PETITION ER'S - IURC Online Services Portal

Petitioner's Exhibit No. 1 Cause No. 37366-GCA 151

CEI South of 10

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

d/b/a CENTERPOINT ENERGY INDIANA SOUTH

(CEI SOUTH)

IURC PETITION ER'S

IURC CAUSE NO. 37366-GCA151 ik!'JW:....;;zzL ~

DIRECT TESTIMONY

OF

KA TIE J. TIEKEN

DIRECTOR, REGULA TORY AND RATES

SPONSORING PETITIONER'S EXHIBIT NO. 1,

ATTACHMENTS KJT-1 THROUGH KJT-4

I Ri,O

1 I.

2

3 Q.

4 A.

5

6

7

8 Q.

9 A.

10

11

12

13

14 Q.

15 A.

16

17

18

19

20 Q.

21 A.

22

23

24 Q.

25 A.

26

27

28

29

30

31 Q.

32


CEI South of 10

DIRECT TESTIMONY OF KA TIE J. TIEKEN

INTRODUCTION

Please state your name and business address.

Katie J. Tieken

211 NW Riverside Drive

Evansville, Indiana 47708

By whom are you employed?

I am employed by Vectren Corporation, a wholly-owned subsidiary of CenterPoint Energy,

Inc. ("CenterPoint"). Southern Indiana Gas and Electric Company d/b/a CenterPoint

Energy Indiana South ("Petitioner", "CEI South" or "the Company") is an indirect subsidiary

of CenterPoint.

What position do you hold with Petitioner GEi South?

I am Director, Regulatory and Rates for CenterPoint, the ultimate parent company of CEI

South. I hold the same position with two other utility subsidiaries of CenterPoint- Indiana

Gas Company, Inc. d/b/a CenterPoint Energy Indiana North ("CEI North") and Vectren

Energy Delivery of Ohio, Inc. d/b/a CenterPoint Energy Ohio ("CEOH").

Please describe your educational background.

I am a 2001 graduate of the University of Evansville with a Bachelor of Science degree in

Business Administration with double majors in finance and mathematics.

Please describe your professional experience.

From 2002 to 2007, I was employed by EG&G Technical Services as a financial analyst and

contract administrator. Since October 2007, I have been employed with CenterPoint Energy

in various regulatory capacities. In 2015, I was named Manager, Rates. In February 2019,

I was named to Manager, Regulatory and Rates. I was named to my current position in April

2021.

What are your present duties and responsibilities as Director, Regulatory and

Rates?

1 A.

2

3

4

5

6

7 Q.

8 A.

9

10

11

12

13

14

15

16

17

18 Q.

19 A.

20

21

22

23

24

25

26 Q.

27 A.

28

29

30

31

32

Petitioner's Exhibit No. 1 Cause No. 37366-GCA151

GEi South of 10

I am responsible for the Indiana and Ohio regulatory and rate matters of the regulated

utilities within CenterPoint in proceedings before the Indiana and Ohio utility regulatory

commissions. I also have responsibility for the implementation of all regulatory initiatives

of CEI South (and other utility subsidiaries in Indiana and Ohio), as well as the preparation

of regulatory and rates exhibits submitted in various regulatory proceedings.

Have you ever testified before any state regulatory commission?

Yes. I have testified before the Indiana Utility Regulatory Commission ("IURC" or

"Commission") on behalf of CEI South in its Gas Cost Adjustment ("GCA"), Cause No.

37366, beginning in GCA 147. I have also testified on behalf of GEi South in its Fuel

Adjustment Clause ("FAG"), Cause No. 38708, beginning in FAC126, in Cause No. 43354

(MISO Cost and Revenue Adjustment ("MCRA"), beginning in MCRA23 and in Cause No.

43406 (Reliability Cost and Revenue Adjustment ("RCRA"), RCRA 18. In addition, I have

testified on behalf of GEi North in its GCA proceeding Cause No. 37394, beginning in GCA

147. Most recently, I have testified on behalf of GEi South in its general gas base rate case

proceeding, Cause No. 45447 and GEi North Cause No. 45468.

What is the purpose of your testimony in this proceeding?

My testimony addresses: 1) GEi South's request for approval of changes in its GCAs for

the period August, September, and October 2021 ("the GCA period"), 2) GEi South's

request for authority to "flex" these GCAs up and down, consistent with the Order in Cause

No. 44374 that was approved by the Commission on August 27, 2014, and 3) GEi South's

proposal to recover variances resulting from the February 2021 Winter Storm Uri which are

included in the reconciliation of this GCA proceeding.

Are you sponsoring any attachments?

Yes, I am sponsoring the following attachments in this proceeding:

• Petitioner's Exhibit No. 1, Attachment KJT-1: Appendix A, GCA tariff sheet

• Petitioner's Exhibit No. 1, Attachment KJT-2: GCA calculation Schedules 1 through

14 as proposed under the Company's alternative recovery method

• Petitioner's Exhibit No. 1, Attachment KJT-3: GCA calculation Schedules 1 through

14 under the traditional recovery method

1

2

3

4 Q.

5 A.

6

7

8 II.

9

10

11 Q.

12 A.

13

14

15

16

17 Q.

18 A.

19

20

21

22

23

24

25

26

27

28

29


CEI South of 10

• Petitioner's Exhibit No. 1, Attachment KJT-4: Supporting calculation of CEI South's

proposed alternative approach

Were your testimony and attachments prepared by you or under your supervision?

Yes, they were.

PETITIONER'S EXHIBIT N0.1 ATTACHMENTS: TARIFF SHEET AND GCA

SCHEDULES

Please describe Attachment KJT-1.

Attachment KJT-1 contains Appendix A, the tariff sheet setting forth the estimated GCAs

proposed to be effective for the GCA period. The Company plans to update the entire Tariff

for Gas Service with the new assumed business name 1 within the Compliance Filing in its

pending general gas rate case, Cause No. 45447.

Please describe Attachment KJT-2 and Attachment KJT-3.

Both Attachment KJT-2 and Attachment KJT-3 contain GCA calculation Schedules 1

through 14, including the sales forecast for the twelve months ending July 2022.

Attachment KJT-2 reflects the quarterly GCA under the Company's alternative recovery

method as described in greater detail below.

Attachment KJT-3 reflects the quarterly GCA as calculated in accordance with the

Commission's Order in Cause No. 44374, where monthly variances are recovered over a

twelve-month period through a per-therm charge incorporated into the GCA factors

("Traditional GCA Recovery").

1 As of January 25, 2001, Southern Indiana Gas and Electric Company d/b/a Vectren Energy Delivery of Indiana, Inc. (formerly known as "Vectren South") operates under a new assumed business name Southern Indiana Gas and Electric Company d/b/a CenterPoint Energy Indiana South ("CEI South")

1 Ill.

2

3 Q.


CEI South of 10

MONTHLY UPDATES TO GAS COST ESTIMATES FOR MARKET PURCHASES

Has CEI South estimated prices for its projected market purchases for the GCA

4 period?

5 A.

6

Yes. CEI South's estimates August, September, and October 2021 are based on current

New York Mercantile Exchange ("NYMEX") prices for these months. Estimated market

7 purchases have been priced at NYMEX prices on a day no more than six (6) business

8 days prior to the filing of the revised GCA schedules included in this quarterly GCA filing.

9 This estimated price is referred to as the "initial market price".

10

11 Q.

12

13 A.

What is CEI South's proposal to reflect changes in the market price of gas via a

pricing and monthly flex adjustment to its estimated GCA?

CEI South will file a monthly flex (the "flex") each month to adjust the GCA for the

14 subsequent month. The flex will follow the Commission's Order for Cause No. 44374 and

15 will be filed no less than three (3) days before the beginning of each calendar month during

16 the GCA period. Market purchases in the flex will be priced at NYMEX prices on a day no

17 more than six (6) business days prior to the beginning of said calendar month. In each

18 flex, changes to the initial market price will be limited to a maximum adjustment (up or

19 down) of $1.00 from the initial market price.

20

21 Q.

22

23 A.

24

25

26 IV.

27

28 Q.

29

30 A.

31

Does this flex methodology proposal differ from that in effect in Cause No. 37366-

GCA 150?

No.

RECONCILIATION OF PRIOR PERIOD GAS COST VARIANCES

Does the applied-for GCA reflect the reconciliation of gas costs recovery and gas

costs incurred for a previous period?

Yes. The applied-for GCA reflects the reconciliation of gas cost recovery and gas cost

incurred for the months of December 2020, January 2021 and February 2021 (the

32 "Reconciliation Period").

33

1

2

Q.

3 A.

4

5

6

7

8 Q.

9

10 A.

11

12

13

14 Q.

15

16 A.

17


CEI South of 10

Was there an over- or under- collection of GCA revenues for the Reconciliation

Period?

Yes. CEI South experienced an under-collection of $18,895,4262 for the Reconciliation

Period. The majority of the under-collection is attributed to the month of February 2021. In

fact, of the $18,895,426 in total under-collection, $17,921,0233 is attributable to the month

of February 2021.

What was CEI South's estimated cost of gas per Oekatherm ("0th") sold compared

to the actual cost of gas per Oekatherm ("0th") sold for the Reconciliation Period?

The following table sets forth a comparison of CEI South's estimated and actual gas cost

per Dth sold for the Reconciliation Period.

Estimated Total Monthly Difference of Actual Total

Commodity Cost Actual Total Monthly Total Monthly Monthly Sales in

(Sch. 1 Pg. 1 Line 12 of Commodity Cost Commodity Cost 0th

Month Monthly Flex Filings) (Sch. 6 Line 7) per 0th Sold (Sch. 6 Line 1)

.

December 2020 $ 4,389,831.00 $ 4,127,308.00 $ (262,523.QQ) , •... 1,755,226

January 2021 $ 6,332,853.00 $ 5,770,639.00 $ (5§2,214.00) 2,030,794 .....

February 2021 $ 5,197,273.00 $ 24,541,585.00 $ 19,344,312.00 2,225,816

Actual Commodity Cost per

Estimated Commodity Cost Dth Sold Estimated vs. Percentage

per 0th Sold (Actual Monthly Actual Difference of

(per monthly flex filing Sch. Commodity Costs divided Commodity Cost Actual

Month 1 Pg. 1 Line 14) by Actual Monthly Sales) per Dth Commodity

December 2020 $ 2.171 $ 2.351 $ 0.180 8.31%

January 2021 $ 2.473 $ 2.842 $ 0.369 14.90%

February 2021 $ 2.683 $ 11.026 $ 8.343 310.95% ...... ... ------

Please describe the extreme weather event that led to high gas prices and the under

collection of revenues during February 2021.

From February 13 - 16, 2021, a large swath of the country was hit by a major winter and

ice storm unofficially referred to as Winter Storm Uri ("Uri"). The storm resulted in the

2 GCA 151 variance consists of$18,579,337 in Commodity, $119,568 in Bad Debt Gas Costs, $747,078 in LIFO Adjustments including Bad Debt Cost of Gas LIFO Adjustment, and $(550,557) in Demand. 3 February 2021 variance consists of $18,268,450 in Commodity, $116,154 in Bad Debt Gas Cost, and $(463,581) in Demand.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16


CEI South of 10

issuance of winter weather alerts by the National Weather Service and blackouts for

millions of people in the United States. Uri contributed to a severe cold wave that affected

most of North America.

A combination of significant disruptions in natural gas supply combined with a sharp rise in

natural gas demand - all due to the arctic cold temperatures across much of the country -

led to an extraordinary increase in natural gas spot market prices, as discussed by

Petitioner's Witness Grizzle. Though natural gas prices have since stabilized, CE! South

incurred approximately $19. 7 million in costs to purchase necessary gas supplies for its

CE! South customers between February 12 and February 22, 2021 (the "February Market

Event"). The February Market Event affected not just CenterPoint4, but utilities across the

country. It was the culmination of unprecedented circumstances that resulted in high spot

market prices for natural gas across the country. On February 12, 2021, gas daily spot

prices surged to all-time record highs as freezing temperatures impacted nearly every

state.

17 Q. How are monthly variances between the forecasted price of gas and the actual prices

of gas typically recovered as part of CE! South's GCA process? 18

19 A. In accordance with the Commission's Order in Cause No. 44374, monthly variances are

recovered over a twelve-month period through a per-therm charge incorporated into the

GCA factors ("Traditional GCA Recovery").

20

21

22

23

24

Q. What is CEI South's proposal in this GCA to recover the variances for February

2021?

25 A. CE! South is proposing an alternative approach to recover the February 2021 variance

over 12 months, which is similar to the alternative approach the Commission recently

approved for Northern Indiana Public Service Company ("NIPSCO") in Cause No. 43629

GCA 585 . Fifty percent of the February 2021 variances (commodity, bad debt gas costs,

and demand) will be recovered evenly over the 12-month period August 2021 through July

26

27

28

29

4 Reference to CenterPoint indicates not only CEI South, but also other jurisdictions served within CenterPoint's service territory. 5 The Commission approved "the 12-month alternative reconciliation process NIPSCO proposed under which the variance created during February 2021 will be split evenly between a fixed and a variable calculation" (In re N. Ind. Public Service Co, Cause No. 43629 at 11 (IURC 5/26/21)).

1

2

3

4

5 Q.

6

7 A.

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22 Q.

23 A.

24

25

26

27

28

29

30

31 Q.

32

33


CEI South of 10

2022. The remaining fifty percent of the variance will be recovered using a volumetric

allocation over the same 12-month period. The supporting calculation of CEI South's

proposed alternative approach is included as Petitioner's Exhibit No. 1, Attachment KJT-4.

Why is CEI South proposing this alternative approach to recovery of the February

2021 gas costs?

Winter Storm Uri was an extraordinary event that occurred at a time when Hoosiers were

already experiencing economic hardships resulting from the COVI D-19 pandemic.

Petitioner's Witness Grizzle explained that prices at delivery points to Indiana increased

dramatically to as much as $65.60 per dekatherm for Rockies Express Pipeline, Zone 3,

on February 13-16, in comparison to the February weighted average cost of gas of $3.17

per dekatherm included in the GCA 149 flex filing. As I stated earlier, the result of Winter

Storm Uri was a net under-collection of $18,895,426 for the Reconciliation Period. The

February 2021 portion of this under-collection was $17,921,023. Recovering the February

2021 under-collection through the approved per-therm charge results in an increased

impact on customers during the winter heating season when their gas usage is the highest.

Accordingly, CEI South has been considering alternate methods to mitigate this rate impact

and considers this 50/50 approach to be in the customer's best interests. By spreading 50

percent of the February 2021 variance evenly over the 12-month period, it mitigates the

costs the customer will experience in the winter heating season.

Did CEI South consider any other alternatives?

Yes. CEI South considered the Traditional GCA Recovery and also an extended recovery

period beyond the typical 12-month period. The Traditional GCA Recovery would lead to a

an increase in customers' bills during the winter heating season. An extended recovery

period beyond the typical 12-month period is inconsistent with Ind. Code § 8-1-2-

42(g)(3)(D) and Commission findings related to that statute. Additionally, an extended

recovery period presents multiple factors that have the potential to negatively impact

customers. The Company decided to request approval of the alternative approach.

Please further describe why an extended recovery period beyond the typical 12-

month period is inconsistent with Ind. Code § 8-1-2-42(g)(3)(D) and Commission

findings related to that statute.

1

2

3

4 5 6 7 8 9

10

11

12

13

14

15

A.

16 Q.

17

18 A.

19

20

21

22

23

24

25

26

27

28

29

30 Q.

31 A.

32


CEI South of 10

Ind. Code § 8-1-2-42(g)(3)(D) states that the Commission must find the following before

granting a gas utility the requested gas cost charge:

The utility's estimate of its prospective average gas costs for each future recovery period is reasonable and gives effect to: (i) the actual gas costs experienced by the utility during the latest recovery period for which actual gas costs are available; and (ii) the actual gas costs recovered by the adjustment of the same recovery period. ( emphasis added).

The Commission affirmed this linkage in its most recent review of the GCA practices. In re

IURC's Investigation into Existing Gas Cost Adjustment Procedures and Schedules,

Cause No. 44374 (approved August 27, 2014). In responding to a request for annual filings

for small gas utilities, the Commission held that "[v]ariances created during an annual filing

will take longer to be recovered from/returned to customers." Id. at 20.

Please describe the factors that an extended recovery period will present that have

the potential to negatively impact customers.

An extended recovery period presents three main factors that have the potential to

negatively impact customers:

1. An extended recovery period would likely span across, and lead to increased customer

rates for, two winter heating seasons.

2. With customer turnover during the extended recovery period, customers new to the

system (who did not use the gas purchased in February 2021) would still be paying

the increased rates.

3. If an extended recovery period were approved, the Commission should authorize the

Company to recover associated carrying costs for financing gas costs over a long

period. Such carrying costs 6 would further increase rates for customers.

Under CEI South's alternative proposal, how will customers be impacted?

The chart below compares the bill impacts of average residential customer using 658

therms per year under the Traditional GCA Recovery, as well as the "alternative" 50/50

6 Estimated carrying costs on the extended recovery period (months 13-24) are approximately $800,000 using the most recently approved weighted average cost of capital of 6.28% from Cause No. 44429-TDSIC 13.

1

2

3

4

5

6

7

8

9

10

11

$30.00

$25.00

$20.00

$15.00

$10.00

$5.C(l

V.

Q.

A.

$-

Petitioner's Exhibit No. 'I Cause No. 37366-GCA 151

GEi South of 10

approach. As shown in the chart below, the alternative 50/50 proposed approach will result

in slightly higher collections in the summer months, when natural gas usage is lower, but

will lessen the impact of the increase during the winter heating season, when natural gas

usage is highest. The alternative 50/50 proposed approach is in the customers' best

interest.

February 2021 Variances Average Residential Bill Impact

$26.48

$6.33 $5.75

$3-02

$1.95

Aug-21 Sep-21 Oct-21 Nov-21 Dec-21 Ja.n-22 Feb-22 Mar-22

>:·.Traditional GCA Reco\i'e1y =Alternative 50/50 Approach

CONCLUSION

Does this conclude your direct testimony?

Yes, it does.

$5.75 $5.60

$1.95 $1.89

Apr-22 fvlay-22 Jun-22 Jul-22

STATE OF INDIANA

) SS:

COUNTY OF VANDERBURGH }

The undersigned, Katie J. Tiel<:en, being duly sworn, under penalty of perjury affirms that the

foregoing Direct Testimony in Cause No. 37366-GCA151 is true to the best of her knowledge,

infor111ation and belief.

' I \\ ,/ \\ \\

~r ?it \ {~tl j~<} __ ~

K~tie J. Tleken(J

Cause No. 37366-GCA151

Petitioner's Exhibit No. Attachment KJT-2

GEi SOUTH DETERMINJ.\TION OF GAS COST ADJUSTMENT (GCA)

WITH DEMAND COSTS ALLOCATED

FOR THE PERIOD AUGUST 2021 THROUGH OCTOBER 2021

Commodity and Other Line ESTIMATED COST OF GAS TO BE RECOVERED No.

Purchased Gas Costs (Schedule 3)

2 Contract Storage & Transportation Costs (Schedule 4)

3 Cost of Gas (lnj.)/With. From Storage (Schedule 5)

4 Total Estimated Gas Costs

5 Estimated Cost of Unaccounted For Gas [2]

6 Net Cost Of Gas To Be Recovered

I COMMODITY COSTS TO BE RECOVERED

7 CommodityVariance-(Schedule 12B (pg. 2 of2), Line 13 TOTAL)

8 1/4 of Excess of NOi Above Authorized NOi

9 Commodity Variance per Dth of Sales ((Line 7 + Line BJ/Schedule 2 Sales)

10 Commodity Dollars to be Refunded (Schedule 12A, Line 12)

11 Commodity Refund Per 0th (Line 10/Schedule 2 Sales)

12 Commodity Gas Costs (Line 6)

13 Monthly Commodity Gas Costs Per Dth (Line 12/Schedule 2 Sales)

14 Total Commodity Cost Per Dth of Sales (Lines 9 + 11 + 13)

Demand [1] August-21 A B

$1,317,998 $2,284,122

$0 $0

$0 ($1,794,061)

$1 317,998 $490,061

N/A $4,411

$1,317,998 $490,061

$919,967

$0

$5.935

$0

$0.000

$490,061

$3.162

$9.097

[1] The Demand portion of Purchased Gas Costs and Contract Storage & Transportation Costs were determined by multiplying the quarterly sales quantities for each rate class by the per 0th costs listed on Schedule 1A

[2] For informational purposes only (Line 4 • 0.9%).

September-21 C

$2,550,849

$0

($1,730,336)

$820 513

$7,385

$820,513

$1,029,217

$0

$3.884

$0

$0.000

$820,513

$3.096

$6.980

October-21 D

$2,106,607

$0

($1,109,328)

$997,279

$8,976

$997,279

$1,093,773

$0

$3.314

$0

$0.000

$997,279

$3.022

$6.336

Schedule 1 Page 1 of3

$8,259,576

$0

($4,633,725)

$3,625,851 1

$20,772

$3,625,851

$3,042,958

$0

$0

$2,307,853


Petitioner's Exhibit No. 1 Attachment KJT-2

CEI SOUTH DETERi\/liNATiON OF GAS COST ADJUSTMENT (GCA)

Line (A) No. DEMAND RELATED COSTS TO BE RECOVERED Total

15 Demand Cost Variance (Schedule 12B (pg 1 of 2), Line 13 Total ($87,980)

16 Demand Variance Per Dth (Line 15 / Schedule 2 Sales) ($0.117)

17 TOTAL Current Demand Costs Per 0th (Schedule 1A, Line 3)

18 TOTAL Demand Costs Recovered Per Dth of Sales (Line 16 + Line 17)

IBAD DEBT GAS COSTS TO BE RECOVERED August-21

19 Total Commodity and Demand Costs $762,428

20 Bad Debt Gas Costs (Line 19 * 0.65%) $4,956

21 Bad Debt Cost Component per Dth (Line 20/Sch. 2 Sales) $0.032

IGCA DERIVATION August-21

22 Total GCA Charges (Lines 14 + 18 + 21) 22a Rate 110/120/129 $10.769

GAS COST ADJUSTMENT MODIFIED FOR 23 UTILITY RECEIPTS TAX -- $/DTH 23a Rate 110/120/129 with IURT (Line 23a / .9853) $10.930

*IURT Rate Effective 1/1/21 is .9853

(B) Rate 110/120/129

$1.757

$1.640

September-21

$1,286,180

$8,360

$0.032

September-21

$8.652

$8.781

Schedule 1 Page 2 of 3

October-21

$1,577,243

$10,252

$0.031

October-21

$8.007

$8.126

Cause No. 37366-GCA 151

Petitioner's Exhibit f\Jo. 1 Attachment l<JT-2

CEI SOUTH DETERMINATION OF GAS COST ADJUSTMENT (GCA)

FOR THE PERIOD AUGUST 2021 THROUGH OCTOBER 2021 ($/Dth)

Line No. Description Aug-21 Sep-21 24 Schedule 3 - Purchases 760,740 852,120

25 Schedule 5 - Storage (604,500) (585,000)

26 Total Gas Available for Sales 156,240 267,120

27 UAFG Percentage - 0.9% 0.9% 0.9%

28 UAFG Volumes 1,406 2,404

29 Average Commodity Price (Line 6 --;- Line 26) $ 3.137 $ 3.072

30 UAFG Costs [1] $ 4,411 $ 7,385

31 Schedule 2 Sales 155,000 265,000

32 UAFG Component (Line 30 + Line 31) [2] $ 0.028 $ 0.028

[1] Equals amount shown on Sch. 1, P1, LS. [2] For informational purposes only.

$

$

$


Oct-21 712,390

(379,750)

332,640

0.9%

2,994

2.998

8,976

330,000

0.027

Petitioner's Exhibit No. Attachment f<JT-2


CE! SOUTH QUARTERLY ALLOCATION OF DEMAND COSTS

Line No.

1 2 3 4 5 6

7

ESTIMATE OF DEMAf\lD COST FOR THE PROJECTED GCA QUARTER

Description

August 2021 Monthly Demand Costs Asset Management Fee (Credit)*

September 2021 Monthly Demand Costs Asset Management Fee (Credit)* October 2021 Monthly Demand Costs Asset Management Fee (Credit)*

GCA Quarter (August, September, & October 2021) Demand Cost

GCA Quarter Demand

Cost

$441,922 ($50,417) $428,695 ($50,417) $598,632 ($50,417)

$1,317,998

*New Asset Management Agreement (AMA) begins April 1, 2021. Credit is $50,417 per month

!Derivation of Unit Demand Rate:! Rate 110 Rate 120

8 Projected Quarter Sales (Sch. 2) 485,000 265,000

9 Total Unit Demand Rate $1757 $1.757

Schedule 1A Page 1 of 1

Total

750,000

Peiitioner's Exhibit No. 1 Attachment KJT-2


Cause No. 37366-GCA151 CEI SOUTH

ESTIMATED SALES FOR THE TWELVE MONTHS ENDING JULY 2022

SUBJECT TO GCA

Sales Sales Sales Demand I\Jot Subject Subject

Month/ Year Forecast To GCA To GCA Rate 110 Rate 120

Aug-21 155,000 155,000 100,000 55,000

Sep-21 265,000 265,000 170,000 95,000

Oct-21 330,000 330,000 215,000 115,000

Subtotal 750,000 0 750,000 485,000 26s,ooo I

Nov-21 945,000 945,000 610,000 335,000

Dec-21 1,865,000 1,865,000 1,200,000 665,000

Jan-22 2,450,000 2,450,000 1,580,000 870,000

Subtotal 5,260,000 0 5,260,000 3,390,000 1,s10,ooo I

Feb-22 1,950,000 1,950,000 1,260,000 690,000

Mar-22 1,315,000 1,315,000 850,000 465,000

Apr-22 620,000 620,000 400,000 220,000

Subtotal 3,885,000 0 3,885,000 2,510,000 1,31s,ooo I

May-22 310,000 310,000 200,000 110,000

Jun-22 155,000 155,000 100,000 55,000

Jul-22 160,000 160,000 100,000 60,000

Subtotal 625,000 0 625,000 400,000 22s,ooo I Total 10,520,000 0 10,520,000 6,785,000 3,73s,ooo I

QUARTERLY PERCENTAGES BY RATE CLASS OF SALES SUBJECT TO GCA

Rate Rate Quarter Total Rate 11 O Rate 120

August 2021 - October 2021 7.129% 7.148% 7.095%

November 2021 - January 2022 50.000% 49.963% 50.067%

February 2022 - April 2022 36.930% 36.993% 36.814%

May 2022 - July 2022 5.941% 5.896% 6.024%


Schedule 3 Page6


GEi SOUTH ESTIMATED PURCHASED GAS COST - COMMODITY COST

August-21

(A) (B) (C) (D) (E) (F) (G) (H) (I) COMP. COMP. PURCHASED TRANSPORT WELLHEAD TRANSPORT WELLHEAD TOTAL

QUANTITIES FUEL FUEL QUANTITIES RATE PRICE' COST GAS COST COST SUPPLIER (DTH) (%) (DTH) (0TH) ($/DTH) ($/DTH) ($) ($) ($)

(Al/(1-rB)l (Al'(El rDl"(Fl (Gl+(Hl

[ TEXAS GAS NNS FT

FT - NNS (Current Month) (46,500) 0.54% (252) (46,752) $0 0501 $2.4369 ($2,330) ($113,931) ($116,261) FT - NNS (SWING) 46,500 0.54% 252 46,752 $0.0501 $3.0250 $2,330 $141,426 $143,756 FIXED PRICE 0 0.54% 0 0 $0.0501 $0.0000 $0 $0 $0 LONG-TERM FIXED PRICE #2 15,416 0.54% 84 15,500 $0.0501 $4.7600 $772 $73,780 $74,552 LONG-TERM FIXED PRICE #4 23.124 0.54% 126 23,250 $0.0501 $4.4900 $1,159 $104,393 $105,552

Subtotal 38,541 1 209 1 38,750 1 $1,931 1 $205,668 1 $207,599 1

TEXAS GAS FT (BACKHAUL) J FT - BACKHAUL FOM 108,500 0.03% 33 108,533 $0.0323 $3.0670 $3,505 $332,869 $336,374 FT - BACKHAUL SWING 393,664 0.03% 118 393,782 $0.0323 $3.0670 $12,715 $1,207,730 $1,220,445 FIXED PRICE 216,935 0.03% 65 217,000 $0.0323 $2.5136 $7,007 $545,445 $552,452

Subtotal 719,099 1 216 1 719,315 1 $23,227 1 $2,□86,044 1 $2,109,271 1

TEXAS EASTERN

TETCO (FOM) 3,100 2.49% 79 3,179 $0.3896 $3.1120 $1,208 $9,894 $11,102 TETCO (SWING) 0 2.49% 0 0 $0.3896 $3.1120 $0 $0 $0

Subtotal 3,100 1 79 1 3,179 I $1,208 I $9,894 1 $11,102 I

Financial Transactions

Long Term Financial Purchase #1 90,000 ($0.3400) ($30,600) ($30,600) Long Term Financial Purchase #2 50,000 ($0.2650) ($13,250) ($13,250)

Total All Suppliers 760,74□ I 5□4 I 761,244 I $26,366 1 $2,2s7,7ss I $2,2s4, 122 I


Schedule 3 Page1

Cause No. 37366-GCA 151 CEI SOUTH

ESTIMATED PURCHASED GAS COST - COMMODITY COST

September-21


QUANTITIES FUEL FUEL QUANTITIES RATE PRICE' COST GAS COST COST SUPPLIER (DTH) (%) (DTH) (DTH) ($/DTH) ($/DTH) ($) ($) ($)

(A\/(1-(B)) (Al'(El (D)'(Fl (G\+(H\

TEXAS GAS NNS FT

FT - NNS (Current Month) (45,000) 0.54% (244) (45,244) $0 0501 $2.4369 ($2.255) ($110,255) ($112,510) FT - NNS (SWING) 110,000 0.54% 597 110,597 $0.0501 $2.9960 $5,511 $331,349 $336,860 FIXED PRICE 0 0.54% 0 0 $0.0501 $0.0000 $0 $0 $0 LONG-TERM FIXED PRICE #2 14,919 0.54% 81 15,000 $0.0501 $4.7600 $747 $71,400 $72,147 LONG-TERM FIXED PRICE #4 22,379 0.54% 122 22,500 $0.0501 $4.4900 $1,121 $101,025 $102,146

Subtotal 102,298 I 555 I 102,853 I $5,124 I $393,519 1 $398,643 I

TEXAS GAS FT (BACKHAUL)

FT - BACKHAUL FOM 105,000 0.03% 32 105,032 $0.0323 $3.0380 $3,392 $319,086 $322,478 FT - BACKHAUL SWING 431,885 0.03% 130 432,015 $0.0323 $3.0380 $13,950 $1,312,460 $1,326,410 FIXED PRICE 209,937 0.03% 63 210,000 $0.0323 $2.5136 $6,781 $527,850 $534,631

Subtotal 746,822 I 224 I 747,046 I $24,123 I $2,159,396 1 $2,183,519 I 24,894

TEXAS EASTERN


Subtotal 3,ooo 1 77 I 3,077 I $1,169 I $9,408 1 $10,577 I



Total All Suppliers 852,120 I 856 1 852,9761 $30,416 I $2,520,433 I $2,550,8491


(A)

QUANTITIES SUPPLIER (DTH)

TEXAS GAS NNS FT --:1 FT - NNS (Current Month) (31,000) FT - NNS (SWING) 74,000 FIXED PRICE 0 LONG-TERM FIXED PRICE #2 15,416 LONG-TERM FIXED PRICE #4 23,124

Subtotal 81.s41 1

[ TEXAS GAS FT (BACKHAUL)

FT - BACKHAUL FOM 108,500 FT - BACKHAUL SWING 302,314 FIXED PRICE 216,935

Subtotal 627,749 I

TEXAS EASTERN

TETCO (FOM) 3,100 TETCO (SWING) 0

Subtotal 3,1001


Long Term Financial Purchase #1 Long Term Financial Purchase #2

Total All Suppliers 112,3so I


GEi SOUTH

ESTIMATED PURCHASED GAS COST- COMMODITY COST

October-21

(B) (C) (D) (E) (F)

COMP COMP. PURCHASED TRANSPORT WELLHEAD FUEL FUEL QUANTITIES RATE PRICE'

(%) (DTH) (DTH) ($/DTH) ($/DTH) (A\/(1-(B\l

0.54% (168) (31,168) $0.0501 $2.4369 0.54% 402 74,402 $0.0501 $3.0090 0.54% 0 0 $0.0501 $0.0000

0.54% 84 15,500 $0.0501 $4.7600

0.54% 126 23,250 $0.0501 $4.4900

443 I 81,984 I

0.03% 33 108,533 $0.0323 $3.0270 0.03% 91 302,405 $0.0323 $3.0270 0.03% 65 217.000 $0.0323 $2 5136

188 I 627,937 I

2.49% 79 3,179 $0.3896 $3.0570

2.49% $0.3896 $3.0570

79 I 3,179 I

90,000 ($0.3420) 50,000 ($0.2670)

1101 113,1001

(G) (H) TRANSPORT WELLHEAD

COST GAS COST ($) ($)

(A\"(E\ (D)'(F)

($1,553) ($75,953) $3,707 $223,876

$0 $0 $772 $73,780

$1,159 $104,393

$4,085 I $326,096 I

$3,505 $328,528 $9,765 $915,379 $7,007 $545,445

$20,277 I $1,789,352 I

$1,208 $9,719 $0 $0

$1,208 I $9,719 I

($30,780) ($13,350)

$2s,s10 I $2,081,0371

Schedule 3 Page1

(I) TOTAL COST

($) (G\+(H\

($77,506) $227,583

$0 $74,552

$105,552

$33□.181 1

$332,033 $925,144 $552,452

$1,809,629 I

$10.927 $0

$10,927 I

($30,780) ($13,350)

$2,106,6071

Cause No. 37366-GCA15·1

NYMEX Close Date:

NYMEX - August $ NYMEX - September $

NYMEX - October $

Purchase Price

August-21 $ September-21 $

October-21 $

6/21/2021

TGT NNS

3.215 3.201 3.217

Swing/FOM

3 025 2.996 3 009

TGT BH Swing/FOM

$ 3.067 $ 3 038 $ 3.027


GEi South For the Period August 2021 - October 2021

Purchase Price Workpaper

Current Basis Differential:

TGT NNS Basis - August $ (0.190) $

Basis - September $ (0.205) $

Basis - October $ (0.208) $

TETCO Swing/FOM

$ 3.112 $ 3.058 $ 3.057

TGT BH (0.148) $ (0.163) $ (0.190) $

TETCO (0.103) (0.143) (0.160)


CEISOUTH Cause No. 37366-GCA 151 FOR THE PERIOD AUGUST 2021 THROUGH OCTOBER 2021 Sch. 3WACOG

WEIGHTED AVERAGE COST OF GAS Workpaper

August 2021 September 2021 October 2021 Total Cause No. 37366-GCA151 Average

Volume Price Extension Volume Price Extension Volume Price Extension Volum~ Price Extension

LONG-TERM FINANCIAL PURCHASE #1 90,000 $ (0.3400) $ (30,600) 90,000 S (0.3260) $ (29,340) 90,000 S (0.3420) S (30,780) 270,000 $ (0.3360) $ (90,720) LONG-TERM FINANCIAL PURCHASE #2 50,000 $ (0.2650) $ (13,250) 50,000 S (0.2510) S (12,550) 50,000 $ (0.2670) S (13,350) 150,000 $ (0.2610) S (39,150)

LONG-TERM FIXED PRICE #2 15,500 $ 4.7600 $ 73,780 15,000 $ 4.7600 $ 71,400 15,500 $ 4.7600 $ 73,780 46,000 $ 4.7600 $ 218,960 LONG-TERM FIXED PRICE #4 23,250 $ 4.4900 $ 104,393 22,500 $ 4.4900 $ 101,025 23,250 $ 4.4900 $ 104,393 69,000 $ 4.4900 $ 309,810 LONG-TERM FIXED WACOG 38,750 $ 3.4664 $ 134,323 37,500 $ 3.4809 $ 130,535 38,750 $ 3.4592 $ 134,043 115,000 $ 3.4687 $ 398,900

SHORT-TERM FIXED TGT 217,000 $ 2.5136 $ 545,445 210,000 $ 2.5136 $ 527,850 217,000 $ 2.5136 $ 545,445 644,000 $ 2.5136 $ 1,618,740 SHORT-TERIVI FIXED WACOG 217,000 $ 2.5136 $ 545,445 210,000 $ 2.5136 $ 527,850 217,000 $ 2.5136 $ 545,445 644,000 $ 2.5136 $ 1,618,740

FIRST OF THE MONTH INDEX - TGT 108,533 S 3.0670 $ 332,869 105,032 $ 3.0380 $ 319,086 108.533 $ 3.0270 $ 328,528 322,097 $ 3.0441 $ 980,483 FIRST OF THE MONTH INDEX -TETCO 3,179 $ 3.1120 $ 9,894 3,077 $ 3.0580 $ 9,408 3,179 $ 3.0570 s 9,719 9,435 $ 3.0759 $ 29,021

FIRST OF THE MONTH WACOG 111,712 $ 3,0683 $ 342,763 108,108 $ 3,0386 $ 328,494 111,712 $ 3,0279 $ 338,247 331,532 $ 3.0450 $ 1,009,504

DAILY SWING INDEX - TGT 46,752 $ 3.0250 $ 141,426 110,597 $ 2.9960 $ 331,349 74,402 $ 3.0090 $ 223,876 231,751 s 3.0060 $ 696,650 DAILY SWING INDEX-TGT BH 393,782 S 3,0670 $ 1,207,730 432,015 $ 3.0380 $ 1,312,460 302,405 $ 3.0270 $ 915,379 1,128,201 $ 3.0452 $ 3,435,569 DAILY SWING INDEX - TETCO $ 3.1120 $ $ 3.0580 $ $ 3.0570 $ $ $

DAILY SWING WA COG 440,535 $ 3.0625 $ 1,349,156 542,612 $ 3.0294 $ 1,643,809 376,807 $ 3.0234 $ 1,139,255 1,359,953 $ 3,0385 $ 4,132,220

COMPANY STORAGE (604,500) $ 2.9678 $ (1,794,061) (585,000) $ 2.9578 $ (1,730,336) (379,750) $ 2.9212 $ (1,109,328) (1,569,250) $ 2.9528 $ (4,633,726) NNS - TEXAS GAS STORAGE (46,752) $ 2.4369 $ (113,931) (45,244) $ 2.4369 $ (110,255) (31,168) $ 2.4369 $ (75,953) (123,164) S 2.4369 $ (300,139)

STORAGE WACOG (651,252) $ 2.9297 $ (1,907,992) (630,244) $ 2.9204 $ (1,840,591) (410,918) $ 2.8845 $ (1,185,281) (1,692,414) $ 2.9153 $ (4,933,865)

LONG-TERM FIXED WACOG 38,750 $ 3.4664 $ 134,323 37,500 $ 3.4809 $ 130,535 38,750 $ 3.4592 $ 134,043 115,000 $ 3.4687 $ 398,900 SHORT-TERM FIXED WACOG 217,000 $ 2.5136 $ 545,445 210,000 $ 2.5136 $ 527,850 217,000 $ 2.5136 $ 545,445 644,000 $ 2.5136 $ 1,618,740

FIRST OF THE IVIONTH WACOG 111,712 $ 3,0683 $ 342,763 108,108 $ 3,0386 $ 328,494 111,712 $ 3,0279 $ 338,247 331,532 $ 3.0450 $ 1,009,504 DAILY SWING WACOG 440,535 $ 3.0625 $ 1,349,156 542,612 $ 3.0294 $ 1,643,809 376,807 $ 3.0234 $ 1,139,255 1,359,953 $ 3.0385 $ 4,132,220

STORAGE WACOG (651,252) $ 2,9297 $ (1,907,992) (630,244) $ 2,9204 $ (1,840,591) (410,918) $ 2,8845 $ (1,185,281) (1,692,414) $ 2.9153 $ (4,933,865)

TOTAL WEIGHTED AVERAGE COST OF GAS 156,744 $ 2,9583 $ 463,694 267,976 $ 2,9484 $ 790,097 333,350 $ 2.9150 $ 971,708 758,070 $ 2,9357 $ 2,225,498



Cause No. 37366-GCA151 CE\ SOUTH

ESTIMATED GAS STORAGE AND DELIVERED SERVICES COST

FOR THE PERIOD AUGUST 2021 THROUGH OCTOBER 2021 COMMODITY COST

Estimated Volumes Estimated Rates Estimated Cost Injected Withdrawn Injected Withdrawn Com- Injected Withdrawn

Month and Compressor pressor Compressor Su lier 0th 0th Fuel 0th Dth Fuel Fuel Total

August-21

TEXAS GAS NNS (46,500) 0 0 $0.0501 $0.0501 $0 $0 $0 $0

Subtotal (46,500)1 O[ 01 $0 1 $0 1 $0 1 $0 1

September-21

TEXAS GAS NNS (45,000) 0 0 $0.0501 $0.0501 $0 $0 $0 $0

Subtotal (45,000)[ 01 01 $0 1 $0 1 $0 1 $0 1

October-21

TEXAS GAS NNS (31,000) 0 0 $0.0501 $0.0501 $0 $0 $0 $0

Subtotal (31,000)[ 01 01 $0 1 $0 1 $0 1 $0 1

Total Commodity Cost $0 I $0 I $0 $0 I

Petitioner's Exhibit No.

Attachment KJT-2 Scl1edule 5 Page 1 of 1

Cause No. 37366-GCA 151 GEi SOUTH

ESTIMATED COST OF GAS INJECTED AND WITHDRAWN FROM STORAGE AND DELIVERED SERVICES

FOR THE PERIOD AUGUST 2021 THROUGH OCTOBER 202·1

Estimated Changes in Storage Month and Injected Withdrawn Net Estimated Gas Rates Cost of Gas

Type of Stora e Dth Dth Dth Demand Commodit Demand Commodit Net

August-21

Company (604,500) 0 (604,500) $2.968 $0 ($1,794,061) ($1,794,061)

(604,500)1 01 (604,500)1 $0 I ($1,794,061)1 ($1,794,061)1

September-21

Company (585,000) 0 (585,000) $2.958 $0 ($1,730,336) ($1,730,336)

rs8s,oooi 1 01 (585,000)1 $0 I ($1,730,336) 1 ($1,730,336)1

October-21

Company (379,750) 0 (379,750) $2.921 $0 ($1,109,328) ($1,109,328)

(379,750)1 o I (379,r5oJ 1 $0 I ($1,109,328)1 ($1, 1 o9,32sJ I

Grand Total (1,569,250) 1 01 (1,569,250) I $0 I ($4,633,725)! ($4,633,725) I

1 l~i ; I ~;i

~im ~1 ;;;

Financial Close Month Mar-21


Line No.

(1)

GAS COST RECOVERED

Sales - Dth


VECTREN SOUTH CAL CU LA TION OF ACTUAL GAS COST VARIAN CE

December 2020

Rate Rate Class 110 Class 120

1,210,904 544,243

II m

Rate Class 129

79

Ill


Total

1,755,226

III (2) GCA (without IURT) from GCAl 48

(a) Demand Cost Component (Sch 1, Line 18) (b) Commodity Cost Component (Sch 1, Line 14)

$0.304 $0.304 $0.304 } II $2.171 $2.171 $2.171

..---i$"'2""'.4""75,,,_----;.,$2,....4.,.,,7""5 ___ $.,...2.""'47""5""'1

(3)

(c) Total

Cost of Gas Recovered (without IURD (a) Demand Costs (Line 1 * Line 2a) (b) Commodity Costs Recovered (Line 1 * Line 2b) (c) Total Gas Costs Recovered

GAS COST TO BE RECOVERED

(4) Actual Demand Costs Incurred (Sch 7 Line 4c) (a) Purchased Gas Cost Demand (b) Storage Demand (c) Total

(5) Demand Variance from GCA148,(Sch 12B (pg 1 of 2), Line 13b)

(6) Total Demand Costs to be Recovered (Line 4c + Line 5)

(7) Actual Commodity Cost Incurred (Sch 7, Line 5)

(8) Commondity Variance from GCA148,(Sch 12B (pg 2 of 2), Line 13b)

(9) Commodity Refunds From GCA148(Sch 12A, Ll2b)

(10) Total Commodity Costs Incurred (Line 7 + Line 8 +Line 9)

DETERMINATION OF THE GAS COST VARIANCES

(11) Gas Cost Variance Representing (Over)/Under Recovery (a) Total Demand Variance (Over)/Under Recovery (Line 6 - Line 3a)

$368,115 $2,628,872 $2,996,987

(b) Total Commodity Variance (Over)/Under Recovery (Line 10 - Line 3b)

(c) Total Gas Cost Variance (Line lla + Line llb)

(12) % of (Over)/Under Recovery to Costs (Line llc / (Line 4c + Line 7))

$165,450 $1,181,551 $1,347,001

$24 $172 $196

• • II

$533,589 $3,810,595 $4,344,184 I

$577,045 0

$577,045

($39,558)

$537,487

$4,127,308

($331,118)

$0

$3,796,190

$3,898

($14,405)

($10,507)!

-0.22%


Cause No. 37366-GCAlSl

Petitioner's Exhibit No. Attachment f<JT-2

VECTREN SOUTH CAlCULATIOI\I OF ACTUAL GAS COST VARIANCE

Line No.

(1)

(2)

(3)

(4)

(5)

(6)

(7)

(8)

(9)

(10)

(11)

(12)

January 2021

GAS COST RECOVERED

Sales - Dth

GCA (without IURT) from GCAl 48 (a) Demand Cost Component (Sch 1, Line 18) (b) Commodity Cost Component (Sch 1, Line 14) (c) Total

Cost of Gas Recovered (without IURT) (a) Demand Costs (Line 1 * Line 2a) (b) Commodity Costs Recovered (Line 1 * Line 2b) (c) Total Gas Costs Recovered


Actual Demand Costs Incurred (Sch 7 Line 4c) (a) Purchased Gas Cost Demand (b) Storage Demand (c) Total

Demand Variance from GCA148,(Sch 12B (pg 1 of 2), Line 13c)

Total Demand Costs to be Recovered (Line 4c + Line 5)

Actual Commodity Cost Incurred (Sch 7, Line 5)

Commondity Variance from GCA148,(Sch 12B (pg 2 of 2), Line 13c)

Commodity Refunds From GCA148(Sch 12A, L12c)

Total Commodity Costs Incurred (Line 7 + Line 8 +Line 9)


Gas Cost Variance Representing (Over)/Under Recovery (a) Total Demand Variance (Over)/Under Recovery (Line 6 - Line 3a)


1,395,282

$0.304 $2.473 $2.777

$424,166 $3,450,533 $3,874,699

$0.304 $2.473 $2.777

$193,143 $1,571,196 $1,764,339



% of (Over)/Under Recovery to Costs (Line llc / (Line 4c + Line 7))

Rate Class 129

172

$0.304 } $2.473

$2.777 I

$52 $425 $477


$617,361 $5,022,154 -

$5,639,515 1

$577,045 0

$577,045

($50,558)

$526,487

$5,770,639

($423,193)

$0

$5,347,446

($90,874)

$325,292

$234,418 1

3.69%

Financial Close Month March 2021


Cause No. 37366-GCA151 VECTREN SOUTH

Line No.

(1)

GAS COST RECOVERED

Sales - Dth

CALCULATION OF ACTUAL GAS COST VARIANCE

Febrna.-y 2021


(2) GCA (without IURT) from GCAl 49 (a) Demand Cost Component (Sch 1, Line 18) (b) Commodity Cost Component (Sch 1, Line 14) (c) Total

(3) Cost of Gas Recovered (without IURT)

(4)

(5)

(6)

(7)

(8)

(9)

(10)

(11)

(a) Demand Costs (Line 1 * Line 2a) (b) Commodity Costs Recovered (Line 1 * Line 2b) (c) Total Gas Costs Recovered



Demand Variance from GCA149,(Sch 12B (pg 1 of 2), Line 13a)



Commondity Variance from GCA149,(Sch 12B (pg 2 of 2), Line 13a)

Commodity Refunds From GCA149(Sch 12A, L12a)




$0.420 $2.683 $3.103

$645,762 $4,125,190 $4,770,952




$0.420 $2.683 $3,103

$289,045 $1,846,446 $2,135,491

Rate Class 129

85

$0.420 -I $2.683 f $3.103 1

$36 $227 $263


$934,843 $5,971,863 $6,906,106 1

$519,306 0

$519,306

($48,044)

$471,262

$24,541,585

($301,272)

$0

$24,240,313

($463,581)

$18,268,450

$17,8□4,869 1



VECTREN SOUTH DETERMINATION OF ACTUAL GAS COST

For The Period December 2020 Through February 2021

Line Fiifrii l!Mi FiW-11

No. December 2020 Janua)J'. 2021 Februa)J'. 2021 (1) Purchased Gas Cost (Schedule 8): II

(a) Demand Costs (Sch. 8, Page 2, Col.H) II $577,045 • $577,045 a $519,306

(b) Commodity & Other Costs (Sch. 8, Page 1 Col. M) $2,963,971 $2,966,804 $22,812,905

(2) Total Purchased Gas Cost (Lla + lb) $;3 S!J;l Ql§ $3 5!J;3Jl!l:2 Ji23 332,Zll

(3) Cost of Gas (Injected Into) / Withdrawn From Storage (Schedule 10)

(a) Demand (Sch. 10, Col. L) $0 $0 $0 (b) Commodity (Sch. 10, Col. G) 1,163,337 2,803,835 1,728,680 (c) Total Cost of Storage Activity (L3a + L3b) $1163 337 $2,8Q3 835 $1 728 68Q

Net Cost of Gas Totals: (4) Demand II • a (a) Purchased Gas Cost (L la) $577,045 $577,045 $519,306

(b) Storage Demand (L 3a) Q. Q. Q. (c) Total Demand (L4a + 4b) $577,045 $577,045 $519,306

(5) Commodity (Line Nos. lb + 3b) $4,127,308 $5,770,639 $24,541,585

(6) Net (Line Nos. 4c + 5) :t;!l,7Q4,~ $6,fil.68!! $;25,Qfill,a2,1


TOTAL

$1,673,395

$28,743,680

$3Q!!JZQZS

$0 5,695,852

$5 695 852

$1,673,395 1Q

$1,673,395

$34,439,532

$36,112,227

Cause No. 37366-GCAlSl Petitioner's 'liXtritliM~oow Schedule 8

NOM~l\1-m!mlf{l.f-ji.i\fES - COMMODITY Page 1 of 2

Tied Out w/ JE 01.00351 Purchased Gas JE I lilm■ December 2020

Col (A) to (E) Col(F)/(M) Col (H) to (L) Net MMBTU By Pieeline Total Commodity Purchases By Pieeline Total Transport

Line Purchased Rate Invoiced/ Quantities Total No. ~ TGT MGT TETCO ANR Other /MMBTU) /$/MMBTU} TGT MGT TETCO ANR Other Cost Received Billing

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N) (0)

l EXELON - PURCHASED GAS 980,394 0 6,283 0 0 986,677 $2.6346 $2,583,168 $0 $16,370 $0 $0 $2,599,538 996,8901 $2.599.538 2 ASSET MANAGER - DELIV SERV VAR 0 0 0 0 0 0 $0.0000 $37,071 $0 $2,445 $0 $0 $39,517 0 $39,517 Sum of A 3 BP CANADA 0 0 0 0 0 0 $0.0000 $0 $0 $0 $0 $0 $0 0 $0 1,035,573

4 BoA/ MERRILL LYNCH 38,750 0 0 0 0 38,750 $4.5980 $178,173 $0 $0 $0 $0 $178,173 38,683 $178,173 5 GAS HEDGING 0 0 0 0 0 0 $0.0000 $0 $0 $0 $0 $ 810 $810 0 $810 6 TGT-NNS 55,335 0 0 0 0 55,335 $2.3640 $ 130,812 $0 $0 $0 $0 $130,812 55,335 $130,812 7 STORAGE VARIBLE COSTS WITH/ (INJ: 0 0 0 0 0 0 $0.0000 $0 $0 $0 $0 $ 3,007 $3,007 0 $3,007 8 CASH-OUT END USERS 0 0 0 0 9,434 9,434 ($0.4155) $0 $0 $0 $0 $ (3,920) ($3,920) 9,434 ($3,920) 9 TEXAS GAS CASH OUTS 0 0 0 0 0 0 $0.0000 $0 $0 $0 $0 $0 $0 ~r $0

10 MGT CASH OUTS 0 0 0 0 0 0 $0.0000 $0 $1,589 $0 $0 $0 $1,589 $1,589 11 TETCO CASH-OUTS 0 0 0 0 0 0 $0.0000 $0 $0 $14,446 $0 $0 $14,446 $14,446 12 LOCAL PRODUCTION 0 0 0 0 0 0 $0.0000 $0 $0 $0 $0 $0 $0 0 $0

MONTHLY SUBTOTAL I • I F,963,971 I 1,100,342 I R963,971 I■ 2.694

Tied Out w/ JE 01.0035, Purchased Gas JE I 11111-11 January 2021

Col (A) to (E) Col(F)/(M) Col (H) to (L) Net MM BTU By Pipeline Total Commodity Purchases By Pipeline Total Transport

Line Purchased Rate Invoiced/ Quantities Total No. Supplier TGT MGT TETCO ANR Other (MMBTU} /$/MMBTUl TGT MGT TETCO ANR Other Cost Received Billing

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N) (0)

l EXELON - PURCHASED GAS 991,721 0 3,708 0 0 995,429 $2.6874 $2,666,675 $0 $8,469 $0 $0 $2,675,145 1,016,5141 $2,675,145 2 ASSET MANAGER - DELIV SERV VAR 0 0 0 0 0 0 $0.0000 $37,751 $0 $1,443 $0 $0 $39,194 D $39,194 Sum of B 3 BP CANADA 0 0 0 0 0 0 $0.0000 $0 $0 $0 $0 $0 $0 0 $0 1,055,200

4 BoA I MERRILL LYNCH 38,750 0 0 0 0 38,750 $4.5980 $178,173 $0 $0 $0 $0 $178,173 38,686 $178,173 5 GAS HEDGING 0 0 0 0 0 o $0,0000 $0 $0 $0 $0 $ 60,870.00 $60,870 o $60,870 6 TGT-NNS 8,768 0 0 0 0 8,768 $2.5610 $22,455 $0 $0 $0 $0 $22,455 8,768 $22,455 7 STORAGE VARIBLE COSTS WITH/ (INJ: 0 0 0 0 0 0 $0.D000 $0 $0 $0 $0 $483 $483 0 $483 8 CASH-OUT END USERS 0 0 0 0 (6,768) (6,768) $6.6174 $0 $0 $0 $0 ($44,787) ($44,787) (6,768) ($44,787) 9 TEXAS GAS CASH OUTS 0 0 0 0 D 0 $0.0000 $0 $0 $0 $0 $0 $0 ~er $0

10 MGT CASH OUTS 0 0 0 0 0 0 $0.0000 $0 $0 $0 $0 $0 $0 $0 11 TETCO CASH-OUTS 0 0 0 0 0 0 $0.0000 $0 $0 $35,271 $0 $0 $35,271 $35,271 12 LOCAL PRODUCTION 0 0 0 0 0 0 $0.0000 $0 $0 $0 $0 $0 $0 0 $0

MONTHLY SUBTOTAL I 1,036,179 111 I $2,966,so4 I 1,057,200 I $2,966,804 Ill 2,806

Tied Out w/ JE 01.0035, Purchased Gas JE 1 lil1!-II February 2021

Col (A) to (El Col(F)/(M) Col (H) to (L) Net MM BTU By Pieeline Total Commodity Purchases By Pieeline Total Transport

Line Purchased Rate Invoiced/ Quantities Total No, Supplier TGT MGT TETCO ANR Other fMMBTUl /$/MM BTU) TGT MGT TETCO ANR Other Cost Received Billing

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N) (0) (E) (Fl

l EXELON - PURCHASED GAS 1,027,480 195,095 14,714 158,500 0 1,395,789 $15.7776 $ 12,403,577 $5,409,869 $ 73,027 $4,135,783 $ $22,022,256 1,432,180122.022.256 2 ASSET MANAGER - DELIV SERV VAR 0 0 0 0 0 0 $0.0000 $ 33,416 $ $ 5,733 $0 $ $39,149 0 $39,149 3 BP CANADA 0 0 0 0 0 0 $0,0000 $ $ $ $0 $ $0 0 $0 4 BoA / MERRILL LYNCH 34,690 0 0 0 0 34,690 $4.5966 $ 159,454 $ $ $0 $ $159,454 34,621 $159,454 5 GAS HEDGING D 0 0 0 0 0 $0,0000 $ $ $ $0 $ 19,850 $19,850 0 $19,850 6 TGT-NNS 71,571 0 0 0 0 71,571 $2.7640 $ 197,822 $ $ $0 $ $197,822 71,571 $197,822 Sum of C 7 STORAGE VARIBLE COSTS WITH/ (INJ: o 0 0 D 0 o $0.0000 $ $ $ $0 $ 7,192 $7,192 o $7,192 1,466,801

8 CASH-OUT END USERS 0 0 0 0 64,606 64,606 $5.8520 $ $ $ $0 $ 378,069 $378,069 64,6061 $378,069 9 TEXAS GAS CASH OUTS 0 0 0 0 0 0 $0.0000 $ $ $ $0 $ $0 0 .,c. $0

10 MGT CASH OUTS 0 0 0 0 0 0 $0.0000 $ $ (2,284) $ $0 $ ($2,284) 0 ($2,284) 11 TETCO CASH-OUTS 0 0 0 0 0 0 $0.D000 $ $ $ (8,603) $0 $ ($8,603) 0 ($8,603) 12 LOCAL PRODUCTION 0 0 0 0 0 0 $0.0000 $ $ $ $0 $ $0 0 $0

MONTHLY SUBTOTAL I 1,566,656 1 11 I $22,s12,905 I 1,6oz,97s I F2,s12,905 ■

QUARTERLY TOTAL I 3,693,031 I I t28,743,6so I 3,760,520 I '!28,743,680 I 7.644

cause No. 37366-GCA151 Petitioner's ilooTit.titi~oon, Schedules

~fufilfr™Nf ~~ES - DEMAND Page 2 of 2 00-Jan-00

26,876,059.62 26,876,060

December 2020

Tied Outw/ JE 01,0035, Purchased Gas JE I Miifrii Line Total ..N9,, DEMAND TGT MGT TETCO Other Billing

(A) (B) (E) (F) (H)

l ASSET MANAGER $ 572,059 $ $ 6,085 $ $578,144 2 ASSET MANAGER - UTIUZATION FEE $ $ $ ($25,000) ($25,000) 3 ASSET MANAGER - TGT NNS OVERRUN $ $ $ $0 $0 4 ASSET MANAGER - VALUE SHARING CREDIT $ $ $ $0 $0 5 ASSET MANAGER - PIPEUNE VARIABLE COSTS $ $ $ $0 $0 6 OHIO VALLEY HUB $ $ $ $ 23,901 $23,901

TOTALf $577,04 ••

January 2021

I Tied Out w/ JE 01,0035, Purchased Gas JE iliili-11 Line Total

..N9,, DEMAND !fil .Mfil illQQ other Billing (A) (B) (E) (F) (HJ

l ASSET MANAGER $572,059 $0 $6,085 $0 $578,144 2 ASSET MANAGER - UTILIZATION FEE $0 $0 $0 ($25,000) ($25,000) 3 ASSET MANAGER - TGT NNS OVERRUN $0 $0 $0 $0 $0 4 ASSET MANAGER - VALUE SHARING CREDIT $0 $0 $0 $0 $0 5 ASSET MANAGER - PIPELINE VARIABLE COSTS $0 $0 $0 $0 $0 6 OHIO VALLEY HUB $0 $0 $0 $23,901 $23,901

TOTALf $577,04-■

February 2021

I Tied Out w/ JE 01.0035, Purchased Gas JE I 11111-11 Line Total

..N9,, DEMAND TGT MGT illQQ Other Billing (A) (B) (E) (F) (HJ

l ASSET MANAGER $516,698 $0 $6,020 $0 $522,718 2 ASSET MANAGER - UTIUZATION FEE $0 $0 $0 $ (25,000) ($25,000) 3 ASSET MANAGER - TGT NNS OVERRUN $0 $0 $0 $0 $0 4 ASSET MANAGER - VALUE SHARING CREDIT $0 $0 $0 $0 $0 5 ASSET MANAGER - PIPEUNE VARIABLE COSTS $0 $0 $0 $0 $0 6 OHIO VALLEY HUB $0 $0 $0 $21,588 $21,588

TOTALf $519,3061111

Cause No. 37366-GCA151 Pl;it. '~msth WACOG DETAILS Deeember-20 e 191¥rfilb 8s OF GAS DETAILS Page 1 r,.f 1

Attachr.mHl!b!!i • .ETs-lruppLEMENT

December 2020 Janua!}:'. 2021 February 2021 Total GCA 151 Line Average No. Supplier Volume Price Extension Volume Price Extension Volume Price Extension Volume Price Extenslor{

TGT AREA: FIXED - SHORT TERM EXELON 325,500 $ 3,0548 $ 994,325 325,500 $ 3,0548 $ 994,325 294,000 $ 3,0548 $ 898,100 945,000 $ 3.0548 $ 2,886,750 INDEXED - FIRST OF MONTH EXELON $ $ $ $ $ $ $ $ DELIVERED EXELON 9,000 $ 2.8500 $ 25,650 $ $ 151,334 $ 26.2133 $ 3,966,962 160,334 $ 24.9018 $ 3,992,612

4 INDEXED - DAILY EXELON 645,894 $ 2.4202 $ 1,563,193 666,221 $ 2.5102 $ 1,672,350 582,146 $ 12.9495 $ 7,538,516 1,894,261 $ 5.6877 $ 10,774,059

5 INDEXED - MIXED TGT Cash-Outs $ $ $ $ $ $ $ $ 6 FIXED - LONG TERM BP Canada $ $ $ $ $ $ $ $ 7 FIXED - LONG TERM BoA / Merrill Lych 38,750 $ 4.5980 $ 178,173 38,750 $ 4.5980 $ 178,173 34,690 $ 4.5966 $ 159,454 112,190 $ 4.5976 $ 515,799

OTHER Asset Manager Supplier Reservation Cost $ $ $ $ $ $ $ $

OTHER Asset Manager Delivery Service Variables $ $ 37,071 $ $ 37,751 $ $ 33,416 $ $ 108,238 10 TOTAL COMMODITY 1,019,144 $ 2.7458 $ 2,798,412 1,030,471 $ 2.7974 $ 2,882,599 1,062,170 $ 11.8592 $ 12,596,447 3,111,785 $ 5,8736 $ 18,277,458

11 DEMAND $ $ 572,059 $ $ 572,059 $ $ 516,698 $ $ 1,660,815

12 TOTALPEPL 1,019,144 $ 3.3072 $ 3.370,470 1,030,471 $ 3.3525 $ 3,454,657 1,062,170 $ 12.3456 $ 13,113,145 3,111,785 $ 6.4073 $ 19,938,273

ANRAREA: 13 DELIVERED EXELON $ $ $ $ 158,500 $ 26.0933 $ 4,135,783 158,500 $ 26.0933 $ 4,135,783

MGT AREA: 14 DELIVERED EXELON $ $ $ $ 195,095 $ 27.7294 $ 5,409,869 195,095 $ 27.7294 $ 5,409,869 15 INDEXED - MIXED MGT Cash-Outs $ $ 1,589 $ $ $ $ (2,284) $ $ (695) 16 OTHER Asset Manager Supplier Reservation Cost $ $ $ $ $ $ $ $ 17 OTHER Asset Manager Delivery Service Variables $ $ $ $ $ $ $ $

18 TOTAL COMMODITY $ $ 1,589 $ $ 353,595 $ 26.9895 $ 9,543,368 353,595 $ 26,9940 $ 9,544,956

19 DEMAND $ $ $ $ $ $ $ $

20 TOTALANR $ $ 1,589 $ $ 353,595 $ 26.9895 $ 9,543,368 353,595 $ 26,9940 $ 9,544,956

TGT NNS AREA: 21 FIXED - SHORT TERM EXELON $ $ $ $ $ $ 22 INDEXED - FIRST OF MONTH EXELON $ $ $ $ $ $ 23 INDEXED - DAILY EXELON $ $ $ $ $ $ $

24 STORAGE TGT No~Notice Storage 55,335 $ 2.3640 $ 130,812 8,768 $ 2.5610 $ 22,455 71,571 $ 2,7640 $ 197,822 135,674 $ 2.5877 $ 351,089 25 STORAGE Asset Manager Delivery Service Variables $ $ 3,007 $ $ 483 $ $ 7,192 $ $ 10,682 26 TOTAL COMMODITY 55,335 $ 2.4183 $ 133,819 8,768 $ 2.6161 $ 22,938 71,571 $ 2.8645 $ 205,014 135,674 $ 2.6665 $ 361,771

27 DEMAND $ $ $ $ $ $ $ $

28 TOTALTGT 55,335 $ 2.4183 $ 133,819 8,768 $ 2.6161 $ 22,938 71,571 $ 2.8645 $ 205,014 135,674 $ 2.6665 $ 361,771

TETCO AREA: 29 FIXED - SHORT TERM $ $ $ $ $ $ $ $ 30 INDEXED - FIRST OF MONTH EXELON Invoice (Gas Cost Summary tab) 3,193 $ 2.7700 $ 8,845 3,193 $ 2.2700 $ 7,248 2,884 $ 2.6400 $ 7,614 9,270 $ 2.5573 $ 23,706 31 INDEXED - DAILY Asset Manager 3,090 $ 2.4354 $ 7,525 515 $ 2.3710 $ 1,221 11,830 $ 5,5294 $ 65,413 15,435 $ 4.8046 $ 74,159 32 INDEXED - MIXED TETCO Cash-Outs $ $ 14,446 $ $ 35,271 $ $ (8,603) $ $ 41,114 33 OTHER Asset Manager Suppller Reservation Cost $ $ $ $ $ $ 34 OTHER Asset Manager Delivery Service Varlables $ $ 2,445 $ $ 1,443 $ $ 5,733 $ $ 9,622 35 TOT AL COMMODITY 6,283 $ 5.2938 $ 33,261 3,708 $ 12.1855 $ 45,184 14,714 $ 4.7680 $ 70,157 24,705 $ 6.0150 $ 148,601

36 DEMAND $ $ 6,085 $ $ 6,085 $ $ 6,020 $ $ 18,190

37 TOTAL TETCO 6,283 $ 6.2623 $ 39,346 3,708 $ 13,8265 $ 51,269 14,714 $ 5.1772 $ 76,177 24,705 $ 6.7513 $ 166,792

MISCELLANEOUS: 38 FIXED - SHORT TERM $ $ $ $ $ $ $ $ 39 INDEXED - MIXED Transportation Customer Cash Outs 9,434 $ (0.4155) $ (3,920) (6,768) $ 6,6174 $ (44,787) 64,606 $ 5,8520 $ 378,069 67,271 $ 4.8960 $ 329,362 40 INDEXED - MIXED Gas Hedging $ $ 810 $ $ 60,870 $ $ $ $ 61,680

41 OTHER Local Production $ $ $ $ $ $ 19,850 $ $ 19,850

42 TOTAL COMMODITY 9,434 $ (0,3296) $ (3,110) (6,768) $ (2.3763) $ 16,083 64,606 $ B.1592 $ 397,919 67,271 $ 6.1080 $ 410,892

43 DEMAND $ $ (1,099) $ $ (1,099) $ $ (3,412) $ $ (5,610)

44 TOTAL MISCELLANEOUS 9,434 $ (0.4461) $ (4,209) (6,768) $ (2.2139) $ 14,984 64,606 $ 6.1064 $ 394,507 67,271 $ 6.0246 $ 405,282

TOTAL COMPANY: 45 FIXED - SHORT TERM 325,500 $ 3.0548 $ 994,325 325,500.00 $ 3.0548 $ 994,325 294,000 $ 3.0548 $ 898,100 945,000 $ 3.0548 $ 2,886,750 46 FIXED - LONG TERM 38,750 $ 4.5980 $ 178,173 38,750.00 $ 4.5980 $ 178,173 34,690 $ 4.5966 $ 159,454 112,190 $ 4.5976 $ 515,799 47 INDEXED - DAILY 648,984 $ 2.4203 $ 1,570,718 666,736.00 $ 2,5101 $ 1,673,571 593,976 $ 12.8017 $ 7,603,928 1,909,696 $ 5.6806 $ 10,848,218 48 INDEXED - FIRST OF MONTH 3,193 $ 2.7700 $ 8,845 3,193.00 $ 2.2700 $ 7,248 2,884 $ 2.6400 $ 7,614 9,270 $ 2,5573 $ 23,706

49 INDEXED - MIXED 9,434 $ 1.3701 $ 12,925 (6,768.09) $ (7.5877) $ 51,354 64,606 $ 5,6834 $ 367,182 67,271 $ 6.4138 $ 431,461 50 DELIVERED 9,000 $ 2.8500 $ 25,650 $ $ 504,929 $ 26,7614 $ 13,512,613 513,929 $ 26.3427 $ 13,538,263 51 STORAGE 55,335 $ 2.4183 $ 133,819 8,768.00 $ 2.6161 $ 22,938 71,571 $ 2,8645 $ 205,D14 135,674 $ 2.6665 $ 361,771 52 OTHER $

2.7~88 ii 39,517 $ 2.8632 ii 39,194 $ ii 58,999 $ $ 137,710

53 TOTAL COMMODITY 1,090,196 $ 2,963,971 1,036,179 $ 2,966,804 1,566,656 $ 14.5615 22,812,905 3,693,030 $ 7.7832 $ 28,743,679

55 TOTAL DEMAND $ $ 577,045 $ $ 577,045 $ $ 519,306 $ $ 1,673,395

56 TOTAL COMPANY 111,090,196 $ 3.2481 11 3,541,016 111,036,179 $ 3.4201 11 3,543,848 a 1.566.656 s 14.8930 11 23,332,211 3,693,030 $ 8.2363 $ 30,417,075 0 $ 0 $ (0) (0) $ (0)

$ $ $




VECTREN SOUTH ACTUAL COST OF GAS INJECTED INTO AND WITHDRAWN FROM STORAGE


Actual Changes in Storage Rates Actual Gas Cost

(Injected) Withdrawn

Month illb. illb. (Column A) (B)

December 2020

Company 24,865 579,152

Free Gas 1,138 580,290

January 2021

Company 8,448 1,009,278

February 2021

Company 40,484 550,720

Total 73,797 2,140,288

Net (Injection) Withdrawal

Dth (C)

604,011 I 1,138

605,155 -1,011,126 I m 591,204 I ,:s,

2,214,oss 1

Injected & Withdrawn

Demand (D)

Commodity (E)

$0.0000 1 $1.9260 I I Summer Strip Pricing

$0.0000 I $2.7550 I I Summer Strip Pricing


(Injected) & Withdrawn

~ (F)

$0

$0

$0

$0

~ (G)

$1,163,337 1m

$2,803,8351m

$1,728,680 ,m $s,69s,ss2 I



Cause No. 37366-GCA151 VECTREN SOUTH Schedule 11 DETERMINATION OF UNACCOUNTED FOR GAS


Line {A) {B) {C) {D) No. December 2020 January 2021 February 2021 TOTAL

{1) Total Dth of Purchased Gas Delivered 1,100,342 1,057.200 1,602,978 3,760,520

{2) Total Dth of Transport Gas Delivered by Pipeline

{a) Cash Outs (9,434) 6,768 (64,606) (67,271) {b) Customer Transp. Deliveries 2,623,218 2.273,308 2,075,603 6,972,129 {c) Total Transported Gas Delivered (Line 2a + Line 2t 2,613,784 2,280,076 2,010,997 6,904,858

{3) Total Dth of Gas (Injected Into)/ Withdrawn From Storage

{a) From Storage (Schedule 10 Col. C) 605,155 1,017,726 591,204 2,214,085 {b) Third Party Storage Activity (7,874) 1.671 6,882 679 {c) Total Dth of Gas (Injected Into) / Withdrawn 597,281 1,019,397 598,086 2,214.764

from Storage

{4) Total Dth of Local Production Gas Delivered Q Q Q Q

{5) Total Dth of Other Gas Injected Into/Withdrawn From System

{a) Gas Loss - Facilities Damage Rpt. 0 0 0 Q {b) Gas Usage Not Billed Due to NONR (34) (70) (104) .C2.QID {c) Total Dth of Other Gas (Injected Into) / Withdrawr 00 .(ZQ). (104) (208)

from Storage

{6) Total Dth of Gas Available (L 1 + L 2c + L 3c + L 4 + L 5) 4.311.373 4.356.603 4,211.957 12,879,934

{7) Total Dth of Gas Sold 1,755,226 2,030,794 2,225,816 6,011,836 (Sch. 6 Line 1)

{8) Total Dth of Gas Transported to Customers

{a) Rate Class 125 46,268 50,896 43,773 140,937 (b) Rate Class 145 196,851 209,239 244,397 650.487 {c) Rate Class 160 472,614 492,153 480,678 1,445,445 {d) Rate Class 170 1,872,340 1,580,091 1,200,242 4,652,673 {e) Total Dth of Gas Transported to Customers 2,588,073 2,332,379 1,969,090 6,889,542

{9) Total Dth of Gas Delivered to Customers (Line 7 + Line Se) 4.343.299 4.363.173 4.194.906 12.901.378

{10) Unaccounted For Gas {a) Total Dth of Unaccounted For Gas

(Line 6 - Line 9) (31.926) (6,570) 17,052 (21.444)

{11) Percentage of Unaccounted for Gas (Line 10(a) / Line 6) -0,70% -0.20% 0.40% -0,20%

lll~C!I lll~m■ 11m~1 Line (6) Tied Out w/ JE 01.0037, Unbilled JE, Sch 1



VECTREN SOUTH Determination of Bad Debt Gas Cost Recoveries

Line ii!Mii -;um, No. DescriEtion December 2020 January 2021

1 Actual Sales in Dth (from Sch. 6, Line 1) II 1,755,226 II 2,030,794

2 Projected Bad Debt Gas Cost Component ($/Dth) II $0.017 Ill $0.019 (from Sch. 1, Page 2, Line 21, prior GCAs)

3 Actual Bad Debt Gas Cost Recovery $29,839 $38,585 (Line 1 * Line 2)

4 Actual Recoverable Gas Costs (from Sch. 7, Line 6) $4,704,353 $6,347,684

5 Actual Recoverable Bad Debt Gas Costs $30,578 $41,260 (Line 4 * 0.65%)

6 Bad Debt Gas Cost Variance (Line 5 - Line 3) $739 $2,675

Schedule 12C

NIUMI 3 Months Ending

February 2021 2/28/2021

II 2,225,816 6,011,836

Ill $0.021

$46,742 $115,166

$25,060,891 $36,112,928

$162,896 $234,734

$116,154 $119,5681



Line No.

1

2

3

4

5

6

7

8

9

10

11

12

12a 12b 12c

CEI SOUTH INITIATION OF REFUND

Refunds to be Included in the GCA FOR THE PERIOD AUGUST 2021 THROUGH OCTOBER 2021

Description:

Nomination and Balancing Charges

Pipeline Refunds

Total to be Refunded

Distribution of Refunds to GCA Quarters (A) Sales Percentage

Quarter All Rate Classes (Schedule 2)

August 2021 - October 2021 7.129%

November 2021 - January 2022 50.000%

February 2022 - April 2022 36.930%

May 2022 - July 2022 5.941%

100.000%\

!Calculation Of Refunds To Be Returned In This GCA




Refunds from this GCA (Schedule 12A, Line 4)

Total to be Refunded in This Cause

August 2021 Refund (Line 12 / Sch. 2 Sales) September 2021 Refund (Line 12 / Sch. 2 Sales) October 2021 Refund (Line 12 / Sch. 2 Sales)

Schedule 12A

Amount of Refund I

$0

$0

$0 I

(B)

Refund (Line 2 * A)

$0

$0

$0

$0

$0 I

$0

$0

$0

$0

$0 I

$0 $0 $0


Line

No. Rate Class Description


CEI SOUTH RECONCILIATION OF DEMAND VARIANCE

Demand

I Demand I

Variance Variance 50% Sales 50% Fixed / mo

(A) (B) Demand Variance: (Over) Under Recovery (Schedule 6, Line 11 a)

(a) December 2020 $3,898 $0 (b) January 2021 ($90,874) $0 (c) February 2021 ($231,791) ($231,791)

2 TOTAL ($318,767) ($231,791)

Distribution Of Demand Variances To Quarters

Demand

I Variance

Total (C) = (A)+(B)

$3,898 ($90,874)

($463,581)

($550,557)

Quarter Col A= Line 2 * Quarter! Sales Percenta es, Sch. 2 ; Col B = Line 2 / 4

3

4

5

6

7

8

9

10

11

12

13

13a 13b 13c

August 2021 - October 2021

November 2021 - January 2022

February 2022 - April 2022

May 2022 - July 2022

Total Demand Variance

($22,725)1 ($57,948)1

($159,383)1 ($57,948)1

($111,120) 1 ($57,948)1

($18,938)1 ($57,948)1

($318,766) 1 ($231,791)1

Calculation Of Demand Variances For This Cause

Cause No. 37366-GCA 148 (Sch. 12B (pg 1 of 2), Line 6) $3,134 $0

Cause No. 37366-GCA149 (Sch. 12B (pg 1 of 2), Line 5) $10,474 $0

Cause No. 37366-GCA150 (Sch. 12B (pg 1 of 2), Line 4) ($20,915) $0

Variance from this GCA (Sch. 12 B (pg 1 of 2), Line 3) ($22,725) ($57,948)

Total Demand Variances to be Included in GCA ($30,032)1 ($57,948)1

Adjusted Total Demand Variance to be included in GCA (Line 12) ($30,032)1 ($57,948)1

August 2021 Variance (Line 13 / Sch. 2 Sales) ($6,207) ($19,316) September 2021 Variance (Line 13 / Sch. 2 Sales) ($10,611) ($19,316) October 2021 Variance (Line 13 / Sch. 2 Sales) ($13,214) ($19,316)

Note: Lines 13a-13C Col A= Line 13 * Quarterly Sales Percentages, Sch. 2 Col B = Line 13 / 3

($80,673)

($217,331)

($175,668)

($76,886)

($550,557)

$3,134

$10,474

($20,915)

($80,673)

($87,980)1

($87,980)1

($25,522) ($29,927) ($32,530)

Schedule 12B Page 1



Line

No.

2

CEISOUTH RECONCILIATION OF COMMODITY VARIANCE

Rate Class Descriotion

Commodity Variance: (Over) Under Recovery (Schedule 6, Line 11 b)

(a) December 2020 (b) January 2021 (c) February 2021 (d) LIFO Adjustment (e) Bad Debt Gas Cost Adjustment Dec. & Jan. (from Sch. 12C, L 6) (f) Bad Debt Gas Cost Adjustment - February 2021 (from Sch. 12C, L 6)

(g) Bad Debt Gas Cost Adjustment - LIFO Adjusted

TOTAL

Commodity Variance

50% Sales

(A)

($14,405) $325,292

$9,134,225 $742,254

$3,414 $58,077

$4,824

$10,253,681 I Distribution Of Commodity Variance To Quarters

Commodity Variance

50% Fixed oer Month

(B)

$0 $0

$9,134,225 $0 $0

$58,077 $0

$9,192,302 I

Commodity Variance

Total

(C) = (A)+(B)

Schedule 12B Page 2

($14,405) $325,292

$18,268,450 $742,254

$3,414 $116,154

$4,824

$19,445,983

Quarter Col A = Line 2 * Quarter! Sales Percenta es, Sch. 2 ; Col B = Line 2 / 4

3 August 2021 - October 2021 $730,985 $2,298,076 $3,029,061

4 November 2021 - January 2022 $5,126,841 $2,298,076 $7,424,917

5 February 2022 -April 2022 $3,786,684 $2,298,076 $6,084,760

6 May 2022 - July 2022 $609,171 $2,298,076 $2,907,247

7 Total Commodity Variance $10,253,681 $9,192,302 I $19,445,983 1

Calculation Of Commodity Variance For This Cause

Cause No. 37366-GCA 148 8 (Sch 12B (pg 2 of 2) , Line 6) ($12,278) $0 ($12,278)

Cause No. 37366-GCA149 9 (Sch 12B (pg 2 of 2) , Line 5) $26,610 $0 $26,610

Cause No. 37366-GCA 150 10 (Sch 12B (pg 2 of 2), Line 4) ($435) $0 ($435)

Variance from this GCA 11 (Sch 12B (pg 2 of 2) , Line 3) $730,985 $2,298,076 $3,029,061

12 Total Commodity Variance to be Included in GCA $744,ss2 I $2,29s,o76 I $3,042,958 I

13 Adjusted Total Commodity Variance to be included in GCA (Line 12) $744,ssz I $2,2ss,07s 1 $3,042,sss 1

13a August 2021 Variance (Line 13 / Sch. 2 Sales) $153,942 $766,025 $919,967 13b September 2021 Variance (Line 13 / Sch. 2 Sales) $263,192 $766,025 $1,029,217 13c October 2021 Variance (Line 13 / Sch. 2 Sales) $327,748 $766,025 $1,093,773

Note: Lines 13a-13C Col A = Line 13 * Quarterly Sales Percentages, Sch. 2 Col B = Line 13 / 3



CEI SOUTH

TABLE NO.1 Effects of

Estimated GCA v. Currently Effective GCA For Residential Customers

Bill At Bill At Currently Dollar

Consumption Estimated Effective Increase 0th GCA GCA (Decrease)

5 $79.49 $58.20 $21.29

10 $132.28 $89.70 $42.58

15 $185.08 $121.21 $63.87

20 $237.87 $152.71 $85.16

25 $290.67 $184.22 $106.45

Estimated GCA v. Currently Effective GCA Currently

Estimated Approved Customer Service Charge $11.00 $11.00 Commodity Charge Block 1 $1.620 $1.620 Commodity Charge Block 2 $1.302 $1.302 USF Rider (Eff. 10/1/20) $0.041 $0.041 EEFC (Eff. 5/6/21) $0.1605 $0.1605 SRC (Eff. 5/6/21) $0.1507 $0.1507 CSIA (Eff. 1/21/21) $14.100 $14.100 GCA150 $8.905 $4.647

TABLE NO. 2

Effects of Estimated GCA v. Prior Year Effective GCA

For Residential Customers

Bill At Bill At Prior Year Dollar

Consumption Estimated Effective Increase Dth GCA GCA (Decrease)

5 $79.49 $54.75 $24.74

10 $132.28 $82.79 $49.50

15 $185.08 $110.82 $74.26

20 $237.87 $138.86 $99.01

25 $290.67 $166.90 $123.77

Estimated GCA v. Prior Year Effective GCA Prior Year

Estimated Approved Customer Service Charge $11.00 $11.00 Commodity Charge Block 1 $1.620 $1.620 Commodity Charge Block 2 $1.302 $1.302 USF Rider (Eff. 10/1/20) $0.041 $0.0390 EEFC (Eff. 5/6/21) $0.1605 $0.1407 SRC (Eff. 5/6/21) $0.1507 $0.1388 CSIA (Eff. 1/21/21) $14.1000 $14.1200 GCA 147 $8.905 $3.987


Percent Increase

(Decrease)

36.58%

47.47%

52.69%

55.76%

57.78%

Percent Increase

(Decrease)

45.19%

59.79%

67.00%

71.30%

74.16%

"-



CEI SOUTH

TABLE NO. 2 A

Effects of


Estimated August 2021 v. Prior Year Effective GCA For Residential Customers

Bill At Bill At Prior Year Dollar Percent

Consumption Estimated Effective Increase Increase Dth GCA GCA (Decrease) (Decrease)

5 $89.61 $54.30 $35.31 65.02%

10 $152.53 $81.90 $70.64 86.25%

15 $215.45 $109.49 $105.97 96.78%

20 $278.37 $137.08 $141.29 103.07%

25 $341.30 $164.67 $176.62 107.26%

Estimated August 2021 v. Prior Year Effective GCA Prior Year

Estimated Approved Customer Service Charge $11.00 $11.00 Commodity Charge Block 1 $1.620 $1.620 Commodity Charge Block 2 $1.302 $1.302 USF Rider (Eff. 10/1 /20) $0.041 $0.038 EEFC (Eff. 5/6/21) $0.1605 $0.1407 SRC (Eff. 5/6/21) $0.1507 $0.1388 CSIA (Eff. 1/21/21) $14.1000 $14.1200

Aug-21 $10.930 $3.899



GEi SOUTH

TABLE NO. 2 B

Effects of


Estimated September 2021 v. Prior Year Effective GCA For Residential Customers


Consumption Estimated Effective Increase Increase 0th GCA GCA (Decrease) (Decrease)

5 $78.87 $55.86 $23.00 41.18%

10 $131.04 $85.02 $46.03 54.14%

15 $183.22 $114.17 $69.05 60.48%

20 $235.39 $143.32 $92.07 64.24%

25 $287.57 $172.47 $115.10 66.73%

Estimated September 2021 v. Prior Year Effective GCA Prior Year

Estimated Approved Customer Service Charge $11.00 $11.00 Commodity Charge Block 1 $1.620 $1.620 Commodity Charge Block 2 $1.302 $1.302 USF Rider (Eff. 10/1/20) $0.041 $0.038 EEFC (Eff. 5/6/21) $0.1605 $0.1407 SRC (Eff. 5/6/21) $0.1507 $0.1388 CSIA (Eff. 1/21/21) $14.100 $14.1200

Sep-21 $8.781 $4.211



CEI SOUTH

TABLE NO. 2 C

Effects of


Estimated October 2021 v. Prior Year Effective GCA For Residential Customers



5 $75.59 $54.38 $21.21 39.00%

10 $124.49 $82.06 $42.44 51.72%

15 $173.39 $109.73 $63.67 58.02%

20 $222.29 $137.40 $84.89 61.79%

25 $271.20 $165.07 $106.12 64.29%

Estimated October 2021 v. Prior Year Effective GCA Prior Year


Oct-21 $8.126 $3.912



August 2021

September 2021

October 2021

CEI SOUTH

TABLE N0.1 Effects of

Estimated GCA v. Prior Year Effective GCA For Residential Spaceheating Customers

At Normal Consumption Levels Bill At

Bill At Prior Year Dollar Consumption Estimated Effective Increase

Dth GCA GCA (Decrease)

1.0 $38.00 $30.96 $7.04

1.7 $43.38 $35.57 $7.81

2.1 $46.31 $37.41 $8.90


Estimated Approved Customer Service Charge $11.00 $11.00 Commodity Charge Block 1 $1.620 $1.620 Commodity Charge Block 2 $1.302 $1.302 USF Rider (Eff. 10/1 /20) $0.041 $0.039 EEFC (Eff. 5/6/21) $0.1605 $0.1407 SRC (Eff. 5/6/21) $0.1507 $0.1388 CSIA (Eff. 1/21/21) $14.100 $14.120 GCA Charge - August-21 $10.930 $3.899 GCA Charge - September-21 $8.781 $4.211 GCA Chan:ie - October-21 $8.126 $3.912

Percent Increase


(Decrease)

22.76%

21.94%

23.79%



CEISOUTH DETERMINATION OF GAS COST ADJUSTMENT (GCA)

WITH DEMAND COSTS ALLOCATED


Commodity and Other Line ESTIMATED COST OF GAS TO BE RECOVERED No.

Purchased Gas Costs (Schedule 3)

2 Contract Storage & Transportation Costs (Schedule 4)

3 Cost of Gas (lnj.)/With. From Storage (Schedule 5)

4 Total Estimated Gas Costs

5 Estimated Cost of Unaccounted For Gas [2]

6 Net Cost Of Gas To Be Recovered

I COMMODITY COSTS TO BE RECOVERED

7 CommodityVariance-(Schedule 128 (pg. 2 of2), Line 13)

8 1 /4 of Excess of NO I Above Authorized NO I

9 Commodity Variance per Dth of Sales ((Line 7 + Line 8)/Schedule 2 Sales)

10 Commodity Dollars to be Refunded (Schedule 12A, Line 12)

11 Commodity Refund Per Dth (Line 10/Schedule 2 Sales)

12 Commodity Gas Costs (Line 6)

13 Monthly Commodity Gas Costs Per Dth (Line 12/Schedule 2 Sales)

14 Total Commodity Cost Per Dth of Sales (Lines 9 + 11 + 13)

Demand [1] August-21 A B

$1,317,998 $2,284,122

$0 $0

$0 ($1,794,061)

$1 317,998 $490,061

N/A $4,411

$1,317,998 $490,061

$289,375

$0

$1.867

$0

$0.000

$490,061

$3.162

$5,029

[1] The Demand portion of Purchased Gas Costs and Contract Storage & Transportation Costs were determined by multiplying the quarterly sales quantities for each rate class by the per Dth costs listed on Schedule 1 A.

[2] For informational purposes only (Line 4 • 0.9%).

September-21 C

$2,550,849

$0

($1,730,336)

$820,513

$7,385

$820,513

$494,737

$0

$1.867

$0

$0.000

$820,513

$3.096

$4.963

October-21 D

$2,106,607

$0

($1,109,328)

$997,279

$8,976

$997,279

$616,088

$0

$1.867

$0

$0.000

$997,279

$3.022

$4.889


$8,259,576

$0

($4,633,725)

$3,625,851 1

$20,772

$3,s2s,8s1 1

$1,400,200

$0

$0

$2,307,853




Line (A) (B) No. DEMAND RELATED COSTS TO BE RECOVERED Total Rate 110/120/129

15 Demand Cost Variance (Schedule 12B (pg 1 of 2), Line 12) ($46,556)

16 Demand Variance Per 0th (Line 15 / Schedule 2 Sales) ($0.062)

17 TOTAL Current Demand Costs Per 0th (Schedule 1A, Line 3) $1.757

18 TOT AL Demand Costs Recovered Per 0th of Sales (Line 16 + Line 17) $1.695

I BAD DEBT GAS COSTS TO BE RECOVERED August-21 September-21

19 Total Commodity and Demand Costs $762,594 $1,286,168

20 Bad Debt Gas Costs (Line 19 * 0.65%) $4,957 $8,360

21 Bad Debt Cost Component per 0th (Line 20/Sch. 2 Sales) $0.032 $0.032

jGCA DERIVATION August-21 September-21

22 Total GCA Charges (Lines 14 + 18 + 21) 22a Rate 110/120/129 $6.756 $6.690

GAS COST ADJUSTMENT MODIFIED FOR 23 UTILITY RECEIPTS TAX --$/DTH

23a Rate 110/120/129 with IURT (Line 23a / .9853) $6.857 $6.790

*IURT Rate Effective 1/1/21 is .9853


October-21

$1,577,089

$10,251

$0.031

October-21

$6.615

$6.714

I




FOR THE PERIOD AUGUST 2021 THROUGH OCTOBER 2021 ($/Dth)

Line No. Description Aug-21 Sep-21 24 Schedule 3 - Purchases 760,740 852,120

25 Schedule 5 - Storage (604,500) (585,000)

26 Total Gas Available for Sales 156,240 267,120

27 UAFG Percentage - 0.9% 0.9% 0.9%

28 UAFG Volumes 1,406 2,404

29 Average Commodity Price (Line 6 + Line 26) $ 3.137 $ 3.072

30 UAFG Costs [1] $ 4,411 $ 7,385

31 Schedule 2 Sales 155,000 265,000

32 UAFG Component (Line 30 + Line 31) [2] $ 0.028 $ 0.028

[1] Equals amount shown on Sch. 1, P1, LS. [2] For informational purposes only.

$

$

$


Oct-21 712,390

(379,750)

332,640

0.9%

2,994

2.998

8,976

330,000

0.027



CE\ SOUTH QUARTERLY ALLOCATION OF DEMAND COSTS

ESTIMATE OF DEMAND COST FOR THE PROJECTED GCA QUARTER

Line No. Description

1 August 2021 Monthly Demand Costs 2 Asset Management Fee (Credit)* 3 September 2021 Monthly Demand Costs 4 Asset Management Fee (Credit)* 5 October 2021 Monthly Demand Costs 6 Asset Management Fee (Credit)*

7 GCA Quarter (August, September, & October 2021) Demand Cost

GCA Quarter Demand

Cost

$441,922 ($50,417) $428,695 ($50,417) $598,632 ($50,417)

$1,317,998

*New Asset Management Agreement (AMA) begins April 1, 2021. Credit is $50,417 per month

!Derivation of Unit Demand Rate:! Rate 110 Rate 120

8 Projected Quarter Sales (Sch. 2) 485,000 265,000

9 Total Unit Demand Rate $1.757 $1.757


Total

750,000




ESTIMATED SALES FOR THE TWELVE MONTHS ENDING JULY 2022

SUBJECT TO GCA

Sales Sales Sales Demand Not Subject Subject

Month/ Year Forecast ToGCA ToGCA Rate 110 Rate 120

Aug-21 155,000 155,000 100,000 55,000

Sep-21 265,000 265,000 170,000 95,000

Oct-21 330,000 330,000 215,000 115,000

Subtotal 750,000 0 750,000 485,000 26s,ooo I Nov-21 945,000 945,000 610,000 335,000

Dec-21 1,865,000 1,865,000 1,200,000 665,000

Jan-22 2,450,000 2,450,000 1,580,000 870,000

Subtotal 5,260,000 0 5,260,000 3,390,000 1,s?o,000 I Feb-22 1,950,000 1,950,000 1,260,000 690,000

Mar-22 1,315,000 1,315,000 850,000 465,000

Apr-22 620,000 620,000 400,000 220,000

Subtotal 3,885,000 0 3,885,000 2,510,000 1,37s,ooo I May-22 310,000 310,000 200,000 110,000

Jun-22 155,000 155,000 100,000 55,000

Jul-22 160,000 160,000 100,000 60,000

Subtotal 625,000 0 625,000 400,000 22s,ooo I Total 10,520,000 0 10,520,000 6,785,000 3,73s,ooo I

QUARTERLY PERCENTAGES BY RATE CLASS OF SALES SUBJECT TO GCA

Rate Rate Quarter Total Rate 110 Rate 120

August 2021 - October 2021 7.129% 7.148% 7.095%

November 2021 - January 2022 50.000% 49.963% 50.067%

February 2022 - April 2022 36.930% 36.993% 36.814%

May 2022 - July 2022 5.941% 5.896% 6.024%


(A)


TEXAS GAS NNS FT

FT - NNS (Current Month) (46,500) FT - NNS (SWING) 46,500 FIXED PRICE 0 LONG-TERM FIXED PRICE#2 15,416 LONG-TERM FIXED PRICE #4 23,124

Subtotal 38,541 1



Subtotal 719,099 I

TEXAS EASTERN


Subtotal 3,1001



Total All Suppliers 7so,140 I


GEi SOUTH ESTIMATED PURCHASED GAS COST - COMMODITY COST

August-21

(8) (C) (D) (E) (F) COMP. COMP. PURCHASED TRANSPORT WELLHEAD FUEL FUEL QUANTITIES RATE PRICE* (%) (DTH) (DTH) ($/DTH) ($/DTH)

(A)/(1-(8))

0.54% (252) (46,752) $0.0501 $2.4369 0.54% 252 46,752 $0.0501 $3.0250 0.54% 0 0 $0.0501 $0.0000 0.54% 84 15,500 $0.0501 $4.7600 0.54% 126 23,250 $0.0501 $4.4900

209 I 38,750 I

0.03% 33 108,533 $0.0323 $3.0670 0.03% 118 393,782 $0.0323 $3.0670 0.03% 65 217,000 $0.0323 $2.5136

2161 719,315 1

2.49% 79 3,179 $0.3896 $3.1120 2.49% 0 0 $0.3896 $3.1120

79 I 3,179 I

90,000 ($0.3400) 50,000 ($0.2650)

504 I 761,244 j

(G) (H) TRANSPORT WELLHEAD


(A)*(E) (D)'(F)

($2,330) ($113,931) $2,330 $141,426

$0 $0 $772 $73,780

$1,159 $104,393

$1,931 1 $205,668 1

$3,505 $332,869 $12,715 $1,207,730

$7,007 $545,445

$23,227 I $2,086,044 1

$1,208 $9,894 $0 $0

$1,208 I $9,894 1

($30,600) ($13,250)

$2s,3ss 1 $2,2s1,7ss I

Schedule 3 Page6

(I) TOTAL COST

($) (G)+(H)

($116,261) $143,756

$0 $74,552

$105,552

$207,599 j

$336,374 $1,220,445

$552.452

$2,109,271 1

$11,102 $0

$11,102 I

($30,600) ($13,250)

$2,2a4, 122 I


(A)


TEXAS GAS NNS FT

FT- NNS (Current Month) (45,000) FT - NNS (SWING) 110,000 FIXED PRICE 0 LONG-TERM FIXED PRICE#2 14,919 LONG-TERM FIXED PRICE#4 22,379

Subtotal 102,298 I



Subtotal 746,822 ! 24,894

TEXAS EASTERN


Subtotal 3,ooo I



Total All Suppliers 852,120 I


CEISOUTH ESTIMATED PURCHASED GAS COST- COMMODITY COST

September-21

(B) (C) (D) (E) (F) COMP. COMP. PURCHASED TRANSPORT WELLHEAD FUEL FUEL QUANTITIES RATE PRICE* (%) (DTH) (DTH) ($/DTH) ($/DTH)

(Al/(1-(B))

0.54% (244) (45,244) $0.0501 $2.4369 0.54% 597 110,597 $0.0501 $2.9960 0.54% 0 0 $0.0501 $0.0000 0.54% 81 15,000 $0.0501 $4.7600 0.54% 122 22,500 $0.0501 $4.4900

5551 102,853 I

0.03% 32 105,032 $0.0323 $3.0380 0.03% 130 432,015 $0.0323 $3.0380 0.03% 63 210,000 $0.0323 $2.5136

224 I 747,046 I

2.49% 77 3,077 $0.3896 $3.0580 2.49% 0 0 $0.3896 $3.0580

77! 3,077 I

90,000 ($0.3260) 50,000 ($0.2510)

8561 852,9761

(G) (HJ TRANSPORT WELLHEAD


(A)*(E) (D)*(F)

($2,255) ($110,255) $5,511 $331,349

$0 $0 $747 $71,400

$1,121 $101,025

$5,124 I $393,519 I

$3,392 $319,086 $13,950 $1,312,460

$6,781 $527,850

$24,123 I $2,159,396 I

$1,169 $9,408 $0 $0

$1,169 I $9,408 I

($29,340) ($12,550)

$30,416 ! $2,520,433 1

Schedule 3 Page1

(I) TOTAL COST

($) (G)+(H)

($112,510) $336,860

$0 $72,147

$102,146

$398,643 I

$322,478 $1,326,410

$534,631

$2,183,519 I

$10,577 $0

$10,577 I

($29,340) ($12,550)

$2,550,8491


Schedule 3 Page1


ESTIMATED PURCHASED GAS COST - COMMODITY COST

October-21


QUANTITIES FUEL FUEL QUANTITIES RATE PRICE* COST GAS COST COST SUPPLIER (DTH) (%) (DTH) (DTH) ($/DTH) ($/DTH) ($) ($) ($)

(AV(1-/B)) (A)*/El /D)'(F) (G)+/Hl

TEXAS GAS NNS FT

FT - NNS (Current Month) (31,000) 0.54% (168) (31,168) $0.0501 $2.4369 ($1,553) ($75,953) ($77,506) FT - NNS (SWING) 74,000 0.54% 402 74,402 $0.0501 $3.0090 $3,707 $223,876 $227,583 FIXED PRICE 0 0.54% 0 0 $0.0501 $0.0000 $0 $0 $0 LONG-TERM FIXED PRICE #2 15,416 0.54% 84 15,500 $0.0501 $4.7600 $772 $73,780 $74,552 LONG-TERM FIXED PRICE #4 23,124 0.54% 126 23,250 $0.0501 $4.4900 $1,159 $104,393 $105,552

Subtotal 81,5411 4431 81,9841 $4,085 I $326,096 I $330,181 1


FT - BACKHAUL FOM 108,500 0.03% 33 108,533 $0.0323 $3.0270 $3,505 $328,528 $332,033 FT - BACKHAUL SWING 302,314 0.03% 91 302,405 $0.0323 $3.0270 $9,765 $915,379 $925,144 FIXED PRICE 216,935 0.03% 65 217,000 $0.0323 $2.5136 $7,007 $545,445 $552,452

Subtotal 627,749 I 1881 627,937 I $20,277 I $1,789,352 I $1,809,629 I

TEXAS EASTERN


Subtotal 3,1001 791 3,179 I $1,208 I $9,719 I $10,927 I



Total All Suppliers 112,3so I 110 1 113,100 I $2s,s10I $2,081,037 I $2,106,6071


NYMEX Close Date:

NYMEX - August $ NYMEX - September $

NYMEX - October $

Purchase Price

August-21 $ September-21 $

October-21 $

6/21/2021

TGTNNS

3.215 3.201 3.217

Swing/FOM

3.025 2.996 3.009

TGTBH Swing/FOM

$ 3.067 $ 3.038 $ 3.027


CEI South For the Period August 2021 - October 2021

Purchase Price Workpaper

Current Basis Differential:

TGT NNS Basis - August $ (0.190) $

Basis - September $ (0.205) $ Basis - October $ (0.208) $

TETCO Swing/FOM

$ 3.112 $ 3.058 $ 3.057

TGTBH (0.148) $ (0.163) $ (0.190) $

TETCO (0.103) (0.143) (0.160)


CEI SOUTH Cause No. 37366-GCA151 FOR THE PERIOD AUGUST 2021 THROUGH OCTOBER 2021 Sch.3WACOG

WEIGHTED AVERAGE COST OF GAS Workpaper

August 2021 Seetember 2021 October 2021 Total Cause No. 37366-GCA151 Average

Volume Price Extension Volume Price Extension Volume Price Extension Volume Price Extension

LONG-TERM FINANCIAL PURCHASE #1 90,000 $ (0.3400) $ (30,600) 90,000 $ (0.3260) $ (29,340) 90,000 $ (0.3420) $ (30,780) 270,000 $ (0.3360) $ (90,720) LONG-TERM FINANCIAL PURCHASE #2 50,000 $ (0.2650) $ (13,250) 50,000 $ (0.2510) $ (12,550) 50,000 $ (0.2670) $ (13,350) 150,000 $ (0.2610) $ (39,150)

LONG-TERM FIXED PRICE #2 15,500 $ 4.7600 $ 73,780 15,000 $ 4.7600 $ 71,400 15,500 $ 4.7600 $ 73,780 46,000 $ 4.7600 $ 218,960 LONG-TERM FIXED PRICE #4 23250 $ 4.4900 $ 104,393 22,500 $ 4.4900 $ 101,025 23250 $ 4.4900 $ 104,393 69,000 $ 4.4900 $ 309,810 LONG-TERM FIXED WACOG 38,750 $ 3.4664 $ 134,323 37,500 $ 3.4809 $ 130,535 38,750 $ 3.4592 $ 134,043 115,000 $ 3.4687 $ 398,900

SHORT-TERM FIXEDTGT 217,000 $ 2.5136 $ 545,445 210,000 $ 2.5136 $ 527,850 217,000 $ 2.5136 $ 545,445 644,000 $ 2.5136 $ 1,618,740 SHORT-TERM FIXED WACOG 217,000 $ 2.5136 $ 545,445 210,000 $ 2.5136 $ 527,850 217,000 $ 2.5136 $ 545,445 644,000 $ 2.5136 $ 1,618,740

FIRST OF THE MONTH INDEX - TGT 108,533 $ 3.0670 $ 332,869 105,032 $ 3.0380 $ 319,086 108,533 $ 3.0270 $ 328,528 322,097 $ 3.0441 $ 980,483 FIRST OF THE MONTH INDEX - TETCO 3,179 $ 3.1120 $ 9,894 3,077 $ 3.0580 $ 9,408 3,179 $ 3.0570 $ 9,719 9,435 $ 3.0759 $ 29,021

FIRST OF THE MONTH WACOG 111,712 $ 3.0683 $ 342,763 108,108 $ 3.0386 $ 328,494 111,712 $ 3.0279 $ 338,247 331,532 $ 3.0450 $ 1,009,504

DAILY SWING INDEX - TGT 46,752 $ 3.0250 $ 141,426 110,597 $ 2.9960 $ 331,349 74,402 $ 3.0090 $ 223,876 231,751 $ 3.0060 $ 696,650 DAILY SWING INDEX - TGT BH 393,782 $ 3.0670 $ 1,207,730 432,015 $ 3.0380 $ 1,312,460 302,405 $ 3.0270 $ 915,379 1,128,201 $ 3.0452 $ 3,435,569 DAILY SWING INDEX - TETCO $ 3.1120 $ $ 3.0580 $ $ 3.0570 $ $ $

DAILY SWING WACOG 440,535 $ 3,0625 $ 1,349,156 542,612 $ 3.0294 $ 1,643,809 376,807 $ 3.0234 $ 1,139,255 1,359,953 $ 3.0385 $ 4,132,220

COMPANY STORAGE (604,500) $ 2.9678 $ (1,794,061) (585,000) $ 2.9578 $ (1,730,336) (379,750) $ 2.9212 $ (1,109,328) (1,569,250) $ 2.9528 $ (4,633,726) NNS - TEXAS GAS STORAGE (46,752) $ 2.4369 $ (113,931) (45,244) $ 2.4369 $ (110,255) (31,168) $ 2.4369 $ (75,953) (123,164) $ 2.4369 $ (300,139)

STORAGE WACOG (651,252) $ 2.9297 $ (1,907,992) (630,244) $ 2.9204 $ (1,840,591) (410,918) $ 2.8845 $ (1,185,281) (1,692,414) $ 2.9153 $ (4,933,865)

LONG-TERM FIXED WACOG 38,750 $ 3.4664 $ 134,323 37,500 $ 3.4809 $ 130,535 38,750 $ 3.4592 $ 134,043 115,000 $ 3.4687 $ 398,900 SHORT-TERM FIXEDWACOG 217,000 $ 2.5136 $ 545,445 210,000 $ 2.5136 $ 527,850 217,000 $ 2.5136 $ 545,445 644,000 $ 2.5136 $ 1,618,740

FIRST OF THE MONTH WACOG 111,712 $ 3,0683 $ 342,763 108,108 $ 3.0386 $ 328,494 111,712 $ 3,0279 $ 338,247 331,532 $ 3.0450 $ 1,009,504 DAILY SWING WACOG 440,535 $ 3.0625 $ 1,349,156 542,612 $ 3.0294 $ 1,643,809 376,807 $ 3.0234 $ 1,139,255 1,359,953 $ 3.0385 $ 4,132,220

STORAGE WACOG (651,252) $ 2.9297 $ (1,907,992) (630,244) $ 2.9204 $ (1,840,591) (410,918) $ 2.8845 $ (1,185,281) (1,692,414) $ 2.9153 $ (4,933,865)

TOTAL WEIGHTED AVERAGE COST OF GAS 156,744 $ 2.9583 $ 463,694 267,976 $ 2.9484 $ 790,097 333,350 $ 2.9150 $ 971,708 758,070 $ 2.9357 $ 2,225,498




ESTIMATED GAS STORAGE AND DELIVERED SERVICES COST

FOR THE PERIOD AUGUST 2021 THROUGH OCTOBER 2021 COMMODITY COST

Estimated Volumes Estimated Rates Estimated Cost Injected Withdrawn Injected Withdrawn Com- Injected Withdrawn

Month and Compressor presser Compressor Su lier Dth Dth Fuel Dth Dth Fuel Fuel Total

August-21

TEXAS GAS NNS (46,500) 0 0 $0.0501 $0.0501 $0 $0 $0 $0

Subtotal (46,500)1 01 01 $0 1 $0 1 $0 1 $0 1

September-21

TEXAS GAS NNS (45,000) 0 0 $0.0501 $0.0501 $0 $0 $0 $0

Subtotal (45,oooil 01 01 $0 1 $0 1 $0 1 $0 1

October-21

TEXAS GAS NNS (31,000) 0 0 $0.0501 $0.0501 $0 $0 $0 $0

Subtotal (31,000)1 01 01 $0 1 $0 1 $0 1 $0 1

Total Commodity Cost $0 I $0 I $0 $0 I




ESTIMATED COST OF GAS INJECTED AND WITHDRAWN FROM STORAGE AND DELIVERED SERVICES


Estimated Changes in Storage Month and Injected Withdrawn Net Estimated Gas Rates Cost of Gas

Type of Stora e Dth Dth Dth Demand Commodi Demand Commodit Net

August-21

Company (604,500) 0 (604,500) $2.968 $0 ($1,794,061) ($1,794,061)

(604,500)1 DI (604,500)1 $0 I ($1,794,061)1 ($1,794,061)1

September-21

Company (585,000) 0 (585,000) $2.958 $0 ($1,730,336) ($1,730,336)

(585,ooo) 1 DI (585,000)1 $0 I ($1,730,336) 1 ($1,730,336)1

October-21

Company (379,750) 0 (379,750) $2,921 $0 ($1,109,328) ($1,109,328)

(379,750)1 DI (379,750)1 $0 I ($1, 109,328)1 ($1,109,328) 1

Grand Total (1,5s9,25oJ 1 DI {1,569,250) I $0 I ($4,633,725)1 ($4,633,725) I



Line No.

(1)

GAS COST RECOVERED

Sales - Dth


Fiifrii VECTREN SOUTH


December 2020


1,210,904 544,243

II Ill

Rate Class 129

79 -Schedule 6 Page 1 of 3

Total

1,755,226

m (2) GCA (without IURT) from GCAl 48

(a) Demand Cost Component (Sch 1, Line 18) (b) Commodity Cost Component (Sch 1, Line 14)

$0.304 $0.304 $0.304 }-__ .... $:;2:.::.l.:.,;71;,.-_ _:;;$2:::;.l::.:.7.;1 __ --:.$.:;;2·:;:;17:..::1:.., 111M

(3)

(c) Total




(5) Demand Variance from GCAl 48,(Sch 12B (pg 1 of 2), Line 13b)



(8) Commondity Variance from GCA148,(Sch 12B (pg 2 of 2), Line 13b)

(9) Commodity Refunds From GCA148(Sch 12A, L12b)

(10) Total Commodity Costs Incurred (Line 7 + Line 8 +Line 9)



$2.475 $2.475 $2.475 I

$368,115 $2,628,872 $2,996,987

$165,450 $1,181,551 $1,347,001

$24 $172 $196

-Ill Ill




$533,589 $3,810,595 $4,344,184 I

$577,045 0

$577,045

($39,558)

$537,487

$4,127,308

($331,118)

$0

$3,796,190

$3,898

($14,405)

($10,507)!

-0.22%




Fiifrii VECTREN SOUTH


January 2021

Line No.

(1)

(2)

(3)

(4)

(5)

(6)

(7)

(8)

(9)

(10)

(11)

(12)

GAS COST RECOVERED

Sales - Dth

GCA (without IURD from GCA148 (a) Demand Cost Component (Sch 1, Line 18) (b) Commodity Cost Component (Sch 1, Line 14) (c) Total




Demand Variance from GCA148,(Sch 12B (pg 1 of 2), Line 13c)



Commondity Variance from GCA148,(Sch 12B (pg 2 of 2), Line 13c)

Commodity Refunds From GCA148(Sch 12A, L12c)




Rate Class 110

1,395,282

m $0.304 $2.473 $2.777

$424,166 $3,450,533 $3,874,699

(b) Total Commodity Variance (Over)/Under Recovery (Une 10 - Line 3b)


% of (Over)/Under Recovery to Costs (Line llc / (Line 4c + Line 7))

Rate Class 120

635,340

m $0.304 $2.473 $2.777

$193,143 $1,571,196 $1,764,339

Rate Class 129

172

m


Total

2,030,794

II $0.304 }m $2.473 $2.777 l

$52 $425 $477

II •

$617,361 $5,022,154 -$5,639,515 1

$577,045 0

$577,045

($50,558)

$526,487

$5,770,639

($423,193)

$0

$5,347,446

($90,874)

$325,292

$234,418 1

3.69%

Financial Close Month March 2021


Line No.

(1)

GAS COST RECOVERED

Sales - Dth


Mifrii VECTREN SOUTH


February 2021


1,537,529 688,202

m m

Rate Class 129

85

Ill


Total

2,225,816 -(2) GCA (without IURT) from GCAl 49 (a) Demand Cost Component (Sch 1, Line 18) (b) Commodity Cost Component (Sch 1, Line 14)

$0.420 $0.420 $0.420 } m $2.683 $2.683 $2.683

..---+$""'3..,..1.,,.,03,----$.;.,3,...,l,..,,0.,,..3---+-$3,....,l.,...,0"'3"'!

(3)

(c) Total

Cost of Gas Recovered (without IURT) (a) Demand Costs (Line 1 * Line 2a) (b) Commodity Costs Recovered (Line 1 * Line 2b) ( c) Tota I Gas Costs Recovered



(5) Demand Variance from GCA149,(Sch 128 (pg 1 of 2), Line 13a)



(8) Commondity Variance from GCA149,(Sch 128 (pg 2 of 2), Line 13a)

(9) Commodity Refunds From GCA149(Sch 12A, L12a)

(10) Total Commodity Costs Incurred (line 7 + Line 8 +Line 9)



$645,762 $4,125,190 $4,770,952

(b) Total Commodity Variance (Over)/Under Recovery (line 10 - Line 3b)

(c) Total Gas Cost Variance (line lla + Line llb)

(12) % of (Over)/Under Recovery to Costs (Line llc / (line 4c + Line 7))

$289,045 $1,846,446 $2,135,491

$36 $227 $263

m

-m

$934,843 $5,971,863 $6,906,106 I

$519,306 0

$519,306

($48,044)

$471,262

$24,541,585

($301,272)

$0

$24,240,313

($463,581)

$18,268,450

$17,804,869 1



VECTREN SOUTH DETERMINATION OF ACTUAL GAS COST


Line Iii/hi MMMM Iii/Mi

JiQ,_ December 2020 January: 2021 Februa[Y'. 2021 (1) Purchased Gas Cost (Schedule 8): II

(a) Demand Costs (Sch. 8, Page 2, Col.H) II $577,045 II $577,045 II $519,306

(b) Commodity & Other Costs (Sch. 8, Page 1 Col. M) :1;2,963,971 $2,966,804 $22,812,905

(2) Total Purchased Gas Cost (Lla + lb) $3 5:11 Q16 :1;3 5:13 8:19 m3322ll

(3) Cost of Gas (Injected Into) / Withdrawn From Storage (Schedule 10)

(a) Demand (Sch. 10, Col. L) $0 $0 $0 (b) Commodity (Sch. 10, Col. G) 1,163,337 2,803,835 1,728,680 (c) Total Cost of Storage Activity (L3a + L3b) $1163.337 $2,803.835 $1.728 680

Net Cost of Gas Totals: (4) Demand

II II II (a) Purchased Gas Cost (L la) $577,045 $577,045 $519,306 (b) Storage Demand (L 3a) Q. Q. Q. (c) Total Demand (L4a + 4b) $577,045 $577,045 $519,306

(5) Commodity (Line Nos. lb+ 3b) $4,127,308 $5,770,639 $24,541,585

(6) Net (Line Nos. 4c + 5) H.7Q4,;J~~ $6,347,6fl4 :t2s Q§Q,IW


TOTAL

$1,673,395

$28,743,680

$3Q1lZ,QZS

$0 5,695,852

$5 695 852

$1,673,395 Ml

$1,673,395

$34,439,532

$36 112,927

cause No. 37366-GCAlSl Petitioner's 'i'il<hibl~~ouni Schedule 8

NO!t!f.,f[!f,\-ffi!m~.f-jil'g>ES - COMMODITY Pagel of 2

Tied Out w/ JE Dl.0035, Purchased Gas JE I 11111-11 December 2020

Col (A) to (E) Col(F)/(M) Col (H) to (L) Net MMBTU By Pieeline Total Commodity Purchases By Pipeline Total Transport

Line Purchased Rate Invoiced/ Quantities Total No. Supplier TGT MGT TETCO ANR Other /MMBTUl /$/MMBTUl TGT MGT TETCO ANR Other Cost Received Billing

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N) (0)

l EXELON - PURCHASED GAS 980,394 0 6,283 0 0 986,677 $2.6346 $2,583,168 $0 $16,370 $0 $0 $2,599,538 996,8901 $2.599.538 2 ASSET MANAGER - DELIV SERV VAR 0 0 0 0 0 0 $0.0000 $37,071 $0 $2,445 $0 $0 $39,517 0 $39,517 Sum of A 3 BP CANADA 0 0 0 o o o $0.0000 $0 $0 $0 $0 $0 $0 0 $0 1,035,573

4 BoA / MERRILL LYNCH 38,750 o o o 0 38,750 $4.5980 $178,173 $0 $0 $0 $0 $178,173 38,683 $178,173 5 GAS HEDGING 0 0 0 0 o 0 $0.0000 $0 $0 $0 $0 $ 810 $810 0 $810 6 TGT-NNS 55,335 0 0 0 0 55,335 $2.3640 $ 130,812 $0 $0 $0 $0 $130,812 55,335 $130,812 7 STORAGE VARIBLE COSTS WITH/ (!NJ; 0 o o 0 0 o $0.0000 $0 $0 $0 $0 $ 3,007 $3,007 o $3,007 8 CASH-OUT END USERS 0 0 0 0 9,434 9,434 ($0.4155) $0 $0 $0 $0 $ (3,920) ($3,920) 9,434 ($3,920) 9 TEXAS GAS CASH OUTS 0 0 0 0 0 0 $0.0000 $0 $0 $0 $0 $0 $0

~~ $0

10 MGTCASH OUTS 0 0 0 0 0 0 $0.0000 $0 $1,589 $0 $0 $0 $1,589 $1,589 11 TETCO CASH-OUTS 0 o o 0 o 0 $0.0000 $0 $0 $14,446 $0 $0 $14,446 $14,446 12 LOCAL PRODUCTION 0 o o 0 o o $0.0000 $0 $0 $0 $0 $0 $0 o $0

MONTHLY SUBTOTAL I 1,1 I 12,963,971 I 1,100,342 I g963,971 11,1 2.694

Tied Out w/ JE 01.0035, Purchased Gas JE 1 11111-11 January 2021

Col (A) to (E) Col (F)/(M) Col (H) to (L) Net MMBTU By Pipeline Total Commodity Purchases By Pipeline Total Transport

Line Purchased Rate Invoiced/ Quantities Total No. Supplier TGT MGT TETCO ANR Other (MMBTU) /$/MM BTU) TGT MGT TETCO ANR Other Cost Received Billing

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N) (0)

l EXELON - PURCHASED GAS 991,721 o 3,708 o o 995,429 $2.6874 $2,666,675 $0 $8,469 $0 $0 $2,675,145 1,016,514 ! $2,675,145 2 ASSET MANAGER - DELIV SERV VAR o o o o o o $0.0000 $37,751 $0 $1,443 $0 $0 $39,194 0 . $39,194 Sum of 8 3 BP CANADA o o o o o o $0.0000 $0 $0 $0 $0 $0 $0 0 $0 1,055,200

4 BoA / MERRILL LYNCH 38,750 o o o o 38,750 $4.5980 $178,173 $0 $0 $0 $0 $178,173 38,686 $178,173 5 GAS HEDGING o o o o o o $0.0000 $0 $0 $0 $0 $ 60,870.00 $60,870 o $60,870 6 TGT-NNS 8,768 o o o o 8,768 $2.5610 $22,455 $0 $0 $0 $0 $22,455 8,768 $22,455 7 STORAGE VARIBLE COSTS WITH/ (!NJ; o o o o o o $0.0000 $0 $0 $0 $0 $483 $483 0 $483 8 CASH-OUT END USERS o o o o (6,768) (6,768) $6.6174 $0 $0 $0 $0 ($44,787) ($44,787) (6,768) ($44,787) 9 TEXAS GAS CASH OUTS o o o o o o $0.0000 $0 $0 $0 $0 $0 $0 ~f $0

10 MGT CASH OUTS o o o o o 0 $0.0000 $0 $0 $0 $0 $0 $0 $0 11 TETCO CASH-OUTS o o o o o 0 $0.0000 $0 $0 $35,271 $0 $0 $35,271 $35,271 12 LOCAL PRODUCTION o o o o o o $0.0000 $0 $0 $0 $0 $0 $0 o $0

MONTHLY SUBTOTAL I 1,036,179 I Ill I 12,966,804 I 1,os11200 I $2,966,804 111 2.806

Tied Out w/ JE 01.0035, Purchased Gas JE 111111-11 February 2021

Col (A) to (E) Col(F)/(M) Col (H) to (L) Net MMBTU B~ Pieeline Total Commodity Purchases By Pipeline Total Transport

Line Purchased Rate Invoiced/ Quantities Total N2,. Supplier Ifil MGT TETCO ANR Q!hg[ (MMBTU) [$/MMBTU) TGT MGT TETCO ANR Other Cost Received Billing

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N) (0) (E) (F)

l EXELON - PURCHASED GAS 1,027,480 195,095 14,714 158,500 o 1,395,789 $15.7776 $ 12,403,577 $5,409,869 $ 73,027 $4,135,783 $ $22,022,256 1,432,180 122.022.256 2 ASSET MANAGER - DELIV SERV VAR o o o o o o $0.0000 $ 33,416 $ $ 5,733 $0 $ $39,149 o $39,149 3 BP CANADA o o o o o o $0.0000 $ $ $ $0 $ $0 o $0 4 BoA / MERRILL LYNCH 34,690 o o o 0 34,690 $4.5966 $ 159,454 $ $ $0 $ $159,454 34,621 $159,454 5 GAS HEDGING 0 o o o o o $0.0000 $ $ $ $0 $ 19,850 $19,850 o $19,850 6 TGT-NNS 71,571 o o o o 71,571 $2.7640 $ 197,822 $ $ $0 $ $197,822 71,571 $197,822 Sum of C 7 STORAGE VARIBLE COSTS WITH/ (!NJ; o 0 o o o o $0.0000 $ $ $ $0 $ 7,192 $7,192 o $7,192 1,466,801

8 CASH-OUT END USERS o o o o 64,606 64,606 $5.8520 $ $ $ $0 $ 378,069 $378,069 64,606 ' $378,069

9 TEXAS GAS CASH OUTS o o o o o o $0.0000 $ $ $ $0 $ $0 o .•• ~ so 10 MGT CASH OUTS o o o o o o $0.0000 $ $ (2,284) $ $0 $ ($2,284) o ($2,284) 11 TETCO CASH-OUTS o o o o o o $0.0000 $ $ $ (8,603) $0 $ ($8,603) o ($8,603) 12 LOCAL PRODUCTION 0 0 o o o o $0.0000 $ $ $ $0 $ $0 o $0

MONTHLY SUBTOTAL I 1,566,656 I II I $22,s12,9os I 1,602,978 I 122,s12,9os ■

QUARTERLY TOTAL I 3,693,031 I I t28,743,68o I 3,160,s20 I 128<743,sso I 7.644

l•-1'

Cause No. 37366-GCA151 Petitioner's ~lllo1.m-1 Schedule 8

r.t{!fu~rr!eNf RWf-ijASES - DEMAND Page 2of 2 OO-Jan-00

26,876,059.62 26,876,060

December 2020

Tied Out w/ JE 01.0035, Purchased Gas JE I MiiiOH Line Total

...N!!. DEMAND TGT MGT TETCO Other Billing (A) (B) (E) (F) (H)

1 ASSET MANAGER $ 572,0S9 $ $ 6,085 $ $578,144 2 ASSET MANAGER - UTILJZATION FEE $ $ $ ($25,000) ($25,000) 3 ASSET MANAGER - TGT NNS OVERRUN $ $ $ $0 $0 4 ASSET MANAGER - VALUE SHARING CREDIT $ $ $ $0 $0 5 ASSET MANAGER - PIPELJNE VARIABLE COSTS $ $ $ $0 $0 6 OHIO VALLEY HUB $ $ $ $ 23,901 $23,901

TOTAL! $577,04 ••

January 2021

Tied Outw/ JE 01.0035, Purchased Gas JE 1111m+ Line Total ...N!!. DEMAND TGT MGT TETCO Other Billing

(A) (B) (E) (F) (H}

1 ASSET MANAGER $572,059 $0 $6,085 $0 $578,144 2 ASSET MANAGER - UTILIZATION FEE $0 $0 $0 ($25,000) ($25,000) 3 ASSET MANAGER - TGT NNS OVERRUN $0 $0 $0 $0 $0 4 ASSET MANAGER - VALUE SHARING CREDIT $0 $0 $0 $0 $0 5 ASSET MANAGER - PIPELINE VARIABLE COSTS $0 $0 $0 $0 $0 6 OHIO VALLEY HUB $0 $0 $0 $23,901 $23,901

TOTALi $577,041111

February 2021

I Tied Out w/ JE 01.00351 Purchased Gas JE 111111-1+ Line Total

...N!!. DEMAND NI MGT ill£Q Q!hfil Billing (A) (B) (E) (F) (H)

1 ASSET MANAGER $516,698 $0 $6,020 $0 $522,718 2 ASSET MANAGER - UTILJZATION FEE $0 $0 $0 $ (25,000) ($25,000) 3 ASSET MANAGER - TGT NNS OVERRUN $0 $0 $0 $0 $0 4 ASSET MANAGER - VALUE SHARING CREDIT $0 $0 $0 $0 $0 5 ASSET MANAGER - PIPELINE VARIABLE COSTS $0 $0 $0 $0 $0 6 OHIO VALLEY HUB $0 $0 $0 $21,588 $21,588

TOTAL( $519,3osll 11

Cause No. 37366-GCA151 Pelitin , r= .. '/_~ftR/;N S<lflth WACOG DETAILS Pmmb .. -20 'WElliWfet> l>.\tt!#J>/GEI~8sl'oF GAS DETAILS Page 1 Of 1

AttachlSl&ll!bl~ .. ET&-&!PPLEMENT

December 2020 January 2021 February 2021 Total GCA 151 Line Average No. Supplier Volume ~ Extension Volume Price Extension Volume Price Extension Volume Price Extension

TGT AREA: FIXED - SHORT TERM EXELON 325,500 $ 3,0548 $ 994,325 325,500 $ 3.0548 $ 994,325 294,000 $ 3.0548 $ 898,100 945,000 $ 3.0548 $ 2,886,750 INDEXED - FIRST OF MONTH EXELON $ $ $ $ $ $ $ $

3 DELIVERED EXELON 9,000 $ 2.8500 $ 25,650 $ $ 151,334 $ 26.2133 $ 3,966,962 160,334 $ 24.9018 $ 3,992,612 4 INDEXED-DAILY EXELON 645,894 $ 2.4202 $ 1,563,193 666,221 $ 2.5102 $ 1,672,350 582,146 $ 12.9495 $ 7,538,516 1,894,261 $ 5.6877 $ 10,774,059 5 INDEXED - MIXED TGT Cash-Outs $ $ $ $ $ $ $ $ 6 FIXED - LONG TERM BP Canada $ $ $ $ $ $ $ $ 7 FIXED-LONGTERM BoA/MerrillLych 38,750 $ 4.5980 $ 178,173 38,750 $ 4.5980 $ 178,173 34,690 $ 4.5966 $ 159,454 112,190 $ 4.5976 $ 515,799 8 OTHER Asset Manager Supplier Reservation Cost $ $ $ $ $ $ $ $

9 OTHER Asset Manager Delivery Service Variables ---~~ $ $ 37,071 ---~~ $ $ 37,751 --~~- $ $ 33,416 -~~=- $ $ 108,238 10 TOTAL COMMODITY 1,019,144 $ 2.7458 $ 2,798,412 1,030,471 $ 2.7974 $ 2,882,599 1,062,170 $ 11.8592 $ 12,596,447 3,111,785 $ 5.8736 $ 18,277,458

11 DEMAND _____ $ $ 572,059 _____ $ $ 572,059 _____ $ $ 516,698 --~=- $ $ 1,660,815

12 TOTALPEPL 1,019,144 $ 3.3072 $ 3,370,470 1,030,471 $ 3.3525 $ 3,454,657 1,062,170 $ 12.3456 $ 13,113,145 3,111,785 $ 6.4073 $ 19,938,273

ANRAREA: 13 DELIVERED EXELON $ $ S $ 158,500 S 26.0933 $ 4,135,783 158,500 $ 26.0933 $ 4,135,783

MGT AREA: 14 DELIVERED EXELON $ $ $ $ 195,095 $ 27.7294 $ 5,409,869 195,095 $ 27.7294 $ 5,409,869 15 INDEXED- MIXED MGT Cash-Outs $ $ 1,589 $ $ $ $ (2,284) $ $ (695) 16 OTHER Asset Manager Supplier Reservation Cost $ $ $ $ $ $ $ $ 17 OTHER Asset Manager Delivery Service Variables _____ $ $ $ $ --==c-=- $ $ _____ $ $ 18 TOTAL COMMODITY $ $ 1,589 _____ $ $ 353,595 $ 26.9895 $ 9,543,368 353,595 $ 26.9940 $ 9,544,956

19 DEMAND _____ $ $ _____ $ $ --==c-=- $

20 TOTAL ANR $ $ 1,589 $ $ 353,595 $ 26.9895 $ 9,543,368 353,595 $ 26.9940 $ 9,544,956

TGT NNS AREA: 21 FIXED - SHORT TERM EXELON $ $ $ $ $ $ $ $ 22 INDEXED - FIRST OF MONTH EXELON $ $ $ $ $ $ $ $ 23 INDEXED - DAILY EXELON $ $ $ $ $ $ $ $

24 STORAGE TGT No-Notice Storage 55,335 $ 2.3640 $ 130,812 8,768 $ 2.5610 $ 22,455 71,571 $ 2.7640 $ 197,822 135,674 $ 2.5877 $ 351,089 25 STORAGE Asset Manager Delivery Service Variables _____ $ $ 3,007 _____ $ $ 483 _____ $ $ 7,192 _____ $ $ 10,682 26 TOTAL COMMODITY 55,335 $ 2.4183 $ 133,819 8,768 $ 2.6161 $ 22,938 71,571 $ 2.8645 $ 205,014 135,674 $ 2.6665 $ 361,771

27 DEMAND ---==,- $ $ ---==c- $ $ _____ $ 28 TOTAL TGT 55,335 $ 2.4183 $ 133,819 8,768 $ 2.6161 $ 22,938 71,571 $ 2.8645 $ 205,014 135,674 $ 2.6665 $ 361,771

TETCO AREA: 29 FIXED-SHORT TERM $ $ $ $ $ $ $ $ 30 INDEXED - FIRST OF MONTH EXELON Invoice (Gas Cost Summary tab) 3,193 $ 2.7700 $ 8,845 3,193 $ 2.2700 $ 7,248 2,884 $ 2.6400 $ 7,614 9,270 $ 2.5573 $ 23,706 31 INDEXED-DAILY AssetManager 3,090 $ 2.4354 $ 7,525 515 $ 2.3710 $ 1,221 11,830 $ 5.5294 $ 65,413 15,435 $ 4.8046 $ 74,159 32 INDEXED - MIXED TETCO Cash-Outs $ $ 14,446 $ $ 35,271 $ $ (8,603) $ $ 41,114 33 OTHER Asset Manager Supplier Reservation Cost $ $ $ $ $ $

34 OTHER Asset Manager Delivery Service Variables ---~~ $ $ 2,445 --~=~ $ $ 1,443 --~=~ $ $ 5,733 --~=~ $ $ 9,622 35 TOTAL COMMODITY 6,283 $ 5.2938 $ 33,261 3,708 $ 12.1855 $ 45,184 14,714 $ 4.7680 $ 70,157 24,705 $ 6.0150 $ 148,601

36 DEMAND ---~~ $ $ 6,085 --~=,- $ $ 6,085 --~=~ $ $ 6,020 --~=~ $ $ 18,190 37 TOTAL TETCO 6,283 $ 6.2623 $ 39,346 3,708 $ 13.8265 $ 51,269 14,714 $ 5.1772 $ 76,177 24,705 $ 6.7513 $ 166,792

MISCELLANEOUS: 38 FIXED - SHORT TERM $ $ $ $ $ $ $ $ 39 INDEXED- MIXED Transportation Customer Cash Outs 9,434 $ (0.4155) $ (3,920) (6,768) $ 6.6174 $ (44,787) 64,606 $ 5.8520 $ 378,069 67,271 $ 4.8960 $ 329,362 40 INDEXED- MIXED Gas Hedging $ $ 810 $ $ 60,870 $ $ $ $ 61,680

41 OTHER Local Production _____ $ $ --~=~ $ $ --~~- $ $ 19,850 --~=- $ $ 19,850 42 TOTAL COMMODITY 9,434 $ (0.3296) $ (3,110) (6,768) $ (2.3763) $ 16,083 64,606 $ 6.1592 $ 397,919 67,271 $ 6.1080 $ 410,892

43 DEMAND _____ $ $ (1,099) _____ $ $ (1,099) _____ $ $ (3,412) _____ $ $ (5,610)

44 TOTAL MISCELLANEOUS 9,434 $ (0.4461) $ (4,209) (6,768) $ (2.2139) $ 14,984 64,606 $ 6.1064 $ 394,507 67,271 $ 6.0246 $ 405,282

TOTAL COMPANY: 45 FIXED-SHORTTERM 325,500 $ 3.0548 $ 994,325 325,500.00 $ 3.0548 $ 994,325 294,000 $ 3.0548 $ 898,100 945,000 $ 3.0548 $ 2,886,750 46 FIXED-LONGTERM 38,750 $ 4.5980 $ 178,173 38,750.00 $ 4.5980 $ 178,173 34,690 $ 4.5966 $ 159,454 112,190 $ 4.5976 $ 515,799 47 INDEXED-DAILY 648,984 $ 2.4203 $ 1,570,718 666,736.00 $ 2.5101 $ 1,673,571 593,976 $ 12.8017 $ 7,603,928 1,909,696 $ 5.6806 $ 10,848,218 48 INDEXED - FIRST OF MONTH 3,193 $ 2.7700 $ 8,845 3,193.00 $ 2.2700 $ 7,248 2,884 $ 2.6400 $ 7,614 9,270 $ 2.5573 $ 23,706 49 INDEXED-MIXED 9,434 $ 1.3701 $ 12,925 (6,768.09) $ (7.5877) $ 51,354 64,606 $ 5.6834 $ 367,182 67,271 $ 6.4138 $ 431,461 50 DELIVERED 9,000 $ 2.8500 $ 25,650 $ $ 504,929 $ 26.7614 $ 13,512,613 513,929 $ 26,3427 $ 13,538,263 51 STORAGE 55,335 $ 2.4183 $ 133,819 8,768.00 $ 2.6161 $ 22,938 71,571 $ 2.8645 $ 205,014 135,674 $ 2.6665 $ 361,771

52 OTHER -~==,- $ - • 39,517 -~=~,.,- $ ii 39,194 -~==,.,- $ - • 58,999 -----c-==~ $ $ 137,710 53 TOTAL COMMODITY 1,090,196 $ 2.7188 2,963,971 1,036,179 $ 2.8632 2,966,804 1,566,656 $ 14.5615 22,812,905 3,693,030 $ 7.7832 $ 28,743,679

55 TOTAL DEMAND -lllllllc-=~~ $ $ 577,045 tlllllllc-=,..,.,,.,- $ $ 577,045 111!1111-c==cc-- $ - $ 519,306 _____ $ $ 1,673,395

56 TOTALCOMPANY i111,090,196 $ 3.2481 II 3,541,016 !111,036,179 $ 3.4201 II 3,543,848 1111,566,656 $ 14.8930 II 23,332,211 3,693,030 $ 8.2363 $ 30,417,075 0 $ 0 $ (0) (0) $ (0)

$ $ $




VECTREN SOUTH ACTUAL COST OF GAS INJECTED INTO AND WITHDRAWN FROM STORAGE


Actual Changes in Storage Rates Actual Gas Cost

(Injected) Withdrawn

Month Dth Dth (Column A) (B)

December 2020

Company 24,865 579,152

Free Gas 1,138 580,290

January 2021

Company 8,448 1,009,278

February 2021

Company 40,484 550,720

Total 73,797 2,140,288

Net (Injection) Withdrawal

Dth (C)

604,011 I 1,138

605,155

II 1,011,726 I •

591,204 I ,., 2,214,085

Injected & Withdrawn

Demand (D)

Commodity (E)

$0.0000 1 $1.9260 I I

Summer Strip Pricing

$0.0000 1 $2.1550 1 I Summer Strip Pricing


(Injected) & Withdrawn

Demand (F)

$0

$0

$0

$0

Commodity (G)

$1,163,337 1111

$2,803,835 1111

$1,728,680 1111 $5,69s,ss2 1



Cause No. 37366-GCA151 VECTREN SOUTH Schedule 11 DETERMINATION OF UNACCOUNTED FOR GAS


Line (A) (B) (C) (D) No. December 2020 Janua!Y 2021 Februa!Y 2021 TOTAL

(1) Total Dth of Purchased Gas Delivered 1.100.342 1.057.200 1.602.978 3,760.520

(2) Total Dth of Transport Gas Delivered by Pipeline

(a) Cash Outs (9,434) 6,768 (64,606) (67,271) (b) Customer Transp. Deliveries 2.623.218 2,273,308 2.075.603 6,972,129 (c) Total Transported Gas Delivered (Line 2a + Line 2t 2,613.784 2.280.076 2.010.997 6,904,858

(3) Total Dth of Gas (Injected Into)/ Withdrawn From Storage

(a) From Storage (Schedule 10 Col. C) 605,155 1,017,726 591,204 2.214.085 (b) Third Party Storage Activity (7,874) 1.671 6.882 679 (c) Total Dth of Gas (Injected Into) / Withdrawn 597,281 1.019.397 598.086 2.214.764

from Storage

(4) Total Dth of Local Production Gas Delivered _Q _Q _Q _Q

(5) Total Dth of Other Gas Injected Into/Withdrawn From System

(a) Gas Loss - Facilities Damage Rpt. 0 0 0 _Q

(b) Gas Usage Not Billed Due to NONR (34) (70) (104) (208) (c) Total Dth of other Gas (Injected Into) / Withdrawr .cw Q._Q) (104) (208)

from Storage

(6) Total Dth of Gas Available (L 1 + L 2c + L 3c + L 4 + L 5) 4,311.373 4.356.603 4,211,957 12,879.934

(7) Total Dth of Gas Sold 1.755,226 2,030.794 2,225,816 6.011,836 (Sch. 6 Line 1)

(8) Total Dth of Gas Transported to Customers

(a) Rate Class 125 46,268 50,896 43,773 140.937 (b) Rate Class 145 196,851 209,239 244,397 650.487 (c) Rate Class 160 472,614 492,153 480,678 1.445.445 (d) Rate Class 170 1,872,340 1,580,091 1,200,242 4,652,673 (e) Total Dth of Gas Transported to Customers 2,588,073 2,332.379 1.969,090 6,889,542

(9) Total Dth of Gas Delivered to Customers (Line 7 + Line Se) 4.343 299 4.363.173 4.194.906 12.901.378

(10) Unaccounted For Gas (a) Total Dth of Unaccounted For Gas

(Line 6 - Line 9) (31.926) (6,570) 17.052 (21.444)

(11) Percentage of Unaccounted for Gas (Line 10(a) / Line 6) -0.70% -0.20% 0.40% -0.20%

Ill~!.!■ 1mm1 lll~MI Line (6) Tied Out w/ JE 01.0037, Unbilled JE, Sch 1



Line

No.

1

2

3

4

5

6

VECTREN SOUTH Determination of Bad Debt Gas Cost Recoveries

iiihJI NiUMI Description December 2020 January 2021

Actual Sales in Dth (from Sch. 6, Line 1) II 1,7ss,226 11 2,030,794

Projected Bad Debt Gas Cost Component ($/Dth) Ill $0.017 - $0.019 (from Sch. 1, Page 2, Line 21, prior GCAs)

Actual Bad Debt Gas Cost Recovery $29,839 $38,585 (Line 1 * Line 2)

Actual Recoverable Gas Costs (from Sch. 7, Line 6) $4,704,353 $6,347,684

Actual Recoverable Bad Debt Gas Costs $30,578 $41,260 (Line 4 * 0.65%)

Bad Debt Gas Cost Variance (Line 5 - Line 3) $739 $2,675

Schedule 12C

iih@i 3 Months Ending

February 2021 2/28/2021

II 2,22S,816 6,011,836

Ill $0.021

$46,742 $115,166

$25,060,891 $36,112,928

$162,896 $234,734

$116,154 $119,5681



Line No.

2

3

4

5

6

7

8

9

10

11

12

12a 12b 12c

CEI SOUTH INITIATION OF REFUND

Refunds to be Included in the GCA FOR THE PERIOD AUGUST 2021 THROUGH OCTOBER 2021

Description:

Nomination and Balancing Charges

Pipeline Refunds

Total to be Refunded

Distribution of Refunds to GCA Quarters

Quarter

August 2021 - October 2021

November 2021 - January 2022

February 2022 - April 2022

May 2022 - July 2022

I calculation Of Refunds To Be Returned In This GCA




Refunds from this GCA (Schedule 12A, Line 4)

Total to be Refunded in This Cause

August 2021 Refund (Line 12 / Sch. 2 Sales) September 2021 Refund (Line 12 / Sch. 2 Sales) October 2021 Refund (Line 12 / Sch. 2 Sales)

(A) Sales Percentage All Rate Classes (Schedule 2)

7.129%

50.000%

36.930%

5.941%

100.000% I

Schedule 12A

Amount of Refund\

(B)

Refund (Line 2 * A)

$0

$0

$0 I

$0

$0

$0

$0

$0 I

$0

$0

$0

$0

$0 I

$0 $0 $0



Line No.

2

3

4

5

6

7

8

9

10

11

12

13

13a 13b 13c

CEI SOUTH RECONCILIATION OF DEMAND VARIANCE

Rate Class Description

Demand Variance: (Over) Under Recovery (Schedule 6, Line 11 a)

(a) December 2020 (b) January 2021 (c) February 2021

TOTAL

Demand Variance

$3,898 ($90,874)

($463,581)

($550,557)

Distribution Of Demand Variances To Quarters

Quarter Line 2 * Quarter! Sales Percenta es, Sch. 2)

August 2021 - October 2021 ($39,249)1

November 2021 - January 2022 ($275,279) 1

February 2022 - April 2022 ($203,321 l I May 2022 - July 2022 ($32,709)1

Total Demand Variance ($550,558) I

Calculation Of Demand Variances For This Cause

Cause No. 37366-GCA 148 (Sch. 12B (pg 1 of 2), Line 6) $3,134

Cause No. 37366-GCA149 (Sch. 12B (pg 1 of 2), Line 5) $10,474

Cause No. 37366-GCA150 (Sch. 12B (pg 1 of 2), Line 4) ($20,915)

Variance from this GCA (Sch. 12 B (pg 1 of 2), Line 3) ($39,249)

Total Demand Variances to be Included in GCA ($46,556)1

Adjusted Total Demand Variance to be included in GCA (Line 12) ($46,556)1

August 2021 Variance (Line 13 / Sch. 2 Sales) ($9,622) September 2021 Variance (Line 13 / Sch. 2 Sales) ($16,450) October 2021 Variance (Line 13 / Sch. 2 Sales) ($20,485)

Schedule 12B Page 1



Line No.

2

3

4

5

6

7

8

9

10

11

12

13

13a 13b 13c

CEI SOUTH RECONCILIATION OF COMMODITY VARIANCE

Rate Class Descri tion

Commodity Variance: (Over) Under Recovery (Schedule 6, Line 11 b)

(a) December 2020 (b) January 2021 ( c) February 2021 (d) LIFO Adjustment (e) Annual UAF Adjustment - LIFO Adjusted (Sch. 11 B, L 18) (f) Bad Debt Gas Cost Adjustment (from Sch. 12C, L 6)

(g) Bad Debt Gas Cost Adjustment - LIFO Adjusted

TOTAL

Commodity Variance

($14,405) $325,292

$18,268,450 $742,254

$0 $119,568

$4,824

$19,445,983 1

Distribution Of Commodity Variance To Quarters Quarter Line 2 * Quarter! Sales Percenta es, Sch. 2

August 2021 - October 2021 $1,386,303

November 2021 - January 2022 $9,722,992

February 2022 - April 2022 $7,181,402

May 2022 - July 2022 $1,155,286

Total Commodity Variance ~19,445,983 I

Calculation Of Commodity Variance For This Cause

Cause No. 37366-GCA 148 (Sch 12B (pg 2 of 2) , Line 6) ($12,278)

Cause No. 37366-GCA149 (Sch 12B (pg 2 of 2) , Line 5) $26,610

Cause No. 37366-GCA150 (Sch 12B (pg 2 of 2), Line 4) ($435)

Variance from this GCA (Sch 12B (pg 2 of 2) , Line 3) $1,386,303

Total Commodity Variance to be Included in GCA $1,400,200 1

Adjusted Total Commodity Variance to be included in GCA (Line 12) $1,400,200 1

August 2021 Variance (Line 13 / Sch. 2 Sales) $289,375 September 2021 Variance (Line 13 / Sch. 2 Sales) $494,737 October 2021 Variance (Line 13 / Sch. 2 Sales) $616,088

Schedule 12B Page 2


Cause No. 37366-GCA 151 Schedule 14 Page 1 of4

GEi SOUTH

TABLE NO.1 Effects of

Estimated GCA v. Currently Effective GCA For Residential Customers

Bill At Bill At Currently Dollar Percent


5 $68.65 $58.20 $10.46 17.97%

10 $110.61 $89.70 $20.91 23.31%

15 $152.57 $121.21 $31.37 25.88%

20 $194.53 $152.71 $41.82 27.38%

25 $236,50 $184.22 $52.28 28.38%

Estimated GCA v. Currently Effective GCA Currently

Estimated Approved Customer Service Charge $11.00 $11.00 Commodity Charge Block 1 $1.620 $1,620 Commodity Charge Block 2 $1,302 $1.302 USF Rider (Eff. 10/1/20) $0.041 $0.041 EEFC (Eff. 5/6/21) $0.1605 $0.1605 SRC (Eff. 5/6/21) $0.1507 $0.1507 CSIA (Eff. 1/21/21) $14.100 $14.100 GCA150 $6.738 $4,647

TABLE NO. 2

Effects of Estimated GCA v. Prior Year Effective GCA




5 $68.65 $54.75 $13.90 25.40%

10 $110.61 $82.79 $27.83 33.61%

15 $152.57 $110.82 $41.75 37.67%

20 $194.53 $138,86 $55.67 40.09%

25 $236.50 $166.90 $69.60 41.70%


Estimated Approved Customer Service Charge $11.00 $11.00 Commodity Charge Block 1 $1.620 $1.620 Commodity Charge Block 2 $1.302 $1.302 USF Rider (Eff. 10/1/20) $0.041 $0.0390 EEFC (Eff. 5/6/21) $0.1605 $0.1407 SRC (Eff. 5/6/21) $0.1507 $0.1388 CSIA (Eff. 1/21/21) $14.1000 $14.1200 GCA 147 $6.738 $3.987

, Petitioner's Exhibit No. 1

Attachment KJT-3

Cause No. 37366-GCA151 Schedule 14 Page 2 of 4

CEI SOUTH

TABLE NO. 2A

Effects of Estimated August 2021 v. Prior Year Effective GCA




5 $69.25 $54.30 $14.94 27.52%

10 $111.80 $81.90 $29.91 36.52%

15 $154.36 $109.49 $44.87 40.98%

20 $196.91 $137.08 $59.83 43.65%

25 $239.47 $164.67 $74.80 45.42%

Estimated August 2021 v. Prior Year Effective GCA Prior Year

Estimated Approved Customer Service Charge $11.00 $11.00 Commodity Charge Block 1 $1.620 $1.620 Commodity Charge Block 2 $1.302 $1.302 USF Rider (Eff. 10/1/20) $0.041 $0.038 EEFC (Eff. 5/6/21) $0.1605 $0.1407 SRC (Eff. 5/6/21) $0.1507 $0.1388 CSIA(Eff.1/21/21) $14.1000 $14.1200

Aug-21 $6.857 $3.899



CEI SOUTH

TABLE NO. 2 B

Effects of


Estimated September 2021 v. Prior Year Effective GCA For Residential Customers



5 $68.91 $55.86 $13.05 23.36%

10 $111.13 $85.02 $26.12 30.72%

15 $153.35 $114.17 $39.19 34.32%

20 $195.57 $143.32 $52.25 36.46%

25 $237.80 $172.47 $65.32 37.87%

Estimated September 2021 v. Prior Year Effective GCA Prior Year


Sep-21 $6.790 $4.211



CEI SOUTH

TABLE NO. 2 C

Effects of


Estimated October 2021 v. Prior Year Effective GCA For Residential Customers



5 $68.53 $54.38 $14.15 26.02%

10 $110.37 $82.06 $28.32 34.51%

15 $152.21 $109.73 $42.49 38.72%

20 $194.05 $137.40 $56.65 41.23%

25 $235.90 $165.07 $70.82 42.90%

Estimated October 2021 v. Prior Year Effective GCA Prior Year


Oct-21 $6.714 $3.912



August 2021

September 2021

October 2021

CEI SOUTH

TABLE N0.1 Effects of

Estimated GCA v. Prior Year Effective GCA For Residential Spaceheating Customers

At Normal Consumption Levels Bill At

Bill At Prior Year Dollar Consumption Estimated Effective Increase

0th GCA GCA (Decrease)

1.0 $33.93 $30.96 $2.97

1.7 $40.00 $35.57 $4.42

2.1 $43.34 $37.41 $5.93


Estimated Approved Customer Service Charge $11.00 $11.00 Commodity Charge Block 1 $1.620 $1.620 Commodity Charge Block 2 $1.302 $1.302 USF Rider (Eff. 10/1 /20) $0.041 $0.039 EEFC (Eff. 5/6/21) $0.1605 $0.1407 SRC (Eff. 5/6/21) $0.1507 $0.1388 CSIA (Eff. 1/21/21) $14.100 $14.120 GCA Charge - August-21 $6.857 $3.899 GCA Charge - September-21 $6.790 $4.211 GCA Chan.:ie - October-21 $6.714 $3.912

Percent Increase


(Decrease)

9.60%

12.43%

15.87%

Cause No. 3735G-GC1\ 151 Petilioner'5 Exhibit No, 1

Altacl1me>11t KJT-4 CEI South

Par,~ lof 1

CE] South GCA 151 Alternative Method of Recovery for February 2021

Total GU\Sale> per Month (Sch,;dule 2

Percentage GC/i, of Sales per Mont

GCA151

Au~-21

155,000

1.4734%

116,154 17,92:1,023

9,134,225.00 (231,790.50)

53,077.00

8,960,511.50

GCA151

AUJt21

Se_e_-21

165,000

2.5190%

5eE_•21

330,000

3.1369%

Oct-21

GCA 152 Nov-21 Dec-21

945,000 1,865,000 2,450,000

B.9829% 17.7281% 23.2890%

GCA152

Nov-21 Dec-21

GCA153 Feb-22 Mar-22 A_e_r-22

1,950,000 1,315,000 620,000

18.5361% .12 . .5000% 5.8935%

GCA153

Feb·Z2 Mar-22. A.e_r-22.

GCA154

May-2:2

3.!0,000

2.9468%

GCA 154

May-22

Jun-22

155.000

1.4734%

Jun-22

Jul-2.2

160,000

1.5209%

Ju!-22

$ 134,582_ $ 230,092 $ 236,530 $ 820,517 $ $ 2,127,267 $ $ 1,141,778 $ 538,319 $ 269,164 $ 134.582 $ 138,924 $

$ (3,415) $ (5,839) $ (7,271) $ (.20,821) $ $ (53,982) $ $ (28,974} $ (13,661) $ {6,830) $ (3/11.5) $ (3,525) $

Total

10,520,000

100%

9,134,225 (231,791)

$ 356 $ 1.463 $ 1,822 $ 5,217 $ 1.0,296 $ 13,526 $ 10,765 $ 7,260 $ 3,423 $ 1,711 $ 856 $ 883 $ 58,077 132,02.3 $ 225,716 $ 281,081 $ 8011,913 $ 1,588,532 $ 2,086,811 $ 1,660,931 $ 1,120,0611 $ 528,091 $ 264,045 $ 132,023 $ 136,282 $ 8,960,512.

876,667

8.3333%

376,667

3.3333% 876,667

8.3333%

875,667 8,3}33~;

876,667

8.3333% 876,667

8.3333% 876,667

S.3333%

876,667

8.3333%

376,667

8.3333%

876,667

8.3333% 876,667 8.3333~0

876,667

8.3333%

$ 761,185 $ 761,185 $ 761,185 $ 761,185 $ 761,185 $ 761,185 $ 761,185 $ 761,185 $ 761,185 $ 761,185 $ 761,185 $ 761,135 $ $ (19,316) $ (19,316) $ (19,316) $ (EJ,316) $ (19,316) $ (19,316) $ (19,316) $ (19,316} $ (19,316) $ (19,316) $ (19,316) $ (19,316) $

10,520,000 100%

9,134,225 (231,791)

$ 4,840 $ 4,8,10 $ 4,840 $ 11,840 S 4,840 $ 11,840 S 4,8110 $ 11,840 $ 4,8,10 $ 4,840 $ 1LS40 $ 4,840 $ 58,077

746,709.29 $ 746,709 $ 746,709 $ 745,709 $ 746,709 $ 746,709 $ 746,709 $ 746,709 $ 7±6?Q? $ _ 746,709 $ __ 7116,7~ 7~6,709 $ ~960,512

17,921,023

GCA151 GCA 152 GCA 153 Aug-21 Sep-21 Oct-21 Nov-21 Dec-21 Jan-22 Feb·22 M;;r-22 Apr-22 ~-22 Jun-22 Jul-22 Total

Total 12 Month R1·":overy $ 132,022.75 $ 225,716.31 $ 281,080.68 S 804,912.87 $ 1,588,531.74 S 2,086,811.14 $ 1,660,931.31 S 1,120,063.94 $ 528,090.98 $ 264,045.49 $ [32,022.75 $ 136,281.54 $ 8,960,511.50

Tot~l 12 Month Recovery $ 746,709.29 5 746,709.29 $ 746,709.29 $ 746,709.29 S 746,709.29 $ 746,709_29 $ 746,709.29 $ 746.709.29 S 746,709.29 $ 7'16,709.29 $ 746,709.2.9 S 746,709.29 $ 3,960,51.\.50

$ 878,732.04 $ 972,425.60 $ 1,027,789.98 $ 1,551,622.15 $ 2,335,241.04 $ 2,833,520.43 $ 2,407,640.61 $ 1.,866,773.:?3 $ 1,274,800.27 $ 1,010,754.78 $ 878.732.04 $ 382,990.84 $ 17,921,023.00

$ $

ResidentialAUPC Residential lm_e.act__i_

155,000

5.669 5,754

1.0 5.75 $

265,000

3.670

1.7 6.33 $

330,000 945,000 1,865,000 2,450,000 1,950,000

3.115 $ 1-Ei42 $ 1.252 1.157 $ 1.235 $ 3.161 $ 1.666 $ 1.271 1.174 $ 1.253 S

5.9 11.7 15.30 12.10 6.64 $ 9.33 $ 14.87 $ 17.96 $ 15.16 $

1,315,000

1.420

1.441

8.20 11.81 $

620,000

2.0SG $ 2.0137 $

3.90 8.14 $

310,000

3.260

3.309

1.90 6.29 $

155,000

5.669

5.754

1.00 5.75 $

160,000 10,520,000

5.519 5.601

1.00 65.80 5.60 $ 114

PETITION ER'S - IURC Online Services Portal

Documents

Transcript of PETITION ER'S - IURC Online Services Portal