IN THE MATTER OF:

CENTRA GAS MANITOBA INC.

2013114

GENERAL RATE APPLICATION

HEARING BEFORETHE PUBLIC UTILITIES BOARD

Board Counsel's Book of Documents

Volume 1 of 2

June 13,2013

Table of Contents

Tab # Panel: DSM, Gas Supply, LoadForecast, Rates

Reference

1 Gas Cost Forecast 2012113 Schedule 10,12.3(b)

2

Differences Between ForecastedGas Costs and Gas CostsRecoverable by Existing Rates,Last Approved Gas Costs

Schedule 1A12A@) and (b)

3Capacity Management DeferralAccounts Schedule 10.6,2, 10,9,2

4Forecasted vs. Actual 2010111Gas Costs Schedule 10.4.0

52010111 and 2011112 CapacityManagement Revenues

Schedule 10.6.1Schedule 10.9.1

6Forecasted vs. Actual 2011112Gas Costs Schedule 10.8.0

7Alberta Monthly Price vs. PrimaryGas Billed Rate PUB/Centra l-88

8 Primary Gas PGVA

Schedule 10.4.1Schedule 10.8.1PUBiCentral-102PUB/Centra ll-179(f)Schedules 1 .1 .3 from August 1 ,

2011 and November 1,2011 PrimaryGas Rate Aoolications

I Summary of All Gas CostDeferral Balances Schedule 10.1 1 .0

10 Previous Gas Supply Contract 2010111 Cost of Gas PUB/Centra 16

11 Current Gas Supply Contract PUB/Centra l-91

12 TCPL Eastern Zone Toll PUB/Centra l-94

13NEB Decision on TCPLRestructuring Proposal PUB/Centra ll-178

14 TCPL Compliance Filing Attachment 84 Part B 2013 TollDesiqn Schedules

15Customer Numbers, Volumes,and Average Use PUB/Centra l-62

16EDDH and Load Forecast/Normal Weather Methodology

PUB/Centra l-66, Board derivedschedule of Normal WeatherMethodology Change and WinnipegEDDH Graph

17SGS Commercial and LGSVolume Forecast Appendix 8.1 p.17

18 Load Forecast Accuracy PUB/Centra l-67

Table of Contents

Tab # Panel: DSM, Gas Supply, LoadForecast, Rates

Reference

19

Power Smart Plan and DSMBudget Comparison - 2011 to2013

PUB/Centra 11164

20 LICO Demographic Data PUB/Centra ll-170

21LIEEP Budget as percentage ofResidential DSM budget PUB/Centra l-59(h)

22 Furnace Replacement Program PUB/Centra ll-172(c) to (g)

23Target Furnace ReplacementMarket PUB/Centra l-59 (b) Attachment

24Home Heating CostComparisons PUB/Centra l-116

25Percentage of New HomesElecting Gas Service PUB/Centra l-68(c) & (d)

26

Power Station CustomerMinimum Annual Gross MarginAmount

PUB/Centra l-1 19(a) and Attachmentto (c)

27Power Station CustomerRevenue to Cost Ratio

PUB/Centra ll-182(a)Tab 1 1 Schedules 1 1.1 .0, 11.1.1,11.1.2, 11.1.3Board Derived Cost AllocationMethodoloqv Schematic

28 Base and Billed Rate ChangesBoard Derived Schedules of Baseand Billed Rate lmpactsExample Gas Bill Redacted

29 Base and Billed Rate Bill lmpacts Schedule 12.1.0

30Unaccounted For Gaspercentages PUB/Centra l-99(b)

31 FRPGS Offerings and Rates Tab 1 3 p.2

32 FRPGS Customer Enrolments PUB/Centra l-124; Appendix 1 3.3

33FRPGS Costs vs. QuarterlyPrimary Gas Costs PUB/Centra l-120

34FRPGS Program FinancialResults Appendix 13.2, p.5-7

35FRPGS Settled and UnsettledHedging Results PUB/Centra l-127

36FRPGS Program OperatingCosts and Program Cost Rate PU B/Centra l-125, l-126

37 FRPGS Risk Margin Distributions Appendix 13.5, PUB/Centra l-128(d)

Table of Contents

Tab # Panel: DSM, Gas Supply, LoadForecast, Rates

Reference

38FRPGS program review $1million threshold PUB/Centra ll-184

39 FRPGS Regulatory Costs Order 156/08 p.60,61

lkolisnik

Text Box

1

Centra Gas Man¡toba lnc.2013/14 Gen€ral Rate Appl¡cat¡on - Cost of Gas Update

Purchase Gost of Gas Supplied to Load2012l13 Gas Yeer

Updated Schedule 10.f 2.3(b)May 10,2013

Supply prices Íoî 2012113 Gas Year per forward strip as of: April 2,2013

Fixed Costs

1 TCPL Firm Service - Man Zone

2 TCPL Firm Service - Sask Zone

3 TCPL STFT to Man Zone

4 TCPL F¡rm Service - Emerson to Man Zone

5 TCPL STS6 ANR Storage Capacity

7 ANR Storage Deliverability

I ANR Oklahoma Winter

9 ANR Crystal Falls from Storage10 GLGT Winter

1 1 Seasonal Storage Capacity12 Seasonal Storage Deliverability

13 Annual Storage Capac¡ty

14 Annual Storage Deliverability

15 ANR Joliet Summer

16 ANR Crystal Falls to Storagel7 GLGTSummer18

19 Total F¡xêd Costs20

21 @22

23 TCPL Firm Service - Man Zone

24 lCPl Firm Service - Sask Zone

25 TCPL Firm Service - Emerson to Man Zone

26 ANR Oklahoma to Crystal Falls

27 ANR Storage Withdrawl

28 ANR Storage Transportation

29 Storage Gas - Trensportation & Delivery Cost (Centra)

30 Compressor Fuel -Emerson

31 Compressor Fuel -Oklahoma

32 Compressor Fuel -Storage

33 Compressor Fuel -MDA

34 Compressor Fuel -SSDA

35

36 Totel Veriable Transportation Costs37

38 9r¡p!r@s!s39

40 Primary Supply Direct to System Supply Load

41 Storage Gas - Primary Supply to System Supply

42 Emerson Supply

43 Oklahoma Supply44 Storage Gas - Supplemental Supply

45 Chicago Supply4647 Total Supply Costs484s glEr50 Minell Charges

51 Load Balancing Charges

52

53 Total Other Costs54

55 TotalCostofGas56 Five Year Average Capacity Management Revenues

57 Net Cost of Gas

CDN $

CDN $CDN $CDN $

CDN $

CDN $

CDN $CDN $CDN $CDN $CDN $

CDN $

CDN $CDN $CDN $

CDN $

CDN $

CDN $

Total

$50,055,362

i21,000,1 68

$'1s6,642

$t l,¡145,045

ì'1,129,240J2,891,292$2,439,499$r ,931,021

$209,910ì298,421

tl,040,369$r,338,963

i99l,267$1,265,78011,297,296

$190,402$l,365,45331.064,594

CDN $CDN $CDN $CDN $

CDN $

CDN $

CDN $CDN $CDN $

CDN $

CDN $CDN $

$1,s'',t,282$1 1,016

$13,82s

$1 9,807

i't48,284$93,913

$2,r79,962$7,032

$148,624$r 03,950

is73,6s4$4.694

CDN $ i4,856,0¡14

$102,842,503

¡24,754,674$6,860,360

¡3,672,012j12,632,218

sg

s1 50,761,797

sr 98,444

9200.000

i398,444

$206,071,646(s6.300.0001

$1 99,771,646

CDN $CDN $

CDN $CDN $CDN $CDN $

CDN $

CDN $

CDN $

CDN $

CDN $

CDN $CDN $

1

lkolisnik

Text Box

2

Gentra Gas Manitoba lnc.2013/'14 General Rate Application - Cost of Gas Update

Difference Between Forecasted Non-Primary Gas Costs

and Non-Primary Gas Costs Recoverable With Existing Base RatesSunolv orices for 2012113 Gas Year Der forward strio as of:

1 Primary Gas2 Supplemential Gas

3 Transportationr4 Distribution5

6

7 TotalsI9'10 Non-Primary Gas Cost Totals11

12 Note 1: Transportation costs including $6'3 mm Capacity Management forecast'

Aoril 2.2013

Updated Schedule '10.12.4 (alMay 10,2013

Difference

($255,007)

$3,776,270($3,s34,s74)

t$715.1 14)

(1)Recoverableat ExistingBase Rates

(2)

Forecastfor 2012113

$'126,260,276$22,865,989

$48,233,057$2.412.324

(3)

$126,515,283$re,089,719

$52,'168,031s3.127.437

$200,900,471 $199,771,646

$74,385,188 $73,511,370

(9r,128,825)

($873,818)

3

Gentra Gas Manitoba lnc.2013114 General Rate Application - Cost of Gas UpdateDifference Between 2O1Ol11Gas Year Approved and 2012113 Gas Year Non-Primary Forecasts

Suoolv orices for 2012113 Gas Year lìêr forward strio as of: Aoril 2.2013

(1)

Approved for20101'11

Updated Schedule 10.12.4 (b)

May 10,2013

Difference

($28,820,991)($14,889,703)

($3,s07,435)ts620.013't

(3)

$155,081,267$37,755,692$52,140,493

s3.032.337

(2)

ForecastÍo¡ 2O12113

$126,260,276$22,865,989$48,233,057$2.412.324

'|

2

3

4

5

6

7

II

Primary GasSupplementral GasTransportationDistribution

10 Non-Primary Gas Cost Totals

Totals $2¿t8,009,789 $199,771,646

$92,928,522 $73,511,370

($¡18,238,142)

($19,417,151)

11

12

4

lkolisnik

Text Box

3

ContE Gåa ilenltoba |rc.20l0rll Gæ Y..r C.påc¡ty ¡l¡n.O.mnt DofÚEl Ac@unt

Ac{u.l

Sch.dule 10.6.2F.bru.ry 22,2013

TOTAL

(¡s,331,031)

(¡s,376,il|¡6)

Oc{sopAugJuJunilsyAplIarFobJenftocNovAclual Actual Acluel Actual Actual Actuel Ac'tual Actual Actuâl Actual Actu.l Actual

2î1¡ 2010 2011 20ll 2011 2r11 m1'l 2011 2011 2011 2¡11 2011

($2S6,3s2) ($11s,1s5) ($373,44s) ($170,010) ($131,660) ($262,159) ($6s4,224) ($711,7sS) ($621,s63) ($s56.530) ($603,071) ($804.624)I2

456

7

Cãpacity Management Revenue

Cãryìng Costs

llot ltrf,ow

Not Bahncô

(¡286,5¡!2)

(1286,s:¡2)

(¡1r5,54s)

(vo2,om

(¡37il,o¡ls)

lr776,1z¿l

(¡170Bs3)

(¡e47,rrÐ

(¡716,1196)

(¡2,760,690)

(¡627,700)

(¡3,38E,æo)

(¡s63,362)

(¡:¡,9sr,7si2)

(¡610,7s4)

(¡4,s62,slrs)

(¡813,901)

(¡s,376,¡106)

(¡132,91¡l)

(¡1,060,016)

(¡70l,lc¡)

(¡2,04¡r,ss4)

(¡263,3sq

(¡t,343,411)

5

c.fi k þnbbr lnqilllrl2 tu Yor CrFdly knsmd D.hml A@ud

*h.dü|.10¡2hhúry2,m13

AfuI

m11

($m¡m) (¡1s,ss)

Aú.1

ú2

(¡s8,44o) (S74Bs)

ßl lrm ts1 t3l

(¡s05¡r)

(lso4¡o9l

Aù¡l AfuI

Ã12

lgs71,%l ltffi,1t2l

/g nút ts5-075ì

AfuI AÉ¡¡I

,¡lt^12

AÊhrrhc

AElul ht At'l Actú¡l AEù¡I DÍAL

2A12

(ssB.r3o) (¡trs,163) (¡5¡!6,$3)

& 9¿l ßlo-47ì G$.Sì

(¡6117¡7rl

Octs.PAugJuJunlrl¡yAÞIHalFbJfi

Gpâdty llãrEgcmnt Rænuê

Gry¡ng Cd

N.l lñil

ìlot &h6

(tsl,ss) (szl.æ7) (1ss6.883)

Ë6.7011

(sT2s,6m)

ts8.sr7)

7

0s0¡^m)

F308,ml

l¡l16:6¿)

(¡¡¡/t l,arl

(¡76,r291

(¡$0,s3¡)

(¡s0¿8m)

(¡1,083¡18)

(¡24,243)

(¡r¡srgt)

lsDrs,z4

(t2,t3¿8æ)

(¡E2r,554

(¡:r¡81¡46)

(¡!l4sJl4l

(,4605,0s)

Fr¡¡,fin

(ts$e,r44

(¡s82,1s1)

(3s,9l1,301)

l¡sr5¡20)

Fa/4sT¡7rl

6

lkolisnik

Text Box

4

C.dr. G.! I¡nlbb. lnc201J14 G.n.El Råb ApPllc.tlonSumm¡ry dÈ. Co¡E

2010/11 G.!

Schdul. l0 4.0

F.bru.ry 22,2013

¡0(3137,09!)

14112,72o1

l¡12,2s3)

11127,170141,2o42,r0sl,€2¡9,84

¡751,33342,376,1G2

(¡ls,o32)¡1,425

(t{¡,6il1¡€3,591(¡21,020)

tn4(¡1lo,4es)

¡37,111¡56,1 t6

FlxGd Co.b

V¡r¡åbl. Tãn¡ooúlion Co.b

TCPL F¡m S.ryiæ - Mân bn!ICPL Ftm Seryice - Sask Zon.TCPL Park t bn SeruiæGLGT Ped( å Loan Seil¡æGLGÍStoÉgs Gæ gsckhaul

Suppleñenbl Gas PeakirE Del¡veEd SeN¡æ lmpuH T6nspoÈton Cost

Pilmary Ga6 Deltuerêd SeMæ TrânspoÈtun Co31

ANR Oklshoma b C$bll Falls

ANR SbEge TrenspoÉl¡onANR SbEge WilMdl Chg

SbrBge Ges -Tmnspodation ãnd Ddiwrycomprcssor Fuål -TCPLb MDA

- TCPL b SSDA- oklâhoma- Slo6ge

Misællâneous TEnspoùtion Cha€gs

Tobl våñ.b|. TEnlpoÉ Co.b

supolv Cdb

Prirory Supply

Pirury Ge6 D€livered SeruiæPrirury Gss tum SbEgePñmâry GeG from StoÉgefor &cha4ssWith CounteÞadìesLBA &T$ervice hbâlances - Pilmery Supply

LBAt lseNiæ lmbalan€E - supplemenbl Supply

Oklahoma Supply

Suppleñênbl&stumStoEgeSupplemenþlGastum SbEge for üchång€s Wilh Gunterpâdi€6

Supplêmenbl Gas Pêakiru Dsliveed SeNiæDêliv€red SeNiæ -msmal€ Sedæ For Cutulld lnbiluPtibles

lor¡l suÞply Co.b

s48,æ5,476

-E

1s2.888'753)

î234

67

8

It011

12't3

14

15

1617

18

19

20212

242526

2829

30

33u36

38394041Q€445464748495051

g555657

585960

62

63ú65666768697071

TCPL Fim Seruice Deffind - Man bneTCPL Fim SsN¡æ Demnd - SackZoneTCPLSTS DemdStorâæ Capacity Chg.

SloraS DelveEb¡lity Chg

ANR oklahoma Demånd

ANR Lou¡sienne OemadANR StoÉge b snd Fom Cryslal Falls DemsndGLGT Emeßon to Crys Falls Dmd

GLGT Bachaul Demand

¡31,168,268v62,1n

¡2,ô11,347¡5,8G0,677

34,847,323

¡s05,183¡1,6,557¡1,71¡,¿l8l$1,912,8441,o27,&

$zE,ß7,650s262,132

42,611,317¡5,7¿,585¡4,59,6û2

¡€2,93051,¿105,564

¡1,6s,06031,831,151

41,o27,W

4872,Ë9¡E¿É42,200¡1,,r52¡9,84

¡4,800,287s2,376,162

34,083

t78271a12E,V1

s2,47,562¡638,370

t6,39212,6?2

¡274,500¡s6,116

(52 130 508)(s0)

(3$ 993)(¡s 4oo)(¡78 683)

{92)

$s99ÁZrs7 045

¡4 057 99

3030

¡0

(112,576,201)

¡1l,s,l¡18

¡20,015$69,84€

s1v,15111,963¡70

¡659,389¡s,689

3t33,17142373A2

30

ltE,¡176,41 I¡1t,545,1Æ¡18,181,1Ss2o,322,0æ

(¡2r,312)32,E52

33,8€,27054,0$,407s2,176424

¡28,1,12,536t5ô9,254

t101,052,620¡0

$35,0s5,8É¡0¡0l0

¡4,050,090$17,1,s81

¡013,1,049,340

t0

Itz1,t12l32,852

(¡200,!20)

s3.875,82ss2,176,44

(¡s,906,804)$$s,2r

(516 E74 670

420 32W

31n,251,201 32,911,74

a¡hs

TCPL Loed Belancing ChâqosMisælleneous Supplerenbl Cherges

CaÞacily MenaEement

Minell CheE€sHeds¡ng lmp.d

¡178,?t6¡3,783

(t5,331,031)

¡198,e3tE,931,r14

¡200.000¡o

(¡6,900,000)3198,4

¡20,6U,337

(¡21,2841

13,783si,5il,969

s0($r,6s1,524)

Torâl ldM lo PGva

PuGh!.ed Volum.. Acludlno PilñsdMS SuÞþlv lGJl

Pdmry GâsSupplemenbl Gas (ãduding AlÞmaÞ SéNice for Cuùiled lnterruptiblos)

AltemabSery¡æ tur CuÉild InlempUbl.s

37,3s7,05610,569,4

147,431

r7,035,ß711,127,Æ

0

321,519(ss,033)147,1X1

7

lkolisnik

Text Box

5

Gentra Gas Manitoba lnc.2O1Ol11 Gas Year Capacity ManagementActivitv bv Transaction Type

1 November 1,2010 to October 31,20112 Capacity Release Revenues3 Capacity Release Costs456 Exchange Revenues7 Exchange Costs8I

10 Totaf Gapacity Management Results November 1,2010 to October 31,201111

12 Carrying Costs1314 October 31,2011Ending Balance

$5,159,829($5s1,7e3)

$722,995

Schedule 10.6.1

February 22,2013

Total

$4,608,036

$722,995

$5,331,031

$45.375

$5,376,406

$o

9

Gentra Gas Manitoba Inc.2011112 Gas Year Capacity ManagementÂcfivifv hv Transaction Tvoe

1

2 Capacity Release Revenues3 Gapacity Release Costs456 Exchange Revenues7 Exchange CostsII

10 Gapacity Management Results''112 Carrying Costs1314 Gapacity Management Results to October 31,2012

$6,195,412

$6,773,423($578,011)

$191,491s0

Schedule 10.9.1

February 22,2013

TOTAL

$191,491

$6,386,903

$50,568

$6,437,471

10

lkolisnik

Text Box

6

cênh Gú M.nltobr lnc.201!r14 GÊn.61 R.h ApPlløüonsumm.ry olGt¡ Cdb

TCPL Load Balancing ChaEÊsCapâcily ManagemnlMinell Charg6s

Hedging lmpad

SchGdul. l0 E.0

FGhtú.ry 2, 2013

2011/12 Gr. Y.¡. Aúd.I234

6

78It011

12

14

15

16

17

18

19

20

21

2

24

26

2728

83031

32

33g

3637

39

40

41

4243445647484950

51

il55

606t5263

il65666766

70

71

72

Er¡r¿csts'

TCPL Fim Seryiæ Demând - Mân Zone

TGPL Fim Seryiæ Demånd - Sask Zone

TCPL STS Demend

Sbrage CepecityChgslorege D€liveêbility Chg

ANR oklåhomå Demand

ANR Louisbnna DeÉndANR SbEg€ b and Frcm crysbl Falls D€månd

GLGÍ EreÉon b CF Falls Dmd

GLGI Backhaul Demand

¡24761,780¡15G,æ

,2,A912s2¡5,E33,7t1¡4,621,263

3502,351

sl,ß8,n9t1,692,769í,878,9tE¡1,03s,582

¡31,1æ,2G8t262,132

¡2,61t,347¡5,rGo,6234,647,38

3505,1t3¡1,154,55711,714,61¡t,9t2,83441,o27,Æ

(36,æG,4891

f¡10s,1c0)t279,g¡ls(¡26,S6¡(¡26,080)

(32,133)

(35,750)(Jzr,6S2)($3 sr7,l¡12 13G

3e,s17,1ü a51'171,2A (36'357,121)Tobl Flr.d Co¡B

V¡drbl. TEn¡poûilon C6b

TCPL F¡m Ssiliæ - Man bnsTCPL Flm Seru¡æ - Sæk Zone

GLGT Park & Loan SeruiæGLGT SþÞge Gas Backheul

Supplemenkl Gæ Peâting D€lireEd Seiliæ lmpubdf€nsFùton Cosl

Pr¡mary &Ê DCivsr.d Seryice lmput€d fEßpoÉÍon CoEt

NR Oklåhoma lo Crysbll Falls

ANR SloEæ TÞnspoûlionNR Slo€ge W¡hdillChgSbÉge Gú -T€nspoôtion and Dêlivery

Compßssr Fæl - TCPL b MDA-TCPL b SSDA

- Okbhoma- SbEge

NR SloÉw Gas CFI¡ng ChaEe

Tobl Varirbl. TEnlpoñ Colb

supolv co.b

Pdmary Supply

Pfmary Ges Deltusrcd SeilicePrimary GaE from SbqePr¡mary es from Sbqe lor ErchnFs With Counte@âdês

LBA &f€eNic6 lmbalancsE - Pdhary Supply

LBA & T-Ssru¡ce Imbalancos- Supplemènlal Suppv

Otlahoma Supply

Supplemenbl Ges hom SbGFSupplemeffil Gås tum SloÉæ for E¡changes Wilh Counlenafres

Supplemênbl Gas Pêåking Deliwêd Sery¡æ

Oeliv6d Seruiæ -AlbrÉÞ Ssryiæ For Cuúiled lnlarupbbl€s

fobl Supply Corb

e!!s

¡101,052,620¡o

¡35,055,8253o30

¡o¡4,050,090

1174,581¡0

¡3,1,049,34030

(¡s6,508,5511

¡34,978,193(¡17,7ss,6881

¡5,509,sil¡3E,255

l0(¡1,897,5E1)

(¡174,s81)

¡0(sr,856,06s)

9526,765

s5,747,700

ts67.2€.688)

{387.959'7S)

5972,803

57,008

¡11,105t0

¡6,5i15

¡o¡10,662,680

¡8,319546,089

¡71,493¡1,193,E57

¡614,ô87¡3,110

¡71,336s188,55E

¡216,7!3

3990,ffi l¡26,62G)(¡36)

!ll,E05¡0

¡E,ff(34,057,ss)

510,662,680

f¡fi,89C)(¡8,75s1

(¡105,959)(¡770,1 l3)lae,7r2l

(s2,s5sl(¡61,835)(¡4,825)¡21Ë,733

37 0¡ß

¡0¡4 0s7854

¡0¡ot0

¡20,01ss59,848

¡tz,45l¡1,963,970

¡6s9,389¡5,669

5133,171

323734230

alônß ¡r2 ç¡ ltl lt¡

aa7¿ ta2 ¿57

a?4 00e frg

¡o¡2 152 509

a2 19327s

344,9,069¡34,9æ,193417,U6,137¡1$9,564

¡s,ãs

t0¡o

s526,765

¡107,138,769

tl60 0s 035

¡203,519(¡6,3E6,903)

3196,44¡0

5200,000(¡G,900,000)

st98,4320,63,337

!3,519¡513,097

¡0(s20,6ã,334

Tobl lnnow b PGVA

Purcþs.d Volunú kclud¡no PdmäN rc SuoDþ IGJì

Pr¡mEry @sSupplemånbl Gæ (Adud¡ng AlÞrnâte SeNiæ for Cuúiled lntempt¡bl€s)

Allcmale Seruiæ for Cudeìled lnlerruptibles

37,03s,ß711,127,155

0

2,n1,û11s,s60,79s)

18t,032

ToblVolums Etcluding P.¡m.rymS Supply (d)

t9,316,t381,566,660

181,032

11

lkolisnik

Text Box

7

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA F88

Subject:

Reference

Tab 10 - Gas Costs

Tab 10 Page 5 of 63

Please provide a graph showing the AEGO monthly reference price and Centra's

Primary Gas rates (both residential and non'residential) since 2000.

NEB:Please see the attachment to this response

2013 04 12 Page 1 of I

13

Gentra Gas Manitoba Inc.2013114 General Rate Application

$0.50Alberta

PUB/Gentra l-88Reference Price and Gentra Primary Gas Billed Rates

$0.45 $12

$0.40

$0.35

^ $0.30Lgoçã $o.zsõ=ob $0.20o-Ø

$10

$a

1(9L

$o 8-@

$0. 1 5 $¿

$z

$o

$0.10

$0.05

$0.00Jun-00 Jun-01 Jun-02 Jun-03 Jun-04 Jun-05 Jun-06 Jun-07 Jun-08 Jun{9 Jun-10 Jun-11 Jun-12

-

Monthly Alberta Firm Market lndex Price at AECO'74'

-

Residential Primary Gas Billed Rate """"' Non-Residential Primary Gas Billed Rate

14

lkolisnik

Text Box

8

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sãt.@

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F,l5

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16

Centra Gas Man¡toba lnc-

November 20'10 to October 2012 AveEqe Monthlv Un¡t Costs

1 Monihly AveEqe Unit Cost of Purchaæs

3 Primary Supply ât Empress fom ConoæPhillips

4 Oklahoro Supp¡y

5 Louisìana Supply

6 Primry Gas Del¡vercd Soryiæ

7 Supplerental Ges Pek¡ng Del¡vered SeNiæ8 Eme6on Supply

I Primry Supply fon StoEge10 Supplerentâl Supply from StoÉge

11

12

1 3 Market lndex Prices14

l5 AECO

16 Michigan City Gale

17 NYMEX

18

20

21 Monthly A@Þqe Unit Cost of Purchaæs

22

23 Primary Supply al Empress frcm ConocoPh¡ll¡ps

24 Oklahomã Supply

25 Louisiana Supply

26 Primary Gas Delivered SeMæ

27 SupplerentalGas Peaking Del¡vered Seryiæ

2E Emerson Supply

29 Primry Supply fon StoEge30 Supplerental Supply from Storage

31

32

33 Mârkêt lndex Pricesu35 AECO

36 Mich¡gên C¡ty Gaie

37 NYI\¡IEX

s3.5427

Dêc-ll -l^^-12

PUBrC€ntE l-102 (a)Attachrent

Aoril 12. 2013

SCAD/GJ

SCAD/GJ

SCAD/GJ

SCAD/GJ

$CAD/GJ

$CAD/GJ

SCAD/GJ

$CAD/GJ

$3.E162

s3 4516

nla

ñ!a

$3 4516

nla

s3 E521

$4 9408

s3.E752

$3.s578

îlanla

$3 5578

nla

s3 6521

s4 9408

$3 6701

$3 7126

ila$3 45s2

$3 5512

$3 E7E4

nJa

tíê

s3 7824

$3 7969

¡la$3 5661

s3.91E2

nlanlañlê

$3-8731

$3.E433

îla$3 7362

n/a

rlanlanle

s3 4948

93.4512

îlas3.3127

n/a

ilanleîlà

s32622$3 57E2s2 8033

s32622n/a

$3 5782

nla

îla

nlas3 083'l

nla

ila

nla

Ár.-11

537720 $3 6266

Mr¡-12

nla

n/â

^ô.-1 ? -tt^-1t

11

$3 8721 53 6169

-tt-1t^ttd-12

s3 9366

nlenlailaîlaîleole

05$3 E1

nla

^larlailaîlenle

s3 5947

s3 7270

nle

$3 343s

nlanlanle

nle

ot-12

s3 E521

s4 9408

s3 6521

$4 940E

$3 8521

s4 940E

$CAD,/GJ

SCAD/GJ

$CAD/GJ

$CAD/GJ

SCAD/GJ

$CAD/GJ

53 4049

s3 2026

s3 1914

53 71 13

s3 4059

s3 6025

s4 2610

$3 9688

s3 2062

$3 4E94

s3.2427

$3 6712

$4 1796

$4 0048

52.8617

53 1 155

s2 93E3

$3 6991

s4 1723

s3 987

s23222s2 6744

s2.5042

$3 3622

s3 7120

$3 4909

s1 9732

$2 4E10

$2.3163

s3 4426

54 0999

$3 9587

$1 7126

s2.1A2A

$2 0526

s3 5354

$4 2698

$4 0219

$1 5566

$2 1285

$1.9971

s3 6558

$4 1860

$3.9575

s1 9472

$2 4534

$2 s462

s3 7166

54 0681

$3.9416

51 8967

$2 6576

$2 6329

s3 4s46

u.2'194s4.061E

52-2794

s2 9634

52,8't3E

s3.4087

s4 0372

53.79'f0

s2.2911

îlanla

52.2144

nla

nlaîlanla

$2 0597

s2.5640

s2 4559

s2.3382

s3.0129

s2_E613

s3 4601

$3.7384

s3 5406

SCAD/GJ

$CAD/GJ

SCAD/GJ

SCAD/GJ

SCAD/GJ

$CAD/GJ

SCAD/GJ

SCAD/GJ

s3 2902

$3.2933

nla

s2 8521

nlanla

s3.6749

^la

63 2077

$2.8255

î!e$2 8255

nla

iJa

$3 6749

nla

$2 6573

$2.6273

nla

s2.4806

s2 6176

nla

s3.6749

nla

$2 2996

nla

nla

s1 9944

$2 4E46

nla

s3.6749

n/a

$l 9316

nla

nla

$'1 7715

$2 5949

îla$3 6749

n/a

$l 7703

^larle

$1 3964

$2 01E7

nle

rl¿nla

s2 0874

nla

nlê

$1 4360

nla

nl¿

nlenla

52 3989$2 0533$2 041 s3.0903

nla

rVa

s2.4888

s3.3294

ilanla

n!a

ilanla

nlàilanle

nlaila

rlanlanle

nla

îleîlenla

nlanlan/a

nla

nlenlanld

17

CentE Gas Man¡toba lnc.

2013/'14 General Rate Appl¡cat¡on

Primary Gas lnflow Volures - 2010/11 & 2011/12 Gas YeaF

1 November2010 to October 20l l lnflowGJ's

2

3 Primary Gas lnflow Volumes fGJl

4

5 Pr¡mary Supply

6 Primary Gas Deliveed Seruìæ

7 Primary Gas from Storage

I Pr¡mary Gas StoEge viâ Exchanges with Courìterparties

9 Total

10

1 1 November 2011 to October2012 lnflow GJ's

12

13 Primarv Gas lnflow volumes IGJ)

14

15 PrimarySupply

16 Primary Gas Del¡vered Seruice

17 Prjmary Gãsfrcm Storage

18 Primary Gas from Storage v¡a Exchanges with Counterpart¡e

1 9 Total

PUBlcenüa l-102 (b)

Attachmmt

April 12 2013

Apr-l l Mav-ll Jun-l1 Jul-l1 Auq-11 SeD-11 Oct-1 1 TotalNov-10

2,A61,540

o

577,1

667.098

2,188,421

1,650,000

297,371

427.904

0

't,092,469

1.O77,243

Feb-11

2p23,273

0

1,A12,48

770 8aO

1,780,409

2,755,000

1,336,742

59 3a7

Mar-11

3,31 8,706

0

488,405

2599117

't,149,420

2,170,000

435,795

251 200

2,O93,423

1,050,000

0

0

1,294,152

't,371,000

0

0

1,1 23,683

775,000

0

0

6f'9,421

930,000

0

0

'1,660,928

775,000

0

o

2.132,783

I,1 1 2,900

0

o

23,861,593

3,500,000

4,719,886

5-275-íTf

17,379,736

15,73t,300

4705,560

1-499-242

Dec-10 Jan-'ll

3,343,665 3,187,933

0

749,404

æ7,364 905,022 951,092

450,000 0 0

000000

804,564

450,000

0

o

935,067 1,086,2148

0 317,400

0000

4,10s,834 5,513,417 6,437,710 5,506,561 4,067,058 3,t43,823 1,898,683 1,'137,364 9O5,O22 951,092 1,254,564 2,435,928 37,357,056

Nov-í1 Dec-11 Jaî-12 Feb-12 I'llar-'|2 þ!:12 Mav-'12 Jun-12 Jul-'12 Aq12 Seo-12 Oct-12 Total

2,4sA334

2,480,000

664,U7

678.000

'1,838,761

2,945,OOO

I,972,305

988,230

0

n

0

857,890

0

0

0

4,563,700 6,2s0,68i 6,838,8i3 5,931,s38 4,006,815 2,665,152 1,599,421 988,230 857,890 935,067 t,4o3,848 3,2¿15,683 39,315,838

18

f)

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA II.179

Reference: PUB/Centra l-102(b); Tab 10 Page 36 of 63; Schedules 10.4.'1, 10.8.1

Please provide the monthly Primary Gas baseload volumes from Empress, the

monthly Primary Gas swing volumes from Empress, the average AECO daily

price for each month, the AECO to Empress Nova tolls, the AECO to Empress

Transportation Basis Differentials, and the monthly Primary Gas sales volumes

for the period November 2010 to October 2012.11Centra claims any portions of

this inforrnation to be commercially sensitive information, such portions may

be filed in confidence, with a redacted response being filed on the public

record.

ANSWER

Please see attachment to this response,

2013 05 07 Page 1 of 1

19

CentR Gas Man¡toba lnc,2013rli+ GeneÊl Rate Appl¡cat¡onPrimry Båsd@d & Swing Volumes, Oa¡ly and Monthly Pricing Components

'l Primary Gãs Baseload Volumes from Empress (Cono@Phill¡ps)t

2 N4onthty Primary Gas Swing Volumes from Empress (Con@Ph¡ll¡pst

3 Cenùa Primary cas Sales Voluæs4

5 AveEge AECO Da¡ly Spor Priæ (NGX)

6 AECO to Empress Nova Tolls (NGTL)

7 AECO to Empress Monthly Basis Diñeænt¡al fndex (CGPR)I9

10

't1

12 Primary Gas Bâseload Volumes from Empress (Con@Phillips)r'13 Monthly Primary cas Swing Volumes from Empress (Con@Ph¡ll¡pst

14 Centra Primery Gas Sales Volumes

16 AveEg€ AECO Daily Spot Priæ (NGX)

17 AECO to Emprcss Nova Tolls ( NGTL)

18 AECO to Empress Monthly Bêsis DifieGntjal lndex (CGPR)

19

20 Note l: Primary Gas StoÊge púrchases ae ¡ncluded,2'1

s3.4786

s0.1982

(so 1rs2)

s3 6995

50.'t982($0 1s0s)

$3 7E4s

$0 19E2

($o 1134)

$3 4132

$0 19E2

(50 12oe)

s3.5259

s0.1s82($0.1000)

93 5414

$01982($0 1603)

53 7006

s0.1982

(s0.1816)

$3 7944

$0 1982

($o 172s)

$3 510E

$0.1962

($0 1630)

$3 4502

$0 1962

($0 2029)

s32019

$0't930($o 27¿6)

PUB/CentE ll-179 (0AttachmentMay7,2013

Nov-10

1,619,700

'1,397,879

3,984,318

Dec-l 0

2,U7,550

1,523,960

6,221,7ß

Jan-11

2,425,750

1,135,2E0

6,937,572

Feb-ll1,867,600

1,355,930

5,593,938

Mar-11

1,556,820

I,960,'132

4,971,003

Jun-ll't,40E,500

429,254

E3t,866

Jul-ll2,224,470

61.209

707,571

Oct-l I855,600

'1,179,343

1,957,990

Total

20,180,680

12,234.899

36,96E,805

Apr-l I'1,396,800

1,636,526

2,4Tt,526

Mav-1 I1.194,430

880.784't,591,395

Aud-ll2,171,æO

169,921

72'1,409

Sep-11

1,411,200

504,681

972,462

s3.4420

$0.'19E2

($0.2364)

Nov-ll tÞc-l1 Jan-12 Feb-12 Mer-12 Aor-12 Mav-12 Jun-12 Jul-12 Auo-12 See-12 Oct-12 Total

52Ê,200.1,716,330

4,556,6't6

1,529,230't,151,756

62O9,2ß

1,47A,700

727,æA6,895,718

625,240

1,429,6'12

6,059,689

't,517,395

2,77't,343

575,994'1,494,099

309,900

711,744

1,147,267

1,4A4,2AO

92,132

794,61

f,467,3E0

165,829

835,266

742,500

531,994

1,274,481

'156,240

21U,6263,252,975

E,771,500

11,A1A,413

39,286,O18

s3.0872

s0.1930

(s0.3393)

s2.8112

$0.'1930($0 3807)

$24204

$0 1740

($o 3E11)

$2 0493

$0.'1740

($o 327E)

431,E30

1,063,463

3,950,897

$1.69E3

s0.1740

($o 2017)

$1.5937

$0 1740

($o 3347)

s.1.9452

s0.1740(s0 1s31)

$t 6586

$0 1740

s0 0245

ö2,43J$0.1740

$0.1 1E3

s20u7s0 1740

90 0161

$2.1848

$0.1740

$0-1123

s29222$0 1740

$0 1 196

20

CEN'TRA GAS MANITOBA INC.

lnterlm Primry Gas Rat6B Effect¡ve Aug I, 2011

Pr¡mary Gas PGVA(based on forward market strlD a6 at Julv l.201I clo6e)

Schodule 1.1.3

(1)

ADrll Mav Ju ne Julv(4)t3l(2)

Ed.treLqec-rcvA'I lnflows

2 Pr¡mary Gas Direct to Load

3 Primary Gas from Storage

4 TCPL Fuel to MDA & SSDA

5 Exchanges With Counterparties (excluding stg. Withd.)

6 TCPL Line Pack/Draft Nomination & T-Service lmbalances

7 Other Primary

I M¡scellaneous Primary

e Hedging (System Supply)

10 Totel lnflov/s

I 1 Less: UFG Component to Trans Accnl'12 lnflow Æter UFG Transfer

14 WACOG Outflows

15 Pr¡mary Gas Rate RiderAmortizations

16 Total Outflows

17

18 Carry¡ng Costs

zo Net Balance

Actual Aclual

$4,172,204

$0

$30,345

$0

$92,438

$2,739,935

$0

$244,780

Outlook

$4,070,537

$o

$26,735

$o

$o

$o

$0

Outlook

$3,959,649

$0

$26,004

$o

$0

$0

$0

$1 85.360

t7,285,701 $¿1,300,882 14,171,O13

(s149,580) ($107,308) ($1 00,699)

s7,136,121 04,193,573 $4,070,31¡f

($6,685,71 5)

$1 90,859

($3,3ô9,788)

s73 163

($3,390,643)

s73.61 5

(t6,494,858) ($3,2e6,026) ($3,317,027)

($5,233) ($e,450) ($7,683)

($5,,!16,176) (t4,8r0,144) (t3,e22,6¡17) (i3,177,043)

21

CENTRA GAS MANITOBA INC,

lnterim Prlmary Ga8 Rates Effectlve November I, 201 IPrimary Ges PGVA

Fl¡ln 3_ ôsâìthaßêrl on foMard market as at October 2011 cl

Schedule 1.1.3

(1)

Julv

(2)

Auoust

(4)(3)

Sêõlember October

PlLmgtr.g3¡-Eçd¿A1 lnflows

2 Primary Gas Direct to Load

3 Pr¡mary Gas from Storage

4 TCPL Fuel to MDA & SSDA

5 Exchânges With Counterparties (excluding stg. Withd.)

6 TCPL Line Pack/Draft Nom¡nation & T-Service ImÞalances

7 Olher Primary

I Miscellaneous Primary

I Hedging (System Supply)

ro Total lnflows

1 1 Less: UFG Component to Trans Accnt

12 lnflow After UFG Transfer

13

14 WACOG Outflows

15 Primary Gas Rate R¡der Amortizations

16 Totel Outflow6

17

18 Carrying Costs

1S

20 Net Balance

Actual Actual

$3,426,094

$o

$1 4,974

$o

$'10,567

$o

$0

s0

Outlook

$5,197,'172

Outlook

$9,4ô5,967

$0

$62,335

$o

$0

$2,145,262

$0

so

s3,4tí,635 s5,231,351 $ll,ô73,564rß98 614ì ,Alìr 1ß1qô 3¿3r

$3,353,02f t5,119,070 611,Æ3,221

($2,87ô,201) ($4,461,788)

$67,18e $s9 1 51

f32.809.012) ts10.025.427ì

($5,e41) ($5,725) ($3,247)

$o

$34 1 78

$o

$o

$o

$oRô

($1 0,253,278)

s227.851

1s3.460.659ì t32.s22.551 ls2 171 883ì lß717.335ì

22

lkolisnik

Text Box

9

Gentra Gas Manitoba lnc.Summary of All Gas Cost Deferral BalancesTo Ju Iv 31,2013

2009/10 Gas Year BalancesApril 30, 2011 Prior Period Gas Deferrals

2010/11 Gas Year BalancesSupplementalGas PGVA

Transportation PGVA1

Distribution PGVAHeating Value Margin Deferral

Gas Cost DeferralBalances as at October

31,2012

$746,'147

($9,750,857)

$7,612,899($505,72e)($786,854)

($6s7,860)

$5,600,955($1,706,117)

($4ee,057)

Schedule 10.11.0

February 22,2013

$746,147

($3,430,541)

$2.697.921

$13,526

$21 8

s13.744

1

2

3

4

5

ô78I10

11

12

13

14

15

16

17

18

19

20

21

2223242526272829

Sub-Total Non Primary Accounts 201012011

2011/12 Gas Year BalancesSupplementalGas PGVA

Transportation PGVA2

Distribution PGVAHeating Value Margin Deferral

Sub-Total Non Primary Accounts 201112012

Total All Non-Primary Account Forecast Balances at October 31,2012

November 2012 through July 2013 Carrying Costs of all Gas Deferral Accounts

Total All Non-Primary Account Forecast Balances at July 31'2013

Note 1: lncludes embedded credit of ($5.376 million) for 2o1Ol2O11 Gas Year Capacity Management results including carrying costs

Note 2: lncludes embedded credit of ($6.437 million) Íor 2011t2O12 Gas Year Capacity Management results including carrying costs

23

lkolisnik

Text Box

10

February 19,2010Page 1 of4

CENTRA GAS MANITOBA INC.

2O1OI11COST OF GAS APPLICATION

RESPONSE TO INFORMATION REQUESTS OF

THE PUBLIC UTILITIES BOARD OF MANITOBA

1

2

3

4

5

6

7

I

9

10

11

12

13

14

15

16

17

18

19

20

21

22

PUB/CENTRA 16

Reference: Tab 5 Page 2 oÍ 10 - Gas Supply Contract

(a) Please file the redacted evatuation matrix used by Centra to select its new Primary

Gas supplier which was previously filed with the Board on October 16' 2009.

Please see the attachment to this response.

(b) Please confirm the name of Centra's new Primary Gas supplier

Centra's new supplier is ConocoPhillips Canada Marketing & Trading ULC'

(c) Please deta¡l the non-pricerelated differences between the new gas supply contract

and the recently expired contract.

Non-price-related features of the new contract that differ from the expired contract are as

follows.

1. New contract: maximum baseload volume of 140,800 GJ/day in any month'

Expired contract: maximum baseload volume of 127,000 GJ/day December-February

and 110,000 GJ/day in the remaining months.

2. New contract: provision for supplier to reasonably accommodate annual adjustments

to maximum baseload and swing volumes.

25

PUB/CENTRA 162O1Ol11 Cost of Gas ication

February 19,2010Page 2 of 4

1

2

3

4

5

6

7

I

I

10

11

12

13

14

15

16

17

18

19

20

21

Expired contract: provision to negotiate such changes.

3. New contract: supply exclusivity is limited to Centra's requirements for its firm

transportation from Empress (excluding WTS supply).

Expired contract: supply exclusivity applies to all requirements at Empress (excluding

WTS supply).

4. New contract: restriction on resale of supply (excluding situations in which Centra has

excess supply at Empress) is limited to Empress.

Expired contract: restriction applies to all delivery points.

5. New contract: in the event Centra is long gas at Empress, supplier has no right of first

refusal on Centra's sale of excess supply.

Expired contract: supplier has such right of first refusal.

(d) This evaluation matrix shows that the winning proponent obtained the maximum

score for minimizing commodity costs. Please demonstrate that the gas costs for

the new Gas Supply Contract are in fact less expensive by calculating the forecast

Primary Gas costs at Empress for the 2009/10 Gas Year for each proponent and

tabulating the results.

The following table provides the differentials between the successful proponent (Party A)

and all other proponents which provided a complete proposal. All forecast costs assume

provision of all of Centra's Primary Gas requirements for comparison purposes.

26

1

February 19,2010Page 3 of 4

Forecast 2009/10 Gas Year Commodity CostDifferential of Proposals as of May 1, 2009

Party AParty B

Party CParty E*

Party F (1)

ParN F Q\

$841,486$1,540,901$1 ,397,415$1,686,146$1,637,316

Party D's proposed pricing was incomplete and is therefore not included in the

comparison.

Party E indicated that its proposed pricing was only valid under certain assumptions

that were not consistent with Centra's operating requirements.

Party F provided two pricing proposals.

(e) Please explain how Gentra evaluated the different proponents for the new gas

supply contract ¡n terms of: 1) providing reliable supply, 2) credit rating/tvorthiness,

3) credit requirements placed on Centra, 4) Customer service and responsiveness, 5)

proven performance, and 6) sustainable development. Please elaborate on the

differentiators for each criteria (i.e. why certain companies scored higher than

others).

Centra considered the following factors in performing the evaluation of the gas supply

proposals:

1) The proponents were evaluated on factors such as their magnitude of operations in

the Western Canadian Sedimentary Basin ("WCSB") including production volumes,

their capability of moving large volumes of gas to Empress, and Centra's

experience with the proponent. The successful proponent (Party A) is affiliated with

one of largest natural gas producers in the WCSB; this affiliate's 2008 Canadian

2

3

4

5

6

7

I

I

10

11

12

13

14

15

16

17

18

19

20

21

22

a

a

27

PUB/CENTRA 162010111 Cost of Gas Application

February 19,2010Paqe 4 of 4

I

2

3

4

5

6

7

I

I

10

11

12

13

14

15

16

17

gas production rate was greater than the combined production rates of the

production affiliates of the other proponents.

2) The proponents were first identified as investment grade based on their credit

ratings from major credit rating agencies. The credit ratings of the parent

companies were used in the case of unrated subsidiary companies. The

proponents were then evaluated based on their credit ratings'

3) The proponents were evaluated based on the credit assurances that each expected

to seek from Centra.

4) The proponents were evaluated based on Centra's experience with the proponents

from a customer service perspective including timeliness of response to inquiries,

problem resolution, and willingness to provide accommodating and flexible service.

5) The proponents were evaluated based on Centra's experience with the proponents

in addition to references from other parties as necessary to confirm the experience

and performance of the proponent as a supplier.

6) The proponents were evaluated using publicly available information on corporate

commitments to sustainability and the environment, such as inclusion on the Dow

Jones Sustainability lndex and corporate reports on sustainable practices.

28

Centra Gas Manitoba lnc.2010/11 Cost of Gas Application

PUB/Centra 16(a)AttachmentPage 1 of 3February 19,2010

ManitobaHydro

PO Box I I 5 . \\'¡nnipcg ñlnnitoba Canadn . Ill(' 2P4

Slrecl l-ocît¡on l"or DEI-IVERY: 3'J l"loor - 820 Tnllor Avellue'f'clcphoncl,V r/ctòléphone: (204)ló0-14ó8 . lin\ /^''rlc,(;r¿copienr: 12041 ló0'ó147

nr nnr qrhl'(aj h¡'dr o. r nb.c a

RE

Octol¡el 16, 2009

PUBLIC U1']LITIES BOARD OF N,IANITOBA400-330 Porlage Avenr¡e

\\/innipeg, Manitoba

R3C OC4

ATTENTION: M¡'. G. Gat¡dreau. Executir,e Director

Dear Mr. Gaucll'eau:

CEN't"R,r GAS I\lÁNtroBA INc. ("CENTRA")

REQUEST FoR PROPOSALS WESTERN C¡\NADIAN GAS SUPPLY - tr\,ALUATION I\.IA.TRIX

Centla's gas couunodity supply contl'act rvith Nexen Gas Markcting, Inc. is due to expire ort October'31,2009. As discrnsed belorv, Centra has unclertaken a thorough process lo solicit nerv natt¡tal gas conltroclitysu¡lply arl'arìgelìrenls to take effect o¡r No't,enrl¡et' I, 2009.

As noled il¡ Centla's lettel to the Public Utitities Boarcl of Manitoba ("PUB") dated February l'7,2009regalding the Request Fot' Pro¡losals ("RFP') fol Westeln Canadian Gas Su¡lply, Centra ertgaged tlre

services of ICF Inlernalional ("lCF") to assist in the assessnlent and evalr¡ation of plos¡tective gas

cornrnodity supply ploposals, Centra issued a RFP to 50 inlelested counlerparties ott Febt'uat'5. 20,2009.Six counter?arties les¡rondecl b¡,subnritting plo¡rosals by the deadline of Malch 17,2009. During the

reyie\\,plocess, all ploposals u,ere assessed nnil evalualecl rvitlr the assislartce ol'lCF.

Lt older to eva.luate the respective gas cornrnodity suppl¡, ploposals, a set of crilcria \vere designed to

¡rlocluce the lnost cost effective conrbination ofchal'actelistics lo se¡'ve the lt4anitoba nla¡'ket. An EvalualionMall'ix s,as developecl and utilized to assist ill the evah¡ation and scolirrg of each les¡rectite conlnoclitysu¡r¡llypro¡losal. Tlrefollou'irrgiclentifiestheEvaluatio¡¡lr4atlixcriteriafblrvhichtlte pt'oposalss,eLetated:

' Plovides Reliable Supply

' Mi¡riurizes'l'otal Cost of Sup¡rly. Credit/FinancialSubstantiation. CoutrlellraltyQuality. Consistent'n,ith other Cor¡rorate Goals. Meets WTS Requilentents. Provides Operational Notni¡ration Flexibilitl,

The findings ancl scoriug results of the various ¡l'oposals 11,s¡s ¡sl,is11,scl b1' ç.rl,t^ Managentent ancl the

lecolunlenclatiolls rvere plesented to Centra's Board of Directols on Jt¡ne 24, 2009. Centra enterecl inlo a

lles, lhree year gas conrmoclity sup¡lly an'angenìerìl rvith lhe successful corurterparly, s,itlr gas flou's fi'oluthis nerv an'arìgenlerìt to begin effective Novetrrbel' 1,2009.

29

Centra Gas Manitoba lnc.2010/1 1 Cost of Gas Application

ocrober 16,2009Public Utilities Boarcl of Manitoba

Page2

PUB/Centra 16(a)AttachmentPage 2 of 3February 19,2010

Due to the sensitive conunercial nature of the plicing fonnula contained in tlte tenns of the nes' gas

colnnrodity supply contract, Centra has sublnitted lhis contracl to the PUB as a separale confidential filing'Cenlra is respectfully subrnitting the results of the proposal evalnation scot'ittg nlatrix as attached to this

letter to the PUB and its advisols. Please note lhat the counlerpany names har,e been reclacted. Centra

arvaits frl'thel direction f¡'onr the PUB as to tlre distribution of tlris letter to irrterestecl parties.

Shoutd you have any questions regarcling this subnission, or prefer a paper copy, please contact tlle lvrilerat 360-3468 or Crcg Barnlund al360-5243.

Yours trrly,IVIANITOBA HYDRO LAW DEPARTIVTENT

Per: 1\4VMarla D. MurphyBan'isler and Solicitor4il.

cc: iVtr. B. Peters, Fillnrore Rilcy

Mr. R. C¡rthcart, Cnthcart Advisors lnc.

i\,1r. B R),nll, Encryy Consultnnls lnc

30

Centra Gas Manitoba lnc.2010/11 Cost of Gas Appl¡cation

RFP 029212 WESTERN GANADIAN GAS SUPPLYCENTRA GAS MANITOBA INC. -. EVALUATION MATRIX

PUB/Centra 16(a)AttachmentPage 3 of 3February 19, 2010

Yes

Yes

5.45

6

10

Yes

3.5

2

4

4

8

PARTY F

5

6

10

Yes

6.25

5

6

6

7

Yes

7

5

10

10

Yes

4

2

PARTY E

6.73

4

5

7.5

Yes

No

7

10

I

Yes

6.5

2

5

PARTY D

7

Yes

Yes

6.88

3

8

Yes

5

6

7

6

6.5

PARTY C

7

7

10

Yes

8.38

2

10

9

10

8.5

Yes

'10

7

10

10

Yes

1

PARTY B

8.5

Yes

Yes

8.83

1

10

10

10

Yes

5

I

9

I

PARTY A

Criteria Score "0-10" or "Yes Útlo" as necessary

I

0.05

Yes No

Yes 10

0.20

0.05

0.05

Yes L No

0.10

0.05

0.05

0.05

SubGategoryWeight

0.40

0.05

0.40

0.30

0.15

0.10

TotalCategoryWeight

Total of All Gategories

5.1 Sustainable Development / Reduced Environmental lmpacts

6l Meets WTS Requ¡rements

6 I Provide for monthly contract level modifìcat¡on (must be present)

7) Provideooerationalnominationflexibility

1 Use of all nom¡nat¡on w¡ndows be

1.1 Reliable Supply to Customers

2l Minimizes Total Gost of SuPPIY

Minimize commodity costs

Minimize fìxed asset costs

Minimize internal Gas Supply mgmt costs

Credit ffinancial Su be investment

3 I Credit Rating / Worthiness

3.2 Credit requirements placed on Centra

4) CounterpartvQualitv

.l Customer Service / Responsiveness

.2 Proven performance / References and Existing Contracts

Consistent with other

Descriotlon of Criterla:

Provides Reliable I

RANK

31

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.91

Subject:

Reference:

Tab 10 - Gas Costs

Tab 10 Pages 16 and 17 of 63 - Gas Supply Contract

a) please file the redacted evaluation matrix used by Centra to select its new

Primary Gas supplier with the respective scoring.

ANSWER:

Please see the attachment to this response

2013 04 12 Page 1 of 1

33

PUB/CENTRA l-91aAttachment IPage 1 of 1

RFP WESTERN CANADIAN GAS SUPPLY 2012-14

CENTRA GAS MANITOBA INC. -PARTY FPARTY B PARTY C PARTY D PARTY EcoNoco

PHILLIPS

SubCategoryWo¡sht

TotalCatogoryWsisht

G¡lterla Score'0-10' or'Yes / No' as necessary

oeic.lollon ôf Cf¡torla:

8.510 8.5 8.5 I 6.50.40

0.¡10

l) Provides Reliable Supply

1 1 Reliable suDolv to ostomers

59.5 8.5 7.510

10 l010 10 10 10

10 10 l0 b

0.30

0.20

0.05

0.05 l0 10

2) Minimizes Total Cost of Supply

2 1 Minimize @mmod¡ty costs

2 2 l\4¡n¡mize lìxed âssetcosts

2 3 M¡nim¡ze internal oas suoolv manaqement æslsYes No YesYes Yes Yes

4.3 5.0 0 3.24.3 3.2

2 6 10

0.15 Y6, No

0.100.05 8 l0 10

Cred¡t / Financial Substantiation (musl be investmsnt grade)

I Cred¡trating/worthlness

Credit

6 9.5 4I 10

bI I 8.5 o

0.10

0.05

0.05 10

4) CounterpartyQuality

4,1 Customer seruice / responsiveness

4 2 Proven oelomance / references and exist¡nq contracts

6.4 7.O0.0s 8.5 7.9 7.9 7.O

0.055) Cons¡stent w¡th olher Corporate Goals

5 I Susta¡nable development / reduæd env¡ronmental lmpacts

Yes Yes Yes YesYcs, No Yes Yes6) Meets wTS Requirements

ì I Prov¡de fôr monthlv æntract level mod¡f¡cation lmust be Dresent)

NoYes Yes Yes YesYsB / No YesProv¡de Opêrational Nomination Flex¡bility

I Ljse of all nom¡nat¡on w¡ndows6.95 6.879.16 8.47 8.23 7.38Total of All Catesories

5 62 3 4RANK

34

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.91

Subject:

Reference:

Tab 10 - Gas Costs

Tab 10 Pages 16 and 17 of 63 - Gas Supply Contract

b) Please explain how Centra evaluated the different proponents for the new gas

supply contract in terms of: 1) providing reliable supply, 2) credit

ratingrtuvorthiness, 3) credit requirements placed on Centra, 4) Gustomer

service and responsiveness, 5) proven performance, and 6) sustainable

development. Please elaborate on the differentiators for each criteria (i.e. why

certain companies scored higher than others).

NEE:

Centra considered the following factors in performing the evaluation of the gas supply

proposals:

1) Providing Reliable Supply - The proponents were evaluated on factors such as

their magnitude of operations in the WCSB including production volumes, their

ability to move large volumes of gas to Empress, and Centra's experience with

the proponent.

2) Credit RatingMorthiness - The proponents were first identified as investment

grade based on their credit ratings from major credit rating agencies. The credit

ratings of the parent companies were used in the case of unrated subsidiary

companies. A credit rating was given slightly greater weight if the rating was for

the proponent rather than its parent company. The proponents were then

2013 04 12 Page 1 of 2

35

Centra Gas Manitoba lnc. 2013114 General Rate Application

scored based on their credit ratings against a continuum of ten investment

grade rating levels.

3) Credit Requirements Placed on Centra - The proponents were evaluated based

on the credit assurances that each expected to seek from Centra. Higher

scores are reflective of less credit security sought by the proponent.

4) Customer Service and Responsiveness - The proponents were evaluated based

on Centra's experience with the proponents from a customer service

perspective including timeliness of response to inquiries, problem resolution,

sharing of market intelligence, and willingness to provide accommodating and

flexible service.

5) Proven Performance - The proponents were evaluated based on Centra's

experience transacting with the proponents in addition to references from other

parties as necessary to confirm the experience and performance of the

proponent as a supplier.

6) Sustainable Development - The proponents were evaluated based on corporate

commitments to sustainable development and environmental stewardship, and

the availability of low environmental impact sources of natural gas supply to

serve Centra. A consultant was retained to provide this evaluation.

2013 04 12 Page 2 of 2

36

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.91

Subject:

Reference

Tab 10 - Gas Costs

Tab 10 Pages 16 and 17 of 63 - Gas Supply Gontract

c) Please detail the non-price-related differences between the new gas supply

contract and the recently expired contract.

ANSWER:

Non-price-related features of the new contract that ditfer from the recently expired contract

are as follow:

1) Term

New contract: two-Year term.

Expired contract: three-year term.

2) Maximum Baseload and Swinq Quantities

New contract: maximum baseload and swing quantities vary by month according

to the following table.

Baseload

maximum(GJld)

Swing

maximum(Gr/d)Months

130,000 70,000Dec, Jan, Feb

100,00095,000Mar, Apr, May, Oct, Nov

85,000 75,000Jun, Jul, Aug, Sep

Expired contract: maximum baseload of 140,800 GJ/day and maximum swing of

120,000 GJ/day do not vary by month.

2013 04 12 Page 1 of 2

37

Centra Gas Manitoba lnc. 2013114 General Rate Application

3) Termination process

New contract: specifies a termination process in the event of substantive changes

in the NOVA Alberta System's or TCPL Mainline's respective tariff or tolling

methodology and the inability of the parties to agree to amended contract terms,

should amendment of the contract be deemed necessary by either party.

Expired contract: specifies that the parties will negotiate in good faith to amend the

contract in the event of substantive changes in the NOVA Alberta System's tariff or

tolling methodology.

2013 04 12 Page 2 of 2

38

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.91

Subject:

Reference:

d)

Tab 10 - Gas Costs

Tab 10 Pages 16 and 17 of 63 - Gas Supply Contract

Please calculate the forecasted Primary Gas costs at Empress for the 201413

Gas Year for each proponent and compare the results.

ANSWER

Forecast 2O1A13 Gas Year Commodity Cost ($ millions)

133.6ConocoPhillips

Party B 133.9

134.4Party C

134.8Party D

Party E 134.1

N/AParty F

Note: Party F's proposed pricing was incomplete and inconsistent with Centra's operating

requirements, and is therefore not included in the comparison'

2013 04 12 Page 1 of 1

39

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.91

Subject:

Reference:

Tab 10 - Gas Gosts

Tab 10 Pages 16 and 17 of 63 - Gas Supply Gontract

e) Please calculate the total Primary Gas supply costs at Empress for the

2OOgl1O, 2010111, and 2011112 gas years for the recently expired

ConocoPhillips contract and compare to the costs Centra would have incurred

with the other contract proponents (i.e. those proponents with compliant

proposals in 2009).

ANSWER

A comparison of actual costs incurred under the ConocoPhillips contract to costs that may

have been incurred under the other proposals can only be made on a theoretical basis. Due

to changing market conditions, Centra significantly reduced its firm transportation capacity

from Empress and baseload quantities taken under the ConocoPhillips contract, and

replaced this deliverability with Primary Gas Delivered Service in the 2010111 and 2011112

gas years. The ConocoPhillips contract contained sufficient flexibility on contract levels and

supply exclusivity to allow Centra to enact these portfolio changes and to realize associated

portfolio savings of $6.6 million and $9.6 million in the 2010111 and 2011112 gas years,

respectively. As Centra did not finalize contract terms with the other proponents, it is

unknown whether such portfolio changes would have been feasible under contracts

negotiated with other proponents, thus making the attainment of similar portfolio savings

uncertain.

2013 04 12 Page 1 of 2

40

Centra Gas Manitoba lnc. 2013114 General Rate Application

Theoretical Commodity Cost Comparison by Gas Year ($ millions)

20111',t22009110 2010111

53.0176.5 120.4ConocoPhillips

117.4 49.4Party B 175.6

NA NA177.2Party C

53.7178.1 121.7Party F (1)

53.6121.6Party F (2) 178.1

Party B suffered a credit downgrade and was sold since its proposal was submitted.

Party C's proposal included a trigger that would have required renegotiation of

pricing terms after the 2009110 gas year, Theoretical costs therefore cannot be

calculated under this proposal for the 2010111 and 2011112 gas years'

Party D's proposed pricing was incomplete. Therefore Party D is not included in the

comparison.

Party E's proposed pricing was only valid under certain assumptions that were not

consistent with Centra's operating requirements, This proposal is therefore not

included in the comparison.

Party F is on a provincial government credit watch. Party F provided two pricing

proposals,

a

a

a

a

2013 04 12 Page 2 of 2

41

lkolisnik

Text Box

12

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I-94

Subject:

Reference:

Tab 10 - Gas Costs

Tab 10 Page 27 of 63

c) Please providethe reference Eastern ZoneTolls since 2006|07.

NEB:

Please find below the annualized Empress to Eastern Zone tolls on the Mainline back to

2006. These tolls are annualized on the calendar year. Please note that going forward

TCPL will be using Empress to Union SWDA (Dawn) as its new reference or benchmark toll

given the elimination of toll zones. Empress to Union SWDA is a shorter distance of haul

than Empress to the Eastern Zone.

2006

2007

2008

2009

2010

2011

2012

$0.935

$1.03

$1.40

$1.1e

$1.64

$2.24

$2.24

2013 04 12 Page 1 of 1

43

lkolisnik

Text Box

13

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA II.178

Reference: PUB/Centra l-94 - NEB Decision

In the high level update of the NEB's Decision on TCPL's Business and Services

Restructuring Application that is being prepared as stated in PUB/Gentra l-94, please

address the NEB's decision on each of the points Centra advocated in its closing

submission, and how Centra anticipates these decisions will affect Centra and its

ratepayers, both in the Test Year and beyond.

ANSWER:

The NEB issued its Reasons for Decision (the "decision") related to the RH-003-2011

hearing on TransCanada's Restructuring Proposal on March 27,2013 to fix multi-year tolls

on the Canadian Mainline (the "Mainline"). Highlights of the decision are as follow:

. The NEB approved multi-year fixed tolls which the NEB deemed to be competitive and

provide TransCanada with a reasonable opportunity to recover its Mainline costs given

the increase in Mainline throughput which is forecast. ln its decision, the NEB

established the Firm Transportation toll from Empress, Alberta to Dawn, Ontario at

$1.421GJ compared to the current interim toll of $1 .89/GJ.

. The NEB expects this toll to remain in effect through 2017. Recognizing the increased

business risk the Mainline is facing, the NEB approved the Mainline's return on equity at

11.S per cent on a 40 per cent equity ratio. The NEB also approved an incentive

mechanism which would further increase the Mainline's profits if annual net revenues

are higher than forecast.

2013 05 07 Page 1 of 5

45

I

Centra Gas Manitoba lnc. 2013114 General Rate Application

The NEB developed a streamlined regulatory process for the Mainline to address new

service and pricing proposals in a timelier manner.

The NEB approved all of TransOanada's proposed changes to the Mainline's cost

allocation and the elimination of both FT-RAM and toll zones on the Mainline. The NEB

also gave greater discretion to TransCanada on how it prices lT and STFT services on

the Mainline.

The NEB did not approve other TransCanada proposals, including the Alberta System

Extension (ASE). Among other things, the NEB viewed the ASE as inappropriate cost

shifting among affiliated companies that is contrary to sound tolling principles. The NEB

also denied the reallocation of accumulated depreciation and the new proposed

treatment of costs related to TransCanada's agreement for transportation services on

Trans Québec and Maritimes (TQM) Pipeline lnc.'s pipeline system.

The NEB denied intervener proposals to disallow costs from the Mainline's rate base or

revenue requirement.

The NEB observed in its decision that the Mainline is in an unprecedented position. No

major NEB-regulated natural gas transmission pipeline has ever been affected by market

forces to the extent that the Mainline is now affected. Throughput on the Mainline has

decreased significantly, and as a result, Mainline tolls have increased substantially over a

short period of time. The future of the Mainline depends on how TransGanada is able to

respond to the changes to its business environment. The NEB also noted that it has

provided TransCanada with the tools it requires to achieve positive outcomes for its

investors and customers, and that TransCanada must now use those tools to construct a

viable future.

201 3 05 07 Page 2 of 5

46

Centra Gas Manitoba lnc. 2013114 General Rate Application

Relative to the status quo the decision is directionally positive for Centra and its ratepayers

although the net cost impact is uncertain at this point and the decision contains elements

which are both favourable and unfavourable.

The NEB expects this toll to remain in effect through 2017 which has the potential to provide

for toll certainty and stability and may facilitate contracting for Centra and the broader

marketplace at least in the short-term; however there are off-ramps defined within the

decision which could lead to the multi-year fixed tolls being in place for less time than

expected.

The NEB gave greater discretion to TransCanada on how it prices lnterruptible

Transportation (lT) service and Short Term Firm Transportation (STFT) service on the

Mainline. Centra has recently used STFT to shape its transportation contracts to better

match its load curve. Centra anticipates that TransCanada will price STFT to Centra's

delivery points (which TransCanada considers captive) at a price which will economically

incent Centra back into holding more annual FT capacity. This will result in Centra having

more Unutilized Demand Charges (UDC) to mitigate in the secondary market'

Centra's most effective UDC mitigation tool, the FT-Risk Alleviation Mechanism (FT-RAM),

was eliminated by way of the decision. Centra will return to using FT-Diversions as a way of

mitigating its UDC but, due to the nature of the market which it serves, FT-Diversions will be

less effective than using FT-RAM. Centra was able to reduce its fixed costs on the Mainline

by almost $5 million in the 201 1112 gas year through its use of the FT-RAM service attribute.

On May 1,2013 TransCanada made a Compliance Filing which included an Application to

Review and Vary portions of the NEB decision.

2013 05 07 Page 3 of 5

47

Centra Gas Manitoba lnc. 2013114 General Rate Application

Centra along with other shippers awaits confirmation of tolls for all paths and services; and

bid floors for lT and STFT services. Once this information becomes available, Centra will

evaluate its options using this information to inform its transportation contracting and gas

supply purchase decisions going forward.

Centra's three key expectations of TransOanada as one of its service providers and as

outlined by Centra in its closing submission in the RH-003-2011 proceeding were as follow:

For stable and predictable tolls;

For TransCanada to be competitive; and

For TransCanada's interests and those of Mainline shippers to be more closely

aligned such that the risk and costs of underutilization are shared.

1)

2)

3)

Although there is some ambiguity in these objectives, in Centra's opinion the NEB's decision

goes a long way to meeting all of these expectations.

Please find below a chaft which presents the key components of TransCanada's proposal

as compared with the position taken by Centra in its final argument and the NEB's decision.

2013 05 07 Page 4 of 5

48

Centra Gas Manitoba lnc. 2013114 General Rate Application

Centra NEB DecisionTransGanada's Proposal

Alberta System ExtensionAccumulated Depreciation TransferTollDesign Changes. Elimination of toll zones. lmprovements to cost allocation

'Allocation of TBO costs on TQM system

Service & Pricing Ghanges. RAM Elimination. Multi-Year Fixed Price Service (MFP). Pricing flexibility (IT/STFT)

AgainstAgainst

ForFor

No Position

AgainstAgainst

Not Approved

Not Approved

ApprovedApproved

Not Approved

ApprovedApproved

Approved +

Return and other Cost of Service elements No Position Approved

*Centra's position on the appropriateness of granting TransCanada with pricing discretion

was influenced by whether the discretion would be accompanied by regulatory oversight and

TransÇanada being accountable for the financial outcomes of the exercising of its

discretion.

+ Approved with additionalflexibility beyond what was requested by TCPL.

201 3 05 07 Page 5 of 5

49

lkolisnik

Text Box

14

Attachment 84Part B - Compliance Filing2013 Tolt Design Schedules

51

Han ö - uomplrance Flnng Io KFI-uuJ-zu I I ueclslonAttachment 84 -

201 3 Toll Design SchedulesSchedule 5 2Page 1 of 23

FT, STFT and lT TollsMainline 2013 - 2017 Tolls effective .lulv .2013

Notes: (i) Any transportetion with a Union Dawn receipt point is subject to a Union Dawn Receipt Point Surcharge. Transport

under FT, FT-NR and FT-SN service is subject to the monthly surcharge toll, and other transportation services are

subject to the daily equivalent toll. Refer to Toll Design Schedule 5.1 for the Union Dawn Receipt Point Surcharge

tolls.(ii) Transportation w¡th receipt points from delivery areas or Spruce is for STFT and lT seNice only.

(¡¡i) The following delivery points are subject to an additional charge for delivery pressure: Emerson 1 & 2, Union

SWDA, Enbridge SWDA, Dawn Export, Niagara Falls, lroquois, Chippawa, East Hereford. Refer to Toll Design

Schedule 5.1 for the delivery pressure toll.

(iv) Bid floors for lT service may be set at any level and bid floors for STFT may be set at the daily equ¡valent FT toll orhigher'

Daily Equivatent FT

FT Toll for lT / STFTLine

No. Point Point

2 Empress3 Empress4 Empress5 Empress6 Empress7 EmpressI EmpressI Empress10 Empress11 Empress12 Empress13 Empress14 Empress15 Empress16 Empress17 Empress'18 Empress19 Empress20 Empress21 Empress22 Empress23 Empress24 Empress25 Empress26 Empress27 Empress28 Empress29 Empress30 Empress31 Empress32 Empress33 Empress34 Empress35 Empress36 Empress37 Bayhurst 1

38 Bayhurst I39 Bayhurst 1

40 Bayhurst 1

41 Bayhurst 1

42 Beyhurst 1

43 Bayhurst 1

44 Bayhurst 1

45 Bayhurst 1

46 Bayhurst 1

47 Bayhurst 1

48 Bayhurst 1

49 Bayhurst 1

50 Bayhurst 1

51 Beyhurst 1

52 Bayhurst 1

53 Bayhurst I54 Bayhurst 1

55 Bayhurst 1

56 Bayhurst 1

57 Bayhurst 1

58 Bayhurst 1

59 Bayhurst 1

60 Bayhurst 1

EmpressTransGas SSDACentram SSDACentram MDACentrat MDAUnion WDANipigon WDAUnion NDACalstock NDATunis NDAGMIT NDAUnion SSMDAUnion NCDAUnion CDAEnbridge CDAUnion EDAEnbridge EDAGMIT EDAKPUC EDANorth Bay JunctionKirkwallEnbridge SWDAUnion SWDASpruceEmerson IEmerson 2St. ClairDawn ExportNiagara FallsChippawalroquoisCornwallNapiervillePhilipsburgEast HerefordWelwynEmpressTranscas SSDACentram SSDACentram MDACentrat MDAUnion WDANipigon WDAUn¡on NDACalstock NDATunis NDAGMIT NDAUnion SSMDAUnion NCDAUnion CDAEnbr¡dge CDAUnion EDAEnbridge EDAGMIT EDAKPUC EDANorth Bay JunctionKirkwallEnbridge SWDAUnion SWDASpruce

9.3479712.1125016.3093818.1884426.0417028.3545540.0567533.4989737.U91740.8825136.331 93

45,4828546.8574947.6280350.2007849.1 359752.6013551.2250042.7542546.1 823043.2477743.1e17818.188441 8.51 678

18.5167842.8771243.2477747.9146847.9518649.4557549.9727652.3624552.6340255.51 31812.112503.072178.87716

1 I .6406015.83764'17.7165325.5701127.8826539.5847033.0270637.0772740.41 06035.8600345.01 06446.3857547.1559749.7288848,6639152j293050.7531042.2823545.7104042.7758742.7198717.71653

0.08550.30730.39820.53620.59800.85620.9322I .3169'1.1013

1.23/.51.34411.1 9451.49531.54051.5659L65041.61541.72941.68411.40561 .51831.42181.42000.59800.60880.60881.40971.42181.57531.57651.62591.64291.72151.73041.82510.39820.10100.29190.38270.52070.58250.84070.91671 .30141.08581.21901.32861.17901.47981.52501.55031.63491.59991.71381.66861.39011.50281.40631.40450.5825

52

lkolisnik

Text Box

15

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA l-62 (Revised)

Subject:

Reference:

Tab 8: Load Forecast

Tab 8 Schedules 8.2.0 to 8.4.5 2011112 COG Hearing; PUB/Gentra 29 (a)

Please provide schedules showing the number of customers, average use, and

volumes by customer class for the years 2003104 through 2013114 for System Supply,

Fixed Rate Primary Gas Service, and Direct Purchase customers, showing the

percentage change each year. P|ease organize in a similar fashion to the schedules

prepared for PUB/Centra 29(a)from the 20111'12 GOG proceeding.

ANSWER:

Please find attached schedules providing the number of customers, average use and

volumes by customer class. Data for 2012113 and 2013114 are forecast.

2013 05 22 Page 1 of '1

53

Gentra Gas Manitoba lnc.2013114 General Rate Appl¡cat¡onNumber of lì¡

PUB/Gentra l-62Revised Attachment

Paoe I of 6Customer Class

Average number of customers ¡n the year

System SupplySGS ResidentialSGS CommercialLarge General ServiceHigh Volume FirmMainline Firmlnterruptible Sales

Fixed Price SupplySGS ResidentialSGS CommercialLarge General Service

Western Transporlation ServiceSGS ResidentialSGS CommercialLarge General ServiceHigh Volume FirmMainline Firmlnterruptible Sales

Transportation ServiceLarge General ServiceHigh Volume FirmMainline Firmlnterruptible SalesPower StationsSpecial Contract

Total Customers

2004105Actual

192,76214,6737,951

672

4'l

39,4981,287

63420

211

25rJA72 253.478

'135

4

15

27311

42

4131560

1

23

4567

II

't0

11

121314't5

16

1718192021

22232425262728293031

3233

2003104Actual

2005/06Actual

2006107Actual

20071o8Actual

2008/09Actual

2009110Actual

2010111Actual

2011112Actual

2012113Forecast

2013114Forecast

'189,605

15,3916,918

61

1

38

'183,549'15,070

6,88363I

38

210,54615,6966,908

631

32

185,27015,0636,934

66,|

37

48,1401,572

76324

2I

192,36415,1806,970

651

35

42,7311,437

76727

2I

195,68215,4176,933

651

33

201,45015,6006,956

671

32

221,449'15,765

6,78959I

30

3981243

'19,997

1,0401,063

281

7

229,34916,0136,776

601

30

235,325't6,2196,646

601

30

10,752883994

271

7

4863596

33 988 47,4291,572

76421

2't0

29,4221,036

89726

1

9

't4,186

9191,008

271

7

41,|

615281856

262

8

37,1021,128

85123

1

I

796549

202

9

243

21

3542I

25

42'l

3

542,|

35421

5b

321

5

6321

5632,|

4b

32'I

3

6

42I

3

5421

16 257 .89s 25s.602 261 .935 263.39',1 264.978 266,699 268,880 271,578

Page 1 of 6

54

Centra Gas Manitoba lnc.2013114 General Rate ApplicationCrrclnmer o/-

System SupplySGS Res¡dent¡alSGS CommercialLarge General ServiceHigh Volume FirmMa¡nline Firmlnterruptible Sales

Fixed Price SupplySGS ResidentialSGS CommercialLarge General Service

PUB/Gentra l-62Revised Attachment

Paoe 2 of 6

1

2345678

I101',!

12131415

161718192021

22232425262728293031

3233

2003104Actual

2004105Actual

2005/06Actual

2006107Actual

20071o8Actual

2008/09Actual

2009/1 0

Actual20'tol11Actual

20't1112Actual

2012113

Forecast2013t14Forecast

Western Transportation ServiceSGS ResidentialSGS GommercialLarge General ServiceHigh Volume FirmlMainline Firmlnterruptible Sales

Transportation ServiceLarge General ServiceHigh Volume FirmMainline Firmlnterruptible SalesPower StationsSpecial Contract

Total Customers

-1.6%4.9To

-13.0o/o

-8.4%-33.5%

-7.7Yo

16.2V,

61.6%15.5%0.0%0.0%

22.4%

0.0%17 -6Yo

17.OYo

0.jYo0.0%

-3-2Yo

-2.1%-O.5To

3.7%-24.8o/o

-1.3o/o

20.1y"22.2o/r205%

6.8%0.OYo

-8.4Yo

46.Oo/o

0.0%o.o%0.o%0.0%

0.9%0.0%O.7Yo

4.6%0.jYo

-2.4o/o

15%0.0%-o.1%12.3%0.0%

-8.3%

2.7o/o

0.0%0.OVo

0.0%0.0%

3.8o/"

0.8o/o

0.5%-2.3Yo

0.0%4.3o/o

0.0%-3.4%0.0%0.0%0.0%

-'t1.2%-8.6%o.5%

13.1olo

0.0o/o

-1.9o/o

1.7Yo

1-60/o

-o.5%

0.1%0.0%

-5.9o/o

-2.6%-10.9%11.7%4.4o/o

-21.Oo/o

-1O.2o/o

0.0%12.2%0.0%0.0%0.0%

2.9o/o

1.2Yo

O.3Yo

2.8Y"0.0%

-3.3o/o

-10.8%-1't.9%

-0.6%-8.5Yo

-36.7o/o

11.4o/o

0.0%10.7%o.o%0.0%O.Oo/o

4.5o/o

O.6Yo

-O.7Vo

-5.4o/o

0.0%-0.8%

'102.40/o

183.3%176.7%

-20.7%-8.2Yo

5.3%1'1.4o/o

0.0%4.7To

27.7o/o

0.0%-1g.go/o

0.0%0.o%

5.2o/o

O.4o/o

-1.7Yo

-6.9%0.0%

-5.8%

45.8%5.2%0.4%

-32.O%0.5%

18-5%5.8%O.OYo

-13.5%

30.5%0.0%

-12.9o/o

0.0%0.o%

3.60/o

1.6%-0.2Yo

1-6Yo

0.o%0.6%

3.9%27.9o/o

39.7%

-29.1%-11.7%

-5-2Yo

-1.8%o.0%

-5.7%

0.0%0-OYo

6.0%0.0%0.0%

2.6%1.3Yo

-1.9o/"0.8%0.0%0.0%

17.5%126.2%60.9%

-24.2o/o

-3.9%-1.4%0.0%0.0%o.oo/"

O.OTo

0-OYo

0.0%0.0%0.0%

1.Oo/" 0.8% 1.OVo O.7Yo 0.9% 0.6% 0.6% 0.6% 0.8% 1.O%

Page 2 of 6

55

Gentra Gas Manitoba lnc,2013114 General Rate ApplicationVolumes bv c lìl¡cc

Volumes are stated in 103m3

System SupplySGS ResidentialSGS CommercialLarge General ServiceHigh Volume FirmMainline Firmlnterruptible Sales

Fixed Price SupplySGS ResidentialSGS CommercialLarge General Service

PUB/Cent¡a 162Revised Attachment

Paoe 3 of 6

1

234567II

1011

1213

14l516't718192021

22232425262728293031

3233

2003104Actual

2004105Actual

2005/06Actr

2006107Actual

2007to8Actual

2008/09Actual

2009/1 0

Actual2010111Actual

2011112Actual

2012113Forecast

2013114Forecast

556,06983,029

476,32387,11817,04797,654

96,8415,212

43,20424,86934,81323,362

25,49167,07426,47094,006

364,277

565,59095,887

483,3s 1

84,6531,645

88,701

115,5229,421

61,66928,02833,29830,095

25,80682,61731,06911,645

407,863

460,22676,513

415,73977,716

1,42682,354

26,84574,39530,483

5,620460,955

740

501,528I'1,772

442,76784,967

1,40884,943

534,36589,361

458,34590,692

1,44284,447

547,68394,452

469,73188,920

1,55984,508

109,6617,834

77,29638,34622,47919,360

26,6691 17,38926,729

8,094423,847

494,75683,062

414,æ685,316

1,75679,858

44543

1,083

83,8806,585

70,79430,28211,',t04

20,885

22,717'129,090

22,81413,513

430,490

525,25288,405

425,48382,688

1,96676,636

67483

2.159

64,4416,633

71,07436,75711,235't8,82'l

31,305119,27317,80715,MO

400,234

470,40274,830

362,21872,2162,296

67,493

556,68790,750

423,06879,4902,498

73,387

1,033106

4,O87

30,7755,879

79,65739,09810,998't7,511

39,819120,550

16,411'15,196

421,289

558,62291,946

414,96484,5302,498

74,501

'I ,169214

6,336

22,8515,650

78,58739,098't0,998

17,813

39,819121,466

19,736'15,196

421,289

85164

3,29'l

western Transportation SewiceSGS ResidentialSGS CommercialLarge General ServiceHigh Volume FirmMaìnline Firmlnterruptible Sales

Transportation ServiceLarge General ServiceHigh Volume FirmMainline Firmlnterruptible SalesPower StationsSpecial Contract

Total Volumes

118,7219,166

59,2',t729,75228,60523,OO7

118,4168,721

58,341

35,85226,41919,227

27,64472,35329,1 9824,O93

438,853

113,1078,842

68,79339,64229,64519,598

27,87778,34228,989

7,161475,800

36,5555,704

75,02937,59410,072't 8,153

36,597114,25316,68917,O48

444,686

2j22.85A 2.',t56-841 1. 2.0s6.503 2.156.447 2.164.558 2.003.119 1.996,366 1,866,039 2,028,289 2,027,285

Page 3 of 6

56

Gentra Gas Manitoba lnc.2013114 General Rate ApplicationVolumes % G

System SupplySGS ResidentialSGS CommercialLarge General ServiceHigh Volume FirmMainline Firmlnterruptible Sales

Fixed Price SupplySGS ResidentialSGS CommercialLarge General Service

PUB/Gentra 162Revised Attachment

Paqe 4 of 6

1

2345b

7II

'10

11

1213

'14

151617'18

192021

22232425262728293031

3233

20031o4Actual

2004105Actual

2005/06 2006107Actual

2007108Actual

2008/09Actual

2009/10Actual

2010111Actual

2011112Actual

2012113Forecast

2013t14Forecast

Western Transportation ServiceSGS ResidentialSGS CommercialLarge General ServiceH¡gh Volume FirmMainline Firmlnterruptible Sales

Transportation ServiceLarge General ServiceHigh Volume FirmMainlìne Firmlnterruptible SalesPower StalionsSpecial Contract

Total Customers

1-7o/o

15.5o/o

1.5o/o

-2.8o/o

-90.4%-9.2%

't9.\Yo80.8%42.7%12.70/"

-4.4o/"

28.8o/.

1.2o/o

23.2o/o

17.4%-87.60/.12.0%

-18.6%-2O.2o/o

-14.0o/o

-8.2Yo

-'13-30/o

-7.2Yo

2.8%-2-7Yo

4.OYo6.1Yo

-14.1%-23.60/,

4.Oo/o

-10.o%-1.9Yo

-51.7"/o

13.0%

9.0%6.9%6.5%9.3%

-1.3Yo

3.1o/o

-0.3%4.9%-1.5To

2O.5o/o

-7.6Yo

-16.4%

3.Oo/"

-2.7o/o

4.2o/o328.7%

4.8%

6.5o/o

9-3Vo

3s%6.7%2.4%

-O.60/o

-45%1.4%

't7.9%10.60/0

12.2o/o

1.9Vo

0.8%8.3%

-o.7%

-7O.3o/.

8.4o/"

2.5%5.7o/o

2.5Yo

-2.0o/o

8.2%o.1%

-3.0o/o

-11.4o/r

12.4%-3.3%

-24.2%-1.2o/o

4-3o/o49-8o/o

-7.8%13.0%

-10.9%

-9.7To

-12.10/.-11.7o/"

-4.|Yo't2.6%-5.5%

-23.5o/o

-'t5.9%-8.4%

-21.Oo/o

-50.6%7.9Yo

-14.8%10.o%

-14.60/r67.O%

1.6Yo

6.2Vo

6.4Yo

2.60/o

-3.1%11.gyo4.0o/o

51.6%95.0%99.3%

-23.2%0.7Yo

O.4Vo

21.4o/o

1.2Yo

-9.9o/o

37.gyo-7.60/o

-21.9Yo14.3Yo

-7.O%

-10.4Vo

-15.4Vo-14.gyo-'t2.7%16.8%

-11.9o/o

26.2%-22-8%52.4o/o

433%-14.0"/o

5.6%2.3Yo

-10.3%-3.60/o

16.9%4.2Yo-6.3%'1o.40/o

11.1o/o

18.3o/o

21.3o/o

16.8%10.1o/.8.8%8.7o/o

21.4%65.8%24.2o/o

-15.8%3.1Yo

6.2Yo

4.0%9.2%-3.50/

8.8%5.5%

-1.7o/o

-10.9o/o

-5.3o/o

O.3o/o

1.3%-1.9%6-3Yo

0.0%1.5o/o

13.2o/o

'|o1.60/0

55.0%

-25.7o/o

-3.9%-1-3Yo

0.0%0.0%1.70/,

0.0%o.8%

20.3o/.O-0o/o

0.0%

1.6Vo -8.2Yo 3.8o/o 4.9Yo 0.4% -7.5% -O.30/. -6.5Yo 8.7o/o 0.o%

Page 4 of 6

57

Gentra Gas Manitoba lnc.2013/14 General Rate Appl¡cationAveraqe Use Þe¡ Customel

Average Use is steted in m3/cust

System SupplySGS ResidentialSGS CommercialLarge General ServiceHigh Volume Firm

Mainline Firmlnterruptible Sales

F¡xed Pr¡ce SupplySGS ResidentialSGS CommercialLarge General Service

Western Transportation ServiceSGS ResidentialSGS CommercialLarge General ServiceHigh Volume FirmMainline Firmlntem.tptible Sales

Transportat¡on Serv¡ceLarge General ServiceHigh Volume FirmMainline Firmlnteruptible SalesPower Stat¡onsSpec¡al Contract

PUB/Centra 162Rev¡sed Attachmenl

Paqe 5 of 6

I234567II

1011

1213

1415

1617'18

19202122232425262728293031

2003104Actual

2,8855,659

59,9051,310,0428,523,3502,367,360

2,8496,546

78,7321,264,291

17,406,5502,619,013

2004105Actual

2005/06Actual

2,5075,077

60,4011,230,2711,426,0002,191,421

2,5035,432

77,il31,416,757

14,302,6002,300,720

2006107Actual

2,7075,429

63,8571,285,8191,407,5692,316,409

2,4605,547

76,4881,520,449

13,209,6832,096,751

20071o8Actual

2,7785,887

65,7591,404,3321,441 ,7392,407,262

2,6476,152

89,7211,486,383

14,822,3182j77,591

2008i09Actual

2,7996,126

67,7501,374,9761,559,3342,560,862

2,63s6,1 15

90,2731,503,770

14,227j022,396,100

2009/1 0

Actual

2,4565,324

59,6071,282,9551,756,4972,501,817

3,29910,64770,665

2,2615,837

83,1 571 ,297,975

I 1,103,9472,320,510

2010t11Actual

2,4955,632

61,5941,314,1U1,966,0372,419,842

2,4707,330

50,903

2,1906,404

79,2571,413,736

11,234,5'lO2,193,638

2011112Aclual

2,1244,747

53,3541,232,7682,295,7462,262,591

2j375,378

77,278

1,8285,483

70,5871,367,056

10,072,3042,446.475

2012t13Forecast

2,4275,667

62,4401,335,9612,498,0942,446,245

2,4996,971

68,685

2,1696,401

79,0381,448,061

10,998,2152,501,636

2013t14Forecast

2,3745,669

62,4391,408,8332,498,0942,483,383

2,4076,212

66,177

2,1256,402

79,0551,448,061

10,998,2152,U4,770

2,9836,230

69,8701,389,5781,236,6952,329,340

2,5257,323

97,3351,424,927

1 6,649,1892,755p48

12,745,300 12,903,093 9,193,390 9,214,833 9,292,224 8,889,578 7,572,211 8,173,521 7,319,461 7,963,761 7,963,761

15,782,217 16,523,394 14,878,940 14,470,509 16,219,912 21,658,437 21,514,990 19,878,835 19,042,220 20,091,623 20,2M,405

7,739,883 7,767,213 7,620,700 7,299,390 7,247,337 6,682,183 5,703,591 5,479,023 5,897,055 5,470,397 6,578,763

47,002,788 5,822,423 2,809,750 12,046,499 3,580,639 4,046,858 6,756,318 7,720,088 8,523,792 7,598,129 7,598,129

364,277,0O0 407,862,732 460,954,700 438,853,488 475,800,114 423,847,345 430,490,196 400,233,854 444,685,729 42',1,288,809 421,2a8,809

Page 5 of 6

58

Gentra Gas Manitoba lnc.2013114 General Rate ApplicationÀvaraa¡ Use %

System SupplySGS ResidentialSGS CommercialLarge General ServiceHigh Volume FirmMainline Firmlnterruptible Sales

Fixed Price SupplySGS ResidentialSGS CommercialLarge General Service

PUB/Gentra 162Revised Attachment

Paoe 6 of 6

1

23

45678I

10

11

12131415l61718192021

22232425262728293031

3233

2003104Actual

2004105Actual

2005/06Actual

2006107ÀcÍ ral

20071o8Actual

2008/09Actual

2009110Actual

20't0111Actual

201',!112Actual

2012113Forecast

2013114Forecast

Western Transportation ServiceSGS ResidentialSGS CommercialLarge General ServiceHigh Volume F¡rmMainline Firmlnterruptible Sales

Transportation ServiceLarge General ServiceHigh Volume FirmMainline Firmlnterruptible SalesPower StationsSpecial Contract

3.4Yo

10.1Vo

't6.6%6.1%

-85.5%-1.60/0

2.6%11.9V.23.6%12.7%4.4Vo5.2o/o

'1.20/o

4.7Yo

0.4%-87.6%

12.Oolo

-15.9o/o

-'18.5%-13.60/.-1'1.5o/r't5.3%

-5.9%

-'14.40/"

-2O.4o/o

-203%-0.6%

-14.1o/o

-16.5o/"

-28.8%-'lo.oo/"-1.9%

-51.7o/.

13.0%

8.O%6.9%5.7Yo

4.5Yo

-1.3%5.7To

-1.7Yo

-4.9To

-1r'.%7.3o/o

-7.6Yo-8.9%

o.2%-2.7o/"

4.2%328.7o/.

4.8Yo

2.6Vo8.4Yo

3.0o/o

9.2o/o

2.4Y"3.9o/o

7.6Yo

10.9%'t7.3%-2.2o/o

12.2o/o

3.9Vo

0.8%12.10/,-0.7Yo

-7O.3o/o

8.4o/o

0.8%4.'t%3.OYo

-2.1%8.2o/o

6.4%

-0.4Yo

-0.6%0.6%1.2Vo

4.O%10.0%

-4.3Yo

33.5%-7.8"/o13.OYo

-'10.9%

-12.3To-13.'t%-12.0%

-6.7%

12.6%-2.3Yo

-'14.2o/o

4.5o/o-7.9Yo

-13.7Vo

-22.O%

-3.2o/o

-14.8%-o.70/"

-14.6%67.0o/.

1.60/0

1.60/o

5.8%3.3To

2.4Yo

11.9o/o

-3.3Yo

-25.|Yo-31.2Vo

-28.Oo/o

-3.1o/o

9.7%4.7%8.9Yo

1.2Vo

-55%

7.9To

-7.60/o

-3.9o/o

14.3o/.

-7.0o/"

-'14.9o/o

-15.7o/r-13.4o/.

-6.2%

16.8%-6.5%

14.3o/o

19.4o/"

't7.0%8.4%8.8o/o

8.1o/o

16.9%29.6%

-11.1%

18.7o/r

16.7%12-OYo

5.9o/o

9.2Yo

2.3%

8.8%5.5%

-7.2%-10.9%

-5.3o/o

-2.2o/o

O.0o/"

0.0%5.5%0.OYo

'' .50/o

-3.7Y"-10.9%

-3.7Yo

-2.OYo

O.Oo/o

0.0%O.OYo

0.0%1.7o/o

O.Oo/o

O.8o/o

20.3%0.0%0.0%

-13.5%-26.6Vo

51.8o/o

-16.5%-'14.40/"

-'t0.9%'3.3o/o

-'to3%1't.5%

-10.4%4.2o/o7.6%

10.4Yo

11 .1o/o

Page 6 of 6

59

lkolisnik

Text Box

16

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA þ66

Subject:

Reference

Tab 8: Load Forecast

Tab 8 Appendix 8.1 Pages 36 and 43 ol52

a) Please describe EDDH and explain how Centra uses EDDH to forecast gas

consumption and to normalize that consumption.

ANSWER:

Degree Days Heating (DDH) is the number of degrees colder than 14 degrees Celsius each

day, based on the average of the high and low temperature of the day. The DDH for each

day is calculated as follows:

lF Average Temperature < 14; DDH = 14 - Average Temperature

lf Average Temperature > or = to 14; DDH = 0

Where:

Average Temperatur" = lDaily high + Daily low)/ 2

Total DDH = sum of DDH over all days

Historical monthly volumes are then heat value and weather adjusted to the 25 year average

of DDH. The weather adjustment is calculated as follows:

Historical volume weather adjusted = historical actual volume + (25 year average DDH -

actual DDH) . weather effect

2013 04 12 Page 1 of 2

61

Centra Gas Manitoba lnc. 2013114 General Rate Application

Centra determines the "weather effect" for each class as described in the response to

PUB/Centra l-65.

The heat value and weather adjusted historical volumes that are based on normal weather

are used as inputs into the Natural Gas Volume Forecast. All forecasts are thus based on

normalweather.

2013 04 12 Page 2of 2

62

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I-66

Subject:

Reference:

Tab 8: Load Forecast

Tab 8 Appendix 8.1 Pages 36 and 43 ol52

b) Please provide the effective degree days heating (EDDH) for Winnipeg for the

years 2008/09 lo 2012113.

ANSWER

Please note that March 2013 was not available at the time of the preparation of this

response.

Mo DDH for Winn

Mar AnnualNov Dec Jan FebJun Jul Aug sep OctApr May

676.4 4,978.2546.4 1,033.0 L,052.3 800,92L.3 0.0 3.0 s6.3 227.92oo8/09 319.8 180.9

793.6 45t.t 4,299.6396.9 895.9 860.147.4 3.8 2.4 19.8 330.12OOe/tO 32t.4 L77.t

788.9 698.8 4,487.8520.6 878.1 L,O3L.21_0.3 0,0 9.0 79.9 188.7zOrO/rr 173.5 108.8

698.9 37L.3 3,677.648t.2 683.6 767.8L2.9 0.0 0.0 60.8 204.O2otrl12 286.8 110.3

78L.7 N/A N/A601.1 889.6 951.19.9 0.0 0.0 89.1 310.92072/t3 244.3 82.7

2013 04 12 Page 1 of 1

63

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.66

Subject:

Reference

Tab 8: Load Forecast

Tab 8 Appendix 8.1 Pages 36 and 43 ol52

c) Please provide the normal EDDH calculated for each of the above years using

the 25 year average method as well as the 10 year average method.

ANSWER

The following table presents normal Degree Days Heating (DDH) based upon the 25 year

average method and the 10 year average method.

Normal DDH from 2OOglO9to20t2lt3

Fiscal Year 10 Year Average 25 Year Average

4,549.8

4,561.6

4,547.1

4,536.7

4,518.4

2008/09

20os/Lo

20t0ht

20!t/t2

2072/t3

4,429.8

4,518,1

4,555.7

4,522.6

4,466.4

2013 04 12 Page 1 of 1

64

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.66

Subiect:

Reference:

Tab 8: Load Forecast

Tab 8 Appendix 8.1 Pages 36 and 43 ol52

d) Please provide the coldest year on record EDDH and the warmest year on

record EDDH.

NEB:

Centra's records contain Winnipeg DDH weather dating back to the 1960/61 fiscal year. The

coldest year during this period of record for Winnipeg is the 1995/96 fiscal year at 5,439.3

DDH. The warmest year during this period of record for Winnipeg is the 2011112 fiscal year

at 3,677.6 DDH

2013 04 12 Page 1 of 1

65

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.66

Subject:

Reference:

Tab 8: Load Forecast

Tab 8 Appendix 8.1 Pages 36 and 43 ol52

e) Please provide the approximate relationship between EDDH and net income.

ANSWER

The relationship between EDDH and Centra's net income would be approximately $15,000

per EDDH.

2013 04 12 Page 1 of 1

66

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I-66

Subject:

Reference:

Tab 8: Load Forecast

Tab 8 Appendix 8.1 Pages 36 and 43 ot 52

f) Please detail the effect on forecasted net income if the warmest or the coldest

winters were experienced in 2O13114.

NEB:

The estimated effect on Centra's net income would be calculated as

Extreme

Warm/Cold

Fiscal Year

2073/!4Normal EDD

Extreme

Year EDD

3 678

5 439

EDD

Variance

(840)

921

Net lncome

lmpact *

s (12 600 ooo)

s 13 81s ooo

2OL3l14

Forecast

Net lncome

s4 821 000

$¿ szr ooo

2ot3/14

Net lncome

with extreme

weather

s (777sooo)

s 18 636 ooo20L!72t99s/s6

45r84 518

*Net income impact is estimated at 515,000 per effective degree day (reference PUB/Centra l-66e)

2013 04 12 Page 1 of I

67

Change in Methodolosy to Calculate Normal Weather:

25 Year Rolling Averaqe Instead of 10 Year Rolling Averaee

Note 1 : For example, the EDDH average up to March 31 , 2012 was used to prepare the 2012 LoadForecast which was used for the 2073114 GRA Test Year

Note 2: PUB/Centra I-66(c) and PUB/Centra II-173(b)

Note 3: Net lncome impact is change in EDDH multiplied by $15,000 per EDDH as stated in PUB/CentraI-66(e)

Note 4: Appendix 8.1 p.43

EDDH¡ey,' ChangeFromPriorYear

EDDH25yl ChangeFrom PriorYear

Impact onNet lncomel0 YearAverage3

Impact onNet lncome25 YearAverage3

Year Test Year(s)EDDHForecastUsedr

2006107 4471 4541($ 165,000)2007108 GRA Test

Years2009170,20t0ltt

4376 (es) 4530 (11) ($1,425,000)

2008/09 COG TestYear20t0ltt

4430 54 4550 20 $810,000 $300,000

20091r0 COG TestYear201l/12

45 18 88 4562 l2 $ 1,320,000 $ 180,000

20r0ltL 4556 38 4547 (1s) ($s70.000) $225,0004523 (33) 45370 (10) ($49s,000) ($ l5o,oo0)20rUt2 GRA Test

Year2013/14

4518 09) ($8s5,000) ($285,000)20r2lt3 4466 (57)

68

Winnipeg Average DDH5,400

I5,200 /\

t \ 10 Yr Average

\II

- - 25 Yr Average

5,000 \\\I\ \

4,800\,

\\\

4,600

,

4,4OO

Sources: PUB/Centra l-66(b)PUB/Centra ll-1-73(a) and (b)

4,2OO

1f

a

It\

\\

l.

1900 1910 7920 1930 1940 19s0 1960 r970 1980 1990 2000 20LO 2020

69

SGS Commercial and LGS Volume

The combined total volume of SGS

Commercial and LGS classes has

decreased by 974103m3 or 0.2% per year

over the last 9 years. lt is expected to

continue to decrease by 3,953 103m3 or

0.7% per year for the next 10 years.

SGS Commercial volume has grown by

547 103m3 or 0.6% over the last 9 years.

The SGS Commercial class is forecast to

increase by 933 103m3 or OS% per year

until202L/22.

Large General Service volume has

decreased by !,52! 103m3 or 0.3% per

year. lt is forecast to continue to decrease

by 4,886 103m3 or t.O% per year until

202L/22.

Figure 9 - SGS Commercial & IGS Volume

Figure 10 - SGS Commercial Volume

Figure 11 - LGS Volume

o History 1-¡Y¡ry¡6¡

SGS COMMERCIALVolume(103m)

110,000

100,000

90,000

80,000

70,000

60,0002003 2005 2007 2009 2011 2013 2015 2017 2019 2021

FlscalYear Ending

ca

c

a History .{bHVWAdj ¡-

ra--r*,^-^o

9 History arHVWAdj ÕForecast

L7

71

700,00067ti,000650,000621i,000

600,00057ti,000550,000521i,000

500,000

COMBINEDSGS COMMERCIAL & LGSVolume(103m)

2003 2005 2007 2009 2011 2013 2015 2017 2019 2021

Fiscal Year Endlng

O History HVWAdj rt- Forecast

72

LARGE GENERAL SERVTCE (LGS)Volume (103m)

540,000

520,000

500,000

480,000460,000

440,000

420,000

40t),000

I v

E--.â.

--o -o

2003 2005 2007 2009 2011 2013 2015 2017 2019 2021

Fiscal Year Ending

e History Fo re castHVWAdj

73

lkolisnik

Text Box

18

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.67

Subject:

Reference:

Tab 8: Load Forecast

Tab 8 Appendix 8.1 Page 39 of 52

Please provide the historica! weather and heating value adjusted load forecast

accuracies for the SGS Residential, SGS Gommercial, and LGS classes for the past

five years.

ANSWER:

Forecast Accuracy For 2OO7

ForecastCreated

Year BeingForecasted

Actual103m3

Forecast103m3

w/A

Diff o/o Dill

Forecast Accuracy For 2008

Absolute"/" Dill Over Under

Actual1osm3Class

SGS Residential

SGS Commercial

LGS

SGS Residential

SGS Commercial

LGS

Total For Year 2

l.7o/o 1

3,Lo/o 1

2

2

.9Yo

-3.5%

-.7o/o

.9o/o

3.SVo

.7%

1

0

0

0

I

1

647,472

98,203

527.138

2007

2007

2007

2007t08

2007108

2007108

605,643

87,824

486,956

600,501

90,977

490,616

5,142

-3,1 53

-3,660

1

0

0

0

1

I

657,344

102,286

547.028

601,882

86,980

482.274

592,395

91,552

496.223

9,488

4,573

-13.948

1.6%

-5.0%

-2.8%

1.60/o

5.Qo/o

2.8%

2007

2007

2007

2008/09

2008/09

2008/09

ForecastCreated

Year BeingForecasted

W/AActual103m3

Forecast103m3 D¡ff o/" Dill

Absoluteo/" Dill Over Under

Actual103m3Glass

SGS Residential

SGS Commercial

Total

SGS Residential

SGS Commercial

LGS

Total For Year 2

2013 04 12

7o/o 1 2

2LPage I of 2

657,344

102,286

547.028

2,733

-1,050

-2.681

.5%

-1.1Yo

-.SYo

.5o/o

1.1%

.5%

1

0

0

0

1

1

2008

2008

2008

2008/09

2008/09

2008/09

601,009

91,482

498,1 1 0

598,276

92,532

500,791

1

0

1

0

I

0

579,081

89,690

486.523

597,688

90,925

49s.081

586,838

91,139

492.404

10,850

-214

2.677

1.8%

-.2%o

.5o/o

.ïYo

.2o/o

.5%

12008

2008

2008

2009110

2009t10

2009110

8o/o

75

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I-67

Forecast Accuracy For 2009

ForecastCreated

Year BeingForecasted

Forecast103m3

w/AActual103m3 D¡ff YoDill

Absolute"/o Dill Over Under

Actual103m3Glass

SGS Residential

SGS Commercial

LGS

Total For Year 1

SGS Residential

SGS Commercial

Total For Year 2

t.2o/o 3

2.4o/o 2 1

Forecast Accuracy For 2010

1

1

1

0

0

0

579,081

89,690

486,523

596,436

92,795

500.034

8,707

143

9.147

1.5o/o

.2%

1.8%

1.5To

.2Yo

1.8%

2009

2009

2009

2009t10

2009/1 0

2009110

605,142

92,939

509,181

1

0

1

0

1

0

590,368

95,120

498.716

588,258

94,831

496.794

12,851

-2,622

11.168

2.2%

-2.8%

2.2o/o

2.2Yo

2.8%

2.2%

2009

2009

2009

2010t11

2010111

2010t11

601,1 09

92,210

507,963

w/AForecastCreated

Year BeingForecasted

Forecast103m3

Actuallosm3 Diff 7o Difl

AbsoluteVoDall Over Under

Actual103m3Class

SGS Residential

SGS Commercial

L

r1 2 1

SGS Residential

SGS Commercial

LGS

Total For Year 2 L.6o/o 0 3

Forecast Accuracy For 201 I

.4o/o

1.7%

.7o/o

1

0

1

0

1

0

590,368

95,1 20

498,716

593,998

93,723

502.986

591,387

95,381

499.302

2,610

-1,658

3,684

.4o/o

-1.7%

.7Yo

20'to

2010

2010

2010111

2010111

2010111

1

507,807

80,599

440.537

4,224

-1,878

-r 0.604

-.7Yo

-2.jYo

-2.1%

.7%

2.0%

2.1%

0

0

0

2010

2010

2010

2011t12

2011112

2011112

591,758

94,315

501,444

595,982

96,1 93

512,048

wlAForecastCreated

Year BeingForecasted

Forecast103m3

Actual1o3mg Diff o/" Dill

Absoluteo/"Ditl Over Under

Actual103m3Class

SGS Residential

SGS Commercial

Total For Year 1 L,9o/o 1 2

1.9o/o

.2Yo

3.50/

0

1

0

1

0

1

507,807

80,599

440,537

583,581

96,1 96

493.152

594,884

96,000

511,155

-1 1,303

197

-18,003

-1.9%

.2lo

-3.5o/o

2011

2Q11

2011

2011112

2011112

2011112

2013 04 12 Page 2 of 2

76

lkolisnik

Text Box

19

Centra Gas Manitoba lnc. 2013114 General Rate Applicatioñ

PUB/CENTRA I¡.164

Reference: PUB/Centra l-53(a); 2013-2016 Power Smart Plan Page 2 - Ut¡l¡ty Costs

Please extend the table in PUB/Centra l-53(a) comparing the DSM spending forecasts

from the 2011 Power Smart Plan and the 2013-2016 Power Smart Plan to include the

yeårs 2014115 and 2015/16.

ANSWER:

Please see the table below

2013 05 07 Page 1 of 2

77

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA II-164

( in S1oo0's )

RESIDENTIAL

New Horne ProgramLower lncome:Power SmortF u m o ce Rep lo ce me nt P ro g ro m

Appottio ned Affo rd o b le En ergy Fu nd

Lower I ncome Tota I

Home I nsulati on ProgramWater and Energy Saver Program

RESI DENTIAL TOTAI

COMMERCIALCommerc¡al Custom Measures Progra m

Commercial Wi ndows ProgramCommercial lnsulat¡ on Progra m

Commercia I New Constructi on Progra m

Commercial Building Optim¡zation Program

lnterna¡ Retrofit ProgramCommercia I Kitchen Appliance Progra m

Co2 Sensors

Commercial Rinse & Save ProgramCommerc¡al Water Heater ProgramCommercial Boiler Program

COMMERCIALTOTAL

INDUSTRIAL

lndustrial Natural Gas Optim¡zat¡on ProgramI NDUSTRIALTOTAL

EFFICI ENCY PROGRAMS SUBTOTAL

CUSTOMER SELF-GENERATION

B¡oEnergy Opti mi zation Progra m

PROGRAMS SUBTOTAL

CUSTOMER SERVICE INITIATIVES, SUPPORT AND CONTINGENCY

I4T438

1,513569255

53

3858

99503

3,373239335

0

t4r380

r,291529214

o

to258

0

o

99447

2,774304335

o

11370

o720

74L1969516482\4

0

10559

o0

7

2Ot2lt32011 PS Plan Updated

I') 011(ì f"n1 "<\

96

2Or3lt42011 PS Plan Updated

2011qì l) 1 7qì

to7

2OL4lts2011 PS Plan Updated

f201 1qì l2012sl

118

5327,878

z0tsl762011 PS Plan Updated

12011sl 12012s)

724 0

6922,3303,2796,2422,600

9.542

92503

3,3732483L4

o

7964

2

91ao4

0

7602,3783,0756,2!37,697

804I 714

^ t92

770770

13 Ê,-, Ê

139139

1? R1q

2,728

6862,3303,2076,2232,534

637

7442,3783,O54

6,r771,688

ao48.669

769

3,r202,478

624

o

7302,3783,O36

6,t441-,685

804

4477,528

o1,9742,419

0

4.522

4 )7ît

763763

9,555

543543

10,097

3,L79

6472,2052,7535,606t,779

o

7,324

) a)o

640640

ro.2a5

279279

10.564

2,474

13.O3 8

5049 6,343 4,632

514 971. 3.230

763 640763 640

72.O77 12.503

96 4396 43

12 1 73 12.546

3,267 2,407

91

6ñ)

oo

5

66

0

97816

741422

t,435440193

0

8856

0

0

543

99447

2,777269335

0

to268

0

L06

764 3

s5 73 qÁ 19

763763

lqRRq

3030

77

770770

1?

)

923923

6 077

572572

915

3,410

756

22r22r

1) q77

2,354

16 F,4q

3,5 51

5

2013 05 07

GRAND TOTAL )n) o0 q o¿2 1q a?q 1S ? 32 \ 44ll 14.953 't1)77

Page 2 of 2

78

lkolisnik

Text Box

20

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA II.170

Reference: PUB/Central-56(a)

In a simllar format as provided in PUB/Centra l-56(a), please provide the demographic

data for gas customers only.

ANSWER

UCo Households in Manitoba

Natural Gas

%ofTotalLtco

Rent

%ofTotalLtco

Total By

DwellingType

DwellingTvpe

Own% ofTotal

Lrco

29,472 84%78% 2,068 6%SingleDetached

27,404

4,714 t4%7,649 5%Multi-Attached

3,065 9%

t% 692 2%480 7% 2L2ApartmentSuite

L2% 34,878 LOO%30,949 88o/o 3,929Total byOwnership

2013 05 07 Page 1 of2

79

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA II-170

tlCO-125 Households in Manltoba

Natural Gas

Own RentDwellingType

5% 85%40,581 800Á

9% 1,801 L2%3%4,944

307 t% 3%788 2%

2013 05 07 Page 2 of 2

80

lkolisnik

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Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.59

Subject:

Reference:

Tab 7 DSM

TabT Appendix 7.3 - FRP

h) Please provide a table showing the annual residential gas DSM budget' the

annual gas LIEEP budget, the LIEEP budget as a percentage of the total DSM

budget, and the cumulative percentage spent on LIEEP for the years 2006/07 to

201?/13.

ANSWER

Forecast20121132009110 2010t11 20111122007loa 2008/092006107

s 7 589 864 s 8.490.352 s 9.974,232$ 4.878,773 $ 7 137 897 $ 7.618.351s 3.991.272Residential Natural Gas DSM Budqets 4954224 $ 6.241 .691s 2 889.875 $ 4.235.793s 256 676 s 325.265 $ 1.183,491B

58.4o/o 62.6V"16.6% 37.9o/o 55.8%6.4o/o 6.7%Natural Gas as % of Total

B

$ 49 680 740$ 31 216 156 $ 39.706.508s 8.870 045 s 16.007.941 s 23.626.292Cumulative Residential Natural GasRr rdoct s 3.991.272

$ 8,891.099 s 13A45.327 $ 20.087.018s 1765.432 s 4.655.307$ 581.941LIEEP

28.50/. 34.9Yo 40.40/o6 60/" 11.Oo/d 19.7Yo6-4o/oCumulative LIEEP Natural Gas as %of Total Residential Budqet

2013 04 16 Page 1 of 1

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Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA II.172

Reference: PUB/Gentral-59

c) Please update the response to PUB/Centra l-59(a) based on the 2013-2016

Power Smart Plan extending the schedule to include 2015116.

NEB:

12l13 values are a combination of actual values to the end of February, 20 13 and forecasted values for March,

2013** Disbursements indicated for the Forecast years do not include amounts in connection with the Neighbourhood

Approach

2014115Forecast**

2015116Forecast**

2üAßProiected*

2013114Forecast**

2009110Actual

2010111Actual

2011112Actual

FurnaceReplacementFund endingMarch 31(000's)

2008/9Actual

$ 17,644 $ 19,621$ 14,145 $ 15,853$ 5,972 $ e,050 $ 11,644OpeningBalance

$ z,szt

$ 3,800 $$ 3,838 $ 3,800 $ 3,800$ s,ass $ 3,800 $ 3,762Funding fromSGS Glass

$ (2,378) $ (2,378)$ (1,627) $ (2,378) $ (2,378)$ (264) $ (815) $ (1 ,312)Disbursements

$ 555 $ z¿o$ 2so $ 286 $ 369$s+ $s3 $Mqlnterest

$ 17,98e$ 15,853 $ 17,644 $ 19,621$ 9,050 $ 1 1,644 s 14,145EndingBalance

$ 5,972

1,018900 937445 662 660Number ofFurnacelnstallations

280 508

I9 15 I16 18Number ofBoilerlnstallations

5 I

5,4102,555 3,455 4,393788 1,233 1,895CumulativeFurnacelnstallations

280

81 9057 7214 30 48CumulativeBoilerlnstallations

5

2013 05 07 Page 1 of 1

83

d)

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA II-172

Reference: PUB/Central-59

Please estimate the number of furnaces and boilers (at the historical mix) that

could be replaced under the FRP beginning in 201116 with the forecasted

$19.6 million, and estimate how long until the FRP fund is depleted. Please

atso estimate the number of targeted furnaces that would remain after the FRP

funds are depleted, factoring in furnaces that may be replaced independently

of the FRP.

ANSWER

Centra projects the Furnace and Boiler market would be depleted before all of the Furnace

Replacement Funds are spent. The number of furnaces and boilers that could be replaced

under the FRP beginning in 2015116 are shown in the following table:

Furnace and boiler replacements could continue at the historical mix for the years 2015116

through to 2017t18 but would drop off in year 2018119 due to the reduced market size. The

standard efficiency furnace market is projected to be depleted at the end of fiscal year

2013 os 07 Page 1 of 2

201 8/1 9

Forecast

2016117

Forecast

2017118

Forecast

2015116

ForecastFRP Replacements

1,183 1 ,183 3121 ,018Number of Furnace lnstallations

I 99 9Number of Boiler lnstallations

8,0886,593 7,7765,410Cumulative Furnace lnstallations

108 11790 99Cumulative Boiler lnstallations

84

Centra Gas Manitoba lnc. 2013114 General Rate Application

2018t19. The FRP Fund Balance is estimated to be $14,824,734 at the end of year 2018119

based on the above activity.

The assumptions used in the Furnace Upgrade Market Table (see Appendix 7.3 p. 1) were

also used to estimate the targeted standard furnaces remaining at the end of each year

starting in 2015/16. Please see the chart below for the market estimations:

LIEEP Standard Efficiency Furnace Target Market

All

DwellingsLtcoL2S% Non-UCO

Furnace Marketplace

at Dec 1 2009

Standard Furnace Market

39,858 55,89216,034Owners

2,285 2,rsz 4,437Rentals

60,3291&319 42,OtO

Total Standard Furnaces

(source:2009 Survey)

Standard Furnaces Remaining

at Fiscal Year End

22,770 33,686end of 2072/73 7t,576

Furnace Marketplace

Projections of Standard

Furnaces Remaining

8,794 13,5005,307end of 2015/16

4,527 7,7443,223end of 2076177

7,\9r 2,4731,223end of 2OI7/18

00 0end of 2018/19

2013 05 07 Page 2 of 2

85

e)

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA II.172

Reference: PUB/Central-59

Please confirm whether the Lower lncome Energy Efficiency Program budget

shown in PUB/Centra l-59(h) includes funding from the Furnace Replacement

Program and the Affordable Energy Fund.

ANSWER:

Confirmed.

2013 05 07 Page 1 of 1

86

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA II-172

Reference: PUB/Central-59

Please add a row to the table in PUB/Centra l-59(c) showing Centra's program

administration and marketing unit cost per furnace and per boiler. Please

confirm whether the program administration and marketing costs are included

in the disbursements of the FRP.

ANSWER:

f)

Standard Furnace

ReplacementStandard BoilerReplacement

Cost Cost

Centra does not differentiate between furnace and boiler marketing and administration

costs. lnstead, the costs are incurred across all Furnace Replacement installations. The

average marketing and administration cost per heating system replaced under the program

is $871. The program administration and marketing costs under the Furnace Replacement

Program are included in the disbursements of the FRP.

S r,r+o S 6,445Customer contribution5 z,tst s 2,500Centra contribution5 z,szl S 9,9+sTotal equipment cost

S szrS szrMa rketine/Administration cost

2013 05 07 Page 1 of I

87

e)

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA II.172

Reference: PUB/Central-59(g)

Please provide a breakdown of FRP disbursements for each of years 2008/09

through 201U15.

ANSWER

2010111

Actual

2011112

Actual

2008/09

Actual

2009/10

Actual

FRP Disbursements

Breakdown

$405,447$358,204lnternal- Labour

$1,231 $1,993 $3,259lnternal - Other

$88, I 67 $1 13,821Marketing

$1,104,506$813,975 $863,256Payments to Contractors $264,258

$1,311,620 $1,627,033$264,258 $815,205Total

20'14115

Forecast Total

201U13

Projected

2013114

Forecast

FRP Disbursements

Breakdown

$452,017 $2,119,704$452,017 $452,017lnternal - Labour

$17,993$3,837 $3,837 $3,837lnternal- Other

$560,668$1 19,560 $119,560Marketing $119,560

$1,802,973 $8,454,913$1,802,973 $1,802,973Payments to Contractors

$2,378,387 $11,153,27792,378,387 $2,378,387Total

2013 05 07 Page 1 of I

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PUB/CENTRA I-59bAttachment 1

Report on Lower lncome Energy Efficiency Program and the Furnace Replacement ProgrBñge 2 of 21

For the Period Endinq December 31,2012

et Furnace Rep lacement Market - As at December 31 ,2012T

LIEEP Standard Efficiency Furnace Target Market Review

d as of December 3L,2OL2l(update

All Dwell¡npsLtcot25% Non-LICOFurnace Marketpl ace at Dec 1 2009*

Standard Furnaces

39.858 55,89216,034Owners

2,t52 4,4372,285Rentals

18.319 42,OLO 60,329Total Standard Furnaces ( 2009r Survey)

Estimeted lnstallation from Dec 1/09 to December 31/12+*

24,85r6,253 78,597Total

Remaining Standerd Furnaces at December 31st, 2OI2*.+

ts,47at2,066 23,4I3Total

t7s,674 225,O8049,406All Natural Gas Furnaces 12fl)9 surueyl*rrt3% L6%24%Standard % of

The following table has been updated to provide an estimate of the standard furnaces being used in

Manitoba and an indication for the target market for Manitoba Hydro's Furnace Replacement Program.

* Statist¡cs from November 2009 survey, gas heated billed customers - excluding boilers and including apts.

Estimated number of standard efficiency furnaces has been slightly refined in Q4 2077/12 reporT-

** Estimated total number of natural gas furnace replacements from Dec 1, 2009 to December 31, 2012 is

based on permit data shown in following table, for a total of 27,6f2 furnace replacements. lt is assumed that

90% of all furnaces replaced since December 2009 were standard efficient furnaces. The breakdown between

LICO and Non-LICO has been further refined based on analysis from the 2009 survey.

+** The standard furnaces being replaced in the lower income market are reflective of Manitoba Hydro's lower

income progrâm, normal furnace failures and marketing efforts by the HVAC ¡ndustry. Although the lower

income market mìght not be influenced bythe HVAC marketing efforts as much as other market sectors, the

average age ofthe furnaces within the lower income market is higher and therefore, ¡t is expected that this

market sector might experience higher overall failure rates. "All Gas Furnace" numbers have been slightly

refined from 2010/11 Q3.

+*+* Represents the total number of natural gas furnaces in the marketplace, including those in renter-

occupied dwellings; however, LIEEP targets owner-occupied dwellings only

2

89

lkolisnik

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)

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA þ116

Subject:

Reference

Tab 12= Rate Schedules & Gustomer lmpacts

Tab 12 Page 3 of 8

Please file the most current Home Heating Cost Comparison as well as a pro forma of

the August 1,2013 Home Heating Cost Gomparison that incorporates any proposed

electricity and gas rate changes.

ANSWER

Please see the attached current Space and Water Heating Cost Comparison Chart based

on energy prices in effect February 1, 2013. Also attached is a pro forma Space and Water

Heating Cost Comparison Chart including Manitoba Hydro's proposed electricity and natural

gas rate increases, which, if approved, would be in effectAugust 1,2013. The natural gas

rate assumes the current February 1't primary gas rate and billing percentages as the

August 1,2013 values are unknown at this time'

2013 04 12 Page I of 1

91

PUB/CENTRA I-116Attachment I1of 3

Typical space & water heat¡ng costsAverage fa

Wonderingabout yourenergyoptions forheating21. Consult the charts

to identiñ7 the costsof your current homeheating and waterheating systems.

2. Review the costs ofother systems to seehow your costscomPare.

3. Consult theaccompanying notesfor guidance if youare thinking ofswitching systems orbuilding a new home.

Energy ratesNatural gas:

S0.2336/cubic metre

Electricity:5O.0694/kilowatt- hour

Fuel oil:S1.090/litre

Propane:

$O.529llitre

Basic monthly chargefor natural gas is $14(5168 per year)

Annual propane tankrental: S151

residence at rates in effect February 1, 2013

Geothermal

Annual Space Heating Gosts(Average Slngls Famlly Resldonce)

Natural Gas Electricity Fuel Oil Propane

(0096 sE)

FuelOil Propane

$3,000

$2,500

$2,000

$1,500

$1,000

ooooIE

cc

(Ú

P$5oo

$oGEoTHERIiIAL GEoTHERMAT High+trcbq Md'Effcsc, CmvfiùonalGmund SdE GDUd Souræ Fúroæ Furo€ Fumæ

ELECTRIC Mid.Emciw

(869t SE)

hvsfioßl

(60'9( SE)

Mñ-E[Éhs1

(829t SE)

Cmv6üoßl

(6296 SE)HelPúmp(scoP=3)

H€l Pomp (92'/6 SE)(scoP= 2)

(00',6 SE) 160% sE) &$hß(100î( sE)

Types of Heating SystemsI Baslc Charges or Storage Tank Rental Charg€s

Water Heating Gosts(based on average annual hot wator usago of 2.4 people per household)

Electric Assisted Natural Gas ElectricityGeothermal

# ssooo

'$¿oo(E5E $soo

E $2oop' $100

$oEnêrgy Sbr EnHgy Sbr coMlMl

Higà Effrcjencï weld kþr Web þldCondqs¡ng CSA P.3¡4 CSA P.344

waEHels (0.67 EF) (0.57 EF)

csAP.3g(0.90 EF)

401.G. (102I) EWsb¡CSAI9104 HighEñìdonc,ElffiW¿w ConhdngtukdsH WabrHælsby Ge{Ml CSA P.3.04oespetuls (0.S EF)(Tl Wsbndby

l6s)

Enerly Sb Cmmb¿lWaþr Haler Wab Hëts

()tG (1021) 60rG (2731)csA-191s csAi91'04

S&VenlRearFlæ

ConHlioml

(0.55 EF)csA P 3{4(067EF)

csAP 3-04 Eldñc wala Elffi Waler WaB H€ls(0 æ EF) tul{ (71 W Hæler (90 W (0 60 EF)

sbndbylN) SñbylN)

Types of Water Heaters

ManitobaHydro

,968

$l,662,528

11,152I$s76

[r#f,rÉVffqlti.ltl

$391

${rlf,.illll

trEIt

rfi

92

Typical space & water heating costsAverage single family residence at rates in effect May 1, 20L3

Wondaboutenergyoptionsheating

eringyour

$3,000

Annual Space Heating Costs(Average Single Femily Ros¡dence)

Geothermal Natural Gas E Fuel Oil Propane

GEOTHERMAL G€oTHEilAL High-Efrcj.ry Md+ffincy ConHlionalGrcundk@ Grilndhm Fum* Fuatræ Funæ

tld.Eftkry Cdwnhål

Hd Pump(scoP= 3)

þdPump(scoP.2)

ELECTRIC

8düds(1009r sE)

(90* sE) (6r¡ sE){02% sE) f00% sE) {6096 sE) (æ% sE) (60i6 sE)

Md-E|fi.¡sy

(02% sE)

Cnwnüod

Types of Heating SystemsE Ba.lc Chârges or Storage Tank R€ntal Charg€r

Water Heating Costs(based on average ennual hot water usage of 2.4 people pêr housohold)

Elect¡ic Assisted Natural Gas Electricity FuelOil PropaneGeothermal

for?

1. Consult the chartsto identify the costsof your current homeheating and waterheating systems.

2. Review the costs ofother systems to seehow your costscomPare.

3. Consult theaccompanying notesfor guidance if youare thinking ofswitching systems orbuilding a new home.

Natural gas:

10.2529/cubic metre

Electricity:S0.O7 183/k¡lowatt- hour

Fuel oil:S1.04llitre

Propane:

SO.545llitre

Basic monthly chargefor natural gas is $14($168 per year)

Annual propane tankrental: S151

Energy rates

ooooG

trtr

G

Ê

$

$

$2 500

$2 000

,500

,000

$soo

$o

# ssooo

I s+oo

=E $goo

E $2oop' $100

$o 40lG (182r)csA-101{4EHicWturHe# $isledby Gehsdæsæñder(71 W sb¡dby

los)

Enêqy ShHith EfücienqhhSng

HPH4(0 90 EF)

Emqysr CøHüond 401G, (182 L) m lG (273 L) *Vñlw#kdef waldHed€f csA-1919 csA-1914 RerFlæCSA P 344 CSA P ¡04 Eledic Wds EHdc W&r W# Me.

(0 67 EF) (0 59 EF) þdr (71 w þû (90 w (0 6ô EF)

ddbylo$) shdbylo$)

Types of Water Heaters

Cdwnbnd

(0 s EFI

Eßgy kHigh EfrdrryCond6iry

c9P3&(0 90 EF)

cs P 3¡4(0 67 EF)

CdEnbnd

csA P 344(0 57 EF)

rilManitobaHydro

Eßgy Sr

I,193

$609

$r'F¡fEn

t-;403

-ls271l

[*9Il

t

'Manltoba Hydrc ls a llcenso ol holEdomaí( and 0lticial Mark.

93

PUB/CENTRA I-116Attachment 21 o12

Annual Space Heating Costs - August I 113 proposed(Average Single Family Residence)

$3,

$3,500

$2,500

$1,500

$1,000

$500

000

Geothermals0.07202/ kwh

GEOTHERMAL GEOTHERMAL High-Effciency

Ground Source Ground Source FumaceHeat Pump Heat Pump (92% SE)

(SCOP = 3) (SCOP = 2)

Fumace orBaseboards

(1oo% sE)

Types of Heating SystemsÐBas¡c Gharges or Storage Tank Rental Gharges

Natural Gas$0.2419 /cu.m.

Mid-EfflciencyFumace

(80% sE)

Electric7

Fuel Oil$1.09 / L

Propane$0.529 / L

Mid-EficiencyFumace

(82% SE)

$2,000

o+roo(J-rú-Jcç

-G+r19

$oConventional

Fumace(60% sE)

Mid-EfficiencyFumace

(86% SE)

Conventional

Fumace(60% sE)

High-EfficiencyFumace

(e0% sE)

ConventionalFumace

(62% SE)

rhfo

POTCR TNRI

1

s2,149

$1,5286621

T

01,968

0G2ôô

-

$5e8

rr'r{l¡ rl.ì :1t-l

312712013 Typical Home Costs Augl 2013 Proposed.xlsm

94

PUB/CENTRA I-116Attachment 22oÍ2Water Heating Costs - August I /,13 proposed

(based on average annual hot water usage o12.4 people per household)

$60

Electric AssistedGeothermal07202

Natural Gas$0.2419 /cu.m.

Electricitys0.07202 /kwh

Fuel Oil$1.09 /L

Propane$0.529/L

Energy StarWater HeatercsA P.3-04(0.67 EF)

o+,ooo-fr-JcC

-(E*rol-

050$

300$

$

$400

$200

1 00

$o40 l.G. (182 L) Energy StarCSA-191-04 HighEfficiencyElectricWater Condensing

Heater assisted Water Heaterby Geothermal CSA P.3-04Desuperheater (0.90 EF)

(71 W standby

loss)

Energy StarWater HeatercsA P.&04

(0.67 EF)

ConventionalWater HeatercsA P.3-04(0.5s EF)

40 r.G. (182 L)

csA-191-04Electric WaterHeater(71 Wstandby loss)

60 r.G. (273 L)

csA-191-04Electric WaterHeater (90 W

standby loss)

Side VentRear Flue

Water Heater(0.68 EF)

ConventionalWater Heater

(0.55 EF)

Energy StarHigh Efidency

CondensingWater HeatercsA P.3-04

(o.so EF)

ConventionalWater HeatercsA P.3-04

(0.57 EF)

Types of Water Heaters

,lì

[,tEl [,Íul [fftrr

[il{ù Íwt

vlttl

IFþFI

Frml

tüeetË'rm

312712013 Typical Home Costs Augl 2013 Proposed.xlsm

95

lkolisnik

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Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.68

Subject:

Reference:

Tab 8: Load Forecast

Tab 8 Appendix 8.1 Page 13,42 to 45 of 52

c) Please provide the percentage of newly constructed homes in the Winnipeg

area that elected gas service in each of the past five years and are forecasted

to elect gas service for the test year.

ANSWER

The table shows the estimated percentage of new single detached homes in Winnipeg

installing natural gas for space heat:

New Single Detached Homesin Winnipeg

with qas space heat95.0%200710895.8%2008/0995.2o/o2009/1096.5%201011197¿%2011112

2012113 forecast 97.6%

2013114 forecast 97.8%

Multi-family homes and apartments are modeled only for Manitoba as a whole. Survey data

indicated that from 2005 to 2009,57o/o of new multi-family homes in Winnipeg were installing

natural gas for space heating. There are no new apartment dwellings installing individual

suite natural gas heating systems.

2013 04 12 Page 1 of 1

97

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.68

Subject:

Reference

Tab 8: Load Forecast

Tab 8 Appendix 8.1 Page 13,42 to 45 of 52

d) Please provide the percentage of newly constructed homes in gas-available

areas outside Winnipeg (by specific geographic region) that elect gas service

in each of the past five years and are forecasted to elect gas service for the

test year.

NEB:

The table shows the estimated percentage of new single detached homes in gas-available

areas outside Winnipeg installing natural gas for space heat:

New Single Detached Homesin South Gas Available Areas

with qas space heat38.7%200710830.0%2008/0932.0o/o2009t1040.2o/o201011144.60/0201111246.0%2012113 forecast45.1o/o2013114 forecast

New homes are forecast for the south-gas available area overall, not by specific geographic

region; multi-family homes and apartments are modeled only for Manitoba as a whole'

Survey data indicated that from 2005 to 2009, 26% of new multi-family homes in gas-

available areas outside Winnipeg were installing natural gas for space heating. There are no

new apartment dwellings installing individual suite natural gas heating systems.

2013 04 12 Page 1 of 1

98

lkolisnik

Text Box

26

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I-119

Subiect:

Reference:

Tab 12= Rate Schedules & Customer lmpacts

Tab12 Page 7 of I

a) What is the dollar amount of the Minimum Annual Gross Margin Amount

payable by the Power Station class customer. Please confirm whether this

amount is aggregate or for each power station.

ANSWER

The Minimum Annual Gross Margin for the Brandon Power Station is $572,600 and the

Selkirk Power Station is $374,500.

2013 04 12 Page 1 of 1

99

Gentra Gas Manitoba Inc.2013114 General Rate Application

PUB/Centra 119 cAttachment

April 12,2013Power Stations Pavments reouired to meet Minimum Gross MarginAmount-9vears

2004Minimum Annual Gross MarqinBrandon $ 572,600 $SelkirkTotal

2006 2007

572,600 $ 572,600 $

2005 2008

572,600 $

2009 2010 2011

572,600 $ 572,600 $

2012

572,600 $

Total

5,153,4003

947, 947,104 947, 947,104 947,1

Actual billed demand and BMC charqesBrandon S szS,ZOS$ 740,913$ 344,6865474,408 $315,957$271,263 $250,564$516,040$440,993$ 3,928,610

Selkirk 67 $ 394,218 $ 240,183 $

Total

Difference - Over /(Under) Minimum Annual Gross Marqin

Brandon $ 1,185$ 168,313$(227,914) $ (e8,1e2) $ (256,643) $ (301,337) $ (322,036) $ (56,560) $ (131,607) $ (1,224,7s0)

572600 572 6003737

$$

$$

SelkirkTotal

71 74 813 $ 18 714(346,451) (450,602)

$ (227,e14) $ (s8,1s2) $ (256, 643) $ (301,337)$ (322,036) $ (56,560)$ (131,607) $ (1,3s4,288)

1 $ 1 117

$ $Reouired PavmentsBrandonSelkirkTotal

11 $ 34 321(390,964)

$ $ 161(157,34

100

lkolisnik

Text Box

27

d)

Gentra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA II.182

Reference: PUB/Centra l-119;Tab 11 Schedule 11.1.0

Please provide the forecasted Test Year revenue to cost ratio for this customer

reflecting the anticipated revenue from the MAGMA.

ANSWER:

Please refer to the tables below

2013 05 07 Page I of 2

101

Centra Gas Manitoba lnc. 2013114 General Rate Application

i) Forecast RCC with all revenues included:

Cost AllocationEnergy

Demand

Customer

Total Allocated costs

Revenue

Energy

Minimum Annual Gross Margin

Total Revenue

Revenue To Cost Ratio

Total Revenue

Total Allocated costs

Revenue To Cost Ratio:

Energy

Demand

Customer

TotalAllocated costs

Revenue

Energy

Minimum Annual Gross Margin (MAGMA)

Total Revenue

Minimum Annual Gross Margin

Less: Demand

Less: Customer

Top-up payment to MAGMA

Revenue Cost Ratio

Total Revenue

Less: Top-up payment to MAGMA

PS Revenue before Top-up payment

Total Allocated costs

Revenue To Cost Ratio:

2013/14 GRA

t25,157

67,332

L96,785

389,273

725,757

947,7M

t,o72,26I

1,o72,26L

389,273

2.8

ii) Forecast RCC excludingtop-up paymentto assure MAGMA:

Cost Allocation 2013/14 GRA

t25,157

67,332

196,785

389,273

125,L57

947,!M1,072,26!

947,7U-67,332

-t96,785

682,988

1,o72,261

-682,988

389,273

389,273

1.0

2013 05 07 Page 2 of 2

102

Schedulo ll,l.0Fobruary 22,20112013/14 Gonorål Raio¡ Appll@llon

Summary otAllocotod Cgll! by Cu.lomor Clú¡2013/lA T..t Ye.r

hldGsftrlfìmOFrdhg A blnhmm ExFreDçræbü6AAMtuCqlbl& OhrTâ6

tulof@

OFGùng & &hm EpF6&Bùtü ßAMiaþnCqþ8tuT9E

kldȡ

OFEüno&MlffiEXFtwh@lâüil AMolbümøplbl I dÞr Tqs

kloltu

OFßùq A Múl6mm ExFnffi&Ei¡ùm &AMlätdGp¡dAffiTus

hloltu

o@üq&MâhlffiEplì6tupdålm A AmdEümødd À qMTsrc

hlôf WæEmnb

2,m,13147

74,f24,179,U

62,W1.W,ø21,1õ7,æ5

0-1,ffi,0240,u,4m17,U6.810

{7ææ3fl67W

2,1S,87û 0 18,49,617467 -57,ã8 S,745

s.g8 ô.0æ,431 1o,ffi,ffi2,4S,ru 2,U7,45 7,m1,æ1

421,911 1,514,912 4,19,7421.070,528 1,3S,7æ 4,030,ffi

74A,2A5 S2ø,7U 2,7S,6q98,il

1

23

5ô7I910

11

12t314

151ô

171ô19m21

222324

25â272dæ3031

3233u35s37æ3940414243

4540a7484Ss51

52

&55s57ssff€1

62æil65tr67æ6970?1

7273

7576

777879mE1

ø283&úæ87sE9m91

9293g95æ0?sæ

6,274,W7 4ffi1ffi2 Zaï g7

1 613 739t 119 615

226f6 2æ-il&

3 æ0 7ô53 æg 146

25,W,4X

24,W.3æ

16,277,741-39,019

1 ffi4977n2f2

2,249,1X5,374,m 8,093,351

ilt

40.105,6S7 11,ru,024 S,S,æ1 137,m,413

9,0s,770 12,f55,7ß7,746,978 t1.ffi,216

30ü 148-11 371

573 519623 ffi

ilz,m0{u

12,01314,7m

4,148,ru-æ,M

2,96,Wffi,8æ755,O32

2,217,913

il3,2v

2ô.462.0S 7,25e,674 12,493,m 48,215,?10

9,ffi

4,4f3

1,m

q,1ô3

1@,031146,702 ñ,gg 19,372 217 ,@A

7.018.4@ 1,071,451 1,æ7,1æ g¡S,m

0-9,4 I I

1,O21,725rs,sl73,70059,74141,4S

æ1,115i3

1,518247,571

0s

a7,n1r4,376

s7,194,U

1,313,241

m0

æ1

t05Mtæ

634tI

124lôx7049

12 740

1S S7&63

9Hi6

1&ffi577

u7211

w7n-5 1@

11717s2&

ffi3S4A 387

76AU4U 3æ

-5 5ã6S 025

61 5æ157 1S

-2237-31

571Ss

10?m24 3æ

21 41ö,1æs5

7q310 7G

107 752-27 W

51ru35 52t

614 ffi42ffi

146 52101S2

-5 3tô614 ffiü 614

1Æ52

l01@1

s79421s9

0-24

2ffiffiÆ26143

-E 215m 270

37098m5142

7ôS5 ô39

452,45X313,913

2,577-743

85,7S-9,51135,37419,0S13,21f

17 g63U2

ffi,u0

181,973192,315 32,0ff 7,427 231,797113.3t ô2,017 0,116 æ1,4æ70.q5 s,w 4,21ã 139,794

æ,79 æ,593 1,9 65,3æ

1,@1,S1 ffi,1æ 1æ,635 2,410,375

s9,æ24,O71

1æ,4333.912 142,326

1,301,1s2 ffi,716 42,114 1,457,O22

1,138,ffi 470,A77 0 1,610,7S-3,74 -77 4,@ -7.919

432,4æ 8,916 44,14 æ5,470173,745 14,4W 70,79 S,W19,8ß 49,S5 S,0ü 2ô0.1æ140,ffi 1æ,ø7 æ,603 8,21097,514 A7,479 æ,S9 m5,8245.672 40.æ2 I,S F,ofl

2,2m,715 920,017 ffi,ru 3,fæ,2f4

0-112

10,ü112,m

124 61f 0-2fo

21,76ã67,ffi43,17532,01722,213

127,59i,015

67,X12 125,157 1S,7ñ w.273

129,M,87

42,ffi

101.S2

1æ,æ,4ô7-5,31ö

76.ð7

&,614

2t,41ô,1Ss5

101.897,q3

101,8il

24,3û

1t16.õ9 0 16,8q1,

trrOp€Éüq e MâhIæM EIFtt*

øp{d E OhrTa¡s

1æ,279,472

I,S7,S3-7ö

6,97462tg3

2,1161,409

1,q2,&

o 1w275,172

1,æ7,ffi-?a

I,S74021g3

2,1461,409

FLd hr il.lmMåñd EmEv C6bmr Tobl

955.ô27-1,1 10

12A,Ð11@,æ7

23242,1101,4U

0 21,ffi,037

ffi,317

21,S,037

235,0il 1,1S,371

M,1æ,737

33,8S,579

0I 071

123 671ß5S

1ôS1 023

710

wa27{0

4ilâ314476

1æ77g

Mt

lß 7& m017mm09,2æ,033

rem01410 7æ 7S

0 1,s2,ã

ddtu

OFÉUno8ffiM6EFfì6&ryr.dm aamorEümc6dBatrrTæ

N.llMm

000

0000

4,108,æ5119,8S

13,U1,ffz6.671,916,710,ffi4,7æ,1223,322.m1,S2.€5

1@,077,472-7,63

mi,4557,2ü,3241,9,ffi3,287,952,241,113I,m,ü0

0-1,7æ,O72t,076,&

i,ffi,ffie.m,0m

1m10t1021m1q105

6.3S.078 tz,W.m2

æ,m1,225 176,135,V2 101,H4,m 3S,65,?S

103

Centra Gas lran¡toba lnc.20l3rl¿l GeneÊ¡ Rttes Appl¡cation

Un¡t Cct Component summary20l3rl4 Test Year

Speciâl

1,497,622 389.273

lnlempl¡ble GesPG

Schedule ll.l.lFøbÛary 22,2013

Fim lnteruplibbSuoolem€nbl Supplemenlal OFednq

FRPGS

F¡xd Priæ

1,902,294

SyslemTobl

Small Gen

SqiÉSGSTolal

Leße GenSeruiæ

LGS

H'Sh

VolumeHVF

CoooeEl¡vecæP

Main Line

Pnmåry

SPFSPNTMLftntÉds Slâl¡on6

1 REVENUE REQUIRE¡TENTS

Total (ind gâs Gls)

15 MONTHLY BILLING DETERMINANTS

2

3

45

6

78I

10

11

12

1314

161718192021223

27282930

32

Upslßem Demând ($)Upstesm Commodity ($)Upst€6m Cuslorer l$)UFIÞ6mTobl($)

45,478,615162,54.65s

020a,o23,270

23,405,7il3,825,955

027,231,719

9.3æ1,2æ

010,il8

1,175,277480.898

'16,801,319

2,745,2970

'19,586.616

368,25469,266

0437,520

3,718,618650,852

DwnstÉan Dsmãnd (S)

Ddnsteãm Commod¡ly ($)35,402,6101 3,594,968

101.64.908150,642,486

86.589.6911 10,728,693

'16,6S,933

7.439.069

't1,661,637

4,474,37712.493.0æ28,629,094

3,299,791426.(x]8

1.357.1685.083,597

3,3580

3,427,2ú

120.635 42.1141,972,A51 1,497,622

00

s0

DwnstEañ C6lomer l$lDwnst@m Tobl(5)

1,233,327618.893

1,3s1,79263,716

67,r32125,157196.785399.273

1,045,441

447,119606.538

2,099,098

00

s0

q1 656 176

s4 59 470

0130,279472

0

130,279,472

021.586,037

021.586,037

01,9î2,29

01,902,29

0963,317

0963,317

00

00

8%

00q0

000

000

0

0

974

24

25270

12

25270

12

00

235.0s4

Upst€åm Demand (1dm'iey)UpÊt€em Comrþd¡ty (lCíf )Up6teem Cuslomer (dsbmeß)

DownslÞâm Demand (1 edley)Downslæam ømmodity (led)Downsl€am customer (cusloreß)

125,3821,409,7783,292,042

62.æ2680,452

3.188.090

44.539499.617

92,428

I 0,138123,624

1,O44

358,665,755 137,960.413 4A,215,710 9,453.068 17.UA 2,410,375

13,496

00% 00% 65 0% 100 0% '100 0%

3,755,274 130,279,472 21,546,03792%

1,r98,3710

13'1,746

100 0% 100 0% 65 0% 100 0% 100 0% 100 0% 100 0%

6,81392.3t5

444

01,102,093

0

011.078

0

0720391

1ú,7432,027,2a53,289,635

62,892680,452

3.194.330

44.539499,617

93,577

12,561'163,46

1,1ß

6,720134,963

96

15,553421,289

12

14.65615,196

24

7,797112,051

480

24 PERCENT IN DEMAND CHARGE

26 RESULTING UNIT CHARGESUpstEem &månd ($/1om¡iây)l..lpslßam commodity ($/1(Pm¡)ljpstreem Cuslomer ($/dstomer)

362720115 298

0 000

0 00040 02000m

0 00039 203

0 000

æa 41315 792

0 000

369 9504 6470 000

377 9155 1320 000

0 0000 0000 000

0 0000 0000 000

112 120I 6650 000

0 000114 211

0 000

0 000163 845

0 000

0 000171 721

0 000

0 000124 7æ

0 000

DdnÊt€sm Commodity ($/l CPm!)

Dilnstresm Customor ($/dslomÊr)

2t4 8966 706

30 899

0,00035 47527 107

0 00032æ7

133 5m

'170 762I 676

1,229 319

1323C20 000

320 192

183 5364 s86

1,256 611

89 4880 l5r

3,509 512

4 5S4

I 2368,199 358

a7 14A7 256

1,263 621

0 0000 0000 000

0 0000 0000 000

0 0000 0000m0

0 0000 0000 000

104

Upstreem Demand (S)

Gas CoslsNon{as cosßTolal

43,910,4211.568.19

45,478,6150

22,598,686807.078

23,405,7640

16,221,976579.93

16,80'1,319

0

UpstE€m commodity (S)

Gas CoslsNon€as coslsTolel

157,812,1164.7æ.539

162.544,6550

2,120,0811.705.8753.825.955

0

CentÊ Gas ftlan¡loba lnc.20'l 3t14 Gsn€ral Râtos Appl¡cation

Compar¡son of Gas Costs vs- Non-Gas Costs201 3/14 Tost Year

9,059

9.383

15.755

215,141

9,690

Cal@lâtion ollhe Fixed Rale Pdmary Gas PCR

355,55612.698

368.254

1,1U,75240.526

1,175,2770

Schodule 11.1.2February22,2O13

Syst6mTolel

Smâll GênSeruiæ

SGS-Tobl

Lerge GênSeryiæ

LGS

High

HVFCÆoæEtive

co-oP

Specia¡ConlEñ Slâlions Gas

PG

Fim lnlerupl¡ble Fixed PriæSupol€menbl SuoÞl€m€nbl O&i!S

FSP ISP FRPGSlnteruptibleMain Line

NT¡¡L

Pdmary

21.418,199

000

129,2æ,4A7 21,418,199

Gs Co.b w. Non&3 Cosb

1 REVENUE REOUIREMENTS234567II

t011

121314l5t61718192021

222324

26272ø

293031

3233

u3637383940414243444546

3 590,393128.225

3 718,6'180

a4

0

600666

12Ê60

0

s0

0

0

s00

0

s0

0

0q000

0q0

0

s0

0235.054235,09

2,785,297

6.3m.æ320a,023,270

24,718,7672.512.95227 ,231,719

17,755,7691.830.&819,586,616

3,933,206436.264

4,369,470

391,270

ßÆ437,520

0

'1.385.8s0

270.3261,656,176

0

129,2ô6,4871.012.985

130,275,4720

167.83821.S6.037

1,887,503

.14J9.11,902,2%

0

955,æ77.490

963.3170

1,533,793

201,722,537

2,265,756

2M,146,737

1,012,985 (line 9. PG ælumn)

1,102,093 (103m3 (schedule ll 1 l. l¡€ 17. PG @lumn)--------õ3Ito'''

u2,a13308.039650.852

0

35,71433.55263,266

0

251,099229.800480,898

0

129,266,4471.012.985

130,279,4720

21,418.199167.838

21,586.0370

1,887,50314.791

1,902,2940

955,8277.490

963.3170

0

s0

0

so

0

s0

0q0

0q00

0

s0

0

s00

0

s0

t,pstream Cuslomer ($)

Gas CoslsNon{as cGlsToÞl

UpsÍ€sm lobl ($)Totâl Ges CosbTobl Non€as C6tsTobl Upst€em Cosb

0

s0

0

s0

0

I0

0

s0

0

9,659

10,6480

DNnstEam Dåilend ($)Gâs CostsNon{es CcbTotâl

1 98.44435.204.16635,402,610

77,60316.622.33016,699,933

55.76511.605.872I 1,661,637

3.2&,0363,299.791

3l3.3273,358

1 0,4841.222.U31,233,327

30,7221.361.070r.391.732

2,9n64.35567.32

r.04¡.3351,045,41

5,107

224,445

DownstEam Commod¡ty ($)

Gâs CoslsNongas CoslsTobl

Downslream Customer ($)Gæ CosbNon{as c6lsTobl

11329.21213.594.968

870.0506.S9.0197.439.069

623.0833.851.2944,474,377

199,387

2E-252426.638

165,400453.492618,893

63.441

z5124,617

540125,157

219,n8227.UO47 119

0

00

0

00

0q0

0

s0

0

s0

0

s0

0

s0

101.64.908't 01,644,S8

86.589.69186,589,691

12.493.08012.493.080

01.357.168'i,357,168

03.U23,U2

0120.635120.635

0

42tl!42,114

0'1 96.785196,785

0606.538606.538

Downstream Tolel ($)

Tolal Ges CÆsß

Totâl Non{as CoslsTolâlDMnslr€âm &sß

2,4ú,200148.178.286150,æ2,486

947,653109.781.040I 10,728.693

678,84827.950.24628,629.094

4.868.4565,083.597

3tZJ.Eg7,2æ

175,8U 94,1631.796.970 1.403.4591s723s 1,497,622

127,554261.679389.273

1.A74.2132,099,0S

0

s0

0235.0S235,054

GÉnd Tobl Gas cosßGÉnd Tobl Non€as CoslsGÉnd Tobl

47 Calculation ofthe Pñmary G¿s Overhead Ratei

48

49

19.479.019358.66s,755

25.666,420I 12.293.993137,960,413

18,434,61729.781.09448,215,710

4.148.3485.3M.7209,453.0æ

567.1 541.843.2202.410.375

94.'163

1.403.4591,497,622

127,5U261.679389,273

1,6'10,735

2.144.5383,755,274

1.012.985 167.838130.279.472 21.546.037

1,887,50314.791

1p022%

955,827242.544

I,198.3718.159

17,U8

242.il4 (lines I & 34, FPO column)

7,720 (1ohr (schedule 11 I 1, line 17. FPo cdumn)

-----liTJPe' ro'm'

105

C.ntÉ Gaa Manitoba lnc, Schedul€ ll.l.3FèhNery 22,2013

Smâll

Cdmâdslktsè ènSç¡¡q

Tobl Functlonal¡¿t¡on By Cuatomer Cl*32013r1 ¡l T6t Year

Hgh

l¿d@ @mBtuê &ln LlmSpdål

Cstd Sbüon3 lntèmotbl. çÆ Suml.h.nbllñÞruptibls

Suæl€mñbl OffêrinoF¡xd Priæ

Ræidenüål

Smil enS!!@

19.731,119130,279,472 21,S,037 1,S2,4 $3317

1 PROOUCTION

2 O6mad3 Eæay

5 Tobl6

7 PIPELINE

8 Dm¡dI Emrgy

11 ToÞl

12

13 STOBGE

15 Enâry

17 Tobl18

19 TMNSMISION

31 t92.7251,626,230

13,885,€0

672 0S2,322,3æ

112,827

16,207,ffi7U,926

11,69,49576,326

2,575,W142,609

255,006

15.S8

13,Ss,890

6,187.306

6,1ffi,5æ2,595,067

1,031,S9

45,9627,197,8S

3,91,0æ5,1ff 855

2,20A,971

1,143,574

s8,243

113,24ø

53,698

6 497311

813,ru105.4æ

351,4æ

374,4102,æ59t

0

0

0

0

0

0

10,452,0213,59,968

3,9q,4095 162,7?9

715.572

2 276,æ0

4,619,981

7,439,0690

2,9A8,43

4,474,377

8e,968426,€S

620,S06r8,893 63,716

67,332

125,157

297,414

47,1191,512

Emry

DìSIRIBUTION

æq10,98,993 r,7æ,959 12,079€52 8,673,19 2,4U.42 1,96 612,71A 748,02724,5S,S9

ONSITÊ

æmånd

En€ry

Tobl

20

21

22

23

24

26

27

za

29

30

3l

33

&35

æ37

38

39

40

41

TOT& SEruICE

Eneq

Tobl

& 8€1,225

176,139,62

9,305,4128,429,95

5,800,285

2,835,079

4.105,63711,%5,O24

28,462,9S

7,259,674

7,018,409

1,On,491

12,740

1,261.601.s1

688,159

1.391,792

63,716

67,332

125,157

2,220,719

928,017 1æ,279,4f2 2r.S6,037 1.92,2s $3,317

106

Centra's Cost Allocation Methodolosv

Step 1:

Functionalize

Step 2: Classiff

Step 3: Allocate toCustomer Classes

CLI

S

t()

nlcr

CapaC

¡

t

v

SC

Comlll()

dit

Onsite

CLI

S

tO

nt

r

PS

CapaL

itv

Colllt-ì1

odit

Distribution

INT

CustomerCapacity

/ Demand

Transmission

Mainline

Cì

Lì

S

tolt-ì

ef

CommoditylEnergy

Storage

HVF

Capacitv

Eg. DSM AmortizationExpense Allocator

Coll-ìtnodit

c:uS

tonlef

Pipeline

LGS

Cap¿t

L

iIv

CoItllIodit

Production

SGS

C[1

S

tot11

cr

Total Revenue Requirement

CapaL

i

tv

Con1

modit

From Tab lI p.2-6

107

lkolisnik

Text Box

28

Centra Gas - Rate Chanees Proposed for Aueust 1. 2013

Base Rates

Basic Monthly Charge ($/month)Small GeneralService

Large General Service

High Volume Firm

Mainline

lnterruptiblePower Station

Special Contract

Demand (S/m3/month)

Small GeneralServiceLarge General Service

High Volume Firm

Mainline

lnterru ptible

Power Station

Special Contract

Commodity (S/m3)

Small GeneralService

Large General Service

High Volume Firm

Mainline

lnterru ptible

Power Station

Special Contract

Commodity ($/m3)

Supplemental Gas - Firm

Supplemental Gas - lnterruptible

Source: Schedule L2.2.O, t2.2.1May 10, 2013

01-MayT4

77

1118,31

2353.33

7042.72

11565.5

135424.7

01-Aug %Change14 0.oo%

77 0.OO%

1230.72 LO.O'%

1258.09 -46.54%

L265.O6 21.32%

8258.46 -28.59%

L20972.43 -L0.67%

Distribution

01-May Ol-Aug %Change

N/A N/A

N/A N/A

0.1504 0.1706 13.43%

0.158 0.1847 76s0%0.0772 0.0871 L2.82%

0.028 0.0047 -83.2L%

N/A N/A

Transportation

01-May 01-Aug % Change

N/A N/A

N/A N/A

0.2408 0.2386 -O.97%

0.4209 03782 -r0.t4%

o.rt27 0.tr22 -0.44%

N/A N/A

N/A N/A

Distribution

01-May 01-Aug

0.0869 0.o97L

0.0362 0.0429

0.0081 0.0096

0.00L5 0.0046

0.0051 0.oo72

0.0165 0,008

0.0002 0.0001

% Change

L7.74%

t8.5r%t8.52%

206.67%

4L.t8%-5t.52%-50.o0%

Transportation

01-May 01-Aug % Change

0.0462 0.04 -13.42%

0.0451 0.0392 -13.08%

0.0201 0.0158 -2L.39%

0.0095 0.0051 -46.32%

0.0139 0.0096 -30.94%

N/A N/A

N/A N/A

01-May

0.1344o.7293

01-Aug %Change

0.L605 19.42%

o.r7t 32.25%

109

Centra Gas - Rate Chanees Proposed for August 1. 2013

Billed Rates

Basic Monthly Charge ($/month)Small General Service

Large General Service

High Volume Firm

Mainline

lnterru ptible

Power StationSpecial Contract

Demand (S/m3/month)

Small General Service

Large General Service

High Volume Firm

Mainline

lnterru ptible

Power Station

Special Contract

Commodity ($/mg)

Small GeneralServiceLarge GeneralSeruice

High Volume Firm (Sales Service)

High Volume Firm (T-Service)

Mainline (Sales Service)

Mainline (T-Service)

I nterruptible (Sales Service)

I nterruptible T-Service)

Power StationSpecial Contract

Commodity ($/m3)

Supplemental Gas - Firm

Supplemental Gas - lnterruptible

01-Mayt477

1118.31

2353.33

7042.72

11565.6

135424.7

01-Aug % Change

L4 0.OO%

77 0.OO%

L230.72 tO.Os%

1258.09 -46.54%

1265.06 2L.32%

8258,46 -28.59%

120972.43 -10.67%

Distribution

01-May 01-Aug o/o Change

N/A N/A

N/A N/A

0.1504 0.L7rL 13.76%

0.158 0.L844 L6.7t%

o.o772 0.0875 t3.34%0.028 0.0048 -82.86%

N/A N/A

Transportation

01-May 01-Aug o/o Change

N/A N/A

N/A N/A

0.2408 0.3619 50.29%

0.4209 0.2594 -38.37%

o.tr27 0.7571 39.40%

N/A N/A

N/A N/A

Distribution01-May 01-Aug % Change

0.0869 0.0876 0.87%

0.0362 0,0333 -8.O7%

0.0081 0.0001 -98.77%

0.0081 0.0076 -6.L7%

0.0015 -0.0045 -400.00%

0,0015 0.003 Loo.oo%

0.0051- -0.0056 -209.80%

0.0051 0.0052 7.96%

0.0155 0.008 -5t.52%0.0002 0.0001 -50.00%

Transportation

01-May 01-Aug %Change

0.0462 0,051 t039%0.0451 0.0506 12.20%

0.0201 0.or27 -36.82%

N/A N/A

0.009s o.oo47 -s0.53%

N/A N/A

0.0139 0.0139 0.OO%

N/A N/A

N/A N/A

N/A N/A

01-Mayo.1344

0.1293

01-Aug % Change

0.1605 L9.42%

o.r7t 32.25%

Source: Schedule L2.2.O,I2.2.I May 10, 2013

110

PF¡.18 Êev iC 02 CllC03-03'72 2/3

ManitobaHydro

Cuslomer nomeNom de l'obonné

Account numberN'd€ compie

Service locolìonAdresse de service

Dole issuedDole d'ém¡ssion

AV27 AvR2Ot2

Speciol messoges / Messoges porliculiels

Þ New Equol Poyment Plon InslqlmenlOne or more of your EPP inslolmenls hos been revised to more occurolely bolonce your lnslolments billed ond Use

by lhe end of the EPP yeor. Your plon(s) will conlinue lo be reviewed until August when your EPP instolmenl(s) will berecolculoted for lhe beginning of ihe nexl EPP yeor.

Nouveou versemenl du Réglme de polements égoux(RPÉ)Nous ovons révisé le monlont ou les monlonls de vos versements du RPÉ pour foire conespondre plus exoclemenl les

versements focturés et votre consommolion jusqu'ò lo fin de l'onnée du RPÉ. Votre régime conlinuerq- d'être révisé

jusgu'ou mois d'ooût olors que votre versemenl'serq recolculé pour le début de lo prochoine onnée du RPÉ.

Þ The Public Ulililies Boord hos opproved new electriciþ roles. Pleose see the enclosed inserl for deloils.

Lo Régie des services publics o opprouvé de nouveoux torifs d'électricilé. Veuillez consulter l'encorl cÞjoint pour lous

les déloils.

¿leler number /" de compleur

Service / Pour lo pffodeFrom I Dv To / Au

Doys /Jours

Meler reodings /Relevés du compleur

Previous / Presenl /PrécâJent Nouveou

Mulliplier /lvlJltiplicoleur

kw.h /kwh

r,040

$ ó.8st 6.ó9

53.34

ReodingType de

lype Irelevé

Mor 23 MAR/|2 ^9t

25 AVR|12 33

Bosic Chorge / Redevonce de boseEnergy Cl'rorge / Frois d'énergie

Sublotol / Totol portiel

Electrlclty chorges ,/ Frols d'élechicilé

EPP inlolmenl / Versemenl du R.P.É.

Bosic Chøge / Redevonce de bosePrimory Gos (Centro) / Goz d'invento-re (Centro)

Supplemenlol Gos / Goz de réserveTronsporlotion fo Cenlro / Tronsport iusqu'ò CentroDilriÞution lo Customer / Distribution oux obonnésSubtotol / Totol pc¡'tiel

2.5O% CilyTox Bosed on Non Heoling Lood /Toxe niun. fondée sur lo chorge denon-chouffoge1.ñ%Prov Tox / Toxe prov.5.0o% GST / TPS

t4a4 I 588 't0 ElimoledEstímoiif

252.121 kw.h787.879

x $O.Oóó20x O.06770

2.5O7" Cily Tox / Toxe mun.7.@%P¡ov Tox / Toxe Prov.5.0O7" GST / TPS

99.O7þ x

1.0 x100.0 x

100.0 x

369.367 mo

369.367369.367369.367

x $0.1105Ox 0.13440x 0.053ó0x 0.08490

76.881.94

5.383.84

8E.04

$ r 4.0040.41

0.s0I9.8031.3ó

53.00

l0ó.07o.73

ì.505.31

I r3.ól

Eleclrlclty - Residenliol / Résidenliel

Nolurol gos - Residentiql / Goz nqlurel ' Résidentlel

tvleler number / Service / Pour to période Or3ür/N'de compfeur

From / Du ïo / Au

ure Melric conversion Cubic melresUsooe / t qe foclof/Focleur de lñ'l I Eeod¡ng lype /Consom-molion 1 9e convers¡on lvlèlaes Cuþes type oe felevede mélrique (m"lPrev¡ous I Ptesenl I

Précédenf Nouveou

Mor23MAR/I2 Apt25AvR/12 33 2683 2815EstimotedBtimotif369.367132 x 0.98780 x2.832784

Nolurol gos chorges,/ Frols de goz nofurel

55009 - 3 B

111

lkolisnik

Text Box

29

Gentra Gas Manitoba lnc.2013/14 Gene¡al Rates Appl¡cation - Gost of Gas Update May 10, 2013

Bill lmpact ComParison2013/14 Test Year

Updated Schedule 12.1.0Page 'l of 2

May 10,2013

BILL ITIPACTS

$

BILLED VS. BILLED

tay l/13 APPROVED BILLED RATES

Bas¡c Chq Demand çstrIlg4f Annuãl

$0 $251

AUG III3 PROPOSED BILLED RATES

Demând Commoditv AnnualLoad

Factor

Annual Use10m' MsI

Bâs¡c Chq

$168 $o $259

$513

.$r''27 1 96%2.45%

$8't 00't 98

Large Genera Sery æ

1

23156789l0'11

12l314l51617l8l92021

2223242526272ø29303l3233343536373839404142/Xl

1145¿t6

17/t8

49505l525354

Small General SeNiæ

Íyp¡æl Res¡dentisl Cßlúet)

High Volume Fim

3570

$168$168

$703$803 $971

$923 9i,091s2,841 $3,009

$3,1 78

$12,756s136,'t45

$419$66s

$181,051$164,656s265,480s517,540

s1,1 16,768

$2,255,708s125,044$15't,904s244,227s475,035

$1,023,738$2,066,646

$829$ss

$2,934

$2,314$12,146

$'138,8'11

$370,162$1,850,810

$3,701,6'19$370,162

$1,850,8 t0$3,70't,619$5.357,499

s11 1,098

$370,328$1,85't,639

$1 I 1,098

$370,328s'1,851,639

$894$997

5't,'t22$3,102

$3,238$13,070

$139,735

$¡15,956

$64,196$90,057

$488,603$23A2,625$4.750.'t53

$440,376$2,141,490$4,267,883$6,1 70,321

$1 53,619

w2,466$2,151,606

$135,392$41s,886

$2.018.706

s60$3'14

$3,590

$23$26$30$e3

1.88%2.46./2 640/.

2.640/0

2.7'lolo

277%3 09%

99113130400

280320368

11 33

850850

1,4162,8336,200

12,600685850

1,4162,8336,200

12,600

250350500

$168$168$168$168

$o$o$o$o

$0$0$o

$168$16S$168$168

$o$0$o

$0$o$0

I 1.3359.49

679.87

2,83314,16424328

2,A3314,1642A32841,000

4002,100

24,000

$924$924s924

s2,254$11,832

$135,221

$s24s924$924

CoopeEtive

Ma¡nline F¡m

Spec¡al Contract

Power Stations

lntetruptible Sales

25y.40%40%400/.

40%40%750/"

7sVo

75%75%75%

350/.

35%35%

40r/.40%40%75%75%75%75%

89%

1ô%

25V40D/.

40%75%750/.

750/o

421,289

15,196

850

30.00030,00050,000

100,000218,866444,79224,14'l30,00050,000

100,000218,866444,792

100,000500,000

'1,000,000

100,000500,000

1,000,0001,447,339

$13,420$ 13,420

$13,420$13,420$13,420$'r3,420$13.420$13,420$13,420$'t3,420$13,420$13,420

$3,289$3,289$3,289

$28,24O$28,240$28,240s24,240$28,240$28,240s28,240

$43,720627,325$45,542$91,084

$'199,351$405,133

s11,747$14,573$24,289$48,578

$106,321$216,071

$123,91 I$123,91 I$206,518$413,037$903,997

s1,837,156$99,877

$123,91 1

$206,518$413,037$903,997

$1,837,156

$14,769$14,769$14,769$'14,769$14,769

$14,769$14,769$14,769$'t4,769$14,769$14,769$14,769

$15,097$15,097$15,097$15,097$15,097$.15,097

$15,097

$1,45'1,669

$198,203

$59,565637,228$62,046

$124,093ï27'l,597$551,956$'r6,004$'r9,85s$33,091$66,183

$144,852$294,376

$1 13,065

$1 r3,0ô5$188,442$376,883$824,869

$1,676,347

$91,'l3s$1 13,065

$188,442$376,883$824,869

$1,676,347

$ 187,398

$1ôs,062$265,257$515,745

$1,1 I 1,235

$2,243,O72$121,907

$147,689$236,302$457,835$984,490

$1,98s,492

s6,347s406

($223)($1,7s5)($s,s33)

($12,637)($3,136)($4,216)($7,e25)

($17,200)($3s,248)($81,1 s4)

3.51%0.25%

-0 08%435%{.50%{.56%-2.5'l%-2.7A%-3.25V.-3.620/o

-3 83%-3 93%

-7 3510-5-59%-5 36%-5 1A%

-307%-2.79%-270%

8,825'12,355

17,650

s3'1,702

$44,382$63,403

$3,854$3,854$3,854

$11,826$16,5s7$23,652

s3'l,275$43,785$62,s50

$'Í,5'16$16,123

$23,032

$134,786$673,931

$1,347,862$7'1,886

$s59,430$718,860

s1.040,434

$o

$87,429

s21,223s44,2't5

$22't,O74$7,O74

$23,581$1 17,90ô

$46,506

$63,7s4$89,724

$s27.339$2,523,736$5,019,232

$464,439s2,209,235$4,390,230$6,341,520

$/149

$403$333

o.97%0.63%o 37./

$3ô4,313$1,821,565$3,543,130

$364,313$1,82'1,565$3,643,130

s5,272,A46

$103,3¿14

$516,719$'1,033,437

$55,'117$275,583$551,1 ô6

$797,725

$o

$14,978

$27,339s56,957

$284,786

$30,377$151,886

2.67%4 13./"4620/.{.06"/6-1.54%-2.10%

(s38,736)($141,1 I 1 )($26e,079)

($24,063)($67,745)

($122,347\($171,199)

($618,679)

(s592,003)

$3,993($s6o)

($13,474)($84)

-36.19%

-96.15%

't4,87'1,907 $1.625,097

536,433 $277,574

$84,2s8 $1,709,3ss

$250,734 $615,737

$115,890 $149,625$386,299 $443,026

$1,93't,494 $2,165,080$f15,890 $135,477s386,299 $422,393

$1,931,494 $2,061,913

942í29 s1,090,676

$'121,568 $23,735

2,833't4,164

8502,833

14,164

30,000100,000500,000

30,000100,000500,000

$12,513$1 2,513

$'r2,5'r3$12,513$12,513$12,5 t3

$1s,18'l$15,1 81

$15,181$'15,'r81

$15,181$15,1B'l

($6 507)(s43 207)

113

Centra Gas Man¡toba lnc.2013/14 General Rates Application - Cost of Gas Update May l0' 2013

Bill lmpact ComParison2013/14 Test Year

Updated Schedule 12.'1.0Page2 ot 2

May 10,2013

BASE ITPACTS

s %

BASE VS. BASE

LoadFactor

Annual Use10"m! t¡gf

MAY ,I/I3 APPROVED BASE RATES

Bas¡c Cho Demand Commoditv Annual

$265 s433

Basic cho

AUG I'13 PROPOSED BASE RATES

Demand Commod¡tv

$0 $271

Annual

100 $168$168

$43ss705

$7

$13

1 54./"'t-910À

40%40%40%400Ã

40%75%750/75%75%75%75%

35%35%35Vo

40%40%400/.

75%75%75./,750/o

89%

'16%

25%400/o

40%750/o

75%750/"

Large GeneE Sery ce

I231567I9l011

'12

1314l5l617't8l92021

2223212526272829303ltr2333435363738394041424:l4145¡¡6

47Æ4S505l52535¡l

Small GeneÉl SeNice

(TWiæl Resident¡61 Cusloñet)

High Volume Firm

CoopeEt¡ve

Mainl¡ne F¡m

Special ContEct

Power Slations

lntetruptible Sales

280320368

11 33

68

$9249924$924

$2,410$12,653

$1¿14,603

400

2,'10024,OOO

30,00030,00150,000

100,000218,866444,79224,14130,00050,000

100,00021 8,8664A4,792

'100,000

500,0001,000,000

100,000500,000

1,000,000'l,447,339

$0$o

$168$16870

't 13130400

$0

$o$0s0

$0$o$0

$'168

$168$168

5742$847$974

$2,997

$168$168$168$168

$868$999

$3,073

$'t3,420$13,420$13,420$13,420$13,420$13,420$13,420$13,420$13,420$13,420$ 13,420

$13,420

$28,240$2A,240s2s,24O928,24o$28,24o$28,240$24,240

$43,720$27,326$45.542$91,084

$199,351

$405,1 33

$11,747s't4,573s24,289$48,578

$106,321$216,071

$135,690$135,694s226,150s452,299$989,929

$2,01't,792$109,371s't35,690s226,150$452,299$989.929

$2,011,792

$192,830$176,440$285,1 I I$556,803

s'1,202,700s2,430,344

$134.538

$'163,683$263,8s8$514,297

s 1,109,670

$2,241,282

$1,015$1,142$3,165

s3,334$'t3,577

$145,s27

$49,97'l$68,645$96,6s4

$556,602$2,720,048$5,411,856

s503,70'ls2.405,547$4,782,854$6,909,780

$14,76s$14,769

$14,769$14,769$'14,769$14,769$14,769$14,769s14,769$14,769$'r4,769$14,769

$15.097$1s,097$15,097$'t5,097$15,097$15,097

$ 15,0s7

ï45,732$28,s83$47,637s95,275

$208,524$423,774

s12,287s15,244$25,4O7$50.8'13

$111,213s226,0't3

$1 1.826

$16,557$23,652

s131,061$6ss,304

$r.310,609$69,899

$349,496$698,991

$1,0't1,678

$135,549$135,553s225,915$4s1,829$988,900

$2,009,700s'109,2585135,549s225,915$451,829$988,900

$2,009,700

$2,450$12,861

$'146,987

s34,725$48,615$69,4s0

$407,354s2,o36,772$4,073,543

$407,354s2,036,772$4,073,543

$5,89s,800

$'t29,770$432,566

$2,162,831$129,770$432,566

$2,162,831

$196,049$r78,905$288,321$561,872

s't,212,'t92$2,448,243

$136,3'13$165,561s266,090$s17,411

$1,1 14,881

$2,250,4A2

$3,220

$2,465s3,209$5,070$9,492

$17,898

$1,776$1,87862,231$3,1 14

$5,212$9,1 99

($13,089)($12,875)($12,607)($1 1,351)

($4,182)

$4,778$12,795

1.67%'1.400/o

'1.'t3%

0.91%o79%o.740k't.32%'t.15%0.85%0.61%047%0.41%

-231V"-o 47%-o23%-225%4 170/.

0 10%0.19%

$0$o$0$o

$0$o$0

$3,374$13,785

$147,911

$40$209

$2,385

$19$21$25$76

1.'19%1.54%1.640/"

$l,036$1,167$3,241

2-06%2.11%2-150/.

239%

11 3359 49

679.A7

850850

1,41õ2,8336,200

12,600685850

1,4162,8336,200

12,600

250350500

$924$924$924

4,42512,35517,650

$3,289$3,28953,289

$35,167$49,233$70,333

s3,854$3,854$3,854

$'11,516

$16,123$23,032

s134,786$ô73,931

$1,347,462$71,886

$3s9,430$718,860

s1,040,434

$o

587,431

$403,57ss2,017,877$4,035,754

$403,575s2,o17,A77

s4,035,79$5,841,106

$50,406$69,026

$96,957

$434$382$303

o-a70/.

0.56%0 31%

2,83314,16428,328

2,83314,'1642A32841,000

$2't,223w,z'ts

s22',1,O74

s7,074$23,s81

$1 17,906

s22,274$46,403

ç232,0'17s7,425

$24,74A$123,742

$553,512$2,707,'173$5,399,249

$492,351$2,401,364$4,787,632$6,922,s7s

$167,224$494,1 s0

$2,410,028$152,375V72,495

$2,301,754

$6,082ï12,734$52,998

$s,381$11,713$¿7,891

377%2650/o2.250/o

3.66%2.54%2 12%

421,249

15,196

850

14,871,900 $1,625,097

536,442 $277,574

30,000100,000500,000

30,000100,000500,000

$84,258 $'1,709,355 $'1,45't,669

$250,738 $6',15,743 s198,203

$127,407 s't61í42$424,689 $481,416

$2,'t23,444 $2,357,030s127,407 $146,994$424,689 M60,783

$2123,444 52,253,862

$0

s14,676

$42j29 $1,493,798 ($21s,557) -1261o/.

$121,570 $334,449 ($281,294) 4s.68%

2,433't4,'t64

8502,833

14,164

$12,513$12,5 1 3

$12,51 3

$12,51 3

$1 2,s13

$1 2,513

$'t5,181$15,181$ 15,181

$15,181$1 5,181

$1 5,1 81

114

lkolisnik

Text Box

30

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.99

Subject:

Reference:

Tab 10 - Gas Costs

Tab 10 Pages 29 and 46 of 63

b) Please provide the actual (trued-up) UFG percentages for the past five years

ANSWER

Actual UFG percentages for the past five years are as follows:

Period

June 2007 to May 2008

June 2008 to May 2009

June 2009 to May 2010

June 2010 to May 2011

June 201 1 lo May 2012

Actual UFG %

0.68%

1.35o/o

0.73o/o

1.01%

0.52o/o

2013 04 12 Page 1 of 1

115

lkolisnik

Text Box

31

Centra Gas Manitoba Inc.2013114 General Rate ApplicationFixed Rate Primary Gas Service

Tab 13Page 2 of 11

February 22,2013

1

2

3

4

5

. November 13 to December 14,2012 (deliveries commencing February 1,2013)

. February I to March 11,2013 (deliveries commencing May 1, 2013)

The following table shows the rates associated with each FRPGS offering noted above

and Centra's quarterly Primary Gas rate in effect during each enrolment period.

13.1.1 Marketing

Centra currently provides FRPGS offerings once each quarter, with each marketing

period to commence shortly after the implementation of the quarterly Primary Gas rate

change. An offering was not available in November/December20ll with a February 1,

6

7

B

9

10

GentraFixed Rate ($/m3)

GentraQuarterly Rate ($/m3)

FRPGS Enrolment Period &Flow Date

$0.1548(May1-July31)

May 16 - June 9,2011(August 1, 2011 flow)

1-Year N/A3-Year $0.19755-Year $0.2095

1-Year N/A3-Year $0.19605-Year $0.2067

$0.1468(Aug. 1-Oct.31)

Aug.25-Sept. 13,2011(November 1, 2011 flow)

$0.1105(Feb. 1-Apr.30)

1-Year $0.15003-Year $0.1661

S-Year N/A

Feb.8-March13,2012(May 1,2012f\ow)

1-Year $0.13423-Year $0.1537S-Year $0.1649

$0.0880(May1-July31)

MayS-June 12,2012(August 1, 2012 flow)

$0.0e67(Aug. 1-Nov30)

1-Year $0.15233-Year $0.16945-Year $0.1807

Aug. 8 - Sept. 11,2012(November 1, 2012 flow)

1-Year $0.17063-Year $0.18155-Year $0.1912

$0.0e67(Nov. 1 -Jan.31)

Nov. 1 3 - Dec. 14, 2012(February 1,2013f\ow)

$0.0e67(Feb. 1 -Apr. 31)

1-Year $0.16903-Year $0.1804S-Year $0.1900

Feb. B -Mar. 11,2012(May 1,2013f\ow)

117

lkolisnik

Text Box

32

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.124

Subject:

Reference:

Tab 13 FRPGS

Tab 13 Pages 8 to 11 of 11

Please provide Centra's views on customer participation in the FRPGS compared to

the currently forecasted participation in a rising gas price environment (i.e. gas prices

rise more than currently forecasted).

NEB:Centra has been offering fixed rate primary gas products since 2009. Program history has

shown that customers are more likely to sign up for a Fixed Rate when primary gas prices

are higher. The following chart shows the number of new customers enrolled during each of

Centra's fixed rate offer periods compared to the corresponding Quarterly Rate at the time

of the offering. As illustrated, in recent quarters when natural gas prices have been low, few

customers signed up for Fixed Rate contracts.

It is anticipated that consumer demand for Fixed Rate products may increase slightly if

natural gas prices rise. However, a significant increase in demand, regardless of natural gas

price fluctuations, is not expected.

2013 04 12 Page 1 of 2

119

New Customers Contracts by Enrolment PeriodSo,3ooo

So,zsoo

So

So lsoo

s

So.osoo

So,oooo

180

160

140

t20

100

80

60

40

20

0

"t" ,""" ",1" "ùt "ùt "d) "d¡ "d) "..ù "d) "d? dP

"dl "S.\r- \r- \ì- .\t' \r' \r \ì .\' \r \ì .!' \,r \r \i

¡d oá t"o Sd sd €o .td ",." ros èd +o" *o +d tð

6oEo6ãIJoot¡E5z

.2000

0

0,oÉ,àoLt!

C,1000

\\I Y-aI \I

I

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRAI-124

2013 04 12 Page 2 of 2

120

Gentra Gas Íl'lan¡toba lnc.2013114 General Rate ApplicationFRPGS Enrolment Results for Fiscal 2011 8 2012

Enrolment Pr¡riod - l6 -June 2011

were

Enrolment Pr¡riod - 25 2011

subscription analys¡s were prepared.

Enrolment P,eriod - I - March I 2012

Enrolment Period - I - June 2012

Appendix 13.3

February 22,2O13

2011

yeal, year

2011

proxy

20'|2

2013

year, yearwere

gas no contracls or

2012

2012

Enrolment Period - I 11 2012

Enrolment Period - November l3 - December 2012

1 vear nla3 vear 14%

61%5 vear27%Total

Subscriotion Analvsis'Producl % Subscribed

29

Contrâcts for P

Product Res SGS Com SGSI vear nla nla nla nla

123 vear 0 012175 vear 0017

029ïotal

q nla nla

04 034

les SGS Com SGS LGS TotalContracts RECEIVED

Productnla1

133 vear 0 0 13

5 vear n21 o2100

Com SGS LGS Total

3150

1 vear 0

3 vear 25 03285 vear 125 o26

Contracts PROJECTED

iubscriotion AnalvsisProduct % Subscribed1 vear nla3 vear nla5 vear nla

nleTofal

nla nla nla1 vear nla

Contrects for ACTIVATIONProduct Res SGS Com SGS LGS Total

19

5 vear 214 218Total 233 338

Cônlrâcts RECEIVED

3 vear 024 125165 vear 2 220

240otal 345

Product Res SGS Com SGS LGS TotalI vear nla nla nla nla

Product Res SGS Com SGS LGS TotalContracts PROJECTED

1 vear nla nla nla n/a3 vear nla nla nla nla5 vear ¡la nla nla nla

¡laotal ¡la nla

Subscriotion AnalvsisProduct % Subscribed'I veer nla3 vear nla5 vear nla

nlaTotal

GS LGS Total

531

TTACTIVATIONCôntrâctsProducf Res S

11'1 vear 0 112153 vear 0 419

5 vear ¡la nla nla nla26Total

29

GS Com SGS LGS Totalles

0 545

Contracts RECEIVEDProd¡ rct

1 vear 015 1163 vear 0255 vear nla nla nla nlaTol;

Prôduct Res SGS Com SGS LGS Total

nlaTotal nla nla nla

Contracts PROJECTED

1 nla nla3 vear nla nla n/a nla5 vear nla nla nla nla

nlaTotal

Subscriotion Analvsis

5 vear nla

Prodrrct o/"Subscribed

1 vear nla3 vear nla

'l vear 01 01

Contracts for ACTIVATIONProducl Res SGS Com SGS LGS Total

3 vear 1 '1 025 vear 04 o4

16Total o7

ST

12

Contracts RECEProduct ResI vear 001

3 year 12 035 vear 8 008

11Total

:l Res SGS Com SGS LGS Total

nlaTotal nla nla nla

)ontmcts PROJECTED

nlaîla3 vear n/a n/a nla nla5 vear nla nla nla nla

Product % Subscribed'I vear nla3 vear nla5 vear ¡laTotal nla

Product Res SGS Com SGS LGS Total

06Total 06

Contracts for ACTIVATION

1 vear 1 0013 vear 03 035 vear 02 o2

Res SGS Com SGS LGS TolalI vear 0I 013 vear 6 0065 vear 04 o4

11 0ïotal 01

Contracts RECEIVED

nla

Product Res SGS Com SGS LGS TotalI vear ¡la nla nla nla3 veer nla nla nla nla

nla nla nla nla

SubscriDtion AnalvsisProduct % SubscribedI veer nla3 vear nla5 vear nla

nlaTotal

Total:om SGSrr ACTIVATION

0 o45 vear 0a 03

ConlraclsProducl Res SGS (

1 vear 000

3 vear 01 010 00

Res SGS Com SGS LGS TotalContracts RECEIVED

1 vear3 vear 2 0025 vear 05 05

07Total o7nlaTotal n/a nla nla

Contracts PROJECTEDProduct Res SGS Com SGS LGS TotalI vear nla n/a nla nla3 vear nla n/a nla nla5 vear nla nla nla nla

121

lkolisnik

Text Box

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Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I-120

Subject:

Reference:

Tab 13 FRPGS

Tab 13 Page2 of 11 - Results

For each completed FRPGS contract, please estimate the amount of additional or

reduced Primary Gas costs compared to the system supply Primary Gas costs,

assuming annual consumption for typical residential customers.

ANSWER

Please see the attachment to this response.

2013 04 12 Page 1 of 1

123

Centra Gas Manitoba lnc.2O1U14 General Rate ApplicationEst¡mated PG costs on completed FRPGS compared to system supply PG costs

Table 1

Estimated PG costs on completed 1 year contracts compared to system suPply PG costs

PUB,/Centra 120AttachmentPage 1 of 2

Apr¡l 12,2013

F¡xed Rate ContractStart Date

FRPGS

offerings

(S/m')Quarterly PG Quarterly PG

Effect¡ve Date Rates (5/m3)

Typical Res¡dent¡al

Quarterly/Monthly

consumption (m3)

Quarterly PG FRPGS offer¡ngsTotal Total

5364.64 5429.72

Szqz.qt S4s2.31

Difference

1-May-09 502670 1-May-09 50.24511-Aug-09 50.24941-Nov-09 SO.zzr:1-Feb-10 s0.2148

ss31.38 s633.8s 5t02.46

1-Dec-09 50.2389 1-Nov-09 50.2213 839 5486.67 Ss67.04 580.37

1-Feb-10 50.2148 834

1-May-10 sO.rA44 t771-Aug-10 50.1810 257

1-Nov-10 s0.1600 267

1-Feb-10 50.2679 1-Feb-10 S0.214S 834 s435.25 s636.02 5200.77

1-May-10 50.1844 I771-Aug-10 50.1810 257

1-Nov-10 s0.1600 1,106

1-May-10 50.2703 1-May-10 50.1844 r77 5395.81 5641.7s 5244.94

1-Aug-10 sO.rSrO 257

1-Nov-10 sO.rSOO 1,106

1-Feb-U s0.1687 834

1-Nov-10 50.1939 1-Nov-10 s0.1600 1,106 s382.78 s460.28 577-501-Feb-11 50.1687 834

1-May-11 50.1548 I771-Aug-11 sO.rqSS 257

177

257

7,106

834

1-Feb-11 So.rSOA 1-Feb-11 50.16871-May-11 50.1548

1-Aug-11 50.1468

1-Nov-11 50.14351-Mar-11 So.rgOS 1-Feb-11 50.1687

l-May-ll 50.15481-Aug-11 50.14581-Nov-11 50.14361-Feb-12 50.u05

834177

257

1,105

564.48

S108.83470

t77257

1,106

354

1-May-11 50.1913 1-May-11 S0.154S L77 5316.11 S4s4.0s 5737.941-Aug-11 50.1468 257

1-Nov-11 50.1436 1,105

1-Feb-12 s0.1105 834

1-May-12 sO.rSOO 1-May-12 s0.0S80 r77 s228.03 s356.10 s128.077-Aug-72 50.0967 2s7

1-Nov-12 50.0967 1,106

1-Feb-13 50.0957 834

124

Centra Gas Man¡toba lnc,2013/14 General Bate Appl¡cat¡onEstimated PG costs on completed FRPGS comParcd to system supply PG costs

Teble 2

Estimated PG costs on completed 3 years contracts compared to system supply PG costs

FRPGS

offerings Quarterlv PG Quarterly PG

Typìcal Residential

Quarterly/Monthly

PUB/Centra 120

AttachmentPage2ot 2

Aorll 12. 2013

F¡xed Rate ContractStart Date consum

Quarterlv PG

Total

FRPGs offer¡ngs

Total

1-May{9

1-Dec{9

1-Feb-10

1-May-10 s0.2833

Effective Date Rates

1-May-09 s0.2451

1-Aug-09 50.24941-Nov-09

1-Feb-10

1-May-10

1-Aug-10

1-Nov-10

1-Feb-11

1-May-11

1-Aug-11

1-Nov-11

1-Feb-12

1-Nov-09

1-Feb-10

1-May-10

1-Aug-10

1-Nov-10

1-Feb-11

1-May-11

1-Aug-11

1-Nov-11

1-Feb-12

1-May-12

I-AuE-721-Nov-12

S0.2213

50.2t4Bs0.1844so.181o

5o.16oo

So 1687

50.1s48S0.1468

s0.1436

50.2213

S0.2148

so.rg44so.181o

So.1600

s0.1687so.1s4850.1468

s0.1436

so.11O5

s0.0880

So 0967

s0.2148

S0.1844

50.1810

s0 1600

S0.1687

So.1s48

s0.1468

S0.1436

so.1105

s0 0880

So.0967

s0.1810

So.16oo

So 1687

So.1s48

S0.1468

s0.1436

s0.11osSo.088o

So.o967

s0.0967qo 0967

777

257

1,106

834

I77257

1,106

834

r77257

L,!06834

777

257

1,106

834

!77257

1,106

834

L77

257

1,106

a34

D¡fference

s2,303 25

s1,95s.9s s825.99839

834

777

257

1,106

834177

257

1,106

834777

257

267

834

777

257

1,106

a34t77257

1,106

834

177

257

s1,039.43 s2,052.56

.66

1-Feb-10

1-May-10

1-Aug-10

1-Nov-10

1-Feb-11

1-May-11

1-Aug-11

1-Nov-11

1-Feb-12

1-May-12

1-Aug-12

1-Nov-12

1-May-10

1-Aug-10

1-Nov-10

1-Feb-11

1-May-11

1-Aug-11

1-Nov-11

1-Feb-12

1-May-12

1-Aug-12

1-Nov-12

1-Feb-13

125

lkolisnik

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34

Centra Gas Manitoba lnc.2013114 General Rate Application

Centra Gas Manitoba Inc.Annual Report on Fixed Rate Primary Gas Service

Appendix 13.2

December 13,2012

Pase 5 of9(as of March 31 2012\

Financial Results by Product Offering (FY 2012)

FISCAL MARCH 3'1,2012 FINANCIAL RESULTS FOR FIXED RATE PRIMARY GAS PROGRAM OFFERINGS

Results reported ln 000's

I Year 3 Year 5 YearFiscal

Mar 3112012

Primary Gas Revenue

Less: Primary Cost of Gas Sold

Cost of Gas I

Hedge Cost for Delivered Gas 2

Total Cost of Gas Sold

Gross Margin

Under/Over Subscribed Hedge lmpacts 3

Program Operating Expense

Net Program lncome (loss)

Other Costs

Amortization of Start Up Costs 4

Mark to Market of Unsettled Hedges 5

Net lncome Statement impact

$20

($t s¡($s¡

($t o¡

$4 -154667$86 $49

$552

($287)

($17e)

$297 $870

($142) ($442)

($106) ($288)

($155) ($202)

($r os)

($17r)

FiscalMar 3'11201'l

$617

($353)

($207)

($238)

($2re)

($4oo)

-(szø- -F750)'($s6o)

$140

($s¡ ($++¡

($too¡

($420)

($1oo)

$52

($6er) ($448)

Notes and explanations:

1. The actual cost of gas for the period is derived by apply¡ng the Fixed Rate Primary Gas Service contract volumes to the actual average

unit cost of physical Primary Gas supplied to the load.

2. The hedge cost for delivered gas is the difference between the locked in cost of gas for each offering and the AECO monthly firm

market index price for each period, multiplied by the contract volumes consumed by customers. lt also includes hedge impacts on

over/under consumed volumes.

3. Under/Over subscribed hedge impacts are the amounts either paid to or received from counterparties associated with excess hedge

instruments due to under-subscription of offerings, as well as unhedged market pr¡ce exposure impacts on over-subscribed primary gas

volumes that have been subscribed but not hedged.

4. The amortization of start up costs represents 1 year of amortization of the deferred costs related to the introduction of the FRPGS

program. These costs are amort¡zed over a s-year per¡od with the annuel amortization being recorded against the FRPGS offêrings

made in each year.

S. The mark to market cost of unsettled hedges for flscal March 31, 201 2 are the amounts expensed in fiscal 201 2 relative to unreal¡zed

FRPGS hedges, During the future periods, these hedges will settle and net reelized gains or losses will be recorded at that time.

127

Centra Gas Manitoba lnc.2013114 General Rate Application

Centra Gas Manitoba Inc.Annual Report on Fixed Rate Primary Gas Service(as of March3l.2012)

Appendix 13.2

December 13,2012

Pase 6 of9

Observations (FY 2012)z

The Fixed Rate Primary Gas Service experienced a loss of S691,000 for FY 2012.It should be

noted that:

l. Of the $691,000 loss, $202,000 relates to the mark-to-market position of over/under

subscribed hedges and an additional $420,000 relates to the mark-to-market position ofunsettled hedges as at March 31,2012. These losses amount to 90o/o of the total program

loss for FY 20t2.2. Program operating expenses were $57,000 lower than forecast ($109,000 actual versus

S166,000 forecast).3. Actual program operating expenses of $109,000 were significantly lower than the actual

operating expenses incurred in previous fiscal years ($219,000 in FY 20lI and $354,000 inFY 2010).

4. The loss incurred in FY 2012 was primarily attributable to lower customer subscriptions

than forecast, along with a continued reduction in the market price of natural gas.

128

Centra Gas Manitoba lnc.2013114 General Rate Application

Centra Gas Manitoba Inc.Annual Report on Fixed Rate Primary Gas Service(as of March3I,2012)

Appendix 13.2

December 13,2012

Paee 7 of9

Financial Results by Fiscal Year

FINANCIAL RESULTS FOR FIXED RATE PRIMARY GAS PROGRAM OFFERINGS FROM INCEPTION TO MARCH 31 2012

Results reported in 000's

Prlmary Gas Revenue

Less: Primary Gost of Gas Sold

Cost of Gas 1

Hedge Cost for Delivered Gas 2

Total Cost of Gas Sold

Gross Margin

FiscalMar 31/2009

FiscalMar 3'l/2010

FiscalMa¡ 3112O11

FiscalMa¡ 3'112012

TotalResults

$0

$0$0

$3SS $617 $870 $1,875

($263) ($353) ($442) ($1,058)($65) ($207) ($288) ($560)

($328) ---T56ot -ls?3ot -l$1 F-ì¡t

$60 $57 $140 $257

Unsubscribed Hedge tmpacts 3 $0 ($76) ($238) ($202) ($516)

program operating Expense ($00¡ ($es+¡ ($219) ($109) ($748)

Net prosram tncome (toss) ------l$õõ -----lFãid-) ---l$4-dot ---($îi1) -l$1p-õ7t

Other Costs

Amortization of start up costs a $0 ($1 oo¡ ($100) ($1 00) ($300)

Mark to Market of Unsetfled Hedges u ,ttt, ($451) $52 ($420) ($897)

Net rncome statement lmpact -l$123t

--l$€=Ð -l$4-46I -]$60i) @-

Notes and explanations:

1. The actual cost of gas for the period is der¡ved by applying the Fixed Rate Primary Gas Service contract volumes to the actual average unit cost ofphysicaPrimary Gas supplied to the load.

2. The hedge cost for delivered gas is the difference between the locked in cost of gas for each offer¡ng and the AECO monthly firm merket index price for

eachperiod, multiplied by the coñtract volumes consumed by customers. lt also includes hedge impacts on over/under consumed volumes.

3. Under/Over subscribed hedge impacts are the amounts either paid to or received from counterparties essociated with excess hedge instruments due to

under€ubscription of offerings, as well as unhedged market price exposure ¡mpacts on over-subscr¡bed primary gas volumes that heve been subscribed but not

hedged.

4. The amortization of start up costs represents 1 year of amortization of the deferred costs related to the introduction of the FRPGS program' These costs

areamortized over a s-year per¡od with the annual amortization being recorded against the FRPGS offerings made in each year.

S.Themarktomarketcostofunsettledhedgesforfiscal MarchSl,2Ol2aretheamountsexpensedinfiscal 20l2relativetoFRPGShedges. Duringthe

futureper¡ods, these hedges will settle and the mark to market cost will be reversed.

129

lkolisnik

Text Box

35

Centra Gas Man¡toba Inc.2013114 Cosi of Gas Application

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/Centra l-127Aprll l, 2013

FRPGS Settled and Mark-to-Market Proiect¡ons lHedqinq In$ruments Onlv)

SETTLED RESULTS to March 31, 2013

May 1, 2009 (1 year ofiering)May 1, 2009 (3 year offering)May 1, 2009 (5 year offering)December 1, 2009 (1 year ofiering)December 1,2OOg (3 year offering)December 1, 2OOg (5 year offering)February 1, 2O1O (l year ofiering)February 1, 2O1O (3 year offering)February '1, 2O1O (5 year ofiering)May 1, 2O1O (1 year offering)May 1, 2010 (3 year offering)May 1, 2010 (5 year ofiering)November 1, 2O1O (1 year offering)Norember 1, 2O1O (3 year ofiering)Nor¡ember 1, 2O1O (5 year offering)February 1, 2011 (1 year ofiering)February 1,2011 (3 year offering)February 1, 2O11 (5 year offering)March 1, 2011 (1year ofiering)March 1, 2O11 (3 year offering)March 1, 2011 (5 year ofiering)May 1, 2011 (1year offering)May 1,2011 (3 yearoffering)May 1, 2011 (5 year offering)August 1,2011 (3 year offering)August 1, 2011 (5 year offering)

Total Settled Results

MARK-TO-MARKET PROJECTION (March 31, 2013 forward)

May 1, 2009 (5 year ofiering)December 1, 2009 (5 year ofiering)February 1, 2O1O (5 year offering)May 1, 2010 (3 year ofiering)May 1, 2010 (5 year offering)Nor,ember 1, 2O1O (3 year offering)Nor¡ember 1, 2O1O (5 year offering)February 1, 2011 (3 year offering)February 1, 2011 (5 year offering)March 1, 2011 (3 year ofiering)March 1, 2O11 (5 year offering)May 1,2011 (3 yearoffering)May 1, 2011 (5 year offering)August 1, 2011 (3 year offering)August 1, 2011 (5 year ofiering)

Total Mark-to-Market P rojection

Total lmpact on Retained Earn¡ngs Since lnception

Total

$$$$$$$$$$$$$$$$$$$$$$$$$$

(18 7e2)(104 879)(2OO 425',)

(42 e58)(14 687)(61 231)

(155 883)(83 411)

(12s 222)(e 33e)

(32 O47)(116 e11)

(2æ7)(16 115)(66 186)(1782)

(138 363)(71 716)(172e)

(52 460)(77 835)

(2 223)(6e 733)(1O 787)(24 3O4)

(7 28O)

$(1 512 94.5)

(3e 282)(15 78e)(46 41o)

(575)(52 634)

(1 01 1)(2e u2)(20 5e5)(37 618)(10 286)(48 471)(17 068)

(6 6e1)(6 06r )(4 256)

$ (336 089)

$ (1 849 034)

2013 04 12 Page 2 of 2

131

lkolisnik

Text Box

36

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.125

Subject:

Reference:

Tab 13 FRPGS

Tab 13 Appendix 13.2 Page 4 of 9 - FRPGS

Please update the schedule of FRPGS program operating costs on page 4lor 2012113

with budgeted and actual numbers.

ANSWER

The following table includes the FRPGS program operating budget for Fiscal Year 2012113.

Actual results for 2012113 are not yet available.

FY

2009ltoFY

20t2lt3FY

20tut2FY

aOLO|tL

Budeet Actual Actual Actual

5+z Ssss30 Ssz

Resu/ts reported in OÙO's

Labour

Marketing

Sqt$s Srz ss1Gas Supply

So.s s2 s14Business Comm unications $o

Srz s18So $o.sLoad Forecast

S+S¡ 52 s4CallCentre

So $1 Ss$oBilling

SS $zSo So.sAccounting

SOSo Ss 5ttRate Department

So.s Sr SrSoLegal

So$o So $oOther

s43

S144

s11

Sso

s11

$zg

s22

So¿

Overhead

MarketingAdvertising

Sr Sr $o $oMaterials & Administration

$o

Ss

So

So

so

So

s4

so

Promotional ltems

OtherComputer Software

Sgs¿S1o7 slos s21eTotal Costs

2013 04 12 Page 1 of I

133

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.126

Subject:

Reference

Tab 13 FRPGS

Tab 13 Appendix 13.2 Page 7 ol9 - PCR

a) Please provide the program administrative and start-up costs that were

recovered through the Program Gost Rate and the percentage recovery of the

total allocated program costs and start-up costs for the years 2008/09 through

to 2012113.

ANSWER:

For rate setting purposes, an initial estimate of the FRPGS Program administration cost was

established at the outset of the Program in 2009. That initial cost estimate, including the

amortization of program start up costs, was used to establish the level of the Program Cost

Rate that was embedded in the calculation of rates for each FRPGS offering. Revenues

were collected from participating FRPGS customers based upon that Program Cost Rate

The PCR will be updated as part of each GRA to reflect current cost estimates. The current

PCR of $26.2 per 103 m3 was approved in Order 128109 and is proposed as part of this

Application to change to $31 .4 per 103 m3 (Schedule 11.1.21ine 49).

Actual operating costs have generally been less than that originally estimated at the outset

of the Program. Centra has incurred those actual operating costs in each fiscal year, and

has obtained actual revenues from FRPGS customers based upon the volumes of gas sold.

As customer subscription rates and actual volumes sold have been less than forecast, there

have been insufficient revenues to offset all of the expenses incurred in each year. As with

20130412 Pagel of2

134

Centra Gas Manitoba lnc. 2013114 General Rate Application

all of Centra's costs of operation that are recovered through the volumetric rates, their

recovery is subject to volatility due to variances in actual consumption compared to forecast

consumption. Shortfalls that occur as a result of lower than forecasted volumes are

reflected in Centra's annual net income.

The table below identifies the actual operating costs of the Fixed Rate Primary Gas Program

compared to the actual costs recovered through the Program Cost Rate with the residual

flowing to Net lncome:

Program Operating Expense

Amortization of Start Up Costs

Total Program Administrative & Start Up Costs

Program Costs Recovered through the PCR

Residual

lo of Program Costs recovered through the PCR

1 FRPGS contra cts commenced on May 1, 2009

zorJ8læ

s 66,000

s

s 66,000

2 lrÛ 2Ûtoltl- zoLilLz Total

s 3s4,Ooo s219,ooo s1o9,oæ s 7l8,ooo

s loo,ooo sloo,ooo s 100,000 s ¡æ,ooo

s 4s4,ooo s319,ooo s209,000 s1,048,m0

s s 42,000 s 76,000 s1,10,000 s 37s,000

s 412,un s243,0æ s ee,æo s 816,000

9% 24% 53% 37/os 66,000

2013 04 12 Page 2 of 2

135

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA I.126

Subject:

Reference:

Tab 13 FRPGS

Tab 13 Appendix 13.2 Page 7 of 9 - PCR

b) Please determine the FRPGS Program Gost Rate necessary to recover the

current balance of unrecovered program costs since program inception in

addition to the currently forecasted program costs.

ANSWER

The only unrecovered program costs pertain to the unamortized Start Up Costs. The annual

amortized amount of these costs ($100,000) is reflected in the proposed Program Cost Rate

($3t.¿ per 103m3).

2013 04 12 Page 1 of 1

136

lkolisnik

Text Box

37

Centra Gas Manitoba lnc.2013114 General Rate Application Appendix 13.5

$12,000,000

$1r,000,000

$10,000,000

$9,000,000

$8,000,000

$7,000,000

Fixed Rate Primary Gas Service Base Gasecustomer Demand Scenario & 8% SRPGumulative Historical Program Risk Margin Distribution - Randomized Market Simulation Output

May 2000 through March 2011

-Mean

Results

-Best

Case Results

-Worst

Case Results

aottoJÈ $6,000,000.EoE_ $5,000,000g6

= $4,ooo,ooo

U'

T o.,ooo,ooo.¿6

= $2,000,000E3o $l,ooo,ooo

$o

($r,000,000)

($2,000,000)

($3,ooo,ooo)

($4,ooo,ooo)

d .f,,.Ê d dP./.f, d d.f .f, J d.f, "t' ./ d.f, dP .f,.t" .r'

I/t

/Jr

137

atU'o

c6o.EotG

=.Y.2É,o

sJ

Efo

$12,000,000

$10,000,000

$8,000,000

$6,000,000

$4,000,000

$2,000,000

$o

($2,ooo,ooo)

($4,ooo,ooo)

Centra Gas Manitoba Inc.201311 4 General Rate Application

PUB 128 (d) - Attachment I

Fixed Rate Primary Gas Service Base Case Customer Demand Scenario & 5olo SRPGumulative Historical Program Risk Margin Distribution - Randomized Market Simulation Output

May 2000 through March 2011

-Mean Results

-Best Case Results

-Worst Case Results

O O - C\t N (rJ (f) $ $ lf) lfJ (O (O t- F- @ O O) O) O OoOOOOooOOOOoOOOOOOOOTE* i * i s. * * 9 *, i i i i, i * i t * å * å i(50(Ú0(Ú0(E0(Ú0(U0(E0(Ú0(u0(U0(U0

138

Centra Gas Manitoba Inc.2O1Aß General Rate Application

PUB 128 (d) - Attachment ll

Fixed Rate Primary Gas Service Base Case Customer Demand Scenario & 12% SRPCumulative Historical Program Risk Margin Distribution - Randomized Market Simulation Output

May 2000 through March 2011$14,000,000

$12,000,000

anano

c6oc'ó(E

=-v.!!É,o.¿-g¿E¿()

$10,000,000

$a

$o

,000

,000

,000

,000

$4,000,000

$z ,000 000

$o

($2,ooo,ooo)

($4,000,000)O O r N C! í) (r) :t :t tO lO (O (O F- F* @ @ O, O) O OOOOOOOOOOOOOOOOOOOOOTF*i *9 *9 i,9 *i Ei Ei i+ ii *i *9oo(Ú0(E0(U0(Ú0(E0(õ0(Ú0(E0(Ú0(U0

-Mean Results

-Best case Results

-worst case Results

139

lkolisnik

Text Box

38

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA II.184

Reference: PUB/Central-127 - FRPGS Mark to Market

In light of the reported updated settled and unsettled results, please indicate to what

level the balances have to reach to trigger the proposed review of the program based

on the million-dollar threshold established

ANSWER:

Please see the table below. The proposed $1 million threshold includes results of the

FRPGS offerings that did not use hedging instruments (i.e. commencing with the November

1,2011 flow offering). Please note that the information contained in the referenced response

to PUB/Centra l-127 reflects FRPGS hedging impacts only. As the $1 million settled and

unsettled thresholds are with respect to risk margin results (i.e. Total FRPGS program

revenues less program cost rate revenues, minus FRPGS WACOG, plus or minus hedging

impacts if applicable), additional information has been included in the table in order to

illustrate risk margin results as at March 31,2013.

2013 05 07 Page 1 of 2

141

Centra Gas Manitoba lnc. 2013114 General Rate Application

PUB/CENTRA II-184

FRPGS Risk Margin as March 3t,2Ot3Relative to S1 Million Risk Margin Thresholds Calculated From the Inception of Self-lnsurance

FRPGS Revenue (Not lncl. Program Cost Rate Revenue)

Less FRPGS WACOG

FRPGS Gross Margin (Not lncl. Program Cost Rate Revenue & Hedge lmpacts)

Hedging lmpact

Risk Margin as @ March 31, 2013

Settled

52,47o,35s

Sr.soo.sgz

5969,763(sr-.s12.94s)

(s543,1821

Unsettled Mark-to-Market

5r,382,s2tSr,o+s.eoz

S336,914(s336.08e)

$gzs

529,282

(s1.029.282)

I$1*028-452I

Risk Margin on Unhedged Offerings From November 2Oll through February 2013 (lncluded Above) $50,146

Further Dreterioration in Risk Margin Required to Reach St Vlilt¡on Threshold (s1.0s0,1461

Net Risk Margin Balance @ $1 M¡ll¡on Threshold Calculated From the lnception of Self-lnsurance 151,593328)

20't3 05 07 Page 2 o1 2

142

lkolisnik

Text Box

39

December 2,2008Order No. 156/08

Page 60 of 73

allocation model would result in a much larger PCR in the initial years with a

decreasing rate in subsequent years. Because of the averaging that Centra has

proposed, at any point in time the PCR may not exactly reflect the cost to provide

the service. The Board agrees with CAC/MSOS that Centra's suggested

approach of using the five-year average cost and the five year average volume is

appropriate and will not penalize customers in the initial years that would

otherwise bear a disproportionate amount of the program costs'

Over time and on average, the PCR will reflect the cost to provide the fìxed price

offering service. The Board hereby approves Centra's modification of its cost

allocation model and the resulting allocation of costs to the fixed price offering

program.

6.6.2. Regulatory Cosfs

On page 94 of Order 160107, the Board commented:

"Not needing to include a profit margin in the price of its offerings is amajor advantage that Centra has over retailer offerings. The Board notesthat this is partially offset by regulatory costs that would be priced into theirofferings."

Centra, in response to PUB/Centra 21(a), states that regulatory costs are not

included in the program costs because regulatory activities are undertaken for

the benefit of all customers and are thus recovered from all customers in the

distribution rate.

Centra has incurred regulatory costs in the preparation of this Application,

responses to information requests, and Centra's final submission. These costs

are, for the most part, labour costs and Centra states that they are non-

incremental. As well, Centra will incur regulatory costs in the future when it

undertakes its reporting activities.

The Board draws a distinction between regulatory costs incurred in offering fìxed

price ofi-erings and the additional costs for faciiitation of the WTS. ln the 2007

Competitive Landscape proceeding, the Board reviewed the allocation of these

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December 2,2008Order No. 156/08

Page 61 of73

additional costs for facilitation of the WTS, which included a premium for the

additionalflexibility in the Nexen gas supply contract, the additional bad debt

expense related to the agency, billing, and collection (ABC) service, and costs to

administer and process Direct Purchase enrolments.

Centra had argued that these costs were incurred for the benefit of the

marketers, and thus they should be borne by the marketers. ln Order 160i07 (p

66-67), the Board disagreed with Centra and ordered they continue cross-

subsidization of these costs by all ratepayers, as the benefits of increased choice

flow to all consumers.

Notwithstanding Centra's assertion that its regulatory costs are incurred for the

benefit of all consumers, the regulatory activities of Centra for the provision of

fixed price offerings provide a benefit to Centra's fixed price offering customers.

The marketers also incur regulatory costs which could be argued are for the

benefit of giving all customers more choice, but the marketers have historically

paid their own regulatory costs. Centra must compete with the marketers, and

this means that each participant must bear their own regulatory costs.

Therefore, the Board requires Centra to include its regulatory costs - both the

costs incurred to date and anticipated future regulatory costs - in its cost

allocation model. This will yield a new PCR, which Centra must submit to the

Board for approval.

6.6.3. Double Allocation of Cosfs

An issue arose during the current proceeding concerning Centra allocating staff

and their associated costs to the fìxed price offering program that had already

been allocated to the distribution rates for all customers. Centra states that this

"double counting" is not material, and it will be addressed in the next General

Rate Application (GRA), that to occur in 2009.

144