David S. Maquera (313) 235-3724 [email protected]

David S. Maquera (313) 235-3724 Maquerad@Dteenergy.Com

DTE Gas Company One Energy Plaza, 688 WCB Detroit, MI 48226-1279

May 14, 2013

Ms. Mary Jo Kunkle Executive Secretary Michigan Public Service Commission 6545 Mercantile Way, Suite 15 Lansing, Michigan 48909-7721

Re: In the Matter of the Application of Michigan Consolidated Gas Company for approval of a Gas Cost Recovery Plan, 5-year Forecast and Monthly GCR Factor for the 12-months ending March 31, 2014 and for approval to implement a Reservation Charge applicable to Gas Customer Choice Suppliers MPSC Case No. U-17131

Dear Ms. Kunkle:

Attached for electronic filing on behalf of DTE Gas Company are the Rebuttal Testimony and Rebuttal Exhibits for James A Brunell and W. Bernard Kramer and also the Rebuttal Testimony, only, for Eric W. Clinton and Barbara J. Goodwin. Also attached is the Proof of Service in the above-captioned matter.

Very truly yours,

David S. Maquera

DSM/lah Attachments cc: Service List STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application of ) Michigan Consolidated Gas Company ) for approval of a Gas Cost Recovery Plan, ) Case No. U-17131 5-year Forecast and Monthly GCR Factor ) for the 12 months ending March 31, 2014 )

REBUTTAL TESTIMONY

JAMES A. BRUNELL

DTE GAS COMPANY REBUTTAL TESTIMONY OF JAMES A. BRUNELL Line No.

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

2 A. My name is James A. Brunell. My business address is One Energy Plaza, Detroit,

3 Michigan 48226. I am employed by DTE Energy Corporate Services, LLC within

4 Regulatory Affairs as a Consultant.

6 Q. Did you previously file direct testimony in this proceeding on behalf of DTE

7 Gas Company (DTE Gas) formerly known as Michigan Consolidated Gas

8 Company?

9 A. Yes, I did.

11 Q. What is the purpose of your rebuttal testimony?

12 A. My rebuttal testimony rebuts Lakeshore Energy Services (LES) witness Mr. Charles

13 Galvin’s proposal that the Reservation Charge be collected from customers instead

14 of the Alternative Gas Suppliers (AGSs); rebuts witness Galvin’s and Interstate Gas

15 Supply (IGS) witness Mr. Matthew White’s claim that the Reservation charge will

16 hurt competition in the gas market; rebuts Retail Energy Supply Association

17 (RESA) witness Mr. Michael Haugh’s claim that billing the Reservation Charge to

18 the AGSs violates the principal that cost allocation should follow cost causation;

19 presents the calculation of the Reservation Charge and the maximum GCR factor if

20 the Commission adopts witness Galvin’s proposal to bill the Reservation Charge to

21 customers; and finally addresses Michigan Community Action Agency Association

22 witness Mr. Geoffry Crandall’s concerns regarding the appropriateness of the

23 Reservation Charge itself, and its inclusion in a GCR proceeding.

25 Q. Are you sponsoring any rebuttal exhibits?

JAB Rebuttal - 1 J. A. BRUNELL Line U-17131 No.

1 A. Yes, I am sponsoring the following rebuttal exhibits that were prepared by me.

2 Exhibit Description

3 A-30 Adjusted GCR Factor and Calculation of Reservation Charge

4 Applied to GCC and GCR Customers

5 A-31 Example GCR and Reservation Charge Reconciliation

7 Charging the Reservation Charge to GCC Customers.

8 Q. At page 12 of his testimony, Lakeshore Energy Services witness Charles Galvin

9 claims that if the Commission approves the Company’s proposed Reservation

10 Charge then that charge should be collected from customers and not suppliers.

11 Do you agree with this recommendation?

12 A. No, Witness Galvin’s proposal should be rejected for the reasons listed in my direct

13 testimony on Page JAB - 13. Specifically, the Company’s proposal will not lead to

14 any new line items on customer bills (for both GCC and therefore GCR customers),

15 which will avoid confusion for the customers; the SOLR role is a supply function

16 and is therefore properly recovered through the commodity charge; and total costs

17 of supply should be bundled into one rate for comparability with other commodity

18 supply sources (i.e. GCR) and jurisdictions.

20 Q. Does witness Galvin provide any support for his proposal that the Reservation

21 Charge not be collected from Alternative Gas Suppliers (AGSs)?

22 A. Yes, at pages 5-8 of his testimony, witness Galvin claims that the mismatch

23 between how suppliers are paid and how the Reservation Charge is collected will

24 create a need for AGSs to charge varying rates to customers throughout the year.

JAB Rebuttal - 2 J. A. BRUNELL Line U-17131 No.

1 Q. Do you agree with witness Galvin’s claim that AGSs may need to charge

2 customers varying rates throughout the year due to the disconnect between

3 how the Reservation Charge is collected and how AGSs are paid?

4 A. No, this claim by witness Galvin is meritless. During the GCR year, AGSs deliver

5 gas to DTE Gas’s system and are paid for that gas at that time. The gas is then

6 stored and delivered to customers later in the GCR year when demand is higher.

7 The Reservation Charge will only be subsequently assessed when the GCC

8 customers use gas, which is AFTER it has been delivered to the Company’s system.

9 Using witness Galvin’s own logic, it is DTE Gas that will have revenue deficiencies

10 due to the timing disconnect between when AGSs are paid for gas, and when the

11 Reservation Charge is collected from the AGSs. This timing issue also exists for

12 the commodity payments as well. DTE Gas pays the AGSs for gas when it receives

13 the commodity, but is not paid until after the GCC customer uses the gas.

14 However, the Company does not alter its GCR charge to equalize its cash flow as

15 witness Galvin suggests that the AGSs would be required to do. The timing

16 difference between cash out lays and cash receipts is simply a part of DTE Gas’

17 business model.

19 Q. At page 9 of his testimony, witness Galvin states that “DTE’s contracts are

20 made subject to all valid laws, orders rules [sic] and regulations of the

21 Commission.” Do you agree?

22 A. Yes, the Company abides by all valid laws, orders, rules, and regulations.

24 Q. Witness Galvin then claims that AGSs do not have the same ability to make

25 their contracts subject to all valid laws, orders, rules, and regulations. Are you

JAB Rebuttal - 3 J. A. BRUNELL Line U-17131 No.

1 aware of anything that restricts the AGSs from having their contracts subject

2 to those constraints?

3 A. No, I am not. Further, DTE Gas can choose to make its contracts subject to

4 changes by a regulator by including provisions that allow the contract terms to be

5 amended for actions taken by regulators because doing otherwise would put DTE

6 Gas at risk for any such changes. The decision to include language in contracts that

7 allow the terms to be amended based on changes in regulation is one of the many

8 business decisions weighing risk and return that companies participating in

9 regulated markets must consider when conducting business. When an AGS enters

10 into a fixed rate contract with a customer, it can purchase gas to serve that customer

11 to hedge its price risk, but that supplier is still exposed to volumetric risk.

12 Volumetric risk would be the difference between what the supplier forecasted that

13 the customer would use and that customer’s actual consumption. Regulatory risk is

14 just another business risk faced by participants in a regulated market. If an AGS

15 chooses not to include a provision in their contracts that allows their terms to be

16 amended based on changes in regulation when engaging in the sale of product in a

17 regulated market, then the AGS is consciously choosing to bear the risk of that

18 decision. In the case of the SOLR Reservation Charge, DTE Gas’s GCR customers

19 have been subsidizing the GCC program by bearing the entire cost for the

20 Company’s Supplier of Last Resort (SOLR) function. The Company’s proposed

21 Reservation Charge eliminates the undue benefit that has been, and continues at this

22 point to be, received by the GCC program participants by allocating a proper

23 proportionate share of the SOLR costs to the AGSs.

25 Q. Interstate Gas Supply, Inc. (IGS) Witness Matthew White claims at page 27 of

JAB Rebuttal - 4 J. A. BRUNELL Line U-17131 No.

1 his testimony that the Reservation Charge should not be applied to preexisting

2 fixed rate contracts because doing so would interfere with the AGS contractual

3 relationships with its customers. Do you agree that preexisting fixed rate

4 contracts should be exempt from the Reservation Charge?

5 A. No, if the AGSs have included provisions within their fixed price contracts to allow

6 them to pass along costs that arise due to legal or regulatory changes, then the

7 contractual relationships will remain unchanged even though the costs will change.

8 As noted above, if IGS or any other AGS has chosen to do business in a market that

9 is regulated by the MPSC and to offer contractual terms that do not allow it to

10 collect costs from its contractual counterparties due to changes in regulations, then

11 that is the business model they have elected. That business model has both benefits

12 and risks and the AGS must live with the results of the business model it has

13 chosen. It would be unfair to make GCR customers continue to subsidize the AGSs

14 just because the AGSs have chosen to contractually bear regulatory risk by offering

15 fixed price contracts. With this filing, the AGSs have ample notice about the

16 Reservation Charge prior to its implementation after the Commission issues an

17 order in this case.

19 Q. At page 9 of his testimony Witness Galvin claims that the Reservation Charge

20 may lead to some AGSs reconsidering if they want to continue to offer fixed

21 price contracts because they may not be able to recover the that charge in such

22 contracts. Do you agree that AGSs may be unable to recover the cost of the

23 Reservation Charge through prospective fixed price contracts?

24 A. No, the claim that AGSs may not be able to recover the cost of the Reservation

25 Charge in prospective fixed price contracts is false. The Reservation Charge is

JAB Rebuttal - 5 J. A. BRUNELL Line U-17131 No.

1 calculated by taking the annual pipeline reservation cost and dividing it by total

2 GCR and GCC sales. The annual pipeline reservation charge is forecasted to be the

3 same amount, $38.9 million found on Exhibit A-12, line 22, for each of the five

4 years in this GCR Plan. Total GCR and GCC sales are forecasted on Exhibit A-1,

5 line 13, to range from approximately 151 Bcf to 155 Bcf. For the forecast period

6 contained in this GCR Plan, the Reservation Charge would range from $0.26 to

7 $0.25 per Mcf, which is significantly more fixed than other cost components that

8 the AGSs must consider when offering fixed price contracts such as commodity

9 cost and volumetric risk.

11 Q. At page 5 of his testimony, IGS witness White claims that the proposed

12 Reservation Charge is anticompetitive. Do you agree with that claim?

13 A. No, I do not agree with the claim that the Reservation Charge is anticompetitive.

14 As noted elsewhere in my rebuttal testimony, the effect of the Reservation Charge

15 is charge is to align cost with causation and to eliminate an undue subsidy to the

16 AGSs at the expense of GCR customers. Subsidies are anticompetitive; the

17 Reservation Charge simply eliminates an inappropriate and anticompetitive

18 subsidy.

20 Q. Retail Energy Supply (RESA) Witness Michael Haugh claims on page 8 of his

21 testimony that the Reservation Charge should be billed directly to customers

22 because of the regulatory principal that cost allocation should follow cost

23 causation. Does the Company’s proposed cost allocation violate that

24 principle?

25 A. No, the Company’s proposal to bill the Reservation Charge to the AGSs does not

JAB Rebuttal - 6 J. A. BRUNELL Line U-17131 No.

1 violate the principle that cost allocation should follow cost causation. The

2 Company is required by Section F1.19 of its tariff to act as a supplier of last resort

3 for the GCC program. The AGSs are selling commodity to their customers without

4 incurring supplier of last resort costs and have been receiving an undue subsidy

5 from the GCR customers as a result. As discussed earlier in my testimony, SOLR

6 is a supply function and it is appropriately recovered through the commodity

7 charge. The AGSs are free to bill their customers to recover that portion of the

8 commodity charge. Because SOLR is a supply function, it should be included in

9 the cost of the sale of the commodity. It is simpler and easier to have a single

10 charge for the commodity. The AGSs are not having the pipeline companies that

11 deliver their gas to DTE’s distribution system bill their retail customers for that

12 charge. Instead, it is included in the commodity charge that they bill to their

13 customers. If witness Haugh’s suggestion were adopted, then all 1.2 million of

14 DTE Gas’s GCR and GCC customers will have a new line item on their bill, which

15 will only facilitate confusion, increase complaints, and ultimately lead to a lower

16 level of customer satisfaction.

18 Q. Witness Haugh claims that DTE is billing the AGSs for the Reservation

19 Charge so that the Company does not have to explain to its customers why

20 their commodity rates are increasing. Is this an accurate statement?

21 A. No, Mr. Haugh’s claim is inaccurate. DTE Gas’s GCR customers are already

22 paying for all of their pipeline reservation expenses, and as detailed in my direct

23 testimony and exhibits, DTE Gas’s commodity charge, the GCR factor, will

24 decrease if the Commission approves the Reservation Charge. Assuming that the

25 AGSs decide to pass the cost of the Reservation Charge along to their retail

JAB Rebuttal - 7 J. A. BRUNELL Line U-17131 No.

1 customers, then it is only the AGSs’ customers who will be seeing increases in the

2 cost of commodity. Witness Haugh notes that if the Reservation Charge is

3 collected in this manner, then any complaints arising from it will be directed to the

4 AGSs instead of DTE Gas. The fact that complaints will be directed to the AGSs is

5 entirely appropriate since it is a commodity related cost and the AGSs are the

6 commodity provider for their customers. Additionally, the charge eliminates an

7 undue subsidy to the AGSs that has been born by the GCR customers, so it is only

8 appropriate that the AGSs field any complaints arising from the elimination of that

9 subsidy instead of DTE Gas.

11 Q. Witness Galvin’s proposal at page 12 of his testimony is to bill customers for

12 the Reservation Charge instead of the AGSs as proposed by DTE Gas. If the

13 MPSC were to adopt witness Galvin’s proposal to bill customers, would the

14 calculation of the Reservation Charge change?

15 A. Yes, if the MPSC adopts witness Galvin’s proposal to bill the Reservation Charge

16 to customers, then the method for calculating the Reservation Charge would

17 change.

19 Q. Why would the method for calculating the charge change if the MPSC adopted

20 witness Galvin’s proposal to bill customers for the Reservation Charge instead

21 of the AGSs?

22 A. If the Reservation Charge is billed directly to customers, then the Company believes

23 that this charge would have to be explicitly billed to both GCC and GCR customers.

24 The Reservation Charge would have to be billed to both GCC and GCR to allow for

25 “apples-to-apples” comparisons between GCR and GCC offerings. As noted at

JAB Rebuttal - 8 J. A. BRUNELL Line U-17131 No.

1 Page JAB - 14 of my direct testimony, calculating the Reservation Charge

2 applicable to GCC suppliers is best done based on billed sales because the GCC

3 program is reconciled on that basis. Billing customers directly requires that the

4 charge be calculated on an unbilled basis in order to be consistent with how the

5 GCR factor is calculated and with how the GCR is reconciled.

7 Q. You stated that in order to bill the Reservation Charge to customers, that

8 charge must be calculated on an unbilled basis. Have you recalculated the

9 Reservation Charge on an unbilled basis?

10 A. Yes, Exhibit A-30, lines 11 to 24, recalculates the Reservation Charge on an

11 unbilled basis. Lines 11-17 adjust the Pipeline Reservation Cost to remove the

12 March 2014 unbilled revenue that will be collected at the 2014 -2015 rate. The

13 GCR unbilled balance was taken from Exhibit A-4 and the GCC unbilled volume

14 balance was provided to me by witness Chapel. Line 22 presents the total GCR and

15 GCC March 2013 unbilled volume balance and because any revenues associated

16 with those volumes will be accrued into the 2012-2013 GCR year, those volumes

17 are excluded from the calculation of the Reservation Charge. The adjusted Pipeline

18 Reservation Cost, line 18, is divided by the April 2013 - March 2014 Adjusted

19 Sales Volume, line 23, to produce the April 2013 – March 2014 Reservation

20 Charge, line 24, of $0.26 per Mcf.

22 Q. Have you recalculated the Adjusted GCR Factor to reflect that GCR

23 customers and GCC customers are paying the Reservation Charge?

24 A. Yes, Exhibit A-30, lines 6 – 10, recalculates the Adjusted GCR Factor to account

25 for the fact that the Reservation Charge is being applied to GCR customers and

JAB Rebuttal - 9 J. A. BRUNELL Line U-17131 No.

1 GCC customers. The Reservation Charge of $0.26 per Mcf is multiplied by the

2 GCR plus GCC Adjusted sales volume of 141.8 Bcf to produce an April 2013 -

3 March 2014 Reservation Revenue of $36.9 million, shown on line 8. This amount

4 is slightly different from the Adjusted Pipeline Reservation Cost due to rounding.

5 The Reservation Charge revenue is subtracted from the Adjusted Cost of Gas,

6 shown on line 1, to produce the Adjusted Cost of Gas Less Reservation Charge

7 Revenue, which is $453 million, shown on line 9. That cost is divided by the GCR

8 Adjusted Sales Volumes, shown on line 4, to produce an Adjusted GCR Factor of

9 $4.38 per Mcf, found on line 10. The sum of the Adjusted GCR Factor and the

10 Reservation Charge is $4.64 per Mcf, which is the same as the Adjusted GCR

11 Factor on Exhibit A-27. The difference between billing the AGSs and billing

12 customers has no effect on the rates being charged to GCR customers. The only

13 result of charging customers for the Reservation Charge is an additional line item

14 on the bill, which will increase customer confusion and decrease customer

15 satisfaction.

17 Q. Will billing the Reservation Charge to GCR and GCC customers instead of the

18 AGSs change the reconciliation process?

19 A. Yes, the reconciliation process for the Reservation Charge is laid out in Exhibit A-

20 28. Page 4 of that exhibit calculated the proportion of the Pipeline Reservation that

21 was attributable to GCC sales and then compared that to the Reservation Revenue.

22 Exhibit A-31 is a revised version of that exhibit that eliminates that allocation, and

23 instead compares total Pipeline Reservation Cost, net of capacity release credits,

24 shown on line 3, to Actual Reservation Revenue, shown on line 4. The difference is

25 the Over (Under) Recovery. The balance of Exhibit A-28 remains structurally

JAB Rebuttal - 10 J. A. BRUNELL Line U-17131 No.

1 unchanged.

3 Q. Witness Crandall asserts that the Company’s proposed Reservation Charge

4 has not been sufficiently supported in this case. Do you agree that the

5 Company’s proposed Reservation Charge has not been sufficiently supported

6 in this case due to a lack of clarity regarding the disposition of the revenue

7 received through the Reservation Charge?

8 A. No, I disagree with witness Crandall’s assertion that DTE Gas’s proposed

9 Reservation Charge has not been sufficiently supported, or that there is a lack of

10 clarity regarding how the revenue received from the Reservation Charge will be

11 treated. Specifically, at page 14 of his testimony Michigan Community Action

12 Agency Association’s (MCAAA) witness Geoffry Crandall appears to be unclear

13 about whether or not the revenue received through the Reservation Charge will be

14 credited solely to GCR customers. At Page JAB - 13, lines 15-17 of my direct

15 testimony, I state that the “revenue received through the Reservation Charge will be

16 treated as an offset to the GCR Cost of Gas Sold, and the pipeline reservation costs

17 will remain a part of the GCR costs for GCR reconciliation purposes.” I addressed

18 this point again when discussing the proposed reconciliation of the Reservation

19 Charge on Page JAB - 16 of my direct testimony, while discussing page 2 of

20 Exhibit A-28, I state, “the revenues collected through the Reservation Charge are

21 identified on line 9 and treated as an offset to the GCR Cost of Gas Sold.” My

22 testimony and exhibits make clear that all revenue received through the reservation

23 charge will be treated as an offset to the GCR Cost of Gas Sold. Exhibit A-27

24 shows that the application of the Reservation Charge would reduce the maximum

25 GCR factor for this Plan period from $4.74 per Mcf to $4.64 per Mcf, a $0.10 per

JAB Rebuttal - 11 J. A. BRUNELL Line U-17131 No.

1 Mcf savings to GCR customers. Witness Crandall, at page 14 of his testimony

2 states that if DTE Gas’s Reservation Charge “removes an existing and real subsidy

3 to GCC customers funded on the backs of GCR customers,” then that proposed

4 charge was a good development. Since removing that subsidy is exactly the intent

5 and effect of the Reservation Charge, then with this understanding I assume witness

6 Crandall and the MCAAA in fact does support DTE Gas’s proposal.

8 Q. At page 15 of his testimony, Witness Crandall raises a concern about including

9 the Reservation Charge within a GCR proceeding but then states that his

10 concern would be ameliorated if the Reservation Charge is collecting expenses

11 currently born by GCR customers and if the revenue collected would be

12 credited 100% as an offset to the GCR Cost of Gas Sold. Are the costs that the

13 Reservation Charge collects currently being paid for by GCR customers?

14 A. Yes.

16 Q. Are the revenues collected through the Reservation Charge credited 100% to

17 the GCR Cost of Gas Sold?

18 A. Yes, and since both of witness Crandall’s criteria for including the Reservation

19 Charge within a GCR proceeding have been met, I assume he in fact agrees that it is

20 appropriate to include the Reservation Charge within this case.

22 Q. At page 5 of his testimony, witness Crandall states that due to the ratemaking

23 process, any spikes in gas prices will be recovered from customers over a

24 number of years and therefore the Company’s Fixed Price Program (FPP) is

25 not needed to protect customers from volatility in the market price for natural

JAB Rebuttal - 12 J. A. BRUNELL Line U-17131 No.

1 gas. Do you agree with that assertion?

2 A. No, the assertion that the costs arising from spikes in the spot price for natural gas

3 would be recovered over several years is inaccurate. DTE Gas’s maximum

4 allowable GCR factor can increase due to changes in the NYMEX prices for natural

5 gas through the Contingent Factor Matrix (CFM). The CFM can increase the GCR

6 factor to reflect up to a $3 change in the NYMEX price for natural gas.

7 Additionally, should the NYMEX price increase by more than $3, then DTE Gas

8 could file for a re-opener of its GCR Plan case in order to seek an increase in the

9 maximum GCR factor. Based on the current GCR FPP, which locks in 75% of

10 DTE Gas’s purchases by the time the GCR Plan is filed, the Fractional Multiplier in

11 the CFM is 0.315. That means for every $1.00 per Dth increase in the NYMEX

12 strip price, DTE Gas’s maximum allowable GCR factor will increase by $0.315 per

13 Mcf. If DTE Gas’s FPP were eliminated, then the Fractional Multiplier would need

14 to reflect the entire increase of the NYMEX in a rising price environment. The fact

15 that the current Fractional Multiplier is only 0.315 is proof that DTE Gas’s FPP is

16 protecting GCR customers from volatility in the price for natural gas.

18 Q. Does this complete your rebuttal testimony?

19 A. Yes, it does.

JAB Rebuttal - 13

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

REBUTTAL EXHIBITS

JAMES A. BRUNELL

Michigan Public Service Commission Case No.: U-17131 MICHIGAN CONSOLIDATED GAS COMPANY Exhibit: A-30 Adjusted GCR Factor and Calculation of Reservation Charge Witness: J. A. Brunell Applied to GCC and GCR Customers Page: 1 of 1

(a) (b) (c) (d) Line No. Description Source 1 Adjusted Cost of Gas $ 490,096 A-21, Line 16

2 GCR April 2013 - March 2014 Billed Sales Volumes 110,613 A-21, Line 17 3 March 2013 Unbilled Volume Balance (7,162) A-21, Line 18 4 April 2013 - March 2014 Adjusted Sales Volumes 103,451 A-21, Line 19 5 April 2013 - March 2014 Gas Cost Recovery Factor $ 4.74 A-21, Line 20

6 Pipeline Reservation Charge $ 0.26 Line 24 7 GCR + GCC April 2013 to March 2014 Billed Sales 141,830 Line 23 8 April 2013 - March 2014 Gas Reservation Charge Revenue $ 36,876 Line7 * Line 6 9 Adjusted Cost of Gas Less Reservation Charge Revenue $ 453,221 Line 1 - Line 8 10 Adjusted GCR Factor $ 4.38 Line 9 / Line 4

Calclulation of Reservation Charge 11 2013-2014 Pipeline Reservation Cost (PRC) $ 38,935 A-12, Line 22, pg 1 12 Calculation of March 2014 Unbilled Revenue Adjustment 13 2014-2015 Pipeline Reservation Cost $ 38,935 A-12, Line 22, pg 2 14 2014-2015 GCR + GCC Sales 151,172 A-1, Line 13 15 2014-2015 Average Reservation Charge $ 0.26 Line 13 / Line 14 16 March 2014 GCR + GCC Unbilled Volume Balance (9,497) 17 March 2014 GCR + GCC Revenue Adjustment $ (2,446) Line 15 * Line 16

18 Adjusted Pipeline Reservation Cost $ 36,489 Line 11 - Line 17

April 2013 - March 2014 Billed Sales Volumes 19 GCR 110,613 A-21 Line 17 20 GCC 40,748 A-4, pg 1, Line 14 21 Total Billed Sales (GCR + GCC) 151,361 Line 12 + Line 13 22 March 2013 GCR +GCC Unbilled Volume Balance (9,531) 23 April 2013 - March 2014 Adjusted Sales Volumes 141,830 Line 21 - Line 22

24 April 2013 - March 2014 Reservation Charge $ 0.26 Line 11 / Line 14 Michigan Public Service Commission Case No.: U-17131 MICHIGAN CONSOLIDATED GAS COMPANY Exhibit.: A-31 Example GCR and Reservation Charge Reconciliation Witness: J. A. Brunell Reservation Charge Billed to GCR and GCC Customers Page.: 1 of 1

(a) (b) Line No. Description Amount 1 Actual Pipeline Reservation Cost (PRC) $ 42,100 2 Less Capacity Release Credits (2,100) 3 Net Pipeline Reservation Cost 40,000 4 Actual Reservation Revenue 40,211 5 Over (Under) Recovery $ 211 STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

REBUTTAL TESTIMONY

W. BERNARD KRAMER

THE DETROIT EDISON COMPANY REBUTTAL TESTIMONY OF W. BERNARD KRAMER Line No.

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

2 A. My name is W. Bernard Kramer. My business address is One Energy Plaza,

3 Detroit, Michigan 48226. I am employed by DTE Energy Corporate Services LLC

4 (“DTE Energy” or “DTE”) in its Regulatory Policy and Operations Department as a

5 Regulatory Compliance Consultant.

7 Q. Did you previously file direct testimony in this proceeding on behalf of DTE

8 Gas Company (DTE Gas), which is formerly known as Michigan

9 Consolidated Gas Company (MichCon)?

10 A. Yes.

12 Q. Are you sponsoring any rebuttal exhibits in this proceeding?

13 A. Yes, I am sponsoring the following rebuttal exhibits that were prepared by me.

14 Exhibit Description

15 A-32 Shipper Index of ANR Pipeline Company

16 A-33 Shipper Index of Great Lakes Gas Transmission

17 A-34 Shipper Index of Panhandle Eastern Pipe Line

18 A-35 Shipper Index of Vector Pipeline

20 Q. What is the purpose of your rebuttal testimony?

21 The purpose of my rebuttal testimony is to address statements made by Interstate

22 Gas Supply (IGS) witness Matthew White and Retail Energy Supply Association

23 (RESA) witness Michael Haugh that AGSs are responsible for obtaining their own

24 capacity to deliver natural gas to the city gate.

WBK Rebuttal - 1 W. B. KRAMER Line U-17131 No. 1 IGS Witness Matthew White

2 Q. While discussing DTE Gas’ proposed Reservation Charge, witness White

3 states at page 9 of his testimony that “AGSs are responsible for obtaining their

4 own capacity to deliver natural gas to the city gate.” Does IGS hold any

5 primary firm interstate pipeline capacity for delivery to any of DTE Gas’

6 transmission system interconnects?

7 A. No, IGS does not hold any firm interstate pipeline capacity with a DTE Gas

8 interconnect (also known as the MichCon Generic delivery point) as the primary

9 delivery point.

10 11 Q. Is information regarding firm transportation contracts available to the

12 public?

13 A. Yes. The Federal Energy Regulatory Commission’s (“FERC”) regulations at 18

14 CFR § 284.13 (c) requires all interstate pipelines to file an index of customers

15 with the Commission on the first business day of each calendar quarter. The

16 Commission’s regulations also direct pipelines to post the index of customers on

17 the applicable pipeline’s Internet web site. The index must include the following

18 shipper contract information:

19 (i) The full legal name, and identification number, of the shipper;

20 (ii) The applicable rate schedule number under which the service is being

21 provided;

22 (iii) The contract number;

23 (iv) The effective and expiration dates of the contract;

WBK Rebuttal - 2 W. B. KRAMER Line U-17131 No. 1 (v) For transportation service, the maximum daily contract quantity (specify

2 unit of measurement), and for storage service, the maximum storage

3 quantity (specify unit of measurement);

4 (vi) The receipt and delivery points and zones or segments covered by the

5 contract in which the capacity is held, including the industry common

6 code for each point, zone, or segment;

7 (vii) An indication as to whether the contract includes negotiated rates;

8 (viii) The name of any agent or asset manager managing a shipper’s

9 transportation service; and

10 (ix) Any affiliate relationship between the pipeline and a shipper or between a

11 pipeline and a shipper’s asset manager or agent.

12 The FERC posts each shipper index on its public web site at www.ferc.gov, and

13 the shipper indexes can be viewed by the public at the FERC website or on each

14 pipeline’s web site.

16 Q. Did you obtain posted shipper indices for interstate pipelines that connect to

17 DTE Gas’s transmission system?

18 A. Yes, I obtained shipper indices for ANR Pipeline Company, Great Lakes Gas

19 Transmission, Vector Pipeline, and Panhandle Eastern Pipe Line. These are

20 attached to my rebuttal testimony as Exhibits A-32 through A-35.

WBK Rebuttal - 3 W. B. KRAMER Line U-17131 No. 1 Q. Did you review each shipper index to determine if IGS holds primary firm

2 interstate transportation capacity for delivery to any of DTE Gas’s

3 transmission system interconnects?

4 A. Yes.

6 Q. What did you find regarding whether IGS holds primary firm interstate

7 transportation capacity for delivery to any of DTE Gas’s transmission system

8 interconnects?

9 A. I found that IGS does not contract for primary firm interstate capacity for primary

10 delivery to any of DTE Gas’s transmission system interconnects.

12 Q. At page 10 of his testimony, witness White states that since DTE Gas is

13 holding enough capacity to serve as SOLR to both GCR and GCC customers,

14 despite the fact that AGSs are responsible for transporting gas to GCC

15 customers, it would indicate that DTE Gas is holding more capacity than it

16 needs. Do you agree with the assertion that DTE Gas is holding more

17 capacity than it needs for its SOLR role because the AGSs are responsible

18 for delivering gas for GCC customers?

19 A. No, I do not agree that DTE Gas is holding more capacity than it needs for its role

20 as SOLR. As discussed in the rebuttal testimony of witness Clinton, any capacity

21 held by the AGSs is in no way duplicative DTE Gas’s primary firm interstate

22 transport portfolio. Additionally, as discussed above, IGS holds no firm

23 transportation service to an interconnect with DTE Gas in DTE Gas’s service

WBK Rebuttal - 4 W. B. KRAMER Line U-17131 No. 1 territory. As provided in FERC’s regulations at 18 CFR 284.7 (a) (3), firm

2 transportation service is the highest priority service. Supply arrangements that

3 rely on lower-priority transportation services cannot offer the same reliability of

4 supply as firm transportation service.

5 6 RESA Witness Michael Haugh

7 Q. At page 6 of his testimony, witness Haugh states that GCC suppliers either

8 purchase firm capacity to DTE Gas’s city gate or purchase gas that is

9 delivered to the city gate. Witness Haugh contends that charging GCC

10 customers for the Reservation Charge will lead to GCC suppliers being

11 double charged for capacity. Do you agree that as a result of the Reservation

12 Charge that GCC customers will be double charged for capacity?

13 A. No, I do not agree that as a result of the Reservation Charge that GCC customers

14 will be double charged for capacity. I reviewed the four shipper indices contained

15 in Exhibits A-32 through A-35, and found that most of the members of RESA

16 listed in footnote 1 of witness Haugh’s testimony hold no long-term firm

17 transportation service to deliver gas to DTE Gas’s service territory. As I

18 previously stated, no other method of supply is as reliable as firm transportation

19 service. As discussed in the rebuttal testimony of witness Clinton, even if the

20 AGSs did hold firm transportation service it would not be duplicative of the

21 Company’s primary firm interstate transport portfolio.

23 Q. Does this complete your rebuttal testimony?

24 A. Yes.

WBK Rebuttal - 5

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

REBUTTAL EXHIBITS

W. BERNARD KRAMER

Michigan Public Service Commission Case No.: U-17131 DTE Gas Company Exhibit: A-32 Shipper Index of ANR Pipeline Witness: W. B. Kramer Page: 40 in total (Including cover page)

H ANR PIPELINE COMPANY 48 4/1/2013 O 41,365.0 T T T Rene Staeb832-320-5215 D LIBERTY ENERGY (MIDSTATES) CORP. 78314967 N ETS 1.0 11/1/1993 3/31/2014 N 3,850 00 A TWIN EAGLE RESOURCE MANAGEMENT, LLC N P MQ KIRKSVILLE 29 4602 MW6I 3850 0 0 P M2 S W HEADSTATION 29 103702 SW4A 3850 0 0 D LIBERTY ENERGY (MIDSTATES) CORP. 78314967 N ETS 50.0 11/1/1993 3/31/2014 N 1,104 00 A TWIN EAGLE RESOURCE MANAGEMENT, LLC N A TWIN EAGLE RESOURCE MANAGEMENT, LLC N P M2 KIRKSVILLE 29 4602 MW6I 1104 0 0 PMQ ANRPL STORAGE FACILITIES 29 153808 MI7E 1104 0 0 D INTERSTATE POWER AND LIGHT COMPANY 6940522 N ETS 200.0 11/1/1993 10/31/2014 N 7,816 00 P M2 S W HEADSTATION 29 103702 SW4A 7816 0 0 P MQ IES UTILITIES-GRP 1 29 139241 MW6K 7816 0 0 D MIDAMERICAN ENERGY COMPANY 884718768 N ETS 700.0 11/1/1993 3/31/2015 N 1,854 00 P M2 S W HEADSTATION 29 103702 SW4A 1854 0 0 P MQ MIDAMERICAN - GRP 1 29 139246 MW6K 1854 0 0 D MIDAMERICAN ENERGY COMPANY 884718768 N ETS 750.0 11/1/1993 3/31/2015 N 651 00 P M2 MIDAMERICAN - GRP 1 29 139246 MW6K 651 0 0 PMQ ANRPL STORAGE FACILITIES 29 153808 MI7E 651 0 0 D WISCONSIN POWER AND LIGHT COMPANY 7946452 N ETS 800.0 11/1/1993 10/31/2017 N 6,106 00 A TENASKA MARKETING VENTURES N P M2 S W HEADSTATION 29 103702 SW4A 6106 0 0 PMQ WISC POWER-GRP 1 29 139257 WI7J 6106 0 0 D WISCONSIN POWER AND LIGHT COMPANY 7946452 N ETS 820.0 11/1/1996 10/31/2017 N 4,948 00 P M2 S E HEADSTATION 29 103565 SE2A 4948 0 0 PMQ WISC POWER-GRP 1 29 139257 WI7J 4948 0 0 D WISCONSIN POWER AND LIGHT COMPANY 7946452 N ETS 840.0 11/1/1996 10/31/2017 N 3,375 00 P M2 MARSHFIELD/VIKING INT 29 28873 WI7Q 3375 0 0 PMQ WISC POWER-GRP 1 29 139257 WI7J 3375 0 0 D WISCONSIN POWER AND LIGHT COMPANY 7946452 N ETS 850.0 11/1/1993 3/31/2017 N 13,057 00 A TENASKA MARKETING VENTURES N PM2 WISC POWER-GRP 1 29 139257 WI7J 13057 00 PMQ ANRPL STORAGE FACILITIES 29 153808 MI7E 13057 00 D WISCONSIN PUBLIC SERVICE CORPORATION 7947435 N ETS 1,600.0 11/1/1993 3/31/2019 Y 46,267 00 PMQ WPSC - GROUP 1 29 139258 WI7K 46267 00 PM2 ANRPL STORAGE FACILITIES 29 153808 MI7E 46267 00 D OHIO VALLEY GAS CORPORATION 6940274 N ETS 1,650.0 11/1/1993 3/31/2019 N 1,650 00 A BP CANADA ENERGY MARKETING CORP. N P M2 S W HEADSTATION 29 103702 SW4A 1650 0 0 P MQ OHIO VAL-GRP 1 29 139236 ME3C 1650 0 0 D OHIO VALLEY GAS CORPORATION 6940274 N ETS 1,700.0 11/1/1993 3/31/2019 N 1,183 00 A BP CANADA ENERGY MARKETING CORP. N P M2 OHIO VAL-GRP 1 29 139236 ME3C 1183 0 0 PMQ ANRPL STORAGE FACILITIES 29 153808 MI7E 1183 0 0 D INTERSTATE POWER AND LIGHT COMPANY 6940522 N ETS 1,800.0 11/1/1993 3/31/2014 N- 00 P M2 IES UTILITIES-GRP 1 29 139241 MW6K 000 PMQ ANRPL STORAGE FACILITIES 29 153808 MI7E 0 0 0 D WISCONSIN PUBLIC SERVICE CORPORATION 7947435 N ETS 5,450.0 5/1/1997 3/31/2019 Y 7,300 00 P M2 S W HEADSTATION 29 103702 SW4A 7300 0 0 PMQ WPSC - GROUP 1 29 139258 WI7K 7300 0 0 D WISCONSIN PUBLIC SERVICE CORPORATION 7947435 N ETS 5,500.0 5/1/1997 10/31/2023 Y - 00 P M2 MARSHFIELD/VIKING INT 29 28873 WI7Q 0 0 0 PMQ WPSC - GROUP 1 29 139258 WI7K 000 D WISCONSIN PUBLIC SERVICE CORPORATION 7947435 N FTS-1 12,000.0 11/1/1993 10/31/2023 Y - 00 P MQ OSHKOSH 29 28868 WI7H 0 0 0 P M2 MARSHFIELD/VIKING INT 29 28873 WI7Q 0 0 0 D OHIO VALLEY GAS CORPORATION 6940274 N FTS-1 15,350.0 11/1/1993 3/31/2019 N 2,420 00 A BP CANADA ENERGY MARKETING CORP. N P M2 S W HEADSTATION 29 103702 SW4A 2420 0 0 P MQ LYNN/WINCHESTER 29 138745 ME3B 2420 0 0 D OHIO VALLEY GAS CORPORATION 6940274 N FTS-1 15,400.0 11/1/1993 3/31/2019 N 1,735 00 A BP CANADA ENERGY MARKETING CORP. N P M2 LYNN/WINCHESTER 29 138745 ME3B 1735 0 0 PMQ ANRPL STORAGE FACILITIES 29 153808 MI7E 1735 0 0 D LIBERTY ENERGY (MIDSTATES) CORP. 78314967 N FTS-1 18,450.0 11/1/1993 3/31/2014 N 954 00 A TWIN EAGLE RESOURCE MANAGEMENT, LLC N P M2 S W HEADSTATION 29 103702 SW4A 954 0 0 PMQ ANRPL STORAGE FACILITIES 29 153808 MI7E 954 0 0 D UNITED STATES GYPSUM COMPANY 5212600 N FTS-1 19,750.0 11/1/1993 3/31/2014 N 5,500 00 P M2 S W HEADSTATION 29 103702 SW4A 5500 0 0 PMQ ANR JOLIET HUB 29 243097 MI7F 5500 0 0 D LIBERTY ENERGY (MIDSTATES) CORP. 78314967 N FSS 30,000.0 11/1/1993 3/31/2014 N- 193200 0 A TWIN EAGLE RESOURCE MANAGEMENT, LLC N PSB ANRPL STORAGE FACILITIES 29 153808 MI7E 0 193200 0 PIJ ANRPL STORAGE FACILITIES 29 153808 MI7E 0 1104 0 P WR ANRPL STORAGE FACILITIES 29 153808 MI7E 0 3864 0 D MIDAMERICAN ENERGY COMPANY 884718768 N FSS 30,300.0 11/1/1993 3/31/2015 N- 113850 0 PSB ANRPL STORAGE FACILITIES 29 153808 MI7E 0 113850 0 PIJ ANRPL STORAGE FACILITIES 29 153808 MI7E 0 651 0 P WR ANRPL STORAGE FACILITIES 29 153808 MI7E 0 2277 0 D WISCONSIN POWER AND LIGHT COMPANY 7946452 N FSS 30,350.0 11/1/1993 3/31/2017 N- 2027900 0 PSB ANRPL STORAGE FACILITIES 29 153808 MI7E 0 2027900 0 PIJ ANRPL STORAGE FACILITIES 29 153808 MI7E 0 11588 0 P WR ANRPL STORAGE FACILITIES 29 153808 MI7E 0 40558 0 D OHIO VALLEY GAS CORPORATION 6940274 N FSS 30,500.0 11/1/1993 3/31/2019 N- 303600 0 A BP CANADA ENERGY MARKETING CORP. N PSB ANRPL STORAGE FACILITIES 29 153808 MI7E 0 303600 0 PIJ ANRPL STORAGE FACILITIES 29 153808 MI7E 0 1735 0 P WR ANRPL STORAGE FACILITIES 29 153808 MI7E 0 6072 0 D OHIO VALLEY GAS CORPORATION 6940274 N FSS 30,950.0 11/1/1993 3/31/2019 N- 207000 0 A BP CANADA ENERGY MARKETING CORP. N PSB ANRPL STORAGE FACILITIES 29 153808 MI7E 0 207000 0 PIJ ANRPL STORAGE FACILITIES 29 153808 MI7E 0 1183 0 P WR ANRPL STORAGE FACILITIES 29 153808 MI7E 0 4140 0 D INTERSTATE POWER AND LIGHT COMPANY 6940522 N FSS 31,050.0 11/1/1993 3/31/2014 N- 1578418 0 PSB ANRPL STORAGE FACILITIES 29 153808 MI7E 0 1578418 0 PIJ ANRPL STORAGE FACILITIES 29 153808 MI7E 0 9020 0 P WR ANRPL STORAGE FACILITIES 29 153808 MI7E 0 19249 0 D LIBERTY ENERGY (MIDSTATES) CORP. 78314967 N FSS 32,250.0 11/1/1993 3/31/2014 N- 190700 0 A TWIN EAGLE RESOURCE MANAGEMENT, LLC N PSB ANRPL STORAGE FACILITIES 29 153808 MI7E 0 190700 0 PIJ ANRPL STORAGE FACILITIES 29 153808 MI7E 0 954 0 P WR ANRPL STORAGE FACILITIES 29 153808 MI7E 0 3814 0 D LIBERTY ENERGY (MIDSTATES) CORP. 78314967 N NNS 99,500.0 11/1/1993 3/31/2014 N 1,500 00 A ATMOS ENERGY CORPORATION N P MQ KIRKSVILLE 29 4602 MW6I 1500 0 0 D INTERSTATE POWER AND LIGHT COMPANY 6940522 N NNS 99,502.0 11/1/1993 3/31/2014 N 5,000 00 P MQ IES UTILITIES-GRP 1 29 139241 MW6K 5000 0 0 D SEMCO ENERGY, INC., DBA SEMCO ENERGY GAS CO 6960553 N NNS 99,505.0 11/1/1993 3/31/2015 N 2,500 00 P MQ SEM GAS - GRP 1 29 139249 MI7C 2500 0 0 D MIDAMERICAN ENERGY COMPANY 884718768 N NNS 99,508.0 11/1/1993 3/31/2015 N 800 00 P MQ MIDAMERICAN - GRP 1 29 139246 MW6K 800 0 0 D WISCONSIN POWER AND LIGHT COMPANY 7946452 N NNS 99,509.0 11/1/1993 3/31/2017 N 9,500 00 PMQ WISC POWER-GRP 1 29 139257 WI7J 9500 0 0 D OHIO VALLEY GAS CORPORATION 6940274 N NNS 99,512.0 11/1/1993 3/31/2019 N 1,500 00 A BP CANADA ENERGY MARKETING CORP. N P MQ OHIO VAL-GRP 2 29 139374 ME3B 1500 0 0 D WISCONSIN PUBLIC SERVICE CORPORATION 7947435 N NNS 99,515.0 11/1/1993 3/31/2019 Y 9,964 00 PMQ WPSC - GROUP 1 29 139258 WI7K 9964 0 0 D OHIO VALLEY GAS CORPORATION 6940274 N NNS 99,517.0 11/1/1993 3/31/2019 N 1,500 00 A BP CANADA ENERGY MARKETING CORP. N P MQ OHIO VAL-GRP 1 29 139236 ME3C 1500 0 0 D CENTERPOINT ENERGY RESOURCES CORP. DBA CE 803838838 N FTS-1 102,083.0 10/1/1998 10/31/2013 N 400 00 P M2 S W HEADSTATION 29 103702 SW4A 400 0 0 P MQ HANOR ROBERTS RANCH INT 29 221448 SW3B 400 0 0 D TOWN OF SOMERVILLE, TENNESSEE 99181786 N STS 102,722.0 11/1/1999 3/31/2014 N 4,500 123750 0 A THE TENNERGY CORPORATION N P M2 S E HEADSTATION 29 103565 SE2A 2025 0 0 PM2 ANRPL STORAGE FACILITIES 29 153808 MI7E 2475 123750 0 PMQ ANRPL STORAGE FACILITIES 29 153808 MI7E 2475 123750 0 P MQ SOMERVILLE GROUP 1 29 267228 ME2C 4500 0 0 D WISCONSIN POWER AND LIGHT COMPANY 7946452 N FSS 103,371.0 6/1/1999 3/31/2017 Y - 1505400 0 PSB ANRPL STORAGE FACILITIES 29 153808 MI7E 0 1505400 0 PIJ ANRPL STORAGE FACILITIES 29 153808 MI7E 0 8602 0 P WR ANRPL STORAGE FACILITIES 29 153808 MI7E 0 20072 0 D WISCONSIN PUBLIC SERVICE CORPORATION 7947435 N FTS-1 104,404.0 4/1/2003 3/31/2019 Y 46,045 00 P M2 S W HEADSTATION 29 103702 SW4A 46045 0 0 PMQ ANRPL STORAGE FACILITIES 29 153808 MI7E 46045 0 0 D WISCONSIN PUBLIC SERVICE CORPORATION 7947435 N FTS-1 104,405.0 11/1/2000 3/31/2019 Y - 00 P MQ FARWELL (DELIVERY) 29 11616 MI7E 0 0 0 PM2 ANRPL STORAGE FACILITIES 29 153808 MI7E 0 0 0 D CITY OF MURRAY, KENTUCKY 956401889 N FTS-1 104,491.0 11/1/2000 10/31/2014 N 150 00 P M2 S E HEADSTATION 29 103565 SE2A 150 0 0 P MQ MURRAY INTERCONNECT 29 283195 ME2C 150 0 0 D INTEGRYS ENERGY SERVICES, INC. 841739824 N FTS-1 104,665.0 11/1/2000 10/31/2013 N 1,400 00 P MQ STEVENS POINT 29 28794 WI7T 1400 0 0 PM2 ALLIANCE/ANR INT 29 277072 MI7U 1400 0 0 D WISCONSIN POWER AND LIGHT COMPANY 7946452 N ETS 104,845.0 11/1/2000 3/31/2017 N- 00 P M2 S W HEADSTATION 29 103702 SW4A 000 PMQ WISC POWER-GRP 1 29 139257 WI7J 0 0 0 D CENTERPOINT ENERGY SERVICES, INC. 838611739 N FTS-1 105,424.0 11/1/2000 10/31/2013 N 356 00 P MQ MENOMINEE FALLS 29 28834 WI7D 356 0 0 PM2 ALLIANCE/ANR INT 29 277072 MI7U 356 0 0 D CENTERPOINT ENERGY SERVICES, INC. 838611739 N FTS-1 105,428.0 11/1/2000 10/31/2013 N 2,898 00 P MQ NORTH MADISON 29 36868 WI7U 2898 0 0 PM2 ALLIANCE/ANR INT 29 277072 MI7U 2898 0 0 D CENTERPOINT ENERGY SERVICES, INC. 838611739 N FTS-1 105,429.0 11/1/2000 10/31/2013 N 324 00 P MQ NEW BERLIN 29 28841 WI7D 324 0 0 PM2 ALLIANCE/ANR INT 29 277072 MI7U 324 0 0 D CENTERPOINT ENERGY SERVICES, INC. 838611739 N FTS-1 105,430.0 11/1/2000 10/31/2013 N 180 00 PMQ WINCHESTER (WEP SALES) 29 100052 WI7H 180 0 0 PM2 ALLIANCE/ANR INT 29 277072 MI7U 180 0 0 D SEMCO ENERGY, INC., DBA SEMCO ENERGY GAS CO 6960553 N ETS 106,023.0 4/1/2001 3/31/2014 N 22,345 00 A BP CANADA ENERGY MARKETING CORP. N P M2 S E HEADSTATION 29 103565 SE2A 22345 0 0 P MQ SEM GAS - GRP 1 29 139249 MI7C 22345 0 0 D NEWPAGE WISCONSIN SYSTEM INC. 945543770 N FSS 106,041.0 4/1/2001 3/31/2014 N- 1080000 0 PSB ANRPL STORAGE FACILITIES 29 153808 MI7E 0 1080000 0 PIJ ANRPL STORAGE FACILITIES 29 153808 MI7E 0 5400 0 P WR ANRPL STORAGE FACILITIES 29 153808 MI7E 0 7200 0 D NEWPAGE WISCONSIN SYSTEM INC. 945543770 N FTS-1 106,052.0 4/1/2001 3/31/2014 N- 00 A INTEGRYS ENERGY SERVICES - NATURAL GAS, LLC N P MQ STEVENS POINT 29 28794 WI7T 0 0 0 PM2 ANRPL STORAGE FACILITIES 29 153808 MI7E 0 0 0 D NEWPAGE WISCONSIN SYSTEM INC. 945543770 N FTS-1 106,054.0 4/1/2001 3/31/2014 N 4,124 00 A INTEGRYS ENERGY SERVICES - NATURAL GAS, LLC N PMQ WISCONSIN RAPIDS 29 28883 WI7X 4124 0 0 PM2 ALLIANCE/ANR INT 29 277072 MI7U 4124 0 0 D NEWPAGE WISCONSIN SYSTEM INC. 945543770 N FTS-1 106,055.0 4/1/2001 3/31/2014 N- 00 PMQ WISCONSIN RAPIDS 29 28883 WI7X 000 PM2 ANRPL STORAGE FACILITIES 29 153808 MI7E 0 0 0 D MIDLAND COGENERATION VENTURE LIMITED PAR 185055373 N FTS-1 106,102.0 11/1/2001 2/28/2025 N 21,000 00 A SHELL ENERGY NORTH AMERICA (US), L.P. N P MQ STAG LAKE(ST JOSEPH CO) 29 22992 MI7J 21000 0 0 P M2 S E HEADSTATION 29 103565 SE2A 21000 0 0 D NORTHERN INDIANA PUBLIC SERVICE COMPANY 6937585 N ETS 106,116.0 5/1/2001 3/31/2015 N 2,172 00 P M2 S E HEADSTATION 29 103565 SE2A 2172 0 0 P MQ NIPSCO - GROUP 1 29 139235 ME3E 2172 0 0 D NORTHERN INDIANA PUBLIC SERVICE COMPANY 6937585 N ETS 106,118.0 5/1/2001 3/31/2015 N 2,273 00 P M2 S E HEADSTATION 29 103565 SE2A 2273 0 0 P MQ NIPSCO - GROUP 2 29 139366 MI7J 2273 0 0 D WISCONSIN PUBLIC SERVICE CORPORATION 7947435 N FTS-1 106,199.0 6/1/2001 3/31/2019 Y - 00 P M2 S W HEADSTATION 29 103702 SW4A 000 PMQ ANRPL STORAGE FACILITIES 29 153808 MI7E 0 0 0 D NORTHERN STATES POWER COMPANY, A MINNESO 6962419 N FTS-1 106,209.0 5/1/2001 3/31/2015 N 4,829 00 P MQ MARSHFIELD/VIKING INT 29 28873 WI7Q 4829 0 0 P M2 S W HEADSTATION 29 103702 SW4A 4829 0 0 D NORTHERN STATES POWER COMPANY, A MINNESO 6962419 N FTS-1 106,211.0 5/1/2001 3/31/2015 N 4,855 00 P M2 MARSHFIELD/VIKING INT 29 28873 WI7Q 4855 0 0 PMQ ANRPL STORAGE FACILITIES 29 153808 MI7E 4855 0 0 D NORTHERN STATES POWER COMPANY, A MINNESO 6962419 N FSS 106,212.0 5/1/2001 3/31/2015 Y - 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CLAIR 29 11772 East 24,312 0 D SUPERIOR WATER, LIGHT AND PO 799110648 N FT 7376 39,539 3/31/2018 N 1,000 P M2 EMERSON 29 33975 West 1,000 0 P M2 FARWELL 29 11601 East 1,000 0 P MQ CARLTON 29 11842 West 1,000 0 P MQ CLOQUET 29 11847 West 1,000 0 P MQ DULUTH 29 385360 West 1,000 0 P MQ MIDLAND 29 169334 East 1,000 0 P MQ SUPERIOR 29 304366 West 1,000 0 P MQ FARWELL 29 11601 East 1,000 0 P MQ FORTUNE LAKE 29 11655 Central 1,000 0 P MQ GRAND RAPIDS NMU 29 11903 West 1,000 0 D TENASKA MARKETING VENTURES 624240628 N FT 17773 41,365 4/30/2013 N 76,000 P M2 EMERSON 29 33975 West 76,000 0 P MQ ST. CLAIR 29 11772 East 76,000 0 D THE SOUTHERN CONNECTICUT GA 4945259 N FT 6534 39,753 3/31/2015 N - A CONNECTICUT NATURAL GAS CORN P M2 FARWELL 29 11601 East - 0 P MQ ST. CLAIR 29 11772 East - 0 D TRANSCANADA PIPELINES LIMITE 249052259 Y FT 17189 41,214 10/31/2014 N 100,000 P M2 EMERSON 29 33975 West 100,000 0 P MQ ST. CLAIR 29 11772 East 100,000 0 D TRANSCANADA PIPELINES LIMITE 249052259 Y FT 17190 41,214 10/31/2015 N 160,000 P M2 ST. CLAIR 29 11772 East 160,000 0 P MQ EMERSON 29 33975 West 160,000 0 D TRANSCANADA PIPELINES LIMITE 249052259 Y FT 17193 41,214 10/31/2015 N - P M2 ST. CLAIR 29 11772 East - 0 P MQ SAULT STE. MARIE TCPL 29 11597 Central - 0 D TRANSCANADA PIPELINES LIMITE 249052259 Y FT 16128 40,848 10/31/2014 N 313,727 P M2 ST. CLAIR 29 11772 East 313,727 0 P MQ EMERSON 29 33975 West 313,727 0 D TWIN EAGLE RESOURCE MANAGEM 965177889 N FT 16885 40,851 10/31/2013 N 20,000 P M2 EMERSON 29 33975 West 20,000 0 P MQ ST. CLAIR 29 11772 East 20,000 0 D U.S. ENERGY SERVICES, INC. 808703524 N FT 17768 41,365 5/31/2013 N 1,050 P M2 EMERSON 29 33975 West 1,050 0 P MQ DULUTH 29 385360 West 1,050 0 D UNION GAS LIMITED 200408144 N FT 16152 40,848 10/31/2014 N 5,829 P M2 BELLE RIVER MILLS 29 11771 East 5,829 0 P MQ SAULT STE. MARIE TCPL 29 11597 Central 5,829 0 D UNITED STATES GYPSUM COMPAN 5212600 N FT 1047 36,708 10/31/2014 N 1,825 P M2 EMERSON 29 33975 West 1,825 0 P MQ FORTUNE LAKE 29 11655 Central 1,825 0 D UNITED STATES GYPSUM COMPAN 5212600 N FT 3140 37,834 10/31/2014 N 3,500 P M2 EMERSON 29 33975 West 3,500 0 P MQ ST. CLAIR 29 11772 East 3,500 0 P MQ CARLTON 29 11842 West 3,500 0 D UNITED STATES GYPSUM COMPAN 5212600 N FT 8525 39,539 3/31/2014 N 750 P M2 EMERSON 29 33975 West 750 0 P MQ ST. CLAIR 29 11772 East 750 0 D UNITED STATES GYPSUM COMPAN 5212600 N FT 187 35,065 10/31/2014 N 8,000 P M2 EMERSON 29 33975 West 8,000 0 P MQ CARLTON 29 11842 West 8,000 0 D WISCONSIN ELECTRIC POWER COM 7947385 N FT 554 35,947 5/31/2018 N 1,655 X12 P M2 FARWELL 29 11601 East 1,655 0 P MQ DUCK CREEK 29 245609 Central 1,655 0 D WISCONSIN PUBLIC SERVICE CORP 7947435 N FT 555 36,100 3/31/2019 N - X14 P M2 FARWELL 29 11601 East - 0 P MQ DUCK CREEK 29 245609 Central - 0

F 3 MDQ IS 0 FOR APRIL 1 THROUGH OCTOBER 31 AND 557,150 FOR NOVEMBER 1 THROUGH MARCH 31. F 5 MDQ IS 0 FOR APRIL 1 THROUGH OCTOBER 31 AND 405,200 FOR NOVEMBER 1 THROUGH MARCH 31. F 12 MDQ IS 1,655 FOR APRIL 1 THROUGH OCTOBER 31 AND 6,425 FOR NOVEMBER 1 THROUGH MARCH 31. F 14 MDQ IS 0 FOR APRIL 1 THROUGH OCTOBER 31 AND 7,000 FOR NOVEMBER 1 THROUGH MARCH 31. Michigan Public Service Commission Case No.: U-17131 DTE Gas Company Exhibit: A-34 Shipper Index of Panhandle Eastern Pipe Line Witness: W. B. Kramer Page: 18 in total (Including cover page) H PANHANDLE EASTERN PIPE LINE CO 28 4/1/2013 O 4/1/2013 T T STEPHEN T. VEATCH (713) 989-2024 D ALSEY REFRACTORIES COMPANY 57746265 N EFT 11521 5/1/1993 10/31/2018 N 385 A SEMINOLE ENERGY SERVICES, L.L.CN P M2 PEPL CIG EXCHANGE 29 46886 FLD 385 PMQ ALSEY REFRACTORIES 29 4088 MKT 385 D AMARILLO NATURAL GAS, INC. 183128321 N EFT 14084 11/6/1995 10/31/2014 N 75 A WTG GAS MARKETING, INC. N P M2 TRANSWESTERN - SNEED 29 22706 FLD 75 P MQ SEABOARD BECKER 1-7 29 185969 FLD 25 P MQ SEABOARD FARMS - DEPUY DELIVERY 29 203543 FLD 25 P MQ SEABOARD FARMS - WITTAKER 1-6 29 185968 FLD 25 D AMEREN ILLINOIS COMPANY 6936017 N EFT 11745 5/1/1993 3/31/2015 N 119,200 A AMEREN ILLINOIS COMPANY N PM2 ANADARKO LIBERAL RECEIPT 29 201534 FLD 51000 P M2 CHANEY DELL - ATLAS PIPELINE MID-CO 29 38465 FLD 5000 P M2 ELK CITY PLANT - ENBRIDGE G & P (OK 29 16494 FLD 14000 P M2 ENOGEX - CARPENTER 29 48393 FLD 6500 P M2 MOBIL - ELK CITY PLANT 29 38407 FLD 2500 P M2 PEPL CIG EXCHANGE 29 46886 FLD 20200 P M2 TRANSWESTERN - SNEED 29 22706 FLD 20000 PMQ AMEREN ILLINOIS 29 1260730 MKT 119200 D AMEREN ILLINOIS COMPANY 6936017 N FS 13620 4/1/1995 3/31/2018 N 9390000 A AMEREN ILLINOIS COMPANY N PIJ AMEREN ILLINOIS - FS 29 183645 FLD 60418 P WR AMEREN ILLINOIS - FS 29 183645 FLD 106150 D AMEREN ILLINOIS COMPANY 6936017 N EFT 14979 9/1/1996 3/31/2018 N 25,000 A AMEREN ILLINOIS COMPANY N P M2 PANHANDLE BOURBON 29 3715 MKT 25000 PMQ AMEREN ILLINOIS 29 1260730 MKT 25000 D AMEREN ILLINOIS COMPANY 6936017 N EFT 15101 11/1/1996 3/31/2015 N 30,000 A AMEREN ILLINOIS COMPANY N P M2 PANHANDLE BOURBON 29 3715 MKT 30000 PMQ AMEREN ILLINOIS 29 1260730 MKT 30000 D AMEREN ILLINOIS COMPANY 6936017 N EFT 16216 4/1/1999 3/31/2018 N 45,000 A AMEREN ILLINOIS COMPANY N P M2 PHILLIPS HANSFORD RESIDUE - WIT 29 38592 FLD 30000 P M2 SATANTA / RICHFIELD CTM 29 245054 FLD 10000 P M2 TRANSWESTERN - SNEED 29 22706 FLD 5000 PMQ AMEREN ILLINOIS 29 1260730 MKT 45000 D AMEREN ILLINOIS COMPANY 6936017 N EFT 22633 8/1/2008 7/31/2018 N 10,000 P M2 PANHANDLE BOURBON 29 3715 MKT 10000 PMQ AMEREN ILLINOIS 29 1260730 MKT 10000 D AMEREN ILLINOIS COMPANY 6936017 N EFT 26857 4/1/2010 3/31/2036 N 8,000 A AMEREN ILLINOIS COMPANY N PM2 WESTANA POINT 29 183687 FLD 8000 PMQ AMEREN ILLINOIS 29 1260730 MKT 8000 D AMEREN ILLINOIS COMPANY 6936017 N EFT 34599 4/1/2012 3/31/2018 N 45,000 PM2 AMEREN ILLINOIS 29 1260730 MKT 45000 P MQ PANHANDLE BOURBON 29 3715 MKT 45000 D AMERICAN MUNICIPAL POWER, INC 105687560 N EFT 25129 4/1/2010 10/31/2022 N 40,000 A THE ENERGY AUTHORITY, INC. 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VESTA ENERGY #3 29 127848 FLD 500 PMQ VILLAGE OF FRANKLIN 29 4015 MKT 500 D VILLAGE OF FRANKLIN 36790558 N SCT 16066 10/1/1998 3/31/2017 N 500 A INTERSTATE MUNICIPAL GAS AGENN PM2 ANR DEFIANCE 29 15671 MKT 500 PMQ VILLAGE OF FRANKLIN 29 4015 MKT 500 D VILLAGE OF MORTON 82089939 N SCT 11506 5/1/1993 3/31/2015 N 9,999 A UTILITY GAS MANAGEMENT N P M2 HT - DUKE ENERGY TRADING AND MARKET 29 127931 FLD 9999 PMQ VILLAGE OF MORTON 29 4079 MKT 9999 D VILLAGE OF MORTON 82089939 N IOS 12048 5/1/1993 3/31/2015 N 200000 A UTILITY GAS MANAGEMENT N PIJ VILLAGE OF MORTON - IOS 29 129025 FLD 1000 P WR VILLAGE OF MORTON - IOS 29 129025 FLD 2000 D VILLAGE OF PAWNEE (UTILITIES DE 33553801 N SCT 11507 5/1/1993 3/31/2015 N 1,550 A UTILITY GAS MANAGEMENT N P M2 HT - ANADARKO TRADING #2 29 127940 FLD 1550 PMQ VILLAGE OF PAWNEE 29 4085 MKT 1550 D VILLAGE OF PLEASANT HILL 80702384 N SCT 11508 5/1/1993 3/31/2017 N 725 A INTERSTATE MUNICIPAL GAS AGENN P M2 HT - OCCIDENTAL ENERGY MARKETING 29 127874 FLD 363 P M2 HT - VESTA ENERGY #3 29 127848 FLD 362 PMQ VILLAGE OF PLEASANT HILL 29 4037 MKT 725 D VILLAGE OF PLEASANT HILL 80702384 N SCT 16068 10/1/1998 3/31/2017 N 725 A INTERSTATE MUNICIPAL GAS AGENN PM2 ANR DEFIANCE 29 15671 MKT 725 PMQ VILLAGE OF PLEASANT HILL 29 4037 MKT 725 D VILLAGE OF RIVERTON 87159174 N SCT 16060 7/1/2001 3/31/2014 N 1,800 A INTERSTATE MUNICIPAL GAS AGENN P M2 HT - OCCIDENTAL ENERGY MARKETING 29 127874 FLD 900 P M2 HT - VESTA ENERGY #3 29 127848 FLD 900 PMQ VILLAGE OF RIVERTON 29 4081 MKT 1800 D VILLAGE OF RIVERTON 87159174 N SCT 23487 12/1/2007 3/31/2014 N 1,800 A INTERSTATE MUNICIPAL GAS AGENN PM2 ANR DEFIANCE 29 15671 MKT 1800 PMQ VILLAGE OF RIVERTON 29 4081 MKT 1800 D VILLAGE OF ROSSVILLE (MUNICIPA 859617029 N SCT 11510 5/1/1993 3/31/2017 N 990 A INTERSTATE MUNICIPAL GAS AGENN P M2 HT - VESTA ENERGY #3 29 127848 FLD 990 PMQ VILLAGE OF ROSSVILLE 29 4124 MKT 990 D VILLAGE OF ROSSVILLE (MUNICIPA 859617029 N SCT 25102 11/1/2008 3/31/2017 N 990 A INTERSTATE MUNICIPAL GAS AGENN PM2 ANR DEFIANCE 29 15671 MKT 990 PMQ VILLAGE OF ROSSVILLE 29 4124 MKT 990 D VILLAGE OF STONINGTON 31114309 N SCT 11511 5/1/1993 3/31/2015 N 1,400 A CONSTELLATION NEWENERGY - GA N P M2 HT - ONEOK ENERGY SERVICES 29 223319 FLD 1400 PMQ VILLAGE OF STONINGTON 29 3616 MKT 1400 D VILLAGE OF WESTVILLE 84314038 N SCT 11512 5/1/1993 3/31/2015 N 2,500 A CONSTELLATION NEWENERGY - GA N P M2 HT - VESTA ENERGY #3 29 127848 FLD 2500 PMQ VILLAGE OF WESTVILLE 29 3739 MKT 2500 D VISCOFAN USA INC. 101392103 N EFT 11708 5/1/1993 3/31/2015 N 3,000 A BP ENERGY COMPANY N P M2 CIG PAN BAKER EXCHANGE - WIT 29 48995 FLD 1500 P M2 PEPL CIG EXCHANGE 29 46886 FLD 1500 PMQ AMEREN ILLINOIS 29 1260730 MKT 3000 F 1 DUNS NUMBER IS NOT AVAILABLE. THE NUMBER PROVIDED IS COMPANY'S OWN IDENTIFICATION NUMBER. F 4 DRN NUMBER HAS NOT BEEN ASSIGNED. THE POINT NUMBER PROVIDED IS COMPANY'S OWN IDENTIFICATION NUMBER. Michigan Public Service Commission Case No.: U-17131 DTE Gas Company Exhibit: A-35 Shipper Index of Vector Pipeline Witness: W. B. Kramer Page: 4 in total (Including cover page) H Vector Pipeline L.P. 175 4/1/2013 R 4/1/2013 T Lisa A. Steinman 734-462-0232 D Bay State Gas Company 69340214 N FT-1 FT1-BAY-0186 4/1/2007 3/31/2016 N 26,645 A Repsol Energy North America Corpor N PM2 Washington 10 Interconnect 29 287427 Zone 2 26645 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 26645 D Bay State Gas Company 69340214 N FT-1 FT1-BAY-0187 4/1/2007 3/31/2016 N 14,645 PM2 Alliance Interconnect 29 287415 Zone 1 14645 PMQ Washington 10 Interconnect 29 287427 Zone 2 14645 D Bluewater Gas Storage LLC 146848804 N FT-1 FT1-BLU-4084 4/1/2013 10/31/2017 N 5,000 P M2 Guardian Interconnect 29 395745 Zone 1 5000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 5000 D Bluewater Gas Storage LLC 146848804 N FT-H FTH-BLU-0004 4/1/2013 3/31/2014 N 6,400 P M2 Bluewater Interconnect 29 388031 Zone 2 6400 P MQ Jackson Interconnect 29 316082 Zone 2 6400 D BP Canada Energy Marketing Corp. 248799413 N FT-1 FT1-BPC-0418 11/1/2007 10/31/2017 N 50,000 PM2 Alliance Interconnect 29 287415 Zone 1 50000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 50000 D BP Canada Energy Marketing Corp. 248799413 N FT-1 FT1-BPC-0419 11/1/2007 3/31/2017 N 100,000 x1 PM2 Washington 10 Interconnect 29 287427 Zone 2 100000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 100000 D BP Canada Energy Marketing Corp. 248799413 N FT-1 FT1-BPC-1301 11/1/2009 10/31/2016 N 60,000 PM2 Alliance Interconnect 29 287415 Zone 1 60000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 60000 D The Brooklyn Union Gas Company d/ 6978795 N FT-1 FT1-KNY-0415 11/1/2007 10/31/2017 N 12,500 A BG Energy Merchants LLC N PM2 Alliance Interconnect 29 287415 Zone 1 12500 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 12500 D Connecticut Natural Gas Corporation 1139294 N FT-1 FT1-CNG-0416 11/1/2007 3/31/2017 N 9,700 x2 PM2 Washington 10 Interconnect 29 287427 Zone 2 9700 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 9700 D Crete Energy Venture LLC 40065091 N FT-1 FT1-CRE-0004 2/1/2002 1/31/2027 Y 108,000 P M2 Crete Interconnect 29 316078 Zone 1 108000 P MQ Crete Interconnect 29 316078 Zone 1 108000 D DTE Energy Trading Inc. 179989231 Y FT-1 FT1-DTE-0005 12/1/2000 11/30/2015 Y 200,000 PM2 Alliance Interconnect 29 287415 Zone 1 200000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 200000 D DTE Energy Trading Inc. 179989231 Y FT-1 FT1-DTE-0425 11/1/2007 10/31/2017 N 70,000 PM2 Alliance Interconnect 29 287415 Zone 1 70000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 70000 D DTE Energy Trading Inc. 179989231 Y FT-1 FT1-DTE-0426 11/1/2007 3/31/2017 N 70,000 x3 PM2 Washington 10 Interconnect 29 287427 Zone 2 70000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 70000 D DTE Gas Company 6958540 Y FT-1 FT1-MCG-0013 1/1/2001 11/30/2020 Y x4 P M2 Belle River Mills Interconnect 29 287422 Zone 2 P MQ Milford Junction Interconnect 29 316118 Zone 2 D DTE Gas Company 6958540 Y FT-1 FT1-MCG-0014 11/1/2003 3/31/2015 N 50,000 PM2 Alliance Interconnect 29 287415 Zone 1 50000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 50000 D Enbridge Gas Distribution Inc. 246667372 Y FT-1 FT1-EGD-0009 12/1/2000 11/30/2016 Y 79,000 PM2 Alliance Interconnect 29 287415 Zone 1 25000 P M2 Northern Border Interconnect 29 282410 Zone 1 54000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 79000 D Enbridge Gas Distribution Inc. 246667372 Y FT-1 FT1-EGD-0010 12/1/2000 11/30/2016 Y 96,000 PM2 Alliance Interconnect 29 287415 Zone 1 75000 P M2 Northern Border Interconnect 29 282410 Zone 1 21000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 96000 D J. Aron & Company 6980312 N FT-1 FT1-JAC-0427 11/1/2007 10/31/2017 N 25,000 x5 PM2 Alliance Interconnect 29 287415 Zone 1 25000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 25000 D J. Aron & Company 6980312 N FT-1 FT1-JAC-1300 11/1/2009 10/31/2019 N 25,000 x6 PM2 Alliance Interconnect 29 287415 Zone 1 25000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 25000 D KeySpan Gas East Corporation d/b/a 53106352 N FT-1 FT1-KLI-0414 11/1/2007 10/31/2017 N 12,500 A BG Energy Merchants LLC N PM2 Alliance Interconnect 29 287415 Zone 1 12500 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 12500 D Merrill Lynch Commodities Inc. 160352865 N FT-1 FT1-MER-1302 11/1/2009 10/31/2017 N 20,000 PM2 Alliance Interconnect 29 287415 Zone 1 20000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 20000 D NJR Energy Services Company 25715165 N FT-1 FT1-NJR-0016 11/1/2006 10/31/2013 N 40,000 PM2 Alliance Interconnect 29 287415 Zone 1 30000 P M2 Northern Border Interconnect 29 282410 Zone 1 10000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 40000 D Northern Indiana Public Service Com 6937585 N FT-1 FT1-NIP-0118 4/1/2007 3/31/2016 N 13,000 PM2 Alliance Interconnect 29 287415 Zone 1 13000 PMQ Washington 10 Interconnect 29 287427 Zone 2 13000 D Northern Indiana Public Service Com 6937585 N FT-1 FT1-NIP-0124 3/1/2006 3/31/2016 N 30,000 PM2 Alliance Interconnect 29 287415 Zone 1 30000 P MQ Crown Point Interconnect 29 285077 Zone 1 30000 D Northern Utilities Inc. 49286305 N FT-1 FT1-NUI-0122 5/1/2006 3/31/2016 N 6,070 A Emera Energy Services Inc. N PM2 Alliance Interconnect 29 287415 Zone 1 6070 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 6070 D ONEOK Energy Services Company L.P 157641445 N FT-1 FT1-ONK-0018 11/1/2004 3/31/2017 N 50,000 PM2 Alliance Interconnect 29 287415 Zone 1 50000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 50000 D ONEOK Energy Services Company L.P 157641445 N FT-1 FT1-ONK-0019 11/1/2004 3/31/2017 N 50,000 x7 PM2 Washington 10 Interconnect 29 287427 Zone 2 50000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 50000 D Sequent Energy Management L.P. 612075846 N FT-1 FT1-SEQ-0423 11/1/2007 3/31/2018 N 25,000 x8 P M2 Northern Border Interconnect 29 282410 Zone 1 25000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 25000 D Sequent Energy Management L.P. 612075846 N FT-1 FT1-SEQ-0424 11/1/2008 3/31/2018 N 25,000 x9/x10 P M2 St. Clair (US) Interconnect 29 287424 Zone 2 25000 P MQ Northern Border Interconnect 29 282410 Zone 1 25000 D The Southern Connecticut Gas Compa 4945259 N FT-1 FT1-SCG-0417 11/1/2007 3/31/2017 N 18,300 x11 PM2 Washington 10 Interconnect 29 287427 Zone 2 18300 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 18300 D Tenaska Marketing Ventures 624240628 N FT-1 FT1-TMV-3840 11/1/2012 10/31/2013 N 40,000 P M2 Northern Border Interconnect 29 282410 Zone 1 40000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 40000 D Tidal Energy Marketing (U.S.) L.L.C. 801390308 Y FT-1 FT1-TEM-0011 12/1/2000 11/30/2016 Y 85,000 A Tidal Energy Marketing Inc. Y PM2 Alliance Interconnect 29 287415 Zone 1 50000 P M2 Northern Border Interconnect 29 282410 Zone 1 35000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 85000 D Union Gas Limited 200408144 N FT-1 FT1-UGL-0024 12/1/2000 11/30/2016 Y 80,000 PM2 Alliance Interconnect 29 287415 Zone 1 80000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 80000 D Union Gas Limited 200408144 N FT-1 FT1-UGL-3785 11/1/2012 10/31/2013 N 10,000 P M2 Northern Border Interconnect 29 282410 Zone 1 10000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 10000 D Westcoast Energy Enterprises (U.S.) 78617244 N FT-1 FT1-WES-0026 12/1/2000 11/30/2015 Y 160,000 PM2 Alliance Interconnect 29 287415 Zone 1 120500 P M2 Northern Border Interconnect 29 282410 Zone 1 39500 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 160000 D Wisconsin Electric Power Company 7947385 N FT-1 FT1-WEP-2503 8/1/2011 3/31/2016 N 33,320 P M2 Bluewater Interconnect 29 388031 Zone 2 33320 P MQ Guardian Interconnect 29 395745 Zone 1 33320 D Wisconsin Gas LLC 7947047 N FT-1 FT1-WIS-0836 4/1/2008 3/31/2015 N 19,997 PM2 Washington 10 Interconnect 29 287427 Zone 2 19997 P MQ Guardian Interconnect 29 395745 Zone 1 19997 D Wisconsin Gas LLC 7947047 N FT-1 FT1-WIS-1090 3/1/2009 3/31/2016 N 78,000 P M2 Belle River Mills Interconnect 29 287422 Zone 2 78000 P MQ Guardian Interconnect 29 395745 Zone 1 78000 D Wisconsin Gas LLC 7947047 N FT-1 FT1-WIS-2501 8/1/2011 3/31/2016 N 33,320 P M2 Bluewater Interconnect 29 388031 Zone 2 33320 P MQ Guardian Interconnect 29 395745 Zone 1 33320 D Wisconsin Gas LLC 7947047 N FT-1 FT1-WIS-2502 8/1/2011 3/31/2016 N 33,320 PM2 Washington 10 Interconnect 29 287427 Zone 2 33320 P MQ Guardian Interconnect 29 395745 Zone 1 33320 D Wisconsin Public Service Corporation 7947435 N FT-1 FT1-WPS-0799 4/1/2008 3/31/2015 N 16,645 PM2 Washington 10 Interconnect 29 287427 Zone 2 16645 P MQ Guardian Interconnect 29 395745 Zone 1 16645 D Wisconsin Public Service Corporation 7947435 N FT-1 FT1-WPS-1045 2/1/2009 3/31/2016 N 59,400 P M2 Belle River Mills Interconnect 29 287422 Zone 2 59400 P MQ Guardian Interconnect 29 395745 Zone 1 59400 D Yankee Gas Services Company 361667371 N FT-1 FT1-YGS-0420 11/1/2007 3/31/2017 N 3,000 x12 A Tenaska Marketing Ventures N PM2 Alliance Interconnect 29 287415 Zone 1 3000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 3000 D Yankee Gas Services Company 361667371 N FT-1 FT1-YGS-0421 11/1/2007 10/31/2017 N 20,000 A Tenaska Marketing Ventures N PM2 Alliance Interconnect 29 287415 Zone 1 20000 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 20000 D Yankee Gas Services Company 361667371 N FT-1 FT1-YGS-0422 11/1/2007 3/31/2017 N 37,200 x13 A Tenaska Marketing Ventures N PM2 Washington 10 Interconnect 29 287427 Zone 2 37200 P MQ St. Clair (US) Interconnect 29 287424 Zone 2 37200 F1Winter MDQ 100,000 Dth/d - November-March and Summer MDQ 0 Dth/d - April-October. F2Winter MDQ 9,700 Dth/d - November-March and Summer MDQ 0 Dth/d - April-October. F3Winter MDQ 70,000 Dth/d - November-March and Summer MDQ 0 Dth/d - April-October. F 4 Contracted Capacity is equal to the capacity of a single 36-inch 1000 psig MAOP pipeline between Belle River Mills and Milford Junction F 4 as determined by a maximum delivery pressure of 1000 psig from DTE Gas to Vector at the Primary Receipt Point and a delivery F 4 pressure of 550 psig from Vector to DTE Gas at the Primary Delivery Point. F 5 Permanent Capacity Release from Nexen Marketing U.S.A. Inc. to J. Aron & Company effective 08/01/2010. F 6 Permanent Capacity Release from Nexen Marketing U.S.A. Inc. to J. Aron & Company effective 08/01/2010. F7Winter MDQ 50,000 Dth/d - November-March and Summer MDQ 0 Dth/d - April-October. F 8 Permanent Capacity Release from Integrys Energy Services Inc. to Sequent Energy Management L.P. effective 01/01/2010. F 9 Permanent Capacity Release from Integrys Energy Services Inc. to Sequent Energy Management L.P. effective 01/01/2010. F10Winter MDQ 25,000 Dth/d - November-March and Summer MDQ 0 Dth/d - April-October. F11Winter MDQ 18,300 Dth/d - November-March and Summer MDQ 0 Dth/d - April-October. F12Winter MDQ 3,000 Dth/d - November-March and Summer MDQ 0 Dth/d - April-October. F13Winter MDQ 37,200 Dth/d - November-March and Summer MDQ 0 Dth/d - April-October. STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application of ) Michigan Consolidated Gas Company ) for a Gas Cost Recovery Plan, ) Case No. U-17131 5-year Forecast and Monthly GCR Factor ) for the 12 months ending March 31, 2014 )

REBUTTAL TESTIMONY

ERIC W. CLINTON

DTE GAS COMPANY REBUTTAL TESTIMONY OF ERIC W. CLINTON Line No.

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

2 A. My name is Eric W. Clinton. My business address is One Energy Plaza, Detroit,

3 Michigan 48226. I am employed by DTE Gas Company (DTE Gas or Company),

4 which is formerly known as Michigan Consolidated Gas Company (MichCon), as a

5 Principal Marketing Specialist in the Gas Supply and Planning Organization.

7 Q. Did you previously file direct testimony in this proceeding on behalf of DTE

8 Gas?

9 A. Yes, I did.

11 Q. What issues are you rebutting in this proceeding?

12 A. I will be rebutting issues related to the Fixed Price Program (FPP) in the direct

13 testimony of RRC Witness Frank Hollewa (Mr. Hollewa), AG Witness Ralph

14 Miller (Mr. Miller), and MCAAA Witness Geoffrey Crandall (Mr. Crandall). I will

15 also be rebutting issues related to the Supplier of Last Resort (SOLR) reservation

16 charge raised by IGS Witness Matthew White (Mr. White) and RESA Witness

17 Michael Haugh (Mr. Haugh). Specifically, I will rebut:

18 1) Mr. Miller’s proposed addition of two new FPP objectives which state that

19 the cost of the FPP should be as low as feasible and the FPP should provide

20 customers with appropriate price signals because these additions undermine

21 and are in conflict with the current FPP objectives.

22 2) Mr. Miller’s recommendation that the fixed price coverage level be lowered

23 from 75% to a level between 25% and 36% because the analysis Mr. Miller

24 uses to support this recommendation is predominately based on hindsight and

25 historical data, which is not a guarantee or predictor of future price

EWC Rebuttal - 1 E. W. CLINTON Line U-17131 No.

1 performance.

2 3) Mr. Miller’s recommendation that the VCA purchase period length be

3 modified from 24 months to 12 months because the analysis Mr. Miller uses

4 to support this recommendation is predominately based on hindsight and

5 historical data, which is not a guarantee or predictor of future price

6 performance.

7 4) Mr. Miller’s recommendation that the last month to execute a purchase of gas

8 under the VCA Method should occur three months later than currently done

9 because this change adds no value and creates unnecessary work and

10 confusion in the GCR process.

11 5) Mr. Miller’s criticisms pertaining to the Random Price Analysis (RPA)

12 which are irrelevant because he agrees with the conclusion that I have

13 reached from the RPA, specifically that the range of possible cost outcomes

14 is reduced as the level of fixed price purchases increase.

15 6) Mr. Hollewa’s recommendation that the VCA Method fixed price coverage

16 level be reduced from 75% to 50% and that the 24-month VCA purchase

17 period start 24 months in advance of the GCR Period versus 27 months

18 because his rationale for such changes are based on unsupported, incorrect,

19 and illogical claims about the natural gas market.

20 7) Mr. Hollewa’s criticisms pertaining to the Random Price Analysis (RPA)

21 which are unwarranted and should be ignored because his statements are

22 nothing more than unsupported rhetoric and reflect a general lack of

23 understanding of the analysis I performed.

24 8) Mr. Crandall’s recommendation that the MPSC approve a 100% index

25 purchasing strategy because it is based on a myriad of superfluous and

EWC Rebuttal - 2 E. W. CLINTON Line U-17131 No.

1 unsupported ancillary arguments as well as inaccurate and misleading

2 assertions about the natural gas market.

3 9) Mr. Crandall’s criticisms pertaining to the Random Price Analysis (RPA)

4 which are not supported with any analysis and appear rooted in a general

5 misunderstanding of the actual analysis.

6 10) Mr. Crandall’s criticism that the VCA Method does not allow DTE Gas to

7 make speculative calls on the natural gas market because the VCA Method

8 was never designed for speculating on the price of natural gas. Instead, it

9 was designed to be prescriptive and time dependent as opposed to price

10 dependent.

11 11) Mr. Crandall’s recommendation that the Commission impose a regulatory

12 “city-gate” ceiling price on all affiliate gas purchases because there is no

13 valid reason to preclude arms-length transactions between DTE Gas and its

14 affiliates when they occur in a non-discriminatory manner consistent with

15 transactions between DTE Gas and all other non-affiliated, similarly situated

16 counterparties.

17 12) Mr. White’s recommendation that the Commission reject DTE Gas’s request

18 to implement a SOLR Reservation Charge because the Commission has

19 already approved a SOLR Reservation Charge as being reasonable and

20 prudent for two other Michigan Local Gas Distribution Companies (LDCs)

21 and my direct testimony supports the reasonableness of a SOLR Reservation

22 Charge for DTE Gas.

23 13) Mr. White’s recommendation that a separate hearing occur to assess DTE

24 Gas’s supply plan and operations to determine the appropriateness of a

25 SOLR charge because conducting such a hearing would be redundant to the

EWC Rebuttal - 3 E. W. CLINTON Line U-17131 No.

1 Commission’s review in this GCR case and therefore unnecessary.

2 14) Mr. White’s recommendation of financial remedies in lieu of a SOLR charge

3 because Mr. White’s proposed financial remedies fail to address the

4 operational responsibilities DTE Gas has as SOLR.

5 15) Mr. White’s recommendation that DTE Gas relinquish control of its storage

6 and pipeline transportation assets to the Alternative Gas Suppliers (AGS)

7 because DTE Gas could not relinquish control of its storage and pipeline

8 assets without inhibiting the operational integrity of DTE Gas’ system and

9 controls, and thus preventing DTE Gas from providing the supply reliability

10 to all of its customers for which it is solely responsible.

11 16) Mr. Haugh’s recommendation that the Commission reject DTE Gas’s SOLR

12 Reservation Charge because the Commission has already approved a SOLR

13 Reservation Charge as being reasonable and prudent for two other Michgian

14 LDCs and my direct testimony supports the reasonableness of a SOLR

15 Reservation Charge for DTE Gas

16 17) Mr. Haugh’s recommendation that DTE Gas relinquish control of its pipeline

17 transportation assets to the AGS because DTE Gas could not relinquish

18 control of its pipeline assets without inhibiting the operational integrity of

19 DTE Gas’ system and controls, and thus preventing DTE Gas from providing

20 the supply reliability to all of its customers for which it is solely responsible.

22 Q. Are you sponsoring any rebuttal exhibits in this proceeding?

23 A. No, I am not.

25 AG WITNESS MILLER

EWC Rebuttal - 4 E. W. CLINTON Line U-17131 No.

1 Fixed Price Program (FPP) Objectives

2 Q. What is Mr. Miller’s recommendation regarding the fixed price program

3 objectives?

4 A. On page 11 of his testimony, Mr. Miller recommends the addition of two new

5 objectives. Specifically, Mr. Miller recommends adding an objective that states

6 “The cost of the FPP plan should be as low as feasible, consistent with the

7 achievement of the other appropriate objectives.” Also, Mr. Miller recommends

8 adding an objective that states “The plan should provide customers with appropriate

9 price signals.”

11 Q. Do you agree with Mr. Miller’s fixed price program objective that states “The

12 cost of the FPP plan should be as low as feasible, consistent with the

13 achievement of the other appropriate objectives.”?

14 A. No. It is not clear what Mr. Miller’s objective is when he states, “the cost of the

15 FPP plan should be as low as feasible.” Specifically, the cost of DTE Gas’ FPP is

16 based on the market price of natural gas at the time the fixed price purchases occur

17 and the fact is that DTE Gas does not have control over the market price of natural

18 gas. Therefore, the cost of DTE Gas’s FPP is already as low as feasible because it

19 is based on the market price of natural gas at the time the fixed price purchases

20 occur and, therefore, a lower cost alternative does not exist at the time of that

21 purchase as asserted by Mr. Miller.

23 Q. Do you agree with Mr. Miller’s fixed price program objective that states “The

24 plan should provide customers with appropriate price signals.”?

25 A. No. The objective of the VCA Method is to mitigate price volatility, price risk,

EWC Rebuttal - 5 E. W. CLINTON Line U-17131 No.

1 price uncertainty, and price fluctuations, all of which are synonymous with each

2 other; it is not intended as a means to send a price signal as defined by Mr. Miller.

3 Mr. Miller defines an appropriate price signal as “one that lets customers know the

4 current and immediately foreseeable cost or market value of the natural gas they are

5 purchasing” on page 12 of his testimony. In essence, Mr. Miller is suggesting that

6 less fixed price purchases and more indexed priced or market priced supply

7 produces a more appropriate price signal. However, the major flaw with Mr.

8 Miller’s logic is that a larger percent of indexed priced or supply purchased at

9 market prices closer to the delivery date would produce an equal and offsetting

10 increase in the level of price risk. The objective of the VCA Program is to mitigate

11 price risk instead of increasing it, which would be the result if DTE Gas were to

12 send a more appropriate price signal as suggested by Mr. Miller.

14 Fixed Price Coverage Level

15 Q. What is Mr. Miller’s recommendation regarding the fixed price coverage

16 level?

17 A. On page 7 of his testimony, Mr. Miller recommends that DTE Gas lower the fixed

18 price coverage level under the VCA Method from 75% to a level between 25% and

19 36%. Mr. Miller’s recommendation is based on: a) his analysis presented in Exhibit

20 AG-2 which allegedly shows that the cost to mitigate price risk is high at the

21 present time as discussed on page 16 of his testimony; b) his analysis on Exhibit

22 AG-1, which is his tailored version of DTE Gas’s historical NYMEX back test as

23 discussed on page 25 of his testimony; and c) his view that reducing the FPP

24 coverage target is the way to obtain more appropriate price signals as discussed on

25 page 17 of his testimony.

EWC Rebuttal - 6 E. W. CLINTON Line U-17131 No.

2 Q. Do you agree with Mr. Miller’s recommendation that the fixed price coverage

3 level should be lowered from 75% to a level between 25% and 36% based on

4 his analysis presented in Exhibit AG-2 which allegedly shows that the cost to

5 mitigate price risk is high at the present time?

6 A. No. Mr. Miller argues that the cost to mitigate price risk is high at the current time

7 based on the trivial fact that DTE Gas’s fixed prices for the future April 2013

8 through March 2015 delivery period are higher than the historical calendar year

9 2012 index prices as shown on Exhibit AG-2. However, it is inappropriate to reach

10 this conclusion about the cost to mitigate price risk because it is based upon an

11 inappropriate apples-to-oranges analysis that compares historical index prices to

12 fixed futures prices. Mr. Miller’s analysis is an invalid comparison of historical

13 prices to fixed futures prices for two separate and distinct delivery periods marked

14 by different supply and demand characteristics. Drawing conclusions based on a

15 comparison of prices for different time periods is misguided. As an example, you

16 could compare the price for a hotel room on New Year’s Eve and the price for that

17 same room two weeks later. The balance of supply and demand on those two

18 different dates is going to yield different pricing results, but that comparison does

19 not provide any useful insight into price risk mitigation. Further, Mr. Miller is

20 taking a market view that is speculative in nature when he makes the very statement

21 “that the cost of risk mitigation is high at the present time”. The fact is that no one

22 knows whether or not the cost of risk mitigation is high or low at the current time

23 because no one, including Mr. Miller, has a crystal ball to know where prices will

24 go in the future.

EWC Rebuttal - 7 E. W. CLINTON Line U-17131 No.

1 Q. Do you agree with Mr. Miller’s recommendation that the fixed price coverage

2 level should be lowered from 75% to a level between 25% and 36% because it

3 is supported by the data on Exhibit AG-1, which is his version of DTE Gas’s

4 historical NYMEX back test?

5 A. No. Mr. Miller’s version of DTE Gas’s historical NYMEX back test is a self-

6 serving exercise using selective data that Mr. Miller appears to have determined in

7 advance would support his recommendation. Even if his analysis of the selective

8 data he used is accurate, DTE Gas’s historical NYMEX back test was presented for

9 informational purposes to shed light on the performance of the VCA program in a

10 historical context. Unfortunately, this historical back test is limited to how market

11 prices have behaved in the past, which is not a guarantee or predictor of future price

12 performance. The fact is that no one knows where prices will go in the future. Mr.

13 Miller’s recommendation is based only on the data in Exhibit AG-1. Therefore, his

14 recommendation is based solely on history with the added benefit of hindsight. In

15 essence, Mr. Miller’s recommendation assumes that future prices will behave in

16 exactly the same manner as historical prices and is based on a hindsight bias and

17 totally speculative. Both Mr. Miller’s selective analysis and the Company’s

18 NYMEX historical back test shows where prices have been, not where prices are

19 going.

21 Q. Do you agree with Mr. Miller’s recommendation that the fixed price coverage

22 level should be lowered from 75% to a level between 25% and 36% because it

23 is the way to obtain more appropriate price signals?

24 A. No. As discussed earlier in my rebuttal testimony, the fixed price program is not

25 intended as a means to send customers price signals.

EWC Rebuttal - 8 E. W. CLINTON Line U-17131 No.

1 VCA Purchase Period Length

2 Q. What is Mr. Miller’s recommendation regarding the VCA purchase period?

3 A. On page 7 of his testimony, Mr. Miller recommends that DTE Gas shorten the VCA

4 purchase period length from 24 months to 12 months. Mr. Miller’s

5 recommendation is based on: a) his analysis on Exhibit AG-3, which allegedly

6 shows that the cost to mitigate price risk in the first 12 months of the 24-month

7 VCA purchase period is significantly higher than the subsequent 12-months, which

8 is discussed on pages 28 and 29 of his testimony; b) his view that DTE Gas has

9 provided no explicit support for using a 24-month VCA Purchase Period, instead of

10 a shorter or longer one as discussed on page 15 of his testimony; c) his analysis on

11 Exhibit AG-1, which is his tailored version of DTE Gas’s historical NYMEX back

12 test as discussed on page 25 of his testimony; and d) his view that a shorter VCA

13 purchase period is the way to obtain more appropriate price signals as discussed on

14 page 17 of his testimony.

16 Q. Do you agree with Mr. Miller’s recommendation that the VCA purchase

17 period should be reduced from 24 months to 12 months based on Exhibit AG-

18 3, which allegedly shows the cost to mitigate price risk in the first 12-months of

19 the 24-month VCA purchase period is significantly higher than the subsequent

20 12-months?

21 A. No. Mr. Miller’s Exhibit AG-3 attempts to use historical data and hindsight to

22 make claims about the future cost to mitigate price risk in the natural gas market.

23 Even if Exhibit AG-3 is accurate from a historical perspective, it is irrelevant with

24 respect to the future cost to mitigate price risk. Neither Mr. Miller nor anyone else

25 knows whether or not the cost to mitigate price risk is high or low at the current

EWC Rebuttal - 9 E. W. CLINTON Line U-17131 No.

1 time because no one has a crystal ball to know where prices will go in the future.

2 Further, Mr. Miller acknowledges his use of perfect hindsight on page 28 of his

3 testimony when he states “Hindsight is needed because the NYMEX LTD price for

4 a delivery month is not known until the beginning of that month, whereas the VCA

5 purchases for that delivery month will have been made in two calendar years

6 preceding that delivery month.” Subsequently, Mr. Miller completely contradicts

7 himself and states the exact opposite on page 29 of his testimony “This comparison

8 is prospective because the NYMEX LTD price for the purchase month is already

9 known when MichCon makes its VCA purchases in that month.” The fact is that

10 the historical data the Mr. Miller uses to derive his conclusions never exists on a

11 prospective basis. Therefore, his entire analysis provides no meaningful insight

12 into the future cost to mitigate price risk.

14 Q. Are there other reasons you disagree with Mr. Miller’s assessment of the cost

15 to mitigate price risk?

16 A. Yes. Mr. Miller’s calculation of the cost to mitigate price risk is distorted and

17 misleading. For example, Mr. Miller believes that if the price of natural gas for

18 delivery 12 months or 24 months into future is significantly higher than the price of

19 natural gas today then the cost to mitigate price risk is high. Mr. Miller’s thought

20 process is flawed because it ignores the cost to carry, which is also reflected in

21 futures prices. The cost to carry would include the time value of money and storage

22 costs associated with purchasing and paying for gas today, holding the natural gas

23 in inventory for some period of time, then subsequently selling the gas at some

24 future delivery date. In addition, Mr. Miller’s analysis does not reflect the fact that

25 futures prices may be higher than the price today because they reflect the market’s

EWC Rebuttal - 10 E. W. CLINTON Line U-17131 No.

1 current expectations of supply and demand fundamentals that will exist at the time

2 of delivery in the future. For example, if the market expects a supply shortage for

3 the delivery period 12 months from today, then the price of natural gas for delivery

4 12 months from today should be higher than today’s price, all things being equal.

5 Another example of the supply and demand fundamentals that exist in the market is

6 the fact that winter futures prices are typically higher than summer futures prices

7 reflecting the higher demand associated with the winter heating season.

9 Q. Is the natural gas market always in a state where futures prices are higher for

10 each subsequent delivery period?

11 A. No. Contrary to Mr. Miller’s belief, the market can exhibit periods when futures

12 prices are lower for each succeeding delivery period. In fact most recently on May

13 1, 2013, the market exhibited such behavior as the price for delivery two years into

14 the future was less than the price for the balance of the current June 2013 – March

15 2014 GCR delivery period as shown below.

16 Future Delivery Period NYMEX Price

17 June 2013 – March 2014 $4.51

18 April 2014 – March 2015 $4.38

19 April 2015 – March 2016 $4.34

20 Therefore, according to Mr. Miller’s flawed logic the market would have a negative

21 cost to mitigate price risk or no risk as the future delivery period prices are lower

22 than preceding delivery periods, which is simply not the case. Contrary to Mr.

23 Miller’s analysis, market price risk exists regardless of whether futures price for

24 each subsequent delivery month are higher or lower than preceding delivery

25 months.

EWC Rebuttal - 11 E. W. CLINTON Line U-17131 No.

1 Q. Are there any additional reasons you disagree with Mr. Miller’s view of

2 market price risk?

3 A. Yes. Mr. Miller’s view ignores the fact that natural gas prices can only fall to zero.

4 However, in theory, they can rise indefinitely. Therefore, the risk profile of natural

5 gas prices is asymmetrical meaning the risk of rising natural gas prices is greater

6 than the risk of falling natural gas prices. For example, if you buy natural gas at the

7 current price it can only fall to zero thereby decreasing 100% in value. However, if

8 natural gas prices rise from the current range of $4 to the $13 price level

9 experienced in 2008, the price increase would be well in excess of 200%. This

10 asymmetrical price risk in natural gas prices is transparent in the Energy

11 Information Administration’s (EIA) Short Term Energy Outlook published in May

12 2013. Specifically, the EIA shows, with a 95% confidence level, that December

13 2014 NYMEX prices could rise 73% to $7.83 from the current level of $4.52 but

14 only fall 42% to $2.61.

16 Q. Do you agree with Mr. Miller’s recommendation that the VCA purchase

17 period should be reduced from 24 months to 12 months because DTE Gas has

18 provided no explicit support for using a 24-month VCA Purchase Period

19 instead of a shorter or longer one?

20 A. No. Mr. Miller’s assertion is unfounded. DTE Gas presented the VCA Method for

21 the first time in Case No. U-16146, filed in December 2009 for the 2010-11 GCR

22 Plan period. Mr. Miller was a witness in that very proceeding. In Case No. U-

23 16146 DTE Gas stated the following regarding the selection of a 24-month VCA

24 purchase period “MichCon chose 24 months for two reasons. First, price

25 movements in any one month will have a limited impact on the total portfolio price.

EWC Rebuttal - 12 E. W. CLINTON Line U-17131 No.

1 Only 3.1% of volumes are locked in at any one time. For example, assume the

2 weighted cost of the total portfolio or jurisdictional rate after the GCR period was

3 $7.00 per Mcf. However, if one month during the VCA period prices were fixed at

4 $13.00 per Mcf, then this would only have a $0.19 per Mcf effect on the

5 jurisdictional rate (($13.00 - $7.00) X 3.1%=$0.19)). Second, there is meaningful

6 liquidity and a depth of sellers competing in the marketplace for pricing physical

7 supply 27 months in advance. If MichCon seeks supply further into the future

8 beyond the 27 month period, then there may be insufficient liquidity and the

9 potential lack of credit worthy suppliers willing to sell which could result in

10 undesirable price execution.”

12 Q. Are there any other reasons you disagree with Mr. Miller’s recommendation

13 that the VCA purchase period should be reduced from 24 months to 12

14 months?

15 A. Yes. The average fixed price of a 24-month VCA purchase period is affected less

16 by the purchase price in any one month compared to the 12-month VCA purchase

17 period. This is because the weight of the purchase price in any one month under the

18 24-month VCA purchase period is only 1/24 or 4.17% versus 8.33% or 1/12 under

19 the 12-month VCA purchase period.

21 Q. Do you agree with Mr. Miller’s recommendation that the VCA purchase

22 period should be reduced from 24 months to 12 months based on Exhibit AG-

23 1, which is his selective data version of DTE Gas’ historical NYMEX back test?

24 A. No. Mr. Miller uses this same analysis for suggesting a lower fixed price coverage

25 level, which I have rebutted earlier in my rebuttal testimony.

EWC Rebuttal - 13 E. W. CLINTON Line U-17131 No.

1 Q. Do you agree with Mr. Miller’s recommendation that the VCA purchase

2 period should be reduced from 24 months to 12 months based on his view that

3 a shorter VCA purchase period is the way to obtain more appropriate price

4 signals?

5 A. No. As discussed earlier in my rebuttal testimony, the fixed price program is not

6 intended as a means to send customers price signals.

8 VCA Purchase Period Ending Month

9 Q. What is Mr. Miller’s recommendation regarding the VCA Method last

10 purchase month?

11 A. On page 8 of his testimony, Mr. Miller recommends that the last month to execute a

12 purchase of gas under the VCA Method should occur three months later than

13 currently done. Currently, the last VCA purchase is completed in the month of

14 December directly preceding the start of the GCR Period, and Mr. Miller wants to

15 change it to the month of March directly preceding the start of the GCR Period.

16 Mr. Miller’s recommendation is based on: a) his view that DTE Gas has provided

17 no explicit support for having the VCA Purchase Period end at December 31, three

18 months before the GCR Period begins on April 1 on page 15 of his testimony; b)

19 his analysis on Exhibit AG-3, which allegedly shows that the cost to mitigate price

20 risk is lower if fixed price purchases are made closer to the beginning of the GCR

21 Year as discussed on pages 28 and 29 of his testimony; and c) his view that a later

22 termination date for the VCA purchases is the way to obtain more appropriate price

23 signals as discussed on page 17 of his testimony.

25 Q. Do you agree with Mr. Miller’s recommendation that the VCA purchase

EWC Rebuttal - 14 E. W. CLINTON Line U-17131 No.

1 period should terminate three months later because DTE Gas’ has provided no

2 explicit support for having the VCA Purchase Period end at December 31,

3 three months before the GCR Period begins on April 1?

4 A. No. The primary reason the VCA Purchase Period was selected to end by

5 December 31 directly preceding the GCR Period is to accommodate the GCR Plan

6 filing which is also filed by December 31 directly preceding the GCR Period.

7 Therefore, the GCR Plan Filing and accompanying exhibits will contain the results

8 of all of DTE Gas’ fixed price purchases and not be subject to revisions as would be

9 the case under Mr. Miller’s proposal. Mr. Miller states as such on page 19 and 20

10 of his testimony, “A March termination date for the VCA Purchase Period would

11 not allow MichCon to put the final VCA purchase costs into its initial filing, but

12 updating the relevant exhibits in the latter part of March would not be difficult, and

13 could easily be handled in the discovery process.” This change that Mr. Miller is

14 requesting adds no value, creates unnecessary work, confusion, and unnecessary

15 contentiousness to the GCR process.

17 Q. Do you agree with Mr. Miller’s recommendation that the VCA purchase

18 period should terminate three months later based on his analysis on Exhibit

19 AG-3, which allegedly shows that the cost to mitigate price risk is lower if fixed

20 price purchases are made closer to the beginning of the GCR Year?

21 A. No. Mr. Miller uses this same analysis for suggesting a shorter VCA purchase

22 period, which I have rebutted above in my testimony, and the same reason I stated

23 earlier in my rebuttal, specifically that historical data provides no meaningful

24 insight into the future cost to mitigate price risk applies here.

EWC Rebuttal - 15 E. W. CLINTON Line U-17131 No.

1 Q. Do you agree with Mr. Miller’s recommendation that the VCA purchase

2 period should terminate three months later based on his view that a later

3 termination date for the VCA purchases is the way to obtain more appropriate

4 price signals?

5 A. No. As discussed earlier in my rebuttal testimony, the fixed price program is not

6 intended as a means to send customers price signals.

8 Random Price Analysis

9 Q. What is the essence of Mr. Miller’s lengthy discussion regarding the Random

10 Price Analysis?

11 A. On pages 29 through 41 of his testimony, Mr. Miller criticizes various aspects of

12 the Random Price Analysis including the assumptions and results.

14 Q. Do you agree with Mr. Miller’s criticism of the Random Price Analysis?

15 A. No. Setting aside Mr. Miller’s unwarranted criticisms of the analysis, on page 30 of

16 his testimony, Mr. Miller agrees that “The Random Price Analysis confirms that the

17 level of price risk or uncertainty that is borne by customers is dependent upon the

18 level of fixed price coverage. Specifically, decreasing the level of fixed price

19 coverage produces an increasingly wider range of potential price outcomes, or

20 higher level of price uncertainty…”. The whole intent of the analysis was to simply

21 show that a lower level of fixed price coverage produces an increasingly wider

22 range of potential price outcomes or higher level of price uncertainty with which

23 Mr. Miller agrees. Contrary to Mr. Miller’s belief, the point of the analysis is not to

24 forecast prices, but more importantly to determine how the GCR cost of gas is

25 effected based on a set of underlying assumptions regarding price and volatility

EWC Rebuttal - 16 E. W. CLINTON Line U-17131 No.

1 with varying degrees of fixed price purchases. DTE Gas’s assumptions were in fact

2 based on the most recent historical volatility and prices for the April 2015 through

3 March 2016 delivery period at the time of filing. These assumptions were input

4 into the Geometric Brownian Motion (GBM) model, which is also known as the

5 lognormal model because the resultant prices are log-normally distributed meaning

6 prices can rise indefinitely but can only fall to zero. Witness Miller’s criticisms

7 pertain to subjects that the RPA was not intended to address, such as the cost of risk

8 mitigation or the impact of hurricanes. Because witness Miller agrees with the

9 conclusion that I have drawn from the RPA, specifically that the range of possible

10 cost outcomes is reduced as the level of fixed price purchases increases, the

11 analytical faults claimed by the AG can be ignored because they pertain to matters

12 unrelated to the purpose of the RPA.

14 RRC WITNESS HOLLEWA

15 VCA Method FPP

16 Q. What is Mr. Hollewa’s recommendation regarding the VCA Method FPP?

17 A. On page 13 of his testimony, although it is not entirely clear, it appears that Mr.

18 Hollewa is recommending that the VCA Method fixed price coverage level be

19 reduced from 75% to 50% and that the 24-month VCA purchase period would start

20 24 months in advance of the GCR Period versus 27 months. Mr. Hollewa’s

21 recommendation is based solely on the underlying theme throughout his testimony

22 that a) natural gas prices are stable and b) natural gas price speculation and

23 volatility in the natural gas futures almost ceased to exist at the beginning of the

24 2009-2010 GCR year as discussed on page 9 of his testimony.

EWC Rebuttal - 17 E. W. CLINTON Line U-17131 No.

1 Q. Do you agree with Mr. Hollewa’s recommendation that the VCA Method fixed

2 price coverage level be reduced from 75% to 50% because he claims that

3 natural gas prices are stable?

4 A. No. Mr. Hollewa’s statement that natural gas prices have been stable is not

5 accurate. The fact is that natural gas prices have not been stable, as exhibited by the

6 rolling 12-month natural gas strip prices, which have increased 64% in the past year

7 from a low of $2.54 on April 23, 2012 to the current price of $4.17 on May 8, 2013.

8 Further, it appears that Mr. Hollewa confuses price stability with a market condition

9 where futures prices are higher for each subsequent delivery period on one specific

10 day. To illustrate Mr. Hollewa’s confusion, on page 9 of his testimony he states

11 that “Even more indicative of stable prices is the 3/26/13 NYMEX projections

12 which reflect the lowest average differences between consecutive years with a

13 difference of only $0.123 between 2013-2014 and 2014-2015; and only $0.065

14 between 2014-2015 and 2015-2016.” Mr. Hollewa is simply stating that futures

15 prices are higher for each subsequent delivery period on one day as opposed to

16 price stability. Price stability is measured through volatility, which is the price risk,

17 or uncertainty, and is based on the rate of change in price for a specific delivery

18 period over a defined period of time (e.g. 30 days) as opposed to a comparison of

19 prices for different delivery periods on the same day. In summary, price stability is

20 not the positive difference for succeeding delivery periods on one specific day that

21 Mr. Hollewa describes in his testimony.

23 Q. Are there any other reasons you disagree with Mr. Hollewa’s recommendation

24 that the VCA Method fixed price coverage level be reduced from 75% to 50%

25 because he claims that natural gas prices are stable?

EWC Rebuttal - 18 E. W. CLINTON Line U-17131 No.

1 A. Yes. If in fact natural gas prices were stable, which they are not, then the VCA

2 Method would yield similar gas costs to a 100% index purchasing strategy. Index

3 purchasing is a passive strategy that does not involve any form of hedging or

4 creating price certainty for future deliveries.

6 Q. Do you agree with Mr. Hollewa’s recommendation that the VCA Method fixed

7 price coverage level be reduced from 75% to 50% because volatility in the

8 natural gas futures almost ceased to exist beginning with the 2009-2010 GCR

9 year?

10 A. No. As discussed above, Mr. Hollewa provides no measure or calculation of

11 volatility in his testimony. Therefore, his conclusion is unsupported. Further,

12 actual measured 30-day historical volatility for the following futures strips as of

13 May 8, 2013 is indicated below.

14 Future Delivery Period 30-Day Historical Volatility

15 June 2013 – March 2014 33%

16 April 2014 – March 2015 15%

17 April 2015 – March 2016 12%

18 The 30-day historical volatility can be interpreted as follows: over the past 30 days

19 the actual price movement suggests that 68% of the time prices will be within a

20 range of plus or minus 33% of the average price in a one year time period.

21 Typically, NYMEX prices exhibit a higher level of volatility as the delivery period

22 nears, as can be seen from the data above. Therefore, Mr. Hollewa’s statement that

23 volatility has ceased to exist, is simply false and unsupported and refuted by the

24 actual volatility presented in the table above.

EWC Rebuttal - 19 E. W. CLINTON Line U-17131 No.

1 Random Price Analysis

2 Q. What is Mr. Hollewa’s criticism of the Random Price Analysis?

3 A. On page 13 of his testimony, Mr. Hollewa states that it is not readily apparent how

4 and why natural gas prices can be considered random and that in his opinion the

5 RPA is specious and not reliable.

7 Q. Do you agree with Mr. Hollewa’s opinion that it is not readily apparent how

8 and why natural gas prices can be considered random and that the Random

9 Price Analysis is specious and is not reliable?

10 A. No. Mr. Hollewa’s rhetoric surrounding the Random Price Analysis is not

11 supported by any analysis. The fact is that the change in natural gas prices from

12 one day to the next cannot be predicted with any level of certainty, thereby

13 exhibiting a random component. Further, as described above in the rebuttal to Mr.

14 Miller, contrary to Mr. Hollewa’s criticisms the Random Price Analysis is based on

15 the Geometric Brownian Motion (GBM) model, which is in fact a well-developed,

16 versatile, and simple quantitative financial model used to forecast price behavior.

17 The fact that Mr. Hollewa may not be familiar with the GBM does not make it

18 specious or unreliable.

20 MCAAA WITNESS CRANDALL

21 VCA Method FPP

22 Q. What is Mr. Crandall’s recommendation regarding the VCA Method FPP?

23 A. On page 10 of his testimony, Mr. Crandall recommends that the MPSC approve a

24 100% index purchasing strategy. Mr. Crandall’s recommendation is based on a

25 myriad of superfluous and unsupported claims throughout his testimony such as a)

EWC Rebuttal - 20 E. W. CLINTON Line U-17131 No.

1 the Commission’s GCR ratemaking process dampens ratepayer price volatility

2 discussed on pages 5, 7, and 10 of his testimony; b) the cost of 75% fixed price

3 contracts is above that of index over the past 11 years with no commensurate

4 volatility reducing benefit as discussed on pages 7 and 8 of his testimony; c) the

5 State of Nevada has rejected hedging and moved to 100% index based purchasing

6 discussed on pages 8 through 10 of his testimony; d) other Michigan utilities such

7 as Consumers Energy and Michigan Gas Utilities have significantly reduced their

8 reliance on fixed price contracts discussed on page 11 of his testimony; and e) gas

9 prices have dropped and become more stable discussed on page 10 of his testimony.

11 Q. Do you agree with Mr. Crandall’s recommendation that the MPSC approve a

12 100% index purchasing strategy because the Commission’s GCR ratemaking

13 process dampens ratepayer price volatility?

14 A. No. Mr. Crandall presents no analysis to support his claim; he simply alleges that

15 gas price fluctuations occurring in one year are spread to ratepayers over two or

16 more years due to the stabilizing effect of the ratemaking process. Further, as

17 discussed in the rebuttal of Mr. Brunell, Mr. Crandall’s allegation that the

18 ratemaking process insulates customers from natural gas market price volatility is

19 inaccurate.

21 Q. Do you agree with Mr. Crandall’s recommendation that the MPSC approve a

22 100% index purchasing strategy because the State of Nevada has rejected

23 hedging and moved to 100% index based purchasing?

24 A. No. This is irrelevant because DTE Gas Company does not operate in the State of

25 Nevada. Further, the climate, winter heating season, natural gas market, natural gas

EWC Rebuttal - 21 E. W. CLINTON Line U-17131 No.

1 storage, and pipeline transportation assets in the state of Nevada are materially

2 different than the state of Michigan.

4 Q. Do you agree with Mr. Crandall’s recommendation that the MPSC approve a

5 100% index purchasing strategy because other Michigan utilities such as

6 Consumers Energy and Michigan Gas Utilities have significantly reduced their

7 reliance on fixed price contracts?

8 A. No. DTE Gas Company has chosen the 75% VCA Method to mitigate price risk

9 and uncertainty. Other Michigan Utilities are free to propose whatever hedging

10 strategy they feel is reasonable and prudent based on their own circumstances,

11 considerations, objectives, and analyses. DTE Gas Company is different from other

12 Michigan utilities with respect to customer demographics, geographic area served,

13 storage assets, and pipeline transportation contracts amongst various other factors.

14 The “one size fits all” approach to hedging that Mr. Crandall is suggesting is not

15 appropriate due to these differences, which Mr. Crandall fails to acknowledge.

17 Q. Do you agree with Mr. Crandall’s recommendation that the MPSC approve a

18 100% index purchasing strategy because the cost of 75% fixed price contracts

19 is above that of index over the past 11-years with no commensurate volatility

20 reducing benefit?

21 A. No. Mr. Crandall’s allegation that the cost of 75% fixed price contracts is above

22 that of index over the past 11 years with no commensurate volatility reducing

23 benefit is not true. As stated in my direct testimony, “…over the 11-year period

24 customers would have paid $25 more annually or $2.08 more per month on average

25 under the VCA Method than compared to the Index Method. However, on Exhibit

EWC Rebuttal - 22 E. W. CLINTON Line U-17131 No.

1 A-26, page 2, line 12, gas price fluctuations, or price uncertainty, which is

2 synonymous with price volatility, over the 11-year period was 15% under the VCA

3 Method, which was significantly less than the Index Method volatility of 34% as

4 described more fully below.” Further, the historical back test is limited to how

5 market prices have behaved in the past, which is not a guarantee or predictor of

6 future price performance. The fact is that no one knows where prices will go in the

7 future and the VCA Method protects customers from this uncertainty.

9 Q. Do you agree with Mr. Crandall’s recommendation that the MPSC approve a

10 100% index purchasing strategy because gas prices have dropped and become

11 more stable?

12 A. No. Mr. Crandall’s allegation that gas prices have dropped and become more stable

13 is false and unsupported by any analysis. As discussed above in my rebuttal

14 testimony to Mr. Hollewa, natural gas prices have not been stable or dropped as

15 demonstrated by the fact that the rolling 12-month NYMEX natural gas strip price

16 has increased 64% in the past year from a low of $2.54 on April 23, 2012 to the

17 current price of $4.17 on May 8, 2013.

19 Q. Are there any other reasons you disagree with Mr. Crandall’s

20 recommendation that the MPSC approve a 100% index purchasing strategy

21 because gas prices have dropped and become more stable?

22 A. Yes. If in fact natural gas prices were stable, which they are not, then the VCA

23 Method would yield similar gas costs to a 100% index purchasing strategy. Index

24 purchasing is a passive strategy that does not involve any form of hedging or

25 creating price certainty for future deliveries.

EWC Rebuttal - 23 E. W. CLINTON Line U-17131 No.

1 Random Price Analysis

2 Q. What is Mr. Crandall’s criticism of the Random Price Analysis?

3 A. On pages 6 and 7 of his testimony, Mr. Crandall states that the Random Price

4 Analysis is invalid and does not account for the stabilizing effect of the ratemaking

5 process on rates that result from gas price volatility. It is not clear from his

6 testimony why Mr. Crandall believes the analysis is invalid.

8 Q. Do you agree with Mr. Crandall’s allegation that the Random Price Analysis is

9 invalid?

10 A. No. Mr. Crandall’s allegation is based on his discussion on page 6 of his testimony

11 about the Random Price Analysis without any supporting analysis and appears

12 deeply rooted in a general misunderstanding of the actual analysis. It appears that

13 Mr. Crandall believes the analysis is invalid because the average price in column

14 (d) of Exhibit A-26 is identical for all five fixed price methods. If I am correct, then

15 it is clear Mr. Crandall does not understand the meaning of the data on Exhibit A-26

16 col (d). The fact that the average price in column (d) of Exhibit A-26 is identical

17 for all five fixed price methods highlights the intent of the analysis, which is to

18 show that over many different prices scenarios all methods on average will yield the

19 same cost. However, a lower level of fixed price coverage produces an increasingly

20 wider range of potential price outcomes or higher level of price uncertainty.

21 Further, the fact that the average price in column (d) of Exhibit A-26 is identical for

22 all five fixed price methods highlights a basic principal that one hedging strategy

23 cannot beat the market, but in fact all strategies over many scenarios will in fact

24 duplicate the market price. The only difference from one strategy to the other is the

25 range of possible price outcomes. Further, as described above in the rebuttal to Mr.

EWC Rebuttal - 24 E. W. CLINTON Line U-17131 No.

1 Miller and Mr. Hollewa, contrary to Mr. Crandall’s criticisms the Random Price

2 Analysis is based on the Geometric Brownian Motion (GBM) model, which is in

3 fact a well-developed, versatile, and simple quantitative financial model used to

4 forecast price behavior. Just because Mr. Crandall is not familiar with the GBM

5 does not make it unreliable or invalid.

7 Q. Do you agree with Mr. Crandall’s allegation that the Random Price Analysis

8 does not account for the stabilizing effect of the ratemaking process on rates

9 that result from gas price volatility?

10 A. No. As discussed above in my testimony and in the testimony of Mr. Brunell, Mr.

11 Crandall’s belief about the stabilizing effect of the ratemaking process on rates that

12 result from gas price volatility is inaccurate and he presents no analysis to support

13 his claim.

15 VCA Method Mechanics

16 Q. What is Mr. Crandall’s criticism of the VCA Method mechanics?

17 A. On pages 8 of his testimony, Mr. Crandall criticizes the VCA Method because the

18 method does not require DTE Gas to make speculative calls on the natural gas

19 market. Specifically, he states that the “…VCA method absolves MichCon of any

20 duties or opportunities to purchase gas with relevance to the market price of gas,

21 and to be opportunistic with respect to gas purchases whenever gas prices fall

22 sharply, or to avoid purchasing gas when temporary gas price spikes occur.”

24 Q. Do you agree with Mr. Crandall’s statement that the VCA Method does not

25 require DTE Gas to make speculative calls on the natural gas market?

EWC Rebuttal - 25 E. W. CLINTON Line U-17131 No.

1 A. Yes, the VCA Method was designed to be prescriptive and time dependent as

2 opposed to price dependent to avoid speculating on the price of natural gas.

3 However, what Mr. Crandall is suggesting is that DTE Gas make purchases of

4 natural gas based on nothing more than speculation about market price. Mr.

5 Crandall does not offer any analysis, methodology, or a trading strategy as to what

6 price or when DTE Gas should purchase natural gas. Mr. Crandall’s suggestion that

7 DTE Gas should make speculative gas purchases should be rejected because it lacks

8 the requisite detail necessary to even be considered a prudent and reasonable

9 purchasing strategy, and also because it is speculative in nature.

11 Affiliate Transactions

12 Q. What is Mr. Crandall’s recommendation with respect to affiliate transactions?

13 A. On pages 13 of his testimony, Mr. Crandall recommends the Commission impose a

14 regulatory “city-gate” ceiling price on all gas purchases by DTE Gas from all of its

15 affiliates to protect customers from affiliate abuses and uncompetitive pricing that

16 may result from affiliated transactions where no arms-length bargaining exists.

18 Q. Do you agree with Mr. Crandall’s recommendation that the Commission

19 impose a regulatory “city-gate” ceiling price on all gas purchases by DTE Gas

20 from all of its affiliates to protect customers from affiliate abuses and

21 uncompetitive pricing that may result from affiliated transactions where no

22 arms-length bargaining exists?

23 A. No. Mr. Crandall’s recommendation is discriminatory because there is no valid

24 reason to preclude arms-length transactions between DTE Gas and its affiliates

25 when they occur in a non-discriminatory manner consistent with transactions

EWC Rebuttal - 26 E. W. CLINTON Line U-17131 No.

1 between DTE Gas and all other non-affiliated, similarly situated counterparties. It

2 should be noted that DTE Gas purchases from MichCon Gathering (MGAT) are in

3 fact priced at the MichCon city-gate index price.

5 IGS WITNESS WHITE

6 SOLR Reservation Charge

7 Q. What is Mr. White’s recommendation regarding the SOLR Reservation

8 Charge?

9 A. On page 3 of his testimony, Mr. White recommends that the Commission reject

10 DTE Gas’s SOLR Reservation Charge. Absent such rejection, Mr. White

11 recommends an audit and a separate hearing to assess the reasonableness of DTE

12 Gas’s supply plan including a financial cost/benefit review of the supply,

13 transportation, and storage assets. If the Commission still deems a SOLR

14 Reservation Charge to be reasonable, then Mr. White recommends: a) DTE Gas

15 release control of its storage assets over to the AGSs; b) the AGSs have more

16 control over the delivery of gas into the DTE Gas system; and c) DTE Gas release

17 the SOLR Reservation Pipeline Assets to the AGSs. Mr. White’s recommendations

18 are addressed below in my rebuttal testimony.

20 Q. Do you agree with Mr. White’s recommendations?

21 A. No. A separate audit and a separate hearing is not necessary and would be

22 redundant because this GCR Plan Case provides the very opportunity Mr. White

23 has requested to fully examine the reasonableness of DTE Gas’s supply plan and

24 DTE Gas’s SOLR Reservation Charge proposal. Furthermore, the Commission has

25 already approved a SOLR Reservation Charge as being reasonable and prudent for

EWC Rebuttal - 27 E. W. CLINTON Line U-17131 No.

1 two Michigan Gas Local Distribution Companies (LDCs). In addition, my direct

2 testimony supports the reasonableness of a SOLR Reservation Charge. With

3 respect to the three operational demands and modifications proposed by Mr. White,

4 DTE Gas opposes these because they are vague and do not provide a reasonable

5 operational alternative to DTE Gas as SOLR.

7 Q. Do you agree with Mr. White’s statement on page 17 of his testimony that “the

8 most logical and easiest way to increase protection would be for DTE to

9 request that AGSs pay higher deposits”?

10 A. No. Repeatedly on pages 11, 12, 13, 15, 16, 17, and 18, of his testimony, Mr.

11 White attempts to present alternative ways through higher AGS deposits and

12 economic penalties for AGS under-delivery, and that DTE Gas could generate and

13 use funds to buy its way out of a shortfall in supply, and thus allegedly solve or

14 prevent an operational problem. Contrary to Mr. White’s ideas, DTE Gas believes

15 that the best way to solve an operational problem is with operational solutions and

16 operational preventative measures. As noted by Witness White, the AGSs’ supply

17 responsibility is to essentially deliver 1/365th of their customers’ annual sales

18 volume to DTE Gas’s system each day of the year. Their responsibility as a

19 supplier ends there. AGSs are not required to have a supply plan for serving

20 customers’ actual demands during the heating season like DTE Gas is required.

21 AGSs are not required to have plans for securing supply under Colder Than

22 Normal (CTN) conditions like DTE Gas is required. AGSs are not required to have

23 a plan to meet the design day conditions for their customers like DTE Gas is

24 required. On a design day, it is DTE Gas that will ensure that the supply

25 requirements of all of its customers are met, using the supply plan included in this

EWC Rebuttal - 28 E. W. CLINTON Line U-17131 No.

1 case. The Company’s supply strategy has remained largely unchanged over the

2 years and has been repeatedly approved by the Commission as a reasonable and

3 prudent gas supply plan that ensures reliability of supply. The Company’s portfolio

4 of primary firm interstate pipeline contracts is the foundation of its reasonable and

5 prudent supply plan to meet the operational needs of all its customers, including the

6 operational responsibility as SOLR.

8 Q. Do you agree with Mr. White’s proposition on page 21 of his testimony that

9 DTE does not need to hold firm interstate transportation capacity to protect its

10 customers as SOLR?

11 A. No. In making his argument, Mr. White asserts that in lieu of holding firm

12 interstate transportation capacity, DTE Gas could purchase gas on the spot market,

13 buy interruptible contracts or off-peak or on-peak contracts, purchase interstate

14 transport capacity release, or get more gas from storage. Simply put, these other

15 avenues of securing supply are interruptible, and by definition cannot fulfill the

16 required need for primary firm service. DTE Gas holds primary firm interstate

17 transportation capacity as an integral part, but not the entire part, of its supply

18 portfolio to ensure firm, secure, and reliable flowing supply to its system, as well as

19 ensuring the high level of availability of such supply as may be needed as SOLR.

20 There is no certainty that the other avenues suggested by Mr. White would be

21 available when supply is needed, and there is a significant increase in supply risk

22 with a supply portfolio that does not maintain at a minimum the quantity of primary

23 firm interstate transport capacity that DTE Gas has historically maintained and

24 proposes to maintain into the future, which the Commission has reviewed and

25 approved in its previous GCR Plan cases. While I agree with Mr. White’s

EWC Rebuttal - 29 E. W. CLINTON Line U-17131 No.

1 statement on page 16 of his testimony that these other avenues of supply could be

2 less costly than holding firm pipeline capacity, such lower costs come at the

3 expense of a lower level of reliability of service and potentially higher supply risk.

4 DTE Gas has conservatively assumed that these lower cost supplies and

5 corresponding lower level of reliability have already been secured by the AGSs.

6 Therefore, this assumption also makes it appropriate for DTE Gas to charge AGSs

7 for their proportionate share of the primary firm interstate transportation capacity

8 that DTE Gas holds for purposes of reliability and security of supply to maintain the

9 operational integrity of its system as SOLR. Generally speaking, AGSs can come

10 and go as they please, and are neither the SOLR, nor have they incurred the costs of

11 supply reliability services associated with SOLR. Consequently, AGSs can benefit

12 from buying lower cost supplies with lower reliability of service, and therefore

13 should be placed onto a level playing field with DTE Gas by paying their

14 proportionate share of the interstate pipeline reservation costs that are incurred by

15 DTE Gas for purposes of SOLR.

17 Q. Do you agree with Mr. White’s claims on pages 14, 15, and 16 of his testimony

18 that, in the event of an AGS failure to deliver gas, the physical supply of gas to

19 DTE’s system would not be at risk because the same physical pipes, storage

20 and supply still exists, therefore, the default would in no way increase the risk

21 of customers not being able to physically receive gas?

22 A. No. Mr. White assumes that DTE Gas could rely on excess storage gas, supply

23 from interstate transport, or city-gate spot purchases in the event of an AGS default.

24 All of these assumptions are unacceptable because there is no guarantee that these

25 alternatives would be as reliable as primary firm interstate transportation capacity

EWC Rebuttal - 30 E. W. CLINTON Line U-17131 No.

1 necessary to serve all customers on a design day or colder than normal conditions.

2 As stated in my direct testimony on page EWC-25, lines 3 through 13, and

3 reiterated here: “Line 10, Exhibit A-16 shows a total peak-day requirement for

4 flowing GCR and GCC supply of slightly more than 500 MMcf/day for January,

5 February, and March. Given this level of peak-day requirements, a level of 400

6 MDth/day of interstate pipeline capacity is necessary to securely and reliably serve

7 these requirements. 400 MDth/day is approximately 80% of the combined GCR

8 and GCC flowing gas supply requirements on a peak-day, and slightly less than

9 50% of the total system wide flowing supply identified on line 14 of Exhibit A-16.”

10 DTE Gas considers, and the Commission has repeatedly approved, this level of

11 interstate capacity as reasonable, prudent, and necessary to ensure access to secure

12 and reliable supply necessary to maintain the operational integrity of DTE Gas’s

13 system on the coldest and most critical days of the year.

15 Q. What is the primary firm interstate transport portfolio for which DTE Gas is

16 requesting the AGSs pay their load proportionate share of SOLR Reservation

17 Charge?

18 A. DTE Gas’ primary firm interstate transport portfolio includes a set of contracts, as

19 shown on Exhibit A-10, that represent a diverse set of geographically located

20 interstate pipelines with various interconnections across all of DTE Gas’

21 transmission system and includes primary firm service priority, primary receipts

22 and primary delivery points, and contractual right of first refusal (ROFR) provisions

23 upon expiration. A ROFR provision guarantees DTE Gas the right to renew the

24 contract upon expiration by matching the highest bidder, consistent with Federal

25 Energy Regulatory Commission’s rules and regulations for posting and open

EWC Rebuttal - 31 E. W. CLINTON Line U-17131 No.

1 bidding of capacity. DTE Gas’ continually monitors and manages this interstate

2 pipeline portfolio for sustaining an ongoing reliability of service upon renewal of

3 contracts to meet changing load requirements and market conditions over time. As

4 noted in several other instances throughout my testimony city-gate spot purchases,

5 firm city-gate supply, interruptible transportation contracts, secondary

6 transportation paths, off-peak supply contracts, on-peak supply contracts, or firm

7 interstate capacity purchased in the secondary monthly capacity release market does

8 not produce the same level of supply reliability and corresponding contractual

9 rights as the primary firm interstate transportation capacity portfolio that DTE Gas’

10 holds as SOLR.

12 Q. Why is Mr. White’s assumption that “AGS would have a buffer of excess gas

13 that it would have already delivered into storage” unacceptable?

14 A. This assumption is unacceptable for three primary reasons: (1) DTE Gas already

15 plans for this gas in storage for purposes of colder than normal protection and to

16 assume that it is also available to backstop an AGS failure to deliver flowing supply

17 would be double counting, i.e. customer requirements are met from the sum of

18 flowing supply and storage supply, so a shortfall would occur if either supply or

19 storage source is unavailable, (2) DTE Gas already plans to withdraw gas from

20 storage at maximum withdrawal capability on a design day and there is no factual

21 basis upon which Mr. White can claim that additional storage withdrawals could be

22 obtained, and (3) flowing supply is needed to meet customer requirements for both

23 normal, colder than normal, and design day conditions, and therefore any shortfall

24 in flowing supply must be replaced with other flowing supply to maintain the

25 balance and integrity of DTE Gas’s system, especially on a design day in the

EWC Rebuttal - 32 E. W. CLINTON Line U-17131 No.

1 coldest and most critical winter months of January, February, and March when

2 storage balances may be at their absolute minimum. Witness Goodwin’s direct

3 testimony and exhibits provide the additional details on DTE Gas’s planning

4 assumptions for design day, minimum storage balances, and colder than normal

5 weather operations.

7 Q. Why do you disagree with Mr. White’s assumption on page 16 of his testimony

8 that “an AGS default would in no way increase the risk of customers not being

9 able to physically receive gas”, and that DTE could simply buy spot gas at the

10 DTE trading hub as a viable alternative to contracting for the firm interstate

11 transportation capacity?

12 A. There is no guarantee that DTE Gas will be able to secure additional capacity on

13 existing interstate pipelines in the future because interstate pipeline capacity is

14 finite and limited to availability. Many of the pipelines that can serve the DTE Gas

15 system could be fully subscribed by other shippers delivering gas to other

16 distribution or transmission systems, thereby leaving no additional capacity for gas

17 to be delivered to the DTE system. The risk of capacity unavailability could be

18 even greater during a colder than normal winter or a peak design day. Incremental

19 supply could be secured on the spot market, through capacity release, interruptible

20 transportation, or at the DTE Gas city gate as suggested by Mr. White, however

21 there is no guarantee that these alternatives would be as reliable as primary firm

22 interstate transport capacity. As I presented in my direct testimony on page EWC-

23 25, lines 3 through 13, DTE Gas believes that the level of primary firm interstate

24 pipeline capacity presented in its plan case is necessary because it represents 80%

25 of the combined GCR and GCC flowing gas supply requirements on a peak-day,

EWC Rebuttal - 33 E. W. CLINTON Line U-17131 No.

1 and slightly less than 50% of the total system wide flowing supply requirements.

2 These levels already allow for a significant portion, 20% to 50%, of the remaining

3 supply requirements to be delivered from alternative, potentially less reliable

4 sources. DTE Gas considers this level of interstate capacity as reasonable, prudent,

5 and necessary to ensure access to secure and reliable supply necessary to maintain

6 the operational integrity of DTE Gas’s system on the coldest and most critical days

7 of the year, and anything less would be unacceptable.

9 Q. Do you agree with his testimony on pages 6, 10 and 20, where Mr. White

10 claims that DTE is holding more firm interstate transport capacity than

11 needed, and that DTE should periodically assess the level of migration to and

12 from the GCR and adjust their pipeline capacity holdings accordingly?

13 A. No. As stated in my direct testimony on page EWC-24, DTE Gas is the SOLR and

14 that for reasons of security and reliability of supply to serve both GCR and GCC

15 requirements, DTE Gas must maintain, and continue to maintain into the future, a

16 portfolio of primary firm interstate transportation capacity sufficient to serve both

17 GCR and GCC customers regardless of the level of GCC participation whether that

18 is 0% of total sales markets requirements, 100%, or anywhere in between. DTE

19 Gas annually assesses the level of supply requirements and pipeline capacity

20 necessary to serve those requirements and presents those findings and

21 recommendations every year in its annual GCR plans filed with the MPSC. This

22 aspect of the GCR plans has been presented every year to the Commission and DTE

23 Gas has received Commission approval of those plans.

25 Q. Do you agree with Mr. White’s testimony on page 10, lines 1 through 3, and

EWC Rebuttal - 34 E. W. CLINTON Line U-17131 No.

1 page 11, lines 7 through 8, that DTE is holding more capacity than needed and

2 that DTE is oversubscribed to pipeline assets because AGSs are also

3 responsible for transporting gas for GCC customers?

4 A. No. DTE Gas witness Bernard Kramer shows in his rebuttal testimony that IGS and

5 most RESA members do not hold primary firm interstate transport capacity to

6 deliver gas to DTE Gas’ transmission system interconnects. Furthermore, as

7 explained elsewhere in my direct and rebuttal testimony, none of the AGS supply

8 arrangements would be sufficient to replace the primary firm interstate transport

9 that DTE Gas holds as SOLR because there is no guarantee or responsibility on the

10 part of any of the AGSs to act as SOLR or to manage any of its supply assets in a

11 way that could replace or duplicate the DTE Gas primary firm interstate

12 transportation portfolio that is used for the sustaining and ongoing purpose of

13 SOLR.

15 Q. Do you agree with his testimony on page 26 where Mr. White proposes that the

16 Commission give AGSs more control and flexibility over the transportation,

17 storage, and delivery of gas in and through DTE’s system because it would

18 mitigate the harm done to GCC customers by requiring AGSs to shoulder the

19 substantial cost of the SOLR Reservation Assets?

20 A. No. DTE Gas’s SOLR reservation charge relates to the primary firm interstate

21 transportation capacity DTE Gas holds to act as SOLR, which excludes the costs of

22 DTE Gas’ transmission, storage, and distribution systems that are recovered

23 through distribution rates. Mr. White’s proposal for DTE to release control and

24 flexibility over its transportation, storage, and deliver of gas is too vague to be

25 reasonable or prudent. There has been no harm done to GCC customers and there is

EWC Rebuttal - 35 E. W. CLINTON Line U-17131 No.

1 nothing to mitigate because they have never paid for these assets in the past, and the

2 proposal is only to pay their proportionate share of the SOLR costs going forward.

3 These SOLR Reservation Assets are an operational necessity for DTE to maintain

4 access to reliable and secure supply to be ready, willing and able as SOLR to meet

5 GCR and GCC customer requirements at all times, and the costs of those assets

6 should be ratably allocated between DTE Gas and AGSs for the purposes of serving

7 our respective GCR and GCC customers.

9 RESA WITNESS HAUGH

10 SOLR Reservation Charge

12 Q. What is Mr. Haugh’s recommendation regarding the SOLR Reservation

13 Charge?

14 A. On page 5 of his testimony, Mr. Haugh recommends that the Commission reject

15 DTE Gas’s SOLR Reservation Charge. However, if the Commission does approve

16 the SOLR Reservation Charge, Mr. Haugh recommends that it should be charged

17 directly to the GCC Customers and not their suppliers (Alternative Gas Suppliers or

18 AGSs). Further, Mr. Haugh recommends that DTE Gas should release control of

19 the interstate pipeline capacity over to the AGSs. My rebuttal will address these

20 recommendations, except for the levy of SOLR Reservation Charges on GCC

21 customers instead of the AGSs, which is rebutted by Witness Brunell.

23 Q. Do you agree with Mr. Haugh’s recommendations?

24 A. No. The Commission has already approved a SOLR Reservation Charge as being

25 reasonable and prudent for two Michigan LDCs and my direct testimony supports

EWC Rebuttal - 36 E. W. CLINTON Line U-17131 No.

1 the reasonableness of a SOLR Reservation Charge. With respect to the operational

2 demands and modifications proposed by Mr. Haugh, DTE Gas is opposed to

3 releasing pipeline capacity to AGSs for operational reasons, but does agree to the

4 month-to-month release of capacity as recallable under the open bidding process at

5 market value to achieve the maximum benefit for all customers. Witness Brunell

6 rebuts the other recommendation concerning application of the SOLR Reservation

7 Charge to GCC customers instead of AGSs.

9 Q. Should DTE discontinue purchasing firm capacity for GCC customers as

10 suggested by Mr. Haugh on pages 6 and 7 of his testimony?

11 A. No. The nature of the primary firm interstate capacity that DTE Gas holds in its

12 portfolio is for the dual purpose of securing supply for its GCR customers and for

13 security and reliability of supply to insure system operation integrity as SOLR.

14 First, Mr. Haugh wrongly assumes on lines 2 and 3, page 6 of his testimony, that

15 DTE Gas “feels it must purchase firm pipeline capacity for 100% of its customer

16 load”. Second, Mr. Haugh misquotes Section F1.7 of DTE’s natural gas tariff as

17 requiring that “GCC Suppliers either purchase firm capacity into the MichCon

18 citygate or purchase firm natural gas commodity already delivered to the citygate,”

19 thereby incorrectly concluding that this results in “purchasing double capacity for

20 customers”. Third, Mr. Haugh wrongly believes that “credit requirements” are

21 sufficient to prevent AGSs supply default. Fourth, Mr. Haugh wrongly believes

22 that DTE Gas could either buy capacity release from AGSs in the event of AGSs

23 supply default in lieu of holding primary firm interstate capacity to meet the needs

24 of SOLR. And fifth, Mr. Haugh wrongly believes that DTE Gas could release

25 capacity to AGSs while retaining the ability to recall it in the instance of default.

EWC Rebuttal - 37 E. W. CLINTON Line U-17131 No.

1 Q. What is the nature of the firm interstate capacity that DTE holds in its

2 portfolio that rebuts all of Mr. Haugh’s assumptions and conclusions around

3 the necessity of these contracts?

4 A. As stated in my direct testimony on page EWC-25, lines 3 through 13, and

5 reiterated above in rebuttal to Mr. White, DTE Gas does not hold capacity for 100%

6 of its customer load. On a design day, DTE Gas’ primary firm interstate transport

7 capacity represents about 80% of the flowing supply requirements from DTE Gas

8 and AGSs combined, thus achieving a balanced supply portfolio between 80%

9 primary firm interstate transport and 20% from other sources, most likely spot city

10 gas supply either purchased by DTE Gas or AGSs. Furthermore, Section F1.7 of

11 DTE Gas’s gas tariff only requires AGSs to “be responsible for obtaining sufficient

12 pipeline capacity to meet its delivery obligations,” which could be achieved with

13 nothing more than interruptible supply and transport contracts. Interruptible supply

14 is not “primary firm capacity”, and thus it is insufficient to provide the level of

15 supply reliability required as SOLR on a design day or colder than normal winter.

16 Again, the AGSs supply responsibility begins and ends with providing 1/365th of

17 their customers’ annual sales on a daily basis. Only DTE Gas is responsible for

18 meeting the needs of all customers on a design day or during CTN conditions. DTE

19 Gas’s supply plan requires primary firm interstate capacity to ensure reliability of

20 supply, and no capacity that may or may not be held by AGSs is duplicative as Mr.

21 Haugh claims. None of Mr. Haugh’s suggested alternatives to DTE Gas’s primary

22 firm interstate capacity would be able to meet the high level of supply reliability

23 that is needed for the 400 MDth/day, which is 80% of flowing supply requirements

24 on a design day. Mr. Haugh’s proposed “credit requirements” to prevent AGSs

25 supply default is an insufficient economic remedy to an operational problem and

EWC Rebuttal - 38 E. W. CLINTON Line U-17131 No.

1 will not ensure that natural gas is available to our customers especially on the most

2 critical and coldest days of winter. Further, DTE Gas cannot rely on purchasing

3 capacity from a defaulting AGS because there is no guarantee the defaulting AGS

4 owns capacity, let alone primary firm capacity, as it is not a requirement of DTE

5 Gas’ Tariff provision F1.7. Lastly, DTE Gas must maintain primary firm interstate

6 capacity to access reliable and secure supply and be ready, willing and able as

7 SOLR to meet GCR and GCC customer requirements at all times.

9 Q. Do you agree with Mr. Haugh’s testimony on page 6, lines 11 through 17, that

10 the firm capacity or firm natural gas commodity already delivered to the city

11 gate is duplicative of the primary firm interstate transport held by DTE Gas

12 for purpose of SOLR?

13 A. No. DTE Gas witness Bernard Kramer shows in his rebuttal testimony that IGS and

14 most RESA members do not hold primary firm interstate transport capacity to

15 deliver gas to DTE Gas’s transmission system interconnects. Furthermore, as

16 explained elsewhere in my direct and rebuttal testimony, none of the AGS supply

17 arrangements would be sufficient to replace the primary firm interstate transport

18 that DTE Gas holds as SOLR because there is no guarantee or responsibility on the

19 part of any of the AGSs to act as SOLR or to manage any of its supply assets in a

20 way that could replace or duplicate the DTE Gas primary firm interstate

21 transportation portfolio that is used for the sustaining and ongoing purpose of

22 SOLR.

24 Q. If the Commission approves the SOLR Reservation Charge, should they also

25 require DTE to release the capacity to the AGSs to manage it on behalf of the

EWC Rebuttal - 39 E. W. CLINTON Line U-17131 No.

1 GCC customers as proposed by Mr. Haugh on page 9 of his testimony?

2 A. On occasions, DTE Gas has capacity available for release on a recallable basis one

3 month at a time and such capacity is posted for release on the applicable pipeline(s)

4 electronic bulletin board(s) (EBB). The AGS is not precluded from bidding on such

5 capacity, and may in fact secure the capacity if it is the highest bidder. This process

6 of capacity release ensures that the maximum value is achieved for all customers,

7 and since the capacity release revenues will be credited back to the SOLR

8 Reservation Charge, it ensures that such Reservation Charge is minimized for the

9 benefit of all customers. Additionally, DTE Gas would not release control of any of

10 its primary firm interstate capacity in any other manner than described above

11 because there is no guarantee that the AGSs would even use the capacity to supply

12 the DTE Gas system from primary firm receipt points, to primary firm delivery

13 points, with firm supply when and where it is operationally needed at the various

14 points of delivery on the DTE Gas System.

16 Q. Does this complete your rebuttal testimony?

17 A. Yes, it does.

EWC Rebuttal - 40 STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

REBUTTAL TESTIMONY

BARBARA J. GOODWIN

DTE GAS COMPANY REBUTTAL TESTIMONY OF BARBARA J. GOODWIN Line No.

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

2 A. My name is Barbara J. Goodwin. My business address is: One Energy Plaza,

3 Detroit, Michigan 48226. I am employed by DTE Gas Company (DTE Gas or

4 Company) (formerly known as Michigan Consolidated Gas Company) as Principal

5 Analyst in the Gas Supply and Planning department.

7 Q. Did you file direct testimony in this proceeding on behalf of DTE Gas

8 Company?

9 A. Yes, I did.

11 Q. What is the purpose of your rebuttal testimony?

12 A. The purpose of my testimony is to rebut the testimony of Michigan Community

13 Action Agency Association (MCAAA) Witness Mr. Geoffrey C. Crandall (Mr.

14 Crandall) concerning DTE Gas’s planned use of Convertible Base Gas (CBG).

16 Q. What issue does Mr. Crandall raise with regards to DTE Gas’s planned use of

17 CBG?

18 A. Mr. Crandall stated that DTE Gas appears to be losing sight of the original intent

19 and purpose of the CBG provisions of the settlement agreement in Case No. U-

20 15628 (“U-15628 settlement” or “the settlement agreement”) by reflecting a

21 provision for the use of 2 Bcf of CBG in its Colder than Normal (CTN) weather

22 plan.

24 Q. Does Mr. Crandall make a recommendation related to the issue of CBG?

25 A. Yes. Mr. Crandall recommends that original intent and purpose for the CBG

BJG Rebuttal - 1 B. J. GOODWIN Line U-17131 No.

1 provision should be preserved. He states that the provision to use CBG during CTN

2 weather should be “subservient” to the provision to use CBG to avoid the purchase

3 of gas during temporary increases in NYMEX market prices due to hurricanes.

5 Q. Do you agree with Mr. Crandall’s recommendation?

6 A. No. DTE Gas continues to follow the settlement agreement as written. Since the

7 time of the order approving the settlement in Case No. U-15628, pursuant to

8 paragraphs 6a, 6c, and 6d(iv) of the settlement agreement, DTE Gas continues to

9 plan to enter the winter season holding a 2 Bcf portion of the planned 5 Bcf of CTN

10 protection (CTNP) as CBG, if not yet utilized. As described in my testimony on

11 page BJG-16, line 8 to BJG- 17, line 8, DTE Gas plans for both the provision in

12 paragraph 6.d(iv) of the settlement agreement to use up to 2 Bcf of CBG for CTNP

13 and also the provision Mr. Crandall is concerned about in paragraph 6.d(ii), to use

14 up to 2 Bcf of CBG for non-CTNP reasons. If, for example, Staff and Interveners

15 direct DTE Gas to use 2 Bcf of the available CBG as gas supply for a non-CTNP

16 reason, then DTE Gas will do so as stated in testimony and pursuant to the

17 settlement agreement. As such Mr. Crandall’s recommendation is misplaced and

18 unnecessary.

20 Q. Does this complete your rebuttal testimony?

21 A. Yes, it does.

BJG Rebuttal - 2 STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application of ) Michigan Consolidated Gas Company1 ) for approval of a Gas Cost Recovery Plan, ) Case No. U-17131 5-year Forecast and Monthly GCR Factor ) for the 12 months ending March 31, 2014 ) and for approval to implement a Reservation ) Charge applicable to Gas Customer Choice ) Suppliers______)

PROOF OF SERVICE

STATE OF MICHIGAN ) ) ss. COUNTY OF WAYNE )

MARILYN Y. OLIVER, being duly sworn, deposes and says that on the 14th day

of May, 2013, she served a copy of the DTE Gas Company’s Rebuttal Testimony and

Rebuttal Exhibits for James A Brunell and W. Bernard Kramer and also the Rebuttal

Testimony, only, for Eric W. Clinton and Barbara J. Goodwin, via electronic mail upon

the parties referred to in the attached service list.

MARILYN Y. OLIVER

Subscribed and sworn to before me this 14th day of May, 2013

______Lorri A. Hanner, Notary Public Wayne County, Michigan My Commission Expires: 4/20/2020

1 fn: Effective January 1, 2013 Michigan Consolidated Gas Company changed its legal name to DTE Gas Company. Because this case was originally captioned under the legal name of Michigan Consolidated Gas Company and will be concluded subsequent to the legal name change to DTE Gas Company, both names are used throughout this document.

ADMINSTRATIVE LAW JUDGE RETAIL ENERGY SUPPLY Sharon L. Feldman ASSOCIATION Administrative Law Judge Eric J. Schneidewind Michigan Public Service Commission Timothy J. Lundgren 525 W Allegan St Fl 3 201 N. Washington Square, Suite 810 North Tower Lansing, MI 48933 Lansing, MI 48913 [email protected] [email protected] [email protected]

ATTORNEY GENERAL INTERSTATE GAS SUPPLY, INC. Michael E. Moody Dickinson Wright PLLC Assistant Attorney General John M. Dempsey Environment, Natural Resources, Brandon C. Hubbard and Agriculture Division 350 S. Main Street, Suite 300 6th Floor, G. Mennen Williams Bldg. Ann Arbor, MI 48104-2131 P.O. Box 30755 [email protected] Lansing, MI 48909 [email protected] [email protected]

LAKESHORE ENERGY SERVICES, MICHIGAN COMMUNITY ACTION LLC AGENCY ASSOCIATION William J. Wolter Don L. Keskey 192 E. Main Street 139 W. Lake Lansing Road, Suite 210 Northville, MI 48167 East Lansing, MI 48823 [email protected] [email protected]

MPSC STAFF RESIDENTIAL RATEPAYER Patricia S. Barone CONSORTIUM Lauren D. Donofrio David L. Shaltz Assistant Attorneys General Chalgian & Tripp Law Offices PLLC Public Service Division 1019 Trowbridge Road 6520 Mercantile Way, Suite 1 East Lansing, MI 48823 Lansing, MI 48911 [email protected] [email protected] [email protected]

Page 1 of 2 MPSC Case No. U-17131 Service List 1/8/13

MICHIGAN CONSOLIDATED GAS COMPANY David S. Maquera Richard P. Middleton Legal Department One Energy Plaza, 688 WCB Detroit, MI 48226 [email protected] [email protected] [email protected]

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