S T A T E O F M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * * In the matter of the Application of ) DTE GAS COMPANY for approval of a ) Gas Cost Recovery Plan, Five-Year Forecast, ) Case No. U-17691 and Monthly GCR Factor for the 12-months ) ending March 31, 2016 approvals. )

NOTICE OF PROPOSAL FOR DECISION

The attached Proposal for Decision is being issued and served on all parties of

record in the above matter on July 7, 2016.

Exceptions, if any, must be filed with the Michigan Public Service Commission,

7109 West Saginaw, Lansing, Michigan 48917, and served on all other parties of record on

or before July 28, 2016, or within such further period as may be authorized for filing

exceptions. If exceptions are filed, replies thereto may be filed on or before August 11, 2016.

The Commission has selected this case for participation in its Paperless Electronic

Filings Program. No paper documents will be required to be filed in this case.

At the expiration of the period for filing exceptions, an Order of the Commission will

be issued in conformity with the attached Proposal for Decision and will become effective

unless exceptions are filed seasonably or unless the Proposal for Decision is reviewed by

action of the Commission. To be seasonably filed, exceptions must reach the Commission

on or before the date they are due.

MICHIGAN ADMINISTRATIVE HEARING SYSTEM For the Michigan Public Service Commission _____________________________________ Mark D. Eyster Administrative Law Judge

July 7, 2016 Lansing, Michigan

S T A T E O F M I C H I G A N

MICHIGAN ADMINISTRATIVE HEARING SYSTEM

FOR THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * * In the matter of the Application of ) DTE GAS COMPANY for approval of a ) Gas Cost Recovery Plan, Five-Year Forecast, ) Case No. U-17691 and Monthly GCR Factor for the 12-months ) ending March 31, 2016 approvals. )

PROPOSAL FOR DECISION

I.

PROCEDURAL HISTORY

On December 30, 2014, the DTE Gas Company (DTE, DTE Gas, or Company)

filed an Application requesting Michigan Public Service Commission (Commission)

approval of a Gas Cost Recovery (GCR) plan (Plan) and factors for the 12-month period

from April 1, 2015 through March 31, 2016.

On February 10, 2015, a pre-hearing conference was held before Administrative

Law Judge, Mark D. Eyster. Counsel appeared on behalf of DTE Gas, the Michigan

Public Service Commission staff (Staff), the Attorney General for the State of Michigan

(Attorney General), the Residential Ratepayer Consortium (RRC), Interstate Gas Supply,

Inc. (IGS), and the Retail Energy Supply Association (RESA). At the pre-hearing

conference, intervenor status was granted to the Attorney General, RRC, IGS, and RESA

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and a schedule was adopted. On March 11, 2015, ANR Pipeline Company (ANR) filed a

Petition for Leave to Intervene. On May 27, 2015, ANR was granted intervenor status.

A full evidentiary hearing was conducted on August 20-21, 2015, at which the pre-

filed testimony of the witnesses was bound into the record, exhibits were admitted into

evidence, and cross-examination was conducted. On October 9, 2015, briefs were filed

by DTE Gas, Staff, RRC, RESA, ANR, and the Attorney General. On November 9, 2015,

reply briefs were filed by DTE Gas, RRC, RESA, ANR, and the Attorney General. On

December 4, 2015, supplemental briefs were accepted from DTE Gas and ANR. The

record consists of testimony contained in the 884 page transcript and 91 exhibits.

II.

FINDINGS OF FACT, POSITIONS OF THE PARTIES, AND DISCUSSIONS A. Introduction

DTE Gas presented the testimony of six witnesses: James A. Brunell, a

Consultant in Regulatory Affairs employed by DTE Energy Corporate Services, LLC.;

Sherri M. Moore, a Senior Gas Supply & Planning Analyst employed by DTE Gas; Robert

G. Lawshe, DTE Gas’ Manager of Gas Supply and Planning; Michael D. Sloan, Principal,

Energy Advisory Services with ICF International; George H. Chapel, Manager, Market

Forecasting for DTE Gas, and; W. Bernard Kramer, a Regulatory Compliance Consultant

in DTE Energy Corporate Services LLC’s Regulatory Policy and Operations Department.

Mr. Brunell provided testimony to address the calculation of DTE Gas’ proposed

monthly base GCR factor, the contingent mechanism and its implementation, the five-

year forecasted cost of gas, and the administration of DTE Gas’s Supplier of Last Resort

U-17691 Page 3

(SOLR) Reservation Charge. He also presented rebuttal testimony in response to

evidence presented by the Attorney General and RESA. Mr. Brunell was subject to cross-

examination. He sponsored Exhibits A-20 through A-24, Exhibit A-28, and Exhibit A-42.

Ms. Moore provided direct testimony is to describe DTE Gas’s operational plan for

the five-year period from April 1, 2015 through March 31, 2020. She also provided

rebuttal testimony to address matters raised by RRC’s witness, Frank Hollewa. She

sponsored Exhibits A-13 through A-18 and A-43 through A-45. She was subject to cross-

examination.

Mr. Lawshe provided direct testimony addressing DTE Gas’ natural gas supply

plan for April 1, 2015 through March 31, 2020. Among other things, he focused on DTE

Gas’ arrangements with NEXUS Gas Transmission. In addition, he provided rebuttal

testimony to address matters raised by ANR’s witness, Mr. Bennett; the Attorney

General’s witness, Mr. Coppola; RRC’s witness, Mr. Hollewa, and; RESA’s witness, Mr.

Dishno. He also presented surrebuttal testimony to address matters raised in Mr.

Dishno’s surrebuttal. He was subject to cross-examination and sponsored Exhibits A-7

through A-12, A-25 through A-27, and A-33 through A-41.

Mr. Sloan provided direct testimony primarily to support admission of Exhibit A-30,

a December 15, 2014 ICF report titled, “The Value of Nexus Pipeline Capacity to DTE

Gas Customers”. He also provided rebuttal testimony to address the testimony provided

by ANR’s Mr. Bennett and the Attorney General’s Mr. Coppola. Mr. Sloan was subject to

cross-examination. In addition to Exhibit A-30, he sponsored Exhibits A-29, A-31, and

A-32.

U-17691 Page 4

Mr. Chapel provided direct testimony to address aspects of DTE Gas’ Five-Year

Forecast and the reasonableness of its Plan. He sponsored Exhibits A-1 through A-6.

He was not the subject of cross-examination.

RESA presented one witness, Daniel Dishno, Director of Gas Supply-Central

Division for IGS. He provided direct testimony addressing DTE Gas’ proposed

Reservation Charge. He provided surrebuttal testimony in response to the rebuttal

testimony of Mr. Lawshe and Mr. Brunell. He was subject to cross-examination. He

sponsored Exhibit RES-1.

ANR called one witness, Lee Bennett, Manager, Short-Term Marketing for

TransCanada, U.S. Pipelines. Mr. Bennett provided direct testimony addressing

alternatives to DTE Gas’ plan to purchase 75,000 Dth/d of firm transportation capacity on

the NEXUS pipeline; a pipeline co-owned by DTE Energy. He was not subject to cross-

examination.

Testifying on behalf of RRC was Frank J. Hollewa, an Independent Energy

Consultant. He provided direct testimony addressing his independent analysis and

evaluation of DTE Gas’ proposed Plan. He sponsored Exhibits RRC-1 through RRC-3.

He was not subject to cross-examination.

Testifying for the Attorney General was Sebastian Coppola, an Independent

Energy Business Consultant. He provided direct testimony to explain his analysis of DTE

Gas’ Plan. He sponsored Exhibits AG-1 through AG-4 and was not subject to cross-

examination.

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B. Plan and Five-Year Forecast Overview DTE Gas expects to serve approximately 1,234,000 customers in the GCR year.

Exh A-1. By the 2019-20 plan year, DTE Gas expects this figure will rise to approximately

1,278,000 customers. Exh A-1.

DTE Gas projects GCR/GCC gas sales of 160.1 Bcf for the GCR year, rising to

165.0 Bcf in year five of its Five-Year Forecast. 5 Tr 729. DTE Gas projects GCR sales

volumes of 125.4 Bcf for 2015-16, 125.9 Bcf for 2016-17, 127.2 for 2017-18, 128.6 for

2018-19, and 130.6 Bcf for 2019-20. 5 Tr 740. DTE Gas projects GCR customer counts

of 1,040,153 for 2015-16, rising to 1,083,869 for 2019-20. 5 Tr 741.

Projected natural gas prices for the Plan year and for the Five-Year Forecast are

found in Exhibit A-8 and are described at 4 Tr 270-72. To make purchases, DTE Gas

maintains a list of about 30 suppliers from which it “generally solicits at least three verbal

offer prices from . . . the supply area that is required.” 4 Tr 272. DTE Gas does not issue

Requests for Proposal to meet its supply requirements. 4 Tr 272.

For 2015-16, DTE Gas projects 193,810 customers will be served by an alternate

supplier through the GCC program. 5 Tr 739. DTE Gas projects GCC sales volumes of

346 Bcf in 2015-16, dropping to 34.5 Bcf for 2016-17 through 2019-20. 5 Tr 740. DTE

Gas projects a sales increase to GCR commercial and industrial volumes, from 61.6 Bcf

to 63.8 Bcf from 2015-16 to 2019-20. 5 Tr 738.

For the GCR Plan year, DTE expects the following supply sources with their

percentage of supply: Mid-Continent – 53%, Canadian – 28%, City-Gate – 13%, and Gulf

Coast – 6%. 4 Tr 282.

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In this case, DTE Gas has utilized weather data from 2000 to 2014 to calculate its

15-year normal weather. 5 Tr 731. “Weather normalization adjusts actual volumes from

a past period to eliminate the impact of abnormal weather on the data during that time

period. Weather normalized data is then used to make inferences about customer

behavior trends.” 5 Tr 731.

DTE Gas proposes a maximum GCR factor of $4.07 per Mcf for the GCR year,

adjustable monthly based upon a contingent factor matrix. 4 Tr 149.

DTE Gas proposes the continuation of fixed price gas purchase pursuant to the

Volume Cost Average methodology (VCA Method) first approved by the Commission in

Case No. U-16146. 4 Tr 257. “In general, DTE Gas [proposes to] fix the price of its future

supply requirements over a two year period prior to the start of delivery during the GCR

Period. In other words, the price of 75% of DTE Gas’ supply requirements will be known

prior to the start of the GCR Period.” 4 Tr 258.1 The remaining 25% of its gas supply will

be purchased at index price. 4 Tr 264.

“DTE Gas maintains a portfolio of 400 MDth/day of firm transportation contracts

for the winter operating season and 340 MDth/day for the summer storage injection

season to meet supply requirements for normal weather, colder than normal weather,

design day, and supplier of last resort.” 4 Tr 273. Information regarding its interstate

transportation contracts can be found in Exhibit A-9. 2 Tr 278. Changes to its

transportation portfolio include: extending the contract for 50 MDth/D of Vector capacity

through October 31, 2017, replacing its ANR/SE 20 MDth/D winter and 10 MDth/D

summer capacity contract with a like contract on Panhandle Eastern Pipe Line Company

1 This part of DTE’s Plan is contested and is more fully examined below.

U-17691 Page 7

(PEPL) to expire on October 31, 2017, and extending the term of the 50 MDth/D of

ANR/SW capacity through October 31, 2017. 4 Tr 279. Beginning November 2017, DTE

Gas intends to utilize a 15-year transportation contract with NEXUS Gas Transmission

(NEXUS) to transport 75 MDth/d of Utica and Marcellus shale production gas from

Eastern Ohio. 4 Tr 286.

As summarized in Exhibit A-10, DTE Gas projects a total expected gas purchase

quantity of 136.7 MMDth and a total expected gas purchase cost of $ 530.0 million for the

April 2015 through March 2016 period. 4 Tr 283. As summarized in Exhibit A-11, DTE

Gas expects transportation and Parking Service costs of $ 49.3 million for the period April

2015 through March 2016. 4 Tr 284.

C. Contested Matters

Most matters in this case are not in dispute. For those uncontested factual matters,

based on the record presented, DTE Gas’ representations appear reasonable and, unless

otherwise noted, are approved. The remaining contested issues are addressed below.

1. NEXUS

a. Findings of Fact

DTE Energy and Spectra Energy Corp are jointly developing the proposed NEXUS

gas transportation pipeline project designed to transport Appalachian Basin gas to

customers in the U.S. Midwest and Ontario, Canada. 4 Tr 287. Commencement of

service on NEXUS is targeted for November 2017. 4 Tr 287. New construction on the

proposed NEXUS pipeline will run approximately 250 miles from receipt points in eastern

Ohio to DTE Gas’ existing pipeline grid in southeastern Michigan. 4 Tr 287. NEXUS

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shippers will be able to reach Dawn, Ontario via DTE Gas pipelines2 or via Vector

Pipeline, L.P., another DTE Gas affiliate, through capacity NEXUS intends to acquire from

these affiliates. 5 Tr 778. NEXUS is expected to have a total transport capacity of

1.5 Bcf/d. 4 Tr 288.

As part of its Five-Year Forecast, DTE Gas has included a 15-year transportation

contract with NEXUS. 4 Tr 286. As stated by Mr. Lawshe, at 4 Tr 289-90:

DTE Gas has entered into a Precedent Agreement dated July 23, 2014 (NEXUS PA), with DTE Pipeline Company and Spectra Energy Transmission, LLC that provides for a 15-year transportation contract to transport 75 MDth/d of Utica and Marcellus shale production gas to the DTE

2 As part of the Nexus Pipeline project, on November 24, 2015, DTE Gas filed an Abbreviated Application of DTE Gas Company for Issuance of Limited Jurisdiction Certificate to Lease Pipeline Capacity to NEXUS Gas Transmission, LLC for Use to Transport Natural Gas in Interstate Commerce (Abbreviated Application). Notice is taken of this filing. In the Abbreviated Application, DTE Gas requested approval of a Capacity Lease with NEXUS and approval of a limited jurisdiction certificate to allow for the interstate transportation of gas through DTE Gas’ system. At page 3-6 of the Abbreviated Application, DTE Gas explained:

Pursuant to the Capacity Lease, NEXUS has agreed to lease existing unsubscribed capacity as well as expansion capacity from DTE Gas. The capacity proposed to be leased extends from a new interconnect between NEXUS and DTE Gas in Ypsilanti Township, Michigan (Willow Run) to (1) the Vector-Milford Junction interconnect (Milford Meter Station) between DTE Gas and Vector Pipeline (Vector), (2) the Vector-Belle River interconnect between DTE Gas and Vector, and (3) the Union-St. Clair interconnect between DTE Gas and Union Gas Limited (Union) at the U.S./Canada border. The Capacity Lease will utilize existing capacity on DTE Gas’s system as well as expansion capacity created by additional compression at existing DTE Gas compressor stations. The construction of the associated DTE Gas expansion capacity will be subject to the jurisdiction of the MPSC, as DTE Gas is a state regulated gas utility providing limited interstate transportation service pursuant to 18 C.F.R. § 284.224.

* * * DTE Gas will continue to own, operate and maintain all of its facilities on an

integrated basis. However, NEXUS will have the right to use the leased capacity on a firm basis to provide transportation services to its customers pursuant to NEXUS’s FERC Gas Tariff.

The daily quantity of firm pipeline capacity associated with the Capacity Lease, exclusive of any fuel gas, from the receipt point to the delivery points will be between 1,001,829 and 1,501,829 Dth/d, subject to and depending on the exercise of certain NEXUS rights to increase or reduce its contracted capacity as provided in the Capacity Lease.

* * * The lease charges under the Capacity Lease were negotiated at arms-length between representatives of DTE Gas and NEXUS and are less than firm transportation rates for comparable service on the DTE Gas pipeline system.

See FERC Docket No. CP-16-24. FERC documents may be found at http://www.ferc.gov/docs-filing/ferconline.asp

U-17691 Page 9

Gas system with an anticipated start date of November 1, 2017. One of the conditions precedent contained in the NEXUS PA is the receipt of an Order or Approval from the MPSC by June 1, 2016, that approves DTE Gas’s utilization of the NEXUS transportation capacity and recovery of all DTE Gas’s costs and expenses related to that transportation service.3

With this in mind, DTE Gas is “requesting MPSC approval of the 75,000 Dth/d NEXUS

transportation capacity as part of its supply plan in this GCR proceeding”. 4 Tr 291.

As currently envisioned, the transportation arrangement with NEXUS will include

a monthly reservation charge of $0.695 per Dth per day of MDQ, plus 1.22% fuel, plus

$0.00 per Dth usage charge. 4 Tr 293. This results in an average monthly Reservation

cost of $1.6 million for 15 years from the NEXUS in-service date. 4 Tr 293.

At 4 Tr 291-92, to explain DTE Gas’ position, Mr. Lawshe stated:

The unique nature of the NEXUS transportation capacity and its importance for DTE Gas’s customers and the state of Michigan in general requires Commission support and approval at this time to make the benefits of the NEXUS pipeline and the transport capacity in the DTE Gas supply portfolio a reality. . . . [I]f the NEXUS pipeline gets built, and DTE Gas acquires 75 MDth/d of NEXUS capacity, then it would reduce the cost of gas to DTE Gas GCR customers by $575 million over the 15-year period November 2017 through March 2032 . . . . In light of these results, DTE Gas plans to start taking the necessary steps during the 2015-2016 GCR Plan Year to replace 75 MDth/d of existing transport with NEXUS capacity effective November 1, 2017. Commission approval of DTE Gas’s transportation arrangement with NEXUS Gas Transmission would benefit not only the customers of DTE Gas, but would also give the support needed for this greenfield pipeline project that will bring new shale gas resources to the state of Michigan with an estimated $2.4 billion reduction in natural gas costs for all Michigan consumers . . . .

At 4 Tr 288-89, Mr. Lawshe provided his opinion that:

The addition of NEXUS Gas Transmission to the DTE Gas

3 In its Business Update, dated December 9, 2015, at page 24, DTE Energy announced that the “DTE Gas system will be expanded to support the NEXUS interconnection” and added that there will be “$200 million of NEXUS related investment at DTE Gas through 2017”. A copy of this document is available at: http://phx.corporate-ir.net/phoenix.zhtml?c=68233&p=irol-SECText&TEXT=aHR0cDovL2FwaS50ZW5rd2l6YXJkLmNvbS9maWxpbmcueG1sP2lwYWdlPTEwNjE3NzQ5JkRTRVE9MCZTRVE9MCZTUURFU0M9U0VDVElPTl9FTlRJUkUmc3Vic2lkPTU3

U-17691 Page 10

transportation portfolio is expected to lower the cost of gas for DTE Gas customers and would increase both DTE Gas’ security of supply and diversity of supply. Diversity of supply is achieved by providing access to the Utica and Marcellus shale gas, thereby supplementing and expanding the diversity of the current portfolio of Mid-Continent, Gulf Coast, Canadian, and city-gate supplies. Security of supply is achieved by providing greater volumes of gas that can be delivered into the DTE Gas system from this new and burgeoning production region, thereby mitigating potential price run ups in the future similar to what occurred this past winter of 2013-14 at each of the major Midwest city-gate market locations, including DTE Gas. Shale gas is the largest and fastest growing source of natural gas supply in North America, and access to the Utica and Marcellus shale gas reserves will position DTE Gas with the ability to secure abundant, long term, cost effective natural gas supply to serve its customers well into the foreseeable future.

* * * [T]he NEXUS pipeline will potentially enhance the value of DTE Gas

storage and transportation assets for the benefits of its customers through incremental midstream revenues and consequently potentially lower distribution rates. NEXUS is also expected to bring lower price gas for all natural gas consumers in the state of Michigan . . . . The NEXUS pipeline will benefit the State of Michigan through increased tax revenues, and it is anticipated to create more jobs, bring economic development, provide supply for potential gas fired electric generation to meet market growth and replace aging coal fired plants with reduced pollution emissions. It is also expected to have a smaller environmental footprint than the other proposed greenfield pipeline traversing East Ohio to Michigan and points beyond.

The history of DTE Gas’ involvement with NEXUS goes back several years and its

beginning is less than clear.4 As for the agreement in question, Mr. Lawshe revealed that

“DTE Gas selected to bid on NEXUS in 2012, and continued from that point forward to

develop its supply portfolio with NEXUS in its plans.” 4 Tr 385. As a result of this decision,

DTE Gas did in fact submit a NEXUS Open Season bid in November 2012. 4 Tr 301.

Mr. Lawshe explained that at the time DTE Gas submitted a bid during the NEXUS Open

Season, NEXUS “was the only greenfield pipeline project . . . designed to transport . . .

4 While the record is silent, one might expect DTE Gas’ involvement with NEXUS to significantly predate NEXUS’ original open season because, as already noted, DTE Gas plans a $200 million expansion of its transportation capacity, which will then be leased to NEXUS at prices lower than the firm transportation rates for comparable service on the DTE Gas pipeline system.

U-17691 Page 11

Appalachian Basin gas . . . to customers in Michigan and the surrounding area” 4 Tr 302.

In December of 2013, DTE Gas Vice-President for Gas Sales and Supply, Mark

W. Stiers, signed an undated Precedent Agreement (PA) that went unsigned by DTE

Pipeline Company, Spectra Energy Transmission, LLC, and Enbridge Inc.; collectively

the contemplated co-owners of the NEXUS pipeline. See Exhibit ANR-23. With Mr. Stiers

signature, Mr. Lawshe testified that “we5 considered that a . . . binding commitment to the

[NEXUS] pipeline”. 4 Tr 395

Prior to signing the 2013 PA, DTE Gas performed no comparisons of alternatives

to NEXUS because, based on the criteria6 that it had developed, it considered none to be

available. 4 Tr 306, 421. Negotiations over the December PA took place between Mr.

Lawshe, on behalf of DTE Gas, and David Slater, on behalf of DTE Pipeline Company,

and extended over four months. 4 Tr 305. 4 Tr 358. Mr. Lawshe did not negotiate with

anyone from Enbridge or Spectra, the other companies that were then involved with

NEXUS. 4 Tr 358.

At 4 Tr 302-03, Mr. Lawshe provided his opinion that:

Supporting the NEXUS Pipeline as a greenfield project was desirable because the Company expected the project to reduce gas cost for GCR customers by providing access to one of the largest and fastest growing sources of supply in North America from a new single pipeline resource that would create additional competition with both the existing interstate transport providers and compete with existing and future supply sources feeding into those pipelines.

At some time between December 2013 and July 2014, Enbridge withdrew from the

NEXUS pipeline project and, on July 23, 2014, DTE Gas signed a second PA (July PA)

5 The record does not make clear who “we” is. 6 Mr. Lawshe states that DTE Gas’ criteria limited its consideration to a greenfield project delivering gas to the DTE Gas system from the Utica Marcellus basin, i.e. NEXUS. 4 Tr 386.

U-17691 Page 12

with DTE Pipeline Co and Spectra. 4 Tr 364. 4 Tr 289, 365-66. DTE Gas did not engage

in any additional meaningful negotiations prior to signing the July PA. 4 Tr 289, 365-66.

At no time between October 2012 and July 2014 did DTE Gas solicit ANR for the

transportation of additional gas to DTE Gas, knowing that ANR would have been

interested in doing so. 4 Tr 367-69. Eventually DTE Gas did, however, analyze the ANR

East7 and Rover8 projects based on the rates posted for the projects’ open seasons.

4 Tr 369-74. DTE Gas did not seek information regarding lower than posted rates nor

specific rates for 75,000 dth/day for 15 years. 4 Tr 373-74. When asked to explain why

DTE Gas had engaged in extensive negotiations with its affiliate for transportation on

NEXUS but didn’t do the same with regard to ANR East and Rover, Mr. Lawshe explained,

at 4 Tr 376-77:

First, our portfolio needs for long-term transportation at that point in time were filled with the NEXUS capacity9. The NEXUS capacity is a long-term project that takes a long time to develop over time. The rates that we negotiated with NEXUS were more structured around the type of rates, whether it was a fixed rate or there was a band of rates, or whether it was a

7 The ANR East project is now defunct. As explained by Mr. Bennett, at 5 Tr 779:

ANR East proposed to construct 240 miles of large diameter pipeline extending east of ANR’s existing system from Defiance, Ohio to points in eastern Ohio, including Leesville and Clarington. ANR East was designed to provide additional access to Utica and Marcellus shale gas, with delivery into the same Michigan and Ontario markets as NEXUS, as well as to other markets connected to ANR’s system. ANR East was designed to transport up to 2.0 Bcf/d of Appalachian supply from Clarington, Ohio to Leesville, Ohio and 2.4 Bcf from Leesville to ANR’s existing system at Defiance, Ohio. In its July 3, 2014 open season, ANR outlined several options, with indicative rates. . . . The options include a transportation path from either Leesville or Clarington to various points, including Willow Run, which serves DTE Gas . . . .

8At 5 Tr 780, Mr. Bennett explained that:

Rover consists of 237 miles of gathering pipeline in Ohio, Pennsylvania and West Virginia and a 374 mile duel 42 inch pipeline system from Cadiz, Ohio to Defiance and then another 100 miles of pipeline from Defiance to an interconnection with Vector. The project can deliver up to 3.25 Bcf/d from eastern to western Ohio along a similar route as ANR East.

9 DTE Gas’ claim that it was dedicated to NEXUS is rather specious and is based on its positon that its sole signature to the December PA; a PA that was never signed by the other three parties, one of which withdrew from the NEXUS project, was binding upon DTE Gas.

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variable rate subject to capital cost tracker. We settled with an agreeable level with NEXUS at that time.

As far as ANR East and Rover, they came in after the fact, and that we looked at our portfolio to see if there was any additional need for long-term commitment, at the rates that they had offered, and we didn't see any need at that time or any reason to try and swap out the -- our commitment to the NEXUS project.

In his testimony, Mr. Lawshe provided further justification for contracting with

NEXUS by citing to DTE Gas’ status as an “Anchor Shipper” on NEXUS with only a

15 year commitment, rather than 20 years, at a lower volume of 75 MDth/day, rather than

the 250 MDth/day that would have been required by ANR East. 4 Tr 290-91. Mr. Lawshe

stated DTE Gas’ position that acquiring “Anchor Shipper” status on NEXUS “was

desirable because it provided the . . . benefit of a guarantee . . . that the rate paid by DTE

Gas would be the lowest rate paid by any similarly situated shipper on NEXUS. 4 Tr 291.

ANR’s witness, Mr. Bennett, calls in to question whether DTE Gas actually has

status as an Anchor Shipper, as that requires a 150,000 Dth/d commitment and DTE Gas’

commitment is to only half that amount. 5 Tr 782-83. And, assuming DTE Gas has this

status, he downplays its significance, because “if ‘Anchor Shipper’ status were provided

to all shippers that subscribe to only 75,000 Dth/d or more on a 1.5 Bcf project, there likely

would not be many shippers that did not qualify for that status, which would dilute the

value of such status.” 5 Tr 783.

In rebuttal, Mr. Lawshe claims that DTE Gas obtained Anchor Shipper status

because the “150,000 Dth/day commitment could come from any combination of

corporate entities and DTE Gas committed to 75,000/d and another DTE corporate entity

took the remainder”. 4 Tr 315-16. However, in a discovery response, admitted into

evidence as Exh ANR-19, Mr. Lawshe generally disclaims knowledge of the other

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corporate entities’ dealings and stated:

[T]he testimony of Mr. John Wagner in the DTE Electric Company 2015 PSCR Plan case filed with the MPSC in Case No. U-17680 on September 30, 2014, states as follows: “DTE Electric has entered into a Precedent Agreement with NEXUS Gas Transmission to provide firm natural gas transportation for 8,500 DTH per day starting in Nov 2017 and increasing to 75,000 DTH per day starting on the later of May 2020 or when DTE Electric has added the required electric generating capacity and supporting infrastructure needed to utilize the increased volume requirement. In addition, DTE Electric has the ability to increase the amount of capacity from 75,000 DTH per day up to 150,000 DTH per day starting in May 2022." (MPSC Case No. U-17680: T 221-222).

Mr. Bennett cast doubt on many other of DTE Gas’ claims. For instance, at

5 Tr 781-82, he asserts that “it is not clear that DTE Gas would have a better ‘status’ on

NEXUS”, and explains:

In NEXUS’ first open season posting in 2012, NEXUS stated that a bidder in the open season can qualify as an “Anchor Shipper” by submitting a bid of 150 MDth/d or greater. See Exhibit ANR-2. Then, in a supplemental open season posted in July 2014, shortly after the ANR and Rover open seasons, NEXUS created another status of shipper. According to this notice, a bidder in the supplemental open season could qualify either as an “Anchor Shipper” with a bid of at least 150,000 Dth/d or as a “Foundation Shipper” by submitting a bid of at least 400,000 Dth/d. See Exhibit ANR-3.

Thus, Mr. Bennett concludes that “even if DTE Gas qualified as an Anchor Shipper,

other shippers could be entitled to either lower rates or other rate-related concessions.”

5 Tr 782.

To explain why DTE Gas did not participate in the ANR-East or Rover open

seasons, at 4 Tr 307, Mr. Lawshe testified that:

DTE Gas did not participate in either the Rover or ANR East Open Season projects primarily because: (1) a landed cost analysis showed that NEXUS was the least cost alternative compared to the rates offered by ANR and Rover in their open seasons; (2) DTE Gas had already committed to the NEXUS Pipeline at the time ANR East and Rover were conducting their open seasons; and (3) DTE Gas could not bid on Rover because it was a binding open season and DTE Gas had already committed to . . . NEXUS.

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Exhibit ANR-12 provides a timeline of projects designed to transport Appalachian

gas to the Midwest. Of the projects listed in Exhibit ANR-12, DTE Gas did not consider

any, including the following, as alternatives to NEXUS: ANR’s Lebanon Lateral through a

reversal of flow to ANR’s SE line to DTE Gas; Texas Eastern at Glen Karn to ANR’s SE

line to DTE Gas; REX at Shelbyville to ANR’s SE line to DTE Gas; Rover at Westrick to

ANR’s SE line to DTE Gas. Exh ANR-17. In Exhibit ANR-17, Mr. Lawshe justified DTE

Gas’ decision to not consider any of these alternative by stating:

DTE Gas did not consider transportation service from any of the routes as an alternative to NEXUS because each of the transportation paths were not available at the time DTE Gas selected the NEXUS transportation service. DTE Gas had already bid on the NEXUS Open Season and was well into negotiation of the Precedent Agreement with NEXUS by then.

However, at 4 Tr 386, Mr. Lawshe stated that “[t]hey were never considered an

alternative to NEXUS because they were not greenfield projects delivering gas to the DTE

Gas system from the Utica Marcellus basin.”

Mr. Bennett also presents evidence questioning the reasonableness of DTE Gas’

actions with alternative providers. At 5 Tr 785, he explains that:

Typically, pipelines will hold open seasons intended to generate interest in their projects. The pipeline will then open a dialogue with interested shippers to negotiate rates and rate-related terms and conditions that will satisfy the shippers’ needs. In a situation where there are several projects competing for the same business, each pipeline does its best to meet the competition. Conversely, shippers that desire capacity on one of several competing projects that can provide such capacity will attempt to negotiate the best price and other terms as it can.

Mr. Bennett explained that on July 9, 2014, “two of ANR’s marketing and business

development representatives met with DTE Gas at its offices and . . . reviewed the terms

of ANR’s recent open season announcement for the ANR East . . . . Although DTE Gas

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indicated at that meeting that it may submit a bid for capacity on the project, it never made

such a bid, nor did it show any interest in the project after that brief meeting.” 5 Tr 786.

Despite these overtures, “at no time did DTE Gas either ask ANR for an offer for 75,000

Dth/d for a 15 year term, or otherwise attempt to negotiate a rate for service on ANR East

or any other ANR alternative.” 5 Tr 786. At 5 Tr 786-77, Mr. Bennett added:

DTE Gas did not submit a request for proposals (“RFP”) or otherwise solicit bids for the transportation service it desired. In a discovery response, Mr. Lawshe states that DTE Gas did not because “at the time DTE Gas entered into discussions with NEXUS, there were no other pipelines proposing the same pipeline path as NEXUS.” Exhibit ANR-8. There are two problems with this explanation. First, NEXUS’ open season was in 2012. There was no need for DTE Gas to limit its discussions for service expected to commence five years later to one provider. Surely, had DTE Gas announced an RFP or otherwise solicited bids at any time during the next two years, providers such as ANR and Energy Transfer would have responded given their participation in these markets. Second, there was no need for DTE Gas to limit the service it requested to the specific path proposed by NEXUS. DTE Gas should have requested proposals to have Appalachian gas supply delivered to its city gates and chosen the most cost effective and reliable service option.

Throughout its presentation, DTE Gas makes the recurring assertion that its

support of NEXUS is needed to create new capacity. At 5 Tr 797-98, Mr. Bennett dispels

this assertion by establishing that:

DTE Gas’ 75,000 Dth/d is not necessary to support the construction of a new pipeline from the Appalachian Basin to Michigan. There exists sufficient support for the construction of either one or two of these pipeline projects without DTE Gas’ 75,000 Dth contract.

* * * Both Rover and NEXUS have reported substantial subscriptions for

the capacity of their projects. . . . . In its certificate application, Rover reported having executed precedent agreements for 3.1 Bcf/d of its proposed 3.25 Bcf/d project. . . . In its pre-filing letter, NEXUS states that it has signed precedent agreements for the majority of the 1.5 Bcf/d of capacity to be created by the project. Thus, including DTE Gas’ precedent agreement, shippers have signed up for 750,000 Dth/d or more of NEXUS capacity. . . . [T]hat means that shippers have supported . . . 3,850,000 Mcf/d of new capacity from the Appalachian Basin, of which 75,000 Dth/d

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or less than 2 percent of that support, is represented by DTE Gas’ contract. With shipper demand for over 3.75 Bcf/d without DTE Gas’ contract, DTE Gas’ participation is not needed to support any of these projects.

DTE Gas presented Exhibit A-30, a copy of a report prepared by ICF Resources,

L.L.C. that was submitted to Mr. Lawshe and is dated December 15, 2014. Exh A-30,

p. 1. As explained in the report, titled “The Value of Nexus Pipeline Capacity to DTE Gas

Customers” (Report), “ICF was engaged by DTE Gas Distribution (DTE Gas) to assess

the value to DTE Gas customers of holding capacity on the proposed NEXUS Gas

Transmission Project (NEXUS) from the Marcellus/Utica gas producing basins in eastern

Ohio/Western Pennsylvania to the DTE citygate in Michigan.” Exh A-30, p. 8. DTE Gas

witness, Mr. Sloan, testified to sponsor the Report.

Mr. Sloan, estimated that addition of the NEXUS pipeline will, over a fifteen year

period, save DTE Gas customers approximately $318 million in natural gas costs.

5 Tr 603-04. This savings is based solely on a reduction of natural gas prices and does

not account for changes in supply portfolio or pipeline capacity portfolio. 5 Tr 604. Mr.

Sloan further estimates that if NEXUS is the only pipeline built, “holding capacity on

NEXUS will allow DTE Gas to reduce its gas supply portfolio costs by about $257 million

during the 15 year contract period from November 23 2017 through October 2032.”

5 Tr 605. However, with the addition of Rover to the equation his estimated savings drop

to $39 million over 15 years. 5 Tr 606. Mr. Sloan projects that the total cost of holding

75,000 Dth/d of capacity on Rover will “exceed NEXUS by an average of about

$3.9 million per year as Rover demand charges and usage costs are higher than NEXUS.”

5 Tr 613-14.

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To calculate the cost of NEXUS, Mr. Sloan relied, in part, on a 1.22% fuel use

estimate provided to him by DTE Gas. During cross-examination, Mr. Sloan

acknowledged that he had not seen any of the studies that produced that estimate and

that it was based on outdated pipeline specifications. 5 Tr 636-41. During additional

cross-examination, Mr. Sloan acknowledged that his opinions regarding the increase in

liquidity that NEXUS may create was based on incorrect capacity information for the

Rover pipeline. 5 Tr 665-66.

At 5 Tr 787-95, Mr. Bennett critiques and seriously puts in question the accuracy

of Mr. Sloan’s NEXUS cost comparison. In his testimony, Mr. Bennet is critical of Mr.

Sloan’s failure to base his analysis on the prices that DTE Gas could have obtained

(5 Tr 787), the inaccuracy of the estimated fuel costs (5 Tr 787), the failure of DTE Gas

to identify and evaluate alternatives to NEXUS (5 Tr 788), the use of maximum recourse

rates in cost comparisons (5 Tr 788), the use of estimated fuel costs (5 Tr 791), and his

use of outdated design parameters for NEXUS (5 Tr 792).

It is Mr. Bennett’s opinion that “there is no reason for DTE Gas and its customers

to pay the high cost of NEXUS capacity when less costly alternatives on existing capacity

exist.”10 5 Tr 798.

10 At 5 Tr 798, Mr. Bennett explains alternatives including: Dominion Gas Transmission, Inc. (“Dominion”), Texas Eastern Transmission, L.P. (“TETCo”), Rockies Express Pipeline, 17 LLC (“REX”) and the Rover project pending before FERC for approval. Exhibit ANR-12 provides a table showing various open seasons for capacity on alternative pipelines.

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b. Positions of the Parties

i. DTE

“DTE Gas is requesting Commission review and approval for 75 MDth/day of

existing transportation capacity being replaced by 75 MDth/day of NEXUS pipeline

transportation capacity beginning in 2017”. DTE Gas Br, p. 55. It is DTE Gas’ position

that “the unique nature of the NEXUS transportation capacity and its importance for DTE

Gas’s customers and the state of Michigan in general requires Commission support and

approval at this time to make the benefits of the NEXUS pipeline and the transport

capacity in the DTE Gas supply portfolio a reality”. DTE Gas Br, p. 66.

DTE Gas argues that it “presented evidence sufficient to warrant Commission

approval of the NEXUS transportation capacity.” DTE Gas Br, p. 67. It is DTE Gas’

position that it is “long-standing law” that Const 1963, Art 6, § 2811 only requires that

Commission’s findings to ‘be supported by competent, material and substantial evidence

on the whole record.’” DTE Gas Rep Br, p. 19. “Thus”, DTE Gas argues, “the applicable

standard of proof for purposes of determining whether the Company’s proposals . . . are

reasonable and prudent is the ‘substantial evidence’ standard, which is a lighter standard

than even the ‘preponderance of the evidence’ standard”. DTE Gas Rep Br, p. 19.

11 Article VI, section 28, of the Michigan Constitution reads as follows:

All final decisions, findings, rulings and orders of any administrative officer or agency existing under the constitution or by law, which are judicial or quasi-judicial and affect private rights or licenses, shall be subject to direct review by the courts as provided by law. This review shall include, as a minimum, the determination whether such final decisions, findings, rulings and orders are authorized by law; and, in cases in which a hearing is required, whether the same are supported by competent, material and substantial evidence on the whole record. Findings of fact in workmen's compensation proceedings shall be conclusive in the absence of fraud unless otherwise provided by law.

In the absence of fraud, error of law or the adoption of wrong principles, no appeal may be taken to any court from any final agency provided for the administration of property tax laws from any decision relating to valuation or allocation.

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ii. Staff

Staff opposes DTE Gas’ plan to purchase transportation capacity from NEXUS.

Staff Br, p. 13. Staff considers DTE Gas’ request for approval of this arrangement to be

“premature” and “not adequately support[ed]”. Staff Br, p. 13. At Staff Br, p. 14-15, Staff

explains that:

DTE Gas’s agreement for NEXUS pipeline capacity should be reviewed together with DTE Electric’s agreement for capacity. A transaction between two or more affiliated entities deserves heightened scrutiny. See In re Application of Consumers Energy Co, MPSC Case No. U-11636, 11/16/1999 Opinion & Order, p 14 (quoting Staff’s argument, which the Commission adopted later in the order, that “the terms of a non-arm’s length transaction between two affiliates should not be accepted at face value and merits careful scrutiny.”). Even though the parties’ negotiations were memorialized in two separate agreements in this case, the documents should nonetheless be reviewed together. Without more information about DTE Electric’s agreement with the NEXUS pipeline, Staff and the other parties only see half the picture.

Staff has an obligation to review affiliated transactions with due diligence, which at a minimum requires reviewing all of the agreements at issue. Because DTE Electric’s agreement with the NEXUS pipeline was not included in the record in this case, and scant additional information was provided, Staff cannot support DTE Gas’s agreement with NEXUS at this time.

In response, DTE Gas argues that DTE Electric’s precedent agreement “is not

relevant” in this GCR Plan case. DTE Gas Rep Br, p. 3. DTE Gas considers Staff’s

reliance on Case No. U-11636 unsound because “there is no affiliate transaction between

DTE Gas and DTE Electric”. DTE Gas Rep Br, p. 4. Further, DTE Gas argues that the

Commission never adopted a “heightened scrutiny” standard in Case No U-11636. DTE

Gas Rep Br, p. 5. DTE Gas considers Staff’s position “uninformed” and that Staff is

“unnecessarily creating hurdles for itself from performing its duties in this GCR Plan case.”

DTE Gas Rep Br, p. 6. After alleging Staff’s possession of the DTE Electric precedent

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agreement, DTE Gas complains that “the requisite constitutional equal protection of the

law requires dismissal of Staff’s argument". DTE Gas Rep Br, p. 7-8.

iii. ANR

ANR urges the Commission to closely examine the NEXUS arrangements and,

generally, argues that DTE Gas has chosen to enter into an affiliated transaction for

service on NEXUS while not seriously considering less costly alternatives. ANR Br,

p. 3.12 See ANR Br, p. 6-19.

More specifically, ANR notes that, for ANR East and Rover projects, DTE Gas “did

not submit bids in their open seasons, [did not] request rate offers for capacity . . ., [and

12 At ANR Br, p 3, ANR states:

The MPSC has stated “the dealings of a public utility with an unregulated affiliate warrant a more searching level of scrutiny and impose a commensurately greater burden on the party seeking to demonstrate the fairness of affiliate dealings.”1 In Midland Cogeneration Venture Ltd. Partnership v Public Service Commission, the Court of Appeals of Michigan stated “it is well recognized that expenses incurred in transactions between utilities and their affiliates deserve special scrutiny, given the potential lack of arms-length bargaining and improper subsidization of the affiliate’s unregulated operations through the utility’s rates. 2 The Court further found, “[t]he PSC need not assume [] that the fees charged to a utility by its affiliate are fair, and the utility has the burden of proving the reasonableness of its transaction with its affiliates. __________________________ _____

1 In re Michigan Consolidated Gas Co., MPSC Case No. U-10982-R (April 12, 1999) (emphasis added) (MPSC disallowing a portion of the fees paid to the affiliate for debt collection services). See also In re Michigan Consolidated Gas Co., MPSC Case No. U-9902 at 24 (June 12, 1992) (stating “the Commission normally views utility/affiliate transactions with a heightened degree of scrutiny.”).

2 Midland Cogeneration Venture Ltd Partnership v Public Service Comm’n, 199 Mich. App. 286, 313- 314; 501 N.W.2d 573 (1993) (internal citations omitted; emphasis added); see also, id. at 314 (“Furthermore, although the transfer [utility moved collection services to its sister subsidiary] was a managerial decision made by Consumers, which the PSC may not control directly, the PSC clearly possesses the authority to deny Consumers recovery through its rates of any increased expenses incurred as the result of Consumers’ unsound or nonecono mic business choices.”). See also In re Michigan Consolidated Gas Co., MPSC Case No. U-15451-R (October 14, 2010) at 11 (“[T]he Commission finds that MichCon must book the costs at the city-gate monthly index price for all affiliate purchases going forward from this order… Finally, the Commission acknowledges the concern regarding affiliate purchases and the lack of evidence justifying the choice of an affiliate over a competitor. Thus, the Commission directs MichCon to provide the Staff with information regarding the company’s selection of an affiliate for each purchase of gas supply.”).

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did not] otherwise engage in any negotiations with either project sponsor.” ANR Br, p. 7.

ANR argues that, because DTE Gas’ Mr. Lawshe “erroneously believed DTE Gas was

already committed to NEXUS”, DTE Gas “never seriously considered either [ANR East or

Rover as] an option to NEXUS.” ANR Br, p. 7. Further, ANR argues, “it is clear that the

cost analysis performed by Mr. Lawshe and subsequently ‘confirmed’ by DTE Gas’

consultant Michael D. Sloan, was not intended to inform DTE Gas’ selection of the lowest

cost provider, but rather to justify the decision already made to support its parent-

sponsored project.” ANR Br, p. 7. At ANR Br, p. 7-8, ANR adds:

A review of DTE Gas’ negotiations and execution of precedent agreements with NEXUS reveals that DTE Gas never considered any alternative other than its parent-sponsored project. In October 2012, NEXUS announced its open season. 4 Tr. 300. In November 2012, DTE Gas submitted a bid for 75,000 Dth/d on NEXUS. 4 Tr. 301. In December 2012, ANR’s then Vice President of Marketing, Dean Patry, informed DTE Gas’ then Vice President of Gas Supply, Mark Stiers, that ANR believed it could provide a better alternative to NEXUS for accessing Appalachian supplies at a fraction of the cost of NEXUS, and asking for a chance to compete against NEXUS. 5 Tr. 785; Exhibit ANR-5.

In December 2013, DTE Gas signed a precedent agreement with NEXUS, which at the time was comprised of its affiliate DTE Pipeline Company, Spectra and Enbridge. 4 Tr. 356-58; Exhibit ANR-15. None of the three NEXUS co-owners, however, signed this precedent agreement. Id. Thereafter, Enbridge dropped out of the project. 4 Tr. 364; Exhibit ANR 15. In July 2014, ANR East and Rover announced their open seasons. In early July, DTE Gas met with representatives of ANR and Rover to discuss their respective projects. 4 Tr. 309. DTE Gas did not submit bids for capacity on either of these projects or ask for a rate quote for 75,000 Dth/d for service on these projects, or otherwise attempt to negotiate rates for service on these projects. 4 Tr. 373-74; 377. On July 23, 2014, DTE Gas executed a second precedent agreement which this time was signed by the remaining two owners. 4 Tr. 289-90; 365.

In this case, much is made of the, never executed, December 2013 PA. ANR

argues that it was not a binding agreement because it went unsigned by all three of the,

then, pipeline owners and because, absent those signatures, DTE Gas presented no

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evidence “indicating the existence of mutual assent.” ANR Br, p. 9. ANR argues that,

none-the-less, DTE Gas “acted as if it was committed to NEXUS under that agreement.”

ANR Br, p. 9. “Thus”, ANR argues, “when DTE Gas met with ANR East and Rover in July

2014 to discuss their respective projects, it could not have intended to even consider

these projects viable options. ANR Br, p. 9-10. ANR considers the “only reasonable

explanation for DTE Gas meeting with ANR East and [Rover] in July 2014 is that DTE

Gas sought to establish evidence, presumably to obtain the approval sought herein, that

other alternatives were considered”. ANR Br, p. 10.

Next, ANR critiques DTE Gas’ cost analysis of the alternative projects. See ANR

Br, p. 10-16. ANR considers DTE Gas’ cost studies to be flawed in several respects.

ANR Br, p. 10. “Most importantly, the studies are meaningless because they compare

the reservation rates DTE negotiated with NEXUS with rates publicly posted by ANR East

and Rover without any negotiation.”13 ANR Br, p. 11.

“Moreover”, ANR argues, “DTE Gas has not shown that NEXUS was less costly.”

ANR Br, p. 12. “After four months of protracted negotiations, DTE Gas agreed to a

reservation rate of $0.695 per Dth/d. [However, as shown in Exhibit A-34], the posted

reservation rate for the ANR East option with the receipt point in Leesville, Ohio is $0.68

per Dth/d.” ANR Br, p. 12. Further, ANR argues that DTE Gas’ estimates of the relative

13 ANR argues that any suggestions by DTE Gas that ANR East nor Rover were unwilling to offer rates lower than those posted in their open seasons is not believable because it is typical, in the industry, to use the open season as a prelude to further negotiations over the terms of any transportation agreement. Further, ANR argues, at ANR Br, p. 12:

[I]t is simply not credible that DTE Gas believed that neither ANR nor Rover would negotiate the rates posted in their open seasons. Indeed, the record demonstrates that ANR in fact offered at least one shipper a significantly lower rate than the rate posted in its open season for service to the same Willow Run delivery point that serves DTE Gas. 5 Tr. 789; Exhibit ANR-9. DTE Gas’ failure to negotiate rates with either ANR East or Rover was imprudent, and renders its cost comparisons meaningless.

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costs of the ANR East and Rover alternatives “rests solely on its forecast that fuel costs”

and adds, at ANR Br, p. 13-14, that:

[I]n all of DTE Gas’ analyses, the cost of fuel for ANR East and Rover is projected to be almost double that of NEXUS. Mr. Sloan’s fuel cost estimates (which were also used by Mr. Lawshe) are far too unreliable to conclude that NEXUS will be less costly than either ANR East or Rover. As Mr. Bennett stated, the level of fuels costs that will be incurred by these projects are not sufficiently known at this stage of the projects and are therefore not reliable. 5 Tr. 791-95. He explained that these estimates are determined by projected fuel use times the price of gas over the 15 year term of DTE Gas’ contract. Neither of these inputs can be projected with sufficient reliability to conclude that fuels costs on NEXUS will be less expensive . . . .

ANR adds, at ANR Br, p. 16:

[E]ven ignoring DTE Gas’ misleading comparison of the reservation charges it negotiated with NEXUS to the non-negotiated posted rates of ANR East and Rover, the reservation charges, which are known fixed payments over the course of the 15 year term of the contract, are less for ANR East and Rover than for NEXUS. In contrast, DTE Gas’ fuel estimates for the three projects, which form the sole basis for its conclusion that NEXUS is less costly, are based on extremely unreliable projections over a 15 year period.

ANR continues by attacking DTE Gas’s assertions regarding the value of NEXUS

to natural gas customers in Michigan and DTE Gas’s status as an Anchor Shipper. As

for NEXUS’ versus Rover’s value to Michigan natural gas consumers, ANR argues, at

ANR Br, p. 17, that:

Mr. Bennett pointed out that the percentage of gas shipped to Michigan versus other destinations is irrelevant and either of the projects will be sized to meet whatever demand to Michigan and DTE Gas’ service territory exists. 5 Tr. 781. In addition, Mr. Sloan’s assertion as to the amount of capacity that Rover will build into Michigan is wrong. The correct amount is 1.3 Bcf, not 1.05 Bcf. 5 Tr. 666 (correcting 4 Tr. 621); Exhibit ANR-23. Thus, even if it made a difference, Rover will build 1.3 Bcf into Michigan, while NEXUS hopes to build 1.5 Bcf into Michigan. More importantly, 95% of Rover’s capacity is subscribed, while only a “majority” of NEXUS’ capacity is subscribed. Mr. Sloan acknowledged that it is more likely than not that Rover will be built, but less likely that NEXUS will be built.

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5 Tr. 664, 669-70.

As for DTE Gas’ “Anchor Shipper” status, ANR argues, at ANR Br, p. 17-18, that:

Although DTE Gas’ precedent agreement with NEXUS states that DTE Gas has anchor status, such status is based on the aggregation of DTE Gas’ 75,000 Dth/d with the contract of another affiliate, DTE Electric, for 75,000 Dth/d to reach the required 150,000 Dth/d to qualify for such status. But the terms of DTE Electric’s contract indicates that the capacity will be 75,000 Dth/d only if it adds electric generation that needs additional pipeline capacity, which may not happen. 4 Tr. 410-18.16 Second, even if DTE Gas were granted Anchor Shipper status, it does not guarantee DTE Gas a lower rate. NEXUS has granted a higher “Foundation Shipper” status to shippers that contract for 400,000 Dth/d and thus these shippers would obtain a lower rate than DTE Gas. 5 Tr. 782. There is also no evidence of any shippers on NEXUS contracting for less than 150,000 Dth/d. If all shippers qualify for “Anchor Shipper” status or the higher “Foundation Shipper” status, DTE Gas would have the same or higher rate than every other shipper. 4 Tr. 419-20. At the end of the day, the rate paid by shippers on NEXUS or any other project is negotiable, subject to the regulatory requirement that similarly situated shippers be treated without undue discrimination._______________________________________________

16 The recitation in DTE Gas’ precedent agreement that DTE Gas is entitled to Anchor Shipper status is subject to challenge at FERC because DTE Gas has not in fact met the eligibility criteria for such status. Saying so does not make it so, particularly in light of the fact that DTE Gas is an affiliate of NEXUS.

Next, relying upon the rate negotiated by Union Gas Ltd, ANR argues that the

record does not demonstrate that DTE Gas negotiated a lower rate than other Anchor

Shippers.14 ANR Br, p. 18.

14 On this point, at ANR Br, p. 18, ANR argues:

Attached as Exhibit ANR-4 are pertinent excerpts from Union Gas Limited’s (“Union Gas”) application to the Ontario Energy Board for approval of its precedent agreement with NEXUS for 150,000 Dth/d. Union Gas stated it has negotiated a reservation rate of $0.635 per Dth/d for the portion of its service from Kensington to Willow Run. The reservation rate in the DTE Gas contract for the same exact path is $0.695 per Dth/d. 5 Tr. 784. While Mr. Lawshe speculated that the terms of the two contracts may be different, he acknowledged that he had not compared the two contracts and the only difference he is aware of is that the Union Gas contract has a capital cost tracker that could result in the rate being +/- 15% of the $.0635 if that estimate turns out to be incorrect.

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Turning from the greenfield projects, ANR argues that DTE Gas failed to consider

other avenues to access Appalachian gas. See ANR Br, p. 19-26. ANR argues that

“market dynamics suggest that DTE Gas could have accessed Appalachian gas supply

at a transportation cost of $0.20 per Dth/d, plus fuel, rather than the $0.695, plus fuel, that

it agreed to pay NEXUS”; saving DTE Gas “$13.5 million per year or over $200 million

over the 15 year term it seeks.” ANR Br, p. 21.

In addition, ANR argues that use of the existing ANR system would have provided

DTE Gas greater security of supply by allowing DTE Gas to acquire gas from the

Appalachian Basin, Arkansas, Texas, Louisiana, North Dakota, Canada, the Anadarko

Basin, and the Gulf of Mexico. ANR Br, p. 22-23. As ANR sees it, the ANR system

“provides greater protection from facility outages” because NEXUS is a single pipeline

with one point of delivery, whereas, ANR provides several alternatives for delivery.

ANR Br, p. 23.

ANR argues that “DTE Gas does not dispute that these options were good

alternatives to NEXUS”, but rather, did not consider these alternatives because of its

“mistaken belief . . . that DTE Gas was committed to NEXUS by virtue of the December

2013 precedent agreement that only it signed.” ANR Br, p. 24. At ANR Br, p. 24-25,

ANR points out that:

[T]he record shows that all of these alternatives were available prior to July 2014 when DTE Gas entered into a binding fully-executed precedent agreement with NEXUS. Exhibit ANR-12; 4 Tr. 390. Indeed, both the Lebanon Lateral and Glen Karn open seasons were held prior to December 2013 when DTE Gas signed the first precedent agreement . . . . 4 Tr. 800; Exhibit ANR-12. . . .

In fact, DTE Gas submitted a bid for capacity on the Lebanon Lateral15 project in October 2013 before it signed the agreement that it now

15 As stated by ANR, the Lebanon Lateral was developed to provide a new export option for Marcellus and Utica gas reserves. ANR Br, p. 25.

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asserts committed it to NEXUS. . . . After equivocating, Mr. Lawshe agreed that by bidding for capacity

on this project, DTE Gas would be able to access Appalachian gas supply. 4 Tr. 403-04. In October 2013, DTE Gas submitted a . . . non-confirming16 bid . . . and DTE Gas’ bid was rejected. Id. Mr. Lawshe stated that DTE Gas bid only three years to meet its short-term objectives. 4 Tr. 408. At the time of its three-year bid for capacity on this ANR project, . . . DTE Gas was moving forward with NEXUS as part of its long-term portfolio and that had DTE Gas’ three-year bid been accepted, service on ANR’s project would have expired around the same time NEXUS was planned to begin service. 4 Tr. 408-09.

The clear import of this bid is that DTE Gas had already decided, or was directed, to support its parent-sponsored project scheduled to be in-service in November 2017. As a result, DTE Gas bid only three years for the ANR capacity as a bridge to the NEXUS capacity. Had DTE Gas bid ten years, or the fifteen years that it agreed to pay NEXUS, DTE Gas would have obtained access to Appalachian gas supply at a much lower cost than NEXUS. Simply characterizing ANR’s project as meeting its short-term objectives while characterizing NEXUS as part of its long-term portfolio does not change the fact that the “reasonable and prudent” course of action for DTE Gas would have been to bid on the lower cost ANR project for ten or fifteen years.

Lastly, ANR challenges DTE Gas’ assertions regarding savings to be made by

utilizing NEXUS. See ANR Br, p. 26-30. “As a threshold matter” ANR argues, “the

savings that Mr. Sloan projects is only valid to the extent the market assumptions the

model utilizes to project gas demand, gas supply and pipeline infrastructure for the next

15 years are accurate. . . . [P]rojecting gas prices over a 15 year period is extremely

uncertain and unreliable.” ANR Br, p. 27. Regardless, ANR argues that DTE Gas could

achieve these savings by obtaining Appalachian gas through the alternatives discussed

above. ANR argues that this is because “more than half of these savings are based on

the construction of 1.5 Bcf of capacity from the Appalachian Basin to Michigan regardless

of whether DTE Gas contracts with NEXUS or for that matter whether NEXUS is ever

16 DTE Gas’ bid was considered non-conforming because it was for only 3 years of service; well below the minimum number of years being offered.

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built.” ANR Br, p. 27. ANR argues that the other half of the savings “result from an ability

to purchase lower cost Marcellus or Utica shale gas from the Appalachian Basin, which

DTE Gas could achieve by contracting for transportation service on any of the alternatives

discussed above that access such supplies”. ANR Br, p. 27.

At ANR Br, p. 30-31, ANR concludes:

The evidence compiled in the record overwhelmingly demonstrates that there were, and continue to be, less costly options than NEXUS for DTE Gas to access Appalachian gas supplies and reduce its gas costs. DTE Gas has not met its high burden of demonstrating that its proposed contract with its parent-sponsored project is reasonable and prudent and minimizes its costs in light of these alternatives. DTE Gas’ request for approval of its contract with NEXUS, as well as it request for pre-approval of the costs of NEXUS, therefore, should be denied. ANR respectfully requests that DTE Gas be required to engage in an open and transparent competitive process for fulfilling its transportation service needs.17

iv. DTE Gas’ Response to ANR

DTE Gas argues that “the evidentiary record shows that DTE Gas undertook a

lengthy and detailed decision making process . . . before reaching the conclusion that

NEXUS was the best option to meet DTE Gas’s requirements for obtaining Utica and

Marcellus gas.” DTE Gas Rep Br, p. 21. At DTE Gas Rep Br, p. 25-26, DTE Gas argues

that:

Although DTE Gas had already committed to the NEXUS Pipeline in December 2013, DTE Gas nevertheless engaged in meaningful discussions with representatives for both the Rover and ANR East projects on July 2, 2014, and July 9, 2014, respectively . . . . In both instances, DTE Gas was advised by representatives for ANR East and Rover to use . . . rates contained in their Open Season to perform a landed cost analysis (4T 307-309). . . . The results of DTE Gas’s July 2014 landed cost analysis showing that NEXUS was projected to provide the lowest landed cost among all

17 DTE Gas considers it “unlawful” to require it “to engage in an open and transparent competitive process for fulfilling its transportation service needs”. DTE Gas Rep Br, p. 16. It is DTE Gas’ position that “determining when DTE Gas will conduct a new competitive bidding process is a management decision, which falls outside the Commission’s statutorily limited purview of ratemaking.” DTE Gas Rep Br, p. 17.

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transport sources . . . were re-affirmed by DTE Gas’s updated landed cost analysis in December 2014 (Exhibit A-35), which examined 14 different transport routes and sources of supply . . . .

. . . In summary, the chronological history of DTE Gas’s decision to contract for transport capacity on NEXUS shows that ever since 2012, DTE Gas has . . . expressed, . . . through its GCR Plan Case filings and elsewhere, its interest in acquiring long-term transportation and supply from the Appalachian Basin, and that it was assessing the merits of the NEXUS Pipeline against other available alternatives . . . . DTE Gas did not prevent any interstate transportation service provider from competing with the services offered by NEXUS Pipeline in its open season in 2012. It was not until . . . July 2014 that ANR and Energy Transfer Partners . . . offered . . . transportation services on ANR East and Rover, respectively. However, DTE Gas had already entered into a precedent agreement in December 2013 for transport capacity on NEXUS. Nevertheless, DTE Gas confirmed its earlier assessment of the merits of the NEXUS Pipeline against these other alternatives and concluded that its original decision to remain with NEXUS was reasonable and prudent. DTE Gas has performed the requisite due diligence and the existence of arms-length good faith negotiations, which support Commission approval of the NEXUS Pipeline in its transportation portfolio.

DTE Gas considers ANR’s cost analysis argument “meritless because when DTE

Gas committed to NEXUS in December 2013 there were no alternative interstate

pipelines that met the DTE Gas’s criteria for its long-term interstate transportation

objectives.” DTE Gas Rep Br, p. 30.

DTE provides a general criticism of ANR’s position by arguing that “DTE Gas’s

decision in December 2013 to commit to transporting capacity on NEXUS must be

evaluated in light of the facts known to DTE Gas at such time. However, many of ANR’s

criticisms are based on recent facts that were non-existent in December 2013”. DTE Gas

Rep Br, p. 30. Additionally, DTE Gas considers any arguments comparing NEXUS to

ANR East to be moot, because the ANR East project is not being pursued at this time.

DTE Gas Rep Br, p. 30-31. DTE Gas rebukes ANR’s claims that DTE Gas didn’t engage

in meaningful negotiation with ANR by arguing that in 2013, ANR East was not an

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alternative, that, when it became available, it was six months past the date that DTE Gas

had committed to NEXUS, and that, even so, DTE Gas considered the ANR East project

and “concluded it was not feasible for DTE Gas to bid on this potential capacity”. DTE

Gas Rep Br, p. 32-33.

With regard to ANR’s Anchor Shipper status, DTE Gas argues, at DTE Gas Rep

Br, p. 33, that:

ANR may bluster that DTE Gas’s “Anchor Shipper” status is subject to challenge at the Federal Energy Regulatory Commission (“FERC”), but Michigan law would continue to give the recital regarding DTE Gas’s “Anchor Shipper” status legal effect through the doctrine of estoppel in Commission proceedings. Otherwise, ANR is engaging in pure conjecture or speculation as to any FERC review of DTE Gas’s “Anchor Shipper” status, which is a prohibited basis for a Commission order.

DTE Gas criticizes ANR’s comparison of DTE Gas’ agreement with that of one

made by Union Gas Ltd, by arguing that Union Gas’ agreement has an adjustable rate

while DTE Gas’ rate is fixed. Thus, DTE Gas considers this an “apples-to-oranges

comparison”. DTE Gas Rep Br, p. 34.

As for ANR’s criticism that DTE Gas failed to consider existing alternatives, DTE

Gas states they are meritless because they fail to account for cost savings attributable to

a new greenfield pipeline running directly from the Appalachian fields to the Kensington

receipt point. DTE Gas Rep Br, p. 34-36.

In sum, DTE Gas indicates, at DTE Gas Rep Br, p. 37, that:

Although NEXUS increases the demand charges paid by DTE Gas in the first few years, it is expected to generate significant cost savings and benefits to DTE Gas and Michigan natural gas customers in general in both the long-run and the short-run that more than offset the increase in demand charges.

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v. Attorney General

The Attorney General argues that the Commission lacks authority to approve DTE

Gas’ agreement to purchase capacity on NEXUS. AG Br, p. 27-32.

First, at AG Br, p 28-29, relying on Eikhoff v Detroit Charter Comm’n, 176 Mich

535, 540; 142 NW 746 (1913), Stowers v Wolodzko, 386 Mich 119, 133; 191 NW2d 355

(1971), and Jennings v Southwood, 446 Mich 125, 142; 521 NW2d 230 (1994), the

Attorney General argues:

MCL 460.6h(7) is very specific. It states that the commission may indicate any cost items in the 5-year forecast that on the basis of present evidence, the commission would be unlikely to permit the gas utility to recover from its customers in rates, rate schedules, or gas cost recovery factors established in the future. This language belies any legislative intent to empower the Commission to approve or reject cost items in a 5-year forecast even though subsection (7) authorizes—but does not require—the Commission to issue warnings. Even though DTE Gas Company’s application and supporting testimony has requested the Commission to approve its proposal to replace 75 Mdth/d of existing transportation capacity by 75 Mdth/d of NEXUS pipeline capacity beginning in 2017, the specificity of the language in MCL 460.6h(7) belies any legislative intent to empower the Commission to approve cost items in a 5-year forecast. The point is that MCL 460.6h(7) does not empower the Commission to approve decisions underlying a proposed gas transportation contract even when it may affect GCR expenses during the last 4 years of a 5-year forecast.

To support this argument, DTE Gas cites to In re Detroit Edison Co Applications,

296 Mich App 101; 817 NW2d 630 (2012) for the proposition that because “MCL

460.6h(6) mandates approval, disapproval, or amendment of a gas cost recovery plan

and approval, rejection, or amendment of the 12 monthly gas cost recovery factors

requested by the utility in its gas cost recovery plan and since MCL 460.6h(7) contains

no similar language, the Commission is not authorized to grant DTE Gas Company’s

request to approve [the Nexus contract].” AG Br, p. 31.

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Next, the Attorney General argues that assuming the Commission possesses

authority to approve the agreement, the evidence “does not show that DTE Gas

Company’s proposal is reasonable and prudent and will minimize future GCR expenses.”

AG Br, p. 32. In addition, with reference to the Commission’s Code of Conduct and the

Affiliate Transaction Guidelines, the Attorney General argues that, “though NEXUS is

partially owned by one of DTE Gas Company’s unregulated affiliates, DTE Gas Company

has offered no evidence to show its projected expenses related to the transaction do not

exceed an amount equal to the lower of a reasonable market price or the affiliate’s actual

expenses”.18 AG Br, p. 33. “Therefore”, the Attorney General argues, “the Commission

should at best refuse to make a decision based upon the evidence presented in this case”.

AG Br, p. 33.

The Attorney General continues by questioning DTE Gas’ purported NEXUS

related cost savings and, at AG Br, p. 36-37, argues:

The Commission . . . should compare the duration and the level of variable cost savings projected by the Company with the Company’s acknowledgment that the NEXUS contract binds DTE Gas to pay a new $24 million for reservation costs over the 15 years with no assurance that future variable cost projections will actually exceed the fixed costs. There are too many uncertainties to approve the contract and cost recovery at this time (5 T 848-849). DTE Gas Company has not agreed to assume the risks inherent in the projected savings presented by the Company. As Mr. Lawshe testified:

One of the conditions precedent contained in the NEXUS PA is the receipt of an Order or Approval from the MPSC by June 1, 2016, that approves DTE Gas’s utilization of the NEXUS transportation capacity and recovery of all DTE

18 At DTE Gas Rep Br, p. 38, DTE Gas rejects this position by arguing:

[T]he AG’s assertion is nowhere found in the Code of Conduct, . . . . In fact, the Code of Conduct also provides for affiliate transactions being at market price. The evidentiary record shows that DTE Gas’s PA contains a “Most Favored Nations” provision, which essentially guarantees that DTE Gas will never pay a higher rate than similarly situated customers (Exhibit ANR-15, p. 7). Therefore, the AG’s assertion is factually deficient . . ., thereby requiring its rejection.

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Gas’s costs and expenses related to that transportation service. Requesting Commission approval of the NEXUS transportation capacity in this GCR Plan case filing provides sufficient time to receive such approval by the target date of June 1, 2016, as well as the overall timeline for NEXUS to achieve the pipeline in-service target date of November 1, 2017. This testimony demonstrates that neither DTE Gas nor NEXUS is

willing to take the risk and construct the pipeline in the absence of an assurance from the MPSC that they will recover the projected fixed costs from the retail customers of DTE Gas plus whatever the future variable costs may be. This circumstance belies the credibility of the projections presented by Mr. Sloan and Mr. Lawshe. Neither or those witnesses represent a party willing to take risk inherent in making the planned investment without regulatory protection.

The Attorney General continues, at AG Br, p. 37, by arguing that:

In addition to ANR East and Rover, there are numerous alternatives available for DTE Gas to have Appalachian gas supply delivered to its city gates at a much lower cost than NEXUS, and these alternatives were available at the time DTE Gas entered into its precedent agreements with NEXUS, and some of them remain available today, so there was no need for DTE Gas to sign a precedent agreement with its parent sponsored project in December 2013, and then again in July 2014, without engaging in an open competition, such as a request for proposals or bid solicitation. DTE Gas does not need to incur the high transportation charges on the NEXUS project to reap commodity gas cost savings that will result from the additional liquidity provided by both existing infrastructure and the additional capacity being constructed from the Appalachian Basin to delivery points in Michigan (5 T 773-780 & 795-807).

In conclusion, at AG Br, p. 38, the Attorney General argues:

[T]he Commission lacks statutory power to approve the NEXUS contract, and assuming the Commission has statutory power to approve the contract and related recovery, the Commission must base its decision on the whole record, and the record demonstrates that approval would result in recovery of explicit fixed costs totaling at least $24 billion based upon a 15-year speculation that the NEXUS pipeline will change the natural gas market and yield variable cost savings. At the present time, the record is not sufficient to justify an order approving the NEXUS contract with its resulting fixed costs and speculation about potential savings resulting from an affiliate transaction. And DTE Gas has offered no evidence to prove that the projected costs will not be higher than the actual costs incurred by its

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affiliate—as required by the Commission’s Code of Conduct governing affiliate transactions.

vi. RRC

Like the Attorney General, RRC argues that MCL 460.6h(6) and MCL 460.6h(7)

define the scope of GCR Plan cases and that the Commission lacks authority to approve

the NEXUS pipeline capacity agreement. RRC Br, p. 2-3.

vii. DTE Gas’ Response to Arguments that Act 304 bars Approval of Nexus

Citing Union Carbide v Pub Serv Comm, 431 Mich 135, 428 NW2d 322 (1988),

DTE Gas notes that it “is well-settled law that ‘[t]he [Commission] is an administrative

body created by statute and the warrant for the exercise of all its power and authority

must be found in statutory enactments.’”. DTE Gas Rep Br, p. 9. “Accordingly”, DTE Gas

argues, “Act 304 provides for the Commission’s review and approval of a gas utility’s

decisions underlying its five-year forecast.” DTE Gas Rep Br, p. 9. Focusing on the

words “shall evaluate”, found in MCL 460.6h(7), DTE Gas argues that it “is clear that the

Commission is not only required to review a gas utility’s decision underlying a five-year

forecast, but also possesses the requisite statutory authority to provide a judgment or

determination of such decision in advance of a future GCR year.” DTE Gas Rep Br,

p. 11. DTE Gas further explains its position, at DTE Gas Rep Br, p. 12, by stating:

[T]he Commission must issue a final order pursuant to Section 6 of Act 304 for cost items in a GCR plan since it concerns the immediate 12-month GCR year. In contrast, the Commission has at least a couple of options for its order with respect to a five-year forecast pursuant to Section 7 of Act 304: either 1) issuing a final order for a decision underlying a cost item if the evidentiary record for such item is adequately developed, or 2) issuing a Section 7 warning for a cost item if the evidentiary record is not adequately developed since there is still time for a gas utility to present additional evidence. Any other interpretation of Section 7 would render the

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second (and only other) sentence of this provision as “surplusage or nugatory,” which is prohibited by the rules of statutory construction.

DTE Gas finds further support of its position “for practical reasons.” DTE Gas Rep

Br, p. 13. As stated by DTE Gas, “[i]f past history is any guidance, a Commission final

order for this case that addresses DTE Gas’s request for such approval will at best be

issued well after the close of the immediate 2015-2016 GCR Year and at worst could be

issued sometime in 2018, which could not for any substantive reasons, but merely due to

administrative delay, prevent DTE Gas customers from realizing the benefits that are

provided by the NEXUS transportation contract.” DTE Gas Rep Br, p. 13-14. DTE Gas

continues by touting the claimed 2.3 to 4.1 billion dollar benefit of the Nexus pipeline to

Michigan gas customers and states that it “plans to start taking the necessary steps during

the 2015- 2016 GCR Plan Year to replace 75 MDth/d of existing transport with NEXUS

capacity effective November 1, 2017.” DTE Gas Rep Br, p. 15.

At DTE Gas Rep Br, p. 15, DTE Gas concludes by stating that:

Based on the foregoing, Commission review of DTE Gas’s request is not only required under Section 7 of Act 304, but also ripe for a final decision. Thus, the assertion that DTE Gas’s request for Commission approval is premature because transportation of gas on NEXUS will not commence until November 2017 is contrary to a proper interpretation of Act 304 and also contrary to sound public policy. Therefore, such assertion must be rejected as a matter of law.

c. Discussion

i. Standard of Proof

It is DTE Gas’ burden to establish, by a preponderance of the evidence, the

reasonableness of the rate requests it makes and the components contained therein.

DTE Gas’ reliance on Article VI, section 28, of the Michigan Constitution to support its

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contention that it is only burdened with a lower, substantial evidence standard, is

misplaced.

DTE Gas’ argument is premised upon some confusion between the standard of

proof the Commission applies to evaluate the evidentiary record and the judicial standard

of review to be used upon appeal of a Commission action. Absent a statutory mandate

to the contrary, the Commission makes findings of fact based on the preponderance of

the evidence standard. On appeal, courts are to defer to Commission findings that are

supported by substantial evidence. As stated by the court in Antrim Resources v Pub

Serv Comm, 179 Mich App 603; 620, 446 NW2d 515; 523 (1989)(citations omitted):

The reviewing court is to give due deference to the PSC's administrative expertise and is not to substitute its judgment for that of the PSC.

The standard of judicial review of a decision of the PSC is whether that decision is lawful and supported by competent, material and substantial evidence on the whole record. It is for the PSC to . . . determine how the evidence preponderated.

The Commission has long held to the preponderance of the evidence standard.

ii. Commission Authority to Approve the NEXUS Capacity Agreement

In this case, DTE Gas requests Commission approval of the 75,000 Dth/day

NEXUS transportation capacity agreement that is included as part of its Five-Year Plan.

Staff, the Attorney General, and RRC all argue that the Commission lacks authority to

approve the agreement in this Plan case. DTE Gas contends that, with regard to the

Five-Year Plan, the Commission can either issue “a final order for a decision underlying

a cost item if the evidentiary record for such item is adequately developed” or issue “a

Section 7 warning for a cost item if the evidentiary record is not adequately developed”.

DTE Gas Rep Br, p. 12. Thus, based on the record presented, DTE Gas argues that

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Commission review of this request is “required” under Section 7 of Act 304 and is “ripe

for a final decision.” DTE Gas Rep Br, p. 15. Further, DTE Gas seems to argue that the

Commission needs to address this matter because it’s already undertaking the necessary

steps to contract with NEXUS. DTE Gas Rep Br, p. 13-15. DTE Gas’s legal position is

not adopted.

The statutory provisions of MCL 460.6h provide, in part:

(6) In its final order in a gas supply and cost review, the commission shall evaluate the reasonableness and prudence of the decisions underlying the gas cost recovery plan filed by the gas utility pursuant to subsection (3), and shall approve, disapprove, or amend the gas cost recovery plan accordingly. . . .

(7) In its final order in a gas supply and cost review, the commission shall evaluate the decisions underlying the 5-year forecast filed by a gas utility pursuant to subsection (4). The commission may also indicate any cost items in the 5-year forecast that on the basis of present evidence, the commission would be unlikely to permit the gas utility to recover from its customers in rates, rate schedules, or gas cost recovery factors established in the future.

Pursuant to MCL 460.6h (3), GCR Plan filed by DTE Gas shall:

describe[] the expected sources and volumes of its gas supply and changes in the cost of gas anticipated over a future 12-month period specified by the commission and request[] for each of those 12 months a specific gas cost recovery factor. . . . The plan shall describe all major contracts and gas supply arrangements entered into by the utility for obtaining gas during the specified 12-month period. The description of the major contracts and arrangements shall include the price of the gas, the duration of the contract or arrangement, and an explanation or description of any other term or provision as required by the commission. The plan shall also include the gas utility's evaluation of the reasonableness and prudence of its decisions to obtain gas in the manner described in the plan, in light of the major alternative gas supplies available to the utility, and an explanation of the legal and regulatory actions taken by the utility to minimize the cost of gas purchased by the utility.

Pursuant to 460.6h (3), contemporaneously with its Plan, DTE Gas must file a 5-

year forecast that includes:

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the gas requirements of its customers, its anticipated sources of supply, and projections of gas costs. The forecast shall include a description of all relevant major contracts and gas supply arrangements entered into or contemplated between the gas utility and its suppliers, a description of all major gas supply arrangements which the gas utility knows have been, or expects will be, entered into between the gas utility's principal pipeline suppliers and their major sources of gas, and such other information as the commission may require.

In this contested case, DTE Gas argues that the Commission is offered at least

two options after evaluating the five-year forecast; either issue “a final order for a decision

underlying a cost item if the evidentiary record for such item is adequately developed” or

issue “a Section 7 warning for a cost item if the evidentiary record is not adequately

developed”. DTE Gas Rep Br, p. 12. As DTE Gas sees it, “[a]ny other interpretation of

Section 7 would render the second (and only other) sentence of this provision as

‘surplusage or nugatory,’ which is prohibited by the rules of statutory construction.” DTE

Gas Rep Br, p. 12. This argument is not convincing.

As noted at Application of Detroit Edison Co v MI Pub Service Comm, 296 Mich

App 101; 109-10, 817 NW2nd 630; 634 (2012)(citations deleted):

[T]he PSC possesses only that authority granted to it by the Legislature. Authority must be granted by clear and unmistakable language, and so the wording in the PSC's enabling statutes must be read narrowly and in the context of the entire statutory scheme. . . . [T]he powers of administrative agencies are ... inherently limited. Their authority must hew to the line drawn by the Legislature. Our Supreme Court has repeatedly stressed the importance of this limitation on administrative agencies, stating that “‘[t]he power and authority to be exercised by boards or commissions must be conferred by clear and unmistakable language, since a doubtful power does not exist.’”

In Application of Detroit Edison, the court was asked to interpret the revenue

decoupling provisions of MCL 460.1089(6) and MCL 460.1097(4). The court found that

the Commission had exceeded its authority when it approved a revenue decoupling

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mechanism for Detroit Edison’s electric utility. The reason being that, where MCL

460.1089(6) states that the Commission “shall authorize” a revenue decoupling

mechanism for qualifying natural gas utilities, MCL 460.1097(4) provided for the

Commission to “report” to the legislature about the potential effects of applying decoupling

to electric utilities. Noting the differences in the language, the court stated “that a plain

reading of MCL 460.1097(4) does not empower the PSC to approve or direct the use of

an RDM for electric providers. If the Michigan Legislature had wanted to do so, it is plain

from the language applicable to gas utilities in MCL 460.1089(6) that it could and would

have made its intention clear.” Id.

Applying the court’s findings in Application of Detroit Edison to the facts of this

case leads to the conclusion that the Commission lacks authority to grant the approval

DTE Gas seeks. Both MCL 460.6h(6) and (7) address actions that the Commission must

take in a Plan case. In MCL 460.6h(6), the Commission is required to evaluate the

reasonableness and prudence of the decisions underlying the Plan and to approve,

disapprove, or amend the Plan accordingly. Similarly, in MCL 460.6h(7) the Commission

is required to evaluate the decisions underlying the 5-year forecast. However, in stark

contrast to MCL 460.6h(6), MCL 460.6h(7) does not mandate that the Commission

approve, disapprove, or amend the five-year forecast. Rather, MCL 460.6h(7), provides

that the Commission may “indicate any cost items” for which, based on the present

evidence, the Commission feels it would be unlikely to permit cost recovery in the future.

Thus, a plain reading of the MCL 460.6h(6) and (7) reveals that the Commission may not

approve cost items found exclusively in the five-year forecast. Had the Legislature wished

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to grant such authority, it is plainly obvious that, from the language in MCL 460.6h(6), it

could and would have made its intention clear.

iii. Section 7 Warning

Based on the evidence presented, a Section 7 Warning is appropriate. DTE Gas’s

July 2014 PA is an affiliate transaction for transportation capacity on the proposed

NEXUS pipeline. The evidence leaves one with the strong impression that this affiliate

transaction is just one component of a largely unexplained contractual scheme, designed

to foster the success of the NEXUS pipeline project, involving DTE Gas, DTE Energy,

DTE Pipeline, DTE Electric, and NEXUS. Given the nature of the NEXUS project and the

parties affected, these arrangements are no great surprise and may prove beneficial to

DTE Gas’ customers. However, because affiliate transactions are inherently susceptible

to abuse, they must be closely examined.

What does appear quite clear is that DTE Gas never seriously considered any

other options for acquisition of the 75,000 Dth/day transportation capacity. As its primary

defense to this conclusion, DTE Gas contends that it may have been bound by the

unsigned December 2013 PA and was certainly bound by the July 2014 PA. This

argument is unconvincing for a number of reasons, most notably because the December

2013 PA was never signed by the parties and, regardless, the agreements are expressly

subject to Commission approval. In addition, it is clear that when DTE Gas was working

out the details of the NEXUS PA, other avenues for the transport of Appalachian gas,

some quite possibly less expensive than NEXUS, were available and today still more are

available. Because of this, it is incumbent upon DTE Gas to establish that approval of

this contractual arrangement is in its customers’ best interest. To do so, DTE Gas must

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present a transparent evidentiary presentation examining the full nature of its NEXUS

arrangements. At a minimum, this should include a thorough presentation of any

investments in its transportation system for which DTE Gas’ customers will be required

to support, an explanation of the nature and risks associated with the apparently linked

proposed PAs for natural gas by DTE Gas and DTE Electric, and a full and complete

examination of all the various transportation options available to DTE Gas. Without such

a presentation, DTE Gas is advised that the Commission may not permit full recovery of

gas transportation services envisioned with NEXUS.

2. RESA’s Proposal to Reallocate Reservation Costs

a. Facts

DTE Gas maintains an interstate transportation portfolio to supply and serve as

supplier of last resort (SOLR) for its GCR and GCC customers. 4 Tr 274. In Exhibit

A-11, DTE Gas provided, among other things, its annual projected reservation costs and

total transportation costs for 2015-2020. For 2015-16, DTE Gas projects transportation

costs of $49,303,946. Exh A-11. Those costs are projected to drop to $47,296,708 for

2016-17, but rise to $49,623,857 in 2017-18, and jump to $56,497,623 in 2018-19 with

the first full-year of proposed transportation with NEXUS. Exh A-11. In addition, Exhibit

A-11, provides the five-year forecast of its reservation charges for firm pipeline capacity.

4 Tr 275. Exh A-11.

To recover its pipeline capacity costs and the cost of Firm Parking Service, DTE

Gas proposes to continue use of its Commission approved SOLR Reservation Charge,

to be charged to both GCC and GCR customers on a load proportionate basis.

4 Tr 274-75. Any revenues from capacity release, of which DTE Gas projects none, will

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be credited back to both customer groups. 4 Tr 275. For 2015-16, DTE Gas plans to

recover approximately $46,600,000 under the SOLR Reservation Charge. 4 Tr 276.

RESA however is proposing an “adjustment to the Reservation Charge to ensure

that the charge is equitable and accurate between GCR and GCC customers.”

4 Tr 523-525. As explained by RESA’s witness Daniel Dishno, at 4 Tr 524:

The main benefit of holding pipeline capacity is the ability to transport natural gas from point A to point B through the pipeline. Delivering supply from point A to point B allows DTE to capture a market spread value between the two points on the pipeline, which ultimately lowers the average supply cost for GCR customers. Currently, DTE utilizes the pipeline assets it retains to transport gas for GCR customers to DTE's city-gate. Conversely, AGSs are responsible for delivering the gas to the city-gate for GCC customers and thus GCC customers do not receive that same reduced supply costs from the Capacity Assets.

* * *

Under the Reservation Charge proposed by DTE, GCC customers will pay a pro rata share of the costs of the Capacity Assets, but do not receive a pro rata share of the benefits stemming from those Capacity Assets.

In Exhibit RES-1, Mr. Dishno presents a model that he used “to identify the amount

of reduced costs GCR customers receive because DTE utilizes the Capacity Assets for

GCR deliveries.”19 4 Tr 527. Exh RES-1. Mr. Dishno considers his model “conservative

and only [an attempt] to quantify the intrinsic market value the Capacity Assets provide to

GCR customers.” 4 Tr 527. Mr. Dishno explains that his model does not include of cost

of parking service and he adds that if the Commission approves the inclusion of parking

service costs in the Reservation Charge, “then the benefits derived from that service

should be shared pro rata between GCR and GCC customers.” 4 Tr 427. Mr. Dishno’s

proposal envisions an annual true-up mechanism once actual data becomes available.

19 For a more detailed explanation of Mr. Dishno’s modeling, see 4 Tr 528-530.

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5 Tr 530.

Mr. Dishno projects “that GCR customers will receive an additional $13,353,414 in

reduced gas supply costs because of the Capacity Assets DTE holds during the 2015-

2016 gas year.” 4 Tr 532. Exh RES-1, p 6. To account for this disparity, Mr. Dishno

recommends the following: that DTE Gas’ 2015-16 Reservation Charge be set at $0.179

per MCF for GCC customers and $0.285 per MCF for GCR customers; that annually, DTE

Gas reconcile the Reservation Charge adjustment to account for the difference between

the forecasted Pipeline Spread Value and the actual Pipeline Spread Value, and; that

DTE Gas calculate a Reservation Charge adjustment in future GCR proceedings.

4 Tr 532.

In rebuttal, at 4 Tr 536-37, Mr. Dishno explained that:

The model is designed to forecast the intrinsic value of DTE's pipeline assets at a point in time for a specific gas year and use the value as an initial adjustment to the Reservation Charge. The actual value received from the pipeline assets can be determined at the end of the gas year and will be adjusted and reconciled with the forecasted value. . . . [T]the Commission will be able to do an after-the-fact analysis to determine whether GCR customers receive more or less value than what my model predicts and the reservation Charge would then be reconciled and adjusted after the final pricing numbers are known.

* * * It is important to note that even [DTE Gas’ witness, Mr. Lawshe,]

concedes that these assets do in fact currently have a value to GCR customers worth roughly $3 million. . . . [T]he fact of the matter is . . . there is a quantifiable inequity between GCR and GCC customers.

DTE Gas’ witness, Mr. Lawshe, stated that Mr. Dishno’s “model grossly overstates

the benefits received by GCR customers by more than 300%, or more than $10 million.”

4 Tr 343. Mr. Lawshe recalculated the benefits after making what he believes were

appropriate adjustments for interstate pipeline utilization, “unfavorable pricing”, and price

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projections. 4 Tr 343-44. His recalculation “leaves about 2 cents per Mcf of what [Mr.

Dishno] describes as a perceived benefit attributable to ‘Intrinsic Spread.’” 4 Tr 344.

Addressing the reconciliation process, Mr. Lawshe states there are two “key

inputs” that can’t “be quantified and verified”; “the market value of gas at the receipt points

into the Gas interstate pipelines for which DTE Gas holds capacity, and the market value

of that gas at the delivery points into the DTE Gas system.” 4 Tr 351. He explains his

contention, at 4 Tr 351, by stating:

There are two primary reasons these values cannot be quantified and verified after the fact:

1. Many receipt points and delivery points do not have publically available data showing the final close index price. One of these points is the Alliance interconnect with either ANR Pipeline or Vector Pipeline. As a proxy, buyers and sellers at that interconnect may use the Inside FERC Gas Market Report published index price for Chicago city-gates, and then add or subtract a mutually agreeable premium or discount to adjust for both the alternate location, and the Physical Index described below. Even Witness Dishno’s model contains an assumed $0.035/Dth premium against the actual Chicago city-gates index price as a proxy for Alliance for the historical months of April, May and June 2014. . . . Similarly, many of the delivery points for which DTE Gas uses its interstate transport capacity to delivery gas into its system are at remote locations . . . that would also be subject to such pricing location adjustment with no publically available information to rely upon to quantify the actual amount for this pricing adjustment. . . .

2. In addition . . . , the market value of index based physical gas purchases is further adjusted by a Physical Index, which is a premium or discount agreed upon between the buyer and seller at the time of the transaction that is added or subtracted from the published index price. Again, Witness Dishno’s model contains an assumed $0.015/Dth Physical Index premium adjustment for all interstate receipt points, except Alliance, and a $0.00/Dth Physical Index adjustment for all DTE Gas city gates for the historical months of April, May and June 2014. . . . [T]here is no publically available information to rely upon to quantify the actual amount for this Physical Index pricing adjustment.

During Cross-examination, Mr. Lawshe indicated it was his belief that, as stated

by the Asst. Attorney General, “some, if not most, of the pipeline spread values calculated

by Mr. Dishno [would] be reflected in Midstream revenues included in base rates”.

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4 Tr 474-75. In answering this leading question. Mr. Lawshe clearly appeared uncertain

and the answer was not credible.

b. Positions of the Parties

i. RESA

RESA argues that DTE Gas’ proposed Reservation Charge of $0.29/Mcf “is unjust

and unreasonable, and, if adopted, will harm GCC customers and the GCC program.”

RESA Br, p. 2. RESA contends this is because “GCC customers are getting less benefit

than GCR customers from the pipeline capacity that DTE holds while paying the same

charge.” RESA Br, p. 2. RESA asks the Commission to approve RESA's proposed

Reservation Charge adjustment and direct DTE to incorporate the adjustment in the

development of any future capacity reservation charges. RESA Br, p. 2.

RESA argues that it presented substantial evidence in support of an adjustment to

DTE's capacity reservation charge and, at RESA Br, p. 6-7, explains:

Mr. Dishno presents a capacity valuation model that quantifies the gas commodity savings that GCR customers receive from DTE's capacity assets.

. . . Using its pipeline assets, DTE is able to source lower cost gas than what it would cost to procure gas at DTE's city-gate. The price differential between buying more remote gas and transporting it to DTE's city-gate via pipeline capacity assets, and the price of buying city-gate gas is the spread value. Mr. Dishno explains:

Delivering supply from point A to point B allows DTE to capture a market spread value between the two points on the pipeline, which ultimately lowers the average supply cost for GCR customers. . . . DTE is able to utilize the Capacity Assets to purchase gas at points along its pipeline pathway that are cheaper than the DTE delivery points. Thus DTE is able to realize this price differential (less variable costs) to reduce the overall supply costs for GCR customers."

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In short, it is RESA’s position that “GCC customers are subsidizing GCR

customers through DTE's capacity reservation charge”. RESA Br, p. 7. “To remedy this

inequity”, RESA calls for adoption of Mr. Dishno’s proposal “that GCC and GCR

customers be charged a different capacity reservation charge commensurate with the

value that each class of customer receives from DTE's capacity assets.” RESA Br, p. 7.

ii. DTE Gas

DTE Gas argues that the Attorney General’s “cross-examination of DTE Gas

witness Mr. Lawshe shows that if there is any Pipeline Spread Value, then it is already

realized by GCC customers through the reduction of base rates.” DTE Gas Rep Br, p.

63. “Thus”, DTE Gas concludes “the entire premise for RESA’s alternative reservation

charge, which is that only GCR customers realize a Pipeline Spread Value, is non-

existent.” DTE Gas Rep Br, p. 63. Therefore, as DTE Gas sees it, RESA’s position is

“meritless” “because GCC customers (along with GCR customers) already realize any

Pipeline Spread Value through the reduction of base rates.” DTE Gas Rep Br, p. 64.

Alternatively, at DTE Gas Rep Br, p. 65-66, DTE Gas questions Mr. Dishno’s

modeling. DTE Gas argues that Mr. Dishno’s model overstates GCR customer benefits

by more than $10 million, leaving “about $3 million of alleged benefits or $0.02/Mcf of

what he describes as a perceived benefit attributable to “Intrinsic Spread’”. DTE Gas Rep

Br, p. 65. In addition, DTE Gas argues that the modeling is questionable for a variety of

reasons including: “the glaring absence of capacity release revenues”; “the wrong

number of days in February 2016”; the wrong MDQ for ANR Alpena contract #112065”;

“the wrong MDQ for Great Lakes contract #FT17664”; “the unsupported assumption of a

$0.015/Dth Physical Index adjustment to all prices”; “the unsupported assumption of a

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$0.035/Dth adjustment to prices at Alliance”; “the unsupported assumption that MichCon

City Gate physical supply trades at a price flat to Index”, and; “numerous other technical

errors not yet found”. DTE Gas Rep Br, p. 65-66. In addition, DTE Gas questions the

feasibility of the annual reconciliation arguing that “the market value of gas at the receipt

points into the gas interstate pipelines for which DTE Gas holds capacity cannot be

quantified or verified” and that, likewise, “the market value of that gas at the delivery points

into the DTE Gas system cannot be quantified or verified”. DTE Gas Rep Br, p. 66.

iii. Attorney General

The Attorney General opposes RESA’s proposal. AG Br, p. 22-27. “The Attorney

General contends the premise that GCC customers receive less value is at best a

factually irrelevant claim.” AG Br, p. 24. As the Attorney General sees it, “[t]his claim

ignores the fact that pipeline reservation costs for DTE Gas are higher because . . . DTE

Gas must provide natural gas to GCC customers as a supplier of last resort.” AG Br,

p. 24. If not for its status as SOLR, the Attorney General contends, there would be no

need for calculation of a reservation charge. AG Br, p. 24.

While the Attorney General recognizes that DTE Gas’ capacity allows it to capture

the value of price spreads, he argues that these “revenues go to reduce the base rates

that are charged for GCR and GCC customers”. AG Br, p. 25. Further, the Attorney

General argues that Mr. Dishno’s “projected spread offset overstates the spread value

benefits”. AG Br, p. 27. “In conclusion”, at AG Br, p. 27, the Attorney General argues

that:

[T]he Commission should reject the revised SOLR reservation charge adjustments proposed by Mr. Dishno because on the record as a whole it is not just and reasonable to offset admitted fixed pipeline costs by

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calculating a variable cost saving, because using the alleged benefits proposed to adjust the factor designed to recover fixed pipeline costs ignores the fact that fixed pipeline costs are higher to enable DTE Gas to provide SOLR service to GCC customers, and because the spread value calculations are not realistic or reasonably accurate.

iv. RESA’s Reply to DTE Gas and the Attorney General

RESA characterizes DTE Gas’ criticism of its proposal as “refinements to

projections Mr. Dishno used in his model when actual data was not available.” RESA Br,

p. 10. RESA notes that “actual data will ultimately become available after DTE makes

deliveries for each gas year, and the reservation charge calculations can be trued-up

based on actual delivery data.” RESA Br, p. 10. “More importantly”, at RESA Br, p. 11,

RESA contends:

DTE's criticisms do not undermine the fundamental soundness of Mr. Dishno's proposal. The undeniable fact remains that there is value derived by GCR customers due to DTE's capacity holdings that is not shared with GCC customers. It is possible to quantify that value and adjust the capacity reservation charge accordingly consistent with the Commission's intent to ensure that the capacity reservation charge "is equitable and accurate."

RESA notes that like any other component of a GCR plan, Mr. Dishno's model

provides a prediction that DTE Gas can reconcile when the actual pipeline spread value

becomes known. RESA Br, p. 13-14. “Importantly”, RESA adds, “differences in

projections do not undermine the validity of [the] capacity valuation model. DTE's

concerns are not bases for rejecting [the] proposed adjustment.” RESA Br, p. 14. At

RESA Br, p. 14-15, RESA argues:

Even if the Commission accepts Mr. Lawshe's assertion that the projected value of the pipeline capacity for GCR customers is only $0.02 during the 2015-2016 GCR year, then the Commission should order that SOLR Reservation Charge adjustment, subject to reconciliation, and direct DTE to perform the SOLR Reservation Charge adjustment calculation as part of its GCR plan application going forward. Even if one accepts DTE's

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representation that its pipeline holdings provide little value today, the value of DTE's pipeline assets will change over time. This is especially true if one believes DTE's testimony in support of its 15-year NEXUS pipeline contract. Recognizing and addressing the reservation charge inequity between GCR and GCC customers, no matter how small it may currently be, is an important step that the Commission should make.

“Over time”, RESA adds, “with the ordered cooperation of the utility, the predictive

capabilities of the model will likely improve.” RESA Rep Br, p. 7.

RESA advises the Commission to “evaluate [DTE Gas’] comments in context.”

RESA Br, p. 16. RESA points out that the “proposed capacity reservation charge

adjustment would be to DTE's detriment” and argues that DTE Gas “has a vested interest

in maintaining the status quo despite repeated demonstrations that the existing capacity

reservation charge is inequitable and inaccurate.” RESA Br, p. 16-17.

In reply to DTE Gas’ claim that any pipeline spread values are included in base

rates, RESA argues, at RESA Rep Br, p. 4-6:

To support this claim, DTE cites vague statements made at hearing (not in pre-filed testimony) by DTE witness Lawshe that DTE uses its storage assets and pipeline assets to engage in exchange transactions (a.k.a. Midstream services) which generate revenue that is returned to distribution customers. The AG also made similar arguments in its brief . . . that DTE is using its pipeline capacity assets to provide Midstream services. The arguments put forth by DTE and the AG do not refute RESA's recommendation. The pipeline spread value described by Mr. Dishno is not related to Midstream services but rather is a quantifiable amount of reduced gas costs GCR customers receive for having the ability to utilize DTE's pipeline assets for natural gas deliveries. Thus, even assuming DTE utilizes its pipeline assets to engage in revenue generating services that are returned to distribution customers, which is far from undisputed,11 it does not negate the fact that DTE is also at other times utilizing its pipeline assets to reduce the gas delivery costs just for GCR customers. The notion that DTE may share some benefits stemming from its pipeline holdings with both GCR and GCC customers, does not undermine Mr. Dishno's recommendation to recognize pipeline spread values that are going only to GCR customers in the calculation of the capacity reservation charge. It is undisputed that GCC customers do not receive the same benefits from DTE's pipeline assets as GCR customers, yet they pay the same capacity

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reservation charge. * * *

The idea that some pipeline benefits may be recognized in base rates does not mean that all pipeline benefits are appropriately allocated between GCC and GCR customers.______________________________________ 11 For instance, at hearing Mr. Lawshe never indicated the amount of Midstream services revenue, and whether the revenue is even a material amount compared to the reservation charge; whether the Midstream services were performed with the pipeline assets DTE recovers through distribution rates, or the pipeline assets recovered through the reservation charge; the percentage of Midstream services revenue generated from storage, and the percentage of revenue that is generated from pipeline assets. In sum, so little is known about Mr. Lawshe's Midstream services claim, that it should be given no evidentiary weight in this proceeding.

v. Staff

Staff opposes RESA’s proposal. Staff Br, p. 15. Staff considers RESA’s model to

be complex, incorporating “several discretionary, even speculative inputs” rendering it

“too difficult (if not impossible) to administer.” Staff Br, p. 15. Staff adds that “[a]lthough

a reconciliation is proposed to correct these flaws, . . . the reconciliation involves inputs

that cannot be quantified.” Staff Br, p. 15.

RESA rejects Staff’s arguments and, at RESA Rep Br, p. 8, argues:

[The] model is no more complex or discretionary than other predictive models routinely relied upon at the MPSC. Indeed, in each GCR or power supply cost recovery plan, utilities submit complex models intended to predict the future. Those models contain many assumptions and thousands, if not tens of thousands, of data points. Gas supply plans make numerous assumptions about capacity, sales volumes and market prices. Electric dispatch models seek to predict how individual generators will be utilized as entire markets unfold. As with any model, the output is highly dependent on the assumptions and inputs incorporated into the model, all of which are subject to different levels of uncertainty. Fortunately, the predictive models used as the basis for plan proceedings are then reconciled to actual data once available. Mr. Dishno's model is no different.

In many ways, Mr. Dishno's model is actually less complex and more accessible than many models relied upon at the MPSC. Mr. Dishno's model is a single spreadsheet that is not proprietary. The parties to this proceeding could readily see and examine each individual data point and manipulate

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the model as they desired. The fact that parties could identify and raise concerns about the model's assumptions is a testament to how accessible and understandable Mr. Dishno's model is. RESA presented substantial evidence in support of an adjustment to DTE's capacity reservation charge in this case. RESA's witness Mr. Dishno presented a capacity valuation model that quantifies the gas commodity savings that GCR customers receive from DTE's capacity assets. Concerns with the predictive capability of the model will be resolved during the reconciliation process.

To address Staff’s (and DTE Gas’) concern that reconciliation inputs cannot be

quantified, RESA notes that, currently, much of the data needed to plan and reconcile

DTE Gas' gas costs is not publicly available, nor verifiable, “until DTE [Gas] discloses it

to the Commission”. RESA Rep Br, p. 9-10. At RESA Rep Br, p. 10, RESA continues

by arguing that:

If the Commission orders DTE to make the capacity reservation charge adjustment warranted by Mr. Dishno's model, then DTE will maintain the data to populate the model during the reconciliation process. During the reconciliation process, DTE will know the price it paid for gas, its variable costs to transport gas, and the city-gate price DTE would have paid for city-gate gas at the time of the purchase, to determine the actual pipeline spread value. The notion that certain pipeline points are not publicly traded does not mean that DTE does not know the industry information. In order for DTE to demonstrate that its decision to buy and transport gas was reasonable and prudent, DTE needs to know the price it will pay for the gas, its variable costs to transport gas, and the city-gate price DTE could have otherwise paid for city-gate gas. These are the variables that populate Mr. Dishno's pipeline spread value model. DTE has, or should have, the requisite data to perform the calculations. What DTE currently lacks is the Commission order directing them to do so.

c. Discussion

The Commission first established DTE gas’ Capacity Reservation Charge (CRC)

in Case No. U-17131, DTE Gas’ 2013-14 GCR Plan Case. Application of DTE Gas,

U-17131, Order, p. 3-9 (April 15, 2014). The CRC again received Commission approval

in DTE Gas’ 2014-15 GCR Plan Case, Case No U-17332. In Case No. U-17332, the

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Commission opted to continue with the CRC rather than to replace it with a proposed

Capital Assignment Plan. Application of DTE Gas, U-17332, Order, p. 9-14 (April 23,

2015). In that case, the Commission took “note of the ALJ’s finding that the capacity

acquired to meet the SOLR obligation may provide benefits to GCR customers that are

not available to GCC customers.” Application of DTE Gas, U-17332, Order, p. 14 (April

23, 2015). However, the Commission also, “note[d] that IGS and RESA failed to show

the extent of any such inequity or that the CAP was a feasible and appropriate mechanism

to attempt to remedy any inequity. Application of DTE Gas, U-17332, Order, p. 14 (April

23, 2015). The Commission also felt it was “not clear what benefits would actually accrue

to any customer as a result of the CAP and that “[f]or these reasons and based on the

scant record before it, the Commission [could not] adopt the CAP, even in concept.”

Application of DTE Gas, U-17332, Order, p. 14 (April 23, 2015). In finding that the CRC

should be continued, the Commission stated that “[g]oing forward, the Commission seeks

to ensure that the allocation of pipeline reservations costs and associated SOLR service

is equitable and accurate” and that it “expects the amount of the reservation charge to be

reviewed in plan cases to make sure that it is appropriate based on actual operations and

expenses, and is commensurate with the benefits afforded by SOLR service for both GCR

and GCC customers.” Application of DTE Gas, U-17332, Order, p. 14 (April 23, 2015).

In the case at bar, RESA’s proposal attempts to comply with the Commission’s

directive from Case No. U-17332. Mr. Dishno’s capacity valuation model provides an

estimate of the gas commodity savings that flows to GCR customers, but not GCC

customers. Rather than the CAP proposal made in Case No. U-17332, RESA proposes

adoption of separate reservation charges for GCC and GCR customers; charges that

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would be adjusted and reconciled based on the value each group realizes from DTE’s

capacity assets. RESA’s proposal is familiar in form and, while not ideal, seemingly

reasonable.

DTE Gas, on the other hand, has failed to take proactive measures to comply with

the Commission’s directive. Rather, DTE Gas has sat back, waited for another RESA

proposal, and then attacked. Because any proposal by RESA will most certainly

negatively affect DTE Gas, this reaction is not all that surprising. Unfortunately, this

obstructionistic tactic does little to move the ball forward on this issue.

Permitting such recalcitrance could lead to an endless cycle of proposals being put

forward by RESA, only to be shot down by DTE in rebuttal. To avoid such continuing

outcomes, RESA’s current proposal, however imperfect, is adopted. As the Commission

has already made clear, in future cases, DTE Gas is expected to cooperate in the

development of an equitable and accurate mechanism that best ensures the reservation

charge is appropriately based on actual operations and expenses and is commensurate

with the benefits afforded by SOLR service for both GCR and GCC customers.

3. Volume Cost Averaging (VCA) Gas Purchasing Strategy

a. Findings of Fact

DTE Gas proposes to continue purchasing fixed price gas under its Volume Cost

Averaging method (VCA). 4 Tr 253. The specifics of DTE Gas’ VMA are found in Exhibit

A-7. The purpose of the VCA is “to create price certainty for natural gas volumes that will

be delivered at a future date, also known as a hedge.” 4 Tr 257. VCA provides a

“smoothing effect on the GCR factor” and provides a “simple” way for DTE Gas to manage

gas price fluctuations and uncertainty. 4 Tr 257. “In general, DTE Gas will fix the price

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of its future supply requirements over a two year period prior to the start of delivery during

the GCR Period [so that] 75% of [its] supply requirements will be known prior to the start

of the GCR Period.” 4 Tr 258. As stated by DTE Gas witness, Mr. Lawshe, at 4 Tr 259:

VCA allows continual market participation over an extended period of time up to two years in advance of the GCR Period start date. The methodology is consistent with the philosophy that one should not try to beat the market but instead regularly participate in the market over an extended period of time.

“VCA eliminates price speculation” because “purchases are fixed each month

regardless of price. Therefore, the purchases are time dependent as opposed to price

dependent.” 4 Tr 260. At 4 Tr 263, Mr. Lawshe explains why he believes the VCA is

reasonable and prudent, by stating:

In general, natural gas is not a discretionary purchase that can be avoided based on price or some other factor. DTE Gas’ customers need to purchase and consume natural gas throughout the year for such basic needs as warmth in their homes and businesses. . . . DTE Gas’ customers should not be unduly subject to risk taking or speculating on what the price of natural gas will be in the future.

At 4 Tr 265, DTE Gas witness, Mr. Lawshe, states that fixing the price of 75% of

its gas supply under the VCA is preferred because DTE Gas believes:

[T]he greater risk to DTE Gas’ customers is rising prices because they are generally believed to have a fixed amount of non-discretionary income to spend on a natural gas utility bill and would ultimately be more financially burdened with higher bills as opposed to steady or lower bills. Therefore, using the VCA method with a 75% fixed price coverage ratio is a reasonable and prudent approach to protecting customers from price risk.

In Exhibit A-25, DTE Gas presents the results of its comparison of using the 75%

VCA method versus purchases at Index over a 13 year period ending March 2014. DTE

Gas estimates that, had it used the 75% VCA method over that period, it would have

resulted in additional natural gas costs of $626,070,300. Exh A-25. For the average

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residential customer, this equates to $37 more annually over the 13-year period.

4 Tr 267. Exh A-25.

To quantify the smoothing effect on gas price that DTE Gas believes supports use

of the VCA, Mr. Lawshe explains, at 4 Tr 267:

As shown on Exhibit A-25, page 2, line 15, volatility under the VCA Method means that, for any given year, 95% of the time the customers’ gas costs would be within a range of 32% higher or 32% lower than the average cost based on the past 13 years. By contrast, volatility under the Index Method means that, for any given year, 95% of the time the customers’ gas costs would be within a range of 66% higher or 66% lower than the average cost based on the past 13 years.

At 4 Tr 267-68, Mr. Lawshe’s expresses his opinion that:

The $37 annual cost difference between the VCA Method and the Index Method that occurred over the historical 13 years . . . is approximately 6% of the customers’ total gas cost . . . , which is a reasonable cost to pay to lower the gas price volatility . . . .

In conformity with its VCA methodology, DTE Gas fixed 75% of its April 2015

through March 2016 gas requirements by December 31, 2014. 4 Tr 268. RRC’s witness,

Mr. Hollewa, projects that, compared to Index Method, this will increase the cost of natural

gas during the 2015-16 GCR year by $114 million. 5 Tr 815.

Mr. Hollewa notes that, in the prior six GCR years, use of the VCA Method

increased the cost of gas to GCR customers. 5 Tr 814. As stated at 5 Tr 815, in his

opinion:

The Company’s proposal to continue burdening the GCR customers with extra, unnecessary gas costs to serve its stated objectives of providing “upward price protection”, and a “way to manage price risk and dampen natural gas price uncertainty or volatility” is not reasonable and prudent in a stable natural gas market.

Mr. Hollewa recommends “the Commission amend the GCR Plan in this case by

reducing the Company’s VCA purchases to 25% of annual requirements” or, in the

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alternative, he recommends “a level of 25% made 24 months in advance beginning with

April purchases made in March and an additional 25% made 12 months in advance.”

5 Tr 816.

In rebuttal, Mr. Lawshe argued that Mr. Hollewa provided no evidence regarding

price stability and no evidence that the future performance of the fixed price program will

be the same as its historical performance. 4 Tr 329. Rather, at 4 Tr 329, Mr. Lawshe

states that:

DTE Gas believes that past performance is not a good predictor of future performance, that future prices are uncertain, and that the fixed price purchase program presented by the Company provides price certainty for its customers under all market conditions.

Addressing Mr. Hollewa’s recommendations, at 4 Tr 339-40, Mr. Lawshe states:

Witness Hollewa’s recommended approach . . . will only serve to reduce the level of protection against price volatility. The Random Price Analysis (RPA), Exhibit A-25, page 1 of 2, shows the varying level of price protection with each successive VCA percentage, ranging from 45%, 55%, 65% and 75%. Although this does not display 25%, a simple interpolation of the values . . . show that at 25% VCA coverage, the average GCR Residential customer runs the risk at the High Price Level (95% Confidence Interval) of seeing their average annual gas costs of $412 increase by $374, or 91%. Compare this to the Company’s recommended 75% VCA coverage, where the average GCR Residential customer runs the risk at the High Price Level (95% Confidence Interval) of seeing their average annual gas costs of $412 increase by only $253, or 61%.

* * *

Shortening the VCA term from 24 to 12 months will only compound the added risk exposure to the GCR customers on top of Witness Hollewa’s recommended reduction to the fixed price coverage ratio from 75% down to 25%. He provides no evidence that changing from a 24 month to a 12 month plan has any advantage.

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b. Positions of the Parties i. DTE Gas

DTE Gas argues that “the Commission has previously evaluated and approved

DTE Gas’s past five . . . GCR Plan cases that include . . . the same VCA methodology

being evaluated in this GCR Plan case”. DTE Gas Rep Br, p. 49. DTE Gas contends

that its “[fixed price purchase (FPP)] coverage ratio and VCA methodology have remained

unchanged since Commission first approval on September 28, 2010, in DTE Gas’s 2010-

11 GCR Plan Case No. U-16146, and the Commission’s confirmation of the

reasonableness and prudence of the VCA methodology should continue in this case”.

DTE Gas Rep Br, p. 52-53. DTE Gas argues that it “provided more than ample evidence

to support the VCA Method including several analyses that provide support for the VCA

Method”. DTE Gas Rep Br, p. 56.

At DTE Gas Br, p. 16, DTE Gas argues that:

The objectives of a reasonable and prudent VCA FPP include: (1) mitigating the impact of market price fluctuations and price uncertainty also known as price volatility or price risk to provide GCR factor stability; (2) allowing participation in downward price movements; (3) protecting customers against upward price movements; (4) utilizing a prescriptive methodology that limits speculation; and (5) ensuring simplicity by utilizing a methodology that is not overly complex. The VCA Method satisfies these objectives . . . .

“In summary”, DTE Gas argues at DTE Gas Br, p. 21:

[T]he VCA Method is analogous in many respects to the highly regarded dollar-cost-averaging (“DCA”) method for investors. Like the DCA method . . ., the VCA Method avoids trying to “beat” or “time” the market by making relatively small purchases (3% of supply) each month over 24 months. This VCA Method ensures that DTE Gas will always participate in price declines as well as avoid making large purchases during price spikes . . . .

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To the merits of Mr. Hollewa’s proposal, DTE Gas criticizes his characterization of

gas prices being stable, arguing that he provided “no evidence that historical prices have

been stable”. DTE Gas Rep Br, 54. Rather, relying on Exhibits A-25 and A-39, DTE Gas

argues that gas prices have been “far from stable”. DTE Gas Rep Br, p. 54. Further,

DTE Gas argues that “Mr. Hollewa provides no evidence, analysis, or study results that

show that future prices will be stable if historical prices are stable.” DTE Gas Rep Br,

p. 55. DTE Gas argues that historically, the gas market “shows sudden price spikes that

could not have been foreseen or prevented.” DTE Gas Rep Br, p. 55. In short, DTE Gas

argues, at DTE Gas Rep Br, p. 55, that:

[P]rices are not “stable,” but are instead unpredictably volatile. Hence, DTE Gas’s VCA Method is not only reasonable and prudent, but also a necessity for GCR customers as demonstrated by its use during the 2013-2014 “Polar Vortex” winter when the VCA Method shielded GCR customers from price spikes by saving them $25 million compared to purchasing gas at index . . . .

Further, DTE Gas argues, Mr. Hollewa “gives no evidence, analysis, or study results that

show that future performance of the fixed price program relative to spot market prices will

be the same as historical performance”. DTE Gas Rep Br, p. 55-56.

Next, DTE Gas argues that “the evidentiary record demonstrates that Mr.

Hollewa’s recommended approach of reducing the percentage of gas purchased under

the VCA will only serve to reduce the level of protection against price volatility.” DTE Gas

Rep Br, p. 57. At DTE Gas Rep Br, p. 57, DTE Gas continues by arguing that:

The Random Price Analysis (“RPA”), Exhibit A-25, page 1 of 2, shows the varying level of price protection with each successive VCA percentage, ranging from 45%, 55%, 65% and 75%. Although this does not display 25%, a simple interpolation of the values presented in the table below show that at 25% VCA coverage, the average GCR Residential customer runs the risk at the High Price Level (95% Confidence Interval) of seeing their average annual gas costs of $412 increase by $374, or 91%.

U-17691 Page 59

Compare this to the Company’s recommended 75% VCA coverage, where the average GCR Residential customer runs the risk at the High Price Level (95% Confidence Interval) of seeing their average annual gas costs of $412 increase by only $253, or 61%. In contrast, Mr. Hollewa’s recommended 25% VCA coverage results in greater risk exposure for a typical Residential customer by $121/year, or 48% more than the level recommended by the Company. This reinforces the actual intended purpose of the VCA Program, which is to provide price stability to the GCR Customer . . . .

As for Mr. Hollewa’s recommendation to shorten the VCA term, DTE Gas argues

that this increases its customers’ exposure to price volatility and provides no advantages.

DTE Gas Rep Br, 58.

ii. RRC

RRC argues that the evidence established that DTE Gas’ VCA method “has

caused excess costs while delivering no tangible value for the premium prices paid for

these supplies.” RRC Br, p. 3-4.

RRC argues that DTE Gas has not complied with the Commission’s orders, in

Case No. U-17332 and Case No. U-17131, by failing to “provide a robust presentation on

current and forecasted market conditions and fundamental economic and physical

considerations that affect gas supply and price” RRC Br, p. 4-5. At RRC Br, p. 5-6, RRC

explains:

DTE Gas does not present these analyses because it eschews the notion that gas procurement decisions should be based on this kind of information. Instead, the entire premise of its VCA purchasing method is that the future is unpredictable and unknowable. The Company’s answer is to make fixed price purchases according to a formula -- regardless of whether real time data shows there are less costly and equally reliable options for purchasing gas for the GCR customers. DTE Gas continues along this path because there is no indication from this Commission that it is serious about holding the Company accountable for the years of dismal results of its fixed price purchasing program for the GCR customers.

. . . Each and every year the VCA method has resulted in millions of dollars of losses for the GCR customers compared to purchasing gas at

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Index prices1. In this case Mr. Hollewa identified $25.7 million in net losses for the 2013-2014 GCR year and $114 million in losses for the 2014-2015 GCR year. __________________________________________________

1 In his testimony in prior DTE Gas Company Reconciliation cases Mr. Hollewa identified $246.1 million in losses in the 2010-2011 GCR period in Case No. U-16146-R, $174.4 million in losses in the 2011-2012 GCR period in Case No. U-16482-R and $164.8 million in losses in 2012-2013 in Case No. U-16921-R.

At RRC Br, p. 6-7, RRC argues that “[i]t is time to stop the bleeding” and that:

Year after year after year DTE Gas Company’s GCR customers have been made to bear hundreds of millions of dollars in excess, unnecessary premiums in their gas costs in the name of price stability. In a period of time when prices are stable, supply is abundant and the Company’s plans include tapping into new resources that will enhance price stability and supply reliability, it makes no sense to continue a purchasing method that makes GCR customers forego relatively low market costs for natural gas. As Exhibit RRC-4 shows, natural gas prices [varied] from a low of $2.517 to a high of $2.886 in April through August of 2015 at the same time the VCA method caused a GCR factor of $4.070 in these months. The VCA fixed price purchasing method needs to be reined in because DTE Gas Company has failed to demonstrate with evidence that GCR customers derive any tangible benefit from it.

At RRC Rep Br, p. 3-4 the RRC adds:

In this GCR Plan case DTE Gas Company has requested a GCR Factor [of] $4.07 per Mcf based on purchasing 75% of its supply using the VCA method. In contrast, the actual NYMEX Natural Gas Contract Closing Prices in April-October of this GCR period range from a low of $2.563 to a high of $3.189. The NYMEX futures for the November-March portion of this GCR period range from $2.456 to $2.808.

The reason that the 75% VCA method causes inflated gas costs is because that methodology ignores the Commission’s charge that gas supply planning should be based on “a robust presentation on current and forecasted market conditions and fundamental economic and physical considerations that affect gas supply and price”. Instead, DTE Gas Company relies on a formula to purchase gas that is grounded on the notion that no such analysis is necessary because the NYMEX futures prices are the best indicator of the market for natural gas -- despite the fact that year after year, the results in GCR Plan and Reconciliation cases have shown that the Company’s GCR customers have paid hundreds of millions of dollars of excess costs that are directly attributable to reliance on the VCA method. That attitude of complacency is exemplified in DTE Gas Company’s initial brief. The Company’s main argument for continuing the

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VCA method is that the Commission has approved it in prior cases. The evidence demonstrates that DTE Gas Company has not met the

burden of proof described in the Commission’s order in Case No. U-17332 on the question of whether the VCA method is a reasonable and prudent approach to gas supply planning. It is time to curtail this formula-driven methodology. DTE Gas should be charged with using its resources to fully engage in exploring the options for securing the benefits of favorable prices in a stable natural gas market for a larger share of its supply mix.

RRC adds that, “[u]nlike DTE Gas Company, [its] witness engaged in a careful

analysis of current and forecasted market conditions and fundamental economic and

physical considerations that affected gas supply and prices in each of [the past five GCR

plan cases].” RRC Rep Br, p. 5. RRC argues that DTE Gas’ “suggestion that Mr.

Hollewa’s recommendations in this case are ‘not supported by careful, thoughtful, rational

and reasonable analysis’ . . . is baseless.” RRC Rep Br, p. 5.

RRC recommends that the Commission “[c]urtail DTE Gas Company’s VCA

method consistent with the recommendations made by RRC witness Hollewa”.

iii. Attorney General

“The Attorney General contends that Mr. Hollewa has presented cogent testimony

supporting his recommendation, and the Attorney General supports adopting his

recommendation.” AG Rep Br, p. 6. At AG Br, p. 19, the Attorney General adds:

The Company’s justification is that the program will mitigate price uncertainty (4 T 253); however, the Company has presented no evidence demonstrate that making fixed price purchase at futures prices for deliveries instead of having quantifiable evidence to support a conclusion that the futures prices will not significantly exceed purchase at market price nearing to the time deliveries will be made.

At AG Br, p. 20, the Attorney General states:

Historically, this method has resulted in actual costs that have exceeded market prices at the time of delivery. It may be true that standing alone historical experience will not necessarily accurately provide an

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accurate prediction of future results, but continuing to use the same method and expecting different results can be accurately described as illogical.

c. Discussion

Clearly, DTE Gas’s recent VCA gas purchasing practices has, when compared to

the alternative of spot purchases, resulted in increased costs to its customers. Though

not entirely clear, the reason appears to be linked to the decade long trend of decreasing

natural gas spot market prices20. That trend has been interrupted by the occasional price

spike, most notably the late 2005 price spike related to hurricanes Katrina and Rita, the

summer 2008 price spike generally linked to rising energy prices across all sectors, and

the price spike related to the historically cold winter of 2014. It is these spikes that DTE

Gas argues it must protect its customers from by implementation of its VCA gas

purchasing policy

DTE Gas argues that its purchasing policy should and does mitigate the impact of

market price fluctuations, allow participation in downward price movements, protect

customers against upward price movements, and utilize a prescriptive methodology that

limits speculation and is not overly complex. DTE Gas’ claims appear exaggerated.

Certainly, DTE Gas’ purchasing strategy smooths out the usual ups and downs of

the natural gas market. However, to date, it has done so at a significant cost to its

customers in the form of higher rates. As for allowing participation in downward price

movements, its strategy permits this, but it does so no more and, possibly less, than

purchasing at index prices.

20 Also, possible is that DTE Gas’ VCA purchases have some sort of built in bias for higher prices. The parties do not clearly explain the reasons DTE Gas’ purchasing practices have proven so expensive for its customers.

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DTE Gas’s claim that its purchasing policy protects customers from upward price

movements is, at best, overstated. Rather, during upward price movements, DTE Gas

makes gas purchases, regardless of the circumstance. For sustained upward price

movements, DTE Gas’ purchasing practices will, over time, incorporate those increased

costs on, at best, a delayed basis. Quite simply, regardless of whether there are

downward of upward moving prices, DTE Gas’ VCA purchasing policy requires it to

purchase gas and its customers fully participate in those price movements. Even during

temporary upward spikes, regardless of the reason for them, DTE Gas’ policy is to

purchase gas and to pass that cost on to its customers, albeit with a significantly muted

effect on its customer’s price. Thus, while purchasing gas over an extended period of

time in advance of the GCR year may lessen the effects of the oscillations in the price of

gas, the record does not establish that, over the long haul, this purchasing strategy

meaningfully protects customers from upward price movements.

DTE Gas correctly points out that its VCA purchasing methodology limits

speculation. As it applies to the actual purchases, this is true. In fact, it eliminates it.

Unfortunately, it also eliminates the utilization of educated professional judgement and

discretion in purchasing decisions. Finally, it is clear that DTE Gas’ purchasing strategy

is not overly complex. Rather its simplicity is abundantly apparent, however in this case,

simplicity is not necessarily a virtue.

As for the parties’ arguments regarding the stability and volatility of the market, it

appears that the degree of stability and/or volatility of the natural gas market is largely in

the eye of the beholder and the time frame under analysis. Thus, characterizing the

natural gas market as stable or volatile is of limited usefulness. However, one thing is

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clear. Over the past decade, gas prices have generally been in decline with occasional,

rare, and unforeseen events that cause short term price spikes. Further, future supply

both in quantity and diversity of source has never been greater. Planned pipeline

expansion will, no doubt, bring greater supplies of Appalachian gas to the Midwest region

and lessen the likelihood of future price spikes. Thus, considering these factors and the

likelihood of increased future demand, it appears that the natural gas market will continue

to be characterized by relatively low prices with a reduced likelihood of price spikes

caused by weather related events. Therefore, DTE Gas’ contention and concerns about

future volatile markets appears no more likely, and quite possibly less likely, than Mr.

Hollewa’s assertion regarding stability in the market.

Not convincing is DTE Gas’ chastisement of Mr. Hollewa’s evidentiary presentation

to show that future performance of DTE Gas’ VCA purchasing policies will be the same

as its dismal historical performance. While DTE Gas’s argument may be correct, it is

none-the-less unpersuasive. It does, however, highlight the fact that DTE Gas’

presentation suffers in the same defect. DTE Gas fails to establish that its future

performance will be any different than its past performance and it is DTE Gas’ burden to

prove its Plan reasonable, not Mr. Hollowa’s burden to prove it is not.

At Application of DTE Gas Co, U-17332, Order, p. 5-6 (April 23, 2015), the

Commission stated:

Just as natural gas markets are not stagnant, the VCA method should be evaluated over time from a cost and risk mitigation standpoint. . . . With each GCR plan case filing, the Staff reviews the use of the VCA method for reasonableness and prudence. The Commission has approved plans incorporating the VCA method for GCR plan years 2011-2014 . . . . [However], the Commission has neither approved nor endorsed the 75% FPP target. [Again], the Commission does not approve or endorse it in this case . . . . The Commission reiterates that . . . the burden continues to be

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on DTE Gas to manage risk and to facilitate the affordability of the natural gas sold to GCR customers. The Commission . . . wants to ensure that, over time and under a variety of actual and potential market and operating conditions, the benefits of price stability to the GCR customers outweigh any additional cost associated with the procurement strategy. Accordingly, the Commission expects DTE Gas to address the risk mitigation costs and benefits under different conditions and . . . provide a robust presentation on current and forecasted market conditions and fundamental economic and physical considerations that affect gas supply and prices, and to demonstrate the reasonableness and prudence of the company’s strategy in future GCR plan and reconciliation proceedings.

As in past cases, DTE Gas has failed to carry its burden of proof regarding the

reasonableness of its VCA gas purchasing strategy. DTE Gas proposes to continue the

use of a purchasing mechanism that gives no consideration to market conditions and

insulates the company from criticism by completely eliminating professional discretion

from its purchasing decisions. DTE Gas’ mechanical purchasing process clearly

moderates the effects of short term gas price swings, but it has done so at a significant

cost. DTE Gas argues that it is worth paying these higher gas costs because it helps

keep the price of gas stable; albeit at a higher cost. However, DTE Gas fails to examine

other mechanisms for cost swing moderation and fails to convince that the increased cost

of fuel is worth that increased likelihood of stability of price. Further, while it would appear

that a decade long general decline in natural gas prices is responsible to the excess cost

generated by its purchasing practices, DTE Gas fails to address whether other forces

explain its higher gas prices and ignores other purchasing arrangements that might be

used to lower its gas costs.

Based on the record presented, DTE Gas’ VCA purchasing policy is again not

approved. In future plan cases, DTE Gas should present an evaluation of the VCA, from

a cost and risk mitigation standpoint, and should explore and explain alternatives or

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modifications that might help to reduce natural gas costs. As previously instructed, DTE

Gas must present, for Staff review, evidence that addresses the VCA’s risk mitigation

costs and benefits under different conditions and that provides a robust presentation on

the conditions that effect gas supply and prices. In addition, DTE Gas should present

evidence on how more complex purchasing policies might work to reduce costs.

4. ANR-ALPENA Costs

a. Facts

Exhibit A-9 provides a summary of DTE Gas’ interstate transport currently under

contract. Included in the exhibit is Contract No. 112065 with ANR Pipeline for

transportation from Alliance to Alpena. As related to Contract No. 112065, a note on

Exhibit A-9 indicates that DTE Gas plans to allocate the costs with all 50,000/d winter

capacity and 20,000/d summer capacity to Distribution Rates with the remaining 30,000/d

summer capacity allocated for recovery in the GCR Plan. Exh A-9. The cost of the

additional 30 MDth/day is $963,908 and DTE Gas seeks to recover this amount in this

GRC Plan. 5 Tr 840.

In Case No. U-16999, the Commission issued an order approving a partial

settlement agreement between Staff, the Attorney General, Mich-Con, RESA, ABATE,

Encana Oil & Gas, and MCAAA. In the order, at App of Mich Consolidated Gas Co,

U-16999, Order Approving Partial Settlement Agreement, p. 2, (Dec 20, 2013), the

Commission stated, in part, that:

The parties . . . agree that this rate increase is based on . . . the inclusion of the operations and maintenance expense associated with the ANR transportation agreement used to serve the company’s Alpena market and Mich Con’s agreement that it shall take a position in future gas cost recovery reconciliation (GCR-R) proceedings that prevents double-recovery

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of this expense.

At App of Mich Consolidated Gas Co, U-16999, Order Approving Partial Settlement

Agreement, Exh A, p. 2, (Dec 20, 2013), the agreement itself stated, in part:

The Parties agree that the annual revenue increase of $19.9 million . . . reflects, on a non-precedential basis, the following findings and actions: . . . (c) Inclusion of the Operations and Maintenance expense (“O&M”) associated with the ANR transportation agreement used to serve the Company’s Alpena market and MichCon’s agreement that the Company shall take a position in future GCR reconciliation proceedings that prevents double recovery of this ANR transportation expense.

At the time of the settlement, the ANR transportation agreement was ANR Alpena

Contract No. 117263. 4 Tr 325. 5 Tr 837. As explained by Mr. Coppola, at 5 Tr 837-38:

The ANR-Alpena transportation contract was addressed in the Company’s last General Rate Case U-16999. In that case, the Company proposed that the cost of the ANR-Alpena transportation (Contract #117263) should be removed from the GCR cost recovery mechanism and included as an O&M expense in base rates. The Company’s reasoning for removing this cost from the GCR was that the ANR-Alpena transportation in effect should be considered an extension of its own transmission system in order to connect its storage facilities at the Woolfolk station to the Alpena gate station. The parties of the rate case settlement agreement agreed to this change and the Commission approved it in its order dated December 20, 2012.

Contract No. 117263 was amended, effective April 1, 2013, expired on December

31, 2013, and was replaced with the current ANR Alpena contract, Contract No. 122065.

4 Tr 325. Contact No. 122065 adds an additional 30 MDth/d capacity in the summer,

resulting in a full 50 MDth/d capacity year round. At 5 Tr 839-40, Mr. Coppola provides

his opinion that:

Contract #122065 is really the same as contract #117263 which it replaced. [DTE Gas] decided to expand the summer capacity of the ANR-Alpena contract, but that change does not alter the basic purpose the contract between the Company and ANR. The purpose of the transportation agreement is to serve as an extension of the Company’s gas transmission system and that premise has not changed, only the amount of capacity has

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changed. . . . The [Exh AG-1]21 discovery response reaffirms the point that the

transportation arrangement serves the ultimate purpose of moving gas into the Alpena gate station through various means.

* * *

[DTE Gas] is attempting to recover through the GCR mechanism costs that properly belong in base rates as ordered by the Commission in Case No. U-16999.

Mr. Coppola recommends removal of the $963,908 of ANR-Alpena costs from the

GCR plan. 5 Tr 840.

In rebuttal, at 4 Tr 323-25, Mr. Lawshe responded by testifying that:

Witness Coppola’s recommendations should not be approved and the reasons he uses to support those recommendations are flawed. The contract covered by the settlement in Case No. U-16999 was for 50,000 Dth/day in the winter and 20,000 Dth/day in the summer from the Company’s Woolfolk station to Alpena. The rationale for moving the costs of this contract from the GCR to base rates is that the contract was used to move gas from the Company’s storage facilities through Woolfolk and across ANR to Alpena where it would serve customers. The [Attorney General] argued that this was more of a system integration; much like the Company’s distribution systems. Therefore, the costs were more appropriately recovered through O&M. The Company segments the current contract of 50,000 Dth/day of annual capacity of which the full 50,000 Dth/day segment from Alliance to Woolfolk, a segment not covered in the original contract, is needed and used for GCR system supply while the remaining segment from Woolfolk to Alpena is used 50,000 Dth/day winter and 20,000 Dth/day summer for system integration to connect it storage facilities at the Woolfolk station to the Alpena gate station. Accordingly, to avoid double recovery of costs, the costs of the capacity are likewise segmented consistent with the MPSC’s 2012 Order in Case No. U-16999, with base rate recovery of the costs associated with the system integration capacity of 50,000 Dth/day winter and 20,000 Dth/day summer, and the remaining costs attributable to the 30,000 Dth/day summer capacity is recovered through the GCR mechanism.

* * *

The Company expanded the summer capacity of the ANR-Alpena contract, but the purpose of the expansion was for GCR system supply and not, as purported by Witness Coppola, to serve as an extension of the

21 Exhibit AG-1, is a discovery response, in which DTE Gas describes the gas flows provided under Contract No. 122065.

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Company’s gas transmission system in order to connect its storage facilities at the Woolfolk station to the Alpena gas station. Specifically, DTE Gas replaced its 50,000 Dth/day forward haul transport on Great Lakes Gas Transmission with this 50,000 Dth/day of forward haul transport on ANR from Alliance to ANR-Alpena . . . .

Mr. Lawshe further explains that the new contract provides greater flexibility with

its receipt point at Alliance, rather than Woolfolk. 4 Tr 477. Under the old contract, DTE

Gas had a receipt point of Woolfolk so only its storage fields could deliver into ANR.

4 Tr 477. Now, under the new contract, the receipt point is at the Chicago area

interconnect with Alliance. 4 Tr 477. This provides DTE Gas not only the ability to deliver

from its Woolfolk storage facility, but also gives DTE Gas the ability to purchase up to

50,000 dths/day of gas for delivery at Alliance and transport to Alpena. 4 Tr 477.

Mr. Lawshe explains at 4 Tr 483 that:

During the summertime, . . . 20,000 of the capacity continues to stay in base rates. And then the additional 30 that we got in the summertime is in cost of gas, because it was secured for gas supply reasons.

The $964,000 is the marginal cost of receiving an additional 30,000 dths/day

during the summer months. 4 Tr 494.

Notice is taken of Exhibit AG-6 from Case No. U-171131-R which has been

attached to the Attorney General’s brief. The exhibit explains that:

The amendment to the ANR Contract No. 117263 that took effect 4/1/2013 changed the receipt point to ANR Alliance to expand the contract for dual purposes at no additional costs, thereby providing the additional purpose of gaining access to purchase gas supply at Alliance, while maintaining the original purpose of system integration between Woolfolk and Alpena. DTE Gas does not have a December 2014 amended contract. Instead DTE Gas has a new ANR Contract No. 122065 effective January 1, 2014 that provides for the continuation of transportation service originally contained in ANR Contract No. 117263 for 50,000 Dth/day winter capacity and 20,000 Dth/day summer capacity from Woolfolk (AKA Detroit A&B) to Alpena, but also provides for receipts at ANR Alliance, and provides for an additional 30,000 Dth/day of summer capacity. This new contract has the

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dual purpose of providing access to purchase gas supply at Alliance, while maintaining the original purpose of system integration between Woolfolk and Alpena, but now also increases the MDQ and associated transport reservation costs during the summer by 30,000 Dth/day for the sole purpose of expanding the access to GCR purchase gas supply at Alliance.

b. Positions of the Parties i. Attorney General

The Attorney General argues that “the contract changes did not alter the basic

purpose of the contract between the Company and ANR, which was agreed upon in

U-16999 to serve as an extension of the Company’s gas transmission system with

reservation charges being included and recovered in base rates.” AG Br, p. 18. The

Attorney General recommends that the Commission “remove the additional $963,908 for

ANR reservation charges because those charges should be recovered via base rates

under DTE Gas Company’s proposal in U-16999 and the final order in that case. It is

neither just nor reasonable to split the recovery classification for the ANR reservation

charges based upon the record evidence. There is no dispute regarding recovery of

ANR’s commodity and fuel charges as GCR expenses.” AG Br, p. 19.

The Attorney General argues that its exhibits, AG-3, AG-4, and AG-6, refute DTE

Gas’ “claim that contractual changes justify re-assigning part of the recovery of ANR

capacity charges as GCR expense.” AG Rep Br, p. 8. At AG Rep Br, p. 8-9, the Attorney

General explains:

Page 6 in Exhibit AG-3 provides for ANR to receive gas from DTE Gas near DTE Gas Company’s Woolfolk storage facility with an agreement that DTE Gas will receive gas from ANR at Alpena delivery points. The sole change adopted in Exhibit AG-4 was to change ANR’s receipt point to Alliance as stated in pages 2-3 of Exhibit AG-4. Page 6 in Exhibit AG-6 identifies an annual 50,000 MDQ entitlement instead of a 50,000 MDQ winter entitlement and a 20,000 MDQ summer entitlement. Page 6 in

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Exhibit AG-6 indicates ANR will continue to receive gas from DTE Gas at the ANR interconnect at Alliance and DTE GAS will receive gas from ANR at Alpena delivery points.

In other words, contract changes did not alter the basic purpose of the contract between the Company and ANR, which was agreed upon in U-16999 to serve as an extension of the Company’s gas transmission system with capacity charges being included and recovered in base rates.

ii. DTE Gas

DTE Gas considers the Attorney General’s “reliance upon Mr. Coppola’s

misinterpretation of the Commission’s U-16999 Order” to be “misplaced”. DTE Gas Rep

Br, p. 42. At DTE Gas Rep Br, p. 43-44, DTE Gas notes that:

The Commission’s U-16999 Order expressly states . . . : “The parties further agree that this rate increase is

based on…(3) the inclusion of the operations and maintenance expense associated with the ANR transportation agreement used to serve the company’s Alpena market and [DTE Gas’s] agreement that it shall take a position in future gas cost recovery reconciliation (GCR-R) proceedings that prevents double-recovery of this expense…”58 (Emphasis added.) The U-16999 Order simply reflects the U-16999 Settlement

Agreement, which states in pertinent part that: “The Parties agree that the annual revenue increase of

$19.9 million stated in paragraph 1 reflects, on a non-precedential basis, the following findings and actions…(c) Inclusion of the Operations and Maintenance expense (“O&M”) associated with the ANR transportation agreement used to serve the Company’s Alpena market and [DTE Gas’s] agreement that the Company shall take a position in future GCR reconciliation proceedings that prevents double recovery of this ANR transportation expense.”59 (Emphasis added.)

At DTE Gas Rep Br, p. 47-48, DTE Gas contends that:

There is no merit to the AG’s opposition to DTE Gas’s recovery of the costs for this incremental 30,000 Dth/day summer capacity under Contract #122065 via GCR for several reasons. First, the incremental 30,000 Dth/day summer capacity was for GCR system supply and not for extending DTE Gas’s transmission system. The change in primary receipt

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point from Detroit A/B to Alliance allows the Company to deliver gas supply purchased at a market hub near Chicago to DTE Gas’s system, which is clearly a supply function and not a system integration function as was the original ANR Alpena contract. Second, obtaining the incremental 30,000 Dth/day summer capacity was necessary to replaced expiring GCR interstate transport capacity on Great Lakes Gas Transmission Pipeline. Third, obtaining the incremental 30,000 Dth/day summer capacity as part of Contract #122065 instead of under a separate contract as suggested by Mr. Coppola actually saves customers approximately $1.7 million per year in GCR costs. (4T 324-327; Exhibit A-41, column (l)) Finally, recovering the incremental 30,000 Dth/day summer capacity via GCR does not violate either the letter or the spirit of the U-16999 Settlement Agreement since DTE Gas is still charging the costs for 50,000 Dth/day winter capacity and 20,000 Dth/day summer capacity used for system integration (from Woolfolk to Alpena) to O&M (4T 324-327).

c. Discussion

DTE Gas’ arguments on this issue are supported by the facts and are persuasive.

In Case No U-16999 the Commission approved the inclusion of capacity costs from

Contract No. 117263 in O & M under the party’s stipulation that this capacity represented

an extension of DTE Gas’ transportation system from Woolfolk to Alpena. This contact

was later amended to make the receipt point the ANR/Alliance interconnect near Chicago.

At no additional cost to DTE Gas’ customers, this arrangement allowed DTE Gas to

deliver gas purchased at the ANR/Alliance interconnect, maintained the extension of DTE

Gas’ transportation system from Woolfolk to Alpena, and contributed to DTE Gas’

transportation flexibility22. This amended contract was replaced by Contract #122065

22 As explained by Mr. Lawshe, in Exhibit AG-1:

[T]he receipt point for the ANR Alpena Contract No. 122065 is at the Alliance interconnect between ANR and Alliance Pipeline located near Chicago, Illinois, and the delivery point is the Alpena interconnect between ANR and DTE Gas in Clare County, Michigan. The gas flows from the higher pressure Alliance Pipeline system into the lower pressure ANR transmission system at the Alliance interconnect, and an equivalent quantity if gas flows from the higher pressure ANR transmission system into the lower pressure DTE Gas transmission system at the Alpena Interconnect. Alternatively, at the request of DTE Gas, the gas flows from the . . . Alliance Pipeline system into the . . . ANR transmission system, [and] into the lower pressure DTE Gas transmission system as the Woolfolk

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which maintained all the advantages of the ANR/Alliance interconnect receipt point and

added an additional 30,000 Dth/day summer capacity at the added cost of $963,908. The

added expense appears reasonable. The contention, however, is that DTE Gas should

not be able to include this amount as a GCR expense.

As already noted above, at 4 Tr 324, Mr. Lawshe explained that:

The Company segments the current contract of 50,000 Dth/day of annual capacity of which the full 50,000 Dth/day segment from Alliance to Woolfolk, a segment not covered in the original contract, is needed and used for GCR system supply while the remaining segment from Woolfolk to Alpena is used 50,000 Dth/day winter and 20,000 Dth/day summer for system integration to connect it storage facilities at the Woolfolk station to the Alpena gate station. Accordingly, to avoid double recovery of costs, the costs of the capacity are likewise segmented consistent with the MPSC’s 2012 Order in Case No. U-16999, with base rate recovery of the costs associated with the system integration capacity of 50,000 Dth/day winter and 20,000 Dth/day summer, and the remaining costs attributable to the 30,000 Dth/day summer capacity is recovered through the GCR mechanism.

This allocation of costs is reasonable. By allocating only a portion of the costs for recovery

via the GCR mechanism, DTE Gas avoids double recovery, as was agreed to in Case

No. U-16999. Further, while expanding summer capacity and providing flexibility to DTE

Gas’ transportation network, the contract fulfills the original goals of the Contract No.

117263 and expands DTE Gas’ access to needed supplies of natural gas. While the

Attorney General’ attention to this issue is appreciated and his arguments are not without

merit, DTE Gas’ handling of this expense is reasonable, complies with the settlement

agreement from Case No. U-16999, and is approved as part of the Plan.

interconnect . . . . As another alternative, at the request of DTE Gas, the gas flows from the higher pressure DTE Gas transmission system into the lower pressure ANR transmission system at the Woolfolk interconnect, and . . . into the . . . DTE Gas transmission system at the Alpena interconnect.

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5. FIRM PARKING

a. Findings of Fact

During the ungodly cold winter of 2013-14, DTE Gas “discovered that its storage

facilities did not perform to the expected level of the winter design day plan.” 4 Tr 202.

“DTE Gas concluded that there is a deliverability requirement of 301 MMcf/d needed to

meet the needs of both GCR and GCC for an end of March design day”. 4 Tr 202.

At the time of the filing of this case, DTE Gas’ Witness, Ms. Moore explained, at

4 Tr 203:

DTE Gas’ 71.9 Bcf of the 2015-16 winter cycleable storage capacity will be achieved for the 2015-16 winter with the purchase of a 4.8 Bcf parking service. 23 This parking service will maintain a cycleable storage capacity of 71.9 Bcf for the GCR/GCC customers, and provide on March 31, 2016, an additional 301 MMcf/d of deliverability necessary to achieve the deliverability requirement to serve the GCR/GCC customers.24

23 As explained below, on July 9, 2015, DTE Gas executed a 2.1 Bcf parking service contract rather than the projected 4.8 Bcf parking service. 24 At 4 Tr 203-04, Ms. Moore explained:

The 4.8 Bcf parking service (or “Park”) is a transaction that consists of DTE Gas paying a counterparty to park (i.e. store) gas in the DTE Gas storage facility for a specified amount of time. The contract defines the following: how much gas the counterparty will deliver into the DTE Gas system, at what locations and flow rate the gas is delivered, the period over which the gas is delivered into the system, when and where the counterparty can withdraw their gas from the DTE Gas system and at what rates of flow, and the price or cost for performing the Park.

* * * The 4.8 Bcf Park will be delivered into the DTE Gas system over the December

2015 through March 2016 period at the rate of 40 MMcf/d. Consequently, this Park will increase the total amount of gas in the DTE Gas storage field at the end of March 2016 by 4.8 Bcf. This 4.8 Bcf of additional gas in storage will create sufficient field pressures necessary to do both of the following: (a) allow DTE Gas to withdrawal (i.e. cycle) up to a total of 71.9 Bcf of gas from storage to serve the GCR/GCC customers over the winter withdrawal period, and (b) provide an additional 261 MMcf/d of storage field deliverability. The additional 261 MMcf/d of storage field deliverability, combined with the additional 40 MMcf/d of deliveries into the DTE Gas system from the Park service, provides 301 MMcf/d of deliverability necessary to achieve the GCR/GCC March 31st design day deliverability requirement.

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DTE Gas witness, Mr. Lawshe testified that when selecting this parking service,

DTE Gas primarily considered “supply reliability, cost and price risk.” 4 Tr 277. He added

that the “4.8 Bcf firm parking service was the only alternative that met all of these

requirements.” 4 Tr 277. The total cost of the Park that DTE Gas was originally planning

to purchase was estimated at $4,646,400. 2 Tr 277. DTE Gas plans to roll the cost of

the Firm Parking Service into the Reservation Charge.25 4 Tr 253, 276.

On behalf of the RRC, Mr. Hollewa analyzed DTE Gas’ Parking Service proposal

and provided testimony questioning the reasonableness of the service and its expense.

5 Tr 813, 816-29. Mr. Hollewa presented two alternatives. First, he recommended that

DTE Gas “reduce the amount of storage dedicated to Storage Service Sales unless the

Company can prove . . . that the 4.8 Bcf of Storage Service Sales is equal to or greater

than the cost of the Parking Service.” 5 Tr 821. Second, he recommended that, “in the

event that the . . . Storage Service Sales do . . . provide a greater financial benefit”, then

DTE Gas should make “additional purchases with the utilization of unused firm

transportation (FT) during Normal weather.” 5 Tr 823. It was Mr. Hollewa’s opinion that

the Commission should disallow the increased costs of DTE Gas’ plan over his

alternatives. 5 Tr 828-29.

In rebuttal, DTE Gas’ witness, Ms. Moore, indicated that DTE Gas had not

executed the 4.8 Bcf parking service, but rather, on July 9, 2015, a more modest 2.1 Bcf

parking service was purchased for the considerably lower cost of $900,000. 4 Tr 231.

25 As explained by Mr. Lawshe, at 4 Tr 278:

This parking service is necessary to achieve the peak day deliverability from the Company’s storage fields that is required to serve both GCR and GCC customers on a design-day. Therefore, DTE Gas is proposing that both GCR and GCC customers pay for their load proportionate share of the cost that DTE Gas incurs for this firm Parking Service in the same manner as GCR and GCC customers pay for their load proportionate share of the cost that DTE Gas incurs for firm interstate transportation capacity.

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This service will involve the delivery of 70 MMcf/d from December 1, 2015 through

December 31, 2015 and the withdrawal of 10 MMcf/d from April 1, 2016 through October

31, 2016. 4 Tr 231. At 4 Tr 231, Ms. Moore explained that:

The 4.8 Bcf parking service was an estimate based on the best available information at the time of the 2015-16 GCR Plan filing in December 2014. Subsequently, the Company updated its requirements, and based on the most recent details for the winter 2015-16, the deliverability requirement is 2.1 Bcf.

b. Positions of the Parties

DTE argues that this service “was purchased as the most reasonable and prudent

alternative to achieve the projected storage deliverability requirements and to meet the

peak day needs of the GCR and GCC customers. The primary factors that DTE Gas

considered when selecting this firm parking service were supply reliability, cost and price

risk. The firm parking service was the only alternative that met all of these requirements”.

DTE Gas Br, p. 28. DTE Gas notes that it “did not execute the 4.8 Bcf Park . . . but,

“[i]nstead, . . . executed only a 2.1 Bcf Park . . . for a cost of only $0.9 million.” DTE Gas

Br, p. 28-29. DTE Gas argues that “[s]ince this parking service is necessary to achieve

the peak day deliverability from the Company’s storage fields that is required to serve

both GCR and GCC customers on a design day, DTE Gas is proposing that both GCR

and GCC customers pay for their load proportionate share of the cost that DTE Gas incurs

for this firm Parking Service in the same manner as GCR and GCC customers pay for

their load proportionate share of the cost that DTE Gas incurs for firm interstate

transportation capacity”. DTE Gas Br, p. 29.

After reviewing portions of the record, the Attorney General argues that the

“evidence supports a conclusion paying $4.6 million for parking service to protect against

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the need to provide additional supplies during CTN weather could be accomplished at a

lower cost”. AG Br, p. 20-22. Thus, the Attorney General takes the position that the

Commission “should adopt Mr. Hollewa’s recommended disallowance.” AG Br, p. 22.

In reply to the Attorney General’s arguments, DTE Gas indicated that they consider

the issue moot because the “evidentiary record shows that DTE Gas is only seeking

recovery for a 2.1 Bcf Park . . . at a cost of $0.9 million”. DTE Gas Rep Br, p. 39-40.

c. Discussion

The Attorney General’s position appears based on a reading of the record that

overlooks the fact that, rather than the originally envisioned Park of 4.8 Bcf, at a cost of

$4,600,000, DTE Gas executed a Park of 2.1 Bcf at the vastly reduced cost of $900,000.

By overlooking these facts, the Attorney General’s recommendation is based upon

circumstances that do not exist.

There being no other objections to DTE Gas’ request on this issue and the expense

otherwise appearing reasonable, DTE Gas’ Park expense of $900,000 is approved.

III.

CONCLUSION

The proposed Plan and Five-Year Forecast meet the minimal filing requirements

found in MCL 460.6h(3) and MCL 460.6h(4).

In conformity with MCL 460.6h(7), the Commission has evaluated the decisions

underlying the Five-Year Forecast and it is accepted for filing.

In conformity with MCL 460.6h(6), the Commission has evaluated the

reasonableness and prudence of the decisions underlying the Plan. Except as otherwise

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explained, above, the decisions underlying the Plan and the Plan, itself, are found to be

reasonable and prudent.

For the reasons stated and as amended, above, the Application is approved.

Any evidence and arguments not specifically addressed in this Proposal for

Decision were deemed irrelevant to the findings and conclusions of this matter.

MICHIGAN ADMINISTRATIVE HEARING SYSTEM For the Michigan Public Service Commission _____________________________________ Mark D. Eyster Administrative Law Judge

ISSUED AND SERVED: July 7, 2016