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 ELECTRIC COMPANY for authority ) Implement a Power Supply Cost Recovery ) Case No. U-18143 plan and factors for the 12-month period ) ending December 31, 2017. ) _____________________________________ )

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 November 1, 2017.

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 November 22, 2017, or within such further period as may be authorized for filing

exceptions. If exceptions are filed, replies thereto may be filed on or before December 6,

2017. 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 E. Cummins Administrative Law Judge

November 1, 2017 Lansing, Michigan

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

MICHIGAN ADMNISTRATIVE HEARING SYSTEM

FOR THE MICHIGAN PUBLIC SERVICE COMMISSION

* * * * * In the matter of the application of ) DTE ELECTRIC COMPANY for authority ) Implement a Power Supply Cost Recovery ) Case No. U-18143 plan and factors for the 12-month period ) ending December 31, 2017. ) _____________________________________ )

PROPOSAL FOR DECISION

I.

HISTORY OF PROCEEDINGS

On September 30, 2016, DTE Electric Company (DTE) filed an application--complete

with supporting testimony and exhibits--requesting approval of its power supply cost recovery

(PSCR) plan and factors for the period of January 1 through December 31, 2017, pursuant

to Section 6j, et seq., of 1982 PA 304 (Act 304), as amended, MCL 460.6j, et seq. As set

forth in its application, DTE requested that it be allowed to assess its PSCR customers a

maximum PSCR factor of 2.14 mills per kilowatt-hour (kWh) during that 12-month period.

Pursuant to due notice, a prehearing conference was held in this matter on

November 21, 2016, before Administrative Law Judge Mark E. Cummins (ALJ). In addition

to DTE and the Commission Staff (Staff), several potential intervenors also filed appearances

and participated at the prehearing. Intervention was granted on that date to the following

parties: the Department of Attorney General (Attorney General); the Association of

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Businesses Advocating Tariff Equity (ABATE); the Great Lake Renewable Energy

Association and the Residential Customer Group (jointly, GLREA); and the Michigan

Environmental Counsel and the Sierra Club (jointly, the MEC). In addition, a schedule

covering the remainder of the case was also established in the course of that prehearing.

Consistent with that schedule, the Attorney General, MEC, and GLREA filed their

direct testimony and accompanying exhibits on March 22, 2017, and rebuttal evidence was

submitted by DTE on April 24, 2017. During the intervening period (specifically, on April 18,

2017), the ALJ heard, and subsequently denied, MEC’s motion for partial summary

disposition regarding the inclusion of the NEXUS Pipeline and any related costs as part of

DTE’s 2017 PSCR cost recovery.1

Also in accordance to the parties’ consensus schedule, evidentiary hearings were

conducted on May 16 and 17, 2017 (although the hearing set for May 18, 2017 was cancelled

in light of the fact that there were no further witnesses to cross-examine). In the course of

those hearings, testimony was received from a total of 13 witnesses, nine on behalf of DTE,

two from MEC, and one each from GLREA and the Attorney General. The resultant record

consists of 4 volumes of transcript totaling 695 pages, as well as 132 exhibits, each of which

was received into evidence (albeit, with some of them given confidential treatment pursuant

to a protective order dated February 23, 2017) . Following the close of the record, each of

1 In essence, the ALJ agreed with arguments expressed by DTE and the Staff that testimony regarding the NEXUS Gas Transmission (NEXUS) Pipeline should be allowed in this proceeding, simply in case the pipeline’s actual construction and initiation of operations could be accomplished within the plan year. See, 2 Tr. 31-34. As addressed later in the Proposal for Decision (PFD), that was shown not to be the case.

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the parties filed briefs on June 12, and all parties except the Staff filed reply briefs on

July 10, 2017.2

II.

STATUTORY REQUIREMENTS

Subsection 6j(3) of 1982 PA 304, as amended, MCL 460.6j et seq., (Act 304) requires

a utility with a PSCR clause to annually file a complete PSCR plan describing the expected

sources of electric power supply and the changes in the cost of power supply anticipated

over a future 12-month period. Based on this information, the utility is to request specific

PSCR factors for each of the 12 months covered by its PSCR plan. The PSCR plan must

also describe all major contracts and power supply arrangements for the 12-month period.

Subsection 6j(4) of Act 304 requires the utility to file--contemporaneously with the

submission of its PSCR plan--a five-year forecast of its power supply requirements, its

anticipated sources of supply, and its projections of power supply costs, all in light of its

existing sources of electrical generation and sources of electric generation under

construction.

Subsection 6j(5) of Act 304 provides that, after a utility files its PSCR plan and

five-year forecast, the Commission is to conduct a proceeding to review the reasonableness

and prudence of the PSCR plan and to establish PSCR factors for the period covered by the

plan. It further provides that this review shall be conducted as a contested case proceeding

pursuant to Chapter 4 of the Administrative Procedures Act of 1969, 1969 PA 306, as

amended, MCL 24.201 et seq.

2 On June 6, 2017, DTE’s unopposed Motion to Correct the Transcript was granted by the ALJ.

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Subsection 6j(6) of Act 304 provides that, in its final order in a PSCR plan case, the

Commission shall evaluate the reasonableness and prudence of the decisions underlying the

utility’s plan and shall approve, disapprove, or amend the plan accordingly. In evaluating the

decisions underlying the utility’s plan, this subsection continues, the Commission shall

consider the cost and availability of the electrical generation open to use by the utility; the

cost of available short-term firm purchases; the availability of interruptible service; the ability

of the utility to reduce or eliminate any firm sales to out-of-state customers (if the utility is not

a multi-state utility whose firm sales are subject to other regulatory authority); whether the

utility has taken all appropriate steps to minimize the cost of fuel; and other relevant factors.

This subsection also provides that the Commission must, in its final order regarding the plan,

specifically approve, reject, or amend the 12 monthly PSCR factors requested by the utility.

Moreover, it demands that those factors shall not reflect any items that the Commission could

reasonably anticipate would be disallowed under Subsection 6j(13)--which sets forth the

criteria to be considered in a subsequent PSCR reconciliation concerning the 12-month

period covered by the plan in question.

III.

TESTIMONY AND POSITIONS OF THE PARTIES

DTE presented a combination of direct and rebuttal testimony, as well as related

exhibits, from its nine witnesses. These witnesses consisted of: (1) Michael D. Sloan, the

Managing Director of Energy Advisory Services for ICF, an energy consulting firm located in

Fairfax, Virginia, who testified regarding the potentially beneficial effects on energy markets

in Michigan, and for DTE in particular, arising from the construction and use of the NEXUS

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Pipeline (See, 3 Tr. 67-204); (2) Ryan C. Pratt, the Supervisor of Planning and Procurement

within DTE’s Fuel Supply Department, whose testimony was designed to both “support the

forecasted fossil fuel supply requirements and fuel supply plan” for DTE, as well as

summarizing how fuel requirements will likely change as the utility moves toward “more

gas-fired electric generation,” including the company’s contract with NEXUS (See, 3 Tr. 204-

309 and 4 Tr. 322-347); (3) David G. Nick, a Regulatory Compliance Consultant working for

one of DTE’s many aligned companies, DTE Energy Corporate Services, LLC, [DTE

Corporate] who presented DTE’s “projected expenses associated with being a network

transmission customer of ITC Transmission (ITC),” as well as “being a Market Participant of

the Midcontinent Independent Transmission System Operator (MISO)” (See, 4 Tr. 348-379);

(4) John O. Yurko, a senior technical specialist in DTE’s Generation Optimization

Organization, whose testimony focused on the projection of DTE’s “capacity, generation,

urea expense for Nitrogen Oxides (NOx) control and limestone expense for Sulfur Dioxide

(So2) control for the 2017-2021 period, as well as expected sales made into the MISO market

over that course of time (See 4 Tr. 381-467); (5) Kevin L. O’Neill, who also works for DTE

Corporate as a Principal Project Manager in its Regulatory Affairs Division and provided the

“calculation of the PSCR billing factors to be used for each month of 2017,” along with the

“projected average annual PSCR billing factors for the years 2018 through 2021” (See,

4 Tr. 468-488); (6) Shawn D. Bergdorf, the Supervisor of the Tactical Merchant Analytics

Team within DTE’s Generation Optimization Department, who provided testimony supporting

the projection of DTE’s “generation expense including emission allowance expense, and

purchase power expense,” as well as purchase power requirements and associated expense

to be used to develop the utility’s 2017 PSCR factor, in addition to testimony addressing

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similar expenses for the 2018-2021 period (See; 4 Tr. 489-515); (7) Barry J. Marietta, a

Manager in DTE Corporate’s Environmental Management and Resources/Air Quality

Services Division, who offered testimony and exhibits to both explain the company’s

compliance with the Mercury and Air Toxic Standards [MATS] emission limitations and the

various sorbent costs related to those activities, as well as information regarding the impact

of in-place environmental air regulations on DTE’s currently existing power plants (See,

4 Tr. 516-532); (8) James D. Wines, the Lead Engineer for the utility’s Nuclear Generation

Division, who provided evidence regarding “the five-year projection of [DTE’s] Fermi 2

nuclear fuel expense” (See, 4 Tr. 533- 547); and (9) Markus B. Leuker, the company’s

Manager of Corporate Energy Forecasting, whose testimony and exhibits were designed to

provide both DTE’s current “electric sales and system output forecast as of August 2016 for

the period 2016-2021, and to explain the basis for this forecast.” See, 4 Tr. 547-565.

Based on the testimony and exhibits provided from its nine witnesses, much of which

evidence is uncontroverted, DTE asserts that the Commission should find that: (1) the

company’s load forecast for the 2017 PSCR plan year is reasonable and prudent, (2) the

utility’s projections regarding its expenses with regard to electric generation, purchased

power, emission compliance, and all associated expenses for the 2017 PSCR year are

likewise reasonable and prudent, including the costs related to urea and limestone used for

NOx and SO2 control, (3) the company’s transmission and MISO-related expenses, as well

as its fuel supply plan for 2017, are also reasonable and prudent, particularly in light of the

effect on costs arising from the agreement related to the use of the NEXUS Pipeline, at least

once it is constructed, and (4) all of the costs associated with meeting the MATS standards

should be included in the PSCR factor approved in this case. See, DTE’s initial brief,

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pp. 12-29. For all of these reasons, DTE contends that its proposed 2017 PSCR plan and

its monthly factors are clearly reasonable and prudent, and thus should be approved by the

Commission, and that any requested warnings for subsequent non-recovery of expenses

addressed in this case made by other parties--pursuant to MCL 460.6j(7), and generally

referred to as Section 7 warnings--be denied. See, Id., pp. 29-30 and 37.

As noted earlier, two witnesses were offered by the MEC. The first was James F.

Wilson, an independent consultant operating Wilson Energy Economics. Mr. Wilson’s

testimony focused on the cost and potential effect of the NEXUS Pipeline with regard to

DTE’s operations, and thus, its customers. Specifically, Mr. Wilson testified that:

• “NEXUS would provide 1.5 million dekatherms per day (Dth/d) of natural gas transportation service from the Marcellus and Utica shale formations in Eastern Ohio and western Pennsylvania to markets in northern Ohio, Michigan, and Ontario, Canada, terminating at the Dawn Hub in Ontario;

• NEXUS is being developed by a company that is owned 50% by DTE’s affiliate, DTE Gas Storage & Pipeline Company (which is wholly owned by DTE), and 50% by an affiliate of Spectra Energy Partners, LP, recently acquired by Enbridge Inc.

• In [December] 2014, (DTE) entered into a Precedent Agreement with NEXUS, which, as amended September 2015 and May 2016, provides for 30,000 Dth/d of firm natural transportation service for twenty years beginning November 2017, and an optional, additional 45,000 Dth/d for fifteen years, to begin on the later of May 1, 2020 or when DTE places new gas-fired electric generating facilities in service. [citation omitted]. The Precedent Agreement contemplates a Rate arrangement that was entered into on September 14, 2016, and which specifies a reservation rate of $0.695 per Dth/d and a shrinkage adjustment (fuel charge) of 1.32%. [citation omitted].

• The Precedent Agreement commits DTE Electric to contract for this service subject to satisfaction of various conditions precedent. One condition precedent is in Section 7.b.v, “Customer’s purchase, lease, or construction of any or all Customer Facilities which Customer must purchase, lease, construct, or cause to be constructed, in order for Customer to utilize the Transportation Service contemplated in this Precedent Agreement,” which includes “At least one 680 MW [CCCT] facility with a 70% capacity factor or

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multiple CCCTs with lower capacity factors” and “Multiple CTs to support peak loads. These are in addition to the CCCT(s).”

• Another condition precedent is Section 7.b.i, “Customer’s receipt of a final, non-appealable order or approval of the MPSC that approves . . . Customers’ utilization of the Project and recovery of all Customer Costs . . . and expenses related to the Project from its customers in rates . . ..” While the Second Amendment to the agreement moved the deadline for this condition back to November 30, 2016, ultimately [DTE] waived this condition on December 1, 2016.

See, Id., pp. 572-573. With regard to the overall matter of timing, Mr. Wilson testified that it is “highly

uncertain” exactly when the NEXUS Pipeline would begin providing service. In this

regard, he pointed out that [at least at that time] “NEXUS has not received FERC

authorization, and at this time FERC lacks a quorum,” a fact that, Mr. Wilson continued,

DTE “has acknowledged.”3 “At this time,” he noted, “NEXUS has not officially updated

the target in-service date of November 1, 2017.” Id., p. 573. “However,” Mr. Wilson went

on to note, the November 1, 2017 date “becomes increasingly doubtful as time passes.”

Id.

The second witness presented by MEC was George E. Sansoucy, a consultant

specializing in the provision of valuation and engineering services to both public and

private utility entities. See, 4 Tr. 625. The focus of Mr. Sansoucy’s testimony was DTE’s

plan to continue operating a portion of its River Rouge coal-fired generating facility

(namely, Unit 3) throughout the PSCR plan year in question. According to him, although

the utility correctly retired Unit 2 of the plant in 2016, its plan to delay the retirement of

3 However, it bears noting that, subsequent to the submission of Mr. Wilson’s testimony on this issue, two new members were appointed to the FERC, and that the commission subsequently approved the construction of the NEXUS Pipeline in late August of 2017.

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Unit 3 until as late as May of 2020 would be uneconomic. See, Id., 630-631. Specifically,

Mr. Sancoucy testified that:

• With the retirement of River Rouge Unit 2, common plant costs that were previously divided between Units 2 and 3 are now borne solely by Unit 3.

• Actual capacity prices for the 2016/2017 delivery year are approximately 18% lower than the forecasted price DTE used in [the] July and August 2015 [net present value (NPV)] analyses [that it claims support the continued operation of Unit 3].

• Forecasted market energy prices at the time DTE decided to retire River Rouge Unit 2 were approximately 9 to 12% lower than the prices DTE used in its July and August 2015 NPV analyses.

Id., 631. Moreover, he noted that the significantly lower capacity prices for 2016 and 2017

would both (1) reduce the revenue that Unit 3 could earn in the MISO capacity sales market,

and (2) reduce the cost at which DTE could purchase capacity to replace that provided by

the continued operation of Unit 3. See, 4 Tr. 634-635.

Based largely on the testimony offered by Mr. Wilson, MEC contends that the

Commission “should reject [DTE’s] request for approval of NEXUS costs in 2017,” and that

it should also warn DTE that, “on the basis of present evidence, the Commission is unlikely

to permit recovery of costs” arising in the future from the utility’s involvement with the NEXUS

Pipeline. MEC’s initial brief, p. 68. Also, according to MEC, any long-term savings that are

alleged by DTE from its involvement in the NEXUS deal are beyond the scope of this Act 304

proceeding, and “are nevertheless based on speculation and flawed assumptions.” Id.,

p. 69. Also, in light of the testimony offered by Mr. Sancoucy, MEC argues that the

Commission should find that River Rouge Unit 3 “is likely uneconomic to operate,” and that,

as a result: (1) DTE should be cautioned that, in the reconciliation of this plan year case, the

Commission will disallow recovery of any part of the 2017 PSCR costs incurred by Unit 3

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“that is in excess of its market energy and capacity revenues,” and (2) issue a Section 7

warning to the effect that “future recovery of such excess costs for the period of 2018 through

2020” are also likely to be denied as well. Id., p. 87.

For its part, the Attorney General offered testimony from Sebastian Coppola, an

independent energy business consultant. As with the MEC’s first witness, Mr. Coppola

focused primarily on DTE’s requested recovery in this PSCR proceeding of costs relating to

the proposed purchase of 30,000 Dth/d of capacity from the NEXUS Pipeline beginning in

November of 2017, “after the planned completion and in-service date” of that facility.

4 Tr. 647. In this regard, he asserted that DTE failed to “fully consider alternative pipeline

suppliers,” and that the alleged cost savings arising from use of the NEXUS Pipeline “are

grossly overstated.” Id., 649.

Moreover, Mr. Coppola testified that DTE did not issue “formal proposals for pipeline

capacity” to either existing or potential pipeline capacity suppliers, as would “normally be

expected in such a situation where a large interstate capacity purchase is being considered.”

Id., 651. He further noted that, apparently after preliminary discussions with two major

competitors to the NEXUS Pipeline, namely ANR East Pipeline and Rover Pipeline, DTE did

not enter into any serious negotiations with either of those two entities, nor for that matter

with other interstate pipelines. See, Id. 651. According to Mr. Coppola, “requests for

proposals and serious negotiations would have clearly established whether or not [DTE]

could have obtained the same or better” rates or terms as ultimately provided under its deal

with NEXUS Pipeline. Id., 651. “Instead,” he continued, “by reaching an arrangement with

NEXUS [and thus DTE Gas and Storage Pipeline]” absent “the transparency of competitive

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bids,” the utility “has created the aura of a preferential deal to support a project sponsored

by an affiliate.” 4 Tr. 651-652.

Based on Mr. Coppola’s testimony, as well as much of the other information provided

on the record, the Attorney General primarily asserts that the Commission should issue an

order: (1) denying DTE’s request to purchase, and assign the cost to its customers, of 30,000

Dth/d of gas transportation capacity on the NEXUS Pipeline during 2017; (2) reducing the

utility’s proposed transportation costs for 2017; (3) denying any requests to approve costs

that will be incurred beyond the 2017 PSCR plan year; (4) issue a Section 7 warning to DTE

based on its failure to challenge the FERC’s “decision assigning all of the cost related to PAR

Transformers to the Company,” and (5) issue a second Section 7 warning regarding the

negative effect of coal and related fuel transportation costs on the utility’s PSCR factor. See,

Attorney General’s initial brief, pp. 3-4.

In addition, GLREA offered testimony and seven exhibits by way of its witness,

Geoffrey C. Crandall, the principal and Vice President of MSB Energy Associates, a utility-

focused consulting firm. The major concern raised by Mr. Crandall was that DTE’s five-year

plan “needs adjustment and improvement because the values used in reference to the

forecast” failed to include “estimates of commercial and industrial customer-owned solar

photovoltaic (PV) resources in DTE’s service territory” during the period covered by its five-

year plan. 3 Tr. 48. Specifically, although accounting for the increase in photovoltaic-based

electric generation from 0 to 58 gigawatt-hours (GWh) from 2016 to 2021 for its residential

customers, no such adjustments were made with regard to either DTE’s commercial or

industrial customers. See, 4 Tr. 49-51. According to Mr. Crandall, his concerns were based

on, but not limited to, the following factors:

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• Customer reliance on solar resources is increasing both nationally, state-wide, and on a local basis;

• The impacts of this trend of customers acquiring significant levels of solar resources should be reflected in DTE’s five-year PSCR plan and forecast;

• This expanded reliance on solar photovoltaic resources results, in part, from steadily decreasing costs of implementing and operating solar energy, and the steadily rising and persistent public interest this source of energy.

• Because the application of customer-owned solar PV represents an opportunity to diversify the energy supply, is should be readily fit into the portfolio of energy resources needed to provide reliable electric services;

• Solar energy aligns well offsetting the need for energy during peak times, normally within summer months, when solar energy is reliable and robust, and can ameliorate air conditioning loads, [as well as] other factors and other factors contributing to the system peak, when energy needs are normally the highest;

• Because customer-owned solar directly impacts and offsets costs that are reviewed in Act 304 PSCR cases [such as this], including, but not limited to, fuel, purchased power, and other costs, and can ameliorate peak demand (and associated costs) particularly during the summer months;

• Solar energy can enhance the reliability and efficiency of system operations, by reducing transmission or distribution line losses, or mitigating congestion on the system; [and]

• Further focus on increases investment on solar energy in Michigan can further encourage both direct and indirect development of the solar industry in Michigan, with employment in this industry.

3 Tr. 51-52. As a result, Mr. Crandall stated that the Commission should also require DTE

to include the effects of commercial and industrial PV resources in its PSCR plan for the next

five years. Id., pp. 53-55.

In light of Mr. Crandall’s testimony, GLREA contends that “DTE should now

undertake in this or the next PSCR plan and forecast case, further analysis” specifically

accounting for the effect on its Act 304 PSCR plan and five-year forecast costs of “customer-

owned solar facilities” that either have been, or are likely to be, constructed by its residential,

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commercial, and industrial customers during that period. GLREA’s initial brief, p. 7.

According to GLREA, the adoption of its recommendations in this case would not prejudice

any parties to this proceeding, and would rather appear to “complement DTE’s planning,” all

in a manner “consistent with Michigan’s new energy statutes.” Id., p. 8.

IV.

DISCUSSION AND FINDINGS

Several of the major areas of dispute that tend to arise in the course of a PSCR plan

case such as this are absent in the proceeding before us. However, seven specific issues

must be addressed here. These are: (1) the 2017 load forecast; (2) DTE’s transmission- and

MISO-related expenses for 2017; (3) the overall cost of generated and purchased power,

including the cost of NOx and SO2 compliance activities; (4) the expenses related to operation

of River Rouge Unit 3, including urea and limestone expense used to reduce the pollutants’

effect on the environment; (5) two proposed Section 7 warnings regarding PAR transformer

costs and expenses related to coal transportation; (6) the timing and transparency of refunds

relating to the ITC and MISO; and (7) costs related to the utility’s agreement to sponsor a

significant share of the cost of constructing and operating the NEXUS Pipeline. Each of

these issues are addressed below.

A. 2017 Electric Load Forecast The company’s witness regarding its 2017 load forecast, Mr. Leuker, explained

(through the use of Exhibit A-21) how DTE’s expected electric sales for all four major rate

classes [namely, residential, commercial, industrial, and other] would likely play out during

that year. The figures he provided, which cover total sales, net system output (NSO), and

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peak electric demand, are based on historical data for 2010 through 2015, a combination of

7 months of historical information and 5 months of projected data for 2016, and forecasted

figures for the period of 2017 through 2021. See, 4 Tr. 553-554.

As noted earlier, GLREA challenged Mr. Leuker’s load forecast for 2017 through 2021

on the grounds that it did not account for commercial/industrial customer-owned renewable

generation, specifically with regard to PV solar projects that those customers might elect to

install. See, 3 Tr. 50-51. According to GLREA’s witness, Mr. Crandall, although DTE did

appropriately include the likely effect of residential PV solar projects, it was remiss in not

making a similar downward adjustment with regard to its commercial and industrial customers

for that 5-year period. See, 3 Tr. 49-55.

The ALJ is not persuaded by GLREA’s asserted problems with regard to DTE’s electric

load forecast. As reflected on several of this intervenor’s own exhibits (i.e., Exhibits GLR-2,

GLR-3, GLR-4, and GLR-6) very few customer-owned PV solar units have been installed by

DTE’s commercial and industrial customers. As a result, no quantitative basis currently exists

for making a reasonable estimation of how much, if any, PV-based generation will be added

by DTE’s commercial and industrial customers in the short term. Moreover, this issue can

be revisited in the near future, and--if commercial and industrial customers actually begin to

install PV solar units on a larger scale than they currently are--adjustments can and will be

made to DTE’s load forecast. In the meantime, the ALJ finds that the electric load forecast

numbers submitted by the utility are reasonable and should be adopted for use in this case.

B. Projected Transmission and MISO Expense for 2017

The utility’s witness regarding transmission- and MISO-related expenses, Mr. Nick,

testified that all such expenses were reasonable and prudent “because they are required in

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order for [DTE] to serve its full service customers.” DTE’s initial brief, p. 19, citing 4 Tr. 363.

According to him, these costs are estimated to be $363 million in 2017. See, Id., p. 20, citing

Exhibit A-19, line 15. Mr. Nick further testified regarding the federal regulatory and appellate

issues that might affect the cost of MISO services received by DTE (and, thus, its customers)

during the 2017-2021 period. See, 4 Tr. 364-371.

The only party to take issue with the assessment provided by Mr. Nick was the

Attorney General, who (based on testimony provided by his witness, Mr. Coppola) raised two

concerns.

First, the Attorney General’s witness asserted that DTE’s total expected transmission

costs for 2017 should be reduced by $25,269,000. As reflected on Exhibit AG-13, Schedule

No. 9, and as a result of an order issued by the FERC on September 28, 2016 in Docket No.

L14-12-002, such a reduction would appear to be warranted. DTE agrees that this reduction

is indeed needed, and therefore “does not dispute Mr. Coppola’s recommendation.” DTE’s

initial brief, p. 20. None of the other parties took issue with that assessment. The ALJ thus

recommends that the Commission reduce the utility’s initially requested PSCR factor to

account for this $25.3 million reduction in DTE’s expected transmission costs for the 2017

PSCR plan year.5

The second concern expressed by Mr. Coppola, and relayed by the Attorney General,

was that DTE should receive a Section 7 warning to the effect that the utility’s failure to

provide additional information in its 2017 PSCR reconciliation case “regarding its decision

5 Based upon its acceptance of this $25.3 million dollar reduction, DTE now asserts that it is in “an over-recovered PSCR position” whereby it would “lower the PSCR factor effective June 1, 2017 in an attempt to eliminate this PSCR over-recovery by December 2017. See, Exhibit A-2. Consequently, DTE filed a new rate sheet (C8.1) setting the PSCR factor from June 2017 forward at negative 0.030 cent per kWh.

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not to pursue rehearing of a FERC order related to PAR transformer costs” would likely lead

to a disallowance of those costs. 4 Tr. 374. According to Mr. Coppola, the FERC’s

September 22, 2016 order in Docket ER11-1844 reversed that commission’s initial

acceptance of the cost allowance for PAR transformers installed at Bunce Creek on the

Michigan-Ontario border in MISO’s base tariff, effectively allocating the total cost of those

PAR facilities to the MISO pricing zone in which DTE is located.

The record established in this case does not provide a reasonable basis for adopting

the Attorney General’s request to find that that the utility’s election not to appeal the FERC’s

order in Docket ER11-1844 is meritless. As a result, the ALJ concludes that, notwithstanding

the $25.3 million reduction discussed above, DTE’s proposed transportation and MISO

expenses for 2017 (as adjusted) are appropriate for recovery from its customers.

C. Projected Generation, Purchased Power, and Emissions Compliance Costs

Company witness, Shawn D. Burgdorf, the Supervisor of DTE’s Tactical Merchant

Analytics Team within its Generation Optimization Department, testified with regard to (1) the

utility’s projected generation expense (including expected emission allowance costs) for

2017, as well as (2) the purchased power requirements and all associated costs for the 2017

PSCR plan year. See, 4 Tr. 493. In addition, he provided information (much of it set forth in

Exhibits A-3 through A-10) regarding the generation expense and emission allowances

expected during 2018 through 2021 to serve DTE’s full service load requirements. Id.

Mr. Burgdorf’s testimony, which placed DTE’s load forecast to be coincident with the

MISO peak demand described by Mr. Leuker (See, 4 Tr. 499), further explained and justified

DTE’s expected expenses for NOx and SO2 compliance activities. See, 4 Tr. 509-515, and

Exhibits A-7 through A-10. Moreover, he pointed out the projections of renewable energy

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production levels (as set forth on Exhibit A-6, and whose purchase is required pursuant to

2008 PA 295) to be acquired by DTE both now and in the future. See, 4 Tr. 504-507.

None of the parties to this case has asserted that the projections Mr. Burgdorf

presented in this proceeding regarding the overall cost of electric generation, purchased

power, and emission compliance (with regard to both NOx and SO2) is in any way

unreasonable or imprudent. As a result, the ALJ recommends that the figure he proposed,

$1,377,898,000, should be adopted by the Commission as the total cost to be used in this

case.

D. River Rouge Unit 3 Costs

Unlike the overall projections provided by Mr. Burgdorf, the MEC--based primarily

on testimony offered by Mr. Sansoucy--directly asserted that DTE’s proposed recovery of

generation, urea expense, NOx control, and limestone costs related to River Rouge Unit 3

running through 2020 should be rejected. See, MEC’s initial brief, pp. 69-87, citing 4 Tr. 398-

400. Specifically, MEC asserted that the Commission should (1) find that this facility is “likely

uneconomic to operate,” (2) “caution DTE that in the reconciliation [of this case], the

Commission will likely disallow recovery of the portion of plan year costs incurred by River

Rouge Unit 3,” at least for those “in excess of its market energy and capacity revenues,” and

(3) issue a Section 7 warning to the effect that “future recovery of such excess costs for the

period of 2018 through 2120 are also likely, on the basis of present evidence, to be denied.”

Id., p. 87.

In contrast, with regard to this issue, the utility’s witness on this matter, Mr. Yurko,

offered testimony and exhibits directly supporting the generation, urea, and limestone costs

for 2017, as well as the following 4 years, and also estimated all economic sales that would

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likely be made by DTE into the MISO market during that time. See, 4 Tr. 391. These included

significant capacity increases over the years based on both owned solar and wind generation

expansion, as well as upgrades to the Ludington Pumped Storage Unit. See, 4 Tr. 391-400,

citing Exhibits A-11 through A-13.

Despite Mr. Sancoucy’s criticisms regarding DTE’s continued use of River Rouge

Unit 3, Mr. Yurko’s testimony was mainly undisputed regarding the reasonableness and

prudence of DTE’s generation, emission levels, urea expenses, and limestone costs. As a

result, the ALJ finds that those costs should be adopted for use by the Commission in this

case. This is based on testimony set forth at 4 Tr. 398-400. To do otherwise would seem to

be adopting a position that is not fully supported on the record, and which would be at odds

with prior Commission rulings regarding such matters.

E. The Reasonableness and Prudence of DTE’s General 2017 Fuel Supply Plan

Two of DTE’s witnesses, Messrs. Pratt and Wines, offered testimony in support of

DTE’s fuel supply plan, which (at least initially) set projected expenses at $800,239,000 for

all of the company’s fossil-fueled and nuclear-fired plants. See, 3 Tr. 211-216 and 4 Tr. 537-

545, as well as Exhibit A-14, line 54. According to these witnesses, DTE’s fuel supply plans

(including all nuclear fuel costs for the Fermi generating facility) for the plan year in question

were reasonable and prudent. See, 3 Tr. 221-222 and 4 Tr. 545.

In addition, Mr. Pratt offered testimony regarding the utility’s forecasted costs related

to coal, oil, coke oven gas, blast furnace gas, and petroleum coke for the 2017 through 2021

period. See, 3 Tr. 211-216, citing Exhibit A-14. In addition to those other various fuel

purchases, he asserted that DTE expected to supply its natural gas requirements through a

“combination of spot market purchases, long-term agreements, and purchases from local

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distribution companies under Commission-approved tariffs.” See, DTE’s initial brief, p. 22,

citing 3 Tr. 216.

Moreover, Mr. Pratt testified that the agreement with the NEXUS Pipeline had been

expected to reduce DTE’s overall fuel expense by approximately $466,000 in the course of

the 2017 PSCR plan year (See, Exhibit A-29), and that for the full 2017 through 2021 period,

the gas-based fuel expense would only rise by approximately $3.4 million. This would, he

asserts, be less than fuel expenses that would be expected under the existing gas and coal

purchasing structure. See, 3 Tr. 219. In addition, Mr. Wines offered testimony supporting

the five-year projection (covering the period of 2017 to 2021) for Fermi’s fuel expense, while

specifically noting that the 2017 fuel cost for that plant would be $50,362,000 during 2017.

See, 4 Tr. 541-546, as well as Exhibit A-20.

Based on the testimony offered by DTE’s witnesses, the ALJ concludes that the

basic fuel supply plan proposed by the company is both reasonable and prudent, and should

be adopted in this proceeding.

Beyond arguments related to the NEXUS Pipeline, which will be discussed in detail

in the following section of this PFD, none of the parties appear to assert that the fuel supply

plan described above by Messrs. Pratt and Wines was in any way unreasonable and

imprudent, with the exception of Mr. Coppola. As for Mr. Coppola, he contends that the

Commission should find that forecasted revenue from DTE’s Midwest Energy Resources

Company (MERC), which is an affiliated company that transports coal and other fuels by rail,

should be a negative $3.6 million, at least with regard to the 2017 PSCR case. See,

4 Tr. 678-679. In addition, Mr. Coppola asserted that DTE should effectively be issued a

Section 7 warning to the effect that the utility should either take all necessary steps to reduce

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its operation and maintenance expenses with regard to MERC or increase its third-party

revenues in order to ensure that MERC’s operations do not impose negative cost impacts on

DTE’s PSCR customers.

In this regard, Mr. Pratt specifically pointed out that Mr. Coppola failed to consider

that the majority of MERC’s operating costs is attributable to DTE’s fuel transshipments, and

that the transshipment level for 2017 was consistent with recent years. See, 3 Tr. 237.

Moreover, Mr. Pratt noted that Mr. Coppola’s analysis failed to take note of the fact that fixed

costs associated with DTE’s operation of MERC (such as the land lease, security efforts,

electric power for things like lighting and environmental controls, stockpile management, fire

watch, etc.) all remain relatively constant regardless of the precise amount of coal that is

shipped into or out of the facility. See, Id. In addition, although its transmission tonnage has

remained relatively constant since 2014, the variable operating costs for MERC have actually

declined by 5%, thus reflecting that MERC and DTE have done a reasonably good job of

reducing costs tied to this facility. See, 3 Tr. 237-238.

For these reasons, the ALJ recommends that the Commission reject the Attorney

General’s assertions and, instead, approve DTE’s general PSCR fuel supply plan for 2017.

F. ITC/MISO Refund Timing and Transparency

ABATE noted that, during January of 2017, DTE received an approximate

$34.2 million refund payment from ITC through MISO that arose from the FERC’s ruling in

Docket No. EL-14-12-002, which ordered a lower rate of return on common equity for ITC

and others operating within MISO’s geographic territory during the period of November 2013

through February 2015. See, ABATE’s initial brief, p. 2. DTE allegedly elected to disburse

this refund by initially lowering its PSCR factor from June through December 2017, with the

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remaining (true-up) amount to be issued to its customers at a later date. See, Id. However,

ABATE goes on to note that nothing on the bills sent to its customers seems to indicate that

DTE is passing back a refund from ITC/MISO, or indicating why that is or is not happening.

See, Id. ABATE further pointed out that DTE is also expected to receive refunds from a

similar FERC-based proceeding (designated as Case No. EL15-45-000) covering the period

running from February 2015 through May 2016. See, Id.

ABATE contends that these refunds have not been, but should be in the future, “flowed

back to customers more promptly, and with better transparency and verification of their

accuracy.” Id. Specifically, it asserts that the PSC should order DTE to distribute to its

customers, in a much more timely fashion, any and all refunds related to FERC Case

No. EL15-45-000, as well as documenting that refund in a more detailed and transparent

fashion than was done with regard to the earlier refund. See, ABATE’s initial brief, pp. 3-5.

The ALJ agrees, to a large degree, with the request by DTE to find that it has not

currently been shown that the ITC/MISO refunds provided thus far have been in any way

inadequate or inappropriate. First, he ALJ concludes that no valid reason exists for the

FERC’s ruling in Docket No. EL-14-12-002 to be viewed as either inadequate or incorrect.

Second, no grounds have been provided for finding that the true-up will be in any way

inadequate to leave DTE’s customers whole.

As for the refunds likely to arise as a result of FERC Case No. EL15-45-000, the ALJ

does agree that the Commission should demand that the utility make such refunds faster (a

2 or 3 month turn-around basis would seem reasonable). This would, as ABATE notes,

reduce the possibility of customers that were entitled to the refund departing the system in

the interim, and thus not actually receiving their share of the refund.

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G. DTE’s Proposed Long-Term Contract Regarding the NEXUS Pipeline

The final (and most litigious) issue arising in this case concerns the treatment of

costs related to the proposed NEXUS Pipeline. DTE contends that all costs arising from both

the construction and operation of the facility, at least as they relate to the utility, should be

passed along to its PSCR customers in the scope of the current and all subsequent PSCR

proceedings covering periods during which that Pipeline provides service to DTE. This is not

a new argument, having been addressed (and ultimately rejected) in DTE’s 2016 PSCR Plan

case. See, the Commission’s January 12, 2017 order in Case No. U-17920, pp. 3-6.

As he did in the context of Case No. U-17920, Mr. Sloan sponsored a report entitled

“Impact of the NEXUS Pipeline on Michigan Energy Markets,” (the 2015 Report) which

provides both a description of the project and asserted commercial benefits that it would

provide to DTE. See, Exhibit A-27. As mentioned above, one of DTE’s affiliates is developing

this project with another entity [initially Spectra Energy Corporation, but which merged with

Enbridge Inc. in late February of 2017]. See, 3 Tr. 75, 217, and DTE’s initial brief at p. 32.

According to Mr. Sloan, the proposed NEXUS Pipeline would connect the Marcellus and

Utica gas production regions in the Appalachian producing basin with markets in the upper

Midwest and Western Ontario, both located to the west of those gas production areas, by

way of 250 miles of large diameter pipe which would ultimately transport up to 1.5 Bcf/day of

natural gas. See, 3 Tr. 75.

As a result of the potential construction and operation of the NEXUS Pipeline, this

witness continued, a portion of the gas needed to supply DTE’s usual customer needs, as

well as the utility’s increasing array of natural gas-fired electric production facilities, would

primarily be delivered to its City Gate at a cost savings in excess of $3.1 billion over the first

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20 years of DTE’s contract with NEXUS (covering the 2018 to 2037 period), $1.9 billion of

which would directly flow to what are generally referred to as non-power consumers (a/k/a

DTE’s residential, commercial, and industrial gas customers). See, 3 Tr. 75-81.6

Mr. Sloan further stated that construction of the NEXUS Pipeline “is being driven by

fundamental changes in North American natural gas markets” due to the “development of

new shale gas production technologies” (otherwise referred to as fracking) which have

“greatly increased the availability of low cost natural gas supply” in the country. 3 Tr. 76. In

summary, Mr. Sloan asserted, the NEXUS Pipeline is “attractive to both producers in the

Appalachian Basin searching for new markets for their natural gas, and to customers in the

Midwest” that seek access to low cost gas supplies originating from somewhere other than

the “traditional supply sources” in the Gulf Coast/Midcontinent/West Canada areas that, he

contends, will become “higher cost, less via liable, or less liquid.” 3 Tr 76-77.

In support of Mr. Sloan’s assertions, Mr. Pratt explained that greenfield pipelines

(those being constructed in an area not already overrun by previously-constructed lines, such

as the proposed NEXUS Pipeline, which would traverse a new route), provide several

benefits to DTE that existing pipelines and their current routes would not. See, 3 Tr. 228.

Most importantly, he stated that a greenfield pipeline like NEXUS would “add incremental

gas deliverability into the Michigan region,” and would thus “ensure that Michigan natural gas

customers, including [DTE] would have access to a reliable, long-term source of gas supply,”

6 Although, DTE’s testimony [the direct portion of which was submitted on September 13, 2016, with the submission of a revised version on April 17, 2017, and whose rebuttal testimony was filed on April 24, 2017] indicated that the service commencement date for the NEXUS Pipeline was targeted for November of 2017 (See, i.e., 3 Tr. 217), current events have made it quite clear that the November 2017 in-service date will not be met. Specifically, due to the lack of quorum on the FERC for several months, leaving the application regarding the NEXUS Pipeline’s construction approval in limbo for a substantial period of time, it took until late August of 2017 before the project’s construction was actually approved.

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thereby “creating additional supply diversity and reliability.” 3 Tr. 227-228. None of those

benefits, he concluded, “would be realized by contracting for natural gas capacity from an

existing pipeline,” such as one of those (or more than one pipeline) that has provided service

to DTE in the past, generally from the Southwest or from Western Canada. 3 Tr. 229.

Finally, Mr. Pratt described in detail the commercial terms of the NEXUS Precedent

Agreement, which he stated would provide DTE with 30,000 Dth/day of natural gas at its City

Gate in November of 2017, and that the level of which would rise to 75,000 Dth/day either on

the later of May 2020 or when DTE has added the natural gas generation capacity needed

to utilize the increased volume of its anticipated gas-fired plants (for example, one or more

CCGT facilities whose combined size would both hit those capacity requirements and have

a total capacity factor of at least 70%). See, 3 Tr. 217. According to him, the utility expects

to meet the capacity requirement in 2022. See, Id. In addition, he noted that (1) the initial

20-year portion of the contract calls for only 30,000 Dth/day to be purchased, while the

subsequent 15 years includes the added 45,000 Dth/day, and (2) the agreement also

includes an option for DTE to extend the term of the agreement (for the entire 75,000 Dth/day

purchase) at the same price for up to 10 additional years. See, Id.

Notwithstanding the testimony offered by Messrs. Sloan and Pratt, several of the

other parties point out that the data--and thus the conclusions based thereupon--set forth in

Exhibit A-27 (the 2015 Report) is/are out of date due to the fact that the report was produced

over two years ago. Even Mr. Sloan concedes that there “have been several significant

changes in the natural gas market” since 2015, including:

Changes in the Marcellus/Utica-related pipelines; Marcellus/Utica production growth continuing despite low prices; lower growth in U.S. [liquefied natural gas] exports; faster growth in U.S. exports to Mexico; and stronger growth in gas demand for electricity generation.

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3 Tr., 83-86, as well as statements provided by the U.S. Energy Information Administration.

Nevertheless, Mr. Sloan continued, the:

2015 Study was based on the best available information at the time. Since that study was completed, gas markets have experienced important changes. However, much of the change in natural gas markets has been the result of improvements in exploration and development technology that have reduced production costs, and significantly increased the long term production outlook for the Marcellus/Utica [area]. The growth in production outlook in these basins has led to additional proposals to add pipeline capacity out of the region. When looked as together, the changes in the natural gas market since the . . . 2015 study was completed have not changed my original conclusions hat holding NEXUS will benefit [DTE’s] customers and Michigan consumers by reducing the net present value of the costs for natural gas purchases.

3 Tr. 89-90.

For his part, Mr. Pratt went on to point out that, within the context of DTE’s fuel supply

plan for the 2017 PSCR plan year, NEXUS’s gas transportation costs and gas supply costs

related to the Kensington facility are both included in the utility’s fuel expense forecast, as

summarized in Exhibit A-14. See, 3 Tr. 219. Moreover, he noted that (as indicated in Exhibit

A-29) DTE expected that its precedent agreement with the NEXUS Pipeline would reduce

the company’s fuel expense by approximately $466,000 for the 2017 PSCR Plan year. See,

3 Tr. 219. In addition, he asserted that although there would likely be “modest increased fuel

expense due to NEXUS from 2017 through 2021,” there would be a $79 million reduction in

fuel expense for the overall period 2017 through 2037. See, Id.

Notwithstanding the testimony offered by Messrs. Sloan and Pratt, other parties to

this case question both (1) whether any portion of the NEXUS-related costs should be

recovered as part of the 2017 PSCR process, and (2) whether any future costs arising from

this proposed project should be approved as part of DTE’s 5-year forecast, as opposed--at

a minimum--to being subject to a Rule 7 warning.

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Among other things, MEC asserted in its initial brief that DTE offered two rationales

for approval of NEXUS Pipeline-based costs. First, MEC claims that DTE argues that the

NEXUS Pipeline will allow “incremental natural gas deliverability” into Michigan that will

create “additional supply deliverability and reliability.” MEC’s Reply Brief, p. 4, citing DTE’s

initial brief, p. 34. Second, MEC points out that DTE asserts that there will be “commercial

benefits” resulting from DTE customers “saving $350 million over the contract period.” MEC’s

reply brief, p. 5, citing DTE’s initial brief at pp. 35-36. MEC contends that the utility’s

arguments “are unavailing” for two reasons.

With respect to the first, stating that construction of the NEXUS Pipeline would

provide additional incremental deliverability, with resulting supply diversity and reliability,

MEC claims that to the extent that this assertion had support in the record (which MEC claims

that it does not) only then “this might be an argument to support construction of a new

pipeline, as those benefits would accrue to all Michigan customers.” MEC’s reply brief p.5,

citing MEC’s initial brief, pp. 64-66. But, MEC continues, DTE is not in the business of new

pipeline construction, and that is the business of its unregulated affiliate, DTE Pipeline

Company. Approving an “above-market affiliate fuel transport contract in order to support a

new pipeline” would, MEC asserts, exceed the Commission’s authority under Act 304, and

would be “in contravention of the [Commission’s] Code of Conduct. MEC’s reply brief, p. 5.

As for MEC’s second argument (regarding DTE’s assertion that the NEXUS Pipeline

will result in an estimated $350 million of savings to the utility’s customers over the next

20 years), it claims that any such assertion “is unsupported by the record and is not credible.”

Id., p. 5. In this regard, MEC claims that the purported savings were derived from “a

November 2015 basis differential analysis, which was based on an August 2015 forecast” of

U-18143 Page 27

natural gas prices. Id. According to MEC, Mr. Sloan--the DTE witness responsible for

analyzing the 2015 basis differential--confirmed that gas production and pipeline changes

between August 2015 and October 2016 resulted in “a very fundamental update to the model”

used to forecast gas costs. See, Id., citing 3 Tr. 172-173. MEC goes on to assert that,

although Mr. Sloan continued to assert that he felt that construction and operation of the

NEXUS Pipeline would lower gas prices in Michigan, “he admitted that he has not quantified”

figures supporting that conclusion. Id., p. 6, citing 3 Tr. 110-111, and 178-179. According to

MEC, and contrary to DTE’s assertion, the evidentiary record does not show a total savings

of $350 million for the utility’s various customers. See, Id. “At best,” MEC continues, the

record shows that a “November 2015 analysis estimated a savings of $350 million, and

subsequent forecasts and events” confirm that this earlier estimate is no longer accurate,

and thus should be discounted. Id., citing Exhibits MEC-2, -5, and -6. For these and other

reasons, MEC contends that the “claimed long-term savings do not provide a reasonable

basis” to approve the inclusion of NEXUS Pipeline costs in the current PSCR Plan. Id.

For his part, the Attorney General asserted that, although DTE’s application and

supporting testimony requested that the Commission approve its proposal to eventually

replace up to 75 Dth/day of its existing gas transportation capacity by use of the NEXUS

Pipeline (beginning with 30 Dth/day in 2017, and then increasing to 75 Dth/day on the later

of May 2020 or whenever DTE has added the required gas-generated electric production

unit(s) to “utilize the increased volume requirement,”) Section 7 precludes the Commission

from including any of those anticipated costs as part of DTE’s 5-year forecast. See, Attorney

General’s initial brief, pp. 26-27. Therefore, he claimed, that “to the extent that [DTE] is

seeking approval of any costs that will be incurred beyond 2017,” such a request should be

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denied. Id., p. 27. This, the Attorney General claims, comports with the Commission’s earlier

orders in Cases Nos. U-17920 and U-17691. See, Id.

In addition to essentially requesting the issuance of a Section 7 warning, the Attorney

General went on to assert that DTE failed to show that it is entitled to recovery of any

transportation expenses related to the NEXUS Pipeline. This, the Attorney General

contends, is based on two factors.

First, he claims that DTE continues to “misrepresent the outcome of the prior

Commission order in Case No. U-17920” regarding the NEXUS Pipeline. Attorney General’s

reply brief, p. 4. Specifically, the Attorney General argues that DTE incorrectly claims that

“its transportation expense on the NEXUS pipeline was thoroughly reviewed in the

Company’s 2016 PSCR Plan, Case No. U-17920,” and that the pipeline’s expenses were

found to “be reasonable and prudent.” Id., citing DTE’s initial brief, at pp. 30-31. According

to the Attorney General:

Those statements are simply not true. It is evident from the Commission’s order in that case that a thorough review of the NEXUS proposal had not been undertaken because all of the relevant information was not before the Commission. In fact, the Commission refused to make any final decisions because no NEXUS costs would be incurred during the 2016 PSCR Plan year.

Attorney General’s reply brief, p. 5. Moreover, he points out that the Commission refrained

from issuing a Section 7 warning in that prior decision simply because it wanted a more

developed record before determining that the costs related to the NEXUS Pipeline were

reasonable. See, Id. However, according to the Attorney General, DTE “continues to rely

on a selective recitation of the Commission’s order” which omits the actual holding. Id. In

this regard, the Attorney General asserts that the order actually stated that:

As it did in the November 22, 2016 order [in] Case No. U-17691, the Commission finds that costs associated with NEXUS should not be

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recoverable absent a transparent evidentiary presentation examining the full nature of the NEXUS arrangements. Only under such circumstances will the Commission be prepared to determine the viability of said costs. The Commission prefers to examine these issues more holistically and therefore refrains issuing a Section 7 warning.

Id. According to him, “the simple fact is that the Commission has not made a final

determination on the reasonableness and prudence of the NEXUS proposal,” let alone any

of the expenses related to its construction or operation. Id., citing the Attorney General’s

initial brief at pp. 13-14.

Second, he asserts that DTE failed to present evident supporting the utility’s request

in this case. According to the Attorney General, “the most glaring omission is [DTE’s] failure

to submit the Precedent Agreement” as part of either its direct or rebuttal cases. Attorney

General’s reply brief, p. 6. Specifically, he asserts that:

This agreement is the foundational document for the Company’s relationship with the NEXUS Pipeline and underlies the NEXUS-related expenses. And, while the Company may have provided the NEXUS Negotiated Rate Agreement that (even with the Precedent Agreement) is not enough to satisfy the Commission’s finding that “costs associated with NEXUS should not be recoverable absent a transparent evidentiary presentation examining the full nature of the NEXUS arrangements.” In fact, the Company’s statement that “[o]therwise, the evidentiary record shows there is no material change in the evidentiary record supporting the recovery of transportation expenses on the NEXUS Pipeline” further illustrates the Company’s failure to meet its burden to produce supporting evidence by a preponderance of the evidence.

Id., citations omitted. Along these lines, the Attorney General continues to assert that DTE

(1) failed to demonstrate a clear need to enter into the agreement regarding the NEXUS

Pipeline, and, likewise (2) did not show that the utility seriously considered other options for

the delivery of gas from the Marcellus/Utica region. Id., pp. 6-7, citations omitted. Moreover,

he points out that the 2015 report relied on by DTE as justification for contracting with the

NEXUS Pipeline has, as noted by Mr. Sloan “generated three iterations” of the base case

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numbers since the initial 2015 report was produced, but that none of the updated figures

were presented in this case. Id. p. 7.

Along these lines, the Attorney General asserts that the utility’s “decision to rely on a

stale report is part of its pattern” in this proceeding “of not putting forth evidence to support

its request and is [thus] contrary to the Commission’s order in Case No. U-17920.” Id.,

citation omitted. According to him:

An updated analysis and report may confirm that the recommendations and conclusions of the report are valid. Otherwise, it is not reasonable and prudent for the Company to rely upon it two years later. Unfortunately, the Company’s position is that [the parties and the Commission] just have to take Mr. Sloan’s word that his fundamental conclusions would or should not change despite the updates to the base case.

In its initial brief, the Company touts the purported commercial benefits to [DTE], its ratepayers, and the State of Michigan from the NEXUS Pipeline, but the Company’s claims specifically as [they] relate to ratepayers are dubious at best and [have] not been substantiated on the whole record. According to Company witnesses, the potential cost savings that could accrue to [DTE] and other consumers in the State of Michigan result primarily from the access the NEXUS Pipeline [which, DTE contends], will provide currently lower-priced gas supply from the Marcellus/Utica gas basins. Mr. Sloan has identified potential benefits to PSCR customers of $79 million over the 20-year from November 2017 to December 2037, with a net present value of $22 million. He also projects a reduction in natural gas expenditures for [Michigan’s electric] power generators, which he asserts represents direct savings to Michigan ratepayers through utility-based recovery of power supply costs.

Id., pp. 7-8.

While conceding that gas from the Marcellus/Utica basins could be beneficial to DTE’s

customers (as well as other Michigan utilities and their customers), the Attorney General

asserts that the Company has failed to demonstrate that securing transportation capacity on

the NEXUS Pipeline at this time is in its ratepayers’ best interest. See, Id., p. 8. According

to him, other options are (or will shortly be) available to have that gas delivered to Michigan

utilities and their customers, most of which DTE failed to seriously explore. See, Id. In this

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regard, the Attorney General continues, the utility’s own witnesses have testified that

Marcellus/Utica gas could be obtained for use in Michigan without the NEXUS Pipeline. See,

Id., p. 9. Specifically, he asserts that other utilities in Michigan are already purchasing and

transporting Marcellus/Utica gas through existing pipelines, and that this is being done at

transportation rates that are lower than what those companies have previously paid. See,

Id. Furthermore, he asserts that none of these other utilities have expressed any concerns

with regard to gas diversity and reliability by using existing gas transportation pipelines. See,

Id. Thus, the Attorney General concludes that DTE has not proven by a preponderance of

the evidence that its goals can only be achieved by the construction and use of “a greenfield

pipeline” like the one proposed by NEXUS. Id.

As for the Staff, it states that although it expressed support for DTE’s position with

regard to the NEXUS Pipeline in Case No. U-17920, “it does not appear that the Commission

wishes to make NEXUS-related determinations in an Act 304 case,” such as this. Staff’s

initial brief, p. 5. As a result, the Staff elected not to take a position on this matter in this

particular proceeding. See, Id.

As previously noted by the Commission in both Cases Nos. U-17691 and U-17920,

the issues raised by the interveners in this regard:

merit the close and thorough discussion undertaken in (Case No. U-17920). Pursuant to 460.6h(7), the Commission may indicate any cost items in the 5-year forecast that, based on present evidence, the Commission would be unlikely to permit an electric utility to recover from its customers in rates, rate schedules, or power supply cost recovery factors established in the future.

As it did in the November 22, 2016 order in Case No. U-17691, as well as its January 12,

2017 decision in Case No. U-17920, the Commission found that the costs associated with

the NEXUS Pipeline should not be recoverable absent a transparent evidentiary presentation

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examining the full nature of the NEXUS arrangements, including its full and actual

construction costs. See, i.e., the January 12, 2017 order in Case No. U-17920, at p. 5.

The ALJ agrees that such a finding should also be applied to this proceeding. Only

under the circumstances previously outlined by the Commission, which were not fully

satisfied in this case, should the Commission determine the viability of the asserted costs.

Moreover, the Commission also expressed its preference to “examine these issues more

holistically” before determining whether issuing a Section 7 warning would be appropriate.

See, Id., p. 6.

In this case, the ALJ concludes that the analyses discussed above cannot be

conducted in an accurate manner (largely because the record shows that construction of the

NEXUS Pipeline will not be completed--and may well not even be initiated--during the 2017

PSCR Plan year). As a result, the ALJ recommends that the Commission not include any

NEXUS-related costs in the 2017 PSCR Plan year, while also recommending both that no

such costs currently be approved as part of the 5-year forecast and no Section 7 warnings

be issued, at least until more certainty and transparency can be provided.

V.

CONCLUSION

Based on the foregoing discussion, the ALJ recommends that the Commission issue

an order adopting each of the findings and conclusions set forth above. Specifically, it is

recommended that the Commission: (1) find that the electric forecast numbers submitted by

the utility for 2017 are reasonable, and should therefore be approved for use in this

proceeding; (2) conclude that--notwithstanding the $25.3 million cost reduction discussed

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earlier which, it appears, is already being implemented by DTE--the utility’s proposed electric

transportation and MISO expenses are appropriate for recovery from its customers, and that

the company’s election not to seek rehearing of the FERC’s adverse decision regarding the

PAR transformer cost issue should not give rise to a Section 7 warning; (3) rule that DTE’s

projected generation, purchased power, and emissions compliance costs--with regard to both

NOx and SO2--are reasonable and prudent; (4) adopt for use in this case DTE’s projected

costs with regard to the continued operation of River Rouge Unit 3, as well as reject MEC’s

request for a Section 7 warning regarding all such costs for the 2018-2020 period; (5) find

that, based on evidence offered by Messrs. Pratt and Wines, DTE’s overall fuel supply plan

for 2017 is reasonable and prudent, and that the Attorney General’s proposed Section 7

warning concerning MERC-related expenses should be rejected; (6) conclude that, although

the ITC/MISO refunds arising from FERC Docket No. EL-14-12-002 do not appear to have

been inadequate or inappropriate, ABATE’s request that DTE be ordered to distribute any

and all refunded monies arising from FERC Docket No. EL15-45-000 faster and with more

transparency should be adopted; and (7) currently refrain from including any NEXUS-related

costs in either the 2017 PSCR Plan year or the 5-year forecast, while also rejecting the

parties’ various Section 7 warnings related to this issue.

Finally, it should be noted that any arguments not specifically addressed in this PFD

are either rejected or have been deemed irrelevant to the ALJ’s ultimate findings and

conclusions in this case.

U-18143 Page 34

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

Issued and Served: November 1, 2017