibit:B-7

Number of rate design Average Annual Bill Increase over Prior Yearsample accounts F2011 F2012 F2013 F2014 F2015 F2016

10 12.3% 7.2% 12.2% 14.2% 13.9% 15.1%20 12.3% 7.1% 12.1% 14.0% 13.8% 15.0%30 12.3% 7.1% 12.1% 13.9% 13.7% 14.9%40 12.2% 7.1% 12.0% 13.9% 13.6% 14.8%

100 12.1% 6.9% 11.7% 13.5% 13.2% 14.4%200 12.1% 6.7% 11.5% 13.2% 12.9% 14.1%300 12.0% 6.6% 11.3% 13.0% 12.6% 13.9%500 11.9% 6.4% 11.0% 12.6% 12.2% 13.5%

1,000 11.8% 6.1% 10.5% 12.0% 11.5% 12.8%2,000 11.6% 5.7% 9.9% 11.1% 10.5% 11.8%3,000 11.4% 5.3% 9.3% 10.4% 9.7% 10.9%5,000 11.1% 4.8% 8.5% 9.3% 8.3% 9.5%

The next table shows the average cumulative bill increases for the top MGS accounts. The accounts in each group in each year are the same as those in the table above. The assumed CARC in each table is as shown in the response to CEC IR 1.25.1.

Number of rate design Average Cumulative Bill Increase over F2010sample accounts F2011 F2012 F2013 F2014 F2015 F2016

10 12.3% 20.4% 35.1% 54.2% 75.7% 102.2%20 12.3% 20.3% 34.9% 53.8% 75.0% 101.2%30 12.3% 20.2% 34.7% 53.5% 74.5% 100.4%40 12.2% 20.2% 34.6% 53.2% 74.0% 99.8%

100 12.1% 19.9% 33.9% 52.0% 72.1% 97.0%200 12.1% 19.6% 33.3% 50.9% 70.3% 94.4%300 12.0% 19.4% 32.9% 50.2% 69.1% 92.6%500 11.9% 19.1% 32.3% 49.0% 67.2% 89.8%

1,000 11.8% 18.6% 31.1% 46.9% 63.8% 84.8%2,000 11.6% 17.9% 29.5% 44.0% 59.1% 77.9%3,000 11.4% 17.3% 28.3% 41.7% 55.5% 72.6%5,000 11.1% 16.4% 26.3% 38.1% 49.7% 64.1%


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Exhibit:B-7


2.7.2 Please also show with this analysis the total load for the group of accounts and the conservation savings assumed to be generated by the price increases.

RESPONSE:

The tables below show the annual consumption and the net conservation for the MGS accounts that receive the largest annual percentage bill increases. The first table shows the number of forecast accounts that correspond to the 10, 20, 30, 40, 100, 200, 300, 500, 1,000, 2,000, 3,000, and 5,000 rate design sample accounts that receive the largest annual percentage bill increases in each year. For example, in the table below, the first row shows that the 10 accounts in the sample represent 11 accounts on a forecast basis. The consumption and conservation estimates shown in the subsequent tables are similarly calibrated to forecast levels.


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Exhibit:B-7

Number of forecast accounts Number of rate design sample accounts F2011 F2012 F2013 F2014 F2015 F2016

10 11 11 11 11 11 11 20 22 22 22 22 22 22 30 34 33 33 33 34 34 40 45 44 44 44 45 45

100 112 111 110 110 112 112 200 224 221 221 220 223 224 300 336 332 331 330 335 335 500 561 553 552 550 558 559

1,000 1,121 1,107 1,103 1,100 1,117 1,118 2,000 2,243 2,214 2,207 2,200 2,233 2,235 3,000 3,364 3,321 3,310 3,300 3,350 3,353 5,000 5,607 5,535 5,516 5,500 5,584 5,588

The table below shows the forecast annual consumption for those accounts.

Annual Consumption (GWh) Number of rate design sample accounts F2011 F2012 F2013 F2014 F2015 F2016

10 10.8 10.7 10.7 10.6 10.8 10.8 20 21.1 20.8 20.7 20.7 21.0 21.0 30 30.9 30.6 30.5 30.4 30.8 30.9 40 40.6 40.1 40.0 39.9 40.5 40.5

100 93.6 92.5 92.2 91.9 93.3 93.4 200 174.8 172.6 172.0 171.5 174.1 174.3 300 249.9 246.9 246.1 245.3 249.1 249.3 500 388.1 383.4 382.1 380.9 386.7 387.0

1,000 689.9 681.1 678.8 676.8 687.2 687.8 2,000 1,183.8 1,168.8 1,164.9 1,161.4 1,179.1 1,180.0 3,000 1,591.5 1,571.4 1,566.3 1,561.5 1,585.3 1,586.6 5,000 2,254.6 2,225.9 2,218.6 2,211.8 2,245.5 2,247.3


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Exhibit:B-7

The table below shows the forecast annual net conservation due to the rate structure change for those accounts.

Annual Net Conservation (GWh) Number of rate design sample accounts F2011 F2012 F2013 F2014 F2015 F2016

10 0.1 0.1 0.3 0.5 0.7 1.0 20 0.1 0.3 0.5 0.9 1.4 1.9 30 0.2 0.4 0.8 1.3 2.0 2.8 40 0.3 0.5 1.0 1.7 2.6 3.7

100 0.6 1.3 2.4 4.0 6.1 8.5 200 1.2 2.3 4.5 7.5 11.3 15.7 300 1.7 3.3 6.4 10.6 16.0 22.4 500 2.6 5.1 9.9 16.4 24.8 34.6

1,000 4.6 9.1 17.4 28.9 43.7 61.0 2,000 7.9 15.5 29.6 49.2 74.2 103.6 3,000 10.5 20.7 39.5 65.8 99.1 138.3 5,000 14.8 29.0 55.4 92.0 138.6 193.3


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Exhibit:B-7


2.8.1 Would it be true to say that over 2000 LGS accounts will have the same or less consumption than the largest MGS account but if they maintain their consumption at the same level as previous years they will have bill impacts 45% lower than the largest MGS customer?

RESPONSE:

It is correct that as many as 2000 LGS accounts would have less annual consumption than the largest MGS account, based on BC Hydro’s rates model.

Under BC Hydro’s proposed two-part rate, if all LGS customers maintain their consumption at the same level as previous years, their bills will increase only by CARC each year. BC Hydro has assumed the cumulative CARC increase (relative to F2010 rates) of 38 per cent in F2015 and 48 per cent in F2016 for the purpose of developing the LGS and MGS rates.

The largest MGS account is modelled to have cumulative bill increases (relative to F2010 rates) of 76 per cent in F2015 and 103 per cent in F2016 inclusive of CARC. Thus, the maximum MGS bill impacts from rate restructuring alone would be 38 per cent in F2015 and 55 per cent in F2016.


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2.8.2 Would it be true to say that close to 800 LGS customers will have the same or less consumption than the top 5% of MGS customers, which would be about 800 MGS customers, but that if they maintain their consumption at the same level as previous years they will have no bill impacts beyond the CARC but that the MGS customers would experience average cumulative bill increases greater than 30% to 40%. (Approximated from answer to CEC 1.25.3 and CEC 1.25.4 – please provide a specific analysis of the cumulative impact).

RESPONSE:

The table above indicates that 779 LGS accounts had F2008 consumption lower than the single MGS customer at the 95th percentile, ordered by consumption.

The average cumulative bill increase from F2010 to F2016 for the 5 per cent largest MGS accounts is about 87 per cent. Comparatively, the CARC cumulative increase over this same period is 47.6 per cent as stated in the response to CEC IR 1.25.3.


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Exhibit:B-7


2.9.1 The CEC intends to provide a proposal that would examine segmentation of the LGS and MGS based on consumption not on capacity. The CEC would intend this design to eliminate this boundary effect between MGS and MGS. The CEC anticipates proposing design scenarios that would provide equal to or more than the conservation impact BC Hydro has proposed. The CEC also anticipates proposing migration rules, which have reasonable levels of mobility between MGS and LGS, and that MGS rate structure design proposals to accompany this proposal to further increases the fairness of bill impacts. The CEC would also be planning a customer panel to speak to the perceived fairness issues with respect to the MGS/LGS boundary proposals. The CEC would be prepared to deal with these issues in an NSP process. The CEC would appreciate being provided the opportunity to work with BC Hydro in modeling these approaches in order to present its proposal. Could BC Hydro please facilitate working with the CEC to analyze these proposals and thereby avoid a dispute over data availability and suitability of the analysis as well as enable a focus on the content of the alternative potentially to the benefit of BC Hydro’s customers?

RESPONSE:

BC Hydro notes that its consultation activities in regard to this application commenced in 2008, almost two years ago. The CEC was involved throughout that process, as well as being a member of the Rates Working Group, a sub-committee of BC Hydro’s Electricity Conservation & Efficiency Advisory Committee. In the course of that time, the CEC has expressed interest in different rate design alternatives.

It is now two months away from the scheduled oral hearing of this LGS rate application, and in that time Vancouver will be hosting the 2010 Winter Olympics, while BC Hydro will be filing a revenue requirements application, and preparing its witnesses for the oral hearing of this LGS rate application. Further, the BCUC has made it clear that it prefers an oral hearing of this application rather than an NSP.

In neither of the two rounds of information requests in this proceeding has the CEC described its rate design proposals, despite assurances from BC Hydro that it would make


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Exhibit:B-7

good faith efforts to model such proposals, so long as they were expressed on the record, through the information request process. BC Hydro has concerns that post-round 2 information requests for modelling of new rate designs will yield new rate designs and evidence that neither the BCUC staff nor other intervenors will have had the opportunity to consider as fully as they otherwise would have.

BC Hydro commits to working with intervenors on their rate design proposals through the normal hearing processes. In particular, BC Hydro expects that it will assess and respond to any motions intervenors might bring regarding "data availability"; pose information requests on any intervenor evidence filed regarding rate design proposals; and cross-examine intervenor witnesses on their evidence and rate design proposals.


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Exhibit:B-7


2.10.1 What would the confidence level be for a sample of 300, 400, 500 and 600?

RESPONSE:



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Exhibit:B-7


2.11.1 Could BC Hydro please provide the analysis for 10% segments of the MGS class in order to size the potential conservation value, and thereby the merits of staying open to the option to extend the two part rate design concept further into the MGS class in the future as BC Hydro has suggested it will be expecting to evaluate? (Please provide the assumptions used for this analysis.)

RESPONSE:

Please refer to the response to BCUC IR 2.1.2 which indicates the amount of conservation that would be obtained by extending a two-part rate to larger segments of the ELGS class than BC Hydro currently proposes. In BC Hydro’s view further analysis is not warranted to justify a review of the LGS rate after three years for the specific purposes of considering an extension of a two-part rate, or otherwise “staying open to the option to extend the two-part rate”.


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2.12.1 The CEC is concerned about the electricity rate design issues that some segments of the commercial customer classes have with the current BC Hydro rate designs and the current proposals for the LGS rate classes. These customers are primarily manufacturing or operating production customers who have to respond to market demands. In so doing they may face demand charges at subsequent periods of time when they may have more limited production. This can also occur at particular times throughout the year when BC Hydro is not capacity constrained or limited. The CEC would like to propose and model a rate design option to be added to the LGS rate design, which would vary the underlying Tier 1 rate component for the Part 1 of the LGS rate. The option would incorporate concepts of collecting revenue requirements for the demand charge by rolling it into the energy charge. The CEC would like to propose and model demand charge concepts which could be applied after a formulaic maximum demand was reached. The CEC would also like to model concepts of a business sector wide participation in scheduling and or limiting demand at the times BC Hydro’s system is capacity constrained in order to contribute to reducing peak demand. The CEC submits that this option would demonstrate an increase in conservation and efficiency results as well as enabling the business sectors seeking this option to be more efficient.

The CEC would also be planning a customer panel to speak to the perceived value improvement issues with respect to the LGS rate design proposals. The CEC is also prepared to deal with these issues in an NSP process. The CEC would appreciate being provided the opportunity to work with BC Hydro in modeling these approaches in order to present its proposal. Could BC Hydro please facilitate working with the CEC to analyze these proposals and thereby avoiding a dispute over data availability and suitability of the analysis as well as enabling a focus on the content of the alternative potentially to the benefit of BC Hydro’s customers?


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Exhibit:B-7

RESPONSE:


Information Request #2: Corix Multi-Utility Services Inc. B.C. Hydro – 2009 LGS Rate Application December 21, 2009

BCUC Project #3698573 Order G-125-09 Page 1

CORIX MULTI-UTILITY SERVICES INC. (“Corix”)

INFORMATION REQUEST NO. 2 TO B.C. Hydro & Power Authority (“B.C. Hydro”)

B.C. Hydro 2009 LGS Rate Application

Question #1: Rate Design – FACOS Study

Reference: Order G-10-08 Compliance Filing for BC Hydro 2007 Rate Design Application (2007 RDA).

On December 15, 2009, BC Hydro filed an updated Fully Allocated Cost of Service (FACOS) Study reflecting F2009 actual results, pursuant to BCUC Directive No. 2 of the 2007 RDA Decision.

Request: 1.1 Please confirm that this Compliance Filing, as filed, is the most current analysis available to assess the relative Revenue-to-Cost ratios of the various rate classes? If not, please provide the most current analysis available.

1.2 As the Revenue-to-Cost ratio of the GS > 35 kW (ELGS) class of customers is now at 110.8% (relative to 106.8% in the 2007 RDA Compliance Filing), will BC Hydro take steps either in this application or in the future to prevent a further increases in cost allocation from other rate classes to ELGS categories (ie. MGS and LGS)?

1.3 Can this FACOS Study be segmented to show how the ELGS will be split between the proposed MGS and LGS classes? If so, please provide the Revenue-to-Cost of the two new rate classes. If not, please explain why this cannot be done and when this information will be available.

1.4 Is it BC Hydro’s intention to equalize the Revenue-to-Cost ratios between these two new proposed classes? If not, what is BC Hydro’s policy in this regard?

1.5 Based on the forecast growth of the various rate classes, what is BC Hydro’s forecast of future Revenue-to-Cost ratios? Will the trend to increasing ELGS Revenue-to-Cost ratios continue if there are no rate re-balancing initiatives undertaken?





Question #2: Transmission Service Stepped Rate (TSR 2005)

Reference: In 2005, the Commission reviewed the issue of a two tier rate structure for Transmission customers (Schedule 1823).

As part of the process it was determined Transmission customers that were re-sellers would be exempt from the rate. The following was extracted from the Reasons for Decision to Order No. G-79-05 (Appendix B, page 4-5 of 54) that stemmed from a Negotiated Settlement Process which included BC Hydro:

“8. Exemptions

At present, FortisBC Inc. (formerly Aquila Networks Canada (British Columbia) Ltd.), the City of New Westminster and the University of British Columbia are exempt from the application of stepped rates. In accepting the Commission's Recommendation #15 in the Heritage Inquiry Report and Recommendations, the Government response described these customers as "effectively distributors who sell the electricity they purchase onwards to end-use customers." BC Hydro proposes to serve these exempt customers under a separate rate schedule, RS 1827.

Two participants to the negotiations (Simon Fraser University ("SFU") and the Vancouver International Airport Authority ("VIAA")) may also wish to seek exemption from stepped rates. All parties agree that the Commission should have the discretion to address the issue of exemptions, and they do not oppose exemptions for SFU or VIAA if they apply at some future date. The parties agree that the Commission should take steps to confirm with Government that the BCUC does have the discretion, or absent such discretion, seek the necessary legislative approvals.”

[Emphasis Added]

Request: 2.1 Please reconcile the decision of BC Hydro to serve these exempt customers under a separate rate schedule, RS 1827, with the BC Hydro’s response to Corix 1.3.1 (Exhibit B-5) where in it stated:“the reason BC Hydro does not propose exemptions for re-sellers or other customers who are not end users is primarily a fairness issue”.

2.2 Please explain why Corix is in any way different from these other re-sellers other than the fact that it is not a Transmission customer?

2.3 Please confirm that BC Hydro continues to believe that the Commission should have the discretion to address the issue of exemptions. If not, why has BC Hydro changed its position?



2.4 Please confirm that each of Fortis BC Inc, the City of New Westminster and the University of British Columbia continues to receive service under RS 1827? Are there any additional customers who now receive service under this rate schedule?

2.5 Has BC Hydro made an application to the Commission to transfer customers under this RS 1827 to RS 1823 or any other existing or future rate schedule or to significantly modify RS 1827? Does it intend to do so in the foreseeable future? If yes, what was or will be the nature of such a filing when was or will this application be filed? If no, please explain why such an application will not be forthcoming?

2.6 Would it be accurate to describe RS 1827 as having a flat (ie. neither inclining nor declining) demand charge? Please confirm that the current demand charge for RS 1827 is $5.260 per kV.A of Billing Demand per Billing Period. What would this charge be in equivalent $ per kW terms?

2.7 Would it be accurate to describe RS 1827 as having a flat (ie. neither inclining nor declining) energy charge? Please confirm that the current energy charge for RS 1827 is 3.083 cents per kWh for all kWh.

2.8 For each customer served under RS 1827 please provide the following information:

2.8.1 Peak Demand (in kV.A) for the most recent fiscal year available.

2.8.2 Annual Energy Consumption (in kWh) for each year from F2005 to the most recent fiscal year for which records are available

2.8.3 The revenue for the most recent fiscal year available segmented as to Basic Charges (if any), Demand Charges, Energy Charges and any other charges applicable under RS 1827.

2.8.4 The equivalent HBL to the proposed RS 1300 (ie. if the same methodology was used on RS 1827 customers as described in Appendix O, Section 6.1, Table O-16, page 23 of 23) for each of F2011 and F2012.



2.9 Please confirm that customers served under RS 1827 are not required to re-sell electricity to their end use customer at the same rates as BC Hydro for the equivalent class of customer. If they are required to sell at the same rates as BC Hydro, please provide the applicable reference in the BC Hydro Electric Tariff.

2.10 Does BC Hydro provide funding directly to any re-sellers served under RS 1827 to aid in conservation programs?

Question #3: Residential Rate Forecasts

Reference: Exhibit B-5, response to Corix 1.1.1, dated December 7, 2009.

Corix is an authorized re-seller of electricity purchased from B.C. Hydro. In excess of 90% of its electricity is sold to residential customers at rates identical to BC Hydro’s residential rates. BC Hydro’s proposed Application, as filed, would see Corix be a RS 1300 customer at its two service area locations.

In order to adequately assess the impact of this Application on its business, Corix needs to understand how future residential rates are expected to move relative to RS 1300 rates, as proposed.

Request: 3.1 Please update Table 5.4 contained in the 2008 RIB Reasons for Decision (G-124-08) at page 89 to reflect the same future cost of power that is now embedded in the LGS rate application.

3.2 Please provide the current residential rate forecast used to estimate future conversation potential in the residential rate class of customers inclusive of Basic Charge, Step 1 and Step 2 energy charges. Note: these do not need to be “tariff ready” per the objection to comply with Corix Request 1.1.1. but the best available forecast currently being used by BC Hydro.

3.3 If BC Hydro is not able to answer Request 3.2, please explain how BC Hydro is able to meaningfully estimate conservation potential of this rate class. Specifically, what methodology is used to calculate residential consumption that does not include elastic demand responses to changes in Step 2 pricing?

3.4 In BC Hydro’s response to Corix 1.3.1 (Exhibit B-5), it stated “it would seem there might be a financial incentive for re-sellers to encourage their customers to reduce energy consumption”. If a re-seller has no clear forecast of future residential and general service rates, how can it discern what that financial incentive might be?

Corix Multi-Utility Services Inc.Information Request No. 2.1.1 Dated: December 21, 2009British Columbia Hydro & Power Authority Response issued January 22, 2010

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Exhibit:B-7

1.0 Rate Design – FACOS Study Reference: Order G-10-08 Compliance Filing for BC Hydro 2007 Rate Design Application (2007 RDA).


2.1.1 Please confirm that this Compliance Filing, as filed, is the most current analysis available to assess the relative Revenue-to-Cost ratios of the various rate classes? If not, please provide the most current analysis available.

RESPONSE:

Confirmed.


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Exhibit:B-7



2.1.2 As the Revenue-to-Cost ratio of the GS > 35 kW (ELGS) class of customers is now at 110.8% (relative to 106.8% in the 2007 RDA Compliance Filing), will BC Hydro take steps either in this application or in the future to prevent a further increases in cost allocation from other rate classes to ELGS categories (ie. MGS and LGS)?

RESPONSE:

Section 58.1 of the UCA currently prevents the BCUC from setting rates for the purpose of changing the revenue-cost ratio of a class of customers. After March 31, 2010, the BCUC may set rates for that purpose, subject to a maximum 2 per cent increase in the revenue-cost ratio of any customer class. BC Hydro currently has no plans to bring a rate application to the BCUC for the purpose of changing revenue-cost ratios.


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Exhibit:B-7



2.1.3 Can this FACOS Study be segmented to show how the ELGS will be split between the proposed MGS and LGS classes? If so, please provide the Revenue-to-Cost of the two new rate classes. If not, please explain why this cannot be done and when this information will be available.

RESPONSE:

BC Hydro would only prepare a FACOS that was segmented into the MGS and LGS rate classes once the proposed split of the ELGS rate class has been approved by the BCUC and if it was clear that a two-part rate would not be extended to the MGS class.

Please also refer to the response to BCUC IR 1.39.1.


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Exhibit:B-7



2.1.4 Is it BC Hydro’s intention to equalize the Revenue-to-Cost ratios between these two new proposed classes? If not, what is BC Hydro’s policy in this regard?

RESPONSE:

BC Hydro’s LGS rate application will create revenue neutral rates for the MGS and LGS classes; it is not BC Hydro’s intention, with this application, to equalize revenue-cost ratios between the proposed MGS and LGS classes.

Revenue-cost ratios are always addressed by taking into account all customer classes at the same time. Please also refer to the response to Corix IR 2.1.2.


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2.1.5 Based on the forecast growth of the various rate classes, what is BC Hydro’s forecast of future Revenue-to-Cost ratios? Will the trend to increasing ELGS Revenue-to-Cost ratios continue if there are no rate re-balancing initiatives undertaken?

RESPONSE:

In order to do a forecast of revenue-cost ratios BC Hydro would require forecasts of all of the parameters that go into a FACOS study (i.e., load profile by rate class, energy consumption and customer count by rate class, increasing costs by function, reviews of incremental costs causation, etc.) and would essentially require BC Hydro to undertake a FACOS study for each year of the forecast. BC Hydro does not have all of the forecast information that would be required.

Further, the burden of doing this analysis would be large, and the probative value is small. For all these reasons BC Hydro declines to respond to this information request.


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Exhibit:B-7

2.0 Transmission Service Stepped Rate (TSR 2005) Reference: In 2005, the Commission reviewed the issue of a two tier rate structure for Transmission customers (Schedule 1823).


“8. Exemptions



2.2.1 Please reconcile the decision of BC Hydro to serve these exempt customers under a separate rate schedule, RS 1827, with the BC Hydro’s response to Corix 1.3.1 (Exhibit B-5) where in it stated: “the reason BC Hydro does not propose exemptions for re-sellers or other customers who are not end users is primarily a fairness issue”.

RESPONSE:

This information request erroneously refers to a decision by BC Hydro to serve certain transmission voltage customers under an exempt flat rate who would in the normal course have been served under the TSR stepped rate. That was not a decision by BC Hydro, but rather by the BCUC (in regard to two of those customers) and a combination of the BCUC and Government (in regard to three of those customers). Thus, there is no decision to reconcile. Please refer to the responses to Terasen IR 2.1.1 and BCSEA IR 1.5.1.

BC Hydro confirms however that it has changed its views since the TSR stepped rate proceedings regarding exemptions from conservation rate structures. As described in


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Exhibit:B-7

response to BCSEA IR 1.5.1, BC Hydro has with time come to the conclusion that all customers have some ability to control their electricity consumption, regardless of whether they are end-users; has adopted a more significant conservation target; and better appreciates the fairness issues inherent in charging some but not all customers an LRMC-based rate for marginal consumption. However, the applicability of the MGS and LGS rate proposals, and the extent to which customers should be exempt from them, is ultimately not BC Hydro's decision but rather, as a matter of law, the BCUC's decision. BC Hydro does not have a view on whether the provincial legislature appropriately delegated that authority to the BCUC, but notes that it is a common feature of public utility regulation across North America.

BC Hydro agrees that Corix has ELGS accounts with BC Hydro, and that in respect of some of those accounts, Corix is not an end-user, but instead re-sells to end-users. However, BC Hydro understands that Corix is also a regulated public utility in regard to those re-sale operations, and charges rates approved by the BCUC in regard to them. BC Hydro is not aware of any reason that Corix could not get relief from the Commission if the mandatory applicability of the LGS or MGS proposals undermined Corix's statutory right to charge rates that allowed it an opportunity to earn a reasonable return on its invested capital.


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“8. Exemptions

At present, FortisBC Inc. (formerly Aquila Networks Canada (British Columbia) Ltd.), the City of New Westminster and the University of British Columbia are exempt from the application of stepped rates. In accepting the Commission's Recommendation #15 in the Heritage Inquiry Report and Recommendations, the Government response described these customers as "effectively distributors who sell the electricity they purchase onwards to end-use customers."BC Hydro proposes to serve these exempt customers under a separate rate schedule, RS 1827.


2.2.2 Please explain why Corix is in any way different from these other re-sellers other than the fact that it is not a Transmission customer?

RESPONSE:

Please refer to the response to Corix IR 2.2.1.


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Exhibit:B-7



“8. Exemptions



2.2.3 Please confirm that BC Hydro continues to believe that the Commission should have the discretion to address the issue of exemptions. If not, why has BC Hydro changed its position?

RESPONSE:



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Exhibit:B-7



“8. Exemptions



2.2.4 Please confirm that each of Fortis BC Inc, the City of New Westminster and the University of British Columbia continues to receive service under RS 1827? Are there any additional customers who now receive service under this rate schedule?

RESPONSE:

Not confirmed. FortisBC does not receive service under RS 1827, but instead receives service under a separate power purchase agreement, RS 3808 (whose energy price is the same as RS 1827). The City of New Westminster, UBC, SFU and Vancouver International Airport Authority are the only customers currently receiving service under RS 1827.


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Exhibit:B-7



“8. Exemptions



2.2.5 Has BC Hydro made an application to the Commission to transfer customers under this RS 1827 to RS 1823 or any other existing or future rate schedule or to significantly modify RS 1827? Does it intend to do so in the foreseeable future? If yes, what was or will be the nature of such a filing when was or will this application be filed? If no, please explain why such an application will not be forthcoming?

RESPONSE:

BC Hydro has not filed, nor is intending to file, any applications to transfer customers currently on RS 1827 onto RS 1823. Special Direction HC2 requires that FortisBC, New Westminster and UBC remain exempted from the Transmission


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Exhibit:B-7

Stepped Rate and the BCUC has also agreed that the other two customers should also be on RS 1827.

Please also refer to the response to Terasen IR 2.1.1 and BCSEA IR 1.5.1.


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“8. Exemptions



2.2.6 Would it be accurate to describe RS 1827 as having a flat (ie. neither inclining nor declining) demand charge? Please confirm that the current demand charge for RS 1827 is $5.260 per kV.A of Billing Demand per Billing Period. What would this charge be in equivalent $ per kW terms?

RESPONSE:

Confirmed, the current demand charge for RS 1827 is $5.260/kV.A. Using a power factor of .95, the charge per kW would be $4.997/kW.


Page 1 of 1


Exhibit:B-7



“8. Exemptions



2.2.7 Would it be accurate to describe RS 1827 as having a flat (ie. neither inclining nor declining) energy charge? Please confirm that the current energy charge for RS 1827 is 3.083 cents per kWh for all kWh.

RESPONSE:

Yes, RS 1827 currently has a flat energy charge of 3.083 cents/kWh.

Corix Multi-Utility Services Inc.Information Request No. 2.2.8.1 Dated: December 21, 2009British Columbia Hydro & Power Authority Response issued January 22, 2010

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Exhibit:B-7



“8. Exemptions



2.2.8 For each customer served under RS 1827 please provide the following information:

2.2.8.1 Peak Demand (in kV.A) for the most recent fiscal year available.

RESPONSE:

BC Hydro declines to respond to this information request because it seeks irrelevant and confidential customer information.


Page 1 of 1


Exhibit:B-7



“8. Exemptions




2.2.8.2 Annual Energy Consumption (in kWh) for each year from F2005 to the most recent fiscal year for which records are available

RESPONSE:



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Exhibit:B-7



“8. Exemptions




2.2.8.3 The revenue for the most recent fiscal year available segmented as to Basic Charges (if any), Demand Charges, Energy Charges and any other charges applicable under RS 1827.

RESPONSE:



Page 1 of 1


Exhibit:B-7



“8. Exemptions




2.2.8.4 The equivalent HBL to the proposed RS 1300 (ie. if the same methodology was used on RS 1827 customers as described in Appendix O, Section 6.1, Table O-16, page 23 of 23) for each of F2011 and F2012.

RESPONSE:



Page 1 of 1


Exhibit:B-7



“8. Exemptions



2.2.9 Please confirm that customers served under RS 1827 are not required to re-sell electricity to their end use customer at the same rates as BC Hydro for the equivalent class of customer. If they are required to sell at the same rates as BC Hydro, please provide the applicable reference in the BC Hydro Electric Tariff.

RESPONSE:

Confirmed.


Page 1 of 1


Exhibit:B-7



“8. Exemptions



2.2.10 Does BC Hydro provide funding directly to any re-sellers served under RS 1827 to aid in conservation programs?

RESPONSE:

Yes, BC Hydro provides funding through its Power Smart programs to re-sellers under RS 1827.


Page 1 of 1


Exhibit:B-7

3.0 Residential Rate Forecasts Reference: Exhibit B-5, response to Corix 1.1.1, dated December 7, 2009.

Corix is an authorized re-seller of electricity purchased from BC Hydro. In excess of 90% of its electricity is sold to residential customers at rates identical to BC Hydro’s residential rates. BC Hydro’s proposed Application, as filed, would see Corix be a RS 1300 customer at its two service area locations.


2.3.1 Please update Table 5.4 contained in the 2008 RIB Reasons for Decision (G-124-08) at page 89 to reflect the same future cost of power that is now embedded in the LGS rate application.

RESPONSE:

Table 5.4 from the BCUC’s RIB rate decision was based on BC Hydro’s proposed RIB pricing principles. The BCUC’s decision was based on different pricing principles. The table below reflects the BCUC’s decision for F2009 through to F2012.

Continuing to use the BCUC’s pricing methodology after F2012 creates a declining block energy structure, on the basis of the assumed RRA rate increases, which will result in an increase in consumption. Therefore, BC Hydro will be applying before the start of F2012 for an adjustment to the RIB pricing to avoid this result. BC Hydro does not know the result of this application and therefore provides RIB pricing only to F2012.

RIB Rates (Nominal $) F2009 to F2012

Fiscal Year Basic Charge (cents / day)

Step-1 Rate (cents/kWh) for

Use up to 1350 kWh bi-monthly

Step-2 Rate (cents/kWh for use above 1350 kWh bi-

monthly usage 2009 12.38 5.46 7.21 2010 12.64 5.91 8.27 2011 12.91 6.71 8.27 2012 13.18 7.36 8.27


Page 1 of 1


Exhibit:B-7




2.3.2 Please provide the current residential rate forecast used to estimate future conversation potential in the residential rate class of customers inclusive of Basic Charge, Step 1 and Step 2 energy charges. Note: these do not need to be “tariff ready” per the objection to comply with Corix Request 1.1.1. but the best available forecast currently being used by BC Hydro.

RESPONSE:



Page 1 of 1


Exhibit:B-7




2.3.3 If BC Hydro is not able to answer Request 3.2, please explain how BC Hydro is able to meaningfully estimate conservation potential of this rate class. Specifically, what methodology is used to calculate residential consumption that does not include elastic demand responses to changes in Step 2 pricing?

RESPONSE:



Page 1 of 1


Exhibit:B-7




2.3.4 In BC Hydro’s response to Corix 1.3.1 (Exhibit B-5), it stated “it would seem there might be a financial incentive for re-sellers to encourage their customers to reduce energy consumption”. If a re-seller has no clear forecast of future residential and general service rates, how can it discern what that financial incentive might be?

RESPONSE:

A financial incentive to a re-seller can arise when energy savings of a re-seller’s customers are credited to the re-seller at a higher rate than to the re-seller’s customers. This incentive, or arbitrage opportunity, exists so long as the re-seller’s marginal rate is greater than the customers’ marginal rate, regardless of how great the difference is, and regardless of how long that difference is maintained.

REQUESTOR NAME: Joint Industry Electricity Steering Committee (JIESC) INFORMATION REQUEST ROUND NO: 2TO: BRITISH COLUMBIA HYDRO & POWER AUTHORITY DATE: December 21, 2009 PROJECT NO: 3698573APPLICATION NAME: BC Hydro 2009 LGS Application __________________________________________________________________________________

6.0 TOPIC: Part 2 Energy Rate - Adjustments for Line Losses and Inflation

Reference: Exhibit B-5, JIESC IR 1.1.3. and BCUC IRs 1.28.1 and 1.28.3

Background:

In IR JIESC IR 1.1.3 BC Hydro was asked:

Explain the reasons for the different treatments for inflation and line losses for the Transmission Service Rate – Tier 2, the Residential Inclining Block Rate - Step 2, and the proposed LGS Part 2 Energy Rate.

In the responses the different treatments were confirmed but the rational for the difference remains unclear.

Request:

6.1 Explain the reasons for the different treatments for inflation and line losses for the Transmission Service Rate – Tier 2, the Residential Inclining Block Rate - Step 2, and the proposed LGS Part 2 Energy Rate.

7.0 TOPIC: HBL Aggregation

Reference:

Ex. B-5, BCUC IR 1.20.1

Background:

In this response BC Hydro states:

Based on BC Hydro’s review, there does not appear to be sufficient DSM or self-generation opportunities evident at this time that might arise from an aggregation option to justify the system and process changes that would be required to accommodate an “automated” system solution.

1



2

.

Request:

7.1 Quantify the amount of DSM or self generation opportunities that BC Hydro is aware of.

7.2 Indicate what quantity of DSM or self generation opportunities that would be “sufficient” to accommodate or justify an automated system solution.

Joint Industry Electricity Steering CommitteeInformation Request No. 2.6.1 Dated: December 21, 2009British Columbia Hydro & Power Authority Response issued January 22, 2010

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Exhibit:B-7

6.0 TOPIC: Part 2 Energy Rate - Adjustments for Line Losses and Inflation Reference: Exhibit B-5, JIESC IR 1.1.3. and BCUC IRs 1.28.1 and 1.28.3

Background:

In IR JIESC IR 1.1.3 BC Hydro was asked:

Explain the reasons for the different treatments for inflation and line losses for the Transmission Service Rate – Tier 2, the Residential Inclining Block Rate - Step 2, and the proposed LGS Part 2 Energy Rate.

In the responses the different treatments were confirmed but the rational for the difference remains unclear.

2.6.1 Explain the reasons for the different treatments for inflation and line losses for the Transmission Service Rate – Tier 2, the Residential Inclining Block Rate – Step 2, and the proposed LGS Part 2 Energy Rate.

RESPONSE:

In the case of each of the existing TSR stepped rate, the existing RIB rate, and the proposed LGS rate, the LRMC-based rate is derived from the 7.36 cents/kwh levelized plant gate price from the F2006 CFT.

Regarding the line loss adjustment, it was prescribed by the BCUC in regard to the RIB rate for the reasons set out at pages 107-108 of the BCUC’s RIB rate decision. In essence the line loss adjustment reflects the cost of energy associated with line losses between the plant gate and the customer meter. It is on this basis that BC Hydro proposes the same adjustment for the LGS LRMC-based Part 2 energy rate. In the case of the TSR stepped rate, the over-riding principle that resulted in no line loss adjustment was the objective of providing a level playing field between BC Hydro and IPPs for supply to potential retail access customers.

Regarding the inflation adjustment, BC Hydro is not justifying or proposing any change to the TSR stepped rate or the RIB LRMC-based rates in this proceeding because it is focused on the rate structure applicable to BC Hydro's ELGS customers. Whether BC Hydro brings an application to change those rates in the future depends on a number of factors, not the least of which is the BCUC's views of the proposals in the instant application. A BCUC decision in this proceeding that gave an unqualified endorsement to the inflation adjustment would cause BC Hydro to consider applying to the BCUC for similar treatment of the LRMC based rates in the RIB rate and TSR stepped rate. However, because those rate structures have their own unique features, and depending on what else is on the regulatory agenda, even an unqualified


Page 2 of 2


Exhibit:B-7

endorsement of the proposal in this proceeding would not necessarily result in such applications.

Please also refer to the responses to BCOAPO IR 2.3.1, CEC IR 1.10.1 and CEC IR 1.10.2.


Page 1 of 2


Exhibit:B-7

7.0 TOPIC: HBL Aggregation Reference: Ex. B-5, BCUC IR 1.20.1

Background:



2.7.1 Quantify the amount of DSM or self generation opportunities that BC Hydro is aware of.

RESPONSE:

The response noted above specifically refers to opportunities within the LGS class for DSM or self-generation that might arise from an aggregation of account HBLs and does not refer to all DSM or self generation projects. Therefore, projects considered here would, by definition, refer to larger-scale DSM or self-generation projects that would warrant individual site HBLs to be combined.

BC Hydro does not have a quantified GWh estimate of these DSM or self-generation opportunities. BC Hydro is aware of the following opportunities:

� Some opportunities are possible in the next few years for LGS accounts in the oil and gas sector for large scale DSM (primarily related to variable speed controls and sizing of gas pipelines) at a single site or across multiple sites (owned by the same customer), but these opportunities are speculative and difficult to quantify. Few (if any) economic opportunities for large scale DSM have been identified for other industries for LGS accounts. It should be noted that aggregation of LGS accounts would only provide an economic benefit to a customer if DSM projects can result in energy savings greater than 20 per cent at any one site. As indicated in Table B-15, Power Smart savings as a percentage of consumption for LGS sites in F2008 averaged 7 per cent, which is well below the 20 per cent threshold.

� To date, there have been few self generation projects undertaken by LGS customers and future projects are difficult to quantify as they are at various stages of development. Cogeneration and self generation opportunities that might benefit from aggregation have been identified with respect to a small


Page 2 of 2


Exhibit:B-7

number of LGS accounts in the oil and gas sector (gas fired), a large hospital (steam operations) and greenhouse operators (biomass combustion).

In addition to the fact that there do not appear to be many large-scale DSM or self-generation opportunities that would be facilitated by LGS account aggregation, there are a number of other reasons why BC Hydro is not proposing aggregation. These reasons include:

� Aggregation introduces the opportunity for some customers to self-select an aggregated HBL that will minimize their exposure to the LRMC-based rate that may have nothing to do with conservation, but yet triggers revenue implications for BC Hydro and cost-shifting to other customers.

� With or without aggregation under the LGS rate, any increased benefit from the LRMC-based rate signal for reduced usage (through DSM or self-generation) will gradually deteriorate over three years because of the rolling baseline and will be eliminated by year four (assuming that aggregation is a multi-year commitment from customers). Therefore, the LGS rate incentive for DSM or self-generation is considerably different than the incentive under the TSR stepped rate which maintains the aggregated baseline at a constant level (provided the aggregated usage is within the deadband).

� The billing system and process changes required to accommodate aggregation are considerable. The complexity centres mainly around meter reading and billing, as consumption aggregation would involve meters from different parts of the province on different meter reading and billing schedules. BC Hydro would have to create manual processes to handle all aggregated accounts as the billing system does not have the logic to standardize billing periods of different length. However, in addition to consolidating energy sales and HBLs at the aggregated sites, BC Hydro would also have to maintain a separate process to disaggregate the data to calculate power factor charges and discounts which are site specific. Even the potential solution of installing automated meters to resolve the issue of coordinating meter reading across various accounts is not an easy solution as it would involve the development of telecommunications system to transfer the data as well as a means to gather that data in a format that can then be fed into BC Hydro’s billing system. BC Hydro does not face this challenge with the TSR stepped rate customers as the meters are read and billed on entirely separate automated remote meter reading and interval billing systems. These were designed to accommodate interval data type meters which are the norm for these large customers. By design, the availability of synchronized and time stamped interval data avoids the synchronization problem.

Please also refer to the response to BC Ferries IR 2.3.1.


Page 1 of 1


Exhibit:B-7

7.0 TOPIC: HBL Aggregation Reference: Ex. B-5, BCUC IR 1.20.1

Background:



2.7.2 Indicate what quantity of DSM or self generation opportunities that would be “sufficient” to accommodate or justify an automated system solution.

RESPONSE:

Please refer to the response to JIESC IR 2.7.1.

REQUESTOR NAME: Pinnacle Pellet Inc. INFORMATION REQUEST ROUND: 2TO: BRITISH COLUMBIA HYDRO & POWER AUTHORITY DATE: December 21, 2009 PROJECT NO: 3698573APPLICATION NAME: Large General Service Rate Application

1.0 TOPIC Historical Baselines (HBLs)

Reference: Exhibit B-1, p. 1-6, p. 1-15, Chapter 2 Direct Testimony of Lisa Coltart, p. 2-18

Background:

BC Hydro proposes to use the three-year rolling average of monthly energy consumption to determine HBLs.

At page 1-6 of the Application BC Hydro states:

“HBLs would be calculated on the basis of the most recent three-year consumption history. For example, the January 2015 HBL of an account would be the average of the accounts energy consumption in each of January 2014, 2013, and 2012; the January 2016 HBL of the account would be the average of the account’s energy consumption in each of January 2015, 2014, and 2013.”


“LGS accounts that on implementation day do not have one full year of billing history in the period 2005 to 2007 and would not otherwise have been eligible for LGS service in that period would have their initial HBLs set as if they were new accounts moving from MGS service to LGS service (section 1.5.2.2 – HBLs for New LGS Accounts (with billing history)).


“During that phase of consultation BC Hydro heard from a number of customers that it would be unfair to set baselines during the current recession when depressed business activity would result in an undue exposure to the LRMC rate in the future as business activity increases. To account for these concerns BC Hydro now proposes that initial baselines be set equal to the average monthly consumption levels in calendar 2005 to 2007, rather than the years 2008 to 2010, which would otherwise be used to determine HBLs in 2011.”



Pinnacle Pellet Inc. has three plants on BC Hydro’s LGS Rate, one in Quesnel (Account # 675335) that commenced service in May 2000, one in Williams Lake (Account # 5230136) that commenced service in September 2004 and one in Armstrong (Account #6839374) that was purchased from another party in June 2007.

As additional background, Pinnacle Pellet Inc. also has two plants on BC Hydro’s Schedule 1823 transmission rate. One is in Houston, and is a joint venture with Canadian Forest Products Ltd. and the First Nations and has been in operation since October 2006. The second is in Strathnaver, south of Prince George, and has been in operation since September 2008. Pinnacle Pellet Inc. is scheduled to build a third plant in the Burns Lake area that will also be on the transmission rate with a scheduled start-up in July 2010.

The average monthly kWh consumption for the Quesnel Plant over the period of 2005 to 2007 was 680,866 kWh. The average monthly kWh consumption over the period of January 2008 to December 2009 (24 billing periods) was 755,200 kWh and represents an increase of 10.9%. Expansions are planned at the Quesnel Plant during 2010 and 2011 that are expected to increase the consumption in each of the two years by approximately 125,000 kWh per month. The expansions in each of the two years will be completed in Q3. Consequently, by the end of 2010 and 2011 the kWh consumption will have increased by approximately 29% and 47% respectively when compared to the 2005 to 2007 period.

The average monthly kWh consumption for the Williams Lake Plant over the period of 2005 to 2007 was 688,267 kWh. The average monthly kWh consumption over the period of January 2008 to November 2009 (19 billing periods), excluding the months of March 2009 to June 2009 when the plant was under force majeure, was 1,271,494 kWh and represents an increase of 84.7%.

The average monthly kWh consumption for the Armstrong Plant in during the seven billings periods in 2007 was 380,571 kWh. The average monthly consumption over the period of January 2008 to November 2009 (23 billing periods) was 418,095 kWh and represents an increase of 9.8%.

Consequently, all of Pinnacle Pellets Plants will adversely impacted on a financial basis by BC Hydro’s decision to use calendar 2005 to 2007 to set initial baselines.

Request:

1.1 Explain why BC Hydro has not taken a more flexible approach in determining HBLs in the case of customers plants that have countered the recent trend and expanded production in recent years and allow the use the years 2008 to 2010 to establish the HBL for 2011 so that these facilities will not face undue exposure to the LRMC in 2011, 2012 and 2013.

1.2 With regards to Pinnacle Pellets Armstrong Plant please clarify what is meant at page 1-15 of the Application by “and would not otherwise have been eligible for LGS service in that period would have their initial HBLs set as if they were new accounts moving from MGS to LGS service..” What happens to LGS customers that do not have one full year of billing history in the year 2005 to 2007 but are eligible for LGS service in that period? Explain why BC Hydro is not using more recent history such as consumption in 2008, 2009 and 2010 to establish initial HBLs in this situation?

1.3 Explain why the proposed LGS Application has not made any provision to accommodate Plant expansions similar to those that exist on BC Hydro’s Rate Schedule 1823A. Given the expansion plans for the Quesnel Plant in 2010 and 2011, explain why it is reasonable for the Plant to face increased exposure to LRMC electricity through to 2015.

2.0 TOPIC Adjustments for Anomolies

Reference: Exhibit B-1, p.1-7 & 1-8, p.3-26

Background:


Under BC Hydro’s proposal the Anomaly Rule: � would be applicable only if the account had at least two years of consumption

history;� would be applicable to the calculation of no more than two HBL’s per BC Hydro

fiscal year; and � if otherwise applicable to the calculation of more than two HBLs per fiscal year,

would be applicable to the calculation of the first two HBLs in that year.


“In recent engagement sessions regarding BC Hydro’s preferred design, BC Hydro proposed both the three year rolling average calculation of HBLs and the use of Price Limit Bands. However, customers continued to express concerns that short-lived anomalous events which cause exceptionally low consumption, such as strikes or equipment malfunctions, would have a dampening effect on HBLs for the following three years. In the customer’s view, this would lead to unfair incremental exposure to LRMC marginal rate in those three years.”

Pinnacle Pellet’s Williams Lake Plant experienced a force majeure event in 2009.A fire occurred in the wood residue dryer on March 7, 2009 and kept the plant down until June 26, 2009 for a total of 111 days (3.6 months).

Request:

Explain why BC Hydro’s Application does not allow Customers the right to claim full relief as the result of a force majeure event. If a force majeure event, similar to that described above, happened to Customer in 2011 explain why BC Hydro believes it is fair and reasonable for that Customer to have reduced HBL’s for three months plus over the period in 2012 to 2014 which result in increased exposure to LRMC electricity.

Pinnacle Pellet Inc.Information Request No. 2.1.1 Dated: December 21, 2009British Columbia Hydro & Power Authority Response issued January 22, 2010

Page 1 of 2


Exhibit:B-7

1.0 TOPIC Historical Baselines (HBLs) Reference: Exhibit B-1, p. 1-6, p. 1-15, Chapter 2 Direct Testimony of Lisa Coltart, p. 2-18

Background:











Page 2 of 2


Exhibit:B-7





2.1.1 Explain why BC Hydro has not taken a more flexible approach in determining HBLs in the case of customers plants that have countered the recent trend and expanded production in recent years and allow the use the years 2008 to 2010 to establish the HBL for 2011 so that these facilities will not face undue exposure to the LRMC in 2011, 2012 and 2013.

RESPONSE:

BC Hydro believes that its LGS rate design customer consultation process was robust and inclusive, and that BC Hydro has been flexible and responsive to customer concerns expressed during the process. During customer consultation, BC Hydro did not hear the theme from customers that they expected to ramp-up their businesses; rather, concern was broadly expressed regarding impacts of the economic downturn. Hence, BC Hydro adjusted its proposed LGS rate design with regard to initial HBL establishment, compared to the design it consulted on in June 2009.

BC Hydro believes that it is very important that the LGS design is formulaic and is administered utilizing standardized processes. BC Hydro has modeled a rate design scenario similar to that suggested in this question, with a standardized process for establishing the highest average initial HBL for each LGS account. This rate design scenario is discussed in the response to BC Ferries IR 2.2.1 and is modeled in the response to BCUC IR 2.1.2 (refer to Scenario LGS3).


Page 1 of 3


Exhibit:B-7


Background:










The average monthly kWh consumption for the Quesnel Plant over the period of 2005 to 2007 was 680,866 kWh. The average monthly kWh consumption over the


Page 2 of 3


Exhibit:B-7

period of January 2008 to December 2009 (24 billing periods) was 755,200 kWh and represents an increase of 10.9%. Expansions are planned at the Quesnel Plant during 2010 and 2011 that are expected to increase the consumption in each of the two years by approximately 125,000 kWh per month. The expansions in each of the two years will be completed in Q3. Consequently, by the end of 2010 and 2011 the kWh consumption will have increased by approximately 29% and 47% respectively when compared to the 2005 to 2007 period.




2.1.2 With regards to Pinnacle Pellets Armstrong Plant please clarify what is meant at page 1-15 of the Application by “and would not otherwise have been eligible for LGS service in that period would have their initial HBLs set as if they were new accounts moving from MGS to LGS service..” What happens to LGS customers that do not have one full year of billing history in the year 2005 to 2007 but are eligible for LGS service in that period? Explain why BC Hydro is not using more recent history such as consumption in 2008, 2009 and 2010 to establish initial HBLs in this situation?

RESPONSE:

The phrase “and would not otherwise have been eligible for LGS service in that period would have their initial HBLs set as if they were new accounts moving from MGS to LGS service..” refers to ELGS accounts that would not have met the demand threshold for the new LGS class (� 150 kW) and indicates that BC Hydro will establish HBLs for these accounts based on data from the most recent 12 months.

For LGS customers without a full year of billing history in 2005 – 2007, their initial monthly HBLs would be the monthly consumption of the most recent year as described in section 1.5.2.2 of the application.

In the case of Pinnacle’s Armstrong plant that has seven months of billing data in 2007, the account’s initial baselines would be set based on monthly consumption data from calendar 2010 assuming a January 1, 2011 implementation date for the new


Page 3 of 3


Exhibit:B-7

rate and assuming that this plant continues to have demand levels > 150 kW in at least one month of 2010.


Page 1 of 3


Exhibit:B-7


Background:











Page 2 of 3


Exhibit:B-7





2.1.3 Explain why the proposed LGS Application has not made any provision to accommodate Plant expansions similar to those that exist on BC Hydro’s Rate Schedule 1823A. Given the expansion plans for the Quesnel Plant in 2010 and 2011, explain why it is reasonable for the Plant to face increased exposure to LRMC electricity through to 2015.

RESPONSE:

The provision for plant expansions under BC Hydro’s Transmission Service Rate 1823 – either through a CBL adjustment or a temporary move to the blended rate 1823A – is a manual, labour intensive process and involves a number of resources from BC Hydro (e.g. Key Account Manager, PowerSmart, Conservation Rates, etc.) as well as considerable resources from the customer. As such, this type of process can reasonably be applied to a customer class with 133 accounts but is not reasonable for a customer class as large as the proposed LGS class (> 5,000 accounts). Therefore, as described in Lisa Coltart’s testimony A21 and A22, pages 2-16 and 2-17, BC Hydro has designed a rate for the LGS class that does not require manual intervention.

In terms of customer plant expansions, the LGS rate would update a customer’s baseline consumption using a rolling three-year average methodology. In this design,


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Exhibit:B-7

LRMC pricing (reflecting the cost of new supply) would apply to load greater than the baseline for the first year of increased consumption. After the first year, the increased load would gradually be incorporated into the customer’s baseline and, as part of the baseline, would then attract the Part 1 rates rather than LRMC-based rate.

It should be noted that Price Limit Bands - another feature of the rate introduced to address customer concerns regarding bill volatility – also incidentally address concerns regarding growth because the bands limit the amount of increased usage that is charged the LRMC-based rate.

There is one other aspect of the LGS application that would mitigate the LRMC price signal in the case of the Quesnel expansion as described in the background to this information request. The increased load that commences in 2010 and 2011 would not attract the full LRMC as the LRMC pricing is being phased-in over the first three years of implementation.

Finally, it is reasonable for the plant to face increased exposure to electricity charged at LRMC-based rates because this pricing reflects the incremental cost of that growth.


Page 1 of 1


Exhibit:B-7

2.0 TOPIC Adjustments for Anomolies Reference: Exhibit B-1, p.1-7 & 1-8, p.3-26

Background:


Under BC Hydro’s proposal the Anomaly Rule:

� would be applicable only if the account had at least two years of consumption history;

� would be applicable to the calculation of no more than two HBL’s per BC Hydro fiscal year; and

� if otherwise applicable to the calculation of more than two HBLs per fiscal year, would be applicable to the calculation of the first two HBLs in that year.


“In recent engagement sessions regarding BC Hydro’s preferred design, BC Hydro proposed both the three year rolling average calculation of HBLs and the use of Price Limit Bands. However, customers continued to express concerns that short-lived anomalous events which cause exceptionally low consumption, such as strikes or equipment malfunctions, would have a dampening effect on HBLs for the following three years. In the customer’s view, this would lead to unfair incremental exposure to LRMC marginal rate in those three years.”

Pinnacle Pellet’s Williams Lake Plant experienced a force majeure event in 2009. A fire occurred in the wood residue dryer on March 7, 2009 and kept the plant down until June 26, 2009 for a total of 111 days (3.6 months).

2.2.1 Explain why BC Hydro’s Application does not allow Customers the right to claim full relief as the result of a force majeure event. If a force majeure event, similar to that described above, happened to Customer in 2011 explain why BC Hydro believes it is fair and reasonable for that Customer to have reduced HBL’s for three months plus over the period in 2012 to 2014 which result in increased exposure to LRMC electricity.

RESPONSE:


December 21, 2009

B.C. Hydro and Power Authority17th Floor 333 Dunsmuir StreetVancouver, BCV6B 5R3

Attention: Ms. Joanna Sofield, Chief Regulatory Officer

Dear Ms. Sofield:

Re: British Columbia Hydro and Power Authority (“BC Hydro”) Large General Service RateApplication (“LGSRA”) ~ Project No 3698573

Terasen Utilities Information Request No. 1 to BC Hydro

In accordance with British Columbia Utilities Commission (the “Commission”) Order No. G-156-09,attached please find Information Request No. 1 on behalf of the Terasen Utilities (comprised of Terasen Gas Inc., Terasen Gas (Vancouver Island) Inc., and Terasen Gas (Whistler) Inc.

If you have any questions regarding this submission, please do not hesitate to contact Dave Perttula at (604) 592-7470.

Yours very truly,

on behalf of the TERASEN UTILITIES

Original signed by: Diane Roy

For: Tom Loski

cc: Ms. Erica Hamilton, Commission Secretary, BCUCcc (e-mail only): Registered Parties

Tom A. LoskiChief Regulatory Officer

16705 Fraser HighwaySurrey, B.C. V4N 0E8Tel: (604) 592-7464Cell: (604) 250-2722Fax: (604) 576-7074Email: [email protected] www.terasengas.com

Regulatory Affairs CorrespondenceEmail: [email protected]



British Columbia Hydro and Power Authority (“BC Hydro”)Large General Service Rate Application - Project No. 3698573

Submission Date:December 21, 2009

Terasen Gas Inc. (“Terasen Gas”)Information Request No. 1

Page 1

1.0 Reference: Exhibit B-1, Chapter 2, A27, p. 2-22, Exhibit B-5, BCUC IR 1.32.1, BCSEA IRs 1.5.1 to 1.5.3, Corix IR 1.3.1 and BCUC Order G-79-05, Appendix A, p.5and 6 of 7 and Appendix B, p.4 of 54

Exemption from the Transmission Service Stepped Rate was granted to New Westminster, Fortis BC and UBC since these were entities that sold much or all of the electricity purchased from BC Hydro to others that were the ultimate consumers of the electricity and it was the end users that determined or controlled ultimately how much electricity was consumed. According to the TSR Negotiated Settlement Agreement and Reasons for Decision the Commission was going to take steps with the provincial government to verify the Commission’s role in granting exemptions to other parties in similar circumstances from the transmission service stepped rate.

1.1 Please describe the outcome of the Commission’s enquiries with the provincial government in terms of the Commission’s authority to grant exemptions from thetransmission service stepped rate.

1.2 Have any other parties been granted exemption from the transmission service stepped rate?

1.3 BC Hydro is not contemplating any similar exemptions or an alternative rate structure for electricity resellers or public utilities that are currently ELGS customers.

1.3.1 Please confirm that the reseller provisions in BC Hydro’s tariff only place a limit on the rate that the reseller may charge to the end user but not on the quantity of electricity that the reseller can resell to the end users.

1.3.2 Please confirm that ELGS resellers or public utilities that sell much or all of the purchased electricity to others that are the ultimate end users, have the same limitations on being able to control the consumption of those end users as those parties exempted from the transmission service stepped rates, such as UBC, New Westminster and Fortis BC.

2.0 Reference: Exhibit B-1, Chapter 1 Section 1.5 Proposed LGS Two Part Rate Structure and BC Hydro Standing Offer Program

ELGS customers that will become part of the proposed LGS rate class may also be project proponents (presently or in the future) seeking contracts under BC Hydro’s Standing Offer Program (“SOP”).

2.1 Please confirm that the SOP was established in response to a policy directive in the BC Energy Plan with the intent of promoting the development of distributed clean electricity generation in BC and streamlining the process for small power project proponents to obtain an electricity purchase agreement from BC Hydro.

2.2 How was the SOP taken into consideration in the development of proposed LGS rate structure?

British Columbia Hydro and Power Authority (“BC Hydro”)Large General Service Rate Application - Project No. 3698573

Submission Date:December 21, 2009

Terasen Gas Inc. (“Terasen Gas”)Information Request No. 1

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2.3 Please explain the inter-relationship between the marginal price signals in the Part 2 rate of the proposed LGS rate structure and those included in the Standing Offer prices available to parties wishing to generate electricity and obtain a contract with BC Hydro under the SOP.

2.3.1 Does BC Hydro expect that the LGS Part 2 rate and the Standing Offer prices will be updated in a similar timeframe such that the economic drivers for SOP projects and investments in energy conservation for LGS customers will be on a similar footing?

2.3.2 Please compare the process for updating Standing Offer prices with that of updating the LGS Part 2 rates. In making this comparison please identify the circumstances under which the basis for these two quantities will diverge from each other..

3.0 Reference: Exhibit B-5, CEC IR 1.19.2 and 2007 Rate Design Decision (BCUC Order G-130-07)

In response to CEC IR 1.19.2 BC Hydro indicated that it did not see any good reason for including a forward-looking report outlining a long term rate structure development plan in its annual rate filings. In its 2007 Rate Design Application BC Hydro made reference a number of times as indicated in the 2007 Rate Design Decision to the development of a long term rate strategy for the purpose of achieving the conservation goals and objectives of the 2007 Energy Plan. BC Hydro also submitted Exhibit B-73 in the 2007 RDA which listed a provisional 5-year program of rate filings, revenue requirements applications and LTAPs. A number of significant developments have occurred since then including the implementation of the Residential Inclining Block rate structure and approval of an expanded DSM plan, among other things.

3.1 How has BC Hydro’s long term rate strategy evolved in light of developments that have occurred since the 2007 RDA?

3.2 How does the Large General Service Rate Application fit in with BC Hydro’s long term rate strategy as contemplated in the 2007 RDA and refined / updated by subsequent occurrences?

Terasen UtilitiesInformation Request No. 2.1.1 Dated: December 21, 2009British Columbia Hydro & Power Authority Response issued January 22, 2010

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1.0 Reference: Exhibit B-1, Chapter 2, A27, p. 2-22, Exhibit B-5, BCUC IR 1.32.1, BCSEA IRs 1.5.1 to 1.5.3, Corix IR 1.3.1 and BCUC Order G-79-05, Appendix A, p.5 and 6 of 7 and Appendix B, p.4 of 54


2.1.1 Please describe the outcome of the Commission’s enquiries with the provincial government in terms of the Commission’s authority to grant exemptions from the transmission service stepped rate.

RESPONSE:

The issue of the BCUC's role regarding the exemption of transmission voltage customers from the TSR stepped rate arose because of uncertainty regarding the scope of section 3 of Heritage Special Direction No. HC2, which had and continues to have the effect of limiting the BCUC's jurisdiction in regard to the design of rates for those customers. No such issue arises in regard to the LGS Application: the BCUC clearly has the jurisdiction to exempt customers from the LGS or MGS rate proposals, or to narrow the scope of applicability of those rate proposals.

Nevertheless, BC Hydro advises that by letter dated September 16, 2005, the BCUC wrote to the Ministry of Energy, Mines and Petroleum Resources (MEMPR) seeking government's views on the BCUC's authority to exempt transmission-voltage customers from the applicability of the TSR stepped rate.

By letter dated January 23, 2006, the MEMPR advised the BCUC that: 1) in the view of ministry staff, the BCUC had the legal authority to consider and rule on its own jurisdiction to grant exemptions from the applicability of the TSR stepped rate; and 2) the MEMPR was not opposed, on a policy basis, to BCUC ordered exemptions from the applicability of the TSR stepped rates, if the BCUC concluded that it had the jurisdiction to do so. The MEMPR did not take a position


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Exhibit:B-7

on the BCUC's jurisdiction to grant exemptions.

On February 14, 2006, the BCUC, having concluded that it had the jurisdiction to grant exemptions to the applicability of the TSR stepped rate, exempted Simon Fraser University and the Vancouver International Airport Authority from the application of the TSR stepped rate, by Order No. G-10-06.

Currently, these two customers, as well as Fortis BC, New Westminster and the University of British Columbia, are the only transmission voltage customers exempted from the applicability of the TSR stepped rate.

Please also refer to the response to Corix IR 2.2.1.


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2.1.2 Have any other parties been granted exemption from the transmission service stepped rate?

RESPONSE:

Please refer to the response to Terasen IR 2.1.1.

Terasen UtilitiesInformation Request No. 2.1.3.1 Dated: December 21, 2009British Columbia Hydro & Power Authority Response issued January 22, 2010

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Exhibit:B-7



2.1.3 BC Hydro is not contemplating any similar exemptions or an alternative rate structure for electricity resellers or public utilities that are currently ELGS customers.

2.1.3.1 Please confirm that the reseller provisions in BC Hydro’s tariff only place a limit on the rate that the reseller may charge to the end user but not on the quantity of electricity that the reseller can resell to the end users.

RESPONSE:

Confirmed.


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2.1.3 BC Hydro is not contemplating any similar exemptions or an alternative rate structure for electricity resellers or public utilities that are currently ELGS customers.

2.1.3.2 Please confirm that ELGS resellers or public utilities that sell much or all of the purchased electricity to others that are the ultimate end users, have the same limitations on being able to control the consumption of those end users as those parties exempted from the transmission service stepped rates, such as UBC, New Westminster and Fortis BC.

RESPONSE:

Generally one can expect that re-sellers of electricity face similar issues regarding their ability to affect the consumption of their end-use customers. However, BC Hydro expects that as between re-sellers the circumstances and ability to affect the consumption behaviour of end-use customers can vary widely. Please refer to the response to Corix IR 2.2.1.


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2.2.1 Please confirm that the SOP was established in response to a policy directive in the BC Energy Plan with the intent of promoting the development of distributed clean electricity generation in BC and streamlining the process for small power project proponents to obtain an electricity purchase agreement from BC Hydro.

RESPONSE:

Confirmed. Policy Action No. 11 from the 2007 Energy Plan states that BC Hydro is to develop a Standing Offer Program.


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2.2.2 How was the SOP taken into consideration in the development of proposed LGS rate structure?

RESPONSE:

The SOP was not taken into consideration in the development of the proposed LGS rate structure.


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2.2.3 Please explain the inter-relationship between the marginal price signals in the Part 2 rate of the proposed LGS rate structure and those included in the Standing Offer prices available to parties wishing to generate electricity and obtain a contract with BC Hydro under the SOP.

RESPONSE:

The proposed LGS rate structure’s Part 2 LRMC-based price is based on the levelized plant gate price from the F2006 CFT. Please refer to the response to BCUC IR 1.4.2 for additional details on Part 2 LRMC-based price calculations under the proposed LGS rate.

The SOP prices are based on the awarded EPAs for the small project stream from the F2006 CFT, as agreed to in the SOP negotiated settlement process.


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2.2.3.1 Does BC Hydro expect that the LGS Part 2 rate and the Standing Offer prices will be updated in a similar timeframe such that the economic drivers for SOP projects and investments in energy conservation for LGS customers will be on a similar footing?

RESPONSE:

As agreed to in the SOP negotiated settlement process, BC Hydro committed to undertaking a two-year review of various elements of the SOP, including the prices to be paid for new projects. BC Hydro plans to file its SOP review report with the BCUC in spring 2010. If there are any changes to the SOP prices, they will not occur until completion of the regulatory process associated with the two-year SOP review.

Please refer to the response to BCUC IR 1.4.1 that outlines BC Hydro’s views regarding potential future changes to the LGS Part 2 LRMC-based rate.

Neither potential pricing review will follow a pre-determined process.


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2.2.3.2 Please compare the process for updating Standing Offer prices with that of updating the LGS Part 2 rates. In making this comparison please identify the circumstances under which the basis for these two quantities will diverge from each other.

RESPONSE:

Please refer to the response to Terasen IR 2.2.3.1.


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2.3.1 How has BC Hydro’s long term rate strategy evolved in light of developments that have occurred since the 2007 RDA?

RESPONSE:

Conservation rates are an important area of focus for BC Hydro. For example, BC Hydro incorporated conservation rate structures into its 2008 DSM Plan. Since the 2007 RDA, BC Hydro has implemented the RIB rate, re-priced the TSR stepped rate, and filed the current LGS Rate Application for the ELGS rate class, all of which will lead to significant rate-related conservation. Energy conservation rates will soon be in place for most major customer rate classes and for the majority of BC Hydro’s domestic load. In the next few years, BC Hydro plans to monitor the effectiveness of these energy conservation rates and apply to the BCUC for adjustments to these rate structures as required. Given the pending implementation of smart metering infrastructure, BC Hydro’s workplan regarding new rate design will focus in the next few years on the integration of time-differentiated rates into its conversation rates.

BC Hydro provides below a strawdog timeline that represents a high-level view of the various conservation rate-related filings that could be expected in the F2011 through F2014 period given BC Hydro’s current plans. The timeline below indicates the estimated timing of filings, does not reflect the timing of the ensuing regulatory processes, and makes no allowance for the government’s response to the BCUC’s December 31, 2009 report regarding BC Hydro’s transmission service rates.

F2011 – F2014 Strawdog Conservation-Rate Regulatory Filing Schedule

F2011 (April 2010 – March 2011)

� Summer: F2010 Adjusted/F2011 Interim TSR CBLs;

� Fall: F2010 TSR Annual Report;


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� Fall: TSR Generator Baseline (GBL) Guideline Filing;

� Fall: RIB Rate Tier 2 Re-pricing Application;

� Winter: F2012 TSR/RIB/LGS/MGS compliance filing (pricing effective April 1, 2011).

F2012 (April 2011 – March 2012)




F2013 (April 2012 - March 2013)



� Fall: Time-differentiated rate application (potentially including a conservation rate for the SGS class);


F2014 (April 2013 - March 2014)



� Winter: LGS Rate Assessment Report (based on assumed LGS implementation date of January 2011);



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2.3.2 How does the Large General Service Rate Application fit in with BC Hydro’s long term rate strategy as contemplated in the 2007 RDA and refined / updated by subsequent occurrences?

RESPONSE:

Please refer to the response to Terasen IR 2.3.1.

2010 01 22 BC Hydro IRES 2 to BCUC and INTV · ExhibitB13,pp.58,59;ExhibitB5BCOAPOIR1.34.3...

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Transcript of 2010 01 22 BC Hydro IRES 2 to BCUC and INTV · ExhibitB13,pp.58,59;ExhibitB5BCOAPOIR1.34.3...