application - force.com

December 21, 2018

Ms. Kavita Kale

Executive Secretary

Michigan Public Service Commission

7109 West Saginaw Highway

Lansing, Michigan 48917

RE: In the matter of the Application of DTE GAS COMPANY for approval

of a Gas Cost Recovery Plan, 5-year Forecast and Monthly GCR Factor

for the 12 months ending March 31, 2020

MPSC Case No. U-20236

Dear Ms. Kale:

Attached for electronic filing in the above referenced matter is DTE Gas

Company’s Application for Approval of Gas Cost Recovery Plan and Monthly GCR

Factor, and Evaluation of its Five-Year Forecast, along with Testimony and Exhibits of

Witnesses, Eric P. Schiffer, George H. Chapel, Sherri M. Moore, Timothy J. Krysinski,

and Lucian Bratu. Also attached is the Proof of Service.

Very truly yours,

Lauren D. Donofrio

LDD/lah

Encl.

cc: Service List

DTE Gas Company

One Energy Plaza, 1635 WCB Detroit, MI 48226-1279

Lauren D. Donofrio

(313) 235-4017

[email protected]

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application of )

DTE GAS COMPANY for approval of a )

Gas Cost Recovery Plan, 5-year Forecast ) Case No. U-20236

and Monthly GCR Factor for the 12 months )

ending March 31, 2020 )

APPLICATION FOR APPROVAL OF DTE GAS COMPANY’S

GAS COST RECOVERY PLAN AND MONTHLY GCR FACTOR,

AND EVALUATION OF ITS FIVE-YEAR FORECAST

DTE Gas Company (“DTE Gas”) pursuant to 1939 PA 3, as amended, MCLA 460.6h et

seq., requests approval of its Gas Cost Recovery (“GCR”) Plan and monthly GCR factor for a 12-

month period from April 1, 2019 through March 31, 2020 (“GCR Plan Year”), and evaluation of

its five-year Forecast as set forth in this Application. In support of this request, DTE Gas states

the following:

1. DTE Gas is a subsidiary of DTE Energy Company, a Michigan corporation with its

principal offices located at One Energy Plaza, Detroit, MI 48226. DTE Gas is a public utility

subject to the jurisdiction of the Michigan Public Service Commission (“Commission” or

“MPSC”) and is engaged in the acquisition, storage, transportation, distribution, and sale of natural

gas and other related services to approximately 1.2 million residential, commercial and industrial

customers within the State of Michigan.

2. For the GCR Plan Year, DTE Gas proposes to implement a maximum base GCR

factor of $2.80 per thousand cubic feet (“Mcf”) that can be increased by a contingency factor

matrix based on increases in New York Mercantile Exchange (“NYMEX”) gas commodity prices

resulting in a new maximum GCR factor. The proposed maximum GCR factor, as adjusted, when

necessary, by the NYMEX based contingency factor matrix includes costs to be paid to DTE Gas’s

gas and pipeline suppliers. In addition, DTE Gas further proposes to implement for the GCR Plan

Year a Supplier of Last Resort (“SOLR”) Reservation Charge in the amount of $0.38 per Mcf that

2

will be billed to GCR customers while the Reservation Charge billed to Gas Customer Choice

(“GCC”) customers will be $0.24 per Mcf, which reflects the 30% discount from the average rate

as mandated by the Commission in Case No. U-17691.

4. The testimony and exhibits of E. P. Schiffer, G. H. Chapel, S. M. Moore, T. J.

Krysinski, and L. Bratu, attached to this Application and made part of it, support the proposed 12-

month GCR factor and constitute DTE Gas’s Gas Cost Recovery Plan for the requested 12-month

GCR factor along with its 5-Year Forecast of Gas Requirements in accordance with Sections 6h(3)

and (4) of 1939 PA 3, as amended.

5. This Application, including testimony and exhibits, will be promptly furnished to

all intervenors in DTE Gas’s 2018-2019 GCR Plan, Case No. U-18412 (“Case No. U-18412”). It

will also be promptly made available to any other persons seeking to intervene in this proceeding

pursuant to Rule 410 of the Commission’s Rules of Practice and Procedure.

6. This Application, including testimony and exhibits, continues to support

fundamental proposals including, but not limited to, DTE Gas’s fixed price purchase program and

also DTE Gas’s Reservation Charge.

7. In addition, this Application supports DTE Gas’s amended NEXUS pipeline

transportation contract for 37.5 Mdth/d of capacity with the addition of the Clarington Receipt

Point.

8. Jurisdiction in this matter is pursuant to 1939 PA 3, as amended, MCL 460.6h et

seq.; as well as 1909 PA 300, as amended; MCL 460.2 et seq.; 1919 PA 419, as amended; 1969

PA 306, as amended; MCL 24.200 et seq.; and the Commission’s Rules of Practice and Procedure,

1979 Michigan Administrative Code, R 460.17101 et seq.

WHEREFORE, DTE Gas respectfully prays that the Commission immediately commence

a gas supply and cost review pursuant to Sections 6h(5), (6) and (7) of 1939 PA 3, as amended,

3

establish dates for a hearing on DTE Gas’s Application, supporting testimony, and exhibits as soon

as scheduling permits in order to facilitate the issuance of a final Commission order that:

(i) Approves a maximum base gas cost recovery factor of $2.80 per Mcf that

can be adjusted to a new maximum GCR rate by the monthly NYMEX-

based contingency factor matrix, to be reflected in DTE Gas’s monthly gas

customer billings beginning April 1, 2019, and continuing through March

31, 2020, and further approves a SOLR Reservation Charge of an additional

$0.38 per Mcf that is billed to GCR customers while the Reservation Charge

billed to GCC customers will be $0.24 per Mcf;

(ii) Finds that DTE Gas’s 5-Year (April 2019-March 2024) Forecast of Gas

Requirements, Supplies and Costs, and Gas Supply Plan does not include

any cost items that the Commission would be unlikely to permit DTE Gas

to recover in the future;

(iii) Approves DTE Gas’s request for Commission review and approval for

amendment of DTE Gas’s NEXUS pipeline transportation capacity contract

as reflected in the testimony of Eric P. Schiffer; and

(iv) Grants such other and further relief as it may find appropriate.

Respectfully submitted,

DTE GAS COMPANY

By:

Lauren D. Donofrio (P66026)

One Energy Plaza, 688 WCB

Detroit, Michigan 48226

(313) 235-3724

Dated: December 21, 2018

Approved:

By:

Daniel G. Brudzynski

Vice President -Gas Sales & Supply-FERC Gas

Dated: December 21, 2018

STATE OF MICHIGAN



DTE Gas Company for approval of a )




)

QUALIFICATIONS

AND

DIRECT TESTIMONY

OF

GEORGE H. CHAPEL

DTE GAS COMPANY

QUALIFICATIONS OF GEORGE H. CHAPEL

Line

No.

GHC-1

Q1. What is your name, business address and by whom are you employed?1

A1. My name is George H. Chapel. My business address is DTE Energy Gas (“DTE 2

Gas” or “the Company”), One Energy Plaza, Detroit, Michigan 48226. I am 3

employed by DTE Gas as Manager, Market Forecasting. 4

5

Q2. On whose behalf are you testifying? 6

A2. I am testifying on behalf of DTE Gas Company. 7

8

Q3. What is your educational background? 9

A3. In December 1985, I earned a Bachelor of Science degree from Central Michigan 10

University with a major in mathematics. 11

12

Q4. What work experience do you have? 13

A4. In April 1988, I was hired by Michigan Gas Company (“MiGas”) as a Rates and Gas 14

Supply Analyst where I performed various duties of increasing responsibility arising 15

out of the regulation of MiGas as a public utility. In 1993, the assets of MiGas were 16

rolled in with those of affiliate Southeastern Michigan Gas Company and Battle 17

Creek Gas Company. These companies were combined to form what is known today 18

as SEMCO Energy Gas Company (“SEMCO”). My duties with SEMCO included 19

demand forecasting, supply planning, supply purchasing, nominating, and pipeline 20

capacity management. I have attended numerous industry conferences focusing on 21

natural gas demand forecasting, sharing knowledge and expertise with a nationwide 22

range of industry peers. 23

24

G. H. CHAPEL

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In May 1998, I was hired by Michigan Consolidated Gas Company (MichCon, later 1

DTE Gas) as a Gas Supply Analyst. My duties with the Company in that capacity 2

included supply purchasing and market analysis. In October 2000, I was promoted 3

to Manager, Gas Supply. I assumed my current position on January 1, 2003. 4

5

Q5. What are your current duties and responsibilities? 6

A5. I am responsible for projecting DTE Gas’ Gas Cost Reconciliation (GCR), Gas 7

Customer Choice (GCC), and Aggregate rate schedule customer growth/decline, 8

natural gas supply demand, and review and analysis of the natural gas market. These 9

duties support DTE Gas’ regulatory, finance, and accounting functions. 10

11

Q6. Have you been involved in any prior regulatory proceedings? 12

A6. Yes. I sponsored testimony on behalf of SEMCO and its subsidiaries in a variety of 13

cases before the Commission. These cases include two general rate cases, two 14

Michigan Residential Conservation Surcharge cases, and a several Gas Cost 15

Reconciliation (“GCR”) Plan and Reconciliation proceedings. I have also provided 16

testimony in a large number of regulatory proceedings for DTE Gas, including GCR 17

Plan and Reconciliation proceedings as well as DTE Gas’ most recent general rate 18

cases. My experience as a GCR witness began with SEMCO in 1990 and has 19

continued to the present day with DTE Gas.20

DTE GAS COMPANY

DIRECT TESTIMONY OF GEORGE H. CHAPEL

Line

No.

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Purpose of Testimony 1

Q7. What is the purpose of your testimony in this proceeding?2

A7. The purpose of my testimony is to present and describe the Company’s GCR market 3

forecast for the five-year operational period 2019-2024. My testimony will address 4

DTE Gas’s natural gas demand forecast over the next five years, April 2019 through 5

March 2024 (“the 5-Year Forecast Period”). My testimony will describe: 6

A) How the Company’s GCR/GCC sales are projected to be 156 Bcf for the 2019-7

2020 GCR Plan year and decreasing slightly over the course of the five-year 8

forecast period. It will also describe how the number of customers is expected to 9

increase over the five-year period due primarily to steadily increasing new 10

customer attachments anticipated over the five-year period. 11

B) The Company’s rate schedule market forecast techniques. I will describe how 12

the Company’s customer count forecast is projected using a build-up approach 13

that incorporates various components that contribute to customer count increases 14

and decreases and how customer demand is projected using the Company’s three-15

step linear methodology. 16

C) The Company’s GCC projection and why it is expected to remain unchanged 17

over the five-year period. 18

D) The Company’s 2020 peak day load requirements, which are expected to change 19

from the volumes projected in last year’s Plan case. 20

E) The Company’s ongoing conservation assumptions with regard to its filed Energy 21

Waste Reduction (EWR) plan. 22

For reasons more fully described in my testimony below, the conclusions and 23

opinions I have reached regarding the above subjects support the reasonableness and 24

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prudence of the decisions underlying DTE Gas’s proposed GCR plan for the 12-1

month period ending March 31, 2020. 2

3

Q8. Are you sponsoring any exhibits in this proceeding? 4

A8. Yes. I am sponsoring the following exhibits: 5

Exhibit Description 6

A-1 Market Outlook – Weather Normalized Sales & Customers 7

A-2 Market Forecast Analysis – Forecasted GCR Volumes 8

A-3 Market Forecast Analysis - Forecasted GCR Number of Customers 9

A-4 April 2019 – March 2024 Total Market Requirements 10

A-5 Mean Peak Day Temperatures by District Peak Day Load by Area 11

A-6 Historical Normalized Annual Sales (GCR & GCC) 12

13

Q9. Were these exhibits prepared by you or under your direction? 14

A9. Yes, they were. 15

16

MARKET OUTLOOK 17

Q10. What is DTE Gas’s rate schedule and GCR sales forecast for the 2019 through 18

2024 planning period? 19

A10. For the April 2019 - March 2020 operational plan year (OPY), I am forecasting 20

GCR/GCC sales volumes of approximately 156 Bcf for DTE Gas’ rate schedule sales 21

customers (Exhibit A-1, page 1 of 2, line 13, column (a)). Rate schedule sales 22

customers include both GCR customers and Gas Customer Choice (GCC) customers. 23

Over the course of the five-year forecast period, I am expecting annual volumes to 24

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decrease slightly, with sales decreasing to approximately 155 Bcf for April 2023 – 1

March 2024. 2

3

Q11. Why are you projecting annual volumes to decrease slightly? 4

A11. Though the Company expects that customer count will grow over the five-year 5

forecast period, I expect the ongoing efforts of the Company’s EWR program to more 6

than offset the higher volumes normally associated with customer count growth. The 7

combination of higher customer count along with the Company’s ongoing EWR 8

efforts are expected to result in a slight reduction to overall GCR/GCC natural gas 9

demand by the end of the five-year forecast period. 10

11

Q12. What is your projection for average number of rate schedule customers from 12

2019 through 2024? 13

A12. As reflected on Exhibit A-1, page 2 of 2, line 13, column (a), I am projecting 14

approximately 1.28 million rate schedule customers (mean average) during the 2019-15

2020 OPY. This number is expected to increase to approximately 1.33 million 16

customers through 2023-2024 as shown in columns (b) through (e), line 13. 17

18

Q13. Why is DTE Gas’s customer count projected to increase over the course of the 19

five-year forecast period? 20

A13. The Company’s customer count continues to show growth. The Company continues 21

to observe a higher rate of requests for service and a lower rate of customer-requested 22

terminations of service, which could be reasonably interpreted as a sign that the 23

Company is still experiencing a period of customer growth. 24

25

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One reason that customer count is projected to grow over the five-year forecast period 1

is as a result of DTE Gas’s continuing actions to reduce long-term uncollectible gas 2

expenses, which include meter locking and service cutting of customers for non-3

payment. These actions are intended and expected to encourage customers to stay 4

current on their outstanding balances, thereby maintaining existing customers that 5

would otherwise have been removed from gas service. 6

7

WEATHER NORMAL PERIODS 8

Q14. What is weather normalization and how is it used? 9

A14. Weather normalization adjusts actual volumes from a past period to eliminate the 10

impact of non-normal weather on the data during that time period. Weather-11

normalized data is then used to make inferences about customer behavior trends. 12

Normal weather is also a key component in compiling volumetric forecasts. 13

14

Q15. What weather-normalization technique does DTE Gas utilize to calculate 15

normal weather? 16

A15. Consistent with the weather-normalization methodology included in prior 17

Commission-approved GCR Plan Cases, the Company uses a rolling 15-Year Normal 18

weather pattern to project its normal demand requirements in this GCR Plan. 19

20

Q16. What 15-year period is DTE Gas using in this plan? 21

A16. DTE Gas is calculating 15-year weather based upon actual weather from calendar 22

year 2003 to calendar year 2017. 23

24

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Q17. Why is DTE Gas proposing to utilize 15-year normal to project forecasted 1

demand requirements in this case? 2

A17. Consistent with the Commission Order in Case No. U-15985 (general rate case), DTE 3

Gas utilizes a rolling 15-year weather for its normal weather in all regulatory filings. 4

5

Q18. Why is the weather-normalization period important? 6

A18. Weather is one of the primary determinants of natural gas demand. If the Company 7

can project Heating Degree Days (HDDs) more accurately, then it can more 8

accurately project demand on its system. Accurate projections lead to optimal 9

planning, which in turn reduces the gas costs DTE Gas will need to recover from its 10

customers. 11

12

Q19. What is an HDD? 13

A19. An HDD is a measure of how temperature relates to natural gas usage for heating 14

purposes; HDDs give an indication of a customer’s likelihood of turning on their 15

furnace to heat their home or facility. Basically, the greater the HDDs, the greater 16

the heating demand. Mathematically, HDDs are defined as the greater of A) zero, or 17

B) 65 – average daily temperature (in degrees Fahrenheit). 18

19

For instance, if the daily high temperature is 30 degrees and the daily low temperature 20

is 20 degrees, then the daily average temperature is 25 degrees. The HDDs for that 21

day then, are: 65 – 25 = 40 HDDs. 22

23

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GHC-8

If, on the other hand, the daily high temperature is 90 degrees and the daily low 1

temperature is 70 degrees, then the daily average temperature is 80 degrees. The 2

HDDs for that day then, are 0, since 65 – 80 results in a negative value. 3

4

RESIDENTIAL RATE SCHEDULE SALES MARKET 5

Q20. How did you develop the forecast for the residential rate schedule sales market 6

including both GCR and GCC customers? 7

A20. The projected residential GCR sales markets are shown on Exhibit A-2, lines 1 8

through 5. There are two key elements used in projecting volumes in the residential 9

sales market. The first element is the forecast of the number of customers, by month, 10

in the seven different market areas that DTE Gas serves. These seven different 11

service regions are: Detroit/Ann Arbor, Grand Rapids, Muskegon, Traverse City, 12

Alpena, Sault Ste. Marie, and Iron Mountain. 13

14

The second element is an analysis of the usage per customer per HDD at varying 15

temperatures. The Company uses a three-step linear factor model that determines the 16

monthly demand for all rate classes. 17

18

The combination of the two elements (customer count and three-step linear heat load 19

factor), along with normal HDDs by month for each respective market area yields the 20

residential sales market forecast. 21

22

Q21. How does the three-step linear methodology work? 23

A21. The three-step linear equation consists of three components: a base load component 24

and two linear temperature-driven components. The base load component 25

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determines how much gas a customer is expected to use every single day, regardless 1

of the weather. The remaining linear temperature-driven components determine how 2

much gas a customer is expected to use depending on how many HDDs are present 3

on any given day. The three-step linear equation is described mathematically with the 4

following equation: 5

6

Customer’s Demand = BL + ax + bx55 7

8

where BL = base load, x = daily HDDs between 55 and 65 degrees Fahrenheit, and 9

x55 = daily HDDs below 55 degrees Fahrenheit. Further, a and b represent usage 10

coefficients unique to both a rate class and a demand region. The “a” coefficient is 11

generally a lower value than the “b” coefficient because the “a” coefficient represents 12

typical customer usage in aggregate at average temperatures between 55 and 65 13

degrees Fahrenheit; these are levels where some, but not all of DTE Gas’s customers 14

will turn on their furnace. This has the impact of dampening the demand calculation 15

in the spring and fall months by weighting the lesser “a” usage coefficient more 16

heavily during mild weather. Conversely, it has the impact of calculating higher heat 17

load factors in the winter months by weighting the higher “b” usage coefficient more 18

heavily during colder weather. The “b” coefficient represents typical customer usage 19

at average temperatures below 55 degrees Fahrenheit, levels at which nearly all of 20

DTE Gas’s active space heating customers turn on their furnace. 21

22

For the purposes of example, I have included a general graph that depicts this 23

equation. It shows the daily consumption pattern of a typical Residential Space 24

Heating customer. At relatively low HDDs (<10), on the left side of the graph, the 25

G. H. CHAPEL

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GHC-10

slope of the graph is upward, but gradual. At higher levels of HDDs (>10), the slope 1

of the graph gets steeper, indicating higher consumption per HDD the colder it gets. 2

3

Please note that the above graph is for illustrative purposes only and does not 4

represent any specific DTE Gas customer class. 5

6

Q22. How did you develop the forecast of the number of residential customers, 7

including both GCR and GCC? 8

A22. Monthly customer additions and losses in each of DTE Gas’s seven service regions 9

over a three-year period were analyzed to develop a trend factor for the number of 10

residential customers. The historical data used is the actual monthly billing data for 11

G. H. CHAPEL

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GHC-11

each of the nearly 1.3 million DTE GCR/GCC customers across DTE Gas’s service 1

territory. Customer growth and loss, by month, is then projected for each region and 2

projected forward for five years to develop the demand forecast. 3

4

The forecast also reflects marketing initiatives within the Company that are expected 5

to add 10,000-12,000 customers annually over the 5-Year Forecast Plan Period. The 6

Company also expects customer count reductions over the ensuing five OPYs due to 7

continued efforts at locking and cutting & capping customers because of theft or non-8

payment. These locks and cuts & caps are expected to occur at a level of 9

approximately 8,400 in OPY 2019-2020 and stay at that level over the remaining 10

years of the five-year forecast period. As discussed elsewhere in my testimony, other 11

factors ultimately outweigh the customer reductions related to locking and cut and 12

cap activity such that, over the five OPYs, DTE Gas expects a net increase in 13

customer count. 14

15

COMMERCIAL & INDUSTRIAL MARKETS 16

Q23. How did you develop the forecast for commercial and small industrial markets 17

including both GCR and GCC customers? 18

A23. The methodology used for forecasting volumes in the commercial and small 19

industrial GCR and GCC markets is essentially the same as that used for the 20

residential market. The process involves forecasting the number of customers for 21

each year and calculating the average base load and usage per HDD per customer. 22

As reflected on Exhibit A-1, page 1 of 1, line 10, I am projecting a slight decrease in 23

commercial and industrial GCR volumes from 26.3 Bcf to 25.9 Bcf for commercial 24

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and industrial GCR sales customers from OPY 2019-2020 to OPY 2023-2024, 1

respectively. 2

3

Q24. For which of the commercial and industrial classes do you use the three-step 4

linear forecast methodology? 5

A24. All rate classes are forecast using the three-step linear methodology. 6

7

Q25. Does the implementation of the three-step linear methodology impact the way 8

in which DTE Gas calculates its Warmer-than-Normal and Colder-than-9

Normal weather scenarios? 10

A25. Yes. The three-step linear approach captures the sensitivities around Warmer-than-11

Normal, and Colder-than-Normal scenarios. During a period of very cold weather, 12

the “b” coefficient (see page 9), which is generally greater than the “a” coefficient, 13

has greater weight in the equation, generating increasingly higher heat load factors 14

because the weather data includes colder temperatures. During a period of very warm 15

weather, the “b” coefficient has less weight, and the equation will generate 16

decreasingly lower heat load factors as the weather gets warmer. The net result is 17

that the three-step method will produce lower consumption per customer per HDD 18

during warmer weather (i.e. spring and fall months) and higher consumption per 19

customer per HDD during colder weather (i.e. the deep winter months). This 20

phenomenon produces an asymmetry in the application of Colder-than-Normal and 21

Warmer-than-Normal demands. 22

23

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GAS CUSTOMER CHOICE 1

Q26. What impact does the GCC program have on forecasted DTE Gas’ markets? 2

A26. The GCC program continues to have a significant impact on DTE Gas’s GCR 3

markets. For 2019-2020 OPY, I have assumed that approximately 156,000 4

customers, or about 12% of DTE Gas’ total rate schedule customers, will be served 5

by an alternate supplier through the GCC program (Exhibit A-1, page 2 of 2, line 12). 6

Over the five-year forecast period, I am forecasting no change in the number of 7

customers participating in the GCC program. Over the past several years, 8

participation in the GCC program has stabilized at a relatively flat customer count, 9

reversing the long-term and upward historical trend observed in prior years. Going 10

forward, due to this shift in participation trends, I assume participation levels in the 11

Choice program to remain at its present level. 12

13

Q27. What are the forecasted GCC sales volumes? 14

A27. Exhibit A-1, page 1 of 2, sets forth DTE Gas’ forecasted GCC sales volumes by OPY. 15

The annual projected GCC sales volumes, identified on line 12, are: 28.6 Bcf for 16

OPY 2019-2020, dropping steadily to 27.5 Bcf by OPY 2023-2024. This drop is due 17

to the Company’s continuing EWR program, assumed to be in operation throughout 18

the five-year forecast period. 19

20

FORECASTED GCR SALES VOLUMES 21

Q28. What are the forecasted GCR sales volumes and customers? 22

A28. Exhibit A-2, pages 1 through 5, sets forth DTE Gas’s forecasted GCR sales volumes 23

by month, and Exhibit A-3, pages 1 through 5, contains DTE Gas’s forecasted 24

number of GCR customers by month. The annual projected GCR sales volumes, 25

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identified on line 11 of each of the pages of Exhibit A-2 are: 127.8 Bcf for OPY 1

2019-2020, 126.9 Bcf for OPY 2020-2021, 126.8 Bcf for OPY 2021-2022, 126.7 Bcf 2

for OPY 2022-2023, and 127.2 Bcf for OPY 2023-2024. 3

4

The annual projected average GCR customer counts by OPY are: 1,126,064 for 5

2019-2020, 1,139,173 for 2020-2021, 1,152,006 for 2021-2022, 1,164,331 for 2022-6

2023, and 1,176,180 for 2023-2024. 7

8

Q29. What is the basis for DTE Gas’s total annual GCR requirements? 9

A29. The forecasted requirements are based on 15-year normal weather, which assumes a 10

change in daily temperature in accordance with the 15-year daily volatility (i.e. 11

“normal variable”); the distribution of daily HDDs is based on 15-year normal 12

weather for the 2019-2020 plan year, as well as for years 2 through 5 of the five-year 13

plan. Exhibit A-4, pages 1 through 3, identifies projected total requirements for 14

OPYs 2019 – 2024, made up of Company use, lost gas, unbilled volume change and 15

balance, and the forecasted GCR sales market volumes previously described. 16

17

DESIGN DAY DEMAND 18

Q30. What average temperatures does DTE Gas use to plan its design-day demand? 19

A30. DTE Gas uses the coldest mean-average temperature it can expect during critical 20

periods in January, February and March. Exhibit A-5, page 1 of 2 identifies sixteen 21

key locations across DTE Gas’ service territory. The coldest mean-average 22

temperature (in degrees Fahrenheit) that DTE Gas can expect at each location during 23

three pivotal times during the winter is also identified on this exhibit. These pivotal 24

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times occur at the ends of January, February, and March and represent the mean-1

average temperatures that DTE Gas uses to plan its design-day demand. 2

3

Q31. What is the 2020 design day load requirement associated with each of the three 4

critical-period mean-average temperatures? 5

A31. DTE Gas plans to serve its peak-day requirements around critical end-of-month 6

demand. DTE Gas’s design-day demand model examines the design weather at these 7

sixteen different locations and condenses them down to five primary demand 8

locations. Exhibit A-5, page 2 of 2 details the projected end-of-month peak demand 9

in January, February, and March 2020 at five primary demand locations (calculated 10

using statewide weather). These five locations are Detroit/Ann Arbor, Alpena, Grand 11

Rapids, the Upper Peninsula, and Traverse City. 12

13

Q32. Have these design day load volumes changed as compared to DTE Gas’s 14

previous GCR filing? 15

A32. Yes. For the 2020 design-day projection, these loads have changed from prior years. 16

January 2020 design-day requirements have decreased by 30 MDth/day versus 17

January 2019. February 2020 design-day requirements have decreased versus 18

February 2019 by 83 MDth/day while March 2020 design-day requirements have 19

decreased by 41 MDth/day versus March 2019. The primary reason for these changes 20

is the annual update of DTE Gas’s database of historical billing data in its Load 21

Program. The annual update reflects a combination of customer count and load 22

changes in the Company’s Detroit area reflecting changes in peaker load; usage data 23

for large end-use customers (including peaker plants) was recently updated. Natural 24

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gas fired generators are modeled, by design day by month, using their most recent 1

three years of activity. 2

3

Population growth in specific areas such as Kent County (major city: Grand Rapids) 4

and Washtenaw County (major city: Ann Arbor), and the population decrease in the 5

Wayne County area (specifically in the city of Detroit) will continue to change the 6

peak-day load. According to the US Census Bureau, from 2000 to 2010, the 7

population of Kent County increased by 4.9% (approximately 28,000 persons) and 8

the population of Washtenaw County increased by 6.8% (approximately 22,000 9

persons). By contrast, the population in Wayne County decreased by 11.7% 10

(approximately 241,000 persons). As I previously indicated, DTE Gas will continue 11

to evaluate the population and customer changes so that it is positioned to respond to 12

regional peak-day load demand changes. 13

14

DEMAND CHANGES 15

Q33. Has the Company experienced a change in normalized GCR and GCC sales in 16

recent years? 17

A33. DTE Gas saw a relatively steep decline in normalized sales through 2009-2010. Into 18

2012, normalized usage characteristics amongst the Company’s customer base 19

appeared to stabilize, and then into 2013, normalized consumption appeared to be on 20

the rebound. Please see Exhibit A-6. As shown on this exhibit, the steepest declines 21

occurred in 2004-2005 and 2005-2006 (9-10 Bcf per year). Coincidentally, these two 22

years saw increasingly higher national natural gas prices. Though still high from a 23

longer-term historical perspective, the 2006-2008 period generally saw a return to 24

lower prices. The 2008-2009 period, shown in column (g), once again showed a 25

G. H. CHAPEL

Line U-20236

No.

GHC-17

marked reduction in normalized consumption, which was driven largely by the 1

continued decline of the economy in the state of Michigan and higher natural gas 2

prices in general. From September 2009 through August 2012, normalized 3

consumption stabilized to approximately 153-154 Bcf per year (126-7 Mcf per 4

customer). In 2012-2013 and 2013-2014, normalized consumption rebounded up 5

slightly to 157 Bcf each year. Following a slight drop for a few years, the past couple 6

of years, however, have seen a return to increased normalized consumption to 7

approximately 158 Bcf annually (131 Mcf per customer). 8

9

Q34. What is the cumulative effect of the load changes from 2004 through 2018? 10

A34. In general, DTE Gas has seen a long-term load reduction. 11

12

Q35. Is the long-term load reduction permanent? 13

A35. A portion of the long-term load reduction is permanent due to several factors. 14

15

Q36. What factors contribute to the permanency of a portion of the longer-term load 16

reduction? 17

A36. First, there is a time-sensitive load reduction, which means that there continues to be 18

ongoing replacement of old equipment with newer and more efficient equipment such 19

as furnaces, water heaters, and appliances. Also, household energy efficiencies are 20

gained by the demolition of older, less well-insulated houses in addition to the 21

construction of new homes built with better building materials. 22

G. H. CHAPEL

Line U-20236

No.

GHC-18

Q37. What factors are not permanent? 1

A37. Potentially less permanent are load reductions that are reflective of higher natural gas 2

prices. The data suggests that customers will react to higher natural gas market prices 3

by reducing their natural gas consumption in a variety of ways, from adding 4

insulation and new windows to their existing homes, to dialing down their 5

thermostats and delaying furnace use in the fall and hastening furnace turn-offs in the 6

spring. This phenomenon affects natural gas customers across the United States. 7

8

Q38. What is the reason for the shorter-term load rebound? 9

A38. DTE believes that the improving economic conditions in Michigan have spurred an 10

increase in normalized consumption across the Company’s service territory. The 11

combination of an improved Michigan economy and continued low and stable prices 12

has likely resulted in higher consumption levels. 13

14

Q39. Has the Company made any adjustments to its usage factors in response to this 15

rebound in load? 16

A39. Yes, it has. The Company has calculated its usage factors in this filing based upon 17

consumption in the 12-months ended July 2018. From Exhibit A-6, one can see that 18

the normalized GCR/GCC consumption over this 12-month period has averaged 19

approximately 158 Bcf. This level of demand forms the basis of the usage factors 20

that the Company uses to project its forecasted demand. 21

G. H. CHAPEL

Line U-20236

No.

GHC-19

Q40. What has the Company assumed for system-wide heating value for forecast 1

purposes in this case? 2

A40. The Company assumes that the system-wide heating value for the entire forecast 3

period of this GCR Plan case to be 1,051 Btu/cf. 4

5

Q41. Why has the Company assumed 1,051 Btu/cf for the system-wide heating value 6

for this GCR Plan? 7

A41. Nexus Pipeline has now begun delivering natural gas to DTE Gas. The gas delivered 8

on that pipeline brings gas from the Utica and Marcellus region. Those regions have 9

been shown to produce natural gas that has, on average, higher heating value levels 10

than DTE Gas received from other pipelines in the past. With that higher-heating-11

value gas coming from the Nexus Pipeline, the Company’s latest system-average 12

heating value has been 1,051 Btu/cf. And, the most recent month of deliveries 13

supports that level of heating value. 14

15

Q42. What are DTE Gas’ current assumptions concerning ongoing conservation 16

efforts from its rate schedule customers? 17

A42. In this plan, DTE Gas has assumed that normalized customer consumptive behavior 18

will closely resemble that shown in the 12-month period ended July 2018 with a 19

further adjustment consistent with expected demand reductions from the EWR 20

program that DTE Gas has put in place in compliance with 2008 PA 295. Pursuant 21

to that EWR program, I am currently forecasting usage reduction of 1% annually, 22

which is consistent with the Company’s most recent EWR filing, Case No. U-18268. 23

G. H. CHAPEL

Line U-20236

No.

GHC-20

Q43. Why are you forecasting growth in the number of customers from 2019 to 2024? 1

A43. The economic recession of earlier years had a marked effect on the citizens of 2

Michigan, particularly in Southeast Michigan, which has the largest concentration of 3

DTE Gas’s customer base. Company billing data in more recent years, however, has 4

shown that customers continue to return to DTE Gas service. Additionally, losses 5

due to the Company’s Revenue Management & Protection efforts are expected to 6

decline over the forecast period. Lastly, the Company is continuing to project new 7

attachments at increased levels through its marketing efforts over the five-year 8

forecast period. Going forward, DTE Gas will continue to monitor these factors and 9

adjusts its long term forecast as necessary. 10

11

Q44. Does this complete your direct testimony? 12

A44. Yes, it does. 13

14

STATE OF MICHIGAN







)

EXHIBITS

OF

GEORGE H. CHAPEL

Case No.: U-20236

Witness: GH Chapel

Exhibit No.: A-1

Page No.: 1 of 2

DTE Gas Company

Market Outlook

April 2019 through March 2024

Weather Normalized Sales by Rate Class

Volumes in MMcf

Apr-Mar Apr-Mar Apr-Mar Apr-Mar Apr-Mar

Line Rate Schedule 2019-2020 2020-2021 2021-2022 2022-2023 2023-2024

Col (a) Col (b) Col (c) Col (d) Col (e)

1 Residential - Rate A 997 991 991 989 994

2 Residential - Rate A Heat (+ AS) 97,046 96,670 96,841 96,971 97,590

3 Residential - Rate 2A (Meter I) 229 216 204 194 183

4 Residential - Rate 2A (Meter II) 3,199 2,998 2,818 2,614 2,453

5 Residential - Total 101,471 100,875 100,854 100,767 101,220

6 Rate GS-1 2,315 2,239 2,177 2,091 2,043

7 Rate GS-1 Heat 22,386 22,123 22,032 21,924 21,941

8 Rate GS-2 Heat 612 665 720 788 829

9 Rate S 1,027 1,045 1,069 1,093 1,123

10 Commercial/Industrial - Total 26,340 26,072 25,998 25,897 25,935

11 GCR Total 127,811 126,947 126,852 126,664 127,155

12 Gas Customer Choice 28,575 28,289 28,006 27,726 27,526

13 Total GCR and GCC Sales Market 156,386 155,236 154,858 154,390 154,682

Case No.: U-20236

Witness: GH Chapel

Exhibit No.: A-1

Page No.: 2 of 2

DTE Gas Company

Market Outlook

April 2019 through March 2024

Projected Average Number of Customers

Apr-Mar Apr-Mar Apr-Mar Apr-Mar Apr-Mar

Line Rate Schedule 2019-2020 2020-2021 2021-2022 2022-2023 2023-2024

Col (a) Col (b) Col (c) Col (d) Col (e)

1 Residential - Rate A 17,215 17,402 17,589 17,776 17,963

2 Residential - Rate A Heat (+ AS) 1,034,260 1,047,148 1,059,788 1,071,972 1,083,730

3 Residential - Rate 2A (Meter I) 1,143 1,106 1,070 1,033 995

4 Residential - Rate 2A (Meter II) 3,608 3,441 3,274 3,107 2,940

5 Residential - Total 1,056,226 1,069,097 1,081,721 1,093,888 1,105,628

6 Rate GS-1 3,951 3,900 3,849 3,808 3,785

7 Rate GS-1 Heat 65,742 66,025 66,279 66,472 66,598

8 Rate GS-2 Heat 47 49 51 53 55

9 Rate S 98 102 106 110 114

10 Commercial/Industrial - Total 69,838 70,076 70,285 70,443 70,552

11 GCR Total 1,126,064 1,139,173 1,152,006 1,164,331 1,176,180

12 Gas Customer Choice 156,319 156,319 156,319 156,319 156,319

13 Total GCR and GCC Sales Customers 1,282,383 1,295,492 1,308,325 1,320,650 1,332,499

Case No.: U-20236

Witness: G.H. Chapel

Exhibit No.: A-2

Page No.: 1 of 5

DTE Gas Company

Market Forecast Analysis

Forecasted GCR Volumes

Volumes in MMcf

Line 2019-20 GCR Demand

No. FORECAST April May June July August September October November December January February March TOTAL

Col (a) Col (b) Col (c) Col (d) Col (e) Col (f) Col (g) Col (h) Col (i) Col (j) Col (k) Col (l) Col (m)

1 Residential - Rate A 78 41 23 23 22 32 62 98 145 178 165 130 997

2 Residential - Rate A Heat 7,167 3,349 1,724 1,603 1,583 2,190 5,475 9,845 15,176 18,655 17,119 13,160 97,046

3 Residential - Rate 2A (Meter I) 20 12 9 9 8 11 17 22 28 35 32 26 229

4 Residential - Rate 2A (Meter II) 288 160 84 76 75 131 250 330 432 510 470 395 3,199

5 Residential - Total 7,552 3,562 1,839 1,710 1,688 2,364 5,805 10,294 15,781 19,378 17,786 13,712 101,471

6 Rate GS-1 166 108 83 89 88 92 135 215 323 388 358 269 2,315

7 Rate GS-1 Heat 1,573 539 488 536 467 538 1,152 2,218 3,413 4,342 4,036 3,084 22,386

8 Rate GS-2 Heat 44 28 21 22 22 19 37 58 78 110 94 80 612

9 Rate S 72 26 8 7 7 8 40 96 164 231 213 157 1,027

10 Commercial/Industrial - Total 1,855 701 601 654 584 657 1,363 2,587 3,979 5,070 4,701 3,589 26,340

11 TOTAL 9,408 4,263 2,440 2,364 2,271 3,021 7,168 12,881 19,760 24,448 22,487 17,300 127,811

Case No.: U-20236


Exhibit No.: A-2

Page No.: 2 of 5

DTE Gas Company



Volumes in MMcf









6 Rate GS-1 161 105 81 87 86 90 131 209 314 377 335 261 2,239

7 Rate GS-1 Heat 1,569 540 486 533 465 536 1,149 2,211 3,402 4,326 3,834 3,072 22,123

8 Rate GS-2 Heat 49 30 22 23 23 20 40 63 86 121 101 87 665

9 Rate S 74 26 9 7 7 8 41 98 168 236 211 160 1,045


11 TOTAL 9,409 4,267 2,438 2,359 2,269 3,017 7,165 12,877 19,758 24,444 21,651 17,294 126,947

Case No.: U-20236


Exhibit No.: A-2

Page No.: 3 of 5

DTE Gas Company



Volumes in MMcf









6 Rate GS-1 157 102 79 85 84 87 127 203 305 367 326 254 2,177

7 Rate GS-1 Heat 1,564 540 484 531 463 534 1,146 2,202 3,388 4,306 3,816 3,058 22,032

8 Rate GS-2 Heat 53 33 23 24 23 21 43 69 94 131 110 95 720

9 Rate S 76 27 9 7 7 9 42 100 172 241 215 164 1,069


11 TOTAL 9,405 4,269 2,435 2,355 2,265 3,014 7,160 12,867 19,745 24,425 21,634 17,277 126,852

Case No.: U-20236


Exhibit No.: A-2

Page No.: 4 of 5

DTE Gas Company



Volumes in MMcf









6 Rate GS-1 152 92 81 85 83 84 125 193 278 356 316 246 2,091

7 Rate GS-1 Heat 1,555 545 478 525 460 526 1,134 2,195 3,391 4,280 3,794 3,041 21,924

8 Rate GS-2 Heat 59 37 25 25 25 28 49 74 101 142 119 102 788

9 Rate S 79 28 8 6 6 11 46 102 173 246 220 167 1,093


11 TOTAL 9,396 4,269 2,430 2,349 2,261 3,008 7,151 12,850 19,720 24,384 21,598 17,250 126,664

Case No.: U-20236


Exhibit No.: A-2

Page No.: 5 of 5

DTE Gas Company



Volumes in MMcf









6 Rate GS-1 147 89 79 83 81 82 121 187 269 346 318 238 2,043

7 Rate GS-1 Heat 1,547 544 475 522 457 523 1,128 2,182 3,370 4,253 3,933 3,007 21,941

8 Rate GS-2 Heat 62 38 25 25 25 28 51 78 108 150 131 108 829

9 Rate S 81 28 8 7 6 11 47 105 177 251 232 170 1,123


11 TOTAL 9,380 4,264 2,423 2,341 2,254 2,999 7,136 12,824 19,682 24,336 22,337 17,181 127,155

Case No.: U-20236


Exhibit No.: A-3

Page No.: 1 of 5

DTE Gas Company


Forecasted GCR Number of Customers

Line 2019-20 GCR Customers

No. FORECAST April May June July August September October November December January February March AVERAGE


1 Residential - Rate A 17,120 17,153 17,124 17,097 17,137 17,175 17,180 17,272 17,324 17,277 17,372 17,349 17,215

2 Residential - Rate A Heat 1,031,558 1,030,717 1,028,764 1,026,421 1,025,932 1,028,563 1,032,519 1,037,634 1,038,780 1,041,458 1,043,046 1,045,723 1,034,260

3 Residential - Rate 2A (Meter I) 1,149 1,145 1,145 1,147 1,144 1,151 1,149 1,147 1,146 1,143 1,142 1,112 1,143

4 Residential - Rate 2A (Meter II) 3,650 3,650 3,640 3,634 3,636 3,635 3,614 3,608 3,585 3,569 3,563 3,510 3,608

5 Residential - Total 1,053,477 1,052,665 1,050,673 1,048,299 1,047,849 1,050,524 1,054,462 1,059,661 1,060,835 1,063,447 1,065,123 1,067,694 1,056,226

6 Rate GS-1 3,978 3,978 3,966 3,955 3,953 3,952 3,922 3,945 3,957 3,949 3,939 3,921 3,951

7 Rate GS-1 Heat 66,213 65,777 65,329 64,950 64,619 64,731 65,307 66,019 66,186 66,416 66,606 66,751 65,742

8 Rate GS-2 Heat 45 45 45 45 46 46 48 48 47 49 47 48 47

9 Rate S 97 96 97 97 97 96 98 99 100 100 100 101 98

10 Commercial/Industrial - Total 70,333 69,896 69,437 69,047 68,715 68,825 69,375 70,111 70,290 70,514 70,692 70,821 69,838

11 TOTAL 1,123,810 1,122,561 1,120,110 1,117,346 1,116,564 1,119,349 1,123,837 1,129,772 1,131,125 1,133,961 1,135,815 1,138,515 1,126,064

Case No.: U-20236


Exhibit No.: A-3

Page No.: 2 of 5

DTE Gas Company











6 Rate GS-1 3,927 3,926 3,915 3,904 3,902 3,901 3,871 3,894 3,906 3,898 3,888 3,870 3,900

7 Rate GS-1 Heat 66,541 66,082 65,613 65,210 64,883 64,999 65,581 66,300 66,473 66,699 66,886 67,028 66,025

8 Rate GS-2 Heat 47 47 47 47 48 48 50 50 49 51 49 50 49

9 Rate S 101 100 101 101 101 100 102 103 104 104 104 105 102


11 TOTAL 1,137,367 1,135,890 1,133,226 1,130,235 1,129,488 1,132,316 1,136,862 1,142,869 1,144,274 1,147,073 1,148,901 1,151,576 1,139,173

Case No.: U-20236


Exhibit No.: A-3

Page No.: 3 of 5

DTE Gas Company











6 Rate GS-1 3,876 3,875 3,864 3,853 3,851 3,850 3,820 3,843 3,855 3,847 3,837 3,819 3,849

7 Rate GS-1 Heat 66,816 66,355 65,882 65,477 65,147 65,258 65,834 66,547 66,714 66,935 67,119 67,258 66,279

8 Rate GS-2 Heat 49 49 49 49 50 50 52 52 51 53 51 52 51

9 Rate S 105 104 105 105 105 104 106 107 108 108 108 109 106


11 TOTAL 1,150,409 1,148,909 1,146,210 1,143,194 1,142,415 1,145,201 1,149,690 1,155,627 1,156,979 1,159,728 1,161,523 1,164,171 1,152,006

Case No.: U-20236


Exhibit No.: A-3

Page No.: 4 of 5

DTE Gas Company











6 Rate GS-1 3,825 3,824 3,813 3,802 3,800 3,799 3,769 3,792 3,804 3,834 3,824 3,806 3,808

7 Rate GS-1 Heat 67,044 66,580 66,102 65,694 65,360 65,466 66,036 66,740 66,901 67,080 67,261 67,398 66,472

8 Rate GS-2 Heat 51 51 51 51 52 52 54 54 53 55 53 54 53

9 Rate S 109 108 109 109 109 108 110 111 112 112 112 113 110


11 TOTAL 1,162,980 1,161,450 1,158,709 1,155,661 1,154,842 1,157,579 1,162,004 1,167,858 1,169,152 1,171,857 1,173,623 1,176,245 1,164,331

Case No.: U-20236


Exhibit No.: A-3

Page No.: 5 of 5

DTE Gas Company








3 Residential - Rate 2A (Meter I) 1,001 997 997 999 996 1,003 1,001 999 998 995 994 964 995



6 Rate GS-1 3,812 3,811 3,800 3,789 3,787 3,786 3,756 3,779 3,791 3,783 3,773 3,755 3,785

7 Rate GS-1 Heat 67,182 66,714 66,234 65,822 65,485 65,587 66,150 66,847 67,003 67,219 67,400 67,537 66,598

8 Rate GS-2 Heat 53 53 53 53 54 54 56 56 55 57 55 56 55

9 Rate S 113 112 113 113 113 112 114 115 116 116 116 117 114


11 TOTAL 1,175,033 1,173,476 1,170,698 1,167,622 1,166,767 1,169,461 1,173,829 1,179,609 1,180,849 1,183,554 1,185,320 1,187,942 1,176,180

DTE Gas Company Case No.: U-20236

April 2019 - March 2024 Witness: G.H. Chapel

Total Market Requirements Exhibit No.: A-4

Volumes in MMcf Page: 1 of 3

Total Total

GCR GCR+GCC

Billed Company Billed

Line Year Month Days Sales Change Balance Total Use Losses Total Sales Change Balance Total

(Col. 1) (Col. 2) (Col. 3) (Col. 4) (Col. 5) (Col. 6) (Col. 7) (Col. 8) (Col. 9) (Col. 10) (Col. 11) (Col. 12) (Col. 13) (Col. 14) (Col. 15) (Col. 16)

1 Beginning Balance 8,597 1,759

2 2019 April 30 13,190 (3,782) 4,815 9,408 307 210 517 9,925 2,818 (614) 1,145 2,204 12,128

3 May 31 6,833 (2,570) 2,244 4,263 383 120 503 4,766 2,013 (221) 925 1,793 6,559

4 June 30 3,384 (943) 1,301 2,440 356 60 416 2,857 1,216 (570) 354 646 3,502

5 July 31 2,407 (43) 1,258 2,364 336 60 396 2,759 575 (93) 261 482 3,241

6 August 31 2,287 (15) 1,243 2,271 296 60 356 2,627 536 81 343 617 3,244

7 September 30 2,396 625 1,868 3,021 346 90 436 3,457 637 126 469 764 4,220

8 October 31 4,341 2,827 4,695 7,168 271 180 451 7,619 1,111 701 1,170 1,812 9,431

9 November 30 8,949 3,932 8,627 12,881 175 300 475 13,355 2,109 725 1,894 2,833 16,188

10 December 31 15,538 4,222 12,849 19,760 182 510 692 20,452 3,423 946 2,840 4,369 24,821

11 2020 January 31 23,211 1,237 14,086 24,448 333 540 873 25,321 4,963 110 2,951 5,074 30,395

12 February 29 23,050 (563) 13,523 22,487 320 480 800 23,287 4,722 (234) 2,717 4,488 27,774

13 March 31 22,222 (4,922) 8,601 17,300 238 390 628 17,929 4,469 (975) 1,742 3,495 21,423

14 Total Period 366 127,808 4 127,811 3,542 3,000 6,542 134,353 28,592 (18) 28,575 162,928

Total Total

GCR GCR+GCC




15 2020 April 30 13,195 (3,785) 4,815 9,409 371 210 581 9,990 2,790 (608) 1,134 2,182 12,172

16 May 31 6,836 (2,569) 2,246 4,267 473 120 593 4,860 1,993 (218) 916 1,775 6,634

17 June 30 3,385 (947) 1,299 2,438 427 60 487 2,925 1,204 (565) 351 639 3,564

18 July 31 2,403 (44) 1,255 2,359 409 60 469 2,828 569 (92) 259 477 3,305

19 August 31 2,283 (14) 1,241 2,269 369 60 429 2,698 530 81 339 611 3,309

20 September 30 2,393 625 1,866 3,017 437 90 527 3,544 631 125 464 756 4,300

21 October 31 4,338 2,827 4,693 7,165 309 180 489 7,654 1,100 694 1,158 1,794 9,448

22 November 30 8,946 3,931 8,624 12,877 205 300 505 13,381 2,087 717 1,875 2,805 16,186

23 December 31 15,534 4,224 12,848 19,758 185 510 695 20,453 3,389 937 2,812 4,326 24,778

24 2021 January 31 23,208 1,236 14,083 24,444 333 540 873 25,317 4,913 109 2,921 5,023 30,340

25 February 28 22,714 (1,064) 13,020 21,651 320 480 800 22,450 4,675 (232) 2,689 4,443 26,893

26 March 31 21,716 (4,422) 8,597 17,294 238 390 628 17,922 4,425 (965) 1,724 3,460 21,382

27 Total Period 365 126,950 (3) 126,947 4,076 3,000 7,076 134,023 28,306 (17) 28,289 162,312

Unbilled

GCR Other Gas Customer Choice


Unbilled Unbilled

Unbilled





Total Total

GCR GCR+GCC




1 2021 April 30 13,189 (3,784) 4,813 9,405 371 210 581 9,986 2,762 (602) 1,123 2,160 12,146

2 May 31 6,835 (2,566) 2,248 4,269 473 120 593 4,862 1,973 (216) 906 1,757 6,619

3 June 30 3,384 (950) 1,298 2,435 427 60 487 2,922 1,192 (559) 347 633 3,555

4 July 31 2,400 (45) 1,253 2,355 409 60 469 2,824 563 (91) 256 472 3,296

5 August 31 2,279 (14) 1,239 2,265 369 60 429 2,694 525 80 336 605 3,299

6 September 30 2,389 624 1,863 3,014 437 90 527 3,541 625 124 460 748 4,289

7 October 31 4,334 2,826 4,689 7,160 309 180 489 7,649 1,089 687 1,146 1,776 9,425

8 November 30 8,939 3,928 8,618 12,867 205 300 505 13,372 2,067 710 1,856 2,777 16,149

9 December 31 15,523 4,222 12,839 19,745 185 510 695 20,440 3,355 928 2,784 4,282 24,722

10 2022 January 31 23,192 1,234 14,073 24,425 333 540 873 25,298 4,864 108 2,892 4,973 30,271

11 February 28 22,697 (1,063) 13,010 21,634 320 480 800 22,434 4,628 (230) 2,663 4,398 26,832

12 March 31 21,698 (4,421) 8,589 17,277 238 390 628 17,906 4,380 (955) 1,707 3,425 21,331

13 Total Period 365 126,860 (8) 126,852 4,076 3,000 7,076 133,927 28,023 (17) 28,006 161,933

Total Total

GCR GCR+GCC




14 2022 April 30 13,176 (3,781) 4,808 9,396 371 210 581 9,977 2,734 (596) 1,111 2,138 12,115

15 May 31 6,830 (2,561) 2,247 4,269 473 120 593 4,861 1,954 (214) 897 1,740 6,601

16 June 30 3,382 (952) 1,295 2,430 427 60 487 2,917 1,180 (553) 344 626 3,544

17 July 31 2,395 (45) 1,250 2,349 409 60 469 2,819 558 (90) 253 467 3,286

18 August 31 2,274 (13) 1,237 2,261 369 60 429 2,690 520 79 332 599 3,289

19 September 30 2,385 623 1,860 3,008 437 90 527 3,535 618 123 455 741 4,276

20 October 31 4,327 2,823 4,683 7,151 309 180 489 7,640 1,078 680 1,135 1,758 9,398

21 November 30 8,927 3,923 8,606 12,850 205 300 505 13,354 2,046 703 1,838 2,749 16,103

22 December 31 15,503 4,217 12,823 19,720 185 510 695 20,414 3,321 918 2,756 4,239 24,654

23 2023 January 31 23,157 1,226 14,049 24,384 333 540 873 25,257 4,816 107 2,863 4,923 30,180

24 February 28 22,659 (1,061) 12,988 21,598 320 480 800 22,397 4,582 (227) 2,636 4,354 26,752

25 March 31 21,662 (4,412) 8,576 17,250 238 390 628 17,879 4,337 (946) 1,690 3,391 21,270

26 Total Period 365 126,678 (13) 126,664 4,076 3,000 7,076 133,740 27,743 (17) 27,726 161,466

Unbilled

Other Gas Customer Choice


GCR

Unbilled Unbilled

Unbilled





Total Total

GCR GCR+GCC




1 2023 April 30 13,155 (3,776) 4,800 9,380 371 210 581 9,961 2,707 (590) 1,100 2,117 12,077

2 May 31 6,819 (2,555) 2,245 4,264 473 120 593 4,857 1,934 (212) 888 1,722 6,579

3 June 30 3,376 (953) 1,292 2,423 427 60 487 2,910 1,168 (548) 340 620 3,531

4 July 31 2,387 (46) 1,246 2,341 409 60 469 2,810 552 (90) 251 463 3,273

5 August 31 2,267 (13) 1,233 2,254 369 60 429 2,683 515 78 329 593 3,276

6 September 30 2,378 622 1,855 2,999 437 90 527 3,526 612 121 450 734 4,260

7 October 31 4,317 2,819 4,673 7,136 309 180 489 7,625 1,068 673 1,123 1,741 9,366

8 November 30 8,909 3,915 8,588 12,824 205 300 505 13,328 2,025 696 1,819 2,721 16,050

9 December 31 15,472 4,210 12,798 19,682 185 510 695 20,376 3,288 909 2,729 4,197 24,573

10 2024 January 31 23,113 1,224 14,021 24,336 333 540 873 25,209 4,768 106 2,835 4,874 30,083

11 February 29 22,926 (589) 13,432 22,337 320 480 800 23,136 4,553 (199) 2,636 4,354 27,491

12 March 31 22,072 (4,891) 8,541 17,181 238 390 628 17,809 4,337 (946) 1,690 3,391 21,200

13 Total Period 366 127,190 (35) 127,155 4,076 3,000 7,076 134,231 27,526 0 27,526 161,757

Unbilled


Unbilled





Total Total

GCR GCR+GCC




1 Beginning Balance 8,597 1,759

2 2019 April 30 13,190 (3,782) 4,815 9,408 307 210 517 9,925 2,818 (614) 1,145 2,204 12,128

3 May 31 6,833 (2,570) 2,244 4,263 383 120 503 4,766 2,013 (221) 925 1,793 6,559

4 June 30 3,384 (943) 1,301 2,440 356 60 416 2,857 1,216 (570) 354 646 3,502

5 July 31 2,407 (43) 1,258 2,364 336 60 396 2,759 575 (93) 261 482 3,241

6 August 31 2,287 (15) 1,243 2,271 296 60 356 2,627 536 81 343 617 3,244

7 September 30 2,396 625 1,868 3,021 346 90 436 3,457 637 126 469 764 4,220

8 October 31 4,341 2,827 4,695 7,168 271 180 451 7,619 1,111 701 1,170 1,812 9,431

9 November 30 8,949 3,932 8,627 12,881 175 300 475 13,355 2,109 725 1,894 2,833 16,188

10 December 31 15,538 4,222 12,849 19,760 182 510 692 20,452 3,423 946 2,840 4,369 24,821

11 2020 January 31 23,211 1,237 14,086 24,448 333 540 873 25,321 4,963 110 2,951 5,074 30,395

12 February 29 23,050 (563) 13,523 22,487 320 480 800 23,287 4,722 (234) 2,717 4,488 27,774

13 March 31 22,222 (4,922) 8,601 17,300 238 390 628 17,929 4,469 (975) 1,742 3,495 21,423

14 Total Period 366 127,808 4 127,811 3,542 3,000 6,542 134,353 28,592 (18) 28,575 162,928

Total Total

GCR GCR+GCC




15 2020 April 30 13,195 (3,785) 4,815 9,409 371 210 581 9,990 2,790 (608) 1,134 2,182 12,172

16 May 31 6,836 (2,569) 2,246 4,267 473 120 593 4,860 1,993 (218) 916 1,775 6,634

17 June 30 3,385 (947) 1,299 2,438 427 60 487 2,925 1,204 (565) 351 639 3,564

18 July 31 2,403 (44) 1,255 2,359 409 60 469 2,828 569 (92) 259 477 3,305

19 August 31 2,283 (14) 1,241 2,269 369 60 429 2,698 530 81 339 611 3,309

20 September 30 2,393 625 1,866 3,017 437 90 527 3,544 631 125 464 756 4,300

21 October 31 4,338 2,827 4,693 7,165 309 180 489 7,654 1,100 694 1,158 1,794 9,448

22 November 30 8,946 3,931 8,624 12,877 205 300 505 13,381 2,087 717 1,875 2,805 16,186

23 December 31 15,534 4,224 12,848 19,758 185 510 695 20,453 3,389 937 2,812 4,326 24,778

24 2021 January 31 23,208 1,236 14,083 24,444 333 540 873 25,317 4,913 109 2,921 5,023 30,340

25 February 28 22,714 (1,064) 13,020 21,651 320 480 800 22,450 4,675 (232) 2,689 4,443 26,893

26 March 31 21,716 (4,422) 8,597 17,294 238 390 628 17,922 4,425 (965) 1,724 3,460 21,382

27 Total Period 365 126,950 (3) 126,947 4,076 3,000 7,076 134,023 28,306 (17) 28,289 162,312

Unbilled



Unbilled Unbilled

Unbilled





Total Total

GCR GCR+GCC




1 2021 April 30 13,189 (3,784) 4,813 9,405 371 210 581 9,986 2,762 (602) 1,123 2,160 12,146

2 May 31 6,835 (2,566) 2,248 4,269 473 120 593 4,862 1,973 (216) 906 1,757 6,619

3 June 30 3,384 (950) 1,298 2,435 427 60 487 2,922 1,192 (559) 347 633 3,555

4 July 31 2,400 (45) 1,253 2,355 409 60 469 2,824 563 (91) 256 472 3,296

5 August 31 2,279 (14) 1,239 2,265 369 60 429 2,694 525 80 336 605 3,299

6 September 30 2,389 624 1,863 3,014 437 90 527 3,541 625 124 460 748 4,289

7 October 31 4,334 2,826 4,689 7,160 309 180 489 7,649 1,089 687 1,146 1,776 9,425

8 November 30 8,939 3,928 8,618 12,867 205 300 505 13,372 2,067 710 1,856 2,777 16,149

9 December 31 15,523 4,222 12,839 19,745 185 510 695 20,440 3,355 928 2,784 4,282 24,722

10 2022 January 31 23,192 1,234 14,073 24,425 333 540 873 25,298 4,864 108 2,892 4,973 30,271

11 February 28 22,697 (1,063) 13,010 21,634 320 480 800 22,434 4,628 (230) 2,663 4,398 26,832

12 March 31 21,698 (4,421) 8,589 17,277 238 390 628 17,906 4,380 (955) 1,707 3,425 21,331

13 Total Period 365 126,860 (8) 126,852 4,076 3,000 7,076 133,927 28,023 (17) 28,006 161,933

Total Total

GCR GCR+GCC




14 2022 April 30 13,176 (3,781) 4,808 9,396 371 210 581 9,977 2,734 (596) 1,111 2,138 12,115

15 May 31 6,830 (2,561) 2,247 4,269 473 120 593 4,861 1,954 (214) 897 1,740 6,601

16 June 30 3,382 (952) 1,295 2,430 427 60 487 2,917 1,180 (553) 344 626 3,544

17 July 31 2,395 (45) 1,250 2,349 409 60 469 2,819 558 (90) 253 467 3,286

18 August 31 2,274 (13) 1,237 2,261 369 60 429 2,690 520 79 332 599 3,289

19 September 30 2,385 623 1,860 3,008 437 90 527 3,535 618 123 455 741 4,276

20 October 31 4,327 2,823 4,683 7,151 309 180 489 7,640 1,078 680 1,135 1,758 9,398

21 November 30 8,927 3,923 8,606 12,850 205 300 505 13,354 2,046 703 1,838 2,749 16,103

22 December 31 15,503 4,217 12,823 19,720 185 510 695 20,414 3,321 918 2,756 4,239 24,654

23 2023 January 31 23,157 1,226 14,049 24,384 333 540 873 25,257 4,816 107 2,863 4,923 30,180

24 February 28 22,659 (1,061) 12,988 21,598 320 480 800 22,397 4,582 (227) 2,636 4,354 26,752

25 March 31 21,662 (4,412) 8,576 17,250 238 390 628 17,879 4,337 (946) 1,690 3,391 21,270

26 Total Period 365 126,678 (13) 126,664 4,076 3,000 7,076 133,740 27,743 (17) 27,726 161,466

Unbilled

Other Gas Customer Choice


GCR

Unbilled Unbilled

Unbilled





Total Total

GCR GCR+GCC




1 2023 April 30 13,155 (3,776) 4,800 9,380 371 210 581 9,961 2,707 (590) 1,100 2,117 12,077

2 May 31 6,819 (2,555) 2,245 4,264 473 120 593 4,857 1,934 (212) 888 1,722 6,579

3 June 30 3,376 (953) 1,292 2,423 427 60 487 2,910 1,168 (548) 340 620 3,531

4 July 31 2,387 (46) 1,246 2,341 409 60 469 2,810 552 (90) 251 463 3,273

5 August 31 2,267 (13) 1,233 2,254 369 60 429 2,683 515 78 329 593 3,276

6 September 30 2,378 622 1,855 2,999 437 90 527 3,526 612 121 450 734 4,260

7 October 31 4,317 2,819 4,673 7,136 309 180 489 7,625 1,068 673 1,123 1,741 9,366

8 November 30 8,909 3,915 8,588 12,824 205 300 505 13,328 2,025 696 1,819 2,721 16,050

9 December 31 15,472 4,210 12,798 19,682 185 510 695 20,376 3,288 909 2,729 4,197 24,573

10 2024 January 31 23,113 1,224 14,021 24,336 333 540 873 25,209 4,768 106 2,835 4,874 30,083

11 February 29 22,926 (589) 13,432 22,337 320 480 800 23,136 4,553 (199) 2,636 4,354 27,491

12 March 31 22,072 (4,891) 8,541 17,181 238 390 628 17,809 4,337 (946) 1,690 3,391 21,200

13 Total Period 366 127,190 (35) 127,155 4,076 3,000 7,076 134,231 27,526 0 27,526 161,757

Unbilled


Unbilled

Case No.: U-20236


Exhibit No.: A-5

Page: 1 of 2

DTE Gas Company

Mean Design Day Temperatures by District

(Temperatures in o F)

January February March

Line District End of Mo. End of Mo. End of Mo.

(Col. 1) (Col. 2) (Col. 3) (Col. 4)

1 Alpena -10 -7 52 Ann Arbor -4 -2 163 Big Rapids -11 -6 64 Cadillac -20 -10 -65 Detroit -4 4 146 Escanaba -16 -7 57 Grand Rapids -7 1 78 Grayling -21 -13 19 Iron Mountain -22 -8 0

10 Ludington -3 0 1111 Mount Pleasant -9 -4 612 Muskegon -6 0 1113 Petoskey -12 -10 514 Sault Ste. Marie -16 -9 215 Tawas -8 -5 716 Traverse City -11 -9 5

Case No.: U-20236


Exhibit No.: A-5

Page: 2 of 2

DTE Gas Company2020 Design Day Load by Area(Volumes in MMcf/d at 1,051 Btu/cf)

End-of-Month Peak Day Load

Line January February March(Col. 1) (Col. 2) (Col. 3) (Col. 4)

1 Detroit / Ann Arbor 1,447 1,313 1,142

2 Alpena 115 84 72

3 Grand Rapids 570 521 471

4 Upper Peninsula 92 87 82

5 Traverse City 140 131 114

6 Total 2,364 2,136 1,880

Case No.: U-20236


Exhibit No.: A-6

Page No.: 1 of 1

DTE Gas Company

Historical Normalized Annual Sales (GCR & GCC)

September 2002 through August 2018

Volumes in MMcf unless otherwise noted

Sep-Aug Sep-Aug Sep-Aug Sep-Aug Sep-Aug Sep-Aug Sep-Aug Sep-Aug Sep-Aug Sep-Aug Sep-Aug Sep-Aug Sep-Aug Sep-Aug Sep-Aug Sep-Aug

Line Rate Schedule 2002-03 2003-04 2004-05 2005-06 2006-07 2007-08 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14 2014-15 2015-16 2016-17 2017-18

Col (a) Col (b) Col (c) Col (d) Col (e) Col (f) Col (g) Col (h) Col (i) Col (j) Col (k) Col (l) Col (m) Col (n) Col (o) Col (p)

1 Actual Billed Sales 204,960 190,672 184,039 162,205 168,102 169,253 169,230 148,239 161,560 132,683 156,391 178,617 167,276 137,706 139,273 159,850

2 Actual Base Load (August Billed Sales x 12) 45,615 50,532 43,193 42,476 43,865 40,861 38,857 35,069 35,483 35,322 37,687 32,041 33,604 33,608 37,747 34,680

3 Actual Heat Load Sales 159,345 140,140 140,845 119,729 124,237 128,392 130,372 113,171 126,078 97,361 118,705 146,575 133,671 104,098 101,527 125,170

(Row 1 - Row 2)

4 Average Number of GCR & GCC Customers 1,248,757 1,247,174 1,256,099 1,262,307 1,253,489 1,244,788 1,229,535 1,216,844 1,212,623 1,213,521 1,219,246 1,224,856 1,230,358 1,240,008 1,249,623 1,260,882

5 Detroit Actual HDDs 6,650 5,985 6,089 5,521 5,939 6,010 6,385 5,652 6,387 4,884 5,937 7,016 6,615 5,183 5,149 6,061

6 Heat Load Mcf per Customer per HDD 0.0192 0.0188 0.0184 0.0172 0.0167 0.0172 0.0166 0.0165 0.0163 0.0164 0.0164 0.0171 0.0164 0.0162 0.0158 0.0164

((Row 3 x 1,000) / Row 4 / Row 5)

7 Detroit 15-Year (03-17) Normal HDDs 5,948 5,948 5,948 5,948 5,948 5,948 5,948 5,948 5,948 5,948 5,948 5,948 5,948 5,948 5,948 5,948

8 Normalized Heat Load 142,524 139,274 137,584 128,989 124,425 127,068 121,449 119,098 117,412 118,572 118,924 124,263 120,193 119,463 117,281 122,836

(Row 4 x Row 6 / 1,000 x Row 7)

9 Normalized Sales 188,139 189,806 180,777 171,465 168,290 167,929 160,307 154,166 152,895 153,894 156,611 156,305 153,797 153,070 155,028 157,516

(Row 2 + Row 8)

Mcf per Customer 150.7 152.2 143.9 135.8 134.3 134.9 130.4 126.7 126.1 126.8 128.4 127.6 125.0 123.4 124.1 124.9

188 190 181 171 168 168 160 154 153 154 157 156 154 153 155 158

188 190 181

171 168 168 160

154 153 154 157 156 154 153 155 158

140

150

160

170

180

190

200

2002-03 2003-04 2004-05 2005-06 2006-07 2007-08 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14 2014-15 2015-16 2016-17 2017-18

Bcf

Normalized Sales (15-Year)GCR & GCC Customers

STATE OF MICHIGAN







)

QUALIFICATIONS

AND

DIRECT TESTIMONY

OF

ERIC P. SCHIFFER

DTE GAS COMPANY

QUALIFICATIONS OF ERIC P. SCHIFFER

Line

No.

EPS - 1

Q1. What is your name and business address? 1

A1. My name is Eric P. Schiffer. My business address is One Energy Plaza, Detroit, 2

Michigan 48226. 3

4

Q2. By whom are you employed and in what capacity? 5

A2. I am employed by DTE Gas Company (DTE Gas or Company) as Senior Gas Supply 6

and Planning Analyst. 7

8


A3. I earned a Bachelor of Arts Degree in Professional Accounting from Michigan State 10

University and a Master Degree in Business Administration from Michigan State 11

University. I have attended conferences related to Risk Management, the natural gas 12

industry, the LDC Gas Forum - Midcontinent, revenue requirements calculation, and 13

VaR. 14

15

Q4. What is your business experience? 16

A4. I have been employed full time by DTE Gas (formerly Michigan Consolidated Gas 17

Company), DTE Energy or MCN Energy Group (parent of MichCon, acquired by 18

DTE in 2001) since 1993. From 1993 to 2001, I held various positions primarily in 19

the non-regulatory accounting groups responsible for Oil and Gas as well as pipeline 20

and processing plant accounting. From 2001 to 2013, I held various positions of 21

increasing responsibility in Enterprise Risk Management, including Risk Associate 22

E. P. SCHIFFER

Line U-20236

No.

EPS - 2

for DTE Energy Trading (gas), Sarbanes Oxley Control Center lead for Trading and 1

Risk Analyst (Enterprise Risk and DTE Gas). In 2013, I was promoted to Principal 2

Supervisor responsible for Gas Accounting – gross margin and then in 2014 I 3

accepted a position in the LLC Controllers – Decision Support Consolidation. In 4

2018, I accepted my current position, Senior Gas Supply and Planning Analyst. 5

6

Q5. What are your responsibilities as Senior Gas Supply and Planning Analyst? 7

A5. As Senior Gas Supply and Planning Analyst, I am responsible for the purchase of 8

natural gas and interstate transportation capacity to deliver the supply to the DTE Gas 9

system to serve GCR customers. I am also responsible for the analysis, planning and 10

forecasting of DTE Gas natural gas supply and transportation volumes, prices and 11

costs, and development and administration of the fixed price program. 12

13

Q6. Have you previously testified or submitted testimony in any Michigan Public 14

Service Commission (MPSC or Commission) proceeding? 15

A6. No, this is my first time submitting testimony in a MPSC proceeding. However, I 16

have provided support for DTE Gas’ Gas Supply witnesses for the 2017-18 GCR 17

Reconciliation MPSC Case No. U-U-20076 as well as audit and discovery requests 18

during 2018-19 GCR Plan MPSC Case No. U-18412. 19

DTE GAS COMPANY

DIRECT TESTIMONY OF ERIC P. SCHIFFER

Line

No.

EPS - 3


Q7. What is the purpose of your testimony in this proceeding? 2

A7. The purpose of my testimony in this proceeding is to present DTE Gas’ natural gas 3

supply plan (“Plan”) for the Plan Period extending from April 1, 2019 through March 4

31, 2024 (“Plan Period”). My testimony will cover the following subjects and 5

demonstrate that DTE Gas’ proposed gas supply Plan for the Plan year and the five-6

year Plan Period is reasonable and prudent: 7

1) Supply Pricing Mix - DTE Gas’ pricing strategy is a mixture of both fixed 8

price supply where the price is known months in advance of delivery and 9

index price supply where the price is uncertain until delivery begins. 10

Specifically, my testimony will discuss how DTE Gas will mitigate price 11

uncertainty utilizing the Volume Cost Averaging methodology (VCA or VCA 12

Method) of purchasing fixed price supply, which was first approved by the 13

MPSC in the Company’s 2010-2011 GCR Plan, Case No. U-16146, and 14

contained in every subsequent Commission-approved GCR Plan (Case Nos. U-15

16482, U-16921, U-17131, U-17332, U-17691, U-17941, and U-18152) 16

through the Company’s 2018-2019 GCR Plan, Case No. U-18412. 17

2) Price Forecast – The price forecast is based on the average settled prices of 18

the first five trading days of December 2018 because this is the most recent 19

data available at the time this filing was prepared. This approach is consistent 20

with past practice. 21

3) Gas Supply Purchasing - How the appropriate supply requirements are 22

determined for the ensuing month in monthly gas supply meetings after taking 23

into account the supply currently under contract and subsequently contracting 24

E. P. SCHIFFER

Line U-20236

No.

EPS - 4

for supply needs from different geographic production regions and market 1

zones based on operational requirements first, followed by the lowest cost 2

supply basin second, while acknowledging such factors as weather, natural gas 3

market fundamentals, national inventory levels, geographical pricing, and 4

system requirements. 5

4) Transportation Portfolio Changes – Since its last GCR Plan Case filing, the 6

only change to the transportation portfolio was an amendment to the NEXUS 7

transport contract to add the Clarington receipt point to gain access to 8

additional supply sources at a significant reduction to gas cost. Also, I have 9

not included any cost adjustments at this time for interstate transportation 10

expense related to the Tax Cuts and Jobs Act of 2017. The four interstate 11

pipelines on which DTE Gas holds maximum recourse rate, firm contracts 12

have filed the Form 501-G with the FERC and DTE is awaiting FERC’s 13

response. Witness Krysinski will address this in further detail. 14

5) NEXUS Transportation costs – How DTE Gas’ acquisition of NEXUS 15

transportation for $0.695 DTH/m is a reasonable and prudent cost. 16

6). Projected Total Gas Supply Costs - How DTE Gas’s total supply 17

requirements for the 2019-20 GCR Plan Period are forecasted at 18

approximately 128.1 Bcf at a total cost around $396 million, including 19

approximately $58 million in total transportation costs. 20

7) Projected Supply Costs for LIFO Valuation of Gas in Storage - The 21

projected NYMEX, volumes and costs are associated with the January 2019 22

through March 2019 period for LIFO valuation of gas in storage, which is 23

utilized by Company Witness Moore.24

E. P. SCHIFFER

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No.

EPS - 5

8) ANR Alpena Transport Costs – Pursuant with the Commission’s Order in 1

Case U-18999, ANR Alpena transport costs will be included in the GCR 2

mechanism. 3

9) Gas Supply Strategy for April 2020 and Beyond – How DTE Gas’ gas supply 4

strategy for April 2020 and beyond is essentially consistent with the strategy 5

used for the April 2019-March 2020 period including a projection of gas 6

purchases and transportation costs. 7

8




A-7 Fixed Price Purchase Guidelines 12

A-8 Projected NYMEX, Basis, and Supply Basin Prices 13

A-9 Summary of Transport Contracts 14

A-10 Projected Purchase Volumes and Cost (Excluding Transportation 15

Costs) 16

A-11 Projected Transportation Utilization, Reservation Costs, and Usage 17

Costs 18

A-12 Projected Total Delivered Cost Including Transportation Cost 19

A-25 Historical Back cast of NYMEX Prices 20

A-26 NEXUS Gas Transmission Currently Effective Rates Applicable to 21

Rate Schedule FT-1 In FERC NGA Gas Tariff 22

A-27 Fixed Price Program Analysis -- Purchase Percentages 23

A-29 NYMEX Monthly Settlement History 24

E. P. SCHIFFER

Line U-20236

No.

EPS - 6

A-30 October 23, 2018 Negotiated Rate Agreement Adding Clarington 1

Receipt Point 2

3



6

Supply Pricing Mix 7

Q10. How is DTE Gas proposing to price its supply during the 2019-2020 GCR Plan 8

Period? 9

A10. DTE Gas’ supply will be priced utilizing a mixture of both fixed price supply where 10

the price is known months in advance of delivery and index price supply where the 11

price is uncertain until delivery begins. 12

13

Q11. What fixed price method is DTE Gas proposing to operate under during the 14

2019-20 GCR Plan Period? 15

A11. DTE Gas will continue to purchase fixed price supply under the Volume Cost 16

Average (VCA) Method, which is the same fixed price method that was first 17

approved expressly by the Commission on September 28, 2010 in the Company’s 18

2010-2011 GCR Plan, Case No. U-16146, thereby replacing the quartile indices 19

method (QIM). This very same VCA method has been contained in every subsequent 20

Commission-approved GCR Plan (Case Nos. U-16482, U-16921, U-17131, U-21

17332, U-17691, U-17941, U-18152), through the Company’s pending 2018-19 22

GCR Plan Case No. U-18412. The specific guidelines of the VCA Method are 23

detailed in Exhibit A-7. 24

25

E. P. SCHIFFER

Line U-20236

No.

EPS - 7

Q12. What is the purpose of the VCA Method? 1

A12. The VCA Method is a methodology used to create price certainty for natural gas 2

volumes that will be delivered at a future date. VCA provides upward price 3

protection, downward price participation, a year-over-year smoothing effect on the 4

GCR factor, and most importantly, it is a simple and effective way to manage price 5

fluctuations and dampen natural gas price uncertainty for GCR Customers under a 6

variety of actual and potential market and operating conditions. 7

8

Q13. How does the VCA Method operate? 9

A13. In general, DTE Gas will fix the price of its future supply requirements over a two-10

year period prior to the start of delivery during the GCR Period. For the 2019/20 11

GCR year, DTE Gas bought 75% of the projected requirements ratably between 12

January 2017 and December 2018 (approximately 3% each month). This program 13

results in the price of 75% of DTE Gas’ supply requirements being known prior to 14

the start of the GCR Period. 15

16

Q14. Did DTE Gas conduct an annual review of the VCA Method? 17

A14. Yes. DTE Gas reviewed the fixed price program (FPP) objectives, the current 75% 18

level of fixed price coverage, and updated the quantitative analysis based on current 19

market conditions. These reviews and analyses were necessary to corroborate the 20

Company’s opinion that the VCA Method continues to form the foundation of a 21

reasonable and prudent FPP. Specifically, DTE Gas updated the NYMEX back test 22

through March 2018, which provides a 16-year historical view of how the VCA 23

Method would have performed based on the current purchase pattern with historical 24

prices. In addition, DTE Gas updated the Random Price Analysis, which is a 25

E. P. SCHIFFER

Line U-20236

No.

EPS - 8

forward-looking analysis of the VCA Method’s performance in 5,000 different price 1

scenarios. The Random Price Analysis update was necessary to determine that the 2

original conclusions resulting from the analysis have not changed based on current 3

market conditions. The NYMEX back test, Random Price Analysis updates, and 4

related conclusions are described in greater detail below as are the FPP’s objectives. 5

This annual review and analyses support the continued use of the VCA Method. DTE 6

Gas also created two additional analyses, an analysis of the fixed price program 7

consisting of the Future NYMEX Projection and a 95% Confidence Interval of 8

possible future prices, and an analysis of the historical NYMEX natural gas price 9

frequency distribution. 10

11

Q15. What are the objectives of a reasonable and prudent FPP? 12

A15. The objectives of a reasonable and prudent FPP include: 13

(1) mitigating the impact of market price fluctuations and price uncertainty, also 14

known as price volatility or price risk, to provide GCR factor stability; 15

(2) allowing participation in downward price movements; 16

(3) protecting customers against upward price movements; 17

(4) utilizing a prescriptive methodology that limits speculation; and 18

(5) ensuring simplicity by utilizing a methodology that is not overly complex. 19

20

Q16. Does the VCA Method still meet all the objectives of a reasonable and prudent 21

FPP? 22

A16. Yes. The VCA Method continues to meet all the objectives for a reasonable and 23

prudent program for purchasing fixed price gas. VCA allows continual market 24

participation over an extended period, up to two years in advance of the GCR Period 25

E. P. SCHIFFER

Line U-20236

No.

EPS - 9

start date. The methodology is consistent with the philosophy that one should not try 1

to beat or time the market, but instead regularly participate in the market over an 2

extended period, which is a reasonable and prudent method for mitigating price 3

fluctuations or volatility. VCA provides upward price protection, downward price 4

participation, GCR factor stability, and most importantly it is a simple and effective 5

way to manage price uncertainty and dampen price fluctuations. 6

7

Q17. How does VCA protect the customer against upward price movements and 8

allow for downward price participation? 9

A17. In the event of a temporary price spike in any given month, only approximately 3% 10

of supply would be exposed to that price spike. Fast forward in time and assume that 11

the temporary price spike does not abate, but instead becomes a fundamental upward 12

price level shift. Under such circumstances, the purchase made during the initial price 13

increase under VCA will be favorable in the new, higher price environment. In the 14

event prices abate in subsequent months, then the customer will participate in the 15

downside price movements with the execution of fixed price purchases during that 16

abatement period. VCA spreads risk evenly over time and volumes in contrast to 17

alternative approaches that may be speculative in nature and subject customers to 18

additional price risks that are inherent with speculative trading. 19

20

Q18. How would VCA provide benefits to the customers in the event prices do not 21

abate but continue in a perpetual fundamental upward price shift? 22

A18. If the market is in a long term upward price shift, then VCA would fix prices during 23

the upward march of market prices, thereby contributing to a lower weighted average 24

cost relative to the higher market prices at the time of the final delivery date. 25

E. P. SCHIFFER

Line U-20236

No.

EPS - 10

Q19. How does VCA eliminate price speculation? 1

A19. VCA eliminates price speculation because the volumetric amount of the purchases is 2

fixed each month regardless of price. Therefore, the purchases are time dependent 3

as opposed to price dependent. VCA also provides protection from price risk and 4

uncertainty through equal volume purchases executed monthly over a defined period 5

well in advance of the delivery month. The purchase price in any given month could 6

be an outlier that is an extreme high or low relative to historical prices. However, 7

any individual monthly price will have a limited impact on the volume weighted price 8

of gas. 9

10

Q20. Does the VCA provide GCR factor stability? 11

A20. Yes. The VCA Method mitigates price uncertainty, price risk, price variability, and 12

volatility, thereby creating greater GCR factor stability. 13

14

Q21. How will the VCA Method perform in a stable price environment? 15

A21. In a stable price environment, the VCA will yield gas costs that are similar to not 16

purchasing forward at all. This is due to the fact that VCA is a time dependent 17

technique and if VCA purchase prices fixed in advance of the delivery date remain 18

relatively stable until the actual delivery date, then VCA will yield similar gas costs 19

to purchasing at Index. Index purchasing is a passive strategy that does not involve 20

any form of advanced purchasing that locks in price certainty for future deliveries, 21

which exposes all purchase requirements to market price fluctuations until the time 22

of delivery. 23

24

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Q22. Would the Company continue to purchase forward transactions during a stable 1

price environment in which the VCA will yield gas costs that are similar to not 2

purchasing forward at all? 3

A22. Yes, because a stable price environment is only visible in hindsight. It is not until 4

the trading for a month has elapsed that one can know what the monthly settlement 5

price will be. The Webster’s New International Dictionary, Second Edition, defines 6

“stable” as meaning “Firmly established; not easily moved, shaken or overthrown; 7

solid; fixed; steadfast.”1 See Exhibit A-29, NYMEX Monthly Settlement History, 8

for a history of NYMEX monthly settlement data. As shown in Exhibit A-29, the 9

NYMEX settlement price has varied between a high of $5.557 in February 2014 and 10

a low of $1.711 in March 2016. These settlements are 25 months apart, which is only 11

one month greater than the 24-month term utilized by DTE Gas’s Volume Cost 12

Averaging (VCA) program. During this 25-month period, the highest settlement price 13

is more than three times or 300% greater than the lowest settlement price. This type 14

of large price swing is not a characteristic of the above definition of a “stable” market. 15

16

Q23. Is there a recent example of price volatility that could impact the cost of gas? 17

A23. Yes. From 10/31/18 through 11/28/18 the December – March NYMEX contracts 18

rose from $3.16 - $4.54 ($1.36) with day over day increases ranging from ($0.799) - 19

$0.736 (over $1.50 swing). On November 14, December NYMEX traded at 20

$4.837/MMBTU (highest price since February 2014). Speculation is that the run up 21

was driven by low storage levels (significantly below the five-year average) as well 22

as colder than expected forecasts. This led to cash prices running up along with 23

current winter prices while out year pricing was relatively flat (April 2019 – March 24

1 Webster’s New International Dictionary 2449 (2d ed. 1934)

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2020 contracts only moved $0.11 from $2.78 to $2.89 from 10/31/18 – 11/28/18). If 1

weather is the driver for volatility, then you would expect the out year to have 2

minimal price moves (or at least a dampened impact). 3

4

Samer Mosis and Jason Lord wrote in Gas Daily (an industry trade publication) on 5

11/16/18, “The market may be in fear this winter with this week’s return to volatility. 6

Weather will be the main driver. Movements as seen Thursday may continue to be 7

irrational through the peak of winter natural gas demand.” The VCA protects the 8

customers by only exposing them to current month/seasonal weather speculation as 9

we purchase 75% of the requirements based on normal weather and based on 10

historical data, as explained further by witness Chapel. For the remaining 25% the 11

company purchases during month-ahead bid week based on normal requirements and 12

adjusting for known weather impacts. 13

14

Q24. Is there any way to predict that a “stable” market will occur in the future? 15

A24. No. One cannot know with any certainty how much the price of natural gas will 16

change or fluctuate from month to month. It is only upon looking back over a period 17

of time that one can ascertain that pricing did not change and can deem that period 18

of time as “stable” in hindsight. Lacking the ability to foresee the future, the most 19

reliable method to secure pricing stability is by acquiring gas supply under fixed 20

prices. That is the function of the VCA program. It is to create a “stable” price 21

environment for the GCR customers regardless of the actual vagaries of the 22

marketplace. 23

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Q25. What is the Random Price Analysis? 1

A25. The Random Price Analysis, originally presented in DTE Gas’ Commission-2

approved 2012-2013 GCR Plan Case No. U-16921, is a method for analyzing the 3

range of possible random outcomes from a particular purchasing method. The 4

Analysis is used to compare the VCA (at different fixed price percentages) with an 5

all-index method. Utilizing the price curve as of November 21, 2018 and current 6

volatility (11%), I ran 5000 random scenarios to identify the range of gas costs an 7

average consumer would experience under each method. 8

9

Q26. What updates did you make to the Random Price Analysis? 10

A26. The Random Price Analysis has been updated for this GCR Plan Case to reflect minor 11

changes in DTE Gas’ purchase profile, current market prices, and associated market 12

price volatility. 13

14

Q27. Did your update change the results of the Random Price Analysis? 15

A27. No. The conclusions and findings of the analysis, that were originally presented in 16

Case No. U-16921, have not changed. Specifically, the Random Price Analysis 17

confirms that the level of price risk or uncertainty that is borne by customers is 18

dependent upon the level of fixed price coverage. More specifically, decreasing the 19

level of fixed price coverage produces an increasingly wider range of potential price 20

outcomes, or higher level of price uncertainty, which is synonymous with increased 21

price volatility or price risk. This can be seen on Table 1 line 5, where 95% of the 22

time, the Index Method produces price outcomes between $3.21 and $6.33. 23

However, 95% of the time, the 75% VCA Method, represented on line 1, produces 24

price outcomes in a smaller, more compact range between $3.55 and $5.83. Stated 25

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differently, 95% of the time, the Index Method produces residential gas costs that are 1

70% to 138% of the average cost. In contrast, the 75% VCA Method produces a 2

more condensed and compact range of possible cost outcomes that are 78% to 128% 3

of the average cost. 4

5

Q28. What is the NYMEX back test? 6

A28. The NYMEX back test was originally presented in DTE Gas’ 2012-2013 GCR Plan 7

Case No. U-16921. The NYMEX is an industry wide benchmark price of natural gas 8

at the Henry Hub receipt point in Louisiana. The NYMEX back test assumes a 9

purchase profile similar to DTE Gas’s current purchase profile for all years to 10

maintain consistency over the 17-year period. The intent of the analysis is to show 11

the cost and benefit of the VCA Method as compared to settled NYMEX prices over 12

an extended historical period. The analysis used NYMEX prices to represent gas 13

costs because of the availability of historical data and because it is an industry 14

recognized benchmark of natural gas prices that correlate to DTE Gas’s purchase 15

costs. 16

Table 1 – Random Price Analysis

Line Fixed Price Method $/Dth

Annual

Residential

Gas Cost 1 $/Dth

Annual

Residential

Gas Cost 1 $/Dth

Annual

Residential

Gas Cost 1

Maximum

Customer

Savings 1

Average

Customer

Savings 1

Maximum

Customer

Cost 1

Average

Customer

Cost 1

col. (a) col. (b) col. (c) col. (d) col. (e) col. (f) col. (g) col. (h) col. (i) col. (j) col. (k)

1 75% VCA 3.55$ 347$ 4.57$ 446$ 5.83$ 570$ (133)$ (22)$ 71$ 19$

2 65% VCA 3.51 343 4.57 446 5.89 576 (115) (19) 62 16

3 55% VCA 3.46 338 4.57 446 5.96 582 (97) (16) 52 14

4 45% VCA 3.42 334 4.57 446 6.02 588 (80) (13) 43 11

5 Index 3.21 313 4.57 446 6.33 618

(1) Based on average residential consumption of 97.7 Dth per year for the forecast year of 2018

Rising Prices Falling Prices

Low Price

(2.5th percentile) Average Price

High Price

(97.5th percentile)

Annual Residential Gas

Cost Compared to

Index

Annual Residential Gas

Cost Compared to

Index

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Q29. Did DTE Gas update the NYMEX back test for the most recent GCR Period 1

ending March 2018? 2

A29. Yes. DTE Gas updated the back test of historical NYMEX prices to include the most 3

recent April 2017 through March 2018 GCR Period. This NYMEX back test update 4

is designated as Exhibit A-25. 5

6

Q30. What were the results of the NYMEX back test update in terms of residential 7

gas costs? 8

A30. As shown in Exhibit A-25 line 18, over the 17-year historical period, a typical 9

residential customer would have paid $515 annually on average under the VCA 10

Method and $467 annually on average under the Index Method. In other words, over 11

the 17-year period customers would have paid $48 more annually or approximately 12

$4.00 more per month on average under the VCA Method than compared to the Index 13

Method. However, gas price fluctuations, or price uncertainty, which is synonymous 14

with price volatility, over the 16-year period was only 15% under the VCA Method, 15

which was significantly less than the Index Method volatility of 33%, as described 16

more fully below. 17

18

Q31. What does a reduction in volatility mean for the GCR customer? 19

A31. As shown in Exhibit A-25, line 19, volatility under the VCA Method means that for 20

any given year, 95% of the time the customers’ gas costs would be within a range of 21

30% higher or 30% lower than the average cost based on the past 15 years. By 22

contrast, volatility under the Index Method means that, for any given year, 95% of 23

the time the customers’ gas costs would be within a range of 66% higher or 66% 24

lower than the average cost based on the past 17 years. Consequently, the VCA 25

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Method significantly reduces the risk of extreme price run ups and provides greater 1

price certainty for the GCR customers, therefore providing greater assurance of price 2

affordability. 3

4

Q32. What conclusions did you reach based on the NYMEX back test? 5

A32. The $48 annual cost difference between the VCA Method and the Index Method that 6

occurred over the historical 17 years used in the back test is approximately 10% of 7

the customers’ gas cost (and an even lower percentage on a total bill basis), which is 8

a reasonable cost to pay to lower the gas price volatility from 33% under the Index 9

Method to 15% under the VCA Method as explained above. 10

11

Q33. In addition to these two analyses, did DTE Gas perform any additional review 12

of the VCA Fixed Price Purchase Program? 13

A33. Yes. DTE Gas prepared the analysis presented in Graph 1, Fixed Price Program 14

Analysis -- Future NYMEX Projection – 95% Confidence Interval and the Frequency 15

Distribution of Historical NYMEX prices analysis. These analyses were created in 16

response to the April 23, 2015 Commission Order U-17332, which states at page 5 17

that:18

“The Commission reiterates that, going forward, the burden continues 19

to be on DTE Gas to manage risk and to facilitate the affordability of the 20

natural gas sold to GCR customers. The Commission is not looking for 21

proof that a specific percentage of purchases were locked-in, but wants 22

to ensure that, over time and under a variety of actual and potential 23

market and operating conditions, the benefits of price stability to the 24

GCR customers outweigh any additional cost associated with the 25

procurement strategy. Accordingly, the Commission expects DTE Gas 26

to address the risk mitigation costs and benefits under different 27

conditions…” 28

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These analyses are intended to show that the benefits of price stability to the GCR 1

customers outweigh any additional cost associated with the VCA procurement 2

strategy. These analyses represent this cost vs. benefit by comparing and quantifying 3

the upside risk of higher prices against the downside opportunity of lower prices in 4

future natural gas prices. 5

6

Q34. What data is contained in the price probability model? 7

A34. Graph 1 is based on the methodology from the “EIA Past Henry Hub Price and 95% 8

NYMEX Confidence Interval” analyses performed by the United States Department 9

of Energy’s Energy Information Administration (EIA) in each monthly publication 10

of its Short-Term Energy Outlook (STEO). The upper and lower dotted lines that 11

create the cone-shaped projection are the Upper Confidence Level (UCL) and Lower 12

Confidence Level (LCL) projected five years into the future for NYMEX natural gas 13

futures prices. The 95% confidence level represents the 95% probability that the final 14

market price for a particular futures contract will fall somewhere within the lower 15

and upper range of prices. Note that the lower range of prices has the same 16

probability of occurrence as the upper range.17

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1

2

Q35. What do the remaining lines on Graph 1 represent? 3

A35. The blue line in the middle of the Graph that displays a series of peaks and valleys as 4

it goes into future months represents the NYMEX natural gas futures prices for the 5

next five years derived from the forward curve on November 26, 2018. The purple 6

jagged line on the left side of the Graph is the actual monthly NYMEX settlement 7

price from January 2015 through December 2018. This shows a range of recent 8

prices that have been as high as $4.72/Dth in December 2018 and as low as $1.71 in 9

March 2016. By displaying the market projections in this manner, the observer can 10

easily review purchases from the perspective of the data that was known at the time 11

Graph 1

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that the purchase decisions were made. This removes the coloring of hindsight from 1

the equation and allows for an understanding of the rationale that shows that the 2

benefits of the VCA outweigh any additional costs. 3

4

Q36. How would you quantify the value of the upside risk and the downside 5

opportunity in future natural gas pricing where the future prices are uncertain? 6

A36. Graph 1 is based upon the methodology used in the U.S. Energy Information 7

Administration (EIA) Short Term Energy Outlook (STEO) for quantifying price 8

uncertainty. This graph covers the time range from January 2016 through March 9

2023. This graph shows projections at a 95% confidence interval at the Henry Hub 10

for Natural Gas Prices going forward for the next six years as projected by the 11

NYMEX prices as of November 29, 2018. The average of the Upper Confidence 12

Level (UCL) of natural gas pricing is $0.67/Dth above the average NYMEX, and the 13

average of the Lower Confidence Level (LCL) is $0.55/Dth below the average 14

NYMEX. This tells us that there is an equal chance of the price rising by $0.67 as 15

there is of the price declining by $0.55. Thus, although the probability is equal of 16

prices going up or down, the 95% confidence interval range of a price increase is 17

21% greater than the range of a price decrease (21% = ($0.67-.55) / ($0.55)). This 18

graphically displays (as summarized in Table 2 below) the fact that the potential cost 19

(risk) exposure of a price increase is greater than the potential cost savings 20

(opportunity) from a price decrease. 21

22

23

24

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Price Outlook for Jan 2018 through Mar 2023 as of Nov 29, 2017: 1

NYMEX

Price

(Col 1)

UCL

Avg Price

(Col 2)

LCL

Avg Price

(Col 3)

UCL

Range

(Col 4)

LCL

Range

(Col 5)

Range Ratio

UCL/LCL

(Col 6)

$2.84 $3.51 $2.29 $0.67 $0.55 121%

2

Q37. Have you also observed this upside risk and the downside opportunity in 3

historical natural gas pricing? 4

A37. Yes, I reviewed the historical NYMEX settled prices from June 1990 to November 5

2018 to prove the upward bias of pricing. Graph 2 is a frequency distribution graph 6

of the historical NYMEX settlement prices from June 1990 to November 2018. The 7

X axis on the graph shows the range of settlement prices from lowest to highest in 8

Table 2

Graph 2

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$1.10 increments, or bins, during that time period, and the Y axis shows the number 1

of occurrences that the NYMEX settled within the price range for each increment. 2

3

Q38. Is there a historical bias toward the upside risk versus downside opportunity? 4

A38. Yes, history has shown that 50% of the time prices ran up as much as $10.81 from 5

the median price but only dropped from the median price by as much as $2.76. The 6

average price above the median was $5.40 ($2.31 above median) and the average 7

price below the median was $2.20 ($0.89 below median), which shows on average 8

that price run ups were 2.3 times greater than price drops ($2.31/$0.89 = 2.3). Thus, 9

compared to the median price, higher prices occurred an equal amount of the time as 10

lower prices, but the cost impact was 2.3 times greater for the higher prices than the 11

lower prices. The fixed price program helps protect the customer from this upside 12

risk of higher gas prices, which historically have 2.3 times greater cost impact than 13

lower prices relative to the median. 14

15

Q39. How does Graph 2 and Table 2 demonstrate that the benefits of price stability 16

to the GCR customers outweigh any additional cost associated with the fixed 17

price procurement strategy? 18

A39. The benefits are twofold: one benefit is the price certainty obtained with a fixed price, 19

and the other benefit is the protection from the potential of higher prices. By 20

implementing the VCA, the Company has locked in 75% of the gas costs prior to the 21

gas year. Assuming normal weather, approximately 2/3 of the costs will be similar 22

from the prior year, thus there will not be huge swings in customer bills. As for the 23

potential of higher prices, the cost of a fixed price program is the impact of higher 24

prices to the customer while the benefit is the potential for lower prices when prices 25

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fall. When you look at the asymmetry of rising versus falling prices and where gas 1

prices have been historically a monthly $3 cost clearly outweighs the benefits. 2

3

Q40. What are the “current and forecasted market conditions and fundamental 4

economic and physical considerations that affect gas supply and prices” (see 5

MPSC Order dated April 15, 2014 in Case No. U-17131)? 6

A40. As described in my testimony above, the forecasted market conditions contain risk 7

and uncertainty. The Short-Term Energy Outlook (STEO) released by the Energy 8

Information Administration (EIA) in October of 2018 shows that current market 9

conditions are very tight, with national storage balances 20% below the 5-year 10

average: 11

Prices for natural gas futures contracts for October delivery generally 12

trade at a lower price than contracts for January delivery, when natural 13

gas demand is expected to be much greater. This year, however, the 14

discount of the October contract to the January contract was at its lowest 15

in the past five years…The tighter natural gas market this summer 16

contributed to a narrower spread between the October and January 17

natural gas future prices, which averaged 16 cents/MMbtu during the 18

month of September compared with a range of 20 cent to 40 cent/MMBtu 19

discount over the past five years. 20

This was caused by natural gas used for power generation and record LNG exports. 21

All of these factors contributed to the national storage balance at the end of the 22

injection season to approximately 3.0 Tcf which is approximately 0.8 Tcf, or 20%, 23

below the 5-year average. As stated in Q. 38, we are already seeing extreme volatility 24

in prices even before entering the deep winter when the risk of the low storage 25

balances will potentially materialize. 26

27

Q41. Why is the VCA method reasonable and prudent for DTE Gas’ customers? 28

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A41. In general, natural gas is not a discretionary purchase that can be avoided based on 1

price or some other factor. DTE Gas’ customers need to purchase and consume 2

natural gas throughout the year for such basic needs as warmth in their homes and 3

businesses. The greatest unknown to the customer is not necessarily how much 4

natural gas they will consume but more importantly at what price they will purchase 5

natural gas to supply their inherent need for natural gas. DTE Gas’ customers should 6

not be unduly subject to risk taking or speculating on what the price of natural gas 7

will be in the future. The greater risk to DTE Gas’s customers is rising prices because 8

most customers, especially residential customers and small businesses, are generally 9

believed to have a fixed amount of non-discretionary income to spend on a natural 10

gas utility bill. These customers would ultimately be more financially burdened with 11

higher bills (if gas prices rise over time) as opposed to steady or somewhat lower bills 12

(if gas prices decline over time). 13

14

Q42. How does the VCA Program mitigate this rising price risk for the customers? 15

A42. Without some method of managing price uncertainty, DTE Gas’ customers could be 16

exposed to prices that could rise without constraint and be exposed to unlimited price 17

risk. While the Random Price Analysis and the 95% Confidence Interval analyses 18

contained in the Graphs and Tables above show the probability of a range of prices 19

into the future, they only represent a snapshot in time reflected by the price volatility 20

of the current market. However, the volatility of gas prices has and can swing widely, 21

rapidly, and unpredictably without any prior notice or forewarning. Thus, to mitigate 22

the potentially unlimited price risk and uncertainty, which could adversely impact 23

customers’ budgets, DTE Gas has implemented the VCA method wherein the price 24

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of natural gas is fixed for a portion of their supply many months prior to delivery, 1

thereby creating price certainty or price protection. 2

3

Q43. Why is 75% a reasonable and prudent level of fixed price coverage? 4

A43. The optimal level of fixed price protection that DTE Gas can provide customers and 5

still have operational flexibility to adjust for lower purchase requirements associated 6

with GCC migration, warmer than normal weather, or conservation resulting from 7

ongoing energy-efficiency initiatives is 75%. Stated differently, customers currently 8

shoulder 25% of the price risk during the delivery period, which is an acceptable and 9

reasonable level of price risk or uncertainty based on operational constraints and the 10

customers’ inherent risk-adverse nature. As the level of fixed-price coverage is 11

reduced from the 75% level, there is an equal and offsetting increase in the level of 12

price risk or uncertainty. Under the 75% VCA Method, if prices rise over time, 13

customers are rewarded through protection from the rising prices. However, if prices 14

fall over time, customers risk paying more than they would have under a fixed-price-15

coverage ratio less than 75%. The greater risk to DTE Gas’ customers is the risk of 16

rising prices because they typically have a fixed amount of non-discretionary income 17

to spend on a natural gas utility bill, and customers would ultimately be more 18

financially burdened with higher bills as opposed to steady or somewhat lower bills. 19

Using the 75% ratio strikes the appropriate balance between protecting customers 20

against rising prices, and allowing them to participate in any price decrease. Using a 21

lower ratio exposes customers to too much risk of price increases. Therefore, using 22

the VCA method with a 75% fixed price coverage ratio is a reasonable and prudent 23

approach to protecting customers from price risk. 24

25

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Q44. How does the VCA Method perform relative to the Index Method in different 1

price environments in terms of gas costs? 2

A44. In a rising price environment, in which prices consistently increase as time 3

progresses, the VCA Method will produce lower gas costs than the Index method. 4

Ina falling price environment, in which prices consistently decrease as time 5

progresses, the VCA Method will produce higher gas costs than the Index method. It 6

is important to remember that no one can accurately predict the future natural gas 7

price environment, and the greater risk to DTE Gas’ customers comes from a 8

drastically rising price environment as opposed to a drastically falling price 9

environment. It is equally important to bear in mind that one of the goals of the VCA 10

Method is to mitigate the risk of price spikes and to provide a stable price to DTE 11

Gas’ customers, and that the VCA Method was not designed or intended to compete 12

with or “beat” the Index-based natural gas market. Although gas costs in a falling 13

price environment may be lower with a fixed price coverage that is less than 75%, 14

there is an equal and offsetting risk of higher gas costs in a rising price environment. 15

The VCA Method protects against the financial burden of higher gas costs to the 16

customer; which is of primary concern because the natural gas utility bill, insofar as 17

it provides home heating during the frigid cold winters of the Michigan climate, is a 18

non-discretionary expense, and many customers may not be able to afford the added 19

cost without undue hardship. 20

21

Q45. How much gas has DTE Gas purchased under the VCA FPP for delivery in the 22

April 2019-March 2020 GCR Period? 23

A45. Currently, DTE Gas has purchased 75% of the April 2019 through March 2020 24

requirements and has therefore achieved the 75% fixed-price-coverage ratio by 25

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December 31, 2018, as specified in the Commission approved FPP. Projected 1

volumes are shown on Exhibit A-10, page 1, line 1. 2

3

Q46. Is DTE Gas proposing any changes to the VCA FPP that was originally 4

approved by the Commission in Case No. U-16146 and subsequently approved 5

as part of every GCR Plan in Case Nos. U-16482, U-16921, U-17131, U-17332, 6

U-17691, U-17941 and U-18152? 7

A46. No. 8

9

Q47. Why is the Company not proposing any changes to the VCA FPP? 10

A47. The Company’s analysis of the VCA Method contained in this filing supports the 11

continuation of the FPP and the benefits derived therefrom. 12

13

Q48. When will DTE Gas lock in fixed-price purchases each month? 14

A48. The timing of each intra-month purchase is based on factors such as willing 15

counterparties, creditworthiness, market liquidity, and other best-available market 16

intelligence at the time of purchase. Utilization of these factors will ensure that intra-17

month purchases are executed in a reasonable and prudent manner. 18

19

Q49. How does DTE Gas plan to price its remaining supply requirements that are not 20

fixed purchases? 21

A49. All gas that is not locked in at fixed prices will be priced utilizing market-based 22

settled-index prices or at the NYMEX settlement price plus a fixed premium or minus 23

a fixed discount based on the geographic purchase point, which is also known as fixed 24

basis. 25

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Q50. What is a market-based settled-index price? 1

A50. Market-based settled-index prices are determined by independent publishing 2

companies that survey market participants a week before the delivery month as to the 3

value of gas to be delivered during the month. The market-based settled-index prices 4

are published industry wide. 5

6

Q51. What is the NYMEX settlement price? 7

A51. NYMEX is the world’s largest physical-commodity futures exchange and is the 8

industry-wide recognized price reference point for commodities including natural 9

gas. NYMEX provides the North American market’s collective assessment of the 10

expected future values for natural gas. NYMEX trades reveal the value in dollars per 11

Dth that the market places on gas delivered to the Henry Hub trading point, located 12

in Louisiana, for each future delivery month. The NYMEX settlement price is 13

determined on the last day that market participants can enter into transactions before 14

the delivery month. 15

16

Q52. Why are either the market-based settled-index price or the NYMEX settlement 17

price, plus a fixed premium or minus a fixed discount, the best methods for 18

pricing remaining gas supplies that are not fixed purchases? 19

A52. These are the best methodologies to secure spot market pricing because they represent 20

the most recent value the market places on gas immediately prior to the month of 21

delivery. 22

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Price Forecast 1

Q53. What methodology did DTE Gas use to forecast gas prices for this GCR Plan 2

Case? 3

A53. The five-year price forecast, which is a long-term price projection for the market, is 4

found on Exhibit A-8. Line 1 contains the average settlement price for the first five 5

trading days of December 2017 for the NYMEX Henry Hub natural gas futures 6

contract for each respective delivery period. The remaining lines show the forecasted 7

basis price differentials and resulting prices for the indicated purchase locations. All 8

prices are stated in dollars per Dth. Throughout this testimony, I assume a simple 9

average heating value of 1.051 Dth per Mcf. This heating value assumption is more 10

fully addressed in the testimony of Witness Chapel. 11

12

Q54. Why did DTE Gas use the average settlement price for the first five trading days 13

of December 2018 to forecast market prices? 14

A54. The average of the settlement prices on the first five trading days of December 2018 15

is the most recent natural gas traded prices at the time the Plan was finalized for filing 16

in this Plan Case. 17

18

Q55. How did DTE Gas forecast the price of gas at geographic locations other than 19

at Henry Hub? 20

A55. The price of gas at different geographic locations is measured through basis-price 21

differentials. Basis-price differentials represent the difference in price for gas 22

delivered at the indicated geographic location and the price for gas delivered at Henry 23

Hub as traded on the NYMEX. Basis prices may be expressed as either a positive (a 24

price that is higher than Henry Hub) or a negative (a price that is lower than Henry 25

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Hub) depending on the geographic location. The basis differential for DTE Gas’ 1

receipt points reflects prices both higher and lower than Henry Hub. 2

3

Q56. What source is DTE Gas using for forecasted basis prices? 4

A56. DTE Gas is utilizing natural gas industry publications to forecast basis prices as 5

well as other available market intelligence. 6

7

Q57. How are projected gas prices at different geographic supply points used in your 8

gas supply forecast? 9

A57. These prices are used to calculate the cost of forecasted volumes that have not been 10

fixed. 11

12

Q58. Has DTE Gas included a forecast of volumes and prices associated with natural 13

gas purchases from affiliates in the Plan? 14

A58. Yes. DTE Gas has included 50,000 Mcf per month of forecasted volumes that it 15

plans to purchase from DTE Gas Gathering (MGAT) at the Platt’s Gas Daily Price 16

Guide first-of-the-month DTE Gas city-gate published index price. However, the 17

actual volumes may be more or less than 50,000 Mcf per month. This volume is 18

shown on Exhibit A-10, page 1, line 3, with the corresponding price projection on 19

line 11 of the same exhibit. 20

21

Gas Supply Purchasing 22

Q59. What process does DTE Gas use to acquire its monthly gas supply? 23

A59. DTE Gas maintains an active list of more than 30 creditworthy suppliers with 24

production in areas that connect to the Company’s contracted interstate transportation 25

E. P. SCHIFFER

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EPS - 30

capacity. Due to the continuous price volatility in the natural gas industry, DTE Gas 1

does not issue formal RFPs (Requests for Proposal) for its supply requirements. 2

3

For its supply needs, the Company generally solicits three or more verbal offer prices 4

from its list of creditworthy suppliers from the supply area that is required. DTE Gas 5

will attempt to complete transactions with the supplier who provides the lowest price 6

offer, but the Company also considers supplier diversity, supplier performance 7

history, ability to deliver to alternate receipt points, and creditworthiness existing at 8

the time of purchase in order to ensure a balanced and prudent gas supply plan. 9

10

Q60. What factors does DTE Gas consider when making decisions about purchasing 11

its supply? 12

A60. DTE Gas considers an array of factors in monthly meetings or more often if necessary 13

when making its supply decisions. These factors include, but are not limited to: 14

weather forecasts, system requirements and operational capabilities, the forward 15

NYMEX price curve, regional market basis prices, national storage levels as reported 16

by the Energy Information Administration (EIA), DTE Gas-owned storage levels, 17

and industry periodicals and reports such as Gas Daily and the EIA Short Term 18

Energy Outlook. 19

20

Q61. What level of interstate firm transport capacity does DTE Gas rely on to meet 21

its market requirements? 22

A61. DTE Gas maintains a portfolio of 400 MDth/day of firm transportation contracts for 23

the winter operating season and 330 MDth/day for the summer storage injection 24

E. P. SCHIFFER

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season to meet supply requirements for normal weather, colder than normal weather, 1

design day, and supplier of last resort. 2

3

Q62. What are the Company’s total reservation charges for firm pipeline capacity for 4

the 2019-2020 GCR year? 5

A62. The Company’s reservation charges for firm pipeline capacity for the 2019-2020 6

GCR year are approximately $55 million, which amount is shown on Exhibit A-11, 7

column (14), line 28. These costs are used by Witness Moore as the basis for the 8

Reservation Charge. 9

10

Q63. How will capacity-release revenues that DTE Gas receives be treated with 11

respect to the proposed SOLR charge? 12

A63. Any capacity-release revenues that DTE Gas receives will be credited back to 13

customers, both GCR and GCC, in the same load-proportionate manner as the 14

transportation-reservation costs were allocated. 15

16

Q64. What level of capacity-release revenues is DTE Gas estimating in this GCR Plan 17

Case to include in the SOLR reservation charge? 18

A64. Due to the highly unpredictable nature of capacity-release revenues, DTE Gas is not 19

predicting any capacity-release revenue to include in the SOLR reservation charge. 20

DTE Gas does not expect capacity-release revenues to materially impact the SOLR 21

reservation charge and any over/under recoveries that may occur will nevertheless be 22

addressed in the GCR Reconciliation. 23

24

E. P. SCHIFFER

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Q65. What are the total reservation charges for pipeline capacity that the Company 1

intends to recover through the SOLR Reservation Charge for the 2019-2020 2

GCR year? 3

A65. The total amount of reservation charges to be recovered for pipeline capacity is 4

approximately $55 million, which amount is shown on Exhibit A-11, line 28, column 5

(14). 6

7

TRANSPORTATION PORTFOLIO CHANGES 8

Q66. What pipeline capacity have you assumed in the GCR Plan Case for the period 9

April 2019 through March 2020? 10

A66. Exhibit A-9 shows all interstate transport currently under contract and their related 11

receipt points, capacity, and term. Exhibit A-11 separates transportation costs by 12

reservation and commodity charges. Exhibit A-11 also displays the total available 13

capacity and forecasted monthly load utilization associated with each pipe. 14

15

Q67. What changes has DTE Gas made to its interstate pipeline capacity since its 16

2018-2019 GCR Plan Filing? 17

A67. The only change that DTE Gas made to its transport portfolio that was not identified 18

in the prior GCR Plan filing was an amendment to the primary receipt point under 19

the NEXUS Contract. In October 2018, DTE Gas successfully negotiated the 20

addition of the Clarington receipt point on the NEXUS contract for the period of 21

November 1, 2018 – October 31, 2022 for an additional $0.15/Dth for 50% of the 22

contracted capacity, or 37.5 MDth/d (Exhibit A-30 October 23, 2018 Negotiated Rate 23

Agreement Adding Clarington Receipt Point). The Kensington receipt point is 24

located at the Kensington Gas Processing Plant, which is the head station of the 25

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NEXUS greenfield pipeline project. The Clarington receipt point is located on the 1

Texas Eastern Appalachian Lease (TEAL) pipeline project and is approximately 75 2

miles south of the Kensington receipt point. The TEAL system, when fully 3

operational, will create additional capacity to deliver up to 950 MDth/d of natural gas 4

production from approximately 11 different receipt points in the Appalachian Basin 5

in Texas Eastern’s Zone M2 between Berne, Ohio, and Uniontown, Pennsylvania, to 6

the interconnect with NEXUS near Kensington. TEAL was constructed by Enbridge 7

Energy Services, partially placed into service in October and November 2018, and 8

leased to NEXUS Pipeline. DTE Gas entered into this amended contract with 9

NEXUS to add the Clarington receipt point in order to gain access to additional 10

supply sources at lower prices in Texas Eastern’s Zone M2 with an estimated $4.8 11

million net reduction in gas costs over the four-year time frame. Table 3 is a summary 12

of the cost savings of $4.8 million by amending the NEXUS contract to add the 13

Clarington receipt point for 37.5 MDth/d for a term of 4 years. DTE Gas requested 14

75 MDth/d, however during negotiations with NEXUS, DTE was only able to acquire 15

37.5 MDth/d at this rate for 4 years. 16

E. P. SCHIFFER

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1

2

3

Q68. Does DTE Gas plan to pursue the remaining 37.5 MDth/d of TEAL capacity? 4

A68. Yes, if the costs are beneficial to the GCR customer. DTE Gas will evaluate the costs 5

associated with acquiring the remaining TEAL capacity, and if it is in the GCR 6

customer’s best interest, the Company will negotiate with NEXUS to acquire the 7

additional receipt point. 8

9

Q69. What changes does DTE Gas plan to make to its interstate pipeline contracts 10

during the 2019-2020 GCR Plan Period? 11

A69. DTE Gas does not have any interstate transportation contracts identified on Exhibit 12

A-9 that are scheduled to expire during the period April 2019 through March 2020. 13

However, 60 MDth/day of transport on Panhandle Eastern Pipeline (winter only) 14

Table 3

E. P. SCHIFFER

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expires on March 31, 2020 and DTE expects to renew or replace that contract prior 1

to expiration. 2

3

Q70. Is there regional diversity in the Company’s current transportation portfolio? 4

A70. Yes, Table 4 shows the regional variety and percentage of firm interstate-5

transportation contracts from each of the Company’s supply sources for the GCR 6

Plan Year. 7

8

9

10

Q71. Why is regional diversity of supply important to DTE Gas and its customers? 11

A71. DTE Gas’ customers benefit from regional diversity of supply with increased supply 12

reliability and mitigated price risk. Security of supply and increased options for 13

supply sources are the primary reasons DTE Gas holds regionally diverse interstate 14

transportation capacity. Supply basin diversity helps the Company mitigate adverse 15

Table 4

Winter Winter Winter

Supply Basin Percentage of Total Nov 17-Mar 18 Nov 18-Mar 19 Nov 19- Mar 20

Canadian:

Great Lakes Gas Transmission 8% 8% 8%

Viking/ANR 5% 5% 5%

Vector 5% 5% 5%

ANR Alliance/Willow 8% 0% 0%

ANR Northern Zone/Alpena 13% 13% 13%

39% 30% 30%

Mid-Continent:

ANR Southwest Leg 31% 19% 19%

Panhandle Eastern Pipeline 31% 31% 31%

61% 50% 50%

Appalachian:

NEXUS - Kensington only 0% 10% 10%

NEXUS - Clarington/TEAL 0% 10% 10%

0% 20% 20%

Total All Pipelines 100.0% 100.0% 100.0%

E. P. SCHIFFER

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effects of major disruptions in the general natural gas industry supply chain. If supply 1

becomes constrained in a particular basin, then a diverse supply portfolio helps in 2

insulating DTE Gas and its customers from the risk of potential supply disruptions in 3

that area. This diversity of supply is even more paramount this year due to the low 4

national storage levels. If we experience a colder than normal winter and need to 5

compete with other utilities for additional supply, having varied sources of that 6

supply increases the chances that the Company will be able to less expensive gas 7

than if the Company were restricted to purchasing from only one location. 8

9

Reasonableness of NEXUS $0.695/Dth Negotiated Ratebuy 10

Q72. What rate does DTE Gas pay for NEXUS transportation service? 11

A72. $0.695/Dth reservation charge plus 1.32% for fuel. There are no additional 12

commodity charges associated with the service. 13

14

Q73. What is the rationale for the $0.695/Dth and is it competitive and reasonable? 15

A73. See Exhibit A-26 showing the NEXUS Tariff Rate for Market Zone 1 to Market Zone 16

1 of $24.841/Dth/month or $0.8167 / Dth/day ((24.841 x 12) / 365), which is the tariff 17

rate for the Kensington to Ypsilanti transportation path held by DTE Gas. In addition, 18

there is a usage charge of $0.0057 / Dth / day as seen in Exhibit A-26. The DTE Gas 19

negotiated rate of $0.695/Dth (without any usage charge) is reasonable because it is 20

$0.1274/Dth less, or 5.5% less, than the tariff rate approved by FERC. This is an 21

annual savings of $3.5 million ((($0.8167+$0.0057-$0.695) x 75,000 x 365). 22

E. P. SCHIFFER

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Q74. Is the rate DTE Gas negotiated in line with what other anchor shippers are 1

paying for for NEXUS transportation service? 2

A74. No, it is anticipated to be lower than other anchor shippers. The other anchor shippers 3

negotiated variable rate contracts for $0.635 Dth/day and $0.65 Dth day with capital 4

trackers (capped at 15% or or $0.09 - $0.10 incremental or decremental costs). Costs 5

increases between 20-30% have been reported on NEXUS therefore it is anticipated 6

final rates will be ~ $0.73 Dth/d and $0.7475 Dth/d for the variable rate contract. 7

8

Q75. How did DTE Gas contract for the $0.695 rate for 15 years? 9

A75. DTE Gas submitted a bid on NEXUS’ open season. The open season terms required 10

a minimum of 15 years. During the negotiations there were two primary alternatives: 11

Fixed price for the entire 15 years or a rate that could be adjusted based on a capital 12

tracking mechanism related to the greenfield portion of the pipeline. As the project 13

was for a 250-mile greenfield pipeline, DTE Gas desired a fixed price for the contract 14

for cost certainty and to avoid the risk of a rate increase associated with potential cost 15

over-runs. 16

17

Q76. Does this rate allow for a known or measurable cost? 18

A76. Yes, DTE negotiated a fixed rate and any risk of cost overruns would be borne by 19

NEXUS and not DTE Gas’s customers. 20

21

Q77. Looking back, were there any cost overruns? 22

A77. Yes. Per the FERC order approving the NEXUS pipeline, the anticipated costs of the 23

pipe were approximately $2.1 billion, however based on Enbridge’s 10-Q dated 24

September 30, 2018 the estimated capital cost is now $2.6 billion. This leads me to 25

believe that there is $500 million of cost overruns, which is approximately 24%. It 26

E. P. SCHIFFER

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is safe to say that DTE Gas customers are better off locking in the fixed price versus 1

including the capital tracker, which would have had them paying for a share of those 2

significant overruns. 3

4

Q78. Was there any other benefit acquired in the negotiated rate with NEXUS? 5

A78. Yes. DTE Gas was able to acquire a most favored nation provision in the Precedent 6

Agreement. This provision guaranteed DTE Gas would be able to match any rate 7

that is lower than the $0.695/Dth if NEXUS entered into such an agreement with a 8

similarly situated shipper prior to the in-service date of the pipeline. Prior to NEXUS 9

going into service, there were no other shippers that negotiated lower rates than DTE 10

Gas. 11

12

PROJECTED TOTAL GAS SUPPLY COSTS 13

Q79. What are DTE Gas’ projected total gas purchase quantities and costs for the 14

April 2019 through March 2020 period? 15

A79. DTE Gas’ projected total gas purchase quantities and costs are summarized in Exhibit 16

A-10. This exhibit reflects projected total purchases and subtotals for these 17

categories: contracted fixed price, contracted indexed price, and supply not under 18

contract. The totals of these subdivisions are added together to arrive at the total 19

expected gas purchase quantity of approximately 138 MMDth (page 1, line 4, column 20

(14) and a total expected gas purchase cost around $338 million (page 1, line 12, 21

column (14) for the April 2019 through March 2020 period. These costs and volumes 22

are prior to pipeline fuel retention, prior to conversion from Dth (energy quantity) to 23

Mcf (volumetric quantity), and do not include pipeline transportation costs. 24

25

E. P. SCHIFFER

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Q80. What are DTE Gas’ projected total transportation costs for the April 2019 1

through March 2020 GCR Plan Period? 2

A80. DTE Gas’ projected total transportation costs are summarized in Exhibit A-11. This 3

exhibit reflects projected transportation reservation and commodity costs by month. 4

The total expected transportation cost is approximately $58 million (page 1, line 38, 5

column (14) for the period April 2019 through March 2020. 6

7

Q81. What are DTE Gas’ projected total supply costs and total delivered supply 8

volumes for the period April 2019 through March 2020? 9

A81. Projected total supply costs are presented on Exhibit A-12 and reflect the sum of the 10

projected gas purchases and transport costs. DTE Gas’ projected total supply cost 11

for the period April 2019 through March 2020 is approximately $396 million (Exhibit 12

A-12, page 1, line 3, column (14). The total delivered supply volumes are presented 13

on Exhibit A-10. DTE Gas’ total delivered supply volume for the period April 2019 14

through March 2020 is approximately 128 Bcf, Exhibit A-10, (page 1, line 8, column 15

(14)). This total delivered supply volume is the quantity delivered into DTE Gas’ 16

system after interstate pipeline fuel is removed and after conversion from Dth (energy 17

quantity) to Mcf (volumetric quantity) at a heating value of 1.051 Dth/Mcf. 18

19

PROJECTED SUPPLY COSTS FOR LIFO VALUATION OF GAS IN STORAGE 20

Q82. What projections have you developed regarding DTE Gas’ gas supply volumes 21

and costs for the period January 2019 through March 2019? 22

A82. Table 5 shows the projected NYMEX, volumes and costs for the period January 2019 23

through March 2019. Furthermore, and consistent with the methods used throughout 24

the GCR Plan, appropriate basis, fuel, transportation charges, and heating value 25

E. P. SCHIFFER

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adjustments were applied. The NYMEX prices below were used to calculate the 1

purchase price for all volumes not already contracted at fixed prices pursuant to the 2

FPP.3

4

Item Jan-19 Feb-19 Mar-19

NYMEX $4.65 $4.16 $2.89

Delivered Vol (MMcf) 9,551 8,573 9,566

Total Cost ($000) $40,434 $35,323 $34,389

5

ANR ALPENA TRANSPORT 6

Q83. How has DTE Gas handled the costs associated with ANR service to Alpena 7

under Contract No. 122065 in the projected transportation costs for the April 8

2019 through March 2020 GCR period? 9

A83. Consistent with the Commission Order in DTE Gas’ General Rate Case No. U-18999, 10

DTE Gas will recover costs associated with the ANR Alpena transport contract 11

through the GCR SOLR Reservation Charge mechanism. 12

13

GAS SUPPLY STRATEGY FOR APRIL 2020 AND BEYOND 14

Q84. How does DTE Gas plan to purchase its required gas supply for April 2020 and 15

beyond? 16

A84. DTE Gas’s proposed natural gas supply acquisition strategy for April 2020 and 17

beyond is essentially the same as that used for the April 2019 - March 2020 period. 18

Specifically, DTE Gas’s supply will be priced utilizing a mixture of fixed-price 19

supply and market-based indexed price supply. 20

Table 5

E. P. SCHIFFER

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Q85. Does DTE Gas plan to execute any fixed price supply contracts during the Plan 1

Period for gas to be delivered in April 2020 and beyond? 2

A85. Yes. Consistent with the Commission approved VCA methodology in the Company’s 3

2010-2011 GCR Plan Case No. U-16146, and contained in every subsequent 4

Commission-approved GCR Plan (Case Nos. U-16482, U-16921, U-17131, U-5

17332, U-17691, U-17941, U-18152) through the Company’s pending 2018-2019 6

GCR Plan Case No. U-18412, as detailed in Exhibit A-7, DTE Gas will continue to 7

make fixed price purchases each month during the April 2019-March 2020 Period for 8

approximately 3% of the total gas supply requirements to be delivered during the 9

April 2020-March 2021 GCR Period. The table on Exhibit A-27 “Fixed Price 10

Program Analysis – Purchase Percentages” summarizes the monthly and cumulative 11

total fixed price purchases to occur by GCR delivery period. 12

13

Q86. Is DTE Gas reviewing any transportation portfolio changes during the Plan 14

Period related to future GCR periods, specifically April 2019 and beyond? 15

A86. DTE Gas’s contract with Panhandle Eastern for 60 MDth/day during the winter will 16

expire on 3/31/2020 and the Company will evaluate this contract as the expiration 17

date approaches. 18

19

Q87. Does DTE Gas plan to change its transport capacity for April 2020 and beyond 20

due to customers switching between GCR and GCC? 21

A87. No. DTE Gas does not plan to change its transport capacity if customers switch 22

between GCR and GCC. DTE Gas intends to maintain a GCR/GCC portfolio of 23

interstate transportation and city-gate supply that is sufficient to serve total GCR and 24

GCC markets. This is necessary from a security of supply standpoint as DTE Gas is 25

the SOLR for all customers, both GCR and GCC. 26

E. P. SCHIFFER

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Q88. What projection of gas purchase and transportation costs have you made for the 1

period April 2020 through March 2024? 2

A88. Projected gas purchase costs for the period April 2020 through March 2024 are 3

calculated on pages 2 through 5 of Exhibit A-10. Projected transportation costs for 4

that same period are calculated on pages 2 through 5 of Exhibit A-11 and the 5

projected total supply costs (the sum of purchase and transport costs) are calculated 6

on Exhibit A-12. 7

8


A89. Yes, it does. 10

11

STATE OF MICHIGAN







)

EXHIBITS

OF

ERIC P. SCHIFFER

Case No.: U-20236 Exhibit No.: A-7

Witness: R.G. Lawshe Page No.: 1 of 2

Case No.: U-16146

Exhibit No. : A-8

DTE Gas Company April 2019-March 2024Fixed Price Purchase Guidelines

Michigan Consolidated Gas Company

April 2010 – March 2015

Proposed Fixed Price Purchase Guidelines Witness: E.W. Clinton

Page No.: 1 of 2

1) Proposed Methodology Description

a) Volume Cost Averaging (VCA) - A timing technique of buying an equal volume of natural gas, on

a regular schedule, at a fixed price.

b) MichCon will commence purchases equal to 75% of the total GCR Period supply requirements

spread equally over a 24 month period (i.e. the VCA Purchase Period) starting on January 1st

which precedes the GCR Period by 27 months.

c) The purchases shall be complete by December 31st directly preceding the GCR Period.

d) Please see below for an example of the timeline associated with the April 1, 2013 through March

31, 2014 GCR Period.

VCA Purchases Start - January 1, 2011

37.5% of Purchases Complete - December 31, 2011

75% of Purchases Complete - December 31, 2012

2) Fixed Purchase Coverage Ratio

a) MichCon will achieve a fixed purchase coverage ratio of 75% of total GCR Period requirements

on December 31st directly preceding the GCR Period.

3) VCA Purchase Limitations

a) The monthly VCA purchase shall not exceed 1/24 of 75% or 3.1% of the total GCR Period

purchase requirements.

b) In the event forecasted GCR Period purchase requirements increase or decrease during the 24

month VCA Purchase Period, MichCon will either increase or decrease the VCA purchase

volume equally over the remaining scheduled purchases so that the 75% fixed purchase

requirement is met by December 31st directly preceding the GCR Period.

4) GCR Period Monthly Receipt Volumes

a) The monthly receipt volumes purchased for the GCR Period may vary due to varying monthly

purchase requirements which is defined as volume shaping described more fully in paragraph 8)

below.

5) GCR Period Purchase Requirements

a) GCR Period purchase requirements utilized to determine VCA purchases may be updated

without limitation, to reflect the best available real time information at the time of purchase.

6) VCA Purchase Timing

a) MichCon may make multiple purchases or one single purchase at any time during the calendar

month at its own discretion, not to exceed the VCA purchase limitations described in paragraph

3).

b) Any purchase made within the calendar month is in compliance with the fixed price guidelines

and cannot be deemed unreasonable and imprudent solely on the basis that the purchase price

was not the lowest price within the calendar month.

7) Purchase Price

a) The purchase price will be representative of physical fixed price supply at the specified receipt

point purchase location, which will be inclusive of any market based premium or discount (i.e.

physical basis) associated with the specific geographic purchase location.

8) Volume Shaping

a) MichCon will attempt to shape purchases consistent with the seasonal profile in place at the time

of purchase.

DTE Gas Company April 2019 - March 2024Fixed Price Purchase Guidelines

Case No.: U-20236 Exhibit No.: A-7

Witness: R.G. Lawshe Page No.: 2 of 2

b) Volume shaping may require MichCon to purchase varying receipt volumes for each month within

the GCR Period in scope.

c) For example, if summer purchase requirements are greater than winter purchase requirements,

MichCon will purchase proportionately more volumes in the summer than in the winter for each of

the VCA purchases.

9) Force Majeure

a) MichCon may suspend the fixed price program for an indefinite period of time in the event of a

Force Majeure.

10) VCA Transition Period (Assuming a January 1, 2011 Commission Order)

a) April 2011 – March 2012 GCR Period

i) MichCon will commence purchasing equal monthly balance of period volumes concurrent

with a Commission Order and will continue each month through October 2011 to achieve a

75% fixed coverage ratio of winter only flowing supply by October 31, 2011. (Refer to

Supplement 1 for illustrative purposes)

ii) Paragraphs 4) through 9) above apply to the April 2011 – March 2012 GCR Period.

b) April 2012 – March 2013 GCR Period

i) MichCon will commence purchasing equal monthly volumes concurrent with a Commission

Order and will continue each month through March 2012 to achieve a 75% fixed coverage

ratio of total GCR Period requirements by March 31, 2012. (Refer to Supplement 1 for

illustrative purposes)

ii) Paragraphs 4) through 9) above apply to the April 2012 – March 2013 GCR Period.

c) In the event a Commission Order or Settlement Agreement is reached earlier than January 1,

2011, MichCon would commence purchases immediately which would extend the duration of the

purchase period in order to achieve the targets described in paragraphs 10) a) i) and 10) b) i).

DTE Gas Company

April 2019 - March 2024 GCR Plan Case

Projected NYMEX, Basis, and Supply Basin Prices

Case No.: U-20236

Exhibit No.: A-8

Witness: E.P. Schiffer

Page No.: 1 of 5

Prices $/Dth(Col. 1) (Col. 2) (Col. 3) (Col. 4) (Col. 5) (Col. 6) (Col. 7) (Col. 8) (Col. 9) (Col. 10) (Col. 11) (Col. 12) (Col. 13)

Month Apr-19 May-19 Jun-19 Jul-19 Aug-19 Sep-19 Oct-19 Nov-19 Dec-19 Jan-20 Feb-20 Mar-20

1 NYMEX Henry Hub Price 2.9590 2.8410 2.8560 2.8794 2.8752 2.8502 2.8714 2.9104 3.0642 3.1818 3.1200 2.8964

Supply Area Basis2 MichCon city-gate (0.1760) (0.1760) (0.1760) (0.1760) (0.1760) (0.1760) (0.1760) (0.1610) (0.1610) (0.1610) (0.1610) (0.1610)3 Emerson (0.3580) (0.3580) (0.3580) (0.3580) (0.3580) (0.3580) (0.3580) 0.0490 0.0490 0.0490 0.0490 0.04904 Chicago city-gate (0.2450) (0.2450) (0.2450) (0.2450) (0.2450) (0.2450) (0.2450) 0.0350 0.0350 0.0350 0.0350 0.03505 Panhandle Field (0.6850) (0.6850) (0.6850) (0.6850) (0.6850) (0.6850) (0.6850) (0.4980) (0.4980) (0.4980) (0.4980) (0.4980)6 ANR SW Field (0.6250) (0.6250) (0.6250) (0.6250) (0.6250) (0.6250) (0.6250) (0.4380) (0.4380) (0.4380) (0.4380) (0.4380)7 Kensington Plant (NEXUS) (0.2620) (0.2620) (0.2620) (0.2620) (0.2620) (0.2620) (0.2620) (0.0940) (0.0940) (0.0940) (0.0940) (0.0940)8 Clarington (TEAL) (0.4770) (0.4770) (0.4770) (0.4770) (0.4770) (0.4770) (0.4770) (0.3390) (0.3390) (0.3390) (0.3390) (0.3390)

Supply Basin Price9 MichCon city-gate 2.7830 2.6650 2.6800 2.7034 2.6992 2.6742 2.6954 2.7494 2.9032 3.0208 2.9590 2.735410 Emerson 2.6010 2.4830 2.4980 2.5214 2.5172 2.4922 2.5134 2.9594 3.1132 3.2308 3.1690 2.945411 Chicago city-gate 2.7140 2.5960 2.6110 2.6344 2.6302 2.6052 2.6264 2.9454 3.0992 3.2168 3.1550 2.931412 Panhandle Field 2.2740 2.1560 2.1710 2.1944 2.1902 2.1652 2.1864 2.4124 2.5662 2.6838 2.6220 2.398413 ANR SW Field 2.3340 2.2160 2.2310 2.2544 2.2502 2.2252 2.2464 2.4724 2.6262 2.7438 2.6820 2.458414 Kensington Plant (NEXUS) 2.6970 2.5790 2.5940 2.6174 2.6132 2.5882 2.6094 2.8164 2.9702 3.0878 3.0260 2.802415 Clarington (TEAL) 2.4820 2.3640 2.3790 2.4024 2.3982 2.3732 2.3944 2.5714 2.7252 2.8428 2.7810 2.5574

DTE Gas Company



Case No.: U-20236

Exhibit No.: A-8


Page No.: 2 of 5

Prices $/Dth(Col. 1)

Month

1 NYMEX Henry Hub Price

Supply Area Basis2 MichCon city-gate3 Emerson4 Chicago city-gate5 Panhandle Field6 ANR SW Field7 Kensington Plant (NEXUS)8 Clarington (TEAL)

Supply Basin Price9 MichCon city-gate10 Emerson11 Chicago city-gate12 Panhandle Field13 ANR SW Field14 Kensington Plant (NEXUS)15 Clarington (TEAL)

(Col. 2) (Col. 3) (Col. 4) (Col. 5) (Col. 6) (Col. 7) (Col. 8) (Col. 9) (Col. 10) (Col. 11) (Col. 12) (Col. 13)

Apr-20 May-20 Jun-20 Jul-20 Aug-20 Sep-20 Oct-20 Nov-20 Dec-20 Jan-21 Feb-21 Mar-21

2.5110 2.4636 2.5084 2.5616 2.5628 2.5372 2.5490 2.6128 2.7942 2.9196 2.8618 2.7246

(0.1918) (0.1918) (0.1918) (0.1918) (0.1918) (0.1918) (0.1918) (0.1610) (0.1610) (0.1610) (0.1610) (0.1610)0.0030 0.0030 0.0030 0.0030 0.0030 0.0030 0.0030 0.3870 0.3870 0.3870 0.3870 0.3870

(0.2570) (0.2520) (0.2520) (0.2520) (0.2520) (0.2520) (0.2520) 0.0400 0.0350 0.0350 0.0350 0.0350(0.5330) (0.5330) (0.5330) (0.5330) (0.5330) (0.5330) (0.5330) (0.3850) (0.3850) (0.3850) (0.3850) (0.3850)(0.4680) (0.4680) (0.4680) (0.4680) (0.4680) (0.4680) (0.4680) (0.3970) (0.3970) (0.3970) (0.3970) (0.3970)(0.3680) (0.3680) (0.3680) (0.3680) (0.3680) (0.3680) (0.3680) (0.1190) (0.1190) (0.1190) (0.1190) (0.1190)(0.5830) (0.5830) (0.5830) (0.5830) (0.5830) (0.5830) (0.5830) (0.3640) (0.3640) (0.3640) (0.3640) (0.3640)

2.3192 2.2718 2.3166 2.3698 2.3710 2.3454 2.3572 2.4518 2.6332 2.7586 2.7008 2.56362.5140 2.4666 2.5114 2.5646 2.5658 2.5402 2.5520 2.9998 3.1812 3.3066 3.2488 3.11162.2540 2.2116 2.2564 2.3096 2.3108 2.2852 2.2970 2.6528 2.8292 2.9546 2.8968 2.75961.9780 1.9306 1.9754 2.0286 2.0298 2.0042 2.0160 2.2278 2.4092 2.5346 2.4768 2.33962.0430 1.9956 2.0404 2.0936 2.0948 2.0692 2.0810 2.2158 2.3972 2.5226 2.4648 2.32762.1430 2.0956 2.1404 2.1936 2.1948 2.1692 2.1810 2.4938 2.6752 2.8006 2.7428 2.60561.9280 1.8806 1.9254 1.9786 1.9798 1.9542 1.9660 2.2488 2.4302 2.5556 2.4978 2.3606

DTE Gas Company



Case No.: U-20236

Exhibit No.: A-8


Page No.: 3 of 5


Month






2.4914 2.4636 2.4966 2.5318 2.5488 2.5428 2.5668 2.6328 2.8074 2.9272 2.8756 2.7790

(0.1918) (0.1918) (0.1918) (0.1918) (0.1918) (0.1918) (0.1918) (0.1610) (0.1610) (0.1610) (0.1610) (0.1610)(0.4590) (0.4790) (0.4790) (0.4790) (0.4790) (0.4790) (0.4790) (0.1860) (0.1860) (0.1860) (0.1860) (0.1860)(0.2570) (0.2570) (0.2520) (0.2520) (0.2520) (0.2520) (0.2520) 0.0400 0.0400 0.0350 0.0350 0.0350(0.5222) (0.5222) (0.5222) (0.5222) (0.5222) (0.5222) (0.5222) (0.3850) (0.3850) (0.3850) (0.3850) (0.3850)(0.4680) (0.4680) (0.4680) (0.4680) (0.4680) (0.4680) (0.4680) (0.3970) (0.3970) (0.3970) (0.3970) (0.3970)(0.4440) (0.4440) (0.4440) (0.4440) (0.4440) (0.4440) (0.4440) (0.1190) (0.1190) (0.1190) (0.1190) (0.1190)(0.6590) (0.6590) (0.6590) (0.6590) (0.6590) (0.6590) (0.6590) (0.3640) (0.3640) (0.3640) (0.3640) (0.3640)

2.2996 2.2718 2.3048 2.3400 2.3570 2.3510 2.3750 2.4718 2.6464 2.7662 2.7146 2.61802.0324 1.9846 2.0176 2.0528 2.0698 2.0638 2.0878 2.4468 2.6214 2.7412 2.6896 2.59302.2344 2.2066 2.2446 2.2798 2.2968 2.2908 2.3148 2.6728 2.8474 2.9622 2.9106 2.81401.9692 1.9414 1.9744 2.0096 2.0266 2.0206 2.0446 2.2478 2.4224 2.5422 2.4906 2.39402.0234 1.9956 2.0286 2.0638 2.0808 2.0748 2.0988 2.2358 2.4104 2.5302 2.4786 2.38202.0474 2.0196 2.0526 2.0878 2.1048 2.0988 2.1228 2.5138 2.6884 2.8082 2.7566 2.66001.8324 1.8046 1.8376 1.8728 1.8898 1.8838 1.9078 2.2688 2.4434 2.5632 2.5116 2.4150

DTE Gas Company



Case No.: U-20236

Exhibit No.: A-8


Page No.: 4 of 5


Month






2.5530 2.5240 2.5520 2.5830 2.5940 2.5840 2.6034 2.6684 2.8144 2.9214 2.8762 2.7902

(0.1918) (0.1918) (0.1918) (0.1918) (0.1918) (0.1918) (0.1918) (0.1610) (0.1610) (0.1610) (0.1610) (0.1610)(0.4840) (0.4840) (0.4840) (0.4840) (0.4840) (0.4840) (0.4840) (0.1060) (0.1060) (0.1060) (0.1060) (0.1060)(0.2570) (0.2570) (0.2570) (0.2520) (0.2520) (0.2520) (0.2520) 0.0400 0.0400 0.0400 0.0350 0.0350(0.5222) (0.5222) (0.5222) (0.5222) (0.5222) (0.5222) (0.5222) (0.3850) (0.3850) (0.3850) (0.3850) (0.3850)(0.4680) (0.4680) (0.4680) (0.4680) (0.4680) (0.4680) (0.4680) (0.3970) (0.3970) (0.3970) (0.3970) (0.3970)(0.4440) (0.4440) (0.4440) (0.4440) (0.4440) (0.4440) (0.4440) (0.1190) (0.1190) (0.1190) (0.1190) (0.1190)(0.6590) (0.6590) (0.6590) (0.6590) (0.6590) (0.6590) (0.6590) (0.3640) (0.3640) (0.3640) (0.3640) (0.3640)

2.3612 2.3322 2.3602 2.3912 2.4022 2.3922 2.4116 2.5074 2.6534 2.7604 2.7152 2.62922.0690 2.0400 2.0680 2.0990 2.1100 2.1000 2.1194 2.5624 2.7084 2.8154 2.7702 2.68422.2960 2.2670 2.2950 2.3310 2.3420 2.3320 2.3514 2.7084 2.8544 2.9614 2.9112 2.82522.0308 2.0018 2.0298 2.0608 2.0718 2.0618 2.0812 2.2834 2.4294 2.5364 2.4912 2.40522.0850 2.0560 2.0840 2.1150 2.1260 2.1160 2.1354 2.2714 2.4174 2.5244 2.4792 2.39322.1090 2.0800 2.1080 2.1390 2.1500 2.1400 2.1594 2.5494 2.6954 2.8024 2.7572 2.67121.8940 1.8650 1.8930 1.9240 1.9350 1.9250 1.9444 2.3044 2.4504 2.5574 2.5122 2.4262

DTE Gas Company



Case No.: U-20236

Exhibit No.: A-8


Page No.: 5 of 5


Month






2.5852 2.5752 2.6122 2.6502 2.6702 2.6762 2.7062 2.7702 2.9172 3.0222 2.9802 2.9072

(0.1918) (0.1918) (0.1918) (0.1918) (0.1918) (0.1918) (0.1918) (0.1610) (0.1610) (0.1610) (0.1610) (0.1610)(0.2610) (0.2610) (0.2610) (0.2610) (0.2610) (0.2610) (0.2610) (0.0610) (0.0610) (0.0610) (0.0610) (0.0610)(0.2570) (0.2570) (0.2570) (0.2570) (0.2520) (0.2520) (0.2520) 0.0400 0.0400 0.0400 0.0400 0.0350(0.5222) (0.5222) (0.5222) (0.5222) (0.5222) (0.5222) (0.5222) (0.3850) (0.3850) (0.3850) (0.3850) (0.3850)(0.4680) (0.4680) (0.4680) (0.4680) (0.4680) (0.4680) (0.4680) (0.3970) (0.3970) (0.3970) (0.3970) (0.3970)(0.4440) (0.4440) (0.4440) (0.4440) (0.4440) (0.4440) (0.4440) (0.1190) (0.1190) (0.1190) (0.1190) (0.1190)(0.6590) (0.6590) (0.6590) (0.6590) (0.6590) (0.6590) (0.6590) (0.3640) (0.3640) (0.3640) (0.3640) (0.3640)

2.3934 2.3834 2.4204 2.4584 2.4784 2.4844 2.5144 2.6092 2.7562 2.8612 2.8192 2.74622.3242 2.3142 2.3512 2.3892 2.4092 2.4152 2.4452 2.7092 2.8562 2.9612 2.9192 2.84622.3282 2.3182 2.3552 2.3932 2.4182 2.4242 2.4542 2.8102 2.9572 3.0622 3.0202 2.94222.0630 2.0530 2.0900 2.1280 2.1480 2.1540 2.1840 2.3852 2.5322 2.6372 2.5952 2.52222.1172 2.1072 2.1442 2.1822 2.2022 2.2082 2.2382 2.3732 2.5202 2.6252 2.5832 2.51022.1412 2.1312 2.1682 2.2062 2.2262 2.2322 2.2622 2.6512 2.7982 2.9032 2.8612 2.78821.9262 1.9162 1.9532 1.9912 2.0112 2.0172 2.0472 2.4062 2.5532 2.6582 2.6162 2.5432

DTE Gas Company


Summary of Interstate Transportation Contracts

Case No.: U-20236

Exhibit No.: A-9


Page No.: 1 of 1

(Col. 1) (Col. 2) (Col. 3) (Col. 4) (Col. 5) (Col. 6) (Col. 7) (Col. 8) (Col. 9)

Number Transporter Service Receipt Point Delivery Point (Dth/Day) (Dth/Day) Date Date

Row Contract MDQ Winter MDQ Summer Start Term

1 109511 ANR Pipeline FTS-1 SW Headstation Sparta-Muskegon 25,000 25,000 11/01/03 10/31/22

2 108268 ANR Pipeline ETS SW Headstation Group 1 10,000 10,000 11/01/03 10/31/22

3 108304 ANR Pipeline ETS SW Headstation Group 2 15,000 15,000 11/01/03 10/31/22

4 122247 ANR Pipeline FTS-1 SW Headstation Willow Run 15,000 15,000 11/01/13 03/31/22

5 122067 ANR Pipeline FTS-1 SW Headstation Menominee/Willow Run 14,000 14,000 11/01/13 03/31/20

6 122065 ANR Pipeline FTS-1 Alliance Alpena 50,000 50,000 01/01/14 04/30/28

7 FT-MCG-5676 Vector Pipeline U.S. FT Alliance Milford Junction 20,000 10,000 11/01/17 10/31/20

8 122248 ANR Pipeline FTS-1 Marshfield Menominee 21,000 21,000 11/01/13 03/31/22

9 FT-A (AF0081) Viking Gas Transmission FT Emerson Marshfield 21,076 21,076 11/01/13 03/31/22

10 00002 NEXUS Gas Transmission1

FT Kensington/Clarington Willow Run 75,000 75,000 09/01/18 03/31/32

11 ASAT 62078 AEP Gas Transportation Agreement IT Gaylord Alpena 50,000 50,000 11/01/17 10/31/27

12 FT4634 Great Lakes Gas Transmission FT Emerson / Belle River Various 10,130 10,130 04/01/05 Evergreen

13 FT4635 Great Lakes Gas Transmission FT Emerson / Belle River Various 20,260 20,260 04/01/05 Evergreen

14 017908 Panhandle Eastern Pipe Line EFT Field Zone MCON/Southern 25,000 25,000 11/01/03 10/31/28

15 018474 Panhandle Eastern Pipe Line FT Field Zone MCON/Southern 40,000 40,000 04/01/02 03/31/29

16 45114 Panhandle Eastern Pipe Line FT Field Zone MCON 60,000 - 11/01/17 03/31/20

Operational Capacity (Costs Included in Distribution Rates)

17 111493 ANR Pipeline (Trufant I) ETS Detroit A&B Group 3 400,000 400,000 07/01/05 06/01/51

18 112110 ANR Pipeline (Trufant II) ETS Detroit A&B Group 3 200,000 200,000 11/01/17 06/01/51

Footnotes:

1

NEXUS transport has an alterante receipt point at Clarington for 37,500 Dth/d from 11/1/2018 through 10/31/2022

DTE Gas CompanyApril 2019 - March 2024Projected Purchase Volumes and Cost (Excluding Transportation Costs)

Case No.: U-20236Exhibit No.: A-10

Witness: E. P. Schiffer

Page No.: 1 of 5

(Col. 1)

Purchase Volume (Dth)

1 Contracted Fixed Price2 Not Under Contract

3 Contracted Indexed Price

4 Total Receipt (Dth)

5 Less Fuel

6 Total Delivered (Dth)7 Heating Value Adjustment

8 Total Delivered (Mcf)

Purchase Cost ($)



12 Total

(Col. 2) (Col. 3) (Col. 4) (Col. 5) (Col. 6) (Col. 7) (Col. 8) (Col. 9) (Col. 10) (Col. 11) (Col. 12) (Col. 13) (Col. 14)

Apr-19 May-19 Jun-19 Jul-19 Aug-19 Sep-19 Oct-19 Nov-19 Dec-19 Jan-20 Feb-20 Mar-20 Apr19-Mar20

9,696,000 10,019,200 9,696,000 10,019,200 10,019,200 9,696,000 6,720,800 7,470,000 7,719,000 7,719,000 7,221,000 7,719,000 103,714,4003,144,747 3,248,827 3,141,667 3,248,827 3,248,827 3,141,667 2,082,925 2,422,819 2,512,519 2,512,519 2,263,652 2,512,519 33,481,518

50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 600,000

12,890,747 13,318,027 12,887,667 13,318,027 13,318,027 12,887,667 8,853,725 9,942,819 10,281,519 10,281,519 9,534,652 10,281,519 137,795,918

244,448 252,597 244,448 252,597 252,597 244,448 233,273 293,629 303,417 303,417 283,842 303,417 3,212,130

12,646,299 13,065,431 12,643,219 13,065,431 13,065,431 12,643,219 8,620,452 9,649,190 9,978,102 9,978,102 9,250,810 9,978,102 134,583,7891.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510

12,032,635 12,431,428 12,029,704 12,431,428 12,431,428 12,029,704 8,202,143 9,180,961 9,493,913 9,493,913 8,801,913 9,493,913 128,053,081

22,029,668 22,763,990$ 22,029,668$ 22,763,990$ 22,763,990$ 22,029,668$ 15,078,191$ 19,437,360$ 20,085,272$ 20,085,272$ 18,789,448$ 20,085,272$ 247,941,787$8,491,115 8,388,717 8,158,950 8,513,472 8,499,827 8,140,729 5,091,970 6,298,024 6,918,961 7,214,433 6,346,980 6,497,360 88,560,539

139,150 133,250 134,000 135,170 134,960 133,710 134,770 137,470 145,160 151,040 147,950 136,770 1,663,400

30,659,933 31,285,957$ 30,322,618$ 31,412,632$ 31,398,777$ 30,304,106$ 20,304,931$ 25,872,854$ 27,149,393$ 27,450,745$ 25,284,378$ 26,719,402$ 338,165,725$




Page No.: 2 of 5

(Col. 1)





5 Less Fuel



Purchase Cost ($)



12 Total



4,605,000 4,758,500 4,605,000 4,758,500 4,758,500 4,605,000 4,758,500 3,522,000 3,639,400 3,639,400 3,287,200 3,639,400 50,576,4008,177,289 8,451,545 8,177,289 8,451,545 8,451,545 8,177,289 3,989,793 6,196,876 6,449,626 6,449,714 5,691,181 6,449,714 85,113,404

50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 600,000

12,832,289 13,260,045 12,832,289 13,260,045 13,260,045 12,832,289 8,798,293 9,768,876 10,139,026 10,139,114 9,028,381 10,139,114 136,289,804

241,607 249,673 241,607 249,673 249,673 241,607 239,629 292,537 302,289 302,289 273,035 302,289 3,185,908

12,590,682 13,010,371 12,590,682 13,010,371 13,010,371 12,590,682 8,558,664 9,476,339 9,836,737 9,836,825 8,755,346 9,836,825 133,103,8971.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510

11,979,717 12,379,040 11,979,717 12,379,040 12,379,040 11,979,717 8,143,353 9,016,498 9,359,407 9,359,491 8,330,491 9,359,491 126,645,002

9,312,375$ 9,622,788$ 9,312,375$ 9,622,788$ 9,622,788$ 9,312,375$ 9,622,788$ 9,062,498$ 9,364,581$ 9,364,581$ 8,458,331$ 9,364,581$ 112,042,846$18,060,963 18,275,986 18,048,771 19,104,237 19,114,379 18,284,277 8,520,469 14,080,658 15,833,216 16,642,243 14,332,088 15,384,548 195,681,836

115,960 113,590 115,830 118,490 118,550 117,270 117,860 122,590 131,660 137,930 135,040 128,180 1,472,950

27,489,298$ 28,012,363$ 27,476,976$ 28,845,515$ 28,855,716$ 27,713,922$ 18,261,116$ 23,265,746$ 25,329,457$ 26,144,753$ 22,925,459$ 24,877,309$ 309,197,632$




Page No.: 3 of 5

(Col. 1)





5 Less Fuel



Purchase Cost ($)



12 Total



- - - - - - - - - - - - -12,809,692 13,238,348 12,809,692 13,238,348 13,238,348 12,809,692 8,802,088 9,729,227 10,099,471 10,099,471 8,987,687 10,099,471 135,961,534

50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 600,000

12,859,692 13,288,348 12,859,692 13,288,348 13,288,348 12,859,692 8,852,088 9,779,227 10,149,471 10,149,471 9,037,687 10,149,471 136,561,534

244,448 252,597 244,448 252,597 252,597 244,448 239,790 292,537 302,289 302,289 273,035 302,289 3,203,363

12,615,243 13,035,751 12,615,243 13,035,751 13,035,751 12,615,243 8,612,297 9,486,689 9,847,182 9,847,182 8,764,652 9,847,182 133,358,1711.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510

12,003,086 12,403,189 12,003,086 12,403,189 12,403,189 12,003,086 8,194,384 9,026,346 9,369,346 9,369,346 8,339,346 9,369,346 126,886,937

-$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$26,746,843 27,242,063 26,791,411 28,154,290 28,379,342 27,383,219 18,183,408 22,318,996 24,939,876 26,149,793 22,783,583 24,653,051 303,725,874

114,980 113,590 115,240 117,000 117,850 117,550 118,750 123,590 132,320 138,310 135,730 130,900 1,475,810

26,861,823$ 27,355,653$ 26,906,651$ 28,271,290$ 28,497,192$ 27,500,769$ 18,302,158$ 22,442,586$ 25,072,196$ 26,288,103$ 22,919,313$ 24,783,951$ 305,201,684$




Page No.: 4 of 5

(Col. 1)





5 Less Fuel



Purchase Cost ($)



12 Total



- - - - - - - - - - - - -12,822,735 13,251,826 12,822,735 13,251,826 13,251,826 12,822,735 8,827,134 9,687,054 10,057,298 10,057,298 8,945,514 10,057,298 135,855,281

50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 600,000

12,872,735 13,301,826 12,872,735 13,301,826 13,301,826 12,872,735 8,877,134 9,737,054 10,107,298 10,107,298 8,995,514 10,107,298 136,455,281

244,448 252,597 244,448 252,597 252,597 244,448 239,993 292,537 302,289 302,289 273,035 302,289 3,203,565

12,628,287 13,049,230 12,628,287 13,049,230 13,049,230 12,628,287 8,637,141 9,444,517 9,805,010 9,805,010 8,722,480 9,805,010 133,251,7161.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510

12,015,497 12,416,013 12,015,497 12,416,013 12,416,013 12,015,497 8,218,022 8,986,219 9,329,219 9,329,219 8,299,219 9,329,219 126,785,648

-$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$27,527,830 28,065,056 27,515,007 28,856,285 29,002,056 27,934,403 18,556,422 22,684,056 25,027,263 26,103,394 22,790,615 24,783,876 308,846,263

118,060 116,610 118,010 119,560 120,110 119,610 120,580 125,370 132,670 138,020 135,760 131,460 1,495,820

27,645,890$ 28,181,666$ 27,633,017$ 28,975,845$ 29,122,166$ 28,054,013$ 18,677,002$ 22,809,426$ 25,159,933$ 26,241,414$ 22,926,375$ 24,915,336$ 310,342,083$




Page No.: 5 of 5

(Col. 1)





5 Less Fuel



Purchase Cost ($)



12 Total



- - - - - - - - - - - - -12,825,441 13,254,622 12,825,441 13,254,622 13,254,622 12,825,441 8,853,907 9,716,445 10,087,740 10,087,740 9,345,150 10,087,740 136,418,911

50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 600,000

12,875,441 13,304,622 12,875,441 13,304,622 13,304,622 12,875,441 8,903,907 9,766,445 10,137,740 10,137,740 9,395,150 10,137,740 137,018,911

244,448 252,597 244,448 252,597 252,597 244,448 240,178 292,537 302,289 302,289 282,786 302,289 3,213,502

12,630,993 13,052,026 12,630,993 13,052,026 13,052,026 12,630,993 8,663,728 9,473,907 9,835,451 9,835,451 9,112,363 9,835,451 133,805,4091.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510 1.0510

12,018,071 12,418,673 12,018,071 12,418,673 12,418,673 12,018,071 8,243,319 9,014,184 9,358,184 9,358,184 8,670,184 9,358,184 127,312,472

-$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$28,294,085 29,108,664 28,640,371 30,102,760 30,377,224 29,470,269 19,893,570 23,816,884 26,217,390 27,276,602 24,861,757 26,116,512 324,176,087

119,670 119,170 121,020 122,920 123,920 124,220 125,720 130,460 137,810 143,060 140,960 137,310 1,546,240

28,413,755$ 29,227,834$ 28,761,391$ 30,225,680$ 30,501,144$ 29,594,489$ 20,019,290$ 23,947,344$ 26,355,200$ 27,419,662$ 25,002,717$ 26,253,822$ 325,722,327$

DTE Gas Company

April 2019 - March 2024

Projected Transportation Utilization, Reservation Costs, and Usage Costs

Case No.: U-20236

Exhibit No.: A-11


Page No.: 1 of 5

(Col. 1) (Col. 2) (Col. 3) (Col. 4) (Col. 5) (Col. 6) (Col. 7) (Col. 8) (Col. 9) (Col. 10) (Col. 11) (Col. 12) (Col. 13) (Col. 14)


Transport Capacity (Dth/Day)

1 Great Lakes 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390

2 Viking/ANR Northern 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000

3 Vector 10,000 10,000 10,000 10,000 10,000 10,000 10,000 20,000 20,000 20,000 20,000 20,000

4 Panhandle Field Zone 65,000 65,000 65,000 65,000 65,000 65,000 65,000 125,000 125,000 125,000 125,000 125,000

5 NEXUS - Kensington 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500

6 NEXUS - Clarington 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500

7 ANR Northern 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000

8 ANR SW 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000

9 Total Delivered Volume 330,390 330,390 330,390 330,390 330,390 330,390 330,390 400,390 400,390 400,390 400,390 400,390

Source of Supply /

Transport Utilization (Dth/Day)

10 MichCon city-gate 91,153 91,076 91,051 91,076 91,076 91,051 4,613 21,786 22,021 22,021 19,140 22,021

11 Great Lakes 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390

12 Viking/ANR Northern 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000

13 Vector 10,000 10,000 10,000 10,000 10,000 10,000 10,000 6,964 6,964 6,964 6,964 6,964

14 Panhandle Field Zone 65,000 65,000 65,000 65,000 65,000 65,000 65,000 125,000 125,000 125,000 125,000 125,000

15 NEXUS - Kensington 37,500 37,500 37,500 37,500 37,500 37,500 7,084 - - - - -

16 NEXUS - Clarington 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500

17 ANR Northern 50,000 50,000 50,000 50,000 50,000 50,000 23,493 - - - - -

18 ANR SW 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000

19 Total Delivered Volume 421,543 421,466 421,441 421,466 421,466 421,441 278,079 321,640 321,874 321,874 318,993 321,874

Reservation Cost ($)

20 Great Lakes 217,740$ 217,740$ 217,740$ 217,740$ 217,740$ 217,740$ 217,740$ 217,740$ 217,740$ 217,734$ 217,734$ 217,734$ 2,612,864$

21 Viking/ANR Northern 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 2,858,563

22 Vector 42,583 42,583 42,583 42,583 42,583 42,583 42,583 85,166 85,166 85,166 85,166 85,166 723,911

23 Panhandle Field Zone 852,950 852,950 852,950 852,950 852,950 852,950 852,950 1,627,250 1,627,250 1,627,250 1,627,250 1,627,250 14,106,900

24 NEXUS - Kensington 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 9,512,820

25 NEXUS - Clarington 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 11,565,945

26 ANR Northern 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 3,437,400

27 ANR SW 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 10,558,812

28 Total Reservation Cost ($) 4,274,402$ 4,274,402$ 4,274,402$ 4,274,402$ 4,274,402$ 4,274,402$ 4,274,402$ 5,091,285$ 5,091,285$ 5,091,278$ 5,091,278$ 5,091,278$ 55,377,215$

Usage Cost ($)

29 Great Lakes 9,883$ 10,212$ 9,883$ 10,212$ 10,212$ 9,883$ 10,212$ 10,108$ 10,887$ 14,710$ 15,653$ 12,124$ 133,979$

30 Viking/ANR Northern 15,375 15,888 15,375 15,888 15,888 15,375 15,888 15,375 15,888 16,148 15,106 16,148 188,344

31 Vector 390 403 390 403 403 390 403 272 281 281 263 281 4,158

32 Panhandle Field Zone 85,020 87,854 85,020 87,854 87,854 85,020 87,854 163,500 168,950 168,950 158,050 168,950 1,434,876

33 NEXUS - Kensington - - - - - - - - - - - - -

34 NEXUS - Clarington - - - - - - - - - - - - -

35 ANR Northern 17,100 17,670 17,100 17,670 17,670 17,100 8,302 - - - - - 112,612

36 ANR SW 54,273 56,082 54,273 56,082 56,082 54,273 56,082 54,273 56,082 56,082 52,464 56,082 662,131

37 Total Usage Cost ($) 182,041$ 188,109$ 182,041$ 188,109$ 188,109$ 182,041$ 178,741$ 243,528$ 252,087$ 256,171$ 241,536$ 253,585$ 2,536,100$

38 Total Transport Cost ($) 4,456,443$ 4,462,511$ 4,456,443$ 4,462,511$ 4,462,511$ 4,456,443$ 4,453,143$ 5,334,812$ 5,343,372$ 5,347,449$ 5,332,815$ 5,344,864$ 57,913,315$

DTE Gas Company



Case No.: U-20236

Exhibit No.: A-11


Page No.: 2 of 5

(Col. 1)


1 Great Lakes

2 Viking/ANR Northern

3 Vector

4 Panhandle Field Zone

5 NEXUS - Kensington

6 NEXUS - Clarington

7 ANR Northern

8 ANR SW

9 Total Delivered Volume

Source of Supply /


10 MichCon city-gate

11 Great Lakes


13 Vector




17 ANR Northern

18 ANR SW



20 Great Lakes


22 Vector




26 ANR Northern

27 ANR SW

28 Total Reservation Cost ($)

Usage Cost ($)

29 Great Lakes


31 Vector




35 ANR Northern

36 ANR SW

37 Total Usage Cost ($)

38 Total Transport Cost ($)



30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390

21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000

10,000 10,000 10,000 10,000 10,000 10,000 10,000 20,000 20,000 20,000 20,000 20,000

65,000 65,000 65,000 65,000 65,000 65,000 65,000 125,000 125,000 125,000 125,000 125,000

37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500

37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500

50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000

79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000

330,390 330,390 330,390 330,390 330,390 330,390 330,390 400,390 400,390 400,390 400,390 400,390

101,667 101,613 101,667 101,613 101,613 101,667 1,613 22,988 24,424 24,427 19,801 24,427

18,023 18,076 18,023 18,076 18,076 18,023 12,802 30,390 30,390 30,390 30,390 30,390

21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000

10,000 10,000 10,000 10,000 10,000 10,000 - - - - - -

65,000 65,000 65,000 65,000 65,000 65,000 65,000 125,000 125,000 125,000 125,000 125,000

37,500 37,500 37,500 37,500 37,500 37,500 37,500 - - - - -

37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500

50,000 50,000 50,000 50,000 50,000 50,000 21,671 - - - - -

79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000

419,689 419,689 419,689 419,689 419,689 419,689 276,086 315,878 317,314 317,317 312,691 317,317

217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 2,612,809$

238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 2,858,563

42,583 42,583 42,583 42,583 42,583 42,583 42,583 85,166 85,166 85,166 85,166 85,166 723,911

852,950 852,950 852,950 852,950 852,950 852,950 852,950 1,627,250 1,627,250 1,627,250 1,627,250 1,627,250 14,106,900

792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 9,512,820

963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 11,565,945

286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 3,437,400

879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 10,558,812

4,274,395$ 4,274,395$ 4,274,395$ 4,274,395$ 4,274,395$ 4,274,395$ 4,274,395$ 5,091,278$ 5,091,278$ 5,091,278$ 5,091,278$ 5,091,278$ 55,377,160$

5,862$ 6,075$ 5,862$ 6,075$ 6,075$ 5,862$ 4,302$ 10,101$ 10,888$ 14,710$ 15,114$ 12,124$ 103,049$

15,627 16,148 15,627 16,148 16,148 15,627 16,148 15,627 16,148 16,148 14,586 16,148 190,133

390 403 390 403 403 390 - - - - - - 2,379

85,020 87,854 85,020 87,854 87,854 85,020 87,854 163,500 168,950 168,950 152,600 168,950 1,429,426

- - - - - - 1,511 - - - - - 1,511

- - - - - - 3,023 2,925 3,023 3,023 2,730 3,023 17,745

17,100 17,670 17,100 17,670 17,670 17,100 7,659 - - - - - 111,969

54,273 56,082 54,273 56,082 56,082 54,273 56,082 54,273 56,082 56,082 50,655 56,082 660,322

178,272$ 184,232$ 178,272$ 184,232$ 184,232$ 178,272$ 176,579$ 246,427$ 255,091$ 258,912$ 235,684$ 256,327$ 2,516,533$

4,452,667$ 4,458,628$ 4,452,667$ 4,458,628$ 4,458,628$ 4,452,667$ 4,450,975$ 5,337,705$ 5,346,369$ 5,350,191$ 5,326,962$ 5,347,606$ 57,893,693$

DTE Gas Company



Case No.: U-20236

Exhibit No.: A-11


Page No.: 3 of 5

(Col. 1)


1 Great Lakes


3 Vector




7 ANR Northern

8 ANR SW


Source of Supply /



11 Great Lakes


13 Vector




17 ANR Northern

18 ANR SW



20 Great Lakes


22 Vector




26 ANR Northern

27 ANR SW


Usage Cost ($)

29 Great Lakes


31 Vector




35 ANR Northern

36 ANR SW





30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390

21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000

10,000 10,000 10,000 10,000 10,000 10,000 10,000 20,000 20,000 20,000 20,000 20,000

65,000 65,000 65,000 65,000 65,000 65,000 65,000 125,000 125,000 125,000 125,000 125,000

37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500

37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500

50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000

79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000

330,390 330,390 330,390 330,390 330,390 330,390 330,390 400,390 400,390 400,390 400,390 400,390

90,118 90,118 90,118 90,118 90,118 90,118 1,613 23,333 24,761 24,761 20,133 24,761

30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390

21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000

10,000 10,000 10,000 10,000 10,000 10,000 - - - - - -

65,000 65,000 65,000 65,000 65,000 65,000 65,000 125,000 125,000 125,000 125,000 125,000

37,500 37,500 37,500 37,500 37,500 37,500 37,500 - - - - -

37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500

50,000 50,000 50,000 50,000 50,000 50,000 5,813 - - - - -

79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000

420,508 420,508 420,508 420,508 420,508 420,508 277,816 316,223 317,651 317,651 313,023 317,651

217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 2,612,809$

238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 2,858,563

42,583 42,583 42,583 42,583 42,583 42,583 42,583 85,166 85,166 85,166 85,166 85,166 723,911

852,950 852,950 852,950 852,950 852,950 852,950 852,950 1,627,250 1,627,250 1,627,250 1,627,250 1,627,250 14,106,900

792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 9,512,820

963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 11,565,945

286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 3,437,400

879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 10,558,812

4,274,395$ 4,274,395$ 4,274,395$ 4,274,395$ 4,274,395$ 4,274,395$ 4,274,395$ 5,091,278$ 5,091,278$ 5,091,278$ 5,091,278$ 5,091,278$ 55,377,160$

9,884$ 10,213$ 9,884$ 10,213$ 10,213$ 9,884$ 10,213$ 10,101$ 10,888$ 14,710$ 15,114$ 12,124$ 133,441$

15,627 16,148 15,627 16,148 16,148 15,627 16,148 15,627 16,148 16,148 14,586 16,148 190,133

390 403 390 403 403 390 - - - - - - 2,379

85,020 87,854 85,020 87,854 87,854 85,020 87,854 163,500 168,950 168,950 152,600 168,950 1,429,426

1,463 1,511 1,463 1,511 1,511 1,463 1,511 - - - - - 10,433

2,925 3,023 2,925 3,023 3,023 2,925 3,023 2,925 3,023 - - - 26,813

17,100 17,670 17,100 17,670 17,670 17,100 2,054 - - - - - 106,364

54,273 56,082 54,273 56,082 56,082 54,273 56,082 54,273 56,082 56,082 50,655 56,082 660,322

186,682$ 192,904$ 186,682$ 192,904$ 192,904$ 186,682$ 176,886$ 246,427$ 255,091$ 255,890$ 232,954$ 253,305$ 2,559,310$

4,461,077$ 4,467,300$ 4,461,077$ 4,467,300$ 4,467,300$ 4,461,077$ 4,451,281$ 5,337,705$ 5,346,369$ 5,347,168$ 5,324,232$ 5,344,583$ 57,936,470$

DTE Gas Company



Case No.: U-20236

Exhibit No.: A-11


Page No.: 4 of 5

(Col. 1)


1 Great Lakes


3 Vector




7 ANR Northern

8 ANR SW


Source of Supply /



11 Great Lakes


13 Vector




17 ANR Northern

18 ANR SW



20 Great Lakes


22 Vector




26 ANR Northern

27 ANR SW


Usage Cost ($)

29 Great Lakes


31 Vector




35 ANR Northern

36 ANR SW





30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390

21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000

10,000 10,000 10,000 10,000 10,000 10,000 10,000 20,000 20,000 20,000 20,000 20,000

65,000 65,000 65,000 65,000 65,000 65,000 65,000 125,000 125,000 125,000 125,000 125,000

37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500

37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500

50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000

79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000

330,390 330,390 330,390 330,390 330,390 330,390 330,390 400,390 400,390 400,390 400,390 400,390

90,553 90,553 90,553 90,553 90,553 90,553 1,613 21,927 23,401 23,401 18,627 23,401

30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390

21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000

10,000 10,000 10,000 10,000 10,000 10,000 - - - - - -

65,000 65,000 65,000 65,000 65,000 65,000 65,000 125,000 125,000 125,000 125,000 125,000

37,500 37,500 37,500 37,500 37,500 37,500 37,500 - - - - -

37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500

50,000 50,000 50,000 50,000 50,000 50,000 6,615 - - - - -

79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000

420,943 420,943 420,943 420,943 420,943 420,943 278,617 314,817 316,291 316,291 311,517 316,291

217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 2,612,809$

238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 2,858,563

42,583 42,583 42,583 42,583 42,583 42,583 42,583 85,166 85,166 85,166 85,166 85,166 723,911

852,950 852,950 852,950 852,950 852,950 852,950 852,950 1,627,250 1,627,250 1,627,250 1,627,250 1,627,250 14,106,900

792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 9,512,820

963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 11,565,945

286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 3,437,400

879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 10,558,812

4,274,395$ 4,274,395$ 4,274,395$ 4,274,395$ 4,274,395$ 4,274,395$ 4,274,395$ 5,091,278$ 5,091,278$ 5,091,278$ 5,091,278$ 5,091,278$ 55,377,160$

9,884$ 10,213$ 9,884$ 10,213$ 10,213$ 9,884$ 10,213$ 10,101$ 10,888$ 14,710$ 15,114$ 12,124$ 133,441$

15,627 16,148 15,627 16,148 16,148 15,627 16,148 15,627 16,148 16,148 14,586 16,148 190,133

390 403 390 403 403 390 - - - - - - 2,379

85,020 87,854 85,020 87,854 87,854 85,020 87,854 163,500 168,950 168,950 152,600 168,950 1,429,426

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

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

17,100 17,670 17,100 17,670 17,670 17,100 2,338 - - - - - 106,648

54,273 56,082 54,273 56,082 56,082 54,273 56,082 54,273 56,082 56,082 50,655 56,082 660,322

182,294$ 188,371$ 182,294$ 188,371$ 188,371$ 182,294$ 172,635$ 243,502$ 252,068$ 255,890$ 232,954$ 253,305$ 2,522,348$

4,456,690$ 4,462,766$ 4,456,690$ 4,462,766$ 4,462,766$ 4,456,690$ 4,447,031$ 5,334,780$ 5,343,347$ 5,347,168$ 5,324,232$ 5,344,583$ 57,899,509$

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

DTE Gas Company



Case No.: U-20236

Exhibit No.: A-11


Page No.: 5 of 5

(Col. 1)


1 Great Lakes


3 Vector




7 ANR Northern

8 ANR SW


Source of Supply /



11 Great Lakes


13 Vector




17 ANR Northern

18 ANR SW



20 Great Lakes


22 Vector




26 ANR Northern

27 ANR SW


Usage Cost ($)

29 Great Lakes


31 Vector




35 ANR Northern

36 ANR SW





30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390 30,390

21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000

10,000 10,000 10,000 10,000 10,000 10,000 10,000 20,000 20,000 20,000 20,000 20,000

65,000 65,000 65,000 65,000 65,000 65,000 65,000 125,000 125,000 125,000 125,000 125,000

37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500

37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500

50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000

79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000

330,390 330,390 330,390 330,390 330,390 330,390 330,390 400,390 400,390 400,390 400,390 400,390

90,643 90,643 90,643 90,643 90,643 90,643 1,613 22,907 24,383 24,383 21,329 24,383

30,390 30,390 30,390 30,390 30,390 30,390 10,600 30,390 30,390 30,390 30,390 30,390

21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000

10,000 10,000 10,000 10,000 10,000 10,000 3,770 - - - - -

65,000 65,000 65,000 65,000 65,000 65,000 65,000 125,000 125,000 125,000 125,000 125,000

37,500 37,500 37,500 37,500 37,500 37,500 37,500 - - - - -

37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500 37,500

50,000 50,000 50,000 50,000 50,000 50,000 23,493 - - - - -

79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000 79,000

421,033 421,033 421,033 421,033 421,033 421,033 279,475 315,797 317,273 317,273 314,219 317,273

217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 217,734$ 2,612,809$

238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 238,214 2,858,563

42,583 42,583 42,583 42,583 42,583 42,583 42,583 85,166 85,166 85,166 85,166 85,166 723,911

852,950 852,950 852,950 852,950 852,950 852,950 852,950 1,627,250 1,627,250 1,627,250 1,627,250 1,627,250 14,106,900

792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 792,735 9,512,820

963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 963,829 11,565,945

286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 286,450 3,437,400

879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 879,901 10,558,812

4,274,395$ 4,274,395$ 4,274,395$ 4,274,395$ 4,274,395$ 4,274,395$ 4,274,395$ 5,091,278$ 5,091,278$ 5,091,278$ 5,091,278$ 5,091,278$ 55,377,160$

9,884$ 10,213$ 9,884$ 10,213$ 10,213$ 9,884$ 3,562$ 10,101$ 10,888$ 14,710$ 15,653$ 12,124$ 127,330$

15,627 16,148 15,627 16,148 16,148 15,627 16,148 15,627 16,148 16,148 15,106 16,148 190,654

390 403 390 403 403 390 152 - - - - - 2,531

85,020 87,854 85,020 87,854 87,854 85,020 87,854 163,500 168,950 168,950 158,050 168,950 1,434,876

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

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

17,100 17,670 17,100 17,670 17,670 17,100 8,302 - - - - - 112,612

54,273 56,082 54,273 56,082 56,082 54,273 56,082 54,273 56,082 56,082 52,464 56,082 662,131

182,294$ 188,371$ 182,294$ 188,371$ 188,371$ 182,294$ 172,101$ 243,502$ 252,068$ 255,890$ 241,274$ 253,305$ 2,530,134$

4,456,690$ 4,462,766$ 4,456,690$ 4,462,766$ 4,462,766$ 4,456,690$ 4,446,496$ 5,334,780$ 5,343,347$ 5,347,168$ 5,332,552$ 5,344,583$ 57,907,294$

DTE Gas Company


Projected Total Delivered Cost Including Transportation Cost ($)

Case No.: U-20236

Exhibit No.: A-12


Page No.: 1 of 1

(Col. 1) (Col. 2) (Col. 3) (Col. 4) (Col. 5) (Col. 6) (Col. 7) (Col. 8) (Col. 9) (Col. 10) (Col. 11) (Col. 12) (Col. 13) (Col. 14)

Apr-19 May-19 Jun-19 Jul-19 Aug-19 Sep-19 Oct-19 Nov-19 Dec-19 Jan-20 Feb-20 Mar-20 Total

1 Commodity Cost 30,659,933$ 31,285,957$ 30,322,618$ 31,412,632$ 31,398,777$ 30,304,106$ 20,304,931$ 25,872,854$ 27,149,393$ 27,450,745$ 25,284,378$ 26,719,402$ 338,165,725$

2 Transportation Cost 4,456,443 4,462,511 4,456,443 4,462,511 4,462,511 4,456,443 4,453,143 5,334,812 5,343,372 5,347,449 5,332,815 5,344,864 57,913,315

3 Total Delivered Cost 35,116,375$ 35,748,468$ 34,779,061$ 35,875,143$ 35,861,288$ 34,760,549$ 24,758,074$ 31,207,666$ 32,492,765$ 32,798,194$ 30,617,192$ 32,064,266$ 396,079,040$


4 Commodity Cost 27,489,298$ 28,012,363$ 27,476,976$ 28,845,515$ 28,855,716$ 27,713,922$ 18,261,116$ 23,265,746$ 25,329,457$ 26,144,753$ 22,925,459$ 24,877,309$ 309,197,632$




7 Commodity Cost 26,861,823$ 27,355,653$ 26,906,651$ 28,271,290$ 28,497,192$ 27,500,769$ 18,302,158$ 22,442,586$ 25,072,196$ 26,288,103$ 22,919,313$ 24,783,951$ 305,201,684$




10 Commodity Cost 27,645,890$ 28,181,666$ 27,633,017$ 28,975,845$ 29,122,166$ 28,054,013$ 18,677,002$ 22,809,426$ 25,159,933$ 26,241,414$ 22,926,375$ 24,915,336$ 310,342,083$




13 Commodity Cost 28,413,755$ 29,227,834$ 28,761,391$ 30,225,680$ 30,501,144$ 29,594,489$ 20,019,290$ 23,947,344$ 26,355,200$ 27,419,662$ 25,002,717$ 26,253,822$ 325,722,327$



DTE Gas CompanyFixed Price Program AnalysisHistorical Backcast of NYMEX Prices

Case No.: U-20236Witness: E.P. Schiffer

Exhibit No.: A-25Page No.: 1 of 1

Line Start Delivery End Delivery $/Dth

Year overYear Price

Change(Volatility)

AnnualResidential

Gas Cost 1 $/Dth

Year overYear Price

Change(Volatility)

AnnualResidential

Gas Cost 1 $/Dth

Annual

ResidentialGas Cost

Above(Below)

Index 1

Total Cost Above

(Below) Index 2

Cumulative TotalCost Above

(Below) Index 2

(col. a) (col. b) (col. c) (col. d) (col. e) (col. f) (col. g) (col. h) (col. i) (col. j) (col. k) (col. l)

1 Apr-01 Mar-02 3.05$ 298$ 3.24$ 316$ (0.19)$ (18)$ (21,480,695) (21,480,695)2 Apr-02 Mar-03 3.67 19% 359 4.06 22% 396 (0.38) (37) (43,717,977) (65,198,673)3 Apr-03 Mar-04 4.09 11% 400 5.15 24% 504 (1.06) (104) (121,823,419) (187,022,091)4 Apr-04 Mar-05 4.72 14% 461 6.22 19% 608 (1.50) (146) (171,656,197) (358,678,288)5 Apr-05 Mar-06 6.18 27% 604 9.04 37% 884 (2.87) (280) (328,416,954) (687,095,242)6 Apr-06 Mar-07 6.85 10% 669 6.67 -30% 651 0.18 18 20,671,518 (666,423,724)7 Apr-07 Mar-08 8.02 16% 783 7.10 6% 694 0.91 89 104,629,325 (561,794,399)8 Apr-08 Mar-09 8.53 6% 833 8.74 21% 854 (0.21) (21) (24,553,492) (586,347,890)9 Apr-09 Mar-10 7.48 -13% 731 3.97 -79% 388 3.51 343 402,248,237 (184,099,653)10 Apr-10 Mar-11 6.72 -11% 656 4.12 4% 403 2.60 254 297,564,605 113,464,95211 Apr-11 Mar-12 5.53 -19% 540 3.82 -8% 373 1.71 167 195,787,028 309,251,98012 Apr-12 Mar-13 4.63 -18% 452 2.86 -29% 279 1.77 173 203,104,859 512,356,83913 Apr-13 Mar-14 4.17 -10% 408 3.99 33% 390 0.18 17 20,471,701 532,828,54014 Apr-14 Mar-15 3.92 -6% 383 4.03 1% 393 (0.10) (10) (11,631,328) 521,197,21215 Apr-15 Mar-16 3.63 -8% 354 2.50 -48% 244 1.13 110 129,494,406 650,691,61816 Apr-16 Mar-17 3.32 -17% 324 2.70 -40% 264 0.62 61 71,137,455 721,829,07417 Apr-17 Mar-18 3.10 -7% 303 3.03 12% 296 0.07 7 8,207,054 658,898,672

18 17-year Average 5.15$ 15% 503$ 4.78$ 33% 467$ 0.37$ 37$ 42,943,302$

19 Volatility (95% Confidence Interval) 230% 66%

(1) Based on average residential consumption of 97.7 Dth per year for the forecast year of 2018(2) Annual volatility on line 16 is multiplied by two to account for 95% of the historical price outcomes.

75% VCA Method Index Method75% VCA Method less

Index Method

DTE Gas CompanyFixed Price Program AnalysisPurchase Percentages

Case No.: U-20236Witness: E.P. Schiffer

Exhibit No.: A-27Page No.: 1 of 1

Line

Transaction Month

Current Month

TransactionCumulative Transactions

Current Month


Current Month


1 Dec-18 75% 37% 0%2 Jan-19 0% 75% 3% 40% 3% 3%3 Feb-19 0% 75% 3% 43% 3% 6%4 Mar-19 0% 75% 3% 47% 3% 9%5 Apr-19 0% 75% 3% 50% 3% 13%6 May-19 0% 75% 3% 53% 3% 16%7 Jun-19 0% 75% 3% 56% 3% 19%8 Jul-19 0% 75% 3% 59% 3% 22%9 Aug-19 0% 75% 3% 62% 3% 25%

10 Sep-19 0% 75% 3% 66% 3% 28%11 Oct-19 0% 75% 3% 69% 3% 31%12 Nov-19 0% 75% 3% 72% 3% 34%13 Dec-19 0% 75% 3% 75% 3% 38%14 Jan-20 0% 75% 0% 75% 3% 41%15 Feb-20 0% 75% 0% 75% 3% 44%16 Mar-20 0% 75% 0% 75% 3% 47%

2019-20 GCR Delivery Period (FPP Coverage)



YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC YR AVG2011 4.216 4.316 3.793 4.240 4.377 4.326 4.357 4.370 3.857 3.759 3.524 3.364 4.042

2012 3.084 2.678 2.446 2.191 2.036 2.429 2.774 3.010 2.634 3.023 3.471 3.696 2.789

2013 3.354 3.226 3.427 3.976 4.152 4.148 3.707 3.459 3.567 3.498 3.497 3.818 3.652

2014 4.407 5.557 4.855 4.584 4.795 4.619 4.400 3.808 3.957 3.984 3.728 4.282 4.415

2015 3.189 2.866 2.894 2.590 2.517 2.815 2.773 2.886 2.638 2.563 2.033 2.206 2.664

2016 2.372 2.189 1.711 1.903 1.995 1.963 2.917 2.672 2.853 2.952 2.764 3.232 2.460

2017 3.930 3.391 2.627 3.175 3.142 3.236 3.067 2.969 2.961 2.974 2.752 3.074 3.108

2018 2.738 3.631 2.639 2.691 2.821 2.875 2.996 2.822 2.895 3.021 3.185 4.646 3.080

Feb-14 Mar-16

5.557 1.711 3.247808

J 11 F M A M J J A S O N D J 124.216 4.316 3.793 4.240 4.377 4.326 4.357 4.370 3.857 3.759 3.524 3.364 3.084

NYMEX NATURAL GAS CONTRACT SETTLEMENT HISTORY

Monthly Settlement Price

-

1.000

2.000

3.000

4.000

5.000

6.000

J14

F M A M J J A S O N D J15




F M A M J J A S O N D

$P

ER

DT

H

Jan 2014 - Dec 2018

NYMEX Natural Gas Contract Monthly "Settlement" Price

Case No.: U-20236

Exhibit No.: A-29


Page: 1 of 1

Case No.: U-20236

Exhibit No.: A-30


Page: 1 of 8

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Exhibit No.: A-30


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Exhibit No.: A-30


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Case No.: U-20236

Exhibit No.: A-30


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Exhibit No.: A-30


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Exhibit No.: A-30


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Case No.: U-20236

Exhibit No.: A-30


Page: 8 of 8

STATE OF MICHIGAN







)

QUALIFICATIONS

AND

DIRECT TESTIMONY

OF

LUCIAN BRATU

DTE GAS COMPANY

QUALIFICATIONS OF LUCIAN BRATU

Line

No.

LB-1

Q1. What is your name and business address?1

A1. My name is Lucian Bratu. My business address is One Energy Plaza, Detroit, 2

Michigan 48226. 3

4


A2. I am employed by DTE Gas Company (DTE Gas or Company) as a Senior Gas 6

Supply & Planning Analyst in Gas Supply and Planning. 7

8


A3. I earned a Bachelor of Electromechanical Engineering Degree from Polytechnic 10

University of Bucharest and a Master Degree in Business Administration from 11

University of Windsor. 12

13

Q4. Do you hold any professional designations? 14

A4. I earned a Professional Engineer certification from Professional Engineers Ontario 15

(PEO), the licensing and regulation body for professional engineers in Ontario, 16

Canada. 17

18

Q5. Have you had other applicable training? 19

A5. I have completed The Oxford Princeton Programme’s “Overview of the North 20

American Natural Gas Industry” and “North American Natural Gas Transportation 21

and Storage” training. 22

23

L. BRATU

Line U-20236

No.

LB-2

Q6. What is your relevant business experience? 1

A6. After an engineering career in the automotive industry, in 2009 I was hired full time 2

by Union Gas Limited, one of the two major natural gas distribution companies in 3

Ontario, Canada where I held positions of increased responsibility in Finance, 4

Operations and Business Development. I was hired by DTE Energy in August 2015 5

as a full time Senior Strategist in the Emergency Preparedness & Response 6

department of DTE Electric Company (DTE Electric) where I implemented 7

engineering solutions and process changes to reduce power outage duration and 8

restoration costs. In August 2017, I accepted a position in the Vegetation 9

Management department where I designed and implemented an herbicide treatment 10

program to control the vegetation in the right-of-way more effectively and at a 11

reduced cost. In July 2018, I accepted a position with DTE Gas as a Senior Gas 12

Supply & Planning Analyst in the Gas Supply and Planning Department. 13

14

Q7. What are your responsibilities as a Senior Gas Supply and Planning Analyst in 15

Gas Supply and Planning? 16

A7. I am responsible for the planning of natural gas supplies necessary to reliably meet 17

the requirements of DTE Gas’s customers. 18

19

Q8. Have you previously testified or submitted testimony in any regulatory 20

proceedings? 21

A8. No, I have not. 22

23

24

DTE GAS COMPANY

DIRECT TESTIMONY OF LUCIAN . BRATU

Line

No.

LB-3



A9. In my testimony, I will describe DTE Gas’s operational plan for the 5-year period 3

April 1, 2019 through March 31, 2024 and I will detail the operational plan year April 4

1, 2019 to March 31, 2020. My testimony will support DTE Gas's operational 5

planning decisions as being reasonable and prudent and will cover the following 6

topics: 7

1. Normal Weather Operating Plan – How the planned supply purchase 8

requirements are developed for normal weather. 9

2. Storage Plan –Total storage field cycleable capacity of 135.1 Bcf has remained 10

unchanged. 11

3. GCR/GCC Storage Allocation – The allocation of 71.9 Bcf of cycleable storage 12

capacity to GCR and Gas Customer Choice (GCC) customers has remained 13

unchanged. 14

4. GCC Plan – DTE Gas administers the GCC program in accordance with DTE 15

Gas’s GCC tariff. 16

5. Design Day and Minimum Storage Balances – How DTE Gas plans need to 17

meet projected peak day requirements. 18

6. Colder than Normal Protection – How the planned supply purchase requirements 19

are adjusted for colder than normal (CTN) weather and that CTN exposure has 20

increased from last year’s GCR Plan case by 0.7 Bcf, from 22.5 Bcf to 23.2 Bcf. 21

The increase is primarily due to the updated 15-year weather normalization period, 22

which is explained in the testimony of Company Witness Mr. Chapel.23

7. Warmer than Normal Weather Operating Plan - How the planned supply 24

purchase requirements are adjusted for warmer than normal weather. 25

L. BRATU

Line U-20236

No.

LB-4

8. Other Operational Changes - During the GCR year, factors influencing DTE 1

Gas’s operations are continually changing. Refinements to the plan will be based 2

on current and projected market and operational conditions. 3

9. Future Outlook - There are no indications at this time that the operating plan for 4

April 2020 through March 2024 will have any significant changes from the April 5

2019 through March 2020 operating plan. 6

7


A10. Yes. I am supporting the following exhibits: 9


A-13 Normal Weather Source and Disposition 11

A-14 Storage Capacity and Utilization 12

A-15 Peak Day Supply Mix 13

A-16 Colder-Than-Normal Storage Balances 14

A-17 Colder-Than-Normal Weather Source and Disposition (CTN) 15

A-18 Warmer-Than-Normal Weather Source and Disposition (WTN) 16

17



20

OPERATIONAL PLANNING 21

Q12. What data was used to develop the operating plan?22

A12. DTE Gas develops its operating plan from four primary sources. These sources are: 23

1) market requirements as supported by Company Witness Mr. Chapel, 2) peak 24

winter day flowing supply, 3) minimum winter storage balances developed in 25

L. BRATU

Line U-20236

No.

LB-5

conjunction with peak day operations, and 4) CTN exposures. I provide support for 1

the last three sources of data in my testimony. 2

3

Q13. Are there factors other than the four discussed above that are important to the 4

development of DTE Gas’s operating plan and supply purchasing pattern? 5

A13. Yes. In addition to reliably meeting customers’ requirements, protecting for peak 6

day operations, and CTN exposures, other factors that influence the supply 7

purchasing pattern include the GCC supply delivery pattern, achieving the target end 8

of injection season and end of withdrawal season storage balances, storage 9

operations, WTN exposures and the operational constraints of DTE Gas’s system. 10

11

NORMAL WEATHER OPERATING PLAN 12

Q14. What is the monthly supply volume that DTE Gas plans to purchase under 13

normal weather conditions? 14

A14. The monthly supply volume that DTE Gas plans to purchase under normal weather 15

conditions is identified on Exhibit A-13. This exhibit illustrates DTE Gas’s normal 16

weather operating plan based on the normal weather market requirements projected 17

by Company Witness Mr. Chapel. As described by Company Witness Mr. Chapel, 18

DTE Gas utilizes a 15-year normal weather pattern to project customers’ 19

requirements. Company Witness Mr. Chapel also describes how DTE Gas assumes 20

normal weather to be expected and it’s use of 15-year normal heating degree-days 21

(HDDs) for the operating plan April 2019 through March 2024. Heating degree-day 22

(HDD) is a measurement meant to quantify the demand of energy needed to heat a 23

building and is calculated as the number of degrees that the average daily temperature 24

is lower than the 65° F. 25

L. BRATU

Line U-20236

No.

LB-6

Q15. Does DTE Gas expect that its actual monthly supply purchases will match those 1

contained in Exhibit A-13? 2

A15. No, it does not. There are numerous factors that can influence monthly supply 3

purchases and cause it to deviate from the plan. It is highly unlikely that DTE Gas 4

will experience normal weather evenly throughout the year for the entire period 5

considered in the plan illustrated in Exhibit A-13. Weather patterns tend to occur 6

unevenly such that even if actual weather experienced was on average normal on an 7

annual basis, the actual storage balances and monthly purchases would differ from 8

those contained in DTE Gas’s normal weather plan based on when during the year 9

the weather deviates from normal. Therefore, on at least a monthly basis during the 10

operating year, DTE Gas refines its planned supply volumes based on actual and 11

projected market requirements; operational conditions including weather variations; 12

actual storage balances; GCC migration; customer count; and changes in customer 13

usage such as conservation. DTE Gas also updates its planned purchases during the 14

plan year due to routine updated projections of lost gas, company use, gas in kind, 15

and GCC enrollment levels. In addition, the market forecast is updated at least once 16

during the plan year based on updated customer count and usage factors assumptions. 17

18

STORAGE PLAN 19

Q16. Where does DTE Gas secure its gas storage service? 20

A16. DTE Gas uses its own facilities for gas storage. DTE Gas owns and operates four 21

gas storage fields in Michigan. The fields are located in different parts of the state 22

and each storage field has unique operating characteristics. The Six Lakes (Taggart) 23

field is located in central Michigan and is operated in a base load manner. The other 24

three fields, Belle River Mills, Columbus, and West Columbus are located on the 25

L. BRATU

Line U-20236

No.

LB-7

eastside of the state in St. Clair County. Belle River and West Columbus are peaking 1

fields while Columbus is considered a base load field. 2

3

Q17. What is the difference between a base load storage field and a peaking storage 4

field? 5

A17. The primary difference is the time required to inject or withdraw the full working 6

volumes from the storage field. A base load field typically requires the entire summer 7

injection season to refill and the entire winter withdrawal season to fully remove gas 8

from storage. By contrast, peak storage fields equipped with the necessary 9

compression and facilities, are capable of withdrawing gas at a much faster rate to 10

meet peak demands than base load fields. The time to fill and empty peak storage 11

fields is considerably shorter, with the actual timing dependent upon the 12

characteristics of each field. 13

14

Q18. What is the capacity of DTE Gas’s storage fields? 15

A18. DTE Gas’s current aggregate cycleable working storage capacity is 135.1 Bcf, and 16

has remained unchanged (Exhibit A-14, line 14, column (d)). Exhibit A-14 depicts 17

DTE Gas’s cycleable working storage capacity and its utilization of total capacity by 18

customer group. 19

20

Q19. Are there any factors that could affect this cycleable storage capacity of 135.1 21

Bcf? 22

A19. Yes. DTE Gas may actually inject or withdraw more or less than the 135.1 Bcf of 23

current aggregate cycleable working storage gas. The maximum capacity may 24

actually be higher or lower depending on numerous operating conditions and design 25

L. BRATU

Line U-20236

No.

LB-8

assumptions. The maximum of this operating range may be constrained by system 1

operating conditions, storage field performance and reservoir characteristics. For 2

example, operating a base load field at the high end of its operating range could result 3

in gas migration to the outer limits of the reservoir increasing the likelihood that a 4

portion of the previously injected storage gas from that field may not be recoverable. 5

In addition, during periods of warmer than normal weather, withdrawals from the 6

base load storage field may be reduced. These withdrawals will be difficult to make 7

up at a later time due to such constraints as available compression and maximum 8

operating pressures. Other factors that affect the cycling capability of the storage 9

fields include performance of DTE Gas’s transmission systems, compressor stations, 10

actual weather patterns, the duration of cold/warm weather, actual temperatures, 11

supply deliveries, loads experienced, and the particular injection and withdrawal 12

patterns of each storage field. System constraints and uneven weather patterns impact 13

storage operations and must be taken into consideration in planning for the safe and 14

efficient operation of the system. 15

16

Q20. How do storage operations affect the supply plan? 17

A20. Storage allows DTE Gas to buy steady daily volumes of gas supply. Changes in daily 18

market volumes are balanced by storage withdrawals or injections. Storage 19

withdrawals are most pronounced during the winter heating season when market 20

requirements exceed supply. By contrast, injections are predominant during the 21

summer when market requirements are low. Storage operations are especially critical 22

during the deep winter months to protect for peak day operations and CTN exposures. 23

DTE Gas’s supply plan is designed to meet the required minimum storage inventory 24

balances to ensure specific storage withdrawal rates necessary to meet peak day 25

L. BRATU

Line U-20236

No.

LB-9

sendout in combination with flowing supplies. Storage holds a portion of the CTN 1

protection volumes and must be managed on both a seasonal and daily basis. Another 2

critical time for storage operations occurs during WTN conditions at the end of the 3

injection season (October) and at beginning of the winter withdrawal season in 4

November when storage fields are near maximum capacity. Facility enhancement 5

projects or other system constraints such as storage field pressures, available 6

compression capacity, available storage field injection or withdrawal capability, and 7

unforeseen pipeline integrity compliance could also affect the supply plan. 8

9

GCR/GCC STORAGE ALLOCATION 10

Q21. Does DTE Gas target a specific storage balance for GCR and GCC customers 11

at the end of the storage injection season? 12

A21. Yes. DTE Gas plans for a specific storage balance on October 31 each year, which 13

is the end of the injection season. The targeted storage level, in addition to winter 14

flowing supply, allows DTE Gas to meet normal winter market requirements and 15

maintain planned minimum storage balances. The targeted storage balance includes 16

the colder-than-normal protection (CTNP) gas held in storage. 17

18

Q22. What is the targeted storage balance for GCR and GCC customers by 19

October 31, 2019? 20

A22. Total working gas in storage by October 31 for both GCR and GCC customers is 21

planned at 70.1 Bcf regardless of the mix between GCR and GCC. See Exhibit A-22

13, page 6 of 10, line 7, column (f). 23

24

L. BRATU

Line U-20236

No.

LB-10

Q23. Has the targeted storage balance for GCR and GCC customers on October 31, 1

2019 changed since the 2018-2019 Plan Case? 2

A23. No, the target storage balance on October 31 for GCR and GCC combined is 70.1 3

Bcf, unchanged since the 2018-2019 Plan Case. 4

5

Q24. How much cycleable storage capacity does DTE Gas propose to allocate for use 6

by GCR and GCC customers in 2019-2020? 7

A24. For 2019-2020, DTE Gas proposes to continue to allocate 71.9 Bcf of cycleable 8

storage capacity to GCR/GCC customers (Exhibit A-14, line 16, column (d)). The 9

details of DTE Gas’s storage utilization are outlined in Exhibit A-14, lines 9-16. As 10

detailed in this Exhibit, the 71.9 Bcf of storage capacity for 2019-2020 is comprised 11

of 66.9 Bcf for both Normal and CTN working gas utilization (line 10), and 5 Bcf of 12

WTN/contingency space (line 11), totaling 71.9 Bcf (line 16). 13

14

Q25. Does this 71.9 Bcf storage allocation for 2019-2020 GCR Plan Year represent a 15

change from the amount that DTE Gas allocated to GCR/GCC customers for 16

the 2018-2019 GCR Plan Year? 17

A25. No. For the 2018-2019 GCR Plan Year, DTE Gas implemented a GCR/GCC 18

cycleable storage allocation volume of 71.9 Bcf. This is also the same 71.9 Bcf of 19

cycleable storage allocation that DTE Gas implemented for the prior 2017-2018 GCR 20

Plan Year. Additionally, this is the same 71.9 Bcf of cycleable storage allocation 21

ordered by the Commission on December 20, 2012, in the DTE Gas Rate Case 22

Settlement in Case No. U-16999. 23

24

L. BRATU

Line U-20236

No.

LB-11

GCC PLAN 1

Q26. What are the specific supply parameters for the GCC program? 2

A26. Each month, based on a supplier’s enrollment of customers, DTE Gas will provide 3

each supplier with a daily flow volume that identifies the daily delivery requirement 4

normally using the 1/365th +/- 10% of total normal weather annual GCC customer 5

usage. Deliveries to the customer continue to be DTE Gas’s responsibility. 6

Operationally, DTE Gas will operate and deliver gas to the GCC customers as if they 7

were DTE Gas sales customers. 8

9

Q27. How does DTE Gas manage its supply strategy in conjunction with the GCC 10

program? 11

A27. The annual GCC volume reflected in the Plan is approximately 28.2 Bcf, which 12

represents 154,995 customers. Because DTE Gas’s GCC tariff identifies it as the 13

supplier of last resort (SOLR), DTE Gas faces uncertainty in the event of a supplier 14

defaulting or a customer returning to sales service. DTE Gas continually monitors 15

the number of customers and their associated flow requirement moving between the 16

GCC program and GCR sales. DTE Gas adjusts its final monthly purchases to reflect 17

the volumes remaining under GCR sales. This approach allows DTE Gas to maintain 18

sufficient daily winter flowing supply to meet the needs of its customers and a 19

sufficient daily summer flowing supply to meet the volume requirements to fill 20

storage sufficiently to meet operational plans. 21

22

DESIGN DAY AND MINIMUM STORAGE BALANCES 23

Q28. What flowing supplies will DTE Gas need to meet projected peak-day 24

requirements? 25

L. BRATU

Line U-20236

No.

LB-12

A28. Total end-of-month peak-day requirements are identified on line 26 of Exhibit A-15. 1

These requirements are provided by Company Witness Mr. Chapel (Exhibit A-5, 2

page 2 of 2, line 6). For the 2019-2020 Plan Year, DTE Gas plans to hold 381 3

MMcf/d (400 MDth/day capacity assuming 1.051 MMbtu/Mcf heating value) of firm 4

transportation contracts for the winter operating season to meet requirements for 5

normal weather, colder than normal weather, design day, and SOLR. DTE Gas 6

projects it will flow approximately 306 MMcf/d of GCR supply for January through 7

March 2020, Exhibit A-15, line 2, to satisfy the projected normal winter 8

requirements. Consequently, the amount of GCR flowing gas supply necessary to 9

meet a design day will be approximately 381 MMcf/d. This volume is approximately 10

74 MMcf/d above the normal GCR flowing supplies, which may be purchased using 11

74 MMcf/d of DTE Gas’s remaining recallable firm transportation either on the first 12

of month or spot day market, depending on the availability of gas in storage at the 13

time. The remainder of the gas supply to serve January through March peak days 14

will come from DTE Gas’s storage. 15

16

Q29. Will storage be utilized to satisfy peak day requirements? 17

A29. Yes. Approximately 66% of DTE Gas’s supply on a January 2020 peak day will be 18

provided from storage. Deliveries out of storage include deliveries to GCR, GCC, 19

EUT, and storage-service customers, including Exelon. 20

21

Q30. What are DTE Gas’s planned colder-than-normal storage balances? 22

A30. The amount of DTE Gas’s planned total storage balances for the CTN weather 23

exposure is identified in Exhibit A-17. The minimum total balance as shown in 24

L. BRATU

Line U-20236

No.

LB-13

Exhibit A-16, line 5, for January, February and March, is the planned quantity to 1

meet the peak day deliveries. 2

3

Q31. Are DTE Gas’s planned colder-than-normal storage balances inclusive of third-4

party gas in storage? 5

A31. Yes. Lines 2 and 3 of Exhibit A-16 represent estimated third-party storage balances 6

at the end of January, February and March in 2020. During the operating year, the 7

mix of the planned end-of-month volumes of DTE Gas and third-party customers’ 8

gas is constantly adjusted in response to weather and third-party activity. DTE Gas 9

may be able to rely on additional third-party gas in inventory above what is included 10

in Exhibit A-16, lines 2 through 4, and reduce winter purchases while maintaining 11

peak-day minimum-storage balances necessary for storage deliverability. In any 12

event, the peak-day minimum-storage balances for the 2019-2020 GCR plan year 13

will be maintained to provide the necessary peak-day withdrawal requirements from 14

storage. 15

16

COLDER-THAN-NORMAL PROTECTION 17

Q32. What is a colder-than-normal protection (CTNP) volume? 18

A32. CTNP is a calculated volume of gas that allows DTE Gas to maintain the minimum 19

storage balances identified in Exhibit A-16, line 5, should colder-than-normal 20

weather persist over a sustained period, or otherwise higher than forecasted sendout 21

occurs. The CTNP volume consists of storage gas and, if necessary, incremental 22

purchases. 23

24

L. BRATU

Line U-20236

No.

LB-14

Q33. What is DTE Gas’s planned maximum winter CTN exposure? 1

A33. DTE Gas’s planned maximum winter CTN exposure for the 2019-2020 GCR plan 2

year represents the incremental customer usage that may occur in the event DTE Gas 3

were to again experience the coldest winter in its history. DTE Gas calculates its 4

maximum winter CTN exposure using the actual monthly Heating Degree Days 5

(HDD) experienced in 2013-2014, which is the coldest November through March 6

winter period since 1951. These actual monthly HDDs from 2013-2014 were then 7

applied to the forecasting model, which is more fully described by Company Witness 8

Mr. Chapel, to calculate the winter markets if such weather were to occur now. The 9

maximum CTN exposure represents the difference between the planned normal 10

winter requirements and the maximum CTN requirements. The total colder-than-11

normal exposure volume for all GCC and GCR customers is 23.2 Bcf. Based on 12

numerous prior Company proposals and Commission approvals, DTE Gas continues 13

to prepare a CTN plan based on the coldest historical period since 1951 to make 14

certain that the Company will be prepared and able to continue to provide reliable 15

gas supply for its customers should it experience a level of severe cold weather that 16

it has experienced in the past. DTE Gas considers all 67 years of weather history 17

(1951-2017) in designing its Plans to ensure that customers will be protected for all 18

possible weather extremes and weather patterns that have occurred. 19

20

Q34. Has DTE Gas’s maximum CTN exposure changed since the 2018-2019 Plan 21

Case? 22

A34. Yes. The maximum winter CTN exposure has increased from last year’s Plan case 23

by 0.7 Bcf, from 22.5 Bcf to 23.2 Bcf (Exhibit A-17, line 7, column (e)). The increase 24

in maximum winter CTN exposure is the result of the updated 15-year weather 25

L. BRATU

Line U-20236

No.

LB-15

normalization period, changes in customer count, and updated usage factors as 1

discussed in the testimony of Company Witness Mr. Chapel. 2

3

Q35. How is the level of CTNP volume supplied? 4

A35. For the winter of 2019-2020, DTE Gas plans to enter the winter season with 5 Bcf of gas 5

in storage for CTNP. In addition, DTE Gas plans to mitigate a portion of the risk of 6

the 23.2 Bcf CTN exposure with 3 Bcf of normal weather purchases in excess of 7

normal weather requirements (made ratably) from November 2019 to March 2020. 8

Furthermore, DTE Gas will monitor actual and projected CTN weather exposures 9

throughout the winter and will obtain additional CTNP supply via incremental winter 10

purchases if gas in storage is insufficient to meet the potential exposure and maintain the 11

necessary minimum storage balances. A CTN plan for the 2019-2020 winter is shown 12

on Exhibit A-17. 13

14

Q36. How will DTE Gas determine when to purchase incremental supply for CTN? 15

A36. Timing of the incremental purchases, and whether these purchases will be first of 16

month (FOM) or daily spot purchases, will depend upon the severity of the winter 17

season, at what point in time the cold weather is actually experienced, supply 18

liquidity, and projected storage balances. DTE Gas plans to limit mid-month daily 19

spot purchases to the most operationally critical deep winter months of January 20

through March. In order to minimize price and supply reliability risk, DTE Gas plans 21

to purchase sufficient FOM quantities to limit daily spot purchases. If, after the 22

month has begun, DTE Gas assesses that FOM flowing supply levels are not adequate 23

to meet operational requirements based on actual and projected storage balances, 24

potential cold weather exposures and weather forecasts, then it will begin to layer in 25

L. BRATU

Line U-20236

No.

LB-16

day gas purchases. On a normal winter basis, DTE Gas plans to fill 307 MMcf/d of 1

its 381 MMcf/d of firm pipeline entitlement, leaving 74 MMcf/d of recallable 2

capacity that would be available for FOM CTN purchases or daily gas purchases for 3

CTN and/or peak-day requirements. 4

5

Q37. Does peak day and CTN planning end at March 31? 6

A37. No. DTE Gas plans for an end-of-month peak day based on the coldest historical 7

temperatures from the 22nd of that month to the 7th of the following month. It is 8

possible for an end of March peak day temperature to occur through the end of the 9

first week in April when storage balances are at their minimums. 10

11

Q38. Is it possible that DTE Gas will need to purchase incremental supply in April 12

for CTN and/or peak day protection? 13

A38. Yes. Operating experience has shown that CTN winter weather could extend into a 14

CTN April. Storage withdrawals for GCR/GCC could continue into the month of 15

April, even under normal weather conditions. If GCR storage balances are projected 16

to be at or near minimums, then DTE Gas may need to purchase incremental supply 17

in April for CTN volumetric coverage and/or peak day protection in the same manner 18

as described above for the deep winter months. 19

20

Q39. What is DTE Gas’s plan if CTN, or otherwise higher than forecasted sendout, 21

should occur during the summer months (April – October)? 22

A39. As the summer injection season progresses, if CTN weather or otherwise higher 23

sendout occurs, then DTE Gas plans to increase its remaining planned summer 24

purchases in order to achieve its planned normal end-of-injection-season storage 25

L. BRATU

Line U-20236

No.

LB-17

target by October 31. For each remaining summer month, DTE Gas plans to evenly 1

purchase its remaining planned summer purchases. However, if DTE Gas 2

experiences higher sendout in October, then the October 31 storage balance will 3

likely fall short of the normal weather target, thereby effectively consuming a portion 4

of the CTNP held in storage. If this were to occur, then DTE Gas plans to replenish 5

CTNP in November with the rest being replaced in December prior to entering the 6

deep winter months of January - March. These replacement purchases as described 7

above are subject to operational limitations, particularly scheduled compressor 8

maintenance, potential WTN weather exposures, and available storage field injection 9

capacity. 10

11

WARMER-THAN-NORMAL WEATHER OPERATING PLAN 12

Q40. What is DTE Gas’s plan if warmer-than-normal weather, or otherwise lower 13

than forecasted sendout, should occur during the summer months (April – 14

October)? 15

A40. As the summer injection season progresses and warmer-than-normal conditions 16

occur, or otherwise lower than forecasted sendout occurs, DTE Gas plans to evenly 17

purchase the reduced remaining planned summer purchase requirements, subject to 18

operational limitations, to achieve its planned normal end-of-injection season 19

working-gas-storage target at October 31, 2019 of 70.1 Bcf. However, depending on 20

the timing of the reduced sendout and the associated reduction to supply, a volume 21

of gas associated with the September and primarily the October weather variation 22

could remain in storage. DTE Gas reserves 5 Bcf of storage space to accommodate 23

higher injections due to lower than expected sendout and other unpredictable system 24

imbalances in September, October and early November. If DTE Gas experiences 25

L. BRATU

Line U-20236

No.

LB-18

lower sendout than planned in October and expects to enter the winter operating 1

season with significantly more GCR and GCC gas in storage above the normal 2

weather injection season target, then November planned purchases may be reduced 3

to permit operational flexibility necessary for compression maintenance, maximum 4

daily flowing supply limitations, limitations on storage field injection capability, 5

continued warmer-than-normal exposure, and storage field maximum capacity 6

limitations. 7

8

Q41. What is DTE Gas’s plan if warmer-than-normal weather occurs during the 9

winter of 2019-2020 (November – March)? 10

A41. DTE Gas’s WTN Plan is provided in Exhibit A-18. It is based on the maximum 11

WTN exposure from the 2011-2012 winter. As illustrated in Exhibit A-18, DTE Gas 12

may begin to reduce flowing supply, if, as the winter progresses, warmer-than-normal 13

weather continues, and storage balances continue to exceed Plan levels. Before any 14

reduction in purchases is implemented, the estimated cumulative WTN surplus is 15

reduced by 1 Bcf for margin of accuracy purposes. The WTN surplus is the excess 16

amount of gas in storage above normal planned target. It includes the net result of a 17

cumulative reduction in sendout resulting from WTN weather actually experienced 18

in prior months offset by the cumulative reduction, if any, in purchases already made 19

in prior months. A reduction in purchases would be at 50% of the cumulative WTN 20

surplus for December purchases, and at a reduced percentage for the deep winter 21

months of January through March, approximately in the range of 35-40% of the WTN 22

surplus. 23

24

L. BRATU

Line U-20236

No.

LB-19

Q42. Are there limits to the WTN Plan supply reductions? 1

A42. Yes, DTE Gas must limit the reduction in flowing supply determined by the above 2

factors to an amount that will result in sufficient flowing supply to meet contracted 3

supply and the requirements of customers located in isolated regions, such as 4

Michigan’s Upper Peninsula, that can only be served by supply delivered from certain 5

pipelines. 6

7

Q43. What will DTE Gas do if storage levels exceed plan levels on March 31? 8

A43. If by March 31, gas remains in storage above the Plan level, then DTE Gas plans to 9

reduce its planned summer purchases in order to achieve its planned October 31 end-10

of-injection-season storage target. DTE Gas plans to evenly purchase each month 11

the reduced summer purchase requirements, subject to operational limitations. 12

13

OTHER OPERATIONAL CHANGES 14

Q44. How likely is it that DTE Gas’s Operational Plan will change during the 2019-15

2020 GCR Plan Year? 16

A44. During a typical GCR year, factors influencing DTE Gas’s operations are continually 17

changing. Such factors may include changes in weather, GCC migration, customer 18

usage, customer count, supply liquidity, changes in inventory levels, and changes in 19

operations. Therefore, before and during the 2019-2020 GCR Year, there is a 20

reasonable likelihood that DTE Gas will continue to refine its operational plan based 21

on current and projected market and operational conditions. 22

23

L. BRATU

Line U-20236

No.

LB-20

FUTURE OUTLOOK 1

Q45. Does DTE Gas’s Operational Plan for the operating years April 2020-March 2

2024 differ from the 2018-2019 Operating Plan? 3

A45. At the time of the filing of the GCR Plan case for the 2019-2020 GCR Year, there 4

are no indications that the operating plan will have any significant changes over the 5

next five years. With regards to storage utilization, DTE Gas’s GCR/GCC storage 6

allocation plan for the operating years April 2020-March 2024 does not differ from 7

the 2019-2020 GCR Plan Year. The Company is currently proposing to maintain a 8

GCR/GCC cycleable storage allocation of 71.9 Bcf for 2019-2020 and all subsequent 9

years of the 5-Year forecast period. However, at some point in the future, depending 10

on increases or decreases in requirements or other operational factors, DTE Gas may 11

decide to modify this storage allocation plan for the future operating years beginning 12

with the 2020-2021 GCR Plan year. 13

14


A46. Yes, it does.16

STATE OF MICHIGAN







)

EXHIBITS

OF

LUCIAN . BRATU

Michigan Public Service Commission Case No.: U-20236

DTE Gas Company Exhibit: A-13

April 2019 - March 2020 GCR Plan Witness: L. Bratu

Normal Weather Source and Disposition Page: 1 of 10

(All volumes in Mmcf except where indicated otherwise.)

(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)

Line

No. Year MONTH

GCR

Markets

Company

Use Lost

\(Found)

Gas

GCR

Sendout

GCC

Markets

Total GCR &

GCC

Sendout GCR Supply GCC Supply

Total

System

Supply

Gas In

Kind Total Supply

1 2019 APRIL 9,408 517 9,925 2,204 12,128 12,033 2,461 14,494 479 14,972

2 MAY 4,263 503 4,766 1,793 6,559 12,431 2,543 14,975 541 15,516

3 JUNE 2,440 416 2,857 646 3,502 12,030 2,461 14,491 523 15,014

4 JULY 2,364 396 2,759 482 3,241 12,431 1,122 13,553 508 14,062

5 AUGUST 2,271 356 2,627 617 3,244 12,431 2,543 14,975 500 15,475

6 SEPTEMBER 3,021 436 3,457 764 4,220 12,030 2,461 14,491 479 14,970

7 OCTOBER 7,168 451 7,619 1,812 9,431 8,202 2,543 10,745 471 11,217

8 NOVEMBER 12,881 475 13,355 2,833 16,188 9,181 2,461 11,642 424 12,066

9 DECEMBER 19,760 692 20,452 4,369 24,821 9,494 2,543 12,037 462 12,499

10 2020 JANUARY 24,448 873 25,321 5,074 30,395 9,494 2,543 12,037 698 12,735

11 FEBRUARY 22,487 800 23,287 4,488 27,774 8,802 2,379 11,181 603 11,784

12 MARCH 17,300 628 17,929 3,495 21,423 9,494 2,543 12,037 581 12,618

13 2019-20 OPY Total 127,811 6,542 134,353 28,575 162,928 128,053 28,605 156,658 6,270 162,928






(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)

Line

No. Year MONTH

GCR

Markets

Company

Use Lost

\(Found)

Gas

GCR

Sendout

Gas

Customer

Choice

Markets

Total GCR &

GCC


Total

System

Supply

Gas In

Kind Total Supply

1 2020 APRIL 9,409 581 9,990 2,182 12,172 11,980 2,444 14,424 611 15,035

2 MAY 4,267 593 4,860 1,775 6,634 12,379 2,526 14,905 678 15,583

3 JUNE 2,438 487 2,925 639 3,564 11,980 2,444 14,424 656 15,080

4 JULY 2,359 469 2,828 477 3,305 12,379 1,064 13,443 644 14,087

5 AUGUST 2,269 429 2,698 611 3,309 12,379 2,526 14,905 635 15,539

6 SEPTEMBER 3,017 527 3,544 756 4,300 11,980 2,444 14,424 610 15,034

7 OCTOBER 7,165 489 7,654 1,794 9,448 8,143 2,526 10,669 607 11,276

8 NOVEMBER 12,877 505 13,381 2,805 16,186 9,016 2,444 11,461 546 12,006

9 DECEMBER 19,758 695 20,453 4,326 24,778 9,359 2,526 11,885 585 12,470

10 2021 JANUARY 24,444 873 25,317 5,023 30,340 9,359 2,526 11,885 678 12,563

11 FEBRUARY 21,651 800 22,450 4,443 26,893 8,330 2,281 10,612 578 11,190

12 MARCH 17,294 628 17,922 3,460 21,382 9,359 2,526 11,885 564 12,449

13 2020-21 OPY Total 126,947 7,076 134,023 28,289 162,312 126,645 28,275 154,920 7,392 162,312






(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)

Line

No. Year MONTH

GCR

Markets

Company

Use Lost

\(Found)

Gas

GCR

Sendout

Gas

Customer

Choice

Markets

Total GCR &

GCC


Total

System

Supply

Gas In

Kind Total Supply

1 2021 APRIL 9,405 581 9,986 2,160 12,146 12,003 2,420 14,423 591 15,014

2 MAY 4,269 593 4,862 1,757 6,619 12,403 2,501 14,904 660 15,564

3 JUNE 2,435 487 2,922 633 3,555 12,003 2,420 14,423 639 15,062

4 JULY 2,355 469 2,824 472 3,296 12,403 1,043 13,446 627 14,073

5 AUGUST 2,265 429 2,694 605 3,299 12,403 2,501 14,904 620 15,524

6 SEPTEMBER 3,014 527 3,541 748 4,289 12,003 2,420 14,423 593 15,016

7 OCTOBER 7,160 489 7,649 1,776 9,425 8,194 2,501 10,695 581 11,276

8 NOVEMBER 12,867 505 13,372 2,777 16,149 9,026 2,420 11,446 507 11,953

9 DECEMBER 19,745 695 20,440 4,282 24,722 9,369 2,501 11,870 545 12,415

10 2022 JANUARY 24,425 873 25,298 4,973 30,271 9,369 2,501 11,870 632 12,502

11 FEBRUARY 21,634 800 22,434 4,398 26,832 8,339 2,259 10,598 539 11,136

12 MARCH 17,277 628 17,906 3,425 21,331 9,369 2,501 11,870 527 12,397

13 2021-22 OPY Total 126,852 7,076 133,927 28,006 161,933 126,887 27,985 154,872 7,062 161,933






(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)

Line

No. Year MONTH

GCR

Markets

Company

Use Lost

\(Found)

Gas

GCR

Sendout

Gas

Customer

Choice

Markets

Total GCR &

GCC


Total

System

Supply

Gas In

Kind Total Supply

1 2022 APRIL 9,396 581 9,977 2,138 12,115 12,015 2,396 14,412 588 14,999

2 MAY 4,269 593 4,861 1,740 6,601 12,416 2,476 14,892 654 15,546

3 JUNE 2,430 487 2,917 626 3,544 12,015 2,396 14,412 626 15,037

4 JULY 2,349 469 2,819 467 3,286 12,416 1,029 13,445 608 14,053

5 AUGUST 2,261 429 2,690 599 3,289 12,416 2,476 14,892 605 15,497

6 SEPTEMBER 3,008 527 3,535 741 4,276 12,015 2,396 14,412 584 14,996

7 OCTOBER 7,151 489 7,640 1,758 9,398 8,218 2,476 10,694 586 11,280

8 NOVEMBER 12,850 505 13,354 2,749 16,103 8,986 2,396 11,382 502 11,884

9 DECEMBER 19,720 695 20,414 4,239 24,654 9,329 2,476 11,805 540 12,346

10 2023 JANUARY 24,384 873 25,257 4,923 30,180 9,329 2,476 11,805 625 12,431

11 FEBRUARY 21,598 800 22,397 4,354 26,752 8,299 2,236 10,536 533 11,069

12 MARCH 17,250 628 17,879 3,391 21,270 9,329 2,476 11,805 523 12,328

13 2022-23 OPY Total 126,664 7,076 133,740 27,726 161,466 126,786 27,706 154,491 6,974 161,466






(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)

Line

No. Year MONTH

GCR

Markets

Company

Use Lost

\(Found)

Gas

GCR

Sendout

Gas

Customer

Choice

Markets

Total GCR &

GCC


Total

System

Supply

Gas In

Kind Total Supply

1 2023 APRIL 9,380 581 9,961 2,117 12,077 12,018 2,372 14,390 585 14,974

2 MAY 4,264 593 4,857 1,722 6,579 12,419 2,451 14,869 650 15,520

3 JUNE 2,423 487 2,910 620 3,531 12,018 2,372 14,390 622 15,012

4 JULY 2,341 469 2,810 463 3,273 12,419 1,014 13,433 605 14,037

5 AUGUST 2,254 429 2,683 593 3,276 12,419 2,451 14,869 600 15,470

6 SEPTEMBER 2,999 527 3,526 734 4,260 12,018 2,372 14,390 581 14,970

7 OCTOBER 7,136 489 7,625 1,741 9,366 8,243 2,451 10,694 584 11,278

8 NOVEMBER 12,824 505 13,328 2,721 16,050 9,014 2,372 11,386 501 11,886

9 DECEMBER 19,682 695 20,376 4,197 24,573 9,358 2,451 11,809 539 12,348

10 2024 JANUARY 24,336 873 25,209 4,874 30,083 9,358 2,451 11,809 625 12,434

11 FEBRUARY 22,337 800 23,136 4,354 27,491 8,670 2,293 10,963 533 11,496

12 MARCH 17,181 628 17,809 3,391 21,200 9,358 2,451 11,809 523 12,332

13 2023-24 OPY Total 127,155 7,076 134,231 27,526 161,757 127,312 27,497 154,810 6,948 161,757






(a) (b) (c) (d) (e) (f)

Line

No. Year Month

To/(From) Balance To/(From) Balance To/(From) Balance

1 2019 APRIL 2,587 11,330 257 2,715 2,844 14,044

2 MAY 8,207 19,537 750 3,466 8,957 23,002

3 JUNE 9,697 29,233 1,816 5,281 11,512 34,514

4 JULY 10,180 39,414 640 5,922 10,821 45,335

5 AUGUST 10,304 49,718 1,926 7,848 12,230 57,565

6 SEPTEMBER 9,052 58,770 1,698 9,545 10,750 68,314

7 OCTOBER 1,054 59,825 731 10,276 1,786 70,100

8 NOVEMBER (3,750) 56,074 (372) 9,904 (4,122) 65,978

9 DECEMBER (10,496) 45,579 (1,826) 8,078 (12,322) 53,656

10 2020 JANUARY (15,130) 30,449 (2,530) 5,548 (17,660) 35,996

11 FEBRUARY (13,882) 16,567 (2,109) 3,439 (15,991) 20,005

12 MARCH (7,854) 8,713 (951) 2,488 (8,805) 11,200

13 2019-20 OPY Total (30) 30 0

GCR Storage GCC Storage GCR and GCC Storage






(a) (b) (c) (d) (e) (f)

Line

No. Year Month


1 2020 APRIL 2,600 11,313 262 2,751 2,863 14,063

2 MAY 8,198 19,511 751 3,501 8,949 23,011

3 JUNE 9,710 29,221 1,805 5,306 11,515 34,527

4 JULY 10,194 39,416 587 5,893 10,781 45,308

5 AUGUST 10,316 49,732 1,915 7,808 12,231 57,539

6 SEPTEMBER 9,046 58,778 1,688 9,496 10,734 68,273

7 OCTOBER 1,096 59,873 732 10,227 1,827 70,100

8 NOVEMBER (3,819) 56,054 (361) 9,867 (4,180) 65,920

9 DECEMBER (10,508) 45,546 (1,800) 8,067 (12,308) 53,612

10 2021 JANUARY (15,280) 30,267 (2,497) 5,570 (17,777) 35,835

11 FEBRUARY (13,541) 16,725 (2,162) 3,408 (15,703) 20,133

12 MARCH (7,999) 8,727 (934) 2,474 (8,933) 11,200

13 2020-21 OPY Total 14 (14) 0

GCR Storage

Gas Customer Choice

Storage GCR and GCC Storage






(a) (b) (c) (d) (e) (f)

Line

No. Year Month


1 2021 APRIL 2,608 11,335 260 2,734 2,868 14,068

2 MAY 8,201 19,536 743 3,478 8,945 23,013

3 JUNE 9,720 29,257 1,787 5,265 11,508 34,521

4 JULY 10,206 39,463 571 5,835 10,777 45,297

5 AUGUST 10,329 49,792 1,896 7,731 12,225 57,522

6 SEPTEMBER 9,056 58,847 1,672 9,403 10,727 68,249

7 OCTOBER 1,126 59,974 725 10,127 1,851 70,100

8 NOVEMBER (3,838) 56,135 (357) 9,770 (4,195) 65,905

9 DECEMBER (10,525) 45,610 (1,782) 7,989 (12,307) 53,598

10 2022 JANUARY (15,297) 30,313 (2,472) 5,517 (17,769) 35,829

11 FEBRUARY (13,556) 16,757 (2,140) 3,377 (15,696) 20,134

12 MARCH (8,009) 8,748 (924) 2,453 (8,934) 11,200

13 2021-22 OPY Total 21 (21) (0)

GCR Storage

Gas Customer Choice







(a) (b) (c) (d) (e) (f)

Line

No. Year Month


1 2022 APRIL 2,626 11,375 258 2,711 2,884 14,084

2 MAY 8,208 19,583 736 3,447 8,945 23,029

3 JUNE 9,724 29,307 1,770 5,217 11,493 34,522

4 JULY 10,205 39,512 562 5,779 10,767 45,290

5 AUGUST 10,331 49,843 1,877 7,656 12,208 57,498

6 SEPTEMBER 9,065 58,908 1,655 9,311 10,720 68,218

7 OCTOBER 1,165 60,072 718 10,028 1,882 70,100

8 NOVEMBER (3,866) 56,206 (353) 9,676 (4,219) 65,881

9 DECEMBER (10,544) 45,662 (1,764) 7,912 (12,308) 53,573

10 2023 JANUARY (15,302) 30,359 (2,447) 5,465 (17,749) 35,824

11 FEBRUARY (13,565) 16,795 (2,118) 3,347 (15,683) 20,141

12 MARCH (8,026) 8,768 (915) 2,433 (8,941) 11,200

13 2022-23 OPY Total 20 (20) (0)

GCR Storage

Gas Customer Choice







(a) (b) (c) (d) (e) (f)

Line

No. Year Month


1 2023 APRIL 2,642 11,410 255 2,687 2,897 14,097

2 MAY 8,212 19,623 728 3,416 8,941 23,038

3 JUNE 9,730 29,353 1,751 5,167 11,481 34,519

4 JULY 10,213 39,566 551 5,719 10,765 45,284

5 AUGUST 10,336 49,902 1,858 7,576 12,194 57,478

6 SEPTEMBER 9,072 58,974 1,638 9,215 10,711 68,188

7 OCTOBER 1,202 60,176 710 9,924 1,912 70,100

8 NOVEMBER (3,813) 56,363 (350) 9,575 (4,163) 65,937

9 DECEMBER (10,479) 45,884 (1,746) 7,828 (12,226) 53,711

10 2024 JANUARY (15,226) 30,658 (2,423) 5,405 (17,649) 36,063

11 FEBRUARY (13,933) 16,725 (2,062) 3,344 (15,995) 20,068

12 MARCH (7,928) 8,797 (940) 2,404 (8,868) 11,200

13 2023-24 OPY Total 29 (29) 0

GCR Storage

Gas Customer Choice




Storage Capacity and Utilization Witness: L. Bratu

(Volumes in Bcf) Page: 1 of 1

(b) (c) (d)

Line

No. W 2017-18 W 2018-19 W 2019-20

Storage Capacity

Storage Field Cyclable Capacity

1 Six Lakes 40.0 40.0 40.0

2 Belle River Mills 66.7 66.0 66.0

3 Columbus 15.9 16.3 16.3

4 West Columbus 12.5 12.9 12.9

5 Total Cyclable Storage Capacity 135.1 135.1 135.1

6

7

8

9 Storage Utilization

10 GCR & GCC customers 66.9 66.9 66.9

11 WTN/contingency space 5.0 5.0 5.0

12 End User Transport & Exelon 11.3 11.4 11.4

13 Storage Service 51.9 51.8 51.8

14 Total Cyclable Working Capacity 135.1 135.1 135.1

15 Total Cyclable Storage Capacity 135.1 135.1 135.1

16 Total GCR & GCC cyclable capacity (line 10+11) 71.9 71.9 71.9

(a)



Peak Day Supply Mix Witness: L. Bratu

(Volumes in MMcfd) Page: 1 of 1

(a) (b) (c) (d)

Line

No. PEAK DAY SUPPLY JANUARY FEBRUARY MARCH

1 SUPPLY

2 Total DTE Gas Normal GCR Purchases 306 304 306

3 Additional Requirements 75 77 75

4 Subtotal GCR Supply 381 381 381

5

6 GIK 22.5 20.8 18.7

7

8 Gas Customer Choice (includes CTN) 90 90 90

9

10 TOTAL GCR & GCC Flowing Supplies 494 492 490

11

12 EUT Receipts 313 299 242

13

14

15

16 TOTAL SUPPLY 807 791 732

17

18 STORAGE WITHDRAWALS

19 Total Storage Withdrawal 2,451 1,930 1,417

20 Less Storage Service 884 574 252

21 DTE Gas Storage Withdrawal 1,567 1,356 1,165

22

23 Total Peak Day Flowing and Storage Supply 2,374 2,147 1,897

24

25 LOAD REQUIREMENTS

26 Total Peak Day Requirements 2,364 2,136 1,880

27 Fuel 9 12 16

28 Total Peak Day Requirements 2,373 2,148 1,896

29

30 Unallocated Supply 1 (0) 1

31

32 Design Temperatures (Detroit) -4oF 4

oF 14

oF

2019-20END OF MONTH PEAK DAY REQUIREMENTS



Colder-Than-Normal Storage Balances Witness: L. Bratu

(All volumes in Bcf except where indicated otherwise) Page: 1 of 1

(a) (b) (c) (d)

Line

No. PLANNED ACTIVITY JANUARY FEBRUARY MARCH

1 DTE Gas GCR/GCC Planned CTN Balance 25.2 10.7 3.2

2 End User Transportation Balance 5.2 3.2 0.4

3 Storage Service Balance 17.6 8.8 0.0

4 TOTAL PROJECTED STORAGE BALANCE 48.0 22.7 3.6

5 MINIMUM TOTAL BALANCE REQUIRED 48.0 22.7 3.6

2019-20



November 2019 - March 2020 Witness: L. Bratu

Colder-Than-Normal Weather Source and Disposition (CTN) Page: 1 of 2

(All volumes in Mmcf except where indicated otherwise.) 2019-20 GCR % 82%

2019-20 GCC % 18%

Total 100%

(a) (b) (c) (d) (e) (f) (g) (h) (i)

Line

No. Year Month

Normal

GCR

Sendout

Normal

GCC

Markets

GCR CTN

Volumes

GCC CTN

Volumes

Total

GCR/GCC

CTN

Volumes

Total GCC &

GCR Sendout

(with CTN

Vols.)

Normal

GCR Supply

Normal

GCC Supply

Total

Normal

GCR/GCC

Supply

1

2 2019 NOVEMBER 13,355 2,833 2,334 522 2,856 19,044 9,181 2,461 11,642

3 DECEMBER 20,452 4,369 2,830 633 3,463 28,284 9,494 2,543 12,037

4 2020 JANUARY 25,321 5,074 4,528 1,012 5,541 35,936 9,494 2,543 12,037

5 FEBRUARY 23,287 4,488 4,020 899 4,919 32,693 8,802 2,379 11,181

6 MARCH 17,929 3,495 5,211 1,165 6,376 27,799 9,494 2,543 12,037

7 Winter 19-20 Total 100,344 20,258 18,924 4,231 23,154 143,757 46,465 12,470 58,934



November 2019 - March 2020 Witness: L. Bratu

Colder-Than-Normal Weather Source and Disposition (CTN) Page: 2 of 2

(j) (k) (l) (m) (n) (o) (p) (q) (r) (s) (t) (u)

Line

No. Year Month

GCR CTN

Volumes

Purchased

GCC CTN

Volumes

Purchased

Total

GCR/GCC

CTN

Volumes

Purchased

Total

System

Supply

Gas in

Kind


1 59,825 10,276 70,101

2 2019 NOVEMBER 0 0 12,066 424 (6,084) 53,741 (894) 9,383 (6,978) 63,123

3 DECEMBER 2,334 522 2,856 15,355 462 (10,992) 42,748 (1,937) 7,445 (12,929) 50,194 Min. Balance

4 2020 JANUARY 2,830 633 3,463 16,198 698 (16,828) 25,920 (2,910) 4,536 (19,738) 30,456 25,200

5 FEBRUARY 4,528 1,012 5,541 17,324 603 (13,374) 12,547 (1,995) 2,541 (15,369) 15,087 10,700

6 MARCH 4,020 899 4,919 17,537 581 (9,045) 3,502 (1,218) 1,323 (10,263) 4,825 3,209

7 Winter 19-20 Total 13,712 3,066 16,778 78,481 2,768 (56,323) (8,953) (65,276)

GCR Storage GCC Storage GCR and GCC Total Storage



November 2019- March 2020 Witness: L. Bratu

Warmer-Than-Normal Weather Source and Disposition (WTN) Page: 1 of 2

(All volumes in Mmcf except where indicated otherwise.) 2019-20 GCR % 82%

2019-20 GCC % 18%

Total 100%

(a) (b) (c) (d) (e) (f) (g) (h) (i)

Line

No. Year Month

Normal

GCR

Sendout

Normal

GCC

Markets

GCR WTN

Volumes

GCC WTN

Volumes

Total

GCR/GCC

WTN Volumes

GCR & GCC

Sendout (with

WTN Vols.)

Normal

GCR Supply

Normal

GCC Supply

Total

Normal

GCR/GCC

Supply

1

2 2019 NOVEMBER 13,355 2,833 (2,135) (477) (2,613) 13,576 9,181 2,461 11,642

3 DECEMBER 20,452 4,369 (2,793) (624) (3,417) 21,404 9,494 2,543 12,037

4 2020 JANUARY 25,321 5,074 (2,836) (634) (3,470) 26,925 9,494 2,543 12,037

5 FEBRUARY 23,287 4,488 (2,977) (666) (3,642) 24,132 8,802 2,379 11,181

6 MARCH 17,929 3,495 (6,712) (1,501) (8,213) 13,211 9,494 2,543 12,037

7 Winter 19-20 Total 100,344 20,258 (17,453) (3,902) (21,354) 99,248 46,465 12,470 58,934



November 2019- March 2020 Witness: L. Bratu

Warmer-Than-Normal Weather Source and Disposition (WTN) Page: 2 of 2

(j) (k) (l) (m) (n) (o) (p) (q) (r) (s) (t)

Line

No. Year Month

GCR

WTN

Purchase

Volumes

GCC

WTN

Purchase

Volumes

Total

GCR/GCC

WTN

Purchase

Volumes Gas in Kind

Total

Supply


1 59,825 10,276 70,101

2 2019 NOVEMBER 0 0 424 12,066 (1,615) 58,210 105 10,382 (1,509) 68,592

3 DECEMBER (659) (147) (806) 462 11,693 (8,362) 49,848 (1,349) 9,033 (9,712) 58,880

4 2020 JANUARY (1,294) (289) (1,584) 698 11,151 (13,589) 36,259 (2,186) 6,847 (15,774) 43,106

5 FEBRUARY (1,872) (419) (2,291) 603 9,493 (12,778) 23,481 (1,862) 4,985 (14,639) 28,467

6 MARCH (2,287) (511) (2,798) 581 9,820 (3,428) 20,053 38 5,023 (3,390) 25,076

7 Winter 19-20 Total (6,112) (1,367) (7,479) 2,768 54,223 (39,772) (5,253) (45,024)

GCC Storage GCR and GCC Total StorageGCR Storage

STATE OF MICHIGAN




Gas Cost Recovery Plan, 5-year Forecast, and )

Monthly GCR Factor for the 12 months ending ) Case No. U-20236

March 31, 2020 )

)

QUALIFICATIONS

AND

DIRECT TESTIMONY

OF

TIMOTHY J. KRYSINSKI

DTE GAS/ELECTRIC COMPANY

QUALIFICATIONS OF TIMOTHY J. KRYSINSKI

Line

No.

TJK-1

Q1. What is your name and address, and by whom you are employed? 1

A1. My name is Timothy J. Krysinski. My business address is One Energy Plaza, Detroit, 2

Michigan 48226. I am employed by DTE Energy Corporate Services, LLC (DTE 3

Energy) as a Principal Project Manager in the Regulatory Affairs Gas Strategy group. 4

5


A2. I have a Bachelor degree in Accounting and a Master of Science degree in Finance. 7

Both degrees were earned from Walsh College in Troy, Michigan. 8

9

Q3. Do you hold any professional designations? 10

A3. I am a CPA. My certification is from the Board of Examiners of the University of 11

Illinois. 12

13

Q4. Have you had other regulatory training? 14

A4. I have attended seminars on various regulatory topics held by the American Gas 15

Association and the Edison Electric Institute. I also completed a week-long Advanced 16

Regulatory Studies Program given by the Institute of Public Utilities. 17

18

Q5. What is your work experience? 19

A5. I joined DTE Energy in 2002 as part of the Controllers Budget, Forecast and 20

Reporting group where I was primarily responsible for internal management 21

reporting. Early in 2005, I accepted the position of Senior Project Analyst in the 22

Facilities, Design and Construction organization where I managed the capital 23

T. J. KRYSINSKI

Line U-20236

No.

TJK-2

appropriation process in support of their asset preservation program. Late in 2005, I 1

transferred back into the Controllers organization, into the Asset Management 2

department in a Senior Business Financial Analyst role. My initial focus was to assist 3

with implementation of the first wave of the enterprise business solution (EBS) 4

migration to SAP. Subsequent responsibilities included budget appropriations, 5

capital project tracking, Sarbanes-Oxley compliance testing, and depreciation work. 6

In 2009, I transferred to a decision support role for Distribution Operations where I 7

provided financial support to the regional managers responsible for Service 8

Operations. In June 2013, I moved to the Regulatory Accounting & Strategy group 9

within the Controllers organization where my responsibilities included researching 10

regulatory accounting issues, drafting white papers, and participating in case filings. 11

In April 2015, I was asked to return to the Asset Management department to assist 12

with conversion activities associated with the launch of the PowerPlan asset system. 13

In July 2016, I transferred to the Regulatory Affairs organization. I was promoted to 14

Principal Project Manager in May 2018. Prior to joining DTE Energy, I spent several 15

years working at various positions in the Accounting department and in the Customer 16

Service organization at TRW Occupant Safety Systems located in Washington, 17

Michigan. 18

19

Q6. What are your responsibilities in your current position? 20

A6. My primary responsibilities are monitoring proceedings before the Federal Energy 21

Regulatory Commission (FERC) and the National Energy Board (NEB) of Canada 22

with the purpose of participating in proceedings that could materially affect DTE Gas 23

and its customers. Participation can mean filing comments, or filing as an intervenor, 24

and/or active, ongoing participation in contested cases or settlement talks. Additional 25

T. J. KRYSINSKI

Line U-20236

No.

TJK-3

responsibilities include forecasting rates for DTE Gas’s interstate pipeline 1

transporters, participating in DTE Gas’s GCR proceedings before the Michigan 2

Public Service Commission (MPSC), and researching issues related to Federal 3

regulatory matters. 4

5

Q7. Have you previously testified before any regulatory body? 6

A7. Yes, I sponsored testimony to the MPSC in Case Nos. U-17762; U-17763; U-17941-7

R; U-18152; U-18412; and U-20076. I also adopted testimony in MPSC Case No. 8

U-17691-R. 9

DTE GAS COMPANY

DIRECT TESTIMONY OF TIMOTHY J. KRYSINSKI

Line

No.

TJK-4



A8. My testimony provides an overview of substantive Federal regulatory issues that 3

affect DTE Gas and activities conducted by DTE Gas before the FERC and the NEB 4

to minimize costs incurred under its interstate and its Canadian inter-provincial 5

pipeline transportation agreements. I also sponsor certain gas transportation cost 6

assumptions that Witness Schiffer uses to develop the forecast of gas costs from DTE 7

Gas’s pipeline transporters. Specifically, my testimony addresses: 1) DTE Gas’s 8

Federal regulatory policies related to pipeline transporters; 2) Order 849, FERC’s 9

final ruling in Docket Nos. RM18-11-000, RP18-415-000; 3) The forecast rates for 10

ANR Pipeline Company’s (ANR) firm transportation services; and 4) The firm 11

transportation rate forecast for DTE Gas’s other transportation suppliers. These other 12

pipelines are Viking Gas Transmission Company (Viking), Great Lakes Gas 13

Transmission Limited (Great Lakes), Panhandle Eastern Pipe Line Company 14

(Panhandle), NEXUS Gas Transmission, LLC (NEXUS), Vector Pipeline L.P. 15

(Vector), and DTE Michigan Gathering Company (DTE Gathering). 16

17


A9. Yes. I am sponsoring the following exhibit: 19


A-19 Forecast ANR, Viking, Great Lakes, Panhandle, NEXUS, Vector, 21

and DTE Gathering Rates. 22

23

Q10. Was this exhibit prepared by you or under your direction? 24

A10. Yes, it was. 25

DTE GAS COMPANY

DIRECT TESTIMONY OF TIMOTHY J. KRYSINSKI

Line

No.

TJK-5

Federal Regulatory Policies 1

Q11. What are DTE Gas’s Federal regulatory policies as they relate to its interstate 2

pipeline transporters? 3

A11. It is DTE Gas’s policy to monitor all rate-related applications filed with the FERC 4

and the NEB by interstate and inter provincial pipelines that provide service to DTE 5

Gas and intervene in those proceedings that may significantly impact DTE Gas’s cost 6

of gas. DTE Gas also monitors FERC rulemaking proceedings affecting pipeline 7

regulation and follows other FERC and NEB activities that could ultimately affect 8

DTE Gas’s pipeline transporters. 9

10

Order 849 Final Rule on FERC Tax NOPR 11

Q12. What initial action did FERC take in 2018 related to the Tax Cuts and Job Act 12

(TCJA)? 13

A12. On March 31, 2018, FERC issued a notice of proposed rulemaking (NOPR) 14

proposing a process to allow interested parties to determine which jurisdictional 15

natural gas pipelines may be collecting unjust and unreasonable rates. Specifically, 16

FERC proposed to require interstate natural gas pipelines to file an informational 17

filing with FERC (a one-time report on the effect of the reduced federal corporate 18

income tax rate as a result of the TCJA). The one-time report, called FERC Form 19

No. 501-G, was designed to collect financial information to evaluate the impact of 20

the TCJA. In addition to the one-time report, FERC proposed four options for each 21

interstate natural gas pipeline, which would allow it to voluntarily make a filing to 22

address the changes to the pipeline’s recovery of tax costs, or explain why no action 23

is needed:24

25

T. J. KRYSINSKI

Line U-20236

No.

TJK-6

(1) File a limited NGA section 4 filing to reduce the pipeline’s rates to reflect the 1

decrease in the federal corporate income tax rate, 2

(2) Make a commitment to file a general NGA section 4 rate case in 2018, 3

(3) File a statement explaining why an adjustment to its rates is not needed, or 4

(4) Take no action other than filing the one-time report. 5

6

Q13. What subsequent action did the FERC take after issuing the NOPR? 7

A13. On July 18, 2018, FERC issued Order No. 849, a Final Rule adopting procedures for 8

determining which jurisdictional natural gas pipelines may be collecting unjust and 9

unreasonable rates considering the federal tax reductions provided by the TCJA. The 10

Final Rule adopted the procedures outlined in the NOPR – and included an additional 11

incentive for pipelines to choose option (1) make a limited NGA section 4 rate 12

reduction filing. The Final Rule includes a guarantee that the Commission will not, 13

for a three-year moratorium period, initiate an NGA section 5 rate investigation of a 14

pipeline that makes such a filing, if that filing reduces the pipeline’s ROE to 12 15

percent or less. 16

17

Q14. What is the current status related to Order 849? 18

A14. Pipelines were required to file the Form 501-G on one of three dates (dependent on 19

which group they are in). Group I: the filing due date was October 11, 2018; Group 20

II: the filing due date was November 8, 2018; Group III: the filing due date was 21

December 6, 2018. 22

T. J. KRYSINSKI

Line U-20236

No.

TJK-7

Q15. Has DTE Gas intervened in any of the filings made as a result of Order 849? 1

A15. Yes, DTE Gas is an intervenor in Docket RP19-60-000 Vector’s filing of Form 501-2

G; Docket RP19-61-000 Vector’s contemporaneous filing of a limited section 4 rate 3

reduction based on their Form 501-G filing; and Docket RP19-78-000 Panhandle’s 4

Form 501-G filing. These three filings were made on October 11, 2018. DTE Gas 5

also intervened in four filings made on December 6, 2018: one by ANR, two filings 6

made by Great Lakes, and one by Viking. Those Dockets are: RP19-403-000; RP19-7

399-000; RP19-409-000; and RP19-386-000 respectively. 8

9

Q16. What is the status of Docket Nos. RP19-60-000 and RP19-61-000; the Form 501-10

G and the limited section 4 rate reduction filed by Vector? 11

A16. FERC issued a letter on November 15, 2018 accepting Vector’s Form 501-G filing; 12

and accepting Vector’s filing of a limited section 4 rate reduction of 9.3% to become 13

effective December 1, 2018. 14

15

Q17. Since the FERC accepted Vector’s rate reduction; will that mean DTE Gas’s 16

transportation rates with Vector will be reduced? 17

A17. No, the current DTE Gas transport contract with Vector is at a discounted rate below 18

the reduction of 9.3% as filed in the limited section 4 filing. Further, Vector projects 19

for 2019 “…that 99.6% of its transportation revenues will be derived from negotiated 20

rate and lease agreements (70.2%), or from discounted rate agreements (29.4%), of 21

which all are at rates below those proposed in the limited Section 4 filing.” 22

23

T. J. KRYSINSKI

Line U-20236

No.

TJK-8

Q18. What is the status of Panhandle’s Form 501-G filing? 1

A18. Panhandle filed their Form 501-G under Docket RP19-78-000, and chose Option (3), 2

by filing a statement that no adjustment is warranted at this time. Panhandle filed an 3

Addendum with its Form No. 501-G, which reflects certain adjustments that 4

Panhandle believes are necessary to properly reflect its situation. On November 5, 5

2018 Panhandle filed a revised Exhibit A to its addendum because “…the regulatory 6

liability reflecting the excess accumulated deferred income taxes shown on page 2, 7

line 17, Other Regulatory Liabilities, was inadvertently omitted.” Currently, there are 8

over thirty separate interventions in this Docket. Several intervenors filed comments 9

and protests along with their interventions. Some intervenors urged the FERC to take 10

action under an NGA section 5 show cause proceeding or stated the adjustments made 11

by Panhandle are unwarranted and unsupported. 12

13

Q19. Does DTE Gas have transportation contracts at Panhandle’s maximum rates? 14

A19. Yes, DTE Gas has two transport contracts at the maximum rates: Maximum Rate 15

EFT Contract No. 17908; and Maximum Rate FT Contract No. 18474. Both 16

contracts have terms that do not end prior to 2028. 17

18

Q20. Will DTE Gas continue to intervene in Panhandle’s proceeding under Docket 19

RP19-78-000? 20

A20. Yes, because the outcome of this proceeding could impact DTE Gas and its 21

customers. 22

T. J. KRYSINSKI

Line U-20236

No.

TJK-9

Q21. What is the status of ANR’s Form 501-G filing? 1

A21. ANR filed their Form 501-G under Docket RP19-403-000, and chose Option (3), by 2

filing a statement that no adjustment is warranted at this time. ANR filed an 3

Addendum with its Form No. 501-G, which reflects certain adjustments that ANR 4

believes are necessary to properly reflect its situation. 5

6

Q22. Will DTE Gas continue to intervene in ANR’s proceeding under Docket RP19-7

403-000? 8

A22. Yes, because the outcome of this proceeding could impact DTE Gas and its 9

customers. 10

11

Q23. What is the status of Docket Nos. RP19-399-000 and RP19-409-000; the Form 12

501-G and the limited section 4 rate reduction filed by Great Lakes? 13

A23. At the time this testimony was written, several parties have intervened in both cases. 14

Some have filed comments or protests. It is uncertain if FERC will accept the Great 15

Lakes filings, or take some other action. 16

17

Q24. Will DTE Gas continue to intervene in the two Great Lake’s proceedings under 18

Docket Nos. RP19-399-000 and RP19-409-000? 19

A24. Yes, because the outcome of these proceedings could affect DTE Gas and its 20

customers. 21

22

Q25. What is the status of Viking’s Form 501-G filing? 23

A25. Viking filed their Form 501-G under Docket RP19-386-000, and chose Option (3), 24

by filing a statement that no adjustment is warranted at this time. Viking states that 25

T. J. KRYSINSKI

Line U-20236

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TJK-10

it is currently preparing for settlement discussions with its shippers, which will 1

commence in January 2019. Viking’s current rates were set by the Stipulation and 2

Agreement approved by the Commission in Docket No. RP14-1185-000. As part of 3

that agreement, Viking committed to initiate a pre-filing settlement process no later 4

than January 31, 2019, and, unless Viking submits a pre-filing settlement, it must file 5

a general section 4 rate case under the Natural Gas Act (“NGA”) with rates effective 6

no later than January 1, 2020. 7

8

Q26. Will DTE Gas continue to be an intervenor in the Viking Form 501-G filing? 9

A26. Yes. 10

11

Q27. Does DTE Gas also plan to participate in the upcoming settlement discussions 12

with Viking and other shippers (proposed to start in January 2019)? 13

A27. Yes, because the outcome of the proposed settlement discussions will impact DTE 14

Gas and its customers. 15

16

Rate Forecast Summary for DTE Gas’s Transportation Providers 17

Q28. What assumptions have you provided to Witness Schiffer regarding DTE Gas’s 18

gas transportation rates from ANR during the forecast period? 19

A28. I assume that the settlement rates from ANR’s last rate case (Docket No. RP16-440-20

000) will continue to apply to the maximum rate contracts that will be in effect at the 21

beginning of the plan period on April 1, 2019. I assume that ANR’s settlement rates 22

will remain effective for the duration of the five-year plan. I also assume that ANR’s 23

fuel retention percentages and Electric Compression Charge approved in Docket No. 24

RP18-490-000 will continue to be in effect through the end of the plan period. The 25

T. J. KRYSINSKI

Line U-20236

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TJK-11

rates and fuel charges related to the ANR transportation contracts are shown in 1

Exhibit A-19, page 1 of 7. 2

3

Q29. Why is some level of estimated reduction related to FERC Order 849 not 4

included in the ANR rate assumptions?5

A29. At the time of writing this testimony, it is uncertain whether FERC will accept ANR’s 6

filing (as submitted, with no reduction in rates); or whether FERC will take some 7

other action. 8

9

Q30. What do you assume regarding the discounted rate firm transport contracts that 10

DTE Gas holds on ANR? 11

A30. I assume that the fixed discount rate that applies will remain unchanged during the 12

plan period. I included ANR’s discounted transportation rates in Exhibit A-19, page 13

1 of 7. 14

15

Q31. What assumptions have you provided to Witness Schiffer with respect to Viking 16

transportation costs billed to DTE Gas? 17

A31. I assume that Viking’s FERC-approved term-differentiated rates reached in the 18

Viking Settlement in Docket No. RP14-1185-000, which became effective on 19

January 1, 2014, will remain in effect through the end of the plan period. Exhibit A-20

19, page 2 of 7 includes my forecast of Viking rates starting April 1, 2019. 21

22

Q32. Do you assume that Viking’s FT-A Category 3 reservation rate will apply to 23

DTE Gas throughout the plan period? 24

A32. Yes. 25

T. J. KRYSINSKI

Line U-20236

No.

TJK-12

Q33. Why is some level of estimated reduction not included in the Viking rate 1

assumptions? 2

A33. As stated above, Viking chose Option (3), by filing a statement that no adjustment is 3

warranted at this time. At the time of writing this testimony, it is uncertain whether 4

FERC will accept Viking’s filing (as submitted), or whether FERC will take some 5

other action. Further, it is not known whether the proposed, future settlement 6

discussions between Viking and its shippers will result in a decrease (or potentially 7

an increase), as compared to the current maximum recourse rates. 8

9

Q34. What do you assume regarding Viking’s fuel charges? 10

A34. I assume that Viking’s fuel charges during the plan period will be the same as those 11

included in Viking’s most recent fuel filing with the FERC, which is found in Docket 12

RP18-1249-000. FERC issued a letter order accepting the filing on October 29, 2018. 13

Exhibit A-19, page 2 of 7, shows the projected Viking rates starting April 1, 2019. 14

15

Q35. What assumptions have you provided to Witness Schiffer regarding the 16

transport costs DTE Gas incurs on Great Lakes? 17

A35. I assume that the settlement rates that were filed in Docket RP17-598-000, and 18

subsequently approved by FERC on February 22, 2018 will remain in effect for the 19

duration of the plan period. Great Lake’s forecast rates and fuel retention percentages 20

are provided in Exhibit A-19, page 3 of 7. 21

T. J. KRYSINSKI

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Q36. Why is some level of estimated reduction not included in the Great Lake’s rate 1

assumptions? 2

A36. As stated above, Great Lakes chose option (1) wherein they filed a contemporaneous 3

limited section 4 rate reduction. The rate reduction is not reflected in their Form 501-4

G filing. Great Lakes instead made additional changes to their Form 501-G filing in 5

the attempt to share some of the benefit of the tax reduction with their shippers. Yet, 6

at the time of this testimony writing, it is not certain that FERC will accept Great 7

Lake’s filed reduction of 2%, or whether FERC will take some other action. 8

9

Q37. What assumptions have you provided to Witness Schiffer regarding 10

transportation fuel costs DTE Gas incurs on Great Lakes? 11

A37. Great Lakes revises its fuel charges monthly, and the monthly fuel charges can vary 12

significantly due, in part, to the reconciliation of fuel over and under recoveries. So, 13

I assume that Great Lake’s average fuel retention percentages for the 12 months 14

ending November, 2018 will apply during the plan period. Great Lakes’ forecast 15

rates and fuel retention percentages are provided in Exhibit A-19, page 3 of 7. 16

17

Q38. What assumptions have you provided to Witness Schiffer with respect to DTE 18

Gas transportation costs on Panhandle? 19

A38. I project that Panhandle’s currently effective maximum tariff rates that apply to the 20

Field Zone to DTE Gas firm contracts will remain in effect through March, 2024. 21

T. J. KRYSINSKI

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TJK-14

Q39. Why is some level of estimated reduction not included in Panhandle’s rate 1

assumptions? 2

A39. At the time of writing this testimony, it is uncertain whether FERC will accept 3

Panhandle’s filing (as submitted, with no reduction in rates); or whether FERC will 4

take some other action. 5

6

Q40. What rate assumptions do you make regarding discounted Panhandle Contract 7

No. 45114? 8

A40. FT Contract No. 41525 from Panhandle’s Field Zone to DTE Gas has a discount term 9

that is in effect until March 31, 2020. I assume the discounted rate will end at that 10

point, and the current maximum rate for that path will apply beginning April 1, 2020 11

for the remainder of the plan period. 12

13

Q41. What assumptions do you provide with respect to Panhandle’s fuel rates? 14

A41. I project that Panhandle’s fuel rate during the plan period will be the same as the 15

applicable fuel rate filed for in Docket No. RP18-1236-000. This is Panhandle’s most 16

recent fuel filing which was approved by the FERC on October 29, 2018. 17

Panhandle’s forecast transportation and fuel rates are contained in Exhibit A-19, page 18

4 of 7. 19

20


Gas transportation costs on NEXUS? 22

A42. I assume that the rates contained in the Negotiated Rate Agreement (NRA) dated 23

October 23, 2018 which was filed with the FERC on October 31, 2018, and accepted 24

by FERC letter order on November 29, 2018 (Docket RP19-183-000), will apply to 25

T. J. KRYSINSKI

Line U-20236

No.

TJK-15

the plan period. The forecast showing NEXUS’s transportation rates are contained 1

in Exhibit A-19, page 5 of 7. 2

3

Q43. What is the ACA surcharge and why is it not a component of the NEXUS 4

forecast rates prior to October 2020? 5

A43. Each interstate natural gas pipeline company may adjust its rates annually to recover 6

from its customers the annual charges assessed on the pipeline by the Commission. 7

This is the Annual Charge Adjustment clause (ACA clause) as stated in the Code of 8

Federal Regulations section §154.402. The required annual charge must be paid by 9

the pipeline company to the Commission (for the current fiscal year) before the 10

company can then collect the ACA unit charge from its customers. NEXUS has not 11

been charged ACA by the Commission. Further, it is expected that NEXUS will not 12

be charged ACA until the first full Commission fiscal year ending on September 30, 13

2019. Therefore, NEXUS cannot incorporate that surcharge into their tariff before 14

October 2020. 15

16

Q44. Did NEXUS file a Form 501-G? 17

A44. No, NEXUS was not required to file the Form 501-G. NEXUS did not provide 18

service as an interstate pipeline in 2017. The specific language in the Form 501-G 19

states, “Each natural gas company, as defined in the NGA, that is required under this 20

Part to file a Form No. 2 or 2A in 2018 for 2017 and has cost-based rates for service 21

under any rate schedule that were filed electronically pursuant to Part 154 of the 22

Commission regulations must file the report with the Commission…” 23

T. J. KRYSINSKI

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Q45. What assumptions do you provide with respect to NEXUS’s fuel rates? 1

A45. I assume that the Applicable Shrinkage Adjustment (ASA) percentages contained in 2

the NEXUS FERC NGA Gas Tariff Original Volume No. 1 Part 4 will apply. The 3

tariff was filed with the FERC on August 1, 2018; and accepted by FERC on 4

September 12, 2018 in Docket RP18-1037-000. The Applicable Shrinkage 5

Adjustment percentage (ASA Percentage) is shown on Exhibit A-19, page 5 of 7. 6

7

Q46. What assumptions have you provided to Witness Schiffer with respect to Vector 8

transportation costs? 9

A46. I assume that the discounted rate in FT Contract No. FT1-MCG-5676 will be in effect 10

throughout the entire plan period. 11

12

Q47. What assumptions do you provide with respect to Vector’s fuel rates? 13

A47. Vector revises its fuel rates and reconciles over and under recoveries on a monthly 14

basis. Therefore, I based Vector’s fuel charge forecast on Vector’s average fuel 15

retention percentages for the period between December, 2017 and November, 2018. 16

Vector’s forecast transportation and fuel rates are presented in Exhibit A-19, page 6 17

of 7. 18

19


Gas transportation costs on DTE Gathering? 21

A48. I assume that the transportation agreement signed by DTE Gas and the associated 22

contract rate as listed on the rate page dated July 18, 2016 will remain in effect 23

throughout the plan period. The rate is presented on Exhibit A-19, page 7 of 7. 24

25

T. J. KRYSINSKI

Line U-20236

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Q49. Does this conclude your pre-filed testimony? 1

A49. Yes, it does.2

STATE OF MICHIGAN







)

EXHIBITS

OF

TIMOTHY J. KRYSINSKI


The DTE Gas Company Witness: T. J. Krysinski

Forecast ANR, Viking, Great Lakes, Panhandle, NEXUS, Exhibit: A-19

Vector, and DTE Gathering Rates Page: 1 of 7

Forecast ANR Rates ($/Dth)

(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k)

Electric

Service/ Compression

Line Effective Date Reservation Usage Reservation Usage Reservation Usage Reservation Usage Fuel % Charge

1 Southwest Fixed Maximum Rate ETS Contracts Nos. 108268, 108304

2 04/19 - 03/24 $9.7320 $0.0216 $0.0000 $0.0009 3.91% $0.0004

3 Southwest to Georgetown Fixed Maximum Rate FTS-1 Contract No. 109511

4 04/19 - 03/24 $11.0000 $0.0216 $0.0000 $0.0009 3.91% $0.0004

5 Discounted Detroit to Group 3 ML-7 ETS Contract No. 112110

6 04/19 - 03/24 $0.8963 $0.0101 $0.0000 $0.0009 0.81% $0.0004

7 Marshfield to Menominee Maximum Rate ML-7 FTS-1 Contract No. 122248

8 04/19 - 03/24 $5.7290 $0.0101 $0.0000 $0.0009 0.81% $0.0004

9 Alliance to Alpena Maximum Rate FTS-1 ML-7 Contract No. 122065

10 04/19 - 03/24 $5.7290 $0.0101 $0.0000 $0.0009 0.81% $0.0004

11 Southwest to Menominee (Winter) and Willow Run (Summer) Maximum Rate ML-7 FTS-1 Contract No. 122067

12 04/19 - 03/24 $12.4690 $0.0216 $0.0000 $0.0009 3.91% $0.0004

13 Southwest to Willow Run Maximum Rate FTS-1 Contract No. 122247

14 04/19 - 03/24 $12.4690 $0.0216 $0.0000 $0.0009 3.91% $0.0004

Southeast Area Southwest Area Northern Area Surcharges





Forecast Viking Rates ($/Dth)

(a) (b) (c) (d) (e) (f)

Line Effective Date Reservation Usage Reservation Usage Fuel %

1 Maximum Rate Contract AF0081 - Category 3 Term of 5 or more Years

2 04/19 - 03/24 $5.3593 $0.0116 $0.0000 $0.0013 0.27%

Surcharges





Forecast Great Lakes Rates ($/Dth)

(a) (b) (c) (d) (e) (f)


1 Maximum Rate Emerson to Central Zone Contract FT4634

2 04/19 - 03/24 $4.6800 0.00544 $0.0000 $0.0013 0.62% (1)

3 0.76% (2)

4 Maximum Rate Emerson to Eastern Zone Contract FT4635

5 04/19 - 03/24 $8.3530 0.00954 $0.0000 $0.0013 0.97% (3)

(1) Fuel for deliveries to Rapid River in the Central Zone (8 fuel segments).

(2) Fuel for deliveries to Mackinac, S.S. Marie, Pellston, and Gaylord in the Central Zone (10 fuel segments).

(3) Fuel for deliveries to Belle River in the Eastern Zone (13 fuel segments).

Surcharges





Forecast Panhandle Rates ($/Dth)

(a) (b) (c) (d) (e) (f)


1 Field Zone to DTE Gas (801 to 900 miles) - Maximum Rate EFT Contract No. 17908

2 04/19 - 03/24 $13.4300 $0.0423 $0.0000 $0.0013 4.10%

3 Field Zone to DTE Gas (801 - 900 miles) - Maximum Rate FT Contract No. 18474

4 04/19 - 03/24 $12.9300 $0.0423 $0.0000 $0.0013 4.10%

5 Field Zone to DTE Gas (801 to 900 miles) - Winter Only Discount Rate FT Contract No. 45114

6 04/19 - 03/20 $12.9050 $0.0423 $0.0000 $0.0013 4.10%

7 04/20 - 03/24 $12.9300 $0.0423 $0.0000 $0.0013 4.10%

Surcharges





Forecast NEXUS Rates ($/Dth)

(a) (b) (c) (d) (e) (f)

Line Effective Date Reservation Usage Reservation Usage Fuel

1 Meter # N4995 NEXUS Interconnect with TELP Mainline, Clarington, OH to Meter # N1001 Ypsilanti, MI

2 04/19 - 09/20 $25.7021 $0.0000 $0.0000 $0.0000 1.91%

3 Meter # N4995 NEXUS Interconnect with TELP Mainline, Clarington, OH to Meter # N1001 Ypsilanti, MI

4 10/20 - 10/22 $25.7021 $0.0000 $0.0000 $0.0013 1.91%

5 Meter # N2002 NEXUS/Kensington Head of Phase II Ohio to Meter # N1001 Ypsilanti, MI

6 04/19 - 09/20 $21.1396 $0.0000 $0.0000 $0.0000 1.32%

7 Meter # N2002 NEXUS/Kensington Head of Phase II Ohio to Meter # N1001 Ypsilanti, MI

8 10/20 - 03/24 $21.1396 $0.0000 $0.0000 $0.0013 1.32%

Surcharges





Forecast Vector Rates ($/Dth)

(a) (b) (c) (d) (e) (f)


1 Vector U.S. - Chicago to MichCon - Discounted FT Contract No. FT1-MCG-5676

2 04/19 - 03/24 $4.2583 $0.0000 $0.0000 $0.0013 0.52%

Surcharges





Forecast DTE Michigan Gathering Rates ($/Dth)

(a) (b) (c) (d) (e) (f)

Line Effective Date Reservation Usage Reservation Usage Fuel

1 FT - Kalkaska-MichCon to Kalkaska-DTE Gas / Consumers-Goose Creek / Kalkaska-ANR / GLGT-Goose Creek - ASAT: 62078

2 04/19 - 03/24 $0.0000 $0.03626 $0.0000 $0.0000 0.00%

Surcharges

STATE OF MICHIGAN







)

QUALIFICATIONS

AND

DIRECT TESTIMONY

OF

SHERRI M. MOORE

DTE GAS COMPANY

QUALIFICATIONS OF SHERRI M. MOORE

Line

No.

SMM-1

Q1. What is your name and business address? 1

A1. My name is Sherri M. Moore. My business address is One Energy Plaza, Detroit, 2

Michigan 48226. 3

4


A2. I am employed by DTE Energy Corporate Services, LLC as a Senior Strategist in 6

Regulatory Affairs. 7

8


A3. I received a Bachelor of Science Degree in Business from Wayne State University 10

and a Master of Science in Finance with a concentration in Economics from Walsh 11

College in 2013. 12

13

Q4. What is your employment history with DTE Energy? 14

A4. I have been employed full time with DTE Energy’s companies since 1999. From 15

2000 to 2010, I performed various roles as an Analyst in DTE Electric Company 16

(DTE Electric) within the Generation Optimization, Portfolio Analyst Group and 17

Fossil Generation and Strategic Planning Departments. From 2010 to 2012, I joined 18

DTE Gas Company (DTE Gas) as an Energy Analyst in the Gas Supply and Planning 19

Department where I assisted DTE Gas’s Gas Supply witness in the preparation of the 20

five-year operating forecast including required gas purchases for the annual GCR 21

Plan Case and assisted in the development of testimony and exhibits for the annual 22

GCR Plan Case and annual reconciliation of GCR gas costs. From 2012 to 2013, I 23

returned to DTE Electric as a Principal Market Planner in the Electric Choice Group 24

with the primary responsibility of ensuring adherence to Electric Choice program 25

http://www.cis.state.mi.us/bcs_corp/dt_llc.asp?id_nbr=D1016J&name_entity=DTE%20ENERGY%20CORPORATE%20SERVICES,%20LLC

S. M. MOORE

Line U-20236

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design requirements and procedures, and lead development and maintenance of 1

program design changes, as needed. I was also responsible for identifying existing 2

and proposed financial, legal and regulatory issues that may impact program success. 3

In 2014, I returned to DTE Gas as a Senior Gas Supply & Planning Analyst in the 4

Gas Supply and Planning Department. I am currently a Senior Strategist in the 5

Regulatory Affairs DTE Gas Strategy department. 6

7

Q5. Have you been involved in any prior regulatory proceedings? 8

A5. Yes. I have sponsored testimony before the MPSC in several cases including the 9

following: 10

U-17332-R: DTE Gas 2014-15 GCR Reconciliation 11

U-17691: DTE Gas 2015-16 GCR Plan 12


U-17941: DTE Gas 2016-17 GCR Plan 14


U-18152: DTE Gas 2017-18 GCR Plan 16

U-20076: DTE Gas 2017-18 GCR Plan Reconciliation 17

18

I have also provided support for DTE Gas’s Gas Supply witnesses in GCR Plan and 19

reconciliation cases from 2010 through 2012 and DTE Electric’s PSCR witnesses 20

from 2000 through 2010. 21

DTE GAS COMPANY

DIRECT TESTIMONY OF SHERRI M. MOORE

Line

No.

SMM - 3



A6. My testimony addresses: 1) the calculation of DTE Gas’s proposed April 2019 3

through March 2020 monthly base GCR factor; 2) the contingent mechanism and its 4

implementation; 3) the five-year forecasted cost of gas; and 4) the administration of 5

DTE Gas’s Supplier of Last Resort (SOLR) Reservation Charge. 6

7




A-20 Derivation of April 2019 through March 2020 GCR Factor 11

A-21 Forecasted Cost of Gas April 2019 – March 2024 12

A-22 Calculation of LIFO Rate and Storage Costs 13

A-23 Proposed Contingent Factor Matrix Tariff Sheet 14

A-24 Contingent Factor Calculations 15

A-28 Calculation of Reservation Charge Applied to GCC and GCR 16

Customers 17

18


A8. Yes, they were.20

S. M. MOORE

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SMM - 4

APRIL 2018 THROUGH MARCH 2019 MAXIMUM BASE GCR FACTOR 1

Q9. What is DTE Gas’s proposed maximum base GCR factor (GCR factor) for April 2

2019 through March 2020? 3

A9. DTE Gas proposes a maximum GCR factor of $2.80 per Mcf for the April 2019 4

through March 2020 operational year (“GCR Year” or “Year”). This maximum 5

factor can be adjusted monthly based upon a contingent factor matrix, which is 6

detailed later in my testimony, to reflect changes in DTE Gas’s cost of gas resulting 7

from higher market prices. 8

9

Q10. How is the GCR factor of $2.80 per Mcf calculated? 10

A10. The GCR factor is calculated by dividing the Adjusted Cost of Gas Less Reservation 11

Charge Revenue incurred for the Year plus any estimated over or (under) recovery 12

from the prior GCR Period by the Year’s Adjusted Sales Volumes. The detailed 13

calculations used to determine the GCR factor are included in Exhibit A-20. This 14

methodology has been used to calculate the GCR factor and all its components in 15

DTE Gas’s previous GCR cases. 16

17

Q11. Are the Reservation Charge revenues removed from the Adjusted Cost of Gas? 18

A11. Yes, the Reservation Revenue is calculated on lines 20-24, and totals $52 million, 19

which is shown on line 25. This amount is slightly different from the Adjusted 20

Pipeline Reservation Cost due to rounding. The Reservation Charge revenue is 21

subtracted from the Adjusted Cost of Gas, shown on line 17, to produce the Adjusted 22

Cost of Gas Less Reservation Charge Revenue, which is $334 million, shown on line 23

26. 24

S. M. MOORE

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Q12. What are the components of the Adjusted Cost of Gas? 1

A12. The Adjusted Cost of Gas includes: 1) the Total Booked Cost of Gas Sold and 2) the 2

March 2020 Unbilled Revenue Adjustment. 3

4

Q13. What are the components of the Total Booked Cost of Gas Sold? 5

A13. The Total Booked Cost of Gas Sold, calculated in Exhibit A-20, includes the cost of: 6

1) Purchased Gas; 2) Gas (To)/From Storage; 3) Company Use Gas; 4) Lost and 7

Unaccounted for Gas; and 5) Gas in Kind. 8

9

Q14. How is the cost of gas injected into or withdrawn from storage calculated? 10

A14. DTE Gas uses annual last in, first out (LIFO) accounting to calculate its cost of gas. 11

Each calendar year’s LIFO rate is calculated by dividing the annual cost of purchased 12

gas by the total annual volume of purchased gas for that year. If, on a net basis, gas 13

is injected into storage in a calendar year, then an increment is created. The increment 14

is priced using that year’s LIFO rate and a LIFO layer is created. If, on a net basis, 15

gas is withdrawn from storage in the calendar year, then there is a decrement. The 16

cost of storage gas withdrawn for a decrement is calculated using the most recent 17

LIFO layer or layers injected into storage. The calculation of LIFO rates and cost of 18

storage for January 2018 through March 2023 is included in detail in Exhibit A-22. 19

20

Q15. What is the cost of 2019 storage in this GCR period? 21

A15. A net increment is forecasted for calendar year 2019. This increment is priced at the 22

2019 LIFO rates and is calculated on page 2 of Exhibit A-22. The cost of storage gas 23

for the calendar year is calculated on page 1, in lines 15 through 28. The impact of 24

storage gas for the period April through December 2019, a $118 million decrease in 25

the cost of gas, is calculated by summing the cost of storage gas for those months. 26

S. M. MOORE

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Q16. What is the cost of storage gas for the January through March 2020 period? 1

A16. The cost of storage gas used during the January through March 2020 period is based 2

on the projected $2.92 per Mcf LIFO rate for 2020. In these three months, 37 Bcf is 3

withdrawn and included in the Year’s cost of gas at a total cost of $108 million. The 4

net impact of storage gas for the GCR Year is a $11 million decrease to the cost of 5

gas. 6

7

Q17. Have you included any provision for an over- or (under)recovery from the 2017– 8

2018 GCR period? 9

A17. Yes. At the time of this filing, DTE Gas projects that it will incur a $26 million under 10

recovery for the GCR year ending March 31, 2018. 11

12

Q18. What rate is used to calculate the cost of gas used by the Company, lost and 13

unaccounted for, and received in kind? 14

A18. The jurisdictional rate is used to calculate these costs. This rate, $3.09 15

per Mcf, calculated in Exhibit A-20, reflects the average cost of gas purchased for 16

the Year. 17

18

Q19. Why is it necessary to adjust the Total Booked Cost of Gas Sold by the Unbilled 19

Revenue Adjustment? 20

A19. The Unbilled Revenue Adjustment recognizes the revenue effect of volumes that are 21

delivered to GCR customers in March 2020 but are not billed until April 2020 at the 22

April 2020 GCR factor. This adjustment is calculated in lines 11 through 15 in 23

Exhibit A-20. 24

S. M. MOORE

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Q20. How are the Adjusted Sales Volumes calculated on Exhibit A-20? 1

A20. The Adjusted Sales Volumes are calculated by subtracting the March 2019 Unbilled 2

Volume Balance from the Year’s Billed Sales Volumes. This adjustment for March 3

2019 unbilled volumes recognizes that the revenues related to volumes delivered to 4

GCR customers in March 2019 but billed for in April 2019 are included in the 2018 5

- 2019 GCR reconciliation. 6

7

FORECASTED COST OF GAS 8

Q21. How did you calculate the forecasted cost of gas for the operational years April 9

2020 – March 2024 included in Exhibit A-21? 10

A21. To calculate the forecasted cost of gas for the operational years April 2020-March 11

2024, I used the same methodology and sources I used to calculate Exhibit A-20. 12

This exhibit shows DTE Gas’s forecasted cost of gas for the four remaining 13

operational years of this GCR plan case. 14

15

CONTINGENT MECHANISM 16

Q22. What is the purpose of DTE Gas’s contingent factor matrix? 17

A22. DTE Gas’s proposed contingent factor matrix allows DTE Gas to mitigate an under-18

recovery that would result from an increase in market prices above those used in the 19

GCR Plan. Without a contingent mechanism, the incremental costs resulting from 20

such a price increase cannot be recovered during the GCR year using the base GCR 21

factor. Any under-recovery resulting from increases in market prices would be rolled 22

forward into the next year’s GCR calculation, shifting costs from one year to another. 23

DTE Gas’s contingent factor matrix mitigates this cost shifting by allowing the GCR 24

S. M. MOORE

Line U-20236

No.

SMM - 8

factor to reflect specific amounts contingent on future market information. The tariff 1

sheet containing the contingent factor matrix is provided in Exhibit A-23. 2

3

Q23. What methodology did DTE Gas use to develop its contingent factor matrix? 4

A23. DTE Gas used a single-input methodology first approved by the Commission in DTE 5

Gas’s 2010 - 2011 GCR Plan, Case No. U-16146, to develop its contingent factor 6

matrix. This methodology has been approved by the Commission in each GCR Plan 7

since that case. This method determines the factor needed, based on current market 8

prices, to recover increased costs from that point in time forward. This method 9

evaluates a single NYMEX strip to estimate the impact of changes in market prices 10

not only on the current Year’s purchases but also on the storage activity that is priced 11

at LIFO. A multiplier is used to establish the contingent factor necessary based on 12

the change in prices. 13

14

Q24. How was the multiplier determined? 15

A24. The multiplier is calculated using the average GCR factor change resulting from two 16

consecutive $1 per Dth increases in the NYMEX beginning in April of the GCR Plan 17

year. Company Witness Mr. Schiffer provided the cost estimates reflecting $1.00 per 18

Dth and $2.00 per Dth NYMEX increases above Plan levels. Using the same 19

methodology shown in Exhibit A-20, two GCR factors are calculated based on these 20

cost estimates. This calculation is performed in Exhibit A-24. The factor resulting 21

from the $1 per Dth increase is $3.13 per Mcf. The factor resulting from the $2 per 22

Dth increase is $ 3.45 per Mcf. 23

24

S. M. MOORE

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No.

SMM - 9

The original Maximum GCR factor, $ 2.80 per Mcf is subtracted from the GCR factor 1

resulting from the $1.00 per Dth NYMEX increase, $3.13 per Mcf. Next, the $1.00 2

per Dth NYMEX increase GCR factor, $3.13 per Mcf, is subtracted from the GCR 3

factor resulting from the $2.00 per Dth NYMEX increase, $3.45 Mcf. The results of 4

these subtractions, $0.32 and $0.32, respectively, are then added together and divided 5

by 2. The result of this calculation, 32.2%, is the multiplier used to calculate the 6

contingent factors. This multiplier is multiplied by $0.10 to arrive at the contingent 7

factor for a $0.10 per Dth NYMEX increase, $0.0322 per Mcf. This calculation is 8

performed for each $0.10 per Dth NYMEX increase up to $3.00 per Dth. The results 9

of the calculations are the contingent factors included in DTE Gas’s tariff sheet, 10

included on Exhibit A-23. 11

12

Q25. Is DTE Gas proposing a maximum contingent factor of $3.00 per Mcf above the 13

Plan base maximum GCR factor? 14

A25. No, DTE Gas is proposing only to reflect those costs that will be incurred if market 15

prices increase. Even if prices increased by $3.00 per Dth, or above, DTE Gas's 16

resultant maximum contingent factor would be well below the base maximum GCR 17

factor plus $3.00 per Mcf. If prices increased $3.00 per Dth above plan levels, then 18

the maximum amount DTE Gas's maximum contingent GCR factor could be is $0.97 19

per Mcf shown on Exhibit A-23, page 2. 20

21

Q26. How is the contingent factor for any given month calculated? 22

A26. All of the NYMEX averages referred to in this calculation are for the January 2019 23

through December 2020 period. First, XN, the current NYMEX average, is 24

calculated. Next, the NYMEX change is calculated. The NYMEX change is the 25

S. M. MOORE

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No.

SMM - 10

difference between the NYMEX average used to determine the most recent maximum 1

GCR factor, XN-1, and XN, which is the current NYMEX average. Once the NYMEX 2

change is calculated, the contingent factor matrix, shown on Exhibit A-23 page 2 of 3

2, is used to identify the contingent factor associated with that level of change. 4

5

If the NYMEX change is positive, then this factor is added to the current maximum 6

GCR factor. If the NYMEX change is negative, then this factor is subtracted from 7

the current maximum GCR factor. In no case will the application of the contingent 8

factor result in a maximum GCR factor below $2.80 per Mcf, even if the current 9

maximum GCR factor is $2.80 per Mcf and the NYMEX change is negative. For 10

the April factor, the contingent factor would be added to the original base GCR 11

factor. 12

13

Q27. Why are prices from months outside of the Plan period included in the NYMEX 14

averages calculated? 15

A27. January through March 2019 and April through December 2020 are included because 16

they are used to derive LIFO rates. Changes in NYMEX for these months will 17

influence the cost of storage during the plan year and impact the GCR factor. 18

19

Q28. Why are no adjustments to the market price purchases made for prices that will 20

be fixed during the year? 21

A28. It is impossible to know the price of any volumes fixed during the GCR year. Valuing 22

these volumes fixed during the year at current market prices is the best estimate 23

available of their cost during the GCR year. 24

S. M. MOORE

Line U-20236

No.

SMM - 11

Q29. How does DTE Gas plan to implement this factor? 1

A29. Prior to each month (March for April, June for July and so on), DTE Gas will make 2

an informational filing with the MPSC, in this docket, comparing the current 3

NYMEX prices to the NYMEX prices used to calculate the then current GCR factor. 4

The resulting difference for each strip will then be identified on the matrix and used 5

to indicate the contingent factor amount. This amount plus (or minus, if prices have 6

fallen) the current GCR factor will result in the maximum GCR factor for the 7

remainder of the year, or until a new GCR factor is identified using the matrix. 8

9

Q30. Is this factor applicable symmetrically? 10

A30. Yes. However, as noted above, the maximum GCR factor will never be less than 11

$2.79 per Mcf, which is the originally filed maximum base GCR factor in this case 12

13

SUPPLIER OF LAST RESORT (SOLR) 14

Q31. What is the Supplier of Last Resort? 15

A31. The Supplier of Last Resort supplies GCC customers’ gas requirements should an 16

alternative supplier fail to do so or if customers return to GCR supply from Gas 17

Customer Choice. DTE Gas agreed to fulfill this role for GCC customers as a part 18

of its voluntary GCC program. DTE Gas’s responsibility for this role is contained in 19

Section F of its tariff, paragraph F1.19. This charge was first approved by the 20

Commission in its April 15, 2014 Order in Case No. U-17131 and was re-approved 21

by the Commission in its April 23, 2015 Order in Case No. U-17332. 22

S. M. MOORE

Line U-20236

No.

SMM - 12

Q32. Have you calculated the Reservation Charge? 1

A32. Yes, Exhibit A-28 calculates the Reservation Charge on an unbilled basis. Lines 1-2

7 adjust the Pipeline Reservation Cost to remove the March 2020 unbilled revenue 3

that will be collected at the 2020-2021 rate. The unbilled balance was taken from 4

Exhibit A-4. Line 15 presents the total GCR and GCC March 2019 unbilled volume 5

balance and because any revenues associated with those volumes will be accrued into 6

the 2018-2019 GCR year, those volumes are excluded from the calculation of the 7

Reservation Charge. The adjusted Pipeline Reservation Cost, line 8, is divided by 8

the April 2019 - March 2020 Adjusted Sales Volume, line 16, to produce the April 9

2019 – March 2020 Reservation Charge, line 17, of an average rate of $0.35 per Mcf. 10

11

Q33. Have you calculated the Reservation Charge to include the 30% discount for 12

GCC customers as directed by the Commission? 13

A33. Yes, I have. As described above, Exhibit A-28, lines 1-16 calculated the Reservation 14

Charge in the manner the Company employed in prior cases. Lines 17-18 calculate 15

a GCC RC that reflects a discount of 30%, which is $0.24 per Mcf. Lines 19-21 16

calculate the Reservation Charge revenue that will be received from GCC customers, 17

subtracts that revenue from the adjusted pipeline reservation cost, and then divides 18

that net GCR pipeline cost by the appropriate GCR adjusted sales volume to produce 19

the GCR Reservation Charge on line 24. The Reservation Charge applicable to GCR 20

customers is $0.38 per Mcf. 21

22

Q34. Does the Reservation Charge remove the pipeline costs from the GCR process? 23

A34. No, it does not. The revenue received through the Reservation Charge will be treated 24

as an offset to the GCR Cost of Gas Sold. 25

26

S. M. MOORE

Line U-20236

No.

SMM - 13

Q35. Does the Company anticipate that it may change the Reservation Charge within 1

the GCR year? 2

A35. Yes, there are two main reasons DTE Gas might lower the Reservation Charge during 3

the GCR year. While pipeline costs do not normally vary from year to year, billed 4

GCR and GCC volumes do. Although DTE Gas could not increase the charge if 5

volumes were below projected levels, if volumes were higher than anticipated and a 6

large over-recovery were anticipated, then DTE Gas might lower the charge. 7

Likewise, if DTE Gas forecasts an over-recovery from the Reservation Charge, then 8

it may lower the actual charge billed from the maximum allowable charge. 9

10

Q36. Q. Does this conclude your direct testimony? 11

A36. A. Yes, it does.12

1

STATE OF MICHIGAN







)

EXHIBITS

OF

SHERRI M. MOORE



Derivation of April 2019 through March 2020 GCR Factor Witness: S. M. Moore

Page: 1 of 1

(a) (b)

Line

Calculation of Jurisdictional Rate

1 Cost of Purchased Gas 396,079$

2 Volume of Purchased Gas 128,053

3 Jurisdictional Rate Line 1 / Line 2 3.09$

Calculation of Total Booked Cost of Gas Sold


5 Cost of Gas (To)/From Storage (10,594)$

6 Company Use, Lost and Unaccounted For and Gas in Kind

7 Gas in Kind 6,270

8 Lost and Unaccounted For / Co Use (6,542)

9 Total (Line 7 + Line 8 ) * Line 3 (272) (840)$

10 Total Booked Cost of Gas Sold 384,645$

Calculation of March 2020 Unbilled Revenue Adjustment

11 2020 - 2021 Net Cost of Gas Sold $ 365,767

12 2020 - 2021 Annual Billed Sales 126,950

13 2020 - 2021 Average GCR Cost of Gas Line 11 / Line 12 $ 2.88

14 March 2020 Unbilled Volume Balance (8,601)

15 March 2020 Unbilled Revenue Adjustment Line 13 * Line 14 $ (24,770)

16 2017-2018 GCR Underrecovery $ 26,000

17 Adjusted Cost of Gas Line 10 + Line 15 385,874$

Calculation of Adjusted Sales Volumes

18 April 2019 - March 2020 Billed Sales Volumes A-4 Line 14 col (4) 127,808

19 A-4 Line 1 col (6) (8,597)

20 April 2019 - March 2020 Adjusted Sales Volumes Line 18 + Line 19 119,210

21 GCR Pipeline Reservation Charge A-28 Line 24 0.38$

22 GCR Adjusted Sales Volume Line 20 119,210

23 GCR Reservation Charge Revenue Line 21 * Line 22 45,300

24 GCC Reservation Charge Revenue A-28 Line 21 6,440

25 Total Reservation Charge Revenue Line 23 + Line 24 51,740

26 Adjusted Cost of Gas Less Reservation Charge Revenue Line 17 - Line 25 334,134

27 April 2019 - March 2020 GCR Factor Line 26 / Line 20 2.80

Note: All Volumes in MMcf @14.65 and Costs in '000s unless otherwise noted.

Sources:

Billed/Unbilled Sales A-4

LAUF / Co. Use / GIK A-13

Purchased Gas Volumes A-10

Purchased Gas Costs A-12

Storage Costs A-22

Cost of Gas A-21

Description

March 2019 Unbilled Volume Balance



Forecasted Cost of Gas Witness: S. M. Moore

April 2020 - March 2021 Page: 1 of 4

(a) (b)

Line







5 Cost of Gas (To)/From Storage (2,241)$

6 Gas in Kind 7,392


8 Cost of GIK, LAUF, and Co. Use (Line 6 + Line 7 ) * Line 3 316 917$

9 Total Booked Cost of Gas Sold Line 4 + Line 5 + Line 8 365,767$


Sources




Storage Costs A-22

Description





(a) (b)

Line







5 Cost of Gas (To)/From Storage 1,414$

6 Gas in Kind 7,062


8 Cost of GIK, LAUF, and Co. Use (Line 6 + Line 7 ) * Line 3 (14) (41)$



Sources




Storage Costs A-22

Description





(a) (b)

Line








6 Gas in Kind 6,974





Sources




Storage Costs A-22

Description





(a) (b)

Line








6 Gas in Kind 6,948





Sources




Storage Costs A-22

Description



Calculation of LIFO Rate and Storage Costs Witness: S. M. Moore

Page: 1 of 3

(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l)

Line Volume Cost Volume Cost Volume Cost Volume Cost Volume Cost Volume Cost

1 January 9,551 40,434 9,494 32,798 9,359 31,495 9,369 31,635 9,329 31,589 9,358 32,767

2 February 8,573 35,323 8,802 30,617 8,330 28,252 8,339 28,244 8,299 28,251 8,670 30,335

3 March 9,566 34,390 9,494 32,064 9,359 30,225 9,369 30,129 9,329 30,260 9,358 31,598

4 April 12,033 35,116 11,980 31,942 12,003 31,323 12,015 32,103 12,018 32,870 - -

5 May 12,431 35,748 12,379 32,471 12,403 31,823 12,416 32,644 12,419 33,691 - -

6 June 12,030 34,779 11,980 31,930 12,003 31,368 12,015 32,090 12,018 33,218 - -

7 July 12,431 35,875 12,379 33,304 12,403 32,739 12,416 33,439 12,419 34,688 - -

8 August 12,431 35,861 12,379 33,314 12,403 32,964 12,416 33,585 12,419 34,964 - -

9 September 12,030 34,761 11,980 32,167 12,003 31,962 12,015 32,511 12,018 34,051 - -

10 October 8,202 24,758 8,143 22,712 8,194 22,753 8,218 23,124 8,243 24,466 - -

11 November 9,181 31,208 9,016 28,603 9,026 27,780 8,986 28,144 9,014 29,282 - -

12 December 9,494 32,493 9,359 30,676 9,369 30,419 9,329 30,503 9,358 31,699 - -

13 Total 127,953 410,746$ 127,385 372,599$ 126,858 363,103$ 126,906 368,150$ 126,884 379,028$ 27,387 94,701$

14 LIFO Rate 3.21$ 2.92$ 2.86$ 2.90$ 2.99$ 3.46$

Volume Cost Volume Cost Volume Cost Volume Cost Volume Cost Volume Cost

15 January 15,141 48,601$ 15,130 44,179$ 15,280 43,700$ 15,297 44,361$ 15,302 45,753$ 15,226 52,681$

16 February 13,386 42,968 13,882 40,536 13,541 38,728 13,556 39,312 13,565 40,559 13,933 48,208

17 March 7,906 25,378 7,854 22,933 7,999 22,876 8,009 23,227 8,026 23,999 7,928 27,431

18 April (2,587) (8,303) (2,600) (7,593) (2,608) (7,460) (2,626) (7,617) (2,642) (7,900)

19 May (8,207) (26,345) (8,198) (23,938) (8,201) (23,455) (8,208) (23,804) (8,212) (24,555)

20 June (9,697) (31,126) (9,710) (28,355) (9,720) (27,801) (9,724) (28,199) (9,730) (29,092)

21 July (10,180) (32,679) (10,194) (29,767) (10,206) (29,189) (10,205) (29,595) (10,213) (30,537)

22 August (10,304) (33,077) (10,316) (30,123) (10,329) (29,541) (10,331) (29,960) (10,336) (30,905)

23 September (9,052) (29,057) (9,046) (26,414) (9,056) (25,899) (9,065) (26,288) (9,072) (27,127)

24 October (1,054) (3,385) (1,096) (3,200) (1,126) (3,221) (1,165) (3,377) (1,202) (3,594)

25 November 3,750 12,038 3,819 11,152 3,838 10,978 3,866 11,212 3,813 11,402

26 December 10,496 33,692 10,476 30,589 10,525 30,101 10,544 30,579 10,479 31,333

27 Decrement - - 32 103 - - - - - -

28 Total (403) (1,295)$ 32 103$ (64) (182)$ (51) (149)$ (222) (664)$ 37,087 128,319$

Volume Cost Volume Cost Volume Cost Volume Cost Volume Cost

29 April (2,587) (8,303) (2,600) (7,593)$ (2,608) (7,460)$ (2,626) (7,617)$ (2,642) (7,900)$

30 May (8,207) (26,345) (8,198) (23,938) (8,201) (23,455) (8,208) (23,804) (8,212) (24,555)

31 June (9,697) (31,126) (9,710) (28,355) (9,720) (27,801) (9,724) (28,199) (9,730) (29,092)

32 July (10,180) (32,679) (10,194) (29,767) (10,206) (29,189) (10,205) (29,595) (10,213) (30,537)

33 August (10,304) (33,077) (10,316) (30,123) (10,329) (29,541) (10,331) (29,960) (10,336) (30,905)

34 September (9,052) (29,057) (9,046) (26,414) (9,056) (25,899) (9,065) (26,288) (9,072) (27,127)

35 October (1,054) (3,385) (1,096) (3,200) (1,126) (3,221) (1,165) (3,377) (1,202) (3,594)

36 November 3,750 12,038 3,819 11,152 3,838 10,978 3,866 11,212 3,813 11,402

37 December 10,496 33,692 10,476 30,589 10,525 30,101 10,544 30,579 10,479 31,333

38 Decrement - - 32 103 - - - - - -

39 January 15,130 44,179 15,280 43,700 15,297 44,361 15,302 45,753 15,226 52,681

40 February 13,882 40,536 13,541 38,728 13,556 39,312 13,565 40,559 13,933 48,208

41 March 7,854 22,933 7,999 22,876 8,009 23,227 8,026 23,999 7,928 27,431

42 Total 30 (10,594)$ (14) (2,241)$ (21) 1,414$ (20) 3,262$ (29) 17,344$

Sources

Purchase Gas Costs A-12

Purchase Gas Volumes A-10

Storage Volumes A-13

Jan - March 2019 Purchase

Volumes and Costs Testimony of Witness Eric Schiffer

Note: All Volumes in MMCF @ 14.65 and Costs in '000s unless otherwise noted; There may be slight deviations in data with other exhibits due to rounding error.

2019 2020

Purchased Gas / LIFO Calculation

20222021 2023 2024

Gas (To)/From Storage

2019 2020 2021 2022 2023 2024

GCR Operational Storage for Cost of Gas (To)/From Storage

2022 - 2023 2023 - 20242019- 2020 2020 - 2021 2021 - 2022



LIFO Layers and Decrement Cost Calculation Witness: S. M. Moore

Page: 2 of 3

(a) (b) (c) (d) (e) (f)

Line

MMcf Cost / Mcf

1 Pre 1956 37,141 0.28415$

2 1956 14,928 0.34313$

3 1957 19,356 0.38716$

4 2002 1,259 4.34650$

5 2014 5,338 5.18100$

2015 - 4.29180$

(Increment) /

Decrement

6 2018 (4,481)

MMcf $ / Mcf Cost in $000s MMcf Cost / Mcf

7 2018 (4,481) 3.25000$ (14,563)$ Pre 1956 37,141 0.28415$

8 1956 14,928 0.34313$

9 Total (4,481) (14,563)$ 1957 19,356 0.38716$

10 2002 1,259 4.34650$

11 2014 5,338 5.18100$

12 2015 - 4.29180$

13 2018 4,481 3.25000$

(Increment) /

Decrement

14 2019 (403)

MMcf Cost / Mcf

15 MMcf $ / Mcf Cost in $000s Pre 1956 37,141 0.28415$

16 2019 (403) 3.21000$ (1,295)$ 1956 14,928 0.34313$

17 Total (403) (1,295)$ 1957 19,356 0.38716$

18 2002 1,259 4.34650$

19 2014 5,338 5.18100$

20 2015 - 4.29180$

21 2018 4,481 3.25000$

22 2019 403 3.21000$

(Increment) /

Decrement

22 2020 32

MMcf Cost / Mcf


24 2019 32 3.21000$ 103$ 1956 14,928 0.34313$

25 Total 32 103$ 1957 19,356 0.38716$

26 2002 1,259 4.34650$

27 2014 5,338 5.18100$

28 2015 - 4.29180$

29 2018 4,481 3.25000$

30 2019 371 3.21000$

LIFO Layer Impact

LIFO Layer Impact

Ending Storage Balance

December 31, 2019

2019 Projected Storage Activity

Beginning Storage Balance

December 31, 2017



LIFO Layer Impact

December 31, 2020



December 31, 2018

Case No.: U-20236

Michigan Public Service Commission Exhibit: A-22

DTE Gas Company Witness: S. M. Moore

LIFO Layers and Decrement Cost Calculation Page: 3 of 3

(a) (b) (c) (d) (e) (f)

(Increment) /

Decrement

1 2021 (64)

MMcf Cost / Mcf


3 2021 (64) 3.21000$ (205)$ 1956 14,928 0.34313$

4 Total (64) (205)$ 1957 19,356 0.38716$

5 2002 1,259 4.34650$

6 2014 5,338 5.18100$

7 2015 - 4.29180$

8 2018 4,481 3.25000$

9 2019 371 3.21000$

2021 64 2.86000$

(Increment) /

Decrement

10 2022 51

MMcf Cost / Mcf


12 2021 51 2.86000$ 147$ 1956 14,928 0.34313$

13 Total 51 147$ 1957 19,356 0.38716$

14 2002 1,259 4.34650$

15 2014 5,338 5.18100$

16 2015 - 4.29180$

17 2018 4,481 3.25000$

18 2019 371 3.21000$

19 2021 12 2.86000$

20

(Increment) /

Decrement

21 2023 222

MMcf Cost / Mcf


23 2021 12 2.86000$ 35$ 1956 14,928 0.34313$

24 2019 210 3.21000$ 673$ 1957 19,356 0.38716$

25 Total 222 709$ 2002 1,259 4.34650$

26 2014 5,338 5.18100$

27 2015 - 4.29180$

28 2018 4,481 3.25000$

29 2019 161 3.21000$

30




December 31, 2021

December 31, 2022

December 31, 2023

LIFO Layer Impact


LIFO Layer Impact


LIFO Layer Impact


M.P.S.C. No. 1 – Gas __________ Revised Sheet No. D-4.00

DTE Gas Company Cancels _________ Revised Sheet No. D-4.00

(Revised pursuant to Case No. U-20236)

Issued _____________, 2019 Effective for bills rendered on

D.M. Stanczak and after the first billing cycle of

Vice President the April 2019 billing month through

Regulatory Affairs the last billing cycle of March 2020

Detroit, Michigan Issued the under authority of

1982 PA 304 Section 6h and the

Michigan Public Service Commission for

Self Implementation in Case No. U-20236

D4. MONTHLY GCR FACTOR CEILING PRICE ADJUSTMENT (CONTINGENCY) MECHANISM

The Maximum Allowable GCR factors listed on Sheet No. D-3.00 may be increased on a monthly basis, for the

remaining months of the April 2019 through March 2020 GCR Plan year, contingent upon the NYMEX futures prices

for natural gas increasing to a level above the level incorporated into the calculation of the GCR factor ceiling prices.

Contingent factors are applied symmetrically. If the NYMEX Change, as defined below, is negative, the factors on

Sheet No. D-5.00 are subtracted from the current GCR factor and if the NYMEX change is positive, they are added

to the current GCR factor. However, the application of the contingent factors will never reduce the Maximum

Allowable GCR factor below the base GCR factor of $2.80 per Mcf, even if the current GCR factor is $2.80 per Mcf

and the NYMEX Change is negative.

NYMEX Change = Xn less Xn-1

Xn = The simple average of the actual NYMEX monthly natural gas futures contract settlement prices, ($/MMBtu)

for January 2019 through December 2020 averaged over the first five trading days of the month prior to

implementation. Closing prices may be used for months that are no longer trading on NYMEX.

Xn-1 = The simple average of the actual NYMEX monthly natural gas futures contract settlement prices, ($/MMBtu)

for January 2019 through December 2020 used to determine the most recent maximum GCR factor. Closing

prices may be used for months that are no longer trading on NYMEX. For the first month’s contingent factor,

the filed Plan NYMEX is Xn-1.

By the fifteenth of each month, the Company shall file with the Michigan Public Service Commission an updated

maximum allowable GCR factor. A filing must be made regardless of whether it increases or decreases the maximum

allowable GCR factor. The maximum allowable GCR factor will not be lowered below the base GCR factor of $2.80

per Mcf. The informational filing shall include all supporting documents necessary to verify the new price ceiling,

including the calculation of the weighted five-day average of the NYMEX strip for the remaining months of the GCR

period and a copy of the published NYMEX futures price sheets for the first five trading days of the month, such sheet

being an authoritative source used by the gas industry. The filing shall be incorporated into the GCR Plan docket,

Case No. U-20236, with notice provided to all intervenors.

(Continued on Sheet No. D-5.00)

Case No.: U-20236

Exhibit: A-23

Witness: S.M. Moore

Page 1 of 2

M.P.S.C. No. 1 – Gas __________ Revised Sheet No. D-5.00

DTE Gas Company Cancels _________ Revised Sheet No. D-5.00

(Revised pursuant to Case No. U-20236)

Issued _____________, 2019 Effective for bills rendered on

D.M. Stanczak and after the first billing cycle of

Vice President the April 2019 billing month through

Regulatory Affairs the last billing cycle of March 2020

Detroit, Michigan Issued the under authority of

1982 PA 304 Section 6h and the

Michigan Public Service Commission for

Self Implementation in Case No. U-20236

(Continued from Sheet No. D-4.00)

D4. MONTHLY GCR FACTOR CEILING PRICE ADJUSTMENT (CONTINGENCY) MECHANISM (CONTD)

The following Contingent Gas Cost Recovery Factors are authorized for the April 2019 through March 2020 GCR plan period:

April 2019-

March 2020

April 2019-

March 2020

Fractional Mult. Fm 0.322 Fractional Mult. Fm 0.322

Base GCR Factor 2.80 Base GCR Factor 2.80

NYMEX Increases

Incremental

Contingent

GCR Factor

$/Mcf

NYMEX Increases

Incremental

Contingent

GCR Factor

$/Mcf

$0.00 $0.10 $0.000 $1.50 $1.60 $0.48

$0.10 $0.20 $0.03 $1.60 $1.70 $0.52

$0.20 $0.30 $0.06 $1.70 $1.80 $0.55

$0.30 $0.40 $0.10 $1.80 $1.90 $0.58

$0.40 $0.50 $0.13 $1.90 $2.00 $0.61

$0.50 $0.60 $0.16 $2.00 $2.10 $0.64

$0.60 $0.70 $0.19 $2.10 $2.20 $0.68

$0.70 $0.80 $0.23 $2.20 $2.30 $0.71

$0.80 $0.90 $0.26 $2.30 $2.40 $0.74

$0.90 $1.00 $0.29 $2.40 $2.50 $0.78

$1.00 $1.10 $0.32 $2.50 $2.60 $0.81

$1.10 $1.20 $0.35 $2.60 $2.70 $0.84

$1.20 $1.30 $0.39 $2.70 $2.80 $0.87

$1.30 $1.40 $0.42 $2.80 $2.90 $0.90

$1.40 $1.50 $0.45 $2.90 $3.00 $0.93

$3.00 $0.97

Case No.: U-20236

Exhibit: A-23

Witness: S.M. Moore

Page: 2 of 2



Derivation Contingent Factor + $1 Witness: S. M. Moore

Page: 1 of 8

(a) (b)

Line







5 Cost of Gas (To)/From Storage 843$


7 Gas in Kind 6,270














19 A-4 Line 1 col (6) (8,597)



22 GCR Adjusted Sales Volume Line 20 119,210 23 GCR Reservation Charge Revenue Line 21 * Line 22 45,300






Sources:





Storage Costs A-22

Cost of Gas A-21


Description





(a) (b)

Line








6 Gas in Kind 7,392


8 Cost of GIK, LAUF, and Co. Use (Line 6 + Line 7 ) * Line 3 316 1,132$



Sources




Storage Costs A-22

Description




Derivation Contingent Factor + $1 Page: 3 of 8

(a) (b) (c) (d) (e) (f)

Line Volume Cost Volume Cost Volume Cost

1 January 9,551 43,713 9,494 35,361 9,359 37,995

2 February 8,573 38,226 8,802 32,931 8,330 33,994

3 March 9,566 37,684 9,494 34,627 9,359 36,725

4 April 12,033 38,311 11,980 40,169 12,003 44,183

5 May 12,431 39,047 12,379 40,973 12,403 45,111

6 June 12,030 37,971 11,980 40,157 12,003 44,227

7 July 12,431 39,174 12,379 41,806 12,403 46,027

8 August 12,431 39,160 12,379 41,816 12,403 46,253

9 September 12,030 37,952 11,980 40,394 12,003 44,822

10 October 8,202 26,891 8,143 26,752 8,194 31,606

11 November 9,181 33,680 9,016 34,850 9,026 37,560

12 December 9,494 35,055 9,359 37,175 9,369 40,568

13 Total 127,953 446,865$ 127,385 447,010$ 126,858 489,069$

14 LIFO Rate 3.49$ 3.51$ 3.86$

Volume Cost Volume Cost Volume Cost

15 January 15,141 52,840$ 15,130 53,106$ 15,280 58,979$

16 February 13,386 46,716 13,882 48,726 13,541 52,270

17 March 7,906 27,592 7,854 27,567 7,999 30,874

18 April (2,587) (9,028) (2,600) (9,127) (2,608) (10,068)

19 May (8,207) (28,643) (8,198) (28,775) (8,201) (31,656)

20 June (9,697) (33,841) (9,710) (34,084) (9,720) (37,521)

21 July (10,180) (35,529) (10,194) (35,782) (10,206) (39,395)

22 August (10,304) (35,962) (10,316) (36,210) (10,329) (39,870)

23 September (9,052) (31,592) (9,046) (31,751) (9,056) (34,955)

24 October (1,054) (3,680) (1,096) (3,846) (1,126) (4,347)

25 November 3,750 13,088 3,819 13,405 3,838 14,816

26 December 10,496 36,631 10,476 36,770 10,525 40,626

27 Decrement - - 32 112 - -

28 Total (403) (1,408)$ 32 112$ (64) (246)$


29 April (2,587) (9,028) (2,600) (9,127)$ (2,608) (10,068)$

30 May (8,207) (28,643) (8,198) (28,775) (8,201) (31,656)

31 June (9,697) (33,841) (9,710) (34,084) (9,720) (37,521)

32 July (10,180) (35,529) (10,194) (35,782) (10,206) (39,395)

33 August (10,304) (35,962) (10,316) (36,210) (10,329) (39,870)

34 September (9,052) (31,592) (9,046) (31,751) (9,056) (34,955)

35 October (1,054) (3,680) (1,096) (3,846) (1,126) (4,347)

36 November 3,750 13,088 3,819 13,405 3,838 14,816

37 December 10,496 36,631 10,476 36,770 10,525 40,626

38 Decrement - - 32 112 - -

39 January 15,130 53,106 15,280 58,979 15,297 60,881

40 February 13,882 48,726 13,541 52,270 13,556 53,953

41 March 7,854 27,567 7,999 30,874 8,009 31,877

42 Total 30 843$ (14) 12,837$ (21) 4,342$

Sources





Volumes and Costs Testimony of Witness Eric Shiffer

2019 - 2020 2020 - 2021 2021 - 2022



2019 2020 2021


2019 2020 2021

Note: All Volumes in MMCF @ 14.65 and Costs in '000s unless otherwise noted; There may be slight deviations in data with other exhibits d





(a) (b) (c) (d) (e) (f)

Line

MMcf Cost / Mcf

1 Pre 1956 37,141 0.28415$

2 1956 14,928 0.34313$

3 1957 19,356 0.38716$

4 2002 1,259 4.34650$

5 2014 5,338 5.18100$

2015 - 4.29180$

(Increment) /

Decrement

6 2018 (4,481)


7 2018 (4,481) 3.25000$ (14,563)$ Pre 1956 37,141 0.28415$

8 1956 14,928 0.34313$

9 Total (4,481) (14,563)$ 1957 19,356 0.38716$

10 2002 1,259 4.34650$

11 2014 5,338 5.18100$

12 2015 - 4.29180$

2018 4,481 3.25000$

13

(Increment) /

Decrement

2019 (403)

MMcf Cost / Mcf


15 2019 (403) 3.49000$ (1,408)$ 1956 14,928 0.34313$

16 Total (403) (1,408)$ 1957 19,356 0.38716$

17 2002 1,259 4.34650$

18 2014 5,338 5.18100$

19 2015 - 4.29180$

2018 4,481 3.25000$

2019 403 3.49000$

(Increment) /

Decrement

20 2020 32

MMcf Cost / Mcf


22 2019 32 3.49000$ 112$ 1956 14,928 0.34313$

23 Total 32 112$ 1957 19,356 0.38716$

24 2002 1,259 4.34650$

25 2014 5,338 5.18100$

26 2015 - 4.29180$

27 2018 4,481 3.25000$

28 2019 371 3.49000$


December 31, 2017



LIFO Layer Impact

December 31, 2019



December 31, 2018LIFO Layer Impact

LIFO Layer Impact


December 31, 2018





Page: 5 of 8

(a) (b)

Line









7 Gas in Kind 6,270














19 A-4 Line 1 col (6) (8,597)



22 GCR Adjusted Sales Volume Line 20 119,210 23 GCR Reservation Charge Revenue Line 21 * Line 22 45,300






Sources:





Storage Costs A-22

Cost of Gas A-24


Description





(a) (b)

Line








6 Gas in Kind 7,392


8 Cost of GIK, LAUF, and Co. Use (Line 6 + Line 7 ) * Line 3 316 1,343$



Sources




Storage Costs A-22

Description





(a) (b) (c) (d) (e) (f)

Line Volume Cost Volume Cost Volume Cost

1 January 9,551 46,991 9,494 37,923 9,359 44,494

2 February 8,573 41,130 8,802 35,244 8,330 39,735

3 March 9,566 40,979 9,494 37,189 9,359 43,224

4 April 12,033 41,506 11,980 48,397 12,003 57,042

5 May 12,431 42,346 12,379 49,474 12,403 58,400

6 June 12,030 41,162 11,980 48,384 12,003 57,087

7 July 12,431 42,473 12,379 50,307 12,403 59,315

8 August 12,431 42,459 12,379 50,317 12,403 59,541

9 September 12,030 41,144 11,980 48,621 12,003 57,681

10 October 8,202 29,024 8,143 30,792 8,194 40,458

11 November 9,181 36,153 9,016 41,097 9,026 47,339

12 December 9,494 37,618 9,359 43,675 9,369 50,718

13 Total 127,953 482,985 127,385 521,422 126,858 615,034

14 LIFO Rate $3.77 $4.09 $4.85


15 January 15,141 57,080 15,130 61,881 15,280 74,106

16 February 13,386 50,464 13,882 56,778 13,541 65,676

17 March 7,906 29,805 7,854 32,122 7,999 38,793

18 April (2,587) (9,752) (2,600) (10,636) (2,608) (12,650)

19 May (8,207) (30,941) (8,198) (33,529) (8,201) (39,776)

20 June (9,697) (36,556) (9,710) (39,716) (9,720) (47,144)

21 July (10,180) (38,380) (10,194) (41,695) (10,206) (49,499)

22 August (10,304) (38,847) (10,316) (42,193) (10,329) (50,095)

23 September (9,052) (34,127) (9,046) (36,997) (9,056) (43,920)

24 October (1,054) (3,975) (1,096) (4,482) (1,126) (5,463)

25 November 3,750 14,138 3,819 15,620 3,838 18,617

26 December 10,496 39,570 10,476 42,846 10,525 51,046

27 Decrement 0 0 32 121 0 0

28 Total (403) ($1,521) 32 $121 (64) ($309)


29 April (2,587) (9,752) (2,600) (10,636) (2,608) (12,650)

30 May (8,207) (30,941) (8,198) (33,529) (8,201) (39,776)

31 June (9,697) (36,556) (9,710) (39,716) (9,720) (47,144)

32 July (10,180) (38,380) (10,194) (41,695) (10,206) (49,499)

33 August (10,304) (38,847) (10,316) (42,193) (10,329) (50,095)

34 September (9,052) (34,127) (9,046) (36,997) (9,056) (43,920)

35 October (1,054) (3,975) (1,096) (4,482) (1,126) (5,463)

36 November 3,750 14,138 3,819 15,620 3,838 18,617

37 December 10,496 39,570 10,476 42,846 10,525 51,046

38 Decrement 0 0 32 121 0 0

39 January 15,130 61,881 15,280 74,106 15,297 77,249

40 February 13,882 56,778 13,541 65,676 13,556 68,458

41 March 7,854 32,122 7,999 38,793 8,009 40,447

42 Total 30 $11,911 (14) $27,915 (21) $7,270

Sources





Volumes and Costs Testimony of Witness Eric Schiffer

Note: All Volumes in MMCF @ 14.65 and Costs in '000s unless otherwise noted; There may be slight deviations in data with other exhibits due to rounding error.

2019 2020 2021


2019 2020 2021


2019- 2020 2020 - 2021 2020 - 2021






(a) (b) (c) (d) (e) (f)

Line

MMcf Cost / Mcf

1 Pre 1956 37,141 0.28415$

2 1956 14,928 0.34313$

3 1957 19,356 0.38716$

4 2002 1,259 4.34650$

5 2014 5,338 5.18100$

2015 - 4.29180$

(Increment) /

Decrement

6 2018 (4,481)


7 2018 (4,481) 3.25000$ (14,563)$ Pre 1956 37,141 0.28415$

8 1956 14,928 0.34313$

9 Total (4,481) (14,563)$ 1957 19,356 0.38716$

10 2002 1,259 4.34650$

11 2014 5,338 5.18100$

12 2015 - 4.29180$

2018 4,481 3.25000$

tyujk,

13

(Increment) /

Decrement

2019 (403)

MMcf Cost / Mcf


15 2019 (403) 3.77000$ (1,521)$ 1956 14,928 0.34313$

16 Total (403) (1,521)$ 1957 19,356 0.38716$

17 2002 1,259 4.34650$

18 2014 5,338 5.18100$

19 2015 - 4.29180$

2018 4,481 3.25000$

2019 403 3.77000$

(Increment) /

Decrement

20 2020 32

MMcf Cost / Mcf


22 2019 32 3.77000$ 121$ 1956 14,928 0.34313$

23 Total 32 121$ 1,957 19,356 0.38716$

24 2002 1,259 4.34650$

25 2014 5,338 5.18100$

26 2015 - 4.29180$

25 2018 4,481 3.25000$

26 2019 371 3.77000$

LIFO Layer Impact

LIFO Layer Impact


December 31, 2019



December 31, 2017



LIFO Layer Impact

December 31, 2020



December 31, 2018



Calculation of Reservation Charge Witness: S. M. Moore

Applied to GCC and GCR Customers Page: 1 of 1

(a) (b) (c) (d)

Line

No. Description Source

Calculation of Reservation Charge

1 2019-2020 Pipeline Reservation Cost (PRC) 55,377$ A-11, Line 28, pg 1

2 Calculation of March 2020 Unbilled Revenue Adjustment

3 2020-2021 Pipeline Reservation Cost 55,377$ A-11, Line 28, pg 2

4 2020-2021 GCR + GCC Sales 155,236 A-1, Line 27

5 2020-2021 Average Reservation Charge 0.36$ Line 3 / Line 4

6 March 2020 GCR + GCC Unbilled Volume Balance (10,343)

7 March 2020 GCR + GCC Revenue Adjustment (3,690)$ Line 5 * Line 6

8 Adjusted Pipeline Reservation Cost 51,688$ Line 1 - Line 7

9 April 2019 - March 2020 Billed Sales Volumes

10 GCR 127,808 A-20 Line 18

11 GCC 28,592 A-4, pg 1, Line 14

12 Total Billed Sales (GCR + GCC) 156,400 Line 9 + Line 10

13 March 2019 GCR Unbilled (8,597)

14 March 2019 GCC Unbilled (1,759)

15 March 2019 GCR +GCC Unbilled Volume Balance (10,356) Line 13+Line 14

16 April 2019 - March 2020 Adjusted Sales Volumes 146,043 Line 12 + Line 15

17 April 2019 - March 2020 Reservation Charge 0.35$ Line 8 / Line 16

18 30% Discount (0.11)$ -30%* Line 17

19 GCC Rate 0.24$ Line 17 + Line 18

20 GCC Volume 26,833 Line 11 +Line 14

21 GCC Revenue 6,440$ Line 19 * Line 20

22 Net GCR Pipeline Cost 45,248$ Line 8 - Line 21

23 GCR Adjusted Sales Volume 119,210 Line 10 + Line 13

24 GCR RC Rate 0.38$ Line 22/ Line 23

STATE OF MICHIGAN



DTE GAS COMPANY for approval of a )




PROOF OF SERVICE

STATE OF MICHIGAN )

) ss.

COUNTY OF WAYNE )

ESTELLA R. BRANSON, being duly sworn, deposes and says that on the 21st day of

December, 2018, she served a copy of DTE Gas Company’s Application for Approval of Gas Cost

Recovery Plan and Monthly GCR Factor, and Evaluation of its Five-Year Forecast, along with

Testimony and Exhibits of Witnesses, Eric P. Schiffer, George H. Chapel, Sherri M. Moore,

Timothy J. Krysinski, and Lucian Bratu, via electronic mail upon the persons referred to in the

attached service list.

______

ESTELLA R. BRANSON

Subscribed and sworn to before

me this 21st day of December, 2018

Lorri A. Hanner, Notary Public

Wayne County, Michigan

My Commission Expires: 4-20-2020

SERVICE LIST

MPSC CASE NO. U-20236

ATTORNEY GENERAL (ENRA)

Joel King

G. Mennen Williams Bldg.

525 W. Ottawa Street, 6th Floor

P.O. Box 30755

Lansing, MI 48909

[email protected]

[email protected]

MICHIGAN ENVIRONMENTAL

COUNCIL (MEC) Christopher M. Bzdok

Tracy Jane Andrews

Lydia Barbash-Riley

Olson, Bzdok & Howard, P.C. 420 E.

Front St. Traverse City, MI 49686

[email protected]

[email protected]

[email protected]

[email protected]

[email protected]

MICHIGAN PUBLIC SERVICE

COMMISSION STAFF ATTORNEYS

Monica M. Stephens

Heather M. S. Durian

7109 West Saginaw Hwy, 3rd Floor

Lansing, MI 48917

[email protected]

[email protected]

RESIDENTIAL CUSTOMER GROUP

Brian W. Coyer

Don L. Keskey

University Office Place

333 Albert Avenue, Suite 425

East Lansing, MI 48823

[email protected]

[email protected]

RETAIL ENERGY SUPPLY

ASSOCIATION (RESA)

Jennifer Utter Heston Fraser Trebilcock Davis & Dunlap, PC

124 W. Allegan, Suite 1000

Lansing, MI 48933

[email protected]

mailto:[email protected]



















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